Renovo Energy Center Plan Approval Application ... - PA DEP

FRE 361-2788 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD

POWER ENGINEERS, INC.

303 U.S. ROUTE ONE FREEPORT, ME 04032 USA

PHONE

FAX

207-869-1200

207-869-1299

December 27, 2019

Mr. Muhammad Zaman

Regional Air Quality Program Manager

PA DEP Northcentral Regional Office

208 W. Third Street, Suite 101

Williamsport, PA 17701-6448

Subject: Renovo Energy Center, LLC Plan Approval Application

Dear Muhammad:

On behalf of Renovo Energy Center, LLC, POWER Engineers, Inc. is submitting three copies of a

Plan Approval Application for the proposed Renovo Energy Center, LLC dual fuel fired combined-

cycle electric generating plant in Renovo, Clinton County, Pennsylvania.

The application consists of the following sections with supporting attachments:

Section 1: Project Overview

Section 2: Applicable Requirements

Section 3: Control Technology Analyses

Section 4: Ambient Air Quality Analyses

Section 5: PaDEP Plan Approval Application Forms

Section 6: Non-attainment Area Requirements

Also enclosed is a check in the amount of $29,700 made payable to the Pennsylvania Clean Air

Fund for the required application fee.

If you have any questions, please contact me at 207-869-1282.

Sincerely,

Tim Donnelly

Senior Project Manager

Enclosure(s):

c: Rick Franzese, Bechtel Development Company

December 27, 2019

RENOVO ENERGY CENTER, LLC

Plan Approval Application

Renovo, Clinton County, Pennsylvania

PROJECT NUMBER:

137575

PROJECT CONTACTS:

Tim Donnelly

EMAIL:

[email protected]

PHONE:

(207) 869-1282

Amy Austin

EMAIL:

[email protected]

PHONE:

(207) 869-1257

Tom Rolfson

EMAIL:

[email protected]

PHONE:

(207) 869-1418

POWER ENGINEERS, INC. Plan Approval Application – Renovo Energy Center, LLC

FRE 361-2787 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD

Plan Approval Application

PREPARED FOR: RENOVO ENERGY CENTER, LLC

PREPARED BY: TIM DONNELLY

(207) 869-1282 [email protected]


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TABLE OF CONTENTS

1.0 PROJECT DESCRIPTION ........................................................................................................... 1

1.1 SITE LOCATION ............................................................................................................................. 1 1.2 PROCESS/EQUIPMENT DESCRIPTION ............................................................................................. 1

1.2.1 Combustion Turbine Generators ........................................................................................... 2 1.2.2 Turbine Inlet Evaporative Coolers ........................................................................................ 7 1.2.3 Heat Recovery Steam Generators with Duct Burners ........................................................... 7 1.2.4 Steam Turbine Generator ...................................................................................................... 7 1.2.5 Auxiliary Boilers ................................................................................................................... 7 1.2.6 Fuel Gas Heaters ................................................................................................................... 8 1.2.7 Dew Point Heater .................................................................................................................. 9 1.2.8 Diesel-Fired Emergency Generator....................................................................................... 9 1.2.9 Diesel-Fired Emergency Fire Water Pump ......................................................................... 10 1.2.10 Fuel Oil Storage Tanks ....................................................................................................... 10 1.2.11 Aqueous Ammonia Storage Tank ....................................................................................... 10 1.2.12 Lube Oil Storage Tanks ...................................................................................................... 10 1.2.13 Circuit Breakers .................................................................................................................. 10

1.3 PROJECT SCHEDULE .................................................................................................................... 11 1.4 FACILITY MAXIMUM POTENTIAL EMISSIONS CALCULATIONS ................................................... 11

1.4.1 CTGs/HRSGs ...................................................................................................................... 11 1.4.2 Auxiliary Boilers, Fuel Gas Heaters, and Dew Point Heater .............................................. 14 1.4.3 Emergency Generator and Fire Pump ................................................................................. 16 1.4.4 Facility Wide ....................................................................................................................... 17

2.0 AIR REGULATORY REQUIREMENTS

3.0 BEST AVAILABLE CONTROL TECHNOLOGY/LOWEST ACHIEVABLE EMISSION

RATE/BEST AVAILABLE TECHNOLOGY (BACT/LAER/BAT) ANALYSIS

4.0 AIR DISPERSION MODELING PLAN

5.0 APPLICATION FORMS

6.0 NON-ATTAINMENT AREA REQUIREMENTS

TABLES:

TABLE 1 MAXIMUM POTENTIAL SHORT-TERM EMISSION RATES .............................. 12 TABLE 2 SUSD LIMITATIONS ................................................................................................ 12 TABLE 3 CTGS ANNUAL POTENTIAL-TO-EMIT ................................................................ 14 TABLE 4 AUXILIARY BOILERS EMISSIONS ESTIMATE ................................................... 15 TABLE 5 FUEL GAS HEATERS EMISSIONS ESTIMATE..................................................... 15 TABLE 6 DEW POINT HEATER EMISSIONS ESTIMATE .................................................... 16 TABLE 7 EMERGENCY GENERATOR EMISSIONS ESTIMATE ........................................ 16 TABLE 8 DIESEL FIRE PUMP EMISSIONS ESTIMATE ....................................................... 17 TABLE 9 ANNUAL FACILITY WIDE MAXIMUM POTENTIAL EMISSIONS

(TONS/YEAR) ............................................................................................................ 17 TABLE 10 CTG HAP MAXIMUM POTENTIAL EMISSIONS .................................................. 18


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APPENDICES:

APPENDIX A FACILITY SITE LOCATION ON USGS TOPOGRAPHICAL MAP APPENDIX B RENOVO ENERGY CENTER SITE PLAN APPENDIX C PROCESS FLOW DIAGRAMS FOR POWER BLOCKS APPENDIX D DETAILED EMISSION CALCULATIONS APPENDIX E POWER BLOCK VENDOR-PROVIDED DATA APPENDIX F FUEL FRACTIONAL ANALYSES APPENDIX G ADVANCED MONITORING AND DIAGNOSTIC SYSTEMS – POWER BLOCKS APPENDIX H COMBUSTION CONTROL DETAILS – POWER BLOCKS APPENDIX I AIR FILTER SPECIFICATIONS APPENDIX J POWER BLOCK OPERATING AND MAINTENANCE DETAILS (GER-3620) APPENDIX K SCR AND OXIDATION CATALYST OPERATING AND MAINTENANCE

DETAILS APPENDIX L AUXILIARY EQUIPMENT MANUFACTURER SPECIFICATION SHEETS APPENDIX M RBLC CLEARINGHOUSE DETERMINATION SUMMARIES APPENDIX N SCR PID APPENDIX O COST ANALYSIS INFORMATION (SCR FOR CTGS AND OXIDATION

CATALYST FOR AUXILIARY BOILERS) APPENDIX P STORAGE TANK INFORMATION APPENDIX Q REGISTRY OF AVAILABLE NOX AND VOC OFFSETS APPENDIX R MUNICIPAL NOTIFICATIONS APPENDIX S CLINTON COUNTY SALDO LETTER, WATER SUPPLY LETTER OF

APPROVAL, PHMC PROJECT REVIEW INFORMATION


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1.0 PROJECT DESCRIPTION

Renovo Energy Center, LLC (REC) proposes to construct a nominally rated 1,240 MW (net) dual fuel-

fired (natural gas and ultra-low sulfur diesel (ULSD)) combined cycle electric generating plant in

Renovo, Pennsylvania. The proposed REC facility will consist of two 1-on-1 power blocks that include a

Combustion Turbine Generator (CTG), Heat Recovery Steam Generator (HRSG), and a Steam Turbine

(STG) in line to produce electricity for distribution into the transmission grid system. Each combined

cycle system is intended to be fired on natural gas unless there is an interruption in supply. Additionally,

each HRSG is equipped with a natural gas-fired Duct Burner (DB) for supplemental steam production,

and the steam from the HRSGs is routed through the condensing STG. REC will utilize Air Cooled

Condensers (ACCs) for condensing the exhaust steam, which is an environmentally preferred method

when compared to a traditional wet cooling tower.

The proposed REC facility will also include two auxiliary boilers, one diesel-fired emergency generator, a

diesel-fired emergency firewater pump, and natural gas-fired fuel heaters. The HRSG DBs, the auxiliary

boilers, and fuel gas heaters will combust only pipeline quality natural gas. The emergency firewater

pump and emergency generator will utilize ULSD fuel.

In addition to the combustion devices, the REC facility will also have potential air emissions from

petroleum storage tanks, ammonia slip from Selective Catalytic Reduction (SCR) process, and sulfur

hexafluoride (SF6) containing circuit breakers.

1.1 Site Location

REC’s proposed site is a 68-acre parcel located north-northeast of the Town of Renovo between Erie

Avenue and Industrial Park Road. The site is the location of the former PRR/Philadelphia & Erie railroad

car renovation facility.

The approximate UTM coordinates of the proposed site are 269.446 kilometers (km) Easting and

4,578.872 km Northing. The project will be located at a base elevation of approximately 670 feet above

mean sea level. The immediate project site consists of flat terrain in an east-west orientated river valley

with increasing elevated terrain to the north and south of the proposed site. Included in Appendix A is a

USGS topographical map with the project site location identified.

1.2 Process/Equipment Description

Appendix B includes a site plan with the proposed location of the buildings and equipment indicated.

REC is proposing to install and operate the following devices:

• Two GE 7HA.02 natural gas/ULSD fired CTGs (each with maximum heat input capacities of

3,541 million British thermal units per hour (MMBtu/hr) High Heating Value (HHV) when firing

natural gas, and 3,940 MMBtu/hr HHV when firing ULSD) with inlet evaporative coolers;

• Paired with each CTG, one condensing STG and one driven electric generator;

• Two HRSGs with supplementary natural gas-fired DBs, each with maximum heat input capacities

of 1,005 MMBtu/hr HHV;

• Two natural gas-fired auxiliary boilers (one for each power block), each with maximum heat

input capacities of 66 MMBtu/hr;

• One diesel-fired emergency generator rated at 1,500 kW (~14.3 MMBtu/hr heat input);


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• Three natural gas-fired fuel gas heaters, each with maximum heat input capacities of 15

MMBtu/hr and located 1.25 miles from the site at a pressure reducing station;

• One on-site natural gas-fired dew point heater with a maximum heat input capacity of 3.0

MMBtu/hr;

• One diesel-fired emergency firewater pump, rated at 250 hp (~1.8 MMBtu/hr heat input);

• Two aqueous ammonia aboveground storage tanks with a capacity of 26,000 gallons each;

• ULSD aboveground storage tank with a capacity of 3.5 million gallons;

• Two lube oil aboveground storage tanks each with a capacity of 20,000 gallons; and

• Twelve high voltage circuit breakers containing sulfur hexafluoride (SF6) within the facility’s

electrical switchyard.

While fuel suppliers are typically not selected at this point in the development process, REC has been

conducting a solicitation process for the firm supply of natural gas and has received offers from a number

of well-known suppliers. REC expects to select the preferred supplier and enter into a long-term supply

contract in approximately mid-2020. ULSD is available from several regional suppliers and will be

purchased on the spot market as needed. Fractional analyses for both fuels are provided in Appendix F.

1.2.1 Combustion Turbine Generators

Overview

The CTG is the main component of a combined-cycle power system. In the initial stage, air is filtered,

cooled by the evaporative cooler during warm weather, and compressed in a multiple stage axial flow

compressor. Compressed air and fuel are mixed and combusted in the turbine combustion chamber. Lean

pre-mix dry low-NOx combustors minimize Nitrogen Oxide (NOx) formation during natural gas

combustion. When combusting ULSD, water injection will be employed to reduce thermal NOx

formation. Hot exhaust gases from the combustion chamber are expanded through a multi-stage power

steam turbine that results in energy to drive both the air compressor and electric generator.

In combined-cycle mode, the exhaust gas exiting the CTG is ducted to a boiler commonly known as a

HRSG where steam is produced to generate additional electricity in a STG. The natural gas fired DBs

located within the HRSGs are used for supplementary firing to increase steam and electrical output.

Design Considerations

To maximize electrical generation efficiency, the STG has been designed with advanced 3D

aerodynamics and improved sealing to minimize leakages. Computational fluid dynamics (CFD)

techniques were applied to inlet and exhaust regions to minimize losses. Optimized steam path design and

development of larger/more efficient LP last stages were customized to particular applications to

minimize exhaust losses, and advanced airfoil manufacturing was used to realize efficiency gains.

Steam Bypass

REC proposes a cascade type steam bypass, which will be designed to control the pressure and facilitate

the STG startup. As pressure initially builds in the HRSG during CTG start-up, the steam generated in the

HRSG will be routed to the ACCs until the steam conditions meet the requirements to start the STG. The

steam bypass system and the decoupling of the STG by a clutch allows the CTG to start rapidly to


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Minimum Emissions Compliance Load (MECL) and then on to full load without the traditional hold

times required by the STG in its warming cycle, thereby limiting startup emissions.

In instances of rapid STG load rejection, the 100-percent capacity cascaded bypass system will allow the

CTG to operate at full load (with evaporative coolers turned off) by diverting 100-percent of the high

pressure and reheat steam flow at rated pressure and 100 percent of the low-pressure steam flow at rated

pressure to the ACC. This will allow a more controlled ramp down of the CTG following such an event.

This steam bypass arrangement supports GE’s Rapid Response Lite plant feature, which is intended to

minimize plant emissions on Start-up and Shutdown (SUSD). The GE Rapid Response Lite plant breaks

the links normally existing between the STG and steam cycle during startup to allow the CTG to start and

load at its own maximum rate, thereby reducing emissions relative to a design that requires a number of

hold points during times of sub-optimum emissions.

Inlet Air Filters

GE provides a self-cleaning filter house with weather hood and moisture separator/coalescing filters

inside the weather hood. The moisture separators are 90% efficient for 50-micron water droplets. The

coalescing filter will also act as a pre-filter with a filtration efficiency of G3 as per EN 779-2002. Final

filter's filtration efficiency is rated F8 as per EN 779-2002. Inlet air filter specifications are provided in

Appendix I.

Operations

Steady-State

REC’s CTGs will operate at very low NOx levels when operating in steady state conditions using dry

low-NOx combustors, proper operation, and SCR technology.

A combined-cycle turbine power train generates power from the CTG while simultaneously recovering

and transferring high temperature exhaust energy to the STG to increase power production and overall

unit efficiency. The benefits of employing combined cycle technology/design is the relatively short SUSD

time and ability to quickly change loads as compared to boiler systems used for generating electricity, and

the significantly higher generating efficiency as compared to a gas turbine in simple cycle mode.

The CTGs/HRSGs will also contain an oxidation catalyst system for reducing exhaust gas emissions of

Carbon Monoxide (CO) and Volatile Organic Compounds (VOCs). The catalyst promotes the oxidation

of CO and VOCs to Carbon Dioxide (CO2) and water as the exhaust gas passes through the oxidation

catalyst bed. There are no reactants used in the catalyst system, the oxidation to CO2 and water

spontaneously occurs.

Startup and Shutdown

During periods of SUSD the emissions from the CTGs are not controlled to the levels of steady state

operation due to flue gas and catalyst temperatures not being high enough to effectively operate the SCR.

Thus, SUSD NOx emissions will be higher than steady state load conditions. The higher, uncontrolled

NOx emissions during SUSD cannot be avoided.

GE’s site specific SUSD procedure for REC is not available at this stage of project development but will

be finalized following delivery of the equipment and prior to initial commissioning. However, the REC


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Plant will employ GE’s Rapid Response Lite auto-start sequence during startup (the same technology as

is being deployed on the Lackawanna, Moxie Freedom, and Birdsboro plants in PA). GE’s Combined

Cycle Rapid Response technology uses a clutch to decouple the CTG from the STG during start-up and

loading sequences. The CTG can be started and brought to full speed, synchronized to the grid and reach

full load while separated from the STG. During this process the steam generated in the HRSG is bypassed

around the STG to either the cold reheat or directly to the ACC. When suitable matching of steam to

metal temperatures is reached the STG can be brought to speed, coupled and loaded. Other features in

Rapid Response fast start plants are the use of an auxiliary boiler that establishes STG steam seals and

sparging prior to start-up, the use of stack dampers to reduce heat loss from the HRSG during shut-down

and controls to coordinate and enhance plant startup sequences. All of these will be included in REC’s

design.

Prior to initiating startup, the plant is in a ready-to-start condition, i.e. all plant equipment which is needed

to be operating during startup is in a no-fault condition, operational and/or in automatic mode. Water

levels and pressures in drums, hotwell and other vessels are within range and/or not in an alarmed

condition. STG sealing steam is on and condenser vacuum is within the range required for STG startup.

CTG start-up consists of firing the unit and accelerating to full speed (no load), then synchronizing and

loading the unit to minimum load quickly where exhaust levels meet compliance emission levels. Once

the CTG has commenced operation the start of the HRSG consists of warming the unit with the CTG

exhaust flow, quickly bringing the catalyst temperatures to operating level. Since the STG is not a

contributor to emissions, its startup is not so time sensitive. After warming and matching steam to unit

temperatures the STG is accelerated to full speed, the clutch is engaged and the unit is loaded. To avoid

thermal stress, various components of the STG must be brought up to temperature prior to normal STG

operation. In a combined cycle system, the amount of time since previous operation of the STG and

HRSG factors into the temperature of components and dictates the duration of the startup period.

Shutdown consists of reducing CTG load to the desired level and then cutting off all steam to the STG,

then the clutch is disengaged to separate the CTG and STG. The CTG is maintained above MECL until

disconnected from the STG, after which it continues to unload until its electrical output is near zero, then

the breaker is opened and the unit coasted down. The fuel is shut off at approximately 40% speed.

The GE Rapid Response Lite Plant reduces emissions through the decoupling of the STG allowing the

CTG to be quickly unloaded and tripped without the usual concern of protective operation requirements

of the STG. The advantage of Rapid Response Lite relative to conventional start-up is the lower amount

of time spent at low loads, resulting in higher efficiency, less fuel burned and reduced criteria pollutant

emissions during startup.

The event definition of SUSD is taken from the manufactures document “Combined Cycle Systems

Engineering Plant Startup and Shutdown Emissions for 7HA.02 Single Shaft Rapid Response Lite”

(included in Appendix E), which is consistent with the Federal and state definition; Startup is defined as

the time from CTG fire to HRSG stack emissions compliance. Shutdown is defined as the time from the

time that the CTG drops below MECL during shutdown to termination of fuel flow to the CTG.

For the purposes of this application, the following summarizes the time periods that define startups:

• Hot Start = unit has not operated in 8 hours or less

• Warm Start = unit has not operated in between 8 to 72 hours

• Cold Start = unit has not operated in over 72 hours


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Monitoring and Combustion Controls

Each Power Block will be equipped with GE’s Advanced Monitoring and Diagnostic System (AM&D)

(see Appendix G), which will monitor the performance of the generating equipment. In addition, each

power block will be equipped with a Continuous Emission Monitor System (CEMS) that will evaluate the

emission performance of the CTGs and SCR/oxidation catalysts.

Both the AM&D system and the CEMS have on-site monitors for use by operations personnel in

optimizing plant performance and identifying required maintenance of the plant. Performance is

monitored using incoming measured data as inputs to performance calculations which are compared to

target values to assess proper operation of the systems. Heat balance of the gas turbine produces

additional information regarding the conditions of the ingoing and outgoing streams. This creates detailed

information about the current operating point that is consistent with the mass and energy balances of the

equipment. A performance audit can be conducted comparing current performance against expected

performance based on design and tests. The AM&D system is also monitored, real time, by GE at their

Monitoring and Diagnostic Center in Atlanta, GA. GE employs over 50 engineers at their center to

continuously monitor customer equipment to help optimize performance and improve maintenance.

GE provides an industry proven Dry Lox NOx combustion system to minimize emissions during

operation. Combustion controls are tuned at the time of plant startup and periodically thereafter.

Appendix H contains documentation on the combustion system and the controls used to monitor the

performance of the power block configuration.

Emission Control Equipment

As previously stated, each CTG will be equipped with SCR for control of NOx emissions, and an

oxidation catalyst to control CO and VOC emissions.

The make and model of the specific SCR to be used is not available at this stage of project development

and will not be determined until GE procures this equipment during project execution. GE typically

utilizes honeycomb vanadium/titanium-based catalysts (or equivalent) from a qualified vendor such as

Cormetech, Haldor Topsoe or Hitachi Zosen. Appendix K contains a representative manufacturer’s data

sheet for the SCR unit.

The make and model of the oxidation catalyst to be used are not available at this stage of project

development and will not be determined until GE procures this equipment during project execution. GE

typically utilizes oxidation catalysts from Emerichem, BASF, JMI, or equivalent. Appendix K contains a

representative manufacturer’s data sheet for the oxidation catalyst unit.

Monitoring

The following monitoring will be provided:

• Differential pressure gauges across the SCR catalyst and across the oxidation catalyst with test

ports located upstream and downstream of the oxidation catalyst and SCR catalyst.

• Thermocouples upstream of the oxidation catalyst and thermocouple downstream of the

Ammonia Injection Grid (AIG)/upstream of the SCR catalyst. The differential pressure and

temperatures are not actively controlled with either the gas turbine controller or the Distributed

Control System (DCS) and there is no set point for any control loop.


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The oxidation catalyst module will be integrated in a suitable temperature window of the HRSG and will

be a gas-tight, self-supporting steel structure. The performance of the catalyst is monitored, but not

actively controlled.

Please see Appendix K for additional information on the active ammonia injection control for the SCR.

Maintenance

Plant specific detailed maintenance and monitoring plans will be prepared during the construction phase

of the project by the plant operators, assisted by REC’s Operations and Maintenance (O&M) Contractor

and consistent with OEM requirements and specifications. These plans will be based on and derived from

the information presented below. All routine covered and unscheduled maintenance will be based on

OEM recommendations and prudent utility practices and implemented through a combination of Long-

Term Services Agreements (LTSA) with OEMs, and a software-based maintenance scheduling system

used by plant maintenance personnel. Additionally, the AM&D will be used to assess plant and

equipment performance on a real time basis to evaluate the need to modify maintenance schedules.

Maintenance for each REC power block and balance of plant emission source equipment will be managed

in three categories:

a. Routine Maintenance – Maintenance of a routine and daily nature, which will be performed by

plant site personnel in accordance with manufacturer’s recommended procedures.

b. Covered Maintenance – Periodic maintenance that includes inspection, overhaul, repair, and

replacement of equipment, which will be performed by the OEM. Specific Equipment O&M

manuals will not be available from the equipment supplier until the equipment is delivered but

will be available prior to the scheduled start of commissioning of the units.

c. Unscheduled/unplanned Maintenance – Maintenance that is unscheduled or unplanned which

arises due to performance shortfalls, indications from AM&D systems or equipment failures will

be performed by the OEM and REC as provided in maintenance agreements.

Maintenance plans for the CTGs, inlet air filters, oxidation catalyst and SCR are provided in the following

appendices:

• Appendix J (GER 3620) brochure provides detail on maintenance planning, maintenance

inspections, and inspection intervals that are common to the GE 7HA.02 gas turbines being

utilized at REC.

• Appendix I (GEK1162969) instructions provides maintenance recommendations for the inlet air

system (starting on page 17). The power augmentation system is media type evaporative coolers

and the corrosive environment is C2 for the maintenance recommendations.

• Appendix K includes a 6-page white paper on Oxidation Catalyst, describing the physical and

chemical deactivation, operating limits, and catalyst maintenance and testing requirements, and a

13-page white paper on SCR Control Philosophy, describing operating theory, equipment

description, maintenance, maintenance schedule and performance evaluation.


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1.2.2 Turbine Inlet Evaporative Coolers

During hot and humid ambient air conditions, REC will employ evaporative cooling to cool the air

entering the CTG by evaporating water sprayed into the air intake, immediately following the inlet filter.

A mist eliminator will prevent water droplets from reaching the turbine blades. The cooling of the inlet air

increases the density of the air entering the CTG resulting in increased power output capacity. CTGs are

volumetric processes that produce more power with more pounds of air entering the machine. The

evaporative cooler achieves this goal in the summer time by cooling the inlet air when ambient air

temperatures are high.

1.2.3 Heat Recovery Steam Generators with Duct Burners

REC will use two HRSGs, one for each CTG, which will utilize waste heat energy to increase electricity

production. The HRSGs systems extract heat from the exhaust of each gas turbine. The HRSG acts as a

heat exchanger to derive heat energy from the CTG exhaust gas to produce steam that will be used to

drive a steam turbine generator. Exhaust gas entering the HRSG at approximately 1,100°F will be cooled

to approximately 180 °F by the time it exits the HRSG exhaust stack. At times, steam production in the

HRSGs may be augmented using DBs that will be fired by natural gas. The proposed DBs will have a

maximum firing rate of 1,005 MMBtu/hr each.

REC’s SCR and oxidation catalysts will be installed within the HRSG to control NOx and CO,

respectively.

A CEMS for monitoring emissions of NOx, CO, NH3, and concentration of O2 or CO2 will be installed on

REC’s HRSG exhaust stack.

1.2.4 Steam Turbine Generator

Each power block will include a reheat, condensing STG designed for variable pressure operation. The

high-pressure section of the steam turbine receives high-pressure super-heated steam from the HRSGs,

and exhausts to the reheat section of the HRSGs. The steam from the HRSGs reheat section is supplied to

the intermediate-pressure section of the turbine, which expands to the low-pressure section. The low-

pressure section of the turbine also receives excess low-pressure superheated steam from the HRSGs and

exhausts to the condenser for cooling. At ISO conditions, REC’s steam turbine sets are designed to

produce up to approximately 176 MW of electrical output without duct firing, and 273 MW of electrical

output with full duct firing capability.

Additionally, the plant is expected to remain in emissions compliance in combined cycle mode down to a

range of 30 to 40 % of base load (reducing down to 30% load is ambient temperature dependent). The

plant will not utilize the steam bypass to operate in simple cycle mode other than during startup, steam

turbine trip or emergency operation, and in each case for only short periods of time. The plant will not

have a provision to bypass the CTG exhaust gas around the HRSG directly to the stack.

1.2.5 Auxiliary Boilers

The proposed facility will include two auxiliary boilers, one per power block. The auxiliary boilers

provide sealing steam to the steam turbine generator during cold start-up and to warm up the steam

turbine generator rotor. The auxiliary boiler steam will not be used to supplement the power generation of


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the CTGs or steam turbine. The proposed boilers will be fired with natural gas with maximum heat input

ratings of 66 MMBtu/hr.

Make and model is not available at this stage of project development and will not be determined until

REC procures this equipment during project execution, however REC anticipates the boilers will be

Cleaver Brooks model NB-200D-50 or equivalent. The boilers will be equipped with ultra-low NOx

burners and no additional control devices. The boilers will only operate during the startup of their

respective power train and will not operate during normal plant operation. Appendix L contains

manufacturer data sheets and Appendix D contains maximum potential emission calculations. REC is

proposing to limit the annual operation of each auxiliary boiler to a total of 145,200 MMBtu/year. This

limit would not apply during the shakedown period authorized under the plan approval to provide

flexibility in the event that more startups or longer duration startups are required to shakedown the

facility. The requirement that the auxiliary boilers would only be operated during startup would be in the

plan approval to ensure that the auxiliary boilers are not operated longer than necessary. REC notes that

this heat input limitation is equivalent to 2,200 hours of operation at maximum firing rate per boiler in

any 12 consecutive month period, however REC is not proposing an annual limit in operational hours in

conjunction with the heat input limit.

Auxiliary boilers will be monitored using the OEM supplied control system which will be incorporated

into the overall plant DCS. Auxiliary boiler control parameters and alarms will be displayed in the main

control room, through the main enunciator system, and on the local control panel. The auxiliary boilers

will be operated in accordance with OEM guidelines including periodic testing and start-up to ensure

reliable operation that meets design parameters. Further, whether operating or not, routine maintenance as

specified in the OEM manuals will be performed by a combination of OEM, plant, and contractor

personnel.

The auxiliary boilers will have a programmable logic controller (PLC) based system for combustion

control, draft control, feedwater control, etc. with a trouble alarm to the DCS. Operating parameters such

as fuel flow, air flow, steam flow, steam pressure and temperature and any other parameters

recommended by the manufacturer will be monitored regularly to confirm that the boilers are operating at

their optimal level to maximize efficiency and minimize emissions. Fuel and air flow trends will be

reviewed and operating data such as fuel usage per month will be collected and reviewed to calculate

emissions, determine compliance, and to ensure that the boilers are operating properly. The boilers will be

tuned-up annually, which will include measuring CO and O2 levels in the exhaust and optimizing

emissions of CO.

1.2.6 Fuel Gas Heaters

REC’s proposed facility design includes fuel gas heaters. The heaters will be used to increase the

temperature of the incoming natural gas fuel to prevent freezing of the gas regulating valves under certain

gas system operating conditions. The fuel gas heaters will follow the pressure reduction stage and

individual gas lines will be piped and metered separately to the individual gas turbine controllers. The

fuel gas heaters will each have maximum heat input ratings of 15 MMBtu/hr and will be located

approximately 1.25 miles from the site at the pressure reducing station. At any given time, a maximum of

two heaters will be running. The third heater is for redundancy.

Make and model is not final at this stage of project development and will not be determined until REC

procures this equipment during project execution. However, the application is based on heaters

manufactured by Aether, and each will be equipped with a Power Flame burner with a maximum heat

input of 15 MMBtu/hr. Manufacturer specifications and maximum potential emission rates are contained


PAGE 9

in Appendix L. Two heaters will operate up to 8,760 hours per year each and maximum potential

emission calculations are provided in Appendix D.

The fuel gas heaters will be monitored and maintained in accordance with the manufacturer’s

recommendations and industry practice pursuant to an O&M plan that will be finalized during the

construction of the project.

1.2.7 Dew Point Heater

In addition to the off-site fuel gas heaters, a Dew Point Heater (DPH) will be included in the plant’s fuel

gas conditioning system to ensure that the fuel gas temperature is above the dew point temperature to

remove excess moisture content. The DPH will have a maximum heat input rating of 3.0 MMBtu/hr.

The DPH will be monitored and maintained in accordance with the manufacturer’s recommendations and

industry practice pursuant to an O&M plan that will be finalized during the construction of the project.

1.2.8 Diesel-Fired Emergency Generator

REC’s proposed facility will include one diesel-fired emergency generator rated at 1,500 kW to be

operated no more than 500 hours per year, including testing and maintenance hours. The emergency

generator will provide power to the plant during emergency situations to allow operation of critical

ancillary equipment (e.g. lube oil pumps, auxiliary cooling water pumps, water supply pumps, etc.). There

are no plans for the emergency diesel generator to provide power for black start, peak shaving or non-

emergency power.


REC procures this equipment during project execution; however, the generator engine for the basis of this

application is a Caterpillar 5312C diesel engine. The generator will only be used during plant

emergencies, if required, to bring the plant to a safe shutdown. Emissions will be maintained within limits

by proper operation and maintenance. The emergency generator control system will be PLC based and

will monitor, among other parameters, hours of operation, the voltage, current, engine speed, coolant

temperature and oil pressure when the engine is operating. Appendix L contains Caterpillar 5312C data

sheets that includes maximum potential emission rates. The generator will be limited to operating 500

hours per year, with up to 100 of those hours available for use during maintenance and testing operations.

Appendix D’s facility maximum potential emission estimates include the emergency generator’s

emissions.

Start-up and operation of the emergency generator will be incorporated into the plant DCS system, control

room and local control panel. All system alarms and performance parameters will be monitored through

the DCS and at the local control panel. Periodic testing and start-up of the system will be performed as

recommended by the OEM and in accordance with prudent utility practice. Plant personnel will perform

routine maintenance checks of the emergency generator; however, an authorized representative of the

manufacturer will perform all maintenance. Contractual requirements of the Utility Grid Interconnection

Agreement will be incorporated into the operation and maintenance of the emergency generator system.

The emergency generators will be monitored and maintained in accordance with the manufacturer’s

recommendations and industry practice pursuant to an O&M plan that will be finalized during the

construction of the project.


PAGE 10

1.2.9 Diesel-Fired Emergency Fire Water Pump

The proposed REC project will include a 250 bhp diesel-fired fire water pump operated as a fire water

pump driver. The unit will be limited to 250 hours per year, including monthly testing and maintenance.


REC procures this equipment during project execution. However, the application is based on a Clarke,

Model JU6H-UFAD88. Emissions will be maintained within limits by proper operation and maintenance.

The fire pump control system will be PLC based with engine speed, hours operated, coolant temperature

and oil pressure among the parameters monitored when the engine is operating. The engine will combust

ULSD and will not be equipped with any add-on emissions controls. Appendix L contains representative

data sheets that includes maximum potential emission rates. It is anticipated the engine will be run weekly

for 30 minutes or less for testing purposes. Otherwise, the engine will be operated for emergency

purposes (loss of power) in the event of a fire where the fire pump requires operation. Appendix D

contains maximum potential emission estimates based on a limit of 250 hours per year.

The fire system pump will be operated and maintained based on OEM recommendations to ensure

reliable operation that meets system requirements. Engine maintenance will be performed based on time

interval (daily/weekly/monthly/yearly) and run-hours as per manufacturer’s recommendations. All system

alarms will be incorporated into the plant DCS and monitored in the main control room and may be

monitored at the remote operations panel. System maintenance requirements will be per the OEMs and

prudent utility practice and incorporated into the plant maintenance database and system. Maintenance

will be performed by a combination of OEM, plant, and contractor personnel to ensure safe, reliable, and

compliant operation of the engine. NFPA requirements will be incorporated into all testing and O&M

procedures.

1.2.10 Fuel Oil Storage Tanks

The proposed REC project will include a 3.5-million-gallon ULSD aboveground storage tank to provide

fuel for CTGs for three days of operation at full load if natural gas supply is curtailed. One 2,500 gallon

and one 350-gallon ULSD storage tank will provide fuel for the emergency generator and fire pump

engine, respectively.

1.2.11 Aqueous Ammonia Storage Tank

REC will include two 26,000 gallon above ground aqueous ammonia storage tanks (one for each power

train) to provide ammonia for the SCR systems on the combined cycle CTGs.

1.2.12 Lube Oil Storage Tanks

REC will include two 20,000 gallon above ground storage tanks for lubrication oil used for the CTGs and

STGs.

1.2.13 Circuit Breakers

REC will have twelve high voltage circuit breakers within the facility’s electrical switchyard. Six circuit

breakers will contain 360 pounds of sulfur hexafluoride (SF6) and the remaining six circuit breakers will

contain 175 pounds of SF6. SF6 is a highly effective electrical insulating dielectric fluid used for

interrupting arcs and is superior to other dielectric fluids. SF6 is a greenhouse gas with a “global warming


PAGE 11

potential” of 22,800 on a 100-year time horizon, which means its impact as a greenhouse gas is 22,800

times greater than that of CO2.

REC’s circuit breakers will be designed as totally enclosed pressure systems with low potential SF6

fugitive emissions (equipment leaks). Leakage is expected to be minimal and equipment will be built to

low leakage design limits. The International Electrotechnical Commission Standard 62271-1 for new

equipment leakage is 0.5% per year.

REC will implement a SF6 leak detection program to minimize SF6 leaks. Alarm set points will be based

on manufacturer’s recommendations. When the alarm is triggered, it will be sent to the DCS or Utility

Remote Terminal Unit (RTU). The facility shall take corrective action as soon as practicable to fix the

circuit breaker units to a like-new state to prevent the emissions of SF6 to the maximum extent possible.

REC will maintain accurate records on the amount of SF6 dielectric fluid added to each circuit breaker

unit on a monthly basis. The date and time that each alarm associated with the circuit breaker is activated

and corrective action is taken to remedy the problem and the date the corrective action remedied the

problem.

1.3 Project Schedule

REC is submitting this initial application on or about December 27, 2019. REC anticipates commencing

actual construction in the third quarter of 2020. REC’s targeted dates for completing construction and

commercial electrical generation are January 2023 and April – November 2023, respectively.

1.4 Facility Maximum Potential Emissions Calculations

The maximum potential emissions from REC’s facility are primarily products of combustion from the

CTGs and duct burners. To a lesser extent, there will also be emissions from the auxiliary boilers, fuel gas

heater, emergency generators, emergency firewater pump, fuel storage tanks, and circuit breakers.

1.4.1 CTGs/HRSGs

Potential emissions of criteria pollutants from the power blocks vary depending on ambient air

temperature, relative humidity, and operating load of each unit. The CTGs and HRSG will also exhaust

greenhouse gases (GHG), i.e., carbon dioxide, methane, and nitrous oxide. REC will calculate GHG

emissions as outlined in 40 CFR Part 60, Subpart 98. The CTG manufacturer, General Electric (GE), has

provided maximum potential criteria pollutant emissions for various operating loads and ambient

conditions, which are summarized in Appendix D.

SO2 potential emissions are based on use of natural gas with a sulfur content of 0.4 grains per 100

standard cubic feet of gas.

CTGs and DBs maximum potential hourly emission rates ("worst-case" from all operating scenarios) for

each pollutant are listed in the table below.


PAGE 12

TABLE 1 MAXIMUM POTENTIAL SHORT-TERM EMISSION RATES

POLLUTANT

NATURAL GAS MAXIMUM POTENTIAL EMISSION RATE (LB/HR)

ULSD MAXIMUM POTENTIAL EMISSION RATE (LB/HR)

NOx 25.70 59.60

CO 10.20 18.10

PM10 11.30 48.20

VOC 3.10 10.40

SO2 4.70 7.00

NH3 24.99 28.98

H2SO4 2.97 4.40

GHGs

CO2 477,400 722,700

CH4 7.81 26.06

N2O 0.78 5.21

CO2e 477,827.8 724,904.8 Note: Reflects the maximum short-term emission rate over a range of ambient temperatures; Emissions calculations, methodology, and vendor data are included in Appendices D and E.

REC is proposing the following limits on duration and emission levels during the various SUSD

procedures:

TABLE 2 SUSD LIMITATIONS

NATURAL GAS OPERATIONS

ULSD OPERATIONS

COLD STARTS

Duration (minutes): 60 60

Maximum Potential NOx Emissions (lbs/event): 164.0 294.7

Maximum Potential CO Emissions (lbs/event): 932.0 938.7

Maximum Potential VOC Emissions (lbs/event): 70.7 188.0

Maximum Potential PM Emissions (lbs/event): 11.1 48.0

WARM STARTS






HOT STARTS






SHUTDOWNS







PAGE 13

REC is proposing to operate for up to 8,760 hours per year per power block, and is proposing only three

run-time limits on the various operational scenarios:

1. A limit of 500 hours of total SUSD events (including both natural gas and ULSD)

2. A limit of 760 hours of total ULSD operations (including both steady-state and SUSD events)

3. A limit of 40 hours of ULSD SUSD events

Thus, there is no limit on the natural gas steady-state operations (which is the lowest-emitting

configuration of the four basic operational categories). REC is proposing the aforementioned limits as a

very conservative estimate, which will provide the operational flexibility required to attract the investors

and lenders necessary to enable construction of the plant. The plant is being designed for baseload

dispatch and not as a peaking plant, however in light of the significant changes in the electricity market

over the past several years (combined with the fact that REC is a merchant plant and must be able to

respond to the needs of the market), these potential hours of SUSD emissions provide the operational

flexibility should electricity markets dictate the plant be called upon to start up and shut down more than

is currently anticipated. Current plans call for REC to interconnect the units to separate ISOs (one to PJM

and one to NYISO), each of which may have differing dispatch profiles leading to additional SUSDs than

if both units were dispatched to the same ISO. The total number of hours a facility estimates for SUSD is

a question of operating flexibility, not one of the level of control and should not impact control

technologies for a specific plant.

The worst-case annual potential-to-emit (PTE) scenario from REC’s power blocks results from the

following:

• 7,540 hours of natural gas steady-state operations

• 460 hours of natural gas SUSD events

• 720 hours of ULSD steady-state operations

• 40 hours of ULSD SUSD events

The following table summarizes the proposed REC project’s annual PTE from each of the four

operational scenarios for this worst-case scenario, for both power blocks combined.


PAGE 14

TABLE 3 CTGS ANNUAL POTENTIAL-TO-EMIT

POLLUTANT

STEADY-STATE ULSD FIRING [720 HOURS] (TONS)

ULSD SUSD EVENTS [40 HOURS] (TONS)

STEADY-STATE NATURAL GAS FIRING [7,540 HOURS] (TONS)

NATURAL GAS SUSD [460 HOURS] (TONS)

TOTAL PTE FROM BOTH POWER BLOCKS (TONS)

NOx 42.91 10.75 251.08 50.42 355.17

CO 13.03 16.70 145.52 181.52 356.78

PM10 34.70 2.10 169.65 5.47 211.92

VOC 7.49 2.00 78.42 22.82 110.73

SO2 5.04 0.28 45.99 2.16 53.48

NH3 20.87 1.16 243.84 11.50 277.36

H2SO4 3.17 0.18 30.69 1.37 35.40

GHGs

CO2 520,344 28,908 4,644,640 219,604 5,413,496

CH4 18.76 1.04 58.86 3.59 82.26

N2O 3.75 0.21 5.89 0.36 10.21

CO2equivalent 521,931 28,996 4,647,866 219,801 5,418,594

1.4.2 Auxiliary Boilers, Fuel Gas Heaters, and Dew Point Heater

The maximum potential emissions of NOx, CO, and SO2 from the auxiliary boilers, fuel gas heaters, and

dew point heater were calculated based on the proposed LAER/BACT/BAT emission rates for natural

gas-fired boilers and heaters. The auxiliary boilers have heat input capacities of 66 MMBtu/hr each, the

fuel gas heaters’ heat input capacities are 15 MMBtu/hr each, and the dew point heater’s heat input

capacity is 3.0 MMBtu/hr. Maximum potential annual emissions for the boilers are based on 145,200

MMBtu/year each (equivalent to 2,200 hours each at maximum load), and for the fuel gas heaters are

based on 8,760 hours of operation for only two heaters, as three heaters will never operate

simultaneously. Maximum potential emissions for the dew point heater are based on 8,760 hours per year.

Maximum hourly and annual emissions for the devices are summarized in the following tables.


PAGE 15

TABLE 4 AUXILIARY BOILERS EMISSIONS ESTIMATE

POLLUTANT

EMISSION FACTOR (LB/MMBTU)

MAXIMUM POTENTIAL EMISSION RATE PER BOILER (LB/HR)

MAXIMUM POTENTIAL EMISSIONS PER BOILER (TPY)

TOTAL MAXIMUM POTENTIAL EMISSIONS (TPY)

NOx 0.0060 0.40 0.44 0.87

CO 0.036 2.38 2.61 5.23

PM10 0.0019 0.13 0.14 0.28

VOC 0.0020 0.13 0.15 0.29

SO2 0.00058 0.038 0.042 0.084

H2SO4 9.0E-05 0.0059 0.0065 0.013

NH3 negligible --- --- --- (kg/MMBtu) (tpy) (tpy)

CO2 53.06 8,475 16,949

CH4 1.0E-03 0.16 0.32

N2O 1.0E-04 0.016 0.032

CO2e --- 8,483 16,967

TABLE 5 FUEL GAS HEATERS EMISSIONS ESTIMATE

POLLUTANT

EMISSION FACTOR (LB/MMBTU)


NOx 0.011 1.45

CO 0.037 4.86

PM10 0.0019 0.25

VOC 0.0050 0.66

SO2 0.00058 0.076

NH3 negligible --- (kg/MMBtu) (tpy)

CO2 53.06 15,339

CH4 1.0E-03 0.29

N2O 1.0E-04 0.029

CO2e --- 15,354


PAGE 16

TABLE 6 DEW POINT HEATER EMISSIONS ESTIMATE

POLLUTANT

EMISSION FACTOR (LB/MMSCF)


NOx 100 1.27

CO 84 1.07

PM10 1.9 0.024

VOC 5.5 0.070

SO2 0.6 0.0076

NH3 negligible --- (kg/MMBtu) (tpy)

CO2 53.06 1,513

CH4 1.0E-03 0.029

N2O 1.0E-04 0.0029

CO2e --- 1,515

1.4.3 Emergency Generator and Fire Pump

Maximum potential emissions from REC’s emergency generator and emergency fire water pump are

based on the NSPS Subpart IIII limits for Stationary Compression Ignition Internal Combustion Engines

and/or BACT/LAER/BAT. The emergency generators and fire pump will be fired on ULSD having a

maximum sulfur content of 0.0015% by weight consistent with NSPS Subpart IIII requirements.

Maximum potential annual emissions from REC’s emergency generators are based on 500 hours of

operation and the emergency fire water pump is based on 250 hours of operation. Short-term and annual

maximum potential emissions are summarized in the tables below.

TABLE 7 EMERGENCY GENERATOR EMISSIONS ESTIMATE

POLLUTANT

TIER 2 EMISSION FACTOR (G/BHP-HR)

EMISSION RATE (LB/HR)


NOx 4.48 21.79 5.45

CO 1.23 5.98 1.50

PM10 0.13 0.63 0.16

VOC 0.80 3.89 0.97

SO2 --- 0.022 0.0055


PAGE 17

TABLE 8 DIESEL FIRE PUMP EMISSIONS ESTIMATE

POLLUTANT

TIER 3 EMISSION FACTOR (G/BHP-HR)

EMISSION RATE (LB/HR)


NOx 2.70 1.41 0.18

CO 0.90 0.47 0.059

PM10 0.10 0.052 0.0065

VOC 0.10 0.052 0.0065

SO2 --- 0.0025 0.00032

1.4.4 Facility Wide

Criteria Pollutants

The following table lists a summary of REC’s maximum potential annual emissions from each emission

unit type.

TABLE 9 ANNUAL FACILITY WIDE MAXIMUM POTENTIAL EMISSIONS (TONS/YEAR)

POLLUTANT POWER-BLOCKS

AUXILIARY BOILERS

DIESEL GENERATOR

DIESEL FIRE PUMP HEATER

ULSD STORAGE TANKS

CIRCUIT BREAKERS

FACILITY-WIDE TOTAL

NOx 355.17 0.87 5.45 0.18 2.72 --- --- 364.4

CO 356.78 5.23 1.50 0.059 5.93 --- --- 369.5

PM10 211.92 0.28 0.16 0.0065 0.27 --- --- 212.6

VOC 110.73 0.29 0.97 0.0065 0.73 0.042 --- 112.8

SO2 53.48 0.084 0.0055 0.00032 0.084 --- --- 53.6

NH3 277.36 --- --- --- --- --- --- 277.4

Lead 0.042 --- --- --- --- --- --- 0.042

CO2 5,413,496 16,949 582.92 33.44 16,852 --- --- 5,447,914

CH4 82.26 0.32 0.024 0.0014 0.32 --- --- 82.9

N2O 10.21 0.032 0.0047 0.00027 0.032 --- --- 10.3

SF6 --- --- --- --- --- --- 0.0080 0.0080

CO2e 5,418,594 16,967 584.92 33.55 16,869 --- 182.97 5,453,232

H2SO4 35.40 0.013 --- --- --- --- --- 35.4

HAPs 19.87 0.27 0.014 0.00078 0.27 --- --- 20.4

Hexane1 7.36 0.26 --- --- 0.25 --- --- 7.9 1Hexane is the single HAP with the highest maximum potential emissions.

Hazardous Air Pollutants

Hazardous air pollutant (HAP) maximum potential emissions were calculated to determine whether the

proposed facility has the potential to be a major source of HAPs under Title III of the Clean Air Act


PAGE 18

Amendments of 1990. Based on conservative emission factors, HAP maximum potential annual

emissions are summarized in the tables below for the CTGs; detailed emission calculations are provided

in Appendix D. The formaldehyde emission factors were provided by GE while the balance of HAP

emission factors are from EPA’s AP-42 document, and reflect the appropriate level of control from the

oxidation catalyst (50% control for CTG, 45% control for CTG with DB) for organic HAPs. Federal

major HAP emissions listed below are on an annual (tons/yr) basis.

TABLE 10 CTG HAP MAXIMUM POTENTIAL EMISSIONS

HAZARDOUS AIR POLLUTANT

ANNUAL EMISSIONS FROM ULSD FIRING (TONS)

ANNUAL EMISSIONS FROM ULSD SUSD (TONS)

ANNUAL EMISSIONS FROM NG FIRING (TONS)

ANNUAL EMISSIONS FROM NATURAL GAS SUSD (TONS)

TOTAL MAXIMUM POTENTIAL ANNUAL EMISSIONS FROM BOTH POWER BLOCKS (TONS)

1,3-butadiene 0.032 0.0018 0.0057 0.00035 0.040

acetaldehyde 0 0 0.53 0.033 0.56

acrolein 0 0 0.085 0.0052 0.090

benzene 0.11 0.0061 0.17 0.010 0.29

dichlorobenzene 0 0 0.0049 0 0.0049

ethyl benzene 0 0 0.43 0.026 0.45

formaldehyde 0.37 0.021 4.46 0.21 5.06

hexane 0 0 7.36 0 7.36

naphthalene 0.070 0.0039 0.020 0.0011 0.094

PAH 0.079 0.0044 0.029 0.0018 0.11

POM 0 0 0.00036 0 0.00036

propylene oxide 0 0 0.39 0.024 0.41

toluene 0 0 1.74 0.11 1.85

xylenes 0 0 0.86 0.053 0.92

arsenic 0.031 0.0017 0.0015 0 0.034

beryllium 0.00088 0.000049 0.000089 0 0.0010

cadmium 0.014 0.00076 0.0082 0 0.023

chromium 0.031 0.0017 0.010 0 0.043

cobalt 0 0 0.00062 0 0.00062

lead 0.040 0.0022 0 0 0.042

manganese 2.24 0.12 0.0028 0 2.37

mercury 0.0034 0.00019 0.0019 0 0.0055

nickel 0.013 0.00073 0.016 0 0.029

selenium 0.071 0.0039 0.00018 0 0.075

Total HAPs 19.87

Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.

Based on the tables above, the maximum potential total collective HAP emissions from the proposed

facility would be less than 25 tons per year; hexane is the individual HAP emitted at the highest rate (less

than 8 tons per year). Major source thresholds for HAPs are 10 tons per year for an individual HAP or 25

tons per year total HAPs. Therefore, REC is not a major source of HAP and is not subject to requirements


PAGE 19

under 40 CFR Part 63 Subpart YYYY, the CTG Maximum Achievable Control Technology (MACT)

standard.

POWER ENGINEERS, INC. Plan Approval Application – Air Regulatory Requirements – Renovo Energy Center, LLC

PAGE i

TABLE OF CONTENTS

2.0 AIR REGULATORY REQUIREMENTS .................................................................................... 1

2.1 NATIONAL AND STATE AMBIENT AIR QUALITY STANDARDS ...................................................... 1 2.2 NEW SOURCE REVIEW AND AIR PERMITTING ............................................................................... 2 2.3 PREVENTION OF SIGNIFICANT DETERIORATION (PSD)................................................................. 2 2.4 NON-ATTAINMENT NEW SOURCE REVIEW ................................................................................... 3 2.5 MINOR NEW SOURCE REVIEW ...................................................................................................... 4 2.6 NEW SOURCE PERFORMANCE STANDARDS (NSPS) ..................................................................... 4

2.6.1 40 CFR Part 60 Subpart A – General Provisions .................................................................. 4 2.6.2 40 CFR Part 60 Subpart Dc – Standards of Performance for Small Industrial-Commercial-

Institutional Steam Generating Units .................................................................................................... 5 2.6.3 40 CFR Part 60 Subpart IIII – Standards of performance for Stationary Compression

Ignition Combustion Engines ................................................................................................................ 5 2.6.4 40 CR Part 60 Subpart KKKK – Standards of Performance for Stationary Combustion

Turbines 5 2.6.5 40 CFR Part 60 Subpart TTTT – Standards of Performance for Greenhouse Gas Emissions

from New Stationary Sources: Electric Utility Generating Units ........................................................ 6 2.7 40 CFR PART 63 – NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS

(NESHAP) ................................................................................................................................................ 6 2.7.1 40 CFR Part 63 Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines .. 7

2.8 40 CFR PART 64 – COMPLIANCE ASSURANCE MONITORING ....................................................... 7 2.9 40 CFR PART 70 - OPERATING PERMIT ......................................................................................... 7 2.10 40 CFR PART 72 – PART 75 - ACID RAIN PROGRAM..................................................................... 8 2.11 40 CFR PART 96 NOX BUDGET TRADING PROGRAM AND CAIR NOX AND SO2 TRADING

PROGRAMS FOR STATE IMPLEMENTATION PLANS .................................................................................... 8 2.12 40 CFR PART 97 – CROSS-STATE AIR POLLUTION RULE (CSAPR) ............................................. 8 2.13 40 CFR PART 98 – MANDATORY GREENHOUSE GAS REPORTING ................................................ 9 2.14 PADEP APPLICABLE REQUIREMENTS ........................................................................................... 9 2.15 REQUIREMENTS EVALUATED THAT DO NOT APPLY .................................................................. 12

TABLES:

TABLE 1 NATIONAL AND PENNSYLVANIA AMBIENT AIR QUALITY STANDARDS... 1 TABLE 2 CLINTON COUNTY NAAQS AND PA AAQS ATTAINMENT STATUS ............... 2 TABLE 3 POTENTIAL EMISSIONS COMPARED TO MAJOR SOURCE THRESHOLDS .... 4


PAGE 1


2.1 National and State Ambient Air Quality Standards

EPA has established primary and secondary National Ambient Air Quality Standards (NAAQS) for six

air pollutants (ozone, Carbon Monoxide (CO), Nitrogen Dioxide (NO2), Sulfur Dioxide (SO2), Particulate

Matter (including PM10 and PM2.5), and lead). Primary NAAQS are intended to protect public health

while secondary standards set limits to protect public welfare. The NAAQS promulgated by EPA have

been incorporated, by reference, as part of the Pennsylvania Department of Environmental Protection’s

(PaDEP) standards contained in Pa. Code Chapter 131. PaDEP ambient air quality standards include

standards for settled particulate (total), beryllium, fluorides, and hydrogen sulfide. Federal and State

Ambient Air Quality Standards (AAQS) are summarized in Table 2.1-1 below.

TABLE 1 NATIONAL AND PENNSYLVANIA AMBIENT AIR QUALITY STANDARDS

POLLUTANT STANDARD TYPE

AVERAGING PERIOD STANDARD NOTE

Carbon Monoxide (CO)

primary 1-hour 35 ppm (40,000 µg/m3)

Not to be exceeded more than once per year

primary 8-hour 9 ppm (10,000 µg/m3)

Not to be exceeded more than once per year

Lead (Pb) primary and secondary

Rolling 3-month average

0.15 µg/m3 Not to be exceeded

Nitrogen Dioxide (NO2)

primary 1-hour 100 ppb 98th percentile of 1-hour daily maximum concentrations, averaged over 3 years

primary and secondary

annual 53 ppb Annual mean

Ozone primary and secondary

8-hour 0.07 ppm Annual fourth-highest daily maximum 8-hr concentration, averaged over 3 years

Particulate matter (PM2.5)

primary and secondary

24-hour 35 µg/m3 Not to be exceeded more than once per year on average over 3 years

primary Annual 12 µg/m3 Annual mean, averaged over 3 years

secondary Annual 15 µg/m3 Annual mean, averaged over 3 years

Particulate matter (PM10) primary and secondary

24-hour 150 µg/m3 Not to be exceeded more than once per year on average over 3 years.

Sulfur dioxide (SO2)

primary 1-hour 75 ppb 99th percentile of 1-hour daily maximum concentrations, averaged over 3 years

secondary 3-hour 0.5 ppm Not to be exceeded more than once per year

Settled particulate primary 30-days 1.5 mg/cm2/mo PaDEP AAQS (131.3)

primary annual 0.8 mg/cm2/mo PaDEP AAQS (131.3)

Beryllium primary 30-days 0.01 µg/m3 PaDEP AAQS (131.3)

Fluorides primary 24-hour 5 µg/m3 PaDEP AAQS (131.3)

Hydrogen sulfide primary 1-hour 0.1 ppm PaDEP AAQS (131.3)

primary 24-hour 0.005 ppm PaDEP AAQS (131.3)


PAGE 2

Geographic areas where the concentration of a given pollutant is at or below the NAAQS are classified as

“attainment” areas for that pollutant. If an area exceeds the NAAQS for a given pollutant then the area is

considered a “nonattainment area”. Areas where there is insufficient monitoring data to determine if the

NAAQS is being met are designated as unclassifiable. For permitting determinations, the unclassifiable

areas are considered attainment areas. The site of the proposed Renovo Energy Center is located in the

town of Renovo in Clinton County. The current federal air quality classifications for the project area in

Clinton County are listed in Table 2.1-2 for each criteria pollutant. These designations were obtained

from 40 CFR Part 81. The project area is designated as attainment or unclassifiable for all criteria

pollutants. PaDEP does not monitor for settled particulate, beryllium, fluorides or hydrogen sulfide.

However, per discussions with PaDEP there are no concerns with attainment of the AAQS for these

pollutants in Clinton County.

The entire Commonwealth of Pennsylvania is located in the Ozone Transport Region (OTR). The

relevance of attainment status and OTR is discussed in the proceeding sections.

TABLE 2 CLINTON COUNTY NAAQS AND PA AAQS ATTAINMENT STATUS

POLLUTANT ATTAINMENT STATUS

Sulfur Dioxide (SO2) Attainment

Carbon Monoxide (CO) Unclassifiable/Attainment

Particulate Matter (PM10) Unclassifiable

Particulate Matter (PM2.5) Unclassifiable/Attainment

Nitrogen Dioxide (NO2) Unclassifiable/Attainment

Ozone (8-hour) Unclassifiable/Attainment

Lead Unclassifiable/Attainment

Settled particulate Attainment (unofficial)

Beryllium Attainment (unofficial)

Fluorides Attainment (unofficial)

Hydrogen sulfide Attainment (unofficial)

2.2 New Source Review and Air Permitting

New air contaminant sources are required to obtain a plan approval prior to construction in accordance

with Pa. Code Chapter 127 of the PaDEP’s Air Resources regulations. The PaDEP’s and EPA’s process

for reviewing new sources of air pollution is the New Source Review (NSR) permitting program.

PaDEP’s NSR requirements are codified in 25 Pa. Code Chapter 127. NSR is applied by pollutant and

depends on whether the area where a proposed facility is located is in attainment of the NAAQS for that

pollutant. A facility classified as a major source is subject to Prevention of Significant Deterioration

(PSD) review if the area is in attainment of the NAAQS for a particular pollutant. A facility classified as

a major source is subject to Non-attainment Area (NAA) NSR if the location is not attaining the NAAQS

for a certain pollutant or, for ozone, is located in the OTR. Since the State of Pennsylvania is within the

OTR, NAA provisions are in effect statewide for major sources of NOx and VOC. A facility is subject to

minor new source review if emissions of a pollutant do not exceed the PSD and Non-attainment NSR

thresholds. Each program is described in the following sections.

2.3 Prevention of Significant Deterioration (PSD)

The PSD requirements are contained in 40 CFR Part 52 and adopted in their entirety by the PaDEP in 25

Pa. Code Chapter 127 Subchapter D. PSD applies to new major stationary sources of air pollutants, which


PAGE 3

are defined as any one of 28 specific source categories, including fossil fuel-fired steam electric plants

with a heat input capacity greater than 250 MMBtu/hr that have the potential to emit 100 tons per year or

more of any regulated NSR pollutant. Renovo Energy Center (REC) is proposing a fossil-fuel fired steam

electric plant of more than 250 MMBtu/hr heat input and is therefore subject to PSD if it has the potential

to emit 100 tons per year of any one pollutant. Once it is determined that a facility is a major source, the

potential to emit of each pollutant must be compared to the corresponding significant net emissions

increase to determine which pollutants are subject to PSD review. PSD significant net emissions increases

are defined in 40 CFR Part 52 and identified in Table 2.4-1.

PSD review for major stationary sources consists of demonstrating that Best Available Control

Technology (BACT) has been applied to each emission source and demonstrating that the proposed

emissions will not cause or contribute to a violation of the NAAQS or PSD increment. PSD increment is

the maximum allowable increase in concentration that is allowed to occur above a baseline concentration

for a pollutant. PSD increments prevent the air quality in “clean areas” from deteriorating to the level set

by the NAAQS. A demonstration of BACT for Renovo’s PSD pollutants is contained in Section 3 of this

application packet and the air quality impact analyses performed to demonstrate compliance with PSD

increment requirements and NAAQS is presented in Section 4. REC’s PSD pollutants are SO2, PM, CO,

and H2SO4 as outlined in Table 2.4-1. As required by the tailoring rule, the June 23, 2014 U.S. Supreme

Court Decision, and resultant EPA guidance, a BACT analysis is required for stationary sources that are

new major source for a regulated NSR pollutant that is not GHGs and will have the potential to emit

75,000 tpy CO2e. Therefore, a BACT analysis is also required for GHG emissions.

2.4 Non-Attainment New Source Review

A new source is subject to the non-attainment area preconstruction review process if it has the potential to

emit any criteria pollutant in major amounts for which the area has been designated nonattainment. Since

the entire Commonwealth of Pennsylvania is in the ozone transport region it is designated nonattainment

for ozone. NOx and VOC are precursors to ozone formation and the nonattainment major source

thresholds for these pollutants are 100 tpy and 50 tpy, respectively. The nonattainment review

requirements differ from the PSD requirements such that the emission control requirement for

nonattainment areas, Lowest Achievable Emission Rate (LAER), is defined differently than the BACT

emissions control requirements. LAER is defined as the most stringent emission limitation contained in

the implementation plan of any state or the most stringent emission limitation achieved in practice.

Section 3 of this application contains the LAER determinations for NOx and VOC for REC’s emission

sources.

In addition, before construction or operation of a source in a nonattainment area can be commenced the

source must obtain Emission Reduction Credits (ERC) or offsets of the nonattainment pollutant from

other emission sources which impact the same area as the proposed source. Per 25 Pa. Code Chapter

127.210, with the exception of fugitive VOC emissions, the emission offset ratio for both NOx and VOC

in the ozone transport region is 1.15:1. The emission offset ratio for fugitive VOC emissions is 1.3:1.

Therefore REC is required to obtain ERCs for VOC and NOx at a rate of 1.15 times the proposed

emissions for these pollutants emitted from the stacks. Based on emission calculations provided in

Appendix D, there will not be any fugitive VOC emissions.

Thirdly, sources impacting visibility in mandatory class I Federal areas must be reviewed by the

appropriate Federal Land Manager (FLM). In addition, 25 Pa. Code § 127.205(5) requires an analysis to

be conducted of alternative sites, sizes, production processes and environmental control techniques for the

proposed facility, which demonstrates that the benefits of the proposed facility significantly outweigh the

environmental and social costs imposed as a result of it location and construction.


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A LAER analysis in accordance with the non-attainment NSR requirements is contained in Section 3 of

this application and the alternative sites analysis is contained in Section 6.

TABLE 3 POTENTIAL EMISSIONS COMPARED TO MAJOR SOURCE THRESHOLDS

POLLUTANT

FACILITY POTENTIAL EMISSIONS (TONS/YR)

MAJOR SOURCE THRESHOLDS (TONS/YR)

PSD SIGNIFICANT NET EMISSIONS INCREASE (TONS/YR)

SUBJECT TO PSD REVIEW?

OZONE NONATTAINMENT MAJOR SOURCE THRESHOLD (TONS/YR)

SUBJECT TO NONATTAINMENT NEW SOURCE REVIEW

SO2 53.6 100 40 Yes NA NA

PM10 212.6 100 15 Yes NA NA

PM2.5 212.6 100 10 Yes NA NA

NOx 364.4 100 40 NA 100 Yes

CO 369.5 100 100 Yes NA NA

VOC 112.8 100 40 NA 50 Yes

H2SO4 35.4 100 7 Yes NA NA

Lead 0.042 100 0.6 No NA NA

CO2e 5,447,914 75,000 75,000 Yes NA NA

2.5 Minor New Source Review

All pollutants, whether or not subject to PSD or non-attainment NSR, must comply with the minor source

permitting requirements of Chapter 127. A facility is required to apply Best Available Technology (BAT)

which is similar to BACT required under the PSD program. Further details of the requirements of Chapter

127 are outlined below under Section 2.14 – PaDEP Applicable Requirements.

2.6 New Source Performance Standards (NSPS)

New Source Performance Standards (NSPS) are established by EPA for source categories that cause or

contribute significantly to air pollution. These standards apply to sources that have been constructed or

modified since the proposal of the standard. NSPS are codified in 40 CFR Part 60. There are several

NSPS standards that potentially apply to the REC facility which are outlined in the following subsections.

2.6.1 40 CFR Part 60 Subpart A – General Provisions

General Provisions contained in Subpart A apply to any source that is subject to another subpart. REC is

subject to Subpart Dc, Subpart KKKK, Subpart IIII, and Subpart TTTT, thus specific provisions in

Subpart A will apply. The following Subpart A provisions will apply:

• 60.7 – Initial notification and recordkeeping: The following notifications are required to be

submitted to EPA and PaDEP: a notification of the date of construction commencement and date

of initial startup; a notification of the date the CEMS performance demonstration has

commenced. The following records are required: occurrence and duration of any startup,

shutdown, or malfunction; periods during which a CEMS is inoperative; records of all

measurements including CEMS, performance testing, CEMS calibration checks, CEMS

performance evaluations, and adjustments and maintenance performed on the monitoring system.


PAGE 5

The following reports are required: semi-annual excess emissions and monitoring system

performance reports.

• 60.8 – Performance Tests: REC will comply with the requirements contained in 60.8 and use the

applicable reference test methods for any performance testing that will apply.

• 60.11 – Compliance with Standards and Maintenance Requirements: Compliance with standards

in Part 60 will be demonstrated with performance testing in accordance with 60.8.

• 60.13 – Monitoring Requirements: CEMS required under applicable subparts will be subject to

the performance specifications under Appendix B and Appendix F of Part 60.

• 60.19 – General Notification and Reporting Requirements: REC will comply with the general

report and notification formats and schedules contained in this section.

2.6.2 40 CFR Part 60 Subpart Dc – Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units

Subpart Dc establishes emission limits for steam generating units constructed, modified or reconstructed

after June 9, 1989 with a heat input capacity of 10 - 100 MMBtu/hr. REC is proposing to install two

natural gas fired auxiliary boilers, each with a heat input capacity of 66 MMBtu/hr. The boilers will be

fired with natural gas only. Since the boilers will combust natural gas exclusively, compliance with

Subpart Dc only requires maintaining monthly fuel consumption records and submitting an annual report

to EPA summarizing those records.

2.6.3 40 CFR Part 60 Subpart IIII – Standards of performance for Stationary Compression Ignition Combustion Engines

40 CFR Part 60, Subpart IIII, Standards of performance for Stationary Compression Ignition Internal

Combustion Engines will apply to REC’s emergency generator engine and emergency fire pump engine.

The regulation requires that manufacturers of internal combustion engines certify the engines to specific

emission standards based on model year, engine size and type. Owners and operators of subject engines

are required to operate and maintain the engine in accordance with the manufacturer’s emission related

written instructions.

The diesel fuel fired in REC’s emergency equipment will meet the requirements of 40 CFR 80.510(a)

which limits the sulfur content to 15 ppm. The emergency generator and diesel fire pump will be certified

to meet the applicable emission standards set forth in Subpart IIII. Both of REC’s engines will be

installed with non-resettable hour meters. REC proposes to limit the operation of the emergency

generator to 500 hours per year and 250 hours per year for the fire pump engine. Maintenance checks and

readiness testing will be limited to 100 hours per year per engine.

2.6.4 40 CR Part 60 Subpart KKKK – Standards of Performance for Stationary Combustion Turbines

Subpart KKKK establishes emission limits for combustion turbines (CT) which commence construction

after February 18, 2005 and have a heat input at peak load of 10 MMBtu/hr or greater based on the higher

heating value of the fuel. Only heat input to the combustion turbine is included when determining

whether or not this subpart applies to the proposed turbines. Any additional heat input associated heat


PAGE 6

recovery steam generators (HRSG) or duct burners is not included when determining the turbine’s peak

heat input. However, Subpart KKKK does apply to emissions from the associated HRSGs and duct

burners. Stationary combustion turbines regulated under Subpart KKKK are exempt from the

requirements of Subpart GG. Heat recovery steam generators and duct burners regulated by Subpart

KKKK are exempt from the requirements of Subparts Da, Db, and Dc.

Under Subpart KKKK, each CT/HRSG train is subject to a NOx emission limit of 15 ppmvd at 15 percent

O2 while firing natural gas and 42 ppmvd at 15 percent O2 while firing ULSD. Compliance is required to

be demonstrated either by annual stack testing or continuous emission monitoring (CEMS). An initial

performance test is required by either conducting a stack test or, if a CEMS is installed, performing a

minimum of nine relative accuracy test audit (RATA) reference method runs. Since REC will be

installing a CEM, the initial performance test will consist of the RATA testing.

REC’s CT/HRSG trains will be subject to a SO2 emission limit of 0.90 pounds per megawatt-hour gross

energy output or 0.060 lb SO2/MMBtu heat input fuel. A facility is exempt from monitoring for SO2 if

sulfur fuel characteristics in a purchase contract, tariff sheet or transportation contract for the fuel specify

that the maximum total sulfur content for natural gas is 20 grains of sulfur or less per 100 standard cubic

feet and for oil is 0.05% or less. As an alternative, REC can provide representative fuel sampling data

which demonstrates that the sulfur content of the fuel does not exceed 0.06 lb/MMBtu. At a minimum,

the amount of fuel sampling data specified in Section 2.3.1.4 or 2.3.2.4 of Appendix D to Part 75 is

required.

Reporting requirements under Subpart KKKK include semi-annual excess emissions and CEMS

downtime reports.

2.6.5 40 CFR Part 60 Subpart TTTT – Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units

REC’s proposed facility is subject to 40 CFR Part 60 Subpart TTTT which was finalized on October 23,

2015. The regulation applies to steam generating units with a base load rating greater than 250 MMBtu/hr

of fossil fuel that serve a generator or generators capable of selling greater than 25 MW of electricity to a

utility power distribution system. Under Subpart TTTT, each CT/HRSG train will be subject to an

emission limit of 1,000 lb CO2 per megawatt-hour of gross energy output or 1,030 lb CO2 per megawatt-

hour of net energy output. REC will be required to follow procedures in Subpart TTTT for calculating

hourly CO2 mass emissions and obtaining generating load data for the output-based standards.

Reporting requirements under Subpart TTTT include quarterly emission reports.

2.7 40 CFR Part 63 – National Emission Standards for Hazardous Air Pollutants (NESHAP)

Appendix D contains a summary of REC’s estimated potential annual emissions of hazardous air

pollutants (HAPs) from the facility. The summary indicates that HAP emissions from the facility will be

less than 10 tons per year for any individual HAP and less than 25 tons per year for combined HAPs.

Therefore, REC’s proposed facility is not classified as a major HAP source (i.e. REC will be non-major or

area source), and the fuel burning and process equipment at the facility will not be subject to any major

source NESHAP promulgated by EPA. However, REC will be subject to the NESHAP for Stationary

Reciprocating Internal Combustion Engines (Subpart ZZZZ) which applies to both major and non-major

sources of HAPs.


PAGE 7

2.7.1 40 CFR Part 63 Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines

40 CFR Part 63 Subpart ZZZZ establishes national emission and operating limitations for HAP emissions

from stationary reciprocating internal combustion engines located at major and area sources of HAP

emissions. In accordance with Subpart ZZZZ, new and reconstructed emergency engines at area sources

must comply with 40 CFR Part 60 Subpart IIII. Therefore, as described above, REC’s diesel engine

powered emergency generator and emergency fire pump engine are subject to the requirements of 40 CFR

Part 60 Subpart IIII.

2.8 40 CFR Part 64 – Compliance Assurance Monitoring

The Compliance Assurance Monitoring (CAM) regulation applies to facilities that are required to obtain a

Part 70 Operating Permit (major sources). The CAM requirements are unit and pollutant specific and

apply if the following criteria are met:

1. The unit is subject to an emission limitation or standard (other than an emission limit or standard

that is exempt under paragraph (b)(1) of Part 64);

2. The unit uses a control device to achieve compliance with that standard; and

3. The unit has potential pre-control device emissions exceeding the major source threshold under

the Title V permitting program.

CAM does not apply to the NOx emissions from the powerblocks (CT and HRSG with duct burners) per

40 CFR 64.2(b)(1)(i) because the NOx emissions are subject to emission limitations and standards

pursuant to Section 111 of the Clean Air Act (NSPS Subpart KKKK) and per 64.2(b)(1)(vi) since NOx

will be monitored by a CEMS. CAM does not apply to CO per 64.2(b)(1)(vi), since CO will be

monitored by a CEMS. The powerblocks will have pre-control VOC emissions that exceed the Title V

major source threshold (50 tpy), VOC emissions will be controlled by a control device (oxidation

catalyst), and will be subject to an emission limitation established by the Non-attainment NSR

requirements. REC will be required to submit a CAM plan for VOC emissions from the powerblocks.

REC’s CAM plan will include the use of a CO CEMS data as an indicator of the oxidation catalyst

performance since CO emissions are also being controlled by the catalyst. The CAM plan will be

submitted as part of REC’s initial Title V Operating Permit application.

The CAM rule will not apply to the auxiliary boilers or diesel fired emergency equipment because all

three criteria outlined above and specified in 40 CFR Part 64.2(a)(1-3) will not be met.

2.9 40 CFR Part 70 - Operating Permit

The PaDEP has adopted EPA’s Part 70 – Operating Permit Program (Title V) which is codified as 25 Pa.

Code Chapter 127, Subchapter G. A Title V permit is required for major sources. For Title V

applicability, a major source is defined as source that has the potential to emit 10 tons per year of any

hazardous air pollutant (HAP), 25 tons per year of a combination of HAPs, 50 tpy of VOC and 100 tpy

for any other regulated air pollutant. Based on potential emissions as presented in Section 2 and Appendix

D, REC is a major source and subject to Title V permitting. A Title permit application will be submitted

within 120 days after the PaDEP provides notice that the application is due.


PAGE 8

2.10 40 CFR Part 72 – Part 75 - Acid Rain Program

Per 40 CFR Section 72.6(a)(3)(i), REC will be subject to the Acid Rain Program since it will be a new

utility unit with a total nameplate capacity of greater than 25 MW as defined by the regulation. A new

unit is defined as a fossil fuel fired combustion device that commences commercial operation on or after

November 15, 1990 and a utility unit is defined as a unit that produces electricity for sale. 72.9(a)

requires the facility to submit a complete Acid Rain permit application at least 24 months prior to

commencing operation. The purpose of Part 75 is to establish requirements for the monitoring,

recordkeeping, and reporting of SO2, NOx, and CO2 emissions, volumetric flow and opacity data from

affected units. For measuring and recording SO2 emissions, REC will follow either 75.11(d)(2):

procedures specified in Appendix D – Optional SO2 Emissions Data Protocol for Gas-fired and Oil-fired

units for determining hourly SO2 emissions and heat input in lieu of continuous SO2 concentration and

flow monitors; or 75.11(e): special considerations during the combustion of gaseous fuels – if the facility

uses a certified flow monitor and a certified diluent gas monitor to measure the heat input rate, during any

hours in which the unit combusts only gaseous fuel, the facility shall determine SO2 emissions in by using

Equation F-23 of Appendix F. The regulation also requires that the facility install a CEMS for NOx and

diluent gas. An opacity monitor is not required as REC will meet the definition of gas-fired unit (a gas-

fired unit combusts natural gas or other gaseous fuel for at least 90 percent of the unit’s average annual

heat input during the previous three calendar years and for at least 85 percent of the annual heat input in

each of those calendar years). In addition, REC will be required to hold SO2 allowances equal to the

actual annual SO2 emissions for the previous calendar year.

2.11 40 CFR Part 96 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs for State Implementation Plans

40 CFR Part 96 is an outline of the requirements for State Implementation Plans and has been superseded

with the requirements contained in Part 97 as described below.

2.12 40 CFR Part 97 – Cross-State Air Pollution Rule (CSAPR)

The Cross-State Air Pollution Rule (CSAPR) requires twenty-three states to reduce annual SO2 and NOx

emissions to help downwind areas attain the 24-hour and/or annual PM2.5 NAAQS. Twenty-five states

are required to reduce ozone season NOx emission to help downwind areas attain the 8-hour ozone

NAAQS. Pennsylvania is one of the states that must reduce annual SO2 and NOx emissions and ozone

season NOx emissions. Pennsylvania is a Group 1 state required to reduce SO2 emissions in Phase I and

make additional reductions in SO2 emissions in Phase II. Phase I implementation is scheduled for 2015

and Phase II is scheduled for 2017. Given that the application is being filed in 2019, REC will be subject

to Phase II.

CSAPR replaces the Clean Air Interstate Rule (CAIR). CSAPR regulations are contained in 40 CFR Part

97. REC’s proposed units will be subject to Subpart AAAAA – Transport Region (TR) NOx Annual

Trading Program, Subpart BBBBB – TR NOx Ozone Season Trading Program, and Subpart CCCCC –

TR SO2 Group 1 Trading Program. REC will be required to submit a NOx Budget permit application at

least 18 months before the date of commencement of operation. The proposed units are also NOx units,

SO2 units, and NOx Ozone Season units per 40 CFR Section 97.104(a)(1), Section 97.204(a)(1), and

97.304(a)(1), respectively, and thus the facility will be required to submit a complete permit application at

least 18 months prior to commencing construction.


PAGE 9

REC is subject to the standard requirements contained in Sections 97.406 (TR NOx Annual Trading

Program requirements), 97.506 (TR NOx Ozone Season Trading Program Requirements), and 97.606

(TR SO2 Group 1 Trading Program requirements). Each program requires that the facility assign a

designated representative. Each TR NOx Annual source/unit is required to comply with the monitoring,

reporting, and recordkeeping requirements of 40 CFR 97.430 through 97.435. Emissions data determined

in accordance with 40 CFR 97.430 through 97.435 shall be used to calculate allocations of TR NOx

Annual allowances to determine compliance with the TR NOx Annual emissions limitation and assurance

provisions. As of the allowance transfer deadline for a control period in a given year, the owner or

operator of each TR NOx Annual source/unit shall hold, in the source’s compliance account, TR NOx

Annual allowances available for deduction for the control period. Each TR NOx Ozone Season

source/unit is required to comply with the monitoring, reporting, and recordkeeping requirements of 40

CFR 97.530 through 97.535. Emissions data determined in accordance with 40 CFR 97.530 through

97.535 shall be used to calculate allocations of TR NOx Ozone Season allowances to determine

compliance with the TR NOx Ozone Season emissions limitation and assurance provisions. As of the

allowance transfer deadline for a control period in a given year, the owner or operator of each TR NOx

Ozone Season source/unit shall hold, in the source’s compliance account, TR NOx Ozone Season

allowances available for deduction for the control period. Each TR SO2 Group 1 source/unit is required

to comply with the monitoring, reporting, and recordkeeping requirements of 40 CFR 97.630 through

97.635. Emissions data determined in accordance with 40 CFR 97.630 through 97.635 shall be used to

calculate allocations of TR SO2 Group 1 allowances to determine compliance with the TR SO2 Group 1

emissions limitation and assurance provisions. As of the allowance transfer deadline for a control period

in a given year, the owner or operator of each TR SO2 Group 1 source/unit shall hold, in the source’s

compliance account, TR SO2 Group 1 allowances available for deduction for the control period.

2.13 40 CFR Part 98 – Mandatory Greenhouse Gas Reporting

In accordance with 98.2(a)(1), EPA’s Mandatory Greenhouse Gas Reporting regulation will apply as

REC is classified as a source category listed in Table A-3 of the regulation (Electricity generation units

that report CO2 mass emissions year round through 40 CFR Part 75). Subpart D of 40 CFR Part 98

outlines the requirements for electricity generation units. Subpart C outlines the requirements for fuel

combustion units that apply to the boilers and emergency engines. REC will be required to report annual

emissions of greenhouse gases by March 1 each year for the previous year.

2.14 PaDEP Applicable Requirements

25 Pa. Code Chapter 121 General Provisions

Chapter 121 contains definitions and general administrative requirements provided for the control and

prevention of air pollution.

25 Pa. Code Chapter 122 National Standards of Performance for New Stationary Sources

Chapter 122 adopts Standards of Performance for New Stationary Sources (NSPS) promulgated by EPA

which allows the standards to be enforceable by the PaDEP and delegates authority to the PaDEP. The

NSPS standards that REC is subject to were previously outlined in this section.

25 Pa Code Chapter 123 Standards for Contaminants

REC is subject to the following general emission standards and requirements as set forth in Chapter 123:


PAGE 10

• Section 123.1 does not permit fugitive emissions in the outdoor air from sources other than the

following:

o Construction or demolition of buildings or structures.

o Grading, paving and maintenance of roads and streets.

o Use of roads and streets

o Clearing of land

o Stockpiling of materials

o Open burning operations.

o Blasting in open pit mines.

o Sources and classes of sources other than those listed above, for which the facility has

obtained a determination from the PaDEP that fugitive emissions meet the following

requirements: emissions are of minor significance with respect to causing air pollution,

and emissions are not preventing or interfering with attainment or maintenance of any

ambient air quality standard.

• Section 123.11 limits particulate matter emissions from combustion sources based on heat input.

The turbines are subject to a limit of 0.1 lb/MMBtu and the auxiliary boilers, emergency

generator, and fire pump engine are subject to a limit of 0.4 lb/MMBtu.

• Section 123.21 and 123.22 establish standards for the control of sulfur dioxide emissions sulfur

content of fuels. Clinton County is in a “non-air basin area” and is therefore subject to the SO2

and sulfur limits contained in 123.22(a). SO2 emissions are limited to 4 lb/MMBtu of heat input

over a 1-hour period. The sulfur content of #2 oil and lighter is limited to 0.05%.

• Section 123.41 limits visible emissions to less than 20% opacity, except for periods of no more

than 3 minutes in any one hour and no more than 60% opacity at any time.

• Section 123.51 requires combustion units with heat inputs greater than 250 MMBtu/hr to install,

operate, and maintain a continuous nitrogen oxides emissions monitoring system

25 Pa. Code Chapter 124 National Emission Standards for Hazardous Air Pollutants (NESHAPs)

Chapter 124 adopts National Emission Standards for Hazardous Air Pollutants (NESHAP) promulgated

by EPA allowing the standards to be enforceable by the PaDEP and delegates authority to the PaDEP.

REC is subject to a NESHAP requirement as previously outlined in this section.

25 Pa. Code Chapter 127 Construction, Modification, Reactivation and Operation of Sources

PaDEP’s Chapter 127 outlines new source permitting and operating permit requirements. Subchapter B

specifies plan approval requirements (new source permitting) which includes the application content

requirements, notification and other administrative tasks and requires a facility to obtain a plan approval

prior to construction. Sections 127.1 and 127.12(a)(5) require new sources to control emissions of air

contaminants to best available technology (BAT) level which applies to major and minor sources and is


PAGE 11

similar to BACT under the PSD program. BAT is defined as equipment, devices, methods or techniques

which will prevent, reduce or control emissions to the maximum degree possible and which are available

or may be made available.

EPA’s PSD requirements are adopted by the PaDEP through Subchapter D of Chapter 127. REC is

subject to Subpart E for nonattainment NSR. As discussed in Section 2.4 (nonattainment NSR), REC is

major for NOx and CO (NSR pollutants) and is thus subject to Subchapter E. Subchapter E requires REC

to apply LAER and obtain ERC credits at the rate of 1.15 to 1 for NOx and VOC emissions and 1.3:1 for

fugitive VOC emissions. Documentation of REC’s intent to secure NOx and VOC offsets is contained in

Appendix Q. In accordance with 127.205(5), REC is required to submit an analysis of alternative sites,

sizes, production processes and environmental control techniques. This analysis is addressed in Section

6.

Chapter 127, Subchapter G contains Title V Operating Permit Program requirements. As discussed in

Section 2.9, REC is required to obtain a Title V Operating Permit. REC will submit an application for the

operating permit within 120 days after the PaDEP provides notice that the application is due. The Title V

operating permit will not impose additional requirements other than periodic reporting and certification.

Subchapter I outlines the plan approval and operating permit fees that apply to REC as follows:

• Sources requiring approval under Subchapter B: $5,300

• Sources requiring approval under NSPS and/or NESHAP: $1,700

• Sources requiring approval under PSD: $22,700

REC is subject to a total plan approval and operating permit fee of $29,700.

25 Pa. Code Chapter 129 Standards For Sources

Since REC is a major NOx emitting facility and major VOC emitting facility as defined in Chapter 201,

Section 129.91 – Control of major sources of NOx and VOC will apply. REC is required to submit a

RACT proposal prior to installation. However, under nonattainment new source review, REC is subject to

the lowest achievable emission rate for NOx and VOC which is more stringent than RACT and

supersedes RACT.

NOx requirements outlined in Section 129.201 through 129.203 do not apply since REC is not located in

one of the listed counties.

25 Pa. Code Chapter 131 Ambient Air Quality Standards

The NAAQS promulgated by EPA are incorporated by reference as part of the standards in Chapter 131.

Section 131.3 sets forth additional ambient air quality standards established by PA for settled particulate,

beryllium, fluorides, and hydrogen sulfide. The NAAQS and PA AAQS are summarized in Table 2-1.

REC will prepare an air dispersion modeling analysis to demonstrate compliance with all ambient air

quality standards.

25 Pa. Code Chapter 135 Reporting of Sources

Chapter 135 requires air emission sources to report actual emissions by March 1 for the previous year.


PAGE 12

25 Pa. Code Chapter 137 Air Pollution Episodes

Chapter 137 outlines the requirements for air pollution episodes. If the PaDEP classifies Clinton County

as an area requiring a standby plan, REC will submit a standby plan within 90 days of the PaDEP’s

request.

25 Pa. Code Chapter 139 Sampling and Testing

Chapter 139 provides general requirements and procedures for sampling and testing, reference test

methods, and requirements for source monitoring.

25 Pa. Code Chapter 145 Interstate Pollution Transport Reduction

Since EPA’s CSAPR has been finalized, per 5/12/2015 discussion with PaDEP, the requirements of 40

CFR Part 97 (CSAPR) take precedence over the requirements contained in Chapter 145.

2.15 Requirements Evaluated That Do Not Apply

25 Pa. Code Section 129.56 and 129.57 Storage Tanks Containing VOC

Section 129.56 applies to storage tanks with capacities greater than 40,000 gallons containing volatile

organic compounds (VOCs) with a vapor pressure of greater than 1.5 psia. Section 129.57 applies to

storage tanks greater than 2,000 gallons containing VOC with a vapor pressure of greater than 1.5 psia.

REC is proposing tanks greater than the 2,000/40,000 gallon threshold for the storage of diesel fuel and

lubricating oil. Diesel fuel and lubricating oil have vapor pressures less than 1.5 psia, thus Sections

129.56 and 129.57 do not apply.

40 CFR Part 60 Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage

Vessels

The storage tanks proposes for this facility (one 3.8 million gallon USLD for the turbines, one 2,500-

gallon ULSD tank associated with the generator, one 350-gallon ULSD tank associated with the fire

pump engine, two 20,000-gallon lube oil tanks, and two 26,000 gallon ammonia tanks) are not subject to

the requirements of Subpart Kb since ammonia is not an organic liquid and the vapor pressure of diesel

oil and lubricating oil is less than the 3.5 kPa and 15 kPa as specified by the regulation.

40 CFR Part 63 Subpart UUUUU – National Emission Standards for Hazardous Air Pollutants:

Coal- and Oil-Fired Electric Utility Steam Generating Units

40 CFR Part 63 Subpart UUUUU is also known as the Mercury and Air Toxics Standard (MATS) applies

to coal-fired and oil-fired electric utility steam generating units. REC’s combustion turbines are not

subject to this rule because the turbines do not meet the definition of electric utility steam generating unit

as defined in CAA section 112(a)(8) and Subpart UUUUU (primarily because the turbines do not

generate steam). Steam generating unit is defined as in Subpart UUUUU as follows:

“Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the

purpose of producing steam (including fossil-fuel-fired steam generators associated with integrated

gasification combined cycle gas turbines; nuclear steam generators are not included).”

The HRSG units generate steam from the heat from the combustion turbines and are provided with

additional heat from natural gas fired duct burners. The HRSG units are not subject to Subpart UUUUU


PAGE 13

because they will not combust coal or oil. The auxiliary boilers are not subject to Subpart UUUUU

because they will not combust coal or oil, nor will they generate electricity.

Subpart DDDDD – National Emission Standards for Hazardous Air Pollutants for Major Sources:

Industrial, Commercial, and Institutional Boilers and Process Heaters

40 CFR Part 63 Subpart DDDDD applies to boilers and process heaters located at major sources of HAP

emissions. Based on the estimated potential annual emissions of HAPs from the REC facility contained

in Appendix D, HAP emissions from the facility will be less than 10 tons per year for any individual HAP

and less than 25 tons per year for combined HAPs. Therefore, REC will not be a major source of HAP

emissions and Subpart DDDDD will not apply.

40 CFR Part 63 Subpart YYYY – National Emission Standard for Hazardous Air Pollutants for

Stationary Combustion Turbines

40 CFR Part 63 Subpart YYYY applies to stationary combustion turbines located at major sources of

HAP emissions. Based on the estimated potential annual emissions of HAPs from the REC facility

contained in Appendix D, HAP emissions from the facility will be less than 10 tons per year for any

individual HAP and less than 25 tons per year for combined HAPs. Therefore, REC will not be a major

source of HAP emissions and Subpart YYYY will not apply.

40 CFR Part 63 Subpart JJJJJJ National Emission Standard for Hazardous Air Pollutants for

Area Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters

40 CFR Part 63 Subpart JJJJJJ does not apply to the auxiliary boilers since the boilers will only combust

natural gas. Per 63.11195(e), gas-fired boilers are exempt from this subpart.

40 CFR Part 76 – Acid Rain Nitrogen Oxide Emission Reduction Program

Part 76 applies to coal-fired utility units subject to the Acid Rain Program. Since REC will not combust

coal, this regulation does not apply.


3.0 BEST AVAILABLE CONTROL TECHNOLOGY/LOWEST ACHIEVABLE EMISSION RATE/BEST AVAILABLE TECHNOLOGY (BACT/LAER/BAT) ANALYSIS


PAGE i

TABLE OF CONTENTS

3.0 BEST AVAILABLE CONTROL TECHNOLOGY/LOWEST ACHIEVABLE EMISSION

RATE/BEST AVAILABLE TECHNOLOGY ANALYSIS (BACT/LAER/BAT) ................................ 1

3.1 INTRODUCTION .............................................................................................................................. 1 3.2 EXECUTIVE SUMMARY OF BACT/LAER/BAT DETERMINATIONS .............................................. 2

3.2.1 Turbines ................................................................................................................................ 2 3.3 BACT/LAER/BAT DETERMINATIONS FOR COMBINED CYCLE TURBINES .................................. 3

3.3.1 Nitrogen Oxides (NOx) ......................................................................................................... 3 3.3.2 Particulate Matter (PM10) ...................................................................................................... 6 3.3.3 Carbon Monoxide (CO) and Volatile Organic Compounds (VOC) ..................................... 9 3.3.4 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ....................................................... 13 3.3.5 Ammonia ............................................................................................................................. 14 3.3.6 Startup and Shutdown Emissions ........................................................................................ 14

3.4 BACT/BAT EVALUATION FOR GREENHOUSE GAS (GHG) EMISSIONS FROM TURBINES .......... 16 3.4.1 Identification and Evaluation of CO2 Control Technologies .............................................. 16 3.4.2 Ranking of Technically Feasible Options ........................................................................... 17 3.4.3 Selection of CO2 Control Technology to Meet BACT/BAT .............................................. 18

3.5 HAZARDOUS AIR POLLUTANTS ................................................................................................... 18 3.5.1 Identification and Evaluation of VOC/HAP Controls......................................................... 19 3.5.2 Selection VOC/HAP Control Technology to Meet BAT .................................................... 19

3.6 BACT/LAER/BAT DETERMINATION AUXILIARY BOILERS ....................................................... 20 3.6.1 Nitrogen Oxides (NOx) ....................................................................................................... 20 3.6.2 Carbon Monoxide (CO) ...................................................................................................... 23 3.6.3 Volatile Organic Compounds (VOC).................................................................................. 26 3.6.4 Particulate Matter (PM) ...................................................................................................... 28 3.6.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ....................................................... 29 3.6.6 Identification of BACT for Greenhouse Gas (GHG) Emissions ......................................... 30

3.7 BACT/LAER/BAT DETERMINATION FOR EMERGENCY GENERATOR AND FIRE PUMP DIESEL

ENGINES .................................................................................................................................................. 30 3.7.1 Identification of Sources with BACT/LAER/BAT ............................................................. 31 3.7.2 Selection of BACT/LAER/BAT For Emergency Generator And Fire Pump Engine ......... 33

3.8 BACT/LAER/BAT DETERMINATION WATER BATH HEATERS .................................................. 34 3.8.1 Nitrogen Oxides (NOx) ....................................................................................................... 34 3.8.2 Carbon Monoxide (CO) ...................................................................................................... 36 3.8.3 Volatile Organic Compounds (VOC).................................................................................. 37 3.8.4 Particulate Matter (PM) ...................................................................................................... 38 3.8.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ....................................................... 39 3.8.6 Identification of BACT for Greenhouse Gas (GHG) Emissions ......................................... 40

3.9 HIGH VOLTAGE CIRCUIT BREAKERS EQUIPMENT LEAKS BACT/BAT ANALYSIS..................... 40 3.9.1 Identification of Control Options ........................................................................................ 40 3.9.2 Evaluation of Control Options ............................................................................................ 40 3.9.3 Selection of BACT/BAT ..................................................................................................... 41

3.10 LAER/BACT/BAT DETERMINATION FOR ULSD STORAGE TANK ............................................ 41 3.10.1 Identification of Sources with BACT/LAER/BAT ............................................................. 41 3.10.2 Selection of BACT/LAER/BAT for ULSD Storage Tank .................................................. 42


PAGE ii

TABLES:

TABLE 1 COMPARISON OF MAXIMUM ALLOWABLE EMISSIONS TO SIGNIFICANT

ALLOWABLE EMISSIONS ........................................................................................ 1 TABLE 2 PROPOSED BACT/LAER/BAT FOR COMBINED CYCLE TURBINES ................. 3 TABLE 3 IDENTIFICATION OF SIMILAR FACILITIES WITH LAER/BAT FOR NOX ....... 3 TABLE 4 FACILITIES WITH BACT/BAT FOR PM10 ................................................................ 7 TABLE 5 FACILITIES WITH BACT/BAT FOR CO................................................................... 9 TABLE 6 FACILITIES WITH LAER/BAT FOR VOC .............................................................. 10 TABLE 7 FACILITIES WITH BACT/BAT FOR SO2/H2SO4 .................................................... 13 TABLE 8 SUSD EMISSION LIMITS PER POWERBLOCK – NATURAL GAS .................... 15 TABLE 9 SUSD EMISSION LIMITS PER POWERBLOCK – ULSD ..................................... 15 TABLE 10 CO2 EMISSION FACTORS FOR VARIOUS FUEL TYPES .................................... 17 TABLE 11 FACILITIES WITH BAT DETERMINATIONS FOR HAPS ................................... 18 TABLE 12 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR NOX .............. 21 TABLE 13 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR CO ................. 23 TABLE 14 OXIDATION CATALYST CAPITAL EXPENSES1 ................................................. 24 TABLE 15 OXIDATION CATALYST ANNUAL OPERATING COSTS1 ................................. 25 TABLE 16 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR VOC .............. 26 TABLE 17 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR PM ................. 28 TABLE 18 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR SO2................. 29 TABLE 19 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR NOX .............. 31 TABLE 20 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR CO ................. 32 TABLE 21 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR VOC .............. 32 TABLE 22 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR PM ................. 33 TABLE 23 SUMMARY OF PROPOSED BACT/LAER/BAT ..................................................... 33 TABLE 24 POTENTIAL EMISSIONS ......................................................................................... 33 TABLE 25 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR NOX .............. 35 TABLE 26 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR CO ................. 36 TABLE 27 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR VOC .............. 37 TABLE 28 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR PM ................. 38 TABLE 29 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR SO2................. 39 TABLE 30 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR VOC .............. 41


PAGE 1

3.0 BEST AVAILABLE CONTROL TECHNOLOGY/LOWEST ACHIEVABLE EMISSION RATE/BEST AVAILABLE TECHNOLOGY ANALYSIS (BACT/LAER/BAT)

3.1 Introduction

Renovo Energy Center, LLC (REC) is submitting an air permit application for the installation of a

nominally rated 1240 MW (net) combined cycle electric generating plant to be located in Renovo,

Pennsylvania. The electric generating plant will consist of two 1x1x1 combined cycle turbines, each

consisting of a combustion turbine, HRSG with duct burner, and a steam turbine. REC is proposing to

utilize General Electric 7HA.02 combustion turbines.

The proposed REC project will include for each powerblock an auxiliary boiler, turbine inlet air

conditioner, and air-cooled condenser. REC also will have two natural gas-fuel heaters, an emergency

generator, and a fire water pump engine. The combustion turbines will fire primarily natural gas with

ULSD fuel as back-up. The duct burners, auxiliary boilers, and natural gas-fuel heaters will fire only on

pipeline quality natural gas, while the emergency generator and fire water pump engine will fire ULSD.

REC is classified as a major stationary source due to potential emissions of Nitrogen Oxides (NOx),

Carbon Monoxide (CO), Volatile Organic Compounds (VOC), and Particulate Matter (PM/PM10/PM2.5),

which exceed their respective PSD significant allowable emissions thresholds. In accordance with the

Non-Attainment New Source Review provisions in 25 Pa. Code Chapter 127, REC will be required to

apply Lowest Achievable Emissions Rate (LAER) technology for emissions of NOx and VOC from

REC’s emission sources. In addition, Best Available Control Technology (BACT) must be met for the

attainment emissions greater than significant threshold and Best Available Technology (BAT) must be

applied to satisfy PaDEP requirements. Table 1 presents REC’s calculated allowable (potential) emissions

in comparison to the regulatory thresholds and indicates what levels of control are required.

TABLE 1 COMPARISON OF MAXIMUM ALLOWABLE EMISSIONS TO SIGNIFICANT ALLOWABLE EMISSIONS

POLLUTANT

MAXIMUM ALLOWABLE EMISSIONS (TONS/YR)

SIGNIFICANT ALLOWABLE EMISSIONS (TONS/YR)

BACT, LAER, OR BAT REQUIRED?

Nitrogen Oxides (NOx) 364.4 100 BACT/LAER/BAT

Carbon Monoxide (CO) 369.5 100 BACT/BAT

Volatile Organic Compounds (VOC)

112.8 50 BACT/LAER/BAT

Particulate Matter (PM/PM10/PM2.5) 212.6 15/10 BACT/BAT

Sulfur Dioxide (SO2) 53.6 40 BACT/BAT

Sulfuric Acid (H2SO4) 35.4 7 BACT/BAT

Ammonia (NH3) 277.4 N/A BAT

Hazardous Air Pollutants (HAPs) 20.4/7.9 25/10 BACT/BAT

Greenhouse Gases (CO2e) 5,453,232 100,000 BACT/BAT

As shown in Table 1, REC’s maximum allowable emissions of NOx, CO, PM, PM10, SO2, VOC, sulfuric

acid, and greenhouse gases exceed significant allowable emission levels and therefore BACT, LAER,

and/or BAT must be applied.


PAGE 2

A BACT analysis is a “top down” procedure to determine the level of pollution control or emission limit

that must be applied to a particular emission unit. The “top down” BACT procedure consists of the

following steps:

• Identify most stringent emission rates and associated control technologies

• Eliminate technically infeasible options

• Rank remaining control technologies by control effectiveness

• Evaluate most effective controls and document results (case-by-case consideration of energy,

environmental and economic impacts)

• Select BACT

The LAER procedure is similar to BACT with the exception that the economic and energy impacts are

not considered. Because LAER is more stringent than BACT or BAT, the LAER analysis will satisfy the

BACT and BAT requirements. PaDEP’s BAT regulations are applicable to all emissions from the project

and are intended as all-encompassing to ensure that all sources apply the best technology available.

To identify LAER, BACT and BAT, REC accessed EPA’s RACT/BACT/LAER Clearinghouse (RBLC).

The RBLC is a compilation of emission limits and controls on emission units from around the United

States that have received air permits from various states and other regulatory agencies. The information is

voluntarily provided by the agencies and entered into the RBLC. Due to the voluntary nature of the

RBLC, not all permits are submitted for inclusion. For this reason, in many cases emission limits and

pollution control information included in the following BACT/LAER/BAT analyses were compiled by

contacting state or local air permit agencies. The facilities determined to be most similar to REC were

selected from facilities that have been issued permits within the last ten years.

3.2 Executive Summary of BACT/LAER/BAT Determinations

3.2.1 Turbines

REC is proposing to install two identical combined cycle units that will each consist of one combustion

turbine, one HRSG with duct burner, one electrical generator and one steam turbine.

Each combustion turbine will combust primarily natural gas and will have the capability of firing ULSD

as a backup fuel. Duct burners, firing only natural gas will be installed in the HRSG. Pollution control

equipment includes dry low-NOx (DLN) burners and Selective Catalytic Reduction (SCR) system for

control of NOx, as well as an oxidation catalyst for control of CO and VOCs. The SCR system and

oxidation catalyst allows REC to meet LAER and BACT for NOx, CO, and VOC.

REC is proposing to combust natural gas with a maximum sulfur content of 0.4 grains per 100 scf (gr

S/100scf) of fuel, and ULSD with a maximum sulfur content of 0.0015% by weight. This allows REC to

comply with BACT/BAT for emissions of SO2 and PM, including coarse (PM10) and fine (PM2.5)

particulates.

To meet BACT/LAER/BAT, REC is proposing the following:


PAGE 3

TABLE 2 PROPOSED BACT/LAER/BAT FOR COMBINED CYCLE TURBINES

POLLUTANT PROPOSED LIMITS1 CONTROL LEVEL COMPLIANCE METHOD

NOx 2.0 ppm (NG) 4.0 ppm (ULSD)

LAER/BAT Initial stack test, CEMS 3-hour block average

CO 1.3 ppm (NG no DB) 1.9 ppm (NG w/DB) 2.0 ppm (ULSD)

BACT/BAT Initial stack test, CEMS 24-hour block average

VOC 0.7 ppm (NG no DB) 1.8 ppm (NG w/DB) 2.0 ppm (ULSD)

LAER/BAT Initial stack test

PM10 0.0032 lb/MMBtu (NG) 0.013 lb/MMBtu (ULSD)

BACT/BAT Initial stack test, fuel sulfur content monitoring/supplier certifications

SO2 0.4 gr S/100scf (NG) 0.0015% S (ULSD)

BACT/BAT Fuel sulfur content monitoring/supplier certifications

Ammonia 5.0 ppm (NG & ULSD) BAT CEMS 3-hour block average

GHG (CO2) 962 lb/MW-hr BACT/BAT CEMS for CO2, 12-month block average 1ppm on dry volume basis, corrected for 15% oxygen

3.3 BACT/LAER/BAT Determinations for Combined Cycle Turbines

3.3.1 Nitrogen Oxides (NOx)

Emissions of NOx can be considered as having two basic components– “fuel NOx,” which is formed by

fuel-bound nitrogen, and “thermal NOx,” which results from oxidation of nitrogen in high-temperature

regions of the combustion zone. The following subsection describes control technologies that can be

applied to reduce NOx emissions from combined cycle powerblock installations and identifies similar

facilities for comparisons to determine the required LAER rate, as well as the appropriateness of the

control technology selected for this project.

TABLE 3 IDENTIFICATION OF SIMILAR FACILITIES WITH LAER/BAT FOR NOX

FACILITY NAME

TURBINE SIZE (MMBTU/HR)

PERMIT DATE

FUEL TYPE(S)

NOX EMISSION LIMIT (PPM)

AVERAGING PERIOD

NOX CONTROLS

West Deptford Energy, NJ

2,276 5/6/2009 NG 2 3-hour rolling SCR and WI1

Renaissance Energy Center, PA

2,666 8/27/2018 NG 2 1-hour block SCR and DLN2

Brunswick County Power Station, VA

2,942 3/12/2013 NG 2 1-hour average

SCR and DLN2

C4GT, LLC, VA 3,482 4/26/2018 NG 2 1-hour average

SCR and DLN2

Greensville Power Station, VA

3,227 6/17/2016 NG 2 1-hour average

SCR and DLN2

Hill Top Energy Center, PA

3,509 12/1/2017 NG 2 1-hour block SCR and DLN2

Indeck Niles, LLC, MI 3,421 6/26/2018 NG 2 24-hour rolling avg

SCR and DLN2

Moxie Freedom Generation Plant, PA

3,727 9/1/2015 NG 2 3-hour average

SCR and DLN2


PAGE 4

FACILITY NAME


PERMIT DATE

FUEL TYPE(S)

NOX EMISSION LIMIT (PPM)

AVERAGING PERIOD

NOX CONTROLS

Lackawanna Energy Center, PA

3,304 12/23/2015 NG 2 1-hour SCR and DLN2

CPV Three Rivers Energy Center, IL

3,474 7/30/2018 NG ULSD

2 5

3-hour SCR and DLN2

Killingly Energy Center, CT

3,863 6/30/2017 NG ULSD

2 4

1-hour SCR and DLN2

Middlesex Energy Center, NJ

3,462 7/19/2016 NG ULSD

2 4

3-hour rolling SCR and DLN2

CPV Towantic, LLC, CT 2,544 11/30/2015 NG ULSD

2 5

1-hour block SCR and DLN2

1WI = wet injection 2DLN = dry low NOx combustor

Identification and Evaluation of NOx Control Technologies

NOx control techniques are generally organized into two groups: combustion controls and post

combustion controls. Combustion controls affect the combustion conditions to minimize the formation of

NOx, while post-combustion controls remove NOx after it has formed.

Combustion Controls

Fuel-NOx Control

Fuel selection is an important consideration for the control of NOx emissions from combustion turbines.

Both NOx formation processes (“fuel NOx” and “thermal NOx”) must be considered in selecting a fuel

source, as both the flame temperature and fuel-bound nitrogen content must be given consideration.

Distillate fuel oils contain inherently low fuel-bound nitrogen and have relatively high flame

temperatures. Natural gas contains essentially zero fuel bound nitrogen, and has a relatively low flame

temperature in comparison to other fuels. The proposed combined cycle turbines will fire primarily on

natural gas and will only fire ULSD as a back-up fuel option during periods when the natural gas supply

is interrupted.

Dry low-NOx Combustor Design

One method of reducing “thermal NOx” formation is by utilizing a dry low-NOx (DLN) combustor that

premixes the air and fuel prior to entering the primary combustion chamber. This allows for a lower flame

temperature due to the homogeneity of the air/fuel mix, and the lack of a flame front. Advanced

combustor design also includes reducing the combustion zone residence time and limiting the oxygen

available to combine with nitrogen to form NOx. REC’s proposed turbines and duct burners include DLN

combustors.

Wet Injection

As stated previously, the flame temperature of distillate oil is relatively high in comparison to other fuel

sources. The injection of water directly into the combustion chamber lowers the flame temperature by

absorbing heat necessary to vaporize the water and raise the temperature of the steam to that of the

combustion temperature. Steam injection utilizes the same principle, although heat can only be absorbed


PAGE 5

by the steam in raising the steam’s temperature to that of combustion. Injection of either water or steam

results in lower “thermal NOx” formation.

Proper injection of water or steam is extremely important when considering equipment life, as well as

emissions performance. Too much injection can cause flame instability, excessive thermal stress, as well

as increases in CO and VOC emissions due to incomplete combustion. The amount of water or steam

injected depends largely on the design of the combustor.

Wet injection is typically not used when firing natural gas due to the lower flame temperature as well as

the low nitrogen content of natural gas. When employed on ULSD-fired combustion turbines, wet

injection has an 80% to 85% control efficiency for emissions of NOx. The design under consideration

utilizes wet injection to control emissions of NOx when firing ULSD only.

Catalytic Combustion (XONONTM)

Catalytic combustion (specifically Kawasaki Heavy Industries Ltd.’s XONONTM technology) also offers

the opportunity to lower NOx emissions from combustion turbine applications; however, this technology

is not available for large combustion turbine applications. Thus, catalytic combustion is not a technically

feasible control technology option.

Post-combustion Controls

The available add-on control technologies for NOx control from fuel burning devices are selective non-

catalytic reduction, non-selective catalytic reduction, selective catalytic reduction, and

EMXTM/SCONOXTM. These NOx controls are described below.

Selective Non-Catalytic Reduction (SNCR)

SNCR is a process in which ammonia is injected directly into the exhaust gas stream to produce nitrogen

and water vapor from NOx. The chemical reactions take place without the presence of a catalyst, and due

to reaction temperature considerations, the ammonia or urea injection must occur in a location where the

exhaust gas temperatures are between approximately 1,600°F and 2,000°F. The exhaust gas temperature

range for the proposed units does not allow for SNCR to be a feasible control technology, as the exhaust

temperature for this project is expected to be considerably below this range.

Non-Selective Catalytic Reduction (NSCR)

NSCR is a process that utilizes a catalyst to produce nitrogen and water vapor from NOx without the

presence of a reducing agent. This technology has not yet been developed for large-scale combustion

turbine applications and is currently only utilized in reciprocating internal combustion engines. Thus,

NSCR is considered technically infeasible for this equipment.

Selective Catalytic Reduction (SCR)

SCR is similar to SNCR except that with SCR, a catalyst is present during the chemical reactions that

produce nitrogen and water vapor from NOx. The chemical reactions are as follows:

4NH3 + 4NO + O2 → 4N2 + 6H2O

4NH3 + 2NO2 + O2 → 3N2 + 6H2O


PAGE 6

The presence of the catalyst (typically consisting of noble metals, base metal oxides, or zeolite-based

materials) decreases the energy required to activate the chemical reactions, and allows for the reducing

agent (ammonia) to be injected at lower temperatures (~600°F to 750°F) in the exhaust gas stream.

Proper injection of ammonia is an important consideration for emissions control, as well as equipment

life. Based on the chemical reactions, a molar ratio of ammonia to NOx of 1 to 1 is required for NOx

removal. Due to imperfections in the injection process (mixing and other factors affecting the reaction),

typically the actual ammonia to NOx molar ratio is greater than 1 to 1.

Another factor that can affect the performance and life of the SCR system is high fuel sulfur content.

Natural gas sulfur contents less than 2 gr S/100scf allow for a reasonable catalyst life, and REC’s

proposed sulfur content of 0.4 gr S/100scf meets the criteria, in conjunction with the limited use of ULSD

as a back-up fuel.

SCR is a widely used control technology for NOx, particularly for large combustion turbine applications

and typically demonstrates removal efficiencies of 80% to 90% whether firing natural gas or ULSD.

EMXTM/SCONOX

TM

EMXTM (formerly known as SCONOX

TM) is a technology that is intended to reduce emissions of NOx,

CO, and VOC simultaneously. CO and NO are both oxidized to form CO2 and NO2, respectively. The

resulting NO2 is then absorbed by the catalyst surface, while the CO2 is emitted into the atmosphere.

Although highly desirable due to the lack of ammonia injection necessary, EMXTM has only been installed

in small powerplants in California (all below 43 MW), and thus is considered technically infeasible for

the proposed REC project.

Selection of NOx Control Technology to Meet LAER/BAT

The most effective control for NOx from a dual fueled combined cycle powerblock is SCR in conjunction

with good combustion practices and DLN combustors, as well as wet injection. The most stringent limit

demonstrated in practice when firing natural gas is 2 ppmvd @ 15% O2 (by numerous facilities), and

when firing ULSD is 4 ppmvd @ 15% O2.

REC therefore proposes to meet LAER for NOx using DLN combustion controls, SCR, and water

injection when firing ULSD. REC proposes a NOx emission limit of 2 ppmvd @ 15% O2 based on a 1-

hour block average when firing natural gas, and 4 ppmvd @ 15% O2 based on a 1-hour block average

when firing ULSD. Compliance with these limits will be demonstrated by a continuous emission

monitoring system installed in compliance with 40 CFR Part 60 and Part 75.

3.3.2 Particulate Matter (PM10)

Particulate matter (PM) emissions from combined cycle turbines are the result of unburned trace

constituents in the fuel, unburned hydrocarbons, and the inlet air supply that may contain dust particles.

PM emissions can also result from the formation of sulfates and nitrates, which are formed when certain

sulfur- and nitrogen-oxide compounds react with ammonia. The following section describes control

technologies that can be applied to reduce PM emissions from combined cycle powerblock applications

and identifies similar facilities for comparisons to determine BACT for this project.


PAGE 7

Identification of Similar Facilities with BACT/BAT for PM10

TABLE 4 FACILITIES WITH BACT/BAT FOR PM10

FACILITY NAME


PERMIT DATE

FUEL TYPE(S)

PM EMISSION LIMIT (LB/MMBTU) PM10 CONTROLS

Filer City Station, MI 1,935 11/17/2017 NG 0.0025 no DB Air filters, good combustion, clean fuels

Jackson Energy Center, IL 3,864 12/31/2018 NG 0.0026 no DB 0.0026 with DB

Good combustion, clean fuels

Warren County Power Station, VA

2,996 6/17/2014 NG 0.0027 no DB 0.004 with DB

Clean fuels


3,304 12/23/2015 NG 0.003 no DB 0.003 with DB

Air filters, good combustion, clean fuels


2,942 3/12/2013 NG 0.0033 no DB 0.0047 with DB


Thetford Generating Station, MI

2,587 7/25/2013 NG 0.0033 no DB 0.0066 with DB

Air filters, good combustion, clean fuels

Long Ridge Energy Generation LLC, OH

3,544 11/7/2017 NG 0.0036 no DB 0.004 with DB

Clean fuels


3,474 7/30/2018 NG ULSD

0.0037 no DB 0.0037 with DB 0.0167 ULSD


Greensville Power Station, VA 3,227 6/17/2016 NG 0.003 no DB 0.0039 with DB

Clean fuels

Renaissance Energy Center, PA

2,666 8/27/2018 NG 0.0043 no DB 0.0043 with DB

Clean fuels

CPV Towantic, LLC, CT 2,544 11/30/2015 NG ULSD

0.0065 no DB 0.0081 with DB 0.0319 ULSD

Clean fuels

CPV Valley Energy Center, NY 2,234 8/1/2013 NG ULSD

0.0073 NG 0.0368 ULSD

Clean fuels

CPV Fairview Energy Center, PA

3,338 9/2/2016 NG ULSD

0.0068 no DB 0.005 with DB 0.0415 ULSD

Clean fuels

Killingly Energy Center, CT 3,863 6/30/2017 NG 0.0044 no DB 0.005 with DB 0.0168 ULSD

Good combustion

Identification and Evaluation of PM10 Controls

PM10 control devices applicable to dual fired combustion turbines include combustion controls, the use of

clean fuels (low sulfur/ash), and high efficiency inlet air filters. Add-on control devices such as multi-

clones or electro-static precipitators (ESPs) are considered technically infeasible for combustion turbines

and were not identified in any of the RBLC entries or other permits, whether fired on natural gas or

ULSD.

The most stringent level of particulate matter control for a dual fired combined cycle turbine is achieved

with good combustion controls, the use of high efficiency inlet air filters, and clean fuels. Therefore, a

ranking of their effectiveness is not necessary.


PAGE 8

The lowest permit value for total PM (filterable) when firing natural gas is 0.0025 lb/MMBtu at Filer City

Station in Michigan. The facility has not been built, nor has Jackson Energy Center proposed for

construction in Illinois with a permit limit of 0.0026 lb/MMBtu. The lowest PM limit for an operating

facility with or without duct burner is Lackawanna Energy Center in Pennsylvania at 0.003 lb/MMBtu.

The lowest value for PM when firing ULSD at an operating facility is CPV Towantic, LLC in

Connecticut at 0.0319 lb/MMBtu/hr. REC is proposing 0.0032 lb/MMBtu when firing natural gas and

0.013 lb/MMBtu when firing ULSD. These values reflect GE emission rates based on historic measured

PM data with the inclusion of recently available emissions testing data. GE has provided the following

justification in support of these limits:

• Measured Particulate Matter is the result of a combined contribution from constituents in the fuel,

introduction of particulate from CT airflow and combustion water injection (for NOx control

during ULSD firing) and the effects of uncertainty and artifacts inherent to the defined

measurement methodologies.

• PM measurement methodology is a complex manual process, conducted in non-ideal conditions

at the top of an operating gas turbine stack, with many opportunities for error in the measurement

process. The testing entails drawing an extracted exhaust stream across a heated measurement

filter and then condensing particulates in that same stream in glass impingers held in an ice bath.

In this process a relatively small particulate sample is collected. This collection is then manually

captured and brought to a laboratory for quantification. Any contamination or introduction of

measurement artifact through this process introduces a high degree of measurement variability

into the measurement results. This inherent measurement variability must be incorporated into the

allowable emission rate.

• Combustion architecture contributes to a variation in emission values across turbine technologies,

but it is not the sole driver of particulate formation. Design and operating factors such as water

injection rate, fuel to water mixing and fuel atomization efficiency will contribute to varying

particulate formation rates. However, the particulate formation due to combustion system

capabilities for any system which operates at a high combustion efficiency, while significant, is

not the primary factor when comparing particulate measurement results across combustion

technologies.

• The best means to determine expected particulate emissions for a particular combustion turbine

and fuel is through field measurements of similar operational equipment. The collection of field

measurement data is a challenge for ULSD firing due to the very limited amount of operation on

this fuel. As a result, there is limited opportunity to capture this measurement data and to

determine the true capability of the emissions and the measurement capability.

• The 7HA.02 is a relatively new gas turbine model with combustion advancements. GE has

limited PM emission data on ULSD across all gas turbine models and simply has no PM emission

data on this specific gas turbine and its specific ULSD combustion technology. The emission

values are extrapolated from available test data.

Selection of PM10 Control Technology to Meet BACT/BAT

REC will meet BACT for PM10 through the use of high efficiency inlet air filters, good combustion

practices, and low sulfur fuels. The total PM (filterable and condensable) emission limit proposed is

0.0032 lb/MMBtu when firing natural gas, and 0.013 lb/MMBtu when firing ULSD. Compliance with


PAGE 9

these limits will be based on initial stack testing, fuel sulfur content monitoring and fuel supplier

certifications.

3.3.3 Carbon Monoxide (CO) and Volatile Organic Compounds (VOC)

CO and VOC emissions from combined cycle combustion turbines are the result of incomplete

combustion. CO emissions are exacerbated by low oxygen availability, poor mixing of air and fuel, low

combustion temperatures, and short residence time in the combustion zone. VOC emissions are the result

of low combustion temperatures and short combustion zone residence times. The following section

describes control technologies that can be applied to reduce CO and VOC emissions from combined cycle

turbine applications and identifies similar facilities for comparisons to determine the lowest achievable

emission rate and/or best available control technology that will be required.

Identification of Similar Facilities with BACT/BAT for CO and LAER/BAT for VOC

TABLE 5 FACILITIES WITH BACT/BAT FOR CO

FACILITY NAME


PERMIT DATE

FUEL TYPE(S)

CO EMISSION LIMIT (PPM) CO CONTROLS

West Deptford Energy Station, NJ

2,276 7/18/2014 NG 0.9 (w/o DB) 1.5 (w/DB)

Oxidation Catalyst, Good Combustion

Killingly Energy Center CT (not operating)

3,863 6/30/2017 NG ULSD

0.9 (w/o DB) 1.7 (W/DB)


Greensville Power Station, VA 3,227 6/17/2016 NG 1.0 (w/o DB) 1.6 (w/DB)


CPV Towantic, LLC, CT 2,544 11/30/2015

NG ULSD

0.9 (w/o DB) 1.7 (W/DB)


C4GT, LLC, VA (not operating)

3,482 4/26/2018 NG 1.0 (w/o DB) 1.6 (W/DB)



2,942 3/12/2013 NG 1.5 (w/o DB) 2.4 (W/DB)


Wildcat Point Generation Facility, MD

2,592 4/8/2014 NG 1.5 (w/o DB) 2.0 (W/DB)


Jackson Energy Center, IL 3,864 12/31/2018 NG

1.5 (w/o DB) 2.0 (W/DB)


Liberty Generation Plant, PA 2,890 1/31/2013 NG

2.0 (w/o DB) 2.0 (W/DB)


Patriot Generation Plant, PA 3,007 12/13/2013 NG

2.0 (w/o DB) 2.0 (W/DB)


West Deptford Energy, NJ 2,352 5/6/2009 NG 2.0 (w/o DB) 2.0 (w/DB)


Renaissance Energy Center, PA (not operating)

2,666 8/27/2018 NG 2.0 (w/o DB) 2.0 (w/DB)


Mattawoman Energy Center, MD (not operating)

2,898 11/13/2015 NG 2.0 (w/o DB) 2.0 (w/DB)


Lackawanna Energy Center, PA 3,304 12/23/2015 NG 2.0 (w/o DB) 2.0 (w/DB)


Hill Top Energy Center, PA (not operating)

3,509 12/1/2017 NG 2.0 (w/o DB) 2.0 (w/DB)



3,727 9/1/2015 NG 2.0 (w/o DB) 2.0 (w/DB)



PAGE 10

FACILITY NAME


PERMIT DATE

FUEL TYPE(S)

CO EMISSION LIMIT (PPM) CO CONTROLS


2,996 6/17/2014 NG 1.5 (w/o DB) 2.4 (W/DB)


TABLE 6 FACILITIES WITH LAER/BAT FOR VOC

FACILITY NAME

TURBINE/DUCT BURNER SIZE (MMBTU/HR)

PERMIT DATE

FUEL TYPE(S)

VOC EMISSION LIMIT (PPM) VOC CONTROLS

Killingly Energy Center, CT (not operating)

3,863 (CT) 1,106 (DB)

6/30/2017 NG ULSD

0.7 (NG w/o DB) 1.6 (NG w/DB) 1.8 (ULSD)



3,227 (CT) 500 (DB)

6/17/2016 NG 0.7 (w/o DB) 1.4 (w/DB)


C4GT, LLC, VA (not operating)

3,482 (CT) 475 (DB)

4/26/2018 NG 0.7 (NG w/o DB) 1.4 (NG w/DB)


CPV Valley Energy Center, NY

2,234 (CT) 500 (DB)

8/1/2013 NG ULSD

0.7 (NG w/o DB) 1.8 (NG w/DB) 0.7 (ULSD)



2,996 (CT) 500 (DB)

6/17/2014 NG 0.7 (w/o DB) 1.6 (w/DB)


Wildcat Point Generation Facility, MD

2,592 (CT) 892 (DB)

4/8/2014 NG 0.7 (w/o DB) 1.6 (w/DB)



2,942 (CT) 500 (DB)

3/12/2013 NG 0.7 (w/o DB) 1.6 (w/DB)


Renaissance Energy Center, PA (not operating)

2,666 (CT) 914 (DB)

8/27/2018 NG 1.0 (w/o DB) 1.4 (w/DB)


Moxie Patriot Generation Plant, PA

3,007 (CT) 164 (DB)

12/13/2013 NG 1.0 (w/o DB) 1.5 (w/DB)


Moxie Liberty Generation Plant, PA

2,890 (CT) 387 (DB)

1/31/2013 NG 1.0 (w/o DB) 1.5 (w/DB)



3,304 (CT) 659 (DB)

12/23/2015 NG 1.0 (w/o DB) 1.5 (w/DB)



3,727 (CT) 200 (DB)

9/1/2015 NG 1.0 (w/o DB) 1.5 (w/DB)


Mattawoman Energy Center, MD (not operating)

2,898 (CT) 687 (DB)

11/13/2015 NG 1.0 (w/o DB) 1.9 (w/DB)


West Deptford Energy Station, NJ

2,276 (CT) 770 (DB)

2018 NG 1.0 (w/o DB) 1.9 (w/DB)1



3,338 (CT) 425 (DB)

9/2/2016 NG 1.0 (w/o DB) 1.9 (w/DB)


West Deptford Energy, NJ 2,352 (CT) 775 (DB)

5/6/2009 NG 1.0 (w/o DB) 1.9 (w/DB)


Hickory Run Energy Station, PA (not operating)

2,942 (CT) 500 (DB)

4/23/2013 NG 1.5 (w/o DB) 1.5 (w/DB)


York Energy Center, PA 2,513 (CT) 722 (DB)

6/15/2015 NG 1.5 (w/o DB) 1.9 (w/DB)


Hill Top Energy Center, PA (not operating)

3,509 (CT) 981 (DB)

12/1/2017 NG 1.0 (w/o DB) 2.0 (w/DB)



PAGE 11

FACILITY NAME

TURBINE/DUCT BURNER SIZE (MMBTU/HR)

PERMIT DATE

FUEL TYPE(S)

VOC EMISSION LIMIT (PPM) VOC CONTROLS

Garrison Energy Center, DE

2,260 (CT) 1/30/2013 NG, ULSD

4.1 lb/hr (NG) 4.5 lb/hr (ULSD)


1Limits were revised in most recent permit and differ from data in RBLC database.

Identification and Evaluation of CO and VOC Controls

Control technologies for evaluation in the BACT/LAER/BAT analysis to control CO and VOC emission

from dual fired combustion turbines consist of combustion controls and oxidation catalysts. Combustion

controls are designed to minimize incomplete combustion by improving oxidation of CO and VOC to

CO2. Oxidation catalysts are used to reduce CO and VOC emissions in many combustion turbine and

reciprocating engine applications. Oxidation catalysts typically operate at temperatures of 700°F to

1,100°F to be effective and thus for combustion turbine applications are typically placed in the exhaust

gas stream where the temperature range for the exhaust of 700°F to 1,100°F can be ensured. An oxidation

catalyst operating outside of this temperature range will experience additional deterioration beyond what

would be expected of a properly located oxidation catalyst. Removal efficiency can vary with gas

residence time, which is a function of catalyst bed depth. Increasing bed depth will increase removal

efficiencies but will also cause an increase in pressure drop across the catalyst bed, potentially increase

particulate matter emissions and result in a decrease in turbine performance.

