Renovo Energy Center Plan Approval Application

August 5, 2015

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.

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

PHONE

FAX

207-869-1200 207-869-1299

FRE 164-303 137575 (08/05/2015) CD

August 5, 2015

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. We appreciate

you meeting with us to review the application.

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

As you are aware, the facility is collecting on-site meteorological data for the ambient air quality

analyses which will be submitted in the fall of 2016.

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

DMS 137575/PER-02-02-09

FRE 164-304 (PER-02-02-09) REC (08/05/2015) 137575 CD PAGE i

Renovo Energy Center, LLC Plan Approval Application Index

Section 1: Project Overview Section 2: Applicable Requirements Section 3: Control Technology Analyses Section 4: Ambient Air Quality Analyses Section 5: Pennsylvania DEP Plan Approval Application Forms Section 6: Non-Attainment Area Requirements

Attachment A: Site Location on USGS Map Attachment B: REC Project Site Plan Attachment C: Emission Calculations Attachment D: Vendor Data Attachment E: BACT/LAER Clearinghouse Determinations Summaries Attachment F: Process Flow Diagrams Attachment G: SCR PID Attachment H: Cost Analysis Information (SCR for Turbines and OxCat for Auxiliary Boilers) Attachment I: Storage Tank Information Attachment J: Municipal Notifications Attachment K: Registry of Available NOx and VOC offsets Attachment L: Meteorological Monitoring Plan and DEP Approval Letter Attachment M: PHMC Project Review Information

Section 1


Section 1 Project Overview

Table of Contents

1.1 Project Description ........................................................................................................................ 1

1.2 Site Location ................................................................................................................................. 1

1.3 Process/Equipment Description .................................................................................................... 1

1.3.1 Combustion Turbine Generators ........................................................................................... 2

1.3.2 Turbine Inlet Evaporative Coolers ........................................................................................ 4

1.3.3 Heat Recovery Steam Generators with Duct Burners ........................................................... 4

1.3.4 Steam Turbine Generator ...................................................................................................... 4

1.3.5 Auxiliary Boilers .................................................................................................................. 4

1.3.6 Fuel Gas Heater .................................................................................................................... 5

1.3.7 Diesel-Fired Emergency Generators ..................................................................................... 5

1.3.8 Diesel-Fired Emergency Fire Water Pump ........................................................................... 5

1.3.9 Fuel Oil Storage Tanks ......................................................................................................... 5

1.3.10 Aqueous Ammonia Storage Tank ........................................................................................ 5

1.3.11 Lube Oil Storage Tanks ........................................................................................................ 5

1.3.12 Circuit Breakers .................................................................................................................... 5

1.4 Project Schedule ............................................................................................................................ 6

1.5 Facility Emissions Calculations .................................................................................................... 6

1.5.1 Combustion Turbines/HRSGs ............................................................................................... 6

1.5.2 Auxiliary Boilers and Fuel Gas Heater ................................................................................. 8

1.5.3 Emergency Generators and Fire Pump ................................................................................. 9

1.5.4 Facility Wide ....................................................................................................................... 10

POWER ENGINEERS, INC. Project Overview for Renovo Energy Center, Renovo, PA

FRE 164-304 (PER-02-02-09) REC (08/05/2015) 137575 CD PAGE 1

1.1 Project Description Renovo Energy Center, LLC (REC) proposes to construct a nominally rated 950 MW (net) dual fuel (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 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 Combustion Turbine (CT), which is intended to be fired on natural gas unless there is an interruption in supply, and a Heat Recovery Steam Generator (HRSG). The steam from the HRSGs is routed through the condensing steam turbine generator. With the exception of the General Electric option, each HRSG has a gas fired Duct Burner (DB) for supplemental firing. 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. REC is requesting a plan approval that will allow three optional plant configurations, each having a different original equipment manufacturer (OEM). The three OEM configuration options being considered are the General Electric (GE) 7HA.02, Siemens SGT6-8000H, and Mitsubishi Hitachi Power Systems America, Inc. (MHPSA) M501J units. Due to pricing, performance, design considerations, and delivery schedule, a final decision on the preferred OEM will be made after a plan approval has been issued, thus the application is structured to reflect the three different options. REC will submit a written request to Pennsylvania Department of Environmental Protection (PaDEP) to withdraw two of the three two options prior to the start of construction. The proposed REC facility will also include two auxiliary boilers, two emergency generators, 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. In addition to the aforementioned combustion devices, the REC facility will also have potential air emissions from the petroleum storage tanks, ammonia slip from selective catalytic reaction process, and SF6 containing circuit breakers. 1.2 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 269.4455 kilometers (km) Easting and 4578.8724 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. 1.3 Process/Equipment Description Attachment A 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 (each @ ~3,558 MMBtu/hr, High Heating Value (HHV)), or Siemens SGT6-8000H (each @ ~3,124 MMBtu/hr, HHV), or MHPSA M501J (each @ ~3,301 MMBtu/hr, HHV), natural gas/ULSD fired combustion turbines with inlet evaporative coolers;



• Paired with each combustion turbine, one condensing steam turbine and one driven electric generator;

• Two heat recovery steam generators (HRSG) with supplementary natural gas-fired duct burners (no duct firing with GE option), each rated at 695 MMBtu/hr (HHV) heat input for the Siemens SGT6-8000H and 435 MMBtu/hr (HHV) heat input for the MHPSA M501J;

• Two natural gas-fired auxiliary boilers (one for each power block), each rated at 30 MMBtu/hr heat input;

• Two diesel-fired Emergency Generators, (one for each power block) rated at 750 kW (~8.4 MMBtu/hr heat input);

• One natural gas-fired fuel gas heater, rated at 18 MMBtu/hr heat input; • One diesel-fired Emergency Fire Water Pump, rated at 250 hp (~1.8 MMBtu/hr heat input); • Two Aqueous Ammonia aboveground storage tanks with a capacity of 15,000 gallons each; • Ultra-low sulfur diesel oil aboveground storage tank with a capacity of 3.8 million gallons; • Two lube oil aboveground storage tanks each with a capacity of 20,000 gallons; and • Eight high voltage circuit breakers containing sulfur hexafluoride within the facility’s electrical

switchyard.

1.3.1 Combustion Turbine Generators Each combustion turbine power block will include an advanced firing combustion turbine, air compressor section, gas combustion system (utilizing dry, low-NOx combustors), power steam turbine, and a generator. The combustion turbine is the main component of a combined-cycle power system. First, 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 oil, 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 power turbine is ducted to a boiler commonly known as a heat recovery steam generator, or HRSG, where steam is produced to generate additional electricity in a steam turbine generator. With the exception of GE’s power block, which does not require duct firing, natural gas- fired duct burners located within the HRSGs are used for supplementary firing to increase steam and electrical output. REC’s combustion turbines will be designed to operate in the dry low-NOx mode at loads from approximately 60 percent up to 100 percent rating. REC’s combustion turbines will operate at very low NOx levels when operating in steady state conditions through the use of low NOx combustors, proper operation, and selective catalytic reduction (SCR) technology. During periods of startup and shutdown (SUSD) the emissions from the combustion turbines 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. Independent of the turbine manufacturer or model number, SUSD NOx emissions will be significantly higher than steady state load conditions. The higher, uncontrolled NOx emissions during SUSD cannot be avoided.

SUSD periods allow for thermal stabilization of the combined cycle power train to allow for efficient and recommended operation.



A combined-cycle turbine power train generates power from the combustion turbine while simultaneously recovering and transferring high temperature exhaust energy to the steam turbine 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.

Combined-cycle units have different startup times depending upon the amount of time since the unit was last operated, which are typically referred to as either hot, warm, or cold startups. The specific startup time will vary based on turbine manufacturer, model, and ambient conditions. In general and for the purposes of this application, the following summarizes startup periods:

• 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.

There are three main stages of a combined cycle startup: purging of the HRSG; gas turbine speed up, synchronization, and loading; and steam turbine speed up, synchronization, and loading. At approximately 60% combustion turbine load suitable steam properties for the steam turbine startup are reached. As stated previously, the startup time for the CT, HRSG and steam turbine are dependent on how long the unit has been out of operation prior to startup. To avoid thermal stress, various components of the steam turbine must be brought up to temperature prior to normal steam turbine operation. In a combined cycle system, the amount of time since previous operation of the steam turbine and HRSG factors into the temperature of components and dictates how long the startup period will be.

Startup is defined as from GT initial fire to HRSG stack emissions compliance. Shutdown is from the time HRSG stack goes out of compliance during shutdown to termination of fuel flow. The following describe SUSD times in ideal conditions for each manufacturer and type of startup; actual startup /shutdown times will be longer, which is reflected in our permit request.

For GE units on natural gas, a hot start is 20 minutes in duration, warm 40 minutes, and cold 45 minutes with shutdown 14 minutes. For Siemens units on natural gas, a hot start is 30 minutes in duration, warm 35 minutes, and cold 35 minutes with shutdown 18 minutes. For MHPSA units on natural gas, a hot start is 28 minutes, warm is 103 minutes, and cold is 143 minutes while shutdown is 13 minutes.

For GE units on ULSD, a hot start is 20 minutes in duration, warm 40 minutes, and cold 45 minutes with shutdown 8 minutes. For Siemens units on ULSD, a hot start is 32 minutes in duration, warm 35 minutes, and cold 35 minutes with shutdown 18 minutes. For MHPSA units on ULSD, a hot start is 37 minutes, warm is 125 minutes, and cold is 182 minutes while shutdown is 14 minutes.

Typically, upon reaching a load greater than 60% capacity with the HRSG/SCR temperature of approximately 570°F the startup period is considered complete as the pollution control equipment can now effectively operate. At this point (steady state load), NOx emissions can be met.

During the shutdown of a combined-cycle unit the combustion turbine load is significantly reduced (in general and for the purposes of this application, shutdown period is when the combustion turbine operates at or below 50% load). Once the combustion turbine’s exhaust gas temperature is below a manufacturer’s specified minimum, the steam turbine is then shut down. The combustion turbine load is further reduced until the unit is shut off.

The combustion turbines/HRSG 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 compounds to carbon dioxide 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. 1.3.2 Turbine Inlet Evaporative Coolers During hot and humid ambient air conditions, REC will employ evaporative cooling to cool the air entering the combustion turbine (CT) 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 CT resulting in increased output capacity. CTs 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. 1.3.3 Heat Recovery Steam Generators with Duct Burners REC will use two HRSGs, one for each CT, 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 CT 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. With the exception of the GE power block, steam production in the HRSGs may be augmented using duct burners (DBs) that will be fired by natural gas. The proposed DBs will have a firing rate of 695 (HHV) MMBtu/hr each for the Siemens SGT6-8000H and 435 (HHV) MMBtu/hr each for the MHPSA M501J. REC’s selective catalytic reduction (SCR) and oxidation catalysts will be installed within the HRSG to control NOx and CO, respectively. A Continuous Emissions Monitoring System (CEMS) for monitoring emissions of NOx, CO, and concentration of O2 or CO2 will be installed on REC’s HRSG exhaust stack. 1.3.4 Steam Turbine Generator Each power block will include a reheat, condensing steam turbine 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. REC’s steam turbine sets are designed to produce up to approximately 160 MW of electrical output at ISO conditions with duct firing for the Siemens and MHPSA units. 1.3.5 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 the CTs or steam turbine. The proposed boilers will be fired with natural gas with a heat input rating of 30 MMBtu/hr.



1.3.6 Fuel Gas Heater REC’s proposed facility design includes a fuel gas heater. The heater 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 heater 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 heater will have a maximum heat input rating of 18 MMBtu/hr. 1.3.7 Diesel-Fired Emergency Generators REC’s proposed facility will include two diesel-fired emergency generators each rated at 750 kW that will be operated no more than 500 hours per year, including testing and maintenance hours. The emergency generators 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.). Per federal regulation, testing and maintenance operation of the emergency generators will be limited to 100 hours per year per device. There are no plans for the emergency diesel generators to provide sufficient power for a black start, peak shaving or non-emergency power. 1.3.8 Diesel-Fired Emergency Fire Water Pump The proposed 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. 1.3.9 Fuel Oil Storage Tanks REC will include a 3.8 MM gallon ultra-low sulfur diesel oil storage aboveground oil tank to provide fuel for combustion turbines for three days of operation at full load if natural gas supply is curtailed. Two 1,800 gallon and one 350 gallon ultra-low sulfur diesel oil storage tanks will provide fuel for the emergency generators and fire pump engine, respectively. 1.3.10 Aqueous Ammonia Storage Tank REC will include two 15,000 gallon above ground aqueous ammonia storage tanks (one for each power train) to provide ammonia for the SCR systems on the combined cycle combustion turbines. 1.3.11 Lube Oil Storage Tanks REC will include two 20,000 gallon above ground storage tanks for lubrication oil used for the combustion turbines and steam turbines. 1.3.12 Circuit Breakers REC will have eight high voltage circuit breakers within the facility’s electrical switchyard. Four circuit breakers will contain 345 pounds of sulfur hexafluoride (SF6) and the remaining four 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, 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. 1.4 Project Schedule REC is submitting this initial application on or about August 5, 2015. REC anticipates commencing actual construction in April 2017. REC’s targeted date for startup and commercial electrical generation is May 2019 and December 2019, respectively. 1.5 Facility Emissions Calculations

1.5.1 Combustion Turbines/HRSGs The potential emissions from REC’s facility are primarily products of combustion from the combustion turbines and duct burners. To a lesser extent, there will also be emissions from the auxiliary boilers, fuel gas heater, emergency generators, and the emergency firewater pump. Potential emissions of criteria pollutants from the power blocks are variable depending on ambient air temperature, relative humidity, and operating load of each unit. The combustion turbine and HRSG will also exhaust the 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 combustion turbine OEMs (GE, Siemens, and MHPSA) have provided criteria pollutant emissions for various operating loads, which are summarized in Attachment D. SO2 emissions are based on use of natural gas with a sulfur content of 0.4 grains per 100 standard cubic feet of gas. CTs and DBs short-term emissions based on the maximum hourly emission rates ("worst-case" from all operating scenarios) for each pollutant are listed in the table below.

Table 1.5-1: Maximum Short Term Emission Rates*

Natural Gas Firing ULSD Firing

Pollutant

General Electric GE7HA.02

(lb/hr)

Siemens SGT6-8000H

(lb/hr)

MHPSA M501J (lb/hr)

General Electric GE7HA.02

(lb/hr)

Siemens SGT6-8000H

(lb/hr)

MHPSA M501J (lb/hr)

NOx 25.52 25.94 27.38 84.00 62.27 40.20 CO 15.54 15.86 16.70 17.01 25.31 36.78

PM10 12.21 20.46 17.38 78.43 33 35.42 VOC 4.44 12.60 7.31 9.74 3.68 18.10 SO2 4.49 4.68 2.16 6.31 4.68 2.04 NH3 23.63 24.05 25.61 25.83 19.22 18.97

H2SO4 3.17 1.54 4.31 4.46 1.54 1.20 GHGs

CO2 415,800 423,576 433,290 616,000 453,279 322,960 CH4 7.39 7.66 8.21 23.53 17.31 17.15 N2O 0.74 0.77 0.82 4.71 3.46 3.43

CO2equivalent 416,205 423,995 433,740 617,991 454,744 324,411 *Reflects the maximum short term emission rate over a range of ambient temperatures; Emissions calculations, methodology, and vendor data are included in Attachments C and D.



The annual emissions for each CT option were determined based on the combinations of operating scenarios shown in the table below. REC is proposing to use the worst-case annual emissions for each OEM for air permitting purposes assuming REC can operate 8,760 hours per year, however, not at worst-case ambient conditions, as such conditions would not occur for all 8,760 hours in a given year.

Table 1.5-2: General Electric 7HA.02

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 Annual Emissions from Both

Powerblocks (tons)

NOx 60.48 11.61 184.47 77.47 334.03 CO 12.25 11.22 112.42 285.61 421.50

PM10 56.47 3.16 91.23 6.07 156.94 VOC 6.68 0.99 32.06 70.84 110.58 SO2 4.54 0.25 32.30 1.97 39.07 NH3 18.60 1.03 170.22 10.38 200.23

H2SO4 3.21 0.18 22.81 1.39 27.59 GHGs

CO2 443,520 24,640 3,135,132 191,268 3,794,560 CH4 16.94 0.94 55.74 3.40 77.02 N2O 3.39 0.19 5.57 0.34 9.49

CO2equivalent 444,953 24,720 3,138,186 191,454 3,799,314 Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.

Table 1.5-3: Siemens SGT6-8000H

Pollutant

Annual Emissions


Annual Emissions



Firing with DBs (tons)


Firing without DBs (tons)

Annual Emissions


(tons)


Powerblocks (tons)

NOx 44.83 11.66 189.22 0 109.70 355.40 CO 18.22 107.99 114.80 0 450.24 691.25

PM10 23.76 1.26 136.85 0 4.98 166.85 VOC 2.65 16.86 67.29 0 90.85 177.65 SO2 3.37 0.085 33.48 0 0.97 37.91 NH3 13.83 0.77 174.97 0 9.90 199.47

H2SO4 1.11 0.062 11.61 0 0.66 13.44 GHGs

CO2 326,361 9,188 3,193,762 0 101,880 3,631,191 CH4 12.46 0.69 57.72 0 3.17 74.04 N2O 2.49 0.14 5.77 0 0.32 8.72

CO2equivalent 327,415 9,247 3,196,925 0 102,053 3,635,641 Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.



Table 1.5-4: MHPSA M501J

Pollutant

Annual Emissions


Annual Emissions






Annual Emissions


(tons)


Powerblocks (tons)

NOx 28.94 4.91 96.43 91.13 35.49 256.90 CO 26.48 84.40 58.81 55.58 900.76 1,126.03

PM10 25.50 2.25 63.03 44.37 2.71 137.87 VOC 13.03 29.69 25.73 24.32 409.37 502.16 SO2 1.47 0.082 7.69 7.24 0.88 17.36 NH3 13.66 0.76 90.22 85.26 10.40 200.31

H2SO4 0.86 0.048 15.22 14.47 1.77 32.37 GHGs

CO2 232,531 8,924 1,633,503 1,543,928 77,562 3,496,448 CH4 12.35 0.69 30.95 27.43 3.35 74.76 N2O 2.47 0.14 3.09 2.74 0.33 8.78

CO2equivalent 233,576 8,982 1,635,199 1,545,431 77,745 3,500,934 Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.

1.5.2 Auxiliary Boilers and Fuel Gas Heater The potential emissions of NOx, CO, and SO2 from the auxiliary boilers and fuel gas heater were calculated based on the proposed BACT emission rates for natural gas-fired boilers and heater. PM10 and PM2.5 emissions for the auxiliary boilers were calculated based on vendor provided data. The auxiliary boilers have heat input rates of 30 MMBtu/hr each, while the fuel gas heater’s heat input capacity is 18 MMBtu/hr. Potential annual emissions for the boilers and heater are based on 150,000 MMBtu and 8,760 hours of operation per year, respectively. Hourly and annual emissions for the devices are summarized in the following tables.



Table 1.5-5: Auxiliary Boilers Emissions Estimate

Pollutant

Emission Factor

(lb/MMBtu)

Emissions per boiler

(lb/hr)

Emissions per boiler

(tpy)

Total Emissions

(tpy) NOx 0.011 0.33 0.41 0.83 CO 0.036 1.08 1.35 2.70

PM10 0.0033 0.099 0.124 0.25 VOC 0.004 0.12 0.15 0.30 SO2 0.0005 0.015 0.019 0.038

H2SO4 9.15E-05 0.0027 0.003 0.0069 NH3 negligible --- --- ---

(kg/MMBtu)

(tpy) (tpy)

CO2 53.06

4,377 8,755 CH4 1.00E-03

0.083 0.17

N2O 1.00E-04

0.0083 0.017 CO2e ---

4,381.97 8,763.94

Table 1.5-6: Natural Gas Water Bath Heater Emissions Estimate

Emission

Factor (lb/MMBtu)

Total Emissions

(tpy) Pollutant NOx 0.04 3.15 CO 0.08 6.31

PM10 0.0033 0.26 VOC 0.005 0.39 SO2 0.0005 0.039 NH3 negligible ---

(kg/MMBtu) (tpy)

CO2 53.06 9,203 CH4 1.00E-03 0.17 N2O 1.00E-04 0.017 CO2e --- 9,213

1.5.3 Emergency Generators and Fire Pump Potential emissions from REC’s emergency generators 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 ultra-low sulfur diesel oil having a maximum sulfur content of 0.0015% by weight consistent with NSPS Subpart IIII requirements. Annual emissions from REC’s emergency generators are based on 500 hours of operation each and the emergency fire water pump is based on 250 hours of operation each. Short-term and annual emissions are summarized in the tables below.



Table 1.5-7: Emergency Generators Emissions Estimate

Pollutant Tier 2

(g/bhp-hr) (lb/hr)

Emissions per Engine

(tpy)

Total Potential Emissions

(tpy) NOx 4.8 12.77 3.19 6.39 CO 2.6 6.92 1.73 3.46

PM10 0.15 0.40 0.10 0.20 VOC 1.00 2.66 0.67 1.33 SO2 --- 0.01 0.003 0.0064

Table 1.5-8: Diesel Fire Pump Emissions Estimate

Pollutant Tier 3

(g/bhp-hr) (lb/hr)

Potential Emissions

(tpy) NOx + VOC 3 1.653 0.21

CO 2.6 1.433 0.18 PM10 0.15 0.083 0.010 VOC 1.00 0.551 0.069 SO2 --- 0.003 0.00034

1.5.4 Facility Wide 1.5.4.1 Criteria Pollutants The following table lists a summary of REC’s estimated annual emissions from each emission unit type.

Table 1.5-9: General Electric 7HA.02 Option – Annual Facility Wide Potential Emissions (Tons/Year)

Pollutant Power-blocks

Auxiliary Boilers

Diesel Generators

Diesel Fire

Pump Heater

ULSD Storage

Tank Circuit

Breakers Facility-

Wide Total NOx 334.03 0.83 6.39 0.21 3.15 --- --- 344.6 CO 421.50 2.70 3.46 0.18 6.31 --- --- 434.1

PM10 156.94 0.25 0.20 0.010 0.26 --- --- 157.7 VOC 110.58 0.30 1.33 0.069 0.39 0.045 --- 112.7 SO2 39.07 0.038 0.0064 0.00034 0.039 --- --- 39.2 NH3 200.23 --- --- --- --- --- --- 200.2 Lead 0.038 --- --- --- --- --- --- 0.038 CO2 3,794,560 8,754.90 684.35 35.67 9,203.15 --- --- 3,813,238 CH4 77.02 0.17 0.028 0.0014 0.17 --- --- 77.4 N2O 9.49 0.017 0.0056 0.00029 0.017 --- --- 9.5 SF6 --- --- --- --- --- --- 0.0051 0.0051

CO2e 3,799,314 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,818,129 H2SO4 27.59 0.0069 --- --- --- --- --- 27.6 HAPs 18.37 0.14 0.016 0.00083 0.15 --- --- 18.7



Table 1.5-10: Siemens SGT6-8000H Option – Annual Facility Wide Potential Emissions

(Tons/Year)


Auxiliary Boilers

Diesel Generators

Diesel Fire

Pump Heater

ULSD Storage

Tank Circuit

Breakers Facility-

Wide Total NOx 355.40 0.83 6.39 0.21 3.15 --- --- 366.0 CO 691.25 2.70 3.46 0.18 6.31 --- --- 703.9


CO2e 3,635,641 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,654,456 H2SO4 13.44 0.0069 --- --- --- --- --- 13.4 HAPs 18.16 0.14 0.016 0.00083 0.15 --- --- 18.5

Table 1.5-11: MHPSA M501J Option – Annual Facility Wide Potential Emissions (Tons/Year)


Auxiliary Boilers

Diesel Generators

Diesel Fire

Pump Heater

ULSD Storage

Tank Circuit

Breakers Facility-

Wide Total NOx 256.90 0.83 6.39 0.21 3.15 --- --- 267.5 CO 1,126.03 2.70 3.46 0.18 6.31 --- --- 1,138.7


CO2e 3,500,934 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,519,749 H2SO4 32.37 0.0069 --- --- --- --- --- 32.4 HAPs 17.15 0.14 0.016 0.00083 0.15 --- --- 17.5

1.5.4.2 Hazardous Air Pollutants Hazardous air pollutant (HAP) 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 Amendments of 1990. Based on worst case emission factors, HAP emissions are summarized in the tables below for the GE,



Siemens, and MHPSA turbines, respectively; detailed emission calculations are provided in Attachment C. The formaldehyde emission factors were provided by each OEM while the balance of HAP emission factors is from EPA’s AP-42 document. Federal major HAP emissions listed below are on an annual (tons/yr) basis.



Table 1.5-12: General Electric 7HA.02 HAP Potential Emissions

Hazardous Air Pollutant

Annual Emissions


Annual Emissions



Firing (tons)

Annual Emissions


(tons)


Powerblocks (tons)

1,3-butadiene 0.041 0.0023 0.011 0.00066 0.055 acetaldehyde 0 0 1.01 0.062 1.07

acrolein 0 0 0.16 0.010 0.17 benzene 0.14 0.0078 0.30 0.019 0.47

ethyl benzene 0 0 0.81 0.049 0.86 formaldehyde 0.68 0.038 6.02 0.37 7.11 naphthalene 0.090 0.0050 0.033 0.0020 0.13

PAH 0.10 0.0057 0.056 0.0034 0.17 propylene oxide 0 0 0.73 0.045 0.78

toluene 0 0 3.29 0.20 3.49 xylenes 0 0 1.64 0.10 1.74 arsenic 0.028 0.0016 0 0 0.030

beryllium 0.00079 0.000044 0 0 0.00084 cadmium 0.012 0.00068 0 0 0.013 chromium 0.028 0.0016 0 0 0.030

cobalt 0 0 0 0 0 lead 0.036 0.0020 0 0 0.038

manganese 2.02 0.11 0 0 2.14 mercury 0.0031 0.00017 0 0 0.0032 nickel 0.012 0.00065 0 0 0.012

selenium 0.064 0.0036 0 0 0.068

Total HAPs 18.37 Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.



Table 1.5-13: Siemens SGT6-8000H HAP Potential Emissions

Hazardous Air

Pollutant

Annual Emissions


Annual Emissions






Annual Emissions


(tons)


Powerblocks (tons)

1,3-butadiene 0.030 0.0017 0.011 0 0.00062 0.044 acetaldehyde 0 0 1.05 0 0.057 1.10

acrolein 0 0 0.17 0 0.0092 0.18 benzene 0.10 0.0058 0.31 0 0.017 0.44

ethyl benzene 0 0 0.84 0 0.046 0.88 formaldehyde 0.61 0.034 6.18 0 0.39 7.21 naphthalene 0.066 0.0037 0.034 0 0.0019 0.11

PAH 0.075 0.0042 0.058 0 0.0032 0.14 propylene

oxide 0 0 0.76 0 0.042 0.80

toluene 0 0 3.40 0 0.19 3.59 xylenes 0 0 1.70 0 0.093 1.80 arsenic 0.021 0.0012 0.0051 0 0.00028 0.027

beryllium 0.00058 0.000032 0.00031 0 0.000017 0.00094 cadmium 0.0090 0.00050 0.028 0 0.0015 0.039 chromium 0.021 0.0012 0.036 0 0.0020 0.060

cobalt 0 0 0.0022 0 0.00012 0.0023 lead 0.026 0.0015 0 0 0 0.028

manganese 1.49 0.083 0.0098 0 0.00054 1.58 mercury 0.0023 0.00013 0.0067 0 0.00037 0.0094 nickel 0.0087 0.00048 0.054 0 0.0030 0.066

selenium 0.047 0.0026 0.00062 0 0.000034 0.050 Total HAPs 18.16 Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD.



Table 1.5-14: MHPSA M501J HAP Potential Emissions

Hazardous Air

Pollutant

Annual Emissions


Annual Emissions






Annual Emissions


(tons)


Powerblocks (tons)

1,3-butadiene 0.030 0.0017 0.0060 0.0054 0.00065 0.044 acetaldehyde 0 0 0.56 0.50 0.061 1.12

acrolein 0 0 0.090 0.080 0.010 0.18 benzene 0.10 0.0057 0.17 0.15 0.018 0.44

ethyl benzene 0 0 0.45 0.40 0.049 0.90 formaldehyde 0.43 0.024 2.74 2.59 0.32 6.10 naphthalene 0.065 0.0036 0.018 0.016 0.0020 0.11

PAH 0.075 0.0041 0.031 0.027 0.0033 0.14 propylene

oxide 0 0 0.41 0.36 0.044 0.81

toluene 0 0 1.82 1.62 0.20 3.64 xylenes 0 0 0.91 0.81 0.10 1.82 arsenic 0.021 0.0011 0.0028 0.0024 0.00030 0.027

beryllium 0.00058 0.000032 0.00017 0.00015 0.000018 0.00094 cadmium 0.0090 0.00050 0.015 0.013 0.0016 0.040 chromium 0.021 0.0011 0.019 0.017 0.0021 0.060

cobalt 0 0 0.0012 0.0010 0.00013 0.0023 lead 0.026 0.0015 0 0 0 0.028

manganese 1.47 0.082 0.0052 0.0046 0.00057 1.57 mercury 0.0022 0.00012 0.0036 0.0032 0.00039 0.0095 nickel 0.0086 0.00048 0.029 0.026 0.0031 0.067

selenium 0.047 0.0026 0.00033 0.00029 0.000036 0.050 Total HAPs 17.15

Table reflects 8,000 hours/year operating on natural gas and 760 hours/year on ULSD. * Federal major Hazardous Air Pollutant (HAP) emissions are annual (tons/yr);

Based on the tables above, the maximum total HAPs from the proposed facility would be less than 25 tons per year regardless of the OEM; the single HAP emitted at the highest rate is formaldehyde at less than 8 tons per year for all OEMs. 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 under 40 CFR Part 63 Subpart YYYY, the Combustion Turbine Maximum Achievable Control Technology (MACT) standard.

Section 2


Section 2 Applicable Requirements

Table of Contents

2.0 Air Regulatory Requirements ........................................................................................................... 1

2.1 National and State Ambient Air Quality Standards .......................................................................... 1

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

2.7 40 CFR Part 63 – National Emission Standards for Hazardous Air Pollutants (NESHAP) ............. 6

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

POWER ENGINEERS, INC. Applicable Requirements for Renovo Energy Center, Renovo, PA


2.0 Air Regulatory Requirements

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 2.1-1: 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)



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 2.1-2: 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 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 Attachment C, 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.

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 2.4-1: Potential Emissions Compared to Major Source Thresholds

Pollutant

Facility Potential Emissions (tons/yr)1

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 39.2 100 40 Yes NA NA PM10 167.6 100 15 Yes NA NA PM2.5 167.6 100 10 Yes NA NA NOx 366.0 100 40 NA 100 Yes CO 1,138.7 100 100 Yes NA NA

VOC 504.3 100 40 NA 50 Yes H2SO4 32.4 100 7 Yes NA NA Lead 0.038 100 0.6 No NA NA GHG (CO2e)

3,818,129 75,000 75,000 Yes NA NA 1Maximum potential based on all three combustion turbine vendors

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. 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. 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.

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 30 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.

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 two emergency generator engines 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 generators and diesel fire pump will be certified to meet the applicable emission standards set forth in Subpart IIII. All of REC’s engines will be installed with non-resettable hour meters. REC proposes to limit the operation of the emergency generators 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.

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 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.

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 potentially subject to 40 CFR Part 60 Subpart TTTT which was proposed in the Federal Register on January 8, 2014 (FR 1430-1517). On January 8, 2014, EPA withdrew the April 13, 2012 proposed new source performance standard for emissions of carbon dioxide for new affected fossil fuel-fired electric utility generating units and proposed new standards of performance for new affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Depending on when the regulation is finalized and when REC commences construction, REC may or may not be subject to the proposed regulation. As proposed, Subpart TTTT will apply to new steam generating units with a design heat input of greater than 73 MW (250 MMBtu/hr) that supply one-third or more of their potential electric output to a utility distribution system on an annual basis. The proposed NSPS emission limit for stationary combustion turbines with a base load rating heat input to the turbine engine of greater than 250 MW (850 MMBtu/hr) is 1,000 lb CO2/MWh on a 12-operating month rolling average basis. Since REC’s turbines will have a heat input of greater than 850 MMBtu/hr, a limit of 1,000 lb CO2/MWh on a 12-operating month rolling average will apply and compliance will be demonstrated monthly by calculating the average CO2 emissions rate at the end of each 12-month operating period.

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



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 two diesel engine powered emergency generators 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 Attachment C, 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.



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 the 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 2015, 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.

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:



• 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 generators 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 0.5% through June 30, 2016 and 0.05% beginning July 1, 2016.

• 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 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 Attachment K. 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 operating permit will not impose additional requirements other than periodic report 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.

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, two 1,800-gallon ULSD tanks associated with each generator, one 350-gallon ULSD tank associated with the fire pump engine, two 20,000-gallon lube oil tanks, and two 15,000 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 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 Attachment C, 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 Attachment C, 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.

Section 3


Section 3 Best Available Control Technology/Lowest Achievable Emission Rate/Best Available

Technology Analysis (BACT/LAER/BAT)

Table of Contents

3.1 Introduction ........................................................................................................................................... 1 3.2 Executive Summary of BACT/LAER/BAT Determinations ................................................................ 2 3.3 BACT/LAER/BAT Determinations For Combined Cycle Powerblocks ............................................. 3

3.3.1 Nitrogen Oxides (NOx) ............................................................................................................. 3 3.3.1.1 Identification of Similar Facilities with LAER/BAT for NOx ................................................ 3 3.3.1.2 Identification and Evaluation of NOx Control Technologies .................................................. 4 3.3.1.3 Selection of NOx Control Technology to Meet LAER/BAT .................................................. 6

3.3.2 Particulate Matter (PM10) .......................................................................................................... 7 3.3.2.1 Identification of Similar Facilities with BACT/BAT for PM10 ............................................... 7 3.3.2.2 Identification and Evaluation of PM10 Controls ...................................................................... 7 3.3.2.3 Selection of PM10 Control Technology to Meet BACT/BAT .................................................. 8

3.3.3 Carbon Monoxide (CO) and Volatile Organic Compounds (VOC) ......................................... 8 3.3.3.1 Identification of Similar Facilities with BACT/BAT for CO and LAER/BAT for VOC ........ 8 3.3.3.2 Identification and Evaluation of CO and VOC Controls ......................................................... 9 3.3.3.3 Selection of CO and VOC Control Technology to Meet BACT/LAER/BAT ....................... 10

3.3.4 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ........................................................... 10 3.3.4.1 Identification of Similar Facilities with BACT/BAT for SO2/H2SO4 .................................... 11 3.3.4.2 Identification and Evaluation of SO2/H2SO4 Controls ........................................................... 11 3.3.4.3 Selection of SO2/H2SO4 Control Technology to Meet BACT/BAT ...................................... 11

3.3.5 Ammonia ................................................................................................................................. 11 3.3.5.1 Identification of Facilities with BAT for Ammonia .............................................................. 11 3.3.5.2 Identification and Evaluation of Ammonia Controls ............................................................. 11 3.3.5.3 Selection of Ammonia Control Technology to Meet BAT .................................................... 12

3.4 BACT/BAT Evaluation For Greenhouse Gas (GHG) Emissions From Powerblocks ........................ 14 3.4.1 Identification and Evaluation of CO2 Control Technologies .................................................. 14 3.4.2 Ranking Of Technically Feasible Options .............................................................................. 15 3.4.3 Selection Of CO2 Control Technology To Meet BACT/BAT ................................................ 16

3.5 BACT/LAER/BAT Determination Auxiliary Boilers ........................................................................ 17 3.5.1 Nitrogen Oxides (NOx) ........................................................................................................... 17

3.5.1.1 Identification of NOx Control Technologies ......................................................................... 17 3.5.1.2 Evaluation of Technically Feasible Control Options ............................................................. 19

FRE 164-304 (PER-02-02-09) REC (08/05/2015) 137575 CD PAGE ii

3.5.1.3 Selection of LAER/BAT for NOx ......................................................................................... 19 3.5.2 Carbon Monoxide (CO) .......................................................................................................... 19

3.5.2.1 Identification of CO Control Technologies ........................................................................... 19 3.5.2.2 Evaluation of CO Control Options ........................................................................................ 20 3.5.2.3 Selection of BACT/BAT for CO ........................................................................................... 23

3.5.3 Volatile Organic Compounds (VOC)...................................................................................... 23 3.5.3.1 Identification of VOC Control Technologies ........................................................................ 23 3.5.3.2 Evaluation of VOC Control Options ..................................................................................... 23 3.5.3.3 Selection of LAER/BAT for VOC......................................................................................... 23

3.5.4 Particulate Matter (PM) .......................................................................................................... 24 3.5.4.1 Identification of PM Control Technologies ........................................................................... 24 3.5.4.2 Evaluation of PM Control Options ........................................................................................ 25 3.5.4.3 Selection of BAT for PM ....................................................................................................... 25

3.5.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ........................................................... 25 3.5.5.1 Selection of BACT/BAT for SO2 and H2SO4 ........................................................................ 26

3.5.6 Identification of BACT for Greenhouse Gas (GHG) Emissions ............................................. 26 3.6 BACT/LAER/BAT Determination For Emergency Generators And Fire Pump Diesel Engines ...... 27

3.6.1 Identification of Sources with BACT/LAER/BAT ................................................................. 28 3.6.2 Selection of BACT/LAER/BAT For Emergency Generators And Fire Pump Engine ........... 31

3.7 BACT/LAER/BAT Determination Water Bath Heater ...................................................................... 34 3.7.1 Nitrogen Oxides (NOx) ........................................................................................................... 34

3.7.1.1 Identification of NOx Control Technologies ......................................................................... 34 3.7.1.2 Evaluation of Technically Feasible Control Options ............................................................. 35 3.7.1.3 Selection of LAER/BAT for NOx ......................................................................................... 35

3.7.2 Carbon Monoxide (CO) .......................................................................................................... 35 3.7.2.1 Identification of CO Control Technologies ........................................................................... 36 3.7.2.2 Evaluation of CO Control Options ........................................................................................ 36 3.7.2.3 Selection of BACT/BAT for CO ........................................................................................... 36

3.7.3 Volatile Organic Compounds (VOC)...................................................................................... 37 3.7.3.1 Identification of VOC Control Technologies ........................................................................ 37 3.7.3.2 Evaluation of VOC Control Options ..................................................................................... 37 3.7.3.3 Selection of LAER/BAT for VOC......................................................................................... 37

3.7.4 Particulate Matter (PM) .......................................................................................................... 37 3.7.4.1 Identification of PM Control Technologies ........................................................................... 37 3.7.4.2 Evaluation of PM Control Options ........................................................................................ 38 3.7.4.3 Selection of BAT for PM ....................................................................................................... 38

FRE 164-304 (PER-02-02-09) REC (08/05/2015) 137575 CD PAGE iii

3.7.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4) ........................................................... 38 3.7.5.1 Selection of BACT/BAT for SO2 and H2SO4 ........................................................................ 38

3.7.6 Identification of BACT for Greenhouse Gas (GHG) Emissions ............................................. 39 3.8 High Voltage Circuit Breakers Equipment Leaks BACT/BAT Analysis ........................................... 40 3.9 BACT/LAER/BAT Determination for ULSD Storage Tank .............................................................. 42

3.9.1 Identification of Sources with BACT/LAER/BAT ................................................................. 42 3.9.2 Selection of BACT/LAER/BAT for ULSD Storage Tank ...................................................... 42

POWER ENGINEERS, INC. BACT/LAER/BAT Analysis for Renovo Energy Center, Renovo, PA


3.1 Introduction Renovo Energy Center, LLC (REC) is submitting an air permit application for the installation of a nominally rated 950 MW (net) combined cycle electric generating plant to be located in Renovo, Pennsylvania. The electric generating plant will consist of two 1x1x1 combined cycle powerblocks, each consisting of a combustion turbine, HRSG, and a steam turbine. Currently, REC is considering equipment from three Original Equipment Manufacturers (OEMs) to be included in the facility’s final design. The OEMs include General Electric (GE), Siemens Energy, Inc. (Siemens), and Mitsubishi Hitachi Power Systems Americas, Inc. (MHPSA). Due to pricing, performance, and delivery schedule, a final decision on the preferred OEM will not be made before a Pennsylvania Department of Environmental Protection (PaDEP) plan approval may be issued. The proposed plant also will include for each powerblock an auxiliary boiler, emergency generator, turbine inlet air conditioner, and air-cooled condenser. REC also will have a natural gas-fuel heater and a fire water pump engine. The combustion turbines will fire primarily natural gas, ULSD fuel as back-up. The auxiliary boilers and natural gas-fuel heater will fire on pipeline quality natural gas, while the emergency generators and fire water pump engine will fire ULSD. REC is classified as a major stationary source due to allowable 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 3.1-1 presents REC’s calculated allowable (potential) emissions in comparison to the regulatory thresholds, and indicates what levels of control are required.

Table 3.1-1: Comparison of Maximum Allowable Emissions to Significant Allowable Emissions

Pollutant

GE Maximum Allowable Emissions (tons/yr)

Siemens Maximum Allowable Emissions (tons/yr)

MHPSA Maximum Allowable Emissions (tons/yr)

Significant Allowable Emissions (tons/yr)

BACT, LAER, or BAT Required?

Nitrogen Oxides (NOx) 344.6 366.0 267.5 100 BACT/LAER/BAT Carbon Monoxide (CO) 434.1 703.9 1,138.7 100 BACT/BAT Volatile Organic Compounds (VOC) 112.7 179.8 504.3 50 BACT/LAER/BAT Particulate Matter (PM/PM10/PM2.5) 157.7 167.6 138.6 15/10 BACT/BAT Sulfur Dioxide (SO2) 39.2 38.0 17.4 40 BACT/BAT Sulfuric Acid (H2SO4) 27.6 13.4 32.4 7 BACT/BAT Ammonia (NH3) 200.2 199.5 200.3 N/A BAT Greenhouse Gases (CO2e) 3,818,129 3,654,456 3,519,749 100,000 BACT/BAT

As shown in Table 3.1-1, regardless of which OEM is chosen, REC’s maximum allowable emissions of NOx, CO, PM, PM10, SO2, VOC, and Ammonia exceed significant allowable emission levels and therefore BACT, LAER, and/or BAT must be applied. Potential greenhouse gas (GHG) emissions expressed as CO2 equivalents from REC’s combustion sources exceed the significant threshold established by EPA in 40 CFR 51.166, therefore a BACT evaluation for GHG emissions is included in this section.



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 impact is 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 and BACT, 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 gathered 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 Powerblocks REC is proposing to install two identical combined cycle powerblocks that will each consist of one combustion turbine, one HRSG, 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. In addition to the combustion turbines, the Siemens and MHPSA proposals include natural gas-fired duct burners for supplemental heat to the HRSGs. The GE proposal does not include duct burners. Included in each OEM’s proposal are dry low-NOx (DLN) burners and Selective Catalytic Reduction (SCR) systems for control of NOx, as well as oxidation catalysts for control of CO and VOCs. The SCR systems and oxidation catalysts allow 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 for each OEM selection:



Table 3.2-1: Proposed BACT/LAER/BAT for Combined Cycle Powerblocks

Pollutant Permit Limits for Each OEM1 Control

Level Compliance Method GE Siemens MHPSA NOx 2.0 ppm (NG)

6.0 ppm (ULSD) 2.0 ppm (NG)

6.0 ppm (ULSD) 2.0 ppm (NG)

4.0 ppm (ULSD) LAER Initial stack test, CEMS 3-hour block average

CO 2.0 ppm (NG & ULSD)

2.0 ppm (NG) 4.0 ppm (ULSD)

2.0 ppm (NG) 6.0 ppm (ULSD) BACT Initial stack test, CEMS 24-

hour block average

VOC 1.0 ppm (NG) 2.0 ppm (ULSD)

1.0 ppm (NG & ULSD)2

2.8 ppm (NG)3

1.5 ppm (NG) 5.0 ppm (ULSD) LAER Initial stack test

PM10 0.0078 lb/MMBtu

(NG) 0.036 lb/MMBtu

(ULSD)

0.006 lb/MMBtu (NG)

0.018 lb/MMBtu (ULSD)

0.0071 lb/MMBtu (NG)

0.013 lb/MMBtu (ULSD)

BACT Initial stack test, fuel sulfur content monitoring/supplier

certifications

SO2 0.4 gr S/100scf

(NG) 0.0015% S

(ULSD)

0.4 gr S/100scf (NG)

0.0015% S (ULSD)

0.4 gr S/100scf (NG)

0.0015% S (ULSD)

BACT Fuel sulfur content monitoring/supplier

certifications

Ammonia 5.0 ppm (NG & ULSD)

5.0 ppm (NG & ULSD)

5.0 ppm (NG & ULSD) BAT CEMS 3-hour block

average GHG (CO2)

1,000 lb/MW-hr BACT CEMS for CO2, 12-month block average

1ppm on dry volume basis, corrected for 15% oxygen 2Without duct firing 3With duct firing

3.3 BACT/LAER/BAT Determinations For Combined Cycle Powerblocks 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 applications, and identifies similar facilities that allow for comparisons to determine the LAER rate that will be required, as well as the appropriateness of the control technology selected for this project. 3.3.1.1 Identification of Similar Facilities with LAER/BAT for NOx

Table 3.3-1: LAER/BAT for NOx

Facility Name

Facility size

(MW) Permit Date

Fuel Type(s)

NOx Emission

Limit (ppm) Averaging

Period NOx

Controls Liberty Generation Plant 916-944 1/31/2013 NG 2.0 1-hour SCR

Patriot Generation Plant 916-944 12/13/2013 NG 2.0 SCR

Westmoreland Generating Station

930-1,065 4/1/2015 NG 2.0 3-hour SCR

Garrison Energy Center 309 1/30/2013 NG,

ULSD 2.0 (NG)

6.0 (ULSD) 1-hour1 3-hour2 SCR, WI3



Facility Name

Facility size

(MW) Permit Date

Fuel Type(s)

NOx Emission

Limit (ppm) Averaging

Period NOx

Controls Caithness Bellport Energy Center 346 5/10/2006 NG,

ULSD 2.0 (NG)

6.0 (ULSD) 3-hour SCR, WI3

Kleen Energy Systems, LLC 620 7/2/2013 NG,

ULSD 2.0 (NG)

5.9 (ULSD) 1-hour SCR, WI3

Cape Canaveral Energy Center 1,250 1/1/2015 NG,

ULSD 2.0 (NG)

8.0 (ULSD) 30 days SCR, WI3

Riviera Beach Energy Center 1,250 1/1/2015 NG,

ULSD 2.0 (NG)

8.0 (ULSD) 30 days SCR, WI3

Warren County Power Station 1,329 6/17/2014 NG 2.0 1-hour SCR

Empire Power Plant 645 7/1/2014 NG, ULSD

2.0 (NG) 9.0 (ULSD) 3-hour SCR, WI3

1Firing natural gas, base load only 2Firing natural gas or ULSD, non-base loads 3WI = wet injection

3.3.1.2 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 also has a relatively low flame temperature in comparison to other fuel sources. The proposed combined cycle powerblocks 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. Each of the three OEM design options under consideration 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 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. Each of the three OEM design options under consideration utilize 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 for any of the three OEM equipment options under consideration.

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 EMX

TM/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 injection 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 each of the three OEM equipment options.

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

The presence of the catalyst (typically made from 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 more than meets this 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.

EMX

TM/SCONOXTM

EMX

TM (formerly known as SCONOXTM) 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, EMX

TM has only been installed in several small powerplants in California (all below 43 MW), and thus is considered technically infeasible for each of the three OEM equipment options. 3.3.1.3 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 DLN combustors, as well as wet injection when firing ULSD. The most stringent limit demonstrated when firing natural gas is 2 ppmvd @ 15% O2 (by numerous facilities), and when firing ULSD is 6 ppmvd @ 15% O2. While Garrison Energy Center has been permitted with a 6 ppm NOx emission limit when firing ULSD, the facility has not begun operation yet and thus the achievability of the emission limit has not yet been determined. Caithness Bellport Energy Center and Kleen Energy Systems, LLC, however, have been commercially operating under 6 ppm and 5.9 ppm NOx emission limits respectively when firing ULSD, and thus represent LAER for NOx when firing ULSD. REC therefore proposes to meet LAER for NOx through the use of combustion controls, SCR, and water injection when firing ULSD. For the GE equipment, REC proposes a NOx emission limit of 2 ppmvd @ 15% O2 based on a 3-hour block average when firing natural gas, and 6 ppmvd @ 15% O2 based on a 3-hour block average when firing ULSD. For the Siemens equipment, REC proposes a NOx emission limit of 2 ppmvd @ 15% O2 based on a 3-hour block average when firing natural gas, and 6 ppmvd @ 15% O2 based on a 3-hour block average when firing ULSD. For the MHPSA equipment, REC proposes a NOx emission limit of 2 ppmvd @ 15% O2 based on a 3-hour block average when firing natural gas, and 4 ppmvd @ 15% O2 based on a 3-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 powerblocks 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 that allow for comparisons to determine BACT for this project. 3.3.2.1 Identification of Similar Facilities with BACT/BAT for PM10

Table 3.3-2: Facilities with BACT/BAT for PM10

Facility Name

Facility size

(MW) Permit Date

Fuel Type(s)

PM Emission Limit

(lb/MMBtu) PM10 Controls Liberty Generation Plant 916-944 1/31/2013 NG 0.0057 Air filters, good

combustion, clean fuels

Patriot Generation Plant 916-944 12/13/2013 NG 0.0057 Air filters, good combustion, clean fuels

Westmoreland Generating Station

930-1,065 4/1/2015 NG 0.0039 Good combustion, clean

fuels

Garrison Energy Center 309 1/30/2013 NG, ULSD

0.018 (NG) 0.030 (ULSD) Clean fuels

Caithness Bellport Energy Center 346 5/10/2006 NG,

ULSD 0.0055 (NG)

0.051 (ULSD) Clean fuels

Kleen Energy Systems, LLC 620 7/2/2013 NG, ULSD

0.0071 (NG) 0.027 (ULSD) Clean fuels

Warren County Power Station 1,329 6/17/2014 NG 0.0027 Clean fuels


ULSD n/a Clean fuels

Riviera Beach Energy Center 1,250 1/1/2015 NG, ULSD n/a Clean fuels

Thetford Generating Station 700 7/25/2013 NG 0.0033 Air filters, good combustion, clean fuels

3.3.2.2 Identification and Evaluation of PM10 Controls PM10 control devices applicable to dual fired combined cycle powerblocks include combustion control, 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 and were not identified in any of the RBLC entries or other permits as control devices for combustion turbines, whether fired on natural gas or ULSD. The highest level of particulate matter control for a dual fired combined cycle powerblock 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.