Gas turbine CO and VOC emissions are a result of incomplete combustion which primarily occurs at the

edges of the gas turbine operating envelop. As a result, the expected emissions are lowest at baseload

steady operation near typical ambient conditions. These emissions, while within the guarantee

capabilities, will tend to be higher when the gas turbine is operated at minimum load conditions and at

extreme temperatures. Overly restrictive CO and VOC emissions limits, based only on baseload steady

operation at typical ambient conditions, when applied to unfired HRSG operating scenarios, will result in

decreased operating flexibility in the form of restricted minimum load turndown capability and can

restrict the rate at which the gas turbine is capable to ramp in load to respond to grid demands. Reduced

turndown and fast ramping capabilities are essential operating parameters for modern gas turbine plants to

ensure grid reliability in support of increased renewable penetration. The reduced turndown avoids over

generation when higher levels of renewable generation are available and during periods of decreased load

demand. Fast load ramping is essential to respond to fluctuations in renewable generation.

Selection of CO Control Technology to Meet BACT/BAT

The two technologies available for controlling CO are an oxidation catalyst and good combustion

practices. REC proposes to meet BACT for CO using good combustion practices in combination with an

oxidation catalyst. REC is proposing a CO limit of 1.3 ppmvd @ 15% O2 when firing natural gas (without

duct firing), 1.9 ppmvd @ 15% O2 firing natural gas with duct firing, and 2 ppmvd @ 15% O2 when firing

ULSD. Compliance with the CO limit will be based on a 24-hour block average using a CEMS.

As provided in Table 5, The RBLC search revealed a few facilities with lower emission limits when firing

natural gas with and without duct burners. The lowest permitted CO emission limit when firing natural

gas without duct firing is 0.9 ppmvd at CPV Towantic, LLC and West Deptford Energy Station. Killingly

Energy Center is at 0.9 ppm but the facility has not been built. Both of the operating facilities have

comparatively smaller combustion turbines. There is one unit operating with a limit of 1 ppmvd without

duct firing (Greensville Power Station) which has a smaller combustion turbine. There are three facilities

(Greensville Power Station, CPV Towantic, LLC, and West Deptford Energy Station that are operating

with limits lower than 1.9 ppmvd (limits are 1.6 ppmvd, 1.7 ppmvd, and 1.5 ppmvd, respectively) with


PAGE 12

duct firing. The turbines and duct burners at these other facilities have significantly lower heat input

capacities and therefore are not appropriate for comparison to REC’s larger gas turbines and burners.

REC will meet BACT with an oxidation catalyst in combination with good combustion practices which is

top control technology of turbines. The proposed limits are consistent with numerous other recent and

past permitted combustion turbines of varying sizes and manufacturers.

Selection of VOC Control Technology to Meet LAER/BAT

The most effective control for VOC is an oxidation catalyst in combination with good combustion. The

lowest permitted VOC emission limit when firing natural gas without duct firing is 0.7 ppm at seven

different facilities identified by the RBLC search. Five of the seven facilities are currently operating and

meeting this limit. REC is proposing to meet 0.7 ppm when firing natural gas without duct firing.

With duct firing, the lowest permitted emission limit for VOC is 1.4 ppm at three facilities only one of

which is operating (Greensville Power Station). Greensville Power Station is equipped with duct burners

that are approximately half the size of the burners proposed by REC. The next highest limit for

combustion turbines with duct firing is 1.5 ppm which is achieved at four facilities currently in

commercial operation. The heat input of these duct burners is much lower (between 164 and 659

MMBtu/hr) than REC’s. There are four facilities with permit limits of 1.6 ppm with duct firing. Three are

in commercial operation, two of which are equipped with duct burners that are less than half the size of

REC’s duct burners. The third facility, Wildcat Point Generation Facility, has a lower duct burner heat

input of 892 MMBtu/hr than REC is proposing (1,005 MMBtu/hr). The next highest limit is 1.8 ppm

which is the limit that REC is proposing for its combustion turbines operating with duct firing.

VOC emission rates vary based on the level of duct burner firing. The amount of duct burner firing varies

with each individual project dependent on the energy demand and electricity the local grid can

accommodate. In addition, the combustion efficiency of a duct burner is lower than that of a turbine.

When duct firing constitutes a higher percentage of the overall heat input, the VOC concentration in the

combined exhaust gas will be higher than that of similar units with lower duct firing.

There is no single established BACT/LAER level for the various combustion turbine/duct burner size

combinations. VOC permit limits during duct firing operation should be determined in relation to the

designed heat capacity as well as anticipated dispatch. Supplemental duct firing capacity is optimized to

suit the capacity needs and operational profile of the installation. Higher levels of duct firing result in

higher levels of VOC emissions and the permitted VOC emissions must consider the amount of duct

firing for the specific installation. As the percent of duct burning increases relative to turbine firing,

VOC/CO emission concentrations of the combined exhaust streams are higher due to fact that duct burner

firing is not able to achieve the same level of emissions performance as compared to the highly efficient

and advanced design of turbine combustors. REC’s proposed duct burners are significantly larger than

most that are currently in commercial operation, thus the OEM’s proposed VOC emission rate of 1.8 ppm

while duct firing is considered to be the most stringent limit for this particular plant design.

In summary, REC proposes to meet LAER for VOC using good combustion practices in combination

with an oxidation catalyst. REC is proposing a VOC limit of 0.7 ppmvd @ 15% O2 when firing natural

gas (without duct firing), 1.8 ppmvd @ 15% O2 firing natural gas with duct firing, and 2 ppmvd @ 15%

O2 when firing ULSD.


PAGE 13

3.3.4 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4)

Emissions of SO2 from fuel combustion result from the oxidation of sulfur compounds present in the fuel.

SO2 emissions from combustion turbines burning natural gas and ULSD are inherently minimized by the

low sulfur content of the fuels. Flue gas desulfurization or scrubber systems are typically used on sulfur-

laden fuels such as coal and residual oil to remove SO2 in the flue gas stream. The following section

describes control technologies that can be applied to reduce SO2 emissions from combined cycle turbines

and identifies similar facilities for comparison to determine the best available control technology that will

be required.

Identification of Similar Facilities with BACT/BAT for SO2/H2SO4

TABLE 7 FACILITIES WITH BACT/BAT FOR SO2/H2SO4

FACILITY NAME


PERMIT DATE

FUEL TYPE(S)

FUEL SULFUR LIMIT

SOX CONTROLS

Warren County Power Plant, VA

2,996 6/17/2014 NG 0.32 gr S/100 scf (NG) Low sulfur fuel

Liberty Generation Plant, PA


Patriot Generation Plant, PA



2,942 3/12/2013 NG 0.4 gr S/100 scf (NG) 0.0011 lb SOx /MMBtu

Low sulfur fuel

C4GT, LLC, VA 3,482 4/26/2018 NG 0.4 gr S/100 scf (NG) 0.0011 lb SOx /MMBtu

Low sulfur fuel



Oregon Clean Energy Center, OH


Identification and Evaluation of SO2/H2SO4 Controls

The primary means for controlling emissions of SO2 and H2SO4 from dual fired combustion turbines is to

limit the sulfur content of the fuel. Add-on control technologies that are available to reduce SO2 emissions

include dry sorbent injection, wet scrubbing systems and spray dryer adsorbers. None of these add-on

control devices have been applied to combined cycle turbine applications identified in the RBLC or other

permit searches. For this reason, the BACT limits for SO2 and H2SO4 will be based on the sulfur content

of the fuels, similar to the most recently permitted sources in Pennsylvania.

Selection of SO2/H2SO4 Control Technology to Meet BACT/BAT

The fuel to be used in REC’s combustion turbines will consist of natural gas and ULSD. The SO2 and

H2SO4 emissions produced from combustion of these fuels are sufficiently low that add-on SO2 removal

technologies would not result in a significant environmental benefit or be cost-effective. REC proposes

the use of natural gas with sulfur content no greater than 0.4 gr S/100scf of gas, as well as the use of

ULSD with a maximum sulfur content of 15 ppm.


PAGE 14

3.3.5 Ammonia

Ammonia will be emitted from the combined cycle turbines as a result of the ammonia injection

associated with the SCR. Greater levels of NOx reduction require greater amounts of ammonia to be

injected. There are no add-on control devices that would be practical for reducing ammonia emissions

from combined cycle turbines, and no add-on control technologies were identified in the RBLC or other

permit searches. Good operating practices are the only practical method of reducing emissions of

ammonia from combined cycle turbines that employ SCR technology.

Identification of Facilities with BAT for Ammonia

An RBLC search was conducted to determine controls recently permitted facilities have employed to

reduce ammonia emissions. It was determined that emission limits of 5 ppm NH3 slip were being

achieved using good operating practices with monitoring of NH3 injection and NOx control, with no add-

on control devices being installed. Two facilities are permitted and operating with an emission limit of 2

ppm NH3 slip (CPV Towantic, LLC and Salem Harbor Station). These are smaller units and not

comparable to REC’s turbines and duct burners. Killingly Energy Center is permitted at 2 ppm, however,

it is not operating.

Identification and Evaluation of Ammonia Controls

Ammonia emissions are primarily a function of the ammonia injection rate for the SCR system. A balance

must be achieved in order to maximize the NOx reductions, while limiting the ammonia emissions.

Ensuring good operating practices that will result in this balance being continuously met is the only

control technology/method practical to be employed in combined cycle turbines similar in nature to this

project.

Selection of Ammonia Control Technology to Meet BAT

REC will use good operating practices in order to meet BAT for emissions of ammonia. These practices

will include continuous monitoring of ammonia slip levels and NOx emissions in order to optimize the

SCR efficiency while minimizing emissions. REC is proposing an ammonia slip limit of 5 ppm when

firing natural gas or ULSD. Compliance will be demonstrated using a CEMS with a 3-hour block

average.

3.3.6 Startup and Shutdown Emissions

The emission limits discussed in the previous sections reflect steady-state operations of the combined

cycle turbines. During startup and/or shutdown (SUSD) of the turbines, the combustors cannot operate at

their maximum efficiency and the add-on control devices (SCR and oxidation catalyst) are not effective

due to the exhaust gas temperatures during SUSD being outside the normal operating range for those

devices. Specific information regarding the duration and operating load where “normal” emissions

compliance can be achieved can be seen in Appendix E. Therefore, the steady-state emission limits are

not appropriate for use during SUSD scenarios, as it would be impossible to consistently achieve the same

emissions performance during SUSD scenarios.

Because BACT limits are determined on a case-by-case basis of achievability (U.S. EPA Responses to

Public Comments on the Proposed PSD Permit for the Desert Rock Energy Facility, July 2008), REC is

proposing secondary BACT limits during periods of SUSD. Thus, the combustion turbines will have


PAGE 15

emission limits that are both stringent during steady-state operations and achievable during SUSD

scenarios.

Tables 8 and 9 summarize the secondary BACT limits proposed for emissions during periods of SUSD

for natural gas firing and ULSD firing, respectively. Pollutants not included in this table are able to

achieve the primary BACT limits proposed above during periods of SUSD. The proposed secondary

BACT limits are based on mass emissions per event. Compliance with NOx and CO emissions will be

demonstrated using CEMS, and CO will be used as a surrogate for VOC with data gathered during the

initial stack testing. These values have been used in the facility-wide potential emissions estimates

included in this application.

TABLE 8 SUSD EMISSION LIMITS PER POWERBLOCK – NATURAL GAS

COLD STARTS

Time (minutes): 60

NOx Emissions (lbs/event): 164.0

CO Emissions (lbs/event): 932.0

VOC Emissions (lbs/event): 70.7

WARM STARTS

Time (minutes): 55




HOT STARTS

Time (minutes): 35




SHUTDOWNS

Time (minutes): 27




TABLE 9 SUSD EMISSION LIMITS PER POWERBLOCK – ULSD

COLD STARTS

Time (minutes): 60




WARM STARTS

Time (minutes): 55




HOT STARTS

Time (minutes): 35




SHUTDOWNS


PAGE 16

Time (minutes): 23




3.4 BACT/BAT Evaluation For Greenhouse Gas (GHG) Emissions From Turbines

GHG emissions from major stationary sources are regulated by EPA in accordance with the “tailoring

rule” contained in 40 CFR Part 51.166 – Prevention of Significant Deterioration of Air Quality as

amended on June 3, 2010. As of January 2, 2011, GHG emissions are subject to regulation if the source is

a proposed major source for a regulated non-GHG new source review (NSR) pollutant and will have the

potential to emit 75,000 tons or more of GHGs (represented as CO2 equivalent emissions (CO2e)).

Although the U.S. Supreme Court issued a decision that held that the EPA may not treat GHGs as an air

pollutant for the purposes of determining whether a proposed source is subject to PSD requirements, this

does not affect proposed sources that would otherwise be subject to PSD regulations for another pollutant.

For this reason, REC is required to complete a BACT analysis for emissions of GHGs from the combined

cycle turbines.

3.4.1 Identification and Evaluation of CO2 Control Technologies

Carbon capture and storage (CCS)

Current CCS technologies are costly to install and operate due to the large parasitic energy requirement,

reducing the amount of electricity available for sale to the grid. Parasitic loads for current CCS

technologies are reported at between 21% to 32% of the plant output. Other challenges related to CCS

technology include the lack of regulatory framework for storing CO2 and uncertainty regarding liability

for stored CO2.

On February 3, 2010, President Obama established an Interagency Task Force on carbon capture and

storage co-chaired by the Department of Energy (DOE) and the EPA with the mission of proposing a plan

to overcome the barriers to the widespread, cost effective deployment of CCS within 10 years. In August

2010, the Task Force issued a 233 page report, “Report of the Interagency Task Force on Carbon Capture

and Storage” that documents the Task Force’s findings, conclusions and recommendations. The report

states that the application of CCS to coal-fired power plant emissions offers the greatest potential for

GHG reductions.

Known barriers to widespread CCS deployment include:

• Lack of comprehensive climate change legislation - without a carbon price and financial

incentives for new technologies, there is no stable framework for investment in low-carbon

technologies such as CCS.

• Regulatory uncertainty – uncertainty and limited experience exists for the regulating and

permitting of CCS. Potential concerns exist for the long-term liabilities for CO2 storage sites.

• Aggregation of pore space for geologic storage on private lands.


PAGE 17

• Public awareness and support of CCS is currently unknown and may be project specific.

Since CCS is not commercially available or cost effective and issues exist for its storage and permitting,

REC concludes that it is not a feasible control option for its dual-fueled combined cycle electric

generating facility.

Energy Efficiency

Efficient production of electricity is an important aspect in reducing GHG emissions. Reducing the

amount of fuel required to produce the same amount of electric power results in lower GHG emissions, as

GHG emissions are largely a function of the fuel composition. In addition to proposing one of the most

efficient gas turbines offered by gas turbine manufacturers, REC’s energy efficient design includes

systems to monitor combustion at all times to ensure maximum combustion efficiency. Optimizing

combustion efficiency not only reduces emissions of GHGs, but also results in reduced emissions of other

pollutants as well (NOx in particular). The combined cycle turbines will be equipped with a continuous

emissions monitoring system that will include monitoring for oxygen, a key parameter in determining

combustion efficiency.

Energy efficiency can also be increased by utilizing good combustion practices, which include proper air

and fuel mixing, adequate residence time in the combustion zone, proper maintenance and operation of

the burner, and achieving the proper temperature in the combustion zone. Additionally, ensuring that the

fuel supply is consistent with minimal fluctuations in quality further improves energy efficiency.

Type of Fuel

Utilizing fuels that have low amounts of CO2 is another way to reduce GHG emissions. The following

table lists the CO2 content of various fuels typically used for electricity generation.

TABLE 10 CO2 EMISSION FACTORS FOR VARIOUS FUEL TYPES

FUEL TYPE CO2 CONTENT IN KG/MMBTU

Coal 95.52

Residual Fuel Oil 75.10

Distillate Fuel Oil 73.96

Natural Gas 53.06

The primary use of natural gas will appreciably reduce CO2 emissions when compared to solid or liquid

fuels. The selection of distillate oil as a backup fuel is the most appropriate alternative when considering

CO2 emissions. REC is proposing to combust primarily natural gas, utilizing ULSD as a backup fuel for

times when natural gas may be unavailable and electrical demand requires the plant to operate.

3.4.2 Ranking of Technically Feasible Options

Carbon capture, while technically feasible, is not commercially available or cost effective for natural gas

and ULSD fueled electric generating facilities. EPA and DOE’s Task Force Report concludes that while

CCS can play an important role in GHG emission reductions, current barriers exist that hinder near and

long-term deployment of CCS technology.


PAGE 18

Energy efficiency, the use of natural gas as the primary fuel with ULSD to be used on a very limited basis

as back-up fuel and good operating and maintenance practices are all technically feasible control options,

all of which REC will implement. As a result, none of these control options needs to be further evaluated

based on energy, environmental, and economic impacts.

3.4.3 Selection of CO2 Control Technology to Meet BACT/BAT

REC will implement energy efficiency, natural gas and ULSD fuel and good operating and maintenance

practices for CO2 control. REC will operate the equipment in accordance with manufacture’s

specifications.

REC is not proposing limits in terms of Btu/kW-hr relative to GHG emissions from the turbines. Several

similar facilities in Pennsylvania were recently issued permits without such an efficiency rate limit

(Hickory Run Energy Station, Berks Hollow Energy Association, Westmoreland Generating Station),

which is due to the difficulty to enforce due to its dependency on ambient temperature and turbine load. A

Btu/kW-hr efficiency rate is also unnecessary with a mass-based emission limit in place that meets the

definition of BACT contained in 40 CFR 52.21(b)(12). In EPA’s comments on the Wisconsin Department

of Natural Resources’ draft of the PSD Permit for Milwaukee Metropolitan Sewerage District Jones

Island Water Reclamation Facility, EPA points out that the definition of BACT allows for the use of a

design standard in lieu of an emission limitation only if imposing an emission limitation is infeasible.

EPA requested that a numerical BACT emission limit be imposed, and suggested units of pounds of CO2e

emitted per megawatt hour of electricity produced, on a 12-month rolling average.

REC is proposing a GHG BACT limit of 962 lb/MW-hr of CO2e, to be demonstrated with a CEMS based

on a 12-month rolling average.

3.5 Hazardous Air Pollutants

Volatile organic compound (VOC) emissions from combined cycle turbines are the result of incomplete

combustion. All hazardous air pollutant (HAP) emissions from natural gas combustion are VOCs.

Negligible amounts of metal HAPs are emitted from the combustion of ultra-low sulfur diesel (ULSD).

Control of metal HAPs is accomplished through the particulate matter BAT/BACT analysis outlined

above. The following section describes potential control technologies that can be applied to reduce

VOC/HAP emissions from REC’s combined cycle turbines and identifies similar facilities for

comparisons to determine the best available control technology that will be required.

TABLE 11 FACILITIES WITH BAT DETERMINATIONS FOR HAPS

FACILITY NAME FACILITY SIZE (MW)

PERMIT DATE

FUEL TYPE(S)

HAP EMISSION LIMIT HAP CONTROLS

Liberty Generation Plant 916-944 1/31/2013 NG 13 tpy Oxidation Catalyst

Patriot Generation Plant 916-944 12/13/2013 NG 12.5 tpy (RBLC) Oxidation Catalyst

Westmoreland Generating Station

930-1,065 4/1/2015 NG HAPs: 22.07 tpy Formaldehyde: 0.986 lb/hr and 8.67 tpy

Oxidation Catalyst

Garrison Energy Center 309 1/30/2013 NG, ULSD

HAPs:1.2 lb/hr (NG) 2.6 lb/hr (ULSD) 5.1 tpy Formaldehyde: 0.6 lb/hr

Oxidation Catalyst

Sunbury Generation LC 1,100 4/1/2013 NG HAPs: 4.63 tpy Oxidation Catalyst


PAGE 19

FACILITY NAME FACILITY SIZE (MW)

PERMIT DATE

FUEL TYPE(S)

HAP EMISSION LIMIT HAP CONTROLS

Formaldehyde: 0.312 lb/hr

Duke Energy Hanging Rock Energy

172 12/18/2012 NG

Formaldehyde: 0.45 lb/hr

Good Combustion

Kleen Energy Systems, LLC

620 7/2/2013 NG, ULSD

No limits Oxidation Catalyst

Cape Canaveral Energy Center

1,250 1/1/2015 NG, ULSD

No limits Good Combustion

Riviera Beach Energy Center

1,250 1/1/2015 NG, ULSD

No limits Good Combustion

Warren County Power Station

1,329 6/17/2014 NG No limits Oxidation Catalyst, Good Combustion

FPL West County Energy Center

1,250 1/10/2007 NG No limits Good combustion

Empire Power Plant 635 7/1/2014 NG, ULSD

No limits Oxidation Catalyst

3.5.1 Identification and Evaluation of VOC/HAP Controls

As listed in the above table the control technologies for evaluation in the BAT analysis to control volatile

organic HAP emissions from REC’s dual fired combustion turbine turbines consist of oxidation catalysts

and combustion controls. Combustion controls are designed to minimize incomplete combustion by

improving oxidation of volatile organic HAPs to CO2. This is achieved by ensuring that the combustors

are designed and operated to allow complete mixing of the combustion air and fuel at combustion

temperatures with an excess of combustion air. Oxidation catalysts are post combustion controls to reduce

volatile organic HAP emissions in some turbine and reciprocating engine applications. Oxidation

catalysts typically operate at temperatures of 700°F to 1,100°F to be effective and thus for combustion

turbine applications are typically placed in the exhaust gas stream where this temperature range for the

exhaust of 700°F to 1,100°F can be ensured. An oxidation catalyst operating outside of this temperature

range will experience additional deterioration beyond what would be expected of a properly located

oxidation catalyst. Oxidation catalysts have an average efficiency of approximately 50 percent for HAP

reduction.

3.5.2 Selection VOC/HAP Control Technology to Meet BAT

The most effective control for volatile organic HAPs from a combustion turbine is an oxidation catalyst in

combination with good combustion practices.

The only facilities identified in the BAT search with a short term emission rate for HAP emissions are

Garrison Energy Center, Westmoreland Generating Station, Sunbury Generation and Duke Energy.

REC’s HAP emissions are presented in Appendix D of this submittal, including formaldehyde emissions

which is based on a concentration of 45.5 ppbvd corrected to 15% O2.

REC is proposing the following hazardous air pollutant (HAP) limits for each power block:


PAGE 20

HAZARDOUS AIR POLLUTANT

NATURAL GAS SHORT TERM LIMIT (LB/HR)

ULSD SHORT TERM LIMIT (LB/HR)

ANNUAL LIMIT (TPY)

Formaldehyde 0.54 0.47 2.42

Toluene 0.23 NA 0.87

Manganese 3.7E-4 3.11 1.12

Toluene and manganese emission rates are based on AP-42 emission factors. Formaldehyde limit is based

on vendor data and an oxidation catalyst control efficiency of 50%.

REC will meet BAT for volatile organic HAPs through the use of good combustion practices in

combination with an oxidation catalyst on each combustion turbine. To be a minor source of HAPs, REC

is proposing a limit of 24.9 tons per year for facility-wide total HAPs, and 9.9 tons per year for any

individual HAP.

3.6 BACT/LAER/BAT Determination Auxiliary Boilers

REC is proposing to install two auxiliary “package” boilers each with a maximum rated heat input of 66

MMBtu/hr firing natural gas. Industrial package boilers are pre-assembled units that are delivered to the

site as a prefabricated unit. Package boilers are very compact and utilize a small furnace volume.

The auxiliary boilers’ function is to provide steam to the steam turbine on start-up, during maintenance

shutdown and for the steam turbine sealing process. Due to their function, the boilers will not be run

continuously or for long periods of time; their use will be limited. REC is proposing a limit on total fuel

use of 145,200 MMBtu per year for both boilers.


Generally NOx is formed during combustion by thermal oxidation of nitrogen in the combustion air

(thermal NOx) and the oxidation of nitrogen in the fuel (fuel-bound NOx). Natural gas contains relatively

small amounts of fuel-bound nitrogen and NOx formation through the fuel NOx mechanism is expected

to be insignificant. The main variables affecting NOx generation in the boilers are temperature, the

availability of nitrogen, the availability of oxygen, and the extent of contact between nitrogen and oxygen

during the combustion process.

Identification of NOx Control Technologies

NOx control techniques are generally organized into two separate categories: combustion controls and

post-combustion controls. Combustion controls affect the combustion conditions to minimize the

formation of NOx, while post-combustion controls remove NOx after it is formed. Combustion control

techniques have been demonstrated as successful in achieving NOx reductions from industrial boilers in a

cost-effective manner. The combustion control methods available to control thermal NOx on boilers

include low and ultra-low NOx burners and flue gas recirculation.

A search of EPA’s RBLC did not identify the application of post-combustion controls to natural gas fired

auxiliary boilers of this size. Table 12 below identifies the facilities in EPA’s RBLC with

BACT/LAER/BAT limits.


PAGE 21

TABLE 12 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR NOX

FACILITY NAME BOILER SIZE (MMBTU/HR) PERMIT DATE

NOX EMISSIONS LIMIT NOX CONTROLS

Moxie Freedom Salem Township, PA

55.4 9/1/2015 0.006 lb/MMBtu Ultra-low NOx burner, FGR, good combustion practices

York Energy Center Delta, PA

62 6/15/2015 0.0086 lb/MMBtu Ultra-low NOx burner, FGR, good combustion practices

Keys Energy Center Brandywine, MD

93 10/31/2014 0.01 lb/MMBtu

Ultra-low NOx burner, good combustion practices, efficient boiler design

Hess Newark Energy Center Newark, NJ

51.9 11/1/2012 0.01 lb/MMBtu Low NOx burner and FGR

Wildcat Point Generation Rising Sun, MD

45 4/8/2014 0.01 lb/MMBtu Good combustion practices and pipeline quality natural gas

Mattawoman Energy Center Brandywine, MD

42 11/13/2015 0.01 lb/MMBtu Good combustion practices and pipeline quality natural gas

Hill Top Energy Center Cumberland Township, PA

42 4/12/2017 0.011 lb/MMBtu Ultra-low NOx burner

CPV Fairview Energy Center Johnston, PA

92.4 9/2/2016 0.011 lb/MMBtu Ultra-low NOx burner, FGR, good combustion practices

CPV St. Charles Waldorf, MD

93 4/23/2014 0.011 lb/MMBtu Ultra-low NOx burner, FGR, exclusive use of nat gas

Hickory Run Energy Station Lawrence, PA

40 4/23/2013 0.011 lb/MMBtu Low NOx burner

Berks Hollow Energy Association Berks, Reading, PA

40 12/17/2013 0.011 lb/MMBtu Low NOx burner

Combustion Controls

Low NOx Burner

The “low NOx burner” (LNB) design generally refers to a set of burner components (e.g. burner register,

atomizing nozzle, diffuser) that are intended to achieve lower NOx by mixing the fuel and combustion air

in a way that limits NOx formation. This is generally done by mixing the combustion air and fuel in

multiple stages, and by utilizing a specially designed nozzle and/or diffuser to achieve a particular flame

pattern.

Flue Gas Recirculation (FGR)

Flue gas recirculation, or FGR, has generally been an effective method of reducing NOx emissions from

gas-fired industrial boilers. With FGR, a portion of the boiler’s exhaust gas is recirculated back to the

burner where it is mixed with combustion air and introduced into the combustion zone. The relatively


PAGE 22

cool flue gas absorbs heat released by the burner flame, thereby lowering peak flame temperatures and

thermal NOx formation. Flue gas recirculation can be accomplished by either using a separate FGR fan to

move the exhaust gases back to the burner, or by using the boiler’s combustion air fan to “induce” the

gases to the burner.

Ultra-Low NOx Burner

Ultra-low NOx burner technology consists of using a combination of lean-premix combustion, fuel

staging, and zoned internal furnace gas recirculation to achieve lower NOx emissions than achieved by

typical low NOx burners and FGR.


Post-combustion technologies include selective catalytic reduction (SCR) and selective non-catalytic

reduction (SNCR).

SCR uses a catalyst to convert NOx to nitrogen gas. An ammonia-based reagent is injected into the

boiler’s combustion gases upstream of the catalyst, and the reactions to remove NOx occur in the

presence of the catalyst. The catalyst allows the ammonia to reduce NOx levels at lower exhaust

temperatures than selective non-catalytic reduction. The optimum temperature range for SCR technology

is typically 600 to 750° F. Thus, most SCR installations have incorporated the catalyst into the heat

recovery section of the boiler to meet the required temperature window. SCR can result in NOx

reductions of up to 90%. However, SCR has a high capital cost and is not economically feasible on

boilers with a heat input capacity of less than 100 MMBtu/hr with low potential NOx emissions due to the

use of natural gas and limited operating hours.

SNCR is based on the chemical reduction of the NO2 molecule into nitrogen and water vapor. SNCR

involves the injection of an ammonia-based reagent directly into the furnace section of the boiler with a

temperature window of 1,600 to 2,100° F. Under these conditions, the reagent will react with and reduce

NOx emissions without the need for a catalyst. Selective non-catalytic reduction reduces NOx up to 70%

in combination with combustion controls. However, SNCR tends to be less effective at lower levels of

uncontrolled NOx. SNCR requires large furnace volumes and residence time for gas mixing in addition to

a specific and stable temperature window in the furnace where the ammonia-based reagent is injected.

The auxiliary boilers will have limited operation and varied load due to their function as well as small

furnace volume, which is not ideal for the required temperature and mixing time. Therefore, REC

concludes that SNCR is not technically feasible.

Evaluation of Technically Feasible Control Options

At stated above, although SCR may be a technically feasible option, REC has not identified any auxiliary

boilers in the 66 MMBtu/hr size range that are equipped with SCR. In addition, SCR is not an

economically feasible option for boilers of this size/limited use and the use of ultra-low NOx

burners/FGR can achieve an emission rate comparable to that of SCR.

Selection of LAER/BAT for NOx

REC’s two auxiliary boilers will be equipped with ultra-low NOx burners or a combination of low NOx

burner technology with FGR to achieve an emission limit of 0.006 lb/MMBtu. In addition, REC will limit

total fuel use to 145,200 MMBtu per year (both boilers combined).


PAGE 23

3.6.2 Carbon Monoxide (CO)

Carbon monoxide forms in combustion devices as a product of incomplete combustion. Production of

CO results when there is a lack of oxygen and insufficient residence time at high enough temperatures to

complete the final step in oxidation. Controlling these factors to decrease CO, however, also tends to

result in increased emissions of NOx. Conversely, a lower NOx emission rate achieved through flame

temperature control may result in higher levels of CO emissions. Thus a balance must be established,

whereby the flame temperature, residence time and excess oxygen are set to achieve the lowest NOx

emission rate possible to comply with LAER while keeping CO emissions to an acceptable level.

3.5.2.1 Identification of CO Control Technologies

There are basically two options for the control of CO emissions from boilers less than 100 MMBtu/hr

heat input: combustion controls and an oxidation catalyst.

The table below identifies CO controls and limits for facilities with natural gas fired auxiliary boilers of

this size in EPA’s RBLC.

TABLE 13 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR CO

FACILITY NAME BOILER SIZE MMBTU/HR PERMIT DATE CO EMISSIONS LIMIT CO CONTROLS

Marshalltown Generation Station (formerly Sutherland), IA

60.1 4/14/2014 0.0164 lb/MMBtu Oxidation catalyst

CPV St. Charles, MD 93 4/23/2014 0.02 lb/MMBtu

Good combustion practices

Renaissance Power, MI 40 11/1/2013 0.036 lb/MMBtu


Wildcat Point Generation, MD 45 4/8/2014 0.036 lb/MMBtu


Hickory Run Energy Station, PA

40 4/23/2013 0.036 lb/MMBtu Good combustion practices

Hill Top Energy Center, PA 42 4/12/2017 0.037 lb/MMBtu


Jackson Energy Center, IL 96 12/31/2018 0.037 lb/MMBtu


Moxie Freedom Generation, PA

55.4 9/1/2015 0.037 lb/MMBtu Good combustion practices



Combustion Controls

CO combustion control performance is a function of available oxygen, combustion temperature,

turbulence, and residence time. Formation of CO is a result of incomplete combustion of the fuel.

Adequate fuel residence time and high temperature in the combustion zone can ensure minimal CO

formation. A properly designed combustion system is effective at limiting CO formation by maintaining

the optimum combustion zone temperature and amount of excess oxygen. Unfortunately, the addition of

excess air and maintenance of high combustion temperatures for control of CO emissions may lead to

increased NOx emissions. Consequently, typical practice is to design the combustion system such that CO

emissions are reduced as much as possible without causing NOx levels to significantly increase.


PAGE 24

Add-on Emission Controls

The only add-on control device that is commercially available for controlling CO emissions from boilers

is an oxidation catalyst. The catalyst lowers the activation energy necessary for CO to react with available

oxygen in the exhaust to produce CO2. Oxidation catalysts operate optimally at a temperature range of

500° to 700° F and can also reduce volatile organic compounds (VOC) emissions, but to a lesser extent

than CO.

Evaluation of CO Control Options

Boiler with oxidation catalyst

Economic Impacts

An economic analysis was performed to identify the cost effectiveness of installing and operating an

oxidation catalyst to reduce CO emissions by approximately 90%. The total capital cost estimate on a per

boiler basis is presented in Table 14 in a format consistent with the cost estimation procedures in EPA’s

Office of Air Quality Planning and standards (OAQPS) Control Cost Manual, sixth edition (January

2002). The total annualized capital investment and annual cost of operating an oxidation catalyst were

calculated using procedures in the OAQPS Control Cost Manual. The annual costs for the construction

and operation of an oxidation catalyst are presented in Table 15.

TABLE 14 OXIDATION CATALYST CAPITAL EXPENSES1

EQUIPMENT COSTS

Oxidation Catalyst $15,1442

Frame and Housing $15,000

Total System (A) $35,144

Freight (0.05A) $1,757

Taxes (0.05A) $1,757

Total purchased equipment cost (B): $22,000

DIRECT INSTALLATION COSTS

Foundations and Supports (0.08B) $3,374

Handling and Erection (0.14B) $5,904

Electrical (0.01B) $422

Total direct installation cost: $9,700

Total Direct Cost: $51,873

INDIRECT COSTS (INSTALLATION)

Engineering and Supervision (0.10B) $4,217

Construction and Field Expenses (0.05B) $2,109

Contractor Fees (0.10B) $4,217

Startup (0.02B) $843

Performance Test (0.01B) $422

Contingencies (0.03B) $1,265


PAGE 25

Total Indirect Cost: $13,074

Total Capital Investment (TCI): $64,946 1Appendix O contains cost calculation sheets 2Cost estimate for catalyst, frame and housing is provided by EmeraChem for a 66 MMBtu/hr boiler

TABLE 15 OXIDATION CATALYST ANNUAL OPERATING COSTS1

DIRECT ANNUAL COST

Operating Labor $160

Supervisory Labor ---

Maintenance Labor and Materials $2,250

Catalyst Replacement (3 year life, 7% interest) $5,353

Spent Catalyst Handling ----

Performance Loss $636

Total direct annual cost: $8,399

INDIRECT ANNUAL COSTS

Overhead (60% total labor and materials) $1,350

Administrative Charges (0.02 TCI) $1,299

Insurance (0.01 TCI) $649

Capital Recovery (10 year at 7% interest) $5,838

(TCI - replacement cost of catalyst = 72,047)

(72,047*0.1424)

Total indirect annual cost: $9,137

Total Annual Costs $17,536

AVERAGE COST EFFECTIVENESS

CO Emissions Removed (tons/year) 1.93

Cost Effectiveness (dollars/ton CO removed) $9,110 1Appendix O contains cost calculation sheets Cost analysis was performed in 2017. It was determined to be unnecessary to update with 2019 estimates as the dollar per ton would increase.

Based on the cost analysis shown in Tables 14 and 15, the average cost effectiveness of an oxidation

catalyst equals $9,110 per ton of CO removed. The dollar per ton value does not support the use of an

oxidation catalyst as BACT/BAT for REC’s auxiliary boilers.

Energy and Environmental Impacts

The increase flow resistance created by the oxidation catalyst results in a pressure drop across the

combustion chamber requiring a corresponding increase in fan speed for the inlet air. The estimated

negative energy impact caused by the pressure drop is as follows:

3.79 kW x 2,200 hours per year = 8,338 kW-hours/year

(note: 3.79 kW is the power requirement based on a pressure drop of 3 psia)


PAGE 26

Environmental impacts would include the increased energy requirements for operation and the waste

generated from the spent catalyst. The marginal environmental benefit associated with reducing CO

emissions by a maximum potential of 1.93 tons per year in the project area does not justify the application

of an oxidation catalyst.

Selection of BACT/BAT for CO

REC proposes good combustion practices and a CO limit of 0.036 lb/MMBtu as BACT/BAT for the

auxiliary boilers.

3.6.3 Volatile Organic Compounds (VOC)

The table below identifies VOC controls and limits for facilities with natural gas fired auxiliary boilers in

EPA’s RBLC with BACT/LAER/BAT limits.

TABLE 16 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR VOC

FACILITY NAME BOILER SIZE MMBTU/HR PERMIT DATE

VOC EMISSIONS LIMIT VOC CONTROLS

Hickory Run Energy Station Lawrence, PA


Berks Hollow Energy Association Berks, PA


CPV St. Charles Waldorf, MD


Keys Energy Center Brandywine, MD


Mattawoman Energy Center Brandywine, MD


Wildcat Point Generation Rising Sun, MD

45 4/8/2014 0.0033 lb/MMBtu Good combustion controls


73.5 8/1/2013 0.0038 lb/MMBtu Good combustion controls

MEC North and MEC South MI


York Energy Center, PA 62 6/15/2015 0.004 lb/MMBtu




Moxie Freedom, PA 55.4 9/1/2015 0.005 lb/MMBtu


Troutdale Energy Center Multnomah, OR


Marshalltown Generating Station (Sutherland), IA



PAGE 27

Identification of VOC Control Technologies

Like CO emissions, VOC emissions occur from incomplete combustion. Effective boiler design and post-

combustion control using oxidation catalysts are the available technologies for controlling VOC

emissions from boilers.

Evaluation of VOC Control Options

Similar to CO, the energy, environmental, and economic impacts of an oxidation catalyst do not support

its use. VOC emissions are lower than CO and the removal efficiency is lower, therefore the dollar per ton

value would be higher than that for CO. In addition, REC did not identify any facilities with an oxidation

catalyst for the control of VOC emissions.

Selection of LAER/BAT for VOC

REC proposes good combustion practices and effective boiler design to meet LAER/BAT for the

auxiliary boilers. The Hickory Run Energy Station and Berks Hollow Energy emission limit for VOC is

lower than other BACT/LAER determinations contained in the RBLC database. REC contacted Ed Orris

and Tom Flaherty of PaDEP’s Northwest Regional Office to request further information on Hickory

Run’s auxiliary boiler. Based on Tom Flaherty’s review of the application, the VOC emission limit was

based on vendor data, however vendor specifications were not included in the application. REC contacted

David Wilson of LS Power (the applicant) who indicated that the emission limit in the Hickory Run

application was taken from LS Power’s application for their Berks Hollow Energy facility. Although the

permit for Berks Hollow was issued after the permit for Hickory Run, the application for Berks Hollow

preceded that of Hickory Run. REC then contacted Thomas Hanlon of PaDEP’s Southcentral Regional

Office to obtain more information on the Berks Hollow auxiliary boiler’s VOC limit. Thomas Hanlon

reviewed the application and did not find any vendor specification data to support the 0.0015 lb/MMBtu

limit. Thomas Hanlon further reviewed the application material and the history of the plan approval

development and based on the following facts has concluded that is it quite possible and likely that the

VOC emission limit was transposed from 0.0051 lb/MMBtu from another LAER determination to 0.0015

lb/MMBtu and was established as the VOC limit for Berks Hollow and Hickory Run’s auxiliary boiler.

• No vendor data is available in either Berks Hollow or Hickory Run’s application to support a

VOC limit of 0.0015 lb/MMBtu.

• Berks Hollow application quoted a LAER determination for Plant McDonough in Smyrna,

Georgia. The LAER limit established for Plant McDonough was 0.0051 lb VOC/MMBtu and is

contained in their current permit.

• Further into the Berks Hollow application the LAER determination was identified as 0.0015

lb/MMBtu instead of 0.0051 lb/MMBtu.

• PaDEP presented the 0.0015 value in the draft plan approval for Berks Hollow.

• Since Berks Hollow and Hickory Run applications were nearly identical and submitted by the

same company and the draft plan approvals were being developed around the same timeframe, for

consistency purposes the two regional offices provided the same limits and requirements in each

plan approval. Therefore, a VOC limit of 0.0015 lb/MMBtu was drafted into the plan approval

for Hickory Run.


PAGE 28

• No comments were received by LS Power for either facility and the 0.0015 lb/MMBtu was

established in the final plan approvals as the VOC limit for the auxiliary boilers.

• Neither facility has been built and the 0.0015 lb/MMBtu limit has not been demonstrated in

practice.

In light of the information summarized above, REC maintains that 0.0015 lb/MMBtu is not LAER for its

auxiliary boilers.

The next lowest emissions limits are for CPV St. Charles and Keys Energy Center. Both facilities are

operating and the VOC limit is 0.002 lb/MMBtu.

REC proposes good combustion practices, effective boiler design, and an emission limit of 0.002

lb/MMBtu as LAER/BAT for its auxiliary boilers.

3.6.4 Particulate Matter (PM)

The table below identifies PM controls and limits for facilities with natural gas fired auxiliary boilers in


TABLE 17 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR PM

FACILITY NAME BOILER SIZE MMBTU/HR PERMIT DATE PM EMISSIONS LIMIT PM CONTROLS

Holland Board of Public Works – East 5th St, MI


Holland Board of Public Works Ottawa, MI


Holland Board of Public Works Ottawa, MI


Thetford Generating Station, MI


Mattawoman Energy Center, MD

42 11/13/2015 0.0019 lb/MMBtu Low sulfur fuel

CPV St. Charles, MD 93 4/23/2014 0.005 lb/MMBtu

Good combustion practices and pipeline quality natural gas

MEC North and MEC South LLC, MI 61.5 6/29/2018 0.005 lb/MMBtu

Good combustion practices and pipeline quality natural gas

Identification of PM Control Technologies

PM emission rates from natural gas combustion are inherently low because of very high combustion

efficiencies and the clean burning nature of natural gas. Best combustion practices will ensure proper

air/fuel mixing ratios to achieve complete combustion, minimizing emissions of unburned hydrocarbons

that can lead to the formation of PM emissions. There are several post combustion technologies for the

control of PM emissions that are generally available, however none are considered practical or technically

and economically feasible for natural gas fired boilers of this size.


PAGE 29

Evaluation of PM Control Options

EPA’s RBLC database research indicates that there are no BACT precedents for TSP/PM10 requiring add-

on controls, which supports the only PM control option available for auxiliary boilers of this size is low

sulfur, pipeline quality natural gas and good combustion practices. The emission limit of 0.0018

lb/MMBtu for The Holland Board of Public Works and Thetford Generating Station boilers is based on

EPA’s AP-42.

Selection of BAT for PM

BACT/BAT for TSP/PM10 is proposed to be the use of low sulfur, pipeline quality natural gas and

efficient combustion. REC proposes to meet an emission limit of 0.0019 lb/MMBtu (filterable only)

which is based on an AP-42 emission factor of 1.9 lb/106 SCF. The four RBLC entries of 0.0018

lb/MMBtu are also based on AP-42 with emission factor conversion and rounding the reason for the

slightly lower limit.


The table below identifies SO2 and Sulfuric acid mist controls and limits for facilities with natural gas

fired auxiliary boilers in EPA’s RBLC with BACT/LAER/BAT limits.

TABLE 18 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR SO2


SO2 EMISSIONS LIMIT SO2 CONTROLS

Wildcat Point Generation, MD 45 4/8/2014 0.0006 lb/MMBtu

Low sulfur fuel

Brunswick County Power Station, MD

66.7 3/12/2013 0.0011 lb/MMBtu Low sulfur fuel

C4GT, LLC 105 4/26/2018 0.0012 lb/MMBtu Low sulfur fuel

Hickory Run Energy Station, PA

40 4/23/2013 0.0021 lb/MMBtu Low sulfur fuel

CVP Valley Energy Center 48.1 8/1/2013 0.0022 lb/MMBtu Low sulfur fuel


H2SO4 EMISSIONS LIMIT H2SO4 CONTROLS

Marshalltown Generating Station, IA

60.1 4/14/2014 8.3 x 10-5 lb/MMBtu Low sulfur fuel

Harrison Power, OH 44.6 4/19/2018 9.0 x 10-5 lb/MMBtu Low sulfur fuel

Wildcat Point Generation, MD 45 4/8/2014 9.0 x 10-5 lb/MMBtu Low sulfur fuel



Brunswick County Power Station, MD


Selection of BACT/BAT for SO2 and H2SO4

SO2 and SO3 are formed during the combustion process as a result of thermal oxidation of sulfur

contained in the fuel. SO3 combines with water vapor released during combustion to form sulfuric acid

(H2SO4) vapor. The only technically and economically feasible technology available to control SO2 and

H2SO4 and from auxiliary boilers of this size is the use of low sulfur fuel, in addition to a limit on total


PAGE 30

fuel use of 145,200 MMBtu per year for both boilers. REC proposes to meet a BACT emission limit for

SO2 of 0.00058 lb/MMBtu and the BACT identified emissions limit of 9.0 x 10-5 lb/MMbtu for H2SO4

emissions.

3.6.6 Identification of BACT for Greenhouse Gas (GHG) Emissions

The only feasible option for reducing GHG emissions from the auxiliary boilers is to use natural gas,

which is the fuel with the lowest pollutant emissions. In addition, emissions will be minimized since REC

is requesting a limit on fuel use.

3.7 BACT/LAER/BAT Determination For Emergency Generator And Fire Pump Diesel Engines

REC is proposing to install one 1,500 kW diesel emergency generator to supply emergency power for the

facility’s critical electrical loads in the event of a power outage. Diesel fired compression ignition

emergency engine generators are proposed as the only technical feasible option to provide critical

electrical loads during a power outage. Natural gas fired generators are not a practical option because in

the event that a power grid outage and a natural gas outage occur at the same time, REC would not have

the necessary power it would need to operate the facility. In addition, REC is proposing a 237 HP diesel

engine powered fire water pump as required by fire codes to provide backup fire water pumping pressure

in the event of a failure of the primary pump systems.

REC’s emergency generator engine and firewater pump engine will each be fired with ultra-low sulfur

diesel (ULSD) containing no more than 0.0015 percent sulfur by weight. Excluding emergencies, each

diesel engine will operate no more than 100 hours per year for testing and maintenance purposes.

REC reviewed LAER and BACT determinations published in the RBLC, PaDEP’s General Plan

Approval for Diesel Internal Combustion Turbines (BAQ-GPA/GP 9), in addition to guidelines and

determinations from three California districts as follows:

• Bay Area Air Quality Management District (BAAQMD) BACT Guideline for emergency CI

internal combustion (IC) engines >50 hp

http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

• San Joaquin Valley Air Quality Management District (SJVAQMD) BACT Guideline 3.1.1 for

emergency diesel IC engines

www.valleyair.org/busind/pto/bact/chapter3.pdf

• South Coast Air Quality Management District (SCAQMD) LAER/BACT Determinations for

emergency CI engines

http://aqmd.gov/bact/aqmdbactdeterminations.htm

Current BAAQMD, SCAQMD, and SJVAQMD BACT guidelines all require new stationary emergency

CI engines to meet applicable EPA NSPS or CARB tier standards for NOx, CO, PM10, and VOC. These

same guidelines require the use of ULSD to control SO2 emissions.

The potentially available control options for reducing emissions from diesel engine emergency generators

and fire pump engines include combustion controls, selective catalytic reduction SCR), and non-selective

catalytic reduction (NSCR). Combustion controls are implemented in the design of the engine. Typical

design features include electronic engine controls, injection systems, combustion chamber geometry, and

turbocharging systems. New engines are designed with these features as standard equipment.

http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

file://///frefs1/enviro/Projects/137575_RENOVO_ENERGY_AIR_QUAL_SERVICE/PER/02%20Environmental/02%20Resources/09%20Air%20Quality%20&%20EC/Application_REV/www.valleyair.org/busind/pto/bact/chapter3.pdf

http://aqmd.gov/bact/aqmdbactdeterminations.htm


PAGE 31

Based on a review of EPA’s RBLC and other permits, no add-on controls were identified for diesel

engines of this size and limited operation (see Tables 19, 20, 21, and 22). SCR is a post-combustion NOx

reduction technology and uses ammonia to react with NOx in the gas stream in the presence of a catalyst

to form nitrogen and water. SCR has not been a demonstrated NOx control technology for emergency use

engines. SCR would not be economically feasible based on a cost per ton of pollutant controlled

considering the minimal emissions due to limited use of the engines. In addition, SCR is not technically

feasible for engines requiring quick start-ups and short operating periods. NSCR is not effective in

controlling emissions from lean burn engines and would not be an appropriate control technology since

diesel engines inherently operate lean. According to EPA’s AP-42 Section 3.2.4.1, “the NSCR technique

is effectively limited to engines with normal exhaust oxygen levels of 4 percent or less. This includes 4-

stroke rich-burn naturally aspirated engines and some 4-stroke rich-burn turbocharged engines. Engines

operating with NSCR require tight air-to-fuel control to maintain high reduction effectiveness without

high hydrocarbon emissions. To achieve effective NOx reduction performance, the engine may need to be

run with a richer fuel adjustment than normal. This exhaust excess oxygen level would probably be closer

to 1 percent. Lean-burn engines could not be retrofitted with NSCR control because of the reduced

exhaust temperatures”. Therefore, the only feasible control technology for the diesel fired emergency

engines is combustion controls.

3.7.1 Identification of Sources with BACT/LAER/BAT

Table 19 provides a summary of the RBLC database findings for NOx; detailed information on each entry

is provided in Appendix M.


FACILITY NAME ENGINE SIZE

PERMIT DATE

NOX EMISSION RATE (G/BHP-HR) COMMENTS

EMERGENCY GENERATOR ENGINE

CPV Fairview Energy Center, PA 1500 kW 6/2/2016 4.8 Good combustion practices and NSPS Subpart IIII

CPV St. Charles, MD 1500 kW 4/23/2014 4.8 Good combustion practices and NSPS Subpart IIII

St. Joseph Energy Center, IN 1006 and 2012 hp

12/3/2012 4.8 Good combustion practices and NSPS Subpart IIII

Jackson Energy Center, IL 1500 kW 12/31/2018 4.8 Good combustion practices and NSPS Subpart IIII

Keys Energy Center, MD 1500 kW 10/31/2014 4.8 Good combustion practices and NSPS Subpart IIII

EMERGENCY FIRE PUMP ENGINE

Moxie Energy LLC, Patriot and Asylum, PA

460/460 hp 1/31/2013 10/10/2012

2.6 Good combustion practices

C4GT, LLC, VA 315 hp 4/26/2018 3.0 Good combustion practices

MEC North, LLC and MEC South, LLC MI

300 hp 6/29/2018 3.0 Good combustion practices and NSPS Subpart IIII

Thetford Generating Station 315 hp 7/25/2013 3.0 Proper combustion design

St. Joseph Energy Center 371 hp 12/3/2012 3.0 Combustion design controls and usage limit


PAGE 32

Table 20 provides a summary of the RBLC database findings for CO; detailed information on each entry



FACILITY NAME ENGINE SIZE PERMIT DATE

CO EMISSION RATE (G/BHP-HR) COMMENTS

EMERGENCY GENERATOR ENGINES


1464/1474 hp 1/31/2013 10/10/2012


Moxie Energy LLC, Freedom, AP 1000 kW 9/1/2015 0.26 Good combustion practices

CPV Valley Energy Center, NY 1495 hp 8/1/2013 0.45 Good combustion practices

Lackawanna Energy Center, PA 2000 kW 12/23/2015 0.6 Good combustion practices

CPV St. Charles, MD 1500 kW 4/23/2014 2.6 Good combustion practices


Lackawanna Energy Center, PA 315 hp 12/23/2015 0.5 Good combustion practices


460/460 hp 1/31/2013 10/10/2012


Moxie Freedom, LLC PA 510 hp 9/1/2015 1 Good combustion practices

CPV St. Charles 300 hp 4/23/2014 2.6 Good combustion practices

Thetford Generating Station, Genesee, MI

315 hp 7/25/2013 2.6 Proper combustion design

Table 21 provides a summary of the RBLC database findings for VOC; detailed information on each

entry is provided in Appendix M.



VOC EMISSION RATE (G/BHP-HR) COMMENTS



1464/1474 hp 1/31/2013 12/13/2013


Moxie Freedom 1000 kW 9/1/2015 0.02 Good combustion practices


Mooreland Generating Station 1341 hp 7/2/2013 0.318 Good combustion practices

Ninemile Point Electric Generating 2000 kW 8/16/2011 1 Good combustion practices



460/460 hp 1/31/2013 10/10/2012


Lackawanna Energy Center, PA 315 hp 12/23/2015 0.12 Combustion controls

Moxie Freedom, LLC PA 510 hp 9/1/2015 0.2 Good combustion practices

Table 22 provides a summary of the RBLC database findings for PM; detailed information on each entry



PAGE 33



PM EMISSION RATE (G/BHP-HR) COMMENTS



CPV Valley Energy Center, NY 1495 hp 8/1/2013 0.03 Good combustion practices

CPV St. Charles, MD 1500 kW 4/23/2014 0.15 Good combustion practices

St. Joseph Energy Center, IN 1006 and 2012 hp

12/3/2012 0.15 Good combustion practices


Lackawanna Energy Center, PA 315 hp 12/23/2015 0.11 Good combustion practices

MEC North, LLC and MEC South, LLC MI

300 hp 6/29/2018 0.15 Good combustion practices

CPV St. Charles 300 hp 4/23/2014 0.15 Good combustion practices

Thetford Generating Station, Genesee, MI

315 hp 7/25/2013 0.15 Good combustion practices

3.7.2 Selection of BACT/LAER/BAT For Emergency Generator And Fire Pump Engine

REC is proposing that BACT/LAER/BAT for the emergency generator engine and fire pump engine is

state of the art design with good combustion practices and compliance with the Tier standards contained

in 40 CFR Part 60 Subpart IIII for emergency engines of the sizes proposed. Tier 2 standards will apply to

the emergency generator engine and Tier 3 standards will apply to the fire pump engine. The following

table summarizes REC’s proposed BACT/LAER/BAT emission limits for each device. NOx, CO, and

PM limits for the generator are based on nominal vendor data and EPA’s weighted emissions calculator

for constant speed engines (40 CFR Part 89, Table 2 of Appendix B to Section E). Generator engine VOC

limit is based on maximum calculated emission rate provided by the vendor. For the fire pump engine,

NOx, CO, VOC, and PM limits are based on vendor data.

TABLE 23 SUMMARY OF PROPOSED BACT/LAER/BAT

DEVICE NOX (G/HP-HR)

HC (G/HP-HR)

CO (G/HP-HR)

PM (G/HP-HR)

Emergency generator engine 4.48 0.8 1.23 0.13

Fire pump engine 2.7 0.10 0.90 0.10

REC is proposing to limit the operation of the emergency generator engine to 500 hours per year and the

operation of the fire pump engine to 250 hours per year. Both engines will fire ultra-low sulfur diesel with

a maximum sulfur content of 0.0015%. Based on the proposed limits and operating hours, potential

emissions are provided in Table 24:

TABLE 24 POTENTIAL EMISSIONS

DEVICE NOX (TPY)

HC (TPY)

CO (TPY)

PM (TPY)

SOX (TPY)

Emergency generator engine 5.45 0.97 1.50 0.16 0.0055

Fire pump engine 0.18 0.007 0.06 0.007 0.0003


PAGE 34

Based on the RBLC review, a few facilities have been identified with emission limits that are lower than

the standards REC is proposing.

The facilities with lower emission limits initially proposed compliance with the NSPS standards and

provided vendor data to support their applications. The vendor data included “nominal” emission rates

which are subject to instrumentation, measurement, facility and engine to engine variations and are not

guaranteed by the vendor. The permitting agencies established the nominal emission rates as limits in the

permit. Based on discussions with engine manufacturer representatives, any emissions data that is

provided by the vendor and is subject to variations is not guaranteed by the manufacturer and should not

be established as emission limits in a permit because the rates may not be able to be demonstrated in

practice for any given engine. Typically, engine manufacturers test one representative engine to

demonstrate compliance with EPA’s Tier Standards. The testing is conducted under specific, controlled

conditions. There is usually a suitable margin between the test results and the standards to allow for

engine deterioration. The engine manufacturers certify to the Tier standards, not to the test results. At this

time, regulatory agencies typically do not require facilities to demonstrate compliance with emergency

engine emission limits, however it is important to establish rates that are reasonably achievable in

practice, in the event that emission testing is required at a future time. Therefore, REC is disregarding the

lower limits since they are based on nominal data and not certified or guaranteed by the manufacturer of

the engines.

In conclusion, REC is proposing to meet BACT/LAER/BAT by complying with proposed emission limits

contained in Table 23. In addition, REC will limit the operating hours of the emergency generator engine

to 500 hours per year and 250 hours per year for the fire pump engine. Both engines will fire ultra-low

sulfur diesel with a maximum sulfur content of 0.0015%. Regarding greenhouse gas emissions,

BACT/LAER/BAT for these engines is limiting the hours of operation.

3.8 BACT/LAER/BAT Determination Water Bath Heaters

REC is proposing to install three water bath heaters each with a maximum rated heat input of 15

MMBtu/hr firing natural gas. Only two heaters will be operating at a given time, the third is for backup

only. The function of the water bath heaters are to provide heat to incoming natural gas pipelines to

increase the temperature of the incoming gas to prevent freezing of the gas regulating valves under certain

gas system operating conditions. The heater will be permitted to operate up to 8,760 hours per year,

although they will not be necessary to operate at full capacity during warmer weather.


NOx is formed during combustion by thermal oxidation of nitrogen in the combustion air (thermal NOx)

and the oxidation of nitrogen in the fuel (fuel-bound NOx). Natural gas contains relatively small amounts

of fuel-bound nitrogen, thus NOx formation through the fuel NOx mechanism is expected to be

insignificant. The main variables affecting NOx generation in the heater are temperature, the availability

of nitrogen, the availability of oxygen, and the extent of contact between nitrogen and oxygen during the

combustion process.

Identification of NOx Control Technologies

NOx control techniques are generally organized into two separate categories: combustion controls and

post-combustion controls. Combustion controls affect the combustion conditions to minimize the

formation of NOx, while post-combustion controls remove NOx after it is formed. Combustion control


PAGE 35

techniques have been demonstrated as successful in achieving NOx reductions from heaters in a cost-

effective manner. The combustion control method available to control thermal NOx on water bath heaters

is low NOx burner technology.

A search of EPA’s RBLC did not identify the application of post-combustion controls to natural gas fired

water bath heaters. Table 25 below identifies the facilities in EPA’s RBLC with BACT/LAER/BAT

limits.


FACILITY NAME HEATER SIZE (MMBTU/HR) PERMIT DATE

NOX EMISSIONS LIMIT NOX CONTROLS

Jackson Energy Center, IL 13 12/31/2018 0.011 lb/MMBtu

Low NOx combustion technology


12.8 7/30/2018 0.011 lb/MMBtu

Low NOx burners


14.6 9/1/2015 0.011 lb/MMBtu

Good combustion


13.8 9/2/2016 0.011 lb/MMBtu

Good combustion

Cheyenne Prairie Generating Station, WY

16.1 8/28/2012 0.012 lb/MMBtu

Ultra low NOx burners

Combustion Controls

Low NOx Burner

The “low NOx burner” (LNB) generally refers to a set of burner components (e.g. burner register,

atomizing nozzle, diffuser) that are designed to achieve lower NOx by mixing the fuel and combustion air

in a way that limits NOx formation. This is generally done by mixing the combustion air and fuel in

multiple stages, and by utilizing a specially designed nozzle and/or diffuser to achieve a particular flame

pattern.


Post-combustion technologies include SCR and SNCR.

SCR uses a catalyst to convert NOx to nitrogen gas. An ammonia-based reagent is injected into the

heater’s combustion gases upstream of the catalyst, and the reactions to remove NOx occur in the

presence of the catalyst. The catalyst allows the ammonia to reduce NOx levels at lower exhaust

temperatures than selective non-catalytic reduction. The optimum temperature range for SCR technology

is typically 600 to 750° F. SCR can result in NOx reductions of up to 90%. However, SCR has a high

capital cost and is not economically feasible on heaters with a heat input capacity of less than 100

MMBtu/hr with low NOx emissions due to the use of natural gas.

SNCR is based on the chemical reduction of the NO2 molecule into nitrogen and water vapor. SNCR

involves the injection of an ammonia-based reagent directly into the furnace section with a temperature

window of 1,600 to 2,100° F. Under these conditions, the reagent will react with and reduce NOx

emissions without the need for a catalyst. Selective non-catalytic reduction reduces NOx up to 70% in

combination with combustion controls. However, SNCR tends to be less effective at lower levels of


PAGE 36

uncontrolled NOx. SNCR requires large furnace volumes and residence time for gas mixing in addition to

a specific and stable temperature window in the furnace where the ammonia-based reagent is injected.

Due to the large furnace requirements, SNCR is technically feasible. In addition, it is not an economically

feasible option for heaters of this size.

Evaluation of Technically Feasible Control Options

REC has not identified any water bath heaters in the 15 MMBtu/hr size range that are equipped with SCR

or SNCR. In addition, post control technology is not an economically feasible option for heaters of this

size. The use of low NOx burners and good combustion practices are the top control options.

Selection of LAER/BAT for NOx

REC’s water bath heaters will be equipped with low NOx burners to achieve an emission limit of 0.011

lb/MMBtu.

3.8.2 Carbon Monoxide (CO)

Carbon monoxide forms in combustion devices as a product of incomplete combustion. Production of CO

results when there is a lack of oxygen and insufficient residence time at high enough temperatures to

complete the final step in oxidation. Controlling these factors to decrease CO, however, also tends to

result in increased emissions of NOx. Conversely, a lower NOx emission rate achieved through flame

temperature control may result in higher levels of CO emissions. Thus a balance must be established,

whereby the flame temperature, residence time and excess oxygen are set to achieve the lowest NOx

emission rate possible to comply with LAER while keeping CO emissions to an acceptable level.

Identification of CO Control Technologies

There are basically two options for the control of CO emissions from water bath heaters less than 100

MMBtu/hr heat input: combustion controls and oxidation catalyst.

The table below identifies CO controls and limits for facilities with natural gas fired water bath heaters in



FACILITY NAME HEATER SIZE MMBTU/HR PERMIT DATE CO EMISSIONS LIMIT CO CONTROLS





Sunbury Generation, PA 15 4/1/2013 0.037 lb/MMBtu Good combustion practices

Marshalltown Generating Station, IA


Cheyenne Prairie Generating Station, WY



PAGE 37

Combustion Controls

CO combustion control performance is a function of available oxygen, combustion temperature,

turbulence, and residence time. Formation of CO is a result of incomplete combustion of the fuel.

Adequate fuel residence time and high temperature in the combustion zone can ensure minimal CO

formation. A properly designed combustion system is effective at limiting CO formation by maintaining

the optimum combustion zone temperature and amount of excess oxygen. Unfortunately, the addition of

excess air and maintenance of high combustion temperatures for control of CO emissions may lead to

increased NOx emissions. Consequently, typical practice is to design the combustion system such that CO

emissions are reduced as much as possible without causing NOx levels to significantly increase.

Add-on Emission Controls

The only add-on control device that is commercially available for controlling CO emissions from water

bath heaters is an oxidation catalyst. The catalyst lowers the activation energy necessary for CO to react

with available oxygen in the exhaust to produce CO2. An oxidation catalyst can also reduce VOC

emissions, but to a lesser extent than CO. Oxidation catalysts operate optimally at a temperature range of

500° to 700° F.

Evaluation of CO Control Options

Oxidation catalysts are not an economically feasible option for water bath heaters of this size and REC is

not aware of any current installations on water bath heaters around 15 MMBtu/hr. Good combustion

practices is the BACT/BAT available control option for CO from REC’s water bath heaters.

Selection of BACT/BAT for CO

REC proposes good combustion practices and a CO limit of 0.037 lb/MMBtu as BACT/BAT for the

water bath heaters. The only lower rate identified is for Mattawoman Energy Center that has not been

built.

3.8.3 Volatile Organic Compounds (VOC)

The table below identifies VOC controls and limits for facilities with natural gas fired water bath heaters

in EPA’s RBLC with BACT/LAER/BAT limits.


FACILITY NAME HEATER SIZE MMBTU/HR PERMIT DATE


Guernsey Power Station, OH 15 10/23/2017 0.005 lb/MMBtu Good combustion practices

Seminole Generating Station, FL


CPV St. Charles, MD 9.5 4/23/2014 0.005 lb/MMBtu Good combustion practices



Belle River Combined Cycle Power Plant, MI



PAGE 38



Renaissance Power, MI 20 11/1/2013 0.05 lb/MMBtu Good combustion practices

Identification of VOC Control Technologies

Like CO emissions, VOC emissions occur from incomplete combustion. Effective heater design and post-

combustion control using oxidation catalysts are the available technologies for controlling VOC

emissions from water bath heaters.

Evaluation of VOC Control Options

Similar to CO, the economic impacts of an oxidation catalyst do not support its use. VOC emissions are

lower than CO and the removal efficiency is lower, therefore the dollar per ton value would be higher

than that for CO. In addition, REC did not identify any facilities with an oxidation catalyst for the control

of VOC emissions.

Selection of LAER/BAT for VOC

REC proposes good combustion practices, effective heater design, and an emission limit of 0.005

lb/MMBtu as LAER/BAT for its water bath heaters.

3.8.4 Particulate Matter (PM)

The table below identifies PM controls and limits for facilities with natural gas fired water bath heaters in



FACILITY NAME HEATER SIZE MMBTU/HR PERMIT DATE PM EMISSIONS LIMIT PM CONTROLS

Thetford Generating 12 7/25/2013 0.0018 lb/MMBtu Good combustion practices



Indeck Niles, LLC, MI 13.5 1/4/2017 0.002 lb/MMBtu Good combustion practices

Renaissance Power, MI 20 11/1/2013 0.009 lb/MMBtu Good combustion practices

Belle River Combined Cycle Power Plant, MI

20.8 7/16/2018 0.15 lb/hr Good combustion practices

Identification of PM Control Technologies

PM emission rates from natural gas combustion are inherently low because of very high combustion

efficiencies and the clean burning nature of natural gas. Best combustion practices will ensure proper

air/fuel mixing ratios to achieve complete combustion, minimizing emissions of unburned hydrocarbons

that can lead to the formation of PM emissions. There are several post combustion technologies for the


PAGE 39

control of PM emissions that are generally available, however none are considered practical or technically

and economically feasible for water bath heaters of this size.

Evaluation of PM Control Options

EPA’s RBLC database research indicates that there are no BACT precedents for PM requiring add-on

controls for a natural gas fired water bath heaters of this size. Therefore, the only PM control option

available for water bath heaters of this size is low sulfur, pipeline quality natural gas and good

combustion practices.

Selection of BAT for PM

BACT/BAT for PM is proposed to be the use of low sulfur, pipeline quality natural gas and efficient

combustion. REC proposes to meet an emissions limit of 0.0019 lb/MMBtu which is identical to the limit

proposed for the natural gas fired auxiliary boilers and is based on AP-42.


The table below identifies SO2 and sulfuric acid mist controls and limits for facilities with natural gas

fired water bath heaters in EPA’s RBLC with BACT/LAER/BAT limits.

TABLE 29 IDENTIFICATION OF SOURCES WITH BACT/LAER/BAT FOR SO2

FACILITY NAME HEATER SIZE MMBTU/HR PERMIT DATE SO2 EMISSIONS LIMIT SO2 CONTROLS

Berks Hollow Energy, PA 8.5 12/17/2013 0.002 lb/MMBtu Low sulfur pipeline natural gas


9 8/1/2013 0.0022 lb/MMBtu Low sulfur pipeline natural gas

Sunbury Generation LP, PA 15 4/1/2013 0.003 lb/MMBtu

Low sulfur pipeline natural gas

Indeck Niles, LLC, MI 13.5 1/4/2017 0.2 grains/100 scf

Low sulfur pipeline natural gas


H2SO4 EMISSIONS LIMIT H2SO4 CONTROLS


14.6 9/1/2015 0.0001 lb/MMBtu Good combustion practices and pipeline natural gas

Guernsey Power Station, OH 15 10/23/2017 0.0002 lb/MMBtu Good combustion practices and pipeline natural gas

Jackson Energy Center, IL 13 12/31/2018 0.001 lb/MMBtu Good combustion practices and pipeline natural gas


12.8 7/30/2018 0.001 lb/MMBtu Good combustion practices and pipeline natural gas


PAGE 40

Selection of BACT/BAT for SO2 and H2SO4

SO2 and SO3 are formed during the combustion process as a result of thermal oxidation of sulfur

contained in the fuel. SO3 combines with water vapor released during combustion to form sulfuric acid

(H2SO4) vapor. The only technically and economically feasible technology available to control SO2 and

H2SO4 and from water bath heaters of this size is the use of low sulfur fuel. To allow for consistency with

the BACT/BAT determination for the auxiliary boilers, REC proposes to meet 0.0005 lb/MMBtu for SO2

from the water bath heaters. REC will meet a BACT emission limit for H2SO4 of 0.001 lb/MMbtu. In

addition, emissions will be minimized through the use of low sulfur content natural gas.

3.8.6 Identification of BACT for Greenhouse Gas (GHG) Emissions

The only feasible option for reducing GHG emissions from the water bath heaters is to use natural gas,

which is the fuel with the lowest pollutant emissions.

3.9 High Voltage Circuit Breakers Equipment Leaks BACT/BAT Analysis

REC will have twelve high voltage circuit breakers within the facility’s electrical switchyard. Six circuit

breakers will contain 345 pounds of sulfur hexafluoride (SF6) and the remaining six circuit breakers will

contain 165 pounds of SF6. SF6 is a highly effective electrical insulating dielectric fluid used for

interrupting arcs and is superior to other dielectric fluids. SF6 is a greenhouse gas with a “global warming

potential” of 22,800 on a 100-year time horizon, which means its impact as a greenhouse gas is 22,800

times greater than that of CO2.

REC’s circuit breakers will be designed as totally enclosed pressure systems with low potential SF6

fugitive emissions (equipment leaks). Leakage is expected to be minimal and equipment will be built to

low leakage design limits. The International Electrotechnical Commission Standard 62271-1 for new

equipment leakage is 0.5% per year.

3.9.1 Identification of Control Options

Three control options have been identified for the SF6 emissions from circuit breakers:

• Use of vacuum circuit breakers;

• Use of alternatives to SF6 such as dielectric oil or compressed air (air blast) circuit breakers; and

• Use of state-of-the-art enclosed pressure SF6 circuit breakers with leak detection monitoring.

3.9.2 Evaluation of Control Options

The use of vacuum circuit breakers is not a technically feasible option currently. Vacuum circuit breakers

are used for medium voltage levels and aren’t currently designed for use with high voltage circuit

breakers which are being proposed for REC.

An alternative to SF6 would be the use of a dielectric oil or compressed air (air blast) circuit breakers.

This option is technically feasible, however SF6 has become the predominant insulator and arc quenching

substance because of its superior performance. SF6 breakers replaced oil and air-blast breakers because of

their superior performance, but also because of other issues with oil and air blast breakers. The


PAGE 41

disadvantage of oil breakers are issues with flammability (safety) and the high maintenance costs

associated with oil replacement requirements. Oil in circuit breakers is degraded by small quantities of

water as well as carbon deposits from the carbonization that occurs when the oil comes into contact with

the electric arc. Air-blast circuit breakers require the installation of expensive compressor stations, are

quite large, and create a high level of noise during operation. The air has relatively lower arc

extinguishing properties and there is a chance of air pressure leakage from the air pipes junction and a

chance of re-striking voltage and current chopping.

EPA’s SF6 Emission Reduction Partnership for Electric Power Systems, a public-private partnership

managed by EPA that is focused on reducing SF6 emissions, does not advocate for a return to oil or air-

blast breakers for high voltage applications, but instead has focused on equipment leak detection and

repair education for SF6 handlers, plus replacement of older SF6 circuit breakers with new SF6 breakers.

The Partnership’s 2014 Annual Report states “Because there is no clear alternative to SF6, Partners reduce

their greenhouse gas emissions through implementing emission reduction strategies such as detecting,

repairing, and/or replacing problem equipment, as well as educating gas handlers on proper handling

techniques of SF6”. (EPA Partnership for Electric Power Systems, 2014 Annual Report, March 2015)

3.9.3 Selection of BACT/BAT

REC proposes the use of state-of-the-art enclosed pressure SF6 circuit breaker technology with a

guaranteed leak rate of less than 0.5% by weight per year as BACT/BAT. In addition, REC’s units will be

equipped with a leak detection monitor that will alarm when a circuit breaker loses 10% of the SF6. REC

will implement routine inspection and maintenance procedures to insure proper circuit breaker operation.

This BACT determination is consistent with other recent determinations for fugitive SF6 emissions from

circuit breakers at power plants, including Jackson Energy Center (Illinois), Shady Hills Combined Cycle

Facility (Florida), CPV Three Rivers Energy Center (Illinois), Dania Beach Energy Center (Florida),

Marshalltown Generating Station (Iowa), and St. Joseph Energy Center (Indiana).

3.10 LAER/BACT/BAT Determination for ULSD Storage Tank

VOC emissions from petroleum storage vessels result from the vaporization of volatile compounds within

the stored product due to changes in temperature, pressure, and liquid level. Several different types of

tank design are available for liquid petroleum storage, depending on the type of liquid petroleum stored.

ULSD is typically stored in fixed roof tanks, with or without an internal floating roof. The presence of an

internal floating roof significantly reduces the space available for the volatile compounds to vaporize, and

evaporative losses only come from deck fittings, seams, and the small amount of space between the deck

and tank wall.

3.10.1 Identification of Sources with BACT/LAER/BAT

Table 30 provides a summary of the RBLC database findings for VOC; detailed information on each

entry is provided in Appendix M.


FACILITY NAME TANK SIZE (GALLONS)

PERMIT DATE

LIQUID STORED COMMENTS

Phillips 66 Pipeline 8,400,000 1/23/2015 ULSD Low vapor pressure material

Baton Rouge Junction Facility, LA

10,000,000 11/2/2009 ULSD Submerged fill line


PAGE 42

FACILITY NAME TANK SIZE (GALLONS)

PERMIT DATE

LIQUID STORED COMMENTS

Lauderdale Plant, FL 3,360,000 6,300,000 3,150,000

4/22/2014 ULSD Pressure relief valves and vapor condensers or floating roof tanks

Lauderdale Plant, FL 3,000,000 (2)

8/25/2015 ULSD Low vapor pressure prevents evaporative losses

Donlin Gold Project 2,500,000 6/30/2017 ULSD Submerged fill line

Troutdale Energy Center, LLC, OR

2,200,000 3/5/2014 ULSD Submerged fill line

3.10.2 Selection of BACT/LAER/BAT for ULSD Storage Tank

REC is proposing the use of an internal floating roof tank (fixed roof) to minimize VOC emissions from

the storage of ULSD. With annual potential emissions of VOC of approximately 0.05 tons, this will

effectively limit the emissions of VOC from the ULSD storage tank.

POWER ENGINEERS, INC. Plan Approval Application – Air Dispersion Modeling Plan – Renovo Energy Center, LLC

PAGE 1


Renovo Energy Center (REC) is submitting an air dispersion modeling protocol to the Pennsylvania

Department of Environmental Protection (PaDEP) simultaneously with this Plan Approval Application.

The protocol outlines the methodologies and assumptions to be used in the refined ambient air quality

impact analysis that will be used to demonstrate compliance with all applicable ambient air quality

standards.

Upon acceptance of the air dispersion modeling protocol, REC will conduct refined dispersion modeling

and will submit a summary report to PaDEP that provides the model results.


5.0 APPLICATION FORMS

2700-PM-AQ0004 Rev. 6/2006

- 1 -

COMMONWEALTH OF PENNSYLVANIA

DEPARTMENT OF ENVIRONMENTAL PROTECTION

BUREAU OF AIR QUALITY

AIR POLLUTION CONTROL ACT COMPLIANCE REVIEW FORM

Fully and accurately provide the following information, as specified. Attach additional sheets as necessary.

Type of Compliance Review Form Submittal (check all that apply)

Original Filing Date of Last Compliance Review Form Filing:

Amended Filing / /

Type of Submittal

New Plan Approval New Operating Permit Renewal of Operating Permit

Extension of Plan Approval Change of Ownership Periodic Submission (@ 6 mos)

Other:

SECTION A. GENERAL APPLICATION INFORMATION

Name of Applicant/Permittee/(“applicant”)

(non-corporations-attach documentation of legal name)

Renovo Energy Center LLC

Address 12011 Sunset Hills Road, Suite 110-RO1

Reston, VA 20190

Telephone (571) 392-6383 Taxpayer ID# 47-2181250

Permit, Plan Approval or Application ID#

Identify the form of management under which the applicant conducts its business (check appropriate box)

Individual Syndicate Government Agency

Municipality Municipal Authority Joint Venture

Proprietorship Fictitious Name Association

Public Corporation Partnership Other Type of Business, specify below:

Private Corporation Limited Partnership

Describe below the type(s) of business activities performed.

Renovo Energy Center, LLC (REC) proposes to construct a nominally rated 1,240 MW (net) dual fuel (natural gas and ultra-low sulfur diesel) combined cycle electric generating plant in Renovo, PA The proposed REC facility will consist of two 1-on-1 power blocks consisting of a combustion turbine and a steam turbine in line to produce electricity for distribution into the transmission grid system. Each combined cycle system consists of a natural gas fired combustion turbine (CT) and heat recovery steam generator (HRSG) equipped with a natural gas-fired duct burner (DB).

2700-PM-AQ0004 Rev. 6/2006

- 2 -

SECTION B. GENERAL INFORMATION REGARDING “APPLICANT”

If applicant is a corporation or a division or other unit of a corporation, provide the names, principal

places of business, state of incorporation, and taxpayer ID numbers of all domestic and foreign parent

corporations (including the ultimate parent corporation), and all domestic and foreign subsidiary

corporations of the ultimate parent corporation with operations in Pennsylvania. Please include all

corporate divisions or units, (whether incorporated or unincorporated) and privately held corporations. (A

diagram of corporate relationships may be provided to illustrate corporate relationships.) Attach

additional sheets as necessary.

Unit Name Principal Places

of Business

State of

Incorporation Taxpayer ID

Relationship

to Applicant

Bechtel Development Company, Inc.

Virginia Delaware 94-3288883 Parent of Applicant

Bechtel Enterprises Holdings, Inc.

Virginia Delaware 94-2959483 Parent of Bechtel Development Company, Inc.

Bechtel Group, Inc. California Delaware 94-2681915 Parent of Bechtel Enterprises Holdings, Inc.

SECTION C. SPECIFIC INFORMATION REGARDING APPLICANT AND ITS “RELATED PARTIES”

Pennsylvania Facilities. List the name and location (mailing address, municipality, county), telephone

number, and relationship to applicant (parent, subsidiary or general partner) of applicant and all Related

Parties' places of business, and facilities in Pennsylvania. Attach additional sheets as necessary.

Unit Name Street Address

County and

Municipality

Telephone

No.

Relationship

to Applicant

Provide the names and business addresses of all general partners of the applicant and parent and

subsidiary corporations, if any.

Name Business Address

2700-PM-AQ0004 Rev. 6/2006

- 3 -

List the names and business address of persons with overall management responsibility for the process

being permitted (i.e. plant manager).

Name Business Address

Plan Approvals or Operating Permits. List all plan approvals or operating permits issued by the

Department or an approved local air pollution control agency under the APCA to the applicant or related

parties that are currently in effect or have been in effect at any time 5 years prior to the date on which this

form is notarized. This list shall include the plan approval and operating permit numbers, locations,

issuance and expiration dates. Attach additional sheets as necessary.

Air Contamination

Source Plan Approval/

Operating Permit# Location

Issuance

Date

Expiration

Date

2700-PM-AQ0004 Rev. 6/2006

- 4 -

Compliance Background. (Note: Copies of specific documents, if applicable, must be made available to

the Department upon its request.) List all documented conduct of violations or enforcement actions

identified by the Department pursuant to the APCA, regulations, terms and conditions of an operating

permit or plan approval or order by applicant or any related party, using the following format grouped by

source and location in reverse chronological order. Attach additional sheets as necessary. See the

definition of "documented conduct" for further clarification. Unless specifically directed by the

Department, deviations which have been previously reported to the Department in writing, relating to

monitoring and reporting, need not be reported.

Date Location

Plan

Approval/

Operating

Permit#

Nature of

Documented

Conduct

Type of

Department

Action

Status:

Litigation

Existing/Continuing

or

Corrected/Date

Dollar

Amount

Penalty

$

$

$

$

$

$

$

$

$

$

List all incidents of deviations of the APCA, regulations, terms and conditions of an operating permit or

plan approval or order by applicant or any related party, using the following format grouped by source

and location in reverse chronological order. This list must include items both currently known and

unknown to the Department. Attach additional sheets as necessary. See the definition of "deviations" for

further clarification.

Date Location

Plan Approval/

Operating Permit#

Nature of

Deviation

Incident Status:

Litigation

Existing/Continuing

Or

Corrected/Date

CONTINUING OBLIGATION. Applicant is under a continuing obligation to update this form using the

Compliance Review Supplemental Form if any additional deviations occur between the date of

submission and Department action on the application.

1300-PM-BIT0001 5/2012 Form

Page 1 of 7

COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF ENVIRONMENTAL PROTECTION

GENERAL INFORMATION FORM – AUTHORIZATION APPLICATION

Before completing this General Information Form (GIF), read the step-by-step instructions provided in this application package. This version of the General Information Form (GIF) must be completed and returned with any program-specific application being submitted to the Department.

Related ID#s (If Known) DEP USE ONLY

Client ID# APS ID# Date Received & General Notes

Site ID# Auth ID#

Facility ID#

CLIENT INFORMATION

DEP Client ID# Client Type / Code

Organization Name or Registered Fictitious Name Employer ID# (EIN) Dun & Bradstreet ID#

Renovo Energy Center LLC 47-2181250

Individual Last Name First Name MI Suffix SSN Franzese Richard P

Additional Individual Last Name First Name MI Suffix SSN

Mailing Address Line 1 Mailing Address Line 2 Bechtel Development Company 12011 Sunset Hills Road, Suite 110-RO1

Address Last Line – City State ZIP+4 Country Reston VA 20190 USA

Client Contact Last Name First Name MI Suffix Franzese Richard P

Client Contact Title Phone Ext Director, Power and Energy Development/Project Manager (571) 392-6383

Email Address FAX [email protected]

SITE INFORMATION

DEP Site ID# Site Name

EPA ID# Estimated Number of Employees to be Present at Site

Description of Site Site is approximately 68 acres located in Renovo north of Erie Avenue and South of Industrial Park Road. Site was formerly in use as a railcar reconditioning operation.

County Name Municipality City Boro Twp State Clinton Renovo

County Name Municipality City Boro Twp State Clinton Renovo

Site Location Line 1 Site Location Line 2 Industrial Park Road

Site Location Last Line – City State ZIP+4 Renovo PA 17764

Detailed Written Directions to Site From Williamsport, travel west on I-180/US-220 South, bearing left at fork to stay on US-220 South for approximately 24 miles; Take exit 111 for PA-120 West and proceed approximately 30 miles to right turn onto Stouts Hill Road for 1/10th mile to right onto Mt. Glen Road, continuing straight ahead onto to Industrial Park Road.

Site Contact Last Name First Name MI Suffix

Site Contact Title Site Contact Firm

Mailing Address Line 1 Mailing Address Line 2

1300-PM-BIT0001 5/2012

Page 2 of 7

Mailing Address Last Line – City State ZIP+4

Phone Ext FAX Email Address

NAICS Codes (Two- & Three-Digit Codes – List All That Apply) 6-Digit Code (Optional)

Client to Site Relationship

FACILITY INFORMATION

Modification of Existing Facility Yes No 1. Will this project modify an existing facility, system, or activity? 2. Will this project involve an addition to an existing facility, system, or activity? If “Yes”, check all relevant facility types and provide DEP facility identification numbers below. Facility Type DEP Fac ID# Facility Type DEP Fac ID#

Air Emission Plant Industrial Minerals Mining Operation

Beneficial Use (water) Laboratory Location

Blasting Operation Land Recycling Cleanup Location

Captive Hazardous Waste Operation MineDrainageTrmt/LandRecyProjLocation

Coal Ash Beneficial Use Operation Municipal Waste Operation

Coal Mining Operation Oil & Gas Encroachment Location

Coal Pillar Location Oil & Gas Location

Commercial Hazardous Waste Operation Oil & Gas Water Poll Control Facility

Dam Location Public Water Supply System

Deep Mine Safety Operation -Anthracite Radiation Facility

Deep Mine Safety Operation -Bituminous Residual Waste Operation

Deep Mine Safety Operation -Ind Minerals Storage Tank Location

Encroachment Location (water, wetland) Water Pollution Control Facility

Erosion & Sediment Control Facility Water Resource

Explosive Storage Location Other:

Latitude/Longitude Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds

0/0 41 19 42 77 45 18.47

Horizontal Accuracy Measure Feet --or-- Meters

Horizontal Reference Datum Code North American Datum of 1927 North American Datum of 1983 World Geodetic System of 1984

Horizontal Collection Method Code

Reference Point Code

Altitude Feet --or-- Meters

Altitude Datum Name The National Geodetic Vertical Datum of 1929 The North American Vertical Datum of 1988 (NAVD88)

Altitude (Vertical) Location Datum Collection Method Code

Geometric Type Code

Data Collection Date

Source Map Scale Number Inch(es) = Feet

--or-- Centimeter(s) = Meters

PROJECT INFORMATION

Project Name Renovo Energy Center

Project Description Renovo Energy Center, LLC (REC) proposes to construct a nominally rated 1,240 MW (net) dual fuel (natural gas and ultra-low sulfur diesel) combined cycle electric generating plant in Renovo, PA The proposed REC facility will consist of two 1-on-1 power blocks consisting of a combustion turbine and a steam turbine in line to produce electricity for distribution into the transmission grid system. Each combined cycle system consists of a natural gas fired combustion turbine (CT) and a heat recovery steam generator (HRSG) with duct burner.

Project Consultant Last Name First Name MI Suffix Donnelly Timothy J Mr

1300-PM-BIT0001 5/2012

Page 3 of 7

Project Consultant Title Consulting Firm Senior Project Manager POWER Engineers, Inc

Mailing Address Line 1 Mailing Address Line 2 303 U.S. Route One

Address Last Line – City State ZIP+4 Freeport ME 04032

Phone Ext FAX Email Address 207-869-1282 207-869-1299 [email protected]

Time Schedules Project Milestone (Optional)

1. Have you informed the surrounding community and addressed any concerns prior to submitting the application to the Department?

Yes No

2. Is your project funded by state or federal grants? Yes No

Note: If “Yes”, specify what aspect of the project is related to the grant and provide the grant source, contact person and grant expiration date.

Aspect of Project Related to Grant

Grant Source:

Grant Contact Person:

Grant Expiration Date:

3. Is this application for an authorization on Appendix A of the Land Use Policy? (For referenced list, see Appendix A of the Land Use Policy attached to GIF instructions)

Yes No

Note: If “No” to Question 3, the application is not subject to the Land Use Policy.

If “Yes” to Question 3, the application is subject to this policy and the Applicant should answer the additional questions in the Land Use Information section.

LAND USE INFORMATION

Note: Applicants are encouraged to submit copies of local land use approvals or other evidence of compliance with local comprehensive plans and zoning ordinances.

1. Is there an adopted county or multi-county comprehensive plan? Yes No

2. Is there an adopted municipal or multi-municipal comprehensive plan? Yes No

3. Is there an adopted county-wide zoning ordinance, municipal zoning ordinance or joint municipal zoning ordinance?

Yes No

Note: If the Applicant answers “No” to either Questions 1, 2 or 3, the provisions of the PA MPC are not applicable and the Applicant does not need to respond to questions 4 and 5 below.

If the Applicant answers “Yes” to questions 1, 2 and 3, the Applicant should respond to questions 4 and 5 below.

4. Does the proposed project meet the provisions of the zoning ordinance or does the proposed project have zoning approval? If zoning approval has been

received, attach documentation.

Yes No

5. Have you attached Municipal and County Land Use Letters for the project? Yes No

1300-PM-BIT0001 5/2012

Page 4 of 7

COORDINATION INFORMATION

Note: The PA Historical and Museum Commission must be notified of proposed projects in accordance with DEP Technical Guidance Document 012-0700-001 and the accompanying Cultural Resource Notice Form.

If the activity will be a mining project (i.e., mining of coal or industrial minerals, coal refuse disposal and/or the operation of a coal or industrial minerals preparation/processing facility), respond to questions 1.0 through 2.5 below.

If the activity will not be a mining project, skip questions 1.0 through 2.5 and begin with question 3.0.

1.0 Is this a coal mining project? If “Yes”, respond to 1.1-1.6. If “No”, skip to Question 2.0.

Yes No

1.1 Will this coal mining project involve coal preparation/ processing activities in which the total amount of coal prepared/processed will be equal to or greater than 200 tons/day?

Yes No

1.2 Will this coal mining project involve coal preparation/ processing activities in which the total amount of coal prepared/processed will be greater than 50,000 tons/year?

Yes No

1.3 Will this coal mining project involve coal preparation/ processing activities in which thermal coal dryers or pneumatic coal cleaners will be used?

Yes No

1.4 For this coal mining project, will sewage treatment facilities be constructed and treated waste water discharged to surface waters?

Yes No

1.5 Will this coal mining project involve the construction of a permanent impoundment meeting one or more of the following criteria: (1) a contributory drainage area exceeding 100 acres; (2) a depth of water measured by the upstream toe of the dam at maximum storage elevation exceeding 15 feet; (3) an impounding capacity at maximum storage elevation exceeding 50 acre-feet?

Yes No

1.6 Will this coal mining project involve underground coal mining to be conducted within 500 feet of an oil or gas well?

Yes No

2.0 Is this a non-coal (industrial minerals) mining project? If “Yes”, respond to 2.1-2.6. If “No”, skip to Question 3.0.

Yes No

2.1 Will this non-coal (industrial minerals) mining project involve the crushing and screening of non-coal minerals other than sand and gravel?

Yes No

2.2 Will this non-coal (industrial minerals) mining project involve the crushing and/or screening of sand and gravel with the exception of wet sand and gravel operations (screening only) and dry sand and gravel operations with a capacity of less than 150 tons/hour of unconsolidated materials?

Yes No

2.3 Will this non-coal (industrial minerals) mining project involve the construction, operation and/or modification of a portable non-metallic (i.e., non-coal) minerals processing plant under the authority of the General Permit for Portable Non-metallic Mineral Processing Plants (i.e., BAQ-PGPA/GP-3)?

Yes No

2.4 For this non-coal (industrial minerals) mining project, will sewage treatment facilities be constructed and treated waste water discharged to surface waters?

Yes No

2.5 Will this non-coal (industrial minerals) mining project involve the construction of a permanent impoundment meeting one or more of the following criteria: (1) a contributory drainage area exceeding 100 acres; (2) a depth of water measured by the upstream toe of the dam at maximum storage elevation exceeding 15 feet; (3) an impounding capacity at maximum storage elevation exceeding 50 acre-feet?

Yes No

1300-PM-BIT0001 5/2012

Page 5 of 7

3.0 Will your project, activity, or authorization have anything to do with a well related to oil or gas production, have construction within 200 feet of, affect an oil or gas well, involve the waste from such a well, or string power lines above an oil or gas well? If “Yes”, respond to 3.1-3.3. If “No”, skip to Question 4.0.

Yes No

3.1 Does the oil- or gas-related project involve any of the following: placement of fill, excavation within or placement of a structure, located in, along, across or projecting into a watercourse, floodway or body of water (including wetlands)?

Yes No

3.2 Will the oil- or gas-related project involve discharge of industrial wastewater or stormwater to a dry swale, surface water, ground water or an existing sanitary sewer system or storm water system? If “Yes”, discuss in Project Description.

Yes No

3.3 Will the oil- or gas-related project involve the construction and operation of industrial waste treatment facilities?

Yes No

4.0 Will the project involve a construction activity that results in earth disturbance? If “Yes”, specify the total disturbed acreage.

Yes No

4.0.1 Total Disturbed Acreage 68

5.0 Does the project involve any of the following? If “Yes”, respond to 5.1-5.3. If “No”, skip to Question 6.0.

Yes No

5.1 Water Obstruction and Encroachment Projects – Does the project involve any of the following: placement of fill, excavation within or placement of a structure, located in, along, across or projecting into a watercourse, floodway or body of water?

Yes No

5.2 Wetland Impacts – Does the project involve any of the following: placement of fill, excavation within or placement of a structure, located in, along, across or projecting into a wetland?

Yes No

5.3 Floodplain Projects by the commonwealth, a Political Subdivision of the commonwealth or a Public Utility – Does the project involve any of the following: placement of fill, excavation within or placement of a structure, located in, along, across or projecting into a floodplain?

Yes No

6.0 Will the project involve discharge of stormwater or wastewater from an industrial activity to a dry swale, surface water, ground water or an existing sanitary sewer system or separate storm water system?

Yes No

7.0 Will the project involve the construction and operation of industrial waste treatment facilities?

Yes No

8.0 Will the project involve construction of sewage treatment facilities, sanitary sewers, or sewage pumping stations? If “Yes”, indicate estimated proposed flow (gal/day). Also, discuss the sanitary sewer pipe sizes and the number of pumping stations/treatment facilities/name of downstream sewage facilities in the Project Description, where applicable.

Yes No

8.0.1 Estimated Proposed Flow (gal/day)

9.0 Will the project involve the subdivision of land, or the generation of 800 gpd or more of sewage on an existing parcel of land or the generation of an additional 400 gpd of sewage on an already-developed parcel, or the generation of 800 gpd or more of industrial wastewater that would be discharged to an existing sanitary sewer system?

Yes No

9.0.1 Was Act 537 sewage facilities planning submitted and approved by DEP? If “Yes” attach the approval letter. Approval required prior to 105/NPDES approval.

Yes No

10.0 Is this project for the beneficial use of biosolids for land application within Pennsylvania? If “Yes” indicate how much (i.e. gallons or dry tons per year).

Yes No

10.0.1 Gallons Per Year (residential septage)

10.0.2 Dry Tons Per Year (biosolids)

11.0 Does the project involve construction, modification or removal of a dam? If “Yes”, identify the dam.

Yes No

11.0.1 Dam Name

1300-PM-BIT0001 5/2012

Page 6 of 7

12.0 Will the project interfere with the flow from, or otherwise impact, a dam? If “Yes”, identify the dam.

Yes No

12.0.1 Dam Name

13.0 Will the project involve operations (excluding during the construction period) that produce air emissions (i.e., NOX, VOC, etc.)? If “Yes”, identify each type of emission followed by the amount of that emission.

Yes No

13.0.1 Enter all types & amounts of emissions; separate each set with semicolons.

364.0 TPY NOx, 375.7 TPY CO, 212.6 TPY PM10, 112.6 TPY VOC, 53.6 TPY SO2, 277.4 TPY NH3, 35.4 TPY H2SO4, 5,449,137 TPY CO2e

14.0 Does the project include the construction or modification of a drinking water supply to serve 15 or more connections or 25 or more people, at least 60 days out of the year? If “Yes”, check all proposed sub-facilities.

Yes No

14.0.1 Number of Persons Served

14.0.2 Number of Employee/Guests

14.0.3 Number of Connections

14.0.4 Sub-Fac: Distribution System Yes No

14.0.5 Sub-Fac: Water Treatment Plant Yes No

14.0.6 Sub-Fac: Source Yes No

14.0.7 Sub-Fac: Pump Station Yes No

14.0.8 Sub Fac: Transmission Main Yes No

14.0.9 Sub-Fac: Storage Facility Yes No

15.0 Will your project include infiltration of storm water or waste water to ground water within one-half mile of a public water supply well, spring or infiltration gallery?

Yes No

16.0 Is your project to be served by an existing public water supply? If “Yes”, indicate name of supplier and attach letter from supplier stating that it will serve the project.

Yes No

16.0.1 Supplier’s Name Renovo Borough Water Department

16.0.2 Letter of Approval from Supplier is Attached Yes No

17.0 Will this project involve a new or increased drinking water withdrawal from a stream or other water body? If “Yes”, should reference both Water Supply and Watershed Management.

Yes No

17.0.1 Stream Name

18.0 Will the construction or operation of this project involve treatment, storage, reuse, or disposal of waste? If “Yes”, indicate what type (i.e., hazardous, municipal (including infectious & chemotherapeutic), residual) and the amount to be treated, stored, re-used or disposed.

Yes No

18.0.1 Type & Amount The site is a Brownfield Site under Pennsylvania Act 2. Certain portions of the Site contain areas of contaminated soil, which, once dug up during construction, will have to be disposed of in an appropriate disposal facility.

19.0 Will your project involve the removal of coal, minerals, etc. as part of any earth disturbance activities?

Yes No

20.0 Does your project involve installation of a field constructed underground storage tank? If “Yes”, list each Substance & its Capacity. Note: Applicant may need a Storage Tank Site Specific Installation Permit.

Yes No

20.0.1 Enter all substances & capacity of each; separate each set with semicolons.

21.0 Does your project involve installation of an aboveground storage tank greater than 21,000 gallons capacity at an existing facility? If “Yes”, list each Substance & its Capacity. Note: Applicant may need a Storage Tank Site Specific Installation Permit.

Yes No

21.0.1 Enter all substances & capacity of each; separate each set with semicolons.

2700-PM-AQ0007 Rev. 7/2004

- 2 -

Section B - Processes Information

1. Source Information

Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary.

Two identical combined cycle combustion turbines consisting of a combustion turbine, steam turbine, and heat recovery steam generator with duct burners.

Manufacturer General Electric

Model No. 7HA.02

Number of Sources 2

Source Designation CT1 and CT2

Maximum Capacity 3,541 MMBtu/hr CT natural gas 4,529 MMBtu/hr CT & DB nat gas 3,940 MMBtu/hr ULSD

Rated Capacity 3,541 MMBtu/hr CT natural gas 4,529 MMBtu/hr CT & DB nat gas 3,940 MMBtu/hr ULSD

Type of Material Processed natural gas combustion to produce heat and shaft power

Maximum Operating Schedule

Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE): 760 hours of ULSD firing on a 12-month rolling total basis

Capacity (specify units) - Maximum

Per Hour 3,541 MMBtu CT NG 4,529 MMBtu CT & DB NG 3,940 MMBtu ULSD

Per Day 84,984 MMBtu CT NG 108,696 MMBtu CT & DB 94,560 MMBtu ULSD

Per Week 594,888 MMBtu CT NG 760,872 MMBtu CT & DB NG 661,920 MMBtu ULSD

Per Year 31,019,160 MMBtu CT NG 39,674,040 MMBtu CT & DB 2,994,400 MMBtu ULSD

Operating Schedule

Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8760

Seasonal variations (Months) From to

If variations exist, describe them Maximum capacity of CTs varies as a function of ambient temperature. Maximum capacity typically occurs at the

lowest ambient design temperature (-20° F). See detailed performance specifications and emissions calculations

presented in Appendix D and Appendix E. Note: maximum per hour, per day, and per week capacities based on maximum capacities; maximum per year capacities based on estimated maximum emissions from worst-case of all anticipated operating scenarios.

2. Fuel

Type Quantity Hourly Annually Sulfur

% Ash (Weight) BTU Content

Oil Number #2 (ULSD)

195,747.6 LB/HR @ 60°F

148,768,206.7 LB/YR

0.0015% by wt

negl 20,130 BTU/LB @ 60 °F

Oil Number

GPH @ 60°F

X 103

Gal

% by wt

Btu/Gal. & Lbs./Gal. @ 60 °F

Natural Gas 191,854.1 LB/HR

1,680,642,013

LB/YR

0.4 grain/100

SCF

0 23,607 Btu/LB

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal

TPH Tons % by wt Btu/lb

Other *

*Note: Describe and furnish information separately for other fuels in Addendum B.

2700-PM-AQ0007 Rev. 7/2004

- 3 -

Section B - Processes Information (Continued)

3. Burner

Manufacturer GE

Type and Model No. dry low-NOx

Number of Burners 12 per CT

Description: Two identical combined-cycle combustion turbines with duct-fired heat recovery steam generators

Rated Capacity 3,541 MMBtu/hr (CT NG), 4,529 MMBtu/hr (CT & DB) 3,940 MMBtu/hr (ULSD)

Maximum Capacity 3,541 MMBtu/hr (CT NG), 4,529 MMBtu/hr (CT & DB) 3,940 MMBtu/hr (ULSD)

4. Process Storage Vessels

A. For Liquids:

Name of material stored

See attached list of tanks

Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure

Capacity (gallons/Meter3)

Type of relief device (pressure set vent/conservation vent/emergency vent/open vent)

Relief valve/vent set pressure (psig)

Vapor press. of liquid at storage temp. (psia/kPa)

Type of Roof: Describe:

Total Throughput Per Year

Number of fills per day (fill/day):

Filling Rate (gal./min.):

Duration of fill hr./fill):

B. For Solids

Type: Silo Storage Bin Other, Describe

Name of Material Stored

Silo/Storage Bin I.D. No.

Manufacturer

Date Installed

State whether the material will be stored in loose or bags in silos

Capacity (Tons)

Turn over per year in tons

Turn over per day in tons

Describe fugitive dust control system for loading and handling operations

Describe material handling system

5. Request for Confidentiality

Do you request any information on this application to be treated as “Confidential”? Yes No If yes, include justification for confidentiality. Place such information on separate pages marked “confidential”.

2700-PM-AQ0007 Rev. 7/2004

- 4 -


6. Miscellaneous Information

Attach flow diagram of process giving all (gaseous, liquid and solid) flow rates. Also, list all raw materials charged to process equipment, and the amounts charged (tons/hour, etc.) at rated capacity (give maximum, minimum and average charges describing fully expected variations in production rates). Indicate (on diagram) all points where contaminants are controlled (location of water sprays, collection hoods, or other pickup points, etc.). Describe collection hoods location, design, airflow and capture efficiency. Describe any restriction requested and how it will be monitored.

Appendix C contains a flow diagram for the combustion turbines. Please note flow and temperature information are approximate based on preliminary data.

Describe fully the facilities provided to monitor and to record process operating conditions, which may affect the emission of air contaminants. Show that they are reasonable and adequate.

CEMS will be installed for O2, NOx, and CO. Calibrated natural gas and ULSD fuel flow orifices will provide input flow rates. Emissions of VOC, SO2, PM, and GHGs will be calculated based on fuel flow, fuel test results, and emission factors or stack test data.

Describe each proposed modification to an existing source.

Not applicable

Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks.

There are no fugitive emission points associated with the CT.

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions.

Emissions are minimized during startups, shutdowns, process upsets and/or disruptions by following the OEM's recommended precedures for these events. REC will follow good combustion practices and will follow the OEM recommended maintenance and testing schedule.

Anticipated Milestones:

i. Expected commencement date of construction/reconstruction/installation: October 2020

ii. Expected completion date of construction/reconstruction/installation: January 2023

iii. Anticipated date of start-up: April – November 2023

2700-PM-AQ0007 Rev. 7/2004

- 5 -

Section C - Air Cleaning Device

1. Precontrol Emissions* All emission calculations are contained in Appendix D. Maximum lb/hr is based on worst case operating scenario during normal operation per CT per fuel type. See Appendix D for emission rates during startup and shutdown. Tons per year are based on the worst-case emissions scenario of 760 hours on ULSD (with 40 of those hours in SUSD events), and 8,000 hours on natural gas (with 460 of those hours in SUSD events). Note that no limit is being proposed on natural gas firing, only ULSD and SUSD.

Pollutant

Maximum Emission Rate Calculation/ Estimation

Method Specify Units Pounds/Hour

Gas/ULSD Hours/Year Tons/Year

PM 22.50 / 48.20 8760 105.96 vendor data

PM10 22.50 / 48.20 8760 105.96 vendor data

SOx 6.10 / 7.00 8760 26.74 vendor data

CO 86.85 / 81.45 8760 911.72 vendor data

NOx 416.25 / 745.0 8760 1,868.05 vendor data

VOC 19.07 / 18.20 8760 90.86 vendor data

Others: (e.g., HAPs) ----- ----- ----- ----- -----

individual HAPs 8760 <10 facility-wide emission factors

total HAPs 8760 <25 facility-wide Emission factors

* These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating schedule for maximum limits or restricted hours of operation and/or restricted throughput. Describe how the emission values were determined. Attach calculations.

2. Gas Cooling

Water quenching Yes No Water injection rate 532.1 GPM (only during ULSD firing)

Radiation and convection cooling

Yes No

Air dilution Yes No

If yes, CFM

Forced Draft Yes No Water cooled duct work Yes No

Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture

Describe the system in detail.

2700-PM-AQ0007 Rev. 7/2004

- 6 -

Section C - Air Cleaning Device (Continued)

3. Settling Chambers (NOT APPLICABLE) Manufacturer

Volume of gas handled

ACFM

@ °F

Gas velocity (ft/sec.)

Length of chamber (ft.)

Width of chamber (ft.)

Height of chamber (ft.)

Number of trays

Water injection Yes No Water injection rate (GPM)

Emissions Data

Inlet Outlet Removal Efficiency (%)

4. Inertial and Cyclone Collectors (NOT APPLICABLE) Manufacturer

Type

Model No.

Pressure drop (in. of water)

Inlet volume ACFM

@ °F

Outlet volume ACFM

@ °F

Number of individual cyclone(s)

Outlet straightening vanes used?

Yes No

Length of Cyclone(s) Cylinder (ft.)

Diameter of Cyclone(s) Cylinder (ft.)

Length of Cyclone(s) cone (ft.)

Inlet Diameter (ft.) or duct area (ft.2) of cyclone(s)

Outlet Diameter (ft.) or duct area (ft.2) of cyclone(s)

If a multi-clone or multi-tube unit is installed, will any of the individual cyclones or cyclone tubes be blanked or blocked off?

Describe any exhaust gas recirculation loop to be employed.

Attach particle size efficiency curve

Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 7 -


5. Fabric Collector (NOT APPLICABLE) Equipment Specifications

Manufacturer

Model No.

Pressurized Design

Suction Design

Number of Compartments

Number of Filters Per Compartment

Is Baghouse Insulated?

Yes No

Can each compartment be isolated for repairs and/or filter replacement?

Yes No

Are temperature controls provided? (Describe in detail)

Yes No

Dew point at maximum moisture °F Design inlet volume SCFM

Type of Fabric

Material Felted Membrane

Weight oz/sq.yd Woven Others: List:

Thickness in Felted-Woven

Fabric permeability (clean) @ ½” water-∆ P CFM/sq.ft.

Filter dimensions Length Diameter/Width

Effective area per filter Maximum operating temperature (°F)

Effective air to cloth ratio Minimum Maximum

Drawing of Fabric Filter

A sketch of the fabric filter showing all access doors, catwalks, ladders and exhaust ductwork, location of each pressure and temperature indicator should be attached.

Operation and Cleaning

Volume of gases handled

ACFM @ °F

Pressure drop across collector (in. of water). Describe the equipment to be used to monitor the pressure drop.

Type of filter cleaning Manual Cleaning Bag Collapse Reverse Air Jets Mechanical Shakers Sonic Cleaning Other: Pneumatic Shakers Reverse Air Flow

Describe the equipment provided if dry oil free air is required for collector operation

Cleaning Initiated By Timer Frequency if timer actuated

Expected pressure drop range in. of water Other Specify

Does air cleaning device employ hopper heaters, hopper vibrators or hopper level detectors? If yes, describe.

Describe the warning/alarm system that protects against operation when the unit is not meeting design requirements.

Emissions Data

Pollutant Inlet Outlet Removal Efficiency (%)

2700-PM-AQ0007 Rev. 7/2004

- 8 -


6. Wet Collection Equipment (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type

Model No.

Design Inlet Volume (SCFM)

Relative Particulate/Gas Velocity (ejector scrubbers only)

Describe the internal features (e.g., variable throat, gas/liquid diffusion plates, spray nozzles, liquid redistributors, bed limiters, etc.).

Describe pH monitoring and pH adjustment systems, if applicable.

Describe mist eliminator or separator (type, configuration, backflush capability, frequency).

Attach particulate size efficiency curve.

Operating Parameters

Inlet volume of gases handled (ACFM)

@ °F

Outlet volume of gases handled (ACFM)

@ °F % Moisture

Liquid flow rates. Describe equipment provided to measure liquid flow rates to scrubber (e.g., quenching section, recirculating solution, makeup water, bleed flow, etc.)

Describe scrubber liquid supply system (amount of make-up and recirculating liquid, capacity of recirculating liquid system, etc.)

State pressure drop range (in water) across scrubber (e.g., venturi throat, packed bed, etc.) only. Describe the equipment provide to measure the pressure drop. Do not include duct or de-mister losses.

Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.

Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 9 -


7. Electrostatic Precipitator (NOT APPLICABLE) Equipment Specifications

Manufacturer

Model No.

Wet Dry

Single-Stage Two-Stage

Gas distribution grids Yes No Design Inlet Volume (SCFM)

Maximum operating temperature (°F)

Total collecting surface area sq. ft. Collector plates size length ft. x width ft.

Number of fields Number of collector plates/field

Spacing between collector plates inches.

Maximum gas velocity ft./sec. Minimum gas treatment time: sec.

Total discharge electrode length ft.

Number of discharge electrodes Number of collecting electrode rappers

Rapper control Magnetic Pneumatic Other Describe in detail


Inlet gas temperature (°F)

Outlet gas temperature (°F)

State pressure drop range (inches water gauge) across collector only

Describe the equipment

Volume of gas handled (ACFM) Dust resistivity (ohm-cm). Will resistivity vary?

Power requirements

Number and size of Transformer Rectifier sets by electrical field

Field No. No. of Sets Each Transformer

KVA Each Rectifier

KV Ave./Peak Ma DC

Current Density

Micro amperes/ft2.

Corona Power

Watts/1000 ACFM

Corona Power Density

Watts/ft2.

Will a flue gas conditioning system be employed? If yes, describe it.



Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 10 -


8. Adsorption Equipment (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type

Model No.


Adsorbent charge per adsorber vessel and number of adsorber vessels

Length of Mass Transfer Zone (MTZ), supplied by the manufacturer based upon laboratory data.

Adsorber diameter (ft.) and area ft2.)

Adsorption bed depth (ft.)

Adsorbent information

Adsorbent type and physical properties.

Working capacity of adsorbent (%)

Heel percent or unrecoverable solvent weight % in the adsorbent after regeneration.


Inlet volume of gases handled (ACFM) @ °F

Adsorption time per adsorption bed

Breakthrough capacity:

Lbs. of solvent / 100 lbs. of adsorbent =

Vapor pressure of solvents at the inlet temperature

Available steam in pounds to regenerate carbon adsorber (if applicable)

Percent relative saturation of each solvent at the inlet temperature

Attach any additional data including auxiliary equipment and operation details to thoroughly evaluate the control equipment.


Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 11 -


9. Absorption Equipment (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type

Model No.


Tower height (ft.) and inside diameter (ft.)

Packing type and size (if applicable)

Height of packing (ft.) (if applicable)

Number of trays (if applicable)

Number of bubble caps (if applicable)

Configuration

Counter-current Cross flow Cocurrent flow

Describe pH and/or other monitoring and controls.

Absorbent information

Absorbent type and concentration.

Retention time (sec.)

Attach equilibrium data for absorption (if applicable)

Attach any additional information regarding auxiliary equipment, absorption solution supply system (once through or recirculating, system capacity, etc.) to thoroughly evaluate the control equipment. Indicate the flow rates for makeup, bleed and recirculation.


Volume of gas handled (ACFM)

Inlet temperature (°F)

Pressure drop (in. of water) and liquid flow rate. Describe the monitoring equipment.

State operating range for pH and/or absorbent concentration in scrubber liquid.


Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 12 -


10. Selective Catalytic Reduction (SCR)


Non-Selective Catalytic Reduction (NSCR)

Equipment Specifications

Manufacturer

TBD

Type

TBD

Model No.

TBD


1.0 – 1.5 MMSCFM

Design operating temperature (°F)

605-610

Is the system equipped with process controls for proper mixing/control of the reducing agent in gas stream? If yes, give details.

Yes, the feed forward and feed back loops are used to calculate the amount of reducing agent required. The SCR ammonia flow control shall utilize a feed forward signal generated by inlet NOx analyzer. Outlet NOx analyzer will trim as feedback control.

Attach efficiency and other pertinent information (e.g., ammonia slip)

See Attachment D for detailed calculations and assumptions


Volume of gases handled 1.0 – 1.9 MM ACFM (ACFM) @ 605-610 °F

Operating temperature range for the SCR/SNCR/NSCR system (°F) From 605 °F To 610 °F

Reducing agent used, if any

ammonia

Oxidation catalyst used, if any

Yes, CO and VOC oxidation catalyst

State expected range of usage rate and concentration.

flow rate: TBD

concentration: 19% aqueous ammonia

Service life of catalyst

3 years

Ammonia slip (ppm)

5 ppm @ 15% O2

Describe fully with a sketch giving locations of equipment, controls systems, important parameters and method of operation.

Not available at this time


Alarms will be programed into the facility's DCS for high outlet NOx concentration and ammonia slip. Specific alarm setpoints will be determined.

SCR will be equipped with alarms to ensure proper operation (high/low temperatures, etc.)

See Section 1 and relevant appendices of this Plan Approval Application for more detailed information.

Emissions Data


NOx 25 ppmvd @ 15% O2 2 ppmvd @ 15% O2 ~92% (NG; normal operation)

CO 9 ppm @ 15% O2 1.9 ppmvd @ 15% O2 ~79% (NG; normal operation)

VOC 1.4 ppm @ 15% O2 0.7 ppmvd @ 15% O2 ~50% (NG; normal operation)

2700-PM-AQ0007 Rev. 7/2004

- 13 -


11. Oxidizer/Afterburners (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type Thermal Catalytic Model No.


Combustion chamber dimensions (length, cross-sectional area, effective chamber volume, etc.)

Describe design features, which will ensure mixing in combustion chamber.

Describe method of preheating incoming gases (if applicable).

Describe heat exchanger system used for heat recovery (if applicable).

Catalyst used

Life of catalyst

Expected temperature rise across catalyst (°F)

Dimensions of bed (in inches).

Height:

Diameter or Width:

Depth:

Are temperature sensing devices being provided to measure the temperature rise across the catalyst? Yes No

If yes, describe.

Describe any temperature sensing and/or recording devices (including specific location of temperature probe in a drawing or sketch.

Burner Information

Burner Manufacturer

Model No.

Fuel Used

Number and capacity of burners

Rated capacity (each)

Maximum capacity (each)

Describe the operation of the burner

Attach dimensioned diagram of afterburner


Inlet flow rate (ACFM) @ °F Outlet flow rate (ACFM) @ °F

State pressure drop range across catalytic bed (in. of water).

Describe the method adopted for regeneration or disposal of the used catalyst.


Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 14 -


12. Flares (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type Elevated flare Ground flare

Other Describe

Model No.

Design Volume (SCFM)

Dimensions of stack (ft.)

Diameter Height

Residence time (sec.) and outlet temperature (°F)

Turn down ratio

Burner details

Describe the flare design (air/steam-assisted or nonassisted), essential auxiliaries including pilot flame monitor of proposed flare with a sketch.

Describe the operation of the flare’s ignition system.

Describe the provisions to introduce auxiliary fuel to the flare.

Operation Parameters

Detailed composition of the waste gas

Heat content

Exit velocity

Maximum and average gas flow burned (ACFM)

Operating temperature (°F)


Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 15 -


13. Other Control Equipment (NOT APPLICABLE) Equipment Specifications

Manufacturer

Type

Model No.


Capacity

Describe pH monitoring and pH adjustment, if any.

Indicate the liquid flow rate and describe equipment provided to measure pressure drop and flow rate, if any.

Attach efficiency curve and/or other efficiency information.

Attach any additional date including auxiliary equipment and operation details to thoroughly evaluate the control equipment.



ACFM @ °F % Moisture

Describe fully giving important parameters and method of operation.


Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 16 -


14. Costs

Indicate cost associated with air cleaning device and its operating cost (attach documentation if necessary)

See Appendix O for cost documentation

Device Direct Cost Indirect Cost Total Cost Annual Operating Cost

SCR/Oxidation Catalyst 1,250,000 431,365 2,142,910 639,395

15. Miscellaneous

Describe in detail the removal, handling and disposal of dust, effluent, etc. from the air cleaning device including proposed methods of controlling fugitive emissions.

Spent catalyst will be returned to manufacturer or regenerating company for disposal or regeneration.

Attach manufacturer’s performance guarantees and/or warranties for each of the major components of the control system (or complete system).

See Appendix E

Attach the maintenance schedule for the control equipment and any part of the process equipment that if in disrepair would increase air contaminant emissions.

REC will follow manufacturer’s recommended operating and maintenance procedures and maintenance schedule for proper operation and maintenance of the equipment. See Section 1 and relevant appendices of this Plan Approval Application for more detailed information.

2700-PM-AQ0007 Rev. 7/2004

- 17 -

Section D - Additional Information

Will the construction, modification, etc. of the sources covered by this application increase emissions from other sources at the facility? If so, describe and quantify.

Not applicable – new facility

If this project is subject to any one of the following, attach a demonstration to show compliance with applicable standards.

See Section 2 for outline of applicable requirements.

a. Prevention of Significant Deterioration permit (PSD), 40 CFR 52? YES NO

b. New Source Review (NSR), 25 Pa. Code Chapter 127, Subchapter E? YES NO

c. New Source Performance Standards (NSPS), 40 CFR Part 60? YES NO

(If Yes, which subpart) KKKK, Dc, IIII, TTTT

d. National Emissions Standards for Hazardous Air Pollutants (NESHAP), YES NO

40 CFR Part 61? (If Yes, which subpart)

e. Maximum Achievable Control Technology (MACT) 40 CFR Part 63? YES NO

(If Yes, which part) ZZZZ

Attach a demonstration showing that the emissions from any new sources will be the minimum attainable through the use of best available technology (BAT).

See Section 3 of the Plan Approval Application

Provide emission increases and decreases in allowable (or potential) and actual emissions within the last five (5) years for applicable PSD pollutant(s) if the facility is an existing major facility (PSD purposes).

Not applicable - new facility

2700-PM-AQ0007 Rev. 7/2004

- 18 -

Section D - Additional Information (Continued)

Indicate emission increases and decreases in tons per year (tpy), for volatile organic compounds (VOCs) and nitrogen oxides (NOx) for NSR applicability since January 1, 1991 or other applicable dates (see other applicable dates in instructions). The emissions increases include all emissions including stack, fugitive, material transfer, other emission generating activities, quantifiable emissions from exempted source(s), etc.

Permit number

(if applicable) Date

issued

Indicate Yes or No if

emission increases and

decreases were used

previously for netting Source I. D. or Name

VOCs NOx

Emission increases

in potential to emit

(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)

If the source is subject to 25 Pa. Code Chapter 127, Subchapter E, New Source Review requirements, a. Identify Emission Reduction Credits (ERCs) for emission offsets or demonstrate ability to obtain suitable ERCs for

emission offsets. See Appendix Q of Plan Approval Application. b. Provide a demonstration that the lowest achievable emission rate (LAER) control techniques will be employed (if

applicable). See Section 3 of Plan Approval Application c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques demonstrating

that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1 of Plan Approval Application

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of Article III and applicable requirements of the Clean Air Act adopted thereunder The Department may request additional information to evaluate the application such as a standby plan, a plan for air pollution emergencies, air quality modeling, etc. See Section 1 and Appendix D of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

- 19 -

Section E - Compliance Demonstration

Note: Complete this section if source is not a Title V facility. Title V facilities must complete Addendum A.

Method of Compliance Type: Check all that apply and complete all appropriate sections below

Monitoring Testing Reporting

Recordkeeping Work Practice Standard

Monitoring:

a. Monitoring device type (Parameter, CEM, etc):

b. Monitoring device location:

c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Testing:

a. Reference Test Method: Citation

b. Reference Test Method: Description

Recordkeeping:

Describe what parameters will be recorded and the recording frequency:

Reporting:

a. Describe what is to be reported and frequency of reporting:

b. Reporting start date:

Work Practice Standard:

Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -

Section F - Flue and Air Contaminant Emission

1. Estimated Atmospheric Emissions* All emission calculations are contained in Appendix D. Maximum lb/hr is based on worst case operating scenario during normal operation per CT. See Appendix D for emission rates during startup and shutdown. Tons per year are based on the worst-case emissions scenario of 760 hours on ULSD (with 40 of those hours in SUSD events), and 8,000 hours on natural gas (with 460 of those hours in SUSD events). Note that no limit is being proposed on natural gas firing, only ULSD and SUSD.

Pollutant

Maximum emission rate

Calculation/

Estimation Method

specify units

Gas/ULSD

lbs/hr

Gas/ULSD tons/yr.

PM 22.50 / 48.20 105.96 manufacturer's data

PM10 22.50 / 48.20 105.96 manufacturer's data

SOx 6.10 / 7.00 26.74 manufacturer’s data

CO 1.3 ppm (w/o DB), 1.9 ppm (w/DB) / 2 ppm

19.30 / 18.10 178.39 manufacturer's data

NOx 2 ppm / 4 ppm 33.30 / 59.60 177.58 manufacturer's data

VOC 0.7 ppm (w/o DB), 1.8 ppm (w/DB) / 2 ppm

10.40 / 10.40 55.36 manufacturer's data

Others: ( e.g., HAPs) ----- ----- ----- -----

individual HAPs <10 facility-wide emission factors

Total HAPs <25 facility-side emission factors

* These emissions must be calculated based on the requested operating schedule and/or process rate e.g., operating schedule for maximum limits or restricted hours of operation and /or restricted throughput. Describe how the emission values were determined. Attach calculations.

2. Stack and Exhauster

Stack Designation/Number Stack 1 and Stack 2

List Source(s) or source ID exhausted to this stack:

CT1 and CT2

% of flow exhausted to stack: 100

Stack height above grade (ft.) 262 (starting point for modeling) Grade elevation (ft.) 672

Stack diameter (ft) or Outlet duct area (sq. ft.)

22 ft

f. Weather Cap

YES NO

Distance of discharge to nearest property line (ft.). Locate on topographic map.

375 ft from Stack 1; 300 ft from Stack 2

Does stack height meet Good Engineering Practice (GEP)?

No

If modeling (estimating) of ambient air quality impacts is needed, attach a site plan with buildings and their dimensions and other obstructions.

Location of stack**



Stack 1

Stack 2

41

41

19

19

44.44

41.41

77

77

45

45

18.68

17.60

2700-PM-AQ0007 Rev. 7/2004

- 21 -

Stack exhaust

Volume varies with operating scenarios (See Appendix D, Raw Data) ACFM Temperature varies with operating

scenarios (See Appendix D, Raw Data °F Moisture varies with operating scenarios %

Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions. Locations of sampling ports will meet EPA and DEP criteria (40 CFR Part 60 App. A and B) for stack sampling and monitoring.

Exhauster (attach fan curves) NA in. of water HP @ RPM.

** If the data and collection method codes differ from those provided on the General Information Form-Authorization Application, provide the additional detail required by that form on a separate form.

2700-PM-AQ0007 Rev. 7/2004

- 22 -

Section G - Attachments

Number and list all attachments submitted with this application below:

See Table of Contents of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

- 2 -




1500 kW diesel engine powered emergency generator

Manufacturer TBD

Model No. TBD

Number of Sources 1

Source Designation ENG1

Maximum Capacity 1500 kW

Rated Capacity 1500 kW

Type of Material Processed Ultra-low sulfur diesel oil combustion to produce shaft power to drive emergency generator


Hours/Day varies

Days/Week varies

Days/Year varies

Hours/Year 500

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE)

Capacity (specify units)

Per Hour

Per Day

Per Week

Per Year 500 hours per year

Operating Schedule

Hours/Day 0.5

Days/Week 1

Days/Year 52

Hours/Year 500 maximum


If variations exist, describe them

2. Fuel



Oil Number ULSD

104.6 GPH @ 60°F

52.3 X 103 Gal 0.0015% by wt

negligible 137,000 Btu/Gal. & Lbs./Gal. @ 60 °F

Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


2700-PM-AQ0007 Rev. 7/2004

- 3 -


3. Burner

Manufacturer NA

Type and Model No.

Number of Burners

Description:

Rated Capacity

Maximum Capacity


A. For Liquids:


Diesel tank will be approximately 2,500 gallons. Diesel has a vapor pressure of less than 1.5 psia.

Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure










B. For Solids




Manufacturer

Date Installed


Capacity (Tons)







2700-PM-AQ0007 Rev. 7/2004

- 4 -




Not applicable - only flows are diesel fuel and combustion air in and exhaust gas out.

REC requests restricting operating hours to 500 hours per year per generator. Hours will be monitored with a non-resettable hour meter and recorded.


Non-resettable hour meter will be installed to monitor operating hours. REC will maintain records of hours operated and reason for operation.


Not applicable


The only emissions that might be considered fugitive are from the relief vent on the diesel storage tank. Emissions are negligible.


Diesel engine will be started up and shut down according to manufacturer instructions. Engine will be run weekly for 30 minutes or less for testing purposes. Otherwise, engine will be operated for emergency purposes only (loss of plant power supply).





2700-PM-AQ0007 Rev. 7/2004

- 5 -


1. Precontrol Emissions*

Pollutant


Method Specify Units Pounds/Hour Hours/Year Tons/Year

PM 0.63 500 0.16 EPA weighted emissions

PM10 0.63 500 0.16 EPA weighted emissions

SOx 0.022 500 0.005 fuel sulfur

CO 5.98 500 1.50 EPA weighted emissions

NOx 21.79 500 5.45 EPA weighted emissions

VOC 3.89 500 0.97 Vendor data

Others: (e.g., HAPs) ----- ----- ----- ----- -----

Total HAPs 500 1.36E-2 AP-42 factors


2. Gas Cooling

Water quenching Yes No Water injection rate GPM


Yes No

Air dilution Yes No

If yes, CFM


Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 6 -


3. Settling Chambers NOT APPLICABLE

Manufacturer


ACFM

@ °F





Number of trays


Emissions Data


4. Inertial and Cyclone Collectors

Manufacturer

Type

Model No.


Inlet volume ACFM

@ °F

Outlet volume ACFM

@ °F



Yes No









Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 7 -


5. Fabric Collector NOT APPLICABLE


Manufacturer

Model No.

Pressurized Design

Suction Design




Yes No


Yes No


Yes No


Type of Fabric












ACFM @ °F








Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 8 -


6. Wet Collection Equipment NOT APPLICABLE Equipment Specifications

Manufacturer

Type

Model No.









@ °F


@ °F % Moisture





Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 9 -


7. Electrostatic Precipitator NOT APPLICABLE


Manufacturer

Model No.

Wet Dry

















Power requirements



KVA Each Rectifier

KV Ave./Peak Ma DC

Current Density

Micro amperes/ft2.

Corona Power

Watts/1000 ACFM


Watts/ft2.




Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 10 -


8. Adsorption Equipment NOT APPLICABLE


Manufacturer

Type

Model No.




















Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 11 -


9. Absorption Equipment NOT APPLICABLE


Manufacturer

Type

Model No.







Configuration














Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 12 -




Non-Selective Catalytic Reduction (NSCR) NOT APPLICABLE


Manufacturer

Type

Model No.






Volume of gases handled (ACFM) @ °F

Operating temperature range for the SCR/SNCR/NSCR system (°F) From °F To °F





Ammonia slip (ppm)



Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 13 -


11. Oxidizer/Afterburners NOT APPLICABLE


Manufacturer







Catalyst used

Life of catalyst



Height:

Diameter or Width:

Depth:


If yes, describe.


Burner Information

Burner Manufacturer

Model No.

Fuel Used











Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 14 -


12. Flares NOT APPLICABLE


Manufacturer


Other Describe

Model No.



Diameter Height


Turn down ratio

Burner details






Heat content

Exit velocity




Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 15 -


13. Other Control Equipment NOT APPLICABLE


Manufacturer

Type

Model No.


Capacity










Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 16 -


14. Costs NOT APPLICABLE



15. Miscellaneous




2700-PM-AQ0007 Rev. 7/2004

- 17 -





See Section 2 for identification of applicable requirements












Not applicable

2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used


VOCs NOx

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)



applicable). See Section 3 of Plan Approval Application. c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques demonstrating

that the benefits of the proposed source outweigh the environmental and social costs (if applicable).

See Section 1 of Plan Approval Application.

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of Article III and applicable requirements of the Clean Air Act adopted thereunder. The Department may request additional information to evaluate the application such as a standby plan, a plan for air pollution emergencies, air quality modeling, etc. See Section 2 and Appendix D of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

- 19 -






Monitoring:




Testing:



Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -


1. Estimated Atmospheric Emissions*

Pollutant

Maximum emission rate Calculation/

Estimation Method specify units lbs/hr tons/yr.

PM 0.63 0.16 EPA weighted emissions

PM10 0.63 0.16 EPA weighted emissions

SOx 0.022 0.005 fuel sulfur

CO 5.98 1.50 EPA weighted emissions

NOx 21.79 5.45 EPA weighted emissions

VOC 3.89 0.97 Vendor data

Others: ( e.g., HAPs) ----- ----- ----- -----

individual HAPs <10 EPA AP-42 factors

total HAPs <25 EPA AP-42 factors



Stack Designation/Number Stack5


ENG1


Stack height above grade (ft.) 16 Grade elevation (ft.) 670


0.833

f. Weather Cap

YES NO


490 ft from Stack5


No


Location of stack**



Stack5 41 19 42.77 77 45 20.61

Stack exhaust

Volume TBD ACFM Temperature TBD °F Moisture TBD %

Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.



2700-PM-AQ0007 Rev. 7/2004

- 21 -



See Table of Contents of Plan Approval Application

2700-PM-AQ0007 Rev. 7/2004

- 2 -




One 237 HP Diesel Fire Pump Engine

Manufacturer TBD

Model No. TBD

Number of Sources 1

Source Designation ENG2

Maximum Capacity ~1.64 MMBtu/hr

Rated Capacity ~1.64 MMBtu/hr

Type of Material Processed


Hours/Day

Days/Week

Days/Year

Hours/Year 250 (proposed limit)

Operational restrictions existing or requested, if any (e.g., bottlenecks or voluntary restrictions to limit PTE)


Per Hour

Per Day

Per Week

Per Year 250 (proposed limit)

Operating Schedule

Hours/Day 0.5

Days/Week 1

Days/Year 52

Hours/Year 250


If variations exist, describe them

2. Fuel



Oil Number ULSD

12.0 GPH @ 60°F

3.0 X 103 Gal

0.0015% by wt

negligible 137,000 Btu/Gal. & Lbs./Gal. @ 60 °F

Oil Number

GPH @ 60°F

X 103

Gal

% by wt


Natural Gas SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Gas (other)

SCFH

X 106

SCF

grain/100

SCF

Btu/SCF

Coal


Other *


2700-PM-AQ0007 Rev. 7/2004

- 3 -


3. Burner

Manufacturer NA

Type and Model No.

Number of Burners

Description:

Rated Capacity

Maximum Capacity


A. For Liquids:


Diesel tank is 350 gallons, which is less than the 2,000 gallon threshold contained in Chapter 129; Diesel has a vapor pressure of less than 1.5 psia.

Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure










B. For Solids




Manufacturer

Date Installed


Capacity (Tons)







2700-PM-AQ0007 Rev. 7/2004

- 4 -




Not applicable - only flows are diesel fuel and combustion air and exhaust gas out.

REC requests restricting operating hours to 250 hour per year. Hours will be monitored with a non-resettable hour meter and recorded.


Non-resettable hour meter will be installed to monitor operating hours. REC will maintain records of hours operated and reason for operation.


Not applicable


The only emissions that might be considered fugitive are from the relief vent on the diesel storage tank.


Diesel engine will be started up and shut down according to manufacturer instructions. Engine will be run weekly for 30 minutes or less for testing purposes. Otherwise, engine will be operated for emergency purposes only (loss of plant power supply).





2700-PM-AQ0007 Rev. 7/2004

- 5 -



Pollutant



PM 0.052 250 0.0065 vendor

PM10 0.052 250 0.0065 vendor

SOx 0.0025 250 0.00032 fuel sulfur

CO 0.47 250 0.059 vendor

NOx 1.41 250 0.18 vendor

VOC 0.052 250 0.0065 vendor

Others: (e.g., HAPs) ----- ----- ----- ----- -----

total HAPs 7.79E-04 AP-42 factors


2. Gas Cooling

Water quenching Yes No Water injection rate GPM


Yes No

Air dilution Yes No

If yes, CFM


Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 6 -


3. Settling Chambers NOT APPLICABLE Manufacturer


ACFM

@ °F





Number of trays


Emissions Data


4. Inertial and Cyclone Collectors

Manufacturer

Type

Model No.


Inlet volume ACFM

@ °F

Outlet volume ACFM

@ °F



Yes No









Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 7 -




Manufacturer

Model No.

Pressurized Design

Suction Design




Yes No


Yes No


Yes No


Type of Fabric












ACFM @ °F








Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 8 -


6. Wet Collection Equipment NOT APPLICABLE


Manufacturer

Type

Model No.









@ °F


@ °F % Moisture





Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 9 -




Manufacturer

Model No.

Wet Dry

















Power requirements



KVA Each Rectifier

KV Ave./Peak Ma DC

Current Density

Micro amperes/ft2.

Corona Power

Watts/1000 ACFM


Watts/ft2.




Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 10 -


8. Adsorption Equipment NOT APPLICABLE


Manufacturer

Type

Model No.




















Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 11 -


9. Absorption Equipment NOT APPLICABLE


Manufacturer

Type

Model No.







Configuration














Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 12 -




Non-Selective Catalytic Reduction (NSCR) NOT APPLICABLE


Manufacturer

Type

Model No.






Volume of gases handled (ACFM) @ °F

Operating temperature range for the SCR/SNCR/NSCR system (°F) From °F To °F





Ammonia slip (ppm)



Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 13 -


11. Oxidizer/Afterburners NOT APPLICABLE


Manufacturer







Catalyst used

Life of catalyst



Height:

Diameter or Width:

Depth:


If yes, describe.


Burner Information

Burner Manufacturer

Model No.

Fuel Used











Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 14 -


12. Flares NOT APPLICABLE


Manufacturer


Other Describe

Model No.



Diameter Height


Turn down ratio

Burner details






Heat content

Exit velocity




Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 15 -


13. Other Control Equipment NOT APPLICABLE


Manufacturer

Type

Model No.


Capacity










Emissions Data


2700-PM-AQ0007 Rev. 7/2004

- 16 -





15. Miscellaneous




2700-PM-AQ0007 Rev. 7/2004

- 17 -














See Section 3 of Plan Approval Application



2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used


VOCs NOx

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)



applicable). See Section 3 of Plan Approval Application c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques demonstrating

that the benefits of the proposed source outweigh the environmental and social costs (if applicable).

See Section 1 of Plan Approval Application.

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of Article III and applicable requirements of the Clean Air Act adopted thereunder The Department may request additional information to evaluate the application such as a standby plan, a plan for air pollution emergencies, air quality modeling, etc. See Section 2 and Appendix D of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

- 19 -






Monitoring:




Testing:



Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -


1. Estimated Atmospheric Emissions*

Pollutant



PM 0.052 0.0065 vendor data

PM10 0.052 0.0065 vendor data

SOx 0.0025 0.00032 fuel sulfur limit

CO 0.47 0.059 vendor data

NOx 1.41 0.18 vendor data

VOC 0.052 0.0065 vendor data

Others: ( e.g., HAPs) ----- ----- ----- -----

total HAPs 7.79E-4 AP-42 emission factors



Stack Designation/Number Stack6


ENG2




0.42

f. Weather Cap

YES NO


145


No


Location of stack**



Stack6 41 19 38.31 77 45 25.74

Stack exhaust


Indicate on an attached sheet the location of sampling ports with respect to exhaust fan, breeching, etc. Give all necessary dimensions.



2700-PM-AQ0007 Rev. 7/2004

- 21 -




2700-PM-AQ0021 Rev. 6/2004

- 2 -

Section B - Combustion Unit Information

1. Combustion Units: Coal Oil Natural Gas Other:

Description: two identical auxilary boilers

Manufacturer Cleaver Brooks or similar

Model No. TBD

Number of units 2

Maximum heat input (Btu/hr) 66 MMBtu/hr

Rated heat input (Btu/hr) 66 MMBtu/hr

Typical heat input (Btu/hr) 66 MMBtu/hr

Furnace Volume TBD

Grate Area (if applicable) NA

Method of firing NA

Indicate how combustion air is supplied to boiler outdoor air supply

Indicate the Steam Usage: Steam is provided to steam turbine and auxiliary steam system on start-up, during maintenance shutdown, and for the steam turbine sealing system.

Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed

iv. Other v. Frequency of Cleaning

Maximum Operating schedule

Hours/Day NA

Days/Week NA

Days/Year NA

Hours/Year NA

Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)


Per hour 66 MMBtu/hr per unit

Per day 1,584 MMBtu/day per unit

Per week 11,088 MMBtu/week per unit

Per year 145,200 MMBtu/yr total both boilers (limit)

Typical Operating schedule

Hours/Day as needed

Days/Week as needed

Days/Year as needed

Hours/Year as needed

Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: NA From to Operating using secondary fuel: Form to Non-operating: From to

2. Specify the primary, secondary and startup fuel. Furnish the details in item 3. primary fuel is natural gas; no secondary fuel

2700-PM-AQ0021 Rev. 6/2004

- 3 -

Section B - Combustion Unit Information (Continued)

3. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas primary

64,706 SCFH

142.353 cf X

106

0.4 gr/100 SCF 0

1020 Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Coal

Other*

* Note: Describe and furnish information separately for other fuels in Addendum B.

4. Burner

Manufacturer TBD

Model Number TBD

Type of Atomization (Steam, air, press, mech., rotary cup) NA

Number of Burners 1

Maximum fuel firing rate (all burners) 64,706 cfh

Normal fuel firing rate varies

If oil, temperature and viscosity. NA

Maximum theoretical air requirement TBD

Percent excess air 100% rating TBD

Turndown ratio TBD

Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe. TBD

Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. spark ignition

5. Nitrogen Oxides (NOx) control Options

Mark and describe the NOx control options adopted

Low excess air (LEA) Over fire air (OFA) Low-NOx burner X Low NOx burners with over fire

air

Flue gas recirculation X Burner out of service Reburning Flue gas treatment (SCR /

SNCR)

Other.

2700-PM-AQ0021 Rev. 6/2004

- 4 -



Describe fly ash reinjection operation Not applicable

Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.

TBD


New source - not applicable

Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.

Not applicable

Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).

Not applicable

Anticipated milestones:

Expected commencement date of construction/reconstruction: October 2020

Expected completion date of construction/reconstruction: January 2023

Anticipated date(s) of start-up: April – November 2023

2700-PM-AQ0021 Rev. 6/2004

- 5 -



Emission Rate

Pollutant



PM 0.13 2200 0.14 AP-42 factor

PM10 0.13 2200 0.14 AP-42 factor

SOx 0.038 2200 0.042 BACT

CO 2.38 2200 2.61 vendor data

NOx 0.40 2200 0.44 LAER

VOC 0.13 2200 0.15 LAER

Others: (e.g., HAPs) ----- ----- ----- -----

total HAPs 0.12 2200 0.13 AP-42 factors


See emission calculations contained in Attachment C.

2. Gas Conditioning

Water quenching YES NO Water injection rate GPM

Radiation and convection cooling YES NO Air dilution YES NO

If YES, CFM

Forced draft YES NO Water cooled duct work YES NO

Other

Inlet volume

ACFM@ °F

Outlet volume

ACFM@ °F % Moisture


2700-PM-AQ0021 Rev. 6/2004

- 6 -


3. Inertial and Cyclone Collectors NOT APPLICABLE

Manufacturer

Type

Model No.

Pressure Drop (in. of water)

Inlet Volume

ACFM @ °F

Outlet Volume


Number of Individual Cyclone(s) Outlet Straightening Vanes Used? Yes No

Length of Cyclone(s) Cylinder (ft)

Diameter of Cyclone(s) Cylinder

Length of cyclone(s) cone (ft)

Inlet Diameter (ft) or Duct Area (ft2) of Cyclone(s) Outlet Diameter (ft) or Duct area (ft2) of cyclone(s)




Emission data


2700-PM-AQ0021 Rev. 6/2004

- 7 -




Manufacturer

Model No. Pressurized Design

Suction Design




Yes No


Yes No


Yes No


Type of Fabric





Filter dimensions Diameter/Width







ACFM °F



If compressed air is required for collector operation, describe the equipment with the compressor to provide dry air free from oil.





Emissions Data


2700-PM-AQ0021 Rev. 6/2004

- 8 -


5. Wet Collection Equipment: NOT APPLICABLE


Manufacturer

Type

Model No.









@ °F


@ °F % Moisture


Describe scrubber liquid supply system (amount of make-up and recirculating liquid, capacity of recirculating liquid system, etc).



Emissions Data


2700-PM-AQ0021 Rev. 6/2004

- 9 -



Equipment specifications

Manufacturer

Model No.

Wet Dry


Gas distribution grids YES NO

Design inlet volume (SCFM) Maximum operating temperature (°F)


Number of fields Number of collector plates/field . Spacing between collector plates inches.

Maximum gas velocity ft/sec. Minimum gas treatment time: sec.


Number of discharge electrodes Number collecting electrode rappers

Rapper control Magnetic Pneumatic Other

Describe in detail

Operating parameters



State pressure drop range (water gauge) across collector only. Describe the equipment.


Power requirements



KVA

Each Rectifier

KV Ave./Peak MaDC

Current density Micro amperes/ft2

Corona power Watts/1000 ACFM

Corona power density Watts/ft2




Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 10 -


7. Absorption Equipment: NOT APPLICABLE


Manufacturer

Type

Model No

Design inlet volume (SCFM)

Tower height (ft) and inside diameter (ft)


Height of packing (ft) (if applicable)



Configuration: Counter-current Cross flow Cocurrent flow

Describe pH and/or other monitoring and controls


Absorbent type and concentration

Sorbent injection rate

Retention time (sec)

Attach equilibrium data for absorption (If applicable).

Attach any additional information regarding auxiliary equipment, reagent (slurry mix) supply system (once through or recirculating, system capacity, etc) to thoroughly evaluate the control equipment. Indicate the flow rates for makeup, bleed and recirculation.




Pressure drop (in of water) and liquid flow rate. Describe the equipment.



Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 11 -


8. SELECTIVE CATALYTIC REDUCTION (SCR)

SELECTIVE NON-CATALYTIC REDUCTION (SNCR)

NON-SELECTIVE CATALYTIC REDUCTION (NSCR) NOT APPLICABLE


Manufacturer

Type

Model No




Attach efficiency and other pertinent information (e.g., Ammonia, urea slip).


Volume of gases handled (ACFM) @ (°F)

Operating temperature range for the SCR/SNCR/NSCR system (°F)

From

To

Reducing agent used, if any.

Oxidation catalyst used, if any.



Ammonia slip (ppm)

Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation.


Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 12 -


9. Other Control Equipment: NOT APPLICABLE


Manufacturer

Type

Model No


Capacity



Attach efficiency curve and/ or other efficiency information.




@ °F % Moisture

Describe, in detail, important parameters and method of operation.


Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 13 -




Device Direct Cost Indirect Cost Total Cost Operating Cost

11 MISCELLANEOUS


Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).

Attach the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.

2700-PM-AQ0021 Rev. 6/2004

- 14 -



Not applicable. New facility.

If this project is subject to any one of the following, attach a demonstration to show compliance with applicable standards

a. Prevention of Significant Deterioration permit (PSD), 40 CFR Part 52? YES NO

b. New Source Review, 25 Pa. Code Chapter 127, Subchapter E? YES NO

c. New Source Performance Standards, 40 CFR Part 60? YES NO


d. National Emissions Standards for Hazardous Air Pollutants (NESHAPS), 40 CFR Part 61? YES NO

If Yes, which subpart)

e. Maximum Achievable Control Technology (MACT), 40 CFR Part 63? YES NO

(If Yes, which subpart) ZZZZ

Attach a demonstration showing that the emissions from any new source will be the minimum attainable through the use of best available technology (BAT).


Provide emission increases and decreases in allowable (or potential) and actual emissions within the last 5 years for applicable PSD pollutant(s) if the facility is an existing major facility (for PSD purposes)

Not applicable

2700-PM-AQ0021 Rev. 6/2004

- 15 -


Indicate emission increases and decreases in tons per year (tpy), for volatile organic compounds (VOCs) and nitrogen oxides (NOx) for NSR applicability since January 1, 1991 or other applicable dates (See other applicable date in instructions). The emissions increases include all emissions including stack, fugitive, material transfer, other emission generating activities, quantifiable emissions from the exempted source(s), etc.

Permit number

(if applicable)

Date issued



decreases were used

previously for netting Source I.D. or Name

VOCs NOx

Emission increases

in potential to emit (tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


Creditable emission

decreases in actual

emissions (tpy)


emission offsets. See Appendix Q of Plan Approval Application. b. Provide a demonstration that the lowest achievable emission rate (LAER) control techniques will be implemented (if

applicable). See Section 3 of Plan Approval Application. c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques

demonstrating that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1 of Plan Approval Application.

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of 25 Pa. Code Article III and applicable requirements of the Clean Air Act and regulations adopted there under. The Department may request additional information to evaluate the application such as a stand by plan, a plan for air pollution emergencies, air quality modeling, etc.

See Section 2 and Appendix D of Plan Approval Application.

2700-PM-AQ0021 Rev. 6/2004

- 16 -


Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.



Monitoring: a. Monitoring device type (stack test, CEM etc.): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Testing:

a. Reference Test Method Citation:

b. Reference Test Method Description:

Recordkeeping:

Describe the parameters that will be recorded and the recording frequency:

Reporting:

a. Describe the type of information to be reported and the reporting frequency:


Work Practice Standard: Describe each

2700-PM-AQ0021 Rev. 6/2004

- 17 -


1. Estimated Maximum Emissions*

Pollutant



PM 0.0019 lb/MMBtu 0.13 0.14 AP-42 emission factor

PM10 0.0019 lb/MMBtu 0.13 0.14 AP-42 emission factor

SOx 0.00058 lb/MMBtu 0.038 0.042 BACT determination

CO 0.036 lb/MMBtu 2.38 2.61 vendor data

NOx 0.006 lb/MMBtu 0.40 0.44 LAER determination

VOC 0.002 lb/MMBtu 0.13 0.15 LAER determination

Others: ( e.g., HAPs) ----- ----- ----- -----

Total HAPs 0.12 0.13 AP-42 emission factors



Stack Designation/Number Stack3 and Stack4


auxiliary boiler #1 and auxiliary boiler #2




3.0

Weather Cap

YES NO


440 ft from Stack3 and 230 ft from Stack4


No


Location of Stack**

Latitude/Longitude

Point of Origin

Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds

Stack3

Stack4

41

41

19

19

43.82

40.79

77

77

45

45

18.41

17.34

Stack Exhaust



** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.

2700-PM-AQ0021 Rev. 6/2004

- 18 -




2700-PM-AQ0021 Rev. 6/2004

- 2 -

Section B - Combustion Unit Information

1. Combustion Units: Coal Oil Natural Gas Other:

Description: Water Bath Heaters

Manufacturer TBD

Model No. TBD

Number of units 3

Maximum heat input (Btu/hr) 15 MMBtu/hr per heater

Rated heat input (Btu/hr) 15 MMBtu/hr

Typical heat input (Btu/hr) 15 MMBtu/hr

Furnace Volume TBD

Grate Area (if applicable) NA

Method of firing NA

Indicate how combustion air is supplied to boiler outdoor air supply

Indicate the Steam Usage: Unit is a heater. The purpose of the unit is to heat a water bath that in turn heats the natural gas pipes. Three heaters will be installed, however only two will operate at a time. The third is for redundancy.

Mark and describe soot Cleaning Method: i. Air Blown ii. Steam Blown iii. Brushed and Vacuumed

iv. Other v. Frequency of Cleaning

Maximum Operating schedule

Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8,760

Operational restrictions taken or requested, if any (e.g., bottlenecks or voluntary restrictions to limit potential to emit)


Per hour 15 MMBtu/hr

Per day 360 MMBtu/day

Per week 2,520 MMBtu/week

Per year 131,400 MMBtu/year

Typical Operating schedule

Hours/Day 24

Days/Week 7

Days/Year 365

Hours/Year 8,760

Seasonal variations (Months): If variations exist, describe them. Operating using primary fuel: From to Operating using secondary fuel: Form to Non-operating: From to

2. Specify the primary, secondary and startup fuel. Furnish the details in item 3. primary fuel is natural gas; no secondary fuel

2700-PM-AQ0021 Rev. 6/2004

- 3 -


3. Fuel



Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas primary

14,706 SCFH

128.824 X 106

Gal

0.4 gr/100 SCF NA

1,020 Btu/SCF

Gas (other)

SCFH

X 106

Gal

gr/100

SCF

Btu/SCF

Coal

Other*

* Note: Describe and furnish information separately for other fuels in Addendum B.

4. Burner

Manufacturer TBD

Model Number TBD

Type of Atomization (Steam, air, press, mech., rotary cup)

Number of Burners 2

Maximum fuel firing rate (all burners) 15 MMBtu/hr

Normal fuel firing rate 15 MMBtu/hr

If oil, temperature and viscosity. NA

Maximum theoretical air requirement TBD

Percent excess air 100% rating TBD

Turndown ratio TBD

Combustion modulation control (on/off, low-high fire, full automatic, manual). Describe.

Main burner flame ignition method (electric spark, auto gas pilot, hand-held torch, other). Describe. spark ignition

5. Nitrogen Oxides (NOx) control Options

Mark and describe the NOx control options adopted

Low excess air (LEA) Over fire air (OFA) Low-NOx burner X Low NOx burners with over fire

air

Flue gas recirculation Burner out of service Reburning Flue gas treatment (SCR /

SNCR)

Other.

2700-PM-AQ0021 Rev. 6/2004

- 4 -



Describe fly ash reinjection operation Not applicable

Describe, in detail, the equipment provided to monitor and to record the source(s) operating conditions, which may affect emissions of air contaminants. Show that they are reasonable and adequate.

TBD


Not applicable

Describe how emissions will be minimized especially during start up, shut down, combustion upsets and/or disruptions. Provide emission estimates for start up, shut down and upset conditions. Provide duration of start up and shut down.

Not applicable

Describe in detail with a schematic diagram of the control options adopted for SO2 (if applicable).

Not applicable

Anticipated milestones:

Expected commencement date of construction/reconstruction: October 2020

Expected completion date of construction/reconstruction: January 2023

Anticipated date(s) of start-up: April – November 2023

2700-PM-AQ0021 Rev. 6/2004

- 5 -



Emission Rate

Pollutant



PM 0.029 8760 0.12 BACT factor

PM10 0.029 8760 0.12 BACT factor

SOx 0.0087 8760 0.038 BACT factor

CO 0.56 8760 2.43 BACT factor

NOx 0.17 8760 0.72 LAER factor

VOC 0.075 8760 0.33 LAER factor

Others: (e.g., HAPs) ----- ----- ----- -----

Total HAPs 8760 0.12 AP-42 factors


See Appendix D for emission calculations.

2. Gas Conditioning

Water quenching YES NO Water injection rate GPM

Radiation and convection cooling YES NO Air dilution YES NO

If YES, CFM

Forced draft YES NO Water cooled duct work YES NO

Other

Inlet volume

ACFM@ °F

Outlet volume

ACFM@ °F % Moisture


2700-PM-AQ0021 Rev. 6/2004

- 6 -


3. Inertial and Cyclone Collectors NOT APPLICABLE

Manufacturer

Type

Model No.

Pressure Drop (in. of water)

Inlet Volume

ACFM @ °F

Outlet Volume


Number of Individual Cyclone(s) Outlet Straightening Vanes Used? Yes No

Length of Cyclone(s) Cylinder (ft)

Diameter of Cyclone(s) Cylinder

Length of cyclone(s) cone (ft)

Inlet Diameter (ft) or Duct Area (ft2) of Cyclone(s) Outlet Diameter (ft) or Duct area (ft2) of cyclone(s)




Emission data


2700-PM-AQ0021 Rev. 6/2004

- 7 -




Manufacturer

Model No. Pressurized Design

Suction Design




Yes No


Yes No


Yes No


Type of Fabric





Filter dimensions Diameter/Width







ACFM °F



If compressed air is required for collector operation, describe the equipment with the compressor to provide dry air free from oil.





Emissions Data


2700-PM-AQ0021 Rev. 6/2004

- 8 -


5. Wet Collection Equipment: NOT APPLICABLE


Manufacturer

Type

Model No.









@ °F


@ °F % Moisture


Describe scrubber liquid supply system (amount of make-up and recirculating liquid, capacity of recirculating liquid system, etc).



Emissions Data


2700-PM-AQ0021 Rev. 6/2004

- 9 -




Manufacturer

Model No.

Wet Dry


Gas distribution grids YES NO

Design inlet volume (SCFM) Maximum operating temperature (°F)


Number of fields Number of collector plates/field . Spacing between collector plates inches.

Maximum gas velocity ft/sec. Minimum gas treatment time: sec.


Number of discharge electrodes Number collecting electrode rappers

Rapper control Magnetic Pneumatic Other

Describe in detail




State pressure drop range (water gauge) across collector only. Describe the equipment.


Power requirements



KVA

Each Rectifier

KV Ave./Peak MaDC

Current density Micro amperes/ft2

Corona power Watts/1000 ACFM

Corona power density Watts/ft2




Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 10 -


7. Absorption Equipment: NOT APPLICABLE


Manufacturer

Type

Model No


Tower height (ft) and inside diameter (ft)


Height of packing (ft) (if applicable)



Configuration: Counter-current Cross flow Cocurrent flow

Describe pH and/or other monitoring and controls


Absorbent type and concentration

Sorbent injection rate

Retention time (sec)

Attach equilibrium data for absorption (If applicable).

Attach any additional information regarding auxiliary equipment, reagent (slurry mix) supply system (once through or recirculating, system capacity, etc) to thoroughly evaluate the control equipment. Indicate the flow rates for makeup, bleed and recirculation.




Pressure drop (in of water) and liquid flow rate. Describe the equipment.



Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 11 -


8. SELECTIVE CATALYTIC REDUCTION (SCR)

SELECTIVE NON-CATALYTIC REDUCTION (SNCR)

NON-SELECTIVE CATALYTIC REDUCTION (NSCR) NOT APPLICABLE


Manufacturer

Type

Model No




Attach efficiency and other pertinent information (e.g., Ammonia, urea slip).


Volume of gases handled (ACFM) @ (°F)

Operating temperature range for the SCR/SNCR/NSCR system (°F)

From

To

Reducing agent used, if any.

Oxidation catalyst used, if any.



Ammonia slip (ppm)

Describe fully with a sketch giving locations of equipment, controls system, important parameters and method of operation.


Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 12 -


9. Other Control Equipment: NOT APPLICABLE


Manufacturer

Type

Model No


Capacity



Attach efficiency curve and/ or other efficiency information.




@ °F % Moisture

Describe, in detail, important parameters and method of operation.


Emissions data


2700-PM-AQ0021 Rev. 6/2004

- 13 -




Device Direct Cost Indirect Cost Total Cost Operating Cost

11 MISCELLANEOUS


Attach manufacturer's performance guarantees and/or warranties for each of the major components of the control system (or complete system).

Attach the maintenance schedule for the control equipment and any part of the process equipment that, if in disrepair, would increase air contaminant emissions.

2700-PM-AQ0021 Rev. 6/2004

- 14 -




If this project is subject to any one of the following, attach a demonstration to show compliance with applicable standards

a. Prevention of Significant Deterioration permit (PSD), 40 CFR Part 52? YES NO

b. New Source Review, 25 Pa. Code Chapter 127, Subchapter E? YES NO

c. New Source Performance Standards, 40 CFR Part 60? YES NO


d. National Emissions Standards for Hazardous Air Pollutants (NESHAPS), 40 CFR Part 61? YES NO

If Yes, which subpart)

e. Maximum Achievable Control Technology (MACT), 40 CFR Part 63? YES NO

(If Yes, which subpart) ZZZZ

Attach a demonstration showing that the emissions from any new source will be the minimum attainable through the use of best available technology (BAT).

See Section 3 of Plan Approval Application

Provide emission increases and decreases in allowable (or potential) and actual emissions within the last 5 years for applicable PSD pollutant(s) if the facility is an existing major facility (for PSD purposes)


2700-PM-AQ0021 Rev. 6/2004

- 15 -


Indicate emission increases and decreases in tons per year (tpy), for volatile organic compounds (VOCs) and nitrogen oxides (NOx) for NSR applicability since January 1, 1991 or other applicable dates (See other applicable date in instructions). The emissions increases include all emissions including stack, fugitive, material transfer, other emission generating activities, quantifiable emissions from the exempted source(s), etc.

Permit number

(if applicable)

Date issued



decreases were used

previously for netting Source I.D. or Name

VOCs NOx

Emission increases


Creditable emission

decreases in actual

emissions (tpy)

Emission increases


Creditable emission

decreases in actual

emissions (tpy)


emission offsets. See Appendix Q of Plan Approval Application. b. Provide a demonstration that the lowest achievable emission rate (LAER) control techniques will be implemented (if

applicable). See Section 3 of Plan Approval Application c. Provide an analysis of alternate sites, sizes, production processes and environmental control techniques

demonstrating that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1 of Plan Approval Application

Attach calculations and any additional information necessary to thoroughly evaluate compliance with all the applicable requirements of 25 Pa. Code Article III and applicable requirements of the Clean Air Act and regulations adopted there under. The Department may request additional information to evaluate the application such as a stand by plan, a plan for air pollution emergencies, air quality modeling, etc.

See Section 2 and Appendix D of Plan Approval Application.

2700-PM-AQ0021 Rev. 6/2004

- 16 -


Note: Complete this section if the facility is not a-Title V facility. Title V facilities must complete Addendum A. Method of Compliance Type: Check all that apply and complete all appropriate sections below.



Monitoring: a. Monitoring device type (stack test, CEM etc.): b. Monitoring device location: c. Describe all parameters being monitored along with the frequency and duration of monitoring each parameter:

Testing:

a. Reference Test Method Citation:

b. Reference Test Method Description:

Recordkeeping:

Describe the parameters that will be recorded and the recording frequency:

Reporting:

a. Describe the type of information to be reported and the reporting frequency:


Work Practice Standard: Describe each

2700-PM-AQ0021 Rev. 6/2004

- 17 -


1. Estimated Maximum Emissions*

Pollutant



PM 0.029 0.12 BACT factor

PM10 0.029 0.12 BACT factor

SOx 0.0087 0.038 BACT factor

CO 0.56 2.43 BACT factor

NOx 0.17 0.72 LAER factor

VOC 0.075 0.33 LAER factor

Others: ( e.g., HAPs) ----- ----- ----- -----

Total HAPs 0.12 AP-42 factors



Stack Designation/Number HTR


Water bath heater


Stack height above grade (ft.) 15’ Grade elevation (ft.) 670


8”

Weather Cap

YES NO


TBD


No


Location of Stack**

Latitude/Longitude

Point of Origin

Latitude Longitude

Degrees Minutes Seconds Degrees Minutes Seconds

TBD

Stack Exhaust



** If the datum and collection method information and codes differ from those provided on the General Information Form - Authorization Application, provide the additional required by that form on a separate sheet.

2700-PM-AQ0021 Rev. 6/2004

- 18 -




POWER ENGINEERS, INC. Plan Approval Application – Non-Attainment Area Requirements – Renovo Energy Center, LLC

PAGE i

TABLE OF CONTENTS

6.0 NON-ATTAINMENT AREA REQUIREMENTS ....................................................................... 1

6.1 EMISSION REDUCTION CREDITS (ERCS) ....................................................................................... 1 6.2 COMPLIANCE WITH LOWEST ACHIEVABLE EMISSION RATE (LAER) .......................................... 1 6.3 COMPLIANCE WITH ALL APPLICABLE EMISSION LIMITS AND STANDARDS IN PENNSYLVANIA ... 2 6.4 ANALYSIS OF ALTERNATIVE SITES, SIZES, PROCESSES, AND CONTROL TECHNIQUES ................. 2

6.4.1 Alternative Sites .................................................................................................................... 2 6.4.2 Alternative Sizes ................................................................................................................... 3 6.4.3 Alternative Processes ............................................................................................................ 4 6.4.4 Alternative Control Techniques ............................................................................................ 4

6.5 CONCLUSION ................................................................................................................................. 4


PAGE 1


To obtain a permit to construct and operate a nominally rated 1,240 MW (net) combined cycle electric generating plant in Renovo, PA, which is part of the Ozone Transport Region (OTR), Renovo Energy Center LLC (REC) must meet the requirements for locating in a non-attainment area as found in Part D, Subpart 1, Section 173 of the Federal Clean Air Act. Section 173 and PaDEP Chapter 127 requires that prior to issuance of a permit to construct and operate, applicants must:

• Prior to commencement of operations, applicant must demonstrate that sufficient emissions offsets have been obtained such that the total allowable emissions from existing sources in the region, new or modified minor sources, and from the proposed sources will be sufficiently less than emissions from existing sources prior to application for such permit to construct and operate the sources;

• Comply with lowest achievable emission rate for non-attainment pollutants;

• Demonstrate that owner or operator of the proposed sources demonstrates that all major sources owned or operated by such entity in Pennsylvania are in compliance, or on a schedule for compliance, with all applicable limitations and standards; and

• Conduct an analysis of alternative sites, sizes, processes, and environmental controls that demonstrate the benefits of the proposed sources significantly outweigh the environmental and social costs of its location and construction.

The balance of this section addresses the requirements listed above.

6.1 Emission Reduction Credits (ERCs)

REC’s maximum potential Nitrogen Oxides (NOx) and Volatile Organic Compounds (VOC) emissions are summarized in Section 1 of this application. Based on the preliminary estimates contained in Section 1 and Attachment D, REC will be required to obtain offsets for both NOx and VOC as the potential emissions are greater than the Pennsylvania Code 127.201 thresholds of 100 tons and 50 tons per year, respectively.

REC has reviewed the Pennsylvania Emissions Reduction Credit registry to identify potential sources for obtaining ERCs to offset potential project emissions. REC will obtain the necessary ERCs at the Pennsylvania Code 127.210 offset ratio of 1.15:1 for NOx emissions and VOC flue emissions and 1.3:1 for fugitive VOC emissions.

REC has included the currently available ERCs for use in Pennsylvania in Appendix Q.

6.2 Compliance with Lowest Achievable Emission Rate (LAER)

REC has prepared BACT/LAER/BAT analyses for all combustion equipment that are contained in Section 3 of this application. LAER determinations for NOx and VOC are included in these analyses and summarized in Section 3.


PAGE 2

6.3 Compliance with All Applicable Emission Limits and Standards in Pennsylvania

REC does not own or operate any facilities in Pennsylvania, thus there are no compliance issues with any emission limits or standards.

6.4 Analysis of Alternative Sites, Sizes, Processes, and Control Techniques

6.4.1 Alternative Sites

Due to the forecasted increase in electricity demand in the service area, the anticipated retirements of old, inefficient coal units in the next 10+ years, and the increased production and reliable availability of shale gas, REC focused on the PJM region for siting a large-scale natural gas combined cycle (NGCC) generation facility. Information was gathered relative to electrical transmission line mapping, gas line mapping and existing generating facilities and competitive development.

Energy Security Analysis, Inc. (ESAI) was engaged in February 2014 to provide support in helping to identify the most optimal locations in PJM to potentially develop plants. ESAI evaluated favorable energy and capacity prices, transmission capacities and availability of natural gas supplies in order to rank the regions and sites.

REC focused primarily on Pennsylvania and high population areas such as Kearney, NJ (Newark), Pensauken, NJ (Philadelphia) and Baltimore, MD. Pensauken had major limitations on gas supply while Kearney and Baltimore were expected to require excessively long and expensive development; further, ESAI’s overall evaluation for these three sites indicated that the PA sites were more attractive, primarily attributable to the local shale gas resource, thus REC’s focus was limited to the PA areas. Although central and western Pennsylvania have plenty of 230-kilovolt (kV) and higher lines networking through the area, major gas lines are of lesser number and accessibility is made very difficult by extremely steep terrain. One must also consider a good part of the western portion of the state has been heavily undermined for coal, making the identification of a suitable site for a power plant very difficult.

For assessment purposes, the state was divided into four areas:

• Homer City (old coal plants that could be displaced by new highly efficiency NGCC plants); • Juniata (old coal plants that could be displaced by new highly efficiency NGCC plants); • Moshannon/Leidy/Milesburg (abundant low-cost gas); and • Susquehanna (proximity to population centers).

In March 2014 REC conducted an assessment over a wide geographical region focusing on the areas of Homer City, Juniata, Leidy – Milesburg, and Susquehanna, visiting more than 16 potential sites. The Susquehanna area ranked lowest in ESAI’s evaluation and was also competing on the 230-kV system with the two Panda projects (Patriot and Liberty), Sunbury Repowering, and Good Springs, at a minimum. Major gas lines in the area of Susquehanna were identified to the south but REC’s search did not identify any sites with suitable gas, power and terrain in the Susquehanna area.

The Homer City area was divided into four search areas to the north and four to the south. The areas north of Homer City were either very hilly with considerable residential development, steep terrain with very


PAGE 3

poor roads, suitable land with residential development/no support, or very remote with steep/undulating terrain; no suitable site for the project was identified in any of the four northern search areas.

Two of the Homer City south areas were located on 230-kV lines that cross the Texas Eastern gas line in very remote areas. Roads and topography are so poor that construction would be imprudently costly. The other two Homer City south search areas were similar to the previous two south areas, but a potential site was identified in New Florence a few miles north of the Seward and Conemaugh existing power plants. The site was level, large enough and next to a 500-kV line and major gas line on the site. However, after consulting coal mining maps it was discovered that the entire area was mined with long wall mining years ago, thus it was not suitable for the construction of a power plant.

REC also assessed the Juniata/Roxbury/Lewistown/Harrisburg area. While the general area did have access to a 500-kV line as well as a 30” gas line, a combination of residential area and large productive farms made the siting of a power plant difficult. In addition, previous efforts at developing independent power plants met strong local opposition. Any potential sites identified in the general area located away from residential or farms were extremely steep and un-buildable terrain.

REC also searched the Moshannon/Leidy Hub area, initially focusing on the areas where the existing gas and transmission lines are close together, however no flat land of adequate size was identified. A potential site was discovered in Renovo at the abandoned Industrial Park, which was the former P&E railyard. This is the site being proposed in this application.

6.4.2 Alternative Sizes

All major combustion turbine manufacturers offer model units in a variety of electrical output sizes. Each time a more efficient model is introduced from each manufacturer, the units are larger with more gross electrical output. Currently the most efficient models from the major manufacturers are all in the 500-600 Megawatt (MW) range for a single unit in combined cycle configuration. While smaller sized units are available, they are older technology and less efficient.

Given REC’s commitment to choose from among the most efficient combustion turbine technologies currently available, REC had to pick in increments of approximately 500-600 MW and decide on number of units for the facility. In general, a 500-600 MW single unit plant is not nearly as economical to build and operate as a multi-unit plant and will require above market electric pricing to survive. The 1,000-1,200 MW range is the most common in many cases due to ability to export the power on nearby transmission lines. Larger plants in the 1,500-1,800 MW range are extremely difficult to site. This difficulty is mainly due to lack of available connection to high voltage transmission lines (345-kV or 500-kV), as well as the need for more make-up water, fuel and land.

REC selected a two-unit, 1,240 MW facility, utilizing among the most efficient technology available today, due to the limited transmission line capacity for exporting additional electrical power and the physical limitation on the site acreage, both of which prevented going to a larger plant. REC was also influenced by the market’s ability to more readily absorb a plant of this size versus a three-unit, 1,500-1,800 MW design. Single unit plants (i.e., approximately 500-600 MW) do not routinely meet the financial requirements of investors and lenders.


PAGE 4

6.4.3 Alternative Processes

Modern NGCC plants are considered an efficient technology for generating large scale electricity, in particular when compared to the traditional boiler/steam cycle. Some advantages of the NGCC technology include:

• NGCC plant has higher efficiency than a turbine cycle or steam cycle plant; • NGCC plants meet rapid start and shutdown demands when compared to the steam power plant,

making NGCC ideal for quickly accepting load variations, which helps in maintaining the stability of the electrical grid;

• NGCC plant capital costs are slightly higher than a simple combustion turbine plant and well below the cost of a traditional steam turbine power plant;

• NGCC plant cooling water demands are much less than conventional steam turbine power plant; • NGCC plants have high ratio of power output to the physical plant footprint/area, thus a NGCC

requires less space for equal output; • NGCC plants have lower operational, maintenance, and personnel costs; • NGCC plants typically have higher dispatch availability than a traditional steam turbine plant;

and • NGCC plants have lower pollutant emissions on a lb/MW output, especially CO2.

For the reasons listed above, REC has not identified an alternative process that warrants consideration.

6.4.4 Alternative Control Techniques

REC is proposing state of the art control technologies, including low NOx combustors, selective catalytic reduction (SCR), and an oxidation catalyst that will control potential emissions to meet stringent LAER/BACT/BAT limits. No technically feasible alternative control techniques have been identified that will provide better pollution control performance. Section 3 contains REC’s LAER/BACT/BAT analysis.

6.5 Conclusion

Following an assessment of alternative sites, alternative sizes, alternative processes, and alternative control technologies, REC proposes to construct a nominally rated 1,240 MW (net) dual fuel (natural gas and ultra-low sulfur diesel) combined cycle electric generating plant in Renovo, Pennsylvania. REC’s proposed plant will meet LAER for NOx and VOC and will offset emissions of these non-attainment pollutants by obtaining ERCs in amounts that satisfy all appropriate offset ratios.


APPENDIX A FACILITY SITE LOCATION ON USGS TOPOGRAPHICAL MAP

!

Renovo Energy Center LLC

Ü

Facility Location

Name:

Date:

Scale:

12/17/20191:24,0001" = 2,000 ft

Location:

Caption:

Renovo, PAFacility location: 41.328114°, -77.756102°

Renovo Energy Center LLCRenovo, PASite Location Map

!

Facility Location

West Virginia

Ohio

New York

MarylandNew

Jersey

Pennsylvania

Virginia


APPENDIX B RENOVO ENERGY CENTER SITE PLAN

0 100 200 300FT

A

B

C

D

23456

REV

SCALE DESIGNED DRAWNCHIEF

ENGR

NO. DATE REVISIONS BY CHKDESIGN

SUPVENGR

PROJ

ENGR

DRAWING NO.JOB NO.

LEVELS12345678 0 23 678901234567890123456789012345678901234567890123

1 11 111122222222223333333333444444444455555555 56666PSC= :1 :

1

5

REF DFN=[ ] . DFN=[ ] . 22 x 34 "D" SIZE

9

5

PLOT PLAN

P1-0010-00001

A

B

C

D

E

F

N

NNE

NE

ENE

E

ESE

SE

SSES

SSW

SW

WSW

W

WNW

NW

NNW

LABELS OF PERCENT FREQUENCY ON NORTH AXIS

1-5 KNOTS6-14 KNOTS15-24 KNOTS

WIND ROSE

B D F

C

C

A

RENOVO ENERGY CENTERCLINTON COUNTY, PA

A

26081-000

G

G

SW -

C

N 423,500.00

E 1,967,075.00

SWAS NOTED SW

E

E

EXISTING STORM

WATER PIPE

EXISTING STORM

WATER PIPE

ISSUED FOR REVIEW

N 423,190.83

E 1,967,157.56

INCOMING GAS PIPELINE

WETLANDS

EMERGENCY PATHWAY

JVGJVG - VS08

0216

MISC. Electrical Testing EQUIPMENT

STG EXCITATION

STEAM TURBINE EQUIPMENT

MISC. Electrical Testing EQUIPMENT

STG EXCITATION

STEAM TURBINE EQUIPMENT

RESERVED SPACE

FOR BUILD. UTILITIES

SPAREEQUIPSPACE

B ISSUED FOR REVIEW SW JVG JVG - VS08

0516

C ISSUED FOR REVIEW DB DB -12

2019

RAPJRB

A

B

C

D

23456

REV

SCALE DESIGNED DRAWNCHIEF

ENGR

NO. DATE REVISIONS BY CHKDESIGN

SUPVENGR

PROJ

ENGR

DRAWING NO.JOB NO.

LEVELS1 2 3 4 5 6 7 8 0 1 2 3 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 3

1 1 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2 2 3 3 3 3 3 3 3 3 3 3 4 4 4 4 4 4 4 4 4 4 5 5 5 5 5 5 5 5 5 6 6 6 6PSC= :1 :

BECHTEL

1 1

4 5

REF DFN=[ ] . DFN=[ ] . 22 x 34 "D" SIZE

FREDERICK, MARYLAND

9

5

RENOVO ENERGY CENTERCLINTON COUNTY, PA

A

26081-000

-

0 100 200 300FT

P1-0090-00001

REFERENCE DRAWING:

26081-000-P1-0010-00001 - PLOT PLAN

FUEL OIL STORAGE TANK (OPTION)ADMINSTRATIVE \ WAREHOUSE BUILDING

HEAT RECOVERY STEAM GENERATOR (HRSG)

ELEV 262.00 FT

TURBINE BUILDING

ELEV 83.00 FTELEV 93.00 FT

DEMINERALIZED WATER STORAGE TANK

WASTE WATER STORAGE TANK

AIR COOLED CONDENSER (ACC)

ELEV 0.00 FT

ELEV 106.00 FT

TURBINE BUILDING HEAT RECOVERY STEAM GENERATOR (HRSG)

LOW BAY

TURBINE BUILDING

BOILER FEEDPUMP

BUILDING

ISOPHASE BUS

MAIN SWITCHGEAR BUILDING

FIRE WALL MAIN TRANSFORMER

B

LKG EAST

LKG NORTH

ISSUED FOR REVIEW

ELEV 0.00 FT

ELEV 18.05 FT

MAIN SWITCHGEAR AND BATTERY ROOM

STEAM DUCT

SERVICE WATER \ FIRE WATER STORAGE TANK

ELEV 50.00 FT

WATER TREATMENT BUILDING

STEAM DUCT

COMBUSTION TURBINE

AIR INLET FILTER

LEC COMBINED

LCI MODULE

LEC \ LCI BUILDING MAIN TRANSFORMER

ELEVATION VIEWS

ELEVATION B

ELEVATION A

AUXILARY BOILER

ELEV 45.00 FT

ELEV 20.00 FT

922

16JVG JVGVS VS

ISSUED FOR REVIEW DBDBB -

-

B

AUX BOILER STACK

JRB RAP12

2019


APPENDIX C PROCESS FLOW DIAGRAMS FOR POWER BLOCKS

HP Steam

Natural 38,410 lb/hr

Gas 150,000 lb/hr

Hot Reheat Steam

ULSD 0 lb/hr Cold Reheat Steam

(backup)

Water LP Steam

(backup)

6,047,500 lb/hr

176 F

StackExhaust(CEMS)

Air

Cooled

Condenser MakeupAir Water

Duct

Burner

Ammonia Injection

Notes:1. ULSD = Ultra Low Sulfur Diesel

2. For a single shaft unit, there is no separate generator for the steam turbine; the steam

turbine drives the same generator as the gas turbine.

3. GT water injection used only for ULSD operation.

4. Data shown reflects operation at 59oF ambient temperature. Rev Sheet # of

B 1 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

December 19, 2019

Heat Recovery

Steam GeneratorWater

Renovo Energy Center

Cycle Schematic

GE 7HA.02 (Natural Gas Operation)

Date

HP Steam

Natural 0 lb/hr

Gas 0 lb/hr

Hot Reheat Steam

ULSD 194,470 lb/hr Cold Reheat Steam

(backup)

Water LP Steam

(backup)6,152,600 lb/hr

281 F

StackExhaust(CEMS)

Air

Cooled

Condenser MakeupAir Water

Duct

Burner

Ammonia Injection

Notes:1. ULSD = Ultra Low Sulfur Diesel

2. For a single shaft unit, there is no separate generator for the steam turbine; the steam

turbine drives the same generator as the gas turbine.

3. GT water injection used only for ULSD operation.

4. Data shown reflects operation at 59oF ambient temperature. Rev Sheet # of

B 1 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

December 16, 2019

Heat Recovery

Steam GeneratorWater

Renovo Energy Center

Cycle Schematic

GE 7HA.02 (ULSD Operation)

Date


APPENDIX D DETAILED EMISSION CALCULATIONS

Renovo Energy CenterFacility-Wide Maximum Potential EmissionsTons Per Year

PollutantPower-blocks

Auxiliary Boilers

Diesel Generator

Diesel Fire Pump Heater

ULSD storage tank

Circuit Breakers

Facility-Wide Total

NOx 355.17 0.87 5.45 0.18 2.72 --- --- 364.4CO 356.78 5.23 1.50 0.059 5.93 --- --- 369.5PM10 211.92 0.28 0.16 0.0065 0.27 --- --- 212.6VOC 110.73 0.29 0.97 0.0065 0.73 0.042 --- 112.8SO2 53.48 0.084 0.0055 0.00032 0.084 --- --- 53.6NH3 277.36 --- --- --- --- --- --- 277.4Lead 0.042 --- --- --- --- --- --- 0.042CO2 5,413,496 16,949 582.92 33.44 16,852 --- --- 5,447,914CH4 82.26 0.32 0.024 0.0014 0.32 --- --- 82.9N2O 10.21 0.032 0.0047 0.00027 0.032 --- --- 10.3SF6 --- --- --- --- --- --- 0.0080 0.0080CO2e 5,418,594 16,967 584.92 33.55 16,869 --- 182.97 5,453,232H2SO4 35.40 0.013 --- --- --- --- --- 35.4HAPs 19.87 0.27 0.014 0.00078 0.27 --- --- 20.4Hexane1 7.36 0.26 --- --- 0.25 --- --- 7.91 Hexane is the single HAP with the highest potential emissions.

December 2019

Renovo Energy CenterRaw Data for General Electric Equipment

OPERATING POINT 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21Ambient Temperature °F -20 95.8 59 95.8 -0.7 59 95.8 -20 35 59 95.8 -0.7 59 95.8 -20 95.8 59 95.8 -20 59 95.8Ambient Pressure psia 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35 14.35Ambient Relative Humidity % 60 35 60 35 60 60 35 60 60 60 35 60 60 35 60 35 60 35 60 60 35

PLANT STATUSSCR/CO Catalyst Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingEvaporative Cooler State1 on/off Off Off On On Off Off Off Off Off Off Off Off Off Off Off Off On On Off On OnGas Turbine Load % 100% 100% 100% 100% 38% 30% 32% 100% 100% 100% 100% 60% 50% 50% 100% 100% 100% 100% 100% 100% 100%Duct Burner Status on/off Off Off Off Off Off Off Off Off Off Off Off Off Off Off On On On On On Off OffTurbine Diluent Injection Type None None None None None None None Water Water Water Water Water Water Water None None None None None Water WaterDiluent Injection Flow klb/hr -- -- -- -- -- -- -- 260.8 266.4 266.4 249.8 151.8 120.1 109.8 -- -- -- -- -- 266.4 254.2

FUEL DATAFuel Type NG NG NG NG NG NG NG DO DO DO DO DO DO DO NG NG NG NG NG DO DOHHV Btu/lb 23,607 23,607 23,607 23,607 23,607 23,607 23,607 20,130 20,130 20,130 20,130 20,130 20,130 20,130 23,607 23,607 23,607 23,607 23,607 20,130 20,130LHV Btu/lb 21,292 21,292 21,292 21,292 21,292 21,292 21,292 18,300 18,300 18,300 18,300 18,300 18,300 18,300 21,292 21,292 21,292 21,292 21,292 18,300 18,300Fuel Molecular Weight lb/lbmole 16.52 16.52 16.52 16.52 16.52 16.52 16.52 n/a n/a n/a n/a n/a n/a n/a 16.52 16.52 16.52 16.52 16.52 n/a n/aFuel Bound Nitrogen Wt % 0 0 0 0 0 0 0 ≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015% 0 0 0 0 0 ≤ 0.015% ≤ 0.015%Fuel Sulfur Content ppmw 13.1 13.1 13.1 13.1 13.1 13.1 13.1 15 15 15 15 15 15 15 13.1 13.1 13.1 13.1 13.1 15 15GT Heat Consumption2 MMBtu/hr HHV 3,523.8 3,230.1 3,541.1 3,459.2 1,837.7 1,516.3 1,470.6 3,940.4 3,892.8 3,848.4 3,588.7 2,646.6 2,258.0 2,109.7 3,523.8 3,230.1 3,541.1 3,459.2 3,523.8 3,914.6 3,824.7DB Heat Consumption2 MMBtu/hr HHV 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,001.9 821.6 906.8 878.2 1,005.3 0.0 0.0Total Heat Consumption MMBtu/hr HHV 3,523.8 3,230.1 3,541.1 3,459.2 1,837.7 1,516.3 1,470.6 3,940.4 3,892.8 3,848.4 3,588.7 2,646.6 2,258.0 2,109.7 4,525.7 4,051.7 4,447.9 4,337.4 4,529.1 3,914.6 3,824.7

HRSG EXIT EXHAUST GASStack N2 mole fraction - 0.7474 0.7326 0.7374 0.7266 0.75 0.7445 0.7377 0.7058 0.7001 0.6947 0.6889 0.7147 0.7113 0.7071 0.738 0.7244 0.7289 0.7184 0.738 0.6938 0.6862Stack O2 mole fraction - 0.1149 0.1115 0.1108 0.1086 0.1233 0.126 0.1262 0.09819 0.09532 0.09332 0.09369 0.1035 0.103 0.1052 0.08825 0.08783 0.08635 0.0846 0.08816 0.09297 0.09254Stack AR mole fraction - 0.0089 0.008724 0.008781 0.008653 0.008932 0.008865 0.008785 0.008406 0.008338 0.008274 0.008205 0.008511 0.008471 0.008422 0.008788 0.008626 0.008679 0.008554 0.008788 0.008263 0.008172Stack H2O mole fraction - 0.0852 0.1039 0.09875 0.1122 0.07808 0.0831 0.09079 0.1243 0.132 0.1391 0.1459 0.1121 0.1163 0.1205 0.1092 0.125 0.1206 0.1335 0.1093 0.1402 0.1496Stack CO2 mole fraction - 0.04344 0.04314 0.04418 0.04381 0.03958 0.03744 0.03641 0.06314 0.06407 0.06444 0.06312 0.06111 0.06083 0.05857 0.05561 0.05397 0.05533 0.05478 0.05565 0.06453 0.0634Molecular Weight lb/lbmole 28.42 28.21 28.28 28.13 28.46 28.39 28.29 28.27 28.19 28.12 28.03 28.38 28.33 28.26 28.26 28.08 28.14 27.99 28.26 28.11 28.00Temperature °F 185.2 190.5 181.4 194 163.1 160.3 166.9 291.5 284.5 280 288.3 259.6 243.4 251.2 172.8 178.6 176.3 182.2 180.5 281.3 293.8Mass Flow lb/hr 6,111,200 5,598,900 6,007,200 5,885,500 3,505,200 3,050,800 3,032,500 6,366,300 6,181,400 6,059,300 5,751,100 4,436,300 3,795,900 3,674,700 6,155,800 5,635,400 6,047,500 5,924,500 6,155,900 6,152,600 6,093,500Volume Flow scf/hr (60°F) 81,604,584 75,312,363 80,617,373 79,407,353 46,734,281 40,781,955 40,670,960 85,461,030 83,198,246 81,767,914 77,853,532 59,317,047 50,841,652 49,342,117 82,648,282 76,168,273 81,562,002 80,322,176 82,651,792 83,061,790 82,598,636

acf/hr 103,700,000 96,501,000 101,850,000 102,280,000 57,353,000 49,823,000 50,219,000 126,510,000 122,010,000 119,190,000 114,760,000 84,074,000 70,446,000 69,122,000 103,010,000 95,811,000 102,230,000 101,600,000 104,270,000 121,290,000 122,650,000acf/min 1,728,333 1,608,350 1,697,500 1,704,667 955,883 830,383 836,983 2,108,500 2,033,500 1,986,500 1,912,667 1,401,233 1,174,100 1,152,033 1,716,833 1,596,850 1,703,833 1,693,333 1,737,833 2,021,500 2,044,167fps 75.778 70.517 74.426 74.740 41.910 36.408 36.697 92.446 89.157 87.097 83.860 61.436 51.478 50.510 75.273 70.013 74.703 74.243 76.194 88.631 89.625

HRSG EXIT EXHAUST GAS EMISSIONSppmvd @ 15% O2 25 25 25 25 25 25 25 42 42 42 42 42 42 42 25 25 25 25 25 42 42lb/hr as NO2 320.00 292.50 321.25 313.75 166.25 137.50 133.75 745.00 736.25 727.50 678.75 500.00 426.25 398.75 416.25 371.25 408.75 397.50 416.25 740.00 722.50ppmvd @ 15% O2 2 2 2 2 2 2 2 4 4 4 4 4 4 4 2 2 2 2 2 4 4

lb/MMBtu 0.0073 0.0072 0.0073 0.0073 0.0072 0.0073 0.0073 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.0074 0.0073 0.0074 0.0073 0.0074 0.015 0.015lb/hr as NO2 25.6 23.4 25.7 25.1 13.3 11 10.7 59.6 58.9 58.2 54.3 40 34.1 31.9 33.3 29.7 32.7 31.8 33.3 59.2 57.8ppmvd @ 15% O2 9 9 9 9 9 9 9 25 25 25 25 25 25 25 9 9 9 9 9 25 25

lb/hr 45.45 41.85 45.90 44.55 23.85 19.80 18.90 81.45 80.55 79.65 74.25 54.90 46.80 43.65 86.40 77.40 85.05 82.80 86.85 81.00 79.20ppmvd @ 15% O2 1.3 1.3 1.3 1.3 1.3 1.3 1.3 2 2 2 2 2 2 2 1.9 1.9 1.9 1.9 1.9 2 2

lb/MMBtu 0.0029 0.0029 0.0029 0.0029 0.0029 0.0029 0.0029 0.0046 0.0046 0.0046 0.0046 0.0046 0.0046 0.0046 0.0042 0.0042 0.0042 0.0042 0.0043 0.0046 0.0046lb/hr 10.10 9.30 10.20 9.90 5.30 4.40 4.20 18.10 17.90 17.70 16.50 12.20 10.40 9.70 19.20 17.20 18.90 18.40 19.30 18.00 17.60ppmvd @ 15% O2 1.4 1.4 1.4 1.4 1.4 1.4 1.4 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.3 3.3 3.3 3.3 3.3 3.5 3.5

lb/hr as methane 6.20 5.80 6.20 6.20 3.20 2.60 2.60 18.20 18.03 17.68 16.63 12.25 10.50 9.80 19.07 17.05 18.88 18.33 19.07 18.03 17.68ppmvd @ 15% O2 0.7 0.7 0.7 0.7 0.7 0.7 0.7 2 2 2 2 2 2 2 1.8 1.8 1.8 1.8 1.8 2 2

lb/MMBtu 0.0009 0.0009 0.0009 0.0009 0.0009 0.0009 0.0009 0.0026 0.0026 0.0026 0.0026 0.0026 0.0027 0.0027 0.0023 0.0023 0.0023 0.0023 0.0023 0.0026 0.0026lb/hr as methane 3.10 2.90 3.10 3.10 1.60 1.30 1.30 10.40 10.30 10.10 9.50 7.00 6.00 5.60 10.40 9.30 10.30 10.00 10.40 10.30 10.10lb/hr 432,000 396,000 434,000 424,000 225,000 186,000 180,000 657,000 649,000 642,000 598,000 441,000 377,000 352,000 560,000 501,000 550,000 536,000 560,000 653,000 638,000lb/MMBtu w/margin 134.9 134.9 134.8 134.8 134.7 134.9 134.6 183.4 183.4 183.5 183.3 183.3 183.7 183.5 136.1 136.0 136.0 135.9 136.0 183.5 183.5lb/hr w/10% margin4 475,200 435,600 477,400 466,400 247,500 204,600 198,000 722,700 713,900 706,200 657,800 485,100 414,700 387,200 616,000 551,100 605,000 589,600 616,000 718,300 701,800lb/MW-hr 836 819 813 821 931 953 979 1,259 1,228 1,223 1,235 1,282 1,283 1,315 894 874 872 876 892 1,210 1,220ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5

lb/MMBtu 0.0067 0.0067 0.0067 0.0067 0.0067 0.0067 0.0067 0.0070 0.0070 0.0070 0.0070 0.0070 0.0070 0.0070 0.0068 0.0068 0.0068 0.0068 0.0068 0.0070 0.0070lb/hr 23.7 21.7 23.8 23.2 12.3 10.2 9.9 27.6 27.2 26.9 25.1 18.5 15.8 14.8 30.8 27.5 30.2 29.5 30.8 27.4 26.8lb/hr w/5% margin4 24.89 22.79 24.99 24.36 12.92 10.71 10.40 28.98 28.56 28.25 26.36 19.43 16.59 15.54 32.34 28.88 31.71 30.98 32.34 28.77 28.14

SOx5 lb/hr as SO2 (+20%) 4.70 4.30 4.70 4.60 2.40 2.00 2.00 7.00 7.00 6.90 6.40 4.70 4.00 3.80 6.10 5.40 6.00 5.80 6.10 7.00 6.80

lb/hr 11.3 11.1 11.3 11.3 10.0 9.7 9.7 48.2 48.2 48.1 47.9 39.6 39.2 39.0 22.5 20.3 21.5 21.1 22.5 48.2 48.1lb/MMBtu 0.0032 0.0034 0.0032 0.0033 0.0054 0.0064 0.0066 0.0122 0.0124 0.0125 0.0133 0.0150 0.0174 0.0185 0.0050 0.0050 0.0048 0.0049 0.0050 0.0123 0.0126lb/hr 2.60 2.40 2.70 2.60 1.40 1.10 1.10 4.00 3.90 3.90 3.60 2.70 2.30 2.10 3.70 3.30 3.70 3.60 3.70 3.90 3.90lb/hr w/10% margin4 2.86 2.64 2.97 2.86 1.54 1.21 1.21 4.40 4.29 4.29 3.96 2.97 2.53 2.31 4.07 3.63 4.07 3.96 4.07 4.29 4.29ppbvd @ 15% O2 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5 45.5

lb/MMBtu 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012 0.00012lb/hr 0.42 0.38 0.42 0.41 0.22 0.18 0.17 0.47 0.46 0.46 0.43 0.31 0.27 0.25 0.54 0.48 0.53 0.52 0.54 0.46 0.45lb/hr w/10% margin4 0.46 0.42 0.46 0.45 0.24 0.20 0.19 0.51 0.51 0.50 0.47 0.35 0.30 0.28 0.59 0.53 0.58 0.57 0.59 0.51 0.50

NOx (pre-control)3

CO (pre-control)3

VOC (pre-control)3

CH2O6

NOx (post-control)

CO (post-control)

H2SO4

NH3

VOC (post-control)

PM

CO2

December 2019

Renovo Energy CenterRaw Data for General Electric EquipmentNotes

1 Operating points included list evaporative coolers as "off," however evaporative coolers may be operated when firing ULSD.

2 The heat consumption provided by G.E. included a ~5% margin to account for equipment degradation and site variability.

3 Pre-control emissions rates when firing natural gas were provided by G.E. on a ppm basis. The same control efficiency for ppm values was used for the lb/hr pre-control emission rates. For emission rates when firing ULSD, the same control efficiency as determined for natural gas emissions was used to determine pre-control emissions when firing ULSD.

4 A 10% margin was added to lb/hr emission values of CO2, H2SO4, NH3, and CH2O to account for equipment degradation and site variability.

5 SOx emission rates provided by G.E. included a margin of 20% to account for fuel and site variability.6 CH2O emission rate of 91 ppb @ 15% O2 is the turbine outlet concentration provided by G.E. (91 ppb) with a 50%

control efficiency applied for the oxidation catalyst.

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

Maximum Fuel Flow Rate: 150,002 lb/hr eachFuel Gross Heating Value: 23,607 Btu/lbMaximum GT heat input capacity: 3,541 MMBtu/hr eachMaximum GT+DB heat input capacity: 4,529 MMBtu/hr eachAnnual capacity factor: 100 %

7,540 hours each

34,149,414 MMBtu/yr each

Maximum annual emissions calculated based on maximum potential operating hours.Values below represent emissions from each individual unit.

(ppmvd @ 15% O2) (lb/hr) (lb/hr) (ton/yr)NOx 2 25.70 33.30 125.54CO 2 10.20 19.30 72.76PM10 -- 11.30 22.50 84.83VOC 1 (GT); 2 (GT+DB) 3.10 10.40 39.21SO2 -- 4.70 6.10 23.00NH3 5 24.99 32.34 121.92H2SO4 -- 2.97 4.07 15.34GHGs 3 (kg/MMBtu) (lb/hr) (lb/hr) (ton/yr)CO2 -- 477,400 616,000 2,322,320CH4 1.0E-03 7.81 7.81 29.43N2O 1.0E-04 0.78 0.78 2.94CO2equivalent 477,827.8 616,427.8 2,323,933

HAPs 4 GT(lb/MMBtu)

DB(lb/MMscf)

GT+DB(lb/hr) (ton/yr)

1,3-butadiene 2.2E-07 0 7.6E-04 0.0029acetaldehyde 2.0E-05 0 7.0E-02 0.27acrolein 3.2E-06 0 1.1E-02 0.043benzene 6.0E-06 1.2E-03 2.2E-02 0.08dichlorobenzene 0 6.6E-04 6.5E-04 0.0025ethyl benzene 1.6E-05 0 5.6E-02 0.21formaldehyde2 -- -- 5.9E-01 2.23hexane 0 9.9E-01 9.8E-01 3.68naphthalene 6.5E-07 3.4E-04 2.6E-03 0.010PAH 1.1E-06 0 3.9E-03 0.015POM 0 4.9E-05 4.8E-05 0.00018propylene oxide 1.5E-05 0 5.1E-02 0.19toluene 6.5E-05 1.9E-03 2.3E-01 0.87xylenes 3.3E-05 0 1.1E-01 0.43

(not including SUSD or ULSD operations) 1

(not including SUSD or ULSD operations)

Maximum emissions scenario operating hours:Maximum emissions scenario annual heat input:

Maximum Short-term Emission Rate (GT only)Emission Factor

Maximum Potential Annual Emissions5

Maximum Short-term Emission Rate (GT+DB)

Pollutant2

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

HAPs 4 GT(lb/MMBtu)

DB(lb/MMscf)

GT+DB(lb/hr) (ton/yr)

arsenic 0 2.0E-04 2.0E-04 0.00074beryllium 0 1.2E-05 1.2E-05 0.000045cadmium 0 1.1E-03 1.1E-03 0.0041chromium 0 1.4E-03 1.4E-03 0.0052cobalt 0 8.4E-05 8.3E-05 0.00031lead 0 0 0 0manganese 0 3.8E-04 3.7E-04 0.0014mercury 0 2.6E-04 2.6E-04 0.00097nickel 0 2.1E-03 2.1E-03 0.0078selenium 0 0 2.4E-05 0.000089TOTAL HAPs 1.00 2.14 8.06

3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O obtained from 40 CFR 98.

4HAP emission factors for GT obtained from EPA's AP-42, Table 3.1-3 and reflect control level of 50% by the oxidation catalyst for organic HAPs, except for formaldehyde, which was obtained from the vendor. HAP emission factors for DB obtained from EPA's AP-42, Tables 1.4-3 and 1.4-4 and reflect control level of 45% by the oxidation catalyst for organic HAPs, except for formaldehyde, which was obtained from vendor.5Potential annual emissions based on the GT + DB scenario, as this is considered worst-case.

1Maximum potential operating hours not including SUSD or ULSD operations was used to estimate emissions.2Emission factors provided by vendor. The maximum emissions rate from all available operating scenarios was used to calculate maximum potential emissions.

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsPowerblocks- Turbines firing ULSD

Maximum Fuel Flow Rate: 195,748 lb/hr eachFuel Gross Heating Value: 20,130 Btu/lbMaximum heat input capacity: 3,940 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 720 hours each (not including SUSD) 1

Maximum annual heat input: 2,837,088 MMBtu/yr (not including SUSD)

Maximum annual emissions calculated based on maximum potential operating hours.Values below represent emissions from each individual unit.

(ppmvd @ 15% O2) (lb/hr) (ton/yr)NOx 4 59.60 21.46CO 2 18.10 6.52PM10 -- 48.20 17.35VOC 2 10.40 3.74SO2 -- 7.00 2.52NH3 5 28.98 10.43H2SO4 -- 4.40 1.58GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)

CO2 -- 722,700 260,172CH4 3.0E-03 26.06 9.38N2O 6.0E-04 5.21 1.88CO2equivalent -- 724,904.8 260,966HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)1,3-butadiene 1.1E-05 4.4E-02 0.016acetaldehyde 0 0 0acrolein 0 0 0benzene 3.9E-05 1.5E-01 0.055dichlorobenzene 0 0 0ethyl benzene 0 0 0formaldehyde2 -- 5.1E-01 0.19hexane 0 0 0naphthalene 2.5E-05 9.7E-02 0.035PAH 2.8E-05 1.1E-01 0.040POM 0 0 0propylene oxide 0 0 0toluene 0 0 0xylenes 0 0 0arsenic 1.1E-05 4.3E-02 0.016beryllium 3.1E-07 1.2E-03 0.00044cadmium 4.8E-06 1.9E-02 0.0068chromium 1.1E-05 4.3E-02 0.016cobalt 0 0 0lead 1.4E-05 5.5E-02 0.020

Pollutant2Emission Factor

Maximum Short-Term Emission Rate

Maximum Potential Annual Emissions

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsPowerblocks- Turbines firing ULSD

HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)manganese 7.9E-04 3.11 1.12mercury 1.2E-06 4.7E-03 0.0017nickel 4.6E-06 1.8E-02 0.0065selenium 2.5E-05 9.9E-02 0.035TOTAL HAPs 4.31 1.55

4HAP emission factors obtained from EPA's AP-42, Tables 3.1-4 and 3.1-5 and reflect control level of 30% by the oxidation catalyst for organic HAPs, except for formaldehyde, which was obtained from the vendor.

3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O obtained from 40 CFR 98.

2Emission factors provided by vendor. The maximum emissions rate from all available operating scenarios was used to calculate maximum potential emissions.

1Maximum potential operating hours not including SUSD was used to estimate emissions.

December 2019

Renovo Energy CenterStartup and Shutdown Operations Emissions DataNatural Gas Firing

SUSD Parameter

Amount per Event - GE Provided

Pro-Rated Amount per Hour

Amount per Event with Time Increase1

Cold StartTime from Ignition until Compliance (minutes) 45 -- 60Fuel Consumed (lb) 39,451 52,602 52,602Fuel Consumed (MMBtu LHV) 840 1,120 1,120Fuel Consumed (MMBtu HHV) 931 1,242 1,242Maximum Potential NOx Emissions (lb) 123.0 164.0 164.0Maximum Potential CO Emissions (lb) 699.0 932.0 932.0Maximum Potential VOC Emissions (lb) 53.0 70.7 70.7Maximum Potential PM10/2.5 Emissions (lb) 8.3 11.1 11.1Warm StartTime from Ignition until Compliance (minutes) 40 -- 55Fuel Consumed (lb) 38,277 57,416 52,631Fuel Consumed (MMBtu LHV) 815 1,223 1,121Fuel Consumed (MMBtu HHV) 904 1,355 1,242Maximum Potential NOx Emissions (lb) 81.0 121.5 111.4Maximum Potential CO Emissions (lb) 190.0 285.0 261.3Maximum Potential VOC Emissions (lb) 24.0 36.0 33.0Maximum Potential PM10/2.5 Emissions (lb) 7.3 11.0 10.0Hot StartTime from Ignition until Compliance (minutes) 20 -- 35Fuel Consumed (lb) 15,264 45,792 26,712Fuel Consumed (MMBtu LHV) 325 975 569Fuel Consumed (MMBtu HHV) 360 1,081 631Maximum Potential NOx Emissions (lb) 53.0 159.0 92.8Maximum Potential CO Emissions (lb) 177.0 531.0 309.8Maximum Potential VOC Emissions (lb) 22.0 66.0 38.5Maximum Potential PM10/2.5 Emissions (lb) 4.0 12.0 7.0Shutdown from 50% loadTime to Shutdown (minutes) 12 -- 27Fuel Consumed (lb) 9,393 46,966 21,135Fuel Consumed (MMBtu LHV) 200 1,000 450Fuel Consumed (MMBtu HHV) 222 1,109 499Maximum Potential NOx Emissions (lb) 14.0 70.0 31.5Maximum Potential CO Emissions (lb) 152.0 760.0 342.0Maximum Potential VOC Emissions (lb) 19.0 95.0 42.8Maximum Potential PM10/2.5 Emissions (lb) 3.0 15.0 6.8Annual Totals2

Total SUSD Operating Hour Limitation Per Unit: 460 hrsTotal Annual SUSD Fuel Consumption Per Unit: 25,302,027 lbsTotal Annual SUSD Heat Input Per Unit: 538,731 MMBtu LHVTotal Annual SUSD Heat Input Per Unit: 597,305 MMBtu HHVTotal Maximum Potential NOx Emissions Per Unit: 25.2 tonsTotal Maximum Potential CO Emissions Per Unit: 90.8 tonsTotal Maximum Potential VOC Emissions Per Unit: 11.4 tonsTotal Maximum Potential PM10/2.5 Emissions Per Unit: 2.7 tonsDecember 2019

Renovo Energy CenterStartup and Shutdown Operations Emissions DataULSD Firing

SUSD Parameter

Amount per Event - GE Provided

Pro-Rated Amount per Hour

Amount per Event with Time Increase1

Cold StartTime from Ignition until Compliance (minutes) 45 -- 60Fuel Consumed (lb) 54,208 72,277 72,277Fuel Consumed (MMBtu LHV) 992 1,323 1,323Fuel Consumed (MMBtu HHV) 1,100 1,466 1,466Maximum Potential NOx Emissions (lb) 221.0 294.7 294.7Maximum Potential CO Emissions (lb) 704.0 938.7 938.7Maximum Potential VOC Emissions (lb) 141.0 188.0 188.0Maximum Potential PM10/2.5 Emissions (lb) 36.0 48.0 48.0Warm StartTime from Ignition until Compliance (minutes) 40 -- 55Fuel Consumed (lb) 54,645 81,967 75,137Fuel Consumed (MMBtu LHV) 1,000 1,500 1,375Fuel Consumed (MMBtu HHV) 1,109 1,663 1,525Maximum Potential NOx Emissions (lb) 172.0 258.0 236.5Maximum Potential CO Emissions (lb) 286.0 429.0 393.3Maximum Potential VOC Emissions (lb) 33.0 49.5 45.4Maximum Potential PM10/2.5 Emissions (lb) 32.0 48.0 44.0Hot StartTime from Ignition until Compliance (minutes) 20 -- 35Fuel Consumed (lb) 18,579 55,738 32,514Fuel Consumed (MMBtu LHV) 340 1,020 595Fuel Consumed (MMBtu HHV) 377.0 1,131 660Maximum Potential NOx Emissions (lb) 112.0 336.0 196.0Maximum Potential CO Emissions (lb) 273.0 819.0 477.8Maximum Potential VOC Emissions (lb) 30.0 90.0 52.5Maximum Potential PM10/2.5 Emissions (lb) 16.0 48.0 28.0Shutdown from 50% loadTime to Shutdown (minutes) 8 -- 23Fuel Consumed (lb) 7,213 54,098 20,738Fuel Consumed (MMBtu LHV) 132 990 380Fuel Consumed (MMBtu HHV) 146 1,098 421Maximum Potential NOx Emissions (lb) 43.0 322.5 123.6Maximum Potential CO Emissions (lb) 48.0 360.0 138.0Maximum Potential VOC Emissions (lb) 7.0 52.5 20.1Maximum Potential PM10/2.5 Emissions (lb) 10.0 75.0 28.8Annual Totals2

Total SUSD Operating Hour Limitation Per Unit: 40 hrsTotal Annual SUSD Fuel Consumption Per Unit: 3,092,896 lbsTotal Annual SUSD Heat Input Per Unit: 56,600 MMBtu LHVTotal Annual SUSD Heat Input Per Unit: 62,755 MMBtu HHVTotal Maximum Potential NOx Emissions Per Unit: 5.4 tonsTotal Maximum Potential CO Emissions Per Unit: 8.4 tonsTotal Maximum Potential VOC Emissions Per Unit: 1.0 tonsTotal Maximum Potential PM10/2.5 Emissions Per Unit: 1.1 tonsDecember 2019

Renovo Energy CenterStartup and Shutdown Operations Emissions Data and Modeling ParametersNotes

1 REC is proposing to add 15 minutes of margin to each SUSD scenario in order to allow operational flexibility in order to ensure that the SUSD can be completed in the permitted length of time. All heat input and emission parameters have been pro-rated for the increased time.

2Annual totals are based on warm starts and the corresponding amount of shutdowns. For the natural gas scenarios, 460 hours of SUSD corresponds to 308.5 hours of warm starts and 151.5 hours of shutdowns. For the ULSD scenarios, 40 hours of SUSD corresponds to 28.2 hours of warm starts and 11.8 hours of shutdowns.

December 2019

Renovo Energy CenterSummary of Worst-Case Maximum Potential Annual Emissions ScenarioPowerblocks- Turbines, HRSGs

720 each powerblock40 each powerblock

7,540 each powerblock460 each powerblock

Total Operating Hours: 8,760 each powerblock

Pollutant

Annual Emissions from ULSD Firing1

(tons)

Annual Emissions from ULSD SUSD2

(tons)

Annual Emissions from NG Firing3

(tons)

Annual Emissions from Natural Gas SUSD4 (tons)

Total Maximum Potential Annual Emissions from Both Powerblocks (tons)

Total Maximum Potential Annual Emissions from Each Powerblock (tons)

NOx 42.91 10.75 251.08 50.42 355.17 177.58CO 13.03 16.70 145.52 181.52 356.78 178.39PM10 34.70 2.10 169.65 5.47 211.92 105.96VOC 7.49 2.00 78.42 22.82 110.73 55.36SO2 5.04 0.28 45.99 2.16 53.48 26.74NH3 20.87 1.16 243.84 11.50 277.36 138.68H2SO4 3.17 0.18 30.69 1.37 35.40 17.70GHGsCO2 520,344 28,908 4,644,640 219,604 5,413,496 2,706,748CH4 18.76 1.04 58.86 3.59 82.26 41.13N2O 3.75 0.21 5.89 0.36 10.21 5.10CO2equivalent 521,931 28,996 4,647,866 219,801 5,418,594 2,709,297HAPs1,3-butadiene 0.032 0.0018 0.0057 0.00035 0.040 0.020acetaldehyde 0 0 0.53 0.033 0.56 0.28acrolein 0 0 0.085 0.0052 0.09 0.045benzene 0.11 0.0061 0.17 0.010 0.29 0.15dichlorobenzene 0 0 0.0049 0 0.0049 0.0025

Natural Gas Normal Operating Hours:ULSD SUSD Operating Hours:

ULSD Normal Operating Hours:

Natural Gas SUSD Operating Hours:

December 2019

Renovo Energy CenterSummary of Worst-Case Maximum Potential Annual Emissions ScenarioPowerblocks- Turbines, HRSGs

Pollutant

Annual Emissions from ULSD Firing1

(tons)

Annual Emissions from ULSD SUSD2

(tons)

Annual Emissions from NG Firing3

(tons)

Annual Emissions from Natural Gas SUSD4 (tons)

Total Maximum Potential Annual Emissions from Both Powerblocks (tons)

Total Maximum Potential Annual Emissions from Each Powerblock (tons)

ethyl benzene 0 0 0.43 0.026 0.45 0.23formaldehyde 0.37 0.021 4.46 0.21 5.06 2.53hexane 0 0 7.36 0 7.36 3.68naphthalene 0.070 0.0039 0.020 0.0011 0.09 0.047PAH 0.079 0.0044 0.029 0.0018 0.11 0.057POM 0 0 0.00036 0 0.00036 0.00018propylene oxide 0 0 0.39 0.024 0.41 0.20toluene 0 0 1.74 0.11 1.85 0.92xylenes 0 0 0.86 0.053 0.92 0.46arsenic 0.031 0.0017 0.0015 0 0.034 0.017beryllium 0.00088 0.000049 0.000089 0 0.0010 0.00051cadmium 0.014 0.00076 0.0082 0 0.023 0.011chromium 0.031 0.0017 0.010 0 0.043 0.022cobalt 0 0 0.00062 0 0.00062 0.00031lead 0.040 0.0022 0 0 0.042 0.021manganese 2.24 0.12 0.0028 0 2.37 1.18mercury 0.0034 0.00019 0.0019 0 0.0055 0.0028nickel 0.013 0.00073 0.016 0 0.029 0.015selenium 0.071 0.0039 0.00018 0 0.075 0.038TOTAL HAPs 3.11 16.12 19.87 9.93

4Annual Emissions from Natural Gas SUSD based on 460 SUSD hours per powerblock when firing natural gas, using emission rates for Warm Starts and Shutdowns for emissions of NOx, CO, PM, and VOC. All other pollutant emissions based on the maximum emission rate for all operating loads when firing natural gas.

3Annual Emissions from Natural Gas Firing based on 7,540 normal operating hours firing natural gas in the CT and DB for each powerblock.

2Annual Emissions from ULSD SUSD based on 40 SUSD hours per powerblock when firing ULSD, using emission rates for Warm Starts and Shutdowns for emissions of NOx, CO, PM, and VOC. All other pollutant emissions based on the maximum emission rate for all operating loads when firing ULSD.

1Annual Emissions from ULSD Firing based on 720 nornal operating hours on ULSD for each powerblock.

December 2019

Renovo Energy CenterCalculations for CO2 BACT LimitPowerblocks- Turbines, HRSGs

SITE CONDITIONSAmbient Temperature °F 59 59 59Ambient Pressure psia 14.35 14.35 14.35Ambient Relative Humidity % 60.00 60.00 60.00PLANT STATUSHRSG Duct Burner Off On OffSCR Operating Operating OperatingCO Catalyst Operating Operating OperatingEvaporative Cooler state (On or Off) On On OffGas Turbine Load % Base Base BaseGas Turbines Operating 1 1 1GT Diluent Injection Type None None WaterGT Diluent Injection Flow (per GT) 103 lb/hr 0 0 266.4FUEL DATAFuel Type NG NG DOHHV BTU/lb 23,607 23,607 19,649LHV BTU/lb 21,292 21,292 18,300GT Heat Consumption per unit MMBTU/hr, HHV 3,541.1 3,541.1 3,848.4Duct Burner Heat Consumption MMBTU/hr, HHV 0 906.8 0Total Heat Consumption MMBTU/hr, HHV 3,541.1 4,447.9 3,848.4HRSG DATA (PER UNIT)HRSG EXIT EXHAUST GASTemperature °F 181 176 280Mass Flow with Permitting Margin lb/hr 6,007,200 6,047,500 6,059,300Std Volume Flow SCF/hr (60°F) 80,617,373 81,562,002 81,767,914Actual Volume Flow Actual ft3/hr 101,850,000 102,230,000 119,190,000HRSG EXIT EXHAUST GAS EMISSIONSCO2 lb/hr 434,000 550,000 642,000 (provided by GE)CH4 kg/MMBtu 1.0E-03 1.0E-03 3.0E-03 (40 CFR 98 emission factor)

lb/hr 7.81 9.81 25.45N2O kg/MMBtu 1.0E-04 1.0E-04 6.0E-04 (40 CFR 98 emission factor)

lb/hr 0.78 0.98 5.09CO2e lb/hr 434,428 550,537 644,153 (CH 4 GWP= 25, N 2 O GWP= 298)Powerblock Net Output MW 534 631 525 (provided by GE)CO2e Emission Factor lb/MW-hr 813.5 872.5 1,227.2Annual Hours of Operation hrs 4,020.0 4,020.0 720Annual CO2e Emission FactorWith 10% OEM-recommended Margin(see attached notes from G.E.)

875 lb/MW-hr962 lb/MW-hr

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsAuxiliary Boilers

Two natural gas fired auxiliary boilersMaximum heat input capacity: 66 MMBtu/hr per boiler

Equivalent to: 64,706 scf/hr per boilerMaximum proposed annual heat input per boiler: 145,200 MMBtu/yr

Equivalent to: 2,200 hours at 100% loadMaximum annual heat input total: 290,400 MMBtu/yr totalMaximum fuel input per boiler: 142 MMcf/yr

Emission Factor

Maximum Potential Emission Rate per Boiler

Maximum Potential Emissions for One Boiler

Total Maximum Potential Emissions

(lb/MMBtu) (lb/hr) (tpy) (tpy)NOx 0.0060 0.40 0.44 0.87CO 0.036 2.38 2.61 5.23PM10 0.0019 0.13 0.14 0.28VOC 0.0020 0.13 0.15 0.29SO2 0.00058 0.038 0.042 0.084H2SO4 9.0E-05 0.0059 0.0065 0.013NH3 negligible --- ---GHGs (kg/MMBtu) (tpy) (tpy)CO2 53.06 8,474.74 16,949.49CH4 1.00E-03 0.16 0.32N2O 1.00E-04 0.016 0.032CO2e -- 8,483.50 16,966.99

Emission Factor

Maximum Potential Emission Rate per Boiler

Maximum Potential Emissions for One Boiler

Total Maximum Potential Emissions

(lb/MMcf) (lb/hr) (tpy) (tpy)benzene 2.10E-03 1.36E-04 1.5E-04 0.00030formaldehyde 7.50E-02 4.85E-03 5.3E-03 0.011hexane 1.8 1.16E-01 1.3E-01 0.26naphthalene 6.10E-04 3.95E-05 4.3E-05 0.000087toluene 3.40E-03 2.20E-04 2.4E-04 0.00048POM 8.82E-05 5.71E-06 6.3E-06 0.000013Total HAP emissions: 0.12 0.13 0.27

Pollutant

HAPs

Emission factors for CO2, CH4 and N2O are provided by Tables C-1 and C-2 of 40 CFR Part 98 - Mandatory Reporting of Greenhouse Gases

Emission factor for SO2 and H2SO4 are based on RBLC database entries for BACT/BAT

Emission factors for PM and HAPs are based on AP-42, Section 1.4. PM factor is for filterable portion only (1.9 lb/MMcf/1,020 Btu/cf = 0.0019 lb/MMBtu)

Emission factors for NOx, CO, and VOC are vendor estimates and/or LAER/BACT limits.

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsDiesel Engines

Emergency GeneratorMaximum rating: 1500 kW

2206 hpMaximum operating hours: 500 hrMaximum fuel firing rate: 104.6 gal/hrMaximum heat input rate: 14.33 MMBtu/hr

(g/hp-hr) (lb/hr) (tpy)NOx 4.48 21.79 5.45CO 1.23 5.98 1.50PM10 0.13 0.63 0.16VOC 0.80 3.89 0.97SO2

1 --- 0.022 0.0055

SO2 emissions are based on ultra low diesel fuel not to exceed 15 ppm sulfur.

Fire Pump EngineMaximum rating: 237 hpMaximum operating hours: 250 hrMaximum fuel firing rate: 12 gal/hrMaximum firing rate: 1.64 MMBtu/hr

(g/hp-hr) (lb/hr) (tpy)NOx 2.7 1.41 0.18CO 0.9 0.47 0.059PM10 0.10 0.052 0.0065VOC 0.10 0.052 0.0065SO2

1 --- 0.0025 0.00032Emissions for NOx, CO, VOC, and PM10 are based on vendor dataSO2 emissions are based on ultra low diesel fuel not to exceed 15 ppm sulfur.

Pollutant

Maximum Potential Emissions

VOC emission rate is based on maximum calculated emission rate provide by CAT for a 3512C engine.

Emission rates for NOx, CO, and PM10 are based on EPA Weighted Emissions Calculator for Constant Speed Engines - 40 CFR 89, Table 2 of Appendix B to Section E.

Tier 2 Emission Factor

Emission Rate

1(15 lb S/ 106 lb fuel) ( 64 lb SO2/32 lb S) (7 lb/gal) ( gal/137,000 Btu) (14.33 MMBtu/hr) = 0.022 lb SO2/hr

Pollutant


1(15 lb S/ 106 lb fuel) ( 64 lb SO2/32 lb S) (7 lb/gal) ( gal/137,000 Btu) (1.75 MMBtu/hr) = 0.003 lb SO2/hr

Emission Factor

Emission Rate

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsDiesel Engines

(lb/MMBtu) (tpy) (tpy) (tpy)

benzene 9.33E-04 3.34E-03 1.92E-04 3.53E-03toluene 4.09E-04 1.47E-03 8.40E-05 1.55E-03xylene 2.85E-04 1.02E-03 5.86E-05 1.08E-031,3 butadiene 3.91E-05 1.40E-04 8.04E-06 1.48E-04formaldehyde 1.18E-03 4.23E-03 2.42E-04 4.47E-03acetaldehyde 7.67E-04 2.75E-03 1.58E-04 2.91E-03acrolein 9.25E-05 3.31E-04 1.90E-05 3.50E-04naphthalene 8.48E-05 3.04E-04 1.74E-05 3.21E-04

Total 1.36E-02 7.79E-04 1.44E-02

1HAP emission factors are based on AP-42, Section 3.

Maximum Potential Fire Pump Emissions

Maximum Potantial Generator Emissions

Emission Factor

HAP Emissions1

Combined Maximum Potential Emissions

December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsHeaters

Two natural gas water bath heaters (located 1.25 miles from site at pressure reducing station)Maximum heat input capacity (each): 15 MMBtu/hrMaximum potential operating hours: 8,760 hours

(lb/MMBtu) (lb/hr) (tpy)NOx 0.011 0.17 1.45CO 0.037 0.56 4.86PM10 0.0019 0.029 0.25VOC 0.0050 0.075 0.66SO2 0.00058 0.0087 0.076NH3 negligible ---GHGs (kg/MMBtu) (tpy)CO2 53.06 15,338.58CH4 1.00E-03 0.29N2O 1.00E-04 0.029CO2e -- 15,354.43

(lb/MMcf) (tpy)

benzene 2.10E-03 2.7E-04formaldehyde 7.50E-02 0.0097hexane 1.8 0.23naphthalene 6.10E-04 7.9E-05toluene 3.40E-03 0.00044POM 8.82E-05 1.1E-05

Total HAP emissions: 0.24

Emission factors for NOx, CO, VOC, PM10 and SO2 are based on RBLC database entries for BACT/BAT

Emission factors for HAPs are based on AP-42, Section 1.4.

Note: Site will be equipped with three heaters. Third heater is for standby/redundancy only. Only two heaters will be operated at the same time.

Combined Maximum Potential Emissions

Maximum Potential Emission Rate per UnitEmission Factor

Pollutant

Maximum Potential EmissionsEmission Factor

HAPs


December 2019

Renovo Energy CenterDetermination of Maximum Potential EmissionsHeaters

One natural gas dew point heater

Maximum heat input capacity: 2.96 MMBtu/hrMaximum potential operating hours: 8,760 hours

(lb/MMcf) (tpy)

NOx 100 1.27CO 84 1.07PM10 1.9 0.024VOC 5.5 0.070SO2 0.6 0.0076NH3 negligible ---GHGs (kg/MMBtu) (tpy)CO2 53.06 1,513.41CH4 1.00E-03 0.029N2O 1.00E-04 0.0029CO2e -- 1,514.97

(lb/MMcf) (tpy)

benzene 2.10E-03 2.7E-05formaldehyde 7.50E-02 9.5E-04hexane 1.8 2.3E-02naphthalene 6.10E-04 7.8E-06toluene 3.40E-03 4.3E-05POM 8.82E-05 1.1E-06

Total HAP emissions: 0.024

Emission factors for criteria pollutants and HAPs are based on AP-42, Section 1.4.

Since heater is exempt from permitting (natural gas, less than 10 MMBtu/hr), BAT/BACT/LAER emission rates are not required. Emissions are provided for inclusion in facility-wide potential emissions.

Potential EmissionsEmission Factor

Pollutant

Maximum Potential EmissionsEmission Factor

HAPs


December 2019

Renovo Energy CenterDetermination of Greehouse Gas EmissionsDiesel Engines

Emergency Generator Engine - 1500kW

Maximum fuel firing rate: 104.6 gal/hrMaximum heat input: 14.33 MMBtu/hrMaximum operating hours: 500 hr

(kg/MMBtu) (tpy) (tpy)CO2 73.96 582.92 1 582.92CH4 3.00E-03 0.024 25 0.59N2O 6.00E-04 0.0047 298 1.41

Total CO2 Equivalent: 584.92

Emergency Fire Pump Engine - 237 HP unit

Maximum fuel firing rate: 12 gal/hrMaximum heat input: 1.64 MMBtu/hrMaximum operating hours: 250 hr

(kg/MMBtu) (tpy) (tpy)CO2 73.96 33.44 1 33.44CH4 3.00E-03 0.0014 25 0.034N2O 6.00E-04 0.00027 298 0.081

Total CO2 Equivalent: 33.55

Emission factors for CO2, CH4 and N2O are provided by Tables C-1 and C-2 of 40 CFR Part 98 - Mandatory Reporting of Greenhouse GasesGlobal warming potentials for CO2, CH4 and N2O are provided by Table A-1 of 40 CFR Part 98.

CO2

EquivalentGlobal Warming Potential


Emission FactorGreenhouse

Gas

CO2



Emission FactorGreenhouse

Gas

December 2019

Renovo Energy CenterDetermination of Potential EmissionsULSD Storage Tank

TANKS 4.0.9dEmissions Report - Summary Format Tank Indentification and Physical Characteristics

REC Tank_1WilliamsportPennsylvaniaRenovo Energy CenterInternal Floating Roof TankULSD Storage Tank for Combustion Turbines

1203,500,000 (based on 72 hours of ULSD firing capability per powerblock)

10 (based on 720 hours of ULSD firing per powerblock)N71

Internal Shell Condition: Light RustShell Color/Shade: White/WhiteShell Condition GoodRoof Color/Shade: White/WhiteRoof Condition: Good

City:

IdentificationUser Identification:

Paint Characteristics

State:Company:Type of Tank:Description:

Tank DimensionsDiameter (ft):Volume (gallons):Turnovers:Self Supp. Roof? (y/n):No. of Columns:Eff. Col. Diam. (ft):

December 2019


Primary Seal: Liquid-mountedSecondary Seal None

Deck Fitting Category: TypicalDeck Type: Welded

Quantity

1171

4111

Meterological Data used in Emissions Calculations: Williamsport, Pennsylvania (Avg Atmospheric Pressure = 14.47 psia)

Vacuum Breaker (10-in. Diam.)/Weighted Mech. Actuation, Gask.

Rim-Seal System

Deck Characteristics

Deck Fitting/Status

Access Hatch (24-in. Diam.)/Unbolted Cover, UngasketedAutomatic Gauge Float Well/Unbolted Cover, UngasketedColumn Well (24-in. Diam.)/Built-Up Col.-Sliding Cover, Ungask.Ladder Well (36-in. Diam.)/Sliding Cover, UngasketedRoof Leg or Hanger Well/AdjustableSample Pipe or Well (24-in. Diam.)/Slit Fabric Seal 10% Open

December 2019


TANKS 4.0.9dEmissions Report - Summary Format Liquid Contents of Storage Tank

REC Tank_1 - Internal Floating Roof TankWilliamsport, Pennsylvania

Liquid Bulk Temp

Avg. Min. Max. (deg F) Avg. Min. Max.Distillate fuel oil no. 2 All 51.52 46.58 56.46 49.92 0.0048 N/A N/A 130 188

TANKS 4.0.9dEmissions Report - Summary Format Individual Tank Emission Totals

Emissions Report for: Annual

REC Tank_1 - Internal Floating Roof TankWilliamsport, Pennsylvania

Rim Seal Loss

Withdrawl Loss

Deck Fitting Loss

Deck Seam Loss

Total Emissions

Distillate fuel oil no. 2 2.07 73.81 8.6 0 84.48

Losses(lbs)

Components

Option 1: VP50 = .0045 VP60 = .0065

Daily Liquid Surf. Temperature(deg. F)

MonthMixture/ Component

Basis for Vapor Calculations

Mol. Weight

Vapor Mol. Weight

Vapor Pressure (psia)

December 2019

Renovo Energy CenterDetermination of Greehouse Gas EmissionsCircuit Breakers

(tons/yr) (tpy)Circuit Breakers (345 kV) 360 6 0.0054 22,800 123.12Circuit Breakers (230 kV) 175 6 0.0026 22,800 59.85Totals -- -- 0.0080 182.97

Emissions are based on a leak rate of 0.5% per year

CO2


SF6 Maximum Potential EmissionsAmount SF6

(lb)Number of Units

December 2019


APPENDIX E POWER BLOCK VENDOR-PROVIDED DATA

SIZE DWG NO SH REV

A 1 C

REVDATE

(dd-mmm-yyyy)APPROVED

- Preliminary Issue 01-Oct-2019 A. Dicke

A Preliminary Issue 08-Oct-2019 A. Dicke

B Preliminary Issue 22-Nov-2019 A. Dicke

C Preliminary Issue 11-Dec-2019 A. Dicke

SIZE A CAGE CODE NONE DWG NO

SCALE NONE SHEET 1

7HA.02

THIS DOCUMENT SHALL BE REVISED

IN ITS ENTIRETY ALL SHEETS OF

THIS DOCUMENT ARE THE SAME

REVISION LEVEL AS INDICATED IN

THE REVISION BLOCK

REVISIONS

DESCRIPTION

Combined Cycle Systems

Combined Cycle Systems Emissions Estimates

© COPYRIGHT 2019 General Electric - Proprietary Information

All Rights Reserved. This document contains proprietary information. No part of this document may be used by or disclosed to others without the prior written permission

of the General Electric Company. Permission must be granted by the General Electric Company for the inclusion of this document in a permitting application.

PREPARED BY

SYSTEM ENGINEER

ISSUED

PROJECT ENGINEER

SIGNATURESDATE

(dd-mmm-yyyy)

GE PowerGENERAL ELECTRIC COMPANY

GENERAL ELECTRIC

INTERNATIONAL, INC. POWER PLANT SYSTEMS

Renovo

01-Oct-2019

01-Oct-2019

01-Oct-2019

01-Oct-2019

DT-7NCopyright 2019, General Electric Company

and its Affiliates

Non-Public

GE Proprietary Information

Renovo

Mike Boisclair

n/a

n/a

Andrew Dicke MADE FOR: IPS # 1270381

FIRST MADE FOR:

MDL - T218

g GE Power Renovo Spec. No. T218

Drawing Revision Status

Revision Date Description

- 01-Oct-2019 Initial issue

A 08-Oct-2019 Additional cases

B 22-Nov-2019 Reduce VOC

C 11-Dec-2019 Reduce CO/VOC increased ULSD Stack Temp

Drawing Number: Non-Public


Page 2

Date: 11-Dec-2019 Rev. C

By : Mike Boisclair


Combined Cycle Systems Emissions Estimates: Renovo

Operating Point 1 2 3Case Description 1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

Ambient ConditionsAmbient Temperature °F -20.0 95.8 59.0

Ambient Pressure psia 14.350 14.350 14.350

Ambient Relative Humidity % 60 35 60

Gas TurbineGT Fuel Type Gas Gas Gas

GT load fraction - 1 1 1

Evap Cooler status off off On

Gas turbine water injection flow rate klb/h 0.0 0.0 0.0

Plant Performance (not guaranteed)CC Net Plant output kW 516571 482965 533150

Abatement StatusCO Catalyst Operating status Operating Operating Operating

SCR Operating status Operating Operating Operating

GT Fuel Gas Turbine fuel LHV Btu/lb 21292 21292 21292

Gas Turbine fuel HHV Btu/lb 23607 23607 23607

Gas Turbine gas fuel molecular weight lb/lbmole 16.52 16.52 16.52

Gas Turbine sulfur ppm (by mass) ppm 13.1 13.1 13.1

Duct BurnerDuct Burner fuel LHV Btu/lb 21292 21292 21292

Duct Burner fuel HHV Btu/lb 23607 23607 23607

Duct Burner fuel molecular weight lb/lbmole 16.52 16.52 16.52

Duct Burner fuel sulfur content (by mass) ppm 13.1 13.1 13.1

Duct Burner status Off Off Off

Duct Burner gas fuel flow lb/h 0.0 0.0 0.0

Duct Burner load fraction % 0.0 0.0 0.0

Heat Consumption for permitting (per unit)GT Heat Cons (HHV), with permitting margin MMBtu/h 3523.8 3230.1 3541.1

DB Heat Cons (HHV) MMBtu/h 0.0 0.0 0.0

HRSG Exit Exhaust gas (per unit)Stack N2 mole fraction - 0.7474 0.7326 0.7374

Stack O2 mole fraction - 0.1149 0.1115 0.1108

Stack AR mole fraction - 0.0089 0.008724 0.008781

Stack H2O mole fraction - 0.0852 0.1039 0.09875

Stack CO2 mole fraction - 0.04344 0.04314 0.04418

Stack Molecular Weight lb/lbmole 28.42 28.21 28.28

Stack Temperature °F 185.2 190.5 181.4

Stack Mass flow, including Permitting Margin, per stack lb/h 6111200 5598900 6007200

Margined exhaust vol flow (incl. permitting margin) Mft3/h 103.7 96.501 101.85

Normalized vol flow, SCF @ 60F (incl. permitting margin) SCF/h 81604464 75312253 80617252

HRSG Exit Emissions (per unit)NOx Volume fraction, dry, at 15 % O2 ppm 2 2 2

NOx mass flow rate (as NO2) lb/h 25.6 23.4 25.7

CO Volume fraction, dry, at 15 % O2 ppm 1.3 1.3 1.3

CO mass flow rate lb/h 10.1 9.3 10.2

VOC Volume fraction, dry, at 15 % O2 ppm 0.7 0.7 0.7

VOC mass flow rate (as methane) lb/h 3.1 2.9 3.1

NH3 Volume fraction, dry, at 15 % O2 ppm 5 5 5

NH3 mass flow rate lb/h 23.7 21.7 23.8

SOx mass flow rate (as SO2) lb/h 4.7 4.3 4.7

Total Particulates lb/h 11.3 11.1 11.3

Sulfur Mist as H2SO4 lb/h 2.6 2.4 2.7

Stack CO2 mass flow rate, including Permitting margin lb/h 432000 396000 434000

Stack CO2 rate (per Net Plant CC Power per stack) lb/MWh 836 819 813

The notes page is an integral part of this document and must be reviewed prior to use of this data.



Page 3


By : Mike Boisclair


4 5 6 7 8 9 10 11 121 GT @ 100%

1 GT @ 38% load,

1 GT @ 30% load,

1 GT @ 32% load,

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 60% load,

95.8 -0.7 59.0 95.8 -20.0 35.0 59.0 95.8 -0.7

14.350 14.350 14.350 14.350 14.350 14.350 14.350 14.350 14.350

35 60 60 35 60 60 60 35 60

Gas Gas Gas Gas Liquid Liquid Liquid Liquid Liquid

1 0.38 0.3 0.32 1 1 1 1 0.6

On off off off off off off off off

0.0 0.0 0.0 0.0 260.8 266.4 266.4 249.8 151.8

516252 241852 194994 184161 521793 528537 524694 484380 344384

Operating Operating Operating Operating Operating Operating Operating Operating Operating


21292 21292 21292 21292 18300 18300 18300 18300 18300

23607 23607 23607 23607 20130 20130 20130 20130 20130

16.52 16.52 16.52 16.52 n.a. n.a. n.a. n.a. n.a.

13.1 13.1 13.1 13.1 15.0 15.0 15.0 15.0 15.0

21292 21292 21292 21292 21292 21292 21292 21292 21292

23607 23607 23607 23607 23607 23607 23607 23607 23607

16.52 16.52 16.52 16.52 16.52 16.52 16.52 16.52 16.52

13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1

Off Off Off Off Off Off Off Off Off

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

3459.2 1837.7 1516.3 1470.6 3940.4 3892.8 3848.4 3588.7 2646.6

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.7266 0.75 0.7445 0.7377 0.7058 0.7001 0.6947 0.6889 0.7147

0.1086 0.1233 0.126 0.1262 0.09819 0.09532 0.09332 0.09369 0.1035

0.008653 0.008932 0.008865 0.008785 0.008406 0.008338 0.008274 0.008205 0.008511

0.1122 0.07808 0.0831 0.09079 0.1243 0.132 0.1391 0.1459 0.1121

0.04381 0.03958 0.03744 0.03641 0.06314 0.06407 0.06444 0.06312 0.06111

28.13 28.46 28.39 28.29 28.27 28.19 28.12 28.03 28.38

194.0 163.1 160.3 166.9 291.5 284.5 280.0 288.3 259.6

5885500 3505200 3050800 3032500 6366300 6181400 6059300 5751100 4436300

102.28 57.353 49.823 50.219 126.51 122.01 119.19 114.76 84.074

79407236 46734218 40781904 40670910 85461030 83198246 81767914 77853532 59317047

2 2 2 2 4 4 4 4 4

25.1 13.3 11.0 10.7 59.6 58.9 58.2 54.3 40.0

1.3 1.3 1.3 1.3 2 2 2 2 2

9.9 5.3 4.4 4.2 18.1 17.9 17.7 16.5 12.2

0.7 0.7 0.7 0.7 2.0 2.0 2.0 2.0 2.0

3.1 1.6 1.3 1.3 10.4 10.3 10.1 9.5 7.0

5 5 5 5 5 5 5 5 5

23.2 12.3 10.2 9.9 27.6 27.2 26.9 25.1 18.5

4.6 2.4 2.0 2.0 7.0 7.0 6.9 6.4 4.7

11.3 9.97 9.72 9.68 48.2 48.2 48.1 47.9 46.8

2.6 1.4 1.1 1.1 4.0 3.9 3.9 3.6 2.7

424000 225000 186000 180000 657000 649000 642000 598000 441000

821 931 953 979 1259 1228 1223 1235 1282



Page 4


By : Mike Boisclair


13 14 15 16 17 18 19 20 211 GT @ 50% load,

1 GT @ 50% load,

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

1 GT @ 100%

59.0 95.8 -20.0 95.8 59.0 95.8 -20.0 59.0 95.8

14.350 14.350 14.350 14.350 14.350 14.350 14.350 14.350 14.350

60 35 60 35 60 35 60 60 35

Liquid Liquid Gas Gas Gas Gas Gas Liquid Liquid

0.5 0.5 1 1 1 1 1 1 1

off off off off On On off On On

120.1 109.8 0.0 0.0 0.0 0.0 0.0 266.4 254.2

293649 267593 626058 572742 630208 612004 627850 533260 515753



18300 18300 21292 21292 21292 21292 21292 18300 18300

20130 20130 23607 23607 23607 23607 23607 20130 20130

n.a. n.a. 16.52 16.52 16.52 16.52 16.52 n.a. n.a.

15.0 15.0 13.1 13.1 13.1 13.1 13.1 15.0 15.0

21292 21292 21292 21292 21292 21292 21292 21292 21292

23607 23607 23607 23607 23607 23607 23607 23607 23607

16.52 16.52 16.52 16.52 16.52 16.52 16.52 16.52 16.52

13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1

Off Off Operating Operating Operating Operating Operating Off Off

0.0 0.0 42441.2 34804.6 38413.1 37201.3 42584.9 0.0 0.0

0.0 0.0 99.7 81.7 90.2 87.4 100.0 0.0 0.0

2258.0 2109.7 3523.8 3230.1 3541.1 3459.2 3523.8 3914.6 3824.7

0.0 0.0 1001.9 821.6 906.8 878.2 1005.3 0.0 0.0

0.7113 0.7071 0.738 0.7244 0.7289 0.7184 0.738 0.6938 0.6862

0.103 0.1052 0.08825 0.08783 0.08635 0.0846 0.08816 0.09297 0.09254

0.008471 0.008422 0.008788 0.008626 0.008679 0.008554 0.008788 0.008263 0.008172

0.1163 0.1205 0.1092 0.125 0.1206 0.1335 0.1093 0.1402 0.1496

0.06083 0.05857 0.05561 0.05397 0.05533 0.05478 0.05565 0.06453 0.0634

28.33 28.26 28.26 28.08 28.14 27.99 28.26 28.11 28.00

243.4 251.2 172.8 178.6 176.3 182.2 180.5 281.3 293.8

3795900 3674700 6155800 5635400 6047500 5924500 6155900 6152600 6093500

70.446 69.122 103.01 95.811 102.23 101.6 104.27 121.29 122.65

50841652 49342122 82648206 76168205 81561950 80322126 82651739 83061790 82598636

4 4 2 2 2 2 2 4 4

34.1 31.9 33.3 29.7 32.7 31.8 33.3 59.2 57.8

2 2 1.9 1.9 1.9 1.9 1.9 2 2

10.4 9.7 19.2 17.2 18.9 18.4 19.3 18.0 17.6

2.0 2.0 1.8 1.8 1.8 1.8 1.8 2.0 2.0

6.0 5.6 10.4 9.3 10.3 10.0 10.4 10.3 10.1

5 5 5 5 5 5 5 5 5

15.8 14.8 30.8 27.5 30.2 29.5 30.8 27.4 26.8

4.0 3.8 6.1 5.4 6.0 5.8 6.1 7.0 6.8

46.4 46.3 22.5 20.3 21.5 21.1 22.5 48.2 48.1

2.3 2.1 3.7 3.3 3.7 3.6 3.7 3.9 3.9

377000 352000 560000 501000 550000 536000 560000 653000 638000

1283 1315 894 874 872 876 892 1224 1236



Page 5


By : Mike Boisclair


Estimated Steady State Emission Notes

HRSG Emission Notes:

1. Gas turbine(s) and steam plant are in steady-state operation.

2. Steady State Emissions data above are estimated values based on GE recommended measurements and analysis procedures, per GEK 28172.

3. Reference conditions for exhaust gas SCF are: 68°F, and 14.6959 psia.

4. Reference conditions for gas fuel SCF are: 60°F, and 14.6959 psia.

5. SO2 emission values have been estimated by assuming that all the sulfur in the fuel is converted to SO2.

6. Consistent with previous emission calculations, the SO2 and sulfur mist emission values are based on maximum sulfur content of 13.1 ppm (0.4 grains/100 scf) for gas and 15 ppm for liquid fuel.

7. SO2 and sulfur mist values are margined by 20 % to account for variation in fuel sulfur content and measurement error.

8. The CO2 estimate derived from the heat rate does not include any margin for measurement errors assuming that the compliance will be demonstrated using the heat rate from the performance test results. If CO2 compliance is to be demonstrated using actual CO2 measurements from the HRSG stack, GE recommends adding 10% margin to the estimated values.

9. Sulfur mist emission calculations conservatively assume that all SO3 combines with water to form sulfur mist. In actuality, some SO3 may form other chemical species. This would include ammonium sulfates in the presence of NH3. The maximum sulfur mist is reported to be conservative.

10. The estimated values for heat consumption and exhaust flows are margined in this document to account for equipment variations, site operating conditions, and life-cycle operating parameters.The Plant Performance section does not include permitting margin, for more information on performance please refer to the Heat Balance.

11. Distillate oil fuel-bound nitrogen is less than or equal to 0.015 % by weight.

Additional Notes for Particulate Emissions

1. Particulate Matter estimates over the entire emissions compliance region of GT operation are based on field data obtained at base load for the GT. In reality, particulate matter emissions measured in lb/h are expected to decrease at part load operation and the lb/MMBTU values at part load operation are expected not to exceed the lb/MMBTU value for PM at baseload.

2. PM10 and PM2.5 are estimated at the same rate as Total Particulates.

3. Consistent with previous emission calculations, the PM estimates are based on maximum S content in the fuel of 13.1 ppm (0.4 grains/100 scf) for gas fuel and 15 ppm for liquid fuel.



Page 6


By : Mike Boisclair

1 Estimated Emissions for 7HA.02 Rapid Response Lite

Proprietary Information & Confidential Information, 2019 General Electric Company, All Rights Reserved

Combined Cycle Startup/Shutdown Emissions for 207HA.02, Rapid Response Lite

October 2019

Per GT/HRSG Stack NOx CO VOC as

Methane

Total PMNOTE

5

Heat Consumption Duration

Cold Start (Table Note 1) 123 699 53 8.3 840 45

Warm Start (48 hrs median) See Below Table Note 2

81 190 24 7.3 815 40

Hot Start (Table Note 1) 53 177 22 4.0 325 20

Shutdown 14 152 19 3 200 12 Pounds [lb] per Event MMBtu Minutes

Table 1: 7HA.02, Natural Gas Fuel

Per GT/HRSG Stack NOx CO VOC as

Methane

Total PMNOTE

5

Heat Consumption Duration

Cold Start (Table Note 1) 221 704 141 36 992 45

Warm Start (48 hrs median) See Below Table Note 2

172 286 33 32 1000 40

Hot Start (Table Note 1) 112 273 30 16 340 20

Shutdown 43 48 7 10 132 8 Pounds [lb] per Event MMBtu Minutes

Table 2: 7HA.02, Distillate Oil Fuel

Table Notes:

(1) Hot starts are defined as taking place within 8 hours of the previous shutdown. Cold starts are preceded by over 72 hours of shutdown. Cold Start and Hot Start values can be used for both typical estimates and not-to-exceed permit limits.

(2) WARM START PERMITTING NOTE – Warm Start cool down duration ranges from >8 to <72 hours after shutdown. The Warm Start emissions will vary depending on duration of the cool down period ranging between the Hot Start and Cold Start values. Warm Start values in Table 1 are based on a 48 hours cool down period as a median point. Warm Starts with less than a 48 hours cool down period will have lower emissions and Warm Starts with a greater than 48 hours cool down period will have higher emissions. For Warm Start emission estimates, the 48 hours median value



should be used. For Warm Start not-to-exceed permit limits, the Cold Start values should be used.

End Table 1 & 2 Basis 1. The table above represents the emissions during startup and shutdown events.

2. Emissions assume no contribution from pollutants present in the GT inlet air.

Notes specific for Natural Gas

3. An average HRSG stack temperature of 174 deg F may be assumed during starts and shutdown when the LP economizer is in service. An average HRSG stack temperature of 214 deg F may be assumed during starts and shutdown when the LP economizer is bypassed.

4. Emissions assume methane as the natural gas fuel in compliance with General Electric Gas Fuel Specification GEI-41040.

5. Particulates emissions account for sulfates resulting from 0.4gr/100SCF total fuel sulfur content. Higher fuel sulfur content will increase particulate emissions.

6. During the start-up event, an average HRSG stack flow rate of 960 lb/second may be assumed.

Notes specific for Liquid Fuel

7. An average HRSG stack temperature of 270 deg F may be assumed during starts and shutdown when the LP economizer is bypassed.

8. Liquid Fuel is assumed to be in compliance with General Electric Liquid Fuel Specification GEI 41047 and is assumed to have 0.015% fuel bound nitrogen or less.

9. Particulate emissions account for sulfates resulting from 15 ppmw total fuel sulfur content. Higher fuel sulfur content will increase particulate emissions.

10. During the start-up event, an average HRSG stack flow rate of 1050 lb/second may be assumed.

General Notes

11. The information is based on a GE designed and supplied extended scope power plant. Design, manufacture, construction, and commissioning of equipment outside of this scope of supply such as auxiliary boiler must meet GE functional requirements.

12. Event duration: Startup is from the time a non-zero value is measured at the HRSG stack (of a pollutant which is guaranteed) to the time of compliance. Emission compliance is verified by 10 subsequent consecutive compliant CEMS readings however this is only a verification measurement and not counted as part of startup emission mass or duration.



Shutdown is from the time that the HRSG stack is out of emissions compliance until the time that the GT fuel valve has closed.

13. There is OpFlex SCR Ammonia control, which optimizes ammonia injection and the resulting transient emissions during the startup transient. For this, ammonia vaporizer is assumed to be electrically pre-heated and ready to inject ammonia at GT fire.

14. NOx and CO Emissions are per HRSG stack and measured at the HRSG stack using CEMS, following the CEMs calibration and commissioning. Emissions concentration (ppm) signal from the HRSG stack CEMS at 15-second or smaller sampling intervals will be converted to emissions mass flow (lb/hr) using a mutually agreed upon method per the emissions test protocol.

15. The plant is started using GE’s Rapid Response Lite auto-start sequence. Prior to start, the plant is in a ready-to-start condition, i.e. all plant equipment which is needed to be operating during startup is in a no-fault condition, operational and/or in automatic mode. Water levels and pressures in drums, hotwell and other vessels are within range and/or not in an alarmed condition. GT and HRSG Purge credit are available.

16. The plant is previously shut down from steady state operation at base load using normal shutdown sequence in accordance with General Electric’s recommendations. The duration of the shutdown/non-operational/standby period for the purpose of defining the start begins at termination of fuel flow to the GT during the plant shutdown. During the standby period, the plant is maintained as per GE-recommended procedures.

17. The GT is kept at MECL load level until stack compliance is achieved.

18. HRSG drum steam is not bled off for auxiliary services, steam seals, etc. during shutdown.

19. HRSG stack damper remains closed during the shutdown period.

20. No steam purity holds are included. No sequence holds or rate reductions caused by operator intervention are allowed.

21. Turbine insulation and enclosures are installed per GE acceptance of drawings and instructions.

22. A GT start-up fuel heater is applied and the GT is kept at MECL load level until HRSG stack compliance is achieved.

End of Startup and Shutdown Estimates

Andrew Dicke

Revision Date Purpose

- 10/21/2019 Initial Issue

A 11/22/2019 Reduced VOC emissions


APPENDIX F FUEL FRACTIONAL ANALYSES

NG fractional analyses

Component Values Methane 96.943 Ethane 2.524 Propane 0.124 Iso Butane 0.007 Normal Butane 0.012 Iso Pentane 0.003 Normal Pentane 0.002 Neo Pentane 0.000 Hexane Plus 0.013 N2 0.234 CO2 0.138 Total of Constituents 100

LIQUID FUEL – FRACTIONAL ANALYSIS

Property ASTM Method Value LHV, Btu/lb D 4809/D 240 ~18300 Kin. Viscosity, cSt, 100°F (37.8°C) D 445 1.8 – 5.8 Specific Gravity, 60°F (15.6°C) D 1298 ≤0.9 Pour Point, °F (° C) D 97 ≤-11°F (-24°C) Flash Point, °F (° C) D 93 100 - 140°F (38 - 60°C) Distillation Temp, 90% Point, (°F) D 86 ≤640°F Sulfur D 4294/D 129 <15ppmw Nitrogen, Wt. % - ≤0.015 Trace Metals , ppmw Sodium + Potassium - ≤1 Vanadium - ≤0.5 Calcium - ≤2 Lead - ≤1 Other Metals over 5 ppmw - None Other Sediment and Water Vol. % D 2709 / D 1796 ≤0.1 Water, Vol. % D 95 ≤0.1


APPENDIX G ADVANCED MONITORING AND DIAGNOSTIC SYSTEMS – POWER BLOCKS

1Monitoring & Diagnostics

4/24/2012

Advanced Sensors and Monitoring & Diagnostics (M&D) for Gas Turbines

Abstract

Advanced sensing and analytics are being used increasingly in power systems, to improve diagnostic and prognostic capabilities for expensive power generation equipment, increase performance and operability, estimate remaining useful life, and manage risk. A wide variety of technologies, from recent sensing technologies to advanced analytics, are being used by power generation equipment manufacturers, and utilities.

This talk will focus on sensor and monitoring & diagnostics (M&D) technologies for gas turbines. A case study in the development and field deployment of sensor and M&D technologies, covering the aspects of signal processing, feature extraction, anomaly detection, and real-world implementation issues will be described in detail.


4/24/12

Outline

� Principles of Monitoring & Diagnostics

� Case study of a real-life M&D application with advanced sensors for gas turbine compressor health monitoring

� Summary

How M&D fits into the big picture

Sensors, M&D/PHM & Analytics provide data that enables new products & services … and generate revenue over the life of the asset

High-Value Assets

Sensors, Data Collection & Control

Signal Processing, M&D &Analytics

Intelligent Business Processes, New Products & Services

Prevent catastrophic

failures & forced outages

Part Life Management

Performance Optimization

Better designs & retrofits

Operational Risk Mgmt

Failure

Avoidance

Parts life

Extension

Optimized

Operation

Uses of M&D

Requirements

� Prevent catastrophic

failure

� Get closer to

performance

entitlement

� Support lifing models

� Design validation

Motivation, Goals& Business Impact


4/24/2012

Impact of good detection capability on asset downtime

0

200

400

600

800

1000

1200

0

57

113

170

226

283

339

396

453

509

566

622

679

735

792

Downtime (hrs)F

requency

0

50

100

150

200

250

0

57

113

170

226

283

339

396

453

509

566

622

679

735

792

Downtime (hrs)

Fre

quency

System OK

Failure

Detected, “Planned” Event

Not detection“Unplanned” Event

Example … we have a system with an onboard sensor / anomaly detection algorithm that detects failures in advance with some Probability of Detection (PoD). If failure indications are detected early on, associated risks, downtime durations & failure costs are typically much lower.

Simulation-based trade studies can be used to optimize the sensor suite (PoD, false alarm rate, time to detect, etc.) with the asset being monitored. This significantly improves reliability, reduces outage durations and reduces overall system operational risk.

Downtime HistogramPoD = 0%

0

100

200

300

400

500

600

0

57

113

170

226

283

339

396

453

509

566

622

679

735

792

Downtime (hrs)

Fre

quency

Downtime HistogramPoD = 50%

Downtime HistogramPoD =100%

Data & results for illustrative purposes only

What is M&D?A set of algorithms, processes & tools that allow monitoring the health of an asset – detect faults before they turn into failures.

time

cost

defect

fault

failure

software

bug

error

message

system

crash

material

defect

crack

machine

destroyed

design, manufacturing

& inspection

sensing, M&D,

control

diagnostics(current

State) prognostics(future state)


4/24/2012

Preventable failures via M&D

example of a gas turbine compressor blade liberationfollowed by extensive secondary damage


4/24/12

Background on Combined Cycle Power Plants

Simple cycle operation: 211 MW

Combine cycle operation: 632 MW

Sufficient to power 250,000 homes

Heavy Duty GT

Principles of GT Operation

Compressor Stator Vane crack detection

Compressor Blade crack detection

Metal Corrosion Detection

Hot gas path component degradation

GT Monitoring Opportunities

Combustor liner cracking & thermal barrier coating

spallation

FuelContaminant

Monitoring – hot gas path degradation

Hot gas path environment is very harsh~ 2400°F~ 14 atm.