The lowest permit value for total PM (filterable and condensable) when firing natural gas is 0.0027 lb/MMBtu at the Warren County Power Station in Virginia, and when firing ULSD is 0.028 lb/MMBtu at Kleen Energy Systems, LLC, in Connecticut. Both of these facilities have been successfully operating under this emission limit.

3.3.2.3 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 for the GE equipment is 0.0072 lb/MMBtu when firing natural gas, and 0.036 lb/MMBtu when firing ULSD. The proposed PM emission limit for the Siemens equipment is 0.006 lb/MMBtu when firing natural gas, and 0.018 lb/MMBtu when firing ULSD, and the proposed limit for the MHPSA equipment is 0.0046 lb/MMBtu when firing natural gas, and 0.013 when firing ULSD. Compliance with these limits will be based on initial stack testing and 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 powerblocks are the result of incomplete combustion. In particular, CO emissions are exacerbated by low oxygen availability, poor mixing of air and fuel, low combustion temperatures, and low residence time in the combustion zone. VOC emissions are the result of low combustion temperatures and low combustion zone residence times. The following section describes control technologies that can be applied to reduce CO and VOC emissions from combined cycle powerblock applications, and identifies similar facilities that allow for comparisons to determine the lowest achievable emission rate and/or best available control technology that will be required. 3.3.3.1 Identification of Similar Facilities with BACT/BAT for CO and LAER/BAT for VOC

Table 3.3-3: Facilities with BACT/BAT for CO

Facility Name

Facility size

(MW) Permit Date

Fuel Type(s)

CO Emission Limit (ppm)

Averaging Period CO Controls

Liberty Generation Plant 916-944 1/31/2013 NG 2.0 1-hour Oxidation

Catalyst Patriot Generation Plant 916-944 12/13/2013 NG 2.0 Oxidation

Catalyst Westmoreland Generating Station 930-1,065 4/1/2015 NG 2.0 3-hour Oxidation

Catalyst Garrison Energy Center 309 1/30/2013 NG,

ULSD 3.0 (NG)

6.0 (ULSD) 1-hour Oxidation Catalyst

Caithness Bellport Energy Center 346 5/10/2006 NG,

ULSD 2.0 (NG)

2.0 (ULSD) 1-hour Oxidation Catalyst


ULSD 0.9 (NG w/o DB)

1.8 (ULSD w/o DB) 1-hour Oxidation Catalyst


ULSD

5.0 (NG w/o DB) 7.6 (NG w/DB) 10.0 (ULSD)

30 days Good Combustion


ULSD

5.0 (NG w/o DB) 7.6 (NG w/DB) 10.0 (ULSD)

30 days Good Combustion

Pinecrest Energy Center 700 11/12/2013 NG 2.0 3-hour Oxidation

Catalyst



Facility Name

Facility size

(MW) Permit Date

Fuel Type(s)

CO Emission Limit (ppm)

Averaging Period CO Controls

Warren County Power Station 1,329 6/17/2014 NG 1.5 (w/o DB)

2.4 (W/DB) 1-hour Oxidation

Catalyst, Good Combustion

Thetford Generating Station 700 7/25/2013 NG 4.0 24-hour

Oxidation Catalyst, Good

Combustion

Table 3.3-4: Facilities with LAER/BAT for VOC

Facility Name Facility size

(MW) Permit Date

Fuel Type(s)

VOC Emission Limit (ppm) VOC Controls

Liberty Generation Plant 916-944 1/31/2013 NG 1.0 (w/o DB) 1.5 (w/DB) Oxidation Catalyst

Patriot Generation Plant 916-944 12/13/2013 NG 1.0 (w/o DB) 1.5 (w/DB) Oxidation Catalyst

Westmoreland Generating Station 930-1,065 4/1/2015 NG 1.4 (w/o DB)

2.4 (w/DB) Oxidation Catalyst

Garrison Energy Center 309 1/30/2013 NG, ULSD

0.8 (NG w/o DB) 1.4 (NG w/DB)

1.6 (ULSD) Oxidation Catalyst


ULSD 5.0 (NG w/o DB)

3.6 (ULSD w/o DB) Oxidation Catalyst


ULSD

1.5 (NG w/o DB) 1.9 (NG w/DB)

6.0 (ULSD) Good Combustion


ULSD

1.5 (NG w/o DB) 1.9 (NG w/DB)

6.0 (ULSD) Good Combustion

Warren County Power Station 1,329 6/17/2014 NG 0.7 (w/o DB)

1.6 (w/DB) Oxidation Catalyst, Good Combustion

FPL West County Energy Center 1,250 1/10/2007 NG 1.2 (w/o DB)

1.5 (w/DB) Good combustion

Empire Power Plant 635 7/1/2014 NG, ULSD

1.0 (NG w/o DB) 7.0 (NG w/DB)

2.0 (ULSD w/o DB) 12.0 (ULSD w/DB)

Oxidation Catalyst

3.3.3.2 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 turbine powerblocks consist of oxidation catalysts and combustion controls. 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. CO 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 location of 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 outside what would be expected of a properly located oxidation catalyst.



3.3.3.3 Selection of CO and VOC Control Technology to Meet BACT/LAER/BAT The most effective control for CO and VOC is an oxidation catalyst in combination with good combustion. The lowest permitted CO emission limit when firing natural gas without duct firing is 0.9 ppm at Kleen Energy Systems, LLC. With duct firing, the lowest permitted emission limit for CO is 1.4 ppm at the Garrison Energy Center, which has not yet been constructed. The lowest permitted VOC emission limit when firing natural gas without duct firing is 0.7 ppm at the Warren County Power Station. For natural gas fuel with duct firing, the lowest permitted VOC emission limit is 1.4 ppm at the Garrison Energy Center, which has yet to be constructed. The Warren County Power Station’s VOC emission limit when firing natural gas with duct firing is 1.6 ppm, however, the West County Energy Center’s VOC emission limit of 1.5 ppm without duct firing is lower. Personnel at the Warren County Power Station have indicated that the limits have been difficult to meet due to the short averaging period (1-hour), and the facility has only been commercially operable since December of 2014. The 1-hour averaging period has not allowed adequate time for tuning, and a considerable effort is being made to attempt emissions compliance during these periods. The equipment selection at the Warren County Power Station is also not identical to the three different OEM equipment options for this project. The lowest permitted VOC emission limit when firing ULSD is 1.6 ppm at the Garrison Energy Center, which has yet to be constructed. The Empire Power Plant, commercially operating since 2010, operates under a VOC emission limit of 2 ppm when firing ULSD without duct firing. While the Empire Power Plant consists of similar equipment to the proposed project, the equipment is not identical. REC will meet BACT for CO and LAER for VOC through the use of good combustion practices in combination with an oxidation catalyst for each OEM option. For the GE equipment, REC is proposing a CO limit of 2 ppmvd @ 15% O2 when firing natural gas or ULSD, and a VOC limit of 1 ppmvd @ 15% O2 when firing natural gas, and 2 ppmvd @ 15% O2 when firing ULSD. For the Siemens equipment, REC is proposing a CO limit of 2 ppmvd @ 15% O2 when firing natural gas and 4 ppmvd @ 15% O2 when firing ULSD, and a VOC limit of 1 ppmvd @ 15% O2 when firing both fuels with no duct firing. When the duct burners are firing natural gas in addition to the combustion turbine firing, a VOC limit for the Siemens equipment of 2.8 ppmvd @ 15% O2 is being proposed. For the MHPSA equipment, REC is proposing a CO limit of 2 ppmvd @ 15% O2 and a VOC limit of 1.5 ppmvd @ 15% O2 when firing natural gas, and a CO limit of 6 ppmvd @ 15% O2 and a VOC limit of 5 ppmvd @ 15% O2 when firing ULSD. Compliance with the CO limit will be based on a 24-hour block average using a CEMS and compliance with the VOC limit will be demonstrated with initial stack testing.

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, and from natural gas and ULSD combustion turbines 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 powerblock applications, and identifies similar facilities that allow for comparisons to determine the best available control technology that will be required.



3.3.4.1 Identification of Similar Facilities with BACT/BAT for SO2/H2SO4

Table 3.3-5: Facilities with BACT/BAT for SO2


(MW) Permit Date

Fuel Type(s)

SOx Emission Limit SOx Controls

Liberty Generation Plant 916-944 1/31/2013 NG 0.4 gr S/100 scf (NG) Low sulfur fuel Patriot Generation Plant 916-944 12/13/2013 NG 0.4 gr S/100 scf (NG) Low sulfur fuel Westmoreland Generating Station 930-1,065 4/1/2015 NG 0.25 gr S/100 scf (NG) Low sulfur fuel

3.3.4.2 Identification and Evaluation of SO2/H2SO4 Controls The primary means for controlling emissions of SO2 and H2SO4 from dual fired combustion turbine powerblocks 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 powerblock 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. 3.3.4.3 Selection of SO2/H2SO4 Control Technology to Meet BACT/BAT

The fuel to be used in REC’s combustion turbine powerblocks 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 for back-up fuel for each of the three OEM equipment options. A sulfur content limit of 0.25 gr S/100scf of gas is not appropriate for REC because of uncertainties and fluctuations in the local natural gas supply. Compliance will be demonstrated with fuel sulfur content monitoring and fuel supplier certifications. 3.3.5 Ammonia Ammonia will be emitted from the combined cycle powerblocks 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 powerblocks, 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 powerblocks that employ SCR technology. 3.3.5.1 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. 3.3.5.2 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 powerblocks similar in nature to this project. 3.3.5.3 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 and NOx emissions in order to optimize the SCR efficiency. REC is proposing an ammonia slip limit of 5 ppm when firing natural gas or ULSD for all of the OEM equipment options. 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 powerblocks. During startup and/or shutdown (SUSD) of the powerblocks, 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 Attachment D. 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 emission limits that are both stringent during steady-state operations and achievable during SUSD scenarios. Tables 3.3-6 and 3.3-7 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 3.3-6: SUSD Emission Limits for Each OEM per Powerblock – Natural Gas OEM: GE Siemens MHPSA Cold Starts Time (min.) 90 90 180 NOx Emissions (lbs/event) 398 268 211 CO Emissions (lbs/event) 746 1,624 5,475 VOC Emissions (lbs/event) 92 186 2,240 Warm Starts Time (min.) 90 90 140 NOx Emissions (lbs/event) 322 320 161 CO Emissions (lbs/event) 834 1,533 4,234 VOC Emissions (lbs/event) 104 172 1,869 Hot Starts Time (min.) 75 75 75 NOx Emissions (lbs/event) 297 267 118 CO Emissions (lbs/event) 1,370 2,127 4,473 VOC Emissions (lbs/event) 169 286 1,814 Shutdowns Time (min.) 30 30 30 NOx Emissions (lbs/event) 18 144 73 CO Emissions (lbs/event) 403 447 1,572 VOC Emissions (lbs/event) 198 179 812

Table 3.3-7: SUSD Emission Limits for Each OEM per Powerblock – ULSD OEM: GE Siemens MHPSA Cold Starts Time (min.) 90 90 180 NOx Emissions (lbs/event) 482 348 315 CO Emissions (lbs/event) 418 4,987 5,436 VOC Emissions (lbs/event) 33 552 1,801 Warm Starts Time (min.) 90 90 140 NOx Emissions (lbs/event) 502 373 248 CO Emissions (lbs/event) 463 5,193 4,583 VOC Emissions (lbs/event) 35 580 1,637 Hot Starts Time (min.) 75 75 75 NOx Emissions (lbs/event) 590 315 244 CO Emissions (lbs/event) 726 4,063 7,392 VOC Emissions (lbs/event) 50 529 1,934 Shutdowns Time (min.) 30 30 30 NOx Emissions (lbs/event) 33 187 135 CO Emissions (lbs/event) 70 609 1,706 VOC Emissions (lbs/event) 17 245 553



3.4 BACT/BAT Evaluation For Greenhouse Gas (GHG) Emissions From Powerblocks 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 powerblocks. 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. The instability of the Clean Power Plan’s deployment also leads to considerable uncertainty.

• Aggregation of pore space for geologic storage on private lands. • 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 considering the most efficient gas turbines offered by each of the three OEMs included in this application, 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 powerblocks will be equipped with a continuous emissions monitoring system that will include monitoring for oxygen, a key parameter n 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 3.3-8: CO2 Emission Factors for Various Fuel Types

Fuel Type CO2 Content in

kg/MMBtu1 Coal 95.52

Residual Fuel Oil 75.10 Distillate Fuel Oil 73.96

Natural Gas 53.06 Relative to solid and liquid fuels, 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. 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’s combined cycle powerblock will implement good operating and maintenance practices and 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 powerblocks. 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 difficult 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 1,000 lb/MW-hr of CO2 for each of the three OEM equipment options, to be demonstrated with a CEMS based on a 12-month block average.



3.5 BACT/LAER/BAT Determination Auxiliary Boilers REC is proposing to install two auxiliary “package” boilers each with a maximum rated heat input of 30 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 150,000 MMBtu per year for both boilers.

3.5.1 Nitrogen Oxides (NOx)

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.

3.5.1.1 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 3.5-1 below identifies the facilities in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.5-1: Identification of Sources with BACT/LAER/BAT for NOx

Facility Name Boiler Size

(MMBtu/hr) Permit Date NOx Emissions

Limit NOx Controls Caithness Bellport Energy Center Suffolk, NY

29.4 5/10/2006 0.011 lb/MMBtu Low NOx Burner and FGR

Avenal Energy Project, Kings, CA 37.4 6/21/2011

9 ppm (approx. equivalent to 0.011

lb/MMBtu)

ULNB, PUC quality natural gas and fuel

usage limit

Victorville 2 Hybrid Project San Bernardino, CA

35 3/11/2010 9 ppm (approx.

equivalent to 0.011 lb/MMBtu)

Low NOx burner and good

combustion practices

Hickory Run Energy Station Lawrence, PA 40 4/23/2013 0.011 lb/MMBtu Low NOx burner

Berks Hollow Energy Association Berks, 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 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.



3.5.1.2 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 30 MMBtu/hr size range that are equipped with SCR. In addition, SCR is not an economically feasible option for boilers of this size and limited use and the use of low/ultra-low NOx burners/FGR can achieve an emission rate comparable to that of SCR.

3.5.1.3 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 9 ppm which is approximately equivalent to 0.011 lb/MMBtu. In addition, REC will limit total fuel use to 150,000 MMBtu per year.

3.5.2 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 compromise 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 oxidation catalyst.

The table below identifies CO controls and limits for facilities with natural gas fired auxiliary boilers in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.5-2: Identification of Sources with BACT/LAER/BAT for CO

Facility name Boiler size MMBtu/hr Permit date CO Emissions Limit CO Controls

IPL – Sutherland Generating Station Marshalltown, IA

60.1 4/14/2014 0.0164 lb/MMBtu Oxidation catalyst

Caithness Bellport Energy Center Suffolk, NY

29.4 5/10/2006 0.036 lb/MMBtu Good combustion practices

Hickory Run Energy Station Lawrence, PA 40 4/23/2013 0.036 lb/MMBtu Good combustion

practices Berks Hollow Energy Association Berks, PA

40 12/17/2013 0.036 lb/MMBtu Good combustion practices

Sierra Pacific Power Co Tracy Substation Expansion Project Storey County, NV




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 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.

3.5.2.2 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 70%. The total capital cost estimate is presented in Table 3.5-3 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 3.5-4.



Table 3.5-3 Oxidation Catalyst Capital Expenses1

EQUIPMENT COSTS

Oxidation Catalyst $5,000 Frame and Housing $15,000 Total System (A) $20,000 Freight (0.05A) $1,000 Taxes (0.05A) $1,000 Total purchased equipment cost (B): $22,000 DIRECT INSTALLATION COSTS Foundations and Supports (0.08B) $1,760 Handling and Erection (0.14B) $3,080 Electrical (0.01B) $220 Total direct installation cost: $5,060 Total Direct Cost: $27,060 INDIRECT COSTS (INSTALLATION) Engineering and Supervision (0.10B) $2,200 Construction and Field Expenses (0.05B) $1,100 Contractor Fees (0.10B) $2,200 Startup (0.02B) $440 Performance Test (0.01B) $220 Contingencies (0.03B) $660 Total Indirect Cost: $6,820 Total Capital Investment (TCI): $33,880

1 Attachment H contains cost calculation sheets



Table 3.5-4 Oxidation Catalyst Annual Operating Costs2

DIRECT ANNUAL COST

Operating Labor --- Supervisory Labor --- Maintenance Labor and Materials $2,250 Catalyst Replacement (3 year life, 7% interest) $1,734 Spent Catalyst Handling ---- Performance Loss $636 Total direct annual cost: $4,620 INDIRECT ANNUAL COSTS Overhead (60% total labor and materials) $1,350 Administrative Charges (0.02 TCI) $678 Insurance (0.01 TCI) $339 Capital Recovery (10 year at 7% interest) $3,215 (TCI - replacement cost of catalyst = 72,047) (72,047*0.1424) Total indirect annual cost: $5,582 Total Annual Costs $10,201 AVERAGE COST EFFECTIVENESS CO Emissions Removed (tons/year) 0.98 Cost Effectiveness (dollars/ton CO removed) $10,463

Based on the cost analysis shown in Tables 3.5-3 and 3.5-4, the average cost effectiveness of an oxidation catalyst equals $10,463 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 creates a pressure drop across the combustion chamber and requires 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 kW3

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 0.98 tons per year in the project area does not justify the application of an oxidation catalyst.

x 2,500 hours per year = 9,475 kW-hours/year

2 Attachment H contains cost calculations sheets 3 Power requirement calculated based on a pressure drop of 3 psia.



3.5.2.3 Selection of BACT/BAT for CO

The energy, economic, and environmental impacts of an oxidation catalyst do not support its selection as BACT/BAT. REC proposes good combustion practices and a CO limit of 0.036 lb/MMBtu as BACT/BAT for the auxiliary boilers.

3.5.3 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 3.5-5: 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 40 4/23/2013 0.0015 lb/MMBtu Good combustion

practices Berks Hollow Energy Association Berks, PA




Troutdale Energy Center Multnomah, OR 39.8 3/5/2014 0.005 lb/MMBtu Good combustion

practices Tracy Substation Expansion Project Storey County, NV


3.5.3.1 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.

3.5.3.2 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.

3.5.3.3 Selection of LAER/BAT for VOC

REC proposes good combustion practices and effective boiler design for LAER/BAT for the auxiliary boilers. The Hickory Run Energy Station and Berks Hollow Energy emission limit for VOC is significantly 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.

• 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 has determined that 0.0015 lb/MMBtu is not LAER for its auxiliary boilers. REC proposes good combustion practices, effective boiler design, and an emission limit of 0.005 lb/MMBtu as LAER/BAT for its auxiliary boilers.

3.5.4 Particulate Matter (PM)

The table below identifies PM controls and limits for facilities with natural gas fired auxiliary boilers in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.5-6: 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 Ottawa, MI



29.4 5/10/2006 0.0033 lb/MMBtu Low sulfur fuel

Hickory Run Energy Station Lawrence, PA 40 4/23/2013 0.005 lb/MMbtu

Good combustion practices and pipeline

quality natural gas Berks Hollow Energy Association Berks, PA

40 12/17/2013 0.005 lb/MMbtu Good combustion

practices and pipeline quality natural gas



Facility name Boiler size MMBtu/hr Permit date PM Emissions Limit PM Controls

Avenal Energy Project, Kings, CA 37.4 6/21/2011 0.0034 gr/dscf Use of PUC quality

natural gas

3.5.4.1 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 boilers of this size.

3.5.4.2 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 Holland Board of Public Works facility is under construction, therefore the PM emissions limit of 0.0018 lb/MMBtu has not been demonstrated in practice. Also, the emission limit is based on EPA’s AP-42.

3.5.4.3 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 0.0033 lb/MMBtu (filterable) which is the lowest PM/PM10 emission limit demonstrated in practice. 3.5.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4)

The table below identifies SOx 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 3.5-7: Identification of Sources with BACT/LAER/BAT for SO2


SO2 Emissions Limit SO2 Controls



Brunswick County Power Station Brunswick, VA


Hickory Run Energy Station Lawrence, PA 40 4/23/2013 0.0021 lb/MMBtu Low sulfur fuel


40 12/17/2013 0.0021 lb/MMBtu Low sulfur fuel

St. Joseph Energy Center St. Joseph, IN 80 12/3/2012 0.0022 lb/MMBtu Low sulfur fuel




H2SO4 Emissions Limit H2SO4 Controls


60.1 4/14/2014 0.0055 lb/hr (9.15x10-5 lb/MMBtu)

Low sulfur fuel

Oregon Clean Energy Center, Lucas, OH 99 6/18/2013 1.1x10-4 lb/MMBtu Low sulfur fuel

Hickory Run Energy Station Lawrence, PA 40 4/23/2013 0.00048 lb/MMbtu Low sulfur fuel


40 12/17/2013 0.00048 lb/MMbtu Low sulfur fuel

Brunswick County Power Station Brunswick, VA


3.5.5.1 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 fuel use of 150,000 MMBtu per year for both boilers. REC proposes to meet the BACT emission limit for SO2 of 0.0005 lb/MMBtu and the BACT identified emissions limit of 9.15 x 10-5 lb/MMbtu for H2SO4 emissions.

3.5.6 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.



3.6 BACT/LAER/BAT Determination For Emergency Generators And Fire Pump Diesel Engines

REC will operate two emergency diesel generators to supply emergency power for the powerblocks’ critical electrical loads in the event of a power outage. Each generator will be capable of producing approximately 750 kW of electricity that will require an engine rated at approximately 1,207 HP (approximately 8.41 MMBtu/hr). 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 250 HP (approximately 1.75 MMBtu/hr) 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 two emergency generator engines and one 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.

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 3.6.1-1, 3.6.1-2, 3.6.1-3, and 3.6.1-4). 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

http://hank.baaqmd.gov/pmt/bactworkbook/default.htm�

http://www.valleyair.org/busind/pto/bact/chapter3.pdf�

http://aqmd.gov/bact/aqmdbactdeterminations.htm�



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.

3.6.1 Identification of Sources with BACT/LAER/BAT Table 3.6-1 provides a summary of the RBLC database findings for NOx; detailed information on each entry is provided in Attachment E.

Table 3.6-1 Identification of Sources with BACT/LAER/BAT for NOx

Facility Name Facility

size (HP) Permit Date

NOx Emission Rate

(g/BHP-hr) Comments Emergency Generator Engines

Cane Island Power Park Osceola, Florida

560-2237 kW 9/8/2008 4.8

Combustion controls NSPS Subpart IIII

standard.

St. Joseph Energy Center St. Joseph, MN 1006, 2012 12/3/2012 4.8

Combustion controls NSPS Subpart IIII Tier 2 standard for NMHC and

NOx.

Langley Gulch Power Payette, ID 750 kW 6/25/2010 4.8


NOx.

International Station Power Plant, Anchorage, AK 1500 kW 3/31/2010 4.8


NOx.

Moxie Energy LLC, Lycoming and Asylum, PA 1464/1474 1/31/2013

12/13/2013 4.93

Combustion controls Nominal emissions data;

not guaranteed by manufacturer.

Emergency Fire Pump Engine


12/13/2013 2.6



St. Joseph Energy Center St. Joseph, MN 371 12/3/2012 3.0


NOx.





NOx Emission Rate

(g/BHP-hr) Comments

Holland Board of Public Works, Ottawa, MI 165 10/17/2013 3.0


NOx.

Thetford Generating Station, Genesee, MI 315 5/8/2013 3.0


NOx.

Victorville Power Project, San Bernardino, CA 135 kW 6/13/2007 3.0


NOx. Table 3.6-2 provides a summary of the RBLC database findings for CO; detailed information on each entry is provided in Attachment E.

Table 3.6-2 Identification of Sources with BACT/LAER/BAT for CO



CO Emission Rate

(g/BHP.-hr) Comments Emergency Generator Engines


12/13/2013 0.13.



Sumpter Power Plant, Wayne, MI 732 11/17/2011 0.31.

Combustion controls Project was not built.

Limit not demonstrated in practice.

St. Joseph Energy Center St. Joseph, MN 1006 12/3/2012 2.6

Combustion controls NSPS Subpart IIII Tier 2

standard.

Ninemile Point Electric Generating, Jefferson, LA 1250 8/16/2011 2.6


standard. Emergency Fire Pump Engine

Avenal Energy Project, Kings, CA 288 6/11/2011 0.447

Combustion controls .Project did not go

forward. Permit was vacated by the courts.

Moxie Energy LLC, Lycoming and Asylum, PA 460/460

1/31/2013 12/13/2013

0.5

Combustion controls Nominal emissions data,

.not guaranteed by manufacturer.

Thetford Generating Station, Genesee, MI 315 5/8/2013 2.6

Combustion controls NSPS .Subpart IIII Tier 2

standard.





CO Emission Rate

(g/BHP.-hr) Comments

Chouteau Power Plant, Mayes, OK 267 6/19/2008

2.6 Combustion controls

NSPS Subpart IIII Tier 2 standard.

Table 3.6-3 provides a summary of the RBLC database findings for VOC; detailed information on each entry is provided in Attachment E.

Table 3.6-3 Identification of Sources with BACT/LAER/BAT for VOC



VOC Emission Rate



12/13/2013 0.01



Ninemile Point Electric Generating, Jefferson, LA 1250 8/16/2011 1 Combustion controls

Langley Gulch Power Payette, ID 750 KW 6/25/2010 4.8


NOx. Emergency Fire Pump Engine


12/13/2013 0.1



Ninemile Point Electric Generating, Jefferson, LA 350 8/16/2011 1 Combustion controls

Langley Gulch Power Payette, ID 235 kW 6/25/2010 3.2


NOx. Table 3.6-4 provides a summary of the RBLC database findings for PM; detailed information on each entry is provided in Attachment E.

Table 3.6-4 Identification of Sources with BACT/LAER/BAT for PM


(HP) Permit Date

PM Emission Rate



12/13/2013 0.02






(HP) Permit Date

PM Emission Rate

(g/BHP-hr) Comments

International Station Power Plant, Anchorage, AK 1500 kW 3/31/2010 0.05 gr/scf

Combustion controls Alaska regulation limits

PM to 0.05 gr/scf for fuel burning equipment.

Sumpter Power Plant, Wayne, MI 732 11/17/2011 0.05

Combustion controls Project was not built.

Limit not demonstrated in practice.

St. Joseph Energy Center St. Joseph, MN 1006, 2012 12/3/2012 0.15


standard.

Ninemile Point Electric Generating, Jefferson, LA 1250 8/16/2011 0.15


standard. Emergency Fire Pump Engine


12/13/2013 0.09



St. Joseph Energy Center St. Joseph, MN 371

12/3/2012 0.15


standard.

Ninemile Point Electric Generating, Jefferson, LA 350

8/16/2011 0.15


standard. 3.6.2 Selection of BACT/LAER/BAT For Emergency Generators And Fire Pump Engine REC is proposing that BACT/LAER/BAT for the emergency generator engines and fire pump engine is state of the art design with good combustion practices and that BACT/LAER/BAT emission limits for NOx, CO, and PM is 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 engines and Tier 3 standards will apply to the fire pump engine. For VOC (HC – hydrocarbons) only, REC proposes an emission limit of 1.0 g/bhr-hr as provided by PaDEP’s General Plan Approval and General Operating Permit for Diesel or No. 2 Fuel-fired Internal Combustion Engines (BAQ-GPA/GP-9) as BACT/LAER/BAT. EPA’s Tier standards for NOx and HC are expressed as one value. Therefore, it is listed as such in the table below. The following table summarizes REC’s proposed BACT/LAER/BAT emission limits for each device.

Table 3.6-5: Summary of Proposed BACT/LAER/BAT

Device NOx and HC

(g/hp-hr) HC

(g/hp-hr) CO

(g/hp-hr) PM

(g/hp-hr) Emergency generator engines 4.8 1.0 2.6 0.15 Fire pump engine 3.0 1.0 2.6 0.15



REC is proposing to limit the operation of each emergency generator engine to 500 hours per year and the operation of the fire pump engine to 250 hours per year. All 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 3.6-6:

Table 3.6-6: Potential Emissions

Device NOx (tpy)

HC (tpy)

CO (tpy)

PM (tpy)

SOx (tpy)

Emergency generator engines 6.39 1.33 3.46 0.20 0.0064 Fire pump engine 0.21 0.07 0.18 0.01 0.0003

Based on the RBLC review, a few facilities have been identified with emission limits that are lower than the NSPS standards. These facilities are Moxie Energy’s two facilities, International Station Power, and Sumpter Power.

Regarding Moxie Energy’s facilities: in the permit applications, Moxie Energy proposed combustion controls and compliance with the NSPS standards as BACT/LAER/BAT for its emergency generator and fire pump engines. Moxie provided vendor specification data with the application. 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 PADEP 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 data from Moxie Energy since it is nominal data and not certified or guaranteed by the manufacturer of the engines.

International Station Power Plant located in Anchorage, Alaska has a 1500 kW emergency generator with diesel engine. The PM limit for the engine is listed in the RBLC database as 0.03 g/hp-hr. This limit was provided in the application by Caterpillar and is also a nominal emission rate. The permit however does not identify 0.03 g/hp-hr as a PM limit. The PM limit for International Station Power Plant’s engine is identified in the permit as 0.05 grains per cubic foot which is well above 0.03 g/hp-hr and the Subpart III Tier 2 standard of 0.15 g/hp-hr.

Sumpter Power Plant proposed in Wayne, MI and Avenal Energy proposed in Kings, CA both have limits in their permits lower than the NSPS standards. Neither one of these projects has or will come to fruition, therefore these lower emission limits have not been demonstrated in practice. REC suspects that non-guaranteed or non-certified data was supplied with the application and was established in the permit as limits. For the reasons mentioned above, REC has determined that the emission limits for Sumpter Power and Avenal Energy do not represent BACT/LAER/BAT for the engines proposed by REC.

In conclusion, REC is proposing to meet BACT/LAER/BAT by complying with EPA’s Tier standards contained in 40 CFR Part 60, Subpart IIII and PaDEP’s VOC limit provided by PaDEP’s General Plan Approval and General Operating Permit for Diesel or No. 2 Fuel-fired Internal Combustion Engines (BAQ-GPA/GP-9). These limits are realistic and obtainable in operation/practice. In addition REC will



limit the operating hours of each emergency generator engine to 500 hours per year and 250 hours per year for the fire pump engine. All 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.



3.7 BACT/LAER/BAT Determination Water Bath Heater REC is proposing to install a water bath heater with a maximum rated heat input of 18 MMBtu/hr firing natural gas. The function of the heater is to heat water 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 it will not be necessary to operate during warmer weather.

3.7.1 Nitrogen Oxides (NOx)

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.

3.7.1.1 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 heaters in a cost-effective manner. The combustion control method available to control thermal NOx on 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 heaters. Table 3.7-1 below identifies the facilities in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.7-1: Identification of Sources with BACT/LAER/BAT for NOx

Facility Name Heater Size (MMBtu/hr) Permit Date

NOx Emissions Limit NOx Controls

Berks Hollow Energy 8.5 12/17/2013 0.035 lb/MMBtu Good combustion practices

Thetford Generating 12 7/25/2013 0.06 lb/MMBtu Low NOx burners

FPL West County Energy 10 1/10/2007 0.095 lb/MMBtu Good combustion practices

Crescent City Power 19 6/6/2005 0.095 lb/MMBtu

Low NOx burners and good

combustion practices

Colusa Generating Station 10 3/11/2011 30 ppm (~0.039 lb/MMBtu)

Good combustion practices



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 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.

3.7.1.2 Evaluation of Technically Feasible Control Options

REC has not identified any heaters in the 18 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.

3.7.1.3 Selection of LAER/BAT for NOx

REC’s heater will be equipped with low NOx burners to achieve an emission limit of 0.04 lb/MMBtu.

3.7.2 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 compromise 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.



3.7.2.1 Identification of CO Control Technologies

There are basically two options for the control of CO emissions from 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 heaters in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.7-2: Identification of Sources with BACT/LAER/BAT for CO

Facility name Heater size MMBtu/hr Permit date CO Emissions Limit CO Controls

Chouteau Power Plant 18.8 1/23/2009 0.39 lb/hr (~0.02 lb/MMBtu) Good combustion

Tracy Substation Expansion Project 4 8/16/2005 0.03 lb/MMBtu Good combustion

Berks Hollow Energy 8.5 12/17/2013 0.05 lb/MMBtu Good combustion Colusa Generating Station 10 3/11/2011 0.079 lb/MMBtu Good combustion FPL West County Energy 10 1/10/2007 0.08 lb/MMBtu Good combustion

Crescent City Power 19 6/6/2005 1.52 lb/hr (~0.08 lb/MMBtu) Good combustion

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 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.

3.7.2.2 Evaluation of CO Control Options

Oxidation catalysts are not an economically feasible option for heaters of this size and REC is not aware of any current installations on heaters equal to or less than 20 MMBtu/hr. Good combustion practices is the BACT/BAT available control option for CO from REC’s heater.

3.7.2.3 Selection of BACT/BAT for CO

REC proposes good combustion practices and a CO limit of 0.08 lb/MMBtu as BACT/BAT for the heater. None of the emission limits from the facilities identified in the RBLC database has been demonstrated in practice.



3.7.3 Volatile Organic Compounds (VOC) The table below identifies VOC controls and limits for facilities with natural gas fired heaters in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.5-5: Identification of Sources with BACT/LAER/BAT for VOC

Facility name Heater size MMBtu/hr Permit date

VOC Emissions Limit VOC Controls

Crescent City Power 19 6/6/2005 0.005 lb/MMBtu Good combustion practices

Thetford Generating 12 7/25/2013 0.008 lb/MMBtu Good combustion practices

Holland Board of Public Works 3.7 12/4/2013 0.03 lb/hr (~0.008

lb/MMBtu) Good combustion

practices


Tracy Substation Expansion Project 4 8/16/2005 0.08 lb/MMBtu Good combustion

practices

3.7.2.1 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 heaters.

3.7.2.2 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.

3.7.2.3 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 heater.

3.7.4 Particulate Matter (PM)

The table below identifies PM controls and limits for facilities with natural gas fired heaters in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.7-6: Identification of Sources with BACT/LAER/BAT for PM

Facility name Heater size MMBtu/hr Permit date PM Emissions Limit PM Controls

Thetford Generating 12 7/25/2013 0.0018 lb/MMBtu 0.007 lb/MMBtu


Colusa Generating Station 10 3/11/2011 0.029 lb/hr (~0.0029 lb/MMBtu)


Chouteau Power Plant 18.8 1/23/2009 0.1 lb/hr (~0.0053 lb/MMBtu)





Facility name Heater size MMBtu/hr Permit date PM Emissions Limit PM Controls

Holland Board of Public Works 3.7 12/4/2013 0.007 lb/MMBtu Good combustion

practices

Crescent City Power 19 6/6/2005 0.14 lb/hr (~0.0074 lb/MMBtu)


3.7.4.1 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 a heater of this size.

3.7.4.2 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 heater of this size. Therefore the only PM control option available for heaters of this size is low sulfur, pipeline quality natural gas and good combustion practices.

3.7.4.3 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 0.0033 lb/MMBtu which is identical to the limit proposed for the natural gas fired auxiliary boilers.

3.7.5 Sulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4)

The table below identifies SO2 and sulfuric acid mist controls and limits for facilities with natural gas fired heaters in EPA’s RBLC with BACT/LAER/BAT limits.

Table 3.7-7: Identification of Sources with BACT/LAER/BAT for SO2

Facility name Heater size MMBtu/hr Permit date SO2 Emissions Limit SO2 Controls

Crescent City Power 19 6/6/2005 0.008 lb/hr (~0.00042 lb/MMBtu)

Low sulfur pipeline natural gas

Chouteau Power Plant 18.8 1/23/2009 0.01 lb/hr (~0.00053 lb/MMBtu) Low sulfur fuel

Berks Hollow Energy 8.5 12/17/2013 0.002 lb/MMBtu FPL West County Energy 10 1/10/2007 2 gr/100 scf

Facility name Heater size MMBtu/hr Permit date

H2SO4 Emissions Limit H2SO4 Controls

Berks Hollow Energy 8.5 12/17/2013 0.001 lb/MMBtu

3.7.5.1 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 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 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.

3.7.6 Identification of BACT for Greenhouse Gas (GHG) Emissions

The only feasible option for reducing GHG emissions from the heater is to use natural gas, which is the fuel with the lowest pollutant emissions.



3.8 High Voltage Circuit Breakers Equipment Leaks BACT/BAT Analysis REC will have eight high voltage circuit breakers within the facility’s electrical switchyard. Four circuit breakers will contain 345 pounds of sulfur hexafluoride (SF6) and the remaining four 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, 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. 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. Evaluation of Control Options The use of vacuum circuit breakers is not a technically feasible option at this time. 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. As 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 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 the growth of SF6 emissions, does not advocated 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”.4

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 Moxie Liberty (Bradford County, PA), Moxie Patriot (Lycoming County, PA), Tenaska Pennsylvania Partners (Westmoreland County, PA), Tampa Electric Company – Polk Power Station (Polk County, FL) and Shady Hills Power Company – Shady Hills Generating Station Project (Pasco County, FL).

4 EPA Partnership for Electric Power Systems, 2014 Annual Report, March 2015



3.9 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. 3.9.1 Identification of Sources with BACT/LAER/BAT Table 3.9-1 provides a summary of the RBLC database findings for VOC; detailed information on each entry is provided in Attachment E.

Table 3.9-1 Identification of Sources with BACT/LAER/BAT for VOC

Facility Name Tank Size (gallons)

Permit Date

Liquid Stored Comments

Progress Bartow Power Plant, FL 3,500,500 1/26/2007 ULSD

Facility must keep records documenting that the true vapor pressure of the liquid

stored is less than 3.5 kPa

FPL West County Energy Center, FL 6,300,000 1/10/2007 ULSD

Facility must keep records documenting that the true vapor pressure of the liquid

stored is less than 3.5 kPa

Lauderdale Plant, FL 3,360,000 6,300,000 3,150,000

4/22/2014 ULSD Use pressure relief valves/vapor condensers or internal floating roof tank

Troutdale Energy Center, LLC, OR 2,200,000 3/5/2014 ULSD Submerged fill line

3.9.2 Selection of BACT/LAER/BAT for ULSD Storage Tank REC is proposing to use an internal floating roof tank (fixed roof) to minimize VOC emissions from the storage of ULSD. With annual emissions of VOC of approximately 0.05 tons, this will effectively limit the emissions of VOC from the ULSD storage tank.

Section 4


Section 4 Ambient Air Quality Impact Analysis Modeling Plan

Table of Contents

4.1 Introduction ....................................................................................................................................... 1 4.2 Applicable Air Quality Standards ..................................................................................................... 1 4.3 Sources .............................................................................................................................................. 2 4.4 Methodologies ................................................................................................................................... 2

4.4.1 Models and Model Options ....................................................................................................... 2 4.4.2 Meteorological Data .................................................................................................................. 2 4.4.3 Terrain Data/Receptor Grid ...................................................................................................... 3 4.4.4 Building Downwash .................................................................................................................. 3 4.4.5 Secondary Formation of PM2.5 .................................................................................................. 3 4.4.6 Increment Analysis ................................................................................................................... 3 4.4.7 Background Air Quality ............................................................................................................ 3 4.4.8 Startup/Shutdown Emissions .................................................................................................... 3 4.4.9 Class I Analysis ......................................................................................................................... 4

4.5 Results of Analyses ........................................................................................................................... 4

POWER ENGINEERS, INC. Ambient Air Quality Impact Analysis Modeling Plan for Renovo Energy Center, Renovo, PA


4.1 Introduction Renovo Energy Center (REC) is proposing to construct a nominally rated 950 MW combined cycle power plant in Renovo, Pennsylvania. Per U.S. Environmental Protection Agency (EPA) regulations, REC is required to conduct an ambient air quality impact analysis (AAQIA) as part of their Prevention of Significant Deterioration/New Source Review (PSD/NSR) air permit application. The following AAQIA modeling plan outlines the methods and assumptions that will be used by REC for demonstrating compliance with National Ambient Air Quality Standards (NAAQS) and Class II Increment Standards. 4.2 Applicable Air Quality Standards All criteria pollutants from REC are required to be included in the AAQIA. In addition to the NAAQS, REC will also be required to demonstrate compliance with Class II Increment Standards. Based on local topography and preliminary screening results, it is anticipated that refined modeling will be required for a project of this scale. Class II Significant Impact Levels (SIL) will be used to determine the extent of the significant impact area inside which other emission sources not associated with REC will be included in the NAAQS analysis. The table below summarizes the applicable ambient air quality standards to be used in the AAQIA.

Table 4.2-1: Applicable Air Quality Standards

Pollutant Averaging

Period NAAQS (μg/m3)

Increment Standard (μg/m3)

Class II SIL

(μg/m3)

SO2

1-hour 1961 N/A 10 3-hour 1,300 512 25

24-hour 365 91 5 Annual 80 20 1

PM10 24-hour 150 90 5

PM2.5 24-hour 352 9 0 Annual 123 4 0

NO2 1-hour 1884 N/A 10 Annual 100 25 1

CO 1-hour 40,000 N/A 2,000 8-hour 10,000 N/A 500

1The 3-year average of the 99th percentile of the daily maximum 1-hour concentration must not exceed standard. 2The 3-year average of the 98th percentile of 24-hour concentrations must not exceed standard. 3Based on the 3-year average of the annual concentrations. 4The 3-year average of the 98th percentile of the daily maximum 1-hour concentration must not exceed standard.

In addition to demonstrating compliance with the NAAQS and Class II Increment, REC will prepare an analysis of the impairment to visibility, soils, and vegetation that would occur as a result of REC’s emissions and general, commercial, residential, industrial and other growth associated with REC will be required, except that an analysis of the impact of vegetation having no significant commercial or recreational value is not required. Also required is an analysis of the air quality impact projected for the area as a result of general commercial, residential, industrial and other growth associated with REC. These analyses will be included in REC’s AAQIA.



4.3 Sources Sources at REC to be included in the air quality impact analysis include the two powerblocks, two auxiliary boilers, two emergency diesel generators, and one emergency fire pump engine. Since REC is in the process of selecting powerblock equipment from one of three original equipment manufacturers (OEM), each of the three powerblock options will be modeled separately. The auxiliary boilers, emergency generators, and fire pump engine will be identical regardless of which powerblock equipment vendor is selected. The following table summarizes the sources to be included in REC’s AAQIA.

Table 4.3-1: REC Emission Sources to be Modeled

Source

Maximum Heat Input Capacity

(MMBtu/hr) Stack ID

Stack Height* (ft agl)

Stack Diameter at

Exit* (ft) GE: CT1 3,558 1 250 21-23 GE: CT2 3,558 2 250 21-23 MHPSA: CT/DB1 3,723 1 250 21-23 MHPSA: CT/DB2 3,723 2 250 21-23 Siemens: CT/DB1 3,472 1 250 21-23 Siemens: CT/DB2 3,472 2 250 21-23 Aux. Boiler 1 30 3 125 2.7 Aux. Boiler 2 30 4 125 2.7 Em. Gen. 1 8.4 5 TBD TBD Em. Gen. 2 8.4 6 TBD TBD Fire Pump 1.75 7 TBD TBD Heater 18 HTR 15 0.7

*Note: All stack heights and diameters are preliminary in nature, and will be refined during the design process.

REC will perform a load case analysis for each OEM option to determine which operational load will result in the highest ambient impacts for each pollutant and averaging period. The load cases resulting in the highest impacts will be used to demonstrate compliance with NAAQS and Class II Increment Standards. 4.4 Methodologies 4.4.1 Models and Model Options EPA’s AERMOD model will be used in REC’s AAQIA, as it is EPA’s preferred model to use for regulatory modeling purposes. The area surrounding the project site is considered rural, thus the rural option will be selected within AERMOD. 4.4.2 Meteorological Data REC is currently in the process of collecting on-site meteorological data for use in REC’s air quality impact analysis. Ambient Air Quality Services, Inc. (AAQS), on behalf of REC, submitted a meteorological monitoring plan to PaDEP on April 27, 2015, which was formally accepted on May 14, 2015 after PaDEP’s comments on the plan were adequately addressed (see Attachment L). Meteorological monitoring will be conducted until a minimum of 12 consecutive months of acceptable data is collected. The data will be processed for use in AERMOD using the latest version of AERMET, and the methods used to process the meteorological data will be outlined in REC’s modeling protocol to be submitted to PaDEP once the meteorological monitoring program is complete.



4.4.3 Terrain Data/Receptor Grid Receptor elevations and hill heights will be determined in AERMAP using a National Elevation Dataset (NED) terrain data file downloaded from the U.S. Geological Survey (USGS) website. The size of the receptor grid will be determined once the meteorological data is available for the SIL analysis. Receptors will be spaced 10 meters apart at REC’s fenceline, and 25 meters apart in the area of maximum impacts. Receptor spacing will increase with distance from the area(s) or maximum impact. 4.4.4 Building Downwash The locations of the emission sources will be used to determine which buildings or structures control the Good Engineering Practice (GEP) stack height. The formula GEP stack height is defined as:

HGEP = Hb 1.5L, where Hb is the height of the building above stack base elevation and L is the lesser of the height above ground level or projected width of the controlling building.

Once building plans are available, REC will use EPA’s BPIP-PRIME algorithm to determine the formula GEP stack height. The preliminary turbine building design indicates a minimum width of approximately 190 feet, and a height of approximately 100 feet above ground level. These preliminary building dimensions indicate HGEP of approximately 250 feet. A copy of all BPIP-PRIME input and output files will be included with the AAQIA. 4.4.5 Secondary Formation of PM2.5 Secondary formation of fine PM2.5 from the emissions of NOx and SO2 contributes to the overall ambient impacts of PM2.5 that will occur from REC’s emission sources. Because REC’s direct PM2.5 emissions are projected to be greater than 10 tons per year and emissions of NOx and/or SO2 are projected to be greater than 40 tons per year, an analysis of both primary and secondary air quality impacts is required, and will be performed as part of REC’s AAQIA. Based on EPA’s Guidance for PM2.5 Permit Modeling (May 2014), a qualitative approach to the analysis of secondary impacts will be sufficient. 4.4.6 Increment Analysis Since REC is a proposed new source, all of REC’s emissions will be considered increment consuming, and compliance with Class II Increment Standards (see Table 4-1) must be met. 4.4.7 Background Air Quality Background air quality values obtained from representative sites will be used for demonstrating compliance with NAAQS. Since REC will be located in an area that is generally free from the impact of other point sources and area sources associated with human activity, monitoring data from a regional site may be used as representative data upon PaDEP approval. 4.4.8 Startup/Shutdown Emissions REC will perform modeling to demonstrate compliance with NAAQS during periods of startup and shutdown (SUSD) of the combustion turbines. During SUSD periods, emission rates of NOx and CO are higher than steady state conditions, and due to the short-term averaging periods, compliance with the 1-



and 8-hr NAAQS must be demonstrated. The SUSD emission rates modeled will be based on the maximum lb/hr value among the various types of SUSD scenarios. For conservatism, the SUSD emission rates will be modeled for the entire year of meteorological data, as SUSD occurrences as well as periods of poor air dispersion are both unpredictable. 4.4.9 Class I Analysis REC’s proposed location is classified as a Class II Area and is approximately 296.8 km northeast of the Dolly Sods Wilderness, the closest Class I Area. REC will communicate with the Federal Land Manager (FLM) for the Dolly Sods Wilderness to determine if an air quality analysis will be required. A typical screening tool used in determining whether proposed sources’ emissions will require a Class I Analysis is a Q/d analysis, where Q represents the combined maximum potential emissions of NOx, SO2, and PM10 in tons per year (tpy), and d represents the distance from the source to the Class I Areas under consideration in kilometers (km). If Q/d is significantly less than 10, a Class I Analysis is typically not required. The table below summarizes the inputs and results of the preliminary Q/d analysis.

Table 4.4-1: Q/d Analysis for Class I Areas OEM: G.E. MHPSA Siemens

NOx Emissions (tpy): 344.6 267.5 366.0 SO2 Emissions (tpy): 39.2 17.4 38.0

PM10 Emissions (tpy): 157.7 138.6 167.6 Q (tpy): 541.5 423.5 571.6

Distance to Dolly Sods Wilderness (km): 296.8 296.8 296.8 Q/d: 1.82 1.43 1.93

As shown in Table 4.4-1, a Class I Analysis is not expected as part of REC’s AAQIA, however this will be confirmed with the FLM at the time AAQIA is prepared. 4.5 Results of Analyses The results of the analyses will be provided to PaDEP in the form of a written report, with all pertinent electronic modeling files included on electronic media.

Section 5

1300-PM-BIT0001 5/2012 Form

Page 1 of 7

COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF ENVIRONMENTAL PROTECTION

GENERAL INFORMATION FORM – AUTHORIZATION APPLICATION Before completing th is Genera l Information Form (GIF), read the s tep-by-s tep ins tructions provided in th is applica tion package. This vers ion of the General Information Form (GIF) mus t be completed and re turned with any program-s pecific applica tion being s ubmitted 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 Berska Barbara Mailing Address Line 1 Mailing Address Line 2 Bechtel Development Company 5275 Westview Drive Address Last Line – City State ZIP+4 Country Frederick MD 21703 USA Client Contact Last Name First Name MI Suffix Franzese Richard P Client Contact Title Phone Ext Director, Development (301) 228-8531 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 62 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

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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 950 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). Project Consultant Last Name First Name MI Suffix Donnelly Timothy J Mr

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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

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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

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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

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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.

GE Option - 344.6 TPY NOx, 434.1 TPY CO, 157.7 TPY PM10, 112.7 TPY VOC, 39.2 TPY SO2, 200.2 TPY NH3, 27.6 TPY H2SO4, 3,818,129 TPY CO2e; Siemens Option - 366.0 TPY NOx, 703.9 TPY CO, 167.6 TPY PM10, 179.8 TPY VOC, 38.0 TPY SO2, 199.5 TPY NH3, 13.4 TPY H2SO4, 3,654,456 TPY CO2e; MHPSA Option - 267.5 TPY NOx, 1,138.7 TPY CO, 138.6 TPY PM10, 504.3 TPY VOC, 17.4 TPY SO2, 200.3 TPY NH3, 32.4 TPY H2SO4, 3,519,749 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.