4/24/2012

Design of an M&D system

Fossil RM&D Overview

• Collect data from asset

• Process locally; Transmit data remotely over network/internet

• Archive, process more & visualize

• Run anomaly detection algorithms

• Validate and escalateArchive

Power Plant

Plant DataAcquisition

Remote M&D Architecture

Monitor

• Identify problem cause• Predict expected future behavior• Recommend Service Actions

Diagnose &Assess

Diagnostic Assessment

• Identify problem cause• Recommend Service Actions

Communicate


4/24/12

Sensing is the fundamental enabler of an M&D system

Mark

VI

level

temperature

pressure

flow

strain

gas properties

position

speed acceleration

Sense Acquire

plant

& turbine

controllers

other

assorted

data

acquisition

systems


4/24/12

Data acquisition & pre-processing

Images from National Instruments

Analog-to-Digital Conversion is the key first processing step;

Translates the analog real-world to the digital world of the computer


4/24/12

Feature extraction & Anomaly Detection –major approaches

• Statistical Methods: various standard statistical measures, such as higher order moments of key parameters, moving statistical calculations, clustering and pattern recognition

• Time Series Analysis: time evolving nature of the major monitored parameters

• Deviation from expected values: track for deviations from set-point for failure modes and incipient failures detection

• Model based methods: increasing differences between models and observed values can give insights into impending failures and isolation using appropriate classification models


4/24/12

Alarming – threshold setting� Threshold development is critical

� Hypothesis testing (False Alarms/Misses) – a key M&D concept

� most real-world anomalies are not discretely separated, they overlap

� need to make decisions with overlapping distributions between True and False

Ho : Null Hypothesis (good)

Ha : Alternate Hypothesis (bad)

False Alarms (Type I)Misses (Type II)

threshold

no win

HaHo HaHo

better

HaHo

best – but unrealistic

select features to maximize separation – key algorithmic challenge

Ho

Ha

Ho Ha

Case Study

Compressor Blade Health Monitoring (BHM)


4/24/12

Typical failure drivers & mechanisms for turbine blades

� High cycle fatigue (HCF)

� Normal corrosion can initiate tiny pits in metal

� Continuous flexing of blades during operation can grow cracks from pits (high cycle fatigue)

� When a crack gets large enough, the centrifugal force can pull blade apart (liberation)

� Foreign Object Damage (FOD):

� Debris gets sucked in and damages blades

� Rubs

� A liberation could cause significant secondary damage -> millions of dollars

examplestressregions

continuous vibration – flutter, resonances

typical gas turbine

compressor blade

crack initiationlocations


4/24/2012

Expected signatures

M&D Approach– model driven diagnostics

model based expectations of feature changes

(validated via seeded fault tests)

sensor

Blade static & dynamic deflection features & clearance are computed in real-time, for� every blade� every rotation

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

crack size

LE

sta

tic

de

f

Static deflection

Resonant Frequency Detuning

Crack size

Crack size

FE crack models

root LE SSDT Tip LE

Resonance

detection:commonlyused structuralhealth monitoringfeature


4/24/2012

Monitoring System Overview

bladeprobes

installedon compressor

casing

A/D converter

Blade tip timingcalculation

DataAcquisitionSystem

Deflections of blades measured

Amplitude, Volts

Time, Milliseconds

Measured Blade Passing

Signal

Expected

Blade VibrationAnalysis

On-site (plant)

Off-site

R0 Blades R1 Blades R2 Blades

1/rev. probe

7.5 Mbytes/sec

400:1

data

reduction


4/24/2012

Sensing blade position

R0 R1 R2

sensors monitorblade passage in real-time(tips move near speed of sound)

passive reluctance

probe

induced voltageby blade passing - Blade Passing Signal (BPS)


4/24/12

DAQ Data Processing Architecture

DAQ

Pre-processing:� Digitize blade passing

signal

(> 300 kHz)

� Filter signal

� Process and find the Time-of-Arrival (TOA) of each blade in real-time (every 500 microseconds)

Mag

LE2

LE3

TE1

Compressor SensorsPC Buffer (Circular)

Producer Thread

Consumer Thread


4/24/2012

Time-of-Arrival Calculation

Single raw BPS from a sensor

Smoothing filter applied (red

trace) -based on a moving

window polynomial

regression

Filtered BPS


4/24/2012

TOA calculation - Interpolation & Centroid Calculation

index

Threshold

x1,x,x2

• Time of Arrival/Departure is measured in terms of the A/D sampling index count.

• Algorithm=(y2-y1/x2-x1)=(y-y1/x-x1). Find X for Y=1.5 volts (example).

• Interpolation needed to reduce quantization error on the DAQ A/D and any residual noise.

First data value > Threshold

First data point

< Threshold

BPSvolts

y1

y2

Time of Departure

TOArr TODep

Peak

TOA = (TOArr+TODep)/2

Time of Arrival

Interpolation

Centroid


4/24/12

Blade Time of Arrival (TOA)

Static

Deflection

VibrationExpected TOA

NoiseMeasured TOA

• Speed Variation • Sensor and Key Phasor Relative Location

• Blade Geometry Variation• IGV/Load Variation• Blade Re-seating

• Asynchronous Vibration(Dynamic Deflection)• Synchronous Vibration(Resonance Parameters)

Blade Delta TOA

SensorBlade – No Vibration

Vibrating Blade

Blade Time

of Arrival

Difference

Field Signal


4/24/2012

Key Blade “Health” Features

Static

Deflection

VibrationExpected TOA

NoiseMeasured TOA

Static blade deflection tracked continuously

Blade Time-of-Arrival

establishedat start of resonance andsteady state condition Campbell

definedresonance


4/24/2012

Feature Trending & Thresholding

Resonances Static Deflection

Thresholds are established prior to monitoring

Feature Extraction server

File Transfer server

Backup server

Oracle server

Processed data back up

Computation server

File transfer server

BHM 24x7 Computing Infrastructure

Storage


4/24/12

Field Validation - anomaly detection

Conclusions

Observed by BHM July 2011

• Shift observed in static deflection on R0 -Blade 1

• No change in vibration or performance

• Borescope inspection recommended

• Tip FOD on R0-1 confirmed

Findings

• FOD based tip damage

• Repairable damage

BHM Signal Change

R0 FOD

30GE Title or job number

4/24/2012

M&D – the future…

� Use of M&D is increasing rapidly across many industries and applications

� Sensors are getting smaller, cheaper, smarter and pervasive

� Computing becoming cheaper exponentially

� Wireless and portable visualization hardware (iEverything) will enable wider deployment

� Provides significant payback

� The next frontier is Prognostics

� Prediction of time to failure

� Analytics will play an increasingly larger role in processing the oncoming data deluge (“Internet of Things”)


APPENDIX H COMBUSTION CONTROL DETAILS – POWER BLOCKS

GE Power Systems

Dry Low NOx CombustionSystems for GE Heavy-DutyGas Turbines

L.B. DavisS.H. BlackGE Power SystemsSchenectady, NY

GER-3568G

g

Contents

Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Dry Low NOx Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Dry Low NOx Product Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1DLN-1 System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3DLN-1 Combustor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Mode/Operating Range . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4DLN-1 Controls and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6DLN-1 Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6DLN-1 Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7DLN-2 System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8DLN-2 Combustion System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Primary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Lean-Lean. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Premix Transfer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Piloted Premix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Premix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Tertiary Full Speed No Load (FSNL). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

DLN-2 Controls and Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2 Emissions Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2 Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11DLN-2.6 Evolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12DLN-2+ Evolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Gas Turbine Combustion Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Equivalence Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Flame Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Operational Stability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Gas Turbine Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Emissions Control Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Dry Low NOx Combustion Systems for GE Heavy-Duty Gas Turbines

GE Power Systems ■ GER-3568G ■ (10/00) i


GE Power Systems ■ GER-3568G ■ (10/00) ii

AbstractState-of-the-art emissions control technology forheavy-duty gas turbines is reviewed with empha-sis on the operating characteristics and fieldexperience of Dry Low NOx (DLN) combustorsfor E and F technology machines. The lean pre-mixed DLN systems for gas fuel have demon-strated their ability to meet the ever-lower emis-sion levels required today. Lean premixed tech-nology has also been demonstrated on oil fueland is also discussed.

IntroductionThe regulatory requirements for low emissionsfrom gas turbine power plants have increasedduring the past 10 years. Environmental agen-cies throughout the world are now requiringeven lower rates of emissions of NOx and otherpollutants from both new and existing gas tur-bines. Traditional methods of reducing NOx

emissions from combustion turbines (water andsteam injection) are limited in their ability toreach the extremely low levels required in manylocalities. GE’s involvement in the developmentof both the traditional methods (References 1through 6) and the newer Dry Low NOx (DLN)technology (References 7 and 8) has been welldocumented. This paper focuses on DLN.

Since the commercial introduction of GE’sDLN combustion systems for natural-gas-firedheavy-duty gas turbines in 1991, systems havebeen installed in more than 222 machines, fromthe most modern FA+e technology (firing tem-perature class of 2420 F/1326 C) to field retro-fits of older machines. As of May 1999, thesemachines have operated more than 4.8 millionhours with DLN; and more than 1.4 millionhours have been in the F technology. To meetmarketplace demands, GE has developed DLNproducts broadly classified as either DLN-1,which was developed for E-technology

(2000°F/1093°C firing temperature class)machines, or DLN-2, which was developedspecifically for the F technology machines andis also being applied to the EC and H machines.

Development of these products has required anintensive engineering effort involving both GEPower Systems and GE Corporate Research andDevelopment. This collaboration will continueas DLN is applied to the H machines and com-bustor development for Dry Low NOx on oil(“dry oil”) continues.

This paper presents the current status of DLN-1technology and experience, including dry oil,and of DLN-2 technology and experience.Background information about gas turbineemissions and emissions control is contained inthe Appendix.

Dry Low NOx Systems

Dry Low NOx Product Plan Figure 1 shows GE’s Dry Low NOx product of-ferings for its new and existing machines inthree major groupings. The first group includesthe MS3002J, MS5001/2 and MS6001B prod-ucts. The 6B DLN-1 is the technology flagshipproduct for this group and, as can be noted, isavailable to meet 9 ppm NOx requirements.Such low NOx emissions are generally notattainable on lower firing temperaturemachines such as the MS3002s and MS5001/2sbecause carbon monoxide (CO) would beexcessive.

The second major group includes theMS7001B/E, MS7001EA and MS9001Emachines with the 9 ppm 7EA DLN-1 as theflagship product.

The dry oil program focuses initially on thisgroup.

The third group combines all of the DLN-2products and includes the FA, EC, and H


GE Power Systems ■ GER-3568G ■ (10/00) 1

machines, with the 7FA product as the flagship.

As shown in Figures 2 and 3, most of these prod-ucts are capable of power augmentation and ofpeak firing with increased NOx emissions. With

gas fuel, power augmentation with steam is inthe premixed mode for both DLN-1 and DLN-2systems.

The GE DLN systems integrate a staged pre-mixed combustor, the gas turbine’sSPEEDTRONIC™ controls and the fuel andassociated systems. There are two principalmeasures of performance. The first is meetingthe emission levels required at baseload on bothgas and oil fuel and controlling the variation ofthese levels across the load range of the gas tur-bine.

The second measure is system operability, withemphasis placed on the smoothness and relia-bility of combustor mode changes, ability toload and unload the machine without restric-tion, capability to switch from one fuel to anoth-er and back again, and system response to rapidtransients (e.g., generator breaker open eventsor rapid swings in load). GE’s design goal is tomake the DLN system operate so the gas tur-bine operator does not know whether a DLN orconventional combustion system has beeninstalled (i.e., its operation is “transparent tothe user”). A significant portion of the DLNdesign and development effort has focused onsystem operability. As operational experience



9 25

Turbine Model

MS6001(B)

MS7001(EA)

MS7001(FA) 9

25

9

25

9

NOx@15% O2(ppmvd)

OperatingMode Diluent

NOx atMax D/F(ppmvd)

MaximumDiluent/Fuel

COMax D/F(ppmvd)

Premix

Premix

Premix

Premix

Premix Steam

Steam

Steam

Steam

Steam 2.5/1

2.5/1

2.5/1

2.5/1

GT24556B.ppt

2.1/1 12

25 15

15

9 25

25 15

Figure 2. DLN power augmentation summary

MS6001(B)

MS7001(EA)

MS7001(FA)

MS9001(E)

9

25

18

50

25

15

6

4

9

25

25

25

25

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18

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40 15

6

4

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6

NOx-Base(ppmvd)

NOx-Peak(ppmvd)

CO-Base(ppmvd)

CO-Peak(ppmvd)

GT24557A . ppt

Figure 3. DLN peak firing emissions - natural gasfuel

Gas Distillate

Turbine Model NOx (ppmvd) CO (ppmvd) Diluent NOx (ppmvd) CO (ppmd) Diluent

MS3002(J)-RC 33 25 Dry N/A N/A N/A

MS3002(J)-SC 42 50 Dry N/A N/A N/A

MS5001P 25 50 Dry 65 20 W ater

MS5001R 42 50 Dry 65 20 W ater

MS5002C 42 50 Dry 65 20 W ater

MS6001B 9 25 Dry 42 30 W ater

MS7001B/E Conv. 25 25 Dry 42 30 W ater

MS7001EA 9 25 Dry 42 30 W ater

MS9001E 15 25 Dry 42 20 W ater

25 25 Dry 90 20 Dry

MS6001FA 25 15 Dry 42/65 20 W ater/Steam

MS7001FA 25 15 Dry 42/65 20 W ater/Steam

9 9 Dry 42/65 30 W ater/Steam

MS7001FB 25 15 Dry 42 20 W ater

MS7001H 9 9 Dry 42/65 30 W ater/Steam

MS9001EC 25 15 Dry 42/65 20 W ater/Steam

MS9001FA 25 15 Dry 42/65 20 W ater

MS9001FB 25 15 Dry 42 20 W ater

MS9001H 25 15 Dry 42 20 W ater

Figure 1. Dry Low NOx product plan

has increased, design and development effortshave moved towards hardware durability andextending combustor inspection intervals.

Design of a successful DLN combustor for aheavy-duty gas turbine also requires the design-er to develop hardware features and opera-tional methods that simultaneously allow theequivalence ratio and residence time in theflame zone to be low enough to achieve lowNOx, but with acceptable levels of combustionnoise (dynamics), stability at part-load opera-tion and sufficient residence time for CO burn-out, hence the designation of DLN combustiondesign as a “four-sided box” (See Figure 4).

A scientific and engineering development pro-gram by GE’s Corporate Research andDevelopment, Power Systems business andAircraft Engine business has focused on under-standing and controlling dynamics in lean pre-mixed flows. The objectives have been to:

■ Gather and analyze machine and labo-ratory data to create a comprehensivedynamics data base

■ Create analytical models of gas turbinecombustion systems that can be used tounderstand dynamics behavior

■ Use the analytical models and experi-mental methods to develop methods tocontrol dynamics

These efforts have resulted in a large number ofhardware and control features that limit dynam-ics, plus analytical tools that are used to predictsystem behavior. The latter are particularly use-ful in correlating laboratory test data from fullscale combustors with actual gas turbine data.

DLN-1 SystemDLN-1 development began in the 1970s withthe goal of producing a dry oil system to meetthe United States Environmental ProtectionAgency’s New Source Performance Standardsof 75 ppmvd NOx at 15% O2. As noted inReference 7, this system was tested on both oiland gas fuel at Houston Lighting & Power in1980 and met its emission goals. Subsequent tothis, DLN program goals changed in responseto stricter environmental regulations and thepace of the program accelerated in the late1980s.

DLN-1 CombustorThe GE DLN-1 combustor (shown in cross sec-tion in Figure 5 and described in Reference 8) is atwo-stage premixed combustor designed for usewith natural gas fuel and capable of operationon liquid fuel. As shown, the combustion systemincludes four major components: fuel injectionsystem, liner, venturi and cap/centerbodyassembly.



GT23812B

NOx

CO

Turndown

Dynamics

Figure 4. DLN technology - a four sided box Figure 5. Dry Low NOx combustor

The GE DLN-1 combustion system operates infour distinct modes, illustrated in Figure 6, dur-ing premixed natural gas or oil fuel operation:

These components form two stages in the com-bustor. In the premixed mode, the first stagethoroughly mixes the fuel and air and delivers auniform, lean, unburned fuel-air mixture to thesecond stage.

Mode/Operating Range■ Primary – Fuel to the primary nozzles

only. Flame is in the primary stageonly. This mode of operation is usedto ignite, accelerate and operate themachine over low- to mid-loads, up toa pre-selected combustion referencetemperature.

■ Lean-Lean – Fuel to both the primaryand secondary nozzles. Flame is inboth the primary and secondarystages. This mode of operation is usedfor intermediate loads between twopre-selected combustion referencetemperatures.

■ Secondary – Fuel to the secondarynozzle only. Flame is in the secondaryzone only. This mode is a transitionstate between lean-lean and premix

modes. This mode is necessary toextinguish the flame in the primaryzone, before fuel is reintroduced intowhat becomes the primary premixingzone.

■ Premix – Fuel to both primary andsecondary nozzles. Flame is in thesecondary stage only. This mode ofoperation is achieved at and near thecombustion reference temperaturedesign point. Optimum emissions aregenerated in premix mode.

The load range associated with these modes var-ies with the degree of inlet guide vane modula-tion and, to a smaller extent, with the ambienttemperature. At ISO ambient, the premix oper-ating range is 50% to 100% load with IGV mod-ulation down to 42°, and 75% to 100% loadwith IGV modulation down to 57°. The 42° IGVminimum requires an inlet bleed heat system.

If required, both the primary and secondaryfuel nozzles can be dual-fuel nozzles, thus allow-ing automatic transfer from gas to oil through-out the load range. When burning either natu-ral gas or distillate oil, the system can operate tofull load in the lean-lean mode (Figure 6). Thisallows wet abatement of NOx on oil fuel andpower augmentation with water on gas.



Primary Operation• Ignition to 20% Load

GT20885B. ppt

Lean-Lean Operation• 20 to 50% Load

Second-Stage Burning• Transient During Transfer to Premixed

Premixed Operation• 50 to 100% Load

Fuel100%

Fuel100%

Fuel70%

Fuel83%

17%

30%

Figure 6. Fuel-staged Dry Low NOx operating modes

The spark plug and flame detector arrange-ments in a DLN-1 combustor are different fromthose used in a conventional combustor. Sincethe first stage must be re-ignited at high load inorder to transfer from the premixed mode backto lean-lean operation, the spark plugs do notretract. One plug is mounted near a primaryzone cup in each of two combustors. The systemuses flame detectors to view the primary stage ofselected chambers (similar to conventional sys-tems), and secondary flame detectors that lookthrough the centerbody and into the secondstage.

The primary fuel injection system is used dur-ing ignition and part load operation. The sys-tem also injects most of the fuel during pre-mixed operation and must be capable of stabi-lizing the flame. For this reason, the DLN-1 pri-mary fuel nozzle is similar to GE’s MS7001EAmulti-nozzle combustor with multiple swirl-sta-bilized fuel injectors. The GE DLN-1 systemuses five primary fuel nozzles for the MS6001Band smaller machines and six primary fuel noz-zles for the larger machines. This design is capa-ble of providing a well-stabilized diffusion flamethat burns efficiently at ignition and duringpart load operation.

In addition, the multi-nozzle fuel injection sys-tem provides a satisfactory spatial distributionof fuel flow entering the first-stage mixer. Theprimary fuel-air mixing section is bound by thecombustor first-stage wall, the cap/centerbodyand the forward cone of the venturi. This vol-ume serves as a combustion zone when thecombustor operates in the primary and lean-lean modes. Since ignition occurs in this stage,crossfire tubes are installed to propagate flameand to balance pressures between adjacentchambers. Film slots on the liner walls providecooling, as they do in a standard combustor.

In order to achieve good emissions perform-

ance in premixed operation, the fuel-air equiv-alence ratio of the mixture exiting the first-stagemixer must be very lean. Efficient and stableburning in the second stage is achieved by pro-viding continuous ignition sources at both theinner and outer surfaces of this flow. The threeelements of this stage comprise a piloting flame,an associated aerodynamic device to force inter-action between the pilot flame and the innersurface of the main stage flow, and an aerody-namic device to create a stable flame zone onthe outer surface of the main stage flow exitingthe first stage.

The piloting flame is generated by the second-ary fuel nozzle, which premixes a portion of thenatural gas fuel and air (nominally, 17% at full-load operation) and injects the mixturethrough a swirler into a cup where it is burned.Burning an even smaller amount of fuel (lessthan 2% of the total fuel flow) stabilizes thisflame as a diffusion flame in the cup. The sec-ondary nozzle, which is mounted in the capcenterbody, is simple and highly effective forcreating a stable flame.

A swirler mounted on the downstream end ofthe cap/centerbody surrounds the secondarynozzle. This creates a swirling flow that stirs theinterface region between the piloting flame andthe main-stage flow and ensures that the flameis continuously propagated from the pilot to theinner surface of the fuel-air mixture exiting thefirst stage. Operation on oil fuel is similarexcept that all of the secondary oil is burned ina diffusion flame in the current dry oil design.

The sudden expansion at the throat of the ven-turi creates a toroidal re-circulation zone overthe downstream conical surface of the venturi.This zone, which entrains a portion of the ven-turi cooling air, is a stable burning zone thatacts as an ignition source for the main stagefuel-air mixture. The cone angle and axial loca-



tion of the venturi cooling air dump have sig-nificant effects on the efficacy of this ignitionsource. Finally, the dilution zone (the region ofthe combustor immediately downstream fromthe flame zone in the secondary) provides aregion for CO burnout and for shaping the gastemperature profile exiting the combustion sys-tem.

DLN-1 Controls and Accessories The gas turbine accessories and control systemsare configured so that operation on a DLN-equipped turbine is essentially identical to thatof a turbine equipped with a conventional com-bustor. This is accomplished by controlling theturbines in identical fashions, with the exhausttemperature, speed and compressor dischargepressure establishing the fuel flow and com-pressor inlet-guide-vane position.

A turbine with a conventional diffusion com-bustor that uses diluent injection for NOx con-trol will use an underlying algorithm to controlsteam or water injection. This algorithm will usetop level control variables (exhaust tempera-ture, speed, etc.) to establish a steam-to-fuel orwater-to-fuel ratio to control NOx.

In a similar fashion, the same variables are usedto divide the total turbine fuel flow between theprimary and secondary stages of a DLN com-bustor. The fuel division is accomplished bycommanding a calibrated splitter valve to moveto a set position based on the calculated com-bustion reference temperature (Figure 7). Figure8 shows a schematic of the gas fuel system for aDLN-equipped turbine.

The only special control sequences required arefor protection of the turbine during a generatorbreaker open trip, or for a Primary ZoneIgnition or Primary Re-Ignition (PRI) (i.e.,flame is established in first stage during pre-mixed operation). When either the breaker

opens at load or a PRI is sensed by ultravioletflame detectors looking into the first stage, thesplitter valve is commanded to move to a pre-determined position. For the breaker openevent the combustor returns to normal opera-tion in primary mode at full speed no load(FSNL). In the case of a PRI there is no hard-ware damage and the combustor maintains loadbut operates in extended lean-lean mode withhigh emissions.

DLN-1 EmissionsThe emissions performance of the GE DLN sys-tem can be illustrated as a function of load for agiven ambient temperature and turbine config-uration. Figures 9 and 10 show the NOx and COemissions from typical MS7001EA andMS6001B DLN systems designed for 9 ppmvdNOx and 25 ppm CO when operated on natural



Lean-Lean

Secondary Mode

Premix Mode

202019501600 º F

11041066871 º C

CombustionReference

Temperature

100

90

0

10

20

30

40

50

60

70

80

% P

rim

ary

Fu

el S

plit

GT20327D

Primary Mode

Figure 7. Typical DLN-1 fuel gas split schedule

Figure 8. Dry Low NOx gas fuel system

gas fuel. Note that in premixed operation, NOx

is generally highest at higher loads and CO onlyapproaches 25 ppm at lower premixed loads.The MS9001E DLN system has very similarbehavior but with somewhat higher NOx emis-sions (See Figure 1). Figures 11 and 12 show NOx

and CO emissions for the same systems operat-ed on oil fuel with water injection for NOx con-trol, rather than premixed oil. These figures arefor units equipped with inlet bleed heat andextended IGV modulation.

At loads less than 20% of baseload, NOx andCO emissions from the DLN are similar to thosefrom standard combustion systems. This resultis expected because both systems are operatingas diffusion flame combustors in this range.Between 20% and 50% load, the DLN system isoperated in the lean-lean mode. On gas fuel theflow split between the primary fuel nozzles and

secondary nozzle may be varied to optimizeemissions, while on oil fuel the flow split isfixed.

From 50% to 100% load, the DLN system oper-ates as a lean premixed combustor when operat-ed on gas fuel, and as a diffusion flame combus-tor with water injection when operated on oilfuel. As shown in Figures 9–12, NOx emissionsare significantly reduced, while CO emissionsare comparable to those from the standard sys-tem.

DLN-1 ExperienceGE’s first DLN-1 system was tested at HoustonLighting and Power in 1980 (Reference 7). A pro-totype DLN system using the combustor designdiscussed above was tested on an MS9001E atthe Electricity Supply Board’s (ESB) NorthwallStation in Dublin, Ireland, between October



Figure 10. MS6001B emissions - natural gas

Figure 12. MS6001B emissions distillate oil fuel

Figure 11. MS7001EA Dry Low NOx combustionsystem performance on distillate oil

Figure 9. MS7001EA/MS9001E emissions - natural gas fuel

1989 and July 1990. A comprehensive engineer-ing test of the prototype DLN combustor, con-trols and associated systems was conducted withNOx levels of 32 ppmvd (at 15% O2) obtainedat baseload. The results were incorporated intothe design of prototype systems for theMS7001E and MS6001B.

The 7E DLN-1 prototype was tested atAnchorage Municipal Light and Power (AMLP)in early 1991 and entered commercial serviceshortly afterward. Since then, development ofadvanced combustor configurations have beencarried out at AMLP. These results have beenincorporated into production hardware.

The MS6001B prototype system was first oper-ated at Jersey Central Power & Light’s ForkedRiver Station in early 1991. A series of addition-al tests culminated in the demonstration of a 9ppm combustor at Jersey Central in November1993.

As of May 1999, 44 MS6001B machines areequipped with DLN-1 systems. In total, theyhave accumulated more than 1.4 million hoursof operation. There are, in addition, 4MS7001E, 8 MS7001B/E, 39 MS7001EA, 27MS9001E, 2 MS5001P and 4 MS3002J DLN-1machines that have collectively operated formore than 2 million hours. Excellent emissionresults have been obtained in all cases, with sin-gle-digit NOx and CO achieved on manyMS7001EAs. Several MS7001E/EA machineshave the capability to power augment withsteam injection in premixed mode.

Starting in early 1992, eight MS7001F machinesequipped with GE DLN systems were placed inservice at Korea Electric Power Company’sSeoinchon site. These F technology machineshave achieved better than 55% (gross) efficien-cy in combined-cycle operation, and the DLNsystems are currently operating between 30 and40 ppmvd NOx on gas fuel (the guarantee level

is 50 ppmvd). These units have operated formore than 250,000 hours. Four additional Ftechnology DLN-1 systems were commissionedat Scottish Hydro’s Keadby site and at NationalPower’s Little Barford site. These 9F machineshave operated more than 80,000 hours at lessthan 60 ppm NOx.

The combustion laboratory’s testing and fieldoperation have shown that the DLN-1 systemcan achieve single digit NOx and CO levels on Etechnology machines operating on gas fuel.Current DLN-1 development activity focuseson:

■ Application of single-digit technologyto the MS6001B and MS7001EAuprates.

■ Application of DLN-1 technology forretrofitting existing field machines(including MS3002s and MS5000s,some of which will require upgradebefore DLN retrofit)

■ Completing the development of steampower augmentation as needed by themarket

■ Completing the development of leanpremixed oil fuel DLN-1 products.

■ Increasing combustion inspection intervals.

■ Improving overall system reliabilityand operability for operation on oilfuel.

DLN-2 SystemAs F-technology gas turbines became availablein the late 1980s, studies were conducted toestablish what type of DLN combustor would beneeded for these new higher firing temperaturemachines. Studies concluded that that air usagein the combustor (e.g., for cooling) other thanfor mixing with fuel would have to be strictly



limited. A team of engineers from GE PowerSystems, GE Corporate Research andDevelopment and GE Aircraft Engines pro-posed a design that repackaged DLN-1 premix-ing technology but eliminated the venturi andcenterbody assemblies that require cooling air.

The resulting combustor is called DLN-2, whichis the standard system for the 6FA, 7FA, and 9FAmachines. Fourteen combustors are installed inthe 7FA, 18 in the 9FA, and six in the 6FA. Twoadditional variants of the DLN-2 system havebeen developed to meet the additional designrequirements imposed by either new machinecycles or reduced emissions levels. These com-bustors, the DLN-2.6 and the DLN-2+, will bedescribed briefly in later sections.

DLN-2 Combustion System The DLN-2 combustion system shown in Figure13 is a single-stage dual-mode combustor thatcan operate on both gaseous and liquid fuel.On gas, the combustor operates in a diffusionmode at low loads (< 50% load), and a pre-mixed mode at high loads (> 50% load). Whilethe combustor can operate in the diffusionmode across the load range, diluent injectionwould be required for NOx abatement. Oiloperation on this combustor is in the diffusionmode across the entire load range, with diluentinjection used for NOx control.

Each DLN-2 combustor system has a singleburning zone formed by the combustor linerand the face of the cap. In low emissions opera-tion, 90% of the gas fuel is injected throughradial gas injection spokes in the premixer, andcombustion air is mixed with the fuel in tubessurrounding each of the five fuel nozzles. Thepremixer tubes are part of the cap assembly.The fuel and air are thoroughly mixed, flow outof the five tubes at high velocity and enter theburning zone where lean, low-NOx combustionoccurs. The vortex breakdown from the swirlingflow exiting the premixers, along with the sud-den expansion in the liner, are mechanisms forflame stabilization. The DLN-2 fuel nozzle/pre-mixer tube arrangement is similar in designand technology to the secondary nozzle/cen-terbody of a DLN-1. Five nozzle/premixer tubeassemblies are located on the head end of thecombustor. A quaternary fuel manifold is locat-ed on the circumference of the combustion cas-ing to bring the remaining fuel flow to casinginjection pegs located radially around the cas-ing.

Figure 14 shows a cross-section of a DLN-2 fuelnozzle. As noted, the nozzle has passages for dif-fusion gas, premixed gas, oil and water. Whenmounted on the end cover, as shown in Figure15, the diffusion passages of four of the fuelnozzles are fed from a common manifold,called the primary, that is built into the endcover. The premixed passages of the same fournozzles are fed from another internal manifoldcalled the secondary. The pre-mixed passages ofthe remaining nozzle are supplied by the terti-ary fuel system; the diffusion passage of thatnozzle is always purged with compressor dis-charge air and passes no fuel.

Figure 15 shows the fuel nozzles installed on thecombustion chamber end cover and the con-nections for the primary, secondary and tertiaryfuel systems. DLN-2 fuel streams are:



Figure 13. DLN-2 combustion system

■ Primary fuel – fuel gas enteringthrough the diffusion gas holes in theswirler assembly of each of theoutboard four fuel nozzles

■ Secondary fuel – premix fuel gasentering through the gas meteringholes in the fuel gas injector spokes ofeach of the outboard four fuel nozzles

■ Tertiary fuel – premix fuel gas deliveredby the metering holes in the fuel gasinjector spokes of the inboard fuelnozzle

■ The quaternary system – injects a smallamount of fuel into the airstream justup-stream from the fuel nozzle swirlers

The DLN-2 combustion system can operate inseveral different modes.

Primary Fuel only to the primary side of the four fuelnozzles; diffusion flame. Primary mode is usedfrom ignition to 81% corrected speed.

Lean-Lean Fuel to the primary (diffusion) fuel nozzles andsingle tertiary (premixing) fuel nozzle. Thismode is used from 81% corrected speed to apre-selected combustion reference tempera-ture. The percentage of primary fuel flow ismodulated throughout the range of operationas a function of combustion reference tempera-ture. If necessary, lean-lean mode can be oper-ated throughout the entire load range of theturbine. Selecting “lean-lean base on” locks outpremix operation and enables the machine tobe taken to base load in lean-lean.

Premix Transfer Transition state between lean-lean and premixmodes. Throughout this mode, the primaryand secondary gas control valves modulate totheir final position for the next mode. The pre-mix splitter valve is also modulated to hold aconstant tertiary flow split.

Piloted Premix Fuel is directed to the primary, secondary andtertiary fuel nozzles. This mode exists whileoperating with temperature control off as anintermediate mode between lean-lean and pre-mix mode. This mode also exists as a defaultmode out of premix mode and, in the eventthat premix operating is not desired, pilotedpremix can be selected and operated to base-load. Primary, secondary and tertiary fuel splitare constant during this mode of operation.

Premix Fuel is directed to the secondary, tertiary andquaternary fuel passages and premixed flameexists in the combustor. The minimum load for



Figure 14. Cross-section of a DLN-2 fuel nozzle

Figure 15. External view of DLN-2 fuel nozzlesmounted

premixed operation is set by the combustionreference temperature and IGV position. It typ-ically ranges from 50% with inlet bleed heat onto 65% with inlet bleed heat off. Mode transi-tion from premix to piloted premix or pilotedpremix to premix, can occur whenever the com-bustion reference temperature is greater than2200 F/1204 C. Optimum emissions are gener-ated in premix mode.

Tertiary Full Speed No Load (FSNL) Initiated upon a breaker open event from anyload > 12.5%. Fuel is directed to the tertiarynozzle only and the unit operates in secondaryFSNL mode for a minimum of 20 seconds, thentransfers to lean-lean mode.

Figure 16 illustrates the fuel flow scheduling as-sociated with DLN-2 operation. Fuel staging de-pends on combustion reference temperatureand IGV temperature control operation mode.

DLN-2 Controls and Accessories The DLN-2 control system regulates the fuel dis-tribution to the primary, secondary, tertiary andquaternary fuel system. The fuel flow distribu-tion to each combustion fuel system is a func-tion of combustion reference temperature andIGV temperature control mode. Diffusion,piloted premix and premix flame are estab-lished by changing the distribution of fuel flowin the combustor. The gas fuel system (Figure

17) consists of the gas fuel stop-ratio valve, pri-mary gas control valve, secondary gas controlvalve premix splitter valve and quaternary gascontrol valve. The stop-ratio valve is designed tomaintain a predetermined pressure at the con-trol-valve inlet.

The primary, secondary and quaternary gascontrol valves regulate the desired gas fuel flowdelivered to the turbine in response to the fuelcommand from the SPEEDTRONIC™ controls.

The premix splitter valve controls the fuel flowsplit between the secondary and tertiary fuelsystem.

DLN-2 Emissions PerformanceFigures 18 and 19 show the emissions perform-ance for a DLN-2-equipped 7FA/9FA for gasfuel and for oil fuel with water injection.

DLN-2 ExperienceThe first DLN-2 systems were placed in serviceat Florida Power and Light’s Martin Station withcommissioning beginning in September 1993,and the first two (of four) 7FA units enteredcommercial service in February 1994. Duringcommissioning, quaternary fuel was added andother combustor modifications were made tocontrol dynamic pressure oscillations in thecombustor.



GT24671

Primary

Secondary

Tertiary

Quaternary

Premix ModeLean-LeanMode

PrimaryMode

235022002135

Combustion Reference Temperature

100

70

60

50

40

30

20

10

0

% o

f Bas

e Lo

ad F

uel F

low

16% Speed 1000 20 40 60 80 100

% Load Typical

Figure 16. Typical DLN-2 gas fuel split schedule

Figure 17. DLN-2 gas fuel system

After the 7FA DLN-2 entered commercial serv-ice the 9FA DLN-2 was introduced. Subsequentfleet experience indicated that to achieve ade-quate operational robustness against the entirerange of site specific events, an improvement inpremixer flashback resistance was needed.Under certain transient conditions flashbackcan occur where flame “holds” or is supportedin the recirculation zone downstream of thepremixed gas pegs. This region is not designedto withstand the abnormally high temperaturesresulting from the presence of a flame. In theevent of a flashback, the metal temperaturesincrease to unacceptable levels and hardware

damage occurs. In some cases, these eventshave caused forced outages and adverselyimpacted availability. The solution chosen wasto install full “fairings” on the downstream sideof the cylindrical fuel injection pegs.Laboratory testing and subsequent fleet experi-ence has demonstrated that full fairings arehighly effective in reducing the probability offuel nozzle flash-back. The fairings improve thepeg aerodynamics in order to reduce the size ofthe recirculation zone downstream of the pegs.The result is to significantly reduce the proba-bility of flame holding or attachment to the pre-mixed pegs. Figure 20 shows the original DLN-2fuel nozzle while Figure 21 illustrates the samenozzle with the addition of the fuel-peg fairings.

As of May 1999 there were 8 6FA, 26 7FA and 389FA units equipped with DLN-2 in commercialservice. They have accumulated more than 1.1million hours of operation.

DLN-2.6 EvolutionRegulatory pressures in the U.S. market in theearly 1990s led to the need to develop a 9 ppmcombustion system for the Frame 7FA. Theresult of this development is the DLN-2.6, whichwas first placed into service in March 1996 atPublic Service of Colorado.

Reduction of NOx levels from the DLN-2 at 25ppm to 9 ppm required that approximately 6%



Figure 20. Un-faired DLN-2 fuel nozzle

Figure 19. Distillate oil emissions with waterinjection above 50% load

Figure 18. Gas fuel emissions in diffusion andpremixed

additional air was needed to pass through thepremixers in the combustor (see Appendix fordescription of the NOx and temperature rela-tionship). This change in air splits was accom-plished through reductions in cap and linercooling air flows, requiring increased coolingeffectiveness. However, without changes in theoperation of the DLN-2 system, certain penal-ties would have been incurred for achieving 9ppm baseload performance. The turndown of aDLN-2 combustor tuned to 9/9 operation wasestimated to be about 70% load, compared to40% load for the 25/15 system. A new combus-tor configuration was conceived based on theDLN-2 burner, but overcoming these difficul-ties. The DLN-2 burner was carried forward asthe basis of the new combustor because of itsexcellent flame stabilization characteristics andthe large database of knowledge, which hadbeen accumulated on the parameters affectingcombustion dynamics.

The key feature of the new configuration is theaddition of a sixth burner located in the centerof the five existing DLN-2 burners. The pres-ence of the center nozzle enables the DLN-2.6to extend its 9/9 turndown well beyond the fivenozzle DLN-2. By fueling the center nozzle sep-arately from the outer nozzles, the fuel-air ratiocan be modulated relative to the outer nozzlesleading to approximately 200°F of turndownfrom baseload with 9 ppm NOx. Turning the

fuel down in the center burner does not resultin any additional CO generation.

Absent any other changes in the DLN-2 otherthan the addition of the center nozzle, theDLN-2.6 combustor would have required fivefuel manifolds, compared to four on the DLN-2. An alternative scheme was proposed to oper-ate the machine at startup and low load, whicheliminated diffusion mode. The result was apremixed-only combustor with 4 manifolds: 3premixed manifolds staging fuel to the sixburners, and a fourth premixed manifold forinjecting quaternary fuel for dynamics abate-ment, (See Figure 22). The first three premixedmanifolds, designated PM1, PM2, and PM3, areconfigured such that any number (1 to 6) ofburners can be operated at any time. The PM1manifold fuels the center nozzle, the PM2 man-ifold fuels the two outer nozzles located at thecross-fire tubes, and the PM3 manifold fuels theremaining three outer nozzles. The five outernozzles are identical to those used for the DLN-2, while the center nozzle is similar but with sim-plified geometry to fit within the availablespace.

With the elimination of the diffusion mode theDLN-2.6 loads and unloads very differently thanthe DLN-2. The loading and unloading strate-gies are shown in Figures 23 and 24. The addi-tional mode changes are necessary to maintainthe premixed flames within their burnablezones and so prevent combustor blowout. The



PM3

PM2

PM3

PM2

PM3

PM1

q

q

q

q

q

q

qq

qq

q

q

PM2 (2 nozzles)located at crossfire tubes PM3

(3 nozzles)

PM1(1 nozzle)

Quaternary (15 pegs)

6 Premix Burners - Five identical outerburners, one smaller center nozzle.

During different machine cycle conditions,PM1, PM2, PM3 are flowed in varyingcombinations to give low F/A.

Quaternary Pegs are locatedcircumferentially around the combustioncasing.

q

q

q

Figure 22. DLN-2.6 fuel nozzle arrangement

Fairing

~Fused Tip

Figure 21. Fully faired (flashback resistant) fuelnozzle

gas fuel control system is also changed relativeto the DLN-2. Control is accomplished with onestop ratio valve and four individual gas controlvalves, (See Figure 25). The splitter valve utilizedin both the DLN-1 and DLN-2 combustion sys-tems is eliminated.

Emissions performance of the DLN-2.6depends on the operational mode (See Figures26 and 27). As can be seen, the emissions goal

of 9 ppm NOx and CO over a 50% load rangewas met. Since its introduction in 1996 theDLN-2.6 has been installed on 8 machines andaccumulated approximately 17,000 hours ofoperation.

DLN-2+ EvolutionIn late 1996 an uprated version of the Frame9FA was introduced. Called the 9FA+e, the cyclefor this machine increased the air and fuel flowto the combustion system by approximately10%. In addition, the machine was intended foruse with gas fuels ranging in heat content from



BREAKEROPENEVENT

UNIT FLAM E-OUT

DLN-2.6TYPICALUN-LOADINGSEQUENCE

STOP

PM1+PM3

PM1+PM2

PM2+PM3+Q

PM1+PM2+PM3+Q

PM1

PM1+PM2

(FSNL operating mode)

Figure 24. DLN-2.6 unloading and fired shutdownsequence

Mode 1

Mode 3

Mode 4

Mode 5Q

Mode 6Q

1

10

100

1000

0% 50% 100%

Load (MW)

CO

(p

pm

)

Figure 27. CO level vs. percent load

GCV3 GAS CONTROL PM3

SRV SPEED/RATIO VALVE



GAS SKID

SRV

GCV4

GCV2

GCV1

GCV3

PM3 - 3 NOZ. PRE-MIX ONLY



Q - QUAT MANIFOLD, CASING, PRE-MIX ONLY

PM2

Q

6 BURNERS

TURBINE COMPARTMENT

BURNINGSINGLE

ZONE

PM1

PM3

GCV4 GAS CONTROL Quaternary

Figure 25. DLN-2.6 fuel distribution and controlssystem

Mode 1Mode 3

Mode 4

Mode 5QMode 6Q

0

20

40

60

80

0% 50% 100%% Baseload

ISO NOx

(ppm)

Figure 26. NOx at 15% O2 vs. percent load

PM1+PM2

PM1

DLN-2.6TYPICALLOADINGSEQUENCE

START

PM1+PM3

PM1+PM2

PM2+PM3+Q

PM1+PM2+PM3+Q

(firing and initial crossfire)

PM2+PM3

PM2 (Complete crossfire to 95 % speed)

(95 % speed to TTRF1 switch #1 at 10 percent load)

(TTRF1 switch #1 to #2 at 25 percent load

(TTRF1 switch #2 to #3 at 40 percent load

(TTRF1 switch #3, brief duration)

(TTRF1 switch #3 + a time delay to #4 at 45 percent load)

(Above TTRF1 switch #4 to base load)

Figure 23. DLN-2.6 ignition, crossfire, accelera-tion, and loading strategy

approximately 70–100% of natural gas whilestill maintaining low emissions.

To meet these requirements an updated versionof the DLN-2, called the DLN-2+, was devel-oped. The DLN-2+ retains the basic architec-ture of the DLN-2 with adaptations for both thenew requirements and to improve the operabil-ity and robustness of the existing system. Incomparison to the DLN-2, the major changesare concentrated in the fuel nozzle and end-cover arrangement (See Figure 28). Both theendcover and fuel nozzle have substantiallyenlarged fuel passages for the increased volu-metric flow of fuel. In addition the fuel nozzle(See Figure 29), was redesigned for furtherimprovements in flame holding margin,reduced pressure drop, and improved diffu-sion-flame stability.

flow entering the premixer, while downstreaman integral outer shroud eliminates any poten-

tial flow disturbances after the point of fuelinjection. The improvement in aerodynamicsalso reduces the overall system pressure drop tothe level required by the new cycle.

The nozzle-tip geometry and the improvementsin diffusion flame stability allow the use of a dif-fusion flame on every nozzle. This eliminatesthe lean-lean mode of the DLN-2 and results inthe simplified staging methodology shown inFigure 30.

A further simplification illustrated in Figure 30 isthe elimination of the DLN-2 Quaternary fuelsystem. This is achieved through the use of bi-radial fuel staging in each swirler vane. In thisdesign the radial fuel injection balance can beadjusted via fixed orifices on the endcover aspart of the system setup procedure.

Overall, the fuel nozzle and endcover arrange-ment of the DLN-2+ can accept fuels withWobbe Index ranging from 28 to 52. The fuel



Figure 28. Parts highly modified for DLN-2+ ascompared to DLN-2

Figure 29. DLN-2+ fuel nozzle

D5IGNITION to LOW LOAD

D5 + PM1 + PM4LOW LOAD toPREMIX TRANSFER

PM1 + PM4 PREMIX TRANSFER to BASE LOAD

D5 - Diffusion Flame on AllPM4 - Premixed Flame on “4”PM1 - Premixed Flame on “1”

PM4 PM1

D51

4

4

4

4

Load Reject to Underlined Mode

Premix Dynamics Control: PM4/PM1 Fuel Split

Figure 30. DLN-2+ staging methodology

The additional gains in flame-holding velocitymargin result from cleaner aerodynamics in thepremixers. This is achieved via a new swirlerdesign, which incorporates fuel injection direct-ly from the swirler surface. Each swirler vanecomprises a turning vane and an upstreamstraight section. The straight section is hollowand houses the fuel manifolds plus the discreteinjection holes. Upstream of the swirler an inletflow conditioner improves the character of the

delivery system is very similar to the one usedfor the DLN-2.6, with a stop ratio valve andindependent gas control valves for each of thethree gas fuel circuits.

The first installation and startup of a 9FA+e wasin early 1999 at the Sutton Bridge Power Stationin the UK. Emissions measured during thestartup were well within design goals (See Figures30 and 31). Additional machines will be com-missioned throughout 1999.

ConclusionGE’s Dry Low NOx Program continues to focuson the development of systems capable of theextremely low NOx levels required to meettoday’s regulations and to prepare for morestringent requirements in the future. New unit

production needs and the requirements ofexisting machines are being addressed. GEDLN systems are operating on more than 222machines and have accumulated more than 4.8million service hours. GE is the only manufac-turer with F technology machines operatingbelow 15 ppmvd.

Appendix

Gas Turbine Combustion Systems A gas turbine combustor mixes large quantitiesof fuel and air and burns the resulting mixture.In concept the combustor is comprised of a fuelinjector and a wall to contain the flame. Thereare three fundamental factors and practicalconcerns that complicate the design of the com-bustor: equivalence ratio, flame stability, andability to operate from ignition through fullload.

Equivalence Ratio A flame burns best when there is just enoughfuel to react with the available oxygen. With thisstoichiometric mixture (equivalence ratio of1.0) the flame temperature is the highest andthe chemical reactions are the fastest, com-pared to cases where there is either more oxy-gen (“fuel lean,” < 1.0) or less oxygen (“fuelrich,” > 1.0) for the amount of fuel present.

In a gas turbine, the maximum temperature ofthe hot gases exiting the combustor is limited bythe tolerance of the turbine nozzles and buck-ets. This temperature corresponds to an equiva-lence ratio of 0.4 to 0.5 (40% to 50% of the sto-ichiometric fuel flow). In the combustors usedon modern gas turbines, this fuel-air mixturewould be too lean for stable and efficient burn-ing. Therefore, only a portion of the compres-sor discharge air is introduced directly into thecombustor reaction zone (flame zone) to bemixed with the fuel and burned. The balance of



0

200

400

600

800

1000

1200

0 50 100 150 200 250 300

GT load (MW)

CO

(ra

w)

Figure 32. DLN-2+ combustion system NOx emissions

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

0 50 100 150 200 250 300

GT load (MW)

ISO

No

x @

15%


the airflow either quenches the flame prior tothe combustor discharge entering the turbineor cools the wall of the combustor.

Flame Stability Even with only part of the air being introducedinto the reaction zone, flow velocities in thezone are higher than the turbulent flame speedat which a flame propagates through the fuel-airmixture. Special mechanical or aerodynamicdevices must be used to stabilize the flame byproviding a low velocity region. Modern com-bustors employ a combination of swirlers andjets to achieve a good mix and to stabilize theflame.

Operational Stability The combustor must be able to ignite and tosupport acceleration and operation of the gasturbine over the entire load range of themachine. For a single-shaft generator-drivemachine, speed is constant under load and,therefore, so is the airflow for a fixed ambienttemperature. There will be a five-to-one or six-to-one turndown in fuel flow over the loadrange. A combustor whose reaction zone equiv-alence ratio is optimized for full-load operationwill be very lean at the lower loads.Nevertheless, the flame must be stable and thecombustion process must be efficient at allloads.

GE uses multiple-combustion chamber assem-blies in its heavy-duty gas turbines to achievereli-able and efficient turbine operation. Asshown in Figure A-1, each combustion chamberassembly comprises a cylindrical combustor, afuel-injection system and a transition piece thatguides the flow of the hot gas from the combus-tor to the inlet of the turbine. Figure A-2 illus-trates the multiple-combustor concept.

There are several reasons for using the multi-ple-chamber arrangement instead of large silo-type combustors:

■ The configuration permits the entireturbine to be factory assembled, testedand shipped without interimdisassembly

■ The turbine inlet temperature can bebetter controlled, thus providing forlonger turbine life with reducedturbine cooling air requirements

■ Smaller parts can be handled moreeasily during routine maintenance

■ Smaller transition pieces are lesssusceptible to damage from dynamicforces generated in the combustor;furthermore, the shorter combustionsystem length ensures that acousticnatural frequencies are higher and lesslikely to couple with the pressureoscillations in the flame



GT21897A .ppt

Figure A-1. MS7001E Dry Low NOx combustionsystem

GT18556

Figure A-2. Exploded view of combustion chamber

■ Smaller combustors generate less NOx

because of much better mixing andshorter residence time

■ As turbine inlet temperatures haveincreased to improve efficiency, thesize of the combustors has decreasedto minimize cooling requirements, asin aircraft gas turbine combustors

■ Small can-type combustors can becompletely developed in thelaboratory through a combination ofboth atmospheric and full-pressure,full-flow tests. Therefore, there is ahigher degree of confidence that acombustor will perform as designedacross all load ranges before it isinstalled and tested in a machine.

Gas Turbine EmissionsThe significant products of combustion in gasturbine emissions are:

■ Oxides of nitrogen (NO and NO2,collectively called NOx)

■ Carbon monoxide (CO)

■ Unburned hydrocarbons or UHCs(usually expressed as equivalentmethane [CH4] parti-cles and arisefrom incomplete combustion)

■ Oxides of sulfur (SO2 and SO3)particulates.

Unburned hydrocarbons include both volatileorganic compounds (VOCs), which contributeto the formation of atmospheric ozone, andcompounds, such as methane, that do not.

There are two sources of NOx emissions in theexhaust of a gas turbine. Most of the NOx is gen-erated by the fixation of atmospheric nitrogenin the flame, which is called thermal NOx.Nitrogen oxides are also generated by the con-

version of a fraction of any nitrogen chemicallybound in the fuel (called fuel-bound nitrogenor FBN). Lower-quality distillates and low-Btucoal gases from gasifiers with hot gas cleanupcarry various amounts of fuel-bound nitrogenthat must be taken into account when emissionscalculations are made. The methods describedbelow to control thermal NOx emissions areineffective in controlling the conversion of FBNto NOx.

Thermal NOx is generated by a chemical reac-tion sequence called the Zeldovich Mechanism(Reference 6). This set of well-verified chemicalreactions postulates that the generation of ther-mal NOx is an exponential function of the tem-perature of the flame and a linear function ofthe time which the hot gases are at flame tem-perature. Thus, temperature and residencetime determine thermal NOx emissions levelsand are the principal variables that a gas tur-bine designer can adjust to control emission lev-els.

For a given fuel, since the flame temperature isa unique function of the equivalence ratio, therate of NOx generation can be cast as a functionof the equivalence ratio. Figure A-3 shows thatthe highest rate of NOx production occurs at anequivalence ratio of 1.0, when the temperatureis equal to the stoichiometric, adiabatic flametemperature.

To the left of the maximum temperature point(Figure A-3), more oxygen is available (theequivalence ratio is < 1.0) and the resultingflame temperature is lower. This is a fuel-leanoperation. Since the rate of NOx formation is afunction of temperature and time, it followsthat some difference in NOx emissions can beexpected when different fuels are burned in agiven combustion system. Since distillate oil andnatural gas have approximately a 100°F/38°Cflame temperature difference, a significant dif-



ference in NOx emissions can be expected ifreaction zone equivalence ratio, water injectionrate are equal.

As shown in Figure A-3, the rate of NOx produc-tion dramatically decreases as flame tempera-ture decreases (i.e., the flame becomes fuellean). This is because of the exponential effectof temperature in the Zeldovich Mechanismand is the reason why diluent injection (usuallywater or steam) into a gas turbine combustorflame zone reduces NOx emissions. For thesame reason, very lean dry combustors can beused to control emissions. Lean, dry control isdesirable for reaching the lower NOx levels nowrequired in many applications, and also to avoidthe turbine efficiency penalty associated withdiluent injection.

There are two design challenges associated withvery lean combustors. First, care must be takento ensure that the flame is stable at the designoperating point. Second, a turndown capabilityis necessary since a gas turbine must ignite,accelerate, and operate over the load range.Both of these challenges are driven by the needto operate the combustor at low flame tempera-tures to achieve very low emissions. Thereforethe combustor operating point at full load isjust above the flame blowout point, which is thepoint at which a premixed fuel and air mixtureis unable to self sustain. At lower loads, as fuel

flow to the combustors decreases, the flametemperature will approach the blowout pointand at some point the flame will either becomeunstable or blow out. This behavior is in directcontrast to that of a diffusion flame combustor.In that type of combustor the fuel is injectedunmixed and burns at maximum flame temper-ature using only a portion of the available air.This results in high NOx emissions, but has thebenefit of very good stability because the flameburns at the same temperature independent offuel flow.

In response to these challenges, combustion sys-tem designers use staged combustors so a por-tion of the flame zone air can mix with the fuelat lower loads or during startup. The two typesof staged combustors are fuel-staged and air-staged (Figure A-4). In its simplest and mostcommon configuration, a fuel-staged combus-tor has two flame zones; each receives a con-stant fraction of the combustor airflow. Fuelflow is divided between the two zones so that ateach machine operating condition, the amountof fuel fed to a stage matches the amount of airavailable. An air-staged combustor uses a mech-anism for diverting a fraction of the airflowfrom the flame zone to the dilution zone at low



PrimaryStage

SecondaryStage

DilutionZone

DilutionZone

Primary Stage

Figure A-4. Staged combustors

Figure A-3. NOx production rate

load to increase turndown. These methods canbe combined, but both work to achieve thesame objective, to maintain a stable flame tem-perature just above the blowout point.

Emissions Control MethodsThere are three principal methods for control-ling gas turbine emissions:

■ Injection of a diluent such as water orsteam into the burning zone of aconventional (diffusion flame)combustor

■ Catalytic clean-up of NOx and COfrom the gas turbine exhaust (usuallyused in conjunction with the other twomethods)

■ Design of the combustor to limit theformation of pollutants in the burningzone by utilizing “lean-premixed”combustion technology

The last method includes both DLN combus-tors and catalytic combustors. GE has consider-able experience with each of these three meth-ods.

Since September 1979, when regulationsrequired that NOx emissions be limited to 75ppmvd (parts per million by volume, dry),more than 300 GE heavy-duty gas turbines haveaccumulated more than 2.5 million operatinghours using either steam or water-injection tomeet required NOx emissions levels, sometimesproducing levels even lower than required. Theamount of water required to accomplish this isapproximately one-half of the fuel flow.However, there is a 1.8% heat rate penalty asso-ciated with using water to control NOx emis-sions for oil-fired simple-cycle gas turbines.Output increases by approximately 3%, makingwater (or steam) injection for power augmenta-tion economically attractive in some circum-

stances (such as peaking applications).

Single-nozzle combustors that use water orsteam injection are limited in their ability toreduce NOx levels below 42 ppmvd on gas fueland 65 ppmvd on oil fuel. GE developed multi-nozzle quiet combustors (MNQC) for theMS7001EA and MS7001FA capable of achieving25 ppmvd on gas fuel and 42 ppmvd on oil,using either water or steam injection. SinceOctober 1987, more than 26 MNQC-equippedMS7001s that use water or steam injection havebeen placed in service. One unit that uses steaminjection has operated nearly 50,000 hours at 25ppmvd NOx (at 15% O2).

Frequent combustion inspections anddecreased hardware life are undesirable sideeffects that can result from the use of diluentinjection to reduce NOx emissions from com-bustion turbines. For applications that requireNOx emissions below 42 ppmvd (or 25 ppmvdin the case of the MS7001EA or MS7001FAMNQC), or to avoid the significant cycle effi-ciency penalties incurred when water or steaminjection is used for NOx control, one of theother two principal methods of NOx controlmentioned above must be used.

Selective catalytic reduction (SCR) converts NOand NO2 in the gas turbine exhaust stream tomolecular nitrogen and oxygen by reacting theNOx with ammonia in the presence of a catalyst.Conventional SCR technology requires that thetemperature of the exhaust stream remain in anarrow range (550°F to 750°F or 288°C to399°C) and is restricted to applications with aheat recovery system installed in the exhaust.The SCR is installed at a location in the boilerwhere the exhaust gas temperature hasdecreased to the above temperature range. Newhigh-temperature SCR technology is beingdeveloped that may allow SCRs to be used forapplications without heat recovery boilers.



For an MS7001EA gas turbine, an SCR designedto remove 90% of the NOx from the gas turbineexhaust stream has a volume of approximately175 cubic meters and weighs 111 tons. It is com-prised of segments stacked in the exhaust duct.Each segment has a honeycomb pattern withpassages that are aligned in the direction of theexhaust gas flow. A catalyst, such as vanadiumpentoxide, is deposited on the surface of thehoneycomb.

SCR systems are sensitive to fuels containingmore than 1,000 ppm of sulfur (light distillateoils may have up to 0.8% sulfur). There are tworeasons for this sensitivity.

First, sulfur poisons the catalyst being used inSCRs. Second, the ammonia will react with sul-fur in the presence of the catalyst to formammonium bisulfate, which is extremely corro-sive, particularly near the discharge of a heatrecovery boiler. Special catalyst materials thatare less sensitive to sulfur have been identified,and there are some theories as to how to inhib-it the formation of ammonium bisulfate. This,however, remains an open issue with SCRs.

More than 100 GE units have accumulatedmore than 100,000 operating hours with SCRsinstalled. Twenty of the units are in Japan; oth-ers are located in California, New Jersey, NewYork and several other eastern U.S. states. Unitsoperating with SCRs include MS9000s,MS7000s, MS6000s, LM2500s and LM5000s.

Lean premixed combustion is the basis forachieving low emissions from Dry Low NOx andcatalytic combustors. GE has participated in thedevelopment of catalytic combustors for manyyears. These systems use a catalytic reactor bedmounted within the combustor to burn a verylean fuel-air mixture. They have the potential toachieve extremely low emissions levels withoutresorting to exhaust gas cleanup. Technicalchallenges in the combustor and in the catalystand reactor bed materials must be overcome in

order to develop an operational catalytic com-bustor. GE has development programs in placewith both ceramic and catalyst manufacturers toaddress these challenges.

References1. Washam, R. M., “Dry Low NOx

Combustion System for Utility GasTurbine,” ASME Paper 83-JPGC-GT-13,Sept. 1983.

2. Davis, L. B. and Washam, R. M., “Develop-ment of a Dry Low NOx Combustor,”ASME Paper No. 89-GT-255, June 1989.

3. Dibelius, N.R., Hilt, M.B., and Johnson,R.H., “Reduction of Nitrogen Oxides fromGas Turbines by Steam Injection,” ASMEPaper No. 71-GT-58, Dec. 1970.

4. Miller, H. E., “Development of the QuietCombustor and Other Design Changes toBenefit Air Quality,” AmericanCogeneration Association, San Francisco,March 1988.

5. Cutrone, M. B., Hilt, M. B., Goyal, A.,Ekstedt, E. E., and Notardonato, J.,“Evaluation of Advanced Combustor forDry NOx Suppression with NitrogenBearing Fuels in Utility and Industrial GasTurbines,” ASME Paper 81-GT-125, March1981.

6. Zeldovich, J., “The Oxidation of Nitrogenin Combustion and Explosions,” Acta Phys-icochimica USSR, Vol. 21, No. 4, 1946, pp577-628.

7. Washam, R. M., “Dry Low NOx

Combustion System for Utility GasTurbine,” ASME Paper 83-JPGC-GT-13,Sept. 1983.

8. Davis, L. B., and Washam, R. M., “Develop-ment of a Dry Low NOx Combustor,”ASME Paper No. 89-GT-255, June 1989.



List of FiguresFigure 1. Dry Low NOx product plan

Figure 2. DLN power augmentation summary

Figure 3. DLN peak firing emissions - natural gas fuel

Figure 4. DLN technology - a four sided box

Figure 5. Dry Low NOx combustor

Figure 6. Fuel-staged Dry Low NOx operating modes

Figure 7. Typical DLN-1 fuel gas split schedule

Figure 8. Dry low NOx gas fuel system

Figure 9. MS7001EA/MS9001E emissions - natural gas fuel

Figure 10. MS6001B emissions - natural gas

Figure 11. MS7001EA Dry Low NOx combustion system performance on distillate oil

Figure 12. MS6001B emissions distillate oil fuel

Figure 13. DLN-2 combustion system

Figure 14. Cross-section of a DLN-2 fuel nozzle

Figure 15. External view of DLN-2 fuel nozzles mounted

Figure 16. Typical DLN-2 gas fuel split schedule

Figure 17. DLN-2 gas fuel system

Figure 18. Gas fuel emissions in diffusion and premixed

Figure 19. Distillate oil emissions with water injection above 50% load

Figure 20. Un-faired fuel nozzle

Figure 21. Fully faired (flashback resistant) fuel nozzle

Figure 22. DLN-2.6 fuel nozzle arrangement

Figure 23. DLN-2.6 ignition, crossfire, acceleration, and loading strategy

Figure 24. DLN-2.6 unloading and fired shutdown sequence

Figure 25. DLN-2.6 fuel distribution and controls system

Figure 26. NOx at 15% O2 vs. percent load

Figure 27. CO level vs. percent load

Figure 28. Parts highly modified for DLN-2+ as compared to DLN-2

Figure 29. DLN-2+ fuel nozzle

Figure 30. DLN-2+ staging methodology



Figure A-1. MS7001E Dry Low NOx combustion system

Figure A-2. Exploded view of combustion chamber

Figure A-3. NOx production rate

Figure A-4. Staged combustors




APPENDIX I AIR FILTER SPECIFICATIONS

g GEK 116269

October 2008

GE Energy

These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser's purposes the matter should be referred to the GE Company.

© General Electric Company, 2008. GE Proprietary Information. All Rights Reserved.

Gas Turbine Inlet Air Specification

GEK 116269 Gas Turbine Inlet Air Specification

2 © General Electric Company, 2008. GE Proprietary Information. All Rights Reserved.

TABLE OF CONTENTS

I. INTRODUCTION TO GAS TURBINE INLET AIR SPECIFICATION............................................. 4 II. CLASSIFICATION OF ATMOSPHERIC CORROSIVITY ................................................................ 5

A. Purpose of Section ................................................................................................................................. 5 B. Introduction: Atmospheric Corrosion and Corrosion Factors................................................................ 5 C. Environmental Classification of Corrosivity: C1-C5m.......................................................................... 7 D. Methods to Establish Corrosivity Classes C1-C5m............................................................................... 7

III. IMPACT OF ENVIRONMENTAL CORROSIVITY ON ENGINE HEALTH................................. 13 A. Impact of C1 Corrosive Environment.................................................................................................. 13 B. Impact of C2 Corrosive Environment.................................................................................................. 13 C. Impact of C3 Corrosive Environment.................................................................................................. 13 D. Impact of C4 Corrosive Environment.................................................................................................. 14 E. Impact of C5i and C5m Corrosive Environments................................................................................ 14 F. General Environmental Identification Recommendations ................................................................... 15

IV. GAS TURBINE MAINTENANCE RECOMMENDATIONS FOR DIFFERENT CORROSIVE ENVIRONMENTS............................................................................................................................................. 17

A. This Sections Outlines and Summarizes Corrosion-Specific Maintenance for c1 to c5 Rated Environments. Maintenance Recommendation for c1 and c2 Environments ...................................... 17

B. Maintenance Recommendation for C3 Environment........................................................................... 17 C. Maintenance Recommendation for C4 Environment........................................................................... 17 D. Maintenance Recommendation for C5i and C5m Environments ........................................................ 17

V. INLET FILTRATION SYSTEM RECOMMENDATIONS FOR DIFFERENT CORROSIVE ENVIRONMENTS............................................................................................................................................. 18

A. Background on Inlet Filtration............................................................................................................. 19 B. Filter System Recommendation for C4, C5i, and C5m Environments ................................................ 19

VI. POWER AUGMENTATION SYSTEM MAINTENANCE RECOMMENDATIONS ..................... 21 A. Introduction.......................................................................................................................................... 21 B. Media Type Evaporative Coolers ........................................................................................................ 22 C. Chiller Coils ......................................................................................................................................... 23 D. Spray Type Evaporative Coolers ......................................................................................................... 23

VII. MEASUREMENT AND MONITORING OF CORROSIVE NATURE OF ENVIRONMENT ...... 24 A. Batch Measurement (Average over Time)........................................................................................... 24

VIII. REFERENCES ......................................................................................................................................... 29 A. All relevant GE documentation ........................................................................................................... 29 B. Non-GE documents for reference: ....................................................................................................... 29

Gas Turbine Inlet Air Specification GEK 116269

© General Electric Company, 2008. GE Proprietary Information. All Rights Reserved. 3

LIST OF FIGURES

Figure 1. ISO 9223 Standard Coupon Mounting Example .................................................................................... 9 Figure 2 & 3. Deposits on the Self-Cleaning Filter Pulse Pipes May be a Sign of Water Carryover .................. 15 Figure 4 & 5. Deposits on the Clean Airside of Self-Cleaning Filters................................................................. 15 Figure 6. Corroded Mesh of a Self-Cleaning Filter Element ............................................................................... 15 Figure 7 & 8. Water Quality Issues and Water Carryover From Evaporative Cooler ......................................... 16 Figure 9 & 10. Leaking Gaskets and Seals .......................................................................................................... 16 Figure 11. Cooling Tower Mist Entering the Inlet ............................................................................................... 16 Figure 12. Inlet Configuration for Corrosive Environment with Moderate Dust................................................. 20 Figure 13. Inlet configuration for Corrosive Environment with Moderate Dust and Icing.................................. 20 Figure 14. Inlet Configuration for Corrosive Environment with High Dust ........................................................ 21 Figure 15. Inlet Configuration for Corrosive Environment with High Dust and Icing ........................................ 21 Figure 16. GE Clean Air ISO Standard Coupon Exposure Unit .......................................................................... 26 Figure 17. Typical Sample Probe......................................................................................................................... 28

LIST OF TABLES

Table 1. List of ISO Standards Pertaining to Atmospheric Corrosivity................................................................. 7 Table 2. Sample Classifications Based on Carbon Steel Exposure........................................................................ 7 Table 3. Corrosion Rates (Mass or Thickness Loss) of Metals for First Year of Exposure for C1-C5m Classes 8 Table 4. Time of Wetness Categories .................................................................................................................. 10 Table 5. Classification of SO2 Deposition............................................................................................................ 10 Table 6. Classification of Chloride Deposition .................................................................................................... 11 Table 7. Classification Based on Previously Established TOW and SO2, and Chlorides

Deposition Categories............................................................................................................................ 11 Table 8. Summary of Some Pollutant Factors...................................................................................................... 12



I. INTRODUCTION TO GAS TURBINE INLET AIR SPECIFICATION

Air quality can be considered in terms of quantity of particulate matter contained in the air stream as well as the elemental concentration and content of that matter. Historically, the quality of the air entering the gas turbine has mainly been driven by considerations for hot gas path corrosion. Advances in compressor technology, higher operating stresses, and reduced clearances have led to greater attention to maintenance as well as corrosion and erosion mitigation for compressor components, in addition to the hot gas path.

The availability, reliability, and performance of a gas turbine compressor depend upon its operating environment, its air inlet filtration system, related maintenance practices and blade material selection. Maintenance practices include inspections of inlet structure (internal and external), inlet filter house and system, filters, water wash systems, power augmentation systems, and forward compressor stages. Given a specified material, operating environment, maintenance practices and filtration technology may be viewed as the three factors driving corrosion and erosion.

This GEK is aimed at describing the requirements of the gas turbine inlet air system, with consideration of these risk factors, as it pertains specifically to corrosion and erosion of the compressor itself. Improper filtration and maintenance, along with compromised inlet system integrity and insufficient filtration can potentially lead to compressor corrosion. It has been stated in earlier GER documents that erosion may be controlled by filtration since erosion is typically caused by larger size particle that may be removed with proper filters (particles > 5 microns in size).

This inlet air specification and any future revisions will provide data-driven maintenance and inspection recommendations that take into consideration site-specific environment data, inlet filtration system application and on-site power augmentation options. Specifically, this GEK describes the corrosivity classes of the environment upstream (“dirty air side”) of the filter system, the gas turbine maintenance and filtration system recommendations for the higher corrosivity environmental classes, and power augmentation system corrosion and erosion-related maintenance recommendations.

In efforts to move beyond these recommendations, GE has ongoing field inspection and monitoring programs at selected customer sites to improve its current database of site-specific maintenance practices, environmental factors, filtration systems and power augmentation options.

The remainder of the GEK document contains the following sections:

Section 2 discusses the classification of all ambient environments into 6 different categories of corrosion C1 to C5m and explains how these can be determined for a given location, with reference to ISO 9223 – 9226 standards.

Section 3 describes the potential impact of environments classified as C1 to C5m on the gas turbine engine and provides some visual indication of issues that could highlight potential corrosion in the engine. GE has observed that the environments classified as C3 or lower tend to experience minimal corrosion issues, when GE issued maintenance practices and guidelines for machine operation are followed. In the higher corrosive environments, C4, C5i and C5m, additional precautionary measures may be taken as highlighted in this section.

Section 4 describes the maintenance recommendations to mitigate corrosion issues in each of the six corrosive environmental categories.



Section 5 highlights the current inlet filter system recommendations for each of the highly corrosive environmental categories.

Section 6 describes the corrosion and erosion-related recommendations for the power augmentation system options.

Section 7 of this GEK highlights the need for air monitoring and describes the instrument options to establish corrosivity rating of upstream (“dirty air side”) and downstream (“clean air side”) of filter system.

Section 8 lists the reference documents.

The recommendations in this GEK are meant as a further addendum and addition to the knowledge pool that already exists in GE issued documentation.

GE recommends that existing sites characterize the corrosive nature of their environment as per GE recommendations in section II & section VII and new sites under consideration start evaluating the corrosive nature of their environment during power plant planning phase. This will enable the site to be classified into either of C1 to C5m categories as per ISO standard and help develop operational and maintenance schedules for the power plant hardware. GE can support this environmental classification and study of different corrosives at site as per section II and section VII of this GEK, this can be done so by placing a site analysis request to the local CPM or GE site representative.

Characterization of air quality at site is the customer responsibility.

II. CLASSIFICATION OF ATMOSPHERIC CORROSIVITY

A. Purpose of Section

The aim is to quantify ambient atmospheric corrosive potential in terms of standard corrosion classes. This GEK describes the methods that GE employs for this corrosion classification, which includes the International Standards Organization (ISO) methodologies, as well as GE design practices.

B. Introduction: Atmospheric Corrosion and Corrosion Factors

Atmospheric corrosion can be defined as the corrosion of materials exposed to air and pollutants. Atmospheric corrosion can be further classified into dry, damp and wet categories. With respect to the applicability of aqueous corrosion to the compressor-operating environment, this document will consider only damp and wet categories, which are associated respectively with corrosion in the presence of microscopic electrolyte (or “moisture”) films and visible electrolyte layers on the metal surface. The damp moisture films are created at a certain critical relative humidity value through water adsorption while the wet films are associated with dew, rainwater and ocean spray. The film and the corrosion rate in the film are affected by factors such as the amount of available moisture, temperature, contaminants, wind conditions, sun and site location.

A brief introduction to these corrosion variables is provided below.

1. Moisture

Time of wetness (TOW): TOW may be defined practically as the time period during which the metallic surface is covered by electrolyte film capable of causing atmospheric corrosion. There is a critical relative humidity level for ferrous materials above which accelerated corrosion begins to occur. This value is not constant, and is a function of the hygroscopic nature of corrosion



products and contaminants (salts). For atmospheric corrosion classification, International Standards Organization (ISO) defines this critical relative humidity value as 80% (temperature >0ºC) and TOW is defined as the amount of time a site spends above this critical value. Due to temperature depression at the inlet of the gas turbine, compressor blades start operating wet when ambient relative humidity > 50%, with significant wetness on blades at 75%.

Rain vs. Surface Condensation: While rainwater can provide electrolytes for corrosion reactions, it can act in a beneficial manner by washing away surface contaminants and reducing corrosion rates. Condensation provides moisture but does not dilute away contaminants, possibly increasing corrosion rates.

2. Temperature

The effect of temperature on atmospheric corrosion rates is complex. Raising the temperature will increase the rate of electrochemical reactions and diffusion processes, thus stimulating corrosion attack. For constant humidity level, increasing temperature will increase corrosion rate. However, increasing the temperature generally leads to decreasing relative humidity and increased evaporation of surface electrolytes. When the TOW is reduced in this manner, the overall corrosion rate tends to decrease.

3. Contaminants

Natural or man-made contaminants can accelerate corrosion. For example, salt can come from road de-icing or airborne ocean salts. Sulfur dioxide (SO2) can enter the air from coal burning plants or volcanic emissions. Table 8 lists sample contaminants, contaminant sources, and affected materials.

Atmospheric salinity distinctly increases corrosion rates. Hygroscopic salts (NaCl, KCl, CaCl2, and MgCl2) enhance surface electrolyte formation through participation of chloride ions in the corrosion reactions.

Sulfur dioxide adsorbs onto metal surfaces and forms sulfate ions in the surface moisture film by oxidation. These sulfate ions are considered the primary corrosion-accelerating effect of SO2.

Other contaminants include hydrogen sulfide, sulfuric acid, hydrochloric acid, chlorine, and nitrogen compounds. Although these species are related to industrial emissions in specific microenvironments and can be considered local pollutants, they can intensify corrosion damage since they acidify surface moisture and break down protective oxides on metal surfaces, accelerating corrosion rates.

4. Wind, Sun, and Site Location

Wind direction and velocity affect rate of accumulation of particles on a surface. The amount of sunshine influences TOW and affects coating performance by ultraviolet degradation. Photosensitive corrosion reactions can occur on metals like copper and steel. Site distance from seashore and altitude above sea level can also affect levels of atmospheric moisture and pollutants.



C. Environmental Classification of Corrosivity: C1-C5m

The nature and rate of corrosive damage depend on the composition and properties of the film surface electrolyte. These in turn are largely affected by the time of wetness and concentration of gaseous and particulate pollutants in the atmosphere. A standard classification of environmental corrosivity provides a basis for specifying suitable materials and corrosion protective measures at the design phase and for asset maintenance management to ensure service life.

The ISO organization has defined and validated a comprehensive corrosivity classification system, and its categorization methods are specified in ISO 9223, 9224, 9225 and 9226. These categories do not address specific service atmospheres.

Table 1. List of ISO Standards Pertaining to Atmospheric Corrosivity

ISO Standard Title ISO 9223 Classification – Corrosivity of Atmospheres ISO 9224 Guiding Values for the Corrosivity Categories of Atmospheres ISO 9225 Measurement of Pollution ISO 9226 Determination of Corrosion Rate of Standard Specimens

Each classification is associated with an amount of metal loss due to corrosion for one year in the given environment. Specifically, standard metallic specimens made of carbon steel, zinc, copper, and aluminum are exposed for one year, and their weight loss is translated directly to environment classification. Long-term predictions should not be extrapolated based on these corrosion rates. Table 2 shows corrosion class based on mass loss of low carbon steel for a period of 1 year.

Table 2. Sample Classifications Based on Carbon Steel Exposure

Mass Loss Typical Examples in Temperate Climate Corrosion

Class Description (g/m2) Typical Exterior Exposures

C1 Very Low ≤10 --- C2 Low >10 to 200 Atmospheres (mostly rural) with low level of pollution.

C3 Medium >200 to 400 Urban and industrial atmospheres, moderate SO2 pollution. Coastal areas with low salinity.

C4 High >400 to 650 Industrial areas and coastal areas with moderate salinity.

C5-i Very High (Industrial) >650 to 1500 Industrial areas with high humidity and aggressive

atmosphere.

C5-m Very High (Marine) >650 to 1500 Coastal and offshore areas with high salinity.

For coastal areas in hot/humid zones, mass losses can exceed the limits of C5-M. In such cases, special precautions shall be taken when selecting protective systems for the prevention of corrosion.

D. Methods to Establish Corrosivity Classes C1-C5m

This GEK document presents 3 methods to determine the corrosion class of a given customer site.

1. Exposure of standard metallic specimens.

2. Calculation based on measured factors (TOW, SO2, Chlorides).

3. Estimation based on environmental and corrosion data sources.



1. Method 1: Exposure of Standard Metallic Specimens

Exposure of standard specimens is deemed the most accurate method to determine corrosion class at a given location (dirty air side corrosivity classification).

As per ISO 9226, metallic standard specimens, either flat plate or open helix type, are exposed to the environment for one year. Methods for preparation, exposure, and removal of the specimens can be found in ISO 8565 and ISO 8407. At the end of the exposure, the corrosion rate, in terms of mass or thickness loss, can be calculated per ISO 9226. A corrosion class can then be determined from ISO 9223. Table 3 indicates the corrosion rates of metals for the first year of exposure for the different corrosivity categories.

Table 3. Corrosion Rates (Mass or Thickness Loss) of Metals for First Year of Exposure for C1-C5m Classes

Corrosion rates (rcorr) of metals Corrosion Class Units Carbon Steel Zinc Copper Aluminum C1 g/(m2.a)

µm/a* rcorr < 10 rcorr < 1.3

rcorr < 0.7 rcorr < 0.1

rcorr < 0.9 rcorr < 0.1

Negligible ---

C2 g/(m2.a) µm/a

10 < rcorr < 200 1.3 < rcorr < 25

0.7 < rcorr < 5 0.1 < rcorr < 0.7

0.9 < rcorr < 5 0.1 < rcorr < 0.6

rcorr < 0.6 ---

C3 g/(m2.a) µm/a

200 < rcorr < 400 25 < rcorr < 50

5 < rcorr < 15 0.7 < rcorr < 2.1

5 < rcorr < 12 0.6 < rcorr < 1.3

0.6 < rcorr < 2 ---

C4 g/(m2.a) µm/a

400 < rcorr < 650 50 < rcorr < 80

15 < rcorr < 30 2.1 < rcorr < 4.2

12 < rcorr < 25 1.3 < rcorr < 2.8

2 < rcorr < 5 ---

C5i /C5m g/(m2.a) µm/a

650 < rcorr < 1500 80 < rcorr < 200

30 < rcorr < 60 4.2 < rcorr < 8.4

25 < rcorr < 50 2.8 < rcorr < 5.6

5 < rcorr < 10 ---

A disadvantage of specimen exposure measurements is the lengthy exposure times required to obtain meaningful data. Extrapolation of the mass or thickness losses to one year from shorter exposure times, or back-extrapolation from longer times, will not give reliable results. Corrosion rates exceeding the upper limits in C5 represent environments beyond the scope of ISO 9223.

This method utilizes a simple mounting system to hold the specimens for the duration of the evaluation, an example of which can be seen in the photo below.

* The unit “a” refers to annual time period



Figure 1. ISO 9223 Standard Coupon Mounting Example

Method 1 describes the use of standard metallic coupons for dirty airside corrosivity classification. Section 6.1 will describe modifications to this method to determine the clean air side (downstream of the filter system, within the GT inlet duct) corrosivity classification.

2. Method 2: Calculation Based on Measured Factors (TOW, SO2, Chlorides)

This second ISO corrosivity classification method is based on the simplifying assumption that the time of wetness and only two types of corrosive contaminants, namely sulfur dioxide and chloride, determine the corrosivity. Practical definitions for these three environmental variables are provided in ISO documentation as follows:

1. Yearly time of wetness (ISO 9223)

2. Yearly mean deposition of sulfur dioxide (ISO 9225)

3. Yearly mean deposition of chloride (ISO 9225)

Time of Wetness (TOW)

Experimental TOW can be measured directly with sensors but such results depend on the type of measuring systems used. Furthermore, they are not directly comparable and are convertible only within a limited extent of temperature-humidity characteristics.

For this reason, ISO uses the number of hours when the relative humidity exceeds 80% and temperature exceeds 0ºC to determine the calculated TOW (τ) of corroding surfaces. The τ calculated by this method does not necessarily correspond with the actual time of exposure to wetness. Actual TOW is influenced by: the type of metal, the shape, mass and orientation of the object, the quantity of corrosion product, the nature of pollutants on the surface and other factors. These considerations may increase or decrease the actual time of wetness. However, this criterion is usually sufficiently accurate for the characterization of atmospheres.

The calculated τ depends on macroclimatic zone and the category of location. Values are based on long-term characteristics of macroclimatic zones for typical conditions of the location categories. Table 4 presents the calculated τ categories from ISO 9223.



Table 4. Time of Wetness Categories

Time of Wetness Category

Hours/year % Example Macroclimate Zones

τ 1 Τ < 10 T < 0.1 Internal microclimates with climatic control, and no condensation. τ 2 10 < T <250 0.1 < T < 3 Internal microclimates without climatic control except for internal

non-air-conditioned spaces in damp climates The probability of liquid forming on the metallic surface is low.

Τ 3 250< T <2500 3 < T <30 Outdoor atmospheres in dry, cold climates and part of temperate climates; properly ventilated sheds in temperate climates. Includes periods of condensation and precipitation.

τ 4 2500 < T < 5500 30 < T < 60 Outdoor atmospheres in all climates (except for dry and cold climates); ventilated sheds in humid conditions; unventilated sheds in temperature climates. Includes periods of condensation and precipitation

τ 5 5500 < T 60 < T Part of damp climates, unventilated sheds in humid conditions. Includes periods of condensation and precipitation.

Weather data for the exact site should be obtained, and the hours spent above 80%relative humidity at >0ºC should be tabulated for 1 year. The following factors shall be used to adjust τ:

• Sheltered surfaces in marine atmospheres where chlorides are deposited may have substantially increased τ, due to the presence of hygroscopic salts and should be classified in category τ5.

• Indoor atmospheres without climate control, τ3- τ5 can occur when water vapor sources are present.

• For τ 1 and τ 2, probability of corrosion is higher for dusty surfaces. Consider increasing to τ 3 if excessive dust will be present.

Deposition of Sulfur Dioxide and Chloride Contaminants

The most important factor within a particular category of TOW is the pollution level caused by sulfur dioxide (SO2) and airborne salinity. Deposition rate and concentration are calculated from continuous measurements during at least one year and are expressed as annual averages. Short-term measurements are highly variable and should not be extrapolated to yearly averages.

Sulfur Dioxide: Methods for measuring SO2 by sulfonation plate are specified in ISO 9225. Classification of pollution by sulfur-containing substances represented by SO2 deposition categories are provided in ISO 9223 and reproduced as Table 5.

Table 5. Classification of SO2 Deposition

SO2 deposition rate SO2 concentration mg/(m2.d) µg/m3 Category Description

Pd < 10 Pc < 12 P0 Background concentration. Insignificant from point of view of corrosive attack

10 < Pd < 35 12 < Pc < 40 P1 Significant pollution by SO2 35 < Pd < 80 40 < Pc < 90 P2 Near extreme pollution by SO2

80 < Pd < 200 90 < Pc < 250 P3 Extreme pollution by SO2. Typical of operational microclimates beyond scope of ISO 9223.



Salinity: Classification of airborne salinity given in ISO 9223, reproduced as Table 6 below, is based on the wet candle method. There are other established methods to determine salt content in the atmosphere, but ISO notes that these methods are not always directly convertible and comparable. Extreme pollution by chloride, typical of marine splash and spray, is beyond the scope of ISO 9223.

Table 6. Classification of Chloride Deposition

Chloride Deposition Rate

mg/(m2 . d) Category Description

S < 3 S0 Background concentration. Insignificant from point of view of corrosive attack

3 < S < 60 S1 Significant pollution by chloride 60 < S < 300 S2 Near extreme pollution by chloride

300 < S < 1500 S3 Extreme pollution by Chloride. Typical of marine splash/spray and beyond scope of ISO 9223.

Practical Classification of Environmental Corrosivity

After the time of wetness and the sulfur dioxide and chloride deposition categories have been determined, the overall atmosphere corrosion class can be determined via Table 7.

Table 7. Classification Based on Previously Established TOW and SO2, and Chlorides Deposition Categories

Unalloyed carbon steel τ 1 τ 2 τ 3 τ 4 τ 5 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 P0-P1

1 1 1or2 1 2 3or4 3or3 3or4 4 3 4 5 3or4 5 5

P2 1 1 1or2 1or2 2or3 3or4 3or4 3or4 4or5 4 4 5 4or5 5 5 P3 1or2 1or2 2 2 3 4 4 4or5 5 5 5 5 5 5 5 Zinc and Copper S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 P0-P1

1 1 1 1 1or2 3 3 3 3or4 3 4 5 3or4 5 5

P2 1 1 1or2 1or2 2 3 3 3or4 4 3or4 4 5 4or5 5 5 P3 1 1or2 2 2 3 3or4 3 3or4 4 4or5 5 5 5 5 5 Aluminum S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 S0,S1 S2 S3 P0-P1

1 2 2 1 2or3 4 3 3or4 3or4 3 3or4 5 4 5 5

P2 1 2 2or3 1or2 3or4 4 3 4 4or5 3or4 4 5 4or5 5 5 P3 1 2or3 3 3or4 4 4 3or4 4or5 5 4or5 5 5 5 5 5 Corrosivity is expressed as the numerical part of the corrosion class code (for example 1 instead of C1).

3. Method 3: Estimation Based on Environmental and Corrosion Data Sources

If it is not possible to expose standard metallic specimens in the actual environment of interest, and if measured sulfur dioxide and chloride deposition data are not available, the classification of corrosivity may be estimated by measuring the time of wetness and pollution levels of sulfur dioxide and chlorides through published site corrosion data and environmental databases for climate and pollution data.



4. Other Corrosion-Accelerating Factors

Aside from the key corrosivity factors of TOW, sulfur dioxide and chloride, there are other factors that may cause accelerated corrosion. While it is important to note macro-level environments according to corrosivity classes, specific local pollution data on the micro level also needs to be acquired to improve fidelity of the corrosion assessment.

Corrosion rates can be greatly increased by airborne pollutants such as acids, alkalis, salts, organic solvents, aggressive gases, and dust particles. These pollutants occur in the vicinity of industrial operations such as coking works, pickling shops, electroplating plants, coal or gas fired power plants, incinerators, dye mills, wood-pulp works, tanneries, oil refineries, etc.

A sample list of important chemical contaminants with typical emission sources, and materials susceptible to these chemicals is presented in Table 8.

Table 8. Summary of Some Pollutant Factors

Polluant Sources Susceptible Metals Sulfur Dioxide (SO2) Contributes to acid rain. Can be deposited far from origin, but generally max SO2 close to source.

¼ natural, and by human activities Industries: Fossil fuel/coal burning, petrochemical, pulp and paper, metal producing (smelting metal sulfide ores to obtain pure metals Zn, Ni, Cu) Organic decay, biomass burning, volcanic activity

Most metals.

Chloride (Cl-) Sea salt mist, road salt areas, cooling towers Most metals. Chlorine (CL2), CL containing gases

Bleaching plants, metal production, PVC plants, cleaning agents

Most metals. Synergistic with other pollutants.

Nitrogen Dioxide (NO2)

Fossil fuel combustion, various industries NOx is the generic term for a group of highly reactive gases, all of which contain nitrogen and oxygen in varying amounts

Copper, brass, synergistic with SO2.

Hydrogen Sulfide (H2S) Industries: Pulp and paper, chemical, sewage plants, garbage dumps, oil refineries, animal shelters, concentrated livestock, volcanic activity, swamp areas, marine tidal areas

All copper and silver based metals.

Soot (Carbon) Combustion, auto and truck emissions, steel production, coal burning

Synergistic with other pollutants; provides cathodic sites for most metals.

Ammonia and it’s salts: (NH3, NH4+)

Fertilizer (production or use), animal and human activity, detergents

All copper based alloys, nickel, and silver.

Ozone Formed in polluted areas, highest concentrations in smog

Strong oxidant to produce acids that attack most metals.

Mineral acids (H2SO4, HCl, HF, HNO3)

Industries: Pickling, chemical, metals production, semiconductor, cooling towers

Most metals, glass, ceramics.

Organic acids Wood, packing material, animals, preservatives

Long term effects on some metals.

Dust Various industries, nearby deserts, farming areas, construction sites

Increase surface moisture film and pollutant levels.



III. IMPACT OF ENVIRONMENTAL CORROSIVITY ON ENGINE HEALTH

Section 2 categorized the operating environment of gas turbines in various categories of corrosion C1, C2, C3, C4, C5i and C5m as per ISO 9223.

This section provides general guidelines to operators on the corrosivity impact of different environments on the engine health. Section 4 of this specification highlights maintenance recommendations for the different environmental corrosion classes.

GE gas turbines operate in a variety of environments spanning combined cycle plants located on the coast within large chemical and industrial complexes, to power plants in an arctic environment with very low levels of pollutants. Best practices and lessons learned to date from the inspection of gas turbine units in diverse environments are discussed in this section, along with typical examples of environment type.

A. Impact of C1 Corrosive Environment

This environment is identified in Section 2 of this specification. Weight loss for the sample metallic specimen when exposed for 1 year should < 10g/m2.

This is the least corrosive environment class and it is well understood by the gas turbine community that power plants are rarely sited in such benign environments.

No examples for this environment exist.

B. Impact of C2 Corrosive Environment

This environment is identified in Section 2 of this specification. Weight loss for the sample metallic specimen when exposed for 1 year should be > 10g/m2 and < 200 g/m2.

Examples would be rural atmospheres with low level of industrialization, low humidity, rainfall and significant distance from large bodies of water.

Gas turbines in this environment have shown little to no indication of corrosion. These are considered low corrosion environments and following the established GE guidelines on Inlet inspection as per GE documentation on air inlets and water wash will mitigate the impact of corrosion on the machine.

Section 4 of this specification provides recommendations to mitigate corrosion issues in gas turbine operation in C2 environments.

C. Impact of C3 Corrosive Environment

C3 corrosive environment is described in Section 2 of this specification. Weight loss for the sample metallic specimen when exposed for 1 year should be > 200g/m2 and < 400 g/m2.

Typical examples would include power plants in urban and semi-industrial settings, within a relatively dry climate with moderate sulfur dioxide pollution levels, and coastal areas with low salinity level.

Potential for pitting on blades due to corrosion (corrosion pits) exists in this environment. It is highly recommended in these environments that GE established guidelines for water washing and inlet inspection be followed on a regular basis. Both online and offline water wash may remove corrosive



deposits on the blades, which over time in a C3 environment, may collect in significant quantities on the blades potentially leading to corrosion.

It is expected that gas turbines operating in C3 environments can potentially develop corrosion pits on the blades when the OEMs and operators have not followed GE established guidelines on inlet filter system maintenance and water wash, both online and offline.

Section 4 of this specification provides recommendations to mitigate corrosion issues in gas turbine operation in C3 environments.

D. Impact of C4 Corrosive Environment

This environment is identified in Section 2 of this specification. Weight loss for the sample metallic specimen when exposed for 1 year should be > 400g/m2 and < 650 g/m2. This is considered a high corrosive environment.

Examples of C4 corrosive environment include heavy industrial areas and coastal areas with moderate salinity, high propensity of rainfall and humidity with salt.

It is expected that gas turbines operating in C4 high corrosive environments can develop corrosion pits on the blades.

In general, most of the corrosion issues in C4 rated environment can be attributed to maintenance, poor or inadequate filtration system, with inadequate water removal mechanism, and inadequate online and offline water washing. Section 4 of this specification provides recommendations to mitigate corrosion issues in gas turbines operation in C4 environments.

It highlights the need for a water removal filtration system and regular online and offline water washing. Section 5 of the specification recommends the optimal filter system for a C4 environment.

E. Impact of C5i and C5m Corrosive Environments

This environment is identified in Section 2 of this specification. Weight loss for the sample metallic specimen when exposed for 1 year should be > 650g/m2 and < 1500 g/m2. This is considered an extreme corrosive environment. Highest corrosion exists in a C5 rating environment.

Examples of C5 corrosive environment include heavy industrial areas and high humidity and aggressive atmosphere, coastal and offshore areas with high salinity.

Propensity for corrosion pits on the blades is the highest in a C5 rated environment and corrosion in a C5 environment can be accelerated further by exposure to elevated temperatures for prolonged periods of time. It has been noted at one particular site that the highly corrosive nature of C5 environment degraded the inlet filter media over time, and reduced the filtration efficiency, resulting in increased fouling and higher levels of corrosive elements entering the machine.

Regular maintenance and inspection are highly recommended for C4 and C5 rated environments. Recommendations for C5 rated environment, highlighted in Section 4 of the specification, comprise new filtration systems coupled with water wash schedules and cycles. Section 5 discussed the need for upgrading the filter system if a power plant operates in C5 environment.



F. General Environmental Identification Recommendations

Visual inspection and a walk-around the power plant hardware and inlet system may provide a quick means to assess the corrosive nature of the operating environment. Below are some pictures of visual indicators of extreme corrosive environments for which plant operators should look.

Figure 2 & 3. Deposits on the Self-Cleaning Filter Pulse Pipes May be a Sign of Water Carryover

Figure 4 & 5. Deposits on the Clean Airside of Self-Cleaning Filters

Figure 6. Corroded Mesh of a Self-Cleaning Filter Element



Figure 7 & 8. Water Quality Issues and Water Carryover From Evaporative Cooler

Figure 9 & 10. Leaking Gaskets and Seals

Figure 11. Cooling Tower Mist Entering the Inlet



IV. GAS TURBINE MAINTENANCE RECOMMENDATIONS FOR DIFFERENT CORROSIVE ENVIRONMENTS

A. This Sections Outlines and Summarizes Corrosion-Specific Maintenance for c1 to c5 Rated Environments. Maintenance Recommendation for c1 and c2 Environments

Follow GE recommended inspection practices, maintenance schedules for online and offline water wash and any other additional GE documentation for maintenance of equipment.

B. Maintenance Recommendation for C3 Environment

Corrosion issues in these environments can develop due to inadequate maintenance. GE recommends the following

1. Daily Online Water Wash, as per GE Guidelines for the particular gas turbine class as per the applicable GE documentation.

2. Schedule Offline water wash at every outage as per applicable GE documentation.

3. Maintenance as per standard GE documentation for the equipment.

C. Maintenance Recommendation for C4 Environment

Corrosion issues in these environments can develop due to inadequate maintenance and inadequate water removal filtration system. GE recommends the following;

1. Daily Online Water Wash, as per GE Guidelines for the particular gas turbine class as per applicable GE documentation.

2. Schedule Offline water wash at every possible opportunity as per applicable GE documentation. Use Mono Propylene glycol in offline water wash in cold ambient as per GE specification.

3. Augment filter system with water removal filtration as noted in section 5 for a C4 Corrosive environment.

4. Installation of corrosion monitoring / detection system in inlet.

5. GE site survey and inspection of the compressor.

6. Strict adherence to all GE maintenance documentation.

D. Maintenance Recommendation for C5i and C5m Environments

Corrosion in C5 environment is the highest and can be attributed to excessive amounts of corrosives in the air stream, inadequate maintenance and inadequate salt and water removal filter system. GE recommends the following:

1. Daily Online Water Wash, as per GE Guidelines for the particular gas turbine class as per applicable GE documentation.

2. Schedule offline water wash at every possible opportunity as per applicable GE documentation. Use Mono Propylene Glycol in offline water wash in cold ambient as per GE specification.



3. Online Water wash before schedule shutdown on peaking units, so that the blades are relatively clean of corrosive deposits while the unit is not operating. Offline water at every possible opportunity to remove corrosive deposits from the blades.

4. Upgrade to salt and water removal filter system as per GE recommendations for C5 Environment.

5. GE inspection of the power plant to determine source and nature of corrosives including air sampling, deposit collections from stages 0 to 3 and offline water wash sample collection.

6. Installation of corrosion monitoring / detection system in inlet. Refer Section 7.

7. GE Borescope and Dental Molds of R0 to S3 blades to determine presence and depth of any erosion and corrosion damage at every available opportunity when casing is removed.

8. Strict adherence to all GE maintenance documentation.

V. INLET FILTRATION SYSTEM RECOMMENDATIONS FOR DIFFERENT CORROSIVE ENVIRONMENTS

Gas turbine inlet filtration is designed to remove dust and dirt particles that cause erosion, fouling of the gas turbine, and cause hot gas path cooling holes to plug up. There are a variety of inlet filter system components available, that leads to a significant diversity in inlet filtration system configurations offered by GE. The recommendations in this filtration section of the GEK are an addendum to the list relevant inlet filtration documentation issued by GE Energy.

To provide corrosion mitigation to the gas turbine engine, the design of the inlet filtration system should reduce the amount of corrosives entering the gas turbine. These corrosives can exist in 3 states, as they enter the gas turbine.

• Solid Particulate Corrosive elements – Examples include: salt and oxide particles, which can be removed by high efficiency filters.

• Liquid (Aqueous) Corrosives elements - Examples include aqueous chlorides or acids for which general particulate filters are not efficient in removing this corrosive element, but specialist filtration is available that is effective. Two main transfer mechanisms are;

1. Solid salts deposited on particulate filters can deliquesce when the humidity of ambient air rises beyond ~60% relative humidity or when the filter elements get wet due to water. Once the salt absorbs moisture and becomes liquid, it may pass or leach through the filter elements, and enter the gas turbine.

2. Salts entering in dissolved state via rain, fog, mist, aerosol and other sources of water entering the inlet air stream. In addition to liquid salts entering, once this salt solution passes through the final filters there is a potential for the liquid to dry and salt to precipitate out of solution. This salt precipitate or crystallized salt can now enter into the gas turbine.

• Gaseous Corrosive Elements – Examples include acid vapors. Current inlet filtration technology does not exist to remove these corrosives gases.



A. Background on Inlet Filtration

Historical high efficiency filters have a high level of filtration efficiency for dry particulates. However, if the filters get wet due to moisture ingress, leaks, condensation, and/or high relative humidity; water-soluble particulates in the filter element dust cake may deliquesce (take on water and become liquid), or dissolve into solution and pass through the final filter into the clean airside of the inlet system. These water-soluble particulates may eventually make their way into the compressor and potentially result in an accelerated rate of corrosion of the compressor. By addressing water bypassing the total inlet filtration system, in addition to maintaining a high particulate efficiency, you may effectively remove the salt from the air stream.

If a site is located in a C4, C5i or C5m environment, a more robust water filtration system is recommended, in addition to a good compressor maintenance program, as noted in section 4 of this specification. Many older units, located in a C4, C5-i or C5-m environments have no moisture removal in the inlet system, other than weather hoods. These units have high possibility of salt migration into the compressor. Some units have basic water removal capabilities with moisture separators/droplet catchers (in the weather hoods), vane separators, and/or coalescing filters. However, the final filters may not be water tight, and deliquescence of water-soluble particulates can still occur.

B. Filter System Recommendation for C4, C5i, and C5m Environments

In a robust water removal filtration system, there are multiple stages used to achieve the desired goal of no water (salt) going past the final filters. These stages have to be selected in sequential combination to achieve the desired filtration system for a C4, C5i or C5m environment. The core water filtration components are:

• Moisture Separator/Droplet Catcher - This is inertial water removal equipment that is provided in the weather hoods, to mitigate the amount of ambient water that could enter into the gas turbine inlet. It is used to remove large water droplets (bulk water), such as wind driven rain, and would be the first stage of a water removal system.

• Vane Separator - This is inertial water removal equipment and would be used instead of a Moisture Separator/Droplet Catcher, which is provided at the face of the filter house, to mitigate the amount of ambient water that could enter into the gas turbine inlet. It is used to remove large water droplets (bulk water), such as wind driven rain, and would be the first stage of a water removal system. Vane separators have higher water removal efficiency than moisture separators/droplet catchers; so weather hoods are not required with vane separators.

• Coalescing Filters - The function of this type of static coalescing filter is to coalesce small droplets (aerosol / mist / spray) into larger ones, which will then drain down the media, or drop out of the air stream. This would be the second stage of any water removal system. This type of filter exists in three configurations: Panel type coalescing pads in weather hoods, panel type coalescing filter in vertical grid and coalescing bag type pre-filter in vertical grid.

• Static Water Tight Final Filters - The static type of watertight final filter is made from a media that is watertight, i.e. does not let water to pass through, while still letting air to pass. It is rated F9 by the EN779-2002 filtration standard, for particulate efficiency and is the final filter. This high level of filtration efficiency allows it to remove very fine dust and dry salt (> 0.3 microns). Being watertight means that it will also remove finer drops of water that may have passed through the earlier stages of filtration (coalescing filters, vane separators, pulse filter etc) and prevent any deliquesced salts passing through.



Some filters may claim to have hydrophobic coatings on their media, but this does not necessarily mean they are water tight, but rather the media does not soak up water, yet water may still pass through the filter itself.

The individual components described in the section above are combined in sequence for different environments to form four basic salt and water removal configurations to mitigate the chance of corrosion for the gas turbine engine. This section is a brief discussion on the functionality and application of these 4 basic configurations to a corrosive environment.

Recommendation for C4, C5i & C5m Corrosive Environments with Moderate or Low Dust.

This configuration can be used in corrosive environments with zero to moderate levels of dust. The F9 final watertight filter prevents water and salt from going downstream into the gas turbine. This can be used when ambient temperatures are greater than 40ºF or there is low possibility of icing.

Figure 12. Inlet Configuration for Corrosive Environment with Moderate Dust

Recommendation for C4, C5i & C5m Corrosive Environments with Moderate or Low Dust and Icing Conditions, Excluding Heavy Snow.

This configuration can be used in corrosive environments with zero to moderate levels of dust and when ambient temperatures are lower than 40ºF or there is possiblity of ice formation on filter elements. This configuration is similar to the configuration above except that there is an anti-icing system designed to prevent ice formation on the filter elements.

Figure 13. Inlet configuration for Corrosive Environment with Moderate Dust and Icing

Vane

F9 Final Water Tight Filter

Coalescing Bag Prefilter

Corrosive Environment w/ Moderate Dust

Bag Prefilter Vane


Coalescing Bag Prefilter Vane

Anti - icing

Corrosive Environment w/ Mod. Dust + Icing



Recommendation for C4, C5i & C5m Corrosive Environments with High Dust Conditions.

This configuration can be used in corrosive environments with high dust levels that have temperatures greater than 40ºF. The self-cleaning filter elements reject most of the dust and the F9 watertight final filter will remove water and salt that passes through the self-cleaning filter element. In months that have fogging season, the weather hoods of the inlet are to be fitted with coalescers and moisture separators to prevent wet dust from sticking to the pulse filter.

Figure 14. Inlet Configuration for Corrosive Environment with High Dust

Recommendation for C4, C5i & C5m Corrosive Environments with High Dust and Icing Conditions, Including Heavy Snow

This configuration can be used in corrosive environments with high dust levels that have temperatures lower than 40ºF and / or Snow. The self-cleaning filter elements reject most of the dust and / or snow and the ice that will form on the filter elements, while an anti-icing system is needed to prevent ice formation on the final static F9 watertight filter, which is designed to remove water, and salt that passes through the self-cleaning filter elements.

Figure 15. Inlet Configuration for Corrosive Environment with High Dust and Icing

VI. POWER AUGMENTATION SYSTEM MAINTENANCE RECOMMENDATIONS

A. Introduction

Optional cooling systems may be integrated into the design of the air inlet compartment, and this is a cost-effective way to increase turbine output during warmer summer months or in warm environments. The power augmentation (cooling) module is typically provided downstream of the filtration stages. Module size and material construction will vary depending on design constraints, contract requirements, and site-specific challenges. Power augmentation in the inlet filter compartment has been typically provided in the form of media-type evaporative coolers or chiller coils. Power augmentation in the inlet ductwork has been typically provided in the form of spray-type evaporative coolers (foggers).

Power augmentation through inlet air conditioning may provide significant performance benefits for gas turbines. The levels of performance benefit, in the form of increased power or heat rate, is dependent on site environmental conditions, i.e., ambient temperatures, relative humidity, etc., and the type of power augmentation used. These benefits typically have trade-offs in the way of increased pressure drops, parasitic loads, parts life, and other considerations. These trade-offs need to be

Weather

hood Self - Cleaning

Filter

Corrosive Environment w/ High Dust D tWeather


Filter


Weather


Filter Anti - Icing Weather


Filter

Corrosive Environment w/ High Dust + Icing

Anti - Icing




considered for a complete system evaluation addressing both short and long-term life cycle costs along with net performance benefits.

Additionally, power augmentation equipment if not maintained may potentially have a significant impact on the health of the gas turbine by generating an inlet air condition that could potentially cause excessive erosion, corrosion, or out-of-spec temperature distortions. The following gives a brief description of each and lists some of the more common benefits and pitfalls around the application of these three power augmentation options:

1. Media Type Evaporative Coolers

2. Chiller Coils

3. Spray Type Evaporative Coolers (Foggers)

B. Media Type Evaporative Coolers

Evaporation of water is one of the simplest and oldest methods of cooling air.

Traditional media type evaporative coolers consist of recirculated water sprayed over an extended surface media mounted downstream from the inlet air filters. A moisture eliminator is then mounted immediately downstream of the cooler media to remove any free moisture carryover from the cooler itself. As inlet air passes through the water soaked evaporative cooler media, evaporation occurs.

Energy in the form of heat is removed from the air by evaporating water in the media, which causes cooling and subsequent increase in the density of air, which in turn increases the mass flow and output of the gas turbine.

The correct installation, setup and checkout of the evaporative cooler are critical to its operation, and particularly to the prevention of water carryover (drift) of liquid droplets in the gas turbine airflow path. The installation instructions provided by the manufacturer of the evaporative cooler need to be followed to ensure the health of the gas turbine. In addition, all evaporative coolers shall undergo commissioning per the GE Evaporative Cooler Commissioning procedure prior to initial start up and, during service, a minimum of once a year, at the beginning of the evaporative cooler use season. A copy of the evaporative cooler commissioning procedure is available in the gas turbine Operational and Maintenance (O&M) manual.

The use of suitable water is essential in reducing carryover, mitigating corrosion and scale formation and in obtaining the expected service life and performance from the evaporative cooler. If suitable water treatment guidelines are not established and followed, the evaporative cooler and its media may need more frequent maintenance and/or replacement. Furthermore, poor water quality and/or the mis-operation of the cooler may result in contamination of the gas turbine and may result in forced outage time needed for maintenance, repair and replacement of gas path components. For this reason, it is important that recommended water quality requirements are adhered to GE recommendation and guidelines for media maintenance and water monitoring are followed in order to ensure proper operation of the evaporative cooler. Such Guidelines are established and discussed in detail in the Water Supply Requirement for Gas Turbine Inlet Air Evaporative Coolers document.



C. Chiller Coils

The heat exchangers used within the inlet system consist of a set of finned tubes installed in the inlet filter compartment downstream from the filtration stage. A moisture eliminator is then mounted immediately downstream of the coil to remove any free moisture carryover from the cooler itself, such as condensate.

The cooling / working fluid (ammonia, ethylene glycol or propylene glycol) is circulated through the coils to cool the inlet air entering the gas turbine below ambient conditions, often below the air saturation point, to increase the mass flow and power output of the gas turbine.

Chiller coils offer significant advantages over evaporative cooler systems in that they offer net output increase with quicker startup and response times, while not being limited by the surrounding ambient conditions. Chiller coils can provide consistent net power output, and heat rate improvement regardless of environmental limitations such as high outside ambient air temperatures and/or high relative humidity conditions.

Units with chiller coils shall be inspected at a minimum at the beginning and end of the running season (twice per running season) to verify that there are no leaks or debris present in the system that could result in potential damage to the gas turbine. Inlet chiller coil leaks may be potentially dangerous to the gas turbine due to the nature of the coolant fluid (water with ethylene glycol or propylene glycol or in some cases ammonia). Care must be taken to ensure that inlet drains are not blocked, and that they are safely routed to appropriate locations in case of leak from the chiller coil system.

Due to the location of the coils themselves (downstream of the filtration system) concerns over water carryover and/or bypass are applicable. Water carryover is the term used to describe water droplets that become entrained in the airflow stream and travel through the coils and drift eliminators. Water bypass is the term used to describe water droplets that become entrained in the airflow and travel around the drift eliminators and flashing. It is often the result of manufacturing and/or installation defects such as poor caulking, welding, or gaps in between adjacent pieces of drift eliminators. It is generally characterized by location (sidewalls, module interfaces, structural member, etc.) and relatively large droplet size. At no time shall any of the cooling fluid flow outside of the areas designated for its containment within the chiller coil. All drains and associated piping shall be inspected on a regular basis to remove any debris that may impede draining. All internal and external piping shall be checked for leaks and replaced / repaired, as appropriate.

All access hatches (including the external doors on the plenum viewing hatches when applicable) shall be closed and sealed prior to turbine start up. The inlet filter compartment must be completely clean and free of debris upon completion of inspection and prior to commissioning of the turbine. Please contact your local GE Product Services representative for copies of the latest commissioning procedure and/or filter compartment O&M manual, as applicable.

D. Spray Type Evaporative Coolers

Spray-type evaporative coolers or foggers evolved in the late 1990s as a way to meet or exceed the evaporative cooling effectiveness of their media-type counterparts (approximately 85%) without the associated parasitic losses inherent in the additional inlet air pressure drop. The fogger system is one way to enhance gas turbine warm weather output. If not designed properly, a fogger system may have an adverse effect on gas turbine compressor life.



High-pressure water spray is injected into the inlet ductwork through a network of manifolds and nozzles creating cooling and additional mass flow to turbine. Spray mixes with inlet air in a long straight run of inlet ductwork prior to entering the compressor inlet bell mouth. High-purity or de-mineralized water is used in fogger systems in order to reduce concerns related to contamination.

Units with foggers shall be inspected at every possible interval to verify that there are no leaks, debris or plugging present in the system that could result in potential damage to the gas turbine. Water pumps, control devices (filters, isolation valves, flow meters, etc.), and interconnecting piping provided as part as the fogger system shall be tested and verified to meet specified parameters per the gas turbine Operational and Maintenance (O&M) manual.

Fogger manifolds and nozzles shall be inspected for plugging and/or bending that may preclude optimal mixing of water and airflow. Excessive water accumulation on the ductwork floors shall be investigated, understood and eliminated to the fullest extent possible. In case of leakage, system drains provided as part of the inlet ductwork and plenum shall be verified to ensure that these drains and gutters are not blocked, and that they are fully functional in order to minimize possibility of damage to the compressor and gas turbine.

All access hatches (including plenum viewing hatches when applicable) shall be closed and sealed prior to turbine start up. The inlet filter compartment must be clean and free of debris upon completion of inspection and prior to commissioning of the turbine.

VII. MEASUREMENT AND MONITORING OF CORROSIVE NATURE OF ENVIRONMENT

Determination of the possibility of compressor corrosion at a particular site requires the understanding of the following 3 elements:

1. Air quality of the local Environment

2. Filtration System Performance

3. Maintenance Practices carried out on the Gas Turbine

An ideal situation would be for these elements to be monitored on a continuous real-time basis and even a direct measure of compressor corrosion. However, using technology available today, it is only possible to quantify elements 1 and 2 by batch measurement (average over time), with element 3 understood in terms of what is carried out, but not its effectiveness at a particular site with respect to compressor corrosion.

A. Batch Measurement (Average over Time)

The following batch measurement techniques provide measurement of key corrosion drivers:

Coupon Placement

• Corrosion rating of the environment being analyzed for various metal types, as detailed within ISO 9223, based upon an annual average

• Average Time of Wetness

• Average Sulfide deposition rate, three month average

• Average Chloride deposition rate, three month average



Air Sampling

• Average dust concentration, dirty air and clean air side

• Average chemical element concentration, dirty air and clean air side

• Average filter efficiency vs. dust experienced at site

• Average filter efficiency vs. various chemical elements experienced at site Off Line Water Wash Drainage Water Sampling

• Levels of chemical elements relative to one another impacted on the surface of the compressor blades, i.e. identification of the major pollutants that affect the compressor at a specific site.

• pH level, which is meaningless in isolation, but useful when compared with other Fleet machines for the same drainage water sample.

1. Coupon Placement

Dirty Air Side Corrosivity Classification – previously described in Section 1.4.1 “Method 1: Exposure of Standard Metallic Specimens.”

Clean Air Side Corrosivity Classification

The clean air path within the GT air inlet downstream of the filter system is a sensitive environment to the safe and reliable operation of the gas turbine and as such, mounting standard coupons, as defined within ISO standard 9223 to 9226, is not appropriate, as it raises the possibility of FOD and flow distortion to unacceptable levels.

GE has defined a proprietary method for exposing standard coupons as defined within ISO 9223 to 9226, utilizing coupon exposure unit as described in figure 16, which draws air out of the GT inlet system, passes it over the coupons and then returns it to the inlet system. The coupon exposure unit provides the following specifically designed features to ensure a high quality and representative measurement.

• Contains a built in pump to drive air across the coupons

• Designed to provide uniform flow across all the coupons

• Extracts air from the inlet system passes it over the coupons and then re-injects it and so is unaffected by the duct under pressure

• Provides a sealed environment

• Test chamber is insulated from external heat to ensure same temperature and humidity conditions as inside the inlet duct

• Electrically isolates coupons from each other

• Mesh on inlet and outlet to prevent risk from FOD

• Provides ability to remove coupons while installed

• Can be opened while online to view the condition of the coupons without interrupting the test or risking contamination

• Intrinsically safe



• Completely stainless steel construction

• Supplied with weather / sun shield

Figure 16. GE Clean Air ISO Standard Coupon Exposure Unit

GE is continuing to define correlations between the results gained utilizing ISO 9223 to 9226 and the exposure method defined in the standard, and those obtained utilizing the Coupon Exposure Unit.

2. Air Sampling

The objective of this technique is to capture the contaminant within a known volume of sampled air, onto a sample filter, which can then be analyzed for content.

In its simplest form this GE proprietary technique utilizes a probe within the airstream, attached to a very high efficiency sample filter, sample extraction pump and flow rate or total flow measuring device, see schematic below.

Total

Rate

Vacuum pump

Probe

Flow measurement Sample Filter

Air Flow Direction



The probe is placed within the airstream to be sampled, e.g., in the clean air duct of the GT inlet system. A sample of the air is drawn out of the duct via the probe, and passed through the sample filter, where contaminants present in the sample air are deposited. The sample air then passes through the airflow rate, or total meter, to enable a measurement of the quantity of air sampled. Finally, the sample air passes through the sample pump, which is driving the sample flow rate.

A single sample is typically run for a set period of time, with the longer the period, the better the average. Typical values range from several hours to about 1 month, with the later being preferred.

If two sampling exercises are carried out simultaneously, with one being upstream (dirty side) of the GT inlet filters and the second being downstream (clean air side) of the GT inlet filters, then it is possible to determine the actual, in-service filtration efficiency of the filters.

Sampling Duration

Within any given day, there can be many variations of the contaminants within the airstream entering the GT inlet, due to local external factors, such as weather conditions, prevailing wind direction, frequency and duration of nearby pollution sources, such as gas flares, major highways etc. It is therefore desirable to capture a sample that represents a true average of all events. The aim being a continuously renewed sample for a 12-month period.

While the equipment may appear to be relatively simple to carryout this type of analysis, there are some important specifics to the design and configuration of the apparatus to ensure a representative and safe sampling exercise.

Probe Design

The inlet ducting of a GT air inlet is a possible risk area for the continued safe operation of a GE machine. As such the design of a probe should be suitable for this type of environment, this would include such items as no loose fixings, calculation of the distortion of the air flowing past, eddy shedding etc.

The airflow conditions at the probe entrance and through the probe tubing are also important to ensure a representative sample of inlet air is obtained.



Figure 17. Typical Sample Probe

Sampler Design

The design of the air sampler (filter, pump and flow meter) should be suitably configured for use with a GT inlet. The specific environment must be considered, in terms of likely operating weather conditions, but also with regards to the types of services available on site, i.e., electric mains, compressed air etc, as well as any safety or hazardous requirements, such as being “Intrinsically Safe”.

Sample Analysis

A variety of analysis techniques can be utilized. Typically, semi quantative X-ray Fluorescence is used to establish the levels of various elements. If the sampling equipment used takes multiple samples at the same time, further detailed analysis can then be carried out depending upon the initial results.

3. Off Line Water Wash Drainage Water Sampling

During an off line water wash, water and water containing a detergent is injected into the machine to clean contaminants that have become attached to the compressor rotor and stator blades. The resulting dirty water is then piped straight to a site drain. This drain water can then provide information as to what substances are being deposited on the compressor blades.

The standard water wash cycle is carried out as follows

1. First wash cycle pulse with water only.

2. Start the off-line water wash program automatically. (This consists of 7 wash pulse with a mixture of water/detergent.)

3. After the 7 pulses, let the mix of water and soap rest in the compressor for 20 minutes before starting the rinse cycle.



4. The compressor will go through 35 rinsing pulses (or more if needed) until it reaches a conductivity that is 5ms or less different that the water in the water tank or has steady readings for more than 5 rinse pulses.

One sample should be taken at the end of step 1, 2, and 3 resulting in a total of three samples.

VIII. REFERENCES

A. All relevant GE documentation

B. Non-GE documents for reference:

1. P. Roberge, “Handbook of Corrosion Engineering”, chapter 2, Atmospheric Corrosion, McGraw-Hill (2000).

2. ISO 9223 (1992 edition), Corrosion of metals and alloys – Corrosivity of atmospheres – Classification.

3. ISO 9224 (1992 edition), Corrosion of metals and alloys – Corrosivity of atmospheres – Guiding values for the corrosivity categories.

4. ISO 9225 (1992 edition), Corrosion of metals and alloys – Corrosivity of atmospheres – Measurement of pollution.

5. ISO 9226 (1992 edition), Corrosion of metals and alloys – Corrosivity of atmospheres – Determination of corrosion rate of standard specimens for the evaluation of corrosivity.



g GE Energy General Electric Company

www.gepower.com


APPENDIX J POWER BLOCK OPERATING AND MAINTENANCE DETAILS (GER-3620)

GE Power & Water

Heavy-Duty Gas Turbine Operating and Maintenance ConsiderationsGER-3620M (02/15)

Jamison Janawitz

James Masso

Christopher Childs

GE Power & WaterAtlanta, GA

GE Power & Water | GER-3620M (02/15) i

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Maintenance Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Gas Turbine Design Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Borescope Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Major Factors Influencing Maintenance and Equipment Life . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Starts and Hours Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Service Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Firing Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Steam/Water Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Cyclic Effects and Fast Starts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Hot Gas Path Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Rotor Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Combustion Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Casing Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Exhaust Diffuser Parts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Off-Frequency Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Compressor Condition and Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Lube Oil Cleanliness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Moisture Intake . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Maintenance Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Standby Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Running Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Rapid Cool-Down . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Combustion Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Hot Gas Path Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Major Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Parts Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Inspection Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Borescope Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Combustion Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Hot Gas Path Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Rotor Inspection Interval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Personnel Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

ii

Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36A .1) Example 1 – Hot Gas Path Maintenance Interval Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

A .2) Example 2 – Hot Gas Path Factored Starts Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

B) Examples – Combustion Maintenance Interval Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

C) Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

D) Estimated Repair and Replacement Intervals (Natural Gas Only) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

E) Borescope Inspection Ports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

F) Turning Gear/Ratchet Running Guidelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

G) B/E- and F-class Gas Turbine Naming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Revision History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

GE Power & Water | GER-3620M (02/15) 1

IntroductionMaintenance costs and machine availability are two of the most

important concerns to a heavy-duty gas turbine equipment

owner. Therefore, a well thought out maintenance program that

reduces the owner’s costs while increasing equipment availability

should be instituted. For this maintenance program to be effective,

owners should develop a general understanding of the relationship

between the operating plans and priorities for the plant, the skill

level of operating and maintenance personnel, and all equipment

manufacturer’s recommendations regarding the number and

types of inspections, spare parts planning, and other major factors

affecting component life and proper operation of the equipment.

In this document, operating and maintenance practices for

heavy-duty gas turbines will be reviewed, with emphasis placed

on types of inspections plus operating factors that influence

maintenance schedules.

Note:

• The operation and maintenance practices outlined in this

document are based on full utilization of GE-approved parts,

repairs, and services.

• The operating and maintenance discussions presented

are generally applicable to all GE heavy-duty gas turbines;

i.e., Frames 3, 5, 6, 7, and 9. Appendix G provides a list of common

B/E- and F-class heavy-duty gas turbines with current and

former naming conventions. For purposes of illustration, the

GE GT-7E.03 was chosen for most components except exhaust

systems, which are illustrated using different gas turbine models

as indicated. Also, the operating and maintenance discussions

presented for all B/E-class units are generally applicable to

Frame 3 and Frame 5 units unless otherwise indicated.

Consult the GE Operation and Maintenance (O&M) Manual

for specific questions on a given machine, or contact the

local GE service representative.

Maintenance PlanningAdvanced planning for maintenance is necessary for utility,

industrial, independent power, and cogeneration plant operators

in order to maintain reliability and availability. The correct

implementation of planned maintenance and inspection provides

direct benefits in the avoidance of forced outages, unscheduled

Heavy-Duty Gas Turbine Operating and Maintenance Considerations

repairs, and downtime. The primary factors that affect the

maintenance planning process are shown in Figure 1. The

owners’ operating mode and practices will determine how each

factor is weighted. Gas turbine parts requiring the most careful

attention are those associated with the combustion process,

together with those exposed to the hot gases discharged from the

combustion system. These are called the combustion section and

hot gas path parts, and they include combustion liners, end caps,

fuel nozzle assemblies, crossfire tubes, transition pieces, turbine

nozzles, turbine stationary shrouds, and turbine buckets.

Additional, longer-term areas for consideration and planning

are the lives of the compressor rotor, turbine rotor, casings, and

exhaust diffuser. The basic design and recommended maintenance

of GE heavy-duty gas turbines are oriented toward:

• Maximum periods of operation between inspections

and overhauls

• In-place, on-site inspection and maintenance

• Use of local trade skills to disassemble, inspect, and re-assemble

gas turbine components

In addition to maintenance of the basic gas turbine, other station

auxiliaries require periodic servicing including the control devices,

fuel-metering equipment, gas turbine auxiliaries, and load package.

The primary maintenance effort involves five basic systems:

controls and accessories, combustion, turbine, generator, and

balance-of-plant. Controls and accessories are typically serviced

in outages of short duration, whereas the other four systems are

maintained through less frequent outages of longer duration.

This document is focused on maintenance planning for the basic

gas turbine, which includes the combustion and turbine systems.

The other systems, while outside the scope of this document, also

need to be considered for successful plant maintenance.

The inspection and repair requirements, outlined in the O&M

Manual provided to each owner, lend themselves to establishing

a pattern of inspections. These inspection patterns will vary from

site to site, because factors such as air and fuel quality are used

to develop an inspection and maintenance program. In addition,

supplementary information is provided through a system of

Technical Information Letters (TILs) associated with specific gas

turbines after shipment. This updated information, in addition

to the O&M Manual, assures optimum installation, operation,

2

and maintenance of the turbine. (See Figure 2.) Many of the TILs

contain advisory technical recommendations to help resolve

issues and improve the operation, maintenance, safety, reliability,

or availability of the turbine. The recommendations contained in

TILs should be reviewed and factored into the overall maintenance

planning program.

• O&M Manual

– Turbine-specific manual provided to customer

– Includes outline of recommended Inspection andRepair requirements

– Helps customers to establish a pattern of systematicinspections for their site

• Technical Information Letters (TILs)*

– Issued after shipment of turbine

– Provides O&M updates related to turbine installation,maintenance, and operation

– Provides advisory technical recommendations to helpresolve potential issues

* Specific smaller frame turbines are issued service letters known as Customer Information Notices (NICs) instead of TILs

Figure 2 . Key technical reference documents to include in maintenance planning

Gas Turbine Design Maintenance FeaturesThe GE heavy-duty gas turbine is designed to withstand severe

duty and to be maintained on-site, with off-site repair required

only on certain combustion components, hot gas path parts, and

rotor assemblies needing specialized shop service. The following

features are designed into GE heavy-duty gas turbines to facilitate

on-site maintenance:

• All casings, shells and frames are split on machine horizontal

centerline. Upper halves may be lifted individually for access to

internal parts.

• With upper-half compressor casings removed, all stationary

vanes can be slid circumferentially out of the casings for

inspection or replacement without rotor removal.

• With the upper-half of the turbine shell lifted, each half of the

first stage nozzle assembly can be removed for inspection,

repair, or replacement without rotor removal. On some units,

upper-half, later-stage nozzle assemblies are lifted with the

turbine shell, also allowing inspection and/or removal of

the turbine buckets.

Figure 1 . Key factors affecting maintenance planning

Manufacturer’sRecommendedMaintenance

Program

Diagnostics &Expert Systems

Reliability Need

On-SiteMaintenance

Capability

Design Features Duty CycleCost of

Downtime

Type of Fuel

ReplacementParts

Availability/Investment

ReserveRequirementsEnvironmentUtilization Need

MaintenancePlanning


• All turbine buckets are moment-weighed and computer charted

in sets for rotor spool assembly so that they may be replaced

without the need to remove or rebalance the rotor assembly.

• All bearing housings and liners are split on the horizontal

centerline so that they may be inspected and replaced when

necessary. The lower half of the bearing liner can be removed

without removing the rotor.

• All seals and shaft packings are separate from the main

bearing housings and casing structures and may be readily

removed and replaced.

• On most designs, fuel nozzles, combustion liners and flow

sleeves can be removed for inspection, maintenance, or

replacement without lifting any casings. All major accessories,

including filters and coolers, are separate assemblies that are

readily accessible for inspection or maintenance. They may

also be individually replaced as necessary.

• Casings can be inspected during any outage or any shutdown

when the unit enclosure is cool enough for safe entry. The

exterior of the inlet, compressor case, compressor discharge

case, turbine case, and exhaust frame can be inspected during

any outage or period when the enclosure is accessible. The

interior surfaces of these cases can be inspected to various

degrees depending on the type of outage performed. All interior

surfaces can be inspected during a major outage when the rotor

has been removed.

• Exhaust diffusers can be inspected during any outage by

entering the diffuser through the stack or Heat Recovery

Steam Generator (HRSG) access doors. The flow path surfaces,

flex seals, and other flow path hardware can be visually

inspected with or without the use of a borescope. Diffusers

can be weld-repaired without the need to remove the exhaust

frame upper half.

• Inlets can be inspected during any outage or shutdown.

As an alternative to on-site maintenance, in some cases plant

availability can be improved by applying gas turbine modular

replacements. This is accomplished by exchanging engine modules

or even the complete gas turbine with new or refurbished units.

The removed modules/engines can then be sent to an alternate

location for maintenance.

Provisions have been built into GE heavy-duty gas turbines to

facilitate several special inspection procedures. These special

procedures provide for the visual inspection and clearance

measurement of some of the critical internal components

without removal of the casings. These procedures include gas

path borescope inspection (BI), radial clearance measurements,

and turbine nozzle axial clearance measurements.

A GE gas turbine is a fully integrated design consisting of stationary

and rotating mechanical, fluid, thermal, and electrical systems.

The turbine’s performance, as well as the performance of each

component within the turbine, is dependent upon the operating

interrelationship between internal components and the total

operating systems. GE’s engineering process evaluates how new

designs, design changes, and repairs affect components and

systems. This design, evaluation, testing, and approval assures

the proper balance and interaction between all components and

systems for safe, reliable, and economical operation.

The introduction of new, repaired, or modified parts must be

evaluated in order to avoid negative effects on the operation

and reliability of the entire system. The use of non-GE approved

parts, repairs, and maintenance practices may represent a

significant risk. Pursuant to the governing terms and conditions,

warranties and performance guarantees are predicated upon

proper storage, installation, operation, and maintenance,

conforming to GE approved operating instruction manuals

and repair/modification procedures.

Borescope InspectionsAn effective borescope inspection program monitors the condition

of internal components without casing removal. Borescope

inspections should be scheduled with consideration given to the

operation and environment of the gas turbine and information

from the O&M Manual and TILs.

GE heavy-duty gas turbine designs incorporate provisions in

both compressor and turbine casings for borescope inspection

of intermediate compressor rotor stages, first, second and third-

stage turbine buckets, and turbine nozzle partitions. These

provisions are radially aligned holes through the compressor

casings, turbine shell, and internal stationary turbine shrouds

that allow the penetration of an optical borescope into the

compressor or turbine flow path area, as shown in Figure 3.

4

Borescope inspection access locations for F-class gas turbines

can be found in Appendix E.

Figure 4 provides a recommended interval for a planned

borescope inspection program following initial baseline

inspections. It should be recognized that these borescope

inspection intervals are based on average unit operating modes.

Adjustment of these borescope intervals may be made based

on operating experience, mode of operation, fuels used, and the

results of previous borescope inspections.

In general, an annual or semiannual borescope inspection uses

all the available access points to verify the condition of the

internal hardware. This should include, but is not limited to, signs

of excessive gas path fouling, symptoms of surface degradation

(such as erosion, corrosion, or spalling), displaced components,

deformation or object damage, material loss, nicks, dents, cracking,

indications of contact or rubbing, or other anomalous conditions.

Borescope

Gas and Distillate Fuel Oil

At combustion inspection or annually, whichever occurs first

Heavy Fuel Oil

At combustion inspection or semiannually, whichever occurs first

Figure 4 . Borescope inspection planning

During BIs and similar inspections, the condition of the upstream

components should be verified, including all systems from the filter

house to the compressor inlet.

The application of a borescope monitoring program will assist with

the scheduling of outages and preplanning of parts requirements,

resulting in outage preparedness, lower maintenance costs, and

higher availability and reliability of the gas turbine.

Primary Inspection Access (Normal Inspection)

Secondary Inspection Access (Additional Stators & Nozzles)

Access for Eddy-current & Nozzle Deflection Inspection

LegendLE = Leading EdgeTE = Trailling Edge

18º

18º

18º

Compressor-4th Stage



1st Nozzle TE1st Bucket LE

32º

1st Bucket TE2nd Nozzle LE

34º

2nd Nozzle TE2nd Bucket LE

42º

2nd Bucket TE3rd Nozzle LE

34º

3rd Nozzle TE3rd Bucket LE

42º

Figure 3 . 7E.03 gas turbine borescope inspection access locations


Major Factors Influencing Maintenance and Equipment LifeThere are many factors that can influence equipment life,

and these must be understood and accounted for in the

owner’s maintenance planning. Starting cycle (hours per start),

power setting, fuel, level of steam or water injection, and

site environmental conditions are some of the key factors in

determining maintenance interval requirements, as these factors

directly influence the life of replaceable gas turbine parts.

Non-consumable components and systems, such as the

compressor airfoils, may be affected by site environmental

conditions as well as plant and accessory system effects. Other

factors affecting maintenance planning are shown in Figure 1.

Operators should consider these external factors to prevent the

degradation and shortened life of non-consumable components.

GE provides supplementary documentation to assist in this regard.

In the GE approach to maintenance planning, a natural gas fuel

unit that operates at base load with no water or steam injection

is established as the baseline condition, which sets the maximum

recommended maintenance intervals. For operation that differs

from the baseline, maintenance factors (MF) are established to

quantify the effect on component lives and provide the increased

frequency of maintenance required. For example, a maintenance

factor of two would indicate a maintenance interval that is half of

the baseline interval.

Starts and Hours CriteriaGas turbines wear differently in continuous duty application and

cyclic duty application, as shown in Figure 5. Thermal mechanical

fatigue is the dominant life limiter for peaking machines, while

creep, oxidation, and corrosion are the dominant life limiters for

continuous duty machines. Interactions of these mechanisms

are considered in the GE design criteria but to a great extent

are second-order effects. For that reason, GE bases gas turbine

maintenance requirements on independent counts of starts and

hours. Whichever criteria limit is first reached determines the

maintenance interval. A graphical display of the GE approach

is shown in Figure 6. In this figure, the inspection interval

recommendation is defined by the rectangle established

by the starts and hours criteria. These recommendations

for inspection fall within the design life expectations and are

selected such that components acceptable for continued use

at the inspection point will have low risk of failure during the

subsequent operating interval.

• Continuous Duty Application

– Rupture

– Creep Deflection

– Corrosion

– Oxidation

– Erosion

– High-Cycle Fatigue

– Rubs/Wear

– Foreign Object Damage

• Cyclic Duty Application

– Thermal MechanicalFatigue

– High-Cycle Fatigue

– Rubs/Wear

– Foreign Object Damage

Figure 5 . Causes of wear – hot gas path components

An alternative to the GE approach, which is sometimes employed

by other manufacturers, converts each start cycle to an equivalent

number of operating hours (EOH) with inspection intervals based

on the equivalent hours count. For the reasons previously stated,

GE does not use this approach. While this logic can create the

impression of longer intervals, it actually may result in more

frequent maintenance inspections, since separate effects are

considered additive. Referring again to Figure 6, the starts and

hours inspection “rectangle” is reduced by half as defined by the

diagonal line from the starts limit at the upper left hand corner

to the hours limit at the lower right hand corner. Midrange duty

applications, with hours-per-start ratios of 30-50, are particularly

penalized by this approach.

This is further illustrated in Figure 7 for the example of a 7E.03

gas turbine operating on natural gas fuel, at base load conditions

with no steam or water injection or trips from load. The unit

operates 4000 hours and 300 starts per year. Following GE’s

recommendations, the operator would perform the hot gas path

inspection after four years of operation, with starts being the

limiting condition. Performing maintenance on this same unit

based on an equivalent hours criteria would require a hot gas

path inspection after 2.4 years. Similarly, for a continuous duty

application operating 8000 hours and 160 starts per year, the

GE recommendation would be to perform the hot gas path

inspection after three years of operation with the operating

hours being the limiting condition for this case. The equivalent

hours criteria would set the hot gas path inspection after

2.1 years of operation for this application.

6

Figure 7 . Hot gas path maintenance interval comparisons. GE method vs. EOH method

GE vs. Equivalent Operating Hours (EOH) Approach

1400

1200

1000

800

600

400

200

00 4 8 12 16 20 24 28

Thousands of Fired Hours

Star

ts

Case 28,000 Hrs/Yr

160 Starts/Yr

GE Every 3 Yr

EOH Every 2.1 Yr

Case 14,000 Hrs/Yr

GE Method

300 Starts/Yr

GE Every 4 Yr

EOH Every 2.4 Yr

Continuous

Unit

Figure 6 . GE bases gas turbine maintenance requirements on independent counts of starts and hours


Service FactorsWhile GE does not subscribe to the equivalency of starts to hours,

there are equivalencies within a wear mechanism that must be

considered. As shown in Figure 8, influences such as fuel type and

quality, firing temperature setting, and the amount of steam or

water injection are considered with regard to the hours-based

criteria. Startup rate and the number of trips are considered with

regard to the starts-based criteria. In both cases, these influences

may reduce the maintenance intervals.

Typical baseline inspection intervals (6B.03/7E.03):

Hot gas path inspection 24,000 hrs or 1200 starts

Major inspection 48,000 hrs or 2400 starts

Criterion is hours or starts (whichever occurs first)

Factors affecting maintenance:

Hours-Based Factors

• Fuel type

• Peak load

• Diluent (water or steam injection)

Starts-Based Factors

• Start type (conventional or peaking-fast)

• Start load (max. load achieved during start cycle, e.g. part, base, or peak load)

• Trips

Figure 8 . Maintenance factors

When these service or maintenance factors are involved in a unit’s

operating profile, the hot gas path maintenance “rectangle” that

describes the specific maintenance criteria for this operation is

reduced from the ideal case, as illustrated in Figure 9. The following

discussion will take a closer look at the key operating factors

and how they can affect maintenance intervals as well as parts

refurbishment/replacement intervals.

FuelFuels burned in gas turbines range from clean natural gas to

residual oils and affect maintenance, as illustrated in Figure 10.

Although Figure 10 provides the basic relationship between fuel

severity factor and hydrogen content of the fuel, there are other

fuel constituents that should be considered. Selection of fuel

Increasing Hydrogen Content in Fuel

Incr

easi

ng F

uel S

ever

ity F

acto

r

Natural Gas

Distillates

Residual

LightHeavy

Figure 10 . Estimated effect of fuel type on maintenance

4 8 12 160 20 24 28

1,400

1,200

1,000

800

600

400

200

0

Hours-Based Factors• Fuel type• Peak load• Diluent

Starts-Based Factors• Start type• Start load• Trips

Star

ts

Thousands of Fired Hours

Maintenance Factors Reduce Maintenance Interval

Figure 9 . GE maintenance intervals

8

severity factor typically requires a comprehensive understanding

of fuel constituents and how they affect system maintenance.

The selected fuel severity factor should also be adjusted based

on inspection results and operating experience.

Heavier hydrocarbon fuels have a maintenance factor ranging

from three to four for residual fuels and two to three for crude

oil fuels. This maintenance factor is adjusted based on the

water-to-fuel ratio in cases when water injection for NOx

abatement is used. These fuels generally release a higher

amount of radiant thermal energy, which results in a subsequent

reduction in combustion hardware life, and frequently contain

corrosive elements such as sodium, potassium, vanadium, and

lead that can cause accelerated hot corrosion of turbine nozzles

and buckets. In addition, some elements in these fuels can

cause deposits either directly or through compounds formed

with inhibitors that are used to prevent corrosion. These

deposits affect performance and can require more frequent

maintenance.

Distillates, as refined, do not generally contain high levels of

these corrosive elements, but harmful contaminants can be

present in these fuels when delivered to the site. Two common

ways of contaminating number two distillate fuel oil are: salt-

water ballast mixing with the cargo during sea transport, and

contamination of the distillate fuel when transported to site in

tankers, tank trucks, or pipelines that were previously used to

transport contaminated fuel, chemicals, or leaded gasoline. GE’s

experience with distillate fuels indicates that the hot gas path

maintenance factor can range from as low as one (equivalent

to natural gas) to as high as three. Unless operating experience

suggests otherwise, it is recommended that a hot gas path

maintenance factor of 1.5 be used for operation on distillate oil.

Note also that contaminants in liquid fuels can affect the life

of gas turbine auxiliary components such as fuel pumps and

flow dividers.

Not shown in Figure 10 are alternative fuels such as industrial

process gas, syngas, and bio-fuel. A wide variety of alternative

fuels exist, each with their own considerations for combustion in

a gas turbine. Although some alternative fuels can have a neutral

effect on gas turbine maintenance, many alternative fuels require

unit-specific intervals and fuel severity factors to account for their

fuel constituents or water/steam injection requirements.

As shown in Figure 10, natural gas fuel that meets GE specification

is considered the baseline, optimum fuel with regard to turbine

maintenance. Proper adherence to GE fuel specifications in

GEI-41040 and GEI-41047 is required to allow proper combustion

system operation and to maintain applicable warranties. Liquid

hydrocarbon carryover can expose the hot gas path hardware to

severe overtemperature conditions that can result in significant

reductions in hot gas path parts lives or repair intervals.

Liquid hydrocarbon carryover is also responsible for upstream

displacement of flame in combustion chambers, which can lead

to severe combustion hardware damage. Owners can control

this potential issue by using effective gas scrubber systems and

by superheating the gaseous fuel prior to use to approximately

50°F (28°C) above the hydrocarbon dew point temperature at

the turbine gas control valve connection. For exact superheat

requirement calculations, please review GEI 41040. Integral to the

system, coalescing filters installed upstream of the performance

gas heaters is a best practice and ensures the most efficient

removal of liquids and vapor phase constituents.

Undetected and untreated, a single shipment of contaminated

fuel can cause substantial damage to the gas turbine hot gas

path components. Potentially high maintenance costs and loss

of availability can be minimized or eliminated by:

• Placing a proper fuel specification on the fuel supplier.

For liquid fuels, each shipment should include a report that

identifies specific gravity, flash point, viscosity, sulfur content,

pour point and ash content of the fuel.

• Providing a regular fuel quality sampling and analysis program.

As part of this program, continuous monitoring of water

content in fuel oil is recommended, as is fuel analysis that,

at a minimum, monitors vanadium, lead, sodium, potassium,

calcium, and magnesium.

• Providing proper maintenance of the fuel treatment system

when burning heavier fuel oils.

• Providing cleanup equipment for distillate fuels when there

is a potential for contamination.

In addition to their presence in the fuel, contaminants can

also enter the turbine via inlet air, steam/water injection, and

carryover from evaporative coolers. In some cases, these

sources of contaminants have been found to cause hot gas path


degradation equal to that seen with fuel-related contaminants.

GE specifications define limits for maximum concentrations of

contaminants for fuel, air, and steam/water.

In addition to fuel quality, fuel system operation is also a factor in

equipment maintenance. Liquid fuel should not remain unpurged

or in contact with hot combustion components after shutdown

and should not be allowed to stagnate in the fuel system when

strictly gas fuel is run for an extended time. To minimize varnish

and coke accumulation, dual fuel units (gas and liquid capable)

should be shutdown running gas fuel whenever possible. Likewise,

during extended operation on gas, regular transfers from gas to

liquid are recommended to exercise the system components and

minimize coking.

Contamination and build-up may prevent the system from

removing fuel oil and other liquids from the combustion,

compressor discharge, turbine, and exhaust sections when

the unit is shut down or during startup. Liquid fuel oil trapped

in the system piping also creates a safety risk. Correct functioning

of the false start drain system (FSDS) should be ensured through

proper maintenance and inspection per GE procedures.

Firing TemperaturesPeak load is defined as operation above base load and is

achieved by increasing turbine operating temperatures.

Significant operation at peak load will require more frequent

maintenance and replacement of hot gas path and combustion

components. Figure 11 defines the parts life effect corresponding

to increases in firing temperature. It should be noted that this is

not a linear relationship, and this equation should not be used for

decreases in firing temperature.

It is important to recognize that a reduction in load does not

always mean a reduction in firing temperature. For example, in

heat recovery applications, where steam generation drives overall

plant efficiency, load is first reduced by closing variable inlet

guide vanes to reduce inlet airflow while maintaining maximum

exhaust temperature. For these combined cycle applications,

firing temperature does not decrease until load is reduced below

approximately 80% of rated output. Conversely, a non-DLN turbine

running in simple cycle mode maintains fully open inlet guide

vanes during a load reduction to 80% and will experience over a

200°F/111°C reduction in firing temperature at this output level.

The hot gas path parts life changes for different modes of

operation. This turbine control effect is illustrated in Figure 12.

Turbines with DLN combustion systems use inlet guide vane

turndown as well as inlet bleed heat to extend operation of

low NOx premix operation to part load conditions.

Firing temperature effects on hot gas path maintenance, as

described above, relate to clean burning fuels, such as natural

gas and light distillates, where creep rupture of hot gas path

components is the primary life limiter and is the mechanism

that determines the hot gas path maintenance interval impact.

With ash-bearing heavy fuels, corrosion and deposits are

the primary influence and a different relationship with firing

temperature exists.

Steam/Water InjectionWater or steam injection for emissions control or power

augmentation can affect part life and maintenance intervals

even when the water or steam meets GE specifications. This

relates to the effect of the added water on the hot gas transport

properties. Higher gas conductivity, in particular, increases the

B/E-class

Max IGV (open)

Min IGV

IGVs close max to minat constant TF

IGVs close max to minat constant TX

Heat RecoverySimple CycleBase LoadPeak Load

2500

2000

1500

1000

1200

1000

800

600

°F°C

FiringTemp.

% Load60 80 100 1204020

Figure 12 . Firing temperature and load relationship – heat recovery vs. simple cycle operation

B/E-class: Ap = e (0.018*ΔTf )

F-class: Ap = e (0.023*ΔTf )

Ap = Peak fire severity factor

ΔTf = Peak firing temperature adder (in °F)

Figure 11 . Peak fire severity factors - natural gas and light distillates

10

heat transfer to the buckets and nozzles and can lead to higher

metal temperature and reduced part life.

Part life reduction from steam or water injection is directly

affected by the way the turbine is controlled. The control system

on most base load applications reduces firing temperature as

water or steam is injected. This is known as dry control curve

operation, which counters the effect of the higher heat transfer

on the gas side and results in no net effect on bucket life. This

is the standard configuration for all gas turbines, both with and

without water or steam injection. On some installations, however,

the control system is designed to keep firing temperature constant

with water or steam injection. This is known as wet control curve

operation, which results in additional unit output but decreases

parts life as previously described. Units controlled in this way

are generally in peaking applications where annual operating

hours are low or where operators have determined that reduced

parts lives are justified by the power advantage. Figure 13

illustrates the wet and dry control curve and the performance

differences that result from these two different modes of control.

An additional factor associated with water or steam injection

relates to the higher aerodynamic loading on the turbine

components that results from the injected flow increasing the

cycle pressure ratio. This additional loading can increase the

downstream deflection rate of the second- and third-stage nozzles,

which would reduce the repair interval for these components.

However, the introduction of high creep strength stage two and

three nozzle (S2N/S3N) alloys, such as GTD-222™ and GTD-241™,

has reduced this factor in comparison to previously applied

materials such as FSX-414 and N-155.

Water injection for NOx abatement should be performed according

to the control schedule implemented in the controls system.

Forcing operation of the water injection system at high loads

can lead to combustion and HGP hardware damage due to

thermal shock.

Cyclic Effects and Fast StartsIn the previous discussion, operating factors that affect the

hours-based maintenance criteria were described. For the

starts-based maintenance criteria, operating factors associated

with the cyclic effects induced during startup, operation, and

shutdown of the turbine must be considered. Operating conditions

other than the standard startup and shutdown sequence can

potentially reduce the cyclic life of the gas turbine components

and may require more frequent maintenance including part

refurbishment and/or replacement.

Fast starts are common deviations from the standard startup

sequence. GE has introduced a number of different fast start

systems, each applicable to particular gas turbine models. Fast

starts may include any combination of Anticipated Start Purge,

fast acceleration (light-off to FSNL), and fast loading. Some fast

start methods do not affect inspection interval maintenance

factors. Fast starts that do affect maintenance factors are

referred to as peaking-fast starts or simply peaking starts.

The effect of peaking-fast starts on the maintenance interval

depends on the gas turbine model, the unit configuration, and

the particular start characteristics. For example, simple cycle

7F.03 units with fast start capability can perform a peaking start

in which the unit is brought from light-off to full load in less than

15 minutes. Conversely, simple cycle 6B and other smaller frame

units can perform conventional starts that are less than 15

minutes without affecting any maintenance factors. For units

that have peaking-fast start capability, Figure 14 shows

conservative peaking-start factors that may apply.

Because the peaking-fast start factors can vary by unit and

by system, the baseline factors may not apply to all units. For

example, the latest 7F.03 peaking-fast start system has the start

factors shown in Figure 15. For comparison, the 7F.03 nominal

fast start that does not affect maintenance is also listed. Consult

applicable unit-specific documentation or your GE service

representative to verify the start factors that apply.

Exha

ust T

empe

ratu

re °F

Compressor Discharge Pressure (psig)

Dry Control

Wet Control

The Wet Control Curve Maintains Constant TF

Steam Injection for 25 pmm NOx

3% Steam Inj.TF = 2020°F (1104°C)

Load Ratio = 1.10

3% Steam Inj.TF = 1994°F (1090°C)

Load Ratio = 1.08

0% Steam Inj.TF = 2020°F (1104°C)

Load Ratio = 1.0

Figure 13 . Exhaust temperature control curve – dry vs. wet control 7E.03


Starts-Based Combustion Inspection

As = 4.0 for B/E-class

As = 2.0 for F-class

Starts-Based Hot Gas Path Inspection

Ps = 3.5 for B/E-class

Ps = 1.2 for F-class

Starts-Based Rotor Inspection

Fs = 2.0 for F-class*

* See Figure 22 for details

Figure 14 . Peaking-fast start factors

7F .03 Starts-Based Combustion Inspection

As = 1.0 for 7F nominal fast start

As = 1.0 for 7F peaking-fast start

7F .03 Starts-Based Hot Gas Path Inspection

Ps = Not applicable for 7F nominal fast start (counted as normal starts)

Ps = 0.5 for 7F peaking-fast start

7F .03 Starts-Based Rotor Inspection

Fs = 1.0 for 7F nominal fast start

Fs = 2.0 for 7F peaking-fast start*

* See Figure 23 for details

Figure 15 . 7F.03 fast start factors

Hot Gas Path PartsFigure 16 illustrates the firing temperature changes occurring

over a normal startup and shutdown cycle. Light-off, acceleration,

loading, unloading, and shutdown all produce gas and metal

temperature changes. For rapid changes in gas temperature,

the edges of the bucket or nozzle respond more quickly than

the thicker bulk section, as pictured in Figure 17. These gradients,

in turn, produce thermal stresses that, when cycled, can eventually

lead to cracking.

Figure 18 describes the temperature/strain history of a 7E.03

stage 1 bucket during a normal startup and shutdown cycle.

Light-off and acceleration produce transient compressive strains

in the bucket as the fast responding leading edge heats up more

quickly than the thicker bulk section of the airfoil. At full load

conditions, the bucket reaches its maximum metal temperature

and a compressive strain is produced from the normal steady

state temperature gradients that exist in the cooled part. At

shutdown, the conditions reverse and the faster responding

edges cool more quickly than the bulk section, which results

in a tensile strain at the leading edge.

Thermal mechanical fatigue testing has found that the number

of cycles that a part can withstand before cracking occurs is

strongly influenced by the total strain range and the maximum

metal temperature. Any operating condition that significantly

increases the strain range and/or the maximum metal temperature

over the normal cycle conditions will reduce the fatigue life and

increase the starts-based maintenance factor. For example,

TimeStartup Shutdown

Tem

pera

ture

Base Load

Acceleration

Light-Off

Warm-Up Fired Shutdown

Full SpeedNo LoadFull Speed

No Load

Unload Ramp

Trip

Load Ramp

Figure 16 . Turbine start/stop cycle – firing temperature changes

Cold

Hot

Figure 17 . Second stage bucket transient temperature distribution

12

Figure 19 compares a normal operating cycle with one that

includes a trip from full load. The significant increase in the

strain range for a trip cycle results in a life effect that equates

to eight normal start/stop cycles, as shown. Trips from part

load will have a reduced effect because of the lower metal

temperatures at the initiation of the trip event. Figure 20

illustrates that while a trip from between 80% and 100% load

has an 8:1 trip severity factor, a trip from full speed no load (FSNL)

has a trip severity factor of 2:1. Similarly, overfiring of the unit

during peak load operation leads to increased component

0

Key Parameters

Fired

Shutdown

• Max Strain Range

• Max Metal Temperature

FSNL

Light Off

& Warm-up

Acceleration

Base Load

Metal Temperature

TMAX

% S

trai

n

∆εMAX

Figure 18 . Bucket low cycle fatigue (LCF)

+

-

Normal Startup/Shutdown

Temperature

∆εMAX

Strain ~ %

+

-

Strain ~ %

Leading Edge Temperature/Strain

TMAX

Normal Start & Trip

1 Trip Cycle = 8 Normal Shutdown Cycles

Temperature∆εMAX

TMAX

TeTempmpereratatururee

∆∆εMAMAXX

Figure 19 . Low cycle fatigue life sensitivities – first stage bucket


metal temperatures. As a result, a trip from peak load has

a trip severity factor of 10:1.

Trips are to be assessed in addition to the regular startup/shutdown

cycles as starts adders. As such, in the factored starts equation

of Figure 43, one is subtracted from the severity factor so that the

net result of the formula (Figure 43) is the same as that dictated

by the increased strain range. For example, a startup and trip

from base load would count as eight total cycles (one cycle for

startup to base load plus 8-1=7 cycles for trip from base load),

just as indicated by the 8:1 maintenance factor.

Similarly to trips from load, peaking-fast starts will affect the

starts-based maintenance interval. Like trips, the effects of

a peaking-fast start on the machine are considered separate

from a normal cycle and their effects must be tabulated in

addition to the normal start/stop cycle. However, there is no

-1 applied to these factors, so a 7F.03 peaking-fast start during

a base load cycle would have a total effect of 1.5 cycles.

Refer to Appendix A for factored starts examples, and consult

unit-specific documentation to determine if an alternative

hot gas path peaking-fast start factor applies.

While the factors described above will decrease the starts-based

maintenance interval, part load operating cycles allow for an

extension of the maintenance interval. Figure 21 can be used in

considering this type of operation. For example, two operating

cycles to maximum load levels of less than 60% would equate

to one start to a load greater than 60% or, stated another way,

would have a maintenance factor of 0.5.

Factored starts calculations are based upon the maximum load

achieved during operation. Therefore, if a unit is operated at part

load for three weeks, and then ramped up to base load for the last

ten minutes, then the unit’s total operation would be described as a

base load start/stop cycle.

Rotor PartsThe maintenance and refurbishment requirements of the rotor

structure, like the hot gas path components, are affected by

the cyclic effects of startup, operation, and shutdown, as well as

loading and off-load characteristics. Maintenance factors specific

to the operating profile and rotor design must be incorporated into

the operator’s maintenance planning. Disassembly and inspection

of all rotor components is required when the accumulated rotor

starts or hours reach the inspection limit. (See Figure 44 and

Figure 45 in the Inspection Intervals section.)

The thermal condition when the startup sequence is initiated

is a major factor in determining the rotor maintenance interval

and individual rotor component life. Rotors that are cold when

the startup commences experience transient thermal stresses

as the turbine is brought on line. Large rotors with their longer

thermal time constants develop higher thermal stresses than

smaller rotors undergoing the same startup time sequence. High

thermal stresses reduce thermal mechanical fatigue life and the

inspection interval.

Though the concept of rotor maintenance factors is applicable

to all gas turbine rotors, only F-class rotors will be discussed in

detail. For all other rotors, reference unit-specific documentation

to determine additional maintenance factors that may apply.

10

8

6

4

2

0

a T – T

rip

Seve

rity

Fac

tor

% Load0 20 40 60 80 100

Base

FSNL

Note:• For Trips During Startup Accel Assume aT=2

• For Trips from Peak Load Assume aT=10

F-class and B/E-class units with

Inlet Bleed Heat

Units withoutInlet Bleed Heat

Figure 20 . Maintenance factor – trips from load

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.0

Mai

nten

ance

Fac

tor

% Load0 20 40 60 80 100

Figure 21 . Maintenance factor – effect of start cycle maximum load level

14

The rotor maintenance factor for a startup is a function of the

downtime following a previous period of operation. As downtime

increases, the rotor metal temperature approaches ambient

conditions, and thermal fatigue during a subsequent startup

increases. As such, cold starts are assigned a rotor maintenance

factor of two and hot starts a rotor maintenance factor of less

than one due to the lower thermal stress under hot conditions.

This effect varies from one location in the rotor structure to

another. The most limiting location determines the overall rotor

maintenance factor.

Initial rotor thermal condition is not the only operating factor

that influences rotor maintenance intervals and component

life. Peaking-fast starts, where the turbine is ramped quickly

to load, increase thermal gradients on the rotor. Trips from

load, particularly trips followed by immediate restarts, and hot

restarts reduce the rotor maintenance interval. Figure 22 lists

recommended operating factors that should be used to determine

the rotor’s overall maintenance factor for certain F-class rotors.

F-class* Rotors

Rotor Maintenance Factors

Peaking-Fast Start**

Normal Start

Hot 1 Start Factor (0–1 Hr. Down)

4.0 2.0

Hot 2 Start Factor (1–4 Hrs. Down)

1.0 0.5

Warm 1 Start Factor (4–20 Hrs. Down)

1.8 0.9

Warm 2 Start Factor (20–40 Hrs. Down)

2.8 1.4

Cold Start Factor (>40 Hrs. Down)

4.0 2.0

Trip from Load Factor 4.0 4.0

*Other factors may apply to early 9F.03 units

**An F-class peaking-fast start is typically a start in which the unit is brought from light-off to full load in less than 15 minutes.

Figure 22 . Operation-related maintenance factors

The significance of each of these factors is dependent on the unit

operation. There are three categories of operation that are typical

of most gas turbine applications. These are peaking, cyclic, and

continuous duty as described below:

• Peaking units have a relatively high starting frequency and a low

number of hours per start. Operation follows a seasonal demand.

Peaking units will generally see a high percentage of warm and

cold starts.

• Cyclic units start daily with weekend shutdowns. Twelve to

sixteen hours per start is typical, which results in a warm rotor

condition for a large percentage of the starts. Cold starts are

generally seen only after a maintenance outage or following a

two-day weekend outage.

• Continuous duty applications see a high number of hours

per start. Most starts are cold because outages are generally

maintenance driven. While the percentage of cold starts is high,

the total number of starts is low. The rotor maintenance interval

on continuous duty units will be determined by operating hours

rather than starts.

Figure 23 lists operating profiles on the high end of each of

these three general categories of gas turbine applications. These

duty cycles have different combinations of hot, warm, and cold

starts with each starting condition having a different effect on

rotor maintenance interval as previously discussed. As a result,

the starts-based rotor maintenance interval will depend on an

application’s specific duty cycle. In the Rotor Inspection Interval

section, a method will be described to determine a maintenance

factor that is specific to the operation’s duty cycle. The application’s

integrated maintenance factor uses the rotor maintenance factors

described above in combination with the actual duty cycle of a

specific application and can be used to determine rotor inspection

intervals. In this calculation, the reference duty cycle that yields

a starts-based maintenance factor equal to one is defined in

Figure 24. Duty cycles different from the Figure 24 definition,

in particular duty cycles with more cold starts or a high number

of trips, will have a maintenance factor greater than one.

Turning gear or ratchet operation after shutdown and before

starting/restarting is a crucial part of normal operating procedure.

After a shutdown, turning of the warm rotor is essential to avoid

bow, or bend, in the rotor. Initiating a start with the rotor in a

bowed condition could lead to high vibrations and excessive rubs.


Figure F-1 describes turning gear/ratchet scenarios and operation

guidelines (See Appendix). Relevant operating instructions and

TILs should be adhered to where applicable. As a best practice,

units should remain on turning gear or ratchet following a planned

shutdown until wheelspace temperatures have stabilized at or

near ambient temperature. If the unit is to see no further activity

for 48 hours after cool-down is completed, then it may be taken

off of turning gear.

Figure F-1 also provides guidelines for hot restarts. When an

immediate restart is required, it is recommended that the rotor

be placed on turning gear for one hour following a trip from load,

trip from full speed no load, or normal shutdown. This will allow

transient thermal stresses to subside before superimposing a

startup transient. If the machine must be restarted in less than

one hour, a start factor of 2 will apply.

Longer periods of turning gear operation may be necessary prior to

a cold start or hot restart if bow is detected. Vibration data taken

while at crank speed can be used to confirm that rotor bow is at

acceptable levels and the start sequence can be initiated. Users

should reference the O&M Manual and appropriate TILs for specific

instructions and information for their units.

Combustion PartsA typical combustion system contains transition pieces,

combustion liners, flow sleeves, head-end assemblies containing

fuel nozzles and cartridges, end caps and end covers, and assorted

other hardware including cross-fire tubes, spark plugs and flame

detectors. In addition, there can be various fuel and air delivery

components such as purge or check valves and flex hoses. GE

provides several types of combustion systems including standard

combustors, Multi-Nozzle Quiet Combustors (MNQC), Integrated

Gasification Combined Cycle (IGCC) combustors, and Dry Low NOx

(DLN) combustors. Each of these combustion systems has unique

operating characteristics and modes of operation with differing

responses to operational variables affecting maintenance and

refurbishment requirements.

DLN combustion systems use various combustion modes to reach

base load operation. The system transfers from one combustion

mode to the next when the combustion reference temperature

increases to the required value, or transfer temperature, for the

next mode.

Peaking Cyclic Continuous

Hot 2 Start (Down 1-4 Hr.)

3% 1% 10%

Warm 1 Start (Down 4-20 hr.)

10% 82% 5%

Warm 2 Start (Down 20-40 Hr.)

37% 13% 5%

Cold Start (Down >40 Hr.)

50% 4% 80%

Hours/Start 4 16 400

Hours/Year 600 4800 8200

Starts/Year 150 300 21

Percent Trips 3% 1% 20%

Trips/Year 5 3 4

Typical Maintenance Factor (Starts-Based)

1 .7 1 .0 NA

• Operational Profile is Application Specific

• Inspection Interval is Application Specific

Figure 23 . 7F gas turbine typical operational profile

Baseline Unit

Cyclic Duty

6 Starts/Week

16 Hours/Start

4 Outage/Year Maintenance

50 Weeks/Year

4800 Hours/Year

300 Starts/Year

0 Trips/Year

1 Maintenance Factor

12 Cold Starts/Year (down >40 Hr.) 4%

39 Warm 2 Starts/Year (Down 20-40 Hr.) 13%

246 Warm 1 Starts/Year (Down 4-20 Hr.) 82%

3 Hot 2 Starts/Year (Down 1-4 Hr.) 1%

Baseline Unit Achieves Maintenance Factor = 1

Figure 24 . Baseline for starts-based maintenance factor definition

16

• Continuous mode operation is defined as operation in a

combustion mode for longer than what is required during normal

startup/shutdown.

• Extended mode operation is defined as operation in a

combustion mode at a firing temperature greater than the

transfer temperature to the next combustion mode.

The DLN combustion mode recommended for continuous mode

operation is the premixed combustion mode (PM), as it achieves

lowest possible emissions and maximum possible part life.

Continuous and extended mode operation in non-PM combustion

modes is not recommended due to its effect on combustion

hardware life as shown in Figure 25. The use of non-PM combustion

modes has the following effects on maintenance:

• DLN-1/DLN-1+ extended lean-lean operation results in a

maintenance factor of 10 (excluding Frame 5 units where MF=2).

• DLN 2.0/DLN 2+ extended piloted premixed operation results in a

maintenance factor of 10.

• Continuous mode operation in lean-lean (L-L), sub-piloted

premixed (sPPM), or piloted premixed (PPM) modes is not

recommended as it will accelerate combustion hardware

degradation.

• In addition, cyclic operation between piloted premixed and

premixed modes leads to thermal loads on the combustion liner

and transition piece similar to the loads encountered during the

startup/shutdown cycle.

Figure 25 . DLN combustion mode effect on combustion hardware life

Continuous mode operation of DLN 2.6/DLN 2.6+ combustors will

not accelerate combustion hardware degradation.

Another factor that can affect combustion system maintenance

is acoustic dynamics. Acoustic dynamics are pressure oscillations

generated by the combustion system, which, if high enough

in magnitude, can lead to significant wear and cracking of

combustion or hot gas path components. GE practice is to

~85% TNH FSNL Full Load

Combustor Combustion mode effect on hardware life

DLN 1/1+ Primary L-LPremixed

Extended L-L

DLN 2.0/2+ Diffusion L-L/sPPM PPMPremixed

Extended PPM

Severity

High

Low

tune the combustion system to levels of acoustic dynamics low

enough to ensure that the maintenance practices described here

are not compromised. In addition, GE encourages monitoring of

combustion dynamics during turbine operation throughout the

full range of ambient temperatures and loads.

Combustion disassembly is performed, during scheduled

combustion inspections (CI). Inspection interval guidelines are

included in Figure 39. It is expected, and recommended, that

intervals be modified based on specific experience. Replacement

intervals are usually defined by a recommended number of

combustion (or repair) intervals and are usually combustion

component specific. In general, the replacement interval as a

function of the number of combustion inspection intervals is

reduced if the combustion inspection interval is extended. For

example, a component having an 8,000-hour CI interval, and a

six CI replacement interval, would have a replacement interval of

four CI intervals if the inspection interval were increased to 12,000

hours (to maintain a 48,000-hour replacement interval).

For combustion parts, the baseline operating conditions that result

in a maintenance factor of one are fired startup and shutdown to

base load on natural gas fuel without steam or water injection.

Factors that increase the hours-based maintenance factor include

peak load operation, distillate or heavy fuels, and steam or water

injection. Factors that increase starts-based maintenance factor

include peak load start/stop cycles, distillate or heavy fuels, steam

or water injection, trips, and peaking-fast starts.

Casing PartsMost GE gas turbines have inlet, compressor, compressor

discharge, and turbine cases in addition to exhaust frames. Inner

barrels are typically attached to the compressor discharge case.

These cases provide the primary support for the bearings, rotor,

and gas path hardware.

The exterior of all casings should be visually inspected for cracking,

loose hardware, and casing slippage at each combustion, hot

gas path, and major outage. The interior of all casings should

be inspected whenever possible. The level of the outage

determines which casing interiors are accessible for visual

inspection. Borescope inspections are recommended for the

inlet cases, compressor cases, and compressor discharge cases


during gas path borescope inspections. All interior case surfaces

should be visually inspected during a major outage.

Key inspection areas for casings are listed below.

• Bolt holes

• Shroud pin and borescope holes in the turbine shell (case)

• Compressor stator hooks

• Turbine shell shroud hooks

• Compressor discharge case struts

• Inner barrel and inner barrel bolts

• Inlet case bearing surfaces and hooks

• Inlet case and exhaust frame gibs and trunions

• Extraction manifolds (for foreign objects)

Exhaust Diffuser PartsGE exhaust diffusers come in either axial or radial configurations

as shown in Figures 26 and 27 below. Both types of diffusers are

composed of a forward and aft section. Forward diffusers are

normally axial diffusers, while aft diffusers can be either axial or

radial. Axial diffusers are used in the F-class gas turbines, while

radial diffusers are used in B/E-class gas turbines.

Exhaust diffusers are subject to high gas path temperatures and

vibration due to normal gas turbine operation. Because of the

extreme operating environment and cyclic operating nature of

gas turbines, exhaust diffusers may develop cracks in the sheet

metal surfaces and weld joints used for diffuser construction.

Additionally, erosion may occur due to extended operation at high

temperatures. Exhaust diffusers should be inspected for cracking

and erosion at every combustion, hot gas path and major outage.

In addition, flex seals, L-seals, and horizontal joint gaskets should

be visually/borescope inspected for signs of wear or damage

at every combustion, hot gas path, and major outage. GE

recommends that seals with signs of wear or damage be replaced.

To summarize, key areas that should be inspected are listed below.

Any damage should be reported to GE for recommended repairs.

• Forward diffuser carrier flange (6F)

• Diffuser strut airfoil leading and trailing edges

• Turning vanes in radial diffusers (B/E-class)

• Insulation packs on interior or exterior surfaces

• Clamp ring attachment points to exhaust frame

(major outage only)

• Flex seals and L-seals

• Horizontal joint gaskets

Off-Frequency OperationGE heavy-duty single shaft gas turbines are engineered to operate

at 100% speed with the capability to operate over a 95% to

105% speed range. Operation at other than rated speed has the

potential to affect maintenance requirements. Depending on the

industry code requirements, the specifics of the turbine design,

and the turbine control philosophy employed, operating conditions

can result that will accelerate life consumption of gas turbine

components, particularly rotating flowpath hardware. Where this

is true, the maintenance factor associated with this operation must

be understood. These off-frequency events must be analyzed and

recorded in order to include them in the maintenance plan for the

gas turbine.

Figure 26 . F-class axial diffuser

Figure 27 . E-class radial diffuser

18

Some turbines are required to meet operational requirements

that are aimed at maintaining grid stability under sudden load

or capacity changes. Most codes require turbines to remain on

line in the event of a frequency disturbance. For under-frequency

operation, the turbine output may decrease with a speed decrease,

and the net effect on the turbine is minimal.

In some cases of under-frequency operation, turbine output must

be increased in order to meet the specification-defined output

requirement. If the normal output fall-off with speed results in loads

less than the defined minimum, the turbine must compensate.

Turbine overfiring is the most obvious compensation option, but

other means, such as water-wash, inlet fogging, or evaporative

cooling also provide potential means for compensation. A

maintenance factor may need to be applied for some of these

methods. In addition, off-frequency operation, including rapid grid

transients, may expose the blading to excitations that could result in

blade resonant response and reduced fatigue life.

It is important to understand that operation at over-frequency

conditions will not trade one-for-one for periods at under-

frequency conditions. As was discussed in the firing temperature

section above, operation at peak firing conditions has a nonlinear,

logarithmic relationship with maintenance factor.

Over-frequency or high speed operation can also introduce

conditions that affect turbine maintenance and part replacement

intervals. If speed is increased above the nominal rated speed,

the rotating components see an increase in mechanical stress

proportional to the square of the speed increase. If firing

temperature is held constant at the overspeed condition, the

life consumption rate of hot gas path rotating components will

increase as illustrated in Figure 28 where one hour of operation at

105% speed is equivalent to two hours at rated speed.

If overspeed operation represents a small fraction of a turbine’s

operating profile, this effect on parts life can sometimes be

ignored. However, if significant operation at overspeed is expected

and rated firing temperature is maintained, the accumulated hours

must be recorded and included in the calculation of the turbine’s

overall maintenance factor and the maintenance schedule

adjusted to reflect the overspeed operation.

Compressor Condition and PerformanceMaintenance and operating costs are also influenced by the quality

of the air that the turbine consumes. In addition to the negative

effects of airborne contaminants on hot gas path components,

contaminants such as dust, salt, and oil can cause compressor

blade erosion, corrosion, and fouling.

Fouling can be caused by submicron dirt particles entering the

compressor as well as from ingestion of oil vapor, smoke, sea salt,

and industrial vapors. Corrosion of compressor blading causes

pitting of the blade surface, which, in addition to increasing the

surface roughness, also serves as potential sites for fatigue crack

initiation. These surface roughness and blade contour changes

will decrease compressor airflow and efficiency, which in turn

reduces the gas turbine output and overall thermal efficiency.

Generally, axial flow compressor deterioration is the major cause

of loss in gas turbine output and efficiency. Recoverable losses,

attributable to compressor blade fouling, typically account for

70-85% percent of the performance losses seen. As Figure 29

illustrates, compressor fouling to the extent that airflow is

reduced by 5%, will reduce output by up to 8% and increase heat

rate by up to 3%. Fortunately, much can be done through proper

operation and maintenance procedures both to minimize fouling

type losses and to limit the deposit of corrosive elements. On-line

compressor wash systems are available to maintain compressor

efficiency by washing the compressor while at load, before

significant fouling has occurred. Off-line compressor wash

systems are used to clean heavily fouled compressors. Other

procedures include maintaining the inlet filtration system, inlet

% Speed

Over Speed OperationConstant Tfire

100 101 102 103 104 105

Mai

nten

ance

Fac

tor

(MF)

MF = 2

10.0

1.0

Figure 28 . Maintenance factor for overspeed operation ~constant TF


evaporative coolers, and other inlet systems as well as periodic

inspection and prompt repair of compressor blading. Refer to

system-specific maintenance manuals.

There are also non-recoverable losses. In the compressor, these are

typically caused by nondeposit-related blade surface roughness,

erosion, and blade tip rubs. In the turbine, nozzle throat area

changes, bucket tip clearance increases and leakages are potential

causes. Some degree of unrecoverable performance degradation

should be expected, even on a well-maintained gas turbine. The

owner, by regularly monitoring and recording unit performance

parameters, has a very valuable tool for diagnosing possible

compressor deterioration.

Lube Oil CleanlinessContaminated or deteriorated lube oil can cause wear and damage

to bearing liners. This can lead to extended outages and costly

repairs. Routine sampling of the turbine lube oil for proper viscosity,

chemical composition, and contamination is an essential part of a

complete maintenance plan.

Lube oil should be sampled and tested per GEK-32568, “Lubricating

Oil Recommendations for Gas Turbines with Bearing Ambients

Above 500°F (260°C).” Additionally, lube oil should be checked

periodically for particulate and water contamination as outlined

in GEK-110483, “Cleanliness Requirements for Power Plant

Installation, Commissioning and Maintenance.” At a minimum,

the lube oil should be sampled on a quarterly basis; however,

monthly sampling is recommended.

Moisture IntakeOne of the ways some users increase turbine output is through

the use of inlet foggers. Foggers inject a large amount of moisture

in the inlet ducting, exposing the forward stages of the compressor

to potential water carry-over. Operation of a compressor in such

an environment may lead to long-term degradation of the

compressor due to corrosion, erosion, fouling, and material

property degradation. Experience has shown that depending on

the quality of water used, the inlet silencer and ducting material,

and the condition of the inlet silencer, fouling of the compressor

can be severe with inlet foggers. Similarly, carryover from

evaporative coolers and water washing more than recommended

can degrade the compressor. Figure 30 shows the long-term

material property degradation resulting from operating the

compressor in a wet environment. The water quality standard

that should be adhered to is found in GEK-101944, “Requirements

for Water/Steam Purity in Gas Turbines.”

For turbines with AISI 403 stainless steel compressor blades, the

presence of water carry-over will reduce blade fatigue strength

by as much as 30% and increase the crack propagation rate in

a blade if a flaw is present. The carry-over also subjects the

blades to corrosion. Such corrosion may be accelerated by a

saline environment (see GER-3419). Further reductions in fatigue

strength will result if the environment is acidic and if pitting is

present on the blade. Pitting is corrosion-induced, and blades

with pitting can see material strength reduced to 40% of its

original value. This condition is exacerbated by downtime in

humid environments, which promotes wet corrosion.

4%

2%

0%

-2%

-4%

-6%

-8%

Out

put L

oss

Hea

t Rat

e In

crea

se

Pressure Ratio Decrease0% 1% 2% 3% 4% 5%

5% A

irflo

w L

oss

Figure 29 . Deterioration of gas turbine performance due to compressor blade fouling

ISO

200°F

Acid H2O 180°F

Wet SteamISO

Pitted in Air

Effect of Corrosive Environment• Reduces Vane Material Endurance Strength

• Pitting Provides Localized Stress Risers

Fatigue Sensitivity to Environment

Alte

rnat

ing

Stre

ss R

atio

Estimated Fatigue Strength (107 Cycles) for AISI 403 Blades

1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0.0

Figure 30 . Long-term material property degradation in a wet environment

20

Uncoated GTD-450™ material is relatively resistant to corrosion

while uncoated AISI 403 is more susceptible. Relative susceptibility

of various compressor blade materials and coatings is shown in

Figure 31. As noted in GER-3569, aluminum-based (Al) coatings are

susceptible to erosion damage leading to unprotected sections

of the blade. Because of this, the GECC-1™ coating was created

to combine the effects of an Al coating to prevent corrosion and

a ceramic topcoat to prevent erosion. Water droplets will cause

leading edge erosion on the first few stages of the compressor. This

erosion, if sufficiently developed, may lead to an increased risk of

blade failure.

Utilization of inlet fogging or evaporative cooling may also

introduce water carry-over or water ingestion into the compressor,

resulting in blade erosion. Although the design intent of evaporative

coolers and inlet foggers is to fully vaporize all cooling water

prior to its ingestion into the compressor, evidence suggests that,

on systems that are not properly commissioned, maintained, or

operated, the water may not be fully vaporized. This can be seen

by streaking discoloration on the inlet duct or bell mouth. If this is

the case, additional inspections and maintenance are required, as

presented in applicable TILs and GEKs.

Maintenance InspectionsMaintenance inspection types may be broadly classified as

standby, running, and disassembly inspections. The standby

inspection is performed during off-peak periods when the unit is

not operating and includes routine servicing of accessory systems

and device calibration. The running inspection is performed by

observing key operating parameters while the turbine is running.

The disassembly inspection requires opening the turbine for

inspection of internal components. Disassembly inspections

progress from the combustion inspection to the hot gas path

inspection to the major inspection as shown in Figure 32.

Details of each of these inspections are described below.

Standby InspectionsStandby inspections are performed on all gas turbines but

pertain particularly to gas turbines used in peaking and

intermittent-duty service where starting reliability is of primary

concern. This inspection includes routinely servicing the battery

system, changing filters, checking oil and water levels, cleaning

relays, and checking device calibrations. Servicing can be

performed in off-peak periods without interrupting the

availability of the turbine. A periodic startup test run is an

essential part of the standby inspection.

The O&M Manual, as well as the Service Manual Instruction

Books, contains information and drawings necessary to

perform these periodic checks. Among the most useful

drawings in the Service Manual Instruction Books for standby

maintenance are the control specifications, piping schematics,

and electrical elementaries. These drawings provide the

calibrations, operating limits, operating characteristics, and

sequencing of all control devices. This information should be

used regularly by operating and maintenance personnel.

Careful adherence to minor standby inspection maintenance

can have a significant effect on reducing overall maintenance

costs and maintaining high turbine reliability. It is essential that

a good record be kept of all inspections and maintenance work

in order to ensure a sound maintenance program.

Running InspectionsRunning inspections consist of the general and continued

observations made while a unit is operating. This starts by

establishing baseline operating data during startup of a new

unit and after any major disassembly work. This baseline then

serves as a reference from which subsequent unit deterioration

can be measured.

Data should be taken to establish normal equipment startup

parameters as well as key steady state operating parameters.

Steady state is defined as conditions at which no more than

a 5°F/3°C change in wheelspace temperature occurs over a

Bare

Al Slurry Coatings

NiCd+ Topcoats

Ceramic

NiCd

Bare

0 2 4 6 8 10Worst Best

GTD-450

AISI 403

Relative Corrosion Resistance

Figure 31 . Susceptibility of compressor blade materials and coatings


15-minute time period. Data must be taken at regular intervals

and should be recorded to permit an evaluation of the turbine

performance and maintenance requirements as a function of

operating time. This operating inspection data, summarized in

Figure 33, includes: load versus exhaust temperature, vibration

level, fuel flow and pressure, bearing metal temperature, lube

oil pressure, exhaust gas temperatures, exhaust temperature

spread variation, startup time, and coast-down time. This list

is only a minimum and other parameters should be used as

necessary. A graph of these parameters will help provide a basis

for judging the conditions of the system. Deviations from the

norm help pinpoint impending issues, changes in calibration, or

damaged components.

A sudden abnormal change in running conditions or a severe trip

event could indicate damage to internal components. Conditions

that may indicate turbine damage include high vibration, high

exhaust temperature spreads, compressor surge, abnormal

changes in health monitoring systems, and abnormal changes

in other monitoring systems. It is recommended to conduct a

borescope inspection after such events whenever component

damage is suspected.

Disassembly Inspections• Combustion

• Hot Gas Path

• Major

Major Inspection

Hot Gas PathInspection

CombustionInspection

Figure 32 . 7E.03 heavy-duty gas turbine – disassembly inspections

• Speed

• Load

• Fired Starts

• Fired Hours

• Temperatures– Inlet Ambient

– Compressor Discharge

– Turbine Exhaust

– Turbine Wheelspace

– Lube Oil Header

– Lube Oil Tank

– Bearing Metal

– Bearing Drains

– Exhaust Spread

• Pressures– Compressor Discharge

– Lube Pump(s)

– Bearing Header

– Barometric

– Cooling Water

– Fuel

– Filters (Fuel, Lube, Inlet Air)

• Vibration

• Generator– Output Voltage

– Phase Current

– VARS

– Load

– Field Voltage

– Field Current

– Stator Temp.

– Vibration

• Startup Time

• Coast-Down Time

Figure 33 . Operating inspection data parameters

22

Load vs. Exhaust Temperature

The general relationship between load and exhaust temperature

should be observed and compared to previous data. Ambient

temperature and barometric pressure will have some effect

upon the exhaust temperature. High exhaust temperature can

be an indicator of deterioration of internal parts, excessive leaks

or a fouled air compressor. For mechanical drive applications,

it may also be an indication of increased power required by

the driven equipment.

Vibration Level

The vibration signature of the unit should be observed and

recorded. Minor changes will occur with changes in operating

conditions. However, large changes or a continuously increasing

trend give indications of the need to apply corrective action.

Fuel Flow and Pressure

The fuel system should be observed for the general fuel flow

versus load relationship. Fuel pressures through the system

should be observed. Changes in fuel pressure can indicate that

the fuel nozzle passages are plugged or that fuel-metering

elements are damaged or out of calibration.

Exhaust Temperature and Spread Variation

The most important control function to be monitored is the

exhaust temperature fuel override system and the back-up over

temperature trip system. Routine verification of the operation

and calibration of these functions will minimize wear on the

hot gas path parts.

Startup Time

Startup time is a reference against which subsequent operating

parameters can be compared and evaluated. A curve of the

starting parameters of speed, fuel signal, exhaust temperature,

and critical sequence bench marks versus time will provide a good

indication of the condition of the control system. Deviations from

normal conditions may indicate impending issues, changes in

calibration, or damaged components.

Coast-Down Time

Coast-down time is an indicator of bearing alignment and bearing

condition. The time period from when the fuel is shut off during a

normal shutdown until the rotor comes to turning gear speed can

be compared and evaluated.

Close observation and monitoring of these operating parameters

will serve as the basis for effectively planning maintenance

work and material requirements needed for subsequent

shutdown periods.

Rapid Cool-DownPrior to an inspection, a common practice is to force cool the unit

to speed the cool-down process and shorten outage time. Force

cooling involves turning the unit at crank speed for an extended

period of time to continue flowing ambient air through the

machine. This is permitted, although a natural cool-down cycle

on turning gear or ratchet is preferred for normal shutdowns

when no outage is pending.

Forced cooling should be limited since it imposes additional

thermal stresses on the unit that may result in a reduction of

parts life.

Opening the compartment doors during any cool-down

operation is prohibited unless an emergency situation requires

immediate compartment inspection. Cool-down times should not

be accelerated by opening the compartment doors or lagging

panels, since uneven cooling of the outer casings may result in

excessive case distortion and heavy blade rubs.

Combustion InspectionThe combustion inspection is a relatively short disassembly

inspection of fuel nozzles, liners, transition pieces, crossfire

tubes and retainers, spark plug assemblies, flame detectors,

and combustor flow sleeves. This inspection concentrates on the

combustion liners, transition pieces, fuel nozzles, and end caps,

which are recognized as being the first to require replacement

and repair in a good maintenance program. Proper inspection,

maintenance, and repair (Figure 34) of these items will contribute

to a longer life of the downstream parts, such as turbine nozzles

and buckets.

Figure 32 illustrates the section of a 7E.03 unit that is disassembled

for a combustion inspection. The combustion liners, transition

pieces, and fuel nozzle assemblies should be removed and

replaced with new or repaired components to minimize downtime.

The removed liners, transition pieces, and fuel nozzles can then be

cleaned and repaired after the unit is returned to operation and

be available for the next combustion inspection interval. Typical

combustion inspection requirements are:


• Inspect combustion chamber components.

• Inspect each crossfire tube, retainer and combustion liner.

• Inspect combustion liner for TBC spalling, wear, and cracks.

• Inspect combustion system and discharge casing for debris and

foreign objects.

• Inspect flow sleeve welds for cracking.

• Inspect transition piece for wear and cracks.

• Inspect fuel nozzles for plugging at tips, erosion of tip holes, and

safety lock of tips.

• Inspect impingement sleeves for cracks (where applicable).

• Inspect all fluid, air, and gas passages in nozzle assembly for

plugging, erosion, burning, etc.

• Inspect spark plug assembly for freedom from binding; check

condition of electrodes and insulators.

• Replace all consumables and normal wear-and-tear items such

as seals, lockplates, nuts, bolts, gaskets, etc.

• Perform visual inspection of first-stage turbine nozzle partitions

and borescope inspect (Figure 3) turbine buckets to mark the

progress of wear and deterioration of these parts. This inspection

will help establish the schedule for the hot gas path inspection.

• Perform borescope inspection of compressor.

Figure 34 . Combustion inspection – key elements

Combustion Inspection

Key Hardware Inspect For Potential Action

Combustion liners Foreign object damage (FOD) Repair/refurbish/replace

Combustion end covers Abnormal wear • TransitionPieces

– Strip and recoat

– Weld repair

– Creep repair

• Liners

– Strip and recoat

– Weld repair

– Hula sealreplacement

– Repair out-of-roundness

• Fuelnozzles

– Weld repair

– Flow test

– Leak test

Fuel nozzles Cracking

End caps Liner cooling hole plugging

Transition pieces TBC coating condition

Cross fire tubes Oxidation/corrosion/erosion

Flow sleeves Hot spots/burning

Purge valves Missing hardware

Check valves Clearance limits

Spark plugs

Flame detectors

Flex hoses

IGVs and bushings

Compressor and turbine (borescope)

Exhaust diffuser Cracks Weld repair

Exhaust diffuser Insulation Loose/missing parts Replace/tighten parts

Forward diffuser flex seal Wear/cracked parts Replace seals

Compressor discharge case Cracks Repair or monitor

Cases – exterior Cracks Repair or monitor

Criteria• O&MManual • TILs• GEFieldEngineer

Inspection Methods• Visual • LiquidPenetrant• Borescope

Availability of On-Site Spares is Key to Minimizing Downtime

24

• Visually inspect the compressor inlet, checking the condition

of the inlet guide vanes (IGVs), IGV bushings, and first stage

rotating blades.

• Check the condition of IGV actuators and rack-and-pinion gearing.

• Verify the calibration of the IGVs.

• Visually inspect compressor discharge case struts for signs

of cracking.

• Visually inspect compressor discharge case inner barrel

if accessible.

• Visually inspect the last-stage buckets and shrouds.

• Visually inspect the exhaust diffuser for any cracks in flow

path surfaces. Inspect insulated surfaces for loose or missing

insulation and/or attachment hardware in internal and external

locations. In B/E-class machines, inspect the insulation on the

radial diffuser and inside the exhaust plenum as well.

• Inspect exhaust frame flex seals, L-seals, and horizontal joint

gaskets for any signs of wear or damage.

• Verify proper operation of purge and check valves. Confirm

proper setting and calibration of the combustion controls.

• Inspect turbine inlet systems including filters, evaporative

coolers, silencers, etc. for corrosion, cracks, and loose parts.

After the combustion inspection is complete and the unit is

returned to service, the removed combustion hardware can

be inspected by a qualified GE field service representative and,

if necessary, sent to a qualified GE Service Center for repairs.

It is recommended that repairs and fuel nozzle flow testing be

performed at qualified GE service centers.

See the O&M Manual for additional recommendations and unit

specific guidance.

Hot Gas Path InspectionThe purpose of a hot gas path inspection is to examine those parts

exposed to high temperatures from the hot gases discharged from

the combustion process. The hot gas path inspection outlined

in Figure 35 includes the full scope of the combustion inspection

and, in addition, a detailed inspection of the turbine nozzles,

Figure 35 . Hot gas path inspection – key elements

Hot Gas Path InspectionCombustion Inspection Scope—Plus:


Nozzles (1, 2, 3) Foreign object damage Repair/refurbish/replace

Buckets (1, 2, 3) Oxidation/corrosion/erosion • Nozzles

– Weld repair

– Reposition

– Recoat

• Statorshrouds

– Weld repair

– Blend

– Recoat

• Buckets

– Strip & recoat

– Weld repair

– Blend

Stator shrouds Cracking

Compressor blading (borescope) Cooling hole plugging

Remaining coating life

Nozzle deflection/distortion

Abnormal deflection/distortion

Abnormal wear

Missing hardware

Clearance limits

Evidence of creep

Turbine shell Cracks Repair or monitor

Criteria• O&MManual • TILs• GEFieldEngineer

Inspection Methods• Visual • LiquidPenetrant• Borescope

Availability of On-Site Spares is Key to Minimizing Downtime


stator shrouds, and turbine buckets. To perform this inspection,

the top half of the turbine shell must be removed. Prior to shell

removal, proper machine centerline support using mechanical

jacks is necessary to assure proper alignment of rotor to stator,

obtain accurate half-shell clearances, and prevent twisting of

the stator casings. Reference the O&M Manual for unit-specific

jacking procedures.

Special inspection procedures apply to specific components

in order to ensure that parts meet their intended life. These

inspections may include, but are not limited to, dimensional

inspections, Fluorescent Penetrant Inspection (FPI), Eddy Current

Inspection (ECI), and other forms of non-destructive testing (NDT).

The type of inspection required for specific hardware is determined

on a part number and operational history basis, and can be

obtained from a GE service representative.

Similarly, repair action is taken on the basis of part number, unit

operational history, and part condition. Repairs including (but not

limited to) strip, chemical clean, HIP (Hot Isostatic Processing),

heat treat, and recoat may also be necessary to ensure full parts

life. Weld repair will be recommended when necessary, typically

as determined by visual inspection and NDT. Failure to perform

the required repairs may lead to retirement of the part before

its life potential is fulfilled. In contrast, unnecessary repairs are

an unneeded expenditure of time and resources. To verify the

types of inspection and repair required, contact your GE service

representative prior to an outage.

For inspection of the hot gas path (Figure 32), all combustion

transition pieces and the first-stage turbine nozzle assemblies must

be removed. Removal of the second- and third-stage turbine nozzle

segment assemblies is optional, depending upon the results of

visual observations, clearance measurements, and other required

inspections. The buckets can usually be inspected in place. FPI of

the bucket vane sections may be required to detect any cracks.

In addition, a complete set of internal turbine radial and axial

clearances (opening and closing) must be taken during any hot

gas path inspection. Re-assembly must meet clearance diagram

requirements to prevent rubs and to maintain unit performance.

In addition to combustion inspection requirements, typical hot gas

path inspection requirements are:

• Inspect and record condition of first-, second-, and third-stage

buckets. If it is determined that the turbine buckets should

be removed, follow bucket removal and condition recording

instructions. Buckets with protective coating should be

evaluated for remaining coating life.

• Inspect and record condition of first-, second-, and

third-stage nozzles.

• Inspect seals and hook fits of turbine nozzles and diaphragms

for rubs, erosion, fretting, or thermal deterioration.

• Inspect and record condition of later-stage nozzle

diaphragm packings.

• Check discourager seals for rubs, and deterioration

of clearance.

• Record the bucket tip clearances.

• Inspect bucket shank seals for clearance, rubs, and deterioration.

• Perform inspections on cutter teeth of tip-shrouded buckets.

Consider refurbishment of buckets with worn cutter teeth,

particularly if concurrently refurbishing the honeycomb of the

corresponding stationary shrouds. Consult your GE service

representative to confirm that the bucket under consideration

is repairable.

• Check the turbine stationary shrouds for clearance, cracking,

erosion, oxidation, rubbing, and build-up of debris.

• Inspect turbine rotor for cracks, object damage, or rubs.

• Check and replace any faulty wheelspace thermocouples.

• Perform borescope inspection of the compressor.

• Visually inspect the turbine shell shroud hooks for signs

of cracking.

The first-stage turbine nozzle assembly is exposed to the direct hot

gas discharge from the combustion process and is subjected to the

highest gas temperatures in the turbine section. Such conditions

frequently cause nozzle cracking and oxidation, and in fact, this

is expected. The second- and third-stage nozzles are exposed to

high gas bending loads, which in combination with the operating

temperatures can lead to downstream deflection and closure

of critical axial clearances. To a degree, nozzle distress can be

tolerated, and criteria have been established for determining when

repair is required. More common criteria are described in the O&M

Manuals. However, as a general rule, first-stage nozzles will require

26

repair at the hot gas path inspection. The second- and third-stage

nozzles may require refurbishment to re-establish the proper axial

clearances. Normally, turbine nozzles can be repaired several

times, and it is generally repair cost versus replacement cost that

dictates the replacement decision.

Coatings play a critical role in protecting the buckets operating

at high metal temperatures. They ensure that the full capability

of the high strength superalloy is maintained and that the bucket

rupture life meets design expectations. This is particularly true

of cooled bucket designs that operate above 1985°F (1085°C)

firing temperature. Significant exposure of the base metal to

the environment will accelerate the creep rate and can lead to

premature replacement through a combination of increased

temperature and stress and a reduction in material strength,

as described in Figure 36. This degradation process is driven by

oxidation of the unprotected base alloy. On early generation

uncooled designs, surface degradation due to corrosion or

oxidation was considered to be a performance issue and not a

factor in bucket life. This is no longer the case at the higher firing

temperatures of current generation designs.

Given the importance of coatings, it must be recognized that even

the best coatings available will have a finite life, and the condition

of the coating will play a major role in determining bucket life.

Refurbishment through stripping and recoating is an option for

achieving bucket’s expected/design life, but if recoating is selected,

it should be done before the coating is breached to expose base

metal. Normally, for 7E.03 turbines, this means that recoating

will be required at the hot gas path inspection. If recoating is not

performed at the hot gas path inspection, the life of the buckets

would generally be one additional hot gas path inspection interval,

at which point the buckets would be replaced. For F-class gas

turbines, recoating of the first stage buckets is recommended at

each hot gas path inspection. Visual and borescope examination

of the hot gas path parts during the combustion inspections as

well as nozzle-deflection measurements will allow the operator

to monitor distress patterns and progression. This makes part-

life predictions more accurate and allows adequate time to plan

for replacement or refurbishment at the time of the hot gas path

inspection. It is important to recognize that to avoid extending the

hot gas path inspection, the necessary spare parts should be on

site prior to taking the unit out of service.

See the O&M Manual for additional recommendations and unit

specific guidance.

Major InspectionThe purpose of the major inspection is to examine all of the internal

rotating and stationary components from the inlet of the machine

through the exhaust. A major inspection should be scheduled in

accordance with the recommendations in the owner’s O&M Manual

or as modified by the results of previous borescope and hot gas

path inspections. The work scope shown in Figure 37 involves

Oxidation & Bucket Life

Base Metal Oxidation

Pressure Side Surface

Reduces Bucket Creep Life

Cooling Hole Surface Oxidation

Depleted Coating

Airfoil Surface OxidationTE Cooling Hole

Increases Stress• Reduced Load Carrying Cross Section

Increases Metal Temperature• Surface Roughness Effects

Decreases Alloy Creep Strength• Environmental Effects

Figure 36 . Stage 1 bucket oxidation and bucket life


inspection of all of the major flange-to-flange components of

the gas turbine, which are subject to deterioration during normal

turbine operation. This inspection includes previous elements of the

combustion and hot gas path inspections, and requires laying open

the complete flange-to-flange gas turbine to the horizontal joints,

as shown in Figure 32.

Removal of all of the upper casings allows access to the

compressor rotor and stationary compressor blading, as well as

to the bearing assemblies. Prior to removing casings, shells, and

frames, the unit must be properly supported. Proper centerline

support using mechanical jacks and jacking sequence procedures

are necessary to assure proper alignment of rotor to stator, obtain

accurate half shell clearances, and to prevent twisting of the

casings while on the half shell. Reference the O&M Manual for

unit-specific jacking procedures. In addition to combustion and

hot gas path inspection requirements, typical major inspection

requirements are:

• Check all radial and axial clearances against their original values

(opening and closing).

• Inspect all casings, shells, and frames/diffusers for cracks

and erosion.

• Inspect compressor inlet and compressor flow-path for fouling,

erosion, corrosion, and leakage.

• Check rotor and stator compressor blades for tip clearance,

rubs, object damage, corrosion pitting, and cracking.

• Remove turbine buckets and perform a nondestructive check

of buckets and wheel dovetails. Wheel dovetail fillets, pressure

faces, edges, and intersecting features must be closely examined

for conditions of wear, galling, cracking, or fretting.

• Inspect unit rotor for cracks, object damage, or rubs.

• Inspect bearing liners and seals for clearance and wear.

Figure 37 . Gas turbine major inspection – key elements

Criteria• O&MManual •TILs• GEFieldEngineer

Inspection Methods• Visual •LiquidPenetrant• Borescope •Ultrasonics

Major InspectionHot Gas Path Inspection Scope—Plus:


Compressor blading Foreign object damage Repair/refurbishment/replace

Unit rotor Oxidation/corrosion/erosion •Bearings/seals

Journals and seal surfaces Cracking – Clean

Bearing seals Leaks – Assess oil condition

Exhaust system Abnormal wear – Re-babbitt

Missing hardware •Compressorblades

Clearance limits – Clean

Coating wear – Blend

Fretting •Exhaustsystem

– Weld repair

– Replace flex seals/L-seals

Compressor and compressor discharge case hooks

Wear Repair

All cases – exterior and interior Cracks Repair or monitor

Cases – Exterior Slippage Casing alignment

28

• Visually inspect compressor and compressor discharge case

hooks for signs of wear.

• Visually inspect compressor discharge case inner barrel.

• Inspect exhaust frame flex seals, L-seals, and horizontal joint

gaskets for any signs of wear or damage. Inspect steam gland

seals for wear and oxidation.

• Check torque values for steam gland bolts and re-torque

to full values.

• Check alignment – gas turbine to generator/gas turbine to

accessory gear.

• Inspect casings for signs of casing flange slippage.

Comprehensive inspection and maintenance guidelines have been

developed by GE and are provided in the O&M Manual to assist

users in performing each of the inspections previously described.

Parts PlanningPrior to a scheduled disassembly inspection, adequate spares

should be on-site. Lack of adequate on-site spares can have

a major effect on plant availability. For example, a planned

outage such as a combustion inspection, which should only

take two to five days, could take weeks if adequate spares are

not on-site. GE will provide recommendations regarding the

types and quantities of spare parts needed; however, it is up

to the owner to purchase these spare parts on a planned basis

allowing adequate lead times.

Early identification of spare parts requirements ensures their

availability at the time the planned inspections are performed.

Refer to the Reference Drawing Manual provided as part of the

comprehensive set of O&M Manuals to aid in identification and

ordering of gas turbine parts.

Additional benefits available from the renewal parts catalog

data system are the capability to prepare recommended spare

parts lists for the combustion, hot gas path and major inspections

as well as capital and operational spares.

Estimated repair and replacement intervals for some of the

major components are shown in Appendix D. These tables assume

that operation, inspections, and repairs of the unit have been

done in accordance with all of the manufacturer’s specifications

and instructions.

The actual repair and replacement intervals for any particular

gas turbine should be based on the user’s operating procedures,

experience, maintenance practices, and repair practices. The

maintenance factors previously described can have a major effect

on both the component repair interval and service life. For this

reason, the intervals given in Appendix D should only be used

as guidelines and not certainties for long range parts planning.

Owners may want to include contingencies in their parts planning.

The estimated repair and replacement interval values reflect

current production hardware (the typical case) with design

improvements such as advanced coatings and cooling technology.

With earlier production hardware, some of these lives may not be

achievable. Operating factors and experience gained during the

course of recommended inspection and maintenance procedures

will be a more accurate predictor of the actual intervals.

The estimated repair and replacement intervals are based on

the recommended inspection intervals shown in Figure 39. For

certain models, technology upgrades are available that extend the

maintenance inspection intervals. The application of inspection (or

repair) intervals other than those shown in Figure 39 can result in

different replacement intervals than those shown in Appendix D.

See your GE service representative for details on a specific system.

It should be recognized that, in some cases, the service life of a

component is reached when it is no longer economical to repair

any deterioration as opposed to replacing at a fixed interval. This

is illustrated in Figure 38 for a first stage nozzle, where repairs

continue until either the nozzle cannot be restored to minimum

acceptance standards or the repair cost exceeds or approaches

the replacement cost. In other cases, such as first-stage buckets,

repair options are limited by factors such as irreversible material

damage. In both cases, users should follow GE recommendations

regarding replacement or repair of these components.

It should also be recognized that the life consumption of any one

individual part within a parts set can have variations. This may

lead to a certain percentage of “fallout,” or scrap, of parts being

repaired. Those parts that fallout during the repair process will

need to be replaced by new parts. Parts fallout will vary based on

the unit operating environment history, the specific part design,

and the current repair technology.


Operating Hours

Noz

zle

Cons

truc

tion

Severe Deterioration

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

New NozzleAcceptance Standards

Repaired NozzleMin. Acceptance Standard

1stRepair

2ndRepair

3rdRepair

Repa

ir C

ost E

xcee

dsRe

plac

emen

t Cos

t

Without Repair

Figure 38 . First-stage nozzle repair program: natural gas fired – continuous dry – base load

Type of Inspection

Type of hours/starts

Hours/Starts

6B 7E 9E

MS3002K MS5001PA MS5002C, D 6B .03 7E .03 (6) 9E .03 (7)

Combustion (Non-DLN) Factored 12000/400 (3) 12000/800 (1)(3)(5) 12000/800 (1)(3)(5) 12000/600 (2)(5) 8000/900 (2)(5) 8000/900 (2)(5)

Combustion (DLN) Factored 8000/400 (3)(5) 8000/400 (3)(5) 12000/450 (5) 12000/450 (5) 12000/450 (5)

Hot Gas Path Factored 24000/1200 (4) 24000/1200 (4)(5) 24000/1200 (4)(5) 24000/1200 (5) 24000/1200 (5) 24000/900 (5)

Major Actual 48000/2400 48000/2400 (5) 48000/2400 (5) 48000/2400 (5) 48000/2400 (5) 48000/2400 (5)

Type of Inspection

Type of hours/starts

Hours/Starts

6F 7F 9F

6F .03 7F .03 7F .04 7FB .01 9F .03 9F .05

Combustion (Non-DLN) Factored 8000/400

Combustion (DLN) Factored 12000/450 (5) 24000/900 32000/900 (5) 12000/450 24000/900 12000/450

Hot Gas Path Factored 24000/900 24000/900 32000/1250 24000/900 24000/900 24000/900

Major Actual 48000/2400 48000/2400 64000/2400 48000/2400 48000/2400 48000/2400

Factors that can reduce maintenance intervals:

• Fuel

• Load setting

• Steam/water injection

• Peak load firingoperation

• Trips

• Start cycle

• Hardware design

• Off-frequency operation

1. Units with Lean Head End liners have a 400-starts combustion inspectioninterval.

2. Multiple Non-DLN configurations exist (Standard, MNQC, IGCC). The typicalcase is shown; however, different quoting limits may exist on a machine andhardware basis. Contact a GE service representative for further information.

3. Combustion inspection without transition piece removal. Combustioninspection with transition pieces removal to be performed every 2combustion inspection intervals.

4. Hot gas path inspection for factored hours eliminated on units that operateon natural gas fuel without steam or water injection.

5. Upgraded technology (Extendor*, PIP, DLN 2.6+, etc) may have longerinspection intervals.

6. Also applicable to 7121(EA) models.7. Applicable to non-AGP units only.*Trademark of General Electric Company

Note:

Baseline inspection intervals reflect current production hardware, unless otherwise noted, and operation in accordance with manufacturer specifications. They represent initial recommended intervals in the absence of operating and condition experience.

For Repair/Replace intervals see Appendix D.

Figure 39 . Baseline recommended inspection intervals: base load – natural gas fuel – dry

30

Inspection IntervalsIn the absence of operating experience and resulting part

conditions, Figure 39 lists the recommended combustion, hot

gas path and major inspection intervals for current production

GE turbines operating under typical conditions of natural gas fuel,

base load, and no water/steam injection. These recommended

intervals represent factored hours or starts calculated using

maintenance factors to account for application specific operating

conditions. Initially, recommended intervals are based on

the expected operation of a turbine at installation, but this

should be reviewed and adjusted as operating and maintenance

data are accumulated. While reductions in the recommended

intervals will result from the factors described previously or

unfavorable operating experience, increases in the recommended

intervals may also be considered where operating experience

has been favorable.

The condition of the combustion and hot gas path parts provides a

basis for customizing a program for inspection and maintenance.

The condition of the compressor and bearing assemblies is the

key driver in planning a major inspection. Historical operation

and machine conditions can be used to tailor maintenance

programs such as optimized repair and inspection criteria to

specific sites/machines. GE leverages these principles and

accumulated site and fleet experience in a “Condition Based

Maintenance” program as the basis for maintenance of units

under Contractual Service Agreements. This experience was

accumulated on units that operate with GE approved repairs,

field services, monitoring, and full compliance to GE’s technical

recommendations.

GE can assist operators in determining the appropriate

maintenance intervals for their particular application. Equations

have been developed that account for the factors described earlier

and can be used to determine application-specific combustion,

hot gas path, and major inspection intervals.

Borescope Inspection IntervalIn addition to the planned maintenance intervals, which

undertake scheduled inspections or component repairs or

replacements, borescope inspections should be conducted to

identify any additional actions, as discussed in the sections

“Gas Turbine Design Maintenance Features.” Such inspections

may identify additional areas to be addressed at a future

scheduled maintenance outage, assist with parts or resource

planning, or indicate the need to change the timing of a future

outage. The BI should use all the available access points to verify

the condition of the internal hardware. As much of the Major

Inspection workscope as possible should be done using this visual

inspection without dissassembly. Refer to Figure 4 for standard

recommended BI frequency. Specific concerns may warrant

subsequent BIs in order to operate the unit to the next scheduled

outage without teardown.

Combustion Inspection IntervalEquations have been developed that account for the earlier

mentioned factors affecting combustion maintenance intervals.

These equations represent a generic set of maintenance factors

that provide guidance on maintenance planning. As such, these

equations do not represent the specific capability of any given

combustion system. For combustion parts, the baseline operating

conditions that result in a maintenance factor of one are normal

fired startup and shutdown (no trip) to base load on natural gas

fuel without steam or water injection.

An hours-based combustion maintenance factor can be determined

from the equations given in Figure 40 as the ratio of factored hours

to actual operating hours. Factored hours considers the effects of

fuel type, load setting, and steam/water injection. Maintenance

factors greater than one reduce recommended combustion

inspection intervals from those shown in Figure 39 representing

baseline operating conditions. To obtain a recommended

inspection interval for a specific application, the maintenance

factor is divided into the recommended baseline inspection interval.

A starts-based combustion maintenance factor can be determined

from the equations given in Figure 41 and considers the effect of

fuel type, load setting, peaking-fast starts, trips, and steam/water

injection. An application-specific recommended inspection interval

can be determined from the baseline inspection interval in Figure 39

and the maintenance factor from Figure 41. Appendix B shows six

example maintenance factor calculations using the above hours

and starts maintenance factor equations.


Figure 40 . Combustion inspection hours-based maintenance factors

Syngas units require unit-specific intervals to account for unit-

specific fuel constituents and water/steam injection schedules.

As such, the combustion inspection interval equations may not

apply to those units.

Hours-Based Combustion Inspection

Where:i = Discrete Operating mode (or Operating Practice of Time Interval)

ti = Operating hours at Load in a Given Operating mode

Api = Load Severity factor

Ap = 1.0 up to Base Load

Ap = For Peak Load Factor See Figure 11

Afi = Fuel Severity Factor

Af = 1.0 for Natural Gas Fuel (1)

Af = 1.5 for Distillate Fuel, Non-DLN (2.5 for DLN)

Af = 2.5 for Crude (Non-DLN)

Af = 3.5 for Residual (Non-DLN)

Ki = Water/Steam Injection Severity Factor

(% Steam Referenced to Compressor Inlet Air Flow, w/f = Water to Fuel Ratio)

K = Max(1.0, exp(0.34(%Steam – 2.00%))) for Steam, Dry Control Curve

K = Max(1.0, exp(0.34(%Steam – 1.00%))) for Steam, Wet Control Curve

K = Max(1.0, exp(1.80(w/f – 0.80))) for Water, Dry Control Curve

K = Max(1.0, exp(1.80(w/f – 0.40))) for Water, Wet Control Curve

(1) Af = 10 for DLN 1/DLN 1+ extended lean-lean, and DLN 2.0/ DLN 2+ extended piloted premixed operating modes.

Maintenance Factor = Factored Hours

Actual Hours

Factored Hours = ∑ (Ki · Afi · Api · ti ), i = 1 to n in Operating Modes

Actual Hours = ∑ (ti ), i = 1 to n in Operating Modes

Maintenance Interval = Baseline CI (Figure 39)

Maintenance Factor

Figure 41 . Combustion inspection starts-based maintenance factors

Starts-Based Combustion Inspection

Where:i = Discrete Start/Stop Cycle (or Operating Practice)

Ni = Start/Stop Cycles in a Given Operating Mode

Asi = Start Type Severity Factor

As = 1.0 for Normal Start

As = For Peaking-Fast Start See Figure 14

Api = Load Severity Factor

Ap = 1.0 up to Base Load

Ap = exp (0.009 x Peak Firing Temp Adder in °F) for Peak Load

Ati = Trip Severity Factor

At = 0.5 + exp(0.0125*%Load) for Trip

At = 1 for No Trip

Afi = Fuel Severity Factor

Af = 1.0 for Natural Gas Fuel

Af = 1.25 for Non-DLN (or 1.5 for DLN) for Distillate Fuel

Af = 2.0 for Crude (Non-DLN)

Af = 3.0 for Residual (Non-DLN)

Ki = Water/Steam Injection Severity Factor

(% Steam Referenced to Compressor Inlet Air Flow, w/f = Water to Fuel Ratio)

K = Max(1.0, exp(0.34(%Steam – 1.00%))) for Steam, Dry Control Curve

K = Max(1.0, exp(0.34(%Steam – 0.50%))) for Steam, Wet Control Curve

K = Max(1.0, exp(1.80(w/f – 0.40))) for Water, Dry Control Curve

K = Max(1.0, exp(1.80(w/f – 0.20))) for Water, Wet Control Curve

Maintenance Factor = Factored Starts

Actual Starts

Factored Starts = ∑ (Ki · Afi · Ati · Api · Asi · Ni ), i = 1 to n Start/Stop Cycles

Actual Starts = ∑ (Ni ), i = 1 to n in Start/Stop Cycles

Maintenance Interval = Baseline CI (Figure 39)

Maintenance Factor

32

Hot Gas Path Inspection IntervalThe hours-based hot gas path criterion is determined from the

equations given in Figure 42. With these equations, a maintenance

factor is determined that is the ratio of factored operating hours

and actual operating hours. The factored hours consider the

specifics of the duty cycle relating to fuel type, load setting and

steam or water injection. Maintenance factors greater than one

reduce the hot gas path inspection interval from the baseline

(typically 24,000 hour) case. To determine the application specific

maintenance interval, the maintenance factor is divided into the

baseline hot gas path inspection interval, as shown in Figure 42.

The starts-based hot gas path criterion is determined from the

equations given in Figure 43.

As previously described, the limiting criterion (hours or starts)

determines the maintenance interval. Examples of these equations

are in Appendix A.

Rotor Inspection IntervalLike hot gas path components, the unit rotor has a maintenance

interval involving removal, disassembly, and inspection. This

interval indicates the serviceable life of the rotor and is generally

considered to be the teardown inspection and repair/replacement

interval for the rotor. The disassembly inspection is usually

concurrent with a hot gas path or major inspection; however,

it should be noted that the maintenance factors for rotor

maintenance intervals are distinct from those of combustion and

hot gas path components. As such, the calculation of consumed

life on the rotor may vary from that of combustion and hot gas

path components. Customers should contact GE when their rotor is

approaching the end of its serviceable life for technical advisement.

Hours-Based HGP Inspection

i = 1 to n discrete operating modes (or operating practices of time interval)

ti = Fired hours in a given operating mode

Api = Load severity factor for given operating mode

Ap = 1.0 up to base load

Ap = For peak load factor see Figure 11.

Afi = Fuel severity factor for given operating mode

Af = 1.0 for natural gas

Af = 1.5 for distillate (=1.0 when Ap > 1, at minimum Af ∙ Ap = 1.5)

Af = 2 to 3 for crude

Af = 3 to 4 for residual

Si = Water/steam injection severity factor = Ki + (Mi ∙ Ii)

I = Percent water/steam injection referenced to compressor inlet air flow

M&K = Water/steam injection constants

M K Control Water/Steam Inj . S2N/S3N Material

0 1 Dry <2.2% All

0 1 Dry >2.2% Non-FSX-414

0.18 0.6 Dry >2.2% FSX-414

0.18 1 Wet >0% Non-FSX-414

0.55 1 Wet >0% FSX-414

Maintenance Factor = Factored Hours

Actual Hours

Factored Hours = ∑ni=1 (Si · Afi · Api · ti )

Actual Hours = ∑ni=1 (ti )

Maintenance Interval = Baseline HGPI (Figure 39) (Hours) Maintenance Factor

Figure 42 . Hot gas path maintenance interval: hours-based criterion

Starts-Based HGP Inspection

Where:

Actual Starts = (NA + NB + NP)

S = Baseline Starts-Based Maintenance Interval (Figure 39)

NA = Annual Number of Part Load Start/Stop Cycles (<60% Load)

NB = Annual Number of Base Load Start/Stop Cycles

NP = Annual Number of Peak Load Start/Stop Cycles (>100% Load)

Ps = Peaking-Fast Start Factor (See Figure 14)

F = Annual Number of Peaking-Fast Starts

T = Annual Number of Trips

aT = Trip Severity Factor = f(Load) (See Figure 20)

n = Number of Trip Categories (i.e. Full Load, Part Load, etc.)


Actual Starts

Factored Starts = 0.5NA + NB + 1.3NP + PsF + ∑ni=1 (aTi – 1) Ti

Figure 43 . Hot gas path maintenance interval: starts-based criterion

Maintenance Interval = S (Starts) Maintenance Factor


Figure 44 describes the procedure to determine the hours-

based maintenance criterion. Peak load operation is the primary

maintenance factor for the F-class rotor and will act to increase

the hours-based maintenance factor and to reduce the rotor

maintenance interval. For B/E-class units time on turning gear also

affects rotor life.

The starts-based rotor maintenance interval is determined from the

equations given in Figure 45. Adjustments to the rotor maintenance

interval are determined from rotor-based operating factors as

described previously. In the calculation for the starts-based rotor

maintenance interval, equivalent starts are determined for cold,

warm, and hot starts over a defined time period by multiplying

the appropriate cold, warm, and hot start operating factors by the

number of cold, warm, and hot starts respectively. Additionally,

equivalent starts for trips from load are added. The total equivalent

starts are divided by the actual number of starts to yield the

maintenance factor. The rotor starts-based maintenance interval

is determined by dividing the baseline rotor maintenance interval

of 5000 starts by the calculated maintenance factor. The baseline

rotor maintenance interval is also the maximum interval, since

calculated maintenance factors less than one are not considered.

When the rotor reaches the earlier of the inspection intervals

described in Figures 44 and 45, an unstack of the rotor is required

so that a complete inspection of the rotor components in both

the compressor and turbine can be performed. It should be

expected that some rotor components will either have reached

the end of their serviceable life or will have a minimal amount of

residual life remaining and will require repair or replacement at this

inspection point. Depending on the extent of refurbishment and

part replacement, subsequent inspections may be required at a

reduced interval.

Hours-Based Rotor Inspection

H = Non-peak load operating hours

P = Peak load operating hours

TG = Hours on turning gear

R = Baseline rotor inspection interval

MachineF-classAll other

R(3)

144,000200,000

(1) Maintenance factor equation to be used unless otherwise notified in unit-specific documentation.

(2) To diminish potential turning gear impact, major inspections must include a thorough visual and dimensional examination of the hot gas path turbine rotor dovetails for signs of wearing, galling, fretting, or cracking. If no distress is found during inspection or after repairs are performed to the dovetails, time on turning gear may be omitted from the hours-based maintenance factor.

(3) Baseline rotor inspection intervals to be used unless otherwise notified in unit-specific documentation.

MF = Factored Hours

Actual Hours

MF forB/E-class

= H + 2P(1)

H + P=

H + 2P + 2TG(2)

H + P

Figure 44 . Rotor maintenance interval: hours-based criterion

Maintenance Interval = R (Hours) Maintenance Factor

Starts-Based Rotor Inspection

For units with published start factors:

For B/E-class units

For all other units additional start factors may apply.

Number of Starts

Nh1 = Number of hot 1 starts

Nh2 = Number of hot 2 starts

Nw1 = Number of warm 1 starts

Nw2 = Number of warm 2 starts

Nc = Number of cold starts

Nt = Number of trips from load

Ns = Total number of fired starts

Start Factors (2)

Fh1 = Hot 1 start factor (down 0-1 hr)

Fh2 = Hot 2 start factor (down 1-4 hr)

Fw1 = Warm 1 start factor (down 4-20 hr)

Fw2 = Warm 2 start factor (down 20-40 hr)

Fc = Cold start factor (down >40 hr)

Ft = Trip from load factor

(1) Baseline rotor inspection interval is 5,000 fired starts unless otherwise notified in unit-specific documentation.

(2) Start factors for certain F-class units are tabulated in Figure 22. For all other machines, consult unit-specific documentation to determine if start factors apply.


Actual Starts

MaintenanceFactor

= (Fh1 · Nh1 + Fh2 · Nh2 + Fw1 · Nw1 + Fw2 · Nw2 + Fc · Nc + Ft · Nt)

(Nh1+Nh2+Nw1+Nw2+Nc )

Maintenance Factor = NS + NT

NS

Figure 45 . Rotor maintenance interval: starts-based criterion

Maintenance Interval = 5,000(1) (Starts) Maintenance Factor

34

The baseline rotor life is predicated upon sound inspection results

at the major inspections. For F-class rotors the baseline intervals

are typically 144,000 hours and 5,000 starts. For rotors other than

F-class, the baseline intervals are typically 200,000 hours and

5,000 starts. Consult unit-specific documentation to determine if

alternate baseline intervals or maintenance factors may apply.

Personnel PlanningIt is essential that personnel planning be conducted prior to an

outage. It should be understood that a wide range of experience,

productivity, and working conditions exist around the world.

However, an estimate can be made based upon maintenance

inspection labor assumptions, such as the use of a crew of

workers with trade skill (but not necessarily direct gas turbine

experience), with all needed tools and replacement parts (no

repair time) available. These estimated craft labor hours should

include controls/accessories and the generator. In addition to

the craft labor, additional resources are needed for technical

direction, specialized tooling, engineering reports, and site

mobilization/demobilization.

Inspection frequencies and the amount of downtime varies

within the gas turbine fleet due to different duty cycles and the

economic need for a unit to be in a state of operational readiness.

Contact your local GE service representative for the estimated

labor hours and recommended crew size for your specific unit.

Depending upon the extent of work to be done during each

maintenance task, a cooldown period of 4 to 24 hours may be

required before service may be performed. This time can be

utilized productively for job move-in, correct tagging and locking

equipment out-of-service, and general work preparations. At the

conclusion of the maintenance work and systems check out, a

turning gear time of two to eight hours is normally allocated prior

to starting the unit. This time can be used for job clean-up and

preparing for start.

Local GE field service representatives are available to help plan

maintenance work to reduce downtime and labor costs. This

planned approach will outline the replacement parts that may be

needed and the projected work scope, showing which tasks can

be accomplished in parallel and which tasks must be sequential.

Planning techniques can be used to reduce maintenance cost by

optimizing lifting equipment schedules and labor requirements.

Precise estimates of the outage duration, resource requirements,

critical-path scheduling, recommended replacement parts, and

costs associated with the inspection of a specific installation may

be sourced from the local GE field services office.

ConclusionGE heavy-duty gas turbines are designed to have high availability.

To achieve maximum gas turbine availability, an owner must

understand not only the equipment but also the factors affecting

it. This includes the training of operating and maintenance

personnel, following the manufacturer’s recommendations, regular

periodic inspections, and the stocking of spare parts for immediate

replacement. The recording and analysis of operating data is also

essential to preventative and planned maintenance. A key factor

in achieving this goal is a commitment by the owner to provide

effective outage management, to follow published maintenance

instructions, and to utilize the available service support facilities.

It should be recognized that, while the manufacturer provides

general maintenance recommendations, it is the equipment

user who controls the maintenance and operation of equipment.

Inspection intervals for optimum turbine service are not fixed for

every installation but rather are developed based on operation

and experience. In addition, through application of a Contractual

Service Agreement to a particular turbine, GE can work with

a user to establish a maintenance program that may differ

from general recommendations but will be consistent with

contractual responsibilities.

The level and quality of a rigorous maintenance program have a

direct effect on equipment reliability and availability. Therefore,

a rigorous maintenance program that reduces costs and outage

time while improving reliability and earning ability is the optimum

GE gas turbine user solution.


ReferencesJarvis, G., “Maintenance of Industrial Gas Turbines,” GE Gas Turbine

State of the Art Engineering Seminar, paper SOA-24-72, June 1972.

Patterson, J. R., “Heavy-Duty Gas Turbine Maintenance Practices,”

GE Gas Turbine Reference Library, GER-2498, June 1977.

Moore, W. J., Patterson, J.R, and Reeves, E.F., “Heavy-Duty Gas

Turbine Maintenance Planning and Scheduling,” GE Gas Turbine

Reference Library, GER-2498; June 1977, GER 2498A, June 1979.

Carlstrom, L. A., et al., “The Operation and Maintenance of General

Electric Gas Turbines,” numerous maintenance articles/authors

reprinted from Power Engineering magazine, General Electric

Publication, GER-3148; December 1978.

Knorr, R. H., and Reeves, E. F., “Heavy-Duty Gas Turbine

Maintenance Practices,” GE Gas Turbine Reference Library, GER-

3412; October 1983; GER- 3412A, September 1984; and GER-3412B,

December 1985.

Freeman, Alan, “Gas Turbine Advance Maintenance Planning,”

paper presented at Frontiers of Power, conference, Oklahoma State

University, October 1987.

Hopkins, J. P, and Osswald, R. F., “Evolution of the Design,

Maintenance and Availability of a Large Heavy-Duty Gas Turbine,”

GE Gas Turbine Reference Library, GER-3544, February 1988 (never

printed).

Freeman, M. A., and Walsh, E. J., “Heavy-Duty Gas Turbine

Operating and Maintenance Considerations,” GE Gas Turbine

Reference Library, GER-3620A.

GEI-41040, “Fuel Gases for Combustion in Heavy-Duty Gas

Turbines.”

GEI-41047, “Gas Turbine Liquid Fuel Specifications.”

GEK-101944, “Requirements for Water/Steam Purity in Gas

Turbines.”

GER-3419A, “Gas Turbine Inlet Air Treatment.”

GER-3569F, “Advanced Gas Turbine Materials and Coatings.”

GEK-32568, “Lubricating Oil Recommendations for Gas Turbines

with Bearing Ambients Above 500°F (260°C).”

GEK-110483, “Cleanliness Requirements for Power Plant Installation,

Commissioning and Maintenance.”

36

AppendixA .1) Example 1 – Hot Gas Path Maintenance Interval CalculationA 7E.03 user has accumulated operating data since the last hot

gas path inspection and would like to estimate when the next

one should be scheduled. The user is aware from GE publications

that the baseline HGP interval is 24,000 hours if operating on

natural gas, with no water or steam injection, and at base load.

It is also understood that the baseline starts interval is 1200,

based on normal startups, no trips, no peaking-fast starts. The

actual operation of the unit since the last hot gas path inspection

is much different from the baseline case. The unit operates in four

different operating modes:

1. The unit runs 3200 hrs/yr in its first operating mode, which is

natural gas at base or part load with no steam/water injection.

2. The unit runs 350 hrs/yr in its second operating mode, which is

distillate fuel at base or part load with no steam/water injection.

3. The unit runs 120 hrs/yr in its third operating mode, which is

natural gas at peak load (+100°F) with no steam/water injection.

4. The unit runs 20 hrs/yr in its fourth operating mode, which is

natural gas at base load with 2.4% steam injection on a wet

control curve.

The hours-based hot gas path maintenance interval parameters

for these four operating modes are summarized below:

Operating Mode (i)

1 2 3 4

Fired hours (hrs/yr) t 3200 350 120 20

Fuel severity factor Af 1 1.5 1 1

Load severity factor Ap 1 1 [e (0.018*100)] = 6 1

Steam/water injection rate (%) I 0 0 0 2.4

For this particular unit, the second- and third-stage nozzles are

FSX-414 material. From Figure 42, at a steam injection rate of 2.4%

on a wet control curve,

M4 = 0.55, K4 = 1

The steam severity factor for mode 4 is therefore,

= S4 = K4 + (M4 ∙ I4) = 1 + (0.55 ∙ 2.4) = 2.3

At a steam injection rate of 0%,

M = 0, K = 1

Therefore, the steam severity factor for modes 1, 2, and 3 are

= S1 = S2 = S3 = K + (M ∙ I) = 1

From the hours-based criteria, the maintenance factor is

determined from Figure 42.

MF = 1.22

The hours-based adjusted inspection interval is therefore,

Adjusted Inspection Interval = 24,000/1.22 = 19,700 hours

[Note, since total annual operating hours is 3690, the estimated

time to reach 19,700 hours is 19,700/3690 = 5.3 years.]

Also, since the last hot gas path inspection the unit has averaged

145 normal start-stop cycles per year, 5 peaking-fast start cycles

per year, and 20 base load cycles ending in trips (aT = 8) per year.

The starts-based hot gas path maintenance interval parameters

for this unit are summarized below:

Normal cycles

Peaking starts, °F

Cycles ending in trip, T

Total

Part load cycles, NA 40 0 0 40

Base load cycles, NB 100 5 20 125

Peak load cycles, NP 5 0 0 5

From the starts-based criteria, the maintenance factor is

determined from Figure 43.

MF = 1.8

The adjusted inspection interval based on starts is

Adjusted Inspection Interval = 1200/1.8 = 667 starts

[Note, since the total annual number of starts is 170, the estimated

time to reach 667 starts is 667/170 = 3.9 years.]

In this case the unit would reach the starts-based hot gas path

interval prior to reaching the hours-based hot gas path interval.

The hot gas path inspection interval for this unit is therefore 667

starts (or 3.9 years).

MF = ∑n

i=1 (Si · Afi · Api · ti )

∑ni=1) (ti )

= (1 · 1 · 1 · 3200) + (1 · 1.5 · 1 · 350) + (1 · 1 · 6 · 120) + (2.3 · 1 · 1 · 20)

(3200 + 350 + 120 + 20)

MF = 0.5NA + NB + 1.3NP + PsF + ∑n

i=1 (aTi - 1) Ti

NA + NB + NP

MF = 0.5 (40) + 125 + 1.3 (5) + 3.5 (5) + (8 - 1 )20

40 + 125 + 5


A .2) Example 2 – Hot Gas Path Factored Starts CalculationA 7E.03 user has accumulated operating data for the past year of

operation. This data shows number of trips from part, base, and

peak load, as well as peaking-fast starts. The user would like to

calculate the total number of factored starts in order to plan the

next HGP outage. Figure 43 is used to calculate the total number of

factored starts as shown below.

Operational history:

Normal cycles

Peaking starts with

normal shutdowns

Peaking starts with

trips

Normal starts with

tripsTotal

Part load cycles, NA

35 0 1 5 41

Base load cycles, NB

25 4 2 35 66

Peak load cycles, NP

40 0 0 10 50

Total Trips

5. 50% load (aT1 = 6.5), T1 = 5 + 1 = 6

6. Base load (aT2 = 8), T2 = 35 + 2 = 37

7. Peak load (aT3 = 10), T3 = 10

Additional Cycles

Peaking-fast starts, F = 7

From the starts-based criteria, the total number of factored starts

(FS) and actual starts (AS) is determined from Figure 43.

Maintenance Factor = =FS

AS= 3.6

558

157

= 0.5 · 41 + 66 + 1.3 · 50 + 3.5 · 7 + (6.5 - 1) 6 + (8 - 1) 37 + (10 - 1) 10 = 558

AS = NA + NB + NP = 41 + 66 + 50 = 157

FS = 0.5NA + NB + 1.3NP + PsF + ∑ni=1 (aTi - 1) Ti

38

B) Examples – Combustion MaintenanceInterval Calculations (reference Figures 40 and 41)

DLN 1 Peak Load with Power Augmentation

+50F Tfire Increase

Factored Hours = Ki * Afi * Api * ti = 34.5 HoursHours Maintenance Factor = (34.5/6) 5 .8

Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) WetAfi = 1.00 Natural Gas FuelApi = 2.46 exp(0.018(50)) Peak Loadti = 6.0 Hours/Start

Factored Starts = Ki * Afi * Ati * Api * Asi * Ni = 17.4 StartsStarts Maintenance Factor = (17.4/1) 17 .4

Where Ki = 2.77 Max(1.0, exp(0.34(3.50-0.50))) WetAfi = 1.00 Natural Gas FuelAti = 1.00 No Trip at LoadApi = 1.57 exp(0.009(50)) Peak LoadAsi = 4.0 Peaking StartNi = 1.0 Considering Each Start

3.5% Steam AugmentationPeaking Start

Natural Gas Fuel6 Hours/StartWet Control Curve

Normal Shutdown (No Trip)

Standard Combustor Base Load on Crude Oil

No Tfire Increase


Where Ki = 1.43 Max(1.0, exp(1.80(1.00-0.80))) DryAfi = 2.50 Crude Oil, Std (Non-DLN)Api = 1.00 Base Loadti = 220.0 Hours/Start


Where Ki = 2.94 Max(1.0, exp(1.80(1.00-0.40))) DryAfi = 2.00 Crude Oil, Std (Non-DLN)Ati = 1.00 No Trip at LoadApi = 1.00 Base LoadAsi = 1.00 Normal StartNi = 1.0 Considering Each Start

1.0 Water/Fuel RatioNormal Start

Crude Oil Fuel220 Hours/StartDry Control Curve


DLN 2 .6 Base Load on Natural Gas with Trip @ Load

No Tfire Increase


Where Ki = 1.00 No InjectionAfi = 1.00 Natural Gas FuelApi = 1.00 Base Loadti = 168.0 Hours/Start


Where Ki = 1.00 No InjectionAfi = 1.00 Natural Gas FuelAti = 2.62 0.5+exp(0.0125*60) for TripApi = 1.00 Base LoadAsi = 1.00 Normal StartNi = 1.0 Considering Each Start

No Steam/Water InjectionNormal Start

Natural Gas Fuel168 Hours/StartDry Control Curve

Trip @ 60% Load

DLN 2 .6 Base Load on Distillate

No Tfire Increase


Where Ki = 1.72 Max(1.0, exp(1.80(1.10-0.80))) DryAfi = 2.50 Distillate Fuel, DLNApi = 1.00 Base Loadti = 220.0 Hours/Start


Where Ki = 3.53 Max(1.0, exp(1.80(1.10-0.40))) DryAfi = 1.50 Distillate Fuel, DLNAti = 1.00 No Trip at LoadApi = 1.00 Base LoadAsi = 1.00 Normal StartNi = 1.0 Considering Each Start


Distillate Fuel220 Hours/StartDry Control Curve


DLN 2 .6 Peak Load on Natural Gas with Peaking Start

+35F Tfire Increase

Factored Hours = Ki * Afi * Api * ti = 12.5HoursHours Maintenance Factor = (12.5/4) 3 .1

Where Ki = 1.67 Max(1.0, exp(0.34(3.50-2.00)))Afi = 1.00 Natural Gas FuelApi = 1.88 exp(0.018(35)) Peak Loadti = 4.0 Hours/Start


Where Ki = 2.34 Max(1.0, exp(0.34(3.50-1.00))) DryAfi = 1.00 Natural Gas FuelAti = 1.00 No Trip at LoadApi = 1.37 exp(0.009(35)) Peak LoadAsi = 4.0 Peaking StartNi = 1.0 Considering Each Start

3.5% Steam AugmentationPeaking Start

Natural Gas Fuel4 Hours/StartDry Control Curve


DLN 1 Combustor Base Load on Distillate

No Tfire Increase


Where Ki = 1.20 Max(1.0, exp(1.80(0.90-0.80))) DryAfi = 2.50 Distillate Fuel, DLN 1Api = 1.00 Part Loadti = 500.0 Hours/Start


Where Ki = 2.46 Max(1.0, exp(1.80(0.90-0.40))) DryAfi = 1.50 Distillate Fuel, DLNAti = 1.00 No Trip at LoadApi = 1.00 Part LoadAsi = 1.00 Normal StartNi = 1.0 Considering Each Start


Distillate Fuel500 Hours/StartDry Control Curve



Reliability: Probability of not being forced out of

service when the unit is needed — includes forced

outage hours (FOH) while in service, while on

reserve shutdown and while attempting to start

normalized by period hours (PH) — units are %.

Reliability = (1-FOH/PH) (100)

FOH = total forced outage hours

PH = period hours

Availability: Probability of being available,

independent of whether the unit is needed – includes

all unavailable hours (UH) – normalized by period

hours (PH) – units are %:

Availability = (1-UH/PH) (100)

UH = total unavailable hours (forced outage,

failure to start, scheduled maintenance

hours, unscheduled maintenance hours)

PH = period hours

Equivalent Reliability: Probability of a multi-shaft

combined-cycle power plant not being totally forced

out of service when the unit is required includes the

effect of the gas and steam cycle MW output

contribution to plant output – units are %.

Equivalent Reliability =

GT FOH = Gas Turbine Forced Outage Hours

GT PH = Gas Turbine Period Hours

HRSG FOH = HRSG Forced Outage Hours

B PH = HRSG Period Hours

ST FOH = Steam Turbine Forced Outage Hours

ST PH = Steam Turbine Period Hours

B = Steam Cycle MW Output

Contribution (normally 0.30)

Equivalent Availability: Probability of a multi-shaft

combined-cycle power plant being available for power

generation — independent of whether the unit is

needed — includes all unavailable hours — includes

the effect of the gas and steam cycle MW output

contribution to plant output; units are %.

Equivalent Availability =

GT UH = Gas Turbine Unavailable Hours

GT PH = Gas Turbine Period Hours

HRSG UH = HRSG Total Unavailable Hours

ST UH = Steam Turbine Unavailable Hours

ST PH = Steam Turbine Period Hours

B = Steam Cycle MW Output

Contribution (normally 0.30)

Operating Duty Definition:

Duty Service Factor Fired Hours/Start

Stand-by < 1% 1 to 4

Peaking 1% – 17% 3 to 10

Cycling 17% – 50% 10 to 50

Continuous > 90% >> 50

MTBF–Mean Time Between Failure: Measure of

probability of completing the current run. Failure

events are restricted to forced outages (FO) while in

service – units are operating hours.

MTBF = OH/FO

OH = Operating Hours

FO = Forced Outage Events from a Running

(On-line) Condition

Service Factor: Measure of operational use, usually

expressed on an annual basis – units are %.

SF = OH/PH x 100

OH = Operating Hours on an annual basis

PH = Period Hours (8760 hours per year)

ST FOHHRSG FOHGT FOH

ST PHB PHGT PH+ B + x 1001 –

GT UH ST UHHRSG UH

ST PHGT PH GT PH+ B + x 100[[ ]1 –

[ ]

C) Definitions

40

D) Estimated Repair and Replacement Intervals(Natural Gas Only)Repair/replace intervals reflect current production hardware, unless

otherwise noted, and operation in accordance with manufacturer

specifications. Consult previous revisions of GER 3620 or other unit-

specific documentation for estimated repair/replacement intervals

of previous generation gas turbine models and hardware. Consult

your GE service representative for further information.

MS3002K PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners CI 4 (CI) 4 (CI)

Transition Pieces CI(1) 4 (CI) 4 (CI)

Stage 1 Nozzles (HGPI)(2) 4 (HGPI) 2 (HGPI)

Stage 2 Nozzles (HGPI)(2) 4 (HGPI) 4 (HGPI)

Stage 1 Shrouds (HGPI)(2) 4 (HGPI) 4 (HGPI)

Stage 2 Shrouds (HGPI)(2) 4 (HGPI) 4 (HGPI)

Stage 1 Buckets – (3) 2 (HGPI)(3) 2 (HGPI)

Stage 2 Buckets (HGPI)(2) 4 (HGPI) 4 (HGPI)

Note: Repair/replace intervals reflect current production hardware, unless otherwise noted, and operation in

accordance with manufacturer specifications. They represent initial recommended intervals in the absence of

operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 39.

CI = Combustion Inspection Interval

HGPI = Hot Gas Path Inspection Interval

(1) Repair interval is every 2 combustion inspection intervals.

(2) Repair interval is every 2 hot gas path inspection intervals with the exception of 1st stage nozzle

start-based repair interval where repair interval is one inspection interval.

(3) No repair required. GE approved repair at 24,000 factored hours may extend replace interval to

72000 factored hours.

Figure D-1 . Estimated repair and replacement intervals

MS5001PA / MS5002C,D PartsRepair Interval Replace Interval (Hours) Replace Interval (Starts)


Transition Pieces CI(1) 4 (CI) 4 (CI)(5)

Stage 1 Nozzles HGPI(2) 4 (HGPI) 2 (HGPI)

Stage 2 Nozzles HGPI(2) 4 (HGPI) 4 (HGPI)

Stage 1 Shrouds HGPI(2) 4 (HGPI) 4 (HGPI)

Stage 2 Shrouds – (3) 4 (HGPI) 4 (HGPI)

Stage 1 Buckets – (4) 2 (HGPI)(4) 2 (HGPI)

Stage 2 Buckets HGPI(2) 4 (HGPI) 4 (HGPI)

Note: Repair/replace cycles reflect current production hardware, unless otherwise noted, and operation in

accordance with manufacturer specifications. They represent initial recommended intervals in the absence of

operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 39.



(1) Repair interval is every 2 combustion inspection intervals.

(2) Repair interval is every 2 hot gas path inspection intervals with the exception of 1st stage nozzle start-

based repair interval where repair interval is one inspection interval.

(3) No repair required

(4) No repair required. GE approved repair at 24,000 factored hours may extend replace interval to 72000

factored hours

(5) 6 replace intervals (starts-based) for DLN and lean head end (LHE) units.


6B .03Repair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners Cl 4 (Cl) 4 (Cl) / 5 (Cl)(1)

Caps Cl 4 (Cl) 5 (Cl)

Transition Pieces Cl 4 (Cl) 4 (Cl) / 5 (Cl)(1)

Fuel Nozzles Cl 2 (Cl) 2 (Cl) / 3 (Cl)(4)

Crossfire Tubes Cl 1 (CI) 1 (CI)

Crossfire Tube Retaining Clips

CI 1 (CI) 1 (CI)

Flow Divider (Distillate)

Cl 3 (Cl) 3 (Cl)

Fuel Pump (Distillate)

Cl 3 (Cl) 3 (Cl)

Stage 1 Nozzles HGPI 3 (HGPI) 3 (HGPI)



Stage 1 Shrouds HGPI 3 (HGPI) 2 (HGPI)



Stage 1 Buckets HGPI 3 (HGPI)(2) 3 (HGPI)


Stage 3 Buckets HGPI 3 (HGPI) 4 (HGPI)

Note: Repair/replace cycles reflect current production (6B.03) hardware, unless otherwise noted, and operation

in accordance with manufacturer specifications. They represent initial recommended intervals in the absence

of operating and condition experience. For factored hours and starts of the repair intervals, refer to Figure 39.

Cl = Combustion Inspection Interval


(1) 4 (CI) for non-DLN / 5 (CI) for DLN

(2) 3 (HGPI) with strip and recoat at first HGPI

(3) 3 (HGPI) for current design only. Consult your GE Energy representative for replace intervals by part number.

(4) 2 (CI) for non-DLN / 3 (CI) for DLN



7E .03 (7)

Repair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners Cl 3 (Cl) / 5 (Cl)(1) 5 (Cl)


Transition Pieces Cl 4 (Cl) / 6 (Cl)(5) 6 (Cl)

Fuel Nozzles Cl 2 (Cl) / 3 (Cl)(6) 3 (Cl)

Crossfire Tubes Cl 1 (Cl) 1 (Cl)


CI 1 (CI) 1 (CI)


Cl 3 (Cl) 3 (Cl)


Cl 3 (Cl) 3 (Cl)







Stage 1 Buckets HGPI 3 (HGPl)(2)(3) 3 (HGPI)

Stage 2 Buckets HGPI 3 (HGPl)(4) 4 (HGPI)

Stage 3 Buckets HGPI 3 (HGPl) 4 (HGPI)

Note: Repair/replace intervals reflect current production (7121(EA) or 7E.03) hardware, unless otherwise noted,

and operation in accordance with manufacturer specifications. They represent initial recommended intervals

in the absence of operating and condition experience. For factored hours and starts of the repair intervals,

refer to Figure 39.



(1) 3 (CI) for DLN / 5 (CI) for non-DLN

(2) Strip and Recoat is required at first HGPI to achieve 3 HGPI replace interval.

(3) Uprated 7E machines (2055 Tfire) require HIP rejuvenation at first HGPI to achieve 3 HGPI replace interval.

(4) 3 (HGPI) interval requires meeting tip shroud engagement criteria at prior HGP repair intervals.

Consult your GE service representative for details.



(7) Also applicable to 7121(EA) models.


9E .03 (6)

Repair Interval Replace Interval (Hours) Replace Interval (Starts)

Combustion Liners Cl 3 (Cl) / 5 (Cl)(1) 5 (Cl)


Transition Pieces Cl 4 (Cl) / 6 (Cl)(4) 6 (Cl)

Fuel Nozzles Cl 2 (Cl) / 3 (Cl)(5) 3 (Cl)



CI 1 (CI) 1 (CI)


Cl 3 (Cl) 3 (Cl)


Cl 3 (Cl) 3 (Cl)









Stage 3 Buckets HGPI 3 (HGPl) 4 (HGPI)

Note: Repair/replace intervals reflect current production (9171(E)) hardware, unless otherwise noted, and

operation in accordance with manufacturer specifications. They represent initial recommended intervals in

the absence of operating and condition experience. For factored hours and starts of the repair intervals, refer

to Figure 39.




(2) Strip and Recoat is required at first HGPI to achieve 3 HGPI replace interval.

(3) 3 (HGPI) interval requires meeting tip shroud engagement criteria at prior HGP repair intervals.

Consult your GE service representative for details.



(6) Applicable to non-AGP units only


42

6F .03Repair Interval Replace Interval (Hours) Replace Interval (Starts)


Caps CI 3 (CI) 2 (CI)

Transition Pieces CI 3 (CI) 2 (CI)

Fuel Nozzles CI 2 (CI) 2 (CI)

Crossfire Tubes CI 1 (CI) 1 (CI)


CI 1 (CI) 1 (CI)

End Covers CI 4 (CI) 2 (CI)










Note: Repair/replace intervals reflect current production (6F.03 DLN 2.6) hardware, unless otherwise noted,



refer to Figure 39.





Combustion Liners Cl 2 (Cl) 2 (Cl)


Transition Pieces Cl 2 (Cl) 2 (Cl)

Fuel Nozzles Cl 2 (Cl) 2 (Cl)



CI 1 (CI) 1 (CI)

End Covers CI 2 (Cl) 2 (Cl)







Stage 1 Buckets HGPI 3 (HGPI)(2) 2 (HGPI)(4)



Note: Repair/replace intervals reflect current production (7F.03 DLN 2.6 24k Super B and non-AGP) hardware,

unless otherwise noted, and operation in accordance with manufacturer specifications. They represent initial

recommended intervals in the absence of operating and condition experience. For factored hours and starts

of the repair intervals, refer to Figure 39.



(1) 3 (HGPI) for current design. Consult your GE service representative for replacement intervals by part

number.

(2) GE approved repair procedure required at first HGPI for designs without platform cooling.

(3) GE approved repair procedure at 2nd HGPI is required to meet 3 (HGPI) replacement life.

(4) 2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned bucket

with platform undercut and cooling modifications.






Fuel Nozzles Cl 2 (Cl) 2 (Cl)



CI 1 (CI) 1 (CI)







Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGP)




Note: Repair/replacement intervals reflect current production (7F.04 DLN 2.6) hardware, unless otherwise

noted, and operation in accordance with manufacturer specifications. They represent initial recommended

intervals in the absence of operating and condition experience. For factored hours and starts of the repair

intervals, refer to Figure 39.




7FB .01Repair Interval Replace Interval (Hours) Replace Interval (Starts)




Fuel Nozzles Cl 2 (Cl)(1) 3 (Cl)(1)



CI 1 (CI) 1 (CI)







Stage 3 Shrouds HGPI 3 (HGPI) 3 (HGP)




Note: Repair/replace cycles reflect current production (7251(FB) DLN 2.0+ extended interval) hardware,

unless otherwise noted, and operation in accordance with manufacturer specifications. They represent initial

recommended intervals in the absence of operating and condition experience. For factored hours and starts

of the repair intervals, refer to Figure 39.



(1) Blank and liquid fuel cartridges to be replaced at each CI







Fuel Nozzles Cl 2 (Cl)(1) 3 (Cl)(1)



CI 1 (CI) 1 (CI)











Note: Repair/replace intervals reflect current production (9F.03 DLN 2.6+) hardware, unless otherwise noted,



refer to Figure 39.




(2) 2 (HGPI) for current design with GE approved repair at first HGPI. 3 (HGPI) is possible for redesigned bucket

with platform undercut and cooling modifications.

(3) Recoating at 1st HGPI may be required to achieve 3 HGPI replacement life.

(4) GE approved repair procedure at 1 (HGPI) is required to meet 2 (HGPI) replacement life.

(5) GE approved repair procedure is required to meet 3 (HGPI) replacement life.




Caps CI 4 (CI) 4 (CI)

Transition Pieces CI 4 (CI) 4 (CI)

Fuel Nozzles CI 2 (Cl)(1) 2 (CI)(1)

Crossfire Tubes CI 1 (Cl) 1 (Cl)


CI 1 (CI) 1 (CI)

End Covers CI 4 (CI) 4 (CI)










Note: Repair/replace intervals reflect current production (9F.05) hardware, unless otherwise noted, and

operation in accordance with manufacturer specifications. They represent initial recommended intervals in

the absence of operating and condition experience. For factored hours and starts of the repair intervals, refer

to Figure 39.





44

Compressor15th, 16th, 17th Stage

Compressor0-6th Stage

24.5°

24.5°

24.5°

24.5°99.5°204.5°

9.8°100.5°170.2°

10.5°100.5°160.5°

9.73°189.73°

12°102°155°

24.5°

1st Stg. LE 1st Stg. TE 2nd Stg. LE 2nd Stg. TE 3rd Stg. LE-Turbine


Secondary Inspection Access (Additional Stators and Nozzles)

Figure E-1 . Borescope inspection access locations for 6F machines

Compressor14th, 15th, 16th Stage

Compressor0-5th Stage

25°

25°

25°

66°13°

15° 151° 66° 62° 130° 64° 39°

25°

1st Stg. LE 1st Stg. TE 2nd Stg. LE 2nd Stg. TE 3rd Stg. LE-Turbine


Secondary Inspection Access (Additional Stators and Nozzles)

Figure E-2 . Borescope inspection access locations for 7F and 9F machines

E) Borescope Inspection Ports


F) Turning Gear/Ratchet Running Guidelines

Scenario Turning Gear (or Ratchet) Duration

Following Shutdown:

Case A.1 – Normal. Restart anticipated for >48 hours

Until wheelspace temperatures <150°F.(1) Rotor classified as unbowed. Minimum 24 hours.(2)

Case A.2 – Normal. Restart anticipated for <48 hours

Continuously until restart. Rotor unbowed.

Case B – Immediate rotor stop necessary. (Stop >20 minutes) Suspected rotating hardware damage or unit malfunction

None. Classified as bowed.

Before Startup:

Case C – Hot rotor, <20 minutes after rotor stop

0–1 hour(3)

Case D – Warm rotor, >20 minutes & <6 hours after rotor stop

4 hours

Case E.1 – Cold rotor, unbowed, off TG <48 hours

4 hours

Case E.2 – Cold rotor, unbowed, off TG >48 hours

6 hours

Case F – Cold rotor, bowed 8 hours(4)

During Extended Outage:

Case G – When idle 1 hour daily

Case H – Alternative No TG; 1 hour/week at full speed (no load).(5)

(1) Time depends on frame size and ambient environment.

(2) Cooldown cycle may be accelerated using starting device for forced cooldown. Turning gear, however,

is recommended method.

(3) 1 hour on turning gear is recommended following a trip, before restarting. For normal shutdowns, use

discretion.

(4) Follow bowed rotor startup procedure, which may be found in the unit O&M Manual.

(5) Avoids high cycling of lube oil pump during long outages.

Figure F-1 . Turning gear guidelines

46

G) B/E- and F-class Gas Turbine Naming

Class PlatformModel Designation

Prior model series

Prior model number

Prior names

F-class

6F

-MS6001(FA)

6101(FA) 6FA.01 6FA

6F.03 6111(FA) 6FA.03 6FA+e

- - - 6F Syngas -

7F

-

MS7001(FA)

7221(FA) 7FA.01 7FA

- 7231(FA) 7FA.02 7FA+

7F.03 7241(FA) 7FA.03 7FA+e

7F.04 - 7FA.04 -

- MS7001(FB) 7251(FB) 7FB.01 -

- - - 7F Syngas -

9F

-

MS9001(FA)

9311(FA) 9FA.01 9FA

- 9331(FA) 9FA.02 9FA+

9F.03 9351(FA) 9FA.03 9FA+e

-

MS9001(FB)

9371(FB) 9FB.01 -

- - 9FB.02 -

9F.05 - 9FB.03 -

Figure G-1 . F-class gas turbine naming

Class PlatformModel Designation

Prior model series

Prior model number

Prior names

B/E-class

6B

-

MS6001(B)

6521(B) -

- 6531(B) -

- 6541(B) -

- 6551(B) -

- 6561(B) -

- 6571(B) -

6B.03 6581(B) -

- - 6B PIP

7E

-

MS7001(EA)

7111(EA) -

- 7121(EA) -

7E.03 - 7EA PIP

9E

-

MS9001(E)

9151(E) -

- 9161(E) -

9E.03 9171(E) -

9E.03 - 9E PIP

9E.03 - 9E AGP

- - 9E Syngas

Figure G-2 . B/E-class gas turbine naming


List of FiguresFigure 1. Key factors affecting maintenance planning

Figure 2. Key technical reference documents to include in maintenance planning

Figure 3. 7E.03 gas turbine borescope inspection access locations

Figure 4. Borescope inspection planning

Figure 5. Causes of wear – hot gas path components

Figure 6. GE bases gas turbine maintenance requirements on independent counts of starts and hours

Figure 7. Hot gas path maintenance interval comparisons. GE method vs. EOH method

Figure 8. Maintenance factors

Figure 9. GE maintenance intervals

Figure 10. Estimated effect of fuel type on maintenance

Figure 11. Peak fire severity factors - natural gas and light distillates

Figure 12. Firing temperature and load relationship – heat recovery vs. simple cycle operation

Figure 13. Exhaust temperature control curve – dry vs. wet control 7E.03

Figure 14. Peaking-fast start factors

Figure 15. 7F.03 fast start factors

Figure 16. Turbine start/stop cycle – firing temperature changes

Figure 17. Second stage bucket transient temperature distribution

Figure 18. Bucket low cycle fatigue (LCF)

Figure 19. Low cycle fatigue life sensitivities – first stage bucket

Figure 20. Maintenance factor – trips from load

Figure 21. Maintenance factor – effect of start cycle maximum load level

Figure 22. Operation-related maintenance factors

Figure 23. 7F gas turbine typical operational profile

Figure 24. Baseline for starts-based maintenance factor definition

Figure 25. DLN combustion mode effect on combustion hardware life

Figure 26. F-class axial diffuser

Figure 27. E-class radial diffuser

Figure 28. Maintenance factor for overspeed operation ~constant TF

Figure 29. Deterioration of gas turbine performance due to compressor blade fouling

Figure 30. Long-term material property degradation in a wet environment

Figure 31. Susceptibility of compressor blade materials and coatings

Figure 32. 7E.03 heavy-duty gas turbine – disassembly inspections

Figure 33. Operating inspection data parameters

Figure 34. Combustion inspection – key elements

Figure 35. Hot gas path inspection – key elements

Figure 36. Stage 1 bucket oxidation and bucket life

Figure 37. Gas turbine major inspection – key elements

Figure 38. First-stage nozzle repair program: natural gas fired – continuous dry – base load

Figure 39. Baseline recommended inspection intervals: base load – natural gas fuel – dry

Figure 40. Combustion inspection hours-based maintenance factors

Figure 41. Combustion inspection starts-based maintenance factors

Figure 42. Hot gas path maintenance interval: hours-based criterion

Figure 43. Hot gas path maintenance interval: starts-based criterion

Figure 44. Rotor maintenance interval: hours-based criterion

Figure 45. Rotor maintenance interval: starts-based criterion

Figure D-1. Estimated repair and replacement intervals











Figure E-1. Borescope inspection access locations for 6F machines

Figure E-2. Borescope inspection access locations for 7F and 9F machines

Figure F-1. Turning gear guidelines

Figure G-1. F-class gas turbine naming

Figure G-2. B/E-class gas turbine naming

48

Revision History9/89 Original

8/91 Rev A

9/93 Rev B

3/95 Rev C

• Nozzle Clearances section removed

• Steam/Water Injection section added

• Cyclic Effects section added

5/96 Rev D

• Estimated Repair and Replacement Cycles added for F/FA

11/96 Rev E

11/98 Rev F

• Rotor Parts section added

• Estimated Repair and Replace Cycles added for FA+E

• Starts and hours-based rotor maintenance interval

equations added

9/00 Rev G

11/02 Rev H

• Estimated Repair and Replace Cycles updated and moved to

Appendix D

• Combustion Parts section added

• Inlet Fogging section added

1/03 Rev J

• Off Frequency Operation section added

10/04 Rev K

• GE design intent and predication upon proper components

and use added

• Added recommendation for coalescing filters installation

upstream of gas heaters

• Added recommendations for shutdown on gas fuel, dual fuel

transfers, and FSDS maintenance

• Trip from peak load maintenance factor added

• Lube Oil Cleanliness section added

• Inlet Fogging section updated to Moisture Intake

• Best practices for turning gear operation added

• Rapid Cool-down section added

• Procedural clarifications for HGP inspection added

• Added inspections for galling/fretting in turbine dovetails to

major inspection scope

• HGP factored starts calculation updated for application of

trip factors

• Turning gear maintenance factor removed for F-class hours-

based rotor life

• Removed reference to turning gear effects on cyclic

customers’ rotor lives

• HGP factored starts example added

• F-class borescope inspection access locations added

• Various HGP parts replacement cycles updated and

additional 6B table added

• Revision History added

11/09 Rev L

• Updated text throughout

• Casing section added

• Exhaust Diffuser section added

• Added new Fig. 26: F-class axial diffuser

• Added new Fig. 27: E-class radial diffuser

• Revised Fig. 3, 5, 7, 8, 11, 19, 20, 23, 35, 37, 38, 40, 41, 42, 43,

44, E-1, and E-2

• Appendix D – updated repair and replacement cycles

• Added PG6111 (FA) Estimated repair and replacement cycles

• Added PG9371 (FB) Estimated repair and replacement cycles

10/10 Correction L.1

• Corrected Fig. D-4, D-5, and D-11 combustion hardware

repair and replacement cycles

2/15 Rev M

• Updated text throughout

• Added Fig. 14, 15, 25

• Revised Fig. 8, 10, 12, 22, 29, 34, 35, 37, 39, 41, 42, 43, 44, 45

• Updated Appendix A

• Updated Appendix D

• Added 7F.04 Estimated repair and replacement intervals

• Added Appendix G

4

GTD-222, GTD-241, GTD-450, GECC-1, and Extendor are trademarks of the General Electric Company.