2700-PM-AQ0007 Rev. 7/2004

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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. Manufacturer GE

Model No. 7HA.02

Number of Sources 2

Source Designation CT1 and CT2

Maximum Capacity 3,353 MMBtu/hr natural gas 3,558 MMBtu/hr ULSD

Rated Capacity 3,196 MMBtu/hr natural gas 3,262 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) Capacity (specify units) - Maximum Per Hour 3,353 MMBtu natural gas 3,558 MMBtu ULSD

Per Day 80,472 MMBtu nat gas 85,392 MMBtu ULSD

Per Week 563,304 MMBtu natural gas 597,744 MMBtu ULSD

Per Year 29,372,280 MMBtu/yr NG 2,704,080 MMBtu/yr 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 occurs at the lowest ambient design temperature (0° F). See detailed performance specifications and emissions calculations presented in Attachment C and Attachment D. Note: maximum per hour, per day, and per week capacities based on 0° F ambient conditions; 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)

175,314 LB/HR @ 60°F

133,238,640 LB/YR

0.0015% by wt

negl 20,295 BTU/LB @ 60 °F

Oil Number

GPH @ 60°F

X 103

Gal

% by wt

Btu/Gal. & Lbs./Gal. @ 60 °F

Natural Gas 145,833 LB/HR

1,277,497,080

LB/YR

0.4 grain/100

SCF

0 22,992 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

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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 unfired heat recovery steam generators

Rated Capacity 3,196 MMBtu/hr (NG) 3,262 MMBtu/hr (ULSD)

Maximum Capacity 3,353 MMBtu/hr (NG) 3,558 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 -

Section B - Processes Information (Continued) 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. Attachment F 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: April 2017 ii. Expected completion date of construction/reconstruction/installation: April 2019 iii. Anticipated date of start-up: May/December 2019

2700-PM-AQ0007 Rev. 7/2004

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Section C - Air Cleaning Device

1. Precontrol Emissions* All emission calculations are contained in Attachment C. Maximum lb/hr is based on worst case operating scenario during normal operation per CT per fuel type. See Attachment C for emission rates during startup and shutdown. Tons per year are based on 8,760 hour per year on natural gas and 760 hours per year on ULSD.

Pollutant

Maximum Emission Rate Calculation/ Estimation

Method Specify Units Pounds/Hour

Gas/ULSD Hours/Year Tons/Year PM 12.21/78.43 8760 53.5/29.8 vendor data PM10 12.21/78.43 8760 53.5/29.8 vendor data SOx 4.49/6.31 8760 19.7/2.4 vendor data CO 69.93/76.55 8760 306.3/29.1 vendor data NOx 318.94/1,050 8760 1,397/399 vendor data VOC 6.22/13.64 8760 27.2/5.2 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 462.1 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 % Moisture

Outlet Volume ACFM

@ °F % Moisture

Describe the system in detail.

2700-PM-AQ0007 Rev. 7/2004

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Section C - Air Cleaning Device (Continued)

10. Selective Catalytic Reduction (SCR) Selective Non-Catalytic Reduction (SNCR) Non-Selective Catalytic Reduction (NSCR) Equipment Specifications Manufacturer TBD

Type TBD

Model No. TBD

Design Inlet Volume (SCFM) 1.0 – 1.3 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 C for detailed calculations and assumptions

Operating Parameters

Volume of gases handled 1.4 – 1.6 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

Describe the warning/alarm system that protects against operation when unit is not meeting design requirements.

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.)

Emissions Data

Pollutant Inlet Outlet Removal Efficiency (%) NOx 25 ppmvd @ 15% O2 2 ppmvd @ 15% O2 ~92% (NG; normal operation)

CO 9 ppm @ 15% O2 2 ppmvd @ 15% O2 ~77.8% (NG; normal operation)

VOC 1.4 ppm @ 15% O2 1 ppmvd @ 15% O2 ~28.6% (NG; normal operation)

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 Attachment H 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 Attachment D

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.

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 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)

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 Attachment K 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 s and Attachment C of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

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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

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Section F - Flue and Air Contaminant Emission

1. Estimated Atmospheric Emissions* All emission calculations are contained in Attachment C. Maximum lb/hr is based on worst case operating scenario during normal operation per CT. See Attachment C for emission rates during startup and shutdown. Tons per year are based on 7,540 hour normal operation on NG, 460 hours of SUSD on NG, 720 hours normal operation on ULSD, and 40 hours of SUSD on ULSD per CT.

Pollutant

Maximum emission rate Calculation/

Estimation Method specify units

Gas/ULSD lbs/hr

Gas/ULSD tons/yr. PM 12.21/78.43 78.47 manufacturer's data

PM10 12.21/78.43 78.47 manufacturer's data

SOx 4.49/6.31 19.53 manufacturer’s data

CO 2 ppm / 2 ppm 15.54/17.01 210.75 manufacturer's data

NOx 2 ppm / 6 ppm 25.52/84.0 167.01 manufacturer's data

VOC 1 ppm / 2 ppm 4.44/9.74 55.29 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 Stack1 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.) 670

Stack diameter (ft) or Outlet duct area (sq. ft.) 21-23 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** Latitude/Longitude

Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack1 Stack 2

41 41

19 19

44.44 41.41

77 77

45 45

18.68 17.60

Stack exhaust Volume varies with operating scenarios (See attachment C, Raw Data) ACFM Temperature varies with operating scenarios (See attachment C, Raw Data °F Moisture varies with operating scenarios %

2700-PM-AQ0007 Rev. 7/2004

- 21 -

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 -


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. Manufacturer Siemens

Model No. SGT6-8000H

Number of Sources 2

Source Designation CT1+DB1 and CT2+DB2

Maximum Capacity 3,124 MMBtu/hr natural gas 2,617 MMBtu/hr ULSD 695 MMBtu/hr duct burner

Rated Capacity 2,976 MMBtu/hr natural gas 2,493 MMBtu/hr ULSD 662 MMBtu/hr Duct burner


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) Capacity (specify units) - Maximum Per Hour 3,124 MMBtu natural gas 2,617 MMBtu ULSD 695 MMBtu duct burner

Per Day 74,976 MMBtu natural gas 62,808 MMBtu ULSD 16,680 MMBtu duct burner

Per Week 524,832 MMBtu natural gas 439,656 MMBtu ULSD 116,760 MMBtu duct burner

Per Year 27,366,240 MMBtu NG 1,988,920 MMBtu ULSD 528,200 MMBtu duct burner


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 occurs at the lowest ambient design temperature (91° F). See detailed performance specifications and emissions calculations presented in Attachment C and Attachment D. Note: maximum per hour, per day, and per week capacities based on 91° F ambient conditions; maximum per year capacities based on estimated maximum emissions from worst-case of all anticipated operating scenarios.

2. Fuel




CT:132,272 lb/hr @ 60°F

CT:100,526,662 lb/yr

0.0015% by wt

negl 19,785 BTU/LB @ 60 °F

Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas CT: 134,112 lb/hr DB: 29,836 lb/hr

CT:1,174,819,266

lb/yr DB: 261,363,441

lb/yr

0.4 grain/100

SCF

0 23,294 Btu/LB

Gas (other)

SCFH

X 106 SCF

grain/100

SCF

Btu/SCF

Coal


Other *


2700-PM-AQ0007 Rev. 7/2004

- 3 -

Section B - Processes Information (Continued) 3. Burner Manufacturer Siemens



Description: Two identical combined-cycle combustion turbines, including auxiliary fired heat recovery steam generators with duct burners

Rated Capacity 2,976 MMBtu/hr (NG), 2,493 MMBtu/hr (ULSD), 662 MMBtu/hr (DB)

Maximum Capacity 3,124 MMBtu/hr (NG), 2,617 MMBtu/hr (ULSD), 695 MMBtu/hr (DB)


Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure










Manufacturer

Date Installed


Capacity (Tons)






2700-PM-AQ0007 Rev. 7/2004

- 4 -







2700-PM-AQ0007 Rev. 7/2004

- 5 -



Pollutant



Gas/ULSD Hours/Year Tons/Year PM 20.46/33.0 8760 89.61/12.54 vendor data PM10 20.46/33.0 8760 89.61/12.54 vendor data SOx 4.68/4.68 8760 20.50/1.78 vendor data CO 79.3/126.5 8760 347.3/48.07 vendor data NOx 324.19/778.31 8760 1,420.0/295.8 vendor data VOC 18.02/3.68 8760 78.9/1.4 vendor data Others: (e.g., HAPs) ----- ----- ----- ----- ----- individual HAPs 8760 <10 facility-wide emission




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 12 -



Type TBD

Model No. TBD

Design Inlet Volume (SCFM) 1.0 – 1.3 MM SCFM










flow rate: TBD





See Attachment G for PID of a typical SCR system




Emissions Data


CO 10 ppmvd @ 15% O2 2 ppmvd @ 15% O2 ~80.0% (NG; normal operation)

VOC 4 ppmvd @ 15% O2 2.8 ppmvd @ 15% O2 ~30.0% (NG; normal operation)

2700-PM-AQ0007 Rev. 7/2004

- 16 -



See Attachment H for cost documentation






See Attachment D



2700-PM-AQ0007 Rev. 7/2004

- 17 -







2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used




(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)





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 Attachment C of Plan Approval Application.

2700-PM-AQ0007 Rev. 7/2004

- 19 -







Testing:


Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -



Pollutant


Estimation Method specify units lbs/hr






VOC 1 ppm / 1 ppm 12.60/3.68 88.82 manufacturer's data

Others: ( e.g., HAPs) ----- ----- ----- -----









Stack diameter (ft) or Outlet duct area (sq. ft.) 21 -23 ft







Latitude Longitude


41 41

19 19

44.44 41.41

77 77

45 45

18.68 17.60


2700-PM-AQ0007 Rev. 7/2004

- 21 -




2700-PM-AQ0007 Rev. 7/2004

- 22 -



2700-PM-AQ0007 Rev. 7/2004

- 2 -


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. Manufacturer Mitsubishi Hitachi Power Systems(MHPSA)

Model No. M501J

Number of Sources 2

Source Designation CT1+DB1 and CT2+DB2

Maximum Capacity 3,301 MMBtu/hr natural gas 2,600 MMBtu/hr ULSD 435 MMBtu/hr duct burner

Rated Capacity 3,144 MMBtu/hr natural gas 2,476 MMBtu/hr ULSD 414 MMBtu/hr Duct burner


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) Capacity (specify units) - Maximum Per Hour 3,301 MMBtu natural gas 2,600 MMBtu ULSD 435 MMBtu duct burner

Per Day 79,224 MMBtu nat gas 62,400 MMBtu ULSD 10,440 MMBtu duct burner

Per Week 554,568 MMBtu natural gas 436,800 MMBtu ULSD 73,080 MMBtu duct burner

Per Year 28,916,760 MMBtu NG 1,976,000 MMBtu ULSD 3,810,600 MMBtu duct burner


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 occurs at the lowest ambient design temperature (-1° F). See detailed performance specifications and emissions calculations presented in Attachment C and Attachment D. Note: maximum per hour, per day, and per week capacities based on -1° F ambient conditions; maximum per year capacities based on estimated maximum emissions from worst-case of all anticipated operating scenarios.

2. Fuel




CT:133,131 lb/hr @ 60°F

CT:101,179,230 lb/yr

0.0015% by wt

negl 19,529.7 BTU/LB @ 60 °F

Oil Number

GPH @ 60°F

X 103 Gal

% by wt


Natural Gas CT: 143,543 lb/hr DB: 18,916 lb/hr

CT:1,257,436,317

lb/yr DB: 165,702,756

lb/yr

0.4 grain/100

SCF

0 22,996.6 Btu/LB

Gas (other)

SCFH

X 106 SCF

grain/100

SCF

Btu/SCF

Coal


Other *


2700-PM-AQ0007 Rev. 7/2004

- 3 -

Section B - Processes Information (Continued) 3. Burner Manufacturer MHPSA



Description: Two identical combined-cycle combustion turbines, including auxiliary fired heat recovery steam generators with duct burners

Rated Capacity 3,144 MMBtu/hr (NG), 2,476 MMBtu/hr (ULSD), 414 MMBtu/hr (DB)

Maximum Capacity 3,301 MMBtu/hr (NG), 2,600 MMBtu/hr (ULSD), 435 MMBtu/hr (DB)


Tank I.D. No.

Manufacturer

Date Installed

Maximum Pressure










Manufacturer

Date Installed


Capacity (Tons)






2700-PM-AQ0007 Rev. 7/2004

- 4 -







2700-PM-AQ0007 Rev. 7/2004

- 5 -



Pollutant



Gas/ULSD Hours/Year Tons/Year PM 17.38/35.42 8760 76.12/13.46 vendor data PM10 17.38/35.42 8760 76.12/13.46 vendor data SOx 2.16/2.04 8760 9.46/0.78 vendor data CO 83.48/306.5 8760 365.64/116.47 vendor data NOx 342.21/422.11 8760 1,498.88/160.40 vendor data VOC 7.31/36.2 8760 32.02/13.76 vendor data Others: (e.g., HAPs) ----- ----- ----- ----- ----- individual HAPs 8760 <10 facility-wide emission




2. Gas Cooling





Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 12 -



Type TBD

Model No. TBD

Design Inlet Volume (SCFM) 1.0 – 1.3 MM SCFM










flow rate: TBD





See Attachment G for PID of a typical SCR system




Emissions Data


CO 10 ppmvd @ 15% O2 2 ppmvd @ 15% O2 ~80.0% (NG; normal operation)

VOC 1.5 ppmvd @ 15% O2 1.5 ppmvd @ 15% O2 0% (NG; normal operation)

2700-PM-AQ0007 Rev. 7/2004

- 16 -



See Attachment H for documentation






See Attachment D



2700-PM-AQ0007 Rev. 7/2004

- 17 -







2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used




(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)






2700-PM-AQ0007 Rev. 7/2004

- 19 -







Testing:


Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -



Pollutant


Estimation Method specify units lbs/hr






VOC 1.5 ppm / 5 ppm 7.31/18.10 251.08 manufacturer's data

Others: ( e.g., HAPs) ----- ----- ----- -----









Stack diameter (ft) or Outlet duct area (sq. ft.) 21-23 ft







Latitude Longitude


41 41

19 19

44.44 41.41

77 77

45 45

18.68 17.60


2700-PM-AQ0007 Rev. 7/2004

- 21 -




2700-PM-AQ0007 Rev. 7/2004

- 22 -



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) 30 MMBtu/hr

Rated heat input (Btu/hr) 30 MMBtu/hr

Typical heat input (Btu/hr) 30 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)

Capacity (specify units) Per hour 30 MMBtu/hr per unit

Per day 720 MMBtu/hr per unit

Per week 5,040 MMBtu/hr per unit

Per year 150,000 MMBtu/hr total (both boilers (limit requested based on 2,500 hour per year each)

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

29,412 SCFH

147 cf X 106

Gal

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) 29,412 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 -

Section B - Combustion Unit Information (Continued)

6. Miscellaneous Information

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

Describe each proposed modification to an existing source.

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: April 2017 Expected completion date of construction/reconstruction: April 2019 Anticipated date(s) of start-up: May/December 2019

2700-PM-AQ0021 Rev. 6/2004

- 5 -


1. Precontrol Emissions*

Emission Rate

Pollutant


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM 0.099 2500 0.124 AP-42 factor

PM10 0.099 2500 0.124 AP-42 factor

SOx 0.015 2500 0.019 BACT

CO 1.08 2500 1.35 vendor data

NOx 0.33 2500 0.41 vendor data

VOC 0.12 2500 0.15 vendor data

Others: (e.g., HAPs) ----- ----- ----- -----

total HAPs 0.06 2500 0.07 AP-42 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.

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

- 14 -

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 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

(If Yes, which subpart) KKKK, Dc, IIII 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)

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 the 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)

Not applicable

2700-PM-AQ0021 Rev. 6/2004

- 15 -

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 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 Attachment K 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 ? 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 1 and Attachment C of Plan Approval Application.

2700-PM-AQ0021 Rev. 6/2004

- 16 -

Section E - Compliance Demonstration 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 -

Section F - Flue and Air Contaminant Emission 1. Estimated Maximum Emissions*

Pollutant


Estimation Method specify units lbs/hr tons/yr. PM 0.0018 lb/MMBtu 0.099 0.124 AP-42 emission factor

PM10 0.0018 lb/MMBtu 0.099 0.124 AP-42 emission factor

SOx 0.0005 lb/MMBtu 0.015 0.019 BACT determination

CO 0.036 lb/MMBtu 1.08 1.35 vendor data

NOx 0.011 lb/MMBtu 0.33 0.41 vendor data

VOC 0.005 lb/MMBtu 0.12 0.15 vendor data

Others: ( e.g., HAPs) ----- ----- ----- -----

Total HAPs 0.06 0.07 AP-42 emission factors



Stack Designation/Number Stack3 and Stack4

List Source(s) or source ID exhausted to this stack: auxiliary boiler #1 and auxiliary boiler #2


Stack height above grade (ft.) 125 Grade elevation (ft.) 670

Stack diameter (ft) or Outlet duct area (sq. ft.) 2.7

Weather Cap YES NO


440 ft from Stack3 and 230 ft from Stack 4



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

Volume TBD ACFM Temperature TBD °F Moisture TBD %


** 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-AQ0007 Rev. 7/2004

- 2 -


Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. Two identical 750 kW diesel engine powered emergency generators

Manufacturer TBD

Model No. TBD

Number of Sources 2

Source Designation ENG1 and ENG2

Maximum Capacity 750 kW

Rated Capacity 750 kW

Type of Material Processed Ultra-low sulfur diesel oil combustion to produce shaft power to drive emergency generator Maximum Operating Schedule 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

Seasonal variations (Months) From to If variations exist, describe them

2. Fuel



Oil Number ULSD

61.4 GPH @ 60°F

30,700 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 -

Section B - Processes Information (Continued) 3. Burner Manufacturer NA

Type and Model No.

Number of Burners

Description:

Rated Capacity

Maximum Capacity

4. Process Storage Vessels A. For Liquids: Name of material stored Diesel tank is 1,800 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










Manufacturer

Date Installed


Capacity (Tons)






2700-PM-AQ0007 Rev. 7/2004

- 4 -

Section B - Processes Information (Continued) 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. 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.

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. Non-resettable hour meter will be installed to monitor operating hours. REC will maintain records of hours operated and reason for operation.


Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. The only emissions that might be considered fugitive are from the relief vent on the diesel storage tank. Emissions are negligible.

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. 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


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM 0.4 500 0.10 EPA Tier cert PM10 0.4 500 0.10 EPA Tier cert SOx 0.01 500 0.001 fuel sulfur CO 6.92 500 1.73 EPA Tier cert NOx 12.77 500 3.19 EPA Tier cert VOC 2.66 500 0.67 PaDEP limit Others: (e.g., HAPs) ----- ----- ----- ----- ----- Total HAPs 500 7.97E-3 AP-42 factors * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating


2. Gas Cooling

Water quenching Yes No Water injection rate GPM




Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 17 -



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 identification 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 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)


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

2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used




(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)


emission offsets. See Attachment K 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.


2700-PM-AQ0007 Rev. 7/2004

- 19 -







Testing:


Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -


1. Estimated Atmospheric Emissions*

Pollutant


Estimation Method specify units lbs/hr tons/yr. PM 0.40 0.10 EPA Tier Certification

PM10 0.40 0.10 EPA Tier Certification

SOx 0.01 0.001 fuel sulfur

CO 6.92 1.73 EPA Tier Certification

NOx 12.77 3.19 EPA Tier Certification

VOC 2.66 0.67 PaDEP Limit

Others: ( e.g., HAPs) ----- ----- ----- -----

individual HAPs <10 EPA AP-42 factors

total HAPs <25 EPA AP-42 factors



Stack Designation/Number Stack5 and Stack6

List Source(s) or source ID exhausted to this stack: ENG1 and ENG2



Stack diameter (ft) or Outlet duct area (sq. ft.) TBD



490 ft from Stack5 and 170 ft from Stack6




Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack5 Stack6

41 41

19 19

42.77 39.74

77 77

45 45

20.61 19.52

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 -


2700-PM-AQ0007 Rev. 7/2004

- 22 -


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 -


Source Description (give type, use, raw materials, product, etc). Attach additional sheets as necessary. One 250 HP diesel fire pump engine

Manufacturer TBD

Model No. TBD

Number of Sources 1

Source Designation ENG3

Maximum Capacity ~1.75 MMBtu/hr

Rated Capacity ~1.75 MMBtu/hr

Type of Material Processed Maximum Operating Schedule 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) Capacity (specify units) 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

Seasonal variations (Months) From to If variations exist, describe them

2. Fuel



Oil Number ULSD

12.8 GPH @ 60°F

3.2 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 -

Section B - Processes Information (Continued) 3. Burner Manufacturer NA

Type and Model No.

Number of Burners

Description:

Rated Capacity

Maximum Capacity

4. Process Storage Vessels A. For Liquids: Name of material stored 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










Manufacturer

Date Installed


Capacity (Tons)






2700-PM-AQ0007 Rev. 7/2004

- 4 -

Section B - Processes Information (Continued) 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. 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.

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. Non-resettable hour meter will be installed to monitor operating hours. REC will maintain records of hours operated and reason for operation.


Identify and describe all fugitive emission points, all relief and emergency valves and any by-pass stacks. The only emissions that might be considered fugitive are from the relief vent on the diesel storage tank.

Describe how emissions will be minimized especially during start up, shut down, process upsets and/or disruptions. 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


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM 0.083 250 0.01 EPA Tier cert PM10 0.083 250 0.01 EPA Tier cert SOx 0.003 250 0.00034 fuel sulfur CO 1.43 250 0.18 EPA Tier cert NOx 1.65 250 0.21 EPA Tier cert VOC 0.55 250 0.069 PaDEP limit Others: (e.g., HAPs) ----- ----- ----- ----- ----- total HAPs 8.31E-04 AP-42 factors * These emissions must be calculated based on the requested operating schedule and/or process rate, e.g., operating


2. Gas Cooling

Water quenching Yes No Water injection rate GPM




Other

Inlet Volume ACFM

@ °F % Moisture

Outlet Volume ACFM

@ °F % Moisture


2700-PM-AQ0007 Rev. 7/2004

- 17 -




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 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 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)

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 Plan Approval Application


2700-PM-AQ0007 Rev. 7/2004

- 18 -



Permit number


issued



decreases were used




(tpy)

Creditable emission

decreases in actual

emissions (tpy)

Emission increases


(tpy)

Creditable emission

decreases in actual

emissions (tpy)




that the benefits of the proposed source outweigh the environmental and social costs (if applicable). See Section 1 of Plan Approval Application.


2700-PM-AQ0007 Rev. 7/2004

- 19 -







Testing:


Recordkeeping:


Reporting:




Describe each:

2700-PM-AQ0007 Rev. 7/2004

- 20 -


1. Estimated Atmospheric Emissions*

Pollutant


Estimation Method specify units lbs/hr tons/yr. PM 0.083 0.01 EPA Tier Certification

PM10 0.083 0.01 EPA Tier Certification

SOx 0.003 0.00034 fuel sulfur limit

CO 1.43 0.18 EPA Tier Certification

NOx 1.65 0.21 EPA Tier Certification

VOC 0.55 0.069 PaDEP Limit

Others: ( e.g., HAPs) ----- ----- ----- -----

total HAPs 8.31E-4 AP-42 emission factors



Stack Designation/Number Stack7

List Source(s) or source ID exhausted to this stack: ENG3



Stack diameter (ft) or Outlet duct area (sq. ft.) TBD



145




Latitude Longitude

Point of Origin Degrees Minutes Seconds Degrees Minutes Seconds Stack7 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: Water Bath Heater

Manufacturer TBD

Model No. TBD

Number of units 1

Maximum heat input (Btu/hr) 18 MMBtu/hr

Rated heat input (Btu/hr) 18 MMBtu/hr

Typical heat input (Btu/hr) 18 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.

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)

Capacity (specify units) Per hour 24

Per day 7

Per week 365

Per year 8,760

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 -

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

17,647 SCFH

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) 18 MMBtu/hr

Normal fuel firing rate 18 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 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 -

Section B - Combustion Unit Information (Continued)

6. Miscellaneous Information

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

Describe each proposed modification to an existing 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: April 2017 Expected completion date of construction/reconstruction: April 2019 Anticipated date(s) of start-up: May/December 2019

2700-PM-AQ0021 Rev. 6/2004

- 5 -



Emission Rate

Pollutant


Method Specify Units Pounds/Hour Hours/Year Tons/Year PM 0.059 8760 0.26 BACT factor

PM10 0.059 8760 0.26 BACT factor

SOx 0.009 8760 0.04 BACT factor

CO 1.44 8760 6.31 BACT factor

NOx 0.72 8760 3.15 BACT factor

VOC 0.09 8760 0.39 BACT factor

Others: (e.g., HAPs) ----- ----- ----- -----

Total HAPs 8760 0.15 AP-42 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. See Attachment C 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

- 14 -

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 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

(If Yes, which subpart) KKKK, Dc, IIII 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)

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 -

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 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 Attachment K 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 1 and Attachment C of Plan Approval Application

2700-PM-AQ0021 Rev. 6/2004

- 16 -

Section E - Compliance Demonstration 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 -

Section F - Flue and Air Contaminant Emission 1. Estimated Maximum Emissions*

Pollutant


Estimation Method specify units lbs/hr tons/yr. PM 0.059 0.26 BACT factor

PM10 0.059 0.26 BACT factor

SOx 0.009 0.04 BACT factor

CO 1.44 6.31 BACT factor

NOx 0.72 3.15 BACT factor

VOC 0.09 0.39 BACT factor

Others: ( e.g., HAPs) ----- ----- ----- -----

Total HAPs 0.15 AP-42 factors



Stack Designation/Number HTR

List Source(s) or source ID exhausted to this stack: Water bath heater


Stack height above grade (ft.) 15’ Grade elevation (ft.) 670

Stack diameter (ft) or Outlet duct area (sq. ft.) 8”

Weather Cap YES NO

Distance of discharge to nearest property line (ft.). Locate on topographic map. TBD



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 -



Section 6


Section 6 Non-Attainment Area Requirements

Table of Contents

6.1 Permit Requirements ........................................................................................................................... 1

6.1.1 Emission Reduction Credits (ERCs) ............................................................................................ 1

6.1.2 Compliance with Lowest Achievable Emission Rate (LAER) .................................................... 1

6.1.3 Compliance with All Applicable Emission Limits and Standards in Pennsylvania..................... 1

6.1.4 Analysis of Alternative Sites, Sizes, Processes, and Control Techniques .................................. 2

6.1.4.1 Alternative Sites ................................................................................................................. 2

6.2 Conclusion .......................................................................................................................................... 4

POWER ENGINEERS, INC. Non-Attainment Area Requirements for Renovo Energy Center, Renovo, PA


6.1 Permit Requirements To obtain a permit to construct and operate a nominally rated 950 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. 6.1.1 Emission Reduction Credits (ERCs) REC’s maximum potential NOx and VOC emissions for each of the three OEMs currently under consideration are summarized in Section 2 of this application. Based on the preliminary estimates contained in Section 2 and Attachment C, 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. Once a final OEM is selected for the project, 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 Attachment K. 6.1.2 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. 6.1.3 Compliance with All Applicable Emission Limits and Standards in Pennsylvania Renovo Energy Center LLC does not own or operate any facilities in Pennsylvania, thus there are no compliance issues with any emission limits or standards.



6.1.4 Analysis of Alternative Sites, Sizes, Processes, and Control Techniques 6.1.4.1 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 gas turbine combined cycle 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 230KV 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 GTCC plants); • Juniata (old coal plants that could be displaced by new highly efficiency GTCC 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 230kV 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 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 230KV 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 500kV 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 500kv 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. 6.1.4.2 Alternative Sizes All major combustion turbine OEMs offer model units in a variety of MW output sizes. Each time a more efficient model is introduced from each OEM, the units are larger with more gross MW output. Currently the most efficient models from the major OEMs are all in the 500 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 MW and decide on number of units for the facility. In general, a 500 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 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 MW range are extremely difficult to site. This difficulty is mainly due to lack of available connection to high voltage transmission lines (345 or 500 kV), as well as the need for more make-up water, fuel and land. REC selected a two-unit, 950 to 1,000 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 vs. a three unit, 1,500 MW design. Single unit plants (i.e., approximately 500 MW) do not routinely meet the financial requirements of investors and lenders. 6.1.4.3 Alternative Processes Modern natural gas combined cycle (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. 6.1.4.4 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. 6.2 Conclusion Following an assessment of alternative sites, alternative sizes, alternative processes, and alternative control technologies, REC proposes to construct a nominally rated 950 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.

Attachment A

!

Renovo Energy Center LLC

Ü

Facility Location

Name:

Date:

Scale:

7/13/20151:24,0001" = 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

Attachment B

RENOVO

A

0 100 200 300FT

95866-000

NORTH EASTDESCRIPTION

EMISSION

POINT NO.

2

1

3

4

5

EMISSIONS POINTS

HRSG STACK 1

HRSG STACK 2

NORTH EAST

AUXILIARY BOILER 1

AUXILIARY BOILER 2

DIESEL GENERATOR 1

PLANT COORDINATE

1967075.00423500.00

423190.90 1967157.82

423436.96 1967094.91

423127.87 1967177.73

423330.70 1966928.41

ELEVATION

FROM GRADE

18 FT

262 FT

125 FT

125 FT

DIESEL GENERATOR 2 423021.60 1967011.2518 FT6

DESCRIPTION ELEVATION

FROM GRADE

18 FT

110 FT

110 FT

25 FT

20 FT

BUILDING SIZES

UNIT 1 TURBINE BUILDING

WATER TREATMENT

BOILER FEEDPUMP ENCLOSURE

UNIT 2 TURBINE BUILDING

ADMINISTRATION\WAREHOUSE

LENGTH WIDTH

190 FT345 FT

345 FT 190 FT

200 FT 100 FT

75 FT 60 FT

75 FT 50 FT

UTM COORDINATE

422878.22 1968534.7515 FT7 DIESEL FIREWATER PUMP

SK-00001

EMISSION POINTS

A

B

C

D

23456

REV

SCALE DESIGNED DRAWNCHIEF

ENGR

NO. DATE REVISIONS BY CHKDESIGN

SUPVSUPVENGR

PROJ

ENGR

DRAWING NO.JOB NO.

LEVELS1234567890123 678901234567890123456789012345678901234567890123

1111 111122222222223333333333444444444455555555 56666PSC= :1 :

B

11

45

REF DFN=[ ] . DFN=[ ] . 22 x 34 "D" SIZE

FREDERICK, MARYLAND

99999

5

B

ISSUED FOR INFORMATION

REVISED EMISSION POINT LOCATIONS

SW

SW

N 423,500.00

E 1,967,075.00

N 423,436.96

E 1,967,094.91

N 423,190.90

E 1,967,157.82

N 423,127.87

E 1,967,177.73

N 423,021.60

E 1,967,011.23

N 423,330.70

E 1,966,928.41

N 422,878.22

E 1,966,534.75

1

2

3

4

5 67

262 FT

Attachment C

Renovo Energy Center - GEFacility-Wide Maximum Potential EmissionsTons Per Year

August 2015

PollutantPower-blocks

Auxiliary Boilers

Diesel Generators

Diesel Fire Pump Heater

ULSD storage

tankCircuit

BreakersFacility-Wide

TotalNOx 334.03 0.83 6.39 0.21 3.15 --- --- 344.6CO 421.50 2.70 3.46 0.18 6.31 --- --- 434.1

PM10 156.94 0.25 0.20 0.010 0.26 --- --- 157.7VOC 110.58 0.30 1.33 0.069 0.39 0.045 --- 112.7SO2 39.07 0.038 0.0064 0.00034 0.039 --- --- 39.2NH3 200.23 --- --- --- --- --- --- 200.2Lead 0.038 --- --- --- --- --- --- 0.038CO2 3,794,560 8,754.90 684.35 35.67 9,203.15 --- --- 3,813,238CH4 77.02 0.17 0.028 0.0014 0.17 --- --- 77.4N2O 9.49 0.017 0.0056 0.00029 0.017 --- --- 9.5SF6 --- --- --- --- --- --- 0.0051 0.0051

CO2e 3,799,314 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,818,129H2SO4 27.59 0.0069 --- --- --- --- --- 27.6HAPs 18.37 0.14 0.016 0.00083 0.15 --- --- 18.7

Renovo Energy CenterRaw Data for General Electric Equipment

August 2015

Operating Point 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Ambient Temperature °F -0.7 -0.7 5.8 5.8 5.8 51 51 51 91.2 91.2 91.2 91.2 95.8 95.8 95.8 -0.7 5.8 5.8 51 51 91.2 91.2 91.2 95.8Ambient Pressure psia 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4Ambient Relative Humidity % 60 60 60 60 60 60 60 60 41.7 41.7 41.7 41.7 60 60 60 60 60 60 60 60 41.7 41.7 41.7 35

Plant StatusHRSG Duct Burner n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/aSCR Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingCO Catalyst Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingEvaporative Cooler State on/off Off Off Off Off Off Off Off Off On On Off Off On Off Off Off Off Off Off Off On Off Off OnGas Turbine Load % BASE 40 BASE 95 37 BASE 98 30 BASE BASE BASE 38 BASE BASE 39 BASE BASE 50 BASE 50 BASE BASE 50 BASETurbine Diluent Injection Type None None None None None None None None None None None None None None None Water Water Water Water Water Water Water Water Water

Fuel DataFuel Type NG NG NG NG NG NG NG NG NG NG NG NG NG NG NG ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSDHHV Btu/lb 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 22,992 20,295 20,295 20,295 20,295 20,295 20,295 20,295 20,295 20,295LHV Btu/lb 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 20,732 18,300 18,300 18,300 18,300 18,300 18,300 18,300 18,300 18,300Fuel Molecular Weight lb/mole 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 16.93 138.25 138.25 138.25 138.25 138.25 138.25 138.25 138.25 138.25Fuel Bound Nitrogen Wt % 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 < 0.015 < 0.015 < 0.015 < 0.015 < 0.015 < 0.015 < 0.015 < 0.015 < 0.015Fuel Sulfur Content gr/100 scf 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83 3.83

Heat Consumption MMBtu/hr HHV 3196 1731 3192 3037 1652 3054 2984 1384 3034 3011 2885 1476 3038 2841 1482 3262 3255 2023 3117 1915 3084 2969 1795 3089Heat Consumption w/Margin1 MMBtu/hr HHV 3353 1816 3349 3186 1733 3204 3130 1452 3183 3159 3027 1548 3187 2980 1555 3558 3550 2207 3400 2089 3364 3238 1958 3369

HRSG Exit Exhaust GasTemperature °F 198 173 196 197 173 191 189 164 200 200 198 170 203 200 172 214 216 183 209 176 218 215 180 221Mass Flow w/Margin lb/hr 5,993,400 3,578,400 5,976,600 5,713,100 3,436,700 5,700,500 5,562,900 3,062,900 5,727,800 5,716,200 5,546,100 3,228,800 5,740,400 5,477,900 3,247,700 6,123,600 6,118,400 3,873,500 5,969,300 3,662,400 5,986,100 5,804,400 3,561,600 5,997,600Std Volume Flow scf/hr (60°F) 81,201,000 48,401,000 80,982,000 77,405,000 46,483,000 77,433,000 75,568,000 41,489,000 78,340,000 78,132,000 75,666,000 43,956,000 78,526,000 74,710,000 44,203,000 83,296,000 83,242,000 52,499,000 81,438,000 49,754,000 82,133,000 79,538,000 48,522,000 82,306,000

HRSG Exit Exhaust Gas Emissionsppmvd @ 15% O2 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25lb/hr as NO2 303.75 165 303.75 288.75 157.5 291.25 283.75 131.25 288.75 286.25 275 140 290 270 141.25 1000 997.5 620 955 586.25 945 908.75 550 946.25lb/hr w/5% margin3 318.94 173.25 318.94 303.19 165.38 305.81 297.94 137.81 303.19 300.56 288.75 147.00 304.50 283.50 148.31 1050.00 1047.38 651.00 1002.75 615.56 992.25 954.19 577.50 993.56ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 6 6 6 6 6 6 6 6 6lb/hr as NO2 24.3 13.2 24.3 23.1 12.6 23.3 22.7 10.5 23.1 22.9 22 11.2 23.2 21.6 11.3 80 79.8 49.6 76.4 46.9 75.6 72.7 44 75.7lb/hr w/5% margin3 25.52 13.86 25.52 24.26 13.23 24.47 23.84 11.03 24.26 24.05 23.10 11.76 24.36 22.68 11.87 84.00 83.79 52.08 80.22 49.25 79.38 76.34 46.20 79.49ppmvd @ 15% O2 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9lb/hr 66.60 36.09 66.60 63.45 34.47 63.90 62.10 28.85 63.45 63.00 60.30 30.74 63.45 59.40 30.92 72.90 72.90 45.45 69.75 42.89 68.85 66.60 40.19 69.3lb/hr w/5% margin3 69.93 37.89 69.93 66.62 36.19 67.10 65.21 30.29 66.62 66.15 63.32 32.27 66.62 62.37 32.46 76.55 76.55 47.72 73.24 45.03 72.29 69.93 42.19 72.77ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2lb/hr 14.8 8.02 14.8 14.1 7.66 14.2 13.8 6.41 14.1 14 13.4 6.83 14.1 13.2 6.87 16.2 16.2 10.1 15.5 9.53 15.3 14.8 8.93 15.4lb/hr w/5% margin3 15.54 8.421 15.54 14.805 8.043 14.91 14.49 6.7305 14.805 14.7 14.07 7.1715 14.805 13.86 7.2135 17.01 17.01 10.605 16.275 10.0065 16.065 15.54 9.3765 16.17ppmvw @ 15% O2 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4lb/hr as methane 5.92 3.21 5.92 5.63 3.07 5.67 5.53 2.56 5.63 5.59 5.35 2.73 5.64 5.26 2.74 12.99 12.95 8.05 12.40 7.62 12.28 11.80 7.14 12.29lb/hr w/5% margin3 6.22 3.37 6.22 5.91 3.22 5.95 5.81 2.69 5.91 5.87 5.62 2.87 5.92 5.53 2.88 13.64 13.60 8.45 13.02 8.00 12.89 12.39 7.50 12.91ppmvw @ 15% O2 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2lb/hr as methane 4.23 2.29 4.23 4.02 2.19 4.05 3.95 1.83 4.02 3.99 3.82 1.95 4.03 3.76 1.96 9.28 9.25 5.75 8.86 5.44 8.77 8.43 5.1 8.78lb/hr w/5% margin3 4.44 2.40 4.44 4.22 2.30 4.25 4.15 1.92 4.22 4.19 4.01 2.05 4.23 3.95 2.06 9.74 9.71 6.04 9.30 5.71 9.21 8.85 5.36 9.22lb/hr 395,000 214,000 395,000 376,000 204,000 378,000 369,000 172,000 375,000 372,000 357,000 183,000 376,000 352,000 183,000 560,000 559,000 348,000 536,000 329,000 530,000 511,000 309,000 531,000lb/MMBtu w/margin 129.6 129.6 129.7 129.8 129.5 129.8 129.7 130.3 129.6 129.5 129.7 130.0 129.8 129.9 129.5 173.1 173.2 173.4 173.4 173.2 173.3 173.6 173.6 173.4lb/hr w/10% margin4 434,500 235,400 434,500 413,600 224,400 415,800 405,900 189,200 412,500 409,200 392,700 201,300 413,600 387,200 201,300 616,000 614,900 382,800 589,600 361,900 583,000 562,100 339,900 584,100ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5lb/hr 22.5 12.2 22.5 21.4 11.6 21.5 21 9.74 21.4 21.2 20.3 10.4 21.4 20 10.4 24.6 24.6 15.3 23.5 14.5 23.3 22.4 13.6 23.3lb/hr w/5% margin3 23.63 12.81 23.63 22.47 12.18 22.58 22.05 10.23 22.47 22.26 21.32 10.92 22.47 21.00 10.92 25.83 25.83 16.07 24.68 15.23 24.47 23.52 14.28 24.47

SOx5 lb/hr as SO2 (+20%) 4.49 2.42 4.48 4.26 2.32 4.28 4.19 1.94 4.26 4.22 4.04 2.06 4.26 3.98 2.08 6.31 6.30 3.91 6.04 3.71 5.96 5.75 3.47 5.98lb/hr 11.1 10.1 11.1 11 10 11 11 9.9 11 11 10.9 9.9 11 10.9 9.9 71.3 71.3 70 71.1 69.9 71.1 71 69.8 71.1lb/hr w/10% margin4 12.21 11.11 12.21 12.1 11 12.1 12.1 10.89 12.1 12.1 11.99 10.89 12.1 11.99 10.89 78.43 78.43 77 78.21 76.89 78.21 78.1 76.78 78.21lb/MMBtu 0.0035 0.0058 0.0035 0.0036 0.0061 0.0036 0.0037 0.0072 0.0036 0.0037 0.0038 0.0067 0.0036 0.0038 0.0067 0.022 0.022 0.035 0.023 0.036 0.023 0.024 0.039 0.023lb/hr 2.88 1.56 2.88 2.74 1.49 2.75 2.69 1.25 2.73 2.71 2.6 1.33 2.74 2.56 1.34 4.05 4.05 2.52 3.88 2.38 3.83 3.69 2.23 3.84lb/hr w/10% margin4 3.17 1.72 3.17 3.01 1.64 3.03 2.96 1.38 3.00 2.98 2.86 1.46 3.01 2.82 1.47 4.46 4.46 2.77 4.27 2.62 4.21 4.06 2.45 4.22ppbvd @ 15% O2 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91 91lb/MMBtu 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00024 0.00026 0.00026 0.00026 0.00026 0.00026 0.00026 0.00026 0.00026 0.00026lb/hr 0.76 0.41 0.76 0.72 0.39 0.73 0.71 0.33 0.72 0.72 0.69 0.35 0.72 0.67 0.35 0.86 0.86 0.54 0.82 0.51 0.82 0.79 0.47 0.82lb/hr w/ 10% margin4 0.84 0.45 0.83 0.79 0.43 0.80 0.78 0.36 0.79 0.79 0.75 0.39 0.79 0.74 0.39 0.95 0.95 0.59 0.91 0.56 0.90 0.86 0.52 0.90

NOx (pre-control)2

CO (pre-control)2

VOC (pre-control)2

CH2O6

NOx (post-control)

CO (post-control)

H2SO4

NH3

CO2

VOC (post-control)

PM

Renovo Energy CenterRaw Data for General Electric EquipmentNotes

August 2015

1 The heat consumption provided by G.E. included a ~5% margin to account for equipment degradation and site variability.

2 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.

3 A 5% margin was added to lb/hr emission values for NOx, CO, VOC, and NH3 to reflect the heat consumption margin provided by G.E.

4 A 10% margin was added to lb/hr emission values of CO2, PM, H2SO4, 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 ppm @ 15% O2 was recommended to be used by G.E. Conversion from ppm to

lb/MMBtu was based on the same conversion ratio as used in the Siemens and MHPSA calculations.

Renovo Energy Center - GEDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

Maximum Fuel Flow Rate: 145,833 lb/hr eachFuel Gross Heating Value: 22,992 Btu/lbRated heat input capacity: 3,196 MMBtu/hr eachMaximum heat input capacity: 3,353 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 7,540 hours each (not including SUSD) 1

Maximum annual heat input: 25,281,620 MMBtu/yr each (not including SUSD)

Maximum allowable annual emissions calculated based on maximum potential operating hoursValues below represent emissions from each individual unit

AverageMaximum Potential

Emission Short-Term AnnualFactor Emission Rate Emissions

Pollutant2 (ppmvd @ 15% O2) (lb/hr) (ton/yr)

NOx 2 24.47 92.23CO 2 14.91 56.21PM10 -- 12.1 45.62VOC 1 4.25 16.03SO2 -- 4.28 16.15NH3 5 22.58 85.11H2SO4 -- 3.03 11.40GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)

CO2 -- 415,800 1,567,566CH4 1.0E-03 7.39 27.87N2O 1.0E-04 0.74 2.79CO2equivalent 416,205.1 1,569,093HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)

1,3-butadiene 4.30E-07 1.44E-03 0.0054acetaldehyde 4.00E-05 1.34E-01 0.51acrolein 6.40E-06 2.15E-02 0.081benzene 1.20E-05 4.02E-02 0.15ethyl benzene 3.20E-05 1.07E-01 0.40formaldehyde2 -- 7.98E-01 3.01naphthalene 1.30E-06 4.36E-03 0.016PAH 2.20E-06 7.38E-03 0.028propylene oxide 2.90E-05 9.72E-02 0.37toluene 1.30E-04 4.36E-01 1.64xylenes 6.50E-05 2.18E-01 0.82arsenic 0 0 0beryllium 0 0 0cadmium 0 0 0

Renovo Energy Center - GEDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

chromium 0 0 0cobalt 0 0 0lead 0 0 0manganese 0 0 0mercury 0 0 0nickel 0 0 0selenium 0 0 0TOTAL HAPs 1.87 7.03

4Emission factors obtained from EPA's AP-42, Table 3.1-3, 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 emission rate for the 51°F operating scenarios was used to calculate maximum potential emissions.

1Maximum potential operating hours not including SUSD was used to estimate emissions.

Renovo Energy Center - GEDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

Maximum Fuel Flow Rate: 175,314 lb/hr eachFuel Gross Heating Value: 20,295 Btu/lbRated heat input capacity: 3,262 MMBtu/hr eachMaximum heat input capacity: 3,558 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 720 hours each (not including SUSD) 1

Maximum annual heat input: 2,561,760 MMBtu/yr (not including SUSD)

Maximum allowable annual emissions calculated based on maximum potential operating hoursValues below represent emissions from each individual unit

Cold DayMaximum Potential




CO2 -- 616,000 221,760CH4 3.0E-03 23.53 8.47N2O 6.0E-04 4.71 1.69CO2equivalent -- 617,990.8 222,477

HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)

1,3-butadiene 1.60E-05 5.69E-02 0.020acetaldehyde 0 0 0acrolein 0 0 0benzene 5.50E-05 1.96E-01 0.070ethyl benzene 0 0 0formaldehyde2 -- 9.49E-01 0.34naphthalene 3.50E-05 1.25E-01 0.045PAH 4.00E-05 1.42E-01 0.051propylene oxide 0 0 0toluene 0 0 0xylenes 0 0 0arsenic 1.10E-05 3.91E-02 0.014beryllium 3.10E-07 1.10E-03 0.00040cadmium 4.80E-06 1.71E-02 0.0061chromium 1.10E-05 3.91E-02 0.014

Renovo Energy Center - GEDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

cobalt 0 0 0lead 1.40E-05 4.98E-02 0.018manganese 7.90E-04 2.81E+00 1.01mercury 1.20E-06 4.27E-03 0.0015nickel 4.60E-06 1.64E-02 0.0059selenium 2.50E-05 8.90E-02 0.032TOTAL HAPs 4.54 1.63

4Emission factors obtained from EPA's AP-42, Tables 3.1-4 and 3.1-5, except for formaldehyde, which was obtained from the vendor.


2Emission factors provided by vendor. The maximum emissions rate from all available operating scenarios was used to calculate maximum potential emissions.


Renovo Energy Center - GEStartup and Shutdown Operations Emissions DataNatural Gas Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 45 45 90NOx Emissions (lb) 181 199 398 265CO Emissions (lb) 339 373 746 497VOC Emissions (lb) 42 46 92 62PM10/2.5 Emissions (lb) 9 10 20 13Warm StartTime from Ignition until Compliance (minutes) 40 40 90NOx Emissions (lb) 130 143 322 215CO Emissions (lb) 337 371 834 556VOC Emissions (lb) 42 46 104 69PM10/2.5 Emissions (lb) 8 9 20 13Hot StartTime from Ignition until Compliance (minutes) 20 20 75NOx Emissions (lb) 72 79 297 238CO Emissions (lb) 332 365 1,370 1,096VOC Emissions (lb) 41 45 169 135PM10/2.5 Emissions (lb) 4 4 17 13Shutdown from 50% loadTime to Shutdown (minutes) 14 14 30NOx Emissions (lb) 7.8 9 18 37CO Emissions (lb) 171 188 403 806VOC Emissions (lb) 84 92 198 396PM10/2.5 Emissions (lb) 2.8 3 7 13Total SUSD Operating Hour Limitation Per Unit: 460 hrsTotal NOx Emissions Per Unit: 39 tonsTotal CO Emissions Per Unit: 143 tonsTotal VOC Emissions Per Unit: 35 tonsTotal PM10/2.5 Emissions Per Unit: 3 tons

Note: G.E. provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - GEStartup and Shutdown Operations Emissions DataULSD Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 45 45 90NOx Emissions (lb) 219 241 482 321CO Emissions (lb) 190 209 418 279VOC Emissions (lb) 15 17 33 22PM10/2.5 Emissions (lb) 53 58 117 78Warm StartTime from Ignition until Compliance (minutes) 40 40 90NOx Emissions (lb) 203 223 502 335CO Emissions (lb) 187 206 463 309VOC Emissions (lb) 14 15 35 23PM10/2.5 Emissions (lb) 48 53 119 79Hot StartTime from Ignition until Compliance (minutes) 20 20 75NOx Emissions (lb) 143 157 590 472CO Emissions (lb) 176 194 726 581VOC Emissions (lb) 12 13 50 40PM10/2.5 Emissions (lb) 24 26 99 79Shutdown from 50% loadTime to Shutdown (minutes) 8 8 30NOx Emissions (lb) 8 9 33 66CO Emissions (lb) 17 19 70 140VOC Emissions (lb) 4 4 17 33PM10/2.5 Emissions (lb) 9.5 10 39 78Total SUSD Operating Hour Limitation Per Unit: 40 hrsTotal NOx Emissions Per Unit: 6 tonsTotal CO Emissions Per Unit: 6 tonsTotal VOC Emissions Per Unit: 0 tonsTotal PM10/2.5 Emissions Per Unit: 2 tons

Note: G.E. provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - GESummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs

August 2015

ULSD Normal Operating Hours: 720 each powerblockULSD SUSD Operating Hours: 40 each powerblockNatural Gas Normal Operating Hours: 7,540 each powerblockNatural Gas SUSD Operating Hours: 460 each powerblock

Pollutant

Annual Emissions from

ULSD Firing1

(tons)


ULSD SUSD2

(tons)


NG Firing3

(tons)


Natural Gas SUSD4 (tons)

Total Annual Emissions from

Both Powerblocks

(tons)


Each Powerblock

(tons)NOx 60.48 11.61 184.47 77.47 334.03 167.01CO 12.25 11.22 112.42 285.61 421.50 210.75

PM10 56.47 3.16 91.23 6.07 156.94 78.47VOC 6.68 0.99 32.06 70.84 110.58 55.29SO2 4.54 0.25 32.30 1.97 39.07 19.53NH3 18.60 1.03 170.22 10.38 200.23 100.12

H2SO4 3.21 0.18 22.81 1.39 27.59 13.79GHGs

CO2 443,520 24,640 3,135,132 191,268 3,794,560 1,897,280CH4 16.94 0.94 55.74 3.40 77.02 38.51N2O 3.39 0.19 5.57 0.34 9.49 4.75

CO2equivalent 444,953 24,720 3,138,186 191,454 3,799,314 1,899,657HAPs

1,3-butadiene 0.041 0.0023 0.011 0.00066 0.055 0.027acetaldehyde 0 0 1.01 0.062 1.07 0.54

acrolein 0 0 0.16 0.010 0.17 0.086benzene 0.14 0.0078 0.30 0.019 0.47 0.24

ethyl benzene 0 0 0.81 0.049 0.86 0.43formaldehyde 0.68 0.038 6.02 0.37 7.11 3.55naphthalene 0.090 0.0050 0.033 0.0020 0.13 0.065

PAH 0.10 0.0057 0.056 0.0034 0.17 0.084

Renovo Energy Center - GESummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs

August 2015

Pollutant


ULSD Firing1

(tons)


ULSD SUSD2

(tons)


NG Firing3

(tons)




Both Powerblocks

(tons)


Each Powerblock

(tons)propylene oxide 0 0 0.73 0.045 0.78 0.39

toluene 0 0 3.29 0.20 3.49 1.74xylenes 0 0 1.64 0.10 1.74 0.87arsenic 0.028 0.0016 0 0 0.030 0.015

beryllium 0.00079 0.000044 0 0 0.00084 0.00042cadmium 0.012 0.00068 0 0 0.013 0.0065chromium 0.028 0.0016 0 0 0.030 0.015

cobalt 0 0 0 0 0 0lead 0.036 0.0020 0 0 0.038 0.019

manganese 2.02 0.11 0 0 2.14 1.07mercury 0.0031 0.00017 0 0 0.0032 0.0016nickel 0.012 0.00065 0 0 0.012 0.0062

selenium 0.064 0.0036 0 0 0.068 0.034TOTAL HAPs 3.27 14.07 18.37 9.19

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 for each

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.