©2015, General Electric Company. All rights reserved.

GER-3620M (02/15)


APPENDIX K SCR AND OXIDATION CATALYST OPERATING AND MAINTENANCE DETAILS

SCR Control Philosophy (Preliminary)

Client: GE Gas Power Systems

EKI Job#: 186216

Doc No: XXXXXX-XXX

101 Milliken Ave

Ontario, CA 91761

Phone: (909) 621-7599

Fax: (909) 621-7899

DESCRIPTIONREV DATECHECKED

BY

APPROVED

BYMADE BY

1

INTRODUCTION This manual presents general information on the function, construction, control, operation, and

maintenance of the EnviroKinetics SCR systems at the xxx Combined Power Plant in xxx. This is not a

comprehensive manual and should be used in conjunction with other equipment manuals. When

interfacing with existing equipment, those respective manuals should be consulted as well.

BACKGROUND With the increased use of fossil fuels to generate electricity, Federal and Local Governments have

imposed regulations to limit nitrogen oxide (NOx) emissions from combustion equipment. The nitrogen

contained in fossil fuels combines with oxygen during combustion to create NOx. If released to the

atmosphere, the NOx (NO, NO2) combine with available oxygen and water to form nitric acid (HNO3). The

nitric acid returns to the earth in the form of acid rain, which is harmful to our environment. The xxx SCR

utilizes an EnviroKinetics Selective Catalytic Reduction (SCR) system to reduce NOx in the flue gas.

OPERATING THEORY The flue gas contains nitrogen oxides (NOx) that form during fuel combustion. These nitrogen oxides can

be converted to nitrogen gas and water vapor using ammonia and a catalyst. Ammonia (NH3) is injected

into the flue gas upstream of the catalyst through a special injection grid designed to promote even

ammonia distribution and mixing with the flue gas. The ammonia acts as a reducing agent as the flue gas

passes through the catalyst. The NOx (NO, NO2) contained in the flue gas is converted into N2 and H2O.

The fundamental chemical reactions are:

4 NO + 4 NH3 + O2 4 N2 + 6 H2O

6 NO2 + 8 NH3 7 N2 + 12 H2O

NO + NO2 + 2 NH3 2 N2 + 3 H2O

2

The catalyst is specifically selected for each unit’s flue gas composition and promotes the chemical

reaction.

Ammonia (NH3) is introduced into the flue gas upstream of the reactor through an injection grid. The grid

is designed to control the flow of ammonia to each region of the reactor to ensure that the ratio of NH3

and NOx is uniform at the catalyst inlet.

3

EQUIPMENT DESCRIPTION

DESIGN CONDITIONS Item Units Design Conditions

Unit Type HRSG

Number of Units xxx

Unit Fuel Type xxx

Flue Gas

Flue Gas Flow Rate lb/hr xxx

Flue Gas Temperature °F xxx

Composition

O2 % vol xxx

H2O % vol xxx

CO2 % vol xxx

N2 % vol xxx

SOx ppmv @15% O2 dry xxx

Flue Gas Emissions

Inlet NOx ppmv @ 15% O2 dry xxx

Performance Requirements

Outlet NOx ppmv @ 15% O2 dry xxx

Outlet NH3 ppmv @ 15% O2 dry xxx

Pressure Drop Through SCR System

inwc xxx

Ammonia Supply

Ammonia Type xx% Aqueous

Supply Condition Liquid

Maximum Ammonia Flow Rate lb/hr xxx

Ammonia Supply Pressure psig xxx

FLUE GAS FLOW PATH Flue gas enters the reactor over a range of temperatures from xxx °F to xxx °F. The flue gas travels

through the AIG and static mixers that are designed to provide optimal distribution of ammonia

throughout the reactor cross section. The ammonia-laden flue gas arrives at the catalyst where the NOx

reacts with ammonia as it passes through the catalyst. Additional heat is recovered from the flue gas

before being discharged to the stack. Instruments used for monitoring flue gas conditions include a

differential pressure transmitter for monitoring pressure drop across the catalyst and thermocouples at

the SCR inlet for monitoring flue gas temperature.

AMMONIA FLOW CONTROL SYSTEM The reaction chemistry of the SCR requires flow control of the ammonia reagent. This is achieved by the

Ammonia Flow Control Unit (AFCU) skid. The AFCU supplies a mixture of ammonia vapor and circulated

hot flue gas to the ammonia injection grid (AIG). The AFCU skid is shop-assembled, pre-piped, and pre-

wired. The skid is operated and controlled by the plant control system.

4

The AFCU has particular features that need to be noted.

Block and drain valves on the aqueous ammonia line to allow for isolation of the ammonia from

the HRSG during shutdown periods for maintenance of the NFPA 85 Purge Credit condition.

An electric heater for rapid starting of the SCR system is provided on the recirculated flue gas.

This locally-operated heater raises the temperature of the recirculated gas during start-up so that

the vaporizer can begin to operate as soon as the SCR catalyst flue gas temperature reaches

350°F. As the temperature of the recirculated flue gas increases during HRSG start-up, the output

of the electric heater will modulate down until the temperature of the incoming recirculated flue

gas exceeds the minimum normal catalyst operating temperature, at which point the heater will

shut off

A vaporizer tower, packed with heat and mass transfer media, provides for efficient vaporization

of the aqueous ammonia into vapor. Flue gas flows vertically up through the media with the

aqueous ammonia sprayed down into the media. The flow and temperature of the circulated flue

gas is enough to vaporize all of the ammonia required for the SCR operation.

Two 100% hot-gas recirculation fans have been provided on the skid that siphon hot flue gas

from the HRSG ducting for use in vaporizing the aqueous ammonia. These fans are provided with

manual, 98% shut-off dampers on their suction and discharge connections. The manual dampers

are for maintenance purposes only and need to remain open during operation to keep the stand-

by fan in a “ready-to-start” condition as automatic and remote fan switch over can occur during

unit operations. A 98% shut-off backdraft damper is provided on each fan discharge. This

intentionally allows some hot-gas to leak back into the fan housing to keep the stand-by fan

warm and ready for operation. Depending on plant operating practices, it may be preferable to

alternate which fan is in operation, but at a minimum each fan shaft needs to be rotated 180°

once per month if left idle.

Variable Frequency Drives (VFDs) for each of the dilution fans allow for fan speed to be

modulated to avoid excess velocity in the vaporizer (flooding) and to prevent the offline fan’s

impeller from remaining idle after a trip.

Ammonia is delivered to the AFCU, filtered, and metered by a flow meter that provides a feedback signal

to the ammonia flow control valve. The amount of ammonia required is determined by feedback from a

NOx analyzer on the stack.

Hot flue gas is circulated from the HRSG duct via the ammonia dilution fans. The fans discharge the flue

gas through the start-up heater and the vaporizer tower, and return it, with ammonia, to the AIG. The

fans are operated with constant output from the Variable Frequency Drive. As previously described, the

start-up heater is only intended to operate during the start-up period so that ammonia vapor can be

delivered when the temperature of the flue gas entering the SCR catalyst is at least 350 °F.

Ammonia is injected into the hot flue gas stream in the vaporizer where it is completely vaporized.

Instrumentation monitors the vaporizer for differential pressure and level. High differential pressure

5

indicates flooding (flue gas velocity too high). Liquid accumulation in the bottom of the tower, as

indicated by the level switch, indicates incomplete vaporization from over-injection or inadequate gas

circulation.

AMMONIA SUPPLY The aqueous ammonia liquid is fed to the AFCU via the ammonia supply line.

Reagent-grade 19% by weight aqueous ammonia of the following specification is required for this system:

Property Requirement

Ammonia Assay 19%

Appearance Colorless and free of suspended matter or sediment

Residue After Ignition < 0.002% weight

Total Non-Volatile Matter < 0.05% weight

Halides < 0.5 ppmw

Alkali Metals < 1.0 ppmw

Total Sulfur < 2.0 ppmw

Phosphates < 2.0 ppmw

Iron < 0.2 ppmw

Heavy Metals < 0.5 ppmw

Makeup Solution Demineralized or deionized water

MAJOR COMPONENTS The system can be divided into three major components:

1. Catalytic Reactor and Ductwork

2. Ammonia Supply System

3. Aqueous Ammonia Vaporization System

SCR REACTOR The SCR reactor utilizes one fixed catalyst bed, horizontal flow reactor with provision for a future 50%

catalyst bed.

The reactor assembly consists of a reinforced casing with structural supports designed for internal

pressure, seismic loading, wind loading, catalyst loading, and thermal stress (design by others). The

reactor housing has inside dimensions of approximately xxx ft tall x xxx ft wide and is constructed of

carbon steel plate. The reactor is insulated internally. An access opening for catalyst loading and removal

is located at the roof.

6

CATALYST The catalyst used for this reactor is highly reactive to NOx. The catalyst units are preassembled into

catalyst modules for ease of shipment and installation.

The total installed catalyst bed consists of xxx catalyst modules with a single layer cross-sectional

arrangement of xxx modules wide by xxx modules high. The catalyst bed is arranged for horizontal flow.

Dimension of each installed catalyst section is approximately xxx’ tall by xxx’ wide by xxx’ deep.

The catalyst should be kept as dry as possible during installation, storage or actual operation. Catalyst

wetting will result in a permanent decrease in catalyst activity and may void the catalyst warranty.

WARNING: The presence of some elements at some level of concentration on the surface of the catalyst

can poison the catalyst and cause permanent deterioration. For this reason, care should be taken to avoid

introducing the following compounds and elements into the flue gas stream ahead of the SCR.

Sodium Platinum

Potassium Palladium

Halogen Compounds Rhodium

Arsenic Ruthenium

Silicon Osmium

Iridium

CATALYST SAMPLES Catalyst can be sampled periodically to monitor catalyst performance. If a program is to be established, it

is recommended that the catalyst samples be tested at twelve month intervals to assure that the catalyst

is performing as expected and to help predict expected catalyst life and replacement time. If testing

shows an unusually high deactivation rate, a consequent investigation can determine the cause and

prevent premature replacement of catalyst.

AMMONIA INJECTION GRID There is one ammonia-air injection grid, originating at the vaporizer discharge on the AFCU. The

ammonia-air injection system is located upstream of the SCR and consists of a feed line that is external to

the ductwork, with a grid of injection pipes containing injection orifices located inside the ductwork (AIG).

Horizontal lances supply ammonia-air mixture to form the grid. The lances are grouped externally with

sub-headers, each with a balancing valve and flow indication. While these valves are intended to remain

fully open, they may be used to balance or adjust the ammonia distribution. These sub-headers are, in

turn, connected to the main header originating at the AFCU vaporizer.

7

MAINTENANCE The system shall be operated and maintained under a planned program of periodic inspection with the

accompanying repair and replacement of parts needed to achieve the maximum availability and reliability

of the system.

The inspection results and maintenance records should be compiled and be accessible at all times.

Results of these inspections are used to determine the necessity for equipment repair or replacement.

CATALYST MAINTENANCE Catalyst protection must be practiced constantly by maintenance personnel when inspecting or

servicing the reactor. Do not physically the catalyst directly during work inside the reactor as

catalyst damage may occur. Temporary scaffolding and footplates are required to avoid the

contact of any direct acting loads onto the catalyst modules or elements. As a precaution, a shield

shall be installed over the catalyst layer to protect the catalyst during maintenance work.

The catalyst must not be exposed to water or other moisture throughout all operating and

storage conditions to prevent catalyst deterioration. This problem can be easily prevented by

careful work and a daily check of the SCR system. All open inspection ports are to be shielded

from the rain.

Should rain enter through a cracked duct or open access door, dry the catalyst as soon as

possible. Flue gas water vapor during startup, shutdown and normal operations is not a concern.

Never wash the catalyst with water.

EQUIPMENT MAINTENANCE Periodic maintenance of the equipment will keep the equipment in excellent condition and in service for

its intended use. All equipment shall be inspected and maintained in accordance with the manufacturer's

instructions. Development of the practical maintenance program is to be based on the site and plant

conditions.

8

RECOMMENDED MAINTENANCE SCHEDULE The following table is a recommended maintenance schedule based on typical operation. Detailed

maintenance procedures for each piece of equipment are available in the manufacturer's data books.

WARNING: Review all recommended safety practices before performing maintenance on any piece of

equipment.

# Equipment Check Points

Du

rin

g O

per

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Wh

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fflin

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Interval

Ever

y Sh

ift

Dai

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Wee

kly

Mo

nth

ly

Year

ly

Oth

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1

Ductwork

Inspection for gas leakage X X

2 Check for abnormal vibration X X

3 Check for signs of color change X X

4 Ammonia

Injection Grid

Check for plugging due to foreign matter inside of nozzles

X X

5 Check for deformation or corrosion X X

6

SCR Reactor

Inspect for gas leakage X X

7 Check for catalyst layer shifting X X

8 Check for corrosion X X

9 Check for dust adhesion to catalyst and clean (if necessary)

X X

10 Check for deformation or movement of sealing device

X X

11 Check total sealing system X X

12 Check for deformation or distortion of structures

X X

13

Catalyst (Visual Check)

Check for deformation of module and catalyst elements

X X

14 Check for dust accumulation and blockage

X X

15 Check catalyst for dust erosion X X

16 Ammonia

Header Confirmation of correct flow at header by pressure drop

X X

17 Vaporizer Check for gas leakage X X

9


Du

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Interval

Ever

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Year

ly

Oth

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18 Check for blockage X X X

19

Dilution Air Fans

Check for sound or vibration at blower and motor

X X

20 Application of grease X X

21 Overhaul fan

X X

22

Control Valve, Shut-Off Valve

Confirm valves are function properly X X

23 Check pressure and temperature settings

X X

24 Check for leakage X X

25 Check or replace gland packings X X

27

Pressure Switches

Visual check for electrical sparking X X

28 Check electrical terminals torque and tightness

X X

29 Measure insulation X X

30 Verify set-point X X

31

Control Panels

Confirmation of annunciator and indicator lamps

X X

32 Check electrical wires for wear X X

33 Check and clean panel internals X X

34 Check electrical terminals torque and tightness

X X

35 Logic sequence test X X

36

Manual Process Controllers

Check electrical terminals torque and tightness

X X

37 Check and clean instruments X X

38 Confirm behavior of control loops X X

39 Thermocouples Remove adhered material X X X

10


Du

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Interval

Ever

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40 Calibration test X X

41

Pressure Gauges

Confirmation of indicated values X X X

42 Calibration test X X X

43 Check for damage X X

44

Piping

Check for leakage X X

45 Check for fouling X X

46 Check for vibration X X

WARNING: Before entering into and working inside the SCR reactor or ductwork, verify the following

conditions in addition to any plant-specific requirements:

Inside temperature must be lower than 104 °F.

Oxygen concentration in flue duct must be higher than 20%.

Plant is shut down and locked out to prevent restart.

The valves on the lines for ammonia, nitrogen, combustible gases and other hazardous fluids are to be

closed and locked out.

The ammonia line must be completely purged.

Depressurize all equipment and piping to atmospheric pressure before opening them.

During maintenance work, FRESH AIR shall be continuously ventilated by a fan or other suitable

equipment.

Before starting any repair work and especially when using open flames, use a combustible gas detector

to confirm that no combustible gases are present in the work area.

Always work in pairs with one remaining as an observer outside of the work/inspection area(s).

When performing work on electrical equipment, follow the instructions below to prevent electric shock

and/or damage to the equipment.

OPEN the circuit breaker for electrical equipment completely and place a safety tag in a safe,

noticeable location.

CONFIRM that the electrical power supply is absolutely isolated by using a circuit tester.

CONNECT the earth wire firmly to the ground to prevent electric shocks.

11

NOTICE: Do not perform maintenance on instruments such as transmitters, analyzers or controllers without

reading and understanding the instruction manuals. Otherwise, personal injury or damage to the

instruments may result.

Prior to starting the maintenance work on the ammonia injection system, DEPRESSURIZE and PURGE the

system using nitrogen or fresh air to secure safe conditions.

If any repairs are necessary on the pressurized section and/or high temperature service section, ISOLATE

the system or STOP OPERATION to reduce the internal pressure to an ATMOSPHERIC level and to bring

the plant temperature down to a SAFE level (120°F) before initiating repairs.

For fire explosion prevention, fire-fighting equipment shall be readily available near the equipment being

repaired. The equipment shall be properly grounded to release static electricity before starting work.

12

PERFORMANCE EVALUATION Although catalyst deterioration has been taken into account in the design, it has been found that catalyst

activity deteriorates gradually with operation time. Initial deterioration that occurs within the first few

thousand operating hours after the first start-up is somewhat more rapid.

The cause of deterioration cannot be quantitatively determined due to several causes, such as:

Decrease of catalyst specific surface area due to sintering in elevated temperatures

Effects of catalyst poisons which are usually contained in flue gas

The impact of each factor is very small. Regardless, the deterioration rate will not change abruptly as long

as the operating conditions are constant.

The expected efficiency of the SCR system should be evaluated based upon the daily operating data,

periodic performance tests, and examination of the catalyst samples.

The following methods can be used to evaluate catalyst performance and estimate remaining catalyst life:

Evaluation of operating data

Periodic system efficiency tests

Analysis of catalyst samples

EVALUATION OF OPERATION DATA Evaluation of system performance is to be done by tracking key operating data on a regular basis. The

operating data at the design conditions are preferable for calculation of system efficiency. Any abnormal

occurrences (ex. process upsets or unit trips) should be recorded.

The following key operating data should be recorded on half-hourly (minimum) intervals. This data should

be stored and readily accessible throughout the warranty period.

Parameter Metric Units Imperial Units

Fuel Flow Rate kg/hr or NM3/hr lb/hr or ft3/min

Gas Flow Rate Entering the SCR kg/hr or NM3/hr lb/hr or ft3/min

O2 Concentration at Reactor Inlet % volume, dry % volume, dry

NOx Mass Flow at Reactor Inlet kg/hr lb/hr

Outlet NOx Setpoint mg/NM3 or ppmvdc ppmvdc

Calculated NOx Reduction % %

13

Total Catalyst Operating Hours hours hours

NOx Concentration at Reactor Inlet mg/NM3 or ppmvdc ppmvdc

NOx Concentration at Stack mg/NM3 or ppmvdc ppmvdc

NH3 Flow Rate kg/hr lb/hr

Flue Gas Temperature at Reactor

Inlet °C °F

Dilution Air Flow for NH3 Injection kg/hr or NM3/hr lb/hr or ft3/min

Differential Pressure Across

Catalyst kPa inH2O

Ammonia Vaporizer Outlet

Temperature °C °F

PERIODIC EFFICIENCY TEST It is recommended to carry out system efficiency testing every 3,000 operating hours. The tendency of

efficiency change with operating time should be reviewed along with a complete evaluation of operating

data. Any abnormal trends or problems should be investigated.

ANALYSIS OF CATALYST SAMPLES Periodic testing can be performed on catalyst samples to help predict remaining catalyst life and

replacement time.

This periodic testing enables the supplier to more accurately define the extent of catalyst deterioration

during actual operation and to determine the required reactivation procedures.

Johnson Matthey

Temperature (Degrees Farenheit)

A p p l i c a t i o n s :

>> Combined Cycle Gas Turbines>> Simple Cycle Gas Turbines

PerformanceJohnson Matthey pioneered Oxidation Catalyst for gas turbines in the 1970’s. Since then, Oxidation Catalysts have been installed in some of the most environmentally challenging applications, consistently providing greater than 90% destruc-tion of CO, VOCs, formaldehyde and other toxic compounds. Our core expertise in catalysis has allowed Johnson Matthey to stay at the cutting edge of new catalyst development meeting the chal-lenges of ever increasing regulatory requirements.

Our Oxidation Catalysts are formulated with Platinum Group Metals (PGM’s) to achieve maximum conversion of pollutants at gas turbine temperatures, whether it is a simple cycle or combined cycle gas turbine. Our high activity catalyst plus flow through metal monolith design delivers the smallest catalyst package and the lowest back pressure in the industry. The chart to the right illustrates the level of conversion achievable. Side reactions such as NO to NO2 are minimized.

RegenerationJohnson Matthey gas turbine Oxidation Catalysts have an established durability of 10 or more years of continuous operation. Catalytic performance can be easily maintained and restored, if necessary, through washing. And at the end of the effective life of the catalyst, Johnson Matthey closes the loop at its West Deptford, NJ facility where spent catalyst can be recycled and precious metal value is credited to you. Johnson Matthey also provides field support during catalyst inspections, bed rotations, and partial bed replacements.

DependabilityYou can count on Johnson Matthey. Founded in 1817, we are the global leader in environmental catalyst technology with more than 40 years of experience in environmental emissions control catalysts for mobile and stationary sources. We are committed to developing and supplying the highest quality product available.

For the Control of CO, VOCs & HAPs

Gas Turbine Oxidation Catalyst

100

95

90

85

80

75

CO C

onve

rsio

n

200 300 400 500 600 700 800 900 1000

OXIDATION CATALYST PERFORMANCE

• 900 Forge Avenue, Suite 100, Audubon, PA 19403-2305, (484) 320-2125• 31 Journey, Suite 250, Aliso Viejo, CA 92656, (949) 297-5200

• 1121 Alderman Drive, Suite 204, Alpharetta, GA 30005, (678) 341-7522

©2013 Johnson Matthey

www.jmsec.com

1.3 Oxidation Catalyst

1.2.1 CO AND HC CATALYST REACTIONS

Carbon monoxide and unburned hydrocarbons, in the presence of sufficient oxygen, are

oxidized over the catalyst to produce carbon dioxide and water vapor:

2CO + O2 ----> 2CO2

CH4 + 2O2 ----> CO2 + 2H2O

H2 + 2O2 ---->2H2O

1.4 Catalyst De Activation

A catalyst participates in and accelerates a chemical reaction, but remains unchanged when

the reaction is complete. In theory, a catalyst can have an infinite life, but in practice,

various factors contribute to eventual deactivation.

Johnson Matthey catalysts are formulated to provide maximum operating life for the fuel

compositions and containment levels expected.

Catalyst deactivation is caused by the physical and chemical interaction of the catalyst with

the gas stream.

1.4.1 Physical Deactivation

Physical deactivation can occur by thermal degradation of the catalyst or by fouling.

a. Catalyst Thermal Degradation

Thermal degradation of the catalyst is caused by sintering, i.e., the loss of active

catalyst surface area due to exposure to excessively high temperatures. Sintering

occurs when the heat of the gas stream causes the catalyst crystals to diffuse and

agglomerate within the wash-coat. This agglomeration reduces the active surface area.

b. Catalyst Fouling

Catalyst fouling or masking occurs when solid particulates from the gas stream adhere

to the catalyst surface, preventing the reactants from reaching the catalyst. The

severity of the fouling is dependent on both the nature and concentration of the

particulates in the individual gas stream. The loss of catalyst activity due to fouling

can usually be recovered by physically removing the fouling agent from the catalyst.

This is normally accomplished by cleaning procedures such as vacuuming or sweeping

the catalyst clean with compressed air. The optimum cleaning procedure and required

cleaning frequency will depend on the exact nature and concentration of the

particulates in the installation. Please consult with JM before attempting to clean the

catalyst.

NOTE: Every effort should be made to avoid silica contamination of the catalyst.

Silica is not volatile, and once deposited on the catalyst surface it may be

impossible to remove. If sufficient silica builds up, it will form a layer

which will prevent the gas stream from contacting active catalyst sites,

reducing catalyst performance.

1.4.2 CHEMICAL DEACTIVATION

Chemical deactivation is caused by poisoning.

a. When elements in the gas stream react with the catalyst causing a reduction in

catalytic activity, the catalyst is said to be poisoned.

It is usually not possible to recover lost activity from a catalyst which has

been poisoned. See Section 1.4 for a listing of materials which can cause

poisoning for oxidation catalyst.

The loss of catalytic activity due to poisoning occurs gradually over time as

poisons accumulate in the catalyst. The rate at which catalyst activity is lost

depends upon the concentration of the poison in the gas stream. Increasing

the inlet gas temperature during the life of the catalyst can compensate for

some loss of activity.

It is possible for catalyst poisons to form complexes with other elements in

the gas stream, thus reducing their tendency to poison the catalyst. For

example, lead and phosphorus in combination have much less effect on the

catalyst than either element separately. The presence of alkali metals and

alkaline earths is also very effective in reducing phosphorous poisoning.

The maximum permissible concentrations of contaminants are presented in

the Section 1.4 of this manual. To maintain catalyst warranties, these levels

must never be exceeded.

b. Catalyst Inhibition

Catalyst inhibition occurs when contaminant elements in the gas stream

chemically adhere to the catalyst causing a reduction in catalytic activity.

Sulfur dioxide and concentrations of halogenated compounds - such as fluoro-

hydrocarbons, chloro-hydrocarbons and brominated hydrocarbons - are all

catalyst inhibitors. Their molecules are relatively large, and when they adhere

to the catalyst molecules, they block the pollutants from reacting with the

catalyst. Catalyst inhibition can then be regarded as a chemical form of

masking.

Catalyst activity can usually be restored by eliminating the inhibitor from the

gas stream, by cycling the system at a higher temperature, or by a

combination of the two. Activity loss will occur rapidly when the catalyst is

exposed to a contaminated gas stream. This loss can be recovered by running

the system at an elevated temperature (typically 100oF/38°C above normal

operating temperature) for several hours. Please contact Johnson Matthey for

assistance with this procedure.

If SO2 and SO

3 are allowed to condense within the catalyst honeycomb

structure, sulfuric acid mist can form and corrode the catalyst support and

permanently lower activity.

1.5 Catalyst Operating Limits

1.5.1 OXIDATION CATALYST

Maximum continuous operating temperature: 750°F

Maximum intermittent operating temperature: (15 min/24 hrs) 850°F

Catalyst poisons:

Lead Arsenic Sodium Iron Silicon

Bismuth Antimony Potassium Chromium Sulfur

Mercury Phosphorus Copper Zinc

Calcium Magnesium Nickel Tin

The cumulative concentration of these poisons must not exceed 10 g/ft3.

Chlorinated compounds must not exceed 10 ppm. Silicon compounds must not be

present.

1.6 Catalyst Regeneration

The maintenance for typical catalyst installation will consist of:

1. Physical inspection every 3-6 months of operation.

2. Vacuuming as needed to remove ash build up and debris associated with increased

backpressure. Fouling, especially by particulates trapped from the gas stream, can

often be remedied by vacuuming the channels clear. This can be done with the

catalyst in place if there is sufficient access room. The air jet should be in the

direction opposite the normal flow through the catalyst.

Note: Johnson Matthey does not recommend blowing the catalyst clear with

compressed air as excessive pressure or contaminated air can cause irrevocable

damage to the catalyst.

3 Approved washing procedure as needed to maintain performance. See Appendix A.

Note: The maximum allowable number of washings is four (4) during the warranty

period of the catalyst.

1.7 Catalyst Testing

1.7.1 TEST CORES

Test cores enable Johnson Matthey to accurately monitor catalyst condition for

boiler operating fuels and operating temperature/flow conditions. This will allow

Johnson Matthey to accurately assess catalyst durability and performance, and to

report results to the customer.

The test samples are a 1" diameter cylinder cores of the catalyst taken in field from

the panel.

The test core location in the catalyst panel should be recorded along with the date

of the installation and site operating hours at the time of removal.

1.7.2. CORE REMOVAL SCHEDULE

It is recommended to test a core sample for catalyst activity after every 8,000 hours

of operation (during boiler shutdown periods):

1.8 Johnson Matthey Facilities

Johnson Matthey maintains complete physical facilities and has personnel experienced in

the analysis and evaluation of catalyst in all phases of catalyst technology. This ensures:

The selection of an optimum catalyst formulation for specific customer requirements.

Proper production control.

Catalyst operating performance analysis.

To completely assist our customers and to ensure optimum catalyst performance, Technical

Service personnel are on call to help solve problems that may develop with an on-stream

situation. The technical service engineer can usually be on the way to your plant within

hours of a request for assistance.

1.8.1 CATALYST TESTING

Analytical Capability

- Atomic Absorption

- X-ray Fluorescence

- GYP Emission Spectrograph

- Wet Chemical Analysis

These tests are used to determine the concentration of active catalyst elements,

impurity levels, and poison accumulation levels in the catalysts.

Electron Microscope with Energy Dispersive XRF

This test is used to examine catalyst at high magnification and discovers

changes in physical properties of the catalyst, determining the composition and

distribution of fouling particulates and inhibitors, and their effects.

Optical Microscope

This test is used to examine catalyst integrity and adhesion to the substrate as

well as physical changes due to excessive operating temperatures and thermal

degradation.

BET Surface Area

This test is used to determine the total surface area which retains catalyst.

Changes can be used to determine the maximum temperature to which the

catalyst has been exposed. Loss of surface area with a known operating on-

stream time can be used to determine remaining catalyst life.

X-Ray Diffraction

This test is used to determine the crystallographic phase of catalysts and

catalyst components, and to determine maximum catalyst exposure temperature

and mechanisms of poisoning.

Mercury Porosimeter

This test is used to determine pore size distribution of the catalyst support

structure.

Simulated Catalyst Activity Test (SCAT)

This test measures catalyst activity under precise conditions, including

controlled flow rate, inlet temperature, and gas composition, over laboratory

scale catalyst samples. Inlet and outlet gas streams are analyzed for O2, CO,

SOx , CO2

, hydrocarbons, oxides of nitrogen, H2, H

2O, and temperature. This

permits measurement of all characteristics of catalyst performance under

simulated operating conditions.

1.9 Catalyst Storage Requirements

If the catalyst will remain in storage for along periods of time, some precautions should be

taken to ensure that the catalyst will retain its activity.

1.9.1 OXIDATION CATALYST

The oxidation catalyst is not soluble in water so no special wrapping is required.

However, the catalyst surface should be protected by crating the panels in plywood.

1.10 Performance Testing

Measurement of carbon monoxide should be conducted according to EPA Method 10.


APPENDIX L AUXILIARY EQUIPMENT MANUFACTURER SPECIFICATION SHEETS

Nebraska D seriesTechNical DaTa iNformaTioN PackeT

Table of Contents

Cleaver-Brooks Nebraska D Boiler Series Technical Data Sheets 100D Series ................................................................. 3-4 200D Series ................................................................. 5-6 300D Series ................................................................. 7-8 400D Series ............................................................... 9-10 500D Series ............................................................. 11-12 600D Series ............................................................. 13-14

ProFire Burner Series Technical Data Sheets ProFire D126, LND145 .................................................. 15 ProFire D252, LND300 .................................................. 16 ProFire D Series Dimension Tables ............................... 17 ProFire LND Series Dimension Tables .......................... 18 ProFire XL Burner General Data ................................... 19 ProFire XL378, LNXL378 ............................................... 20 ProFire XL504, LNXL504 ............................................... 21 ProFire XL630, LNXL630 ............................................... 22 ProFire XL Series Dimension Tables ............................. 23 ProFire LNXL Series Dimension Tables ........................ 24

NXT Burner Series Technical Data Sheets NXT Burner General Data ............................................. 25 NXT-048 ......................................................................... 26 NXT-060 ......................................................................... 27 NXT-072 ......................................................................... 28 NXT-085 ......................................................................... 29 NXT-097 ......................................................................... 30 NXT-109 ......................................................................... 31 NXT-120 ......................................................................... 32 NXT-132 ......................................................................... 33 NXT-144 ......................................................................... 34 NXT-162 ......................................................................... 35 NXT-180 ......................................................................... 36 NXT-210 ......................................................................... 37 NXT-240 ......................................................................... 38 NXT-271 ......................................................................... 39 NXT-048 to NXT-109 Dimension Tables ........................ 40 NXT-120 to NXT-271 Dimension Tables .................. 41–42

Boiler Dimensions CBND-10P-100D-25 CBND-20P-100D-35 CBND-30P-100D-40

Capacity 10,000 lb/h 20,000 lb/h 30,000 lb/h

Upper Drum 36 in 36 in 36 in

Lower Drum 24 in 24 in 24 in

Length Over Casing 10 ft 13 ft 4 in 15 ft

Width, Gas Outlet 12 3/4 in 16 3/4 in 28 3/4 in

Height, Gas Outlet 67 in 67 in 67 in

Front to CL Gas Outlet 12 5/8 in 14 5/8 in 20 5/8 in

Shipping Height 11 ft 5 in 11 ft 5 in 11 ft 5 in

Overall Width 9 ft 8 1/2 in 9 ft 8 1/2 in 9 ft 8 1/2 in

Min Operating Pressure 100 psig 100 psig 100 psig

Cleaver-Brooks Nebraska DSteam-Ready 100D Series

Capacities and Specifications

3

* Shown with NATCOM NXT Burner. For 100D Series, ProFire Burner is standard feature.

Economizer

Pressure Vessel

Design Pressure up to 375 psig • • •

Hinged Manways • • •

Lower Drum Heating Coil (LDHC) • • •

Tubes 2 in 178-A.120 Wall–PV • • •


Operating Pressure - 200–325 psig • • •

Auxiliary Equipment

Platforms & Ladders - Boiler • • •

Platforms & Ladders - Stack ◊ ◊ ◊

Platform & Ladder - Economizer ◊ ◊ ◊

Sootblowers • • •

Variable Frequency Drive • • •

Selective Catalytic Reduction ◊ ◊ ◊

Controls

Parallel Positioning (PP) • • •

Fully Metered (FM) ◊ ◊ ◊

Eye-Hye® Remote Drum Level Transmitter

• • •

Feedwater 2- or 3-Element • • •

O2 Trim • • •

O2 Analyzer • • •

Pressure Vessel

Design Pressure 250 • • •

Tubes 2 in 178-A.105 Wall • • •

Steam Quality 0.5% Moist • • •

RH - Right Hand • • •

LH - Left Hand • • •

AL - Aluminum Casing • • •


Auxiliary Equipment

Steam Trim • • •

Feedwater Trim • • •

Boiler Platform Clips • • •

Economizer • • •

Stack - 40 ft, 50 ft, 60 ft ◊ ◊ ◊

Controls

Hawk 5000 Control • • •

Single Point (SP) • • •

Feedwater - Single Element • • •

Burner

ProFire D • •

ProFire XL (See ProFire Burner technical data sheet for detailed information)

•

Standard Features Optional FeaturesCB

ND

-10P

-100

D-2

5

(Cap

acity

10,

000

lb/h

)

CB

ND

-10P

-100

D-2

5

(Cap

acity

10,

000

lb/h

)

CB

ND

-20P

-100

D-3

5

(Cap

acity

20,

000

lb/h

)

CB

ND

-20P

-100

D-3

5

(Cap

acity

20,

000

lb/h

)

CB

ND

-30P

-100

D-4

0

(Cap

acity

30,

000

lb/h

)

CB

ND

-30P

-100

D-4

0

(Cap

acity

30,

000

lb/h

)

◊ Contact us for details.

E1 Economizers CBND-10P-100D-25 CBND-20P-100D-35 CBND-30P-100D-40

Fin Height 0.75 in 0.75 in 0.75 in

Transverse Pitch 4.5 in 4.5 in 4.5 in

Longitudinal Pitch 4.5 in 4.5 in 4.5 in

Segment 0.172 in 0.172 in 0.172 in

Fin Thickness 0.05 in 0.05 in 0.05 in

Effective Length 7 ft 7 ft 7 ft

Material Carbon Steel Carbon Steel Carbon Steel

Fins Serrated Serrated Serrated

Bends Cold Bent Cold Bent Cold Bent

Fuel NG & #2 oil NG & #2 oil NG & #2 oil

Economizer Trim

Economizer feedwater bypass 1.25 in 1.5 in 2 in

Header vent valve 1 in 1 in 1 in

Header drain valve 1 in 1 in 1 in

STANDARD EQUIPMENT ALSO INCLUDED

Temperature gauges – feedwater inlet/outlet

Temperature thermowell – feedwater inlet/outlet

Temperature gauges – flue gas inlet/outlet

Temperature thermowell – flue gas inlet/outlet

4

Boiler Dimensions CBND-40E-200D-40CBND-40P-200D-40

CBND-50E-200D-45CBND-50P-200D-45

CBND-60E-200D-50




Length Over Casing 15 ft 16 ft 8 in 18 ft 4 in


Height, Gas Outlet 79 3/4 in 79 3/4 in 79 3/4 in


Shipping Height 13 ft 7 5/16 in 13 ft 7 5/16 in 13 ft 7 5/16 in





5

* Shown with NATCOM NXT Burner.

Economizer

Pressure Vessel







Auxiliary Equipment







Controls


Fully Metered (FM) - NXT • • •


• • •


O2 Trim • • •


Pressure Vessel


Tubes 2 in 178-A.105 Wall • • •






Auxiliary Equipment





Stack - 40 ft, 50 ft, 60 ft ◊ ◊ ◊

Controls


Single Point (SP) - NXT • • •

Parallel Positioning (PP) - PF • • •


Burner

NATCOM NXT for E Series (See NXT Burner technical data sheet for detailed information)

• • •

ProFire XL for P Series (See ProFire Burner technical data sheet for detailed information)

• •


ND

-40E

-200

D-4

0

CB

ND

-40P

-200

D-4

0

CB

ND

-40E

-200

D-4

0

CB

ND

-40P

-200

D-4

0

CB

ND

-50E

-200

D-4

5

CB

ND

-50P

-200

D-4

5

CB

ND

-50E

-200

D-4

5

CB

ND

-50P

-200

D-4

5

CB

ND

-60E

-200

D-5

0

CB

ND

-60E

-200

D-5

0


E2 Economizers CBND-40E-200D-40CBND-40P-200D-40

CBND-50E-200D-45CBND-50P-200D-45

CBND-60E-200D-50




Segment 0.172 in 0.172 in 0.172 in







Economizer Trim

Economizer feedwater bypass 2 in 2.5 in 2.5 in








6

Boiler Dimensions CBND-70E-300D-55 CBND-80E-300D-65 CBND-90E-300D-70




Length Over Casing 20 ft 23 ft 4 in 25 ft




Shipping Height 14 ft 6 in 14 ft 6 in 14 ft 6 in

Overall Width 11 ft 5 in 11 ft 5 in 11 ft 5 in




7

Economizer

Pressure Vessel







Auxiliary Equipment







Controls


Fully Metered (FM) • • •


• • •


O2 Trim • • •


Pressure Vessel


Tubes 2 in 178-A.105 Wall • • •






Auxiliary Equipment





Stack - 40 ft, 50 ft, 60 ft ◊ ◊ ◊

Controls


Single Point (SP) • • •


Burner

NATCOM NXT (See NXT Burner technical data sheet for detailed information)

• • •


ND

-70E

-300

D-5

5

(Cap

acity

70,

000

lb/h

)

CB

ND

-70E

-300

D-5

5

(Cap

acity

70,

000

lb/h

)

CB

ND

-80E

-300

D-6

5

(Cap

acity

80,

000

lb/h

)

CB

ND

-80E

-300

D-6

5

(Cap

acity

80,

000

lb/h

)

CB

ND

-90E

-300

D-7

0

(Cap

acity

90,

000

lb/h

)

CB

ND

-90E

-300

D-7

0

(Cap

acity

90,

000

lb/h

)


E3 Economizers CBND-70E-300D-55 CBND-80E-300D-65 CBND-90E-300D-70




Segment 0.172 in 0.172 in 0.172 in







Economizer Trim

Economizer feedwater bypass 2.5 in 3 in 3 in








8





Length Over Casing 26 ft 8 in 30 ft 31 ft 8 in




Shipping Height 15 ft 1/2 in 15 ft 1/2 in 15 ft 1/2 in





9

* CBND-90E-300D-70 shown. 400D to 600D CBND units are available with grade mounted fan, fuel train and controls. See corresponding burner dimension table for details.

Economizer

Pressure Vessel







Auxiliary Equipment







Controls


• • •


Pressure Vessel


Tubes 2 in 178-A.105 Wall • • •






Auxiliary Equipment





Stack - 40 ft, 50 ft, 60 ft ◊ ◊ ◊

Controls



O2 Trim • • •


Burner


• • •


ND

-100

E-4

00D

-75

(Cap

acity

100

,000

lb/h

)

CB

ND

-100

E-4

00D

-75

(Cap

acity

100

,000

lb/h

)

CB

ND

-110

E-4

00D

-85

(Cap

acity

110

,000

lb/h

)

CB

ND

-110

E-4

00D

-85

(Cap

acity

110

,000

lb/h

)

CB

ND

-120

E-4

00D

-90

(Cap

acity

120

,000

lb/h

)

CB

ND

-120

E-4

00D

-90

(Cap

acity

120

,000

lb/h

)






Segment 0.172 in 0.172 in 0.172 in







Economizer Trim

Economizer feedwater bypass 3 in 3 in 3 in








10





Length Over Casing 30 ft 35 ft 40 ft




Shipping Height 15 ft 10 1/2 in 15 ft 10 1/2 in 15 ft 10 1/2 in





11


Economizer

Pressure Vessel







Auxiliary Equipment







Controls


• • •


Pressure Vessel


Tubes 2 in 178-A.105 Wall • • •






Auxiliary Equipment





Stack - 40 ft, 50 ft, 60 ft ◊ ◊ ◊

Controls



O2 Trim • • •


Burner


• • •


ND

-135

E-50

0D-9

5

(Cap

acity

135

,000

lb/h

)

CB

ND

-135

E-50

0D-9

5

(Cap

acity

135

,000

lb/h

)

CB

ND

-150

E-50

0D-1

00

(Cap

acity

150

,000

lb/h

)

CB

ND

-150

E-50

0D-1

00

(Cap

acity

150

,000

lb/h

)

CB

ND

-175

E-50

0D-1

15

(Cap

acity

175

,000

lb/h

)

CB

ND

-175

E-50

0D-1

15

(Cap

acity

175

,000

lb/h

)






Segment 0.172 in 0.172 in 0.172 in







Economizer Trim

Economizer feedwater bypass 3 in 4 in 4 in








12

Boiler Dimensions CBND-200E-600D-120 CBND-225E-600D-125

Capacity 200,000 lb/h 225,000 lb/h

Upper Drum 54 in 54 in

Lower Drum 24 in 24 in

Length Over Casing 41 ft 8 in 43 ft 4 in

Width, Gas Outlet 92 3/4 in 104 3/4 in

Height, Gas Outlet 91 1/2 in 91 1/2 in

Front to CL Gas Outlet 52 5/8 in 58 5/8 in

Shipping Height 15 ft 10 1/2 in 15 ft 10 1/2 in

Overall Width 12 ft 9 1/8 in 12 ft 9 1/8 in

Min Operating Pressure 100 psig 100 psig



13


Economizer

Pressure Vessel

Design Pressure up to 375 psig • •

Hinged Manways • •

Lower Drum Heating Coil (LDHC) • •

Tubes 2 in 178-A.120 Wall–PV • •

Tubes 2 in 178-A.135 Wall–PV • •

Operating Pressure - 200–325 psig • •

Auxiliary Equipment

Platforms & Ladders - Boiler • •

Platforms & Ladders - Stack ◊ ◊

Platform & Ladder - Economizer ◊ ◊

Sootblowers • •

Variable Frequency Drive • •

Selective Catalytic Reduction ◊ ◊

Controls


• •

Feedwater 2- or 3-Element • •

Pressure Vessel

Design Pressure 250 • •

Tubes 2 in 178-A.105 Wall • •

Steam Quality 0.5% Moist • •

RH - Right Hand • •

LH - Left Hand • •

AL - Aluminum Casing • •

Operating Pressure - 100–200 psig • •

Auxiliary Equipment

Steam Trim • •

Feedwater Trim • •

Boiler Platform Clips • •

Economizer • •

Stack - 40 ft, 50 ft, 60 ft ◊ ◊

Controls

Hawk 5000 Control • •

Fully Metered (FM) • •

O2 Trim • •

Feedwater - Single Element • •

Burner


• •


ND

-200

E-60

0D-1

20

(Cap

acity

200

,000

lb/h

)

CB

ND

-200

E-60

0D-1

20

(Cap

acity

200

,000

lb/h

)

CB

ND

-225

E-60

0D-1

25

(Cap

acity

225

,000

lb/h

)

CB

ND

-225

E-60

0D-1

25

(Cap

acity

225

,000

lb/h

)


E4 Economizers CBND-200E-600D-120 CBND-225E-600D-125

Fin Height 0.75 in 0.75 in

Transverse Pitch 4.5 in 4.5 in

Longitudinal Pitch 4.5 in 4.5 in

Segment 0.172 in 0.172 in

Fin Thickness 0.05 in 0.05 in

Effective Length 16 ft 16 ft

Material Carbon Steel Carbon Steel

Fins Serrated Serrated

Bends Cold Bent Cold Bent

Fuel NG & #2 oil NG & #2 oil

Economizer Trim

Economizer feedwater bypass 6 in 6 in

Header vent valve 1 in 1 in

Header drain valve 1 in 1 in






14

ProFire BurnersD126, LND145Technical Data Sheet

Physicalarrangement:

Combustion Control System (CCS) compatibility options:

Fuel Options:Choice of NFPA or CSA compliance for U.S. or Canadian units, respectively (contact us for TSSA compliance).

Designed integral FD fan, packaged fuel train and remote control panel. Choice of right- or left-hand fuel rack.

Single Point or Parallel Positioning Combustion Control System (CCS) with O2 trim.

Main Fuel: Natural gas and/or #2 oil.

Igniter fuel: Natural gas and/or propane.

NG, no FGR #2 Oil, no FGR NG, 18% FGR #2 Oil, 18% FGR

Excess Air %* 20 20 20 20

NOx emissions ppmvd @3%O2 95 135 30 100

CO emissions ppmvd @3%O2 100 75 100 100

VOC lb/MM BTU (HHV) 0.006 0.004 0.006 0.004

Total PM lb/MM BTU (HHV) 0.01 0.05 0.01 0.05

Turndown 10 8 8 6

Performance guarantees

Performance guarantees are based on normal operating conditions and valid from 25% to 100% MCR, boiler with gas tight furnace division wall and to nominal operating pressure and temperature. Igniter emissions are not guaranteed. For application where CB does not provide the controls, emissions are guaranteed in manual mode only. SOx emissions are not burner dependent and depend solely on the sulfur content of the fuel. Burner/boiler systems are not intended for automatic recycling use. Please contact your local representative for more details.

*Excess air given for 100% MCR only.

Regulated pressure at train inlet (psig) Atomizing

Steam flow (pph)

Atomizing air for cold start

NG #2 OilAtomizing

Steam(psig) (SCFM)

10 30 30 65 30 32

Specific operating conditions

Pressure control valve not included. See piping spec for design ratings. See also general design data for additional details.

Reference documents Please reference the below documents for additional information on the content outlined in this data sheet. All documents are available in the Cleaver-Brooks Boiler Book.

Guide specificationsGeneral design dataProduct dimension tables

Piping specificationsInspection and test planPaint specification

Scope detailJob document listCommissioning plan

For 50ºF to 100ºF combustion air applications, uncontrolled or 30 ppm NOx emissions

Designed for CBND-10P-100D-25

12.2 MM BTU/H NG; 12.1 MM BTU/H #2 OIL

15

ProFire BurnersD252, LND300Technical Data Sheet




Designed integral FD fan, packaged fuel train and remote control panel. Choice of right- or left-hand fuel rack.

Single Point or Parallel Positioning Combustion Control System (CCS) with O2 trim.




Excess Air %* 20 20 20 20



VOC lb/MM BTU (HHV) 0.006 0.006 0.006 0.004


Turndown 10 8 8 6





Steam flow (pph)


NG #2 OilAtomizing

Steam(psig) (SCFM)

10 30 30 130 30 65










16

Gas input based on natural gas at 1,000 Btu/cu. ft. and 0.60 gravity. Oil input based on No. 2 oil at 140,000 Btu/gal. PPH overall efficiency of 84% estimated. Blower wheel and motor HP is based on altitude up to 2,500 ft. above sea level. For higher altitude or 50 Hz. applications, consult factory. Firing at higher furnace pressures de-rates the burner by approximately 5% per 1/2 in. of additional pressure; consult factory.

Boiler Size Burner Model

Gas Input (MBH)

#2 Oil Input (GPH)

PPH @ 84% Eff.

Motor HP

Metering System Motor

HP 3 PH.

Blower Motor Volt/PH 60 Hz.

Gas Pressure Required

(PSI)

CBND-10P-100D-25 D-126 12,600 90 10,000 15 1/2 460/3 2.5

CBND-20P-100D-35 D-252 25,200 180 20,000 30 3/4 460/3 4.3

17

Boiler Size Burner Model A B C D E F G H I J K L M N P Q R

CBND-10P-100D-25 D-126 22 27 12 21 1/2 56 7/8 15 30 1/8 4 1/8 24 3/4 21 12 25 45 37 3/8 30 1/2 1 1/4 3

CBND-20P-100D-35 D-252 31 1/2 37 15 22 66 3/8 21 37 3/8 4 5/8 32 3/8 23 3/4 12 35 56 7/8 47 1/2 31 1 1/4 4

ProFire D Series BurnersD-126, D-252Dimension Tables

Designed for 10P-100D-25 and 20P-100D-35 CBND Boilers

12.6–25.2 MM BTU/H NG; 12.6–25.2 MM BTU/H #2 OIL

18

ProFire LND Series BurnersLND-145, LND-300Dimension Tables

Designed for 10P-100D-25 and 20P-100D-35 CBND Boilers




Gas Input (MBH)

#2 Oil Input (GPH)

PPH @ 84% Eff.

Motor HP

Metering System Motor

HP 3 PH.

Blower Motor Volt/PH 60 Hz.


(PSI)

F.G.R. Line Piping

Size

CBND-10P-100D-25 LND-145 12,600 90 10,000 15 1/2 460/3 2.5 8

CBND-20P-100D-35 LND-300 25,200 180 20,000 40 3/4 460/3 4.3 10

Boiler Size Burner Model A B C D E F G H I J K L M N

CBND-10P-100D-25 LND-145 22 27 12 21 1/2 56 7/8 15 30 1/8 4 1/8 24 3/4 20 5/8 12 25 45 47 3/8

CBND-20P-100D-35 LND-300 31 1/2 37 15 22 66 3/8 21 37 3/8 4 5/8 32 3/8 23 3/4 12 35 56 7/8 58

Boiler Size Burner Model P Q R S T U V

CBND-10P-100D-25 LND-145 30 1/2 1 1/4 3 47 7/8 16 7/8 9 1/2

CBND-20P-100D-35 LND-300 31 1 1/4 4 51 5/8 16 7/8 11 3/4

* The noise level emission guarantee applies for each individual system component provided (not combined) and does not consider the overall plant floor level noise. Noise emission guarantee is based on free field sound, hemispherical radiation at the stated distance and does not include combination of sound effect radiated from other sources or noise reflected from the interior building walls and other surfaces. Also, it does not take into consideration factors which may contribute to overall installed noise levels such as existing noise from motors, casings, ducts, flowmeters, dampers, VIVs and other power house equipment.

Packaged burner general design conditions

Each pre-engineered burner system shall be designed for the following general conditions:

Codes & Regulations

System Compliant to: Component listing: Piping standard: Enclosure rating: Area classification:

NFPA 85 or CSA B149.3

UL B31.3 NEMA 4 Non hazardous

Plant General Data

Altitude Equipment LocationFD

Fan MotorVoltage

Control Voltage

Instrument Air Pressure

NoiseLimitation*

Ambient Temperature

Combustion Air Temperature

MaximumRelativeHumidity

0–2500 ft ASL

Indoors orOutdoors

480V/3/60HZor

600V/3/60HZ(Canada)

120V 80 psigRegulated

92dBA @ 3ft15ºF to100ºF

50ºF to 100ºF must be tempered to

the specified temperature

60%

Fuel

Main Burner Fuel option

Igniter Fueloption

Natural Gas Temperature at Train Inlet

Natural Gas #2 Oil

Natural Gas and/or #2 Oil

Natural Gas and/or

Propane Gas

60ºF–80ºF

Composition % Volume

High Heating Value (HHV) Composition

% MassHigh Heating Value (HHV)

Fuel Bound Nitrogen

(FBN) % Mass

Asphaltene% Mass

Viscocity SSU@60ºF

95% CH4

2% C2H6

2% N2

1% CO2

994 BTU/SCF

87.27 C12.5 H0.2 S

0.01 ash

19,300 BTU/lb

≤0.02 ≤3 42

ProFire XL BurnerGeneral Data Sheet

For 100D to 200D CBND Boilers

12.6 to 63 MM BTU/H Burners

19

ProFire BurnersXL378, LNXL378Technical Data Sheet




Designed integral FD fan, parallel positioning, packaged fuel train and remote control panel. Choice of right- or left-hand fuel rack.

O2 trim and Variable Speed Drive (VSD).




Excess Air %* 20 20 20 20



VOC lb/MM BTU (HHV) 0.006 0.004 0.006 0.004


Turndown 10 8 8 6





Steam flow (pph)


NG #2 OilAtomizing

Steam(psig) (SCFM)

10 30 30 170 30 95










20










Excess Air %* 20 20 20 20



VOC lb/MM BTU (HHV) 0.006 0.004 0.006 0.004


Turndown 10 8 8 6





Steam flow (pph)


NG #2 OilAtomizing

Steam(psig) (SCFM)

10 30 30 255 30 125










21










Excess Air %* 20 20 20 20



VOC lb/MM BTU (HHV) 0.006 0.004 0.006 0.004


Turndown 10 8 8 6





Steam flow (pph)


NG #2 OilAtomizing

Steam(psig) (SCFM)

10 30 30 315 30 155










22

23

VIEW B-B BURNER MTNG. FLANGE

A A

B

B

W

V

S

F

E

J

K

G

H

L

M

N

P

R

VIEW A-A

GAS PILOTPIPING

ØDD

ØEEB.C.

FFX ØHH

FFX GG°

ELECTICALJ-BOX

AIR INLET

D

MAIN GAS INLET 4" NPT

GAS PILOT INLET 1/2" NPT

OIL INLET 1/2" NPT

STEAM INLET 1" NPT

Q

T

U

ProFire XL Series BurnersXL-378, XL-504, XL-630Dimension Tables

Designed for 30P-100D-40, 40P-200D-40 and 50P-200D-45 CBND Boilers


Boiler Size Burner Model D E F G H J K L M N P Q

CBND-30P-100D-40 XL-378 137 3/10 83 3/10 26 3/5 24 31 7/10 17 3/5 33 6 1/2 28 36 2/5 38 3/10 23 3/10

CBND-40P-200D-40 XL-504 144 1/2 90 1/2 28 25 2/5 33 3/10 17 3/5 33 7 30 1/2 36 9/10 38 4/5 27

CBND-50P-200D-45 XL-630 144 1/2 90 1/2 28 25 2/5 33 3/10 17 3/5 33 7 30 1/2 36 9/10 38 4/5 27

Boiler Size Burner Model R S T U V W DD EE FF GG HH

CBND-30P-100D-40 XL-378 110 4/5 72 3/10 38 1/2 3 3/5 98 9/10 16 1/10 30 28 3/10 12 30˚ 47/50

CBND-40P-200D-40 XL-504 116 1/2 74 1/5 40 1/2 4 1/2 108 4/5 19 2/5 41 39 12 30˚ 47/50

CBND-50P-200D-45 XL-630 116 1/2 74 1/5 40 1/2 4 1/2 108 4/5 19 2/5 41 39 12 30˚ 47/50



Gas Input (MBH)

#2 Oil Input (GPH)

PPH @ 84% Eff.

Motor HP

Blower Motor Volt/3 PH

60 Hz.

Furnace Pressure

("w.c.)


(PSI)

CBND-30P-100D-40 XL-378 37,800 270 30,000 30 460/3 5.0 10

CBND-40P-200D-40 XL-504 50,400 360 40,000 50 460/3 3.5 10

CBND-50P-200D-45 XL-630 63,000 450 50,000 75 460/3 5.0 10

24

SECTION B-B F.G.R. INLET MNTG. FLANGE

VIEW C-C BURNER MTNG. FLANGE

A A

B

B

C

C

Z

Y

V

U

W

F

E

J

K

G

H

L

M

N

P

R

S

T

VIEW A-A

GAS PILOTPIPING

ØKK

ØLLB.C.

MMX ØPP

MMX NN°

ELECTICALJ-BOX

AIR INLET

F.G.R. INLET

D

ØDDØEEB.C.

GGX ØHHGGX JJ°

ØFF

MAIN GAS INLET 4" NPT

GAS PILOT INLET 1/2" NPT

OIL INLET 1/2" NPT

STEAM INLET 1" NPT

Q

ProFire LNXL Series BurnersLNXL-378, LNXL-504, LNXL-630Dimension Tables

Designed for 30P-100D-40, 40P-200D-40 and 50P-200D-45 CBND Boilers


Boiler Size Burner Model D E F G H J K L M N P Q R S T U

CBND-30P-100D-40 LNXL-378 137 3/10 83 3/10 26 3/5 24 31 7/10 17 3/5 33 6 1/2 28 36 2/5 38 3/10 23 3/10 31 1/2 56 4/5 110 4/5 72 3/10

CBND-40P-200D-40 LNXL-504 144 1/2 90 1/2 28 25 2/5 33 3/10 17 3/5 33 7 30 1/2 36 9/10 38 4/5 27 33 1/2 62 1/2 116 1/2 74 1/5

CBND-50P-200D-45 LNXL-630 144 1/2 90 1/2 28 25 2/5 33 3/10 17 3/5 33 7 30 1/2 36 9/10 38 4/5 27 33 1/2 62 1/2 116 1/2 74 1/5

Boiler Size Burner Model V W Y Z DD EE FF GG HH JJ KK LL MM NN PP

CBND-30P-100D-40 LNXL-378 38 1/2 3 3/5 98 9/10 16 1/10 21 18 4/5 13 3/10 24 1 10/77 15˚ 30 28 3/10 12 30˚ 47/50

CBND-40P-200D-40 LNXL-504 40 1/2 4 1/2 108 4/5 19 2/5 23 1/2 21 3/10 15 3/10 16 1 10/77 22 1/2˚ 41 39 12 30˚ 47/50

CBND-50P-200D-45 LNXL-630 40 1/2 4 1/2 108 4/5 19 2/5 23 1/2 21 3/10 15 3/10 16 1 10/77 22 1/2˚ 41 39 12 30˚ 47/50



Gas Input (MBH)

#2 Oil Input (GPH)

PPH @ 84% Eff.

Motor HP

Blower Motor Volt/3 PH

60 Hz.

Furnace Pressure

("w.c.)


(PSI)

F.G.R. Line Piping

Size

CBND-30P-100D-40 LNXL-378 37,800 270 30,000 40 460/3 6.0 10 14

CBND-40P-200D-40 LNXL-504 50,400 360 40,000 60 460/3 7.7 10 16

CBND-50P-200D-45 LNXL-630 63,000 450 50,000 100 460/3 9.6 10 16

* The noise level emission guarantee applies for each individual system component provided by NATCOM (not combined) and does not consider the overall plant floor level noise. Noise emission guarantee is based on free field sound, hemispherical radiation at the stated distance and does not include combination of sound effect radiated from other sources or noise reflected from the interior building walls and other surfaces. Also, it does not take into consideration factors which may contribute to overall installed noise levels such as existing noise from motors, casings, ducts, flowmeters, dampers, VIVs and other power house equipment.

Packaged burner general design conditions

Each NXT burner system shall be designed for the following general conditions:

Codes & Regulations

System Compliant to: Component listing: Piping standard: Enclosure rating: Area classification:

NFPA 85 or CSA B149.3

UL B31.3 NEMA 4 Non hazardous

Plant General Data

Altitude Equipment LocationFD

Fan MotorVoltage

Control Voltage

Instrument Air Pressure

NoiseLimitation*

Ambient Temperature

Combustion Air Temperature

MaximumRelativeHumidity

0–2500 ft ASL

48 to 109 MM BTU/H200D–300D

120 to 271 MM BTU/H400D–600D

480V/3/60HZor

600V/3/60HZ(Canada)

120V 70 psigRegulated

85dBA @ 3ft15ºF to125ºF

48 to 109 MM BTU/H200D–300D

120 to 271MM BTU/H400D–600D

60%50ºF to 100ºF must be tempered to

the specified temperature

IndoorsIndoors orOutdoors

Fuel

Main Burner Fuel option

Igniter Fueloption

Natural Gas Temperature at Train Inlet

Natural Gas #2 Oil

Natural Gas and/or #2 Oil

Natural Gas and/or

Propane Gas

40ºF–80ºF

Composition % Volume

High Heating Value (HHV) Composition

% MassHigh Heating Value (HHV)

Fuel Bound Nitrogen

(FBN) % Mass

Asphaltene% Mass

Viscocity SSU@60ºF

95% CH4

2% C2H6

2% N2

1% CO2

994 BTU/SCF

87.27 C12.5 H0.2 S

0.01 ash

19,300 BTU/lb

≤0.02 ≤3 42

NXT BurnerGeneral Data Sheet

For 200D to 600D CBND Boilers

48 to 271 MM BTU/H Burners

25


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)

Allowed furnace pressure @ MCR

(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

9% FGR NG

FM 20 100 95 240 70 45 40/40 Oil40/50 NG 3.5 3.9

SP, PP 18 95 95 240 70 45

NXT-048 BurnerTechnical Data Sheet




Designed for furnace dimensions of at least:



Fuel Options: Choice of NFPA or CSA compliance for U.S. or Canadian units, respectively (contact us for TSSA compliance).

H=8.34'W=6.69' Lturn=11.33' Ltot=13.00'

FD fan, fuel train and control panel are windbox mounted. Right- or left-hand drum arrangements available.

Fully Metered (FM), Parallel Positioning (PP) and Single Point Positioning (SP). All systems use 4-20mA and pneumatic actuators.



Performance guarantees are based on normal operating conditions and valid from 12.5% to 100% MCR, boiler with gas tight furnace division wall and to nominal operating pressure and temperature. Igniter emissions are not guaranteed. For application where CB does not provide the controls, emissions are guaranteed in manual mode only. SOx emissions are not burner dependent and depend solely on the sulfur content of the fuel. Burner/boiler systems are not intended for automatic recycling use. Fan motors of 100 HP and above are only offered with manual start/stop control. Please contact your local representative for more details.

*Excess air given for MCR only.

Allowed furnace pressure given for NG fuel including 0.75 inwc margin. Oil-only application will result in slightly reduced furnace pressure. Pressure control valves not included. See piping spec for design ratings. See also general operating conditions for additional details.

Guide specificationsGeneral design dataProduct dimension tablesPiping specifications

Inspection and test planPaint specificationScope detailJob document list

Fan & motor specificationCommissioning plan

For indoor applications, uncontrolled or 30 ppm NOx emissions

Designed for CBND-40E-200D-40, 40 K PPH sat.

48 MM BTU/H NG; 46 MM BTU/H #2 OIL

26


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)


(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

10% FGR NG

FM 20 100 95 300 70 60 50/60 Oil60/60 NG 5.1 5.7

SP, PP 18 95 95 300 70 60









H=8.34'W=6.69' Lturn=12.67' Ltot=14.67'














27


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)


(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

11% FGR NG

FM 20 100 95 360 70 70 75/100 Oil75/100 NG 7.1 8.2

SP, PP 18 95 95 360 70 70









H=8.34'W=6.69' Lturn=14.00' Ltot=16.33'














28


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)


(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

12% FGR NG

FM 22 125 120 420 70 80 75/100 Oil75/100 NG 5.3 6.1

SP, PP 20 120 120 420 70 80









H=8.97'W=6.69' Lturn=15.33' Ltot=18.00'














29


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)


(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

13% FGR NG

FM 22 125 120 475 70 90 100/125 Oil100/150 NG 7.1 8.4

SP, PP 20 120 120 475 70 90









H=8.97'W=6.69' Lturn=18.33' Ltot=21.33'














30


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Fan test block

No FGR/FGR(HP)


(inwc)

NG #2 OilAtomizing

Steam(psig) (SCFM)

No FGRNG

13% FGR NG

FM 22 125 120 540 70 100 125/150 Oil125/150 NG 9.1 10.8

SP, PP 20 120 120 540 70 100









H=8.97'W=6.69' Lturn=19.67' Ltot=23.00'














31


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)


Burner + Windbox DP No FGR/FGR

AHG DP No FGR/FGR

NG #2 OilAtomizing

Steam(psig) (SCFM) (in wc) (in wc)

22 125 120 600 70 1158.1/8.4 Oil8.1/8.4 NG

2.1/2.3 Oil3.3/3.6 NG









H=9.04'W=6.69' Lturn=21.00' Ltot=24.67'

Designed for remote installation of FD fan, fuel train and control panel. Choice of right- or left-hand fuel rack. Choice of right, left, top, or bottom combustion air inlet flanged connection.

Fully Metered (FM) Combustion Control System (CCS) with O2 trim. All systems use 4-20mA and pneumatic actuators.



Performance guarantees are based on normal operating conditions and valid from 12.5% to 100% MCR, boiler with gas tight furnace division wall and to nominal operating pressure and temperature. Igniter emissions are not guaranteed. For application where CB does not provide the controls, emissions are guaranteed in manual mode only. SOx emissions are not burner dependent and depend solely on the sulfur content of the fuel. Burner/boiler systems are not intended for automatic recycling use. Please contact your local representative for more details.


Pressure control valves not included. See piping spec for design ratings. See also general design data for additional details. All pressure drops are given at worst case conditions specified in the general design data. Burner + Windbox DP includes a windbox mounted opposed blade damper. Actual site DP may vary. DP shown does not include any design margin.







32


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


22 125 120 660 70 1258.4/9.0 Oil8.4/8.7 NG

2.2/2.6 Oil3.4/3.1 NG









H=9.04'W=6.69' Lturn=24.00' Ltot=28.00'














33


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


22 125 120 720 70 1358.7/9.4 Oil8.6/9.0 NG

2.2/2.3 Oil3.0/3.2 NG









H=9.04'W=6.69' Lturn=25.00' Ltot=29.67'














34


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


24 150 145 820 70 1459.5/9.8 Oil9.2/9.7 NG

2.3/2.4 Oil2.8/3.4 NG









H=10.11'W=6.69' Lturn=26.33' Ltot=31.33'














35


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


24 150 145 900 70 1759.9/10.4 Oil9.7/10.3 NG

2.0/2.2 Oil3.4/3.6 NG









H=10.11'W=6.69' Lturn=27.67' Ltot=33.00'














36


Excess Air %* 15 15 15 15



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


24 150 145 1040 70 2009.4/10.3 Oil9.3/10.2 NG

2.8/3.0 Oil3.5/3.7 NG









H=10.11'W=6.69' Lturn=32.00' Ltot=38.00'














37

NG, no FGR #2 Oil, no FGR NG, 17.5% FGR #2 Oil, 17.5% FGR

Excess Air %* 15 17.5 15 17.5



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


26 150 145 1200 70 2309.5/10.2 Oil

10.4/10.5 NG2.9/3.0 Oil3.5/3.7 NG









H=10.09'W=6.69' Lturn=32.67' Ltot=39.67'














38


Excess Air %* 17.5 17.5 17.5 17.5



VOC lb/MM BTU (HHV) 0.004 0.004 0.004 0.004


Turndown 10 8 10 8


steam flow (pph)



AHG DP No FGR/FGR

NG #2 OilAtomizing


26 150 145 1350 70 26010.2/10.8 Oil10.2/10.8 NG

2.7/2.9 Oil3.7/3.9 NG









H=10.11'W=6.69' Lturn=33.67' Ltot=41.33'














39

All dimensions are in inches. Dimensions may differ depending on the options chosen and are given for general reference only. Refer to final project specific general arrangement drawing for exact dimensions to be used for construction purposes. Refer to the “E” dimension for shipping width. Control panel, if supplied, is being folded towards the burner when units are shipped. (Control panel is mounted on hinged supporting brackets). For retrofit application, oil gun and ignitor removal length could be larger by up to 12 inches.

A B C D E F G H J K L M N P

98.5 81 48 52 37 37 25 98 23 100 66 37 137 99

105 90 54 52 40 37 28 108 26 106 72 38 149 111


CBND-40E-200D-40CBND-50E-200D-45CBND-60E-200D-50

NXT-048NXT-060NXT-072



NXT-048 to NXT-109 BurnersDimension Tables

Designed for 200D to 300D CBND Boilers


40

NXT-120 to NXT-271 BurnersDimension Tables

Boiler Size Burner Model A B C D E F G H



88 78 84 63 39 128 162 117



92 82 90 65 41 134 169 124

CBND-200E-600D-120CBND-225E-600D-125

NXT-240NXT-271

100 90 96 69 45 141 176 131

Boiler Size Burner Model Fuel A B C D E F

CBND-100E-400D-75CBND-110E-400D-85CBND-120E-400D-90CBND-135E-500D-95CBND-150E-500D-100CBND-175E-500D-115CBND-200E-600D-120CBND-225E-600D-125

NXT-120NXT-132NXT-144NXT-162NXT-180NXT-210NXT-240NXT-271

Natural Gas 108 72 48 96 66 32

Natural Gas + Oil 124 68 60 108 84 60

All dimensions shown in inches. Dimensions may differ depending on options chosen and are given for general reference only. Refer to final project specific general arrangement drawing for exact dimensions to be used for construction purposes. For retrofit application - oil gun (G) and igniter (H) removal length may expand by up to 12 inches.

General Dimensions

Fuel Rack Dimensions

Designed for 400D to 600D CBND Boilers


41

Boiler Size Burner Model A B C* D E F G

CBND-100E-400D-75 NXT-120 70 28 142 78 116 40 32

CBND-110E-400D-85 NXT-132 78 30 154 78 126 44 32

CBND-120E-400D-90 NXT-144 78 30 154 84 132 48 34

CBND-135E-500D-95 NXT-162 84 32 158 94 136 52 38

CBND-150E-500D-100 NXT-180 84 32 168 94 140 56 38

CBND-175E-500D-115 NXT-210 94 34 190 102 154 60 40

CBND-200E-600D-120 NXT-240 102 38 202 114 170 68 44

CBND-225E-600D-125 NXT-271 102 38 218 114 184 72 44

All dimensions shown in inches. Dimensions may differ depending on options chosen and are given for general reference only. Refer to final project specific general arrangement drawing for exact dimensions to be used for construction purposes. To obtain the total length without FGR, subtract dimension “F” from dimension “C.” *Subtract 3 inches from dimension “C” when the silencer is ducted.

Air Handling Components Dimensions

42

Printed in the USA©2011 Cleaver-Brooks, Inc

CB-83911/11

Engineered Boiler Systems 6940 Cornhusker Hwy, Lincoln, NE 68507 USA

402.434.2000 · [email protected] cleaverbrooks.com/engineered

BOILER PREDICTED PERFORMANCE*Version: NB-Size-2014.0.1 Customer: Bechtel (Renovo PA) Engineer: JMJ

Proposal: TBD Fuel:

Model: NB-200D-50 Design Pressure: 350 PSIG

Boiler load - % 100% 75% 50% 25%

Steam Flow - Gross Production 54,000 40,500 27,000 13,500 Lb/Hr

Net Steam Flow - Gross less Pegging Steam 45,000 33,750 22,500 11,250 Lb/Hr

Pegging Steam 9,000 6,750 4,500 2,250 Lb/Hr

Steam Pressure - Operating 300 300 300 300 PSIG

Steam Temperature 421 421 421 421 °F

Fuel Input (HHV) 65.6 49.0 32.6 16.5 MMBTU/Hr

Ambient Air Temperature 80 80 80 80 °F

Relative Humidity 60 60 60 60 %

Excess Air 20 20 20 25 %

Flue Gas Recirculation 25 25 25 25 %

Steam Output Duty 54.7 41.0 27.3 13.7 MMBTU/hr

Heat Release Rate - Volumetric 71,774 53,638 35,716 18,028 BTU/FT3-Hr

Heat Release Rate - Area 112,551 84,111 56,008 28,270 BTU/FT2-Hr

Heat Flux 17,242 BTU/FT2-Hr

Feed Water Temperature 228 228 228 228 °F

Water Temperature Leaving Economizer 334 322 307 296 ±10°F

Blow Down 3.0 3.0 3.0 3.0 %

Boiler Gas Exit Temperature 633 576 515 456 ±10°F

Economizer Gas Exit Temperature 301 282 264 249 ±10°F

Air Flow 57,514 42,981 28,620 15,048 Lb/Hr

Flue Gas to Stack 60,293 45,058 30,003 15,746 Lb/Hr

Flue Gas Including FGR 75,366 56,322 37,504 19,682 Lb/Hr

Fuel Flow 2,778 2,076 1,382 697 Lb/Hr

Flue Gas Analysis,Losses,Efficiency - %

Dry Gas Loss 4.3 3.9 3.6 3.5 %

Air Moisture Loss 0.1 0.1 0.1 0.1 %

Fuel Moisture Loss 10.7 10.6 10.6 10.5 %

Casing Loss 0.5 0.7 1.0 2.0 %

Margin 1.0 1.0 1.0 1.0 %

Efficiency - LHV 92.4 92.7 92.9 92.0 %

Efficiency - HHV 83.3 83.6 83.7 83.0 %

Total Pressure Drop Including Economizer 7.95 4.44 1.96 0.51 IN WC

Products of Combustion - CO2 7.96 7.96 7.96 7.66 % vol.

- H2O 17.59 17.59 17.59 17.02 % vol.

-N2 71.29 71.29 71.29 71.52 % vol.

-O2 3.16 3.16 3.16 3.80 % vol.

- - - - #/mmbtu

Fuel Composition - Gas BOILER SURFACE AREAS-ft2

methane 96.943 % vol. Furnace Volume: 913 ft3

ethane 2.5240 % vol. Furnace Projected Area: 583 ft2

propane 0.1240 % vol. Evaporator: 2,591 ft2

butane 0.0007 % vol. Total Area: 3,173 ft2

carbon dioxide 0.1400 % vol. Economizer: 7,904 ft2

nitrogen 0.2700 % vol. Superheater: - ft2

LHV-Btu/lb 21285

HHV-Btu/lb 23601

NOTE: Emissions rates are estimated to be at or below as follows: CO (.036), VOC (.005) , NOx (.011) #/mmbtu

*Above data is predicted only, see proposal for guaranteed numbers.

Natural Gas

June 27, 2016

Cleaver-Brooks, Inc.

Engineered Boiler Systems

Renovo PA Boiler Performance rev1

LoadsCase1 12/19/2016

aaustin

Highlight

DIESEL GENERATOR SET

STANDBY1500 ekW 1875 kVA60 Hz 1800 rpm 480 VoltsCaterpillar is leading the power generationmarketplace with Power Solutions engineeredto deliver unmatched flexibility, expandability,reliability, and cost-effectiveness.

Image shown may notreflect actual package.

FEATURES

FUEL/EMISSIONS STRATEGY• EPA Certified for Stationary

Emergency Application(EPA Tier 2 emissions levels)

DESIGN CRITERIA• The generator set accepts 100% rated load in one

step per NFPA 110 and meets ISO 8528-5 transientresponse.

UL 2200 / CSA - Optional• UL 2200 listed packages• CSA Certified

Certain restrictions may apply.Consult with your Cat® Dealer.

FULL RANGE OF ATTACHMENTS• Wide range of bolt-on system expansion

attachments, factory designed and tested• Flexible packaging options for easy and cost

effective installation

SINGLE-SOURCE SUPPLIER• Fully prototype tested with certified torsional

vibration analysis available

WORLDWIDE PRODUCT SUPPORT• Cat dealers provide extensive post sale support

including maintenance and repair agreements• Cat dealers have over 1,800 dealer branch stores

operating in 200 countries• The Cat® S•O•SSM program cost effectively detects

internal engine component condition, even thepresence of unwanted fluids and combustionby-products

CAT® 3512C DIESEL ENGINE• Reliable, rugged, durable design• Four-stroke-cycle diesel engine combines

consistent performance and excellent fueleconomy with minimum weight

CAT GENERATOR• Designed to match the performance and output

characteristics of Cat diesel engines• Single point access to accessory connections• UL 1446 recognized Class H insulation

CAT EMCP 4 CONTROL PANELS• Simple user friendly interface and navigation• Scalable system to meet a wide range of

customer needs• Integrated Control System and Communications

Gateway

SEISMIC CERTIFICATION• Seismic Certification available• Anchoring details are site specific, and are

dependent on many factors such as generator setsize, weight, and concrete strength.IBC Certification requires that the anchoringsystem used is reviewed and approved by aProfessional Engineer

• Seismic Certification per Applicable BuildingCodes: IBC 2000, IBC 2003, IBC 2006, IBC 2009,CBC 2007

• Pre-approved by OSHP and carries anOPA#(OSP-0084-01) for use in healthcare projectsin California

STANDBY 1500 ekW 1875 kVA60 Hz 1800 rpm 480 Volts

FACTORY INSTALLED STANDARD & OPTIONAL EQUIPMENT

System Standard OptionalAir Inlet • Single element canister type air cleaner

• Service indicator[ ] Dual element & heavy duty air cleaners (with

pre-cleaners)[ ] Air inlet adapters & shut-off

Cooling • Radiator fan and fan drive• Fan and belt guards• Coolant level sensors*• Cat Extended Life Coolant*

[ ] Coolant level switch gauge[ ] Heat exchanger and expansion tank

Exhaust • Exhaust manifold - dry - dual - 8 in• 203 mm (8 in) ID round flanged outlet

[ ] Mufflers[ ] Stainless steel exhaust flex fittings[ ] Elbows, flanges, expanders & Y adapters

Fuel • Secondary fuel filters• Fuel cooler*• Fuel priming pump• Flexible fuel lines (shipped loose)

[ ] Duplex secondary fuel filter[ ] Primary fuel filter with fuel water separator

Generator • Class H insulation• Cat digital voltage regulator (CDVR) with kVAR/PF

control, 3-phase sensing• Winding temperature detectors• Anti-condensation heaters• Reactive Droop

[ ] Oversize & premium generators [ ] Bearingtemperature detectors

Power Termination • Bus bar (NEMA or IEC mechanical lug holes)- rightside standard

• Top and bottom cable entry

[ ] Circuit breakers, UL listed, 3 pole with shunttrip,100% rated, manual or electrically operated [ ]Circuit breakers, IEC compliant, 3 or 4 pole with shunttrip, manual or electrically operated

[ ] Bottom cable entry[ ] Power terminations can be located on the right, left

and/or rear as an optionGovernor • ADEM™ 3 [ ] Load share module

Control Panel • EMCP 4.2• User Interface panel (UIP) - rear mount• AC & DC customer wiring area (right side)• Emergency stop pushbutton

[ ] Option for right or left mount UIP[ ] Local & remote annunciator modules[ ] Digital I/O Module[ ] Generator temperature monitoring & protection[ ] Remote monitoring software

Lube • Lubricating oil and filter• Oil drain line with valves• Fumes disposal• Gear type lube oil pump

[ ] Oil level regulator[ ] Deep sump oil pan[ ] Electric & air prelube pumps [ ] Manual prelube with

sump pump [ ] Duplex oil filterMounting • Rails - engine / generator / radiator mounting

• Anti-vibration mounts (shipped loose)[ ] Spring-type vibration isolator [ ] IBC Isolators

Starting/Charging • 24 volt starting motor(s)• Batteries with rack and cables• Battery disconnect switch

[ ] Battery chargers (10 or 20 Amp)[ ] 45 amp charging alternator[ ] Oversize batteries[ ] Ether starting aid[ ] Heavy duty starting motors[ ] Barring device (manual)[ ] Air starting motor with control & silencer

Note Standard and optional equipment may vary for UL2200 Listed Packages. UL 2200 Listed packages mayhave oversized generators with a differenttemperature rise and motor starting characteristics.

General • Right hand service• Paint - Caterpillar Yellow(with high gloss black rails & radiator)• SAE standard rotation• Flywheel and flywheel housing - SAE No. 00

[ ] CSA certification[ ] CE Certificate of Conformance[ ] Seismic Certification per Applicable Building Codes:

IBC 2000, IBC 2003, IBC 2006, IBC 2009, CBC 2007* Not included with packages without radiators

February 13 2012 16:44 PM2


SPECIFICATIONS

CAT GENERATOR

Cat GeneratorFrame size......................................................................... 697Excitation................................................ Permanent MagnetPitch.............................................................................. 0.7333Number of poles...................................................................4Number of bearings...................................... Single bearingNumber of Leads.............................................................. 006Insulation....................... UL 1446 Recognized Class H withtropicalization and antiabrasion- Consult your Caterpillar dealer for available voltagesIP Rating........................................................................... IP23Alignment.............................................................. Pilot ShaftOverspeed capability........................................................150Wave form Deviation (Line to Line)........................... 003.00Voltage regulator.............. 3 Phase sensing with selectiblevolts/HzVoltage regulation............Less than +/- 1/2% (steady state)Less than +/- 1/2% (w/3% speed change)

CAT DIESEL ENGINE

3512C ATAAC, V-12, 4-Stroke Water-cooled DieselBore........................................................ 170.00 mm (6.69 in)Stroke..................................................... 190.00 mm (7.48 in)Displacement.........................................51.80 L (3161.03 in3)Compression Ratio....................................................... 14.7:1Aspiration........................................................................... TAFuel System.................................... Electronic unit injectionGovernor Type........................................................... ADEM3

CAT EMCP 4 SERIES CONTROLS

EMCP 4 controls including:- Run / Auto / Stop Control- Speed and Voltage Adjust- Engine Cycle Crank- 24-volt DC operation- Environmental sealed front face- Text alarm/event descriptions

Digital indication for:- RPM- DC volts- Operating hours- Oil pressure (psi, kPa or bar)- Coolant temperature- Volts (L-L & L-N), frequency (Hz)- Amps (per phase & average)- ekW, kVA, kVAR, kW-hr, %kW, PF

Warning/shutdown with common LED indication of:- Low oil pressure- High coolant temperature- Overspeed- Emergency stop- Failure to start (overcrank)- Low coolant temperature- Low coolant level

Programmable protective relaying functions:- Generator phase sequence- Over/Under voltage (27/59)- Over/Under Frequency (81 o/u)- Reverse Power (kW) (32)- Reverse reactive power (kVAr) (32RV)- Overcurrent (50/51)

Communications:- Six digital inputs (4.2 only)- Four relay outputs (Form A)- Two relay outputs (Form C)- Two digital outputs- Customer data link (Modbus RTU)- Accessory module data link- Serial annunciator module data link- Emergency stop pushbutton

Compatible with the following:- Digital I/O module- Local Annunciator- Remote CAN annunciator- Remote serial annunciator

February 13 2012 16:44 PM3


TECHNICAL DATA

Open Generator Set - - 1800 rpm/60 Hz/480 Volts DM8260EPA Certified for Stationary Emergency Application(EPA Tier 2 emissions levels)

Generator Set Package PerformanceGenset Power rating @ 0.8 pfGenset Power rating with fan

1875 kVA1500 ekW

Fuel Consumption100% load with fan75% load with fan50% load with fan

396.0 L/hr 104.6 Gal/hr310.5 L/hr 82.0 Gal/hr219.8 L/hr 58.1 Gal/hr

Cooling System1

Air flow restriction (system)Air flow (max @ rated speed for radiator arrangement)Engine Coolant capacity with radiator/exp. tankEngine coolant capacityRadiator coolant capacity

0.12 kPa 0.48 in. water2075 m³/min 73278 cfm390.8 L 103.2 gal156.8 L 41.4 gal234.0 L 61.8 gal

Inlet AirCombustion air inlet flow rate 129.4 m³/min 4569.7 cfm

Exhaust SystemExhaust stack gas temperatureExhaust gas flow rateExhaust flange size (internal diameter)Exhaust system backpressure (maximum allowable)

403.9 º C 759.0 º F308.9 m³/min 10908.7 cfm203.2 mm 8.0 in6.7 kPa 26.9 in. water

Heat RejectionHeat rejection to coolant (total)Heat rejection to exhaust (total)Heat rejection to aftercoolerHeat rejection to atmosphere from engineHeat rejection to atmosphere from generator

616 kW 35032 Btu/min1322 kW 75182 Btu/min481 kW 27354 Btu/min124 kW 7052 Btu/min94.0 kW 5345.8 Btu/min

Alternator2

Motor starting capability @ 30% voltage dipFrameTemperature Rise

2670 skVA697130 º C 234 º F

Lube SystemSump refill with filter 310.4 L 82.0 gal

Emissions (Nominal)3

NOx g/hp-hrCO g/hp-hrHC g/hp-hrPM g/hp-hr

5.08 g/hp-hr.44 g/hp-hr.11 g/hp-hr.03 g/hp-hr

1 For ambient and altitude capabilities consult your Cat dealer. Air flow restriction (system) is added to existing restriction from factory.2 UL 2200 Listed packages may have oversized generators with a different temperature rise and motor starting characteristics. Generatortemperature rise is based on a 40 degree C ambient per NEMA MG1-32.3 Emissions data measurement procedures are consistent with those described in EPA CFR 40 Part 89, Subpart D & E and ISO8178-1 formeasuring HC, CO, PM, NOx. Data shown is based on steady state operating conditions of 77ºF, 28.42 in HG and number 2 diesel fuelwith 35º API and LHV of 18,390 btu/lb. The nominal emissions data shown is subject to instrumentation, measurement, facility and engineto engine variations. Emissions data is based on 100% load and thus cannot be used to compare to EPA regulations which use valuesbased on a weighted cycle.

February 13 2012 16:44 PM4


RATING DEFINITIONS AND CONDITIONS

Meets or Exceeds International Specifications: AS1359,CSA, IEC60034-1, ISO3046, ISO8528, NEMA MG 1-22,NEMA MG 1-33, UL508A, 72/23/EEC, 98/37/EC,2004/108/ECStandby - Output available with varying load for theduration of the interruption of the normal source power.Average power output is 70% of the standby powerrating. Typical operation is 200 hours per year, withmaximum expected usage of 500 hours per year.Standby power in accordance with ISO8528. Fuel stoppower in accordance with ISO3046. Standby ambientsshown indicate ambient temperature at 100% load whichresults in a coolant top tank temperature just below theshutdown temperature.

Ratings are based on SAE J1349 standard conditions.These ratings also apply at ISO3046 standard conditions.Fuel rates are based on fuel oil of 35º API [16º C (60º F)]gravity having an LHV of 42 780 kJ/kg (18,390 Btu/lb)when used at 29º C (85º F) and weighing 838.9 g/liter(7.001 lbs/U.S. gal.). Additional ratings may be availablefor specific customer requirements, contact your Catrepresentative for details. For information regarding LowSulfur fuel and Biodiesel capability, please consult yourCat dealer.

February 13 2012 16:44 PM5


DIMENSIONS

Package DimensionsLength 5895.0 mm 232.09 inWidth 2537.5 mm 99.9 inHeight 2749.5 mm 108.25 in

NOTE: For reference only - do not use forinstallation design. Please contactyour local dealer for exact weightand dimensions. (GeneralDimension Drawing #2846048).

www.Cat-ElectricPower.com

2012 CaterpillarAll rights reserved.

Materials and specifications are subject to change without notice.The International System of Units (SI) is used in this publication.

CAT, CATERPILLAR, their respective logos, "Caterpillar Yellow," the"Power Edge" trade dress, as well as corporate and product identity used

herein, are trademarks of Caterpillar and may not be used withoutpermission.

19498305

Performance No.: DM8260

Feature Code: 512DE6C

Gen. Arr. Number: 2628100

Source: U.S. Sourced

February 13 2012

6

FIRE PUMP ENGINES

MODELSJU6H-UFADMG JU6H-UFADP0 JU6H-UFADR0 JU6H-UFADT0JU6H-UFAD58 JU6H-UFADP8 JU6H-UFADR8 JU6H-UFADW8

JU6H-UFADNG JU6H-UFADQ0 JU6H-UFADS8 JU6H-UFADX8JU6H-UFADN0 JU6H-UFAD88 JU6H-UFADS0 JU6H-UFAD98

JU6H

MODEL

RATED SPEED US-EPA

(NSPS)

Available

Until

1760 2100 2350 2400

UFADMG 175 131 175 131 No Expiration

UFAD58 183 137 No Expiration

UFADNG 190 142 181 135 183 137 183 137 No Expiration

UFADN0 197 147 197 147 200 149 200 149 No Expiration

UFADP0 209 156 211 157 211 157 No Expiration

UFADP8 220 164 No Expiration

UFADQ0 224 167 226 169 226 169 No Expiration


UFADR0 238 177.5 240 179 240 179 No Expiration

UFADR8 250 187 No Expiration

UFADS8 260 194 No Expiration

UFADS0 260 194 268 200 268 200 No Expiration

UFADT0 274 204 275 205 275 205 No Expiration

UFADW8 282 211 No Expiration

UFADX8 305 227.5 No Expiration


ITEM

JU6H MODELS

MG 58 NG N0 P8 88 P0 Q0 R0 S0 T0 R8 S8 W8 X8 98Number of Cylinders 6

Aspiration TRWA

Rotation* CW

Overall Dimensions – in. (mm) 59.8 (1519) H x 56.7 (1414) L x 36.7 (933) W 60.9 (1547) H x 58.6 (1488) L x 40.0 (1015) W

Crankshaft Centerline Height – in. (mm) 14 (356)

Weight – lb (kg) 1747 (791)

Compression Ratio 19.0:1 17.0:1

Displacement – cu. in. (L) 415 (6.8)

Engine Type 4 Stroke Cycle – Inline Construction

Bore & Stroke – in. (mm) 4.19 x 5.00 (106 x 127)

Installation Drawing D628

Wiring Diagram AC C07651

Wiring Diagram DC C071367, C072146, C071361 C071368, C072146, C071761

Engine Series John Deere 6068 Series Power Tech E John Deere 6068 Series Power Tech Plus

Speed Interpolation N/A

SPECIFICATIONS

Abbreviations: CW – Clockwise TRWA – Turbocharged with Raw Water Aftercooling N/A - Not Available L – Length W – Width H - Height

*Rotation viewed from Heat Exchanger / Front of engine

FM

®

FM-UL-cUL APPROVED RATINGS BHP/KW

CERTIFIED POWER RATING

• Each engine is factory tested to verify power and performance.

• FM-UL power ratings are shown at specific speeds, Clarke engines can be applied at a single rated RPM setting ± 50 RPM.

Picture represents JU6H-TRWA Power Tech Plus Engine Series

USA EPA (NSPS) Tier 3 Emissions Certified Off-Road (40 CFR Part 89) and NSPS Stationary (40 CFR Part 60 Sub Part llll). Meet EU Stage IIIA emission levels.

All Models available for Export

ENGINE RATINGS BASELINES

• Engines are to be used for stationary emergency standby fire pump service only. Engines are to be tested in accordance with NFPA 25.

• Engines are rated at standard SAE conditions of 29.61 in. (752.1 mm) Hg barometer and 77°F (25°C) inlet air temperature [approximates 300 ft. (91.4 m) above sea level] by the testing laboratory (see SAE Standard J 1349).

• A deduction of 3 percent from engine horsepower rating at standard SAE conditions shall be made for diesel engines for each 1000 ft. (305 m) altitude above 300 ft. (91.4 m)

• A deduction of 1 percent from engine horsepower rating as corrected to standard SAE conditions shall be made for diesel engines for every 10°F (5.6°C) above 77°F (25°C) ambient temperature.

ENGINE EQUIPMENTEQUIPMENT STANDARD OPTIONAL

Air Cleaner Direct Mounted, Washable, Indoor Service with Drip Shield Disposable, Drip Proof, Indoor Service Outdoor Type, Single or Two Stage (Cyclonic)

Alarms Overspeed Alarm & Shutdown, Low Oil Pressure, Low & High Coolant Temperature, Low Raw Water Flow, High Raw Water Temperature, Alternate ECM Warning, Fuel Injection Malfunction, ECM Warning and Failure with Automatic Switching

Low Coolant Level, Low Oil Level, Oil Filter Differential Pressure, Fuel Filter Differential Pressure, Air Filter Restriction

Alternator 12V-DC, 42 Amps with Poly-Vee Belt and Guard 24V-DC, 40 Amps with Poly-Vee Belt and GuardCoupling Bare Flywheel UL Listed Driveshaft and Guard, JU6H-

UFAD58/NG/ADMG/ADM8/K0/N0/Q0/R0-CDS30-S1; JU6H-UFADP8/P0/T0/88/R8/S8/S0/W8/X8/98- CDS50-SC at 1760/2100 RPM only

Electronic Control Module 12V-DC, Energized to Stop, Primary ECM always Powered on 24V-DC, Energized to Stop, Primary ECM always Powered onEngine Heater 115V-AC, 1360 Watt 230V-AC, 1360 WattExhaust Flex Connection SS Flex, 150# ANSI Flanged Connection, 5” for JU6H-

UFAD58/MG/NG/N0/P8/88;SS Flex, 150# ANSI Flanged Connection, 6” for JU6H-UFADP0/Q0/R0/S0/T0/R8/S8/W8/X8/98 (w/ orifice plate)

SS Flex, 150# ANSI Flanged Connection, 6” for JU6H-UFAD58/MG/NG/N0/P8/88;SS Flex, 150# ANSI Flanged Connection, 8” for JU6H-UFADP0/Q0/R0/S0/T0/R8/S8/W8/X8/98 (w/ orifice plate)

Exhaust Protection Metal Guards on Manifolds and TurbochargerFlywheel Housing SAE #3Flywheel Power Take Off 11.5” SAE Industrial Flywheel ConnectionFuel Connections Fire Resistant, Flexible, USA Coast Guard Approved, Supply and

Return LinesSS, Braided, cUL Listed, Supply and Return Lines

Fuel Filter Primary Filter with Priming Pump Fuel Injection System High Pressure Common Rail

Governor, Speed Dual Electronic Control ModulesHeat Exchanger Tube and Shell Type, 60 PSI (4 BAR), NPT(F) Connections – Sea

Water CompatibleInstrument Panel Multimeter to Display English and Metric, Tachometer, Hourmeter,

Water Temperature, Oil Pressure and One (1) Voltmeter with Toggle Switch, Front Opening

Junction Box Integral with Instrument Panel; For DC Wiring Interconnection to Engine Controller

Lube Oil Cooler Engine Water Cooled, Plate TypeLube Oil Filter Full Flow with By-Pass ValveLube Oil Pump Gear Driven, Gear TypeManual Start Control On Instrument Panel with Control Position Warning LightOverspeed Control Electronic, Factory Set, Not Field AdjustableRaw Water Cooling Loop w/Alarms

Galvanized Seawater, All 316SS, High Pressure

Raw Water Cooling Loop Solenoid Operation

Automatic from Fire Pump Controller and from Engine Instrument Panel (for Horizontal Fire Pump Applications)

Not Supplied (for Vertical Turbine Fire Pump Applications)

Run – Stop Control On Instrument Panel with Control Position Warning LightStarters Two (2) 12V-DC Two (2) 24V-DC

Throttle Control Adjustable Speed Control by Increase/Decrease Button, Tamper Proof in Instrument Panel

Water Pump Centrifugal Type, Poly-Vee Belt Drive with Guard

C133421 revR19JUN15

Specifications and information contained in this brochure subject to change without notice.

FIRE PUMP ENGINES

Fire Protection Products, Inc.100 Progress Place, Cincinnati, Ohio 45246United States of AmericaTel +1-513-475-FIRE(3473) Fax +1-513-771-8930www.clarkefire.com

UK, Ltd.Grange Works, Lomond Rd., Coatbridge, ML5-2NNUnited KingdomTel +44-1236-429946 Fax +44-1236-427274www.clarkefire.com

®

®

Abbreviations: DC – Direct Current, AC – Alternating Current, SAE – Society of Automotive Engineers, NPT(F) – National Pipe Tapered Thread (Female), ANSI – American National Standards Institute, SS – Stainless Steel

MODELSJU6H-UFADMG JU6H-UFADP0 JU6H-UFADR0 JU6H-UFADT0JU6H-UFAD58 JU6H-UFADP8 JU6H-UFADR8 JU6H-UFADW8

JU6H-UFADNG JU6H-UFADQ0 JU6H-UFADS8 JU6H-UFADX8JU6H-UFADN0 JU6H-UFAD88 JU6H-UFADS0 JU6H-UFAD98

JU6H - UFADR0John Deere Base Engine

350 Series6 Cylinders

Heat Exchanger Cooled

Power Curve NumberEPA Tier 3 CertifiedBuilt in USAFM ApprovedUL Listed

MODEL NOMENCLATURE: (10 Digit Models)

JU6H-UFAD88

USA ProducedINSTALLATION & OPERATION DATA (I&O Data)

Basic Engine Description Engine Manufacturer John Deere Co. Ignition Type Compression (Diesel) Number of Cylinders 6 Bore and Stroke - in (mm) 4.19 (106) X 5 (127) Displacement - in³ (L) 415 (6.8) Compression Ratio 19.0:1 Valves per cylinder

Intake 1

Exhaust 1 Combustion System Direct Injection Engine Type In-Line, 4 Stroke Cycle Fuel Management Control Electronic, High Pressure Common Rail Firing Order (CW Rotation) 1-5-3-6-2-4 Aspiration Turbocharged Charge Air Cooling Type Raw Water Rotation, viewed from front of engine, Clockwise (CW) Standard Engine Crankcase Vent System Open Installation Drawing D628 Weight - lb (kg) 1747 (792)

Power Rating 1760 Nameplate Power - HP (kW) 237 (177)

Cooling System - [C051386] 1760 Engine Coolant Heat - Btu/sec (kW) 80 (84.4) Engine Radiated Heat - Btu/sec (kW) 54 (57) Heat Exchanger Minimum Flow

60°F (15°C) Raw H20 - gal/min (L/min) 13 (49.2)

100°F (37°C) Raw H20 - gal/min (L/min) 20 (75.7) Heat Exchanger Maximum Cooling Raw Water

Inlet Pressure - psi (bar) 60 (4.1)

Flow - gal/min (L/min) 40 (151) Typical Engine H20 Operating Temp - °F (°C)[1] 180 (82.2) - 195 (90.6) Thermostat

Start to Open - °F (°C) 180 (82.2)

Fully Opened - °F (°C) 203 (95) Engine Coolant Capacity - qt (L) 20.5 (19.4) Coolant Pressure Cap - lb/in² (kPa) 15 (103) Maximum Engine Coolant Temperature - °F (°C) 230 (110) Minimum Engine Coolant Temperature - °F (°C) 160 (71.1) High Coolant Temp Alarm Switch - °F (°C)[2] 235 (113) - 241 (116)

Electric System - DC Standard Optional System Voltage (Nominal) 12 24 Battery Capacity for Ambients Above 32°F (0°C)

Voltage (Nominal) 12 [C07633] 24 [C07633]

Qty. Per Battery Bank 1 2 SAE size per J537 8D 8D CCA @ 0°F (-18°C) 1400 1400 Reserve Capacity - Minutes 430 430

Battery Cable Circuit, Max Resistance - ohm 0.0012 0.0012 Battery Cable Minimum Size

0-120 in. Circuit Length[3] 00 00

121-160 in. Circuit Length[3] 000 000 161-200 in. Circuit Length[3] 0000 0000

Charging Alternator Maximum Output - Amp, 40 [C071363] 55 [C071365] Starter Cranking Amps, Rolling - @60°F (15°C) 440 [RE69704/RE70404] 250 [C07819/C07820]

NOTE: This engine is intended for indoor installation or in a weatherproof enclosure. 1Engine H2O temperature is dependent on raw water temperature and flow. 2High Coolant Switch threshold varies with engine load. 3Positive and Negative Cables

Combined Length.

Page 1 of 2

JU6H-UFAD88

USA ProducedINSTALLATION & OPERATION DATA (I&O Data)

Exhaust System 1760 Exhaust Flow - ft.³/min (m³/min) 1189 (33.7) Exhaust Temperature - °F (°C) 986 (530) Maximum Allowable Back Pressure - in H20 (kPa) 30 (7.5) Minimum Exhaust Pipe Dia. - in (mm)[4] 5 (127)

Fuel System 1760 Fuel Consumption - gal/hr (L/hr) 12 (45.4) Fuel Return - gal/hr (L/hr) 16.6 (62.8) Fuel Supply - gal/hr (L/hr) 28.6 (108) Fuel Pressure - lb/in² (kPa) 3 (20.7) - 6 (41.4) Minimum Line Size - Supply - in. .50 Schedule 40 Steel Pipe

Pipe Outer Diameter - in (mm) 0.848 (21.5) Minimum Line Size - Return - in. .375 Schedule 40 Steel Pipe

Pipe Outer Diameter - in (mm) 0.675 (17.1) Maximum Allowable Fuel Pump Suction Lift

with clean Filter - in H20 (mH20) 80 (2)

Maximum Allowable Fuel Head above Fuel pump, Supply or Return - ft (m) 6.6 (2) Fuel Filter Micron Size 2 (Secondary)

Heater System Standard Optional Engine Coolant Heater

Wattage (Nominal) 1360 1360 Voltage - AC, 1 Phase 115 (+5% -10%) 230 (+5%, -10%) Part Number [C123640] [C123644]

Air System 1760 Combustion Air Flow - ft.³/min (m³/min) 457 (12.9) Air Cleaner Standard Optional

Part Number [C03396] [C03327] Type Indoor Service Only, Canister,

with Shield Single-Stage Cleaning method Washable Disposable

Air Intake Restriction Maximum LimitDirty Air Cleaner - in H20 (kPa) 10 (2.5) 10 (2.5)

Clean Air Cleaner - in H20 (kPa) 6 (1.5) 5 (1.2) Maximum Allowable Temperature (Air To Engine Inlet) - °F (°C)[5] 130 (54.4)

Lubrication System Oil Pressure - normal - lb/in² (kPa) 40 (276) - 60 (414) Low Oil Pressure Alarm Switch - lb/in² (kPa)[6] 30 (207) to 35 (241) In Pan Oil Temperature - °F (°C) 220 (104) - 245 (118) Total Oil Capacity with Filter - qt (L) 21.1 (20)

Lube Oil Heater Optional Optional Wattage (Nominal) 150 150 Voltage 120V (+5%, -10%) 240V (+5%, -10%) Part Number C04430 C04431

Performance 1760 BMEP - lb/in² (kPa) 257 (1770) Piston Speed - ft/min (m/min) 1467 (447) Mechanical Noise - dB(A) @ 1m C133373 Power Curve C132682 4Based on Nominal System. Back pressure flow analysis must be done to assure maximum allowable back pressure is not exceeded. (Note:

minimum exhaust Pipe diameter is based on: 15 feet of pipe, one 90° elbow, and a silencer pressure drop no greater than one half of the maximum allowable back pressure.) 5Review for horsepower derate if ambient air entering engine exceeds 77°F (25°C). 6Low Oil Pressure Switch threshold

varies w/engine speed. [ ] indicates component reference part number.

Page 2 of 2C132910 Rev F

KJK 09JAN15

HEATER SPECIFICATION SHEET

CUSTOMER Mulcare Pipeline Solutions DATE 15-Jul-16

ADDRESS 9 Mars Court CUSTOMER REFERENCE Hanover Engineering - Line Heater

CITY/STATE/ZIP Boonton Twp, NJ 07005 CUSTOMER PROJECT NO.

LOCATION Pennsylvania QUOTATION ITEM NUMBER

STATION OPERATING DATA 1450 psig 45°F / 1442 psig 96°F

ENGINEER Brian Shomper

PURCHASING AGENT

REMARKS

DIAMETER (inches) 120 BATH MEDIA VOLUME (Gal) 11,680 ETHYLENE GLYCOL 50/50

LENGTH (ft) 36' - 0" HEATER WEIGHT (DRY lbs) 78,360 HORIZONTAL -

WIDTH (ft) 10' - 6" HEATER WEIGHT (WET lbs) 183,780

HEIGHT (ft) (Shipping / Top of Stack) 10' - 6" / 16' - 6" POWER INPUT 480 VAC / 60 hz / 3 PH

NOMINAL RATING (MMBtu/hr) 10.9351

REMARKS

INLET OUTLET Forced Draft Burner

TYPE OF FLUID Natural Gas Natural Gas Blower Motor (HP) 5

TOTAL FLUID ENTERING SCFH 6,675,000 6,675,000 Sparging System NO

VAPOR lb/hr 305,768 305,768 Sparging System Motor (HP) NA

LIQUID lb/hr ------ ------ Safety include:

STEAM lb/hr ------ ------ Low Water Level

NON-CONDENSABLE lb/hr ------ ------ High Water Temp

FLUID VAPORIZED OR COND lb/hr ------ ------ Pilot Flame Failure

LIQUID DENSITY lbs/ft3 ------ ------ Controls Include:

LIQUID VISCOSITY cP ------ ------ Water Temp Control

LIQUID SPECIFIC HEAT Btu/lb-F ------ ------ Nat Gas Disch Temp Control

LIQUID THERMAL COND Btu/hr-ft-F ------ ------

VAPOR MOLECULAR WT lbs/lbs Mol 17.343 ------

VAPOR DENSITY lbs/ft3 5.9032 4.9277 Fluid Specific Gravity 0.600

VAPOR VISCOSITY cP 0.0143 0.0145 After Regulation (psig) 675

VAPOR SPECIFIC HEAT Btu/lb-F 0.7446 0.6695 After Regulation (F) 60

VAPOR THERMAL COND Btu/hr-ft-F 2.44E-02 2.48E-02 MINIMUM SUPPLY PRESSURE (MSP)

TEMPERATURE (IN/OUT) F 45 96 Outlet Temp at MSP (F) NA

OPERATING PRESSURE psig 1450 1442 Min Supply Press (psig) NA

VELOCITY ft/sec ------ 32 VEL @ Min Oper Press (ft/sec) NA

PRESSURE DROP (ALLOW/EST) psid 10 8 Press Drop at MPS (psid) NA

FOULING RESISTANCE hr-ft2-f/Btu ------ ------

HEAT TRANSFERRED Btu/hr 10,935,096 Operating Bath Temperature 180.0 F

BURNER'S HEAT RELEASE (LHV) Btu/hr 13,668,869 Minimum Ambient Tempeature -20 F

TRANSFER RATE (FOULED/CLEAN) Btu/hr-ft2-F 61.34 Maximum Ambient Temperature 100 F

TEMPERATURE DIFF (LMTD) 107

MAWP psig 1480 Fabrication Code ASME Section VIII Div 1

TEST PRESSURE psig 2220 Radiographic (Percentage) 100%

DESIGN TEMPERATURE F -20F to 250F National Board Stamped Yes

NUMBER OF PASS / PATH 12 Coil Material SA-106 Grade B Smls

NUMBER OF PATHS 6 Coil Hydrotest Note: 1.5 x MAWP for 4 hours Charted

TOTAL NUMBER OF TUBES 72

STRAIGHT TUBE LENGTH ft 1620 Inlet 10 inch ANSI 900# RF

TYPE Serpentine Outlet 10 inch ANSI 900# RF

REMOVABLE Yes Inlet Header thk 0.594 in

HEAT FLUX Btu/hr-ft2 5,734 Inlet Header Velocity 29 ft/sec

TUBE SIZE inches OD 4.5 Outlet Header thk 0.594 in

TUBE WALL THICKNESS inches 0.237 Outlet Header Velocity 35 ft/sec

CORROSION ALLOWANCE inches ------ Surface Area Actual 1909 ft2

REMARKS

DESIGN CODE ASME CSD-1

SHELL DIAMETER inches 120 Shell Pressure Test: 5 psig for 1 hour

SHELL LENGTH ft 26

SHELL (THICK) inches 3/8

FIRETUBE DIAMETER inches OD 30 / 4

NUMBER OF FIRETUBES 2 / 32

EACH FIRE / RETURN TUBE LENGTH ft 22 / 22

FIRE TUBE MATERIAL/THICKNESS inches 0.25 / 0.109

FIRE TUBE HEAT DENSITY Btu/hr-in2 10,000

FIRE TUBE FLUX RATE Btu/hr-ft2 10,173

REMOVABLE No

STACK DIAMETER (NO OF STACK/OD) inches 2 / 24 STACK MATERIAL SS304

STACK HEIGHT (ACT / OF GRADE) ft 6 WALL THICKNESS Gauge 10 (0.1406" Thick)

EXPANSION TANK DIAMETER inches 36 EXPANSION TANK MATERIAL Carbon Steel

EXPANSION TANK LENGTH ft 14 WALL THICKNESS 1/4 inches

PERCENT OF NET SHELL VOL % 6

Forced Draft Line Heater

HEATER DATA

BASIC HEATER DATA

REMARKS

PROCESS CONDITIONS

THERMAL DATA

PROCESS COIL

Power Flame Incorporated 9/28/2006Rev. 02/28/2012

Typical Flue Product Emissions Data for Power Flame Burners

Natural Gas L.P. Gas # 2 Fuel Oil (1)

Carbon Monoxide - CO .037 lb CO 106 BTU input .037 lb CO 106 BTU input .037 lb per 106 BTU INPUT(50 PPM) (50 PPM) (50 PPM)

Sulfur Dioxide - SO2 (1.05) x (% Sulfur by weight in fuel) = lb SO2 per 106 BTU Input

Particulate Matter .0048 lb PM per 106 BTU input .0048 lb PM per 106 BTU input .0143 lb PM per 106 BTU input

Hydrocarbons .025 lb HC's per 106 BTU input .025 lb HC's per 106 BTU input .038 lb HC's per 106 BTU input

CO2 9 % to 10% 10% to 12% 10% to 13%

Nitrogen Oxides - NOx

.088 lb NOx per 106 BTU input .092 lb NOx per 106 BTU input N/A(75 PPM) (75 PPM) N/A

Standard C(R) Burners .088 lb NOx per 106 BTU input .092 lb NOx per 106 BTU input .12 lb NOx per 106 BTU Input

(75 PPM) (75 PPM) (90) PPM(2)

LNIC(R) Burners .029 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input .12 lb NOx per 106 BTU Input

Fire box/Cast Iron boilers (25 PPM) (25 PPM) (90) PPM(2)

LNIC(R) Burners .024 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input .12 lb NOx per 106 BTU Input

Water tube boilers (20 PPM) (25 PPM) (90) PPM(2)

LNIAC Burners .029 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input .12 lb NOx per 106 BTU Input(25 PPM) (25 PPM) (90) PPM

CM Burners .070 lb NOx per 106 BTU input .074 lb NOx per 106 BTU input .146 lb NOx per 106 BTU Input(60 PPM)(4) (60 PPM)(4) (110) PPM

LNICM Burners .033 lb NOx per 106 BTU input .033 lb NOx per 106 BTU input .12 lb NOx per 106 BTU InputScotch Boiler (30) PPM (30) PPM (90) PPMLNICM Burners .029 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input .12 lb NOx per 106 BTU InputFire box/Cast Iron boilers (25) PPM (25) PPM (90) PPMLNICM Burners .029 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input .12 lb NOx per 106 BTU InputWater tube boilers (20) PPM (20) PPM (90) PPMNPM Premix Burners .029 lb NOx per 106 BTU input .031 lb NOx per 106 BTU input N/A

(25) PPM (25) PPM N/ANova Plus Burners .010 lb NOx per 106 BTU input .015 lb NOx per 106 BTU input N/ANVC AND NP2 ( 9) PPM (12) PPM N/A

(1)

(2) 90 PPM NOx on cast iron sectional, fire box and water tube boiler, 120 PPM on fire tube boilers. (.159 lb NOx per 106 BTU Input)(3) Burning natural gas the VOC are estimated at 0.003 # per million BTU and SOX are 0.0005 # per million BTU.(4) In some applications the CMAX will achieve less than 60 PPM without flue gas recirculation - consult factory.

These emission rates are general estimates and do not constitute guarantees by Power Flame Inc. In instances where guarantees are required, please consult the factory with the specific application information. All NOx numbers stated are corrected to 3% O2

NOx emissions at 3 % 02 will vary based on the percent of fuel bound nitrogen (these are based on .02%) and boiler or heat exchanger configurations

Standard J, FDM & X4 Gas Burners

ksridharan

Rectangle

ksridharan

Rectangle

ksridharan

Callout

Ultra Low NOx Burners

gmartin

Rectangle

gmartin

Rectangle

gmartin

Callout

LOW NOx


APPENDIX M RBLC CLEARINGHOUSE DETERMINATION SUMMARIES

Renovo Energy CenterPowerblocksRBLC Search ResultsNitrogen Oxides (NOx)

RBLC ID Facility Name State Permit Date Process Name/Description Fuel Size Units Control Description Limit Units Averaging Period BasisMI-0406 RENAISSANCE POWER LLC MI 11/01/2013 &Natural gas fueled combined cycle combustion turbine generators Natura 2807 MMBTU/H SCR and DLN 2 PPMVOL 3-H ROLL AVG., EXC BACT-PSDNJ-0074 WEST DEPTFORD ENERGY NJ 5/6/2009 TURBINE, COMBINED CYCLE NG 17298 MMFT3/YR SCR and water injection 2 ppmvd @ 15% O2 3 HR ROLLING AVERLAERNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012 Combined Cycle Combustion Turbine NG 39463 MMCF/year SCR 2 PPMVD AVERAGE OF THREE LAER*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018 COMBUSTION TURBINE UNIT w/o DUCT BURNERS UNIT NG 2665.9 MMBtu/hr SCR 2 PPMDV @15% O2 LAER*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Combined-Cycle Combustion Turbine NG 3864 mmBtu/hr SCR and DLN 2 PPMV 3-UNIT OPERATING LAERVA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2012 COMBUSTION TURBINE GENERATORS, (3) NG 3442 MMBtu/hr SCR and DLN 2 ppmvd @ 15% O2 1 H AVG BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 GE Combustion Turbine - Option 1 - Normal Operation NG 34000 MMCF/YR SCR and DLN 2 ppmvd @ 15% O2 1 H AV BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Siemens Combusion Turbine - Option 2 - Normal Operation NG 35000 MMCF/YR SCR and DLN 2 ppmvd @ 15% O2 1 H AV BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016 COMBUSTION TURBINE GENERATOR WITH DUCT-FIRED HEAT RECO NG 3227 MMBtu/hr SCR 2 PPMVD 1 HR AVG N/A*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018 Combustion Turbine Firing NG NG 0 SCR 2 PPMDV CORRECTED TO 15% LAER*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017 Combustion Turbine without Duct Burner NG 3509 MMBtu/hr 2 PPMDV CORRECTED TO 15% LAER*TN-0164 TVA - JOHNSONVILLE COGENERATION TN 2/1/2018 Dual-fuel CT and HRSG with duct burner NG 1020 MMBtu/hr SCR, good combustion design & practices 2 ppmvd @ 15% O2 30-DAY AVG WHEN BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 1-on-1 combined cycle unit (GE 7HA) NG 3266.9 MMBtu/hr SCR and DLN 2 ppmvd @ 15% O2 24-HOUR BLOCK AV BACT-PSDTX-0641 PINECREST ENERGY CENTER TX 11/12/2013 combined cycle turbine NG 700 MW SCR 2 PPMVD 24-HR ROLLING AVG BACT-PSDTX-0834 MONTGOMERY COUNTY POWER STATIOIN TX 3/30/2018 Combined Cycle Turbine NG 2635 MMBtu/hr SCR and DLN 2 PPMVD 15% O2 1-HOUR AVLAERMI-0431 INDECK NILES LLC MI 6/26/2018 FGCTGHRSG (2 Combined Cycle CTG with HRSGs) NG 3421 MMBtu/hr SCR with DLN 2 PPM AT 15%O2; 24-HR R BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 EUCTGHRSG (South Plant): A combined cycle natural gas-fired com NG 500 MW SCR with DLN 2 PPMV AT 15%O2; 24-HR R BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 EUCTGHRSG (North Plant): A combined-cycle natural gas-fired com NG 500 MW SCR with DLN 2 PPMVD AT 15%O2; 24-H RO BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 Combined Cycle Combustion Turbines NG 3474 mmBtu/hr SCR with DLN; water injection (ULSD) 2 ppmvd @ 15% O2 3-UNIT OPERATING LAERMI-0432 NEW COVERT GENERATING FACILITY MI 7/30/2018 FG-TURB/DB1-3 (3 combined cycle combustion turbine and heat re NG 1230 MW Good combustion practices, DLN burners, SCR 2 PPMVD AT 15%O2; EACH IN BACT-PSDPA-0306 TENASKA PA PARTNERS/WESTMORELAND GE PA 2/12/2016 Large combustion turbine NG 0 SCR, DLN, and good combustion practice 2 ppmvd @ 15% O2 LAERPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY G PA 6/15/2015 Two Combine Cycle Combustion Turbine with Duct Burner NG 3001.57 MCF/hr SCR, DLN, good combustion practices 2 ppmvd @ 15% O2 LAERPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015 Combustion Turbine With Duct Burner NG 3727 MMBtu/hr DLN burner, SCR, good engineering practice 2 ppmvd @ 15% O2 LAERPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016 Combustion turbine and HRSG with duct burner NG only NG 3338 MMBtu/hr DLN, SCR, good combustion & operating practice 2 ppmvd @ 15% O2 LAERPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Combustion turbine with duct burner NG 3304.3 MMBtu/hr DLN, SCR, exclusive natural gas 2 ppmvd @ 15% O2 LAERTN-0162 JOHNSONVILLE COGENERATION TN 4/19/2016 Natural Gas-Fired Combustion Turbine with HRSG NG 1339 MMBtu/hr Good combustion design and practices, SCR 2 ppmvd @ 15% O2 30 UNIT-OPERATING BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 Natural Gas w/Duct Firing NG 2639 MMBtu/hr SCR 2 ppmvd @ 15% O2 1 HOUR BLOCK LAERMD-0041 CPV ST. CHARLES MD 4/23/2014 2 COMBINED-CYCLE COMBUSTION TURBINES NG 725 MW SCR and DLN 2 ppmvd @ 15% O2 3-HOUR BLOCK AVE LAERNJ-0079 WOODBRIDGE ENERGY CENTER NJ 7/25/2012 Combined Cycle Combustion Turbine w/o duct burner NG 40297.6 MMCF/year SCR and DLN 2 PPMVD 3-HR ROLLING AVE LAERNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012 Combined cylce turbine with duct burner NG 39463 MMCF/year SCR 2 PPMVD 3-HR ROLLING AVER LAERCT-0157 CPV TOWANTIC, LLC CT 11/30/2015 Combined Cycle Power Plant NG 21200000 MMBtu/12 SCR 2 ppmvd @ 15% O2 1 HR BLOCK LAER*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014 2 COMBINED CYCLE COMBUSTION TURBINES, WITH DUCT FIRING NG 1000 MW SCR and DLN 2 ppmvd @ 15% O2 3-HOUR BLOCK AVE LAER*TX-0660 FGE TEXAS POWER I AND FGE TEXAS POWER I TX 3/24/2014 Alstom Turbine NG 230.7 MW SCR 2 PPMVD CORRECTED TO 15% BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 Turbines and duct burners - NG NG 0 SCR and DLN 2 ppmvd @ 15% O2 1 H LAERTX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 Combined Cycle Turbine with Heat Recovery Steam Generator, fire NG 426 MW SCR and DLN 2 PPMVD 15% O2 3-H AVG BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016 Combined Cycle Combustion Turbine firing Natural Gas with Duct NG 4000 h/yr SCR and DLN 2 ppmvd @ 15% O2 3 H ROLLING AV BA LAERNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016 Combined Cycle Combustion Turbine firing Natural Gas without Du NG 8040 H/YR SCR and DLN 2 ppmvd @ 15% O2 3 H ROLLING AV BA LAERTX-0788 NECHES STATION TX 3/24/2016 Combined Cycle & Cogeneration NG 231 MW SCR 2 PPM BACT-PSDOK-0154 MOORELAND GENERATING STA OK 7/2/2013 Combustion Turbine NG 360 MW SCR and DLN 2 ppmvd @ 15% O2 ONE-HR BACT-PSDOK-0154 MOORELAND GENERATING STA OK 7/2/2013 COMBUSTION TURBINE NG 360 MW SCR and DLN 2 ppmvd @ 15% O2 ONE-HR BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterPowerblocksRBLC Search ResultsCarbon Monoxide (CO)

RBLC ID Facility Name State Permit Date Process Name/Description Fuel Size Units Control Description Limit Units Averaging Period BasisCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 Natural Gas w/o Duct Firing NG 2969 MMBtu/hr Oxidation Catalyst 0.9 ppmvd @ 15% O2 1 HOUR BLOCK BACT-PSDNJ-0082 WEST DEPTFORD ENERGY STATIONNJ 7/18/2014 Combined Cycle Combustion Turbine without Duct Burner NG 20282 MMCF/YR Oxidation Catalyst and use of natural gas 0.9 ppmvd @ 15% O2 3-HR ROLLING AVE BAS BACT-PSDCT-0157 CPV TOWANTIC, LLC CT 11/30/2015 Combined Cycle Power Plant NG 21200000 MMBtu/12 Oxidation Catalyst 0.9 ppmvd @ 15% O2 1 HR BLOCK BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 GE Combustion Turbine - Option 1 - Normal Operation NG 34000 MMCF/YR Oxidation catalyst, good combustion practices 1 ppmvd @ 15% O2 3 HR AV/WITHOUT DB BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATVA 3/12/2013 Three Mitsubishi M501 GAC Turbines (3,442 mmBtu/hr each) NG 3342 MMBtu/hr Oxidation catalyst and good combustion practices inc 1.5 PPMVD 3-HOUR ROLLING AVG W BACT-PSD*MD-0042 WILDCAT POINT GENERATION FAC MD 4/8/2014 2 COMBINED CYCLE COMBUSTION TURBINES, WITHOUT DUCT FIRING NG 270 MW EXCLUSIVE USE OF PIPELINE QUALITY NATURAL GAS, 1.5 ppmvd @ 15% O2 3-HOUR BLOCK AVERAG BACT-PSDNJ-0082 WEST DEPTFORD ENERGY STATIONNJ 7/18/2014 Combined Cycle Combustion Turbine with Duct Burner NG 20282 MMCF/YR Oxidation catalyst and use of natural gas a clean burn 1.5 ppmvd @ 15% O2 3-HR ROLLING AVE BAS BACT-PSDVA-0315 WARREN COUNTY POWER PLANT - VA 12/17/2010 COMBINED CYCLE TURBINE & DUCT BURNER, 3 NG 2996 MMBtu/hr Oxidation catalyst and good combustion practices. 1.5 PPMVD ONE HR AVERAGE (W/O BACT-PSDCA-1212 PALMDALE HYBRID POWER PROJECCA 10/18/2011 COMBUSTION TURBINES (NORMAL OPERATION) NG 154 MW Oxidation Catalyst 1.5 PPMVD @15% O2, 1-HR AVG (N BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016 COMBUSTION TURBINE GENERATOR WITH DUCT-FIRED HEAT RECOVERY STEAM NG 3227 MMBtu/hr Oxidation Catalyst 1.6 PPMVD 3 HR AVG N/ACT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 Natural Gas w/Duct Firing NG 2639 MMBtu/hr Oxidation Catalyst 1.7 LB/MMBTU 1 HOUR BLOCK BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Siemens Combusion Turbine - Option 2 - Normal Operation NG 35000 MMCF/YR Oxidation catalyst & good combustion practice 1.8 ppmvd @ 15% O2 3 H AV/WITH OR WITHO BACT-PSDVA-0322 GREEN ENERGY PARTNERS/ STONE VA 4/30/2013 Large combustion turbines (>25MW) CCT1 and CCT2 NG 2.23 MMBtu/hr Catalytic Oxidizer 2 PPMVD BACT-PSDNJ-0074 WEST DEPTFORD ENERGY NJ 5/6/2009 TURBINE, COMBINED CYCLE NG 17298 MMFT3/YR Oxidation Catalyst 2 ppmvd @ 15% O2 3 HR ROLLING AVERAGEBACT-PSD*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018 COMBUSTION TURBINE UNIT w/o DUCT BURNERS UNIT NG 2665.9 MMBtu/hr Oxidation Catalyst 2 PPPDV @15% O2 BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Combined-Cycle Combustion Turbine NG 3864 mmBtu/hr Oxidation catalyst 2 PPMV 3 OPERATING HOUR AV BACT-PSD*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017 Combustion Turbine without Duct Burner NG 3509 MMBtu/hr Oxidation Catalyst 2 PPMDV CORRECTED TO 15% O2 BACT-PSD*TN-0164 TVA - JOHNSONVILLE COGENERAT TN 2/1/2018 Dual-fuel CT and HRSG with duct burner NG 1020 MMBtu/hr Oxidation catalyst, good combustion design & practic 2 ppmvd @ 15% O2 30-DAY AVG WHEN BUR BACT-PSDTX-0641 PINECREST ENERGY CENTER TX 11/12/2013 combined cycle turbine NG 700 MW oxidation catalyst 2 PPMVD 3-HR ROLL AVG, 15% OX BACT-PSDTX-0834 MONTGOMERY COUNTY POWER S TX 3/30/2018 Combined Cycle Turbine NG 2635 MMBtu/hr Oxidation Catalyst 2 PPMVD 15% O2 3 HOUR AVERA BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTE IL 7/30/2018 Combined Cycle Combustion Turbines NG 3474 mmBtu/hr Oxidation catalyst 2 ppmvd @ 15% O2 3 OPERATING-HOUR, RO BACT-PSDMI-0432 NEW COVERT GENERATING FACILITMI 7/30/2018 FG-TURB/DB1-3 (3 combined cycle combustion turbine and heat recovery steam NG 1230 MW Oxidation catalyst technology and good combustion 2 PPMVD EACH CT/HRSG TRAIN; 2 BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 EL PA 6/15/2015 Two Combine Cycle Combustion Turbine with Duct Burner NG 3001.57 MCF/hr Oxidation catalyst and good combustion practices 2 ppmvd @ 15% O2 BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PL PA 9/1/2015 Combustion Turbine With Duct Burner NG 3727 MMBtu/hr Oxidation catalyst and good combustion practices 2 ppmvd @ 15% O2 BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PL PA 9/1/2015 Combustion Turbine without Duct Burner NG 0 Oxidation catalyst, good engineering practice 2 ppmvd @ 15% O2 BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016 Combustion turbine and HRSG with duct burner NG only NG 3338 MMBtu/hr Oxidation catalyst operated at all steady state operat 2 ppmvd @ 15% O2 BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSU PA 12/23/2015 Combustion turbine with duct burner NG 3304.3 MMBtu/hr Oxidation catalyst, combustion controls, exclusive na 2 ppmvd @ 15% O2 BACT-PSDTN-0162 JOHNSONVILLE COGENERATION TN 4/19/2016 Natural Gas-Fired Combustion Turbine with HRSG NG 1339 MMBtu/hr Good combustion design and practices, oxidation cat 2 ppmvd @ 15% O2 30 UNIT-OPERATING-DA BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014 2 COMBINED-CYCLE COMBUSTION TURBINES NG 725 MW Oxidation catalyst and good combustion practices 2 ppmvd @ 15% O2 3-HOUR BLOCK AVERAG BACT-PSDNJ-0079 WOODBRIDGE ENERGY CENTER NJ 7/25/2012 Combined Cycle Combustion Turbine w/o duct burner NG 40297.6 MMcf/yr Oxidation Catalyst, good combustion practices and u 2 PPMVD 3-HR ROLLING AVE BAS BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012 Combined cylce turbine with duct burner NG 39463 MMcf/yr Oxidation catalyst 2 PPMVD 3-HR ROLLING AVERAGE BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENE PA 1/31/2013 Combined Cycle Power Blocks 472 MW - (2) NG 0 CO Catalyst 2 PPMDV BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 2 COMBINED-CYCLE COMBUSTION TURBINES NG 286 MW Good combustion practice and oxidation catalyst. 2 ppmvd @ 15% O2 3-HOUR BLOCK AVERAG BACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POW PA 10/10/2012 Combined-cycle Turbines (2) - Natural gas fired NG 3277 MMBtu/hr Oxidation Catalyst 2 PPMVD @15% O2 BACT-PSD*TX-0660 FGE TEXAS POWER I AND FGE TEXA TX 3/24/2014 Alstom Turbine NG 230.7 MW Oxidation catalyst 2 PPMVD CORRECTED TO 15% O2 BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 Turbines and duct burners - NG NG 0 Good combustion practice and oxidation catalyst. 2 ppmvd @ 15% O2 1 H BACT-PSDTX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 Combined Cycle Turbine with Heat Recovery Steam Generator, fired Duct Burne NG 426 MW SCR and dry low NOx burners 2 PPMVD 15% O2 3-H AVG BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016 Combined Cycle Combustion Turbine firing Natural Gas with Duct Burner NG 4000 h/yr Oxidation Catalyst and good combustion practices 2 ppmvd @ 15% O2 3 H ROLLING AV BASED BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 2 COMBINED-CYCLE COMBUSTION TURBINES NG 235 MW Good combustion practice and oxidation catalyst. 2 ppmvd @ 15% O2 3-HOUR BLOCK AVERAGBACT-PSDOK-0154 MOORELAND GENERATING STA OK 7/2/2013 Combustion Turbine NG 360 MW Oxidation catalyst and good combustion practice. 2 ppmvd @ 15% O2 3-HR BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterPowerblocksRBLC Search ResultsParticulate Matter (PM/PM10/PM2.5)

RBLC ID Facility Name StatePermit Date Process Name/Description

Fuel Type Size Units Control Description

Emission Limit Units Averaging Period Basis

MI-0427 FILER CITY STATION MI 11/17/2017 EUCCT (Combined cycle CTG with unfired HRSG) NG 1934.7 MMBtu/hr Good combustion practices and the use of pipel 0.0025 lb/MMBtu BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Combined-Cycle Combustion Turbine NG 3864 MMBtu/hr Good combustion practices 0.0026 lb/MMBtu 3-HR BLOCK AVERAGE BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Combustion turbine with duct burner NG 3304.3 MMBtu/hr Exclusive natural gas, high-efficiency inlet air filt 0.003 lb/MMBtu BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATIONVA 3/12/2013 COMBUSTION TURBINE GENERATORS, (3) NG 3442 MMBtu/hr Low sulfur/carbon fuel and good combustion pr 0.0033 lb/MMBtu 3 H AVG/WITHOUT DUCT BURNING BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 FGCCA or FGCCB--4 nat. gas fired CTG w/ DB for HRSG NG 2587 MMBtu/hr Combustion air filters; efficient combustion con 0.0033 lb/MMBtu TEST PROTOCOL; (3 1-H TESTS IF PO BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC OH 11/7/2017 General Electric Combustion Turbine (P004) NG 3544 MMBtu/hr natural gas or a natural gas and ethane mixture 0.0036 lb/MMBtu BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 Combined Cycle Combustion Turbines NG 3474 MMBtu/hr Good combustion practices 0.0037 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016 COMBUSTION TURBINE GENERATOR WITH DUCT-FIRED HEAT REC NG 3227 MMBtu/hr Pipeline Quality Natural Gas 0.0039 lb/MMBtu AVG OF 3 TEST RUNS N/APA-0306 TENASKA PA PARTNERS/WESTMORELA PA 2/12/2016 Large combustion turbine NG 0 Good combustion practices with the use of low 0.0039 lb/MMBtu BACT-PSDMI-0405 MIDLAND COGENERATION VENTURE MI 4/23/2013 Natural gas fueled combined cycle combustion turbine generator NG 2486 MMBtu/hr Good combustion practices 0.004 lb/MMBtu TEST PROTOCOL BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC OH 11/7/2017 Mitsubishi Combustion Turbine (P005) NG 3320 MMBtu/hr natural gas or a natural gas and ethane mixture 0.004 lb/MMBtu WITH DUCT BURNER. SEE NOTES. BACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER P PA 10/10/2012 Combined-cycle Turbines (2) - Natural gas fired NG 3277 MMBtu/hr Using fuel with little or no ash and sulfur conten 0.004 lb/MMBtu FOR 468 MW POWERBLOCK BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 Natural gas fueled combined cycle combustion turbine generator NG 2147 MMBtu/hr Good combustion practices 0.0042 lb/MMBtu TEST PROTOCOL BACT-PSDVA-0315 WARREN COUNTY POWER PLANT - DO VA 6/17/2014 COMBINED CYCLE TURBINE & DUCT BURNER, 3 NG 2996 MMBTU/H Natural Gas only, fuel has maximum sulfur cont 0.004 lb/MMBtu 3 HR AVG. (WITHOUT DUCT BURNER BACT-PSD*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018 COMBUSTION TURBINE UNIT w/o DUCT BURNERS UNIT NG 2665.9 MMBtu/hr 0.0043 lb/MMBtu BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 Natural Gas w/o Duct Firing NG 2969 MMBtu/hr Good Combustion 0.0044 lb/MMBtu BACT-PSDCA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 COMBUSTION TURBINES (NORMAL OPERATION) NG 154 MW USE PUC QUALITY NATURAL GAS 0.0048 lb/MMBtu 9-HR AVG (NO DUCT BURNING) BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 Mitsubishi Hitachi Power Systems (MHPS) Combustion Turbines NG 3231 MMBtu/hr Good combustion practices and pipeline quality 0.005 lb/MMBtu WITH DUCT BURNER. SEE NOTES. BACT-PSD*TN-0164 TVA - JOHNSONVILLE COGENERATION TN 2/1/2018 Dual-fuel CT and HRSG with duct burner NG 1020 MMBtu/hr Good combustion design & practice 0.005 lb/MMBtu WHEN BURNING NATURAL GAS BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016 Combustion turbine and HRSG with duct burner NG only NG 3338 MMBtu/hr Low sulfur fuel, good combustion practicies 0.005 lb/MMBtu BACT-PSDTN-0162 JOHNSONVILLE COGENERATION TN 4/19/2016 Natural Gas-Fired Combustion Turbine with HRSG NG 1339 MMBtu/hr Good combustion design and practices 0.005 lb/MMBtu BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 Natural Gas w/Duct Firing NG 2639 MMBtu/hr Good Combustion 0.005 lb/MMBtu BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014 2 COMBINED-CYCLE COMBUSTION TURBINES NG 725 MW USE OF PIPELINE-QUALITY NATURAL GAS EXCLU 0.005 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 General Electric (GE) Combustion Turbines (P005 & P006) NG 3459.6 MMBtu/hr Good combustion practices and pipeline quality 0.0052 lb/MMBtu WITH DUCT BURNER. SEE NOTES. BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC OH 11/7/2017 Siemens Combustion Turbine (P006) NG 3602 MMBtu/hr natural gas or a natural gas and ethane mixture 0.0057 lb/MMBtu WITH DUCT BURNER. SEE NOTES. BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENERAT PA 1/31/2013 Combined Cycle Power Blocks 472 MW - (2) NG 0 0.0057 lb/MMBtu OTHER CASEPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Combustion turbine with duct burner NG 3304.3 MMBtu/hr Exclusive natural gas, high-efficiency inlet air filt 0.0059 lb/MMBtu BACT-PSD*IL-0112 NELSON ENERGY CENTER IL 12/28/2010 Electric Generation Facility NG 220 MW each 0.006 lb/MMBtu HOURLY AVERAGE BACT-PSDMI-0405 MIDLAND COGENERATION VENTURE MI 4/23/2013 Natural gas fueled combined cycle combustion turbine generator NG 2237 MMBTU/H Good combustion practices 0.006 lb/MMBtu EACH CTG; TEST PROTOCOL BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOPMMA 1/30/2014 Combustion Turbine with Duct Burner NG 2449 MMBTU/H 0.0062 lb/MMBtu 1 HR AVG/DO NOT APPLY DURING S BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015 Combustion Turbine With Duct Burner NG 3727 MMBtu/hr 0.0063 lb/MMBtu BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Siemens Combusion Turbine - Option 2 - Normal Operation NG 35000 MMCF/YR good combustion practices and the use of pipel 0.0065 lb/MMBtu AV OF 3 TEST RUNS/WITHOUT DUCT BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTR PA 6/15/2015 Two Combine Cycle Combustion Turbine with Duct Burner NG 3001.6 MCF/hr Good combustion practices and low sulfur fuels 0.0066 lb/MMBtu BACT-PSDMI-0427 FILER CITY STATION MI 11/17/2017 EUCCT (Combined cycle CTG with unfired HRSG) NG 1934.7 MMBTU/H Good combustion practices and the use of pipel 0.0066 lb/MMBtu BACT-PSDMI-0410 THETFORD GENERATING STATION MI 07/25/2013 FGCCA or FGCCB--4 nat. gas fired CTG w/ DB for HRSG NG 2587 MMBTU/H h Combustion air filters; efficient combustion con 0.0066 lb/MMBtu TEST PROTOCOL (3 1-H TESTS IF POSBACT-PSDMI-0402 SUMPTER POWER PLANT MI 11/17/2011 Combined cycle combustion turbine w/ HRSG NG 130 MW electrical output 0.0066 lb/MMBtu TEST BACT-PSDAK-0071 INTERNATIONAL STATION POWER PLA AK 12/20/2010 GE LM6000PF-25 Turbines (4) NG 59900 hp ISO Good Combustion Practices 0.0066 lb/MMBtu 3-HOUR AVERAGE BACT-PSDOH-0365 ROLLING HILLS GENERATING, LLC OH 05/20/2015 Combustion Turbines, Scenario 1 (4, identical) (P001, P002, P004, NG 2022 MMBTU/H good combustion practices along with clean fue 0.0068 lb/MMBtu HHV, 3 HR AVG. SEE NOTES. BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTR PA 06/15/2015 Two combined cycle turbines with out duct burner NG 2291.6 MCF/hr Good combustion practices and low sulfur fuels 0.0068 lb/MMBtu BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Combustion turbine and HRSG without duct burner NG only NG 0 Low sulfur fuels and good combustion practices 0.0068 lb/MMBtu BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterPowerblocksRBLC Search ResultsVolative Organic Compounds (VOC)

RBLC ID Facility Name State Permit Date Process Name/Description Fuel Size Units Control Description Limit Units Averaging Period BasisVA-0321 BRUNSWICK COUNTY POWER STATVA 3/12/2013 New, combined-cycle, natural gas-fired, electrical power generating facility. NG 3442 MMBTU/H Oxidation catalyst; good combustion practices. 0.7 PPMVD 3 H AVG/WITHOUT BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 34000 MMCF/YR Oxidation catalyst and good combustion practices 0.7 ppmvd @ 15% O2 3 HR AV/WITHOUT BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2969 MMBtu/hr Oxidation Catalyst 0.7 ppmvd @ 15% O2 BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013

facility located in Middletown, NY. The combustion turbines are rated at NG 0 Good combustion practice and oxidation catalyst. 0.7 ppmvd @ 15% O2 1 H LAER

NJ-0082 WEST DEPTFORD ENERGY STATIONNJ 7/18/2014

consisting of a 427 MW Siemens Combined Cycle combustion turbine unit is NG 20282 MMCF/YR Oxidation catalysts and use of Natural gas 0.7 ppmvd @ 15% O2 AVERAGE OF THREE LAEROH-0365 ROLLING HILLS GENERATING, LLC OH 5/20/2015 Electrical services NG 2144 MMBtu/hr good combustion practices along with clean fuels 0.84 PPMVD 3-hr avg; without D BACT-PSD*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018 This Plan Approval is to allow the construction and temporary operation of a NG 2665.9 MMBtu/hr Oxidation Catalyst 1 PPMDV @15% O2 LAERVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 35000 MMCF/YR Oxidation catalyst and good combustion practice 1 ppmvd @ 15% O2 3 H AV/WITHOUT DBACT-PSD*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018 A natural-gas-fired combined-cycle power plant consisting of two (2) identica NG 0 1 PPMDV CORRTECTED TO 15 LAER*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017

combined cycle, single shaft configuration, including a combustion turbine NG 3509 MMBtu/hr 1 PPMDV CORRECTED TO 15% LAER

MI-0432 NEW COVERT GENERATING FACILI MI 7/30/2018 Power plant NG 1230 MW An oxidation catalyst and good combustion practices. 1 PPMVD HOURLY; EACH CT/ BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 0 1 ppmvd @ 15% O2 BACT-PSD

PA-0309 LACKAWANNA ENERGY CTR/JESSUPA 12/23/2015

(3) identical General Electric Model 7HA.02 natural gas fired combustion NG 0 Oxidation catalyst, combustion controls, natural gas 1 ppmvd @ 15% O2 LAERFL-0364 SEMINOLE GENERATING STATION FL 3/21/2018 Existing fossil-fueled power plant. Two coal-fired units each rated at 736 MW NG 3514 MMBtu/hr Oxidation catalyst 1 ppmvd @ 15% O2 WITHOUT DUCT BU BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 725 MW Oxidation catalyst and good combustion practices 1 ppmvd @ 15% O2 3-HOUR BLOCK AVE LAER

NJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of Newark (Essex NG 39463 mmcf/year Oxidation catalyst 1 PPMVD 3-HR ROLLING AVER LAER*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with limited NG 4000 MMBtu/hr Clean fuels 1 ppmvd @ 15% O2 FOR NATURAL GAS BACT-PSDTX-0817 CHOCOLATE BAYOU STEAM GENER TX 2/17/2017 support facility providing steam and electricity NG 50 MW OXIDATION CATALYST 1 PPMDV BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

1.ONE GENERAL ELECTRIC (GE) 7HA.02 CCCT NOMINALLY RATED AT 380 NG 8040 H/YR Oxidation catalyst and good combustion practices 1 ppmvd @ 15% O2 AV OF THREE ONE H LAER

FL-0356 OKEECHOBEE CLEAN ENERGY CENTFL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle unit and aux NG 3096 MMBtu/hr p Complete combustion minimizes VOC 1 ppmvd @ 15% O2 GAS OPERATION BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GEN PA 1/31/2013 This plan approval is for the construction of two natural-gas-fired combined NG 0 CO Catalyst 1 PPMDV WITHOUT DUCT BUBACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBU PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation facility. T NG 2538000 MMBtu/hr Oxidation Catalyst 1 PPM 3 LB/HR, DUCT BUR OTHER CASEMD-0046 KEYS ENERGY CENTER MD 10/31/2014

NOTE: PARTICULATE MATTER FACILITYWIDE EMISSIONS ARE PARTICULATE NG 235 MW Oxidation catalyst and good combustion practices 1 ppmvd @ 15% O2 W/OUT DUCT FIRIN LAER

MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: PARTI NG 286 MW Oxidation catalyst and good combustion practices 1 ppmvd @ 15% O2 3-HR BLOCK AVG. W LAERTX-0714 S R BERTRON ELECTRIC GENERATIN TX 12/19/2014 NRG Texas is proposing to construct an additional electric power generation NG 240 MW oxidation catalyst 1 PPMVD @15% O2 BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELMA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) proposes to NG 2449 MMBtu/hr Oxidation catalyst 1 ppmvd @ 15% O2 1 HR AVG EXCLUDIN OTHER CASEIA-0107 MARSHALLTOWN GENERATING ST IA 4/14/2014 Utility electric generating station NG 2258 mmBtu/hr catalytic oxidizer 1 PPM AVG. OF 3 ONE HOU BACT-PSDIA-0107 MARSHALLTOWN GENERATING ST IA 4/14/2014 Utility electric generating station NG 2258 mmBtu/hr 1 PPM AVERAGE 0F 3 ONE BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 STATIONARY ELECTRIC UTILITY GENERATING STATION NG 2300 MMBtu/hr OXIDIZED CATALYST 1 PPMVD 3 HOURS BACT-PSDNJ-0081 PSEG FOSSIL LLC SEWAREN GENER NJ 3/7/2014

project will comprise of two combustion turbines, EITHER GE7FA.05 OR NG 33691 MMCF/YR Good Combustion Practices and use of Natural gas 1 ppmvd @ 15% O2 AVERAGE OF THREE LAER

NJ-0081 PSEG FOSSIL LLC SEWAREN GENER NJ 3/7/2014

project will comprise of two combustion turbines, EITHER GE7FA.05 OR NG 33691 MMCF/YR Oxidation Catalyst and use of natural gas 1 ppmvd @ 15% O2 AVERAGE OF THREE LAERNJ-0082 WEST DEPTFORD ENERGY STATIONNJ 7/18/2014 An existing Electric Generating Facility with a PSD permit. A new project con NG 20282 MMCF/YR Oxidation Catalyst and use of natural gas 1 ppmvd @ 15% O2 AVERAGE OF THREE LAERCT-0157 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Power Plant NG 21200000 MMBtu/12 Oxidation Catalyst 1 ppmvd @ 15% O2 BACT-PSDCT-0158 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Plant NG 21200000 MMBtu/yr Oxidation Catalyst 1 ppmvd @ 15% O2 BACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POW PA 10/10/2012 NG 3277 MMBtu/hr Oxidation Catalyst 1 PPMVD WITHOUT DUCT BULAERLA-0331 CALCASIEU PASS LNG PROJECT LA 9/21/2018 New Liquefied Natural Gas (LNG) production, storage, and export terminal. NG 921 MMBtu/hr Catalytic Oxidation, Proper Equipment Design and Good C 1.1 PPMV 3 HOUR AVERAGE BACT-PSD*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018

a natural gas-fired combined cycle power plant to be located in NG 0 1.4 PPMDV @15% O2 LAER

VA-0325 GREENSVILLE POWER STATION VA 6/17/2016

electrical power generating facility utilizing three combustion turbines each NG 3227 MMBtu/hr Oxidation Catalyst and good combustion practices 1.4 PPMVD N/AFL-0337 POLK POWER STATION FL 10/14/2012 The Polk Power Station consists of: a nominal 250 MW (net) solid fuel-based NG 1160 MW fuel Sulfur limits 1.4 ppmvd @ 15% O2 BACT-PSD

Renovo Energy CenterPowerblocksRBLC Search ResultsVolative Organic Compounds (VOC)

RBLC ID Facility Name State Permit Date Process Name/Description Fuel Size Units Control Description Limit Units Averaging Period BasisLA-0254 NINEMILE POINT ELECTRIC GENER LA 8/16/2011

NO. 2 & NO. 4 FUEL OIL ARE SECONDARY FUELS. NG 7146 MMBtu/hr GOOD COMBUSTION PRACTICES 1.4 ppmvd @ 15% O2 HOURLY AVERAGE W BACT-PSD

PA-0307 YORK ENERGY CENTER BLOCK 2 EL PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy Center NG 2291.64 MCF/hr Oxidation catalyst, good combustion practices 1.5 ppmvd @ 15% O2 LAERPA-0311 MOXIE FREEDOM GENERATION PL PA 9/1/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) and NG 3727 MMBtu/hr Oxidation catalyst and good engineering practice 1.5 ppmvd @ 15% O2 LAER

PA-0311 MOXIE FREEDOM GENERATION PL PA 9/1/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) and NG 0 Oxidation catalyst, and good engineering practice 1.5 LB/MMBTU LAERPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 3338 MMBtu/hr Oxidation catalyst and good combustion practices 1.5 ppmvd @ 15% O2 LAER

PA-0309 LACKAWANNA ENERGY CTR/JESSUPA 12/23/2015

(3) identical General Electric Model 7HA.02 natural gas fired combustion NG 3304.3 MMBtu/hr Oxidation catalyst, combustion controls, natural gas 1.5 ppmvd @ 15% O2 LAERPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that is designed NG 3.4 MMCF/HR Oxidation Catalyst 1.5 ppmvd @ 15% O2 WITH OR WITHOUT OTHER CASECT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2639 MMBtu/hr Oxidation Catalyst 1.6 ppmvd @ 15% O2 BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACMD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 1000 MW Oxidation catalyst, good combustion practices and nat ga 1.6 ppmvd @ 15% O2 3-HOUR BLOCK AVE LAER

TX-0590 KING POWER STATION TX 8/5/2010 Four combined-cycle natural gas-fired combustion turbines NG 1350 MW DLN burners in combination with an oxidation catalyst 1.8 ppmvd @ 15% O2 THREE-HOUR ROLL LAERPA-0307 YORK ENERGY CENTER BLOCK 2 EL PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy Center NG 3001.57 MCF/hr Oxidation catalyst, good combustion practices 1.9 ppmvd @ 15% O2 LAERNJ-0074 WEST DEPTFORD ENERGY NJ 5/6/2009 A NEW POWER GENERATING FACILITY TO BE BUILT IN WEST DEPTFORD. IT IS NG 17298 MMFT3/YR Oxidation catalyst, good combustion practices 1.9 ppmvd @ 15% O2 AVERAGE OF 3 TEST LAERTop 51 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy StationPowerblocksRBLC Search ResultsSulfur Dioxide (SO2)

RBLC ID Facility Name State Permit Date Facility Description Fuel Size Units Control DescriptionEmission

Limit UnitsAveraging

Period Basis*FL-0367 SHADY HILLS COMBINED CYCLE FAC FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant which includes a NG 3266.9 MMBtu/hr Clean Fuels 0 BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with limited NG 4000 MMBtu/hr Clean fuels 0 BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATI VA 3/12/2013 New, combined-cycle, natural gas-fired, electrical power generating facility. NG 3442 MMBtu/hr Low sulfur fuel 0.0011 lb/MMBtu BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 34000 MMCF/YR natural gas with a maximum sulfur content of 0.4 gr/100 scf o 0.0011 lb/MMBtu 3 HR AVG OTHER CASEVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 35000 MMCF/YR natural gas with a maximum sulfur content of 0.4 gr/100 scf o 0.0011 lb/MMBtu 3 H AV OTHER CASEVA-0325 GREENSVILLE POWER STATION VA 6/17/2016

electrical power generating facility utilizing three combustion turbines each NG 3227 MMBtu/hr Low Sulfur fuel 0.4 gr/100 scf DURING NORMA N/A

PA-0286 MOXIE ENERGY LLC/PATRIOT GENER PA 1/31/2013 This plan approval is for the construction of two natural-gas-fired combined c NG 0 0.0011 lb/MMBtu EXPRESSED AS SOBACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POWE PA 10/10/2012 NG 3277 MMBtu/hr low sulfur fuel with a sulfur content of 0.4 grains per 100 scf. 0.0011 lb/MMBtu OTHER CASEOH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 799 Megawatt Combined Cycle Combustion Turbine Power Plant NG 515600 MMSCF/roll low sulfur fuel, only burning natrual gas with GR/100 SCF 0.0014 lb/MMBtu N/AOH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 799 Megawatt Combined Cycle Combustion Turbine Power Plant NG 51560 MMSCF/roll low sulfur fuel, only burning natural gas with 0.5 GR/100 SCF 0.0014 lb/MMBtu N/AOH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 799 Megawatt Combined Cycle Combustion Turbine Power Plant NG 47917 MMSCF/roll low sulfur fuel, only burning natural gas with 0.5 GR/100 SCF 0.0014 lb/MMBtu N/AOH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 799 Megawatt Combined Cycle Combustion Turbine Power Plant NG 47917 MMSCF/roll low sulfur fuel, only burning natural gas with 0.5 GR/100 SCF 0.0014 lb/MMBtu N/AOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating facility NG 3516 MMBtu/hr natural gas with max sulfur content not exceed 0.50 gr/100 sc 0.0015 lb/MMBtu SEE NOTES. BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2969 MMBtu/hr Low Sulfur fuel 0.0015 lb/MMBtu OTHER CASECT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2639 MMBtu/hr Low Sulfur Fuel 0.0015 lb/MMBtu OTHER CASECT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant ULSD 2639 MMBtu/hr Low sulfur fuel 0.0015 lb/MMBtu OTHER CASENY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generating fac ULSD 0 Ultra low sulfur diesel with maximum sulfur content 0.0015 pe 0.0015 lb/MMBtu 1 H BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 3459.6 MMBtu/hr Good combustion practices and pipeline quality natural gas 0.0017 lb/MMBtu SEE NOTES. BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 3231 MMBtu/hr Good combustion practices and pipeline quality natural gas 0.0021 lb/MMBtu BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generating fac NG 0 Natural gas 0.0022 lb/MMBtu 1 H BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBUR PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation facility. Th NG 3E+06 MMBtu/hr 0.0024 lb/MMBtu OTHER CASE*IL-0112 NELSON ENERGY CENTER IL 12/28/2010 Natural gas-fired electic power generation facility with two "combined NG 220 MW each 0.0062 lb/MMBtu HOURLY AVERAGBACT-PSDCA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 172 MW 0.2 LB/H TURBINE SHUTDO BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOMA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) proposes to c NG 2449 MMBtu/hr 0.3 ppmvd@15 1 HR AVG, DOES OTHER CASETX-0672 CORPUS CHRISTI LIQUEFACTION PLATX 9/12/2014

natural gas liquefaction and export plant and import facilities with NG 40000 hp 0.31 LB/H 1 HOUR BACT-PSD

TX-0672 CORPUS CHRISTI LIQUEFACTION PLATX 9/12/2014

natural gas liquefaction and export plant and import facilities with NG 40000 hp 0.31 LB/H 1 HOUR BACT-PSDCA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 172 MW 0.4 LB/H WARM STARTUP BACT-PSDCA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 172 MW 0.4 LB/H HOT STARTUP PEBACT-PSDDE-0023 NRG ENERGY CENTER DOVER DE 10/31/2012 The facility operates two electric generation units and an auxilliliary steam boNG 655 MMBtu/hr 0.51 LB/H 1 HOUR AVERAG N/AIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 STATIONARY ELECTRIC UTILITY GENERATING STATION NG 2300 MMBtu/hr FUEL SPECIFICATION 0.75 gr/100 dscf BACT-PSDMI-0432 NEW COVERT GENERATING FACILITYMI 7/30/2018 Power plant NG 1230 MW Use of clean fuel (natural gas) with a fuel sulfur limit of 0.8 gra 0.8 gr/100 dscf NAT.GAS BURNE BACT-PSDVA-0315 WARREN COUNTY POWER PLANT - DVA 12/17/2010 Virginia Electric and Power Company (Dominion) has proposed to construct a NG 2996 MMBtu/hr Natural Gas only, fuel has maximum sulfur content of 0.0003% 0.98 LB/H 3 HR AVG. OTHER CASETX-0834 MONTGOMERY COUNTY POWER ST TX 3/30/2018 NG 2635 MMBtu/hr PIPELINE QUALITY NATURAL GAS 1 gr/100 scf BACT-PSD*TX-0660 FGE TEXAS POWER I AND FGE TEXAS TX 3/24/2014 Electric Generating Utility NG 230.7 MW Low sulfur fuel, good combustion practices 1 gr/100 dscf HOURLY BACT-PSDTX-0788 NECHES STATION TX 3/24/2016 either 4 simple cycle combustion turbine generators (CTGs) or two CTGs oper NG 232 MW good combustion practices, low sulfur fuel 1 gr/100 scf HOURLY BACT-PSDTX-0788 NECHES STATION TX 3/24/2016 either 4 simple cycle combustion turbine generators (CTGs) or two CTGs oper NG 231 MW GOOD COMBUSTION PRACTICES, LOW SULFUR FUEL 1 gr/100 scf HOURLY BACT-PSDOH-0356 DUKE ENERGY HANGING ROCK ENEROH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Burners; Combined C NG 172 MW Burning natural gas in an efficient combustion turbine burning 1.2 LB/H BACT-PSDOH-0356 DUKE ENERGY HANGING ROCK ENEROH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Burners; Combined C NG 172 MW Burning natural gas in an efficient combustion turbine burning 1.52 LB/H BACT-PSDTX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 constructed in phases, with natural gas-fired simple cycle combustion turbine NG 227.5 MW Pipeline quality natural gas; limited hours; good combustion p 1.54 gr/100 dscf BACT-PSDTX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 constructed in phases, with natural gas-fired simple cycle combustion turbine NG 426 MW Pipeline quality natural gas 1.54 gr/100 dscf BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy StationPowerblocksRBLC Search ResultsSulfuric Acid Mist (H2SO4)


Limit Units Averaging Period Basis*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant which incl NG 3266.9 MMBtu/hr Clean fuels 2 gr/100 scf BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with li NG 4000 MMBtu/hr Clean fuels 2 gr/100 scf BACT-PSDVA-0315 WARREN COUNTY POWER PLANT - DOMINIO VA 12/17/2010 Virginia Electric and Power Company (Dominion) has proposed to const NG 2996 MMBtu/hr Natural Gas burning. 0.32 gr/100 scf WITHOUT DUCT BU BACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 ACT NG 3277 MMBtu/hr 0.0005 lb/MMBtu OTHER CASE-CT-0161 KILLINGLY ENERGY CENTER CT 06/30/2017 550 MW Combined Cycle Plant NG 2969 MMBtu/hr Low Sulfur content fuel 0.00053 lb/MMBtu BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 06/30/2017 550 MW Combined Cycle Plant ULSD 2639 MMBtu/hr Low Sulfur Fuel 0.00054 lb/MMBtu BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generati ULSD 0 ULSD with maximum sulfur content 0.0015 percent. 0.0005 lb/MMBtu 1 H BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLPA 01/31/2013 This plan approval is for the construction of two natural-gas-fired comb NG 0 0.0005 lb/MMBtu OTHER CASE-VA-0321 BRUNSWICK COUNTY POWER STATION VA 03/12/2013 New, combined-cycle, natural gas-fired, electrical power generating fac NG 3442 MMBtu/hr Low sulfur fuel 0.4 gr/100 scf WITHOUT DUCT BUBACT-PSDVA-0325 GREENSVILLE POWER STATION VA 06/17/2016

cycle electrical power generating facility utilizing three combustion NG 3227 MMBtu/hr Low Sulfur fuel 0.4 gr/100 scf N/A

PA-0306 TENASKA PA PARTNERS/WESTMORELAND GE PA 02/12/2016 The plan approval will allow construction and temporary operation of a NG 0 Low sulfur fuel and good combustion practices 0.0006 lb/MMBtu HHV BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generati NG 0 Natural gas 0.8 GR/100 SCF 1 H BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC - HAN OH 11/07/2017 Combined cycle combustion turbine power generation facility NG 3320 MMBtu/hr natural gas or a natural gas and ethane mixture only 0.0009 lb/MMBtu BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) NG 3727 MMBtu/hr 0.0009 lb/MMBtu BACT-PSD

PA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) 0 0.0009 lb/MMBtu BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

three (3) identical General Electric Model 7HA.02 natural gas fired NG 3304.3 MMBtu/hr Exclusive natural gas 0.0009 lb/MMBtu BACT-PSD

OH-0377 HARRISON POWER OH 04/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 3459.6 MMBtu/hr Good combustion practices, pipeline quality natural g 0.001 lb/MMBtu WITH DUCT BURNE BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 01/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) propos NG 2449 MMBtu/hr 0.001 lb/MMBtu 1 HR AVG, DOES N BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating facNG 3516 MMBtu/hr pipeline quality natural gas with a maximum sulfur co 0.0011 lb/MMBtu SEE NOTES. BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC - HAN OH 11/07/2017 Combined cycle combustion turbine power generation facility NG 3544 MMBtu/hr natural gas or a natural gas and ethane mixture only 0.0011 lb/MMBtu BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY G PA 06/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy C NG 3001.57 MCF/hr 0.0011 lb/MMBtu BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANTMI 07/16/2018 Natural gas combined-cycle power plant NG 0 Good combustion practices and the use of pipeline qu 0.0013 lb/MMBtu HOURLY; EACH UNBACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016

temporarily operate the Fairview Energy Center. ULSD 0 Water/steam injection, ULSD fuel (CCCT only - duct bu 0.0013 lb/MMBtu BACT-PSD

PA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016

temporarily operate the Fairview Energy Center. NG 3338 MMBtu/hr ULSD fuel (CCCT only - duct burner is not fired with UL 0.0014 lb/MMBtu BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016

temporarily operate the Fairview Energy Center. NG 0 Low sulfur fuels and good combustion practices 0.0014 lb/MMBtu BACT-PSD

OH-0360 CARROLL COUNTY ENERGY OH 11/05/2013 Natural gas fired combined cycle gas turbine electric generating station NG 2045 MMBtu/hr natural gas only w/ maximum sulfur content of 1.0 gr/ 0.0016 lb/MMBtu WITH DUCT BURNE BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY G PA 06/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy C ULSD and N 0 Good combustion practices and low sulfur fuels 0.0017 lb/MMBtu BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 04/01/2013 This plan approval is for the repowering of the Sunbury Generation faci NG 2538000 MMBtu/hr 0.0018 lb/MMBtu OTHER CASE-OH-0377 HARRISON POWER OH 04/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 3231 MMBtu/hr Good combustion practices, pipeline quality natural g 0.0022 lb/MMBtu BACT-PSDIA-0107 MARSHALLTOWN GENERATING STATION IA 04/14/2014 Utility electric generating station NG 2258 MMBtu/hr 0.0032 lb/MMBtu 3 ONE-HOUR TEST BACT-PSDIA-0107 MARSHALLTOWN GENERATING STATION IA 04/14/2014 Utility electric generating station NG 2258 MMBtu/hr 0.0032 lb/MMBtu AVERAGE OF 3 ON BACT-PSDDE-0023 NRG ENERGY CENTER DOVER DE 10/31/2012 The facility operates two electric generation units and an auxilliliary ste NG 655 MMBtu/hr 0.12 LB/H 1 HOUR AVERAGE OTHER CASE-OH-0356 DUKE ENERGY HANGING ROCK ENERGY OH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Burners; Combi NG 172 MW Burning natural gas in an efficient combustion turbine 0.18 LB/H BACT-PSDOH-0356 DUKE ENERGY HANGING ROCK ENERGY OH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Burners; Combi NG 172 MW Burning natural gas in an efficient combustion turbine 0.23 LB/H BACT-PSDTX-0714 S R BERTRON ELECTRIC GENERATING STATIONTX 12/19/2014 NRG Texas is proposing to construct an additional electric power gener NG 240 MW 0.5 GR SULFUR/100 DSCF BACT-PSDNJ-0082 WEST DEPTFORD ENERGY STATION NJ 07/18/2014 An existing Electric Generating Facility with a PSD permit. A new projec NG 20282 MMCF/YR Use of natural gas a clean burning fuel 0.74 LB/H OTHER CASE-IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 STATIONARY ELECTRIC UTILITY GENERATING STATION NG 2300 MMBtu/hr FUEL SPECIFICATION 0.75 GR S/100SCF FUEL BACT-PSDNJ-0082 WEST DEPTFORD ENERGY STATION NJ 07/18/2014 An existing Electric Generating Facility with a PSD permit. A new projec NG 20282 MMCF/YR Use of natural gas a clean burning fuel 0.98 LB/H OTHER CASE-TX-0834 MONTGOMERY COUNTY POWER STATIOIN TX 03/30/2018 ACT NG 2635 MMBtu/hr PIPELINE QUALITY NATURAL GAS 1 GR/100 DSCF BACT-PSDMI-0432 NEW COVERT GENERATING FACILITY MI 07/30/2018 Power plant NG 1230 MW Use of natural gas with a fuel sulfur limit of 0.8 grains 1 LB/H HOURLY; EACH CT/ BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterPowerblocksRBLC Search ResultsAmmonia (NH3)


Limit Units Averaging Period BasisCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2969 MMBtu/hr Good Combustion, Optimization of SCR 2 ppmvd @ 15% O2 1 HR BLOCK OTHER CASE-CT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant NG 2639 MMBtu/hr Optimization of SCR 2 ppmvd @ 15% O2 1 HR BLOCK OTHER CASE-MA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permit NG 2449 MMBtu/hr 2 ppmvd @ 15% O2 1 HR BLOCK AVG, DOES OTHER CASE-CT-0157 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Power Plant NG 21200000 MMBtu/12 mo 2 ppmvd @ 15% O2 BACT-PSDCT-0158 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Plant NG 21200000 MMBtu/yr 2 ppmvd @ 15% O2 1 HR BLOCK OTHER CASE-*PA-0319 RENAISSANCE ENERGY CENTER PA 8/27/2018

temporary operation of a natural gas-fired combined cycle NG 2665.9 MMBtu/hr 5 PPMDV

PA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

operation of three (3) identical General Electric Model NG 13.31 MMBtu/hr 5 ppmvd @ 15% O2 12-MONTH ROLLING B BACT-PSDCT-0161 KILLINGLY ENERGY CENTER CT 6/30/2017 550 MW Combined Cycle Plant ULSD 2639 MMBtu/hr Optimization of SCR 5 ppmvd @ 15% O2 1 HOUR BLOCK OTHER CASE-NJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

OF NG 8040 H/YR USE OF NATURAL GAS A CLEAN BURNING FUEL 5 ppmvd @ 15% O2 3 H ROLLING AV BASED BACT-PSD

PA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Gen NG 2538000 MMBtu/hr 5 PPMVD OTHER CASE-MD-0046 KEYS ENERGY CENTER MD 10/31/2014

PLANT NG 235 MW INITIAL STACK TEST USING EPA METHOD CTM-027 OR E 5 ppmvd @ 15% O2 AVG OF 3 TEST RUNS O OTHER CASE-

MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PL NG 286 MW INITIAL STACK TEST USING EPA METHOD CTM-027 OR E 5 ppmvd @ 15% O2 AVERAGE OF 3 TEST RU OTHER CASE-PA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUPA 12/17/2013 This application is for the construction of a natural gas-fired NG 3046 MMBtu/hr 5 PPMVD BACT-PSDCT-0157 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Power Plant ULSD 1720000 gal/12 mo 5 ppmvd @ 15% O2 1 HR BLOCK BACT-PSDCT-0158 CPV TOWANTIC, LLC CT 11/30/2015 805 MW Combined Cycle Plant ULSD 1720000 gal/12 mo 5 ppmvd @ 15% O2 1 HR BLOCK OTHER CASE-PA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 NG 3277 MMBtu/hr 5 PPMVD OTHER CASE-DE-0023 NRG ENERGY CENTER DOVER DE 10/31/2012 The facility operates two electric generation units and an au NG 655 MMBtu/hr 5.29 LB/H 1 HOUR AVERAGE OTHER CASE-*TX-0660 FGE TEXAS POWER I AND FGE TEXAS POWER TX 3/24/2014 Electric Generating Utility NG 230.7 MW AVO, good combustion practices 7 PPMVD CORRECTED TO 15% O BACT-PSDTX-0600 THOMAS C. FERGUSON POWER PLANT TX 9/1/2011 Power Plant. Two natural gas-fired combined cycle turbine NG 390 MW best management practices 7 PPMVD ROLLING 24-HR AT 15% BACT-PSDWY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The NG 40 MW 10 ppmvd @ 15% O2 3-HOUR AVERAGE OTHER CASE-WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The NG 40 MW 10 PPM AT 15% O2 3-HOUR AVERAGE OTHER CASE-WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The NG 40 MW 10 ppmvd @ 15% O2 3-HOUR AVERAGE OTHER CASE-WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The NG 40 MW 10 ppmvd @ 15% O2 3-HOUR AVERAGE OTHER CASE-WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The NG 40 MW 10 ppmvd @ 15% O2 3-HOUR AVERAGE OTHER CASE-NJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

OF ULSD 720 H/YR USE OF ULSD OIL A CLEAN BURNING FUEL 25.9 LB/H 3 H ROLLING AV BASED OTHER CASE-

NJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

OF NG 4000 h/yr USE OF NATURAL GAS A CLEAN BURNING FUEL 27.4 LB/H AV OF THREE ONE H ST OTHER CASE-OH-0356 DUKE ENERGY HANGING ROCK ENERGY OH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Bur NG 172 MW 28 LB/H N/AOH-0356 DUKE ENERGY HANGING ROCK ENERGY OH 12/18/2012 Four Natural Gas Fired Combustion Turbines, with Duct Bur NG 172 MW 31.7 LB/H N/A*PA-0298 FUTURE POWER PA/GOOD SPRINGS NGCC FA PA 3/4/2014 Natural gas-fired combined-cycle electric generation facility NG 2267 MMBtu/hr 72.5 TPY BASED ON A 12-MONT BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility NG 3.4 MMCF/HR 110.2 TPY 12-MONTH ROLLING T OTHER CASE-*Draft determination December 2019

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsNitrogen Oxides (NOx)


Limit Units Averaging Period BasisLA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 8/16/2011

FUEL; NO. 2 & NO. 4 FUEL OIL ARE SECONDARY FUELS. NG 338 MMBtu/hr PROPER OPERATION AND GOOD COMBUSTION PRACTICES 0.0002 lb/MMBtu BACT-PSD

PA-0309 LACKAWANNA ENERGY CTR/JESSUP PA #########

three (3) identical General Electric Model 7HA.02 natural gas fired NG 184.4 MMBtu/hr SCR and ultra low NOx burners, Fired only on natural gas s 0.006 lb/MMBtu 30-DAY ROLLING AV LAER*IL-0130 JACKSON ENERGY CENTER IL ######### The proposed facility is designed to generate baseload power. It will co NG 96 MMBtu/hr Ultra low-NOx burners and flue gas recirculation air prehe 0.01 lb/MMBtu 3-HOUR AVERAGE LAERMD-0046 KEYS ENERGY CENTER MD #########

NOTE: PARTICULATE MATTER FACILITYWIDE EMISSIONS ARE NG 93 MMBtu/hr EFFICIENT BOILER DESIGN WITH ULTRA LOW NOX BURNER 0.01 lb/MMBtu 3-HOUR BLOCK AVE BACT-PSD

TX-0698 BAYPORT COMPLEX TX 9/5/2013 Air Liquid currently operates a cogeneration facility in Pasadena, Texas NG 550 MMBtu/hr Selective Catalytic Reduction (SCR) 0.01 lb/MMBtu 3 HOUR ROLLING AVBACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) NG 55.4 MMBtu/hr 0.006 lb/MMBtu LAER

PA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY GE PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy C NG 62.04 MCF/hr Good combustion practices, Ultra-Low NOx burners, FGR 0.0086 lb/MMBtu LAERNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of Newark NG 51.9 mmcf/yr Low NOx burners and flue gas recirculation 0.01 lb/MMBtu AVERAGE OF THREE LAER

*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 45 MMBtu/hr EXCLUSIVE USE OF PIPELINE QUALITY NATURAL GAS AND 0.01 lb/MMBtu 3-HOUR BLOCK AVE LAERMD-0045 MATTAWOMAN ENERGY CENTER MD ######### 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: NG 42 MMBtu/hr EXCLUSIVE USE OF PIPELINE QUALITY NATURAL GAS, ULTR 0.01 lb/MMBtu 3-HOUR BLOCK AVE BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 902 mmcf/y Low NOx burners 0.011 lb/MMBtu CORRECTED TO 3% OBACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016

cycle electrical power generating facility utilizing three combustion NG 185 MMBtu/hr ultra low-NOx burners 0.011 lb/MMBtu N/A

*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

two (2) identical 1 x 1 powerblocks where each powerblock consists of NG 118800 MMBtu/12 ultra-low NOx burners and flue gas re-circulation 0.011 lb/MMBtu MMBTU LAER*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017

combined cycle, single shaft configuration, including a combustion NG 42 MMBtu/hr 0.011 lb/MMBtu MMBTU

IL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate baseload power. It will co NG 96 mmBtu/hr Ultra-low NOx burners and flue gas recirculation, air prehe 0.011 lb/MMBtu 3-HOUR AVERAGE LAERPA-0306 TENASKA PA PARTNERS/WESTMORELAND GEN PA 2/12/2016 The plan approval will allow construction and temporary operation of a NG 1052 MMscf/yr Good combustion practices and ULNOx burners 0.011 lb/MMBtu LAERPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 92.4 MMBtu/hr Ultra low NOx burners, FGR, good combustion practices 0.011 lb/MMBtu AVG OF 3 1-HR TEST LAER

MD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 93 MMBtu/hr Ultra low NOx burners, FGR, good combustion practices 0.011 lb/MMBtu 3-HOUR AVERAGE LAERPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that is desi NG 40 MMBtu/hr 0.011 lb/MMBtu OTHER CASEMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) propos NG 80 MMBtu/hr ultra low NOx burners 0.011 lb/MMBtu 1 HR BLOCK AVG, DO LAERIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 Utility electric generating station NG 60.1 mmBtu/hr 0.013 lb/MMBtu AVERAGE OF 3 ONE- BACT-PSDTX-0708 LA PALOMA ENERGY CENTER TX 2/7/2013 The proposed project is a new electric power plant, fueled by pipeline q NG 150 MMBtu/hr low-NOx burners, limited use 0.02 lb/MMBtu 3-HR ROLLING AVER BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the permi NG 40 MMBtu/hr Good combustion practices. 0.035 lb/MMBtu TEST PROTOCOL; EA BACT-PSDOR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 Troutdale Energy Center (TEC) proposes to construct and operate a 653 NG 39.8 MMBtu/hr Utilize Low-NOx burners and FGR. 0.035 lb/MMBtu 3-HR BLOCK AVERAGBACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 99.9 MMBtu/hr Low NOx burners/Flue gas recirculation. 0.036 lb/MMBtu HOURLY BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation faci NG 106000 MMBTU 0.036 lb/MMBtu OTHER CASETX-0714 S R BERTRON ELECTRIC GENERATING STATION TX ######### NRG Texas is proposing to construct an additional electric power gener NG 80 MMBtu/hr low-NOx burners 0.036 lb/MMBtu 3-HR ROLLING BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and south) NG 61.5 MMBtu/hr Ultra low NOx burners, FGR, good combustion practices 0.04 lb/MMBtu 30-DAY ROLLING AV BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and south) NG 61.5 MMBtu/hr Ultra low NOx burners, FGR, good combustion practices 0.04 lb/MMBtu 30 DAY ROLLING AV BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 182 MMBtu/hr Ultra low NOx burners, FGR, good combustion practices 0.04 lb/MMBtu 30 DAY ROLLING AV BACT-PSDMI-0427 FILER CITY STATION MI ######### New natural gas combined heat and power plant proposed at existing c NG 182 MMBtu/hr LNB that incorporate internal (within the burner) FGR and 0.04 lb/MMBtu 30 DAY ROLLING AV BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generati NG 0 Flue gas recirculation with low NOx burners. 0.045 lb/MMBtu 1 H LAER*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant which incl NG 60 MMBtu/hr low-NOx burners 0.05 lb/MMBtu BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH MI 12/5/2016 Natural gas combined heat and power plant. NG 83.5 MMBtu/hr Low NOx burners/Internal flue gas recirculation and good 0.05 lb/MMBtu TEST PROTOCOL WIL BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle unit an NG 99.8 MMBtu/hr Low-NOx burners 0.05 lb/MMBtu BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH MI 12/4/2013 Natural gas combined heat and power plant. NG 95 MMBtu/hr Dry low NOx burners, flue gas recirculation and good com 0.05 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH MI 12/4/2013 Natural gas combined heat and power plant. NG 55 MMBtu/hr Low NOx burners and good combustion practices 0.05 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generato NG 100 MMBtu/hr Low NOx burners and flue gas recirculation. 0.05 lb/MMBtu TEST PROTOCOL BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC - HANNI OH 11/7/2017 Combined cycle combustion turbine power generation facility NG 26.8 MMBtu/hr Flue gas recirculation and low NOX burner 0.29 LB/H BACT-PSDOH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 8/25/2015 962 MW (gross winter output) combined cycle gas turbine (CCGT) facilitNG 34 MMBtu/hr Flue gas recirculation (FGR) and low NOx burner 0.68 LB/H BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsCarbon Monoxide (CO)

RBLS CD Facility Name State Permit Date Facility Description Fuel Size Units Control DescriptionEmission

Limit Units Averaging Period BasisIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 Utility electric generating station NG 60.1 mmBtu/hr CO catalytic oxidizer 0.0164 lb/MMBtu AVERAGE OF 3 ON-HOUR TEST BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 93 mmBtu/hr GOOD COMBUSTION PRACTICES 0.02 lb/MMBtu 3-HOUR AVERAGE BLOCK BACT-PSD


cycle electrical power generating facility utilizing three combustion NG 185 MMBtu/hr Clean fuel and good combustion practices 0.035 lb/MMBtu N/A*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

two (2) identical 1 x 1 powerblocks where each powerblock consists NG 118800 MMBtu/12 month period 0.036 LB MMBTU BACT-PSD


PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 45 mmBtu/hr good combustion practices and pipeline NG 0.036 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the perm NG 40 mmBtu/hr Good combustion practices 0.036 lb/MMBtu TEST PROTOCOL; EACH UNIT. BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that is de NG 40 mmBtu/hr 0.036 lb/MMBtu OTHER CASE-*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 The proposed facility is designed to generate baseload power. It will NG 96 mmBtu/hr Good combustion practice 0.037 lb/MMBtu 3-HOUR BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 902 mmcf/y good combustion practices and clean fuel 0.037 lb/MMBtu BACT-PSD*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017

combined cycle, single shaft configuration, including a combustion NG 42 MMBtu/hr 0.037 LB MMBTU

IL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate baseload power. It will NG 96 mmBtu/hr Good combustion practices 0.037 lb/MMBtu 3-HOUR AVERAGE BACT-PSDPA-0306 TENASKA PA PARTNERS/WESTMORELAND GEN PA 2/12/2016 The plan approval will allow construction and temporary operation o NG 1052 MMscf/yr Good combustion practices 0.037 lb/MMBtu BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

1 power blocks, each consisting of a combustion gas turbine (CGT or NG 55.4 MMBtu/hr 0.037 lb/MMBtu BACT-PSD


temporarily operate the Fairview Energy Center. NG 92.4 MMBtu/hr ULSD and good combustion practices 0.037 lb/MMBtu AVG OF 3 1-HR TEST RUNS BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

of three (3) identical General Electric Model 7HA.02 natural gas NG 184.4 MMBtu/hr 0.037 lb/MMBtu BACT-PSD

MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE NG 42 MMBtu/hr GOOD COMBUSTION PRACTICES 0.037 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDTX-0714 S R BERTRON ELECTRIC GENERATING STATION TX 12/19/2014 NRG Texas is proposing to construct an additional electric power gen NG 80 MMBtu/hr low-NOx burners 0.037 lb/MMBtu 3-HR ROLLING AVERAGE BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 182 MMBtu/hr Good combustion practices. 0.04 lb/MMBtu TEST PROTOCOL WILL SPECIFY BACT-PSDMI-0427 FILER CITY STATION MI 11/17/2017 New natural gas combined heat and power plant proposed at existing NG 182 MMBtu/hr Good combustion practices 0.04 lb/MMBtu BACT-PSDOR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 Troutdale Energy Center (TEC) proposes to construct and operate a 6 NG 39.8 MMBtu/hr Utilize Low-NOx burners and FGR. 0.04 lb/MMBtu 3-HR BLOCK AVERAGE BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY G PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy NG 62.04 MCF/hr Good combustion practices 0.06 lb/MMBtu BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric genera NG 0 Good combustion practice. 0.0721 lb/MMBtu 1 H BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation fa NG 106000 MMBTU 0.074 lb/MMBtu OTHER CASE-MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 99.9 MMBtu/hr Good combustion practices 0.075 lb/MMBtu HOURLY BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generat NG 100 MMBtu/hr Efficient combustion. 0.075 lb/MMBtu HEAT INPUT. TEST PROTOCOL BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/5/2016 Natural gas combined heat and power plant. NG 83.5 MMBtu/hr Good combustion practices. 0.077 lb/MMBtu TEST PROTOCOL WILL SPECIFY BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/4/2013 Natural gas combined heat and power plant. NG 95 MMBtu/hr Good combustion practices. 0.077 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/4/2013 Natural gas combined heat and power plant. NG 55 MMBtu/hr Good combustion practices 0.077 lb/MMBtu TEST PROTOCOL BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant which in NG 60 MMBtu/hr Good combustion practices and low-NOx bu 0.08 lb/MMBtu BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and sout NG 61.5 MMBtu/hr Good combustion practices. 0.08 lb/MMBtu HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and sout NG 61.5 MMBtu/hr Good combustion practices. 0.08 lb/MMBtu HOURLY BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with NG 99.8 MMBtu/hr Clean fuel 0.08 lb/MMBtu BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle unit NG 99.8 MMBtu/hr Proper combustion prevents CO 0.08 lb/MMBtu BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014

NOTE: PARTICULATE MATTER FACILITYWIDE EMISSIONS ARE NG 93 MMBtu/hr good combustion practice, effic design 0.08 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSD

OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANN OH 11/7/2017 Combined cycle combustion turbine power generation facility NG 26.8 MMBtu/hr Good combustion controls 0.99 LB/H BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plantNG 44.55 MMBtu/hr Good combustion practices 1.67 LB/H BACT-PSDOH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 8/25/2015 962 MW (gross winter output) combined cycle gas turbine (CCGT) facNG 34 MMBtu/hr Good combustion controls 1.87 LB/H BACT-PSDOH-0370 TRUMBULL ENERGY CENTER OH 9/7/2017 940 MW combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr Good combustion controls 2.08 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 9/27/2017 Combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr good combustion controls 2.08 LB/H BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of Newark NG 51.9 mmcubic ft/use of natural gas a clean fuel 2.45 LB/H AVERAGE OF THREE TESTS BACT-PSD

Top 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsParticulate Matter (PM/PM10/PM2.5)


Limit Units Averaging Period Basis*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant w NG 60 MMBtu/hr Clean fuels 0 BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant w NG 60 MMBtu/hr Clean fuels 0 BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fire NG 99.8 MMBtu/hr Clean fuels 0 BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/5/2016 Natural gas combined heat and power plant. NG 83.5 MMBtu/hr Good combustion practices. 0.0018 lb/MMBtu TEST PROTOCOL WI BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/4/2013 Natural gas combined heat and power plant. NG 95 MMBtu/hr Good combustion practices 0.0018 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/4/2013 Natural gas combined heat and power plant. NG 55 MMBtu/hr Good combustion practices 0.0018 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine g NG 100 MMBtu/hr Efficient combustion; natural gas fuel. 0.0018 lb/MMBtu HEAT INPUT; TEST P BACT-PSD*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

consisting of two (2) identical 1 x 1 powerblocks where each NG 1E+05 MMBtu/12 mo 0.0019 LB MMBTU BACT-PSD

MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLAN NG 42 MMBtu/hr good combustion practices and natural gas 0.0019 lb/MMBtu 3-HOUR BLOCK AVEBACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

operation of three (3) identical General Electric Model 7HA.02 NG 184.4 MMBtu/hr Natural gas fired exclusively 0.002 lb/MMBtu BACT-PSD

MI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and NG 61.5 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and NG 61.5 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu HOURLY BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 93 MMBtu/hr good combustion practices and natural gas 0.005 lb/MMBtu 3-HOUR AVERAGE BACT-PSD

MI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 182 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu TEST PROTOCOL WI BACT-PSDMI-0427 FILER CITY STATION MI 11/17/2017 New natural gas combined heat and power plant proposed at e NG 182 MMBtu/hr Good combustion practices 0.005 lb/MMBtu BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact th NG 40 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu TEST PROTOCOL; EA BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact th NG 40 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu TEST PROTOCOL; EA BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric NG 0 Natural gas. 0.0063 lb/MMBtu 1 H BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016

combined-cycle electrical power generating facility utilizing NG 185 MMBtu/hr Low sulfur /carbon fuel and good combust 0.007 lb/MMBtu N/A

MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANTMI 7/16/2018 Natural gas combined-cycle power plant NG 99.9 MMBtu/hr Good combustion practices, low sulfur fue 0.007 lb/MMBtu HOURLY BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

POWER PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 NG 45 MMBtu/hr good combustion practices and natural gas 0.0075 lb/MMBtu 3-HOUR BLOCK AVEBACT-PSD

MD-0046 KEYS ENERGY CENTER MD 10/31/2014

PLANT NG 93 MMBtu/hr good combustion practices, natural gas, ef 0.0075 lb/MMBtu 3-HOUR BLOCK AVEBACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

1.ONE GENERAL ELECTRIC (GE) 7HA.02 CCCT NOMINALLY NG 4000 H/YR use of natural gas a clean fuel 0.181 LB/H AV OF THREE ONE H BACT-PSD


HESS Newark Energy Center (Hess-NEC), proposed at City of NG 51.9 mmcf/yr use of natural gas a clean fuel 0.22 LB/H AVERAGE OF THREE N/ANJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of NG 51.9 mmcf/yr use of natural gas a clean fuel 0.33 LB/H AVERAGE OF THREE BACT-PSD


HESS Newark Energy Center (Hess-NEC), proposed at City of NG 51.9 mmcf/yr use of natural gas a clean fuel 0.33 LB/H AVERAGE OF THREE N/APA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUPA 12/17/2013 This application is for the construction of a natural gas-fired co NG 40 MMBTU/H 0.46 T/YR OTHER CAS*Draft determination December 2019

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsVolatile Organic Compounds (VOC)


Limit Units Averaging Period BasisTX-0708 LA PALOMA ENERGY CENTER TX 2/7/2013 The proposed project is a new electric power plant, fueled by pipeline qu NG 150 MMBtu/hr good combustion practices 0 BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that is design NG 40 MMBtu/hr 0.0015 lb/MMBtu OTHER CASEMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 93 MMBtu/hr Good combustion practices and natural gas 0.002 lb/MMBtu 3-HOUR AVERAGE BLAER

MD-0046 KEYS ENERGY CENTER MD 10/31/2014

NOTE: PARTICULATE MATTER FACILITYWIDE EMISSIONS ARE NG 93 MMBtu/hr EFFICIENT BOILER DESIGN, EXCLUSIVE USE OF PIPELINE 0.002 lb/MMBtu 3-HOUR BLOCK AVE LAERMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: PA NG 42 MMBtu/hr Good combustion practices and natural gas 0.003 lb/MMBtu 3-HOUR BLOCK AVE LAER*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 45 MMBtu/hr Good combustion practices, natural gas and limited hou 0.0033 lb/MMBtu 3-HOUR BLOCK AVE LAER

NY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generatin NG 0 Good combustion practice. 0.0038 lb/MMBtu 1 H LAERMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and south) NG 61.5 MMBtu/hr Good combustion practices. 0.004 lb/MMBtu HOURLY BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICIT PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Energy Ce NG 62.04 MCF/hr Good combustion practices and FGR 0.004 lb/MMBtu LAERPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 92.4 MMBtu/hr ULSD and good combustion practices 0.004 lb/MMBtu AVG OF 3 1-HR TEST LAER

MI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 182 MMBtu/hr Good combustion practices. 0.004 lb/MMBtu TEST PROTOCOL WI BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 New, combined-cycle, natural gas-fired, electrical power generating facil NG 66.7 MMBtu/hr Clean fuel and good combustion practices 0.005 lb/MMBtu BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 902 mmcf/y good combustion practices. 0.005 lb/MMBtu BACT-PSD*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

two (2) identical 1 x 1 powerblocks where each powerblock consists of a NG 118800 MMBtu/12 mo 0.005 LB MMBTU N/A


power blocks, each consisting of a combustion gas turbine (CGT or CT) NG 55.4 MMBtu/hr 0.005 lb/MMBtu LAERPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

three (3) identical General Electric Model 7HA.02 natural gas fired NG 184.4 MMBtu/hr 0.005 lb/MMBtu 30-DAY ROLLING BALAER

MI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the permit e NG 40 MMBtu/hr Good combustion practices. 0.005 lb/MMBtu TEST PROTOCOL; EA BACT-PSDTX-0756 CCI CORPUS CHRISTI CONDENSATE SPLITTE TX 6/19/2015 Two identical condensate splitter trains each capable of processing 50,00 NG 37 MMBtu/hr (Good combustion practices will limit VOC emissions to 0 0.005 LB/100 SCF EACH BOILER BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation facilit NG 106000 MMBTU 0.005 lb/MMBtu OTHER CASEOR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 Troutdale Energy Center (TEC) proposes to construct and operate a 653 m NG 39.8 MMBtu/hr Utilize Low-NOx burners and FGR. 0.005 lb/MMBtu 3-HR BLOCK AVERAGBACT-PSDIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 Utility electric generating station NG 60.1 mmBtu/hr 0.005 lb/MMBtu AVERAGE OF 3 ONE BACT-PSDPA-0306 TENASKA PA PARTNERS/WESTMORELAND PA 2/12/2016 The plan approval will allow construction and temporary operation of a p NG 1052 MMscf/yr Good combustion practice 0.0054 lb/MMBtu LAERMI-0435 BELLE RIVER COMBINED CYCLE POWER PLAMI 7/16/2018 Natural gas combined-cycle power plant NG 99.9 MMBtu/hr Good combustion practices 0.008 lb/MMBtu HOURLY BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/5/2016 Natural gas combined heat and power plant. NG 83.5 MMBtu/hr Good combustion practices. 0.008 lb/MMBtu TEST PROTOCOL WI BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/4/2013 Natural gas combined heat and power plant. NG 95 MMBtu/hr Good combustion practices 0.008 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/4/2013 Natural gas combined heat and power plant. NG 55 MMBtu/hr Good combustion control 0.008 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generators NG 100 MMBtu/hr Efficient combustion; natural gas fuel. 0.008 lb/MMBtu HEAT INPUT; TEST P BACT-PSDOH-0375 LONG RIDGE ENERGY GENERATION LLC - H OH 11/7/2017 Combined cycle combustion turbine power generation facility NG 26.8 MMBtu/hr Good combustion controls 0.13 LB/H BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTE PA 12/17/2013 This application is for the construction of a natural gas-fired combined-cy NG 40 MMBtu/hr 0.14 T/YR BASED ON 12-MONT N/AOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 44.55 MMBtu/hr Good combustion practices 0.16 LB/H BACT-PSDOH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LL OH 8/25/2015 962 MW (gross winter output) combined cycle gas turbine (CCGT) facilityNG 34 MMBtu/hr Good combustion controls 0.2 LB/H BACT-PSDOH-0370 TRUMBULL ENERGY CENTER OH 9/7/2017 940 MW combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr Good combustion controls 0.23 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 9/17/2017 Combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr good combustion controls 0.23 LB/H BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plant NG 80 MMBtu/hr Good combustion practices 0.248 LB/H BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of Newark NG 51.9 mmcf/yr use of natural gas a clean fuel 0.27 LB/H AVERAGE OF THREE LAER

NJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

1.ONE GENERAL ELECTRIC (GE) 7HA.02 CCCT NOMINALLY RATED AT NG 4000 H/YR Good combustion practices and natural gas 0.488 LB/H AV OF THREE ONE H LAERVA-0325 GREENSVILLE POWER STATION VA 6/17/2016

electrical power generating facility utilizing three combustion turbines NG 185 MMBtu/hr Good combustion pratices 0.5 T/12 MO RO 12 MONTH ROLLING N/A

TX-0817 CHOCOLATE BAYOU STEAM GENERATING TX 2/17/2017 support facility providing steam and electricity NG 0 GOOD COMBUSTION PRACTICES 0.54 LB/H BACT-PSDOH-0367 SOUTH FIELD ENERGY LLC OH 9/23/2016 1150 MW combined-cycle gas turbine (CCGT) facility NG 99 MMBtu/hr Good combustion controls and natural gas/ultra low su 0.59 LB/H BACT-PSDOH-0360 CARROLL COUNTY ENERGY OH 11/5/2013 Natural gas fired combined cycle gas turbine electric generating station o NG 99 MMBtu/hr Good combustion practices and using combustion optim 0.59 LB/H BACT-PSDTop 40 sources with lowest emission rates from RBLC search. December 2019*Draft determination

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsSulfur Dioxide (SO2)

RBLC ID Facility Name State Permit Date Facility Description Fuel Size Units Control DescriptinEmission

Limit Units Averaging Period Basis*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant whic NG 60 MMBtu/hr Limited sulfur content in natural gas 0 BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, w NG 99.8 MMBtu/hr Clean fuels 0 BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

POWER PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 NG 45 MMBtu/hr EXCLUSIVE USE OF PIPELINE QUALITY NATURAL GAS 0.0006 lb/MMBtu 3-HOUR BLOCK AVERAGEBACT-PSD

VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 New, combined-cycle, natural gas-fired, electrical power generati NG 66.7 MMBtu/hr Low sulfur fuel. 0.0011 lb/MMBtu BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 6/17/2016

combined-cycle electrical power generating facility utilizing three NG 185 MMBtu/hr Low sulfur fuel 0.0011 lb/MMBtu N/A

VA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 105 MMBtu/hr The use of pipeline quality natural gas with a max sul 0.0012 lb/MMBtu BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that i NG 40 MMBtu/hr 0.0021 lb/MMBtu OTHER CASENY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric gen NG 0 Natural gas. 0.0022 lb/MMBtu 1 H BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generatio NG 106000 MMBTU 0.003 lb/MMBtu OTHER CASEOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plNG 44.55 MMBtu/hr Pipeline quality natural gas 0.022 LB/H BACT-PSDOH-0370 TRUMBULL ENERGY CENTER OH 9/7/2017 940 MW combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr Low sulfur fuel 0.06 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 9/27/2017 Combined cycle gas turbine (CCGT) facility NG 37.8 MMBtu/hr low sulfur fuel 0.06 LB/H BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/1/2012

HESS Newark Energy Center (Hess-NEC), proposed at City of NG 51.9 mmcf/yr use of natural gas a clean fuel and a low sulfur fuel 0.08 LB/H N/A

OH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine plNG 80 MMBtu/hr Pipeline quality natural gas 0.12 LB/H BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

1.ONE GENERAL ELECTRIC (GE) 7HA.02 CCCT NOMINALLY NG 4000 H/YR USE OF NATURAL GAS A CLEAN BURNING LOW SULFU 0.128 LB/H OTHER CASE

OH-0367 SOUTH FIELD ENERGY LLC OH 9/23/2016 1150 MW combined-cycle gas turbine (CCGT) facility NG 99 MMBtu/hr natural gas/ultra low sulfur diesel 0.15 LB/H BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNPA 12/17/2013 This application is for the construction of a natural gas-fired comb NG 40 MMBtu/hr 0.19 T/YR BASED ON 12-MONTH RO N/AOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generati NG 185 MMBtu/hr Pipeline natural gas fuel 0.28 LB/H BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 182 MMBtu/hr Good combustion practices and the use of pipeline q 0.6 LB/MMSCF BASED ON FUEL RECEIPT BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) p NG 80 MMBtu/hr 0.9 PPMVD@3% 1 HR BLOCK AVG, DOES N OTHER CASEMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and soNG 61.5 MMBtu/hr Good combustion practices and the use of pipeline q 1.8 LB/MMSCF MONTHLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 6/29/2018 Natural gas combined cycle power plant (two plants: north and soNG 61.5 MMBtu/hr Good combustion practices and the use of pipeline q 1.8 LB/MMSCF MONTHLY BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle u NG 99.8 MMBtu/hr Use of low-sulfur gas 2 GR. S/100 SCF GAS BACT-PSD*Draft determination December 2019

Renovo Energy CenterAuxiliary Boiler - Natural GasRBLC Search ResultsSulfuric Acid Mist (H2SO4)


Limit Units Averaging Time BasisVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 902 mmcf/y The use of pipeline quality natural gas with a max sulfur conte 0 BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 7/27/2018 A 573-megawatt (MW) (winter) 1-on-1 combined cycle plant which NG 60 MMBtu/houClean fuels 0 BACT-PSDPA-0307 YORK ENERGY CENTER BLOCK 2 ELECTRICITY PA 6/15/2015 Calpine Mid-Merit, LLC. currently operates Block 1 of the York Ener NG 62.04 MCF/hr Good combustion practices and low sulfur fuels 0 LB/MMBTU BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, wi NG 99.8 MMBtu/hr Clean fuels 0 BACT-PSDOR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 Troutdale Energy Center (TEC) proposes to construct and operate a NG 39.8 MMBTU/H

Utilize only natural gas. 0 BACT-PSD


cycle electrical power generating facility utilizing three NG 185 MMBTU/HRPipeline quality natural gas 0.0001 LB/MMBTU N/APA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

1 x 1 power blocks, each consisting of a combustion gas turbine NG 55.4 MMBtu/hr 0.0001 LB/MMBTU BACT-PSD

PA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015

operation of three (3) identical General Electric Model 7HA.02 NG 184.4 MMBtu/hr 0.0001 LB/MMBTU BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric gene NG 48.1 Natural gas. 0.0002 LB/MMBTU 1 H BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 Natural gas-fired combined-cycle electric generation facility that is NG 40 MMBTU/H 0.0005 LB/MMBTU OTHER CASEMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 1/30/2014 Footprint Power Salem Harbor Development LP (the Permittee) pro NG 80 MMBTU/H 0.0009 LB/MMBTU 1 HR BLOCK AVG, D BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 92.4 MMBtu/hr ULSD and good combustion practices 0.0011 LB/MMBTU AVG OF 3 1-HR TES BACT-PSD

OH-0375 LONG RIDGE ENERGY GENERATION LLC - HAN OH 11/7/2017 Combined cycle combustion turbine power generation facility NG 26.8 MMBTU/H Low sulfur fuel 0.003 LB/H BACT-PSDOH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine pla NG 44.55 MMBTU/H Pipeline quality natural gas 0.004 LB/H 9e-5 lb/MMBtu BACT-PSDOH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 8/25/2015 962 MW (gross winter output) combined cycle gas turbine (CCGT) f NG 34 MMBTU/H Low sulfur fuel 0.004 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 9/27/2017 Combined cycle gas turbine (CCGT) facility NG 37.8 MMBTU/H low sulfur fuel 0.004 LB/H BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 45 MMBTU/H EXCLUSIVE USE OF PIPELINE QUALITY NATURAL GAS 0.004 LB/MMBTU 3-HOUR BLOCK AV BACT-PSD

MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNO NG 42 MMBTU/H EXCLUSIVE USE OF NATURAL GAS, AND GOOD COMBUSTION P 0.004 LB/MMBTU 3-HOUR BLOCK AV BACT-PSDPA-0306 TENASKA PA PARTNERS/WESTMORELAND GE PA 2/12/2016 The plan approval will allow construction and temporary operation NG 1052 MMscf/yr Good combustion practices 0.0049 TPY BACT-PSDIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 Utility electric generating station NG 60.1 mmBtu/hr 0.0055 LB/H AVERAGE OF 3 ONE BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 New, combined-cycle, natural gas-fired, electrical power generating NG 66.7 MMBTU/H

H2SO4 0.0086 LB/MMBTU BACT-PSD

OH-0370 TRUMBULL ENERGY CENTER OH 9/7/2017 940 MW combined cycle gas turbine (CCGT) facility NG 37.8 MMBTU/H Low sulfur fuel 0.0087 LB/H BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 7/19/2016

1.ONE GENERAL ELECTRIC (GE) 7HA.02 CCCT NOMINALLY NG 4000 H/YR USE OF NATURAL GAS A CLEAN BURNING AND LOW SULFUR F 0.01 LB/H BACT-PSD

OH-0367 SOUTH FIELD ENERGY LLC OH 9/23/2016 1150 MW combined-cycle gas turbine (CCGT) facility NG 99 MMBTU/H natural gas/ultra low sulfur diesel 0.011 LB/H BACT-PSDOH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 799 Megawatt Combined Cycle Combustion Turbine Power Plant NG 99 MMBtu/H only burning natural gas 0.5 GR/100 SCF 0.011 LB/H BACT-PSD*WV-0029 HARRISON COUNTY POWER PLANT WV 3/27/2018

NG 77.8 mmBtu/hr Use of Natural Gas 0.0132 LB/HR BACT-PSD

OH-0377 HARRISON POWER OH 4/19/2018 1000 MW natural gas-fired combined cycle combustion turbine pla NG 80 MMBTU/H Pipeline quality natural gas 0.018 LB/H BACT-PSDOH-0360 CARROLL COUNTY ENERGY OH 11/5/2013 Natural gas fired combined cycle gas turbine electric generating sta NG 99 MMBtu/H only burning natural gas 0.02 LB/H BACT-PSD*WV-0032 BROOKE COUNTY POWER PLANT WV 9/18/2018 Nominal 925 mWe natural gas-fired combined-cycle power plant. S NG 111.9 mmBtu/hr Use of Natural Gas 0.02 LB/HR BACT-PSDOH-0363 NTE OHIO, LLC OH 11/5/2014 Combined-cycle, natural gas-fired power plant NG 150 MMBTU/H Exclusive Natural Gas 0.03 LB/H BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELA PA 12/17/2013 This application is for the construction of a natural gas-fired combin NG 40 MMBTU/H 0.04 T/YR BASED ON 12-MON N/AOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating NG 185 MMBTU/H Pipeline natural gas fuel 0.043 LB/H BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 The proposed facility is designed to generate baseload power. It w NG 96 mmBtu/hr Good combustion practice 0.1 POUNDS/HOUR BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate baseload power. It w NG 96 mmBtu/hr Good combustion practice 0.1 LB/HR BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLAN MI 7/16/2018 Natural gas combined-cycle power plant NG 99.9 MMBTU/H Good combustion practices, low sulfur fuel 0.34 GR S/100 SC FUEL SUPPLIER RECBACT-PSD*Draft determination December 2019

Renovo Energy CenterDiesel Emergency Generator EngineRBLC Search ResultsNitrogen Oxides (NOx)

RBLC ID Facility Name State Permit Date Process Name Size Units Process Notes Control DescriptionEmission


Period BasisIL-0129 CPV THREE RIVERS ENERGY CENTER IL 07/30/2018 Emergency Engines 0

One large emergency engine-generator, 1500 kW 0 LAER

WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 08/28/2012 Diesel Emergency Generator (EP15) 839 hp EPA Tier 2 rated 0 BACT-PSDWV-0025 MOUNDSVILLE COMBINED CYCLE POWER PWV 11/21/2014 Emergency Generator 2015.7 HP Nominal 1,500 kW. Limited to 100 hours/year. 0 BACT-PSDOK-0154 MOORELAND GENERATING STA OK 07/02/2013 DIESEL-FIRED EMERGENCY GENERATOR EN 1341 HP <100 HR/YR OPERATION. COMBUSTION CONTROL 0.011 LB/HP-HR =4.99 g/hp- BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELPA 12/17/2013 Emergency Generator 60 Gal/hr 0.53 T/YR BASED ON 1 OTHER CASECA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 EMERGENCY IC ENGINE 182 HP UNIT IS 135 KW. 4 G/KW-H 3-HR AVG BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Diesel GEN 500 H/YR 2500 KW good combustion practices and the use of ultra low sulfur d 4.8 G/HP H BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Emergency Generator Engines 0 (2) 1500 kW emergency diesel genset. Emission limitations are for each genset and fuel is restricted to ULSD (1 4.8 G/BHP-HR LAERMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY GENERATOR 1500 KW 40 CFR 60 SUBPART IIII, ULTRA LOW-SULFUR DIESEL EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUSTION PRACT 4.8 G/HP-H N/A LAER*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY GENERATOR 1 2250 KW 40 CFR 60 SUBPART IIII, ULTRA LOW-SULFUR DIESEL LIMITED OPERATING HOURS, USE OF ULTRA- LOW SULFUR 4.8 G/HP-H LAERMA-0039 SALEM HARBOR STATION REDEVELOPMEN MA 01/30/2014 Emergency Engine/Generator 7.4 MMBTU/H

period 4.8 GM/BHP-H 1 HR BLOCK LAER

IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATOR 1006 HP EACH THE TWO INTERNAL COMBUSTION ENGINES, IDENT COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 4.8 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP THIS ONE (1) INTERNAL COMBUSTION ENGINE, IDEN COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 4.8 G/HP-H 3 HOURS BACT-PSDMI-0402 SUMPTER POWER PLANT MI 11/17/2011 Diesel fuel-fired combustion engine (RICE) 732 HP Diesel fuel-fired engine for emergency. Good combustion practices 4.85 G/HP-H TEST BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Emergency Generator 0

emergency diesel generator shall not exceed 15 4.93 G/HP-HR LAER

PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PA 01/31/2013 EMERGENCY GENERATOR-ENGINE 0 the permittee shall only use diesel fuel that is classified as ULTRA-LOW SULFUR NON-HIGHWAY DIESEL FUEL (1 4.93 GM/B-HP-H OTHER CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Emergency Generator 0 The emergency generator will be restricted to operate not more than 100 hr/yr. 4.93 G/B-HP-H OTHER CASEPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 2000 kW Emergency Generator 0 To allow maintenance of vital plant loads during power outages or maintenance of the switchyard. 5.45 GM/HP-HR LAERCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 03/11/2010 EMERGENCY ENGINE 2000 KW 2000 KW (2,683 hp) engine OPERATIONAL RESTRICTION OF 50 HR/YR 6 G/KW-H BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Emergency Engine 1500 kW One large emergency engine-generator at the plant; one small emergency engine-generator at the switchyard. 6.4 G/KW-HR LAERVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED EMERGENCY GENERATOR 30 0 Good Combustion Practices/Maintenance 6.4 G/KW PER HR N/A*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 1,500 kW Emergency Diesel Generator 14.82 MMBtu/h

total of 100 hr/yr for maintenance checks, Operate and maintain the engine according to the manufa 6.4 G/KW-HOUR BACT-PSD

MI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUEMENGINE (North Plant): Emergency E 1341 HP A 1,341 HP (1,000 kilowatts (KW)) diesel-fired emer Good combustion practices and meeting NSPS Subpart IIII 6.4 G/KW-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUEMENGINE (South Plant): Emergency E 1341 HP A 1,341 HP (1,000 kilowatts (kW)) diesel-fired emer Good combustion practices and meeting NSPS IIII requirem 6.4 G/KW-H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLAMI 07/16/2018 EUEMENGINE: Emergency engine 2 MW A nominal 2 MW diesel-fueled emergency engine w State of the art combustion design. 6.4 G/KW-H HOURLY BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 EUEMENGINE (Diesel fuel emergency engi 22.68 MMBTU/Ha 2,922 horsepower (HP) (2,179 kilowatts (kW)) die Good combustion practices and meeting NSPS IIII requirem 6.4 G/KW-H TEST PROTO BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 DIESEL-FIRED AUXILIARY (EMERGENCY) EN 1500 KW TWO DIESEL-FIRED AUXILIARY GENERATORS (EMER EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD C 6.4 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 EMERGENCY GENERATOR 1490 HP 40 CFR 60 SUBPART IIII, 40 CFR 63 SUBPART ZZZZ UL EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD C 6.4 G/KW-H BACT-PSDCA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 EMERGENCY IC ENGINE 2683 HP UNIT IS 2000 KW. 6.4 G/KW-H 3-HR AVG BACT-PSDAK-0071 INTERNATIONAL STATION POWER PLANT AK 12/20/2010 Caterpillar 3215C Black Start Generator (1 1500 KW-e Turbocharger and Aftercooler 6.4 G/KW-H INSTANTAN BACT-PSDID-0018 LANGLEY GULCH POWER PLANT ID 06/25/2010 EMERGENCY GENERATOR ENGINE 750 KW COMPRESSION IGNITION INTERNAL COMBUSTION (

GOOD COMBUSTION PRACTICES (GCP) 6.4 G/KW-H NOX+NMHCBACT-PSD

*Draft Determination December 2019

Renovo Energy CenterDiesel Fire Pump EngineRBLC Search ResultsNitrogen Oxides (NOx)



Period BasisPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PPA 01/31/2013 Fire Pump Engine - 460 BHP 0 2.6 G/HP-H EXPRESSED OTHER CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Fire Pump 0 The fire pump will be restricted to operate not more than 100 hr/yr. 2.6 G/B-HP-H OTHER CASEVA-0328 C4GT, LLC VA 04/26/2018 Emergency Fire Water Pump 500 HR/YR 315 BHP Good combustion practices and the use of ultra 3 G/HP-HR BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUFPENGINE (South Plant): Fire pump engine 300 HP A 300 HP diesel-fired emergency f Good combustion practices and meeting NSPS Su 3 G/BHP-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUFPENGINE (North Plant): Fire pump engine 300 HP A 300 HP diesel-fired emergency f Good combustion practices and meeting NSPS Su 3 G/BHP-H HOURLY BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Fire Pump Engine 0

combusted by the fire engine 3 G/HP-HR LAER

PA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Emergency Fire Pump Engine 0 Sulfur content of diesel fuel shall not exceed 15 ppm, operation of engine shall not 3 G/BHP-HR LAERPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Fire pump engine 15 gal/hr 3 GM/HP-HR LAERMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUM 300 HP 40 CFR 60, SUBPART IIII, ULTRA LO EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUST 3 G/HP-H N/A LAER*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUM 477 HP 40 CFR 60, SUBPART IIII, ULTRA LO LIMITED OPERATING HOURS, USE OF ULTRA- LOW 3 G/HP-H LAERMI-0423 INDECK NILES, LLC MI 01/04/2017 EUFPENGINE (Emergency engine--diesel fire pump) 1.66 MMBTU/H A 260 brake horsepower (bhp) die Good combustion practices and meeting NSPS Su 3 G/BHP-H TEST PROTO BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST MI 12/05/2016 EUFPENGINE (Emergency engine--diesel fire pump) 500 H/YR A 165 horsepower (hp) diesel-fue Good combustion practices. 3 G/HP-H TEST PROTO BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 01/30/2014 Fire Pump Engine 2.7 MMBTU/H

12-month rolling period 3 GM/BHP-H1 HR BLOCK LAER

MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST MI 12/04/2013 Emergency Engine --Diesel Fire Pump (EUFPENGINE 165 HP A 165 hoursepower (hp) diesel-fu Good combustion practices 3 G/HP-H TEST PROTOBACT-PSDMI-0410 THETFORD GENERATING STATION MI 07/25/2013 EU-FPENGINE: Diesel fuel fired emergency backup 315 hp namepla

emergency backup fire mump. Proper combustion design and ultra low sulfur d 3 G/HP-H TEST PROTO BACT-PSD

IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH THE TWO FIREWATER PUMP ENG COMBUSTION DESIGN CONTROLS AND USAGE LI 3 G/HP-H 3 HOURS BACT-PSDLA-0331 CALCASIEU PASS LNG PROJECT LA 09/21/2018 Firewater Pumps 634 kW Good Combustion and Operating Practices. 3.1 G/HP-H BACT-PSDCA-1192 AVENAL ENERGY PROJECT CA 06/21/2011 EMERGENCY FIREWATER PUMP ENGINE 288 HP EQUIPPED W/ A TURBOCHARGER AND AN INTER 3.4 G/HP-H BACT-PSDCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 03/11/2010 EMERGENCY FIREWATER PUMP ENGINE 135 KW 135 KW (182 hp) IC Diesel-fired Em OPERATIONAL RESTRICTION OF 50 HR/YR, OPERA 3.8 G/KW-H BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Firewater Pump Engine 420 horsepowerOne engine will power the pump in the firewater system. The fuel must meet the 4 G/KW-HR LAER*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 Emergency Fire Pump Engine (347 HP) 8700 gal/year Limits equal Subpart IIII limits Operate and maintain the engine according to th 4 G/KW-HR BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANMI 07/16/2018 EUFPENGINE: Fire pump engine 399 BHP A 399 brake HP diesel-fueled eme State of the art combustion design. 4 G/KW-H HOURLY BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 DIESEL-FIRED FIRE PUMP ENGINE 300 HP ONE DIESEL-FIRED FIRE PUMP EN EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL F 4 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUM 305 HP 40 CFR 60, SUBPART IIII, 40 CFR 63 EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AN 4 G/KW-H LAERCA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 EMERGENCY IC ENGINE 182 HP UNIT IS 135 KW. 4 G/KW-H 3-HR AVG BACT-PSDID-0018 LANGLEY GULCH POWER PLANT ID 06/25/2010 FIRE PUMP ENGINE 235 KW COMPRESSION IGNITION INTERNA

GOOD COMBUSTION PRACTICES (GCP) 4 G/KW-H NOX+NMHCBACT-PSD

VA-0328 C4GT, LLC VA 04/26/2018 Emergency Diesel GEN 500 H/YR good combustion practices and the use of ultra l 4.8 G/HP H BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Emergency Generator Engines 0 (2) 1500 kW emergency diesel genset. Emission limitations are for each genset and 4.8 G/BHP-HR LAERMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY GENERATOR 1500 KW 40 CFR 60 SUBPART IIII, ULTRA LO EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUST 4.8 G/HP-H N/A LAER*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY GENERATOR 1 2250 KW 40 CFR 60 SUBPART IIII, ULTRA LO LIMITED OPERATING HOURS, USE OF ULTRA- LOW 4.8 G/HP-H LAERMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 01/30/2014 Emergency Engine/Generator 7.4 MMBTU/H

12-month rolling period 4.8 GM/BHP-H1 HR BLOCK LAER

IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH THE TWO INTERNAL COMBUSTIO COMBUSTION DESIGN CONTROLS AND USAGE LI 4.8 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP THIS ONE (1) INTERNAL COMBUST COMBUSTION DESIGN CONTROLS AND USAGE LI 4.8 G/HP-H 3 HOURS BACT-PSDMI-0402 SUMPTER POWER PLANT MI 11/17/2011 Diesel fuel-fired combustion engine (RICE) 732 HP Diesel fuel-fired engine for emergGood combustion practices 4.85 G/HP-H TEST BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Emergency Generator 0

combusted by the emergency 4.93 G/HP-HR LAER

PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PPA 01/31/2013 EMERGENCY GENERATOR-ENGINE 0 the permittee shall only use diesel fuel that is classified as ULTRA-LOW SULFUR NO 4.93 GM/B-HP-H OTHER CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Emergency Generator 0 The emergency generator will be restricted to operate not more than 100 hr/yr. 4.93 G/B-HP-H OTHER CASEOH-0375 LONG RIDGE ENERGY GENERATION LLC - HAN OH 11/07/2017 Emergency Diesel Fire Pump Engine (P002) 700 HP 700 hp emergency diesel-fired fire Good combustion design 4.97 LB/H NMHC+NOX BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 Emergency Fire Pump (P006) 410 HP 410 HP emergency diesel-fired fir Certified to the meet the emissions standards in 2.7 LB/H NMHC+NOX BACT-PSDLA-0308 MORGAN CITY POWER PLANT LA 09/26/2013 380 HP Diesel Fired Pump Engine 2.3 MMBTU/hr Good combustion and maintenance practices, an 2.92 LB/H HOURLY MABACT-PSD

Top 50 sources with lowest emission rates from RBLC search.*Draft Determination December 2019

Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsCarbon Monoxide (CO)

RBLC ID Facility Name State Permit Date Equipment Type Size Units Control DescriptionEmission

Limit Limit Averaging Period BasisPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLT PA 01/31/2013 Emergency Generator 0 0.13 GM/B-HP-H OTHER CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Emergency Generator 0 0.13 G/B-HP-H OTHER CASEPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Emergency Generator 0 0.26 G/HP-HR BACT-PSDMI-0402 SUMPTER POWER PLANT MI 11/17/2011 Diesel fuel-fired combustion engine (RICE) 732 HP Good combustion practices 0.31 G/HP-H TEST BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Emergency generator 0 Good combustion practice. 0.45 G/BHP-H 1 H BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Fire pump engine 15 gal/hr 0.5 GM/HP-HR BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLT PA 01/31/2013 Fire Pump Engine - 460 BHP 0 0.5 G/HP-H OTHER CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Fire Pump 0 0.5 G/B-HP-H OTHER CASEPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 2000 kW Emergency Generator 0 0.6 GM/HP-HR BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Fire Pump Engine 0 1 G/HP-HR BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATION VA 03/12/2013 Diesel Fire water pump 376 bhp 500 h/yr good combustion practices 3.5 G/KW-HR BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Diesel GEN 500 H/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD 2.6 G/HP H BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Fire Water Pump 500 HR/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD 2.6 G/HP HR BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED WATER PUMP 376 bph (1) 0 Good Combustion Practices/Maintenance 2.6 G/HP-H HR N/AMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUFPENGINE (South Plant): Fire pump engine 300 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 2.6 G/BPH-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUFPENGINE (North Plant): Fire pump engine 300 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 2.6 G/BHP-H HOURLY BACT-PSDMD-0041 CPV ST. CHARLES MD 04/23/2014 Emergency Generator 1500 KW USE OF ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 2.6 G/HP-H N/A BACT-PSDMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 300 HP USE OF ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 2.6 G/HP-H N/A BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY GENERATOR 1 2250 KW USE OF ULSD FUEL, GOOD COMBUSTION PRACTICES AND HOURS OF OPERA 2.6 G/HP-H BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 477 HP USE OF ULSD FUEL, GOOD COMBUSTION PRACTICES AND HOURS OF OPERA 2.6 G/HP-H BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 Fire Pump Engine 1.66 MMBTU/H Good combustion practices and meeting NSPS Subpart IIII requirements. 2.6 G/BHP-H TEST PROTOCOL W BACT-PSDMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 01/30/2014 Emergency Engine/Generator 7.4 MMBTU/H 2.6 GM/BHP-H 1 HR BLOCK AVG IN OTHER CASEMA-0039 SALEM HARBOR STATION REDEVELOPMENT MA 01/30/2014 Fire Pump Engine 2.7 MMBTU/H 2.6 GM/BHP-H 1 HR BLOCK AVG OTHER CASEMI-0410 THETFORD GENERATING STATION MI 07/25/2013 Fire pump Engine 315 hp nameplaProper combustion design and ultra low sulfur diesel fuel. 2.6 G/HP-H TEST PROTOCOL W BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 Fire pump Engines 371 BHP, EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 2.6 G/HP-H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 2.6 G/HP-H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 2.6 G/HP-H 3 HOURS BACT-PSDLA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 08/16/2011 EMERGENCY DIESEL GENERATOR 1250 HP ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 2.6 G/HP-H ANNUAL AVERAGE BACT-PSDLA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 08/16/2011 EMERGENCY FIRE PUMP 350 HP ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 2.6 G/HP-H LB/MM BTU BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Emergency Generator Engines 0 2.61 G/BHP-HR BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 09/02/2016 Emergency Fire Pump Engine 0 2.61 G/BHP-HR BACT-PSD*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 Firewater Pump Engine 420 horsepower 3.5 G/KW-HR BACT-PSDVA-0321 BRUNSWICK COUNTY POWER STATION VA 03/12/2013 Emergency diesel generator- 2200 kW 500 hrs/yr good combustion practices 3.5 G/KW-HR BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED EMERGENCY GENERATOR 3000 kW (1) 0 Good Combustion Practices/Maintenance 3.5 G/KW PER HR N/A*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 1,500 kW Emergency Diesel Generator 14.82 MMBtu/ho Operate and maintain the engine according to the manufacturer's written i 3.5 G/KW-HOUR BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 Emergency Fire Pump Engine (347 HP) 8700 gal/year Operate and maintain the engine according to the manufacturer's written i 3.5 G/KW-HOUR BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUEMENGINE (North Plant): Emergency Engine 1341 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 3.5 G/KW-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 EUEMENGINE (South Plant): Emergency Engine 1341 HP Good combustion practices and meeting NSPS IIII requirements. 3.5 G/KW-H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 EUEMENGINE: Emergency engine 2 MW State of the art combustion design. 3.5 G/KW-H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 EUFPENGINE: Fire pump engine 399 BHP State of the art combustion design. 3.5 G/KW-H HOURLY BACT-PSD

Top 50 sources with lowest emission rates from RBLC search.*Draft Determination

December 2019Page 3 of 2

Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsCarbon Monoxide (CO)

RBLC ID Facility Name State Permit Date Equipment Type Size Units Control DescriptionEmission

Limit Limit Averaging Period Basis*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Two 3300 kW emergency generators 0 Certified engine 3.5 GRAMS PER KWH BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Emergency Fire Pump Engine (422 hp) 0 Certified engine 3.5 G / KWH BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 EUEMENGINE (Diesel fuel emergency engine) 22.68 MMBTU/H Good combustion practices and meeting NSPS Subpart IIII requirements. 3.5 G/KW-H TEST PROTOCOL SH BACT-PSDCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 03/11/2010 EMERGENCY ENGINE 2000 KW OPERATIONAL RESTRICTION OF 50 HR/YR 3.5 G/KW-H BACT-PSDCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 03/11/2010 EMERGENCY FIREWATER PUMP ENGINE 135 KW OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE AS REQUIRED FOR FIRE 3.5 G/KW-H BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 03/09/2016 One 422-hp emergency fire pump engine 0 Use of clean engine technology 3.5 G / KW-HR BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 DIESEL-FIRED AUXILIARY (EMERGENCY) ENGINES (TW 1500 KW EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRA 3.5 G/KW-H BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 DIESEL-FIRED FIRE PUMP ENGINE 300 HP EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL AND GOOD COMBUST 3.5 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 EMERGENCY GENERATOR 1490 HP EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRA 3.5 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 305 HP USE OF ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 3.5 G/KW-H BACT-PSD

Top 50 sources with lowest emission rates from RBLC search.*Draft Determination

December 2019Page 4 of 2

Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsParticulate Matter (PM/PM10/PM2.5)

RBLC ID Facility Name State Permit Date Process Name Size Units Control DescriptionEmission


Period BasisPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 2000 kW Emergency Generator 0 0.025 GM/HP-HR BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Emergency generator 0 Ultra low sulfur diesel with maximum sulfur content 0.0015 percent. 0.03 G/BHP-H 1 H BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Fire pump 0 Ultra low sulfur diesel with maximum sulfur content 0.0015 percent. 0.043 LB/MMBTU 1 H BACT-PSDMI-0402 SUMPTER POWER PLANT MI 11/17/2011 Diesel fuel-fired combustion engine (RICE) 732 HP Good combustion practices 0.05 G/HP-H TEST BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 07/19/2016 EMERGENCY DIESEL FIRE PUMP 100 H/YR Use of Ultra Low Sulfur Diesel (ULSD) Oil a clean burning fuel and limited hours of ope 0.108 LB/H BACT-PSDPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Fire pump engine 15 gal/hr 0.11 GM/HP-HR BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Diesel GEN 500 H/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD) fuel oil wi 0.15 G/HP H BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (South Plant): Fire pump engine 300 HP Diesel particulate filter, good combustion practices and meeting NSPS Subpart IIII req 0.15 G/BHP-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (North Plant): Fire pump engine 300 HP Diesel particulate filter, good combustion practices and meeting NSPS Subpart IIII req 0.15 G/BHP-H HOURLY BACT-PSDMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY GENERATOR 1500 KW EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRACTICES 0.15 G/HP-H N/A BACT-PSDMD-0041 CPV ST. CHARLES MD 04/23/2014 Emergency Diesel Engine Fire Water Pump 300 HP EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRACTICES 0.15 G/HP-H N/A BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 EMERGENCY GENERATOR 1 2250 KW EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUSTION PRACTICES, LIMITED HOURS OF O 0.15 G/HP-H BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 Emergency Diesel Engine Fire Water Pump 477 HP EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUSTION PRACTICES, LIMITED HOURS OF O 0.15 G/HP-H BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 Emergency engine--diesel fire pump 1.66 MMBTU/H Good combustion practices and meeting NSPS Subpart IIII requirements. 0.15 G/BHP-H TEST PROTOCOL W BACT-PSDLA-0308 MORGAN CITY POWER PLANT LA 09/26/2013 380 HP Diesel Fired Pump Engine 2.3 MMBTU/hr Good combustion and maintenance practices, and compliance with NSPS 40 CFR 60 S 0.15 LB/H HOURLY MAXIMU BACT-PSDMI-0410 THETFORD GENERATING STATION MI 07/25/2013 Diesel fuel fired emergency backup fire pump 315 hp namepla Proper combustion design and ultra low sulfur diesel fuel. 0.15 G/HP-H TEST PROTOCOL W BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP COMBUSTION DESIGN CONTROLS AND USAGE LIMITS 0.15 G/HP-H 3 HOURS BACT-PSDNJ-0081 PSEG FOSSIL LLC SEWAREN GENERATING SNJ 03/07/2014 Emergency diesel fire pump 0 Use of Ultra low sulfur distillate oil 0.15 G/B-HP-H BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 1,500 kW Emergency Diesel Generator 14.82 MMBtu/houOperate and maintain the engine according to the manufacturer's written instruction 0.2 G/KW-HOUR BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILITY FL 07/27/2018 Emergency Fire Pump Engine (347 HP) 8700 gal/year Operate and maintain the engine according to the manufacturer's written instruction 0.2 G/KW-HOUR BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (North Plant): Emergency Engine 1341 HP Diesel particulate filter, good combustion practices and meeting NSPS Subpart IIII req 0.2 G/KW-H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (South Plant): Emergency Engine 1341 HP Diesel particulate filter, good combustion practices and meeting NSPS IIII requirement 0.2 G/KW-H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLAMI 07/16/2018 EUEMENGINE: Emergency engine 2 MW State of the art combustion design 0.2 G/KW-H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLAMI 07/16/2018 EUFPENGINE: Fire pump engine 399 BHP State of the art combustion design 0.2 G/KW-H HOURLY BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Two 3300 kW emergency generators 0 Clean fuel 0.2 GRAMS PER KWH BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Emergency Fire Pump Engine (422 hp) 0 Certified engine 0.2 G / KWH BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 Diesel fuel emergency engine 22.68 MMBTU/H Good combustion practices and meeting NSPS Subpart IIII requirements. 0.2 G/KW-H TEST PROTOCOL W BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 Diesel Fired Auxiliary Emergency Engines 1500 KW USE OF ULTRA LOW SULFUR DIESEL AND GOOD COMBUSTION PRACTICES 0.2 G/KW-H BACT-PSDMD-0046 KEYS ENERGY CENTER MD 10/31/2014 DIESEL-FIRED FIRE PUMP ENGINE 300 HP EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL AND GOOD COMBUSTION PRACT 0.2 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 EMERGENCY GENERATOR 1490 HP EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRACTICES 0.2 G/KW-H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 Emergency Diesel Engine Fire Water Pump 305 HP EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD COMBUSTION PRACTICES 0.2 G/KW-H BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/05/2016 Emergency engine--diesel fire pump 500 H/YR Good combustion practices. 0.22 G/HP-H TEST PROTOCOL W BACT-PSD


Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsParticulate Matter (PM/PM10/PM2.5)

RBLC ID Facility Name State Permit Date Process Name Size Units Control DescriptionEmission


Period BasisMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/04/2013 Emergency Engine --Diesel Fire Pump 165 HP Good combustion practices 0.22 G/HP-H TEST PROTOCOL BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/01/2012 Emergency Generator 200 H/YR use of ULSD, a low sulfur clean fuel 0.59 LB/H N/ANJ-0080 HESS NEWARK ENERGY CENTER NJ 11/01/2012 Emergency Generator 200 H/YR 0.66 LB/H BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 07/19/2016 EMERGENCY GENERATOR DIESEL 0 100 H/YR Use of Ultra Low Sulfur Diesel (ULSD) Oil a clean burning fuel and limited hours of ope 0.661 LB/H BACT-PSDLA-0308 MORGAN CITY POWER PLANT LA 09/26/2013 2000 KW Diesel Fired Emergency Generator En 20.4 MMBTU/hr Good combustion and maintenance practices, and compliance with NSPS 40 CFR 60 S 1.06 LB/H HOURLY MAXIMU BACT-PSDLA-0308 MORGAN CITY POWER PLANT LA 09/26/2013 2000 KW Diesel Fired Emergency Generator En 20.4 MMBTU/hr Good combustion and maintenance practices, and compliance with NSPS 40 CFR 60 S 1.06 LB/H HOURLY MAXIMU BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Fire Water Pump 500 HR/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD) fuel oil wi 15 G/HP/HR BACT-PSDWV-0025 MOUNDSVILLE COMBINED CYCLE POWER WV 11/21/2014 Emergency Generator 2015.7 HP 0 BACT-PSDWV-0025 MOUNDSVILLE COMBINED CYCLE POWER WV 11/21/2014 Fire Pump Engine 251 HP 0 BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/01/2012 Emergency Generator 200 H/YR use of ULSD, a low sulfur clean fuel 0 BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTE PA 12/17/2013 Emergency Generator 60 Gal/hr 0.005 T/YR BASED ON 12-MO CASE-BY-CASEPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTE PA 12/17/2013 Emergency Firewater Pump 16 Gal/hr 0.005 T/YR BASED ON 12-MO N/A


Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsVolatile Organic Compounds (VOC)



Period BasisPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 01/31/2013 EMERGENCY GENERATOR-ENGINE 0 the permittee shall only use diesel fuel that is classified as ULTRA-LOW SULFUR NON-H 0.01 GM/B-HP-H EXPRESSED CASE-BY-CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Emergency Generator 0 The emergency generator will be restricted to operate not more than 100 hr/yr. 0.01 G/B-HP-H CASE-BY-CASEPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Emergency Generator 0

combusted by the emergency diesel 0.02 G/HP-HR LAER

PA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 2000 kW Emergency Generator 0 To allow maintenance of vital plant loads during power outages or maintenance of th 0.22 GM/HP-HR LAEROK-0154 MOORELAND GENERATING STA OK 07/02/2013 Diesel fired Emergency Generator Engine 1341 HP <100 HR/YR OPERATION. COMBUSTION CONTROL. 0.318 G/HP-HR BACT-PSDLA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 08/16/2011 EMERGENCY DIESEL GENERATOR 1250 HP ULTRA LOW SULFUR DIESEL AND GOOD CO 1 G/HP-H ANNUAL AVBACT-PSDMD-0041 CPV ST. CHARLES MD 04/23/2014 EMERGENCY GENERATOR 1500 KW 40 CFR 60 SUBPART IIII, ULTRA LOW-SULF EXCLUSIVE USE OF ULSD FUEL, GOOD COM 4.8 LB/MMBTU N/A LAERVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 Diesel fire Emergency Generator 3000 kW 0 Good Combustion Practices/Maintenance 6.4 G/KW PER HR N/AID-0018 LANGLEY GULCH POWER PLANT ID 06/25/2010 EMERGENCY GENERATOR ENGINE 750 KW COMPRESSION IGNITION INTERNAL COMB

GOOD COMBUSTION PRACTICES (GCP) 6.4 G/KW-H NOX+NMHCBACT-PSD

OH-0377 HARRISON POWER OH 04/19/2018 Emergency Diesel Generator (P003) 1860 HP 1,387 KW (1,860 HP) emergency diesel-fir Good combustion practices (ULSD) and com 19.68 LB/H NMHC+NOX BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 Emergency Generators (2 identical) 2206 HP Two identical Emergency Generators; 1,64

standards in 40 CFR 89.112 and 89.113 23.21 LB/H NMHC+NOX BACT-PSD

OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANN OH 11/07/2017 Emergency Diesel Generator Engine (P001) 2206 HP 1,645 kW (2,206 HP) emergency diesel-fire Good combustion design 24.71 LB/H NMHC+NOX BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 01/31/2013 Fire Pump Engine - 460 BHP 0 0.1 G/HP-H CASE-BY-CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PL T PA 10/10/2012 Fire Pump 0 The fire pump will be restricted to operate not more than 100 hr/yr. 0.1 G/B-HP-H CASE-BY-CASEOH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 08/25/2015 Emergency fire pump engine (P004) 140 HP 140 hp (104.5 kW) emergency diesel-fired State-of-the-art combustion design 0.11 LB/H BACT-PSDNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 07/19/2016 EMERGENCY DIESEL FIRE PUMP 100 H/YR ULSD: Ultra low sulfur diesel Use of Ultra Low Sulfur Diesel (ULSD) Oil a 0.117 LB/H LAERNJ-0081 PSEG FOSSIL LLC SEWAREN GENERATING STATINJ 03/07/2014 Emergency diesel fire pump 0 The fire pump has a maximum heat input rate of 2.63 MMBtu/hr (approximately 250 0.119 LB/H LAERPA-0309 LACKAWANNA ENERGY CTR/JESSUP PA 12/23/2015 Fire pump engine 15 gal/hr 0.12 GM/HP-HR LAERMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 EUFPENGINE: Fire pump engine 399 BHP A 399 brake HP diesel-fueled emergency f State of the art combustion design. 0.13 LB/H HOURLY BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH THE TWO FIREWATER PUMP ENGINES, IDE COMBUSTION DESIGN CONTROLS AND USA 0.16 LB/H BACT-PSDWV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANWV 11/21/2014 Fire Pump Engine 251 HP Limited to 100 Hours/year. 0.17 LB/H BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 09/01/2015 Fire Pump Engine 0

combusted by the fire engine pump shall 0.2 G/HP-HR LAER

OH-0370 TRUMBULL ENERGY CENTER OH 09/07/2017 Emergency fire pump engine (P004) 300 HP Emergency Fire Pump 300 hp (224 kW meState-of-the-art combustion design 0.24 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 09/27/2017 Emergency fire pump engine (P004) 300 HP 300 hp emergency diesel-fired fire pump State-of-the-art combustion design 0.24 LB/H BACT-PSDOH-0367 SOUTH FIELD ENERGY LLC OH 09/23/2016 Emergency fire pump engine (P004) 311 HP 311 hp (232.1 kW mechanical) emergency State-of-the-art combustion design 0.25 LB/H BACT-PSDOH-0352 OREGON CLEAN ENERGY CENTER OH 06/18/2013 Emergency fire pump engine 300 HP 223.8 kW. Emergency fire pump engine re Purchased certified to the standards in NSP 0.25 LB/H BACT-PSDOH-0360 CARROLL COUNTY ENERGY OH 11/05/2013 Emergency fire pump engine (P004) 400 HP 400 hp (298 kW) emergency diesel-fired fi Purchased certified to the standards in NSP 0.325 LB/H BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Fire pump 0 Good combustion practice. 0.3612 lb/MMBtu 1 H LAERLA-0331 CALCASIEU PASS LNG PROJECT LA 09/21/2018 Firewater Pumps 634 kW Good combustion and operating practices. 0.44 G/HP-H BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/05/2016 Emergency engine--diesel fire pump 500 H/YR A 165 horsepower (hp) diesel-fueled emer Good combustion practices 0.47 LB/H TEST PROTO BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 Emergency engine--diesel fire pump 1.66 MMBtu/hr A 260 brake horsepower (bhp) diesel-fuele Good combustion practices 0.64 LB/H TEST PROTO BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (South Plant): Fire pump engine 300 HP A 300 HP diesel-fired emergency fire pum Good combustion practices. 0.75 LB/H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (North Plant): Fire pump engine 300 HP A 300 HP diesel-fired emergency fire pum Good combustion practices 0.75 LB/H HOURLY BACT-PSDLA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 08/16/2011 EMERGENCY FIRE PUMP 350 HP ULTRA LOW SULFUR DIESEL AND GOOD CO 1 G/HP-H ANNUAL AVBACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 04/23/2013 EMERGENCY FIREWATER PUMP 3.25 MMBtu/hr EMERGENCY FIREWATER PUMP (450 BHP) 1.11 LB/H CASE-BY-CASEOH-0377 HARRISON POWER OH 04/19/2018 Emergency Fire Pump (P004) 320 HP 238.6 KW (320 HP) emergency diesel-fired Good combustion practices (ULSD) and com 2.12 LB/H NMHC+NOX BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 Emergency Fire Pump (P006) 410 HP 410 HP emergency diesel-fired fire pump t Certified to the meet the emissions standar 2.7 LB/H NMHC+NOX BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED WATER PUMP 376 bph (1) 0 FWP-1: 104.0 tons/year (12-month rolling Good Combustion Practices/Maintenance 3 G/HP-H PER HR N/AID-0018 LANGLEY GULCH POWER PLANT ID 06/25/2010 FIRE PUMP ENGINE 235 KW COMPRESSION IGNITION INTERNAL COMB

GOOD COMBUSTION PRACTICES (GCP) 4 G/KW-H NOX+NMHCBACT-PSD

OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANN OH 11/07/2017 Emergency Diesel Fire Pump Engine (P002) 700 HP 700 hp emergency diesel-fired fire pump t Good combustion design 4.97 LB/H NMHC+NOX BACT-PSD


Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsVolatile Organic Compounds (VOC)



Period BasisVA-0328 C4GT, LLC VA 04/26/2018 Emergency Fire Water Pump 500 HR/YR 315 BHP good combustion practices and the use of u 0 BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5T MI 12/04/2013 Emergency Engine --Diesel Fire Pump 165 HP A 165 hoursepower (hp) diesel-fueled eme Good combustion practices 0.001 LB/H TEST PROTOBACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNPA 12/17/2013 Emergency Firewater Pump 16 Gal/hr 0.013 T/YR BASED ON 1 N/AMI-0410 THETFORD GENERATING STATION MI 07/25/2013 Diesel fuel fired emergency backup fire pump 315 hp nameplat

backup fire mump. It has a capacity of Proper combustion design and ultra low su 0 BACT-PSD

PA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNPA 12/17/2013 Emergency Generator 60 Gal/hr 0.03 T/YR BASED ON 1 CASE-BY-CASENY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Emergency generator 0 Good combustion practice. 0.0331 lb/MMBtu 1 H LAERNJ-0079 WOODBRIDGE ENERGY CENTER NJ 07/25/2012 Emergency Generator 100 H/YR The Emergency Generator will use Ultra Lo Use of ULSD oil 0.49 LB/H LAERNJ-0085 MIDDLESEX ENERGY CENTER, LLC NJ 07/19/2016 EMERGENCY GENERATOR DIESEL 0 100 H/YR Use of Ultra Low Sulfur Diesel (ULSD) Oil a 0.557 LB/H LAERPA-0291 HICKORY RUN ENERGY STATION PA 04/23/2013 EMERGENCY GENERATOR 7.8 MMBTU/H EMERGENCY GENERATOR (1,135 BHP - 750 KW) 0.7 LB/H CASE-BY-CASEMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (North Plant): Emergency Engine 1341 HP A 1,341 HP (1,000 kilowatts (KW)) diesel-f Good combustion practices. 0.86 LB/H HOURLY BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 (South Plant): Emergency Engine 1341 HP A 1,341 HP (1,000 kilowatts (kW)) diesel-fi Good combustion practices 0.86 LB/H HOURLY BACT-PSDOH-0352 OREGON CLEAN ENERGY CENTER OH 06/18/2013 Emergency generator 2250 KW Emergency diesel fired generator restricte Purchased certified to the standards in NSP 3.93 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 09/27/2017 Emergency generator (P003) 1529 HP 1,000 kWe (1,140 kW mechanical) emerge State-of-the-art combustion design 2 LB/H BACT-PSDNJ-0080 HESS NEWARK ENERGY CENTER NJ 11/01/2012 Emergency Generator 200 H/YR use of ULSD, a low sulfur clean fuel 2.62 LB/H LAEROH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 08/25/2015 Emergency generator (P003) 2346 HP 1,750 kW (2,346 hp) emergency generator 3.1 LB/H BACT-PSDOH-0367 SOUTH FIELD ENERGY LLC OH 09/23/2016 Emergency generator (P003) 2947 HP 2,000 kW electric, 2,198 kW mechanical (2 State-of-the-art combustion design 3.84 LB/H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH THE TWO INTERNAL COMBUSTION ENGIN COMBUSTION DESIGN CONTROLS AND USA 1.04 LB/H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP THIS ONE (1) INTERNAL COMBUSTION ENG COMBUSTION DESIGN CONTROLS AND USA 1.04 LB/H 3 HOURS BACT-PSDWV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANWV 11/21/2014 Emergency Generator 2015.7 HP Nominal 1,500 kW. Limited to 100 hours/year. 1.24 LB/H BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 EUEMENGINE (Diesel fuel emergency engine) 22.68 MMBTU/H a 2,922 horsepower (HP) (2,179 kilowatts Good combustion practices. 1.87 LB/H TEST PROTO BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 EUEMENGINE: Emergency engine 2 MW A nominal 2 MW diesel-fueled emergency State of the art combustion design. 1.89 LB/H HOURLY BACT-PSDOH-0360 CARROLL COUNTY ENERGY OH 11/05/2013 Emergency generator (P003) 1112 KW 1,112 kW emergency diesel fired generatoPurchased certified to the standards in NSP 1.93 LB/H BACT-PSDOH-0370 TRUMBULL ENERGY CENTER OH 09/07/2017 Emergency generator (P003) 1529 HP Emergency Generator 1000 kW (electrical State-of-the-art combustion design 2 LB/H BACT-PSD


Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsSulfur Dioxide (SO2)

RBLC ID Facility Name State Permit Date PROCESS_NAME Size Units Control DescriptionEmission


Period BasisOH-0377 HARRISON POWER OH 04/19/2018 Emergency Diesel Generator (P003) 1860 HP ultra-low sulfur diesel (ULSD) fuel with a sulfur content of less than 15 ppm (0.0015 pe 0.0015 LB/MMBTU BACT-PSDOH-0377 HARRISON POWER OH 04/19/2018 Emergency Fire Pump (P004) 320 HP ultra-low sulfur diesel (ULSD) fuel with a sulfur content of less than 15 ppm (0.0015 pe 0.0015 LB/MMBTU BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Diesel GEN 500 H/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD) fuel oil wit 0 BACT-PSDVA-0328 C4GT, LLC VA 04/26/2018 Emergency Fire Water Pump 500 HR/YR good combustion practices and the use of ultra low sulfur diesel (S15 ULSD) fuel oil wit 0 BACT-PSDVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED EMERGENCY GENERATOR 3000 kW (1) 0 Ultra Low Sulfur Diesel/Fuel (15 ppm max) 0.0015 LB/MMBTU N/AVA-0325 GREENSVILLE POWER STATION VA 06/17/2016 DIESEL-FIRED WATER PUMP 376 bph (1) 0 Ultra Low Sulfur Diesel/Fuel (15 ppm max) 0.0015 LB/MMBTU N/AOH-0370 TRUMBULL ENERGY CENTER OH 09/07/2017 Emergency generator (P003) 1529 HP Ultra low sulfur diesel fuel 0.016 LB/H BACT-PSDOH-0370 TRUMBULL ENERGY CENTER OH 09/07/2017 Emergency fire pump engine (P004) 300 HP Ultra low sulfur diesel fuel 3.2 X10-3 LB/H BACT-PSDLA-0331 CALCASIEU PASS LNG PROJECT LA 09/21/2018 Firewater Pumps 634 kW Ultra-Low Sulfur Diesel Fuel with Sulfur Content of 15 ppmv. 0.04 LB/GAL BACT-PSDOH-0367 SOUTH FIELD ENERGY LLC OH 09/23/2016 Emergency fire pump engine (P004) 311 HP Ultra low sulfur diesel fuel 0.004 LB/H BACT-PSDOH-0367 SOUTH FIELD ENERGY LLC OH 09/23/2016 Emergency generator (P003) 2947 HP Ultra low sulfur diesel fuel 0.03 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 09/27/2017 Emergency generator (P003) 1529 HP Ultra low sulfur diesel fuel 0.016 LB/H BACT-PSDOH-0372 OREGON ENERGY CENTER OH 09/27/2017 Emergency fire pump engine (P004) 300 HP Ultra low sulfur diesel fuel 3.2 X10-3 LB/H BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 Emergency Generators (2 identical, P004 and P005) 2206 HP ultra-low sulfur diesel (ULSD) fuel with a sulfur content of less than 15 ppm (0.0015 pe 0.0015 LB/MMBTU BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 Emergency Fire Pump (P006) 410 HP Certified to the meet the emissions standards in Table 4 of 40 CFR Part 60, Subpart IIII. 0.0015 LB/MMBTU BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILFL 07/27/2018 1,500 kW Emergency Diesel Generator 14.82 MMBtu/hr Clean fuel 15 PPM S IN FUEL BACT-PSD*FL-0367 SHADY HILLS COMBINED CYCLE FACILFL 07/27/2018 Emergency Fire Pump Engine (347 HP) 8700 gal/year Clean fuel 15 PPM S IN FUEL BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH L MI 06/29/2018 EUFPENGINE (South Plant): Fire pump engine 300 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUPPL BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH L MI 06/29/2018 EUEMENGINE (North Plant): Emergency Engine 1341 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUPPL BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH L MI 06/29/2018 EUFPENGINE (North Plant): Fire pump engine 300 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUPPL BACT-PSDMI-0433 MEC NORTH, LLC AND MEC SOUTH L MI 06/29/2018 EUEMENGINE (South Plant): Emergency Engine 1341 HP Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUPPL BACT-PSDWY-0070 CHEYENNE PRAIRIE GENERATING STAWY 08/28/2012 Diesel Emergency Generator (EP15) 839 hp Ultra Low Sulfur Diesel 0 CASE-BY-CASEWY-0070 CHEYENNE PRAIRIE GENERATING STAWY 08/28/2012 Diesel Fire Pump Engine (EP16) 327 hp Ultra Low Sulfur Diesel 0 BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Two 3300 kW emergency generators 0 Clean fuel 15 PPM S IN FUEL BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 Emergency Fire Pump Engine (422 hp) 0 Clean fuel 15 PPM S IN FUEL BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILIMD 04/08/2014 EMERGENCY GENERATOR 1 2250 KW USE OF ULTRA-LOW DIESEL SULFUR FUEL, LIMITED HOURS OF OPERATION AND DESIGN 0.006 G/B-HP-H 3-HOUR BLO BACT-PSD*MD-0042 WILDCAT POINT GENERATION FACILIMD 04/08/2014 EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 477 HP USE OF ULTRA-LOW DIESEL SULFUR FUEL, LIMITED HOURS OF OPERATION AND DESIGN 0.0049 G/B-HP-H 3-HOUR BLO BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 EUEMENGINE (Diesel fuel emergency engine) 22.68 MMBtu/hr Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUPPL BACT-PSDMI-0423 INDECK NILES, LLC MI 01/04/2017 EUFPENGINE (Emergency engine--diesel fire pump) 1.66 MMBtu/hr Good combustion practices and meeting NSPS Subpart IIII requirements. 15 PPM FUEL SUP. C BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Emergency generator 0 Ultra low sulfur diesel with maximum sulfur content 0.0015 percent. 0.0014 LB/MMBTU 1 H BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 08/01/2013 Fire pump 0 Ultra low sulfur diesel with maximum sulfur content 0.0015 percent. 0.0014 LB/MMBTU 1 H BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTE FL 03/09/2016 One 422-hp emergency fire pump engine 0 Use of ULSD 0.0015 % S IN ULSD BACT-PSDPA-0286 MOXIE ENERGY LLC/PATRIOT GENER PA 01/31/2013 Fire Pump Engine - 460 BHP 0 0.005 G/HP-H EXPRESSED CASE-BY-CASEPA-0286 MOXIE ENERGY LLC/PATRIOT GENER PA 01/31/2013 EMERGENCY GENERATOR-ENGINE 0 The permittee shall only use diesel fuel that is classified as ULTRA-LOW SULFUR NON-H 0.005 GM/B-HP-H EXPRESSED BACT-PSDPA-0291 HICKORY RUN ENERGY STATION PA 04/23/2013 EMERGENCY FIREWATER PUMP 3.25 MMBtu/hr 0.0055 LB/H CASE-BY-CASEPA-0291 HICKORY RUN ENERGY STATION PA 04/23/2013 EMERGENCY GENERATOR 7.8 MMBtu/hr 0.01 LB/H CASE-BY-CASEMA-0039 SALEM HARBOR STATION REDEVELO MA 01/30/2014 Emergency Engine/Generator 7.4 MMBtu/hr 0.011 LB/H 1 HR BLOCK CASE-BY-CASEMA-0039 SALEM HARBOR STATION REDEVELO MA 01/30/2014 Fire Pump Engine 2.7 MMBtu/hr 0.004 LB/H 1 HR BLOCK CASE-BY-CASEOH-0352 OREGON CLEAN ENERGY CENTER OH 06/18/2013 Emergency fire pump engine 300 HP 0.003 LB/H N/A


Renovo Energy CenterDiesel Generator and Fire Pump EngineRBLC Search ResultsSulfur Dioxide (SO2)

RBLC ID Facility Name State Permit Date PROCESS_NAME Size Units Control DescriptionEmission


Period BasisOH-0352 OREGON CLEAN ENERGY CENTER OH 06/18/2013 Emergency generator 2250 KW 0.03 LB/H N/AIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) FIREWATER PUMP DIESEL ENGINES 371 BHP, EACH ULTRA LOW SULFUR DISTILLATE AND USAGE LIMITS 0.0015 % SUFLUR DIESEL FUEL BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 TWO (2) EMERGENCY DIESEL GENERATORS 1006 HP EACH ULTRA LOW SULFUR DISTILLATE AND USAGE LIMITS 0.012 LB/H BACT-PSDIN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/03/2012 EMERGENCY DIESEL GENERATOR 2012 HP ULTRA LOW SULFUR DISTILLATE AND UASGE LIMITS 0.024 LB/H 3 HOURS BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ PA 12/17/2013 Emergency Generator 60 Gal/hr 0.0001 T/YR CASE-BY-CASEPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ PA 12/17/2013 Emergency Firewater Pump 16 Gal/hr 0.0001 T/YR N/ANJ-0081 PSEG FOSSIL LLC SEWAREN GENERAT NJ 03/07/2014 Emergency diesel fire pump 0 Use of Ultra low sulfur fuel oil 0.002 LB/MMBTU BACT-PSDPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PA 10/10/2012 Emergency Generator 0 0.005 G/B-HP-H CASE-BY-CASEPA-0278 MOXIE LIBERTY LLC/ASYLUM POWER PA 10/10/2012 Fire Pump 0 0.005 G/B-HP-H CASE-BY-CASE


Renovo Energy CenterHeater - Natural GasRBLC Search ResultsNitrogen Oxides (NOx)

RBLC ID Facility Name State Permit Date Facility Descriptin Fuel Size Units Control DescriptionEmission

Limit Units Averaging Period Basis*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

two (2) identical 1 x 1 powerblocks where each powerblock consists of NG 15 mmBtu/hr 0.01 LB MMBTU LAER

*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 The proposed facility is designed to generate baseload power. It will co NG 13 mmBtu/hr Low-NOx combustion technology 0.011 lb/MMBtu LAER*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017

combined cycle, single shaft configuration, including a combustion NG 6.4 MMBtu/hr good combustion and operating practices 0.011 LB MMBTU

IL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate baseload power. It will co NG 12.8 mmBtu/hr Low-NOx burners 0.011 lb/MMBtu LAERPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) NG 14.6 mmBtu/hr 0.011 lb/MMBtu LAER


temporarily operate the Fairview Energy Center. NG 13.8 mmBtu/hr 0.011 lb/MMBtu LAERWY-0070 CHEYENNE PRAIRIE GENERATING STATIONWY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The station is to NG 16.1 mmBtu/hr Ultra Low NOx Burners 0.012 lb/MMBtu 3-HOUR AVERAGE BACT-PSDIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 Utility electric generating station NG 13.32 mmBtu/hr 0.013 lb/MMBtu 3-HOUR AVERAGE BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

temporarily operate the Fairview Energy Center. NG 3.2 MMBtu/hr 0.035 lb/MMBtu LAER

MD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 9.5 mmBtu/hr USE OF PIPELINE QUALITY NATURAL GAS AND GOOD CO 0.035 lb/MMBtu LAERMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: P NG 13.8 mmBtu/hr USE OF PIPELINE QUALITY NATURAL GAS AND GOOD CO 0.035 lb/MMBtu 3-HOUR BLOCK AVERAGBACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTEPA 12/17/2013 This application is for the construction of a natural gas-fired combined-c NG 8.5 mmBtu/hr 0.035 lb/MMBtu OTHER CASE*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 5 mmBtu/hr USE OF EFFICIENT DESIGN OF THE HEATER, EXCLUSIVE U 0.049 lb/MMBtu 3-HOUR BLOCK AVERAGLAER

NY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generatin NG 0 Forced draft low NOx burner. 0.058 lb/MMBtu 1 H LAERMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generator NG 12 mmBtu/hr Low NOx burners 0.06 lb/MMBtu 30-D ROLL AVG EACH D BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation facil NG 15 mmBtu/hr 0.085 lb/MMBtu OTHER CASE*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with lim NG 9.9 MMBtu/hr Manufacturer certification 0.1 lb/MMBtu DESIGN VALUE BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle unit an NG 10 MMBtu/hr Must have NOx emission design value less than 0.1 lb/M 0.1 lb/MMBtu BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLMI 7/16/2018 Natural gas combined-cycle power plant NG 3.8 mmBtu/hr Low NOx burner 0.14 LB/H HOURLY BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the permit NG 20 mmBtu/hr Good combustion practices 0.15 lb/MMBtu TEST PROTOCOL BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating faciNG 15 mmBtu/hr Low-NOx gas burner 0.3 LB/H BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/5/2016 Natural gas combined heat and power plant. NG 3.7 mmBtu/hr Good combustion practices. 0.55 LB/H TEST PROTOCOL WILL S BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAS MI 12/4/2013 Natural gas combined heat and power plant. NG 3.7 mmBtu/hr Good combustion practices. 0.55 LB/H TEST PROTOCOL BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLMI 7/16/2018 Natural gas combined-cycle power plant NG 20.8 mmBtu/hr Low NOx burner 0.75 LB/H HOURLY BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 140 MMCF/YR Ultra Low NOx burners 0.8 T/YR BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 13.5 mmBtu/hr Good combustion practices. 2.65 LB/H HOURLY; EACH UNIT BACT-PSDCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 563 MW power plant comprised of a hybrid of natural gas-fired combine NG 40 mmBtu/hr OPERATIONAL RESTRICTION OF 1000 HR/YR 9 PPMVD 1-HR AVG, @3% O2 BACT-PSDCA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 570 MW NATURAL GAS FIRED COMBINED CYCLE POWER PLANT WITH A NG 40 mmBtu/hr 9 PPMVD @3% O2, 3-HR AVG BACT-PSDCA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 10 mmBtu/hr 30 PPMVD @3% O2, 3-HR AVG BACT-PSDAK-0071 INTERNATIONAL STATION POWER PLANT AK 12/20/2010 Combined Cycle Power Power Plant NG 12.5 mmBtu/hr Low NOx Burners and Flue Gas Recirculation 32 LB/MMSCF 3-HOUR AVERAGE BACT-PSD*Draft determination December 2019

Renovo Energy CenterHeater - Natural GasRBLC Search ResultsCarbon Monoxide (CO)

RBLC ID Facility Name State Permit Date Facility Description Fuel Size Units Control Description mission Lim Units Averaging Period BasisMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANT NG 13.8 MMBtu/hr good combustion practices 0.021 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSD*PA-0315 HILLTOP ENERGY CENTER, LLC PA 4/12/2017

(1x1), combined cycle, single shaft configuration, including a NG 6.4 mmBtu/hr 0.037 LB MMBTU


identical 1 x 1 power blocks, each consisting of a combustion NG 14.6 mmBtu/hr 0.037 lb/MMBtu BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generat NG 15 MMBtu/hr 0.037 lb/MMBtu OTHER CASEIA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2004 Utility electric generating station NG 13.32 mmBtu/hr 0.041 lb/MMBtu 3-HOUR AVERAGE BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNEE PA 12/17/2013 This application is for the construction of a natural gas-fired com NG 8.5 MMBtu/hr 0.05 lb/MMBtu N/A*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 The proposed facility is designed to generate baseload power. It NG 13 MMBtu/hr Good combustion practice 0.08 lb/MMBtu BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate baseload power. It NG 12.8 mmBtu/hr Good combustion practice 0.08 LB/HR BACT-PSDPA-0310 CPV FAIRVIEW ENERGY CENTER PA 9/2/2016

and temporarily operate the Fairview Energy Center. NG 3.2 MMBtu/hr 0.08 lb/MMBtu BACT-PSD

WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 A nominal 220 megawatt (MW) gross electrical facility. The stat NG 16.1 MMBtu/hr good combustion practices 0.08 lb/MMBtu 3-HOUR AVERAGE BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 9.5 MMBtu/hr good combustion practices 0.08 lb/MMBtu BACT-PSD


POWER PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 NG 5 MMBtu/hr good combustion practices, na 0.083 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric g NG 0 Good combustion practice. 0.084 lb/MMBtu 1 H BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the NG 20 MMBtu/hr Good combustion practices 0.09 lb/MMBtu TEST PROTOCOL BACT-PSDMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine ge NG 12 MMBtu/hr Efficient combustion 0.11 lb/MMBtu TEST PROTOCOL WILL SPECIF BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 3.8 MMBtu/hr Good combustion controls 0.14 LB/H HOURLY BACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/5/2016 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr Good combustion practices. 0.41 LB/H TEST PROTOCOL WILL SPECIF BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr Good combustion practices 0.41 LB/H TEST PROTOCOL BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 20.8 MMBtu/hr Good combustion controls. 0.77 LB/H HOURLY BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical genera NG 15 MMBtu/hr Combustion control 0.83 LB/H BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 13.5 MMBtu/hr Good combustion practices. 2.22 LB/H HOURLY; EACH UNIT BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 140 MMBtu/hr good combustion practices 2.6 T/YR BACT-PSDCA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 563 MW power plant comprised of a hybrid of natural gas-fired NG 40 MMBtu/hr 1000 hr/yr 50 PPMVD 1-HR AVG, @3% O2 BACT-PSDCA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 570 MW NATURAL GAS FIRED COMBINED CYCLE POWER PLANT NG 40 MMBtu/hr 50 PPMVD @3% O2, 3-HR AVG BACT-PSDCA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 10 MMBtu/hr 100 PPMVD @3% O2, 3-HR AVG BACT-PSD*Draft determination December 2019

Renovo Energy CenterHeater - Natural GasRBLC Search ResultsParticulate Matter (PM/PM10/PM2.5)


Limit Units Averaging Period BasisMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generato NG 12 MMBtu/hr Efficient combustion; natural gas fuel. 0.0018 LB/MMBTU TEST PROTOCOL WILL SP BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: NG 13.8 MMBtu/hr Good combustion practices and natural gas 0.0019 LB/MMBTU BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 13.5 MMBtu/hr Good combustion practices. 0.002 LB/MMBTU TEST PROTOCOL WILL SP BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 9.5 MMBtu/hr Good combustion practices and natural gas 0.007 LB/MMBTU BACT-PSD

MI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STMI 12/5/2016 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr Good combustion practices. 0.007 LB/MMBTU TEST PROTOCOL WILL SP BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STMI 12/4/2013 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr Good combustion practices. 0.007 LB/MMBTU TEST PROTOCOL BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNEE PA 12/17/2013 This application is for the construction of a natural gas-fired combined NG 8.5 MMBtu/hr 0.007 LB/MMBTU OTHER CASE*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 5 MMBtu/hr Good combustion practices and natural gas 0.0075 LB/MMBTU 3-HOUR AVERAGE BASIS BACT-PSD

NY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric genera NG 0 MMBtu/hr Natural gas. 0.0076 LB/MMBTU 1 H BACT-PSDMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the perm NG 20 MMBtu/hr Good combustion practices 0.009 LB/MMBTU TEST PROTOCOL BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 3.8 MMBtu/hr Low sulfur fuel 0.03 LB/H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 20.8 MMBtu/hr Low sulfur fuel 0.15 LB/H HOURLY BACT-PSD*Draft determination December 2019

Renovo Energy CenterHeater - Natural GasRBLC Search ResultsVolatile Organic Compounds (VOC)


Limit Units Averaging Period Basis*PA-0316 RENOVO ENERGY CENTER, LLC PA 1/26/2018

two (2) identical 1 x 1 powerblocks where each powerblock consists of NG 15 MMBtu 0.005 LB MMBTU LAER

TX-0756 CCI CORPUS CHRISTI CONDENSATE SPLITTER FACIL TX 6/19/2015 Two identical condensate splitter trains each capable of processing 50,0 NG 153 MMBtu/hr (Good combustion practices 0.005 LB/ 100 SCF EACH HEATER BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating fac NG 15 MMBtu/hr (Combustion control 0.075 LB/H 0.005 lb/MMBtu BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 20.8 MMBtu/hr (Good combustion controls 0.17 LB/H HOURLY BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 7/16/2018 Natural gas combined-cycle power plant NG 3.8 MMBtu/hr (Good combustion controls. 0.03 LB/H HOURLY BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 13.5 MMBtu/hr (Good combustion practices. 0.15 LB/H HOURLY; EACH FUEL HEATBACT-PSDMI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STMI 12/5/2016 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr (Good combustion practices. 0.03 LB/H TEST PROTOCOL WILL SPE BACT-PSDMI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STMI 12/4/2013 Natural gas combined heat and power plant. NG 3.7 MMBtu/hr (Good combustion practices 0.03 LB/H TEST PROTOCOL BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

power blocks, each consisting of a combustion gas turbine (CGT or CT) NG 0 0.005 lb/MMBtu LAER

FL-0364 SEMINOLE GENERATING STATION FL 3/21/2018 Existing fossil-fueled power plant. Two coal-fired units each rated at 736 NG 9.9 MMBtu/hr 0.005 lb/MMBtu BACT-PSDMD-0041 CPV ST. CHARLES MD 4/23/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 96.6 TONS/YR NG 9.5 MMBtu/hr (Good combustion practices and natural gas 0.005 lb/MMBtu LAER


PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 5 MMBtu/hr (good combustion, natural gas, effic design 0.005 lb/MMBtu 3-HOUR BLOCK AVERAGE LAERMI-0406 RENAISSANCE POWER LLC MI 11/1/2013 For technical questions regarding this permit, please contact the permit NG 20 MMBtu/hr (Good combustion practices 0.05 lb/MMBtu TEST PROTOCOL BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation faci NG 15 MMBtu/hr (max) 0.006 lb/MMBtu OTHER CASEMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED POWER PLANTNOTE: P NG 13.8 MMBtu/hr (Good combustion practices and natural gas 0.0054 lb/MMBtu 3-HOUR BLOCK AVERAGE LAERMI-0410 THETFORD GENERATING STATION MI 7/25/2013 Four (4) natural gas fired combined cycle combustion turbine generator NG 12 MMBtu/hr (Efficient combustion; natural gas fuel. 0.008 lb/MMBtu TEST PROTOCOL WILL SPE BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNEE PA 12/17/2013 This application is for the construction of a natural gas-fired combined-c NG 8.5 MMBtu/hr (max) 0.05 lb/MMBtu OTHER CASECA-1211 COLUSA GENERATING STATION CA 3/11/2011 660 MW NATURAL GAS FIRED POWER PLANT NG 10 MMBtu/hr (max) 7 PPMVD @3% O2, 3-HR AVG BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 140 MMCF/YR good combustion practices 0 BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generati NG 0 Good combustion practice. 0 LAER*Draft determination December 2019

Renovo Energy CenterHeater - Natural GasRBLC Search ResultsSulfur Dioxide (SO2)

RBLC ID Facility Name State Permit Date FACILITY_DESCRIPTION Fuel Size Units Control DescriptionEmission

Limit Units Averaging Period BasisVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 140 MMCF/YR natural gas with a max sulfur content of 0.4 gr/100 scf 0.4 GR S /100 SCF OTHER CASE*MD-0042 WILDCAT POINT GENERATION FACILITY MD 4/8/2014

PLANTFACILITY-WIDE PM10 EMISSION LIMIT = 278 TONS/YR NG 5 MMBtu/hr USE OF EFFICIENT DESIGN OF THE HEATER, EXCLUSIVE U 0.0006 lb/MMBtu 3-HOUR BLOCK AVERABACT-PSD

PA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNE PA 12/17/2013 This application is for the construction of a natural gas-fired combined- NG 8.5 MMBtu/hr 0.002 lb/MMBtu OTHER CASENY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined cycle electric generat NG 9 MMBtu/hr Natural gas. 0.0022 lb/MMBtu 1 H BACT-PSDPA-0288 SUNBURY GENERATION LP/SUNBURY SES PA 4/1/2013 This plan approval is for the repowering of the Sunbury Generation fac NG 15 MMBtu/hr 0.003 lb/MMBtu OTHER CASEOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine electrical generating facNG 15 MMBtu/hr Pipeline natural gas fuel 0.023 LB/H BACT-PSD*FL-0363 DANIA BEACH ENERGY CENTER FL 12/4/2017 1200 megawatt 2-on-1 combined cycle facility, natural gas-fired, with l NG 9.9 MMBtu/hr Clean fuel 2 GR S /100 SCF BACT-PSDFL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 3/9/2016 Fossil-fueled power plant, consisting of a 3-on-1 combined cycle unit an NG 10 MMBtu/hr Use of low-sulfur fuel 2 GR S /100 SCF BACT-PSDMI-0423 INDECK NILES, LLC MI 1/4/2017 Natural gas combined cycle power plant. NG 13.5 MMBtu/hr Good combustion practices and the use of pipeline qual 2000 GR/MMSCF BASED UPON FUEL RE BACT-PSD*Draft determination December 2019

Renovo Energy CenterHeater - Natural GasRBLC Search ResultsSulfuric Acid Mist (H2SO4)



PeriodEquivalent lb/MMBtu Basis

*IL-0130 JACKSON ENERGY CENTER IL 12/31/2018 The proposed facility is designed to generate bas NG 13 MMBtu/hr Good combustion practice 0.014 lb/hr 0.0011 BACT-PSDVA-0328 C4GT, LLC VA 4/26/2018 Natural gas-fired combined cycle power plant NG 140 MMCF/YR Pipeline quality natural gas with a maximum 0.4 GR S/100 SCF BACT-PSDOH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 1,650 MW combined cycle combustion turbine e NG 15 MMBtu/hr Pipeline natural gas fuel 0.0035 lb/hr 0.0002 BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PMI 7/16/2018 Natural gas combined-cycle power plant NG 20.8 MMBtu/hr Low sulfur fuel 0.34 GR S/100 SCF FUEL SUPPLIER RECORDS BACT-PSDMI-0435 BELLE RIVER COMBINED CYCLE POWER PMI 7/16/2018 Natural gas combined-cycle power plant NG 3.8 MMBtu/hr Low sulfur fuel 0.34 GR S/100 SCF FUEL SUPPLIER RECORDS BACT-PSDIL-0129 CPV THREE RIVERS ENERGY CENTER IL 7/30/2018 The proposed facility is designed to generate bas NG 12.8 MMBtu/hr Good combustion practice 0.014 lb/hr 0.001 BACT-PSDPA-0311 MOXIE FREEDOM GENERATION PLANT PA 9/1/2015

operation of two identical 1 x 1 power blocks, NG 14.6 MMBtu/hr 0.0001 lb/MMBtu BACT-PSD


GAS-FIRED POWER PLANTFACILITY-WIDE PM10 NG 5 MMBtu/hr good combustion, natural gas, effic design 0.0005 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDNY-0104 CPV VALLEY ENERGY CENTER NY 8/1/2013 CPV Valley Energy Center is a 680 MW combined NG 0 Natural gas. 0.0002 lb/MMBtu 1 H BACT-PSDMD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 990 MW COMBINED-CYCLE NATURAL GAS-FIRED NG 13.8 MMBtu/hr good combustion practices and natural gas 0.004 lb/MMBtu 3-HOUR BLOCK AVERAGE BACT-PSDPA-0296 BERKS HOLLOW ENERGY ASSOC LLC/ONTPA 12/17/2013 This application is for the construction of a natu NG 8.5 MMBtu/hr 0.001 lb/MMBtu OTHER CASE*Draft determination December 2019


APPENDIX N SCR PID

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C

D

E

F

G

H

78 6 5 24 3 1

B

A

C

D

G

E

F

H

REV DESCRIPTION DATE APPROVED

E

SIZE

REVISIONS

DWG NO SH REV

COPYRIGHT 2014 GENERAL ELECTRIC COMPANYC

SIGNATURES

TOLERANCES ON:

MADE FOR

3 PL DECIMALS

2 PL DECIMALS

FRACTIONS

PROJECT

ANGLES

±

±

±

±

ELECTRICAL

MECHANICAL

CONTROLS

ISSUED

CIVIL

PROJ ENG

CHECKED

DIMENSIONS ARE IN INCHES

UNLESS OTHERWISE SPECIFIED

DRAWN

DWG NO

GE Power & Water

SIZE CAGE CODE

SCALE

E

DATE

SHEET

1

GENERAL ELECTRIC COMPANY

GENERAL ELECTRIC INTERNATIONAL, INC.