Renovo Energy Center - GEDetermination of Potential EmissionsAuxiliary Boilers

August 2015

Two natural gas fired auxiliary boilersMaximum heat input capacity: 30 MMBtu/hr per boilerMaximum potential operating hours: 2,500 hours per boilerMaximum annual heat input limit: 150,000 MMBtu/yr totalMaximum fuel input limit: 147 MMcf/yr 29,412 cf/hr

Emission Emissions Emissions TotalPollutant Factor per boiler per boiler Emissions

(lb/MMBtu) (lb/hr) (tpy) (tpy)

NOx 0.011 0.33 0.41 0.83CO 0.036 1.08 1.35 2.70

PM10 0.0033 0.099 0.124 0.25VOC 0.0040 0.12 0.15 0.30SO2 0.00050 0.015 0.019 0.038

H2SO4 9.15E-05 0.002745 0.003 0.007NH3 negligible --- ---

(kg/MMBtu) (tpy) (tpy)

CO2 53.06 4,377.45 8,754.90CH4 1.00E-03 0.083 0.17N2O 1.00E-04 0.0083 0.017CO2e -- 4,381.97 8,763.94

Emission Emissions Emissions TotalFactor per boiler per boiler Emissions

HAPs (lb/MMcf) (lb/hr) (tpy) (tpy)

benzene 2.10E-03 6.18E-05 7.7E-05 0.00015formaldehyde 7.50E-02 2.21E-03 0.0028 0.0055

hexane 1.8 5.29E-02 0.066 0.13naphthalene 6.10E-04 1.79E-05 2.2E-05 4.5E-05

toluene 3.40E-03 1.00E-04 0.00013 0.00025POM 8.82E-05 2.59E-06 3.2E-06 6.5E-06

Total HAP emissions: 0.06 0.07 0.14

Emission factors for NOx, CO, and VOC are vendor guarantees.

Emission factors for HAPs are based on AP-42, Section 1.4.

Emission factors for PM10, SO2 and H2SO4 are based on RBLC database entries for BACT/BATEmission 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

Renovo Energy Center - GEDetermination of Potential EmissionsDiesel Engines

August 2015

Emergency Generators

maximum rating: 750 kW (2) 750 kW1207 hp

Maximum operating hours: 500 hr eachMaximum fuel firing rate: 61.4 gal/hr eachMaximum heat input rate: 8.41 MMBtu/hrAnnual fuel rate: 30,700 gal/yr Total

Emissions PotentialTier 2 per engine Emissions

Pollutant (g/hp-hr) (lb/hr) (tpy) (tpy)

NOx + VOC 4.8 12.77 3.19 6.39CO 2.6 6.92 1.73 3.46

PM10 0.15 0.40 0.10 0.20VOC 1.00 2.66 0.67 1.33SO2

1 --- 0.01 0.003 0.0064

Emissions for NOx, CO and PM10 are based on Tier 2 certified standards

SO2 emissions are based on ultra low diesel fuel not to exceed 15 ppm sulfur.

Fire Pump Engine

maximum rating: 250 hpMaximum operating hours: 250 hrMaximum fuel firing rate: 12.8 gal/hrMaximum firing rate: 1.75 MMBtu/hr

PotentialTier 3 Emissions

Pollutant (g/hp-hr) (lb/hr) (tpy)

NOx + VOC 3 1.653 0.21CO 2.6 1.433 0.18

PM10 0.15 0.083 0.010VOC 1.00 0.551 0.069SO2

1 --- 0.003 0.00034


Emissions of VOC are based on PaDEP's General Plan Approval and General Operating Permit for Diesel or No. 2 Fuel-fired Internal Combustion Engines (BAQ-GPA/GP-9)

1(15 lb S/ 106 lb fuel) ( 64 lb SO2/32 lb S) (7 lb/gal) ( gal/137,000 Btu) (8.41 MMBtu/hr) = 0.01 lb SO2/hr

Renovo Energy Center - GEDetermination of Potential EmissionsDiesel Engines

August 2015


generator totalHAP Emissions1 Emission emissions generator fire pump

factor per engine emissions emissions(lb/MMBtu) (tpy) (tpy)

benzene 9.33E-04 1.96E-03 3.92E-03 2.05E-04toluene 4.09E-04 8.60E-04 1.72E-03 8.97E-05xylene 2.85E-04 5.99E-04 1.20E-03 6.25E-051,3 butadiene 3.91E-05 8.22E-05 1.64E-04 8.57E-06formaldehyde 1.18E-03 2.48E-03 4.96E-03 2.59E-04acetaldehyde 7.67E-04 1.61E-03 3.23E-03 1.68E-04acrolein 9.25E-05 1.95E-04 3.89E-04 2.03E-05naphthalene 8.48E-05 1.78E-04 3.57E-04 1.86E-05

Total 7.97E-03 1.59E-02 8.31E-04

1HAP emission factors are based on AP-42, Section 3.



Renovo Energy Center - GEDetermination of Potential EmissionsWater Bath Heater

August 2015

One natural gas water bath heaterMaximum heat input capacity: 18 MMBtu/hrMaximum potential operating hours: 8,760 hours

Emission Pollutant Factor Emissions

(lb/MMBtu) (lb/hr) (tpy)

NOx 0.04 0.72 3.15CO 0.08 1.44 6.31

PM10 0.0033 0.059 0.26VOC 0.0050 0.09 0.39SO2 0.00050 0.009 0.04NH3 negligible ---

(kg/MMBtu) (tpy)

CO2 53.06 9,203.15CH4 1.00E-03 0.173N2O 1.00E-04 0.0173CO2e -- 9,212.66

Emission Factor Emissions

HAPs (lb/MMcf) (tpy)

benzene 2.10E-03 1.6E-04formaldehyde 7.50E-02 0.0058

hexane 1.8 0.139naphthalene 6.10E-04 4.7E-05

toluene 3.40E-03 0.00026POM 8.82E-05 6.8E-06

Total HAP emissions: 0.15

Emission factors for NOx, CO, PM10, VOC, and SO2 are based on RBLC database entries for BACT/BAT


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

Renovo Energy Center - GEDetermination of Greehouse Gas EmissionsDiesel Engines

August 2015

Emergency Generator Engines - (2) 750 kW units

Maximum fuel firing rate: 61.4 gal/hr eachMaximum heat input: 8.41 MMBtu/hrMaximum operating hours: 500 hr each

Emission Total (2 engines) Global CO2

Factor Emissions Warming Equivalent(kg/MMBtu) (tpy) Potential (tpy)

CO2 73.96 684.35 1 684.35CH4 3.00E-03 0.028 25 0.69N2O 6.00E-04 0.0056 298 1.65

Total CO2 Equivalent: 686.70

Emergency Fire Pump Engine - 250 HP unit

Maximum fuel firing rate: 12.8 gal/hrMaximum heat input: 1.75 MMBtu/hrMaximum operating hours: 250 hr

Emission Global CO2


CO2 73.96 35.67 1 35.67CH4 3.00E-03 0.0014 25 0.036N2O 6.00E-04 0.00029 298 0.086


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.

Renovo Energy Center - GEDetermination of Potential EmissionsULSD Storage Tank

August 2015

REC Tank_1

Williamsport

Pennsylvania

Renovo Energy Center

Internal Floating Roof Tank

ULSD Storage Tank for Combustion Turbines

120

3,800,000.00 (based on 72 hours of ULSD firing capability per powerblock)

9.21 (based on 720 hours of ULSD firing per powerblock)

N

7

1

Internal Shell Condition: Light Rust

Shell Color/Shade: White/White

Shell Condition Good

Roof Color/Shade: White/White

Roof Condition: Good

Primary Seal: Liquid-mounted

Secondary Seal None

Deck Fitting Category: Typical

Deck Type: Bolted

Construction: Sheet

Deck Seam: Sheet: 5 Ft Wide

Deck Seam Len. (ft): 2,261.94

Rim-Seal System

Deck Characteristics

Paint Characteristics

State:

Company:

Type of Tank:

Description:

Tank Dimensions

Diameter (ft):

Volume (gallons):

Turnovers:

Self Supp. Roof? (y/n):

No. of Columns:

Eff. Col. Diam. (ft):

City:

TANKS 4.0.9dEmissions Report - Summary Format

Tank Indentification and Physical Characteristics

Identification

User Identification:


August 2015

Quantity

1

1

7

1

41

1

116

1

Meterological Data used in Emissions Calculations: Williamsport, Pennsylvania (Avg Atmospheric Pressure = 14.47 psia)

Vacuum Breaker (10-in. Diam.)/Weighted Mech. Actuation, Gask.

Deck Fitting/Status

Access Hatch (24-in. Diam.)/Unbolted Cover, Ungasketed

Automatic Gauge Float Well/Unbolted Cover, Ungasketed

Column Well (24-in. Diam.)/Built-Up Col.-Sliding Cover, Ungask.

Ladder Well (36-in. Diam.)/Sliding Cover, Ungasketed

Roof Leg or Hanger Well/Adjustable

Sample Pipe or Well (24-in. Diam.)/Slit Fabric Seal 10% Open

Stub Drain (1-in. Diameter)/Slit Fabric Seal 10% Open


August 2015

REC Tank_1 - Internal Floating Roof TankWilliamsport, Pennsylvania

Liquid

Bulk Vapor Liquid Vapor

Temp Mol. Mass Mass Mol.

Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight

All 51.52 46.58 56.46 49.92 0.0048 N/A N/A 130 188

Emissions Report for: Annual


ComponentsRim Seal

LossWithdrawl

LossDeck Fitting

LossDeck Seam

LossTotal

Emissions

Distillate fuel oil no. 2 2.07 73.81 10.1 4.35 90.34

Individual Tank Emission Totals

Losses(lbs)

Mixture/ Component Calculations

Distillate fuel oil no. 2 Option 1: VP50 = .0045 VP60 = .0065



Liquid Contents of Storage Tank

Daily Liquid Surf.

Temperature (deg F) Vapor Pressure (psia) Basis for Vapor Pressure

Renovo Energy Center - GEDetermination of Greehouse Gas EmissionsCircuit Breakers

August 2015

SF6 Global CO2

Amount Number Emissions Warming EquivalentSF6 (lb) of Units (tons/yr) Potential (tpy)

Circuit Breaker #1 345 4 0.0035 22,800 78.66Circuit Breaker #2 165 4 0.0017 22,800 37.62

0.0051


Emissions are based on a leak rate of 0.5% per year

Renovo Energy Center - MHPSAFacility-Wide Maximum Potential EmissionsTons Per Year

August 2015

Pollutant PowerblocksAuxiliary Boilers

Diesel Generators


ULSD storage

tankCircuit


TotalNOx 256.90 0.83 6.39 0.21 3.15 --- --- 267.5CO 1126.03 2.70 3.46 0.18 6.31 --- --- 1138.7


CO2e 3,500,934 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,519,749H2SO4 32.37 0.0069 --- --- --- --- --- 32.4HAPs 17.15 0.14 0.016 0.00083 0.15 --- --- 17.5

Renovo Energy CenterRaw Data for MHPSA Equipment

August 2015

Operating Point 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3

Ambient Temperature °F 91 91 91 51 51 51 51 6 6 6 96 -1 91 51 6Ambient Pressure psia 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42Ambient Relative Humidity % 41.7 41.7 41.7 60 60 60 60 60 60 60 35 60 41.7 60 60

Plant StatusHRSG Duct Burner On Off Off On On Off Off On Off Off On On Off Off OffSCR Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingCO Catalyst Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingEvaporative Cooler State on/off On On Off Off Off Off Off Off Off Off On Off Off Off OffGas Turbine Load % BASE BASE 50 BASE BASE BASE 50 BASE BASE 50 BASE BASE BASE BASE BASETurbine Diluent Injection Type None None None None None None None None None None None None Water Water Water

Fuel DataFuel Type NG NG NG NG NG NG NG NG NG NG NG NG ULSD ULSD ULSDHHV Btu/lb 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 22,996.6 19,529.7 19,529.7 19,529.7LHV Btu/lb 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 20,727.0 18,300.0 18,300.0 18,300.0Fuel Molecular Weight lb/mole - - - - - - - - - - - - - - -Fuel Bound Nitrogen Wt % 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Fuel Sulfur Content gr/100 scf 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.0015% 0.0015% 0.0015%

GT Fuel Flow MMBtu/hr LHV 2,476 2,476 1,529 2,613 2,613 2,613 1,614 2,822 2,822 1,791 2,468 2,832 2,131 2,314 2,314MMBtu/hr HHV1 2,748 2,748 1,697 2,900 2,900 2,900 1,792 3,132 3,132 1,988 2,739 3,144 2,280 2,476 2,476w/5% margin2 2,886 2,886 1,782 3,045 3,045 3,045 1,881 3,289 3,289 2,087 2,876 3,301 2,394 2,600 2,600

DB Fuel Flow MMBtu/hr LHV 373 0 0 373 116 0 0 362 0 0 373 364 0 0 0MMBtu/hr HHV1 414 0 0 414 129 0 0 402 0 0 414 404 0 0 0w/5% margin2 435 0 0 435 135 0 0 422 0 0 435 424 0 0 0

Heat Consumption MMBtu/hr HHV 3,161 2,747 1,696 3,313 3,028 2,899 1,791 3,533 3,131 1,987 3,152 3,546 2,274 2,469 2,469w/5% margin2 3,319 2,884 1,781 3,479 3,179 3,044 1,880 3,709 3,288 2,086 3,310 3,723 2,388 2,593 2,593

HRSG Exit Exhaust GasTemperature °F 182 191 173 172 180 185 169 175 189 170 183 175 202 202 201Mass Flow lb/hrStd Volume Flow scfm 979,600 979,600 653,400 1,027,000 1,027,000 1,027,000 667,300 1,083,000 1,083,000 709,700 977,100 1,083,000 964,100 1,041,000 1,015,000

HRSG Exit Exhaust Gas Emissionsppmvd @ 15% O2 25 25 25 25 25 25 25 25 25 25 25 25 42 42 42lb/hr as NO2 290.53 252.49 155.92 304.50 278.29 266.46 164.59 324.69 287.78 182.64 289.71 325.92 370.22 402.01 402.01lb/hr w/5% margin2 305.06 265.12 163.72 319.73 292.21 279.79 172.82 340.93 302.17 191.77 304.20 342.21 388.73 422.11 422.11ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 4 4 4lb/MMBtu4 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.016 0.016 0.016lb/hr as NO2 23.24 20.20 12.47 24.36 22.26 21.32 13.17 25.98 23.02 14.61 23.18 26.07 35.26 38.29 38.29lb/hr w/5% margin2 24.40 21.21 13.10 25.58 23.38 22.38 13.83 27.27 24.17 15.34 24.34 27.38 37.02 40.20 40.20ppmvd @ 15% O2 10 10 10 10 10 10 10 10 10 10 10 10 50 50 50lb/hr 70.87 61.59 38.04 74.28 67.89 65.00 40.15 79.21 70.20 44.55 70.67 79.51 268.82 291.90 291.90lb/hr w/5% margin2 74.42 64.67 39.94 78.00 71.28 68.25 42.16 83.17 73.71 46.78 74.21 83.48 282.26 306.50 306.50ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 6 6 6lb/MMBtu4 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.014 0.014 0.014lb/hr 14.17 12.32 7.61 14.86 13.58 13.00 8.03 15.84 14.04 8.91 14.13 15.90 32.26 35.03 35.03lb/hr w/5% margin2 14.88 12.93 7.99 15.60 14.26 13.65 8.43 16.63 14.74 9.36 14.84 16.70 33.87 36.78 36.78ppmvd @ 15% O2 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 10 10 10lb/hr as methane 6.20 5.39 3.33 6.50 5.94 5.69 3.51 6.93 6.14 3.90 6.19 6.96 31.75 34.48 34.48lb/hr w/5% margin2 6.51 5.66 3.50 6.83 6.24 5.97 3.69 7.28 6.45 4.09 6.49 7.31 33.34 36.20 36.20ppmvd @ 15% O2 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 5 5 5lb/MMBtu4 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0020 0.0070 0.0070 0.0070lb/hr as methane 6.20 5.39 3.33 6.50 5.94 5.69 3.51 6.93 6.14 3.90 6.19 6.96 15.88 17.24 17.24lb/hr w/5% margin2 6.51 5.66 3.50 6.83 6.24 5.97 3.69 7.28 6.45 4.09 6.49 7.31 16.67 18.10 18.10lb/hr 375,900 326,600 201,700 393,900 359,900 344,700 212,900 420,100 372,300 236,300 374,800 421,600 270,400 293,600 293,600lb/MMBtu w/10% margin 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8 130.8lb/hr w/10% margin5 413,490 359,260 221,870 433,290 395,890 379,170 234,190 462,110 409,530 259,930 412,280 463,760 297,440 322,960 322,960ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5lb/MMBtu4 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0069 0.0073 0.0073 0.0073lb/hr 21.75 18.90 11.67 22.79 20.83 19.94 12.32 24.30 21.54 13.67 21.68 24.39 16.64 18.07 18.07lb/hr w/5% margin2 22.83 19.84 12.25 23.93 21.87 20.94 12.94 25.52 22.62 14.35 22.77 25.61 17.47 18.97 18.97lb/hr as SO2 1.6 1.4 0.9 1.7 1.5 1.5 0.9 1.8 1.6 1 1.6 1.8 1.6 1.7 1.7lb/hr w/20% margin6 1.92 1.68 1.08 2.04 1.80 1.80 1.08 2.16 1.92 1.20 1.92 2.16 1.92 2.04 2.04lb/hr 14.6 9.4 6.1 15.2 11.6 10 6.3 15.8 10.7 6.9 14.6 15.8 29.5 32.2 31.7lb/MMBtu 0.0046 0.0034 0.0036 0.0046 0.0038 0.0034 0.0035 0.0045 0.0034 0.0035 0.0046 0.0045 0.013 0.013 0.013lb/hr w/10% margin5 16.06 10.34 6.71 16.72 12.76 11.00 6.93 17.38 11.77 7.59 16.06 17.38 32.45 35.42 34.87lb/hr 3.50 3.06 1.85 3.67 3.37 3.23 1.96 3.92 3.49 2.17 3.49 3.93 1.03 1.09 1.09lb/hr w/10% margin5 3.85 3.37 2.04 4.04 3.71 3.55 2.16 4.31 3.84 2.39 3.84 4.32 1.13 1.20 1.20ppbvd @ 15% O2 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80lb/MMBtu 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00021 0.00023 0.00023 0.00023lb/hr 0.66 0.57 0.35 0.69 0.63 0.61 0.37 0.74 0.65 0.41 0.66 0.74 0.53 0.57 0.57lb/hr w/5% margin2 0.69 0.60 0.37 0.73 0.66 0.64 0.39 0.77 0.69 0.44 0.69 0.78 0.56 0.60 0.60

NOx (pre-control)3

CO (pre-control)3

VOC (pre-control)3

CH2O

H2SO4

PM

CO (post-control)

NOx (post-control)

NH3

CO2

VOC (post-control)

SO2

Renovo Energy CenterRaw Data for MHPSA EquipmentNotes

August 2015

1 Heat consumption was provided by MHPSA in terms of LHV. Values were converted to HHV using the HHV/LHV ratio for each fuel type.

2 A 5% margin was added to all heat input rates as well as lb/hr emission rates of NOx, CO, VOC, NH3, and CH2O to account for equipment degradation and site variability.

3 Pre-control emission rates were provided by MHPSA in terms of ppm. The corresponding lb/hr values were calculated using the same conversion ratios as were used for the post-control emission rates.

4 Post-control emission rates were provided by MHPSA in terms of ppm. These values were converted to lb/MMBtu using techniques from Output-Based Regulations: A Handbook for Air Regulators (U.S. EPA and Combined Heat and Power Parnerthip, August 2014).

5 A 10% margin was added to emission rates for CO2, PM, and H2SO4 to account for equipment degradation and site variability.

6 A margin of 20% was added to the SO2 emission rates to account for equipment degradation, site variability, and fuel variability.

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs, DBs firing Natural Gas

August 2015

Maximum Fuel Flow Rate: 161,905 lb/hr eachFuel Gross Heating Value: 22,997 Btu/lbCT rated heat input capacity: 3,144 MMBtu/hr eachCT max heat input capacity: 3,301 MMBtu/hr eachDB rated heat input capacity: 414 MMBtu/hr eachDB max heat input capacity: 435 MMBtu/hr eachPowerblock rated heat input capacity: 3,546 MMBtu/hr eachPowerblock max heat input capacity: 3,723 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 3,770 hours each (not including SUSD) 1


Potential annual emissions calculated based on maximum potential operating hoursValues below represent emissions from each individual unit




NOx 2 25.58 48.21CO 2 15.60 29.40PM10 -- 16.72 31.52VOC 1.5 6.83 12.87SO2 -- 2.04 3.85NH3 5 23.93 45.11H2SO4 -- 4.04 7.61GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)

CO2 -- 433,290 816,752CH4 1.0E-03 8.21 15.47N2O 1.0E-04 0.82 1.55CO2equivalent -- 433,739.8 817,600HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)

1,3-butadiene 4.30E-07 1.60E-03 0.0030acetaldehyde 4.00E-05 1.49E-01 0.28acrolein 6.40E-06 2.38E-02 0.045benzene 1.20E-05 4.47E-02 0.084ethyl benzene 3.20E-05 1.19E-01 0.22formaldehyde2 -- 0.73 1.37naphthalene 1.30E-06 4.84E-03 0.0091PAH 2.20E-06 8.19E-03 0.0154propylene oxide 2.90E-05 1.08E-01 0.20toluene 1.30E-04 4.84E-01 0.91

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs, DBs firing Natural Gas

August 2015

xylenes 6.50E-05 2.42E-01 0.46arsenic 1.96E-07 7.30E-04 0.00138beryllium 1.18E-08 4.38E-05 0.000083cadmium 1.08E-06 4.02E-03 0.0076chromium 1.37E-06 5.11E-03 0.0096cobalt 8.24E-08 3.07E-04 0.00058lead 0 0 0manganese 3.73E-07 1.39E-03 0.0026mercury 2.55E-07 9.49E-04 0.00179nickel 2.06E-06 7.67E-03 0.0144selenium 2.35E-08 8.76E-05 0.000165TOTAL HAPs 1.93 3.64

1Maximum potential operating hours not including SUSD or non-duct firing was used to estimate emissions.

3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O obtained from 40 CFR 98.4Emission factors obtained from EPA's AP-42, Table 3.1-3, except for formaldehyde, which was obtained from the vendor.

2Emission factors provided by vendor. The maximum emission rate for the 51°F operating scenarios with duct firing was used to calculate maximum potential emissions.

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

Maximum Fuel Flow Rate: 143,530 lb/hr eachFuel Gross Heating Value: 22,997 Btu/lbCT rated heat input capacity: 3,144 MMBtu/hr eachCT max heat input capacity: 3,301 MMBtu/hr eachPowerblock rated heat input capacity: 3,546 MMBtu/hr eachPowerblock max heat input capacity: 3,723 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 3,770 hours each (not including SUSD) 1



Maximum PotentialEmission Short-Term Annual

Factor Emission Rate EmissionsPollutant2 (ppmvd @ 15% O2) (lb/hr) (ton/yr)

NOx 2 24.17 45.57CO 2 14.74 27.79PM10 -- 11.77 22.19VOC 1.5 6.45 12.16SO2 -- 1.92 3.62NH3 5 22.62 42.63H2SO4 -- 3.84 7.24GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)


1,3-butadiene 4.30E-07 1.42E-03 0.0027acetaldehyde 4.00E-05 1.32E-01 0.25acrolein 6.40E-06 2.11E-02 0.040benzene 1.20E-05 3.96E-02 0.07ethyl benzene 3.20E-05 1.06E-01 0.20formaldehyde2 -- 0.69 1.29naphthalene 1.30E-06 4.29E-03 0.008PAH 2.20E-06 7.26E-03 0.014propylene oxide 2.90E-05 9.57E-02 0.18toluene 1.30E-04 4.29E-01 0.81xylenes 6.50E-05 2.15E-01 0.40arsenic 1.96E-07 6.47E-04 0.0012beryllium 1.18E-08 3.88E-05 0.00007

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

cadmium 1.08E-06 3.56E-03 0.0067chromium 1.37E-06 4.53E-03 0.009cobalt 8.24E-08 2.72E-04 0.00051lead 0 0 0manganese 3.73E-07 1.23E-03 0.0023mercury 2.55E-07 8.41E-04 0.0016nickel 2.06E-06 6.80E-03 0.013selenium 2.35E-08 7.77E-05 0.00015TOTAL HAPs 1.76 3.31

1Maximum potential operating hours not including SUSD or duct firing was used to estimate emissions.2Emission factors provided by vendor. The maximum emission rate from all available scenarios without duct firing was used to calculate maximum potential emissions.3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O obtained from 40 CFR 98.4Emission factors obtained from EPA's AP-42, Table 3.1-3, except for formaldehyde, which was obtained from the vendor.

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

Maximum Fuel Flow Rate: 132,770 lb/hr eachFuel Gross Heating Value: 19,530 Btu/lbCT rated heat input capacity: 2,476 MMBtu/hr eachCT max heat input capacity: 2,600 MMBtu/hr eachDB rated heat input capacity: 0 MMBtu/hr eachDB max heat input capacity: 0 MMBtu/hr eachPowerblock rated heat input capacity: 2,469 MMBtu/hr eachPowerblock max heat input capacity: 2,593 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 720 hours each (not including SUSD) 1







1,3-butadiene 1.60E-05 4.15E-02 0.015acetaldehyde 0 0 0acrolein 0 0 0benzene 5.50E-05 1.43E-01 0.051ethyl benzene 0 0 0formaldehyde2 -- 0.60 0.22naphthalene 3.50E-05 9.08E-02 0.033PAH 4.00E-05 1.04E-01 0.037propylene oxide 0 0 0toluene 0 0 0xylenes 0 0 0

Renovo Energy Center - MHPSADetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

arsenic 1.10E-05 2.85E-02 0.010beryllium 3.10E-07 8.04E-04 0.00029cadmium 4.80E-06 1.24E-02 0.0045chromium 1.10E-05 2.85E-02 0.010cobalt 0 0 0lead 1.40E-05 3.63E-02 0.013manganese 7.90E-04 2.05E+00 0.74mercury 1.20E-06 3.11E-03 0.0011nickel 4.60E-06 1.19E-02 0.0043selenium 2.50E-05 6.48E-02 0.023TOTAL HAPs 3.22 1.16





Renovo Energy Center - MHPSAStartup and Shutdown Operations Emissions DataNatural Gas Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 143 143 180NOx Emissions (lb) 152.3 168 211 70CO Emissions (lb) 3,955 4,350 5,475 1,825VOC Emissions (lb) 1618.1 1,780 2,240 747PM10/2.5 Emissions (lb) 13 14 18 6CO2 Emissions (lb) 382,046 420,251 528,987 176,329Warm StartTime from Ignition until Compliance (minutes) 103 103 140NOx Emissions (lb) 107.5 118 161 69CO Emissions (lb) 2,832 3,115 4,234 1,814VOC Emissions (lb) 1249.9 1,375 1,869 801PM10/2.5 Emissions (lb) 9.1 10 14 6CO2 Emissions (lb) 264,461 290,907 395,408 169,460Hot StartTime from Ignition until Compliance (minutes) 28 28 75NOx Emissions (lb) 40.2 44 118 95CO Emissions (lb) 1,518 1,670 4,473 3,578VOC Emissions (lb) 615.8 677 1,814 1,452PM10/2.5 Emissions (lb) 1.8 2 5 4CO2 Emissions (lb) 43,917 48,309 129,398 103,519Shutdown from 50% loadTime to Shutdown (minutes) 12.5 12.5 30NOx Emissions (lb) 27.5 30 73 145CO Emissions (lb) 595 655 1,572 3,143VOC Emissions (lb) 307.5 338 812 1,624PM10/2.5 Emissions (lb) 1.2 1 3 6CO2 Emissions (lb) 30,611 33,672 80,813 161,626Total SUSD Operating Hour Limitation Per Unit: 460 hrsTotal NOx Emissions Per Unit: 18 tonsTotal CO Emissions Per Unit: 450 tonsTotal VOC Emissions Per Unit: 205 tonsTotal SO2 Emission Per Unit: 0 tonsTotal PM10/2.5 Emissions Per Unit: 1 tonsTotal CO2 Emissions Per Unit: 38,781 tons

Note: MHPSA provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - MHPSAStartup and Shutdown Operations Emissions DataULSD Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 182 182 180NOx Emissions (lb) 289.1 318 315 105CO Emissions (lb) 4,997 5,497 5,436 1,812VOC Emissions (lb) 1655.6 1,821 1,801 600PM10/2.5 Emissions (lb) 156 172 170 57CO2 Emissions (lb) 635,953 699,548 691,861 230,620Warm StartTime from Ignition until Compliance (minutes) 125 125 140NOx Emissions (lb) 201.2 221 248 106CO Emissions (lb) 3,720 4,092 4,583 1,964VOC Emissions (lb) 1328.7 1,462 1,637 702PM10/2.5 Emissions (lb) 105.3 116 130 56CO2 Emissions (lb) 423,050 465,355 521,198 223,370Hot StartTime from Ignition until Compliance (minutes) 37 37 75NOx Emissions (lb) 109.3 120 244 195CO Emissions (lb) 3,315 3,647 7,392 5,914VOC Emissions (lb) 867.2 954 1,934 1,547PM10/2.5 Emissions (lb) 30.9 34 69 55CO2 Emissions (lb) 87,698 96,468 195,543 156,434Shutdown from 50% loadTime to Shutdown (minutes) 14 14 30NOx Emissions (lb) 57.1 63 135 269CO Emissions (lb) 724 796 1,706 3,412VOC Emissions (lb) 234.7 258 553 1,106PM10/2.5 Emissions (lb) 13.1 14 31 62CO2 Emissions (lb) 46,812 51,493 110,343 220,685Total SUSD Operating Hour Limitation Per Unit: 40 hrsTotal NOx Emissions Per Unit: 2 tonsTotal CO Emissions Per Unit: 42 tonsTotal VOC Emissions Per Unit: 15 tonsTotal PM10/2.5 Emissions Per Unit: 1 tonsTotal CO2 Emissions Per Unit: 4,462 tons

Note: MHPSA provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - MHPSASummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs, DBs

August 2015

ULSD Normal Operating Hours: 720 each powerblockULSD SUSD Operating Hours: 40 each powerblockNatural Gas Normal Operating Hours (w/DB): 3,770 each powerblockNatural Gas Normal Operating Hours (w/o DB): 3,770 each powerblockNatural Gas SUSD Operating Hours: 460 each powerblock

Pollutant


ULSD Firing1

(tons)


ULSD SUSD2

(tons)

Annual Emissions from NG Firing with

DBs3 (tons)


NG Firing without DBs4

(tons)




Both Powerblocks

(tons)


Each Powerblock (tons)

NOx 28.94 4.91 96.43 91.13 35.49 256.90 128.45CO 26.48 84.40 58.81 55.58 900.76 1,126.03 563.01

PM10 25.50 2.25 63.03 44.37 2.71 137.87 68.93VOC 13.03 29.69 25.73 24.32 409.37 502.16 251.08SO2 1.47 0.082 7.69 7.24 0.88 17.36 8.68NH3 13.66 0.76 90.22 85.26 10.40 200.31 100.15

H2SO4 0.86 0.048 15.22 14.47 1.77 32.37 16.19GHGs

CO2 232,531 8,924 1,633,503 1,543,928 77,562 3,496,448.38 1,748,224CH4 12.35 0.69 30.95 27.43 3.35 74.76 37.38N2O 2.47 0.14 3.09 2.74 0.33 8.78 4.39

CO2equivalent 233,576 8,982 1,635,199 1,545,431 77,745 3,500,934 1,750,467HAPs

1,3-butadiene 0.030 0.0017 0.0060 0.0054 0.00065 0.044 0.022acetaldehyde 0 0 0.56 0.50 0.061 1.12 0.56

acrolein 0 0 0.090 0.080 0.010 0.18 0.090benzene 0.10 0.0057 0.17 0.15 0.018 0.44 0.22

ethyl benzene 0 0 0.45 0.40 0.049 0.90 0.45formaldehyde 0.43 0.024 2.74 2.59 0.32 6.10 3.05naphthalene 0.065 0.0036 0.018 0.016 0.0020 0.11 0.053

PAH 0.075 0.0041 0.031 0.027 0.0033 0.14 0.070

Renovo Energy Center - MHPSASummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs, DBs

August 2015

Pollutant


ULSD Firing1

(tons)


ULSD SUSD2

(tons)


DBs3 (tons)



(tons)




Both Powerblocks

(tons)



propylene oxide 0 0 0.41 0.36 0.044 0.81 0.41toluene 0 0 1.82 1.62 0.20 3.64 1.82xylenes 0 0 0.91 0.81 0.10 1.82 0.91arsenic 0.021 0.0011 0.0028 0.0024 0.00030 0.027 0.014

beryllium 0.00058 0.000032 0.00017 0.00015 0.000018 0.00094 0.00047cadmium 0.0090 0.00050 0.015 0.013 0.0016 0.040 0.020chromium 0.021 0.0011 0.019 0.017 0.0021 0.060 0.030

cobalt 0 0 0.0012 0.0010 0.00013 0.0023 0.0012lead 0.026 0.0015 0 0 0 0.028 0.014

manganese 1.47 0.082 0.0052 0.0046 0.00057 1.57 0.78mercury 0.0022 0.00012 0.0036 0.0032 0.00039 0.0095 0.0048nickel 0.0086 0.00048 0.029 0.026 0.0031 0.067 0.033

selenium 0.047 0.0026 0.00033 0.00029 0.000036 0.050 0.025TOTAL HAPs 17.15 8.58

5Annual 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, VOC, and CO2. All other pollutant emissions based on the maximum emission rate for all operating loads when firing natural gas.

3Annual Emissions from Natural Gas Firing with DBs based on 3,770 normal operating hours firing natural gas with duct firing 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, VOC, and CO2. All other pollutant emissions based on the maximum emission rate for all operating loads when firing ULSD.


4Annual Emissions from Natural Gas Firing without DBs based on 3,770 normal operating hours firing natural gas without duct firing for each powerblock.

Renovo Energy Center - MHPSADetermination of Potential EmissionsAuxiliary Boilers

August 2015




NOx 0.011 0.33 0.41 0.83CO 0.036 1.08 1.35 2.70

PM10 0.0033 0.099 0.124 0.25VOC 0.0040 0.12 0.15 0.30SO2 0.00050 0.015 0.019 0.038



CO2 53.06 4,377.45 8,754.90CH4 1.00E-03 0.083 0.17N2O 1.00E-04 0.0083 0.017CO2e -- 4,381.97 8,763.94










Renovo Energy Center - MHPSADetermination of Potential EmissionsDiesel Engines

August 2015






NOx + VOC 4.8 12.77 3.19 6.39CO 2.6 6.92 1.73 3.46

PM10 0.15 0.40 0.10 0.20VOC 1.00 2.66 0.67 1.33SO2

1 --- 0.01 0.003 0.0064



Fire Pump Engine




NOx + VOC 3 1.653 0.21CO 2.6 1.433 0.18

PM10 0.15 0.083 0.010VOC 1.00 0.551 0.069SO2

1 --- 0.003 0.00034




Renovo Energy Center - MHPSADetermination of Potential EmissionsDiesel Engines

August 2015





Total 7.97E-03 1.59E-02 8.31E-04




Renovo Energy Center - MHPSADetermination of Potential EmissionsWater Bath Heater

August 2015


Emission Pollutant Factor Emissions Emissions


NOx 0.04 0.72 3.15CO 0.08 1.44 6.31


(kg/MMBtu) (tpy)

CO2 53.06 9203.15CH4 1.00E-03 0.17N2O 1.00E-04 0.02CO2e -- 9,212.66

Emission Factor

HAPs (lb/MMcf)

benzene 2.10E-03 1.62E-04formaldehyde 7.50E-02 5.80E-03

hexane 1.8 1.39E-01naphthalene 6.10E-04 4.71E-05

toluene 3.40E-03 2.63E-04POM 8.82E-05 6.82E-06

Total HAP emissions: 1.45E-01

Emission factors for NOx, CO, PM10, VOC, and SO2 are based on RBLC database entries for BACT/BATEmission factors for HAPs are based on AP-42, Section 1.4.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

Renovo Energy Center - MHPSADetermination of Greehouse Gas EmissionsDiesel Engines

August 2015





CO2 73.96 684.35 1 684.35CH4 3.00E-03 0.028 25 0.69N2O 6.00E-04 0.0056 298 1.65




Emission Global CO2


CO2 73.96 35.67 1 35.67CH4 3.00E-03 0.0014 25 0.036N2O 6.00E-04 0.00029 298 0.086



Renovo Energy Center - MHPSADetermination of Potential EmissionsULSD Storage Tank

August 2015

REC Tank_1

Williamsport

Pennsylvania




120



N

7

1







Secondary Seal None


Deck Type: Bolted

Construction: Sheet



Rim-Seal System



State:

Company:

Type of Tank:

Description:

Tank Dimensions

Diameter (ft):

Volume (gallons):

Turnovers:


No. of Columns:


City:



Identification



August 2015

Quantity

1

1

7

1

41

1

116

1


Vacuum Breaker (10-in. Diam.)/Weighted Mech. Actuation, Gask.

Deck Fitting/Status









August 2015


Liquid




All 51.52 46.58 56.46 49.92 0.0048 N/A N/A 130 188



ComponentsRim Seal

LossWithdrawl

LossDeck Fitting

LossDeck Seam

LossTotal

Emissions

Distillate fuel oil no. 2 2.07 73.81 10.1 4.35 90.34


Losses(lbs)






Daily Liquid Surf.


Renovo Energy Center - MHPSADetermination of Greehouse Gas EmissionsCircuit Breakers

August 2015

SF6 Global CO2



0.0051



Renovo Energy Center - SiemensFacility-Wide Maximum Potential EmissionsTons Per Year

August 2015

Pollutant PowerblocksAuxiliary Boilers

Diesel Generators


ULSD storage

tankCircuit


TotalNOx 355.40 0.83 6.39 0.21 3.15 --- --- 366.0CO 691.25 2.70 3.46 0.18 6.31 --- --- 703.9


CO2e 3,635,641 8,763.94 686.70 35.79 9,212.66 --- 116.28 3,654,456H2SO4 13.44 0.0069 --- --- --- --- --- 13.4HAPs 18.16 0.14 0.016 0.00083 0.145 --- --- 18.5

Renovo Energy CenterRaw Data for Siemens Equipment

August 2015

Operating Point 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9

Ambient Temperature °F 91 91 91 91 51 51 51 51 6 6 6 6 91 91 91 51 51 51 6 6 6Ambient Pressure psia 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42Ambient Relative Humidity % 42 42 42 42 60 60 60 60 60 60 60 60 42 42 42 60 60 60 60 60 60

Plant StatusHRSG Duct Burner On Off Off Off On Off Off Off On Off Off Off n/a n/a n/a n/a n/a n/a n/a n/a n/aSCR Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingCO Catalyst Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating Operating OperatingEvaporative Cooler State on/off On On On Off Off Off Off Off Off Off Off Off Off Off Off Off Off Off Off Off OffGas Turbine Load % 100 100 100 40 100 100 100 40 100 100 100 40 100 75 61 100 75 54 100 75 54Turbine Diluent Injection Type None None None None None None None None None None None None Water Water Water Water Water Water Water Water Water

Fuel DataFuel Type NG NG NG NG NG NG NG NG NG NG NG NG ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSDHHV Btu/lb 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 19,785 19,785 19,785 19,785 19,785 19,785 19,785 19,785 19,785LHV Btu/lb 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 18,491 18,491 18,491 18,491 18,491 18,491 18,491 18,491 18,491Fuel Molecular Weight lb/mole - - - - - - - - - - - - - - - - - - - - -Fuel Bound Nitrogen Wt % 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.4644 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015 0.015Fuel Sulfur Content gr/100 scf 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.0015% 0.0015% 0.0015% 0.0015% 0.0015% 0.0015% 0.0015% 0.0015% 0.0015%

GT Fuel Flow lb/hr 113,559 113,587 111,360 57,425 119,330 119,065 116,754 62,994 127,739 127,725 127,014 67,526 119,662 97,196 84,512 125,091 101,649 82,235 125,986 102,486 83,681MMBtu/hr HHV1 2,645 2,646 2,594 1,338 2,780 2,774 2,720 1,467 2,976 2,975 2,959 1,573 2,368 1,923 1,672 2,475 2,011 1,627 2,493 2,028 1,656w/5% margin2 2,778 2,778 2,724 1,405 2,919 2,912 2,856 1,541 3,124 3,124 3,107 1,652 2,486 2,019 1,756 2,599 2,112 1,708 2,617 2,129 1,738

DB Fuel Flow lb/hr 28,405 0 0 0 17,588 0 0 0 7,806 0 0 0 0 0 0 0 0 0 0 0 0MMBtu/hr HHV1 662 0 0 0 410 0 0 0 182 0 0 0 0 0 0 0 0 0 0 0 0w/5% margin2 695 0 0 0 430 0 0 0 191 0 0 0 0 0 0 0 0 0 0 0 0

Total Heat Consumption MMBtu/hr HHV 3,307 2,646 2,594 1,338 3,189 2,774 2,720 1,467 3,157 2,975 2,959 1,573 2,368 1,923 1,672 2,475 2,011 1,627 2,493 2,028 1,656w/5% margin2 3,472 2,778 2,724 1,405 3,349 2,912 2,856 1,541 3,315 3,124 3,107 1,652 2,486 2,019 1,756 2,599 2,112 1,708 2,617 2,129 1,738

HRSG Exit Exhaust GasTemperature °F 203 217 218 196 200 211 213 193 209 214 216 197 236 216 212 240 214 207 251 216 207Mass Flow lb/hr 4,852,860 4,824,455 4,823,546 2,794,685 5,079,811 5,062,026 5,060,167 2,962,015 5,288,326 5,280,520 5,356,596 3,134,932 4,740,925 3,738,293 3,365,733 5,129,740 3,879,170 3,271,120 5,355,372 3,912,232 3,265,846

w/5% margin2 5,095,503 5,065,678 5,064,723 2,934,419 5,333,802 5,315,127 5,313,175 3,110,116 5,552,742 5,544,546 5,624,426 3,291,679 4,977,971 3,925,208 3,534,020 5,386,227 4,073,129 3,434,676 5,623,141 4,107,844 3,429,138Std Volume Flow acfm 1,421,596 1,435,489 1,438,638 803,110 1,467,927 1,483,424 1,486,452 843,490 1,543,373 1,551,102 1,578,624 895,755 1,436,318 1,098,250 981,410 1,551,097 1,127,666 940,594 1,636,188 1,135,517 935,209

HRSG Exit Exhaust Gas Emissionsppmvd @ 15% O2 25 25 25 25 25 25 25 25 25 25 25 25 75 75 75 75 75 75 75 75 75lb/hr as NO2 308.75 247.5 242.5 122.5 298.75 260 255 133.75 293.75 277.5 277.5 143.75 707.5 568.75 492.5 738.75 595 477.5 741.25 597.5 483.75lb/hr w/5% margin2 324.19 259.88 254.63 128.63 313.69 273.00 267.75 140.44 308.44 291.38 291.38 150.94 742.88 597.19 517.13 775.69 624.75 501.38 778.31 627.38 507.94ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 6 6 6 6 6 6 6 6 6lb/hr as NO2 24.7 19.8 19.4 9.8 23.9 20.8 20.4 10.7 23.5 22.2 22.2 11.5 56.6 45.5 39.4 59.1 47.6 38.2 59.3 47.8 38.7lb/hr w/5% margin2 25.94 20.79 20.37 10.29 25.10 21.84 21.42 11.24 24.68 23.31 23.31 12.08 59.43 47.78 41.37 62.06 49.98 40.11 62.27 50.19 40.64ppmvd @ 15% O2 10 10 10 10 10 10 10 10 10 10 10 10 20 20 20 20 20 20 20 20 20lb/hr 75.5 60.5 59.0 30.0 72.5 63.5 62.0 33.0 71.5 67.5 67.5 35.0 115.0 92.5 80.0 120.0 96.5 77.5 120.5 97.0 78.5lb/hr w/5% margin2 79.3 63.5 62.0 31.5 76.1 66.7 65.1 34.7 75.1 70.9 70.9 36.8 120.8 97.1 84.0 126.0 101.3 81.4 126.5 101.9 82.4ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2 4 4 4 4 4 4 4 4 4lb/hr 15.1 12.1 11.8 6 14.5 12.7 12.4 6.6 14.3 13.5 13.5 7 23 18.5 16 24 19.3 15.5 24.1 19.4 15.7lb/hr w/5% margin2 15.86 12.71 12.39 6.30 15.23 13.34 13.02 6.93 15.02 14.18 14.18 7.35 24.15 19.43 16.80 25.20 20.27 16.28 25.31 20.37 16.49ppmvd @ 15% O2 4.00 1 1 1 2.86 1 1 1 1.86 1 1 1 1 1 1 1 1 1 1 1 1lb/hr as methane 17.16 3.5 3.4 1.7 12.16 3.7 3.6 1.9 7.72 3.9 3.9 2.0 3.3 2.7 2.3 3.5 2.8 2.3 3.5 2.8 2.3lb/hr w/5% margin2 18.02 3.68 3.57 1.79 12.76 3.89 3.78 2.00 8.11 4.10 4.10 2.10 3.47 2.84 2.42 3.68 2.94 2.42 3.68 2.94 2.42ppmvd @ 15% O2 2.8 1 1 1 2 1 1 1 1.3 1 1 1 1 1 1 1 1 1 1 1 1lb/hr as methane 12 3.5 3.4 1.7 8.5 3.7 3.6 1.9 5.4 3.9 3.9 2 3.3 2.7 2.3 3.5 2.8 2.3 3.5 2.8 2.3lb/hr w/5% margin2 12.60 3.68 3.57 1.79 8.93 3.89 3.78 2.00 5.67 4.10 4.10 2.10 3.47 2.84 2.42 3.68 2.94 2.42 3.68 2.94 2.42lb/hr 398,956 320,084 313,738 158,328 385,069 335,630 328,995 173,557 379,952 358,207 358,085 185,305 392,724 315,864 273,243 410,846 330,314 265,089 412,072 331,606 268,561lb/hr w/10% margin4 438,852 352,092 345,112 174,161 423,576 369,193 361,895 190,913 417,947 394,028 393,894 203,836 431,996 347,450 300,567 451,931 363,345 291,598 453,279 364,767 295,417lb/MMBtu w/margin 132.7 133.1 133.0 130.2 132.8 133.1 133.1 130.1 132.4 132.4 133.1 129.6 182.5 180.7 179.8 182.6 180.7 179.2 181.8 179.9 178.4ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5lb/hr 22.9 18.3 18 9.1 22.1 19.2 18.8 9.9 21.8 20.5 20.5 10.6 17.5 14.1 12.2 18.3 14.7 11.8 18.3 14.8 12lb/hr w/5% margin2 24.05 19.22 18.90 9.56 23.21 20.16 19.74 10.40 22.89 21.53 21.53 11.13 18.38 14.81 12.81 19.22 15.44 12.39 19.22 15.54 12.60lb/hr as SO2 3.9 3.1 3 1.6 3.7 3.2 3.2 1.7 3.7 3.5 3.4 1.9 3.7 3 2.7 3.9 3.2 2.6 3.9 3.2 2.6lb/hr w/20% margin5 4.68 3.72 3.6 1.92 4.44 3.84 3.84 2.04 4.44 4.2 4.08 2.28 4.44 3.6 3.24 4.68 3.84 3.12 4.68 3.84 3.12lb/hr 18.6 11.4 11.4 8 16.5 12.1 12.1 8 14.7 12.7 12.9 8 30 30 30 30 30 30 30 30 30lb/hr w/10% margin4 20.46 12.54 12.54 8.8 18.15 13.31 13.31 8.8 16.17 13.97 14.19 8.8 33 33 33 33 33 33 33 33 33lb/MMBtu 0.0056 0.0043 0.0044 0.0060 0.0052 0.0044 0.0044 0.0055 0.0047 0.0043 0.0044 0.0051 0.013 0.016 0.018 0.012 0.015 0.018 0.012 0.015 0.018lb/hr 1.40 1.10 1.10 0.60 1.40 1.20 1.20 0.70 1.30 1.30 1.30 0.70 1.40 1.10 1.00 1.40 1.20 1.00 1.40 1.20 1.00lb/hr w/10% margin4 1.54 1.21 1.21 0.66 1.54 1.32 1.32 0.77 1.43 1.43 1.43 0.77 1.54 1.21 1.10 1.54 1.32 1.10 1.54 1.32 1.10ppbvd @ 15% O2 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100lb/hr 0.81 0.7 0.7 0.4 0.78 0.7 0.7 0.4 0.77 0.8 0.8 0.4 0.7 0.5 0.5 0.7 0.6 0.5 0.7 0.6 0.5lb/hr w/5% margin2 0.85 0.74 0.74 0.42 0.82 0.74 0.74 0.42 0.81 0.84 0.84 0.42 0.74 0.53 0.53 0.74 0.63 0.53 0.74 0.63 0.53

NOx (pre-control)3

CO (pre-control)3

VOC (pre-control)3

H2SO4

CH2O

PM

NOx (post-control)

CO (post-control)

VOC (post-control)

NH3

CO2

SOx

Renovo Energy CenterRaw Data for Siemens EquipmentNotes

August 2015

1 Heat consumption in MMBtu/hr HHV determined using the heat consumption rates in lb/hr and the HHV of each fuel type.

2 A 5% margin was added to all heat input rates as well as lb/hr emission rates of NOx, CO, VOC, NH3, and CH2O to account for equipment degradation and site variability.