PROPRIETARY INFORMATION-THIS DOCUMENT CONTAINS

PROPRIETARY INFORMATION OF GENERAL ELECTRIC

COMPANY AND MAY NOT BE USED BY OR DISCLOSED TO

OTHERS, EXCEPT WITH THE WRITTEN PERMISSION OF

GENERAL ELECTRIC COMPANY.

DT-7N

THIRD ANGLE PROJECTION

YYYEZZZZ

A

V. B.

XXXXXXX

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PRELIMINARY

FLOW DIAGRAM

YY-MM-DD

YY-MM-DD

YY-MM-DD

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NONE

14-04-17

TYPICAL HRSG SCR SYSTEM

08-11-25

AY

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XXXA

XXX

E. B.

14/04/17


APPENDIX O COST ANALYSIS INFORMATION (SCR FOR CTGS AND OXIDATION CATALYST FOR AUXILIARY BOILERS)

Cost Analysis for SCR/Oxidation Catalyst

on Combustion Turbines

SCR and Oxidation Catalyst - NOx, CO, VOC

Equipment Costs

SCR/OxCat Unit $1,250,000

frame and housing $15,000

total system (A) $1,265,000

freight (0.05A) $63,250 Page 2-27 Control Cost Manual

taxes (0.05A) $63,250

$1,391,500

Direct Installation Costs direct installation cost factors provided by Control Cost Manual for thermal and

Foundations and supports (0.08B) $111,320 catalytic incinerators and carbon adsorbers.


Electrical (0.01B) $13,915

$320,045

Total direct cost: $1,711,545

standard factors for most control equipment contained in Control Cost Manual



Contractor fees (0.10B) $139,150

Startup (0.02B) $27,830

Performance Test (0.01B) $13,915


Total indirect cost: $431,365

Total Capital investment (TCI): $2,142,910

Operating Labor ---


Maint. Labor and Materials $27,000 $45/hr; 600 hr/yr

Total purchased equipment cost (B):

Total direct installation cost:

Indirect Costs (installation)

Direct Annual Cost

Cost Analysis for SCR/Oxidation Catalyst

on Combustion Turbines

Catalyst replacement (3 year life, 2% interest) $432,500 1734

Spent catalyst handling ----

performance loss not accounted for


Overhead (60% total labor and materials) $16,200 Page 2-34 Control Cost Manual

Administrative charges (0.02 TCI) $42,858 Page 2-34 Control Cost Manual

Insurance (0.01 TCI) $21,429 Page 2-34 Control Cost Manual

Capital recovery (10 year at 2% interest) $99,408

(TCI - 1,250,000 = 892,910)

(892,910*0.11133)



In accordance with equation 2.11 of the Control Cost Manual, the annual cost of the

catalyst is calculated by annualizing a $5,000 replacement cost over 3 years at 2%

(0.3468 x 5,000 = $1,734). As a conservative measure the labor cost for catalyst

replacement is not factored in. The capital recovery factor is calculated using the

equation identified below. (CRF (3 yr at 2%) = 0.3468

Spent catalyst removal/disposal cost was not estimated as a conservative measure.

The spent catalyst is returned to the vendor for metal recovery and the cost for

removal/disposal is indirectly factored in the cost of a new catalyst.

At 2% interest rate over 10 years, using capital recovery factor (CRF) equation: CRF = (I (1+i)n) / (1+i)n -1) (used online calculator at http://www.ajdesigner.com/phpdiscountfactors/capital_recovery_equation.php). CRF = 0.11133 (10 years at 2%)

Indirect Annual Costs

Cost Analysis for a CO Oxidation Catalyst

for one Auxiliary Boiler

Oxidation Catalyst - CO

Per Boiler

Equipment Costs

oxidation catalyst $15,144 as provided by EmeraChem on 2/8/17 for a 66 MMBtu/hr boiler

frame and housing $20,000

total system (A) $35,144

freight (0.05A) $1,757

taxes (0.05A) $1,757

instrumentation (0.10A) $3,514

$42,173

Direct Installation Costs direct installation cost factors provided by Control Cost Manual for thermal and

Foundations and supports (0.08B) $3,374 catalytic incinerators and carbon adsorbers.


Electrical (0.01B) $422

$9,700

Total direct cost: $51,873

standard factors for most control equipment contained in Control Cost Manual



Contractor fees (0.10B) $4,217

Startup (0.02B) $843

Performance Test (0.01B) $422


Total indirect cost: $13,074

Total Capital investment (TCI): $64,946

Operating Labor $160 $40/hr; 4 hours per year for operations


Maint. Labor and Materials $2,250 $45/hr; 50 hr/yr approximately 1 hour per week for testing and maintenance

Page 2-27 of EPA's Office of Air Quality Planning and Standards (OAQPS) Control Cost

Manual, sixth edition (January 2002)

Total purchased equipment cost (B):

Total direct installation cost:

Indirect Costs (installation)

Direct Annual Cost

Cost Analysis for a CO Oxidation Catalyst

for one Auxiliary Boiler

Catalyst replacement (3 year life, 3% interest) $5,353 $5,353.40

Spent catalyst handling ----

performance loss $636 0.0671$/kWhr


Overhead (60% total labor and materials) $1,350 Page 2-34 Control Cost Manual

Administrative charges (0.02 TCI) $1,299 Page 2-34 Control Cost Manual

Insurance (0.01 TCI) $649 Page 2-34 Control Cost Manual

Capital recovery (10 year at 3% interest) $5,838

(TCI - 15,144 = 49,802)

(49,802*0.11723)



CO emissions removed (tons/year) 1.93

Cost effectiveness (dollars/ton CO removed) $9,110 maximum per boiler

CO emission reduction is from 0.036 lb/MMBtu to 0.0036 lb/MMBtu

which is equivalent to a reduction of 1.925 tpy (2.138 tpy to 0.2138 tpy) for one boiler

0.036-0.0036/0.036*100 = 90%

Indirect Annual Costs

In accordance with equation 2.11 of the Control Cost Manual, the annual cost of the

catalyst is calculated by annualizing a $15,144 replacement cost over 3 years at 3%

(0.3535 x 15,144 = $5,353). As a conservative measure the labor cost for catalyst

replacement is not factored in. The capital recovery factor is calculated using the

equation identified below. (CRF (3 yr at 3%) = 0.3535

Spent catalyst removal/disposal cost was not estimated as a conservative measure.

The spent catalyst is returned to the vendor for metal recovery and the cost for

removal/disposal is indirectly factored in the cost of a new catalyst.

energy cost obtained from US Energy Information Administration, online interactive

Electricity Data Browser: http://www.eia.gov/electricity/data.cfm. Value provided is

the rolling 12-month cost ending in February 2013 for the industrial sector.

Average Cost Effectiveness

At 3% interest rate over 10 years, using capital recovery factor (CRF) equation: CRF = (I (1+i)n) / (1+i)n -1) (used online calculator at http://www.ajdesigner.com/phpdiscountfactors/capital_recovery_equation.php). CRF = 0.11723 (10 years at 3%)


APPENDIX P STORAGE TANK INFORMATION

Appendix P

Storage Tank Information

Supplement to Plan Approval Application Form Section B.4

Tanks 2,000 gallons or greater containing VOC

installation max pressure type of relief vent vapor pressure type of

Tank ID Tank description Manf. date of tank relief device set pressure

at storage temp

(psia) roof

Tank #1

storage of backup fuel

for turbines ULSD TBD TBD ambient 3.5 MM

emergency

vent TBD 0.0048

fixed roof

with

internal

floating 35 MM

Tank #2

turbine/generator #1

lube oil tank luricating oil TBD TBD ambient 20,000 breather vent NA <0.0048 fixed nil

Tank #3

turbine/generator #2

lube oil tank lubricating oil TBD TBD ambient 20,000 breather vent NA <0.0048 fixed nil

Tank #4

Emergency Generator

Tank ULSD TBD TBD ambient 2,500 breather vent NA <0.0048 fixed nil

Tanks identified above are not subject to 129.56 and 129.57 because the vapor pressures do not exceed 1.5 psia.

Tank associated with the fire pump engine is not included because it is less than 2,000 gallons.

material

stored capacity (gal)

throughput

per year (gal)

Project will also include two 26,000 gallon above ground aqueous ammonia storage tanks to provide ammonia for the SCR systems. The ammonia tanks are not listed in the table above

since ammonia is not a VOC.


APPENDIX Q REGISTRY OF AVAILABLE NOX AND VOC OFFSETS

November 26, 2019 Page 1

DEPARTMENT OF ENVIRONMENTAL PROTECTION COMMONWEALTH OF PENNSYLVANIA

CERTIFIED EMISSION REDUCTION CREDITS IN PENNSYLVANIA’S ERC REGISTRY

Emission reduction credits (ERCs) are surplus, permanent, quantified and federally enforceable emission reductions used to offset emission increases of oxides of nitrogen (NOx), volatile organic compounds (VOCs) and the following criteria pollutants: carbon monoxide (CO), lead (Pb), oxides of sulfur (SOx), particulate matter (PM), particulate matter with an aerodynamic diameter of 10 micrometers or less (PM-10), and particulate matter with an aerodynamic diameter of 2.5 micrometers or less (PM-2.5). The Pennsylvania Department of Environmental Protection (PADEP) maintains an ERC registry in accordance with the requirements of 25 Pa. Code § 127.209. The ERC registry system provides for the tracking of the creation, transfer and use of ERCs. Prior to registration of the credits, ERC Registry Applications are reviewed and approved by the Department to confirm that the ERCs meet the requirements of 25 Pa. Code §§ 127.206-208. Registration of the credits in the ERC registry system constitutes certification that the ERCs satisfy applicable requirements and that the credits are available for use. The following registered and certified ERCs in the ERC Registry are currently available for use as follows: (1) To satisfy non-attainment new source review (NNSR) emission offset ratio requirements; (2) To “net-out" of NSR at ERC-generating facilities; (3) To sell or trade the ERCs for use as emission offsets at new or modified facilities. The certified ERCs shown below, expressed in tons per year (tpy), satisfy the applicable ERC requirements contained in 25 Pa. Code §§ 127.206-208. ERCs created from the curtailment or shutdown of a source or facility expires for use as offsets 10 years after the emission reduction occurs. ERCs generated by the over control of emissions by an existing facility do not expire for use as offsets. However, credits in the registry that are not used in a plan approval will be discounted if new air quality requirements are adopted by the Department or U.S. Environmental Protection Agency (EPA). For additional information concerning this listing of certified ERCs, contact the Bureau of Air Quality, Division of Permits, Department of Environmental Protection, 12th Floor, Rachel Carson State Office Building, P. O. Box 8468, Harrisburg, PA 17105-8468, (717) 787-4325. This Pennsylvania ERC registry report, ERC Registry application and instructions are located at www.dep.pa.gov, select Businesses, Air, Bureau of Air Quality, Permits, Emission Reduction Credits.

Facility information Criteria

Pollutant Certified

ERCs Available

(tpy)

Expiration date

Intended use of ERCs

LSC Communications Inc. (f.k.a. R.R. Donnelley & Sons) County: Lancaster Contact Person: Stacey Haefner Telephone Number: (712)-293-2056

VOCs

16.00

None

Internal Trading


Facility information Criteria Pollutant

Certified ERCs

Available (tpy)

Expiration date


PPG Industries, Inc. Source Location: Springdale Complex County: Allegheny Contact Person: Joe Frank Telephone Number: (412) 274-3884

VOCs 171.82 None Trading

The Procter & Gamble Paper Products Company Source Location: Mehoopany Plant County: Wyoming Contact Person: Amy Jacoby Telephone Number: (570) 833-6396

NOx

91.10

None

Internal Use

INDSPEC Chemical Corp. Source: Boiler # 8 Source Location: Petrolia County: Butler Contact Person: John Kane Telephone Number: (724) 756-2370 Ext. 108

NOx SOx

158.68 717.95

None Trading

Sunoco Partners Marketing & Terminals, LP Source: Wastewater Conveyance System Source Location: Marcus Hook Borough County: Delaware Contact Person: Kevin Smith Telephone Number: (610) 859-1279

VOCs 142.62 None Trading/ Internal

Use

World Kitchen Inc. Source Location: Charleroi Plant County: Washington Contact Person: Tony Pane Telephone Number: (724) 489-2255

NOx 131.43 None Trading

Highway Materials, Inc.

Source: 1011

Source: 1011

Source: 1011

Source: 1012

Source: 1012

Source: 1012

Source location: Whitemarsh Township

County: Montgomery

Contact Person: Greg Mullen

Telephone Number: (610) 832-8000

VOCs

NOx

SOx

VOCs

NOx

SOx

0.435

1.655

4.888

0.383

1.436

4.346

9/27/2021

9/27/2021

9/27/2021

10/7/2021

10/7/2021

10/7/2021

Trading



Certified ERCs

Available (tpy)

Expiration date


GenOn Emissions, LLC Source Location: Titus Station Township: Cumru County: Berks Contact Person: Randall Lack Telephone Number: (281) 207-7213

NOx VOCs CO SOx PM-10 PM-2.5 Pb

1453.26 11.32 94.79

9100.08 223.38 96.57 0.06

8/30/2023 8/30/2023 8/30/2023 8/30/2023 8/30/2023 8/30/2023 8/30/2023

Trading

P.H. Glatfelter Company Source Location: 228 South Main St, Spring Grove County: York Contact Person: Jonathan E. Moores Telephone Number: (717) 225-4711 X 2395

SOx

428.00 None Trading

Bellefield Boiler Plant Source Location: 4400 Forbes Ave, Pittsburgh County: Allegheny Contact Person: Anthony J. Young Telephone Number: (412) 578-2495

PM-10 PM-2.5 SOx

61.81 52.68

578.89

None None None

Trading/ Internal

Use

University of Pittsburgh Medical Center (UPMC) Source Location: 600 Grant Street, Pittsburgh County: Allegheny Contact Person: Eric Cartwright Telephone Number: (412) 647-0896

PM-10 PM-2.5 SOx

16.69 14.22

156.31

None None None

Trading/ Internal

Use

Philadelphia Energy Solutions (PES)

ERC Generating Source: Sunoco, Inc. (R&M)

Source Location: Marcus Hook Borough

County: Delaware

Contact Person: Chuck Barksdale


NOx

SO2

VOCs

CO

PM-10

PM-2.5

295.23

0.36

32.98

199.11

28.33

28.33

12/31/2021

12/31/2021

12/31/2021

12/31/2021

12/31/2021

12/31/2021

Trading/ Internal

Use

Philadelphia Energy Solutions (PES)

ERC Generating Source: Sunoco, Inc. (R&M)


County: Delaware

Contact Person: Chuck Barksdale


NOx

SO2

VOCs

CO

PM-10

PM-2.5

111.37

128.42

2.21

365.60

317.94

317.94

12/31/2021

12/31/2021

12/31/2021

12/31/2021

12/31/2021

12/31/2021

Internal Use Only



Certified ERCs

Available (tpy)

Expiration date


Pactiv, LLC

ERC Generating Source: Dopaco, Inc.

Sources: Presses 101 to 104

Source Location: Downingtown, Chester

Contact Person: Phoebe C. Robb


VOCs 60.30

None Trading/ Internal

Use

Exelon Power

Sources: Boiler #1

Source: Eddystone Generating Station

Source Location: Eddystone Borough

County: Delaware

Contact person: Albert Hatton


NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

2547.85

5.97

2988.50

130.53

54.84

127.77

0.38

2/17/2021

2/17/2021

2/17/2021

2/17/2021

2/17/2021

2/17/2021

2/17/2021

Trading

Exelon Power

Sources: Boiler #2, centrifuge dryers &

coal handling fugitives

Source: Eddystone Generating Station

Source Location: Eddystone Borough

County: Delaware



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

2016.85

5.81

2720.10

302.43

178.38

135.40

0.40

4/27/2021

4/27/2021

4/27/2021

4/27/2021

4/27/2021

4/27/2021

4/27/2021

Trading

Texas Eastern Transmission, L.P.

Sources: I.C. Engines 031 thru 039

Source Location: Bedford Compression Station

Township: Bedford

County: Bedford

Contact Person: Matthew Myers


NOx

CO

VOCs

PM-10

PM-2.5

SO2

164.46

32.45

34.30

4.37

4.37

0.054

4/15/2023

4/15/2023

4/15/2023

4/15/2023

4/15/2023

4/15/2023

Trading

International Paper

Source: Bleach Plant, Erie Mill

County: Erie

Contact Person: Allyson Bristow


VOCs 0.60 None Trading



Certified ERCs

Available (tpy)

Expiration date


Merck, Sharp & Dohme

Source Location: 770 Sumneytown Pike, PO Box 4,

WP2-205, West Point, PA 19486-0004

County: Montgomery

Contact Person: Amy Earley


VOCs 3.69 3/30/2021 Trading



WP2-205, West Point, PA 19486-0004

County: Montgomery



VOCs 1.12 12/31/2021 Trading

Monroe Energy, LLC

Source Location: 4101 Post Rd., Trainer, PA

County: Delaware

Contact Person: Jeff K. Warmann


VOCs 4.80 None Internal use / Trading

Exelon Power

Sources: Coal boiler #31, centrifuge dryers, reheat

burners, diesel generator, coal handling fugitives &

ash handling fugitives

Source: Cromby Generating Station

Source Location: East Pikeland Township

County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

1825.89

0.96

3235.58

143.40

60.31

78.48

0.06

2/18/2021

2/18/2021

2/18/2021

2/18/2021

2/18/2021

2/18/2021

2/18/2021

Trading

Exelon Power

Sources: Oil boiler #32



County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

127.40

2.60

239.65

19.05

15.35

17.52

7/31/2021

7/31/2021

7/31/2021

7/31/2021

7/31/2021

7/31/2021

Trading



Certified ERCs

Available (tpy)

Expiration date


Exelon Power

Sources: Oil boiler #33



County: Chester



NOx

SO2

PM-10

PM-2.5

CO

1.68

2.32

0.25

0.17

0.55

6/29/2022

6/29/2022

6/29/2022

6/29/2022

6/29/2022

Trading

Exelon Power

Sources: Oil delivery fugitives



County: Chester



PM-10

PM-2.5

0.48

0.07

6/30/2022

6/30/2022

Trading

Exelon Power

Sources: Natural gas preheater



County: Chester



NOx

SO2

PM-10

PM-2.5

CO

0.06

0.02

0.01

0.01

0.05

10/16/2022

10/16/2022

10/16/2022

10/16/2022

10/16/2022

Trading

UGI Development Company

Source: Hunlock Creek Energy Center

Source Location: Hunlock Township

County: Luzerne

Contact Person: Jeff Steeber

Telephone Number: (570) 542-5369 ext. 232

SO2

PM-10

3263.16

54.45

5/22/2020

5/22/2020

Trading/

Internal

Shell Chemical Appalachia LLC

Source: G.F. Wheaton Power Plant / Units 034 & 035

Source Location: Potter Township / Monaca

County: Beaver

Contact Person: Jim Sewell


SOx

PM-10

CO

1898.73

44.26

64.20

9/11/2021

9/11/2021

9/11/2021

Trading



Certified ERCs

Available (tpy)

Expiration date


Armstrong World Industries, Inc.

Source: Beaver Falls Ceiling Plant

Source Location: Beaver Falls Township

County: Beaver

Contact Person: John Ackiewicz

Telephone Number: 717-396-5373

NOx

VOCs

PM-2.5

CO

14

27

21

46

3/31/2021

3/31/2021

3/31/2021

3/31/2021

Trading

Exelon Power

Sources: Boiler #1

Source: Schuylkill Generating Station

Source Location: 2800 Christian St., Phila.

County: Philadelphia



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

40.02

0.68

68.06

6.10

4.81

4.50

0.0014

6/21/2022

6/21/2022

6/21/2022

6/21/2022

6/21/2022

6/21/2022

6/21/2022

Trading

Volvo Construction Equipment, N.A.

Source: Paint Booth / ID 101

Source: Clean & Prime Paint Booth / ID 102

Source: Big Paint Booth / ID 103

Source Location: Shippensburg Borough

County: Franklin

Contact Person: Richard Halter


VOCs

VOCs

VOCs

4.61

5.81

2.17

12/31/2023

9/26/2022

12/31/2023

Internal

Letterkenny Army Depot

Source: Coating Booth / ID 102 (2009 & 2010)

Source: Coating Booth / ID 103 (2009 & 2010)

Source: Coating Booth / ID 109

Source Location: Letterkenny Township

County: Franklin

Contact Person: Samuel J. Pelesky


Hurst Jaws of Life, Inc.

(f.k.a. Hale Products, Inc.)

Source: Test Engines (IDs 111, 732 & 733), paint

booths (IDs 900 & 902) & misc. combustion sources

(ID 901)

Source Location: Conshohocken Borough

County: Montgomery

VOCs

VOCs

VOCs

NOx

6.07

6.21

0.12

6.3552

9/19/2023

9/19/2023

9/18/2022

2/26/2023

Internal

Trading



Certified ERCs

Available (tpy)

Expiration date


Contact Person: Michael Laskaris

Telephone Number: 1-800-533-3569

Carmeuse Lime, Inc

Source: Kiln 3

Source Location: Millard Lime Plant

Township: North Londonderry

County: Lebanon

Contact Person: Mark Reider


NOx

VOCs

SOx

PM-10

PM-2.5

PM

CO

79.87

0.24

33.49

0.80

0.39

1.46

256.50

4/08/2023

4/08/2023

4/08/2023

4/08/2023

4/08/2023

4/08/2023

4/08/2023

Trading

Allegheny Energy Supply Company, LLC

Source: Unit 1

Source Location: Armstrong Power Plant

Township: Washington

County: Armstrong

Contact Person: Tonia A. Downs


NOx

VOCs

SOx

PM-10

PM-2.5

Pb

CO

760.40

0.04

12552.65

203.16

56.66

0.0369

85.39

8/31/2022

8/31/2022

8/31/2022

8/31/2022

8/31/2022

8/31/2022

8/31/2022

Trading


Source: Unit 2

Source Location: Armstrong Power Plant

Township: Washington

County: Armstrong

Contact Person: Tonia A. Downs


* Reduction needed in accordance with 25 Pa. Code §

127.206(c) for compliance with Pennsylvania’s RACT

II requirements of 1.4 tpy NOx ERCs.

NOx

SOx

PM-10

PM-2.5

Pb

CO

1557.50

13334.05

160.50

90.49

0.0247

90.36

7/21/2022

7/21/2022

7/21/2022

7/21/2022

7/21/2022

7/21/2022

Trading



Certified ERCs

Available (tpy)

Expiration date


GenOn Emissions, LLC Source Location: Brunot Island Station, Pittsburgh County: Allegheny Contact Person: Randall Lack Telephone Number: (281) 207-7213

NOx 4.91 9/26/2023 Trading

Shell Chemical Appalachia LLC

Source: Monaca Zinc Smelter / 24 emission sources

Source Location: Potter Township / Monaca

County: Beaver

Contact Person: Jim Sewell


NOx

SOx

PM-10

PM-2.5

CO

197.60

877.90

308.84

30.32

21705.20

4/26/2024

4/26/2024

4/26/2024

4/26/2024

4/26/2024

Trading

GenOn Emissions, LLC Source Location: Elrama Station, Union Township Source: Unit 1 County: Washington Contact Person: Randall Lack


VOCs

NOx

SOx

PM-10

PM-2.5

CO

Pb

2.93

784.99

555.14

76.73

20.85

30.41

0.03

6/23/2022

6/23/2022

6/23/2022

6/23/2022

6/23/2022

6/23/2022

6/23/2022

Trading

GenOn Emissions, LLC Source Location: Elrama Station, Union Township Sources: Units 2 & 3 County: Washington Contact Person: Randall Lack Telephone Number: (281) 207-7213

VOCs

NOx

SOx

PM-10

PM-2.5

CO

Pb

7.39

1925.11

1377.46

183.53

50.56

76.63

0.06

5/30/2022

5/30/2022

5/30/2022

5/30/2022

5/30/2022

5/30/2022

5/30/2022

Trading

GenOn Emissions, LLC Source Location: Elrama Station, Union Township Source: Unit 4 County: Washington Contact Person: Randall Lack Telephone Number: (281) 207-7213

VOCs

NOx

SOx

PM-10

PM-2.5

CO

Pb

7.25

2065.25

1487.09

182.06

49.57

74.81

0.07

9/03/2022

9/03/2022

9/03/2022

9/03/2022

9/03/2022

9/03/2022

9/03/2022

Trading



Certified ERCs

Available (tpy)

Expiration date


Bemis Company, Inc

Source: #711

Source Location: Hazle Township

County: Luzerne

Contact Person: Rob Harmon


VOCs

9.17

9/15/2024

Trading

First Energy Solutions Corporation

(f.k.a. Allegheny Energy Supply Company, LLC)

Source: Unit 3

Source Location: Mitchell Power Plant

Township: Union

County: Washington

Contact Person: Eric R. Foster


NOx

SOx

PM-10

1636

1215

141

10/04/2023

10/04/2023

10/04/2023

Trading

Republic Services of PA, LLC

Modern Landfill

Source: #104

Engine 2

Source Location: Lower Windsor Township

County: York

Contact Person: Karl Schmit


VOCs

NOx

SOx

PM-2.5

CO

1.07

7.98

0.60

0.25

39.32

12/16/2023

12/16/2023

12/16/2023

12/16/2023

12/16/2023

Trading


Modern Landfill

Source: #105

Engine 3


County: York



VOCs

NOx

SOx

PM-2.5

CO

1.41

12.54

0.82

0.34

56.62

11/11/2023

11/11/2023

11/11/2023

11/11/2023

11/11/2023

Trading



Certified ERCs

Available (tpy)

Expiration date



Modern Landfill

Source: #106

Engine 4


County: York



VOCs

NOx

SOx

PM-2.5

CO

1.88

9.04

0.70

0.29

45.76

11/04/2023

11/04/2023

11/04/2023

11/04/2023

11/04/2023

Trading

Environmental Strategy Consultants, Inc.

(f.k.a. G-Seven LTD)

Sources: Various

Source Location: Hatfield, PA

Township: Hatfield

County: Montgomery

Contact Person: Lorna Velardi


NOx

0.08

12/02/2023 Trading

Transcontinental Gas Pipeline Co., LLC

Sources: 033, 034, 035

Source Location: Station 195, Delta, PA

Township: Peach Bottom

County: York

Contact Person: Jim Powel


VOCs

NOx

SOx

PM-2.5

CO

39.0

301.4

0.2

6.7

223.6

5/01/2024

5/01/2024

5/01/2024

5/01/2024

5/01/2024

Trading

Sunoco Partners Marketing & Terminals, LP

Sources: 104, 105


County: Delaware

Contact Person: Kevin Smith


NOx

VOCs

SO2

PM-2.5

PM-10

CO

38.00

26.46

2.54

64.32

64.32

199.78

12/30/2021

12/30/2021

12/30/2021

12/30/2021

12/30/2021

12/30/2021

Trading

AES Beaver Valley, LLC

Sources: 032, 033, 034, 035

Source Location: Cogen Plant

Borough: Potter

County: Beaver

Contact Person: Eric Holtvogt


NOx

CO

SOx

PM-10

PM-2.5

2067.7

1665.0

3187.0

198.0

89.0

6/30/2025

6/30/2025

6/30/2025

6/30/2025

6/30/2025

Trading



Certified ERCs

Available (tpy)

Expiration date


Recipient/Holder of ERC: Elements Markets, LLC Contact Person: Randall Lack Telephone Number: (281) 207-7200

ERC Generating Facility: Allegheny Energy

Supply Company, LLC

Source Municipality: Washington Township County: Armstrong

Source: Unit 1

NOx 27.58 8/31/2022 Trading


ERC Generating Facility: Quad Graphics Inc.

Source Municipality: Village of Depew County: Erie State: New York

VOCs 26.51 12/16/2020 Trading


ERC Generating Facility: Team Ten, LLC

Source: 033A

Source Location: Tyrone Paper Mill

Township: Tyrone Borough

County: Blair

VOCs

NOx

SOx

2.48

182.70

2638.21

07/16/2026

07/16/2026

07/16/2026

Trading

Viking Energy, LLC

Source: 031

Source Location: 909 Cannery Road,

Northumberland, PA 18757

Township: Point

County: Northumberland

Contact Person: Robert Maggiani


NOx

184.25

4/01/2022

Trading

Recipient/Holder of ERC: Elements Markets, LLC

Contact Person: Randall Lack Telephone Number: (281) 207-7200

ERC Generating Facility: Quad Graphics, Inc.

Source Location: Atglen Plant

Township: West Sadsbury

County: Chester

VOCs

44.80

03/04/2026

Trading



Certified ERCs

Available (tpy)

Expiration date


LSC Communications Inc. (f.k.a. R.R. Donnelley & Sons) Sources: 200 & 210 (Printing Presses) Source Location: City of Lancaster County: Lancaster Contact Person: Stacey Haefner

Telephone Number: (712)-293-2056

VOCs

5.43 03/31/2025 Trading

Recipient/Holder of ERC: Elements Markets, LLC Contact Person: Randall Lack Telephone Number: (281) 207-7200 ERC Generating Facility: LEDVANCE, LLC (f.k.a. Osram Sylvania, Inc.) Source: P109 (Glass Melting Furnace) Source Location: Wellsboro Borough County: Tioga

SOx

NOx

PM-10

VOCs

47.45

146.31

26.23

12.04

9/28/2026

9/28/2026

9/28/2026

9/28/2026

Trading

Recipient/Holder of ERC: Elements Markets, LLC

Contact Person: Randall Lack


ERC Generating Facility: Osram Sylvania, Inc.

Sources: 101 Degreaser

102 Stamping Lubrication

104 Glassing Furnace

199 Solvent Source Location: West Manchester Township County: York Contact Person: Kelley Reynolds Telephone Number: (978) 753-6602

VOCs

VOCs

VOCs

NOx

SOx

PM-10

PM-2.5

VOCs

3.91

4.29

0.57

16.14

10.63

1.80

0.63

2.43

12/19/2024

12/19/2024

9/30/2024

9/30/2024

9/30/2024

9/30/2024

9/30/2024

12/19/2024

Trading

PaperWorks Industries Inc.

Sources: Boilers #1, #3, #4

Source Location: City of Philadelphia

County: Philadelphia

Contact Person: Frank Delgrego


VOCs

NOx

14.356

110.055

4/12/2027

4/12/2027

Trading



Certified ERCs

Available (tpy)

Expiration date


Lindy Paving, Inc – West Pittsburg

Source Location: Taylor Township Facility

County: Lawrence

Contact Person: Paul J. Reiner, Jr


VOCs

NOx

SOx

PM-10

CO

1.64

4.05

1.34

7.19

9.47

4/04/2022

4/04/2022

4/04/2022

4/04/2022

4/04/2022

Trading

Piney Creek Power Plant

Source Location: Clarion Township Facility

County: Clarion

Contact Person: Kendall Reed


NOx

SOx

PM-10

PM-2.5

CO

267.00

256.28

34.81

8.65

115.00

4/12/2023

4/12/2023

4/12/2023

4/12/2023

4/12/2023

Trading


Source: Unit 1

Source Location: Hatfield’s Ferry Power Station

Township: Monongahela

County: Greene



NOx

VOCs

SOx

PM-10

PM-2.5

6983.6

20.5

840.2

352.3

252.9

9/26/2023

Trading


Source: Unit 2



County: Greene



NOx

VOCs

SOx

PM-10

PM-2.5

6864.4

20.3

840.1

731.3

525.2

10/06/2023

Trading


Source: Unit 3



County: Greene



NOx

VOCs

SOx

PM-10

PM-2.5

6811.8

21.9

1180.6

920.7

661.2

9/28/2023

Trading



Certified ERCs

Available (tpy)

Expiration date


Mack Trucks, Inc.

Source: 003

003

103

104

118A

119A Township: Lower Macungie County: Lehigh Contact Name: Robert Peterson Telephone Number: (610) 966-8810

VOCs

NOx

VOCs

VOCs

VOCs

VOCs

0.008

0.142

59.151

6.577

4.921

0.547

8/01/2027

8/01/2027

12/08/2026

12/08/2026

12/08/2026

12/08/2026

Trading

GenOn Emissions, LLC Township: Upper Mount Bethel Source Location: Portland Generating Station County: Northampton Contact Person: Randall Lack Telephone Number: (281) 207-7213

VOCs

NOx

16.84

2331.40

12/01/2025

12/01/2025

Trading



WP2-205, West Point, PA 19486-0004

Source: Rotary Kiln Incinerator (005)

County: Montgomery



NOx

PM-10

10.43

1.36

2/19/2027

2/19/2027

Trading

Mack Trucks, Inc.

Sources: 106

107 Township: Lower Macungie County: Lehigh Contact Name: Robert Peterson Telephone Number: (610) 966-8810

VOCs

VOCs

39.06

4.34

12/04/2027

12/04/2027

Trading



Certified ERCs

Available (tpy)

Expiration date


Hill Top Energy Center, LLC (Subsidiary) AEIF Hill Top, LLC (Parent Company) Township: Cumberland County: Greene Contact Name: Jason Kahan Telephone Number: (212) 564-4287

NOx 197.0 7/16/2026 Internal

Maryland Department of Environment

Available Emission Reduction Credits (ERC)

As of May 1, 2019Owner Amount (Tons) ERC Expiration Date ERC Source ERC Contact Information

VOC: 0 Permit #: 021-00003 Gary A. Molchan

NOx: 0 Company Name: 610-837-3329

SO2: 1,137 Essroc Cement Corp. Mailing Address:

PM2.5: 56 Jurisdictions: 3251 Bath Pike

Frederick County Nazareth, PA 18064

VOC: Permit #: 025-0212 Mr. Chris Skaggs


SO2: 33Harford County Resource

Recovery FacilityMailing Address:

PM2.5: Jurisdictions: 100 S. Charles Street, Tower II,

Suite 403

Harford Baltimore MD 21201-2705

VOC: 0 Permit #: 021-00005 Michael A. Palazzolo


SO2: 3,014 Alcoa Inc. Mailing Address:

PM2.5: 312 Jurisdictions: 201 Isabella Street

Frederick County Pittsburgh, PA 15212

VOC: 0 Permit #: 005-01956 Donald Gerard

NOx: 0 Company Name: Phone:

SO2: 0Polystyrene Products

Company, Inc.410-574-0680

PM2.5: 0 Jurisdictions: Mailing Address:

Baltimore County 8845 Kelso Drive

Baltimore, MD 21221

VOC: 0 Permit #: 005-0147 Roberto Perez

NOx: 2,404 Company Name: 847-418-2071 cell:847-815-

8488

SO2: 3,519 HRE Sparrows Point

PM2.5: 1,355 Jurisdictions: Mailing Address:

Baltimore County

VOC: 93 Permit #: 11-0006 Tom Johnson

NOx: Company Name: 410-742-5540

SO2: Eastern Shore Forest

ProductsMailing Address:

PM2.5: Jurisdictions:

Caroline County Eastern Shore Forest Products

3667 St. Luke's Road

Salisbury, MD 21804

Alcoa Inc. 3/31/2020

Essroc Cement

Corporation12/31/2018

Harford County

Resource Recovery

Facility

3/17/2026

Polystyrene Products

Company, Inc.10/27/2020

HRE Sparrows Point

LLC9/14/2022

Eastern Shore Forest

Products2/16/2027

mailto:[email protected]



ContaminantRegion

Available (TPY)*Nonattainment Area

Facility NameDEC ID

ContactTelephone #

Comments Reduction Date

VOC 0.00 Alcan Packaging Mr. Coil1 Severe Ozone 1-2820-00185 773-399-8599

VOC 15.29 Alcan Packaging Mr. Coil1 Severe Ozone 1-2820-00185 773-399-8599

VOC**** 43.73 Northville E. Setauket Terminal Mr. Ripp

Severe Ozone 1-4722-01658 631-753-42200.00 Mr. Lack

Severe Ozone 281-207-7213

VOC 8.40 FiberMark/Arcon Coating Mr. Kraft Emission point(s) shutdown

1 Severe Ozone 1-2820-01862 215-536-4000 2.8 tpy DEC retainedVOC 5.325 Marglo Pack. Corp. Mr. Glassman Emission point(s) shutdown

1 Severe Ozone 1-2824-00898 718-649-2800 1.775tpy DEC retain

VOC 0.00 Northrop Grumman Corp. Mr. Cofman

1 Severe Ozone 1-2824-00112 516-575-4680

VOC 0.00 TRW INC., Steering Wheel Systems Mr. Ferrentino

Severe Ozone 1-4722-00898 518-465-10100.00 Mr. Marchmont


VOC 0.00 TRW INC., Steering Wheel Systems Mr. Ferrentino

Severe Ozone 1-4722-00898 518-465-10100.00 Mr. Marchmont


VOC 3.34 Adchem Industries, Inc. Mr. Pufahl Facility shutdown

1 Severe Ozone 1-2822-00620 631-727-6000 1.11 tpy DEC retain

VOC 0.00 Arkay Packaging Corp. Ms. Triglia



1

New York State Department of Environmental Conservation Emission Reduction Credits (ERCs) Registry

Pursuant to the New York State Clean Air Compliance Act and 6NYCRR Subparts 231-2 and 231-10, Notice is hereby given of the following listing of ERCs, registered by the NYSDEC, which are available for offsets as of November 6, 2019.Contact: ERC Unit, NYS DEC, 625 Broadway, 11th Floor, Albany NY 12233-3254, 518-402-8403

1

Ramapo Energy 7 tpy committed to Calpine # 1-4722-02441

1 tpy transferred to Ramapo Energy & re-transferred to Calpine # 1-4722-02441

42.55 tpy transferred to Caithness LI Energy #1-4722-04426

7 tpy transferred to Ramapo Energy & re-transferred to Calpine # 1-4722-02441

1

1

24.03 transferred to Element Markets

Element Markets, LLC 24.03 transferred to Philadelphia Energy Solutions (PA)

Ramapo Energy 1 tpy committed to Calpine # 1-4722-02441

8.80 tpy transferred to Alcan Packaging #1-4728-04190

69.20 tpy transferred to Alcan Packaging #1-4728-04190

Elements Markets, LLC

9.86 tpy transferred to Elements Markets

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 0.00 Sprague Energy Corp. Mr. Johnson

Severe Ozone 1-2820-01104 516-622-71100.00 Carbo industries, Inc. Mr. Wieting

Severe Ozone 1-2820-01085 516-229-3600VOC 0.00 Uniflex Holdings, Inc. Mr. Remillard

1 Severe Ozone 1-2822-00367 781-817-8970

VOC 1.70 Freeport Power Plant#2 Mr. Bianco Emission Points Shutdown

1 Severe Ozone 1-2820-00358 516-377-2200 0.60 tpy DEC retainVOC 0.00 Printpack, Seal-it Mr. Wiederhold Facility shutdown

Severe Ozone 1-4720-01685 404-691-5830 19.77 tpy transferred to Koch Supply0.00 Mr. Porter

Severe Ozone 316-828-6250VOC 0.00 PE Bay Shore LLC Mr. Murphy Facility Shutdown

Severe Ozone 1-4728-00141 315-448-2266 4.07 transferred to Element Markets0.00 Mr. Lack


VOC 0.00 Aladdin Packaging, LLC Mr. Endzweig Facility shutdown

1 Severe Ozone 1-4728-00618 631-273-4747 81.30 used as offsets

VOC 0.00 Montauk Generating Fac. Mr. Flannery Facility shutdown

Severe Ozone 1-4724-00036 516-545-4875 1.16 tpy transferred To Element Markets0.00 Mr. Lack

Severe Ozone 281-207-72131.16 Mr. Torell


VOC 0.00Glenwood Combustion Turbine Fac., Mr. Flannery

Emission Points shutdown




VOC 0.072National Grid – EF Barrett Power Station, Mr. Flannery

1 Severe Ozone 1-2820-00553 516-545-4875VOC 0.00 Con Ed. – 59th St. Mr. Cartagena

2 Severe Ozone 2-6202-00032 212-460-6275VOC 0.00 Con Ed. – Astoria Mr. Cartagena

2 Severe Ozone 2-6301-00006 212-460-6275VOC 0.00 P&G Port Ivory Plant Ms. Clancy

2 Severe Ozone 2-6401-00004 973-690-3487

October 13, 2011***


Element Markets, LLC 4.07 tpy transferred to Monroe Energy, LLC (PA)

7.42 tpy committed to ConEd East River #2-6206-00012


0.60 tpy transferred to Port Auth. Of NY & NJ

Koch Supply & Trading, LP

19.77 tpy transferred to Tenaska, Inc. (PA)1

Element Markets, LLC 9.42 tpy transferred to Monroe Energy (Broker) LLC

1

Element Markets, LLC 1.16 tpy transferred to Monroe Energy (Broker) LLC

Monroe Energy (Broker), LLC

1


July 1, 2012***

11.81(6.00 and 5.81) tpy transferred to Carbo industries, Inc.

11.81 retired, OOC # R1-20130603-74

1

1

58 tpy committed To CPV Energy Center #3-3356-00136

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 69.22 Betts Ave. Municipal

Incinerator Mr. Bekowies

2 Severe Ozone 2-6304-00093 212-837-8383

VOC 47.14 Green point Municipal Incinerator Mr. Bekowies

2 Severe Ozone 2-6101-00022 212-837-8383

VOC 149.00 SW Brooklyn Municipal Incinerator Mr. Bekowies

2 Severe Ozone 2-6106-00002 212-837-8383VOC 0.00 Con Ed.- Waterside Mr. Cartagena

2 Severe Ozone 2-6206-00038 212-460-3968VOC 0.00 Con Ed.- Waterside Mr. Cartagena Future Facility Shutdown

2 Severe Ozone 2-6206-00038 212-460-4858 35.34 tpy committed To # 2-6206-00012 (East River)

VOC 0.00 Con Ed.- Hudson Ave. Mr. Guastafeste

Severe Ozone 2-6101-00042 212-460-485812.86 Mr. Karalus


VOC 7.83 Con Ed.- Hudson Ave. Mr. Ogunsola

2 Severe Ozone 2-6101-00042 212-460-1223

VOC 0.00 Astoria Generating Station – Orion Mr. Webb

Severe Ozone 2-6301-00185 410-234-0994

85.22 Astoria Generating Station – Orion Mr. Webb

Severe Ozone 2-6301-00185 410-234-0994

VOC 132.00 Newtown Creek WPCP Mr. Lopez

2 Severe Ozone 2-6101-00025 718-595-5049

VOC 0.10 East River Housing Corp. Mr. Jacob

2 Severe Ozone 2-6206-00096 212-677-5858VOC 0.00 GATX SI, Inc. Mr. Dahl


19.85 tpy transferred To National Grid Generation LLC19.85 Mr. Flannery

Severe Ozone 516-545-4875VOC 6.90 Arrow Lock Mfg. Co. Mr. Shah Facility shutdown

2 Severe Ozone 2-6105-00250 718-927-2772 x240 2.3 tpy DEC retainVOC 0.00 Tanagraphics Ms. Jurist

2 Severe Ozone 2-6205-00088 212-255-6876

VOC 0.00 Seybert-Nichol's Printing Mr. Steinberg

Facility shutdown

Facility shutdown

Emission point(s) shutdown

2Elements Markets, LLCSevere Ozone 281-207-7213

National Grid Generation LLC

NRG Power Marketing Inc.

2

2

10.53 tpy committed to Tanaseybert 2-6202-01677



12.86 tpy transferred to NRG Power Marketing Inc.

85.22 tpy of PA ( Leonard Acd.) ERCs were transferred

Emission Point(s) Shutdown

93.69 tpy transferred to Element Markets, Inc.


57 tpy transferred to PSEG Energy resources & trading (CT)

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


2 Severe Ozone 2-6205-00087 212-548-7836

VOC 0.00 Kenner Printing Co. Inc. Mr. Steinberg

2 Severe Ozone 2-6205-00119 212-548-7836VOC 0.00 Digital Now Ms. Kahanec

2 Severe Ozone 2-6205-01660 212-453-9266

VOC 3.20 American Sugar Refining, Inc. Mr. Demone Facility shutdown

2 Severe Ozone 2-6101-00152 732-590-1177 1.01 tpy DEC retainVOC 48.60 Poletti Power Project Mr. Ramos

2 Severe Ozone 2-6301-00084 914-681-6682

VOC 0.00 NYOFCO Sludge Pellet. Facility Mr. Lambalot Facility shutdown

Severe Ozone 2-6007-00140 203-509-2577 11.18 tpy transferred to Element Markets, Inc.0.00 Mr. Lack


VOC 0.01 Astoria Gas Turbine Power Mr. Cartagena

2 Severe Ozone 2-6301-00191 917-612-5224

VOC 0.00National Grid Far Rockaway Power Station

Mr. FlanneryFacility shutdown




VOC 0.00 Interstate Brands Corporation Mr. Davis Facility shutdown

Severe Ozone 2-6307-00276 816-502-4023 22.78 tpy transferred to Koch Supply & Trading, LP0.00 Ms. Barnthouse


VOC 15.50N. Shores Towers Appt. total energy plant

Mr. Castro

2 Severe Ozone 2-6206-00096 718-423-3335

VOC 0.30Tallman Island Wastewater Treatment Plant

Ms. Elardo

2 Severe Ozone 2-6302-00012 718-595-6924

VOC 0.00 Genpak Corp.-Middletown Mr. Postulka

3 Moderate Ozone 3-3309-00064 518-798-9511

VOC 5.60 Harlem Valley Psychiatric Center Mr. Bard

3 Moderate Ozone 3-1326-00023 518-473-5823

Emission Sources Shutdown

69.00 tpy temporarily unavailable for use

Source Reduction

Emission sources shutdown September 19, 2013***

2

2

Emission Source shutdown

2Element Markets, LLC 9.27 tpy transferred to Monroe Energy (Broker) LLC



22.78 tpy transferred to Tenaska, Inc. (PA)


11.18 tpy transferred to Monroe Energy, LLC (PA)




ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 0.00 General Motors Corp. Mr. Pordon 178.58 tpy DEC retained100 tpy committed to Vulcraft of NY, INC170 tpy committed to ConEd East River #2-6206-00012258.76 tpy transferred to PG & E Energy trading145 tpy committed to Astoria Energy, LLC, #2-6301-00647 from PG & E45 tpy committed to GenOn, Bowline LLC from PG &E68.76 transferred to FPL Energy (PA) from PG &E

0.00 145 tpy committed to Astoria Energy, LLC, #2-6301-00647

45 tpy committed to GenOn, Bowline LLC68.76 transferred to FPL Energy (PA)

0.00 Mr. Konary Name Change 12/03/10Severe Ozone 617-529-3874 Name change to GenOn Emissions, LLC

45.00 Mr. LackSevere Ozone 281-207-7213

28.76 Mr. BusaSevere Ozone 561-691-7171

VOC 2.44 IBM-Poughkeepsie Fac. Mr. Brannen

3 Moderate Ozone 3-1346-00035 914-433-1509

VOC 0.78 Wyeth-Ayerst/Lederle Mr. Kontaxis

3 Severe Ozone 3-3924-00025 914-732-2500VOC 0.00 Tesa tape Inc. Mr. Rigano 35.95 DEC retained

Severe Ozone 3-3352-00111 704-553-4664 107.85 Transferred to Element Markets, LLC

8.75 Mr. Lack 4.50 tpy transferred to Philadelphia Ship Repair LLC., PA

40.00 tpy transferred to Monroe Energy LLC., PA54.60 tpy transferred to Philadelphia Ship Repair LLC., PA

VOC 1.27 St. John’s Riverside Hospital Mr. Doerr Emission point shutdown

3 Severe Ozone 3-5518-00222 914-964-4211 00.42 DEC retained

VOC 0.10 A.G. Properties of Kingston, LLC Mr. Ginsberg

3 Ozone Transport Region 3-5154-00153 845-383-0400

VOC 1.55 Wyeth Ayerst Pharmaceutical Mr. Alexandro Emission point shutdown


VOC 0.00 Lovett Generating Station Mr. Konary Facility shutdown

Severe Ozone 3-3928-00010 617-529-3874 Name change to GenOn Emissions, LLC27.20 Mr. Lack


3GenOn Emissions, LLC

Facility shutdown

Emission point shutdown

3

3

Severe Ozone

Severe Ozone


PG & E Energy trading

GenOn Bowline LLC

Element Markets, LLC

GenOn Emissions, LLC

3-5534-00104 313-556-0791

FPL Energy 40 tpy committed to Caithness LI Energy, # 1-4722-04426

Emission points shutdown

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 14.72 Metal Container Corp. Mr. Kimutis 107.9 used for internal offsets

4.53 used for internal offsets67.85 used for internal offsets

VOC 1.161 Schenectady Int. Inc. Mr. Windish4 Marginal Ozone 4-4228-00056 518-370-4200

VOC 0.00 Mr. Arcone4 Marginal Ozone 301-280-6607

VOC 107.00 Glens Falls Lehigh Portland Cement Co Mr. Matz

4 Marginal Ozone 4-1926-00001 610-366-4752

VOC 0.07 Knolls Atomic Power Lab. Mr. Seepo

4 Marginal Ozone 4-4224-00024 518-395-6366VOC 4.60 BASF Corporation Ms. Roque

4 Marginal Ozone 4-3814-00006 973-426-2662

VOC 45.74 General Electric Power System Mr. Oldi

4 Marginal Ozone 4-4215-00015 518-385-3505

VOC 7.45 Von Roll Isola USA, Inc. Ms. Mellon

4 Marginal Ozone 4-4215-00099 518-344-7140

VOC 0.00 Bennington Paperboard Co. Mr. Doerr

4 Marginal Ozone 4-3828-00006 740-862-3594VOC 0.00 Norbord Industries Mr. Towles Facility shutdown

Ozone Transport Region 4-1230-00019 864-697-1250 15.56 tpy transferred to Element Markets, Inc.0.00 Mr. Lack

Ozone Transport Region 281-207-7213

15.56 BEMIS company, Inc. Mr. Kubicek

Ozone Transport Region 927-527-7695VOC 0.00 Holcim (US) Inc. Mr. Graves Facility shutdown

Ozone Transport Region 4-1926-00021 518-943-4040 20 tpy transferred to Element Markets, LLC20.00 Mr. Lack

Ozone Transport Region 281-207-7200VOC 0.00 Karg Brothers Mr. Wood


VOC 0.00 Graphic Packaging Corp. Mr. Hollod 106 tpy committed to Besicorp-Recycling # 4-3814-00061

82 tpy committed to Besicorp-Power # 4-3814-00052308.97 tpy transferred to Evolution Markets

116.00 Mr. Ammirato 90 tpy transferred to Moxie Freedom, PA

Marginal Ozone 914-323-0255 102.97 tpy transferred to Lackawanna Energy Center (PA)

VOC 0.35 Pactiv LLC. Mr. Pettit

Moderate Ozone3

42.20 transferred to Panda Liberty/ Patriot Plant., PA


15.56 tpy transferred To BEMIS company, Inc.

5 Marginal Ozone 5-4115-00004 770-644-3223

4

30.68 tpy committed to Vulcraft of NY, INC

Evolution Markets, LLC

Facility shutdown

Facility shutdown

Facility shutdown


Source reduction


PG&E Energy Trading 41.10 tpy committed to Athens Gen. Fac.

845-567-56373-3348-00084


Element Markets, LLC4

ContaminantRegion


Facility NameDEC ID

ContactTelephone #



VOC 0.34 Mohawk Paper Mills, Inc. Mr. Milner

5 Marginal Ozone 5-4154-00003 518-237-1740

VOC 13.40 Mallinckrodt Anesthesiology Ms. Zeigler


VOC 0.00 General Elect.- Ft. Edward Mr. West


VOC 35.30 Pliant Solutions Corp. Mr. Shuder


VOC 0.00 International Paper-Corinth Mr. Lienert Facility shutdown

Ozone Transport Region 5-4126-00007 901-419-3895 32.10 tpy transferred to Element Markets, LLC

32.10 Mr. Lack

Ozone Transport Region 281-207-7200VOC 0.00 F.E. Hale Mfg. Co. Mr. Benson Facility shutdown

Ozone Transport Region 6-2130-00004 315-894-5490 43 tpy transferred to Element Markets, LLC0 Mr. Lack


43.00 American Packaging Corp Mr. Foerster

Ozone Transport Region 8-2622-00202 920-623-1008VOC 0.337 Anitec Image Corp. Mr. Markle


VOC 3.02 Lockheed Martin Corp. Mr. Maciel


VOC 0.00 Binghamton Cogen. Plant Mr. Potts

7 Ozone Transport Region 7-0302-00079 609-625-7699VOC 6.32 Syracuse Power Co. Mr. Ingalls


VOC 20.56 Syracuse Terminal (Hess) Mr. Haid


VOC 0.00 Intelicoat Technologies Mr. Stratton


VOC 75.00 Marsellus Casket Co. Mr. Vredenburg


5Element Markets, LLC

Element Markets, LLC 43 tpy transferred to American Packaging Corporation6


Facility shutdown


Facility shutdown

19.00 tpy committed to Athens Gen. Fac.

Facility shutdown



114.02 tpy committed To Athens Gen. Fac.

Facility shutdown

45.21 tpy committed to Flexo Trans. Inc., # 9140200574

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 1.00 St. Joseph=s Hospital Mr. Scicchitamo


VOC 31.08 Sunoco, Inc. Syracuse Term. Mr. McGill


VOC 0.80 Owens-Brockway Glass Cont. Inc. Mr. Tussing


VOC 0.00 Westover Generating Station, Mr. Irwin Facility shutdown

Ozone Transport Region 7-0346-00045 315-536-2359 x3423 7.92 tpy transferred to Greenidge Generation LLC

0.00 Greenidge Generation LLC Mr. Irwin

Ozone Transport Region 8-5736-00004 315-536-2359 x34230.00 Mr. Lack

Ozone Transport Region 281-207-72137.92 Mr. Kwok

Ozone Transport Region 917-589-0012VOC 3.50 Erdle Perforating Co. Mr. Rick

8 Ozone Transport Region 8-2626-00047 716-247-4700VOC 0.00 Eastman Kodak Co. Ms. Karatas


VOC 1.60 NYSOMH -Rochester Psychiatric Center Mr. Bard

8 Ozone Transport Region 8-2614-00341 518-473-5823VOC 0.00 ITT Automotive Inc. Mr. Johnson

8 Ozone Transport Region 8-2614-00192 716-277-3534VOC 0.00 Eastman Kodak Co. Mr. Spiegel



VOC 1.58 E I DuPont Co.-Driving Pk. Mr. Olson


VOC 0.00 Imation Enterprises Corp. Mr. Metzger



VOC 4.40 RG&E, Beebee Station Ms. Selbig


VOC 3.48 Monroe-Livingston Landfill Mr. Moriera


7


1.90 retired, CAA-02-2011-1209

Emission Unit shutdown

Emission point(s) Shutdown


Element Markets, LLC 7.92 tpy transferred to Hill Top Energy Center, LLC


Facility shutdown

7.92 tpy transferred to Element Markets, LLC

Facility shutdown



39.60 retired, CAA-02-2011-1209

Hill Top Energy Center, LLC

9.40 retired, CAA-02-2011-1209


60.20 retired, CAA-02-2011-1209

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


VOC 16.10 RG&E, Russell Station Ms. Sahler


VOC 3.50 Monroe-Livingston Landfill Mr. Chraston


VOC 15.21 Greenidge Generation LLC Mr. Irwin

8 Ozone Transport Region 8-5736-00004 315-536-2359VOC 16.00 Weber Knapp Co. Mr. Monsen

9 Ozone Transport Region 9-0608-00087 716-484-9135VOC 0.00 Dowcraft Corp. Gene Sadowski


VOC 0.40 Delphi Harrison Th. Sys. Ms. Harper Emission point(s) shutdown

Marginal Ozone 9-2909-00018 716-439-2955 29.53 tpy transferred to Element Markets, LLC0.03 Mr. Lack

Marginal Ozone 281-207-7200


Marginal Ozone 8-2622-00202 920-623-1008

VOC 0.00 Delphi Harrison Th. Sys. Ms. Harper Source Reduction

Marginal Ozone 9-2909-00018 716-439-2955 47.6 tpy transferred to Elements Markets, LLC0.00 Mr. Lack 38.88 tpy transferred to BEMIS company, Inc.

Marginal Ozone 281-207-7213 8.72 tpy transferred to Hill Top Energy Center, LLC38.88 Mr. Kubicek

Marginal Ozone 927-527-76958.72 Mr. Kwok

Marginal Ozone 917-589-0012VOC 0.00 Bush Industries Inc. Mr. Newman Source Reduction

Ozone Transport Region 9-0454-00001 716-665-2000 175.7 transferred to Element Markets, LLC0.00 Mr. Lack 174 tpy transferred to Perdue AgriBusiness (PA)

Ozone Transport Region 281-207-7213 1.7 tpy transferred to Perdue AgriBusiness (PA)

VOC 74.12 CWM Chemical serv. Inc. Mr. Hino


VOC 0.00 TitanX Engine Cooling, Inc. Mr. Anderson Emission Point(s) shutdown

Ozone Transport Region 9-0699-00056 716-665-2620 41.4 tpy transferred to Element Markets, LLC41.40 Mr. Lack


VOC 0.00 Occidental Chemical Corp. Ms. Desmukh Facility shutdown

Marginal Ozone 9-2912-00041 972-404-3217 88.3 tpy transferred to American Packaging Corp. #8-2622-00202

9

Facility shutdown




BEMIS company, Inc.

9Element Markets, LLC 29.5 tpy transferred to American Packaging Corporation

9Element Markets, LLC

Element Markets, LLC9

9


Emission Point(s) shutdown

Hill Top Energy Center, LLC

Emission sources shutdown March 18, 2011***

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


7.80 American Packaging

Corp Mr. Foerster

Marginal Ozone 8-2622-00202 920-623-1008

VOC 7.50 The Colad Group, Inc. Mr. Pelz

9 Marginal Ozone 9-1402-00009 716-849-1776

VOC 19.07 Dunlop Tire Corporation Mr. Pyanowski Emission point(s) shutdown

9 Marginal Ozone 9-1464-00030 716-879-8274 137.93 tpy used as offsets

VOC 0.00 Bethlehem Steel Corp. Mr. Ossman Facility shutdown

200 tpy transferred to St. Lawrence Cement (Holcim) and committed to Greenport Project DEC ID #4-1040-00011

105 tpy transferred to Tecumseh Redevelop. Inc.0.00 Holcim (US) Inc. Ms. Garakani

Marginal Ozone 4-1040-00011 734-529-4233137.61 Mr. Lack 62.39 tpy transferred to Crown Cork & Seal

Marginal Ozone 281-207-7200105.00 Mr. Nagel

Marginal Ozone 716-856-06350.00 Crown Cork & Seal Mr. Antry

Marginal Ozone 7-4928-00064 215-698-5308

VOC 1.10 Limestone Compressor Fac. Mr. Young


VOC 1.80 UCAR Carbon company Ms. Bolton

9 Marginal Ozone 9-2911-00185 931-380-4215VOC 34.75 Dinaire, LLC Mr. Schmitt

9 Marginal Ozone 9-1402-00218 716-894-1201

VOC 13.83 United Refining Company Mr. Roy

9 Marginal Ozone 9-1464-00007 814-726-4859

VOC 0.00 Prestolite Electric Inc. Mr. Koch


VOC 22.70 Medina Power Company Mr. Pecnik


VOC 4.22 Saint-Gobain Abrasives Mr. Fogarty

9 Marginal Ozone 9-2940-00048 508-795-5860VOC 0.00 SGL Carbon LLC Mr. Higgs Facility shutdown

Marginal Ozone 9-2911-00038 704-593-5165 127.52 tpy transferred to Element Markets, LLC0.02 Mr. Lack

9Element Markets, LLC 127.5 tpy transferred to American Packaging Corporation

Facility shutdown

Facility shutdown



9

62.39 tpy used as offsets

4.5 tpy committed to Prestolite (P00001)

Facility shutdown

Tecumseh Redevelop Inc.


Facility shutdown


Marginal Ozone 9-1409-00003 610-694-2060

200 tpy transferred to Element Markets, LLC

80.5 tpy used as offsets

ContaminantRegion


Facility NameDEC ID

ContactTelephone #




Marginal Ozone 8-2622-00202 920-623-1008

VOC 29.53 The Goodyear Tire and Rubber Co. Mr. Jones

9 Marginal Ozone 9-2911-00036 716-236-2635

VOC 1.77 Caraustar Mill/Buffalo Paperboard Mr. Cohen

9 Marginal Ozone 9-2909-00062 770-799-3844

VOC 13.45 Arcelormittal Lackawanna LLC Mr. Nagel

9 Marginal Ozone 9-1499-00067 330-659-9102

VOC 0.00 QG Printing Corporation Mr. Estock Facility shutdown

400 tpy transferred to Mid-Atlantic Develop(PA)55 tpy transferred to American Craft Brewing, PA106.10 transferred to LI Land Dev., LLC, PA

VOC 0.00 SGK Ventures Frewsburg Fac. Mr. Stalkamp Facility shutdown

Ozone Transport Region 9-1499-00067 312-683-9454 21.56 tpy transferred Element Markets0.00 Mr. Lack

Ozone Transport Region 281-207-721321.56 Mr. Kubicek

Ozone Transport Region 927-527-7695VOC 0.00 Mr. Marchmont

Severe Ozone 508-786-72140.00 Mr. Mussleman Ramapo changed name to ANP

Severe Ozone 508-382-9356 31.50 tpy transferred to Element Markets0.50 Mr. Lack

Severe Ozone 281-207-721331.00 Mr. Kubicek

Severe Ozone 927-527-7695VOC 0.00 Mr. Slade

PA Severe Ozone 914-681-6387VOC 0.00 Mr. Svendsen

PA Severe Ozone 410-230-3500VOC 0.00 Mr. Hribar

Severe Ozone 440-358-48320.00 Mr. Konary Name Change 12/3/10

Severe Ozone 617-529-3874 Name change to GenOn Emissions, LLC73.02 Mr. Lack

Severe Ozone 281-207-7213VOC 0.00 Mr. Marchmont

Severe Ozone 508-786-72140.00 Mr. Mussleman 5 tpy transferred to Calpine # 1-4722-02441

PA


Marginal Ozone 9-1430-002139 414-566-7617

GenOn Bowline LLC

21.56 tpy transferred To BEMIS company, Inc.

PA

American National

3M Company, Bristol, PA

31 tpy transferred to Ramapo Energy(ANP)

Avery Dennison Corp., PA

73.02 tpy committed to GenOn Bowline


41 tpy committed to NYPA Poletti site

Leonardo Academy Inc., PA

85.22 tpy committed to Astoria Generating, #2-6301-00185


American National Power

9

BEMIS company, Inc.

March 31, 2015***

PA

BEMIS company, Inc.

Progress Lighting Inc., Philadelphia, PA

31.5 tpy transferred to Ramapo Energy

Element Markets, LLC 31.00 tpy transferred To BEMIS company, Inc.


Facility shutdown

Facility shutdown

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


Severe Ozone 508-382-9356 26 tpy transferred to Element Markets, LLC0.00 Mr. Lack

Severe Ozone 281-207-721326.00 Mr. Kubicek

Severe Ozone 927-527-7695VOC 0.00 Mr. Kane

PA Moderate Ozone 607-974-6568VOC 0.00 Mr. Proia

PA Moderate Ozone 607-529-9000VOC 0.00

Moderate Ozone0.00 Mr. Alexander

Moderate Ozone (518) 452-70000.00 Holcim (US) Inc. Ms. Garakani

Moderate Ozone 4-1040-00011 734-529-42330.00 Mr. Lack 31.61 tpy transferred to Crown Cork & Seal

Moderate Ozone 281-207-72000.00 Crown Cork & Seal Mr. Antry 31.61 tpy used as offsets

Moderate Ozone 7-4928-00064 215-698-5308VOC 0.00 Ms. Frazier

PA Severe Ozone 617-456-2200VOC 0.00 Mr. Remillard

PA Severe Ozone 781-817-8970

NOx 20.50National Grid (Formerly KeySpan Gen. LLC.)

Mr. Teetz

1 Severe Ozone 1-4722-00107 516-391-6133

NOx 253.80National Grid (Formerly KeySpan Gen. LLC.)

Mr. TeetzName change (2007)

Severe Ozone 1-2822-00481 516-391-6133 225 tpy transferred to Morgan Stanley0.00 Mr. Woods 78.36 tpy transferred to Bronx Zoo, # 2-6005- 00125

Severe Ozone 212-761-8895 146.64 transferred to Caithness LI II, LLC #1-4722-04426146.64 Mr. Grace


NOx 0.00Zapco Energy Tactics Corp. - Oceanside LGRF

Mr. AntignanoEmission point(s) shutdown

7.35 tpy DEC retained15.86 tpy transferred to Morgan Stanley6.24 tpy transferred to KeySpan

0.00 Mr. WoodsSevere Ozone 212-761-8895

1

Newcomer Products Inc., PA

Air Resources Group (ARG)

31.61 transferred to Holcim (US) Inc. 4-1040-00011

31.61 tpy transferred to Element Markets, LLC

Morgan Stanley 15.86 tpy transferred to Bronx Zoo, # 2-6005- 00125

1 Severe Ozone 1-2820-02479 516-563-6336

Name change (2007)

Morgan Stanley


136 tpy transferred to CVEC#3-1326-00275

Arbill Industries Inc., PA

17 tpy committed to CPV Energy Center #3-3356-00136

Caithness Long Island II, LLC

19.00 tpy committed to Vulcraft of NY, #8-0728-00033

Cogentrix of PA., PA 31.61 transferred to Air Resources Group (ARG)

Element Markets, LLC 26.00 tpy transferred To BEMIS company, Inc.

LTV Steel Company, PA

140 tpy committed to Corning Inc.

BEMIS company, Inc.

Power

PA


ContaminantRegion


Facility NameDEC ID

ContactTelephone #


6.24

National Grid (Formerly KeySpan Gen. LLC.)

Mr. Teetz

Severe Ozone 1-2820-02479 516-391-6133

NOx 0.00Zapco Energy Tactics Corp. - Old Bethpage LGRF

Mr. Smith (Spagnoli Road Energy)

Severe Ozone 1-2824-00077 516-512-7415

0.00National Grid (Formerly KeySpan Gen. LLC.)

Mr. Teetz

Severe Ozone 1-2824-00077 516-391-6133

64.80National Grid (Spagnoli Rd. Energy Centre)

Mr. Teetz

Severe Ozone 1-2824-00077 516-391-6133

NOx 0.00Zapco Energy Tactics Corp. -Old Bethpage LGRF

Facility shutdown

8.35 tpy DEC retained25.06 tpy transferred to Morgan Stanley

0.00 Mr. Woods 10.00 tpy transferred to Bristol-Myers (CT)Severe Ozone 212-761-8895 15.06 tpy transferred to Bronx Zoo, # 2-6005-00125

NOx 10.30 Central Islip Psychiatric Center Mr. Bard

1 Severe Ozone 1-4728-00244 518-473-5823

NOx 0.00 Zapco Energy Tactics Corp. Mr. Antignano 4.01 tpy retained by DEC

10.2 tpy committed to Spagnoli Rd. Energy center # 1-4726-015001.82 tpy transferred to KeySpan

1.82National Grid (Formerly KeySpan Gen. LLC.)

Mr. Teetz

Severe Ozone 1-2820-00951 516-391-6133

10.20National Grid (Spagnoli Rd. Energy Centre)

Mr. Teetz

Severe Ozone 1-2820-00951 516-391-6133

NOx 0.00 Environmental Waste Incineration, Inc. Mr. Walker Facility shutdown

1 Severe Ozone 1-2809-00088 215-766-7230 38.25 tpy retained by DEC

NOx 0.00 TRW INC, Steering Wheel Systems Mr. Ferrentino Facility shutdown

1.9 tpy DEC retained5.7 tpy committed to GenOn Bowline LLC

1

64.8 tpy committed to Spagnoli Rd. Energy center # 1-4726-01500 through KeySpan

Name change (2007)1

Morgan Stanley

Name change (2007)

Severe Ozone 1-4722-00898 518-465-1010

1 Severe Ozone 1-2824-00077

Source Reduction

Name change (2007)

1 Severe Ozone 1-2820-00951 516-563-6336

ContaminantRegion


Facility NameDEC ID

ContactTelephone #




NOx 59.10NYSOMH - Kings Park Psychiatric Center Mr. Bard

1 Severe Ozone 1-4734-00103 518-473-5823

NOx 0.00 Smithtown West Energy Generating Mr. Woods Emission point(s) shutdown

4.28 tpy DEC retained12.82 tpy transferred to Morgan Stanley

0.00Severe Ozone

NOx 0.00

Brookhaven Landfill Gas Recovery (Wehran Energy Corp.)

Mr. Wehran, Jr.

23 tpy transferred to Kleen Energy System(CT)

Severe Ozone 1-4722-00799 201-327-0215 56.15 tpy transferred to Shell energy (US)0.00 Mr. Martin

Severe Ozone 713-767-5419NOx 0.00 Covanta Babylon Inc. Mr. Volpe Source Reduction

Severe Ozone 1-4720-00777 631-491-1976 141 tpy transferred to Shell energy (US)0.00 Mr. Martin 37.95 tpy transferred to Plainfield Renew. Energy, CT

Severe Ozone 713-767-5419 103.05 tpy transferred to CPV Shore, LLC0.00 Mr. Freeman


NOx 54.40 Freeport Power Plant#2 Mr. Bianco Emission Points Shutdown


NOx 14.60 Suffolk County Dev. Ctr. Mr. Bard

1 Severe Ozone 1-4726-00428 518-473-5823NOx 0.00 PE Bay Shore LLC Mr. Murphy Facility Shutdown

Severe Ozone 1-4728-00141 315-448-2266 29.55 & 13.66 tpy transferred to CPV Shore, LLC2.94 Mr. Freeman


NOx 8.54 Montauk Generating Fac. Mr. Flannery

1 Severe Ozone 1-4724-00036 516-545-4875

NOx 0.00 Glenwood Combustion Turbine Mr. Flannery Emission Points shutdown

Severe Ozone Fac., 1-2822-00481 516-545-4875 112.64 tpy transferred To Element Markets LLC0.00 Mr. Lack

Severe Ozone 281-207-7213112.64 Mr. Mirabito


1

Shell Energy North America (US) L.P.CPV Shore, LLC

1

103.05 tpy transferred to Wood bridge Energy Center, NJ

Morgan Stanley 12.82 tpy transferred to Bronx Zoo, # 2-6005-00125

CPV Shore, LLC 29.55 & 10.72 tpy transferred to Wood bridge Energy Center, NJFacility shutdown


19.7 tpy DEC retained

1 Severe Ozone 1-4734-00169 212-761-8895

Shell Energy North America (US) L.P.

56.15 tpy transferred to Plainfield Renew. Energy, CT1

GenOn, Bowline LLC

1July 1, 2012***112.64 tpy transferred To NTE Connecticut, LLC

NTE Connecticut, LLC

ContaminantRegion


Facility NameDEC ID

ContactTelephone #



NOx 12.10 National Grid – EF Barrett Power Station Mr. Flannery

1 Severe Ozone 1-2820-00553 516-545-4875NOx 682.12 Con Ed.- Astoria Mr. Cartagena 133 tpy committed to GenOn Bowline LLC

148.9 tpy committed to Brookhaven Energy425 tpy committed to Astoria Energy, LLC, #2-6301-00647

116.1 tpy transferred to Ramapo Energy.0.00

Severe Ozone0.00 42 tpy committed to Calpine, # 1-4722-02441

25 tpy committed to Bethpage Energy Center # 1-2824-0094749.10 tpy transferred to Bronx Zoo, # 2-6005-00125



0.00Severe Ozone

0.00 Mr. Woods 118 tpy committed to Caithness LI Energy # 1-4722-04426Severe Ozone 212-834-3568 30.90 tpy transferred to Koch Supply and Trading, LP

42.00Severe Ozone

30.90 Mr. LockeSevere Ozone 713-544-7998

NOx 316.30 Con Ed.- 59th St. Mr. Cartagena2 Severe Ozone 2-6202-00032 212-460-6275

NOx 38.24 Greenpoint Municipal Incinerator Mr. Bekowies

2 Severe Ozone 2-6101-00022 212-837-8383

NOx 189.00 SW Brooklyn Municipal Incinerator Mr. Bekowies

2 Severe Ozone 2-6106-00002 212-837-8383NOx 126.22 Con Ed.- Waterside Mr. Cartagena

2 Severe Ozone 2-6206-00038 212-460-3968NOx 481.30 Con Ed.- Waterside Mr. Cartagena Facility shutdown

2 Severe Ozone 2-6206-00038 212-460-4858 193.02 committed to # 2-6206-00012 (East River)

NOx 0.00 Con Ed.- Hudson Ave. Mr. Guastafeste

Severe Ozone 2-6101-00042 212-460-485825.82 Mr. Karalus


NOx 355.84 Con Ed.- Hudson Ave. Mr. Ogunsola


2


2

Calpine Stony Brook Energy Center


Severe Ozone

Severe Ozone 2-6301-00006 212-460-6275

Brookhaven Energy


148.9 tpy transferred to J.P. Morgan Energy



J.P. Morgan Vent. Energy Corp.

Ramapo Energy 116.1 tpy transferred to Morgan Stanley

October 13, 2011***

Morgan Stanley

GenOn, Bowline LLC


Facility shutdown


25.82 tpy transfer to NRG Power Marketing Inc.

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


2 Severe Ozone 2-6101-00042 212-460-1223NOx 11.03 St. John=s University Mr. Zweifler Source Reduction

2 Severe Ozone 2-6306-00067 718-990-2520 17.44 used for netting

NOx 294.40 Newtown Creek WPCP Mr. Lopez 115.5 DEC retained

2 Severe Ozone 2-6101-00025 718-595-5049 50.7 tpy committed to Fountain Ave. Landfill #2-6105-00687

NOx 80.00 Visy Paper Mr. Davey2 Severe Ozone 2-6403-00107 718-370-1114

NOx 21.4 East River Housing Corp. Mr. Jacob

2 Severe Ozone 2-6206-00096 212-677-5858

NOx 220.00 Betts Ave. Municipal Incinerator Mr. Nabavi

2 Severe Ozone 2-6304-00093 917-237-5958NOx 2.80 Arrow Lock Mfg. Co. Mr. Shah Facility shutdown

2 Severe Ozone 2-6105-00250 718-927-2772 x240 1.0 tpy DEC retain

NOx 0.00 Kings Plaza Total Energy Mr. Williams

2 Severe Ozone 2-6105-00301 609-654-6166

NOx 0.00 Warbasse Houses & Power Plant Mr. Sellitti

Severe Ozone 2-6107-00141 718-372-87640.00 Mr. Lack 1.0 tpy transferred to Kleen Energy, CT

21.38 tpy transferred to Merck, Sharpe & Dohme Corp., PA

4.82 tpy transferred to CPV Shore, LLC4.82 Mr. Freeman


NOx 15.64 Long Island Jewish Med. Center Mr. LaBonne 26.8 used for netting


NOx 59.30 American Sugar Refining, Inc., Mr. Demone Facility shutdown

2 Severe Ozone 2-6101-00152 732-590-1177 19.7 tpy DEC retainNOx 0.00 Simsmetal East LLC. Mr. Witte

2 Severe Ozone 2-6304-00268 908-964-8812NOx 1239.72 Poletti Power Project Mr. Ramos Emission Source shutdown

125 tpy transferred to PSEG Energy resources & trading (CT)

41.78 tpy transferred to Lotus Danbury LMS100, LLC (CT)147.5 tpy transferred to North Bergen Liberty Generating Station (NJ)

NOx 0.00 NYOFCO Sludge Pellet. Facility Mr. Witte

2

Severe Ozone 2-6301-00084 914-681-6682

186 tpy transferred to Kleen Energy System (CT)

27.2 tpy transferred To Elements Markets

2

Severe Ozone 281-207-7213Elements Markets, LLC

CPV Shore, LLC

34.12 tpy committed to Northeast Dredging Equipment Co.

Facility shutdown


33.44 tpy committed to Northeast Dredging Equipment Co.

1 tpy transferred to CVEC#3-1326-00275

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


2 Severe Ozone 2-6007-00140 908-964-8812

NOx 11.18 Astoria Gas Turbine Power Mr. Cartagena

2 Severe Ozone 2-6301-00191 917-612-5224

NOx 49.84National Grid Far Rockaway Power Station

Mr. FlanneryFacility shutdown

Severe Ozone 2-6308-00040 516-545-4875 87.36 tpy transferred To Element Markets50.36 tpy transferred To NTE Connecticut, LLC7 tpy transferred to Monroe Energy (Broker), LLC1 tpy transferred to Monroe Energy, LLC (PA)

Severe Ozone 281-207-7213 29 tpy transferred to Cogen Technologies Linden Venture, LP (NJ)

50.36 Mr. MirabitoSevere Ozone 904-436-6898

0.00 Mr. TorellSevere Ozone 610-364-8399


NOx 0.00 Terranext Eastchester Hts. Mr. Woodruff Source Reduction

Severe Ozone 2-6002-00465 347-221-0070 12.10 tpy transferred to CPV Shore, LLC0.00 Mr. Freeman


NOx 0.00 Interstate Brands Corporation Mr. Davis Facility shutdown

Severe Ozone 2-6307-00276 816-502-4023 2.16 tpy transferred to Koch Supply & Trading, LP2.16 Ms. Barnthouse


NOx 18.63N. Shores Towers Appt. total energy plant

Mr. CastroEmission Sources Shutdown

2 Severe Ozone 2-6206-00096 718-423-3335 40.87 used for netting

NOx 0.00 St. Barnabas Hospital Mr. DiGirolomo Emission Sources Shutdown

2 Severe Ozone 2-6005-00232 718-690-6556 18.08 tpy transferred to North Bergen Liberty Generating Station (NJ)

NOx 42.40Tallman Island Wastewater Treatment Plant

Ms. Elardo

2 Severe Ozone 2-6302-00012 718-595-6924

NOx 42.00 Harlem Valley Psychiatric Center Mr. Bard

3 Moderate Ozone 3-1326-00023 518-473-5823

NOx 2.93 Wyeth-Ayerst/Lederle Mr. Kontaxis

0.00 Mr. Lack

Source Reduction /Facility shutdown


CPV Shore, LLC 12.10 tpy transferred to Wood bridge Energy Center, NJ2

2Koch Supply & Trading, LP




NTE Connecticut, LLC


7 tpy transferred to Element Markets, LLC

2

Emission sources shutdown September 18, 2013***

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


3 Severe Ozone 3-3924-00025 914-732-2500

NOx 0.052 IBM-Poughkeepsie Fac. Mr. Brannen

3 Moderate Ozone 3-1346-00035 914-433-1509

NOx 13.10 Hudson River Psychiatric Center Mr. Bard

3 Moderate Ozone 3-1346-00030 518-473-5823

NOx 0.00 BICC Cable Corporation Mr. Sniffen 1.95 DEC retained

Severe Ozone 3-5518-00067 281-207-7213 5.90 transferred to Elements Markets0.00 Mr. Lack

Severe Ozone 281-207-72135.90 Mr. Freeman

Severe Ozone 240-723-2312NOx 0.00 Tesa Tape Inc. Mr. Rigano 1.48 DEC retained

Severe Ozone 3-3352-00111 704-553-4664 4.42 Transferred to Element Markets, LLC0.00 Mr. Lack


NOx 0.00 Algonquin Gas Stony Pt. Mr. Wooden Future Emission units shutdown

3 Severe Ozone 3-3928-00001 617-560-1345 14.08 tpy committed for netting

NOx 6.52 St. John’s Riverside Hospital, Mr. Doerr Emission point shutdown


NOx 17.00 A.G. Properties of Kingston, LLC, Mr. Ginsberg


NOx 1.04 Wyeth Ayerst Pharmaceutical, Mr. Alexandro Emission point shutdown


NOx 0.00 Lovett Generating Station, Mr. Konary Facility shutdown

643 tpy transferred to Element Markets, LLCName change to GenOn Emissions, LLC

643.00 Element Markets, LLC Mr. Lack

Severe Ozone 281-207-72133566.20 Mr. Lack

Severe Ozone 281-207-7213NOx 0.59 Cibro Pet. Prod. Inc. Mr. Harvey

4 Marginal Ozone 4-0101-00070 518-761-0750NOx 2.10 Schenectady Int. Inc. Mr. Windish

4 Marginal Ozone 4-4228-00056 518-370-4200

NOx 2003.00 Glens Falls Lehigh Portland Cement Co Mr. Matz

4 Marginal Ozone 4-1926-00001 610-366-4752

Severe Ozone 3-3928-00010 617-529-38743


Facility shutdown



3

Element Markets, LLC 4.42 tpy transferred to Merck, Sharpe & Dohme Corp., PA

CPV Shore, LLC

3

Source Reduction

Element Markets, LLC 5.90 tpy transferred to CPV Shore, LLC


ContaminantRegion


Facility NameDEC ID

ContactTelephone #


NOx 0.00 Fiber glass Industries

Inc. Mr. Lierheimer Source Reduction

Marginal Ozone 4-2701-00013 518-842-4000 62.20 tpy transferred to Air Resources Group. (ARG)0.00 Mr. Alexander

Marginal Ozone (518) 452-70000.00 Holcim (US) Inc. Ms. Garakani

Marginal Ozone 4-1040-00011 734-529-423362.20 Mr. Lack


NOx 392.67 PSEG Power New York Inc. Mr. Verqura

4 Marginal Ozone 4-0122-00044 518-436-5027

NOx 10.57 Knolls Atomic Power Lab. Mr. Seepo

4 Marginal Ozone 4-4224-00024 518-395-6366NOx 52.60 BASF Corporation Ms. Roque

4 Marginal Ozone 4-3814-00006 973-426-2662NOx 7.57 G. E. Power System Mr. Oldi

4 Marginal Ozone 4-4215-00015 518-385-3505

NOx 0.00 Bennington Paperboard Co. Mr. Doerr

4 Marginal Ozone 4-3828-00006 740-862-3594NOx 0.00 Norbord Industries Mr. Towles

4 Ozone Transport Region 4-1230-00019 864-697-1250NOx 0.00 Holcim (US) Inc. Mr. Graves Facility shutdown

Ozone Transport Region 4-1926-00021 518-943-4040 1789.00 tpy transferred to Element Markets Emissions, LLC

1789.00 Mr. LackOzone Transport Region 281-207-7200

NOx 20.63 Peckham Materials Corp. Mr. Yaremko

5 Ozone Transport Region 5-5344-00009 914-949-2000NOx 0.00 Georgia Pacific Corp. Mr. Frenia


NOx 59.20 General Electric Silicone Ms. Arisman

5 Marginal Ozone 5-4154-00002 518-233-3540NOx 56.36 Pactiv Corporation Mr. Pettit


NOx 61.50 Mohawk Paper Mills, Inc. Mr. Milner

5 Marginal Ozone 5-4154-00003 518-237-1740

NOx 0.00 International Paper-Corinth Mr. Lienert Facility shutdown

Ozone Transport Region 5-4126-00007 901-419-3895 161.20 tpy transferred to Element Markets LLC74.20 Mr. Lack

4

Element Markets Emissions, LLC

5


Element Markets, LLC 87 tpy transferred to Invenergy Thermal Development LLC

178.24 tpy transferred to CVEC#3-1326-00275

Facility shutdown

142.87 tpy transferred to CVEC#3-1326-00275




Facility shutdown

65.40 tpy transferred to Burgess Biopower (NH)

Source reduction

62.20 tpy transferred to Element Markets Emissions, LLC

Air Resources Group. (ARG)

62.20 tpy transferred to St. Lawrence Cement (Holcim) and committed to Greenport Project DEC ID #4-1040-00011

Facility shutdown, 446.20 tpy committed for netting.

4


ContaminantRegion


Facility NameDEC ID

ContactTelephone #


Ozone Transport Region 281-207-720087.00 Mr. King


NOx 59.70NYSOMH - Mohawk Valley Psychiatric Center

Mr. Bard


NOx 226.10 Magan-Racine Facility Mr. Megan


NOx 22.20NYSOMH - St. Lawrence Psychiatric Center

Mr. Bard


NOx 35.80GLDC/Former Griffiss Air Force Base Steam Plant

Ms. Lemaire

6 Marginal Ozone 6-3013-00229 315-330-4092NOx 134.00 Anitec Image Corp. Mr. Markle

7 Ozone Transport Region 7-0302-00064 607-774-3375NOx 297.00 NiMo Power Corp. Mr. Russo

7 Ozone Transport Region 7-3512-00030 315-428-6798NOx 0.00 Fibertek Energy Fac. Mr. Schintzius

7 Ozone Transport Region 7-3132-00052 315-487-4346NOx 233.00 Heritage Power LLC Mr. Dreisbach

7 Ozone Transport Region 7-3556-00097 518-385-9122NOx 55.53 Syracuse Power Co. Mr. Ingalls


NOx 496.00 Owens-Brockway Glass Container Inc. Mr. Tussing


NOx 85.30 Cornell Uni. Cent. Energy Plant Ms. Brown


NOx 0.00 Westover Generating Station Mr. Irwin Facility shutdown

Ozone Transport Region 7-0346-00045 315-536-2359 x3423 1046.40 tpy transferred to Greenidge Generation LLC

346.10 Greenidge Generation LLC Mr. Irwin 69 tpy transferred to High Acres Landfill

47.30 tpy transferred to Riga/Mill Seat Landfill91 tpy transferred to Invenergy Thermal Development( PA)

177 tpy used as offsets by Greenidge316 tpy transferred to NRG Canal 3 Development LLC (MA)

47.30 Riga/Mill Seat Landfill Mr. Garland

Invenergy Thermal Development LLC

Facility shutdown


7

315-536-2359 x34238-5736-00004Ozone Transport Region

560 tpy committed to Athens Gen. Fac.

From Bethlehem Steel Corp., PA

Facility shutdown



233 tpy used by Corning Inc.

Facility shutdown

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


Ozone Transport Region 8-2648-00014 585-753-751169.00 High Acres Landfill Ms. Zayatz

Ozone Transport Region 8-9908-00162 716-286-03554NOx 0.00 SUNY - Brockport Ms. Boyle


NOx 64.00 NYSEG-Hickling Generating Station Mr. Malecki


NOx 14.70 E I DuPont Co.-Driving Pk. Mr. Olson


NOx 159.20 University of Rochester Mr. Stillman


NOx 41.50 NYSOMH-Rochester Psychiatric Center Mr. Bard


NOx 783.00 RG&E, Beebee Station Ms. Selbig 18 tpy committed to Besicorp-Recycling # 4-3814-00061

8 Ozone Transport Region 8-2614-00448 716-771-2145 242 tpy committed to Besicorp-Power # 4-3814-00052

NOx 187.03 Corning Inc.- Fall brook plant Mr. Ritter


NOx 0.00 Monroe-Livingston Landfill Mr. Moriera 10.60 tpy transferred to High Acres Landfill

Ozone Transport Region 8-2656-00008 603-929-3443 00.40 tpy transferred to Riga/Mill Seat Landfill


Ozone Transport Region 8-2648-00014 585-753-751110.60 High Acres Landfill Ms. Zayatz

Ozone Transport Region 8-9908-00162 716-286-03554

NOx 2026.30 RG&E, Russell Station Ms. Sahler


NOx 0.00 Monroe-Livingston Landfill Mr. Chraston Emission point(s)

Ozone Transport Region 8-2656-00008 585-889-9460 Shutdown, 15 tpy transferred to Riga/Mill Seat Landfill


Ozone Transport Region 8-2648-00014 585-753-7511NOx 438.02 Greenidge Generation

LLC Mr. Irwin


NOx 5.00 Delphi Harrison Th. Sys. Ms. Harper

9 Marginal Ozone 9-1402-00286 716-439-2955


8

8

Facility shutdown

Emission sources shutdown March 18, 2011***

source reduction

Facility Shutdown

24.00 tpy committed to Guardian Glass


ContaminantRegion


Facility NameDEC ID

ContactTelephone #


NOx 0.00 GM Powertrain-

Tonawanda Mr. Pordon

9 Marginal Ozone 9-1464-00048 313-556-0791

NOx 24.60 Delphi Harrison Th. Sys. Ms. Harper

9 Marginal Ozone 9-2909-00018 716-439-2955

NOx 71.54 Occidental Chemical Corp. Ms. Desmukh

9 Marginal Ozone 9-2912-00041 972-404-3217NOx 37.00 LFG Energy Inc. Mr. Zeliff

9 Marginal Ozone 9-1432-00281 716-759-0366

NOx 0.00 Bethlehem Steel Corp. Mr. Ossman Facility shutdown

1300 tpy transferred to St. Lawrence Cement (Holcim) and committed to Greenport Project DEC ID #4-1040-00011

459 tpy transferred to Tecumseh Redevelop. Inc.0.00 Holcim (US) Inc. Ms. Garakani 216.60 tpy transferred to Burgess Biopower (NH)

250 tpy transferred to Element Markets Emissions, LLC833.40 tpy transferred to Element Markets Emissions, LLC

459.00 Mr. NagelMarginal Ozone 716-856-0635

0.00 Mr. LackMarginal Ozone 281-207-7200

250.00 Mr. KingMarginal Ozone 312-582-1419

833.40 Mr. LackMarginal Ozone 281-207-7200

NOx 30.40 Limestone Compressor Fac. Mr. Young


NOx 17.30 UCAR Carbon company Ms. Bolton

9 Marginal Ozone 9-2911-00185 931-380-4215

NOx 67.00 American Ref-fuel company of Niagara Mr. Gleason

9 Marginal Ozone 9-2911-00113 716-278-8509NOx 132.24 E.I. DuPont Mr. Jain

9 Marginal Ozone 9-2911-00030 716-278-5502

NOx 165.10 Medina Power Company Mr. Pecnik


NOx 19.73 Saint-Gobain Abrasives Mr. Fogarty

9 Marginal Ozone 9-2940-00048 508-795-5860

9


Marginal Ozone4-1040-00011

734-529-4233

Source Reduction

99.00 tpy committed to Corning Inc. # 6- 4030-00002

Source Reduction

Facility shutdown

Facility shutdown

Marginal Ozone 9-1409-00003 610-694-2060

Facility shutdown



Tecumseh Redevelop. Inc.



250 tpy transferred to Invenergy Thermal Development LLC

Invenergy Thermal Development LLC

Facility shutdown

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


NOx 12.21 SGL Carbon LLC Mr. Higgs9 Marginal Ozone 9-2911-00038 704-593-5165

NOx 18.32 The Goodyear Tire and Rubber Co. Mr. Jones

9 Marginal Ozone 9-2911-00036 716-236-2635

NOx 0.00 Samuel A. Carlson Generating Station Mr. Oelbracht Future Emission Point shutdown/ Curtailment

9 Ozone Transport Region 9-0608-00053 516-377-2200 125 tpy will be available upon EU shutdown

NOx 40.54 Caraustar Mill/Buffalo Paperboard Mr. Cohen

9 Marginal Ozone 9-2909-00062 770-799-3844

NOx 33.50 Arcelormittal Lackawanna LLC Mr. Nagel

9 Marginal Ozone 9-1499-00067 330-659-9102

NOx 0.00 SGK Ventures Frewsburg Fac. Mr. Stalkamp Facility shutdown

Ozone Transport Region 9-1499-00067 312-683-9454 2.37 tpy transferred to Element Markets2.37 Mr. Lack

Ozone Transport Region 281-207-7213NOx 0.00

Severe Ozone0.00 Mr. Konary Name Change 12/3/10

Severe Ozone 617-529-3874 Name change to GenOn Emissions, LLC207.00 Mr. Lack

Severe Ozone 281-207-7213NOx 0.00 Mr. Marchmont

Severe Ozone 508-786-72140.00 Mr. Mussleman Ramapo changed name to ANP

Severe Ozone 508-382-9356 200 tpy transferred to Element Markets0.00 Mr. Lack

Severe Ozone 281-207-7213200.00 Mr. Flannery

Severe Ozone 516-545-4875NOx 0.00 Mr. Neal

PA Moderate Ozone 617-557-5333NOx 0.00

Moderate Ozone0.00 Mr. Alexander

Moderate Ozone (518) 452-70000.00 Holcim (US) Inc. Ms. Garakani

Moderate Ozone 4-1040-00011 734-529-4233658.72 Mr. Lack

Moderate Ozone 281-207-7200NOx 0.00

CT Severe OzoneNOx 0.00 Mr. Remillard


CT


PA


9 March 31, 2015***

Sony Electronics Inc., 216 tpy committed to CPV Energy Center #3-3356-00136

658.72 tpy transferred to Element Markets Emissions, LLC

Wisvest-Connecticut, LLC., CT Mr. Slade 217 tpy committed to NY Power Authority # 2-6301-00084

Facility shutdown

Cogentrix of PA., PA 658.72 transferred to Air Resources Group (ARG)

Air Resources Group (ARG)

658.72 transferred to Holcim (US) Inc. 4-1040-00011

Element Markets, LLC 200 tpy transferred To National Grid Generation LLC

Bethlehem Steel Corp., PA

145 tpy committed to Wawayanda Energy # 3-3356-00109

Wisvest-Connecticut, LLC., CT Mr. Beres 207 tpy committed to GenOn Bowline

USX Corp., PA 200 tpy transferred to Ramapo Energy

American National Power

GenOn, Bowline LLC

Facility shutdown

Facility shutdown


PA

National Grid Generation LLC

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


PA Severe Ozone 781-817-8970NOx 0.00 Mr. Ritter

PA Severe Ozone 607-974-7247

PM-10 0.86 Con Ed.- 59th St. Mr. Cartagena2 Moderate 2-6202-00032 212-460-6275

PM-10 0.00 Con Ed.- Waterside Mr. Cartagena2 Moderate 2-6206-00038 212-460-3968

PM-10 0.00 Con Ed.- Waterside Mr. Cartagena Future Facility Shutdown2 Moderate 2-6206-00038 212-460-4858 70.40 committed to # 2-6206-00012 (East River)

PM-10 1.40 East River Housing Corp. Mr. Jacob

2 Moderate 2-6206-00096 212-677-5858 PM-2.5 Poletti Power Project Mr. Ramos

2 2-6301-00084 914-681-6682

PM-2.5 Con Ed.- Hudson Ave. Mr. Ogunsola

2 2-6101-00042 212-460-1223

PM-2.5 NYOFCO Sludge Pellet. Facility Mr. Lambalot

2-6007-00140 203-509-2577Ms. Evensen316-828-7496

PM-2.5National Grid Far Rockaway Power Station

Mr. Flannery

2 2-6308-00040 516-545-4875

PM-2.5 Lovett Generating Station, Mr. Konary Facility shutdown

3-3928-00010 617-529-3874 Name change to GenOn Emissions, LLCMr. Lack281-207-7213

CO 8.32 Zapco Energy Tactics Corp. Mr. Jansen

1 Moderate 1-2820-02479 516-924-5300

CO 34.52 Zapco Energy Tactics Corp. Mr. Antignano

1 Moderate 1-2824-00077 516-563-6336

CO 16.03 Zapco Energy Tactics Corp. Mr. Antignano

1 Moderate 1-2820-00951 516-563-6336

CO 6.35 Environmental Waste Incineration, Inc. Mr. Walker

1 Moderate 1-2809-00088 215-766-7230

Facility shutdown




2

12.81 Facility shutdown

0.00 25.76 tpy transferred to Koch Supply & Trading

25.76 Koch Supply & Trading, LP

0.00

3336.30 GenOn Emissions,

LLC


93.60 Emission Source shutdown

44.71 Emission point(s) shutdown

25.04 committed to ConEd East River #2-6206-00012

13.92 committed to ConEd East River #2-6206-00012

PA

Corning Asahi Video Inc., PA

173 tpy committed to Corning Diesel Mfg. Fac. #8-4642-00108

ContaminantRegion


Facility NameDEC ID

ContactTelephone #


CO 125.62 Con Ed.- Astoria Mr. Cartagena2 Moderate 2-6301-00006 212-460-6275

CO 48.00 Con Ed.- 59th St. Mr. Cartagena2 Moderate 2-6202-00032 212-460-6275

CO 4.00 Hershey Choc. & Conf. Corp. Mr. Simmons

2 Moderate 2-6304-00481 717-534-7540CO 0.00 P&G Port Ivory Plant Ms. Clancy

2 Moderate 2-6401-00004 973-690-3487

CO 40.84 SW Brooklyn Municipal Incinerator Mr. Bekowies

2 Moderate 2-6106-00002 212-837-8383CO 81.70 Con Ed.- Waterside Mr. Cartagena

2 Moderate 2-6206-00038 212-460-3968CO 86.63 Con Ed.- Waterside Mr. Cartagena Facility shutdown

2 Moderate 2-6206-00038 212-460-4858 120.27 committed to # 2-6206-00012 (East River)

CO 0.00 Con Ed.- Hudson Ave. Mr. Guastafeste

Moderate 2-6101-00042 212-460-485812.79 Mr. Karalus

Moderate 612-373-5307

SO2**Glenwood Combustion Turbine Fac. Mr. Flannery

1 1-2822-00481 516-545-4875

SO2** Con Ed.- Hudson Ave. Mr. Ogunsola

2 2-6101-00042 212-460-1223

SO2** NYOFCO Sludge Pellet. Facility Mr. Lambalot

2 2-6007-00140 203-509-2577

SO2**National Grid Far Rockaway Power Station

Mr. Flannery

2 2-6308-00040 516-545-4875

SO2** Lovett Generating Station Mr. Konary Facility shutdown

3-3928-00010 617-529-3874 Name change to GenOn Emissions, LLCMr. Lack281-207-7213


12.79 tpy transfer to NRG Power Marketing Inc.


15.90 tpy transferred to Port Auth. of NY & NJ

2



1.04

July 1, 2012***

Emission Points. Shutdown

460.34 Emission point(s) shutdown


* (TPY) - tons per year

** SO2 ERCs can only be available for use as precursors for PM2.5 non-attainment

3

0.00

10178.00


18.16 tpy used by Freshkill Landfill

145 tpy committed to Astoria Energy, LLC, #2-6301-00647


ContaminantRegion


Facility NameDEC ID

ContactTelephone #


Total ERCs TPY

Bold entries - additions this week VOC 2384.565NOx 23444.422PM-10 2.26PM-2.5 513.18SO2** 10655.48CO 464.80

NOTE: THIS REGISTRY IS FOR INFORMATIONAL PURPOSES ONLY. THE DEPARTMENT IS NOT RESPONSIBLE FOR ANY ERRORS AND OMISSIONS. PARTIES USING THE INFORMATION CONTAINED HEREIN ARE SOLELY RESPONSIBLE FOR VERIFYING LEGAL OWNERSHIP AND THE VALIDITY OF ERCs. REPORTED TRANSFERS OF ERCs ARE NOTED AS A COURTESY AND NO ATTEMPT HAS BEEN MADE TO VERIFY THAT REPORTED ERCs TRANSFERS ARE VALID OR EFFECTIVE AS A MATTER OF LAW.

*** As of January 29, 2016, Reduction Date for the creation of the newly approved ERCs will be listed for all the ERCs placed in the registry.**** Original ERCs of 84.94 tpy was changed to 67.76 tpy, to be consistent with the facility’s Air Permit dated 1/5/2016.


APPENDIX R MUNICIPAL NOTIFICATIONS

FRE 361-2786 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD



PHONE

FAX

207-869-1200

207-869-1299

December 27, 2019

Clinton County Commissioners

Clinton County Government

232 East Main Street

Lock Haven, PA 07745


Dear Commissioners:

On behalf of Renovo Energy Center, LLC (REC), POWER Engineers, Inc. is providing this notice

that REC is submitting a Plan Approval Application to the Pennsylvania Department of

Environmental Protection (PaDEP) for the construction and operation of a nominally rated 1,240

MW (net) dual fuel fired (natural gas and ultra-low sulfur diesel) combined-cycle electric generating

plant to be located in Renovo, Clinton County, Pennsylvania.

The proposed REC facility will consist of two 1-on-1 power blocks that include a Combustion

Turbine Generator (CTG), Heat Recovery Steam Generator (HRSG), and a Steam Turbine (STG)

in line to produce electricity for distribution into the transmission grid system. Each combined

cycle system is intended to be fired on natural gas unless there is an interruption in supply.

Additionally, each HRSG is equipped with a natural gas-fired Duct Burner (DB) for supplemental

steam production, and the steam from the HRSGs is routed through the condensing STG.

The facility will be equipped with state-of-the-art air pollution control equipment. REC will utilize

air cooled condensers for condensing the exhaust steam, which is an environmentally preferred

method as compared to a traditional wet cooling tower. The proposed REC facility will also include

two auxiliary boilers, an emergency generator, an emergency firewater pump, and a natural gas

heater. The HRSG DBs, the auxiliary boilers, and fuel gas heater will only combust pipeline quality

natural gas. The emergency firewater pump and emergency generator will utilize ultra-low sulfur

diesel fuel oil.

This notice is being provided in accordance with the Municipal Notification requirements in 25 Pa

Code Section 127.43a. The Plan Approval Application may be reviewed by making arrangements

with:

Pennsylvania Department of Environmental Protection

Northcentral Regional Office (Air Quality)

208 West Third Street Suite 101


(570) 327-3637

Renovo Energy Center, LLC

December 27, 2019

FRE 361-2786 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD

PAGE 2 OF 2

A 30-day comment period begins when the municipality and county receive the notice. Those

wishing to comment to the PaDEP on this application must do so within 30 days from the date of

receipt of this notice.

If you have any comments or concerns regarding the Plan Approval Application, please contact

Muhammad Zaman, Environmental Program Manager at the address above or he can be reached at

570-327-3648.

Sincerely,

Tim Donnelly


Enclosure(s): Correspondence letter to DEP


Bill Bousquet, Innovative Power Solutions, LLC

DMS 137575/PER-02-02-09

FRE 361-2785 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD



PHONE

FAX

207-869-1200

207-869-1299

December 27, 2019

Renovo Borough

140 3rd Street, Apt 11

Renovo, PA 17764


To Whom It May Concern:

On behalf of Renovo Energy Center, LLC (REC), POWER Engineers, Inc. is providing this notice

that REC is submitting a Plan Approval Application to the Pennsylvania Department of

Environmental Protection (PaDEP) for the construction and operation of a nominally rated 1,240

MW (net) dual fuel fired (natural gas and ultra-low sulfur diesel) combined-cycle electric generating

plant to be located in Renovo, Clinton County, Pennsylvania.

The proposed REC facility will consist of two 1-on-1 power blocks that include a Combustion

Turbine Generator (CTG), Heat Recovery Steam Generator (HRSG), and a Steam Turbine (STG)

in line to produce electricity for distribution into the transmission grid system. Each combined

cycle system is intended to be fired on natural gas unless there is an interruption in supply.

Additionally, each HRSG is equipped with a natural gas-fired Duct Burner (DB) for supplemental

steam production, and the steam from the HRSGs is routed through the condensing STG.

The facility will be equipped with state-of-the-art air pollution control equipment. REC will utilize

air cooled condensers for condensing the exhaust steam, which is an environmentally preferred

method as compared to a traditional wet cooling tower. The proposed REC facility will also include

two auxiliary boilers, an emergency generator, an emergency firewater pump, and a natural gas

heater. The HRSG DBs, the auxiliary boilers, and fuel gas heater will only combust pipeline quality

natural gas. The emergency firewater pump and emergency generator will utilize ultra-low sulfur

diesel fuel oil.

This notice is being provided in accordance with the Municipal Notification requirements in 25 Pa

Code Section 127.43a. The Plan Approval Application may be reviewed by making arrangements

with:

Pennsylvania Department of Environmental Protection

Northcentral Regional Office (Air Quality)

208 West Third Street Suite 101


(570) 327-3637

Renovo Energy Center, LLC

December 27, 2019

FRE 361-2785 (PER-02-02-09) RENOVO 137575 (2019-12-27) TD

PAGE 2 OF 2

A 30-day comment period begins when the municipality and county receive the notice. Those

wishing to comment to the PaDEP on this application must do so within 30 days from the date of

receipt of this notice.

If you have any comments or concerns regarding the Plan Approval Application, please contact

Muhammad Zaman, Environmental Program Manager at the address above or he can be reached at

570-327-3648.

Sincerely,

Tim Donnelly


Enclosure(s): Correspondence letter to DEP


Bill Bousquet, Innovative Power Solutions, LLC

DMS 137575/PER-02-02-09


APPENDIX S CLINTON COUNTY SALDO LETTER, WATER SUPPLY LETTER OF APPROVAL, PHMC PROJECT REVIEW INFORMATION

Renovo Energy Center LLC 5275 Westview Drive Frederick, MD 21703

July 27, 2015

Pennsylvania Historical and Museum Commission Bureau for Historic Preservation Attn: Steven McDougal 400 North Street, 2th Floor Harrisburg, PA 17120

Steven:

It was a pleasure speaking with you the other day. Enclosed are the documents which I

described over the phone. They are several views of the same piece of property. When you

have had a chance to familiarize yourself with these documents, let's spend 15 minutes on the

phone and I can help explain them to you.

Also enclosed is a revised document titled "Project Narrative - PHMC Review Renovo Energy

Center Proposed Location." Please replace the previously filed document of the same name

with this one.

With regard to the contamination- while it is found throughout the industrial park, it appears

heaviest in the areas where the power plant will be located and we will have to pay particular

attention to these areas during construction.

Thank you very much for your effort in this matter and I look forward to talking with you

soon. Also, I will be at the site in the next few weeks and we could always plan a site visit

together.

Very truly yours,

~-Thomas D. Emero, Director

Innovative Power Solutions LLC

Consultant to Renovo Energy Center LLC

1

Project Narrative – PHMC Review

Renovo Energy Center Proposed Location

Renovo Energy Center LLC is proposing to use an approximately 20-acre portion of the Renovo

Industrial Park to site a natural gas electrical plant. The property is located in Renovo Borough,

Clinton County. The site is shown on the Quadrangle map included with this submission. This

site has a long history of heavy industrial use. Beginning in 1862, the site was used for over 100

years for the construction, modification and repair of rail cars. Over 3,000 people worked on

the site at its height in the 1920s and 30s. The site has changed hands several times since the

1960s. The power plant is proposed to be located directly over that portion of the site which

has been most heavily used over the past 100 to 150 years.

In 1995, Clinton County Economic Partnership completed Phase II and Expanded Phase II ESA

Investigation Reports of the site to facilitate and encourage its redevelopment. In 2011,

additional environmental investigation of the site revealed contamination throughout the site,

with higher levels of contamination identified at several locations. A Remedial Investigation

Report was prepared, along with Site Specific Remediation and ecological and human health

risk assessments. Restrictive covenants have been placed on the property with regard to the

disturbance of soils in certain areas.

In 2001, a road was added to the site to facilitate the use of the site as an industrial park. Over

the last 30 years or so numerous buildings have been demolished including: former machine

shop, tool room, foundry, paint shop, store depot, lumber shed, and tank shop. These

demolitions left only the chimney to the foundry, a former machine shop, the former erecting

shop, and the former boiler shop. The existing buildings are labeled with their previous usage in

the included site plan.

In order to prepare the land for development of the power plant, the road that was constructed

to facilitate industrial park development will be partially demolished and a turnaround area will

be constructed near the intersection of Industrial Park Road and Mt. Glen Road. The remaining

buildings and the chimney will be removed. A cell tower located on the site will be relocated to

a parcel shown on the map off of Renovo Road. The power plant will be located in the center

of the site where the current buildings are and where the demolished buildings were situated.

We are submitting this project site for review to determine whether there are any structures on

the site that would require additional investigation prior to starting construction on the power

plant. Such construction would include demolition and clearing of the remaining structures

within the project area. The placement of utilities, fences, additional buildings, etc. has not

2

plant. Such construction would include demolition and clearing of the remaining structures

within the project area. The placement of utilities, fences, additional buildings, etc. has not

been proposed at this time. For this reason, the project boundary is assumed to be coincident

with the area of potential effect.

In addition to the aforementioned 7.5’ USGS Quadrangle, the following materials are included:

a) a basic site plan consisting of annotated Google Earth imagery copy written 2015, b)

annotated images of the site including aerial imagery from 1938, 1959, and 1968 from Penn

Pilot and c) images taken by Sweetland Engineering and Associates survey crews, which are

labeled individually below the images. This project will require Pennsylvania DEP permitting for

an NPDES permit for Earth Disturbances. Because this permit has not yet been acquired, it was

not listed in section C of the request for consultation form.

Renovo Energy Center Plan Approval Application ... - PA DEP

Documents

Transcript of Renovo Energy Center Plan Approval Application ... - PA DEP