3 Pre-control emission rates were provided by Siemens in terms of control efficiency. All ppm and lb/hr values reflect control efficiencies of 92% for NOx, 80% for CO, and 30% for VOC emissions with duct firing. Without duct firing, VOC emissions are not controlled.

4 A 10% margin was added to emission rates for CO2, PM, and H2SO4 to account for equipment degradation and site variability.

5 A margin of 20% was added to the SO2 emission rates to account for equipment degradation, site variability, and fuel variability.

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs, DBs firing Natural Gas

August 2015

Maximum Fuel Flow Rate: 149,062 lb/hr eachFuel Gross Heating Value: 23,294 Btu/lbCT rated heat input capacity: 2,976 MMBtu/hr eachCT max heat input capacity: 3,124 MMBtu/hr eachDB rated heat input capacity: 662 MMBtu/hr eachDB max heat input capacity: 695 MMBtu/hr eachPowerblock rated heat input capacity: 3,307 MMBtu/hr eachPowerblock max heat input capacity: 3,472 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 7,540 hours each (not including SUSD) 1







CO2 -- 423,576 1,596,881CH4 1.0E-03 7.66 28.86N2O 1.0E-04 0.77 2.89CO2equivalent -- 423,995.4 1,598,463HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)

1,3-butadiene 4.30E-07 1.49E-03 0.0056acetaldehyde 4.00E-05 1.39E-01 0.52acrolein 6.40E-06 2.22E-02 0.084benzene 1.20E-05 4.17E-02 0.157ethyl benzene 3.20E-05 1.11E-01 0.42formaldehyde2 -- 0.82 3.09naphthalene 1.30E-06 4.51E-03 0.0170PAH 2.20E-06 7.64E-03 0.0288propylene oxide 2.90E-05 1.01E-01 0.38toluene 1.30E-04 4.51E-01 1.70

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs, DBs firing Natural Gas

August 2015

xylenes 6.50E-05 2.26E-01 0.85arsenic 1.96E-07 6.81E-04 0.00257beryllium 1.18E-08 4.09E-05 0.000154cadmium 1.08E-06 3.74E-03 0.0141chromium 1.37E-06 4.77E-03 0.0180cobalt 8.24E-08 2.86E-04 0.00108lead 0 0 0manganese 3.73E-07 1.29E-03 0.0049mercury 2.55E-07 8.85E-04 0.00334nickel 2.06E-06 7.15E-03 0.0270selenium 2.35E-08 8.17E-05 0.000308TOTAL HAPs 1.94 7.33


3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O obtained from 40 CFR 98.4Emission factors obtained from EPA's AP-42, Table 3.1-3, except for formaldehyde, which was obtained from the vendor.

2Emission factors provided by vendor. The maximum emission rate for the 51°F operating scenarios with duct firing was used to calculate maximum potential emissions.

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

Maximum Fuel Flow Rate: 134,126 lb/hr eachFuel Gross Heating Value: 23,294 Btu/lbCT rated heat input capacity: 2,976 MMBtu/hr eachCT max heat input capacity: 3,124 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 0 hours each (not including SUSD) 1

Maximum annual heat input: 0 MMBtu/yr each (not including SUSD)




NOx 2 23.31 0CO 2 14.18 0PM10 -- 14.19 0VOC 2 4.10 0SO2 -- 4.2 0NH3 5 21.53 0H2SO4 -- 1.43 0GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)

CO2 -- 394,028 0CH4 1.0E-03 6.89 0N2O 1.0E-04 0.69 0CO2equivalent -- 394,405.2 0HAPs 4 (lb/MMBtu) (lb/hr) (ton/yr)

1,3-butadiene 4.30E-07 1.34E-03 0acetaldehyde 4.00E-05 1.25E-01 0acrolein 6.40E-06 2.00E-02 0benzene 1.20E-05 3.75E-02 0ethyl benzene 3.20E-05 1.00E-01 0formaldehyde2 -- 0.84 0naphthalene 1.30E-06 4.06E-03 0PAH 2.20E-06 6.87E-03 0propylene oxide 2.90E-05 9.06E-02 0toluene 1.30E-04 4.06E-01 0xylenes 6.50E-05 2.03E-01 0arsenic 1.96E-07 6.13E-04 0beryllium 1.18E-08 3.68E-05 0cadmium 1.08E-06 3.37E-03 0chromium 1.37E-06 4.29E-03 0

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing Natural Gas

August 2015

cobalt 8.24E-08 2.57E-04 0lead 0 0 0manganese 3.73E-07 1.16E-03 0mercury 2.55E-07 7.96E-04 0nickel 2.06E-06 6.43E-03 0selenium 2.35E-08 7.35E-05 0TOTAL HAPs 1.85 0


2Emission factors provided by vendor. The maximum emission rate from all available scenarios without duct firing was used to calculate maximum potential emissions.3Emission factor for CO2 provided by vendor. Emission factors for CH4 and N2O 4Emission factors obtained from EPA's AP-42, Table 3.1-3, except for formaldehyde, which was obtained from the vendor.

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

Maximum Fuel Flow Rate: 132,285 lb/hr eachFuel Gross Heating Value: 19,785 Btu/lbCT rated heat input capacity: 2,493 MMBtu/hr eachCT max heat input capacity: 2,617 MMBtu/hr eachDB rated heat input capacity: 0 MMBtu/hr eachDB max heat input capacity: 0 MMBtu/hr eachPowerblock rated heat input capacity: 2,493 MMBtu/hr eachPowerblock max heat input capacity: 2,617 MMBtu/hr eachAnnual capacity factor: 100 %Maximum potential operating hours: 720 hours each (not including SUSD) 1





NOx 6 62.27 22.42CO 4 25.31 9.11PM10 -- 33 11.88VOC 1 3.68 1.32SO2 -- 4.68 1.68NH3 5 19.22 6.92H2SO4 -- 1.54 0.55GHGs 3 (kg/MMBtu) (lb/hr) (ton/yr)


1,3-butadiene 1.60E-05 4.19E-02 0.015acetaldehyde 0 0 0acrolein 0 0 0benzene 5.50E-05 1.44E-01 0.052ethyl benzene 0 0 0formaldehyde2 -- 0.85 0.31naphthalene 3.50E-05 9.16E-02 0.033PAH 4.00E-05 1.05E-01 0.038propylene oxide 0 0 0toluene 0 0 0xylenes 0 0 0

Renovo Energy Center - SiemensDetermination of Potential EmissionsPowerblocks- Turbines, HRSGs firing ULSD

August 2015

arsenic 1.10E-05 2.88E-02 0.010beryllium 3.10E-07 8.11E-04 0.00029cadmium 4.80E-06 1.26E-02 0.0045chromium 1.10E-05 2.88E-02 0.010cobalt 0 0 0lead 1.40E-05 3.66E-02 0.013manganese 7.90E-04 2.07E+00 0.74mercury 1.20E-06 3.14E-03 0.0011nickel 4.60E-06 1.20E-02 0.0043selenium 2.50E-05 6.54E-02 0.024TOTAL HAPs 3.49 1.26





Renovo Energy Center - SiemensStartup and Shutdown Operations Emissions DataNatural Gas Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 35 35 90NOx Emissions (lb) 94.8 104.28 268 179CO Emissions (lb) 574 631.4 1,624 1,082VOC Emissions (lb) 65.7 72.27 186 124SO2 Emissions (lb) 1.1 1.21 3 2PM10/2.5 Emissions (lb) 5.2 5.72 15 10CO2 Emissions (lb) 112,286 123,514.6 317,609 211,739Warm StartTime from Ignition until Compliance (minutes) 35 35 90NOx Emissions (lb) 113 124.3 320 213CO Emissions (lb) 542 596.2 1,533 1,022VOC Emissions (lb) 60.7 66.77 172 114SO2 Emissions (lb) 1.3 1.43 4 2PM10/2.5 Emissions (lb) 6.2 6.82 18 12CO2 Emissions (lb) 139,862 153,848.2 395,610 263,740Hot StartTime from Ignition until Compliance (minutes) 30 30 75NOx Emissions (lb) 97.2 106.92 267 214CO Emissions (lb) 463 509.3 1,273 1,019VOC Emissions (lb) 60.4 66.44 166 133SO2 Emissions (lb) 1.1 1.21 3 2PM10/2.5 Emissions (lb) 5.2 5.72 14 11CO2 Emissions (lb) 111,974 123,171.4 307,929 246,343Hot Start On-the-FlyTime from Ignition until Compliance (minutes) 32 32 75NOx Emissions (lb) 87 95.7 224 179CO Emissions (lb) 825 907.5 2,127 1,702VOC Emissions (lb) 111 122.1 286 229SO2 Emissions (lb) 0.8 0.88 2 2PM10/2.5 Emissions (lb) 4.7 5.17 12 10CO2 Emissions (lb) 87,273 96,000.3 225,001 180,001

Renovo Energy Center - SiemensStartup and Shutdown Operations Emissions DataNatural Gas Firing

August 2015

Shutdown from 50% loadTime to Shutdown (minutes) 18 18 30NOx Emissions (lb) 78.5 86.35 144 288CO Emissions (lb) 244 268.4 447 895VOC Emissions (lb) 97.9 107.69 179 359SO2 Emissions (lb) 0.4 0.44 1 1PM10/2.5 Emissions (lb) 2.5 2.75 5 9CO2 Emissions (lb) 37,991 41,790.1 69,650 139,300Total SUSD Operating Hour Limitation Per Unit: 460 hrsTotal NOx Emissions Per Unit: 55 tonsTotal CO Emissions Per Unit: 225 tonsTotal VOC Emissions Per Unit: 45 tonsTotal SO2 Emission Per Unit: 0 tonsTotal PM10/2.5 Emissions Per Unit: 2 tonsTotal CO2 Emissions Per Unit: 50,940 tons

Note: Siemens provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - SiemensStartup and Shutdown Operations Emissions DataULSD Firing

August 2015

ProposedScenario 1 Unit w/margin Limits lb/hrCold StartTime from Ignition until Compliance (minutes) 35 35 90NOx Emissions (lb) 123 135.3 348 232CO Emissions (lb) 1,763 1,939.3 4,987 3,325VOC Emissions (lb) 195 214.5 552 368SO2 Emissions (lb) 1.2 1.32 3 2PM10/2.5 Emissions (lb) 16.2 17.82 46 31CO2 Emissions (lb) 122,058 134,263.8 345,250 230,167Warm StartTime from Ignition until Compliance (minutes) 35 35 90NOx Emissions (lb) 132 145.2 373 249CO Emissions (lb) 1,836 2,019.6 5,193 3,462VOC Emissions (lb) 205 225.5 580 387SO2 Emissions (lb) 1.2 1.32 3 2PM10/2.5 Emissions (lb) 16.3 17.93 46 31CO2 Emissions (lb) 130,183 143,201.3 368,232 245,488Hot StartTime from Ignition until Compliance (minutes) 32 32 75NOx Emissions (lb) 122 134.2 315 252CO Emissions (lb) 1,576 1,733.6 4,063 3,251VOC Emissions (lb) 205 225.5 529 423SO2 Emissions (lb) 1 1.1 3 2PM10/2.5 Emissions (lb) 14.8 16.28 38 31CO2 Emissions (lb) 110,544 121,598.4 284,996 227,997Shutdown from 50% loadTime to Shutdown (minutes) 18 18 30NOx Emissions (lb) 102 112.2 187 374CO Emissions (lb) 332 365.2 609 1,217VOC Emissions (lb) 133.4 146.74 245 489SO2 Emissions (lb) 0.5 0.55 1 2PM10/2.5 Emissions (lb) 9 9.9 17 33CO2 Emissions (lb) 54,276 59,703.6 99,506 199,012

Renovo Energy Center - SiemensStartup and Shutdown Operations Emissions DataULSD Firing

August 2015

Total SUSD Operating Hour Limitation Per Unit: 40 hrsTotal NOx Emissions Per Unit: 6 tonsTotal CO Emissions Per Unit: 54 tonsTotal VOC Emissions Per Unit: 8 tonsTotal SO2 Emission Per Unit: 0 tonsTotal PM10/2.5 Emissions Per Unit: 1 tonsTotal CO2 Emissions Per Unit: 4,594 tons

Note: Siemens provided SUSD emission values without margin. Emission values presented reflect a margin of 10% to account for equipment degradation, and site and operational variability.

Renovo Energy Center - SiemensSummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs, DBs

August 2015

ULSD Normal Operating Hours: 720 each powerblockULSD SUSD Operating Hours: 40 each powerblockNatural Gas Normal Operating Hours (w/DB): 7,540 each powerblockNatural Gas Normal Operating Hours (w/o DB): 0 each powerblockNatural Gas SUSD Operating Hours: 460 each powerblock

Pollutant


ULSD Firing1

(tons)


ULSD SUSD2

(tons)


DBs3 (tons)



(tons)




Both Powerblocks

(tons)



NOx 44.83 11.66 189.22 0 109.70 355.40 177.70CO 18.22 107.99 114.80 0 450.24 691.25 345.63

PM10 23.76 1.26 136.85 0 4.98 166.85 83.43VOC 2.65 16.86 67.29 0 90.85 177.65 88.82SO2 3.37 0.085 33.48 0 0.97 37.91 18.95NH3 13.83 0.77 174.97 0 9.90 199.47 99.74

H2SO4 1.11 0.062 11.61 0 0.66 13.44 6.72GHGs

CO2 326,361 9,188 3,193,762 0 101,880 3,631,191 1,815,596CH4 12.46 0.69 57.72 0 3.17 74.04 37.02N2O 2.49 0.14 5.77 0 0.32 8.72 4.36

CO2equivalent 327,415 9,247 3,196,925 0 102,053 3,635,641 1,817,820HAPs

1,3-butadiene 0.030 0.0017 0.011 0 0.00062 0.044 0.022acetaldehyde 0 0 1.05 0 0.057 1.10 0.55

acrolein 0 0 0.17 0 0.0092 0.18 0.088benzene 0.10 0.0058 0.31 0 0.017 0.44 0.22

ethyl benzene 0 0 0.84 0 0.046 0.88 0.44formaldehyde 0.61 0.034 6.18 0 0.39 7.21 3.60naphthalene 0.066 0.0037 0.034 0 0.0019 0.11 0.053

PAH 0.075 0.0042 0.058 0 0.0032 0.14 0.070

Renovo Energy Center - SiemensSummary of Worst-Case Annual EmissionsPowerblocks- Turbines, HRSGs, DBs

August 2015

Pollutant


ULSD Firing1

(tons)


ULSD SUSD2

(tons)


DBs3 (tons)



(tons)




Both Powerblocks

(tons)



propylene oxide 0 0 0.76 0 0.042 0.80 0.40toluene 0 0 3.40 0 0.19 3.59 1.80xylenes 0 0 1.70 0 0.093 1.80 0.90arsenic 0.021 0.0012 0.0051 0 0.00028 0.027 0.014

beryllium 0.00058 0.000032 0.00031 0 0.000017 0.00094 0.00047cadmium 0.0090 0.00050 0.028 0 0.0015 0.039 0.020chromium 0.021 0.0012 0.036 0 0.0020 0.060 0.030

cobalt 0 0 0.0022 0 0.00012 0.0023 0.0011lead 0.026 0.0015 0 0 0 0.028 0.014

manganese 1.49 0.083 0.0098 0 0.00054 1.58 0.79mercury 0.0023 0.00013 0.0067 0 0.00037 0.0094 0.0047nickel 0.0087 0.00048 0.054 0 0.0030 0.066 0.033

selenium 0.047 0.0026 0.00062 0 0.000034 0.050 0.025TOTAL HAPs 2.51 14.65 18.16 9.08

5Annual 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, VOC, SO2, and CO2. All other pollutant emissions based on the maximum emission rate for all operating loads when firing natural gas.

3Annual Emissions from Natural Gas Firing with DBs based on 7,540 normal operating hours firing natural gas with duct firing 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, VOC, SO2, and CO2. All other pollutant emissions based on the maximum emission rate for all operating loads when firing ULSD.


4Annual Emissions from Natural Gas Firing without DBs based on zero operating hours firing natural gas without duct firing for each powerblock.

Renovo Energy Center - SiemensDetermination of Potential EmissionsAuxiliary Boilers

August 2015




NOx 0.011 0.33 0.41 0.83CO 0.036 1.08 1.35 2.70

PM10 0.0033 0.099 0.124 0.25VOC 0.0040 0.12 0.15 0.30SO2 0.00050 0.015 0.019 0.038



CO2 53.06 4,377.45 8,754.90CH4 1.00E-03 0.083 0.17N2O 1.00E-04 0.0083 0.017CO2e -- 4,381.97 8,763.94










Renovo Energy Center - SiemensDetermination of Potential EmissionsDiesel Engines

August 2015






NOx + VOC 4.8 12.77 3.19 6.39CO 2.6 6.92 1.73 3.46

PM10 0.15 0.40 0.10 0.20VOC 1.00 2.66 0.67 1.33SO2

1 --- 0.01 0.003 0.0064



Fire Pump Engine




NOx + VOC 3 1.653 0.21CO 2.6 1.433 0.18

PM10 0.15 0.083 0.010VOC 1.00 0.551 0.069SO2

1 --- 0.003 0.00034




Renovo Energy Center - SiemensDetermination of Potential EmissionsDiesel Engines

August 2015





Total 7.97E-03 1.59E-02 8.31E-04




Renovo Energy Center - SiemensDetermination of Potential EmissionsWater Bath Heater

August 2015


Emission Pollutant Factor Emissions Emissions


NOx 0.04 0.72 3.15CO 0.08 1.44 6.31


(kg/MMBtu) (tpy)

CO2 53.06 9,203.15CH4 1.00E-03 0.173N2O 1.00E-04 0.017CO2e -- 9,212.66

Emission Factor Emissions

HAPs (lb/MMcf) (tpy)

benzene 2.10E-03 1.62E-04formaldehyde 7.50E-02 5.80E-03

hexane 1.8 1.39E-01naphthalene 6.10E-04 4.71E-05

toluene 3.40E-03 2.63E-04POM 8.82E-05 6.82E-06

Total HAP emissions: 0.145

Emission factors for NOx, CO, PM10, VOC, and SO2 are based on RBLC database entries for BACT/BATEmission factors for HAPs are based on AP-42, Section 1.4.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

Renovo Energy Center - SiemensDetermination of Greehouse Gas EmissionsDiesel Engines

August 2015





CO2 73.96 684.35 1 684.35CH4 3.00E-03 0.028 25 0.69N2O 6.00E-04 0.0056 298 1.65




Emission Global CO2


CO2 73.96 35.67 1 35.67CH4 3.00E-03 0.0014 25 0.036N2O 6.00E-04 0.00029 298 0.086



Renovo Energy Center - SiemensDetermination of Potential EmissionsULSD Storage Tank

August 2015

REC Tank_1

Williamsport

Pennsylvania




120



N

7

1







Secondary Seal None


Deck Type: Bolted

Construction: Sheet



City:



Identification



State:

Company:

Type of Tank:

Description:

Tank Dimensions

Diameter (ft):

Volume (gallons):

Turnovers:


No. of Columns:


Rim-Seal System



August 2015

Quantity

1

1

7

1

41

1

116

1Vacuum Breaker (10-in. Diam.)/Weighted Mech. Actuation, Gask.

Deck Fitting/Status










August 2015


Liquid




All 51.52 46.58 56.46 49.92 0.0048 N/A N/A 130 188



ComponentsRim Seal

LossWithdrawl

LossDeck Fitting

LossDeck Seam

LossTotal

Emissions

Distillate fuel oil no. 2

2.07 73.81 10.1 4.35 90.34

Daily Liquid Surf.





Losses(lbs)




Renovo Energy Center - SiemensDetermination of Greehouse Gas EmissionsCircuit Breakers

August 2015

SF6 Global CO2



0.0051



Attachment D

g GE Energy Renovo Spec. No. T218

Drawing Number: 100A5986GE COMPANY PROPRIETARY

Page 7 of 7Date: 18-Jun-2015 Rev. B

By : M. Boisclair

SIZE DWG NO SH REV

A 100A5986 1 B

REV DATE (dd-mmm-yyyy) APPROVED

- Preliminary Issue 30-Mar-2015 C. MatisA Preliminary Issue 06-May-2015 C. MatisB Preliminary Issue 18-Jun-2015 D. Rancruel

SIZE A CAGE CODE NONE DWG NO 100A5986SCALE NONE PA# pre-ITO SHEET 1 of 7

1x17HA.02 Single Shaft

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

MADE FOR: IPS # 1019085

FIRST MADE FOR:

SIGNATURES DATE (dd-mmm-yyyy)

g GE Energy

Renovo

MDL - T218

30-Mar-2015

30-Mar-2015

© COPYRIGHT 2015 General Electric - Proprietary InformationAll Rights Reserved. This document contains proprietary information. No part of this document may be used by or disclosed to others, reproduced, transmitted, stored in a retrieval system nor translated into any human or computer language, in any form

or any means, electronic, mechanical magnetic, optical, chemical, manual or otherwise, without the prior written permission of the General Electric Company.

PREPARED BY

SYSTEM ENGINEER

ISSUED

PROJECT ENGINEER

GENERAL ELECTRIC COMPANY GENERAL ELECTRIC

INTERNATIONAL, INC. POWER PLANT SYSTEMS

Bechtel

M. Boisclair

D. Ziobroski




By : M. Boisclair

Drawing Revision Status

Revision Date Description- 30-Mar-2015 -A 06-May-2015 Added GT Diluent Injection Flow to output pageB 18-Jun-2015 Changed sulfur content from 1 gr/100SCF to 0.4 gr 100SCF.




By : M. Boisclair


OPERATING POINT 1 2 3 4 5Case Description Unfired Unfired Unfired Unfired UnfiredSITE CONDITIONSAmbient Temperature °F -0.7 -0.7 5.8 5.8 5.8Ambient Pressure psia 14.4 14.4 14.4 14.4 14.4Ambient Relative Humidity % 60 60 60 60 60

PLANT STATUSHRSG Duct Burner Not Present Not Present Not Present Not Present Not PresentSCR Operating Operating Operating Operating OperatingCO Catalyst Operating Operating Operating Operating OperatingEvaporative Cooler state (On or Off) Off Off Off Off OffGas Turbine Load % BASE 40% BASE 95% 37%Gas Turbines Operating 1 1 1 1 1GT Diluent Injection Type None None None None NoneGT Diluent Injection Flow (per GT) 10^3 lb/hr 0 0 0 0 0

FUEL DATAFuel Type NG NG NG NG NGHHV BTU/lb 22992 22992 22992 22992 22992LHV BTU/lb 20732 20732 20732 20732 20732Fuel Mol. Wt. lb/mole 16.93 16.93 16.93 16.93 16.93Fuel Bound Nitrogen Wt % 0 0 0 0 0Fuel Sulfur Content grains/100 SCF @ 60°F 0.4 0.4 0.4 0.4 0.4

GT Heat Consumption per unit with Permitting Margin See HRSG NOTE MMBTU/hr, HHV 3353 1816 3349 3186 1733Duct Burner Heat Consumption MMBTU/hr, HHV 0 0 0 0 0

HRSG DATA (PER UNIT)

HRSG EXIT EXHAUST GASComposition:

Ar mol % 0.8899 0.8901 0.8899 0.8900 0.8901CO2 mol % 4.2596 3.8704 4.2696 4.2500 3.8504H2O mol % 8.2992 7.5408 8.3392 8.3000 7.5208N2 mol % 74.7925 75.0975 74.7625 74.7800 75.0975O2 mol % 11.7588 12.6013 11.7388 11.7800 12.6413

Molecular weight 28.4401 28.4873 28.4369 28.4394 28.4877Temperature °F 198 173 196 197 173Mass Flow with Permitting Margin See HRSG NOTE 10 lb/hr 5993400 3578400 5976600 5713100 3436700Std Volume Flow SCF/hr (60°F) 81201000 48401000 80982000 77405000 46483000

HRSG EXIT EXHAUST GAS EMISSIONSNOx ppmvd @ 15% O2 2 2 2 2 2NOx lb/hr as NO2 24.3 13.2 24.3 23.1 12.6CO ppmvd @ 15% O2 2 2 2 2 2CO lb/hr 14.8 8.02 14.8 14.1 7.66VOC ppmvd @ 15% O2 1 1 1 1 1VOC lb/hr as methane 4.23 2.29 4.23 4.02 2.19CO2 lb/hr 395000 214000 395000 376000 204000NH3 ppmvd @ 15% O2 5 5 5 5 5NH3 lb/hr 22.5 12.2 22.5 21.4 11.6SOx lb/hr as SO2 4.488 2.424 4.476 4.26 2.316Particulates - Filterable + Condensible, Including Sulfates lb/hr 11.1 10.1 11.1 11 10

Sulfuric Acid Mist lb/hr 2.88 1.56 2.88 2.74 1.49The notes page is an integral part of this document and must

be reviewed prior to use of this data.




By : M. Boisclair


OPERATING POINTCase DescriptionSITE CONDITIONSAmbient Temperature °FAmbient Pressure psiaAmbient Relative Humidity %

PLANT STATUSHRSG Duct BurnerSCRCO CatalystEvaporative Cooler state (On or Off)Gas Turbine Load %Gas Turbines OperatingGT Diluent Injection TypeGT Diluent Injection Flow (per GT) 10^3 lb/hr

FUEL DATAFuel TypeHHV BTU/lbLHV BTU/lbFuel Mol. Wt. lb/moleFuel Bound Nitrogen Wt %Fuel Sulfur Content grains/100 SCF @ 60°F

GT Heat Consumption per unit with Permitting Margin See HRSG NOTE MMBTU/hr, HHVDuct Burner Heat Consumption MMBTU/hr, HHV



Ar mol %CO2 mol %H2O mol %N2 mol %O2 mol %

Molecular weightTemperature °FMass Flow with Permitting Margin See HRSG NOTE 10 lb/hrStd Volume Flow SCF/hr (60°F)

HRSG EXIT EXHAUST GAS EMISSIONSNOx ppmvd @ 15% O2NOx lb/hr as NO2CO ppmvd @ 15% O2CO lb/hrVOC ppmvd @ 15% O2VOC lb/hr as methaneCO2 lb/hrNH3 ppmvd @ 15% O2NH3 lb/hrSOx lb/hr as SO2Particulates - Filterable + Condensible, Including Sulfates lb/hr

Sulfuric Acid Mist lb/hrThe notes page is an integral part of this document and must


6 7 8 9 10Unfired Unfired Unfired Unfired Unfired

51 51 51 91.2 91.214.4 14.4 14.4 14.4 14.460 60 60 41.7 41.7

Not Present Not Present Not Present Not Present Not PresentOperating Operating Operating Operating OperatingOperating Operating Operating Operating Operating

Off Off Off On OnBASE 98% 30% BASE BASE

1 1 1 1 1None None None None None

0 0 0 0 0

NG NG NG NG NG22992 22992 22992 22992 2299220732 20732 20732 20732 2073216.93 16.93 16.93 16.93 16.93

0 0 0 0 00.4 0.4 0.4 0.4 0.4

3204 3130 1452 3183 31590 0 0 0 0

0.8800 0.8800 0.8900 0.8701 0.87004.2700 4.2700 3.6200 4.1904 4.17008.9800 8.9900 7.7200 10.6911 10.5100

74.2700 74.2700 74.7600 72.8773 73.000011.6000 11.5900 13.0100 11.3711 11.450028.3662 28.3648 28.4456 28.1721 28.1901

191 189 164 200 200

5700500 5562900 3062900 5727800 571620077433000 75568000 41489000 78340000 78132000

2 2 2 2 223.3 22.7 10.5 23.1 22.9

2 2 2 2 214.2 13.8 6.41 14.1 14

1 1 1 1 14.05 3.95 1.83 4.02 3.99

378000 369000 172000 375000 3720005 5 5 5 5

21.5 21 9.74 21.4 21.24.284 4.188 1.944 4.26 4.224

11 11 9.9 11 11

2.75 2.69 1.25 2.73 2.71




By : M. Boisclair














91.2 91.2 95.8 95.8 95.814.4 14.4 14.4 14.4 14.441.7 41.7 35 35 35


Off Off On Off Off BASE 38% BASE BASE 39%

1 1 1 1 1None None None None None

0 0 0 0 0

NG NG NG NG NG22992 22992 22992 22992 2299220732 20732 20732 20732 2073216.93 16.93 16.93 16.93 16.93

0 0 0 0 00.4 0.4 0.4 0.4 0.4

3027 1548 3187 2980 15550 0 0 0 0

0.8700 0.8800 0.8700 0.8699 0.88004.1300 3.6400 4.1900 4.1196 3.63009.9900 9.0400 10.7400 9.8990 8.9700

73.3800 73.7400 72.8300 73.4327 73.800011.6300 12.7000 11.3700 11.6788 12.720028.2429 28.3033 28.1671 28.2522 28.3095

198 170 203 200 172

5546100 3228800 5740400 5477900 324770075666000 43956000 78526000 74710000 44203000

2 2 2 2 222 11.2 23.2 21.6 11.32 2 2 2 2

13.4 6.83 14.1 13.2 6.871 1 1 1 1

3.82 1.95 4.03 3.76 1.96357000 183000 376000 352000 183000

5 5 5 5 520.3 10.4 21.4 20 10.4

4.044 2.064 4.26 3.984 2.076

10.9 9.9 11 10.9 9.9

2.6 1.33 2.74 2.56 1.34




By : M. Boisclair














-0.7 5.8 5.8 51 5114.4 14.4 14.4 14.4 14.460 60 60 60 60


Off Off Off Off OffBASE BASE 50% BASE 50%

1 1 1 1 1Water Water Water Water Water229.1 230.1 121.7 228.4 115

DO DO DO DO DO20295 20295 20295 20295 2029518300 18300 18300 18300 18300138.25 138.25 138.25 138.25 138.25

≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015%3.83 3.83 3.83 3.83 3.83

3558 3550 2207 3400 20890 0 0 0 0

0.8501 0.8500 0.8600 0.8400 0.85005.8906 5.8800 5.8000 5.7600 5.7900

11.5212 11.5700 10.5000 12.1600 11.090071.1571 71.1100 71.9200 70.6100 71.460010.5811 10.5900 10.9200 10.6300 10.810028.3272 28.3210 28.4295 28.2432 28.3634

214 216 183 209 176

6123600 6118400 3873500 5969300 366240083296000 83242000 52499000 81438000 49754000

6 6 6 6 680 79.8 49.6 76.4 46.92 2 2 2 2

16.2 16.2 10.1 15.5 9.532 2 2 2 2

9.28 9.25 5.75 8.86 5.44560000 559000 348000 536000 329000

5 5 5 5 524.6 24.6 15.3 23.5 14.5

6.312 6.3 3.912 6.036 3.708

71.3 71.3 70 71.1 69.9

4.05 4.05 2.52 3.88 2.38




By : M. Boisclair













21 22 23 24Unfired Unfired Unfired Unfired

91.2 91.2 91.2 95.814.4 14.4 14.4 14.441.7 41.7 41.7 35

Not Present Not Present Not Present Not PresentOperating Operating Operating OperatingOperating Operating Operating Operating

On Off Off On BASE BASE 50% BASE

1 1 1 1Water Water Water Water218.7 219.8 101.1 219.1

DO DO DO DO20295 20295 20295 2029518300 18300 18300 18300138.25 138.25 138.25 138.25

≤ 0.015% ≤ 0.015% ≤ 0.015% ≤ 0.015%3.83 3.83 3.83 3.83

3364 3238 1958 33690 0 0 0

0.8300 0.8299 0.8500 0.82995.6500 5.6194 5.5700 5.6494

13.5200 13.1587 11.6200 13.568669.5100 69.7730 70.9600 69.463110.4900 10.6189 11.0000 10.489028.0829 28.1193 28.2828 28.0779

218 215 180 221

5986100 5804400 3561600 599760082133000 79538000 48522000 82306000

6 6 6 675.6 72.7 44 75.7

2 2 2 215.3 14.8 8.93 15.4

2 2 2 28.77 8.43 5.1 8.78

530000 511000 309000 5310005 5 5 5

23.3 22.4 13.6 23.35.964 5.748 3.468 5.976

71.1 71 69.8 71.1

3.83 3.69 2.23 3.84




By : M. Boisclair

Estimated Steady State Emission Notes

HRSG Emission Notes:1. Gas turbine(s) and steam plant are in steady-state operation.2. HRSG Stack Exhaust emissions are reported based on the following conversion rates: - Gas Turbine: 95% conversion of sulfur to SO2 and 5% conversion to SO3. - For installations that are equipped with a CO catalyst it is expected that 10% to about 35% of the SO2 in the exhaust gas is converted to SO3. The actual conversion rate used in these calculations is 30%. - For installations with an SCR catalyst for NOx abatement it is expected that 1% to 5% of the SO2 in the exhaust gas will be converted to SO3. The actual conversion rate used in these calculations is 5%.3. HRSG Stack NH3 Emissions are based on assuming no conversion to ammonium salts4. Steady State Emissions data above are estimated values based on GE recommended measurements and analysis procedures, per GEK 28172.5. Reference conditions for exhaust gas SCF are: 68°F, and 14.6959 psia. Reference conditions for exhaust gas fuel SCF are: 60°F, and 14.6959 psia.6. Reference conditions for exhaust gas Nm3 are: 32°F, and 14.6959 psia. Reference conditions for gas fuel Nm3 are: 60°F, and 14.6959 psia.7. SO2 emission values have been estimated by assuming that all the sulfur in the fuel is converted to SO2 and is based on maximum S content in the fuel of 0.4 grains/100 SCF @ 60°F for gas, and 15 ppmw for distillate. SO2 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 the 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.

Additional Notes for Particulate Emissions1. 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. PM estimates are based on maximum S content in the fuel of 0.4 grains/100 SCF @ 60°F for gas, and 15 ppmw for distillate.

1 Estimated Emissions for Renovo Energy Center

Proprietary Information & Confidential Information, 2015 General Electric Company, All Rights Reserved

GE 1x1 7HA.02 Combined Cycle Startup/Shutdown Emissions for

Renovo Energy Center June 19th, 2015

Per GT/HRSG stack

NOx lb

CO lb

VOC as Methane

lb

Total PM lb

Duration minutes

Cold Start 181 339 42 9.0 45

Warm Start 130 337 42 8.0 40

Hot Start 72 332 41 4.0 20

Shutdown 7.8 171 84 2.8 14

Notes: 1. The table above represents the startup emissions and duration per event.

2. Emissions assume methane as the fuel.

3. Particulates emissions account for sulfates resulting from 0.4gr/100SCF total fuel sulfur content. Higher fuel sulfur content will increase particulate emissions.

4. Emissions assume no contribution from pollutants present in the GT inlet air.

Basis: 1. 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 requirements.

2. Event definition: startup is from GT fire to HRSG stack emissions compliance. Shutdown is from the time that the HRSG stack goes out of compliance during shutdown to termination of fuel flow to the GT.

3. Hot starts are defined as taking place within 8 hours of the previous shutdown. Cold starts are preceded by over 72 hours of shutdown. Warm starts are in between hot and cold starts, defined at 48 hours after shutdown for testing purposes.

4. NOx and CO Emissions are per HRSG stack and measured at the HRSG stack using CEMS, following calibration. 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 the GT control exhaust flow signal and integrated over the event or hour.

5. VOC will be calculated equal to the measured heat input rate to each GT MMBtu/hr multiplied by an emissions factor based on the steady state base load VOC emission rate lb/MMBtu.

6. 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. Steam turbine sealing steam is on and condenser vacuum is within the range required for steam turbine startup. GT and HRSG Purge credit are available.



7. The plant is previously shut down from steady state operation at base load using normal shutdown sequence in accordance with General Electric’s recommendations. Shutdown period starts at termination of fuel flow to the GT during shutdown. During the standby period, the plant is maintained as per GE-recommended procedures including HP drum warming if required.

8. No steam purity holds are included. No sequence holds or rate reductions caused by operator intervention are allowed.

9. Turbine insulation and enclosures are installed per GE acceptance of drawings and instructions.

End of Startup and Shutdown Estimates



GE 1x1 7HA.02 Combined Cycle Startup/Shutdown Emissions for

Renovo Energy Center May 13th, 2015

Table 1: Liquid Fuel Emissions

Notes: 1. The table above represents the startup emissions and duration per event.

2. Emissions assume liquid fuel as the fuel, in compliance with General Electric Liquid Fuel Specification GEI 41047 and is assumed to have 0.015% fuel bound nitrogen or less.

3. Particulates emissions account for sulfates resulting from 15 ppmw total fuel sulfur content. Higher fuel sulfur content will increase particulate emissions.

4. Emissions assume no contribution from pollutants present in the GT inlet air.

Basis: 1. 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 requirements.

*if the auxiliary boiler operates on natural gas, it is assumed that sufficient natural gas is available for the auxiliary boiler to be operating and providing steam for the various startup needs listed in this document.

2. Event definition: startup is from GT fire to HRSG stack emissions compliance. Shutdown is from the time that the HRSG stack goes out of compliance during shutdown to termination of fuel flow to the GT.

3. Hot starts are defined as taking place within 8 hours of the previous shutdown. Cold starts are preceded by over 72 hours of shutdown. Warm starts are in between hot and cold starts, defined at 48 hours after shutdown for testing purposes.

4. NOx and CO emissions are per HRSG stack and measured at the HRSG stack using CEMS, following calibration. 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 the GT control exhaust flow signal and integrated over the event or hour.

5. VOC will be calculated equal to the measured heat input rate to each GT MMBtu/hr multiplied by an emissions factor based on the steady state base load VOC emission rate lb/MMBtu.

Per GT/HRSG Stack

NOx

lb/event CO lb/event

VOC as

Methane

lb/event

Total PM

lb/event

Time to/out of Stack

Compliance

minutes

Cold start 219 190 15 53 45

Warm start 203 187 14 48 40

Hot start 143 176 12 24 20

Shutdown 8 17 4 9.5 8



6. 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. Steam turbine sealing steam is on and condenser vacuum is within the range required for steam turbine startup. GT and HRSG Purge credit are available.

7. The plant is previously shut down from steady state operation at base load using normal shutdown sequence in accordance with General Electric’s recommendations. Shutdown period starts at termination of fuel flow to the GT during shutdown. During the standby period, the plant is maintained as per GE-recommended procedures including HP drum warming if required.

8. No steam purity holds are included. No sequence holds or rate reductions caused by operator intervention are allowed.

9. Turbine insulation and enclosures are installed per GE acceptance of drawings and instructions.

End of Startup and Shutdown Estimates

PRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLY

Mitsubishi Hitachi Power Systems Americas, Inc.

Expected Steady State Emissions for Combined Cycle Power PlantThis document contains Company Confidential and Proprietary information of Mitsubishi Hitachi Power Systems Americas, Inc. (“MHPSA”). Neither this document, nor any information obtained

therefrom is to be reproduced, transmitted or disclosed to any third party without first receiving the express written authorization of MHPSA.

COMMERCIAL DATA

Customer Bechtel

Project Name Renovo Energy Center

Manufacturer Mitsubishi Hitachi Power Systems Americas Inc.

INPUT INFORMATION

Gas Turbine Type M501J

Configuration & Arrangement Combined Cycle 1x1 Single Shaft CGS

Scope Power Train

Fuel Type Natural Gas

Fuel Heat Input,LHV Btu/lb 20,727.0

Fuel Heat Input,HHV Btu/lb 22,996.6

CASE # 1 2 3 4 5 6 7 8 9 10 11 12

Ambient Dry Bulb Temperature °F 91 91 91 51 51 51 51 6 6 6 96 -1

Barometric Pressure psia 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42 14.42

Relative Humidity % 41.7 41.7 41.7 60.0 60.0 60.0 60.0 60.0 60.0 60.0 35.0 60.0

Inlet Conditioning Evaporative Cooler On/Off ON ON OFF OFF OFF OFF OFF OFF OFF OFF ON OFF

Duct Burner Status On/Off ON OFF OFF ON ON OFF OFF ON OFF OFF ON ON

GT PERFORMANCE (per GT)

GT Load % Base Base 50% Base Base Base 50% Base Base 50% Base Base

GT Heat Input MMBtu/h - LHV 2,476 2,476 1,529 2,613 2,613 2,613 1,614 2,822 2,822 1,791 2,468 2,832

CC PERFORMANCE

Duct Burner Heat Input (per HRSG)MMBtu/h - LHV 373 0 0 373 116 0 0 362 0 0 373 364

GT EMISSIONS @ GT FLANGE (per GT)

NOx ppmvd@15% O2 25 25 25 25 25 25 25 25 25 25 25 25

NO/NOx % 88.0 88.0 81.1 88.0 88.0 88.0 81.9 88.0 88.0 83.9 88.0 88.0

CO ppmvd@15% O2 10 10 10 10 10 10 10 10 10 10 10 10

VOC ppmvd@15% O2 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

UHC ppmvd@15% O2 8 8 8 8 8 8 8 8 8 8 8 8

SO2 lb/h 3.03 3.03 1.83 3.19 3.19 3.19 1.93 3.45 3.45 3.45 3.02 3.46

Particulates (PM10 Total) lb/h 5.50 5.50 3.70 5.80 5.80 5.80 3.80 6.20 6.20 6.20 5.40 6.2

Formaldehyde (CH2O) ppbvd@15% O2 91 91 91 91 91 91 91 91 91 91 91 91

CC EXHAUST CONDITIONS @ Stack (per Stack)

CC Exhaust Flow scfm 979,600 979,600 653,400 1,027,000 1,027,000 1,027,000 667,300 1,083,000 1,083,000 709,700 977,100 1,083,000

CC Exhaust Gas Temperature °F 182 191 173 172 180 185 169 175 189 170 183 175

CC Exhaust Gas Composition wt%

O2 10.70% 12.25% 13.36% 11.05% 12.06% 12.52% 13.26% 11.04% 12.39% 12.94% 10.70% 10.99%

CO2 8.01% 6.98% 6.31% 7.95% 7.28% 6.98% 6.49% 8.02% 7.13% 6.76% 8.01% 8.06%

H2O 7.99% 7.18% 6.29% 6.79% 6.26% 6.02% 5.63% 6.44% 5.73% 5.44% 8.02% 6.45%

N2 72.03% 72.30% 72.74% 72.92% 73.09% 73.17% 73.31% 73.21% 73.44% 73.54% 72.00% 73.21%

Ar 1.29% 1.29% 1.30% 1.31% 1.31% 1.31% 1.31% 1.31% 1.31% 1.32% 1.29% 1.31%

CC EMISSIONS @ STACK (per Stack)

NOx (abated) ppmvd@15% O2 2 2 2 2 2 2 2 2 2 2 2 2

CO (abated) ppmvd@15% O2 2 2 2 2 2 2 2 2 2 2 2 2

VOC (abated) ppmvd@15% O2 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

UHC (abated) ppmvd@15% O2 8 8 8 8 8 8 8 8 8 8 8 8

Sulfur Mist (H2SO4) lb/h 3.50 3.06 1.85 3.67 3.37 3.23 1.96 3.92 3.49 2.17 3.49 3.93

Particulates (PM10 Total) lb/h 14.6 9.4 6.1 15.2 11.6 10.0 6.3 15.8 10.7 6.9 14.6 15.8

Ammonia Slip (NH3) ppmvd@15% O2 5 5 5 5 5 5 5 5 5 5 5 5

Formaldehyde (CH2O) (abated) ppbvd@15% O2 80 80 80 80 80 80 80 80 80 80 80 80

CO2 kpph 375.9 326.6 201.7 393.9 359.9 344.7 212.9 420.1 372.3 236.3 374.8 421.6

SO2 lb/h 1.6 1.4 0.9 1.7 1.5 1.5 0.9 1.8 1.6 1.0 1.6 1.8

---

NOTES (Performance notes apply to all cases unless otherwise specified.):

1. All performance data are based on New & Clean conditions.

2. All supplied values are estimations and not guaranteed.

3. N/A

4. Fuel gas composition (vol%), 95.3206% CH4, 2.8183% C2H6, 0.2748% C3H8, 0.097% n-C4H10, 0.031% n-C5H12, 0.0295% C6H14,

, 0.4644% N2, 0.9644% CO2 normalized to 100%

5. 0.4 gr/100scf of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.

6. Fuel must be in compliance with MHPSA's fuel specification.

7. N/A

8. Balance of plant design (condenser, piping losses, etc.) shall be based on MHPSA estimations.

9. Assumed Site Conditions: Frequency 60 Hz, GT Generator Power Factor 0.9, HRSG Drum blowdown 0%, wet condenser cooling water circuit

10. This data is based on estimated and/or assumed values. Confer with MHPSA prior to including in any air permit application or contract guarantees.

11. Emissions shall be tested in accordance with the following EPA methods: NOx: 20, CO: 10, VOC: 25/18, NH3: CTM-027,

PM10: Non-condensables using Method 201 or 201A and condensables using Method 202.

12. Data included in any air permit application or Environmental Impact Study is strictly the Customer's responsibility.

13. Emission values are net emissions generated from MHPSA's equipment, unless otherwise stated.

14. VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.

15. GT values given are as measured at the GT exhaust flange (prior to any downstream emission control equipment).

16. CC values given are as measured at the HRSG stack outlet with the applicable emission control equipment in operation.

17. At extreme ambient conditions, GT load may be restricted for equipment operation.

In such a case, part load performance is calculated based on the theoretical unrestricted base load performance.

Company Confidential and Proprietary

© 2015, Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved

ISSUED ON: 6/11/2015 By:

520_Bechtel_02c_J-G-1x1-PSSCv2 9_20150609R0.xlsm, Customer

PRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLYPRELIMINARY/FOR INFORMATION ONLY

Mitsubishi Hitachi Power Systems Americas, Inc.

Expected Performance and Steady State Emissions for Combined Cycle Power PlantThis document contains Company Confidential and Proprietary information of Mitsubishi Hitachi Power Systems Americas, Inc. (“MHPSA”). Neither this document, nor any information obtained

therefrom is to be reproduced, transmitted or disclosed to any third party without first receiving the express written authorization of MHPSA.

COMMERCIAL DATA

Customer Bechtel

Project Name Renovo Energy Center

Manufacturer Mitsubishi Hitachi Power Systems Americas Inc.

INPUT INFORMATION

Gas Turbine Type M501J

Configuration & Arrangement Combined Cycle 1x1 Single Shaft CGS

Scope Power Train

Fuel Type Fuel Oil

Fuel Heat Input,LHV Btu/lb 18,300.0

Fuel Heat Input,HHV Btu/lb 19,529.7

CASE # 1 2 3 4 5 6 7 8 9 10 11 12

Ambient Dry Bulb Temperature °F 91 51 6

Barometric Pressure psia 14.42 14.42 14.42

Relative Humidity % 41.7 60.0 60.0

Inlet Conditioning Evaporative Cooler On/Off OFF OFF OFF

Duct Burner Status On/Off OFF OFF OFF

GT PERFORMANCE (per GT)

GT Load % Base Base Base

Water Injection Flow lb/h 121,118 131,480 131,481

GT Heat Input MMBtu/h - LHV 2,131 2,314 2,314

GT EMISSIONS @ GT FLANGE (per GT)

NOx ppmvd@15% O2 42 42 42

NO/NOx % 85.0 79.6 66.0

CO ppmvd@15% O2 50 50 50

VOC ppmvd@15% O2 10 10 10

UHC ppmvd@15% O2 10 10 10

SO2 lb/h 3.46 3.75 3.75

Particulates (PM10 Total) lb/h 25.0 27.3 26.8

Formaldehyde (CH2O) ppbvd@15% O2 91 91 91

CC EXHAUST CONDITIONS @ Stack (per Stack)

CC Exhaust Flow scfm 964,100 1,041,000 1,015,000

CC Exhaust Gas Temperature °F 202 202 201

CC Exhaust Gas Composition wt%

O2 13.17% 13.36% 13.22%

CO2 8.02% 8.03% 8.21%

H2O 6.48% 5.69% 5.41%

N2 71.06% 71.64% 71.87%

Ar 1.27% 1.28% 1.29%

CC EMISSIONS @ STACK (per Stack)

NOx (abated) ppmvd@15% O2 4 4 4

CO (abated) ppmvd@15% O2 6 6 6

VOC (abated) ppmvd@15% O2 5 5 5

UHC (abated) ppmvd@15% O2 5 5 5

Particulates (PM10 Total) lb/h 29.5 32.2 31.7

Ammonia Slip (NH3) ppmvd@15% O2 5 5 5

Formaldehyde (CH2O) (abated) ppbvd@15% O2 80 80 80

CO2 kpph 270.4 293.6 293.6

SO2 lb/h 1.6 1.7 1.7

---

NOTES (Performance notes apply to all cases unless otherwise specified.):

1. All performance data are based on New & Clean conditions.

2. All supplied values are estimations and not guaranteed.

3. N/A

4. Fuel oil composition (wt%): 86.0% Carbon, 14.0% Hydrogen

5. 15 ppmvd of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.

6. Fuel shall be as specified in ASTM D975-06, Grade No.2-D S15 diesel fuel oil,also previously referred to as ultra-low sulfur grade or ULSD.

7. N/A

8. Balance of plant design (condenser, piping losses, etc.) shall be based on MHPSA estimations.

9. Assumed Site Conditions: Frequency 60 Hz, GT Generator Power Factor 0.9, HRSG Drum blowdown 0%, wet condenser cooling water circuit

10. This data is based on estimated and/or assumed values. Confer with MHPSA prior to including in any air permit application or contract guarantees.

11. Emissions shall be tested in accordance with the following EPA methods: NOx: 20, CO: 10, VOC: 25/18, NH3: CTM-027,

PM10: Non-condensables using Method 201 or 201A and condensables using Method 202.

12. Data included in any air permit application or Environmental Impact Study is strictly the Customer's responsibility.

13. Emission values are net emissions generated from MHPSA's equipment, unless otherwise stated.

14. VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.

15. GT values given are as measured at the GT exhaust flange (prior to any downstream emission control equipment).

16. CC values given are as measured at the HRSG stack outlet with the applicable emission control equipment in operation.

17. At extreme ambient conditions, GT load may be restricted for equipment operation.

In such a case, part load performance is calculated based on the theoretical unrestricted base load performance.

Company Confidential and Proprietary

© 2015, Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved

ISSUED ON: 5/14/2015 By:

520_Bechtel_RFP_J-O-1x1-PSSCv2 9_20150505R0.xlsm, Customer

PRELIMINARY/FOR INFORMATION ONLY

Expected Startup Emissions for Combined Cycle 1x1, Single-Shaft CGS

Customer: Bechtel

Project: Renovo Energy Center

Engine: M501J

Scope: Combined Cycle 1x1, Single-Shaft CGS

Fuel: Natural Gas

Total Stack Emissions Per GT Per Event

Duration NOx CO VOC CO2 PM (Total) Avg Exhaust Temp Avg Exhaust Flow

minutes lb lb lb lb lb °F kpph

Cold Start 143 152.3 3,954.5 1,618.1 382,046 13.0 82 2,781

Warm Start 103 107.5 2,831.5 1,249.9 264,461 9.1 288 2,564

Hot Start 28 40.2 1,518.0 615.8 43,917 1.8 285 2,564

Shutdown 12.5 27.5 595.3 307.5 30,611 1.2

NOTES:

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

Emissions shall be tested in accordance with the following EPA methods:

Data included in any air permit application or Environmental Impact Study is strictly the Customer's responsibility.

Emission values are net emissions generated from MHPSA's equipment, unless otherwise stated.

VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.

Values given are as measured at the HRSG stack outlet with the applicable emission control equipment in place.

N/A

, 0.4644% N2, 0.9644% CO2 normalized to 100%

NOx: 20, CO: 10, VOC: 25/18, NH3: CTM-027, PM(Total): Non-condensables using Method 201 or 201A and condensables using Method 202.

Assumed Site Conditions: Frequency 60 Hz, Generator Power Factor 0.9, exhaust loss of 18 in.H2O (total) at ISO conditions.

For permitting purposes, MHPSA recommends 10% margin on all 'lb' and 'lb/h' values.

All performance data are based on New & Clean conditions.

All supplied values are estimations and not guaranteed.

Measurement of startup begins at time of GT ignition and ends at MECL (Minimum Emissions Compliance Load for the GT).

Generator sync time of 0 seconds is included in the startup time.

Measurement of shutdown begins at MECL, includes a 5 minute hold at FSNL , and ends at GT flame off.

Calculations were performed with evap. coolers off and anti-icing off at the following conditions: -1 deg F, 60% RH, and 14.42 psia

Fuel must be in compliance with MHPSA's fuel specification.

Fuel gas composition (vol%), 95.3206% CH4, 2.8183% C2H6, 0.2748% C3H8, 0.097% n-C4H10, 0.031% n-C5H12, 0.0295% C6H14,

0.4 gr/100scf of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.

Company Confidential and Proprietary© 2015, Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved. ISSUED ON: 6/11/2015520_Bechtel_02c_J-G-SUSDCv1.8_20150609.xlsm, Customer Copy

PRELIMINARY/FOR INFORMATION ONLY

Expected Startup Emissions for Combined Cycle 1x1, Single-Shaft CGS

Customer: Bechtel

Project: Renovo Energy Center

Engine: M501J

Scope: Combined Cycle 1x1, Single-Shaft CGS

Fuel: Fuel Oil

Total Stack Emissions Per GT Per Event

Duration NOx CO VOC CO2 PM (Total)minutes lb lb lb lb lb

Cold Start 182 289.1 4,997.1 1,655.6 635,953 156.0

Warm Start 125 201.2 3,720.1 1,328.7 423,050 105.3

Hot Start 37 109.3 3,315.3 867.2 87,698 30.9

Shutdown 14.0 57.1 723.7 234.7 46,812 13.1

NOTES:

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

Emissions shall be tested in accordance with the following EPA methods:

Data included in any air permit application or Environmental Impact Study is strictly the Customer's responsibility.

Emission values are net emissions generated from MHPSA's equipment, unless otherwise stated.

VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.

Values given are as measured at the HRSG stack outlet with the applicable emission control equipment in place.

N/A

NOx: 20, CO: 10, and VOC: 25/18.

Assumed Site Conditions: Frequency 60 Hz, Generator Power Factor 0.9, exhaust loss of 18 in.H2O (total) at ISO conditions.

For permitting purposes, MHPSA recommends 10% margin on all 'lb' and 'lb/h' values.

All performance data are based on New & Clean conditions.

All supplied values are estimations and not guaranteed.

Measurement of startup begins at time of GT ignition and ends at MECL (Minimum Emissions Compliance Load for the GT).

Generator sync time of 0 seconds is included in the startup time.

Measurement of shutdown begins at MECL, includes a 5 minute hold at FSNL , and ends at GT flame off.

Calculations were performed with evap. coolers off and anti-icing off at the following conditions: 6 deg F, 60% RH, and 14.42 psia

Fuel must be in compliance with MHPSA's fuel specification.

Fuel oil composition (wt%): 86.0% Carbon, 14.0% Hydrogen

15 ppmvd of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.

Company Confidential and Proprietary© 2015, Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved. ISSUED ON: 5/14/2015520_Bechtel_02_J-O-SUSDCv1.8_20150505.xlsm, Customer Copy

Siemens Energy, Inc. Proprietary Information

Bechtel - Renovo Estimated Emissions Data Sheet1x1 SCC6-8000H - Estimated Exhaust Stack Emissions July 15, 2015Combined Cycle / PCS

SITE CONDITIONS: CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 CASE 7 CASE 8 CASE 9 CASE 10 CASE 11 CASE 12

OPERATING MODE Performance Optimized

Performance Optimized

Interval Optimized




Interval Optimized




Interval Optimized


FUEL TYPE Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas GT LOAD LEVEL, % 100% 100% 100% 40% 100% 100% 100% 40% 100% 100% 100% 40% NET FUEL HEATING VALUE, Btu/lbm (LHV) 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 20,989 GROSS FUEL HEATING VALUE, Btu/lbm (HHV) 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 23,294 EVAPORATIVE COOLER STATUS ON ON ON OFF OFF OFF OFF OFF OFF OFF OFF OFF LOW LOAD CO HARDWARE STATUS OFF OFF OFF ON OFF OFF OFF ON OFF OFF OFF ON AMBIENT DRY BULB TEMPERATURE, °F 91 91 91 91 51 51 51 51 6 6 6 6 AMBIENT RELATIVE HUMIDITY, % 42 42 42 42 60 60 60 60 60 60 60 60 BAROMETRIC PRESSURE, psia 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 DUCT BURNER STATUS ON OFF OFF OFF ON OFF OFF OFF ON OFF OFF OFF GT FUEL FLOW, lbm/hr 113,559 113,587 111,360 57,425 119,330 119,065 116,754 62,994 127,739 127,725 127,014 67,526 DUCT BURNER FUEL FLOW, lbm/hr 28,405 --- --- --- 17,588 --- --- --- 7,806 --- --- ---

HRSG STACK EXHAUST GAS EXHAUST FLOW, lbm/hr 4,852,860 4,824,455 4,823,546 2,794,685 5,079,811 5,062,026 5,060,167 2,962,015 5,288,326 5,280,520 5,356,596 3,134,932 EXHAUST FLOW, acfm 1,421,596 1,435,489 1,438,638 803,110 1,467,927 1,483,424 1,486,452 843,490 1,543,373 1,551,102 1,578,624 895,755 STACK TEMPERATURE, °F 203 217 218 196 200 211 213 193 209 214 216 197 OXYGEN, Vol. % 9.43 11.51 11.68 12.90 10.58 11.84 12.01 12.87 11.22 11.75 11.88 12.92 CARBON DIOXIDE, Vol. % 5.09 4.13 4.05 3.54 4.73 4.15 4.07 3.68 4.50 4.26 4.20 3.72 WATER, Vol. % 12.38 10.54 10.39 8.84 9.87 8.74 8.59 7.82 8.79 8.31 8.19 7.26 NITROGEN, Vol. % 72.25 72.97 73.03 73.85 73.95 74.39 74.45 74.75 74.62 74.81 74.86 75.22 ARGON, Vol. % 0.85 0.86 0.86 0.87 0.87 0.87 0.87 0.88 0.88 0.88 0.88 0.88 MOLECULAR WEIGHT 28.06 28.19 28.20 28.32 28.31 28.38 28.39 28.44 28.40 28.44 28.45 28.51

HRSG STACK EMISSIONS (Based on USEPA Test Methods):NOX, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2NOX, lbm/hr as NO2 24.7 19.8 19.4 9.8 23.9 20.8 20.4 10.7 23.5 22.2 22.2 11.5NH3, ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5 5 5 5NH3, lbm/hr 22.9 18.3 18.0 9.1 22.1 19.2 18.8 9.9 21.8 20.5 20.5 10.6CO, ppmvd @ 15% O2 2 2 2 2 2 2 2 2 2 2 2 2CO, lbm/hr 15.1 12.1 11.8 6.0 14.5 12.7 12.4 6.6 14.3 13.5 13.5 7.0VOC, ppmvd @ 15% O2 as CH4 2.8 1 1 1 2.0 1 1 1 1.3 1 1 1VOC, lbm/hr as CH4 12.0 3.5 3.4 1.7 8.5 3.7 3.6 1.9 5.4 3.9 3.9 2.0THC, ppmvd @ 15% O2 as CH4 5.6 2 2 2 4.1 2 2 2 2.6 2 2 2THC, lbm/hr as CH4 24.0 7.0 6.8 3.4 17.0 7.4 7.2 3.8 10.8 7.8 7.8 4.0CH2O, ppmvd @ 15% O2 100 100 100 100 100 100 100 100 100 100 100 100CH2O, lbm/hr 0.81 0.70 0.70 0.40 0.78 0.70 0.70 0.40 0.77 0.80 0.80 0.40SO2, lbm/hr 3.9 3.1 3.0 1.6 3.7 3.2 3.2 1.7 3.7 3.5 3.4 1.9PARTICULATES, lbm/hr 18.6 11.4 11.4 8.0 16.5 12.1 12.1 8.0 14.7 12.7 12.9 8.0PARTICULATES, lbm/MMBtu 0.0056 0.0043 0.0044 0.0060 0.0052 0.0044 0.0044 0.0055 0.0047 0.0043 0.0044 0.0051H2SO4, lbm/hr 1.4 1.1 1.1 0.6 1.4 1.2 1.2 0.7 1.3 1.3 1.3 0.7CO2, lbm/hr 398,956 320,084 313,738 158,328 385,069 335,630 328,995 173,557 379,952 358,207 358,085 185,305CO2, lbm/MMBtu 121 121 121 118 121 121 121 118 120 120 121 118

NOTES: - All data is ESTIMATED, NOT guaranteed and is for ONE unit. - Gas fuel composition (mole percent) is: 95.3206% CH4, 2.8183% C2H6, 0.2748% C3H8, 0.097% nC4H10, 0.031% nC5H12, 0.0295% nC6H14, 0.4644% N2, 0.9644% CO2, and ~ 0.4 grains S/100 SCF. - Gas fuel must be in compliance with the Siemens Gas Fuel Specification. - NOX and CO assume the use of an SCR and oxidation catalyst, respectively. - VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH4). - Particulates are per US EPA Method 5 and 202 (front and back half). - Emissions exclude ambient air contributions and assume steady-state conditions. - Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only. Data included in any permit application or Environmental Impact Statement are strictly the customer's responsibility. Siemens is available to review permit application data upon request.

Siemens Energy, Inc. Proprietary Information

Bechtel - Renovo Estimated Emissions Data Sheet1x1 SCC6-8000H - Estimated Exhaust Stack Emissions July 15, 2015Combined Cycle / PCS

SITE CONDITIONS: CASE 1 CASE 2 CASE 3 CASE 4 CASE 5 CASE 6 CASE 7 CASE 8 CASE 9

OPERATING MODE Performance Optimized









FUEL TYPE ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSD ULSD GT LOAD LEVEL, % 100% 75% 61% 100% 75% 54% 100% 75% 54% NET FUEL HEATING VALUE, Btu/lbm (LHV) 18,491 18,491 18,491 18,491 18,491 18,491 18,491 18,491 18,491 GROSS FUEL HEATING VALUE, Btu/lbm (HHV) 20,522 20,522 20,522 20,522 20,522 20,522 20,522 20,522 20,522 EVAPORATIVE COOLER STATUS OFF OFF OFF OFF OFF OFF OFF OFF OFF AMBIENT DRY BULB TEMPERATURE, °F 91 91 91 51 51 51 6 6 6 AMBIENT RELATIVE HUMIDITY, % 42 42 42 60 60 60 60 60 60 BAROMETRIC PRESSURE, psia 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 14.420 GT FUEL FLOW, lbm/hr 119,662 97,196 84,512 125,091 101,649 82,235 125,986 102,486 83,681 WATER INJECTION RATE, lbm/hr 76,381 49,595 37,194 63,116 40,324 26,355 44,386 27,468 18,774

HRSG STACK EXHAUST GAS EXHAUST FLOW, lbm/hr 4,740,925 3,738,293 3,365,733 5,129,740 3,879,170 3,271,120 5,355,372 3,912,232 3,265,846 EXHAUST FLOW, acfm 1,436,318 1,098,250 981,410 1,551,097 1,127,666 940,594 1,636,188 1,135,517 935,209 STACK TEMPERATURE, °F 236 216 212 240 214 207 251 216 207 OXYGEN, Vol. % 11.90 11.81 12.20 12.50 12.05 12.53 13.04 12.30 12.59 CARBON DIOXIDE, Vol. % 5.21 5.32 5.12 5.07 5.40 5.14 4.89 5.40 5.24 WATER, Vol. % 9.35 9.02 8.49 7.38 7.38 6.78 5.95 6.21 5.87 NITROGEN, Vol. % 72.69 72.99 73.33 74.18 74.30 74.67 75.23 75.21 75.42 ARGON, Vol. % 0.85 0.86 0.86 0.87 0.87 0.88 0.88 0.88 0.88 MOLECULAR WEIGHT 28.49 28.54 28.58 28.69 28.73 28.77 28.83 28.86 28.88

HRSG STACK EMISSIONS (Based on USEPA Test Methods):NOX, ppmvd @ 15% O2 6 6 6 6 6 6 6 6 6NOX, lbm/hr as NO2 56.6 45.5 39.4 59.1 47.6 38.2 59.3 47.8 38.7NH3, ppmvd @ 15% O2 5 5 5 5 5 5 5 5 5NH3, lbm/hr 17.5 14.1 12.2 18.3 14.7 11.8 18.3 14.8 12.0CO, ppmvd @ 15% O2 4 4 4 4 4 4 4 4 4CO, lbm/hr 23.0 18.5 16.0 24.0 19.3 15.5 24.1 19.4 15.7VOC, ppmvd @ 15% O2 as CH4 1 1 1 1 1 1 1 1 1VOC, lbm/hr as CH4 3.3 2.7 2.3 3.5 2.8 2.3 3.5 2.8 2.3THC, ppmvd @ 15% O2 as CH4 2 2 2 2 2 2 2 2 2THC, lbm/hr as CH4 6.6 5.4 4.6 7.0 5.6 4.6 7.0 5.6 4.6CH2O, ppmvd @ 15% O2 100 100 100 100 100 100 100 100 100CH2O, lbm/hr 0.70 0.50 0.50 0.70 0.60 0.50 0.70 0.60 0.50SO2, lbm/hr 3.7 3.0 2.7 3.9 3.2 2.6 3.9 3.2 2.6PARTICULATES, lbm/hr 30 30 30 30 30 30 30 30 30PARTICULATES, lbm/MMBtu 0.012 0.015 0.017 0.012 0.014 0.018 0.012 0.014 0.017H2SO4, lbm/hr 1.4 1.1 1.0 1.4 1.2 1.0 1.4 1.2 1.0CO2, lbm/hr 392,724 315,864 273,243 410,846 330,314 265,089 412,072 331,606 268,561CO2, lbm/MMBtu 160 158 158 160 158 157 159 158 156

NOTES: - All data is ESTIMATED, NOT guaranteed and is for ONE unit. - ULSD composition (weight percent) is: 86.4765% C, 13.507% H2, 0.0015% sulfur, and 0.015% N2. - ULSD must be in compliance with the Siemens Liquid Fuel Specification. - NOX and CO assume the use of an SCR and oxidation catalyst, respectively. - VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH4). - Particulates are per US EPA Method 5 and 202 (front and back half). - Emissions exclude ambient air contributions and assume steady-state conditions. - Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only. Data included in any permit application or Environmental Impact Statement are strictly the customer's responsibility. Siemens is available to review permit application data upon request.

Siemens Energy, Inc. Proprietary Information 3/25/2015

Bechtel - Renovo - SCC6-8000H with Drum+ HRSG & ACC on Natural Gas @ 59 °F Total Estimated Startup & Shutdown Emissions, Fuel Use, Exhaust Gas Volumetric Flow Rate & Temperature

NOX CO VOC SO2 PM CO2 Fuel Use acfm °F

"Cold" Startup (GT Ignition to Emissions Compliance @ 70% GT Load) 35 94.8 574 65.7 1.1 5.2 112,286 39,802 907,457 174

"Cold" Startup (GT Ignition to 100% GT Load / STB Valves Closed) 140 123 590 88.7 5.4 22.2 564,619 200,286 1,068,876 182

"Warm" Startup (GT Ignition to 100% GT Load) 17 56.2 536 59.6 0.4 2.5 39,465 13,968 741,625 164

"Warm" Startup (GT Ignition to Emissions Compliance @ 100% GT Load) 35 113 542 60.7 1.3 6.2 139,862 49,596 1,092,968 176

"Warm" Startup (GT Ignition to STB Valves Closed) 70 125 549 62.9 3.2 13.4 335,079 118,872 1,258,880 182

"Hot" Startup (GT Ignition to 100% GT Load) 17 56.2 459 59.6 0.4 2.5 39,465 13,968 741,625 164

"Hot" Startup (GT Ignition to Emissions Compliance @ 100% GT Load) 30 97.2 463 60.4 1.1 5.2 111,974 39,699 1,037,664 175

"Hot" Startup (GT Ignition to STB Valves Closed) 60 107.7 470 62.3 2.7 11.3 279,302 99,079 1,231,228 181

"Hot Startup On-the-Fly" (GT Ignition to Emissions Compliance @ 100% GT Load) 32 87 825 111 0.8 4.7 87,273 30,912 842,583 172

"Hot Startup On-the-Fly" (GT Ignition to STB Valves Closed) 40 90 827 111 1.3 6.5 134,683 47,736 966,303 175

Shutdown (50% GT Load to Fuel Cut Off) 18 78.5 244 97.9 0.4 2.5 37,991 13,435 768,913 176

Shutdown (100% GT Load to Fuel Cut Off) 50 91.0 252 107 1.6 7.4 157,521 55,829 913,885 179

(A) Time-weighted average values over the designated startup time period

General Notes

1.) All data is ESTIMATED, NOT guaranteed and is for ONE unit (gas turbine and HRSG).

2.) Emissions are at the HRSG exhaust stack outlet and exclude ambient air contributions.

3.) Emissions are based on new and clean conditions.

4.) VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH4).

5.) Fuel gas composition (molar volume) is: 95.3206% CH4, 2.8183% C2H6, 0.2748% C3H8, 0.097% nC4H10, 0.031% nC5H12, 0.0295% nC6H14, 0.4644% N2, 0.9644% CO2, and ~ 0.4 grains S/100 SCF.

6.) Particulate (PM) emissions are based on the aforementioned fuel sulfur content and are per USEPA Methods 5/202.

7.) Fuel use is based on a fuel heating value of approximately 23,300 Btu/lbm (HHV).

8.) Gas fuel must be in compliance with the Siemens fuel specification.

9.) Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only.

Data included in any permit application or Environmental Impact Statement is strictly the customer's responsibility. Siemens is available to review permit application data upon request.

Startup / Shutdown Emissions Notes

1.) "Cold" startup (SU) data are based on an extended gas turbine (GT) shutdown (SD), greater than ~ 64 hours, with the steam turbine (ST) rotor temperature less than ~ 509 °F (265 °C)

and greater than ~ 302 °F (150 °C).

2.) "Warm" SU data are based on the GT being shutdown between ~ 16 and 64 hours, with the ST rotor temperature between ~ 509 °F (265 °C) and 716 °F (380 °C).

3.) "Hot" SU data are based on the GT being shutdown less than ~ 16 hours, with the ST rotor temperature greater than ~ 716 °F (380 °C).

4.) "Hot Start-on-the-Fly" SU data are based on the GT being shutdown less than ~ 8 hours, with the ST rotor temperature greater than ~ 780 °f (416 °C).

5.) Estimated "Cold", "Warm", "Hot" and Shutdown data are based on the assumed times noted above at ~ 29 MW/min per "Renovo Energy Center-SCC6-8000H-1S-KN-(drum+)-29WM-rev001-.pdf"

dated March 19, 2015, and assume the use of a fast start SFC to get from GT ignition to synchronization in 6-minutes, and will be higher for longer times and/or slower ramp rates.

6.) Estimated "Hot Start On-the-Fly" data are based on the assumed time noted above at ~ 12.5 MW/min per "Renovo Energy Center-SCC6-8000H-1S-KN-(drum+)-HOF-rev001.pdf"

dated March 19, 2015, and assume the use of a fast start SFC to get from GT ignition to synchronization in 6-minutes, and will be higher for longer times and/or slower ramp rates.

7.) Estimated NOX emissions assume the use of an SCR system, and estimated CO and VOC emissions assume the use of an oxidation catalyst.

8.) "Emissions Compliance" assumed to mean 2 ppmvd NOX and 2 ppmvd CO at the stack.

9.) HRSG high (HP), intermediate (IP) and low pressure (LP) drums are filled to start up levels, the HRSG is ready for operation, and purge credit is established prior to GT startup.

10.) Steam chemistry adequate for ST operation (no waiting time included).

11.) Data assumes all BOP systems and auxiliaries meet Siemens start and shutdown prerequisites and that all systems run smoothly without upsets.

12.) Air Cooled Condenser (ACC) receiver tank is filled to startup level, vacuum is maintained during shutdown, and condenser pressure is below 20 in. HgA prior to GT start.

13.) ACC is able to receive full bypass steam at 100% GT load without ST back pressure violation in startup mode at any ambient temperature less than ~ 91 °F.

14.) Operator actions do not extend SU or SD times.

15.) HRSG stack damper has been closed as soon after SD as possible to maintain heat, and HRSG has been maintained in a "bottled-up" condition during the SD with drain valves in AUTO to allow

removal of condensation.

16.) It is assumed that there is no restriction from the interconnected utility for loading the GT within the SU times considered and GT & ST can be synchronized to the grid in 30 seconds.

17.) CEMS may calculate emissions differently.

Mode Time (min)

Total Pounds Per Event Stack Exhaust (A)

Siemens Energy, Inc. Proprietary Information 4/28/2015

Bechtel - Renovo - SCC6-8000H with Drum+ HRSG & ACC on ULSD @ -4 °F Total Estimated Startup & Shutdown Emissions, Fuel Use, Exhaust Gas Volumetric Flow Rate & Temperature

NOX CO VOC SO2 PM CO2 Fuel Use acfm °F "Cold" Startup (GT Ignition to Emissions Compliance @ 70% GT Load) 35 123 1,763 195 1.2 16.2 122,058 36,649 781,795 267

"Cold" Startup (GT Ignition to 100% GT Load / STB Valves Closed) 180 228 1,775 200 8.0 88.7 846,611 254,317 962,393 273

"Warm" Startup (GT Ignition to 100% GT Load) 32 122 1,835 205 1.0 14.8 110,544 33,187 794,409 267

"Warm" Startup (GT Ignition to Emissions Compliance @ 100% GT Load) 35 132 1,836 205 1.2 16.3 130,183 39,080 862,055 268

"Warm" Startup (GT Ignition to STB Valves Closed) 80 175 1,853 208 4.0 38.8 424,765 127,474 1,267,927 275

"Hot" Startup (GT Ignition to 100% GT Load and Emissions Compliance) 32 122 1,576 205 1.0 14.8 110,544 33,187 794,409 267

"Hot" Startup (GT Ignition to STB Valves Closed) 71 159 1,591 207 3.4 34.3 365,848 109,795 1,227,911 274

Shutdown (50% GT Load to Fuel Cut Off) 18 102 332 133.4 0.5 9.0 54,276 16,283 778,466 263

Shutdown (100% GT Load to Fuel Cut Off) 50 122 337 134 1.8 25.3 194,340 58,350 857,796 268

(A) Time-weighted average values over the designated startup time period

General Notes1.) All data is ESTIMATED, NOT guaranteed and is for ONE unit (gas turbine and HRSG).

2.) Emissions are at the HRSG exhaust stack outlet and exclude ambient air contributions.

3.) Emissions are based on new and clean conditions.4.) VOC consist of total hydrocarbons excluding methane and ethane and are expressed in terms of methane (CH4).

5.) Ultra Low Sulfur Diesel (ULSD) composition (weight percent) is: 86.434 C, 13.5 H2, 0.015 N2, 0.001 ash, and 0.0015 S.

6.) Particulate (PM) emissions are based on the aforementioned fuel sulfur content and are per USEPA Methods 5/202.

7.) Fuel use is based on a fuel heating value of approximately 19,680 Btu/lbm (HHV).

8.) ULSD must be in compliance with the Siemens liquid fuel specification.

9.) Please be advised that the information contained in this transmittal has been prepared and is being transmitted per customer request specifically for information purposes only.

Data included in any permit application or Environmental Impact Statement is strictly the customer's responsibility. Siemens is available to review permit application data upon request.

Startup / Shutdown Emissions Notes1.) "Cold" startup (SU) data are based on an extended gas turbine (GT) shutdown (SD), greater than ~ 64 hours, with the steam turbine (ST) rotor temperature less than ~ 509 °F (265 °C)

and greater than ~ 302 °F (150 °C).

2.) "Warm" SU data are based on the GT being shutdown between ~ 16 and 64 hours, with the ST rotor temperature between ~ 509 °F (265 °C) and 716 °F (380 °C).

3.) "Hot" SU data are based on the GT being shutdown less than ~ 16 hours, with the ST rotor temperature greater than ~ 716 °F (380 °C).

4.) "Hot Start-on-the-Fly" SU data are based on the GT being shutdown less than ~ 8 hours, with the ST rotor temperature greater than ~ 780 °f (416 °C).

5.) Estimated "Cold", "Warm", "Hot" and Shutdown data are based on the assumed times noted above at ~ 13 MW/min per "Renovo Energy Center-SCC6-8000H-1S-KN-(drum+)-13WM-FO-rev002-.pdf"

dated April 27, 2015, and assume the use of a fast start SFC to get from GT ignition to synchronization in 7-minutes, and will be higher for longer times and/or slower ramp rates.6.) Estimated NOX emissions assume the use of an SCR system, and estimated CO and VOC emissions assume the use of an oxidation catalyst.

7.) "Emissions Compliance" assumed to mean 6 ppmvd NOX and 4 ppmvd CO at the stack.

8.) HRSG high (HP), intermediate (IP) and low pressure (LP) drums are filled to start up levels, the HRSG is ready for operation, and purge credit is established prior to GT startup.

9.) Steam chemistry adequate for ST operation (no waiting time included).

10.) Data assumes all BOP systems and auxiliaries meet Siemens start and shutdown prerequisites and that all systems run smoothly without upsets.

11.) Air Cooled Condenser (ACC) receiver tank is filled to startup level, vacuum is maintained during shutdown, and condenser pressure is below 20 in. HgA prior to GT start.

12.) ACC is able to receive full bypass steam at 100% GT load without ST back pressure violation in startup mode at any ambient temperature less than ~ 91 °F.

13.) Operator actions do not extend SU or SD times.

14.) HRSG stack damper has been closed as soon after SD as possible to maintain heat, and HRSG has been maintained in a "bottled-up" condition during the SD with drain valves in AUTO to allow

removal of condensation.

15.) It is assumed that there is no restriction from the interconnected utility for loading the GT within the SU times considered and GT & ST can be synchronized to the grid in 30 seconds.

16.) CEMS may calculate emissions differently.

Mode Time (min)

Total Pounds Per Event Stack Exhaust (A)

Attachment E

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesNitrogen Oxides (NOx)

August 2015 page 1 of 3

RBLC ID Facility Name State Permit Date Process Name/Description BasisFuel

Type(s)Control

Description Averaging Period CommentsAR-0105 AECI DELL AR 3/31/2010 CC Power Plant 2,112 MMBtu/hr BACT-PSD ULSD SCR 6 PPMVD @ 15% O2 3-hour

CO-0056ROCKY MOUNTAIN ENERGY CENTER, LLC

CO 5/2/2006 CC CTG 300 MW BACT-PSD NG DLN, SCR 3 PPMVD @ 15% O2 hourly maximum

CT-0151KLEEN ENERGY SYSTEMS, LLC

CT 2/25/2008Siemens SGT6-5000F CTGs with DBs

2.100 MMcf/hr LAER NG DLN, SCR2

5.9PPMVD @ 15% O2 (NG)PPMVD @ 15% O2 (ULSD)

w/out duct burner

n/aGARRISON ENERGY CENTER

DE 1/30/2013CC unit consisting of 2 GE 7FA CTGs each with HRSGs

309 MW BACT-PSD NG, ULSDDLN, SCR, WI,

Oxidation Catalyst

26

PPMVD @ 15% O2 (NG)PPMVD @ 15% O2 (ULSD)

1-hour (NG baseload)3-hour (NG non-base, ULSD)

not yet built

FL-0286FPL WEST COUNTY ENERGY CENTER

FL 1/10/20072 CC units consisting of 3x250 MW 501G CTGs each with HRSGs

2,333 MMBtu/hr BACT-PSD NG DLN, SCR, WI 2 PPMVD @ 15% O2 24-hour (gas) Meeting all limits

FL-0303FPL WEST COUNTY ENERGY CENTER UNIT 3

FL 7/30/2008CC unit consisting of 3 nominal 250 MW CTGs each with HRSGs

2,333 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPMVD (GAS) 24-hour Meeting all limits

n/aCAPE CANAVERAL ENERGY CENTER

FL 1/1/2015CC unit consisting of 3 Siemens H-class CTGs with HRSGs and DBs

1,250 MW BACT-PSD NG, ULSD DLN, SCR, WI28


30 unit operating days

n/aRIVIERA BEACH ENERGY CENTER

FL 1/1/2015CC unit consisting of 3 Siemens H-class CTGs with HRSGs and DBs



30 unit operating days

GA-0138LIVE OAKS POWER PLANT

GA 4/8/2010 CC Power Plant 600 MW BACT-PSD NG DLN, SCR 2.5 PPMVD @ 15% O2 3-hour

ID-0018LANGLEY GULCH POWER PLANT

ID 6/25/2010 Siemens SGT6-5000F CT 2,375.28 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 3-hour Meeting all limits

*IL-0112NELSON ENERGY CENTER

IL 12/28/2010 2 CC CTGs each with HRSGs 220 MWe each BACT-PSD NG DLN, SCR 4.5 PPMVD @ 15% O2 1-hour except during SSM or tuning

*IN-0158ST. JOSEPH ENEGRY CENTER, LLC

IN 12/3/2012 4 CC CTGs 2,300 MMBtu/hr BACT-PSD NG 443 LB event SUSD Cycle

LA-0136PLAQUEMINE COGENERATION FACILITY

LA 7/23/2008 4 CTGs each with DBs 2,876 MMBtu/hr BACT-PSD NG DLN, SCR 5 PPMVD @ 15% O2 annual average

LA-0192CRESCENT CITY POWER

LA 6/6/2005 Gas Turbines 2,006 MMBtu/hr BACT-PSD NG DLN, SCR 3 PPMVD @ 15% O2 annual average

LA-0224ARSENAL HILL POWER PLANT

LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NG DLN, SCR 4 PPMVD @ 15% O2 annual average


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NG DLN, SCR 400 LB/HR max HOT STARTUP

*MI-0405MIDLAND COGENERATION VENTURE

MI 4/23/2013CC unit with 2 CTGs each with HRSGs

2,237 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPM 24-hour never installed



2,486 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPM 24-hour never installed


MI 4/23/2013CC unit consisting of 2 CTGs each with HRSGs

2,237 MMBtu/hr BACT-PSD NG DLN, SCR 185.7 LB/HR hourly maximum startup, not yet installed

*MI-0410THETFORD GENERATING STATION

MI 7/25/20132 CC units consisting of 2 CTGs each with HRSGs

2,587 MMBtu/hr BACT-PSD NG DLN, SCR 3 PPMV 24-hour


MI 7/25/2013 4 CTGs each with HRSGs and DBs 2,587 MMBtu/hr BACT-PSD NG DLN, SCR 78.4 TPY 12-month rolling total SUSD only

NV-0035TRACY SUBSTATION EXPANSION PROJECT

NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 3-hour

Size Emission Limit




Type(s)Control

Description Averaging Period CommentsSize Emission Limit


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 3-hour

NY-0095CAITHNES BELLPORT ENERGY CENTER

NY 5/10/2006 CC CTG with DB 2,221 MMBtu/hr BACT-PSD NG, ULSD SCR26


w/out duct burner

NY-0098ATHENS GENERATING PLANT

NY 1/19/2007 3 CC CTGs each with HRSGs, 501G 3,100 MMBtu/hr LAER NG DLN, SCR, WI29


3-hour

NY-0100EMPIRE POWER PLANT

NY 7/1/2014 Fuel Combustion (NG) 2,099 MMBtu/hr LAER NG DLN, SCR, WI29


3-hour

*OH-0352OREGON CLEAN ENERGY CENTER

OH 6/18/20132 CC units consisting of either 2 Siemens or 2 MHI CTGs each with DBs

47,917MMscf per rolling 12-mos.

BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 w/out duct burner. 20.8 lb/hr




BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 w/out duct burner. 21 lb/hr




BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 w/duct burner. 22 lb/hr




BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 w/duct burner. 22.6 lb/hr

OK-0129CHOUTEAU POWER PLANT

OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBtu/hr BACT-PSD NG DLN 568 LB/EVENT 4-hour Startup

OR-0048 CARTY PLANT OR 12/29/2010 NG fired CC 2,866 MMBtu/hr BACT-PSD NG SCR 2 PPMVD @ 15% O2 3-hour

*PA-0286MOXIE ENERGY LLC/PATRIOT GENERATION PLT

PA 12/13/20132 CC units each consisting of 1 Siemens SGT6-8000H with HRSG

0 BACT-PSD NG SCR 2 PPMDV not yet built

*PA-0296BERKS HOLLOW ENERGY ASSOC LLC/ONTELAUNEE

PA 12/17/2013 CC CTGs 3,046 MMBtu/hr BACT-PSD NG SCR 131.6 TPY 12-month rolling total not yet built

*PA-0298FUTURE POWER PA/GOOD SPRINGS NGCC FACILITY

PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG SCR 2 PPMVD @ 15% O2 not yet built

n/aMOXIE ENERGY LLC/LIBERTY GENERATION PLT

PA 1/31/20132 CC units each consisting of 1 Siemens SGT6-8000H CTG with HRSG

0 BACT-PSD NG SCR 2 PPMVD @ 15% O2 1-hour not yet built

n/aWESTMORELAND GENERATING STATION

PA 4/1/20152 CC units each consisting of 1 MHI J-class CTG with HRSG and DB

3,147 MMBtu/hr BACT-PSD NGDLN, SCR, Oxidation Catalyst

2 PPMVD @ 15% O2 3-hour not yet built

*TX-0641PINECREST ENERGY CENTER

TX 11/12/2013CC unit consisting of either 2 GE7FA or 2 Siemens SGT6-5000F CTGs each with HRSGs

700 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 24-hour

TX-0546PATTILLO BRANCH POWER PLANT

TX 6/17/2009GE Frame 7 of Siemens SGT6-5000F CTGs

350 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 24-hour never built

TX-0547NATURAL GAS-FIRED POWER GENERATION FACILITY

TX 6/22/2009CC unit consisting of either 2 GE 7FA or 2 MHI 501GS CTGs

250 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 24-hour never built

TX-0548MADISON BELL ENERGY CENTER

TX 8/18/20092 CC units consisting of 2 GE CTGs each with HRSGs

275 MW BACT-PSD NG SCR 2 PPMVD @ 15% O2 24-hour not yet built

TX-0590KING POWER STATION

TX 8/5/20102 CC units consisting of either 2 GE Frame 7 or 2 Siemens SGT6-5000F CTGs each with HRSGs

1,350 MW LAER NG DLN, SCR 2 PPMVD @ 15% O2 1-hour

TX-0600THOMAS C. FERGUSON POWER PLANT

TX 9/1/2011CC unit consisting of 2 GE7FA CTGs each with HRSGs

390 MW BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 24-hour never built, permit voided




Type(s)Control

Description Averaging Period CommentsSize Emission Limit

*VA-0315WARREN COUNTY POWER PLANT - DOMINION

VA 12/17/2010 3 MHI Model 501GAC CTGs 2,996 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 1-hourMeeting limits, however 1-hour average has been difficult to meet during maintenance

*VA-0321BRUNSWICK COUNTY POWER STATION

VA 3/12/20133 MHI Model 501GAC CTGs each with HRSGs

3,442 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2 1-hourNot yet built- first fire expected November 2015.

*WV-0025MOUNDSVILLE COMBINED CYCLE POWER PLANT

WV 11/21/2014CC unit consisting of GE 7FA CTG with HRSG

2,159 MMBtu/hr BACT-PSD NG DLN, SCR 2 PPMVD @ 15% O2

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesCarbon Monoxide (CO)



Type(s) Control Description Averaging Period Comments


CO 5/2/2006 CC CTG 300 MW BACT-PSD NGOxidation catalyst, good combustion

3 PPMVD @ 15% O2



2.1 MMCF/H BACT-PSD NG, ULSD Oxidation catalyst0.91.8


w/out duct burner

n/a GARRISON ENERGY CENTER

DE 1/30/2013 CC unit consisting of 2 GE 7FA CTGs each with HRSGs


Oxidation Catalyst25.328.8

LB/HR (NG)LB/HR (ULSD)

not yet built

FL-0265HINES POWER BLOCK 4

FL 6/8/2005 CC CTG 530 MW BACT-PSD NG Good combustion 8 PPM

FL-0285PROGRESS BARTOW POWER PLANT

FL 1/26/2007 CC unit with 4 CTGs 1,972 MMBTU/H BACT-PSD NG Good combustion 8 PPMVD 24-hour



2,333 MMBTU/H BACT-PSD NG Good combustion 8 PPMVD @ 15% O2 24-hour Meeting all limits



2,333 MMBTU/H BACT-PSD NG Good combustion 6 PPMVD (GAS) 12-month Meeting all limits

n/a CAPE CANAVERAL ENERGY CENTER

FL 1/1/2015 CC unit consisting of 3 Siemens H-class CTGs with HRSGs and DBs


10PPMVD @ 15% O2 (NG)PPMVD @ 15% O2 (ULSD)

30 unit operating days w/out duct burner. 7.6 ppm with DB.

n/a RIVIERA BEACH ENERGY CENTER




30 unit operating days w/out duct burner. 7.6 ppm with DB.

GA-0127PLANT MCDONOUGH COMBINED CYCLE

GA 1/7/20083 CC units each consisting of 2 CTGs with HRSGs and DBs

254 MW BACT-PSD NG, ULSD Oxidation catalyst1.8


3-hour


GA 4/8/2010 CC Power Plant 600 MW BACT-PSD NGOxidation catalyst, good combustion

2 PPMVD @ 15% O2 3-hour w/out duct burner

*IA-0107MARSHALLTOWN GENERATING STATION

IA 4/14/2014CC unit consisting of 2 Siemens SGT6-5000F CTGs

2,258 mmBtu/hr BACT-PSD NG Oxidation catalyst 2 PPMVD @ 15% O2 30-day rolling average


ID 6/25/2010 Siemens SGT6-5000F CTG 2,375.28 MMBTU/H BACT-PSD NGDLN, Oxidation catalyst, good combustion

2 PPMVD @ 15% O2 3-hour


IN 12/3/2012 4 CC CTGs 2,300 MMBTU/H BACT-PSD NG Oxidation catalyst 2 PPMVD 3-hour


IN 12/3/2012 4 CC CTGs 2,300 MMBTU/H BACT-PSD NG 2125 LB per event


LA 7/23/2008 4 CTGs each with DBs 2,876 MMBTU/H BACT-PSD NG Good combustion 25 PPMVD @ 15% O2 Annual Average


LA 6/6/2005 Gas Turbines 2,006 MMBTU/H BACT-PSD NGOxidation catalyst, good combustion

4 PPMVD @ 15% O2 Annual Average


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBTU/H BACT-PSD NG Good combustion 10 PPMVD @ 15% O2 Annual Average


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBTU/H BACT-PSD NG

Good combustion, manufacturer's recommended

procedures

1576 LB/HR hourly maximum Hot Startups

LA-0254NINEMILE POINT ELECTRIC GENERATING PLANT

LA 8/16/2011 CC CTG 7,146 MMBTU/H BACT-PSD NGOxidation catalyst, good combustion




2,237 MMBtu/hour BACT-PSD NG Good combustion 9 PPM 24-hour not yet installed

Size Emission Limit




Type(s) Control Description Averaging Period CommentsSize Emission Limit



2,486 MMBTU/H BACT-PSD NG Good combustion 10.5 PPM 24-hour not yet installed



2,237MMBtu/hour each

BACT-PSD NG Good combustion 3123 LB/HR hourly during startup not yet installed


MI 7/25/20132 CC units consisting of 2 CTGs each with HRSGs

2,587MMBTU/H heat input, each CTG

BACT-PSD NGOxidation catalyst, good combustion

4 PPMV 24-hour


MI 7/25/2013 4 CTGs each with HRSGs and DBs 2,587MMBTU/H design heat input, each


694 T/Y 12-month rolling total SUSD

*MI-0412HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREET

MI 12/4/2013CC unit consisting of 2 CTGs with HRSGs and DBs

647MMBtu/hr for each CTGHRSG


4 PPM 24-hour not including SUSD

MN-0060HIGH BRIDGE GENERATING PLANT

MN 8/12/2005 CC CTGs 330 MEGAWATTS BACT-PSD NG Good combustion 10 PPMVD @ 15% O2 w/out duct burner

MN-0066

NORTHERN STATES POWER CO. DBA XCEL ENERGY - RIVERSIDE PLANT

MN 5/16/2006 CC CTG 1,885 mmbtu/h BACT-PSD NG Good combustion 10 PPMVD @ 15% O2 3-hour


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG Oxidation catalyst 3.5 PPMVD @ 15% O2 3-hour


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG Oxidation catalyst 3.5 PPMVD @ 15% O2 3-hour


NY 5/10/2006 CC CTG with DB 2,221 MMBUT/H BACT-PSD NG, ULSD Oxidation catalyst22


ULSD limit between 90-100% load. 4ppm between 75-90% road.


OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBTU/H BACT-PSD NG Good combustion 8 PPMV 1-hour


OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBTU/H BACT-PSD NG Good combustion 1596 LB/EVENT 4-hour Startup

*OR-0050TROUTDALE ENERGY CENTER, LLC

OR 3/5/2015 MHI M501-GAC CTG, CC w/DB 2,988 MMBtu/hr BACT-PSD NG

Oxidation catalyst; Limit the time in

startup or shutdown.

3.3 PPMVD @ 15% O2 3-hour

OR-0041WANAPA ENERGY CENTER

OR 8/8/2005 GE 7241FA CTG with HRSG 2,384 MMBTU/H BACT-PSD NG Oxidation catalyst 2 PPMVD @ 15% O2 3-hour never built


PA 12/13/2013 2 CC units each consisting of 1 Siemens SGT6-8000H with HRSG

0 BACT-PSD NG Oxidation catalyst 2 PPMVD @ 15% O2 not yet built

*PA-0291HICKORY RUN ENERGY STATION

PA 4/23/2013CC units with either GE 7FA, MHI 501G, Siemens SGT6-5000F, or Siemens SGT6-8000H CTGs

3.4 MMCF/HROTHER

CASE-BY-CASE

NG Oxidation catalyst 2 PPMVD @ 15% O2 with or w/out duct burner


PA 12/17/2013 CC CTGs 3,046 MMBtu/hr BACT-PSD NG Oxidation catalyst 211.9 TPY 12-month rolling total not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG Oxidation catalyst 3 PPMVD @ 15% O2 not yet built



0 BACT-PSD NG SCR 2 PPMVD @ 15% O2 1-hour not yet built


PA 4/1/2015 2 CC units each consisting of 1 MHI J-class CTG with HRSG and DB

3,147 MMBtu/hr BACT-PSD NG DLN, SCR, Oxidation Catalyst

2 PPMVD @ 15% O2 3-hour not yet built







700 MW BACT-PSD NG Oxidation catalyst 2 PPMVD @ 15% O2 3-hour 80-100% load



350 MW BACT-PSD NG Oxidation catalyst 2 PPMVD @ 15% O2 3-hour never built



275 MW BACT-PSD NG Good combustion 17.5 PPMVD @ 15% O2 1-hour not yet built



1,350 MW BACT-PSD NGOxidation catalyst, good combustion




390 MW BACT-PSD NGOxidation catalyst, good combustion

4 PPMVD @ 15% O2 3-hour loads greater than 60%. Never built, permit voided.


VA 12/17/2010 3 MHI Model 501GAC CTGs 2,996 MMBTU/H BACT-PSD NGOxidation catalyst, good combustion

1.5 PPMVD 1-hourw/out duct burner- 2.4 ppm with duct burner. Meeting all limits, however 1-hour average has been difficult to meet during maintenance.



3,442 MMBTU/H BACT-PSD NGOxidation catalyst, good combustion

1.5 PPMVD 3-hourw/out duct burner. Not yet built- first fire expected November 2015.


WV 11/21/2014CC unit consisting of GE 7FA CTG with HRSG

2,159 mmBtu/Hr BACT-PSD NGOxidation catalyst, good combustion

2 PPMVD @ 15% O2

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesVolatile Organic Compounds (VOC)




CA-1178 APPLIED ENERGY LLC CA 3/20/2009 CC CTG 0 BACT-PSD NG Oxidation catalyst 2 PPM 1-hour


CO 5/2/2006 CC CTG 300 MW BACT-PSD NGOxidation catalyst, good combustion

0.003 LB/MMBTU



2.1 MMcf/hr BACT-PSD NG, ULSD Oxidation catalyst5

3.6PPMVD AT 15% O2 (NG)PPMVD AT 15% O2 (ULSD)

1-hour w/out duct burner

n/aGARRISON ENERGY CENTER

DE 1/30/2013CC unit consisting of 2 GE 7FA CTGs each with HRSGs


Oxidation Catalyst4.14.5


not yet built


FL 1/26/2007 CC unit with 4 CTGs 1,972 MMBtu/hr BACT-PSD NG Good combustion 1.2 PPMVD AT 15% O2 w/out duct burner. 1.5 ppm with duct burner


FL 1/10/2007 2 CC units consisting of 3x250 MW 501G CTGs each with HRSGs

2,333 MMBtu/hr BACT-PSD NG 1.5 PPMVD AT 15% O2 Meeting all limits


FL 7/30/2008 CC unit consisting of 3 nominal 250 MW CTGs each with HRSGs

2,333 MMBtu/hr BACT-PSD NG 1.2 PPMVD Meeting all limits

FL-0337POLK POWER STATION

FL 10/14/2012 4 SC CTGs 1,160 MW BACT-PSD NG fuel sulfur limits 1.4 PPMVD AT 15% O2



1,250 MW BACT-PSD NG, ULSD DLN, SCR, WI1.51.9

6

PPMVD @ 15% O2 (NG)PPMVD @ 15% O2 (NG w/DB)PPMVD @ 15% O2 (ULSD)



1,250 MW BACT-PSD NG, ULSD DLN, SCR, WI1.51.9

6

PPMVD @ 15% O2 (NG)PPMVD @ 15% O2 (NG w/DB)PPMVD @ 15% O2 (ULSD)

GA-0127PLANT MCDONOUGH COMBINED CYCLE

GA 1/7/2008 3 CC units each consisting of 2 CTGs with HRSGs and DBs

254 MW LAER NG, ULSD Oxidation catalyst1.8

4PPMVD AT 15% O2 (NG)PPMVD AT 15% O2 (ULSD)

3-hour NG value with duct burner, ULSD value without


GA 4/8/2010 CC Power Plant 600 MW BACT-PSD NGOxidation catalyst, good combustion

2 PPMVD AT 15% O2 3-hour


IA 4/14/2014 CC unit consisting of 2 Siemens SGT6-5000F CTGs

2,258 MMBtu/hr BACT-PSD NG Oxidation catalyst 1 PPMAvg. of three 1-hour

test runs



2,258 MMBtu/hr BACT-PSD NG 1 PPMAvg. of three 1-hour

test runs


ID 6/25/2010 Siemens SGT6-5000F CTG 2,375.28 MMBtu/hr BACT-PSD NGDLN, Oxidation catalyst, good combustion



IL 12/28/2010 2 CC CTGs each with HRSGs 220 MW BACT-PSD NG 4 PPMVD AT 15% O2 1-hour except during SSM or tuning


IN 12/3/2012 4 CC CTGs 2,300 MMBtu/hr BACT-PSD NG Oxidation catalyst 1 PPMVD 3-hour


IN 12/3/2012 4 CC CTGs 2,300 MMBtu/hr BACT-PSD NG 22 TONS 12-month rolling


LA 6/6/2005 Gas Turbines 2,006 MMBtu/hr BACT-PSD NGOxidation catalyst, good combustion

1.1 PPMVD AT 15% O2 annual average


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NG Good combustion 4.9 PPMVD AT 15% O2 annual average


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NG

Good combustion, manufacturer's recommended

procedures

214.1 LB/H MAX


LA 8/16/2011 CC CTG 7,146 MMBtu/hr BACT-PSD NG Good combustion 1.4 PPMVD AT 15% O2 1-hour w/out duct burner

Size Emission Limit






MI 4/23/2013 CC unit consisting of 2 CTGs each with HRSGs

2,237 MMBtu/hr BACT-PSD NG Good combustion 0.002 LB/MMBTUEACH CTG; TEST

PROTOCOLnever installed



2,486 MMBtu/hr BACT-PSD NG Good combustion 0.004 LB/MMBTU TEST PROTOCOL never installed


MI 7/25/2013 2 CC units consisting of 2 CTGs each with HRSGs

2,587 MMBtu/hr BACT-PSD NGOxidation catalyst, good combustion

0

MN-0060HIGH BRIDGE GENERATING PLANT

MN 8/12/2005 CC CTGs 330 MW BACT-PSD NG Good combustion 2 PPMVD AT 15% O2 w/out duct burner

MN-0066

NORTHERN STATES POWER CO. DBA XCEL ENERGY - RIVERSIDE PLANT

MN 5/16/2008 CC CTG 1,885 MMBtu/hr BACT-PSD NG Good combustion 4.6 PPMVD AT 15% O2 3-hour

MN-0071FAIRBAULT ENERGY PARK

MN 6/5/2007 CC unit consisting of GE 7FA CTG with DB

1,758 MMBtu/hr BACT-PSD NG, ULSD1.5

33.5

PPMVD (NG, w/o DB)PPMVD (NG, w/DB)PPMVD (ULSD, w/ or w/o DB)

w/out duct burner

NJ-0074WEST DEPTFORD ENERGY

NJ 5/6/2009 CC CTG 17,298 MMcf/year LAER NGOxidation catalyst, good combustion

1.9 PPMVD AT 15% O2Avg. of three 1-hour

test runs


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG Oxidation catalyst 4 PPMVD AT 15% O2 3-hour


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG Oxidation catalyst 4 PPMVD AT 15% O2 3-hour

NY-0098ATHENS GENERATING PLANT

NY 1/19/2007 3 CC CTGs each with HRSGs, 501G 3,100 MMBtu/hr LAER NG, ULSD Good combustion4

13PPMVD AT 15% O2 (NG)PPMVD AT 15% O2 (ULSD)

3-hour1-hour

NY-0100EMPIRE POWER PLANT

NY 7/1/2014 Fuel Combustion (NG) 2,099 MMBtu/hr LAER NG, ULSD Oxidation catalyst

127

12

PPMVD AT 15% O2 (NG)PPMVD AT 15% O2 (ULSD)PPMVD AT 15% O2 (NG w/DB)PPMVD AT 15% O2 (ULSD w/DB)

AS PER EPA METHOD 25A



515,600MMscf/ rolling 12-months

BACT-PSD NG Oxidation catalyst 1 PPMVD AT 15% O2 w/out duct burner




BACT-PSD NG Oxidation catalyst 1.9 PPMVD AT 15% O2 w/duct burner




BACT-PSD NG Oxidation catalyst 2 PPMVD AT 15% O2 w/duct burner




BACT-PSD NG Oxidation catalyst 2 PPMVD AT 15% O2 w/out duct burner


OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBtu/hr BACT-PSD NG Good combustion 0.3 PPMVD AT 15% O2 3-hour


OR 3/5/2014 MHI M501-GAC CTG, CC w/DB 2,988 MMBtu/hr BACT-PSD NGOxidation catalyst,

limit the time in startup or shutdown



OR 8/8/2005 GE 7241FA CTG with HRSG 2,384 MMBtu/hr BACT-PSD NG Oxidation catalyst 0 SEE POLUTANT NOTE never built



0 BACT-PSD NG Oxidation catalyst 1 PPMDVw/out duct burner. 1.5 ppm with duct burner. Not yet built.



3.4 MMcf/hrOTHER

CASE-BY-CASE

NG Oxidation catalyst 1.5 PPMVD AT 15% O2 with or w/out duct burner. Not yet built






PA 12/17/2013 CC CTGs 3,046 MMBtu/hr NG 93.85 TPY 12-month rolling not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG Oxidation catalyst 2 PPMVD AT 15% O2 not yet built



0 BACT-PSD NG SCR, Oxidation Catalyst

1 PPMVD @ 15% O2 1-hourw/out duct burner. 1.5 ppm with duct burner. Not yet built.



3,147 MMBtu/hr BACT-PSD NG DLN, SCR, Oxidation Catalyst

1.4 PPMVD @ 15% O2 3-hourw/out duct burner. 2.4 ppm with duct burner. Not yet built



700 MW BACT-PSD NG Oxidation catalyst 2 PPMVD AT 15% O2

*TX-0660FGE TEXAS POWER I AND FGE TEXAS POWER II

TX 3/24/2014 Four Alstom GT24 CTGs each with HRSGs and DBs

230.7 MW BACT-PSD NGOxidation catalyst, good combustion


TX-0516CITY PUBLIC SERVICE JK SPRUCE ELECTRICE GENERATING UNIT 2

TX 12/28/2005 Spruce Power Generator Unit #2 BACT-PSD NG 29 LB/H



350 MW BACT-PSD NG Oxidation catalyst 2 PPMVD AT 15% O2 3-hour not yet built

TX-0547NATURAL GAS-FIRED POWER GENERATION FACILITY

TX 6/22/2009CC unit consisting of either 2 GE 7FA or 2 MHI 501GS CTGs

250 MW BACT-PSD NG Good combustion 4 PPMVD AT 15% O2 24-hour



275 MW BACT-PSD NG Good combustion 2.5 PPMVD AT 15% O2 1-hour not yet built



1,350 MW LAER NGDLN, Oxidation

catalyst1.8 PPMVD AT 15% O2 3-hour


TX 9/1/2011 CC unit consisting of 2 GE7FA CTGs each with HRSGs

390 MW BACT-PSD NGOxidation catalyst, good combustion

2 PPMVD AT 15% O2 3-hour Never built, permit voided.


VA 12/17/2010 3 MHI Model 501GAC CTGs 2,996 MMBtu/hr BACT-PSD NGOxidation catalyst, good combustion

2.6 LB/H 3-hourw/out duct burner- 6.1 lb/hr with duct burner. Meeting all limits, however 1-hour average has been difficult to meet during maintenance.


VA 3/12/2013 3 MHI Model 501GAC CTGs each with HRSGs


0.7 PPMVD 3-hourw/out duct burner. Not yet built- first fire expected November 2015.


WV 11/21/2014 CC unit consisting of GE 7FA CTG with HRSG


2 PPMVD AT 15% O2

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesParticulate Matter (PM/PM10/PM2.5)



Type(s) Control Description Averaging Period CommentsAR-0105 AECI DELL AR 3/31/2010 CC Power Plant 2,112 MMBtu/hr BACT-PSD ULSD Good combustion 0.009 LB/MMBtu 3-hour


CO 5/2/2006 CC CTG 300 MW BACT-PSD NGGood combustion, low sulfur

fuel0.0074 LB/MMBtu


CT 2/25/2008 Siemens SGT6-5000F CTGs with DBs

2.1 MMcf/hr BACT-PSD NG 11 LB/HR w/out duct burner. 15.2 lb/hr with duct burner.


CT 2/25/2008 Siemens SGT6-5000F CTGs with DBs

15,119 gal/hr BACT-PSD ULSD 57 LB/HR w/out duct burner

DE-0024GARRISON ENERGY CENTER


2,260 MMBtu/hr BACT-PSD NG Low sulfur fuel 120.4 TONS 12-month rolling total not yet built


FL 6/8/2005 CC CTG 530 MW BACT-PSD NG Low sulfur fuel 10 % OPACITY 6-minute


FL 1/10/2007 2 CC units consisting of 3x250 MW 501G CTGs each with HRSGs

2,333 MMBtu/hr BACT-PSD NG 2 gr S/100 scf in NG Meeting all limits


FL 7/30/2008 CC unit consisting of 3 nominal 250 MW CTGs each with HRSGs


FL-0304CANE ISLAND POWER PARK

FL 9/8/2008 CC CTGs 1,860 MMBtu/hr BACT-PSD NG Low sulfur fuel 2 gr S/100 scf in NG


FL 10/14/2012 4 SC CTGs 1,160 MW BACT-PSD NG Good combustion 2 gr S/100 scf in NG



1,250 MW BACT-PSD NG, ULSD Low sulfur fuel2

0.0015gr S/100 scf in NG% S in ULSD







2,258 MMBtu/hr BACT-PSD NG 0.01 LB/MMBtu Avg. of three 1-hour test runs


ID 6/25/2010 Siemens SGT6-5000F CTG 2,375.28 MMBtu/hr BACT-PSD NG Good combustion 0 No emission limits available


IL 12/28/2010 2 CC CTGs each with HRSGs 220 MW BACT-PSD NG 0.006 LB/MMBtu 1-hour




IN 12/3/2012 4 CC CTGs 2,300 MMBtu/hr BACT-PSD NGGood combustion, low sulfur

fuel18 LB/HR 3-hour


LA 7/23/2008 4 CTGs each with DBs 2,876 MMBtu/hr BACT-PSD NG Low sulfur fuel 33.5 LB/HR hourly maximum


LA 6/6/2005 Gas Turbines 2,006 MMBtu/hr BACT-PSD NGGood combustion, low sulfur

fuel29.4 LB/HR hourly maximum


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NGGood combustion, low sulfur

fuel24.23 LB/HR hourly maximum


LA 8/6/2011 CC CTG 7,146 MMBtu/hr BACT-PSD NGGood combustion, low sulfur

fuel26.23 LB/HR 1-hour w/out duct burner


MI 4/23/2013 CC unit consisting of 2 CTGs each with HRSGs and DBs

2,486 MMBtu/hr BACT-PSD NG Good combustion 0.004 LB/MMBtu never installed





MI 4/23/2013 CC unit consisting of 2 CTGs each with HRSGs and DBs




2,587 MMBtu/hr BACT-PSD NGCombustion air filters, good combustion, low sulfur fuel

0.0033 LB/MMBtu Avg. of three 1-hour test runs




0.0066 LB/MMBtu Avg. of three 1-hour test runs

Size Emission Limit





MN-0071FAIRBAULT ENERGY PARK

MN 6/5/2007 CC unit consisting of GE 7FA CTG with DB

1,758 MMBtu/hr BACT-PSD NG 0.01 LB/MMBtu


NJ 5/6/2009 CC CTG 17,298 MMcf/yearOther Case-

by-CaseNG Low sulfur fuel 18.66 LB/HR


NV 8/16/2005 CC CTG with HRSG 306 MW BACT-PSD NG Good combustion 0.011 LB/MMBtu 3-hour


NY 5/10/2006 CC CTG with DB 2,221 MMBtu/hr BACT-PSD NG Low sulfur fuel 0.0055 LB/MMBtu w/out duct burner


NY 5/10/2006 CC CTG with DB 2,125 MMBtu/hr BACT-PSD ULSD Low sulfur fuel 0.051 LB/MMBtu w/out duct burner, 90-100% load




BACT-PSD NG Low sulfur fuel 10.1 LB/HR












BACT-PSD NG Low sulfur fuel 14 LB/HR

OK-0117PSO SOUTHWESTERN POWER PLT

OK 2/9/2007 Gas Turbines BACT-PSD NGGood combustion, low sulfur

fuel0.0093 LB/MMBtu


OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBtu/hr N/A NG Low sulfur fuel 6.59 LB/HR 3-hour


OR 3/5/2014 MHI M501-GAC CTG, CC w/DB 2,988 MMBtu/hr BACT-PSD NGLow sulfur fuel, limit the

time in SUSD23.6 LB/HR 6-hour total PM


OR 8/8/2005 GE 7241FA CTG with HRSG 2,384.1 MMBtu/hr BACT-PSD NG 0 never built



0OTHER

CASE-BY-CASE

NG 0.0057 LB/MMBtu not yet built



3.4 MMcf/hrOTHER

CASE-BY-CASE

NG 18.5 LB/HR w/duct burner. 11.0 lb/hr without. Not yet built.


PA 12/17/2013 CC CTGs 3,046 MMBtu/hr BACT-PSD NG 48.56 TPY 12-month rolling total not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG 10.4 LB/HR not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG 15.6 LB/HR not yet built



0 BACT-PSD NG Combustion air filters, good combustion, low sulfur fuel

0.00570.4

LB/MMBtugr S/100 scf in NG

1-hour not yet built



3,147 MMBtu/hr BACT-PSD NG Good combustion, low sulfur fuel

0.00390.25





700 MW BACT-PSD NGGood combustion, low sulfur

fuel26.2 LB/HR


TX 3/24/2014 Four Alstom GT24 CTGs each with HRSGs and DBs

230.7 MW BACT-PSD NGGood combustion, low sulfur

fuel2 PPMVD


TX 12/28/2005 Spruce Power Generator Unit #2 BACT-PSD NG 264 LB/HR







1,350 MW BACT-PSD NG

use low ash fuel (natural gas or low sulfur diesel as a

backup) and good combustion practices

11.1 LB/HR


TX 9/1/2011 CC unit consisting of 2 GE7FA CTGs each with HRSGs

390 MW BACT-PSD NG Low sulfur fuel 33.43 LB/HR 1-H Never built, permit voided.


VA 12/17/2010 3 MHI Model 501GAC CTGs 2,996 MMBtu/hr BACT-PSD NG Low sulfur fuel 8 LB/HR 3-hour w/out duct burner


VA 3/12/2013 3 MHI Model 501GAC CTGs each with HRSGs

3,442 MMBtu/hr BACT-PSD NGGood combustion, low sulfur

fuel0.0033 LB/MMBtu 3-hour

w/out duct burner. Not yet built- first fire expected November 2015.


WV 11/21/2014 CC unit consisting of GE 7FA CTG with HRSG


7.6 LB/HR

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesSulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4)






2.115,119

MMcf/hr (NG)gal/hr (ULSD)

BACT-PSD NG, ULSD Low sulfur fuel4.93.2


w/out duct burner. 5.1 LB/HR (NG) and 3.7 LB/HR (ULSD) with duct burner


FL 6/8/2005 CC CTG 530 MW BACT-PSD NG, ULSD Low sulfur fuel2


continuous


FL 1/26/2007 CC unit with 4 CTGs 1,972 MMBtu/hr BACT-PSD NG 2 gr S/100 scf in NG



2,333 MMBtu/hr BACT-PSD NG, ULSD Low sulfur fuel2


Meeting all limits





FL 9/8/2008 CC CTGs 1,860 MMBtu/hr BACT-PSD NG Low sulfur fuel 2 gr S/100 scf in NG


FL 10/14/2012 4 SC CTGs 1,160 MW BACT-PSD NG, ULSD2





LA 7/23/2008 4 CTGs each with DBs 2,876 MMBtu/hr BACT-PSD NG Low sulfur fuel40.7

5LB/HRgr S/100 scf in NG

hourly maximum


LA 6/6/2005 Gas Turbines 2,006 MMBtu/hr BACT-PSD NG Low sulfur fuel10.1

1.8LB/HRgr S/100 scf in NG

hourly maximum


LA 3/20/2008 2 CC CTGs with DBs 2,110 MMBtu/hr BACT-PSD NG Low sulfur fuel 12.06 LB/HR hourly maximum


NY 5/10/2006 CC CTG with DB2,2212,125

MMBtu/hr (NG)MMBtu/hr (ULSD)

BACT-PSD NG, ULSD Low sulfur fuel

0.00110.042

0.00040.015

LB/MMBtu (SO2- NG)LB/MMBtu (SO2- ULSD)LB/MMBtu (H2SO4- NG)LB/MMBtu (H2SO4- ULSD)

w/out duct burner when firing ULSD. 0.036 LB/MMBtu SO2 and 0.0128 LB/MMBtu H2SO4

with duct burner when firing ULSD




N/A NG Low sulfur fuel0.0014

0.5LB/MMBtugr S/100 scf in NG

















OK 1/23/2009 2 Siemens V84.3A CTGs 1,882 MMBtu/hr N/A NG Low sulfur fuel 1.06 LB/HR 3-hour



0 BACT-PSD NG 0.0011 LB/MMBtu expressed as SO2. Not yet built.



3.4 MMcf/hrOTHER

CASE-BY-CASE

NG 7.19 LB/HRw/duct burner. 6.15 lb/hr without duct burner. Not yet built.


PA 12/17/2013 CC CTGs 3,046 MMBtu/hr BACT-PSD NG 19.7 TPY 12-month rolling total not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG 5.2 LB/HR w/duct burner


TX 3/24/2014Four Alstom GT24 CTGs each with HRSGs and DBs

230.7 MW BACT-PSD NGLow sulfur fuel, good combustion practices

1 gr S/100 scf in NG 1-hour


TX 12/28/2005 Spruce Power Generator Unit #2 BACT-PSD NG 2,880 LB/HR

Size Emission Limit

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesSulfur Dioxide (SO2) and Sulfuric Acid Mist (H2SO4)






3,442 MMBtu/hr BACT-PSD NG Low sulfur fuel 0.0011 LB/MMBtuNot yet built- first fire expected November 2015.


IN 12/3/2012 4 CC CTGs 2,300 MMBtu/hr BACT-PSD NG Low sulfur fuel 0.75 gr S/100 scf in NG



390 MW BACT-PSD NG Low sulfur fuel 27.07 LB/HR 1-hour Never built, permit voided.


OR 8/8/2005 GE 7241FA CTG with HRSG 2,384.1 MMBtu/hr BACT-PSD NG 0 SEE POLLUTANT NOTE never built


VA 12/17/2010 3 MHI Model 501GAC CTGs 2,996 MMBtu/hrOTHER

CASE-BY-CASE

NG Low sulfur fuel0.98

0.0003LB/HR% S in NG

3-hour


NJ 5/6/2009 CC CTG 17,298 MMcf/yearOTHER

CASE-BY-CASE

NG, ULSD Low sulfur fuel5.66

0.0015LB/HR% S in ULSD











0 BACT-PSD NG Combustion air filters, good combustion, low sulfur fuel

0.00110.4





3,147 MMBtu/hr BACT-PSD NG Good combustion, low sulfur fuel

2.70.000574

LB/HR (SO2)LB/MMBtu (H2SO4)


DE-0024GARRISON ENERGY CENTER


2,260 MMBtu/hr BACT-PSD NG, ULSD Low sulfur fuel6.53.0


12-month rolling total not yet built

Renovo Energy CenterPowerblocksRBLC Search Results and Other Similar FacilitiesAmmonia (NH3)






2.1 MMCF/H BACT-PSD NG 2 PPMVD @ 15% O2



15,119 GAL/H BACT-PSD ULSD 5 PPMVD @ 15% O2 1-hour

n/a GARRISON ENERGY CENTER


309 MW BACT-PSD NG, ULSD 7 PPMVD @ 15% O2 1-hour not yet built


FL 1/26/2007 CC unit with 4 CTGs 1,972 MMBTU/HOther Case-

by-CaseNG 5 PPMVD @ 5% O2



2,333 MMBTU/H BACT-PSD NG 5 PPMVD @ 15% O2 Meeting all limits



2,333 MMBTU/H BACT-PSD NG 5 PPMVD Meeting all limits


FL 9/8/2008 CC CTGs 1,860 MMBTU/H BACT-PSD NG 5 PPMVD



1,250 MW BACT-PSD NG, ULSD 5 PPMVD @ 15% O2 30 unit operating days



1,250 MW BACT-PSD NG, ULSD 5 PPMVD @ 15% O2 30 unit operating days


OR 8/8/2005 GE 7241FA CTG with HRSG 2,384.1 MMBTU/HOther Case-

by-CaseNG 5 PPMVD @ 15% O2 3-hour never built


PA 12/17/2013 CC CTGs 3,046 MMBtu/hr BACT-PSD NG 5 PPMVD not yet built


PA 3/4/2014 CC unit with Siemens CTG 2,267 MMBtu/hr BACT-PSD NG 72.5 TPY 12-month rolling total not yet built



0 BACT-PSD NG 5 PPMVD @ 15% O2 1-hour not yet built


PA 4/1/2015 2 CC units each consisting of 1 MHI J-class CTG with HRSG and DB

3,147 MMBtu/hr BACT-PSD NG 5 PPMVD @ 15% O2 3-hour not yet built

n/aMOXIE ENERGY LLC/PATRIOT GENERATION PLT


0 BACT-PSD NG 5 PPMVD @ 15% O2 not yet built


TX 3/24/2014Four Alstom GT24 CTGs each with HRSGs and DBs

230.7 MW BACT-PSD NGAVO, good

combustion practices7 PPMVD @ 15% O2 24-hour



390 MW BACT-PSD NGBest management

practices7 PPMVD @ 15% O2 24-hour Never built, permit voided.

Size Emission Limit


Auxiliary Boilers - Natural Gas

RBLC Search Results


RBLC ID Facility Name State Permit Date

Size

MMBtu/hr Control Description

Emission

Limit Units Averaging Period Comments

NY-0095 CAITHNES BELLPORT ENERGY CENTER NY 5/10/2006 29.4 Good combustion practices 0.036 LB/MMBTU

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 33.5 Good combustion 5.02 LB/H

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 35 Operational restriction of 500 hr/yr 50 PPMVD 1-HR AVG, @3% O2

CA-1192 AVENAL ENERGY PROJECT CA 6/21/2011 37.4

Ultra Low NOx Burner, use PUC quality

natural gas, operational restriction of

46,675 MMBtu/yr 50 PPMVD 3-HR AVG, @3% O2

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 37.7 Best combustion practices 0.036 LB/MMBTU 3-HR Rolling

*OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 39.8 Utilize Low-NOx burners and FGR. 0.04 LB/MMBTU 3-HR block avg

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 40 0.036 LB/MMBTU Not constructed

*PA-0296

BERKS HOLLOW ENERGY ASSOC

LLC/ONTELAUNEE PA 12/17/2013 40 3.31 TPY 12-month rolling avg Plan approval provides an additional limit of 0.036 lb/MMBtu.

*MI-0412

HOLLAND BOARD OF PUBLIC WORKS -

EAST 5TH STREET MI 12/4/2013 55 Good combustion practices 0.077 LB/MMBTU

An oxidation catalyst is greater than $12,000/ton for CO and VOC

together.

*IA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 60.1 CO catalytic oxidizer 0.0164 LB/MMBTU Avg. 3 1-hr test runs

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7 Clean fuel and good combustion practices 50 PPMVD

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 80 Good combustion practices 0.083 LB/MMBTU 3 hours LIMIT ONE AND TWO ARE FOR EACH BOILER

*MI-0412


EAST 5TH STREET MI 12/4/2013 95 Good combustion practices. 0.077 LB/MMBTU Test protocol


together.

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 99

Good combustion practices and using

combustion optimization technology 5.45 LB/H

BACT: 0.055 LB/MMBTU.

Restricted to 2000 hours of operation per rolling 12-months.

FL-0285 PROGRESS BARTOW POWER PLANT FL 1/26/2007 99 0.08 LB/MMBTU

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 99.8 0.08 LB/MMBTU

*WV-0025

MOUNDSVILLE COMBINED CYCLE POWER

PLANT WV 11/21/2014 100 Good Combustion Practices 4 LB/HR

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 100 Efficient combustion. 0.075 LB/MMBTU Test protocol The limit is 0.075 lb/MMBtu heat input for each boiler.

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 110 50 PPMVD 3-HR AVG, @3% O2

NC-0101 FORSYTH ENERGY PLANT NC 9/29/2005 110.2

Good combustion control and Low NO

Burner 9.08 LB/H 3-HR block avg

*TX-0641 PINECREST ENERGY CENTER TX 11/12/2013 150

pipeline quality natural gas and good

combustion 75 PPMVD

INITIAL STACK TEST,

3% OXYGEN

MN-0066

NORTHERN STATES POWER CO. DBA XCEL

ENERGY - RIVERSIDE PLANT MN 5/16/2006 160 Good combustion 0.08 LB/MMBTU 3-HR avg

GA-0127 PLANT MCDONOUGH COMBINED CYCLE GA 1/7/2008 200 0.037 LB/MMBTU 3-hour

LA-0254

NINEMILE POINT ELECTRIC GENERATING

PLANT LA 8/16/2011 338

Use of pipeline quality natural gas and

good combustion practices 84 LB/MMSCF Annual average

*Draft Determination

August 2015



RBLC Search Results

Nitrogen Oxides (NOx)


Size


Emission


NY-0095 CAITHNESS BELLPORT ENERGY CENTER NY 5/10/2006 28 Low NOx burners and flue gas recirculation 0.1 LB/MMBTU

NY-0095 CAITHNESS BELLPORT ENERGY CENTER NY 5/10/2006 29.4 Low NOx burners and flue gas recirculation 0.011 LB/MMBTU

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 33.5 Low NOx burners 0.07 LB/MMBTU

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 35 Operation restriction of 500 hr/yr 9 PPMVD 1-HR AVG, @3% O2


Ultra Low NOx Burner, use PUC quality natural gas,

operational restriction of 46,675 MMBtu/yr 9 PPMVD 3-HR AVG, @3% O2

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 37.7 Best combustion practices 0.037 LB/MMBTU 3-HOUR ROLLING

*OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 39.8 Utilize Low-NOx burners and FGR. 0.035 LB/MMBTU 3-hr Block avg

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 40 0.011 LB/MMBTU

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 40 1.01 TPY 12-Month rolling total

Plan approval provides an additional limit of 0.011

lb/MMBtu

*MI-0412


EAST 5TH STREET MI 12/4/2013 55 Low NOx burners and good combustion practices 0.05 LB/MMBTU TEST PROTOCOL

Low NOx burners (LNB) with flue gas recirculation is

greater than $8,000/ton for NOx. The efficiency range

for LNB alone is 40-70 percent.

*IA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 60.1 0.013 LB/MMBTU 3-hr Block avg

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7 Dry Low NOx burner. 9 PPMVD

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 80 Low NOx burners and flue gas recirculation 0.032 LB/MMBTU 3 HOURS LIMIT ONE AND TWO ARE FOR EACH BOILER

OR-0048 CARTY PLANT OR 12/29/2010 91 Low NOx burners 4.5 LB/H

*MI-0412


EAST 5TH STREET MI 12/4/2013 95

Dry low NOx burners, flue gas recirculation and

good combustion practices. 0.05 LB/MMBTU TEST PROTOCOL

Selective catalytic reduction is greater than

$11,000/ton for NOx. The efficiency range for Low

NOx burners and flue gas recirculation is 60-85

percent.

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 99 low NOx burners and flue gas recirculation 1.98 LB/H


Restricted to 2000 hours of operation per rolling 12-

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 99.8 0.05 LB/MMBTU

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 100 Low NOx burners and flue gas recirculation. 0.05 LB/MMBTU TEST PROTOCOL

Limit is 0.05 lb/MMBtu heat input for each boiler. Fuel

usage limited to not more than 416.3 MMSCF natural

gas per boiler per 12-month period.

*WV-0025

MOUNDSVILLE COMBINED CYCLE POWER

PLANT WV 11/21/2014 100

Ultra Low-NOx Burners, Flue-Gas Recirculation, &

Good Combustion Practices 2 LB/HR

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 110 9 PPMVD @3% O2, 3-HR AVG


Low NOx burners, good combustion control and

clean burning, low sulfur fuel 15.13 LB/H 3-hr Block avg

*TX-0641 PINECREST ENERGY CENTER TX 11/12/2013 150 Low NOx burners 16 PPMVD

INITIAL STACK TEST,

3% OXYGEN

OK-0115 LAWTON ENERGY COGEN FACILITY OK 12/12/2006

Dry low NOx burners, flue gas recirculation and

good combustion practices. 0.036 LB/MMBTU


August 2015



RBLC Search Results

Particulate Matter (PM/PM10/PM2.5)


Size


Emission


NY-0095 CAITHNESS BELLPORT ENERGY CENTER NY 5/10/2006 29.4 Low sulfur fuel 0.0033 LB/MMBTU

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 35 Operation restriction of 500 hr/yr 0.2 GR/100 DSCF


Use PUC quality natural gas, operational limit of

46,675 Mmbtu/yr 0.0034 GR/DSCF

USE EPA METHOD 5 & 202, OR METHOD 201A & 202,

OR USE CTM 039 IN LIEU OF METHOD 202

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 37.7 Best combustion practices 0.004 LB/MMBTU 3-hr rolling

*OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 39.8

Good combustion practices;

Utilize only natural gas. 0


*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 40 0.46 TPY 12-month rolling total


lb/MMBtu

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 55 Good combustion practices 0.0018 LB/MMBTU Test protocol Limit is for PM (filterable) based on AP-42.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREETMI 12/4/2013 55 Good combustion practices 0.007 LB/MMBTU Test protocol

Limit is for PM10/PM2.5 based on vendor data

(filterable and condensable).

*IA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 60.1 0.008 LB/MMBTU Avg 3 1-hr test runs

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7

Low sulfur/carbon fuel and good combustion

practices 0.007 LB/MMBTU

*IN-0158 ST. JOSEPH ENERGY CENTER, LLC IN 12/3/2012 80 Good combustion practices and fuel specifications 0.0075 LB/MMBTU 3 HOURS Limit is for each boiler.

OR-0048 CARTY PLANT OR 12/29/2010 91 Clean fuel 2.5 LB/MMCF good combustion practices using natural gas fuel

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREETMI 12/4/2013 95 Good combustion practices 0.0018 LB/MMBTU Test protocol Limit is for PM (filterable) based on AP-42.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREETMI 12/4/2013 95 Good combustion practices 0.007 LB/MMBTU Test protocol

Limit is for PM10/PM2.5 based on vendor data

(filterable and condensable).

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 99 Clean burning fuel, only burning natural gas 0.79 LB/H

Limit is for PM10 and PM2.5 together.


FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 99.8 2 GR/100 SCF

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 100 Efficient combustion; natural gas fuel. 0.0018 LB/MMBTU Test protocol

The limit is 0.0018 LB/MMBTU heat input for each

boiler. Test protocol will specify the averaging time.

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 100 Efficient combustion; natural gas fuel. 0.007 LB/MMBTU Test protocol

The limit is 0.007 LB/MMBTU heat input for each

boiler. Test protocol will specify averaging time.

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANT WV 11/21/2014 100 Use of Natural Gas & Good Combustion Practices 0.5 LB/HR

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 110 Use PUC quality natural gas 0.8 LB/H



clean burning, low sulfur fuel 0.82 LB/H based on 3-hour average

*TX-0641 PINECREST ENERGY CENTER TX 11/12/2013 150 pipeline quality natural gas and good combustion practices1.14 LB/H

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 8/16/2011 338

Use of pipeline quality natural gas and good

combustion practices 7.6 LB/MMSCF Annual average


August 2015



RBLC Search Results

Sulfur Dioxide (SO2)


Size


Emission


NY-0095 CAITHNES BELLPORT ENERGY CENTER NY 5/10/2006 29.4 Low sulfur fuel 0.0005 LB/MMBTU

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7 Low sulfur fuel 0.0011 LB/MMBTU

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 40 0.0021 LB/MMBTU not constructed

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 80 Fuel specification 0.0022 LB/MMBTU 3 hours Limit is for each boiler

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 33.5 Low sulfur fuel 0.03 LB/H

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 40 Low sulfur fuel 0.19 TPY 12-month rolling total

not constructed; plan approval provides an additional

limit of 0.0021 lb/MMBtu



clean burning, low sulfur fuel 0.59 LB/H 3-hour average




FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 99.8 2 GR/100 SCF


August 2015



RBLC Search Results

Volatile Organic Compounds (VOC)


Size


Emission



NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 37.7 Best combustion practices 0.005 LB/MMBTU 3-hr rolling

MN-0066

NORTHERN STATES POWER CO. DBA XCEL ENERGY

- RIVERSIDE PLANT MN 5/16/2006 160 Good combustion 0.005 LB/MMBTU 3-hr average

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7 Clean fuel and good combustion practices 0.005 LB/MMBTU

*IA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 60.1 0.005 LB/MMBTU Avg of 3 1-hr test runs

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 80 Good combustion practices 0.005 LB/MMBTU 3 hours Limit is for each boiler

*OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 39.8 Utilize Low-NOx burners and FGR. 0.005 LB/MMBTU 3-hr block average

GA-0127 PLANT MCDONOUGH COMBINED CYCLE GA 1/7/2008 200 0.0051 LB/MMBTU 3-hour

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 100 Efficient combustion; natural gas fuel. 0.008 LB/MMBTU Test protocol Limit is for each boiler

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 95 Good combustion practices 0.008 LB/MMBTU Test protocol

An oxidation catalyst is greater than $13,000/ton for

CO and VOC together.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 55 Good combustion control 0.008 LB/MMBTU Test protocol

An oxidation catalyst is greater than $12,000/ton for




lb/Mmbtu

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 33.5 Good combustion 0.54 LB/H





Good combustion practices and using

combustion optimization technologies 0.59 LB/H



months.

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANT WV 11/21/2014 100 Use of Natural Gas & Good Combustion Practices 0.6 LB/HR

*TX-0641 PINECREST ENERGY CENTER TX 11/12/2013 150 pipeline quality natural gas and good combustion 0.9 LB/H

FL-0285 PROGRESS BARTOW POWER PLANT FL 1/26/2007 99 2 GR/100 SCF Natural gas specifications

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 99.8 2 GS/100 SCF

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 8/16/2011 338

Use of pipeline quality natural gas and good

combustion practices 5.5 LB/MMSCF ANNUAL AVERAGE


August 2015



RBLC Search Results

Sulfuric Acid Mist (H2SO4)


Size


Emission


*IA-0107 MARSHALLTOWN GENERATING STATION IA 4/14/2014 60.1 0.0055 lb/hr is equivalent to 9.15 x 10-5 lb/MMBtu 0.0055 LB/HR Avg of 3 1-hr test runs


only burning natural gas 0.5 GR/100 SCF. 0.011

lb/hr is equivalent to 1.1 x 10-4 lb/MMBtu 0.011 LB/H

*OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 39.8

Good combustion practices;

Utilize only natural gas. 0


months.




lb/MMBtu

*VA-0321 BRUNSWICK COUNTY POWER STATION VA 3/12/2013 66.7

Pipeline quality natural gas and 5% oxidation of S

to H2SO4 0.0086 LB/MMBTU


August 2015


Diesel Generators and Fire Pump Engines

RBLC Search Results


RBLC ID Facility Name State Permit Date Description Size Units Control Description

Emission

Limit Units

Averaging

Period Comments

*WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 fire pump 327 hp EPA Tier 3 rated 2.6 G/HP-H limited to 250 hours of non-emergency operation per calendar year

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANT WV 11/21/2014 generator 2015.7 HP 2.6 G/HP-H

*WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 generator 839 hp EPA Tier 2 rated 2.6 G/HP-H limited to 500 hours of non-emergency operation per calendar year

MN-0071 FAIRBAULT ENERGY PARK MN 6/5/2007 generator 1750 KW 0.0055 LB/HP-H 3-hr avg EXCEPT SSM. 10 HOUR/DAY OPERATING LIMIT

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 fire pump 16 Gal/hr 0.09 TPY

12-month

rolling total

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLT PA 1/31/2013 generator 1464 HP 0.13 G/HP-H

*MI-0402 SUMPTER POWER PLANT MI 11/17/2011 generator 732 HP Good combustion practices 0.31 G/HP-H TEST Top ranking option

CA-1192 AVENAL ENERGY PROJECT CA 6/21/2011 fire pump 288 HP

Equipped with a turbocharger

and intercooler/aftercooler 0.447 G/HP-H

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLT PA 1/31/2013 fire pump 460 HP 0.5 G/HP-H

FL-0285 PROGRESS BARTOW POWER PLANT FL 1/26/2007 fire pump 300 HP 2.6 G/HP-H

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 fire pump 2.6 G/HP-H

FL-0304 CANE ISLAND POWER PARK FL 9/8/2008 fire pump 2.6 G/HP-H

FL-0304 CANE ISLAND POWER PARK FL 9/8/2008 generator 2.6 G/HP-H

THE PERMITTEE SHALL ADHERE TO THE COMPLIANCE TESTING AND

CERTIFICATION REQUIREMENTS LISTED IN 40 CFR 60.4211 AND

MAINTAIN RECORDS DEMONSTRATING USE OF ULSD FO.

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012

(2) fire

pumps 371 BHP ea

Combustion design controls

and usage limits 2.6 G/HP-H operating limit of 500 hours per year.

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 8/16/2011 fire pump 350 HP

Ultra low sulfur diesel and

good combustion practices 2.6 G/HP-H

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 fire pump 315 HP

Proper combustion design and

ultra low sulfur diesel fuel. 2.6 G/HP-H Test protocol

ultra low sulfur diesel fuel (15 pppmw); 100 hours per year operation

for maintenance and readiness testing; NSPS IIII and NESHAP ZZZZ.

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 fire pump 267 HP 2.6 G/HP-H NSPS

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 1006 HP ea


and usage limits 2.6 G/HP-H Limit is for each generator

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 2012 HP


and usage limits 2.6 G/HP-H 3 HOURS Limit is for each generator

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANT LA 8/16/2011 generator 1250 HP

Ultra low sulfur diesel and

good combustion practices 2.6 G/HP-H annual avg

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 fire pump 135 KW

Operational restriction of 50

hr/yr; operate as required for

fire safety testing 3.5 G/KW-H

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 fire pump 182 HP 3.5 G/KW-H

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 generator 2000 KW Operational restriction of 50 hr/yr 3.5 G/KW-H

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 generator 2683 HP 3.5 G/KW-H

ID-0018 LANGLEY GULCH POWER PLANT ID 6/25/2010 generator 750 KW

TIER 2 ENGINE-BASED,

GOOD COMBUSTION

PRACTICES (GCP) 3.5 G/KW-H

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 fire pump 165 HP Good combustion practices 3.7 G/HP-H Test protocol An oxidation catalyst is greater than $619,000/ton for CO and VOC.

August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 generator 7.8 MMBtu/hr 5.79 LB/H

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 generator 21 MMBtu/hr 8 G/HP-H

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 generator 2250 KW 8.5 G/HP-H

CA-1144 BLYTHE ENERGY PROJECT II CA 4/25/2007 fire pump 303 HP 0.7 LB/H Diesel fuel with sulfur concentration of 0.05% or less

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLANT WV 11/21/2014 fire pump 251 HP 1.44 LB/HR

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 fire pump 300 HP

Purchased certified to the

standards in NSPS Subpart IIII 1.7 LB/H

Additional limit: 3.5 g CO/kW-h, standard from Subpart IIII

If required Method 10.

LA-0192 CRESCENT CITY POWER LA 6/6/2005 fire pump

Good engine desing and proper

operating practices 1.88 LB/H hourly max OPERATING TIME = 52 HR/YR

LA-0224 ARSENAL HILL POWER PLANT LA 3/20/2008 fire pump 310 HP

Use of low-sulfur fuels, limiting

operating hours and proper

engine maintenance 2.07 LB/H hourly max

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 fire pump 3.25 MMBtu/hr 2.58 LB/H

NC-0101 FORSYTH ENERGY PLANT NC 9/29/2005 generator 11.4 MMBtu/hr 9.69 LB/H emergency use only


OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 generator 2200 HP 12.66 LB/H

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 generator 2250 KW



Additional limit: 3.5 g CO/KW-H, standard from Subpart IIII.

Method 10 if required.

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 generator 60 Gal/hr 0.29 TPY

12-month

rolling total

*Draft determination

August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

FL-0304 CANE ISLAND POWER PARK FL 9/8/2008 generator 560-2237 KW 4.8 G/B-HP-H




THE NMHC+NOX AND PM BACT LIMITS ARE EQUAL TO THE VALUES

CORRESPONDING TO THE SIZE CLASS INDICATED ABOVE AND CITED IN

40 CFR 60, SUBPART IIII.

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 1006 HP EACH

Combustion design controls and

usage limits 4.8 G/HP-H 3 HOURS Limit is for each generator


Combustion design controls and

usage limits 4.8 G/HP-H 3 HOURS Limit is for each generator

*MI-0402 SUMPTER POWER PLANT MI 11/17/2011 generator 732 HP Good combustion practices 4.85 G/HP-H TEST Top ranking option

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 1/31/2013 generator 1464 HP 4.93 G/B-HP-H

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 4 generators 6.9 G/B-HP-H

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 2 generators 21 MMBTU/H (2250 kW) 6.9 G/B-HP-H

FL-0285 PROGRESS BARTOW POWER PLANT FL 1/26/2007 fire pump 7.8 G/B-HP-H

NMHC+NOX (BACT FOR VOC)

NON METHANE HYDROCARBONS (NMHC) ARE SURROGATE FOR VOC

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 fire pump 7.8 G/B-HP-H

NMHC + NOX : 7.8 G/B-HP-H

NON-METHANE HYDROCARBONS (NMHC) ARE SURROGATE FOR VOC.

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 generator 2000 KW Operational restriction of 50 hr/yr 6 G/KW-H

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 generator 2683 HP 6.4 G/KW-H 3-HR AVG



GOOD COMBUSTION PRACTICES

(GCP) 6.4 G/KW-H NOX+NMHC LIMIT APPLIES TO NOX+NMHC COMBINED EMISSIONS.

AK-0071 INTERNATIONAL STATION POWER PLANT AK 3/31/2010 generator 1500 KW-e Turbocharger and Aftercooler 6.4 G/KW-H INSTANTANEOUS

Cost analysis not conducted since cost was not a factor in BACT

determination. BACT limit set to NSPS limit since limit proposed by

Chugach Electric Association was higher than NSPS.

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 1/31/2013 fire pump 460 HP 2.6 G/HP-H EXPRESSED AS NO2

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 fire pump 371 BHP ea Combustion design controls and usage limits3 G/HP-H 3 hour limit is for each fire pump engine

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREETMI 12/4/2013 fire pump 165 HP Good combustion practices 3 G/HP-H Test protocol

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 fire pump 315 hp nameplate


ultra low sulfur diesel fuel. 3 G/HP-H Test protocol

The limit is NMHC + NOx, but that pollutant is not an option in the

'Pollutant' field above.

Ultra low sulfur diesel fuel (15 ppmw); 100 hours per year operation

for maintenance and readiness testing; NSPS IIII and NESHAP ZZZZ.

August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

CA-1192 AVENAL ENERGY PROJECT CA 6/21/2011 fire pump 288 HP

Equipped with a turbocharger

and intercooler/aftercooler 3.4 G/HP-H

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 fire pump 135 KW

Operational restriction of 50

hr/yr; operate as required for

fire safety testing 3.8 G/KW-H

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 fire pump 182 HP 4 G/KW-H 3-HR AVG

ID-0018 LANGLEY GULCH POWER PLANT ID 6/25/2010 fire pump 235 KW

TIER 3 ENGINE-BASED


(GCP) 4 G/KW-H NOX+NMHC LIMIT APPLIES TO NOX+NMHC COMBINED EMISSIONS.


August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 1/31/2013 generator 1464 HP 0.02 GM/HP-H

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 1/31/2013 generator 0 0.02 GM/HP-H

FL-0304 CANE ISLAND POWER PARK FL 9/8/2008 generator 0.15 G/B-HP-H




FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 4 generators 0.4 G/B-HP-H

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 fire pump 0.4 G/B-HP-H

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 2 2,250 kW generators21 MMBTU/H 0.4 G/B-HP-H

AK-0073 INTERNATIONAL STATION POWER PLANT AK 12/20/2010 generator 1500 kW-e Turbocharging and aftercooling 0.03 G/HP-H

AK-0071 INTERNATIONAL STATION POWER PLANT AK 3/31/2010 generator 1500 KW-e Good Combustion Practices 0.03 G/HP-H instantaneous

Cost analysis not conducted since cost was not a factor in BACT

determination.

*MI-0402 SUMPTER POWER PLANT MI 11/17/2011 generator 732 HP Good combustion practices 0.05 G/HP-H testing Top ranking option

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLTPA 1/31/2013 fire pump 460 HP 0.09 G/HP-H

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 fire pumps 371 BHP, EACH Combustion design controls and usage limits0.15 G/HP-H LIMIT TWO IS FOR EACH FIREWATER PUMP ENGINES

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 generators 1006 HP EACH Combustion design controls and usage limits0.15 G/HP-H 3 hours LIMIT ONE AND TWO ARE FOR EACH GENERATOR

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 2012 HP Combustion design controls and usage limits0.15 G/HP-H 3 hours LIMIT ONE AND TWO ARE FOR EACH GENERATOR

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 fire pumps 371 BHP, EACH Combustion design controls and usage limits0.15 G/HP-H 3 hours LIMIT TWO IS FOR EACH FIREWATER PUMP ENGINE

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 generators 1006 HP EACH Combustion design controls and usage limits0.15 G/HP-H 3 hours LIMIT ONE AND TWO ARE FOR EACH GENERATOR


*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 fire pumps 371 BHP, EACH Combustion design controls and usage limits0.15 G/HP-H LIMIT TWO IS FOR EACH FIREWATER PUMP ENGINE

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 2 generators 1006 HP EACH Combustion design controls and usage limits0.15 G/HP-H LIMIT ONE AND TWO ARE FOR EACH GENERATOR


LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 8/16/2011 fire pump 350 HP ultra low sulfur diesel and good combustion practices0.15 G/HP-H annual avg

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 8/16/2011 generator 1250 HP ultra low sulfur diesel and good combustion practices0.15 G/HP-H annual avg

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 8/16/2011 fire pump 350 HP ultra low sulfur diesel and good combustion practices0.15 G/HP-H annual avg

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLANTLA 8/16/2011 generator 1250 HP ultra low sulfur diesel and good combustion practices0.15 G/HP-H annual avg

*VA-0319 GATEWAY COGENERATION 1, LLC - SMART WATER PROJECTVA 8/27/2012 fire pump 1.86 MMBTU/H Clean burning ULSD fuel and good combusion practices0.15 G/HP-H

*VA-0319 GATEWAY COGENERATION 1, LLC - SMART WATER PROJECTVA 8/27/2012 fire pump 1.86 MMBTU/H Clean burning ULSD fuel and good combustion practices.0.15 G/HP-H

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 fire pump 315 hp nameplateProper combustion design and ultra low sulfur diesel fuel.0.15 G/HP-H test protocol

ultra low sulfur diesel fuel (15 pppmw); 100 hours per year operation

for maintenance and readiness testing; NSPS IIII and NESHAP ZZZZ

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH STREETMI 12/4/2013 fire pump 165 HP Good combustion practices 0.22 G/HP-H test protocol

ID-0018 LANGLEY GULCH POWER PLANT ID 6/25/2010 FIRE PUMP ENGINE 235 KW



(GCP) 0.2 G/KW-H

ID-0018 LANGLEY GULCH POWER PLANT ID 6/25/2010 EMERGENCY GENERATOR ENGINE750 KW


GOOD COMBUSTION PRACTICES 0.2 G/KW-H

CA-1212 PALMDALE HYBRID POWER PROJECT CA 10/18/2011 EMERGENCY IC ENGINE182 HP USE ULTRA LOW SULFUR FUEL 0.2 G/KW-H


August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 EMERGENCY FIREWATER PUMP ENGINE135 KW OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE AS REQUIRED FOR FIRE SAFETY TESTING0.2 G/KW-H


CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 EMERGENCY ENGINE2000 KW OPERATIONAL RESTRICTION OF 50 HR/YR; USE OF ULTRA LOW SULFUR FUEL NOT TO EXCEED 15 PPMVD0.2 G/KW-H


CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 EMERGENCY FIREWATER PUMP ENGINE135 KW OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE AS REQUIRED FOR FIRE SAFETY TESTING0.2 G/KW-H


CA-1191 VICTORVILLE 2 HYBRID POWER PROJECT CA 3/11/2010 EMERGENCY ENGINE2000 KW OPERATIONAL RESTRICTION OF 50 HR/YR; USE OF ULTRA LOW SULFUR FUEL NOT TO EXCEED 15 PPMVD FUEL SULFUR0.2 G/KW-H



August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PA 1/31/2013 fire pump 460 HP ultra-low sulfur diesel fuel 0.005 G/HP-H EXPRESSED AS SO2

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PA 1/31/2013 generator 1464 HP ultra-low sulfur diesel fuel 0.005 G/HP-H EXPRESSED AS SO2

FL-0304 CANE ISLAND POWER PARK FL 9/8/2008 generator 560-2237 KW ultra-low sulfur diesel fuel 0.0015 % S by weight

THIS UNIT SHALL FIRE ULSD FO (OR SUPERIOR FUEL), WHICH SHALL

CONTAIN NO MORE THAN 0.0015% SULFUR BY WEIGHT. THE

PERMITTEE SHALL MAINTAIN A PERMANENT FILE OF THE CERTIFIED

FUEL SULFUR ANALYSIS FROM THE FUEL VENDOR.

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 generators 2250 kW ultra-low sulfur diesel fuel 0.0015 % S

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 fire pump 371 HP ultra-low sulfur diesel fuel 0.0015 % S

LIMIT ONE AND TWO ARE FOR EACH FIREWATER PUMP ENGINE.

LIMIT THREE: EACH FIRE PUMP SHALL NOT EXCEED 500 HOURS OF

OPERATION PER YEAR.

LA-0192 CRESCENT CITY POWER LA 6/6/2005 fire pump 425 HP

good engine design and proper

operating practices 0.61 LB/H hourly max OPERATING TIME = 52 HR/YR

LA-0224 ARSENAL HILL POWER PLANT LA 3/20/2008 fire pump 310 HP low-sulfur fuel, limit operating hours 0.64 LB/H max

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 fire pump 300 HP 0.003 LB/H Method 6C if required

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 fire pump 267 HP low sulfur diesel 0.11 LB/H

*WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 fire pump 327 hp ultra-low sulfur diesel fuel 0 limited to 250 hours of non-emergency operation per calendar year

NC-0101 FORSYTH ENERGY PLANT NC 8/31/2004 generator 11.4 MMBTU/H 0.58 LB/H emergency use only

NC-0101 FORSYTH ENERGY PLANT NC 8/31/2004 fire pump 11.4 MMBTU/H 0.58 LB/H emergency use only

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 1006 HP EACH ultra-low sulfur diesel fuel 0.012 LB/H LIMIT ONE AND TWO ARE FOR EACH GENERATOR

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 2012 HP ultra-low sulfur diesel fuel 0.024 LB/H 3-hours LIMIT ONE AND TWO ARE FOR EACH GENERATOR

MN-0071 FAIRBAULT ENERGY PARK MN 6/5/2007 generator 1750 KW 0.0004 LB/HP-H 3-hr avg INCLUDING SSM. 10 HOUR/DAY OPERATING LIMIT

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 generator 2250 KW 0.03 LB/H Method 6C if required

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 generator 2200 HP low sulfur diesel 0.89 LB/H

WA-0328 BP CHERRY POINT COGENERATION PROJECT WA 1/11/2005 generator 1.5 MW on-road diesel fuel specs 0 * SEE NOTES -SEE CONTROL METHOD DESCRIPTION FOR SO2 ABOVE

*WY-0070 CHEYENNE PRAIRIE GENERATING STATION WY 8/28/2012 generator 839 hp ultra-low sulfur diesel fuel 0 limited to 500 hours of non-emergency operation per calendar year


August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 generator 60 Gal/hr 0.03 TPY

12 month

rolling total

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PA 1/31/2013 generator 1464 HP 0.01 GM/HP-H THC




(GCP) 6.4 G/KW-H NOX+NMHC

LIMIT APPLIES TO NOX+NMHC COMBINED

EMISSIONS.

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 generator 1006 HP EACH

COMBUSTION DESIGN CONTROLS

AND USAGE LIMITS 1.04 LB/H LIMIT ONE AND TWO ARE FOR EACH GENERATOR



AND USAGE LIMITS 1.04 LB/H 3 HOURS LIMIT ONE AND TWO ARE FOR EACH GENERATOR

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLT LA 8/16/2011 generator 1250 HP

ULTRA LOW SULFUR DIESEL AND

GOOD COMBUSTION PRACTICES 1 G/HP-H Annual avg

MN-0071 FAIRBAULT ENERGY PARK MN 6/5/2007 generator 1750 KW 0.317 g/hp-hr 0.0007 LB/HP-H 3-hr avg EXCEPT SSM. 10 HOUR/DAY OPERATING LIMIT

*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 generator 2250 KW



Additional limit: 0.79 g VOC/kW-h; and 6.4 g

NMHC + NOx/kW-h Subpart IIII standard.

Method 25A if required

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 generator 2200 HP GOOD COMBUSTION 1.55 LB/H

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 generator 7.8 MMBtu/hr 0.7 LB/H

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLT WV 11/21/2014 generator 2015.7 HP 1.24 LB/HR


NC-0101 FORSYTH ENERGY PLANT NC 8/31/2004 fire pump 11.4 MMBtu/hr 1.04 LB/H emergency use only

ID-0018 LANGLEY GULCH POWER PLANT ID 6/25/2010 fire pump 235 KW



(GCP) 4 G/KW-H NOX+NMHC

LIMIT APPLIES TO NOX+NMHC COMBINED

EMISSIONS.

*IN-0158 ST. JOSEPH ENEGRY CENTER, LLC IN 12/3/2012 fire pump 371 HP, ea


AND USAGE LIMITS 0.16 LB/H

LIMIT ONE AND TWO ARE FOR EACH FIREWATER

PUMP ENGINE

LA-0192 CRESCENT CITY POWER LA 6/6/2005 fire pump

GOOD ENGINE DESIGN AND

PROPER OPERATING PRACTICES 0.05 LB/H hourly max OPERATING TIME = 52 HR/YR

LA-0224 ARSENAL HILL POWER PLANT LA 3/20/2008 fire pump 310 HP

USE OF LOW-SULFUR FUELS,

LIMITING OPERATING HOURS AND

PROPER ENGINE MAINTENANCE 0.77 LB/H MAX

LA-0254 NINEMILE POINT ELECTRIC GENERATING PLT LA 8/16/2011 fire pump 350 HP

ULTRA LOW SULFUR DIESEL AND

GOOD COMBUSTION PRACTICES 1 G/HP-H Annual avg

August 2015



RBLC Search Results



Emission

Limit Units

Averaging

Period Comments

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 fire pump 315 HP


ultra low sulfur diesel fuel. 0

Ultra low sulfur diesel fuel (15 pppmw); 100 hours

per year operation for maintenance and readiness

testing. Both CO and VOC are products of

incomplete combustion and are controlled using

efficient combustion methods. The limitation on

CO is an appropriate surrogate for VOC emissions.

VOC also included in NMHC which is limited in

combination with NOx.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH ST MI 12/4/2013 fire pump 165 HP Good combustion practices 0.001 LB/H Test protocol

An oxidation catalyst is greater than $619,000 for


*OH-0352 OREGON CLEAN ENERGY CENTER OH 6/18/2013 fire pump 300 HP



Additional limit: 0.50 g VOC/kW-h; and 4.0 g

NMHC + NOx/kW-h Subpart IIII standard.

Method 25A if required

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 fire pump 267 HP GOOD COMBUSTION 0.66 LB/H

*PA-0286 MOXIE ENERGY LLC/PATRIOT GENERATION PLT PA 1/31/2013 fire pump 460 HP 0.1 G/HP-H

*PA-0291 HICKORY RUN ENERGY STATION PA 4/23/2013 fire pump 3.25 MMBtu/hr 1.11 LB/H

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 fire pump 16 Gal/hr 0.013 TPY

12 month

rolling total

*WV-0025 MOUNDSVILLE COMBINED CYCLE POWER PLT WV 11/21/2014 fire pump 251 HP 0.17 LB/HR


August 2015


Heater - Natural Gas

RBLC Search Results



Size


Emission


*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 8.5 4996.3 TPY

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion; energy efficiency. 6156 T/YR 12-month rolling

The CO2e limit is 6,156 T/YR based on a 12-month rolling time

period as determined at the end of each calendar month for

EACH heater.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 1934 T/YR 12-month rolling

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion 0.11 LB/MMBTU test protocol The CO limit is 0.11 LB/MMBTU heat input for EACH heater.

OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 18.8 0.39 LB/H

LA-0192 CRESCENT CITY POWER LA 6/6/2005 19 Good combustion practices 1.52 LB/H hourly average

*TPY LIMIT FOR ALL 3 HEATERS. AGGREGATE HEAT INPUT IS

LIMITED TO 14,250 MM BTU/YR. ONLY 2 OF THE 3 HEATERS ARE

ALLOWED TO OPERATE AT ANY GIVEN TIME.

*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 8.5 0.05 LBS/MMBTU

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 Good combustion practices 0.03 LB/MMBTU 3-hour rolling

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 0.41 LB/H test protocol


together.

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 10 0.08 LB/MMBTU

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 10 Good combustion practices 0.08 LB/MMBTU

EACH UNIT SHALL BE STACK TESTED TO DEMONSTRATE INITIAL

COMPLIANCE WITH THE EMISSION STANDARDS FOR CO, NOX

AND VISIBLE EMISSIONS. THE TESTS SHALL BE CONDUCTED

WITHIN 60 DAYS AFTER ACHIEVING THE MAXIMUM PRODUCTION

RATE AT WHICH THE UNIT WILL BE OPERATED, BUT NOT LATER

CA-1211 COLUSA GENERATING STATION CA 3/11/2011 10 100 PPMVD @3% O2, 3-HR AVG


August 2015



RBLC Search Results



Size


Emission


*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Low NOx burners 0.06 LB/MMBTU 30 day rolling avg

The NOx limit is 0.06 LB/MMBTU heat input based on a 30-day

rolling average as determined each day in operation for EACH

heater.


LA-0192 CRESCENT CITY POWER LA 6/6/2005 19

Low Nox burners and good combustion

practices 1.81 LB/H hourly maximum




*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 8.5 0.035 LB/MMBTU

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 Good combustion practices 0.14 LB/MMBTU 3-hr rolling

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 0.55 LB/H test protocol Low NOx burners are greater than $23,000/ton for NOx.

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 10 0.095 LB/MMBTU

FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 10 Good combustion practices 0.095 LB/MMBTU

EACH UNIT SHALL BE STACK TESTED TO DEMONSTRATE INITIAL

COMPLIANCE WITH THE EMISSION STANDARDS FOR CO, NOX

AND VISIBLE EMISSIONS. THE TESTS SHALL BE CONDUCTED

WITHIN 60 DAYS AFTER ACHIEVING THE MAXIMUM PRODUCTION

RATE AT WHICH THE UNIT WILL BE OPERATED, BUT NOT LATER

THAN 180 DAYS AFTER THE INITIAL STARTUP OF THE COMBINED

CYCLE UNIT. AS AN ALTERNATIVE, A MANUFACTURER

CERTIFICATION OF EMISSIONS CHARACTERISTICS OF THE

PURCHASED MODEL THAT ARE AT LEAST AS STRINGENT AS THE

BACT VALUES CAN BE USED TO FULFILL THIS REQUIREMENT.



August 2015



RBLC Search Results



Size


Emission


FL-0303 FPL WEST COUNTY ENERGY CENTER UNIT 3 FL 7/30/2008 10 2 GS/100 SCF


USE OF LOW SULFUR PIPELINE NATURAL

GAS AND GOOD COMBUSTION

PRACTICES 0.14 LB/H hourly maximum




*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 8.5 0.007 LB/MMBTU

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 best combustion practices 0.02 LB/MMBTU 3-hour rolling

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 best combustion practices 0.02 LB/MMBTU 3-hour rolling

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 10 2 GR S/100 SCF

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion; natural gas fuel. 0.0018 LB/MMBTU test protocol The PM limit is 0.0018 LB/MMBTU heat input for EACH heater.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 0.007 LB/MMBTU test protocol

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion; natural gas fuel. 0.007 LB/MMBTU test protocol The PM10 limit is 0.007 LB/MMBTU heat input for EACH heater.


*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 0.0075 LB/MMBTU test protocol

CA-1211 COLUSA GENERATING STATION CA 3/11/2011 10 0.029 LB/H

*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion; natural gas fuel. 0.007 LB/MMBTU test protocol The PM2.5 limit is 0.007 LB/MMBTU heat input for EACH heater.

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion pracitces. 0.0075 LB/MMBTU test protocol

CA-1211 COLUSA GENERATING STATION CA 3/11/2011 10 0.029 LB/H


August 2015



RBLC Search Results



Size


Emission


OK-0129 CHOUTEAU POWER PLANT OK 1/23/2009 18.8 low sulfur fuel 0.01 LB/H


USE OF LOW SULFUR PIPELINE NATURAL

GAS AND GOOD COMBUSTION

PRACTICES 0.008 LB/H hourly maximum





FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 10 2 GS/100 SCF


VOC, SO2, PM/PM10

2 GR S/100SCF NATURAL GAS SPEC AND 10% OPACITY


August 2015



RBLC Search Results



Size


Emission


*MI-0410 THETFORD GENERATING STATION MI 7/25/2013 12 Efficient combustion; natural gas fuel. 0.008 LB/MMBTU test protocol The VOC limit is 0.008 LB/MMBTU heat input for EACH heater.


LA-0192 CRESCENT CITY POWER LA 6/6/2005 19 good combustion practices 0.1 LB/H hourly maximum





NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 best combustion practices 0.08 LB/MMBTU 3-hr average

NV-0035 TRACY SUBSTATION EXPANSION PROJECT NV 8/16/2005 4 best combustion practices 0.08 LB/MMBTU 3-hr rolling

*MI-0412 HOLLAND BOARD OF PUBLIC WORKS - E 5TH ST MI 12/4/2013 3.7 Good combustion practices 0.03 LB/H test protocol


together.

FL-0286 FPL WEST COUNTY ENERGY CENTER FL 1/10/2007 10 2 GR S/100 SCF


VOC, SO2, PM/PM10

2 GR S/100SCF NATURAL GAS SPEC AND 10% OPACITY



August 2015



RBLC Search Results

Sulfuric Acid Mist (H2SO4)


Size


Emission


*PA-0296 BERKS HOLLOW ENERGY ASSOC LLC PA 12/17/2013 8.5 0.001 lb/MMBtu


August 2015

Renovo Energy CenterRBLC Search Results for ULSD Storage TanksVolatile Organic Compounds (VOC)

August 2015 Page 1 of 1

RBLC ID Facility Name StatePermit Date Process Name/Description Basis

Fuel Type(s) Control Description

Emission Limit Comments


FL 1/26/2007Two nominal 3,500,000 gallon ULSD storage tanks

BACT-PSD ULSD --Facility must keep records documenting that the true vapor pressure of the liquid stored is less than 3.5 kPa.


FL 1/10/2007Two nominal 6,300,000 gallon ULSD storage tanks

BACT-PSD ULSD --Facility must keep records documenting that the true vapor pressure of the liquid stored is less than 3.5 kPa.

*FL-0346 LAUDERDALE PLANT FL 4/22/2014Three ULSD storage tanks: 3,360,000 gallons; 6,300,000 gallons; and 3,150,000 gallons

BACT-PSD ULSDpressure relief vales/vapor condensors or internal floating roof tank

--


OR 3/5/2014One 2,200,000 gallon fixed roof ULSD storage tank

BACT-PSD ULSD submerged fill line --

Attachment F

HP Steam

Natural 17,600 lb/hr

GasHot Reheat Steam

119,330 lb/hr

ULSD 0 lb/hr Cold Reheat Steam

(backup)

Water LP Steam

(backup) 5,079,800 lb/hr

200 F

StackExhaust(CEMS)

Air

Cooled

Condenser MakeupAir Water

Duct

Burner

(gas

only)

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 51oF ambient temperature. Rev Sheet # of

A 1 2

Date

June 17, 2015

Steam Turbine

Gas Turbine

Heat Recovery

Steam Generator


Cycle Schematic

Water

Electricity

Electricity

SCR &

CO

Catalyst

Inlet Air Cooler

Siemens SGT6-8000H (Natural Gas Operation)

HP Steam

Natural 0 lb/hr

GasHot Reheat Steam

0 lb/hr

ULSD 125,100 lb/hr Cold Reheat Steam

(backup)

Water LP Steam


240 F

StackExhaust(CEMS)

Air

Cooled


Duct

Burner

(gas

only)

Ammonia Injection






A 2 2June 17, 2015

Heat Recovery

Steam GeneratorWater


Cycle Schematic

Siemens SGT6-8000H (ULSD Operation)

Date

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

HP Steam


GasHot Reheat Steam

126,070 lb/hr


(backup)

Water LP Steam

(backup)4,954,720 lb/hr

172 F

StackExhaust(CEMS)

Air

Cooled


Duct

Burner

(gas

only)

Ammonia Injection






A 1 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

June 17, 2015

Heat Recovery



Cycle Schematic

MHPSA 501J (Natural Gas Operation)

Date

HP Steam

Natural 0 lb/hr

GasHot Reheat Steam

0 lb/hr


(backup)

Water LP Steam

(backup)3,656,290 lb/hr

202 F

StackExhaust(CEMS)

Air

Cooled


Duct

Burner

(gas

only)

Ammonia Injection






A 2 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

June 17, 2015

Heat Recovery



Cycle Schematic

MHPSA 501J (ULSD Operation)

Date

HP Steam


GasHot Reheat Steam


(backup)

Water LP Steam


191 F

StackExhaust(CEMS)

Air

Cooled


Ammonia Injection






A 1 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

June 17, 2015

Heat Recovery



Cycle Schematic

GE 7HA.02 (Natural Gas Operation)

Date

HP Steam

Natural 0 lb/hr

GasHot Reheat Steam


(backup)

Water LP Steam


209F

StackExhaust(CEMS)

Air

Cooled


Ammonia Injection






A 2 2

Inlet Air Cooler

Steam Turbine

Electricity

Electricity

Gas Turbine

SCR &

CO

Catalyst

June 17, 2015

Heat Recovery



Cycle Schematic

GE 7HA.02 (ULSD Operation)

Date

Attachment G

12345678

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

XXXXXXX

XXXXXXX

XXXXXXX

XXXXXXX

PRELIMINARY

FLOW DIAGRAM

YY-MM-DD

YY-MM-DD

YY-MM-DD

YY-MM-DD

YY-MM-DD

NONE

14-04-17

TYPICAL HRSG SCR SYSTEM

08-11-25

AY

YY

EZ

ZZ

Z

XXXA

XXX

E. B.

14/04/17

Attachment H

Cost Analysis for a CO Oxidation Catalyst on the Auxiliary Boilers

Oxidation Catalyst - CO

Equipment Costsoxidation catalyst $5,000frame and housing $15,000total system (A) $20,000freight (0.05A) $1,000 Page 2-27 Control Cost Manualtaxes (0.05A) $1,000

$22,000

Direct Installation Costs direct installation cost factors provided by Control Cost Manual for thermal and Foundations and supports (0.08B) $1,760 catalytic incinerators and carbon adsorbers.Handling and Erection (0.14B) $3,080Electrical (0.01B) $220

$5,060

Total direct cost: $27,060

standard factors for most control equipment contained in Control Cost ManualEngineering and Supervision (0.10B) $2,200Construction and Field Expenses (0.05B) $1,100Contractor fees (0.10B) $2,200Startup (0.02B) $440Performance Test (0.01B) $220Contingencies (0.03B) $660

Total indirect cost: $6,820

Total Capital investment (TCI): $33,880

Operating Labor ---Supervisory Labor ---Maint. Labor and Materials 2,250 $45/hr; 50 hr/yr

Total purchased equipment cost (B):

Total direct installation cost:

Indirect Costs (installation)

Direct Annual Cost

Cost Analysis for a CO Oxidation Catalyst on the Auxiliary Boilers

Catalyst replacement (3 year life, 2% interest) 1,734 1734

Spent catalyst handling ----

performance loss 636 0.0671$/kWhrTotal direct annual cost: 4,620

Overhead (60% total labor and materials) 1,350 Page 2-34 Control Cost ManualAdministrative charges (0.02 TCI) 678 Page 2-34 Control Cost ManualInsurance (0.01 TCI) 339 Page 2-34 Control Cost Manual

Capital recovery (10 year at 2% interest) 3,215(TCI - 5,000 = 50,090)(50,090*0.11133)

Total indirect annual cost: 5,582

Total Annual Costs 10,201

CO emissions removed (tons/year) 0.98Cost effectiveness (dollars/ton CO removed) 10,463

CO emission reduction is from 0.036 lb/MMBtu to 0.010 lb/MMBtuwhich is equivalent to 1.35 tpy to 0.375 tpy.

0.036-0.010/0.036*100 = 72%

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. 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 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 VOC Oxidation Catalyston the Auxiliary Boilers

Oxidation Catalyst - VOC

Equipment Costsoxidation catalyst $5,000frame and housing $15,000total system (A) $20,000freight (0.05A) $1,000 Page 2-27 Control Cost Manualtaxes (0.05A) $1,000

$22,000

Direct Installation Costs direct installation cost factors provided by Control Cost Manual for thermal and Foundations and supports (0.08B) $1,760 catalytic incinerators and carbon adsorbers.Handling and Erection (0.14B) $3,080Electrical (0.01B) $220

$5,060

Total direct cost: $27,060

standard factors for most control equipment contained in Control Cost ManualEngineering and Supervision (0.10B) $2,200Construction and Field Expenses (0.05B) $1,100Contractor fees (0.10B) $2,200Startup (0.02B) $440Performance Test (0.01B) $220Contingencies (0.03B) $660


Total Capital investment (TCI): $33,880

Operating Labor ---Supervisory Labor ---




Direct Annual Cost

Cost Analysis for a VOC Oxidation Catalyston the Auxiliary Boilers

Maint. Labor and Materials 2,250 $45/hr; 50 hr/yr


Spent catalyst handling ----

performance loss 636 0.0671$/kWhrTotal direct annual cost: 4,620

Overhead (60% total labor and materials) 1,350 Page 2-34 Control Cost ManualAdministrative charges (0.02 TCI) 678 Page 2-34 Control Cost ManualInsurance (0.01 TCI) 339 Page 2-34 Control Cost Manual

Capital recovery (10 year at 2% interest) 3,215(TCI - 5,000 = 50,090)(50,090*0.11133)



VOC emissions removed (tons/year) 0.09Cost effectiveness (dollars/ton VOC removed) 108,815

VOC emission reduction is from 0.036 lb/MMBtu to 0.010 lb/MMBtuwhich is equivalent to 1.35 tpy to 0.375 tpy.

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.


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%)

Average Cost Effectiveness

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%) = 0.3468Spent 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.

Cost Analysis for SCR/Oxidation Catalyston Combustion Turbines

SCR and Oxidation Catalyst - NOx, CO, VOC

Equipment CostsSCR/OxCat Unit $1,250,000frame and housing $15,000total system (A) $1,265,000freight (0.05A) $63,250 Page 2-27 Control Cost Manualtaxes (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.Handling and Erection (0.14B) $194,810Electrical (0.01B) $13,915

$320,045

Total direct cost: $1,711,545

standard factors for most control equipment contained in Control Cost ManualEngineering and Supervision (0.10B) $139,150Construction and Field Expenses (0.05B) $69,575Contractor fees (0.10B) $139,150Startup (0.02B) $27,830Performance Test (0.01B) $13,915Contingencies (0.03B) $41,745


Total Capital investment (TCI): $2,142,910

Operating Labor ---Supervisory Labor ---Maint. Labor and Materials 27,000 $45/hr; 600 hr/yr




Direct Annual Cost

Cost Analysis for SCR/Oxidation Catalyston Combustion Turbines


Spent catalyst handling ----performance loss not accounted for

Total direct annual cost: 459,500

Overhead (60% total labor and materials) 16,200 Page 2-34 Control Cost ManualAdministrative charges (0.02 TCI) 42,858 Page 2-34 Control Cost ManualInsurance (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%)


Attachment I

Attachment I

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 3.8 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

Tanks identified above are not subject to 129.56 and 129.57 because the vapor pressures do not exceed 1.5 psia.

Tanks associated with the two emergency generators and fire pump engine are not included because they are less than 2,000 gallons each.

material

stored capacity (gal)

throughput

per year (gal)

Project will also include two 15,000 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.

Attachment J



PHONE

FAX

207-869-1200 207-869-1299

FRE 164-305 137575 (08/05/2015) CD

August 5, 2015 Clinton County Commissioners Clinton County Government 232 East Main Street Lock Haven, PA 07745 Subject: Renovo Energy Center, LLC Plan Approval Application 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 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 identical 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 combustion turbine (CT), which is intended to be fired on natural gas unless there is an interruption in supply, and a heat recovery steam generator (HRSG). The steam from the HRSGs is routed through the condensing steam turbine generator. REC is requesting a plan approval that will allow three optional plant configurations, each having a different original equipment manufacturer (OEM). The three OEM configuration options being considered are the General Electric (GE) 7HA.02, Siemens SGT6-8000H, and Mitsubishi Hitachi Power Systems America, Inc. (MHPSA) M501J units. Due to pricing, performance, design considerations, and delivery schedule, a final decision on the preferred OEM will be made after a plan approval has been issued, thus the application is structured to reflect the three different options. REC will submit a written request to the DEP to withdraw two of the three two options prior to the start of construction. With the exception of the General Electric option, each HRSG has a gas fired duct burner (DB) for supplemental firing. 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, two emergency generators, 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.

August 5, 2015 Page 2

FRE 164-305 137575 (08/05/2015) CD POWER ENGINEERS, INC.

PAGE 2 OF 2

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 Williamsport, PA 17701-6448 (570) 327-3637 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 Senior Project Manager Enclosure(s): Correspondence letter to DEP c: Rick Franzese, Bechtel Development Company Bill Bousquet, Innovative Power Solutions, LLC DMS 137575/PER-02-02-09



PHONE

FAX

207-869-1200 207-869-1299

FRE 164-306 137575 (08/05/2015) CD

August 5, 2015 Renovo Borough 140 3rd Street, Apt 11 Renovo, PA 17764 Subject: Renovo Energy Center, LLC Plan Approval Application 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 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 identical 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 combustion turbine (CT), which is intended to be fired on natural gas unless there is an interruption in supply, and a heat recovery steam generator (HRSG). The steam from the HRSGs is routed through the condensing steam turbine generator. REC is requesting a plan approval that will allow three optional plant configurations, each having a different original equipment manufacturer (OEM). The three OEM configuration options being considered are the General Electric (GE) 7HA.02, Siemens SGT6-8000H, and Mitsubishi Hitachi Power Systems America, Inc. (MHPSA) M501J units. Due to pricing, performance, design considerations, and delivery schedule, a final decision on the preferred OEM will be made after a plan approval has been issued, thus the application is structured to reflect the three different options. REC will submit a written request to the DEP to withdraw two of the three two options prior to the start of construction. With the exception of the General Electric option, each HRSG has a gas fired duct burner (DB) for supplemental firing. 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, two emergency generators, 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.

August 5, 2015 Page 2

FRE 164-306 137575 (08/05/2015) CD POWER ENGINEERS, INC.

PAGE 2 OF 2

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 Williamsport, PA 17701-6448 (570) 327-3637 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 Senior Project Manager Enclosure(s): Correspondence letter to DEP c: Rick Franzese, Bechtel Development Company Bill Bousquet, Innovative Power Solutions, LLC DMS 137575/PER-02-02-09

Attachment K

July 2015 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), PM-10, and 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 new source review (NSR) 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.depweb.state.pa.us, select Air, Bureau of Air Quality, Permits, Emission Reduction Credits.

Facility information Criteria

Pollutant Certified

ERCs Available

(tpy)

Expiration date

Intended use of ERCs

R. R. Donnelley & Sons Co. County: Lancaster Contact Person: Frederick Shaak, Jr. Telephone Number: (717)-293-3750

VOCs VOCs VOCs VOCs

16.00 7.80 10.50 7.62

11/30/2015 12/31/2015 3/27/2017

Internal Trading Trading

PPG Industries, Inc. Source Location: Springdale Complex County: Allegheny Contact Person: Joe Frank Telephone Number: (412) 274-3884

VOCs 171.82 Trading

http://www.depweb.state.pa.us/

July 2015 Page 2

Facility information Criteria Pollutant

Certified ERCs

Available (tpy)

Expiration date


The Procter & Gamble Paper Products Company Source Location: Mehoopany Plant County: Wyoming Contact Person: Amy Jacoby Telephone Number: (570) 833-6396

NOx

91.10

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

Trading

Sun Company, Inc. Source: Wastewater Conveyance System Source Location: Marcus Hook Borough County: Delaware Contact Person: Steve Martini Telephone Number: (610) 859-1000

VOCs 147.93 Trading/ Internal Use

World Kitchen Inc. Source Location: Charleroi Plant County: Washington Contact Person: Tony Pane Telephone Number: (724) 489-2255

NOx 131.43 Trading

Cabinet Industries, Inc.

Source Location: Danville Borough

County: Montour

Contact Person: Laura Lee Spatzer

Telephone Number: (570) 275-1400, Ext 1400

VOCs 7.29

9/01/2015 Trading

Arbill Industries, Inc

Source Location: 2207 West Glenwood Avenue

County: Philadelphia

Contact Person: Barry Bickman

Telephone Number: (800) 523-5367

(215) 225-1482

VOCs

NOx

SOx

2.32

0.38

0.21

1/01/2016 Trading

Carmeuse Lime, Inc

Source Location: Hanover Lime Plant

County: Adams

Contact Person: Kenneth Kauffman


NOx

VOCs

SOx

PM-10

PM-2.5

46.61

1.96

10.26

14.64

7.18

1/03/2016 Trading

Morgan Adhesives Company (MACtac) Source Location: Scranton County: Lackawanna Contact Person: Cara Glaser Telephone Number: (570) 963-5352

VOCs 5.16 10/29/2019 Trading

July 2015 Page 3


Certified ERCs

Available (tpy)

Expiration date


Cinram Manufacturing LLC

Source location: City of Olyphant

County: Lackawanna

Contact Person: Mark A. Thallmayer


VOCs

VOCs

6.53

6.75

2/06/2016

5/09/2016

Internal use

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


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

Fleetwood Industries Source Location: St Lawrence Plant County: Berks Contact Person: Robert Mervine Telephone Number: (610) 779-7700

VOCs 24.50 7/31/2015 Internal

use/Trade

Sunoco Inc. (R&M) Source Location: 200 Neville Road, Pittsburgh, PA

15225 County: Allegheny Contact Person: Gary P. Rabik Telephone Number: (610) 859-3435

VOCs

25.16

4/01/2017. Trading

/Internal

use

Philadelphia Baking Company Source Location: 2550 Grant Avenue County: Philadelphia Contact Person: Brent Williams Telephone Number: 410-266-0006

NOx VOCs PM-10 SOx

CO

4.09

24.20 0.10 0.02 1.33

4.09 24.20

0.10 0.02

1.33

9/21/2017 Trading

Lindy Paving, Inc Source Location: 200 Neville Island Facility County: Allegheny Contact Person: Paul J. Reiner, Jr Telephone Number: 412-281-4389

NOx VOCs PM-10 PM-2.5 SOx CO

6.85 9.10 5.71 1.77 0.66

18.78

10/27/2017 Trading / Internal use

July 2015 Page 4


Certified ERCs

Available (tpy)

Expiration date


CNH America LLC Source Location: Belleville Plant, Union Township County: Mifflin Contact Person: Audrey Van Dyke Telephone Number: (262)636-6073

VOCs 39.11 8/01/2018 Trading

Foamex, L.P. Source Location: 1500 East 2

nd Street, Eddystone

County: Delaware Contact Person: John F. McLaverty Telephone Number: (610) 245-2765

NOx VOCs SOx CO

7.67 84.25 1.03 26.93

12/31/2018 Trading

Norcross Safety Products Source Location: US RT 1 at Brinton Lake Rd,

Concordville County: Delaware Contact Person: Anthony Ricci Telephone Number: 401-275-2432

VOCs

7.62

3/27/2017 Trading

NRG REMA, LLC Source Location: Titus Station, Cumru Township County: Berks Contact Person: Brian W. Green Telephone Number: (724) 597-8219

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 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 Trading

The Hershey Company Source Location: Derry Township Plant County: Dauphin Contact Person: Charles Stoner Jr. Telephone Number: (717)-534-4692

VOCs NOx PM-10 PM-2.5 CO

37.00 4.00 44.50 8.00 4.90

7/01/2018 Trading

The Hershey Company Source Location: Reading Plant County: Berks Contact Person: Charles Stoner Jr. Telephone Number: (717)-534-4692

VOCs PM-10 PM-2.5

5.36 24.63

4.00

5/01/2019 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

Trading/ Internal Use

July 2015 Page 5


Certified ERCs

Available (tpy)

Expiration date


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


Texas Eastern Transmission, L.P.

Source Location: Holbrook Station, Wind Ridge

County: Greene

Contact Person: Mathew J. Myers


NOx

VOCs

PM

CO

117.00

11.00

4.00

24.00

9/15/2019 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 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

111.37

128.42

2.21

365.60

317.94

317.94

12/31/2021

Internal Use Only

Pactiv, LLC

ERC Generating Source: Dopaco, Inc.

Sources: Presses 101 to 104

Source Location: Downingtown, Chester

Contact Person: Phoebe C. Robb


VOCs 60.30


Philadelphia Authority for Industrial Development

Sources: 3 boilers

Source Location: 2000 Constitution Ave, Philadelphia


Contact Person: Raymond McCaffrey

Telephone Number: (215)-389-0835

NOx

SOx

CO

VOCs

PM-10

PM-2.5

27.16

53.38

4.52

0.27

5.24

2.92

1/01/2019

Trading

July 2015 Page 6


Certified ERCs

Available (tpy)

Expiration date


Exelon Power

Sources: Boiler #1

Source: Eddystone Generating Station

Source Location: Eddystone Borough

County: Delaware

Contact person: John Tissue


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 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 Trading

Leggett & Platt Inc

Source location: Zell Brothers

County: York

Contact Person: Theresa Block


VOCs 6.51 11/1/2015 Trading

United States Steel Corporation

Clairton Works

400 State Street

Clairton, PA 15025

County: Allegheny

Contact Person: Coleen Davis

Telephone Number: (412)-273-4730

NOx

SO2

VOCs

CO

Pb

577.30

46.30

7.50

98.70

0.00

4/16/2019 Trading

International Paper

Source: Bleach Plant, Erie Mill

County: Erie

Contact Person: Allyson Bristow


VOCs 0.60 Trading

July 2015 Page 7


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

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 1.12 12/31/2021 Trading

Monroe Energy, LLC

Source Location: 4101 Post Rd., Trainer, PA

County: Delaware

Contact Person: Jeff K. Warmann


NOx

0.32

9/16/2017

Trading

PPL Martins Creek, LLC

Source Location: Lower Mount Bethel Township

County: Northampton

Contact Person: Linda A. Boyer


VOCs

NOx

SO2

PM-2.5

PM-10

13.55

742.82

15841.10

60.30

145.04

9/17/2017 Trading

Monroe Energy, LLC

Source Location: 4101 Post Rd., Trainer, PA

County: Delaware

Contact Person: Jeff K. Warmann


VOCs 4.80 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 Trading

July 2015 Page 8


Certified ERCs

Available (tpy)

Expiration date


Exelon Power

Sources: Oil boiler #32



County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

127.40

2.60

239.65

19.05

15.35

17.52

0.00

7/31/2021 Trading

Exelon Power

Sources: Oil boiler #33



County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

1.68

0.00

2.32

0.25

0.17

0.55

0.00

6/29/2022 Trading

Exelon Power

Sources: Oil delivery fugitives



County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

0.00

0.00

0.00

0.48

0.07

0.00

0.00

6/30/2022 Trading

Exelon Power

Sources: Natural gas preheater



County: Chester



NOx

VOCs

SO2

PM-10

PM-2.5

CO

Pb

0.06

0.00

0.02

0.01

0.01

0.05

0.00

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

VOCs

NOx

SO2

PM-10

PM-2.5

CO

0.00

649.60

3306.90

219.80

135.50

14.55

5/22/2020

5/22/2020

5/22/2020

5/22/2020

5/22/2020

Trading

Internal

Internal

Internal

Internal

July 2015 Page 9


Certified ERCs

Available (tpy)

Expiration date


Horsehead Corporation (Zinc Corp of America)

Source: G.F. Wheaton Power Plant / Units 034 & 035

Source Location: Potter Township / Monaca

County: Beaver

Contact Person: William N. Bailey


VOCs

NOx

SOx

PM-10

PM-2.5

CO

9.00

899.60

1898.73

44.26

24.05

64.20

9/11/2021

Trading

Bemis Company, Inc

Source: #103

Source: #104

Source: #105

Source: #106

Source: #108

Source: #109

Source Location: Hazle Township

County: Luzerne

Contact Person: Rob Harmon


VOCs

VOCs

VOCs

VOCs

VOCs

VOCs

13.70

8.57

12.90

4.20

17.60

11.90

1/01/2016

7/30/2016

9/26/2021

9/26/2021

1/01/2018

1/01/2018

Trading

Darlington Brick & Clay Products Company

General Shale Brick Inc.

Source: Darlington Plant/Kilns 3 & 4

Source Location: Darlington Township

County: Beaver

Contact Person: Martha West

Telephone Number: 423-952-4240

VOCs

1.0 10/31/2015 Trading

Jewel Acquisition, LLC

Source: Zurn Boiler / ID 040

Source Location: Midland Borough

County: Beaver

Contact Person: Deborah Calderazzo


NOx

VOCs

7.0

0.0

11/03/2016 Netting

Offsetting

Trading

Armstrong World Industries, Inc.

Source: Beaver Falls Ceiling Plant

Source Location: Beaver Falls Township

County: Beaver

Contact Person: John Ackiewicz


NOx

VOCs

SOx

PM-2.5

CO

14

27

0

21

46

3/31/2021 Trading

July 2015 Page 10


Certified ERCs

Available (tpy)

Expiration date


Allegheny Ludlum Corporation

Source: West Leechburg Plant

Source Location: Leechburg Borough

County: Westmoreland

Contact Person: Deborah Calderazzo


NOx

VOCs

30.0

0.0

7/01/2016 Trading

Exelon Power

Sources: Boiler #1

Source: Schuylkill Generating Station

Source Location: 2800 Christian St., Phila.




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 Trading

Netting

Offsetting

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: Sean J. Glennon


VOCs

VOCs

VOCs

4.61

5.81

2.17

12/31/2023

9/26/2022

12/31/2023

Netting

Internal

Netting

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


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

Contact Person: Michael Laskaris

Telephone Number: 1-800-533-3569

VOCs

VOCs

VOCs

NOx

VOCs

6.07

6.21

0.12

6.3552

1.4966

9/19/2023

9/19/2023

9/18/2022

2/26/2023

Internal

Netting /

Offsetting

Trading

July 2015 Page 11


Certified ERCs

Available (tpy)

Expiration date


Tegrant Diversified Brands, Inc.

Source: 101

Source Location: New Brighton Borough

County: Beaver

Contact Person: Victoria Brind’Amour


VOCs 19.45 4/30/2021 Trading

Carmeuse Lime, Inc

Source: Kilns 1 & 2

Source Location: Millard Lime Plant

Township: North Londonderry

County: Lebanon

Contact Person: Mark Reider


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

CO

NOx

VOCs

SOx

PM-10

PM-2.5

PM

CO

161.05

0.46

149.48

10.57

3.12

238.94

79.87

0.24

33.49

0.80

0.39

1.46

256.50

6/03/2016

4/08/2023

Trading

Trading

First Energy Solutions Corporation

(f.k.a. 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

1007.40

10.22

12552.65

203.16

105.66

0.0369

85.39

8/31/2022 Trading



Source: Unit 2

Source Location: Armstrong Power Plant

Township: Washington

County: Armstrong

Contact Person: Tonia A. Downs


NOx

VOCs

SOx

PM-10

PM-2.5

Pb

CO

1558.90

10.82

13334.05

160.50

90.49

0.0247

90.36

7/21/2022 Trading

July 2015 Page 12


Certified ERCs

Available (tpy)

Expiration date


NRG Power Midwest LP Source Location: Brunot Island Station, Pittsburgh County: Allegheny Contact Person: Kevin R. Shumaker Telephone Number: (724) 597-8390

NOx 4.91 9/26/2023 Trading

Horsehead Corporation (Zinc Corp of America)

Source: Monaca Zinc Smelter / 24 emission sources

Source Location: Potter Township / Monaca

County: Beaver

Contact Person: Timothy R. Basilone


VOCs

NOx

SOx

PM-10

PM-2.5

CO

64.00

211.00

877.90

308.84

34.10

21705.20

4/26/2024

Trading

NRG Power Midwest LP Source Location: Elrama Station, Union Township Source: Unit 1 County: Washington Contact Person: Keith Schmidt


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 Trading

NRG Power Midwest LP Source Location: Elrama Station, Union Township Sources: Units 2 & 3 County: Washington Contact Person: Keith Schmidt Telephone Number: (724) 597-8193

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 Trading

NRG Power Midwest LP Source Location: Elrama Station, Union Township Source: Unit 4 County: Washington Contact Person: Keith Schmidt Telephone Number: (724) 597-8193

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 Trading

July 2015 Page 13


Certified ERCs

Available (tpy)

Expiration date


General Electric Transportation System

Source: Boiler #5

Source Location: Erie Plant

Township: Lawrence Park

County: Erie

Contact Person: James Verderese


NOx

VOCs

SO2

PM-10

PM-2.5

PM

CO

74.50

0.39

383.00

14.60

14.60

14.60

12.70

06/30/2016

Internal use

/ Trading

General Electric Transportation System

Source: Boiler #9

Source Location: Erie Plant

Township: Lawrence Park

County: Erie

Contact Person: James Verderese


NOx

VOCs

SO2

PM-10

PM-2.5

PM

CO

174.00

0.88

843.00

13.60

13.60

13.60

26.20

06/30/2016

Internal use

/ Trading

Bemis Company, Inc

Source: #701

Source: #711

Source: #712

Source: #713

Source: #714

Source: #715

Source Location: Hazle Township

County: Luzerne

Contact Person: Rob Harmon


VOCs

VOCs

VOCs

VOCs

VOCs

VOCs

14.53

31.11

4.37

34.88

29.10

34.18

6/01/2024

9/15/2024

11/24/2023

6/01/2024

6/01/2024

9/15/2024

Trading

Kutztown University of Pennsylvania

Sources: #031, #032, #033, #034

Source Location: Maxatawny Township

County: Berks

Contact Person: Thomas Green


NOx

VOCs

PM-2.5

25.32

0.21

5.08

12/31/2018 Trading



Source: Unit 3

Source Location: Mitchell Power Plant

Township: Union

County: Washington

Contact Person: Eric R. Foster


NOx

VOCs

SOx

PM-10

PM-2.5

1636

13

1215

141

91

10/04/2023 Trading

Maryland Department of Environment Available Emission Reduction Credits (ERC) As of June, 2015

Owner Amount (Tons)

Notes ERC

Expiration Date

ERC Source ERC Contact Information VOC NOx SO2 PM2.5 Permit# Company

Name Jurisdiction

Schmidt Baking Company

42 1 1/17/2017 510-00582 Hauswald Bakery Baltimore City George Philippou, Esq. Phone: 410-649-0030 ext 3451 Mailing Address: Schmidt Baking Company 1515 Fleet Street Baltimore, MD 21231

SASOL North America, Inc.

51 225 7 7/17/2017 510-00100 SASOL North America

Baltimore City Joseph Ledvina Phone: 281-588-3446 Mailing Address: SASOL North America, Inc. 900 Threadneedle, Suite 100 Houston, TX 77079

FMC Corporation

16 105 325 17 All VOC, NOX, SO2, , and PM 2.5 ERCs committed as of 8/6/2013

6/2/2018 510-00073 FMC Corporation Baltimore City Michael D. Shannon Phone: p: (215) 299-6125; f: (215) 299-6947 Mailing Address: FMC Corporation 1735 Market Street Philadelphia, PA 19103

GST Autoleather

94 6/2/2017 043-0075 GST Autoleather Washington County

Dennis Hiller Phone: (248) 436-2300 Mailing Address: GST Autoleather 20 Oak Hollow Road. Suite 300 Southfield , MI 48033

HRE Sparrows Point LLC

2710 3519 1355 9/14/2022 005-0147 HRE Sparrows Point Baltimore County Roberto Perez Phone: 847-418-2071 cell:847-815-8488 Mailing Address: HRE Sparrows Point LLC

mailto:[email protected]�






ERCs Registry Pursuant to the New York State Clean Air Compliance Act and 6NYCRR Subpart 231-2, Notice is hereby given of the following listing of ERCs, registered by the NYSDEC, which are available for offsets as of July 22, 2015.

VOC ERCs as of Specified Date

Contaminant Region

Available (TPY)* Nonattainment

Area

Facility Name DEC ID

Contact Telephone # Comments

VOC 1

15.29 Severe Ozone

Alcan Packaging 1-2820-00185

Mr. Coil 773-399-8599

69.20 tpy trnsfrd. to Alcan Packaging #1-4728-04190

VOC 1

84.94 Severe Ozone

Northville E. Setauket Termin. 1-4722-01658

Mr. Maus 516-753-4364

Emission point(s) shutdown

VOC 1

8.4 Severe Ozone

FiberMark/Arcon Coating 1-2820-01862

Mr. Kraft 215-536-4000

Emis.pt(s) shutdown; 2.8 tpy DEC retained

VOC 1

5.325 Severe Ozone

Marglo Pack. Corp. 1-2824-00898

Mr. Glassman 718-649-2800

Emis.pt(s) shutdown; 1.775 tpy DEC retain

VOC 1

3.34 Severe Ozone

Adchem Industries, Inc. 1-2822-00620

Mr. Pufahl 631-727-6000

Facility shutdown; 1.11 tpy DEC retain

VOC 1

0.00 Severe Ozone

Arkay Packaging Corp. 1-4734-00016

Ms. Triglia 631-297-3345

9.86 tpy trnsfrd. To Elements Market

VOC 1

9.86 Severe Ozone

Elements Markets, LLC Mr. Taylor 281-207-7200

VOC 1

0.00 Severe Ozone

Sprague Energy Corp. 1-2820-01104

Mr. Johnson 516-622-7110

11.81 (6.00 and 5.81) tpy trnsfrd. to Carbo industries, Inc.

VOC 1

1.70 Severe Ozone

Freeport Power Plant #2 1-2820-00358

Mr. Bianco 516-377-2200

Emission Pts. shutdown 0.60 tpy DEC retain

VOC 19.77 Printpack, Seal-it Mr. Facility shutdown

1 Severe Ozone 1-4720-01685 Wiederhold 404-691-5830

4.07 Severe Ozone

Element Markets, LLC Mr. Taylor 281-207-7200

VOC 1

81.30 Severe Ozone

Aladdin Packaging, LLC 1-4728-00618

Mr. Endzweig 631-273-4747

Facility shutdown

VOC 2

69.22 Severe Ozone

Betts Ave. Municipal Incin. 2-6304-00093

Mr. Bekowies 212-837-8383

Facility shutdown

VOC 2

47.14 Severe Ozone

Greenpoint Municipal Incin. 2-6101-00022


Facility shutdown

VOC 2

149.00 Severe Ozone

SW Brooklyn Mun. Incin. 2-6106-00002

Mr. Beckowies 212-837-8383


12.86 Severe Ozone

NRG Power Marketing Inc.

Mr. Karalus 612-373-5307

VOC 2

7.83 Severe Ozone

Con Ed.-Hudson Ave. 2-6101-00042

Mr. Ogunsola 212-460-1223


VOC 2

132.00 Severe Ozone

Newtown Creek WPCP 2-6101-00025

Mr. Lopez 718-595-5049

VOC 2

0.10 Severe Ozone

East River Housing Corp. 2-6206-00096

Mr. Jacob 212-677-5858

Emis. pt(s). Shtdown

VOC 2

00.00 Severe Ozone

GATX SI, Inc. 2-6401-00042

Mr. Dahl 312-621-8452

93.69 tpy trnsfrd. to Element Markets, Inc.

93.69 Severe Ozone

Elements Markets, LLC Mr. Taylor

281-207-7200

VOC 2

6.90 Severe Ozone

Arrow Lock Mfg. Co. 2-6105-00250

Mr. Shah 718-927-2772 X240

Facility shutdown 2.3 tpy DEC retain

VOC 2

3.20 Severe Ozone

American Sugar Refining, Inc., 2-6101-00152

Mr. Demone 732-590-1177


VOC 2

48.60 Severe Ozone

Poletti Power Project 2-6301-00084

Mr. Rao 914-681-6387

Emission Source shutdown

VOC 2

11.18 Severe Ozone

NYOFCO Sludge Pellet. Facility 2-6007-00140

Mr. Lambalot 203-509-2577

Facility shutdown

VOC 2

00.01 Severe Ozone

Astoria Gas Turb. Power 2-6301-00191

Mr. Cartagena 917-612-5224

Emis. Source shutdown

VOC 2

9.27 Severe Ozone

NationalGrid Far Rockaway Power Station 2-6308-00040

Mr. Flannery 516-545-4875

Facility shutdown

22.78 Severe Ozone

Koch Supply & Trading, LP

Ms. Barnthouse 316-828-7270

VOC 3

69.00 Moderate Ozone

Genpak Corp. - Middletwn 3-3309-00064

Mr. Postulka 518-798-9511

Temporarily unavailable for use

VOC 3

5.60 Moderate Ozone

Harlem Valley Psyc. Cntr. 3-1326-00023

Mr. Bard 518-473-5823

Source Reduction

VOC 3

45.00 Severe Ozone

GenOn Bowline LLC Mr. Konary 671-529-3874

Name change 12/03/10

VOC 3

28.76 Severe Ozone

FPL Energy Mr. Busa 561-691-7171

40 tpy commtd to Caithness LI Energy, # 1-4722-04426

VOC 3

2.44 Moderate Ozone

IBM - Poughkeepsie Fac. 3-1346-00035

Mr. Brannen 914-433-1509

Emission points shutdown

8.75 Severe Ozone

Element Markets, LLC Mr. Taylor 281-207-7200

4.50 tpy transferred to Philadelphia Ship Repair LLC., PA

40.00 tpy transferred to Monroe Energy LLC., PA 54.60 tpy transferred to Philadelphia Ship Repair LLC., PA

VOC 3

1.27 Severe Ozone

St. John's Riverside Hospital, 3-5518-00222

Mr. Doerr 914-964-4211

Emission point shutdown, 00.42 DEC retained

VOC 3

1.55 Severe Ozone

Wyeth Ayerst Pharmaceutical, 3-3924-00025

Mr. Alexandro 914-732-2160

Emission point shutdown, 00.51 DEC retained

VOC 3

27.20 Severe Ozone

Lovett Generating Station, 3-3928-00010

Mr. Konary 617-529-3874

Facility shutdown

VOC 3


Metal Container Corp. 3-3348-00084

Mr. Kimutis 845-567-5637

107.9 used for internal offsets 4.53 used for internal offsets

VOC 4

1.161 Marginal Ozone

Schenectady Int. Inc. 4-4228-00056

Mr. Windish 518-370-4200


VOC 4

0.13 Marginal Ozone

Schenectady Int. Inc. 4-4215-00032

Mr. Windish 518-370-4200

Source red./Emisn. points shutdown

VOC 4


Glens Falls Lehigh Portland Cement Co. 4-1926-00001

Mr. Matz 610-366-4752


VOC 4

4.6 Marginal Ozone

BASF Corporation 4-3814-00006

Ms. Roque 973-426-2662

Facility shutdown

VOC 4


General Electric Power System 4-4215-00015

Mr. Oldi 518-385-3505

Facility shutdown

VOC 4

7.45 Marginal Ozone

Von Roll Isola USA, Inc. 4-4215-00099

Ms. Mellon 518-344-7140

Facility shutdown

VOC 15.56 Norbord Industries Mr. Towles Facility shutdown

4 Ozone Transport Region

4-1230-00019 864-697-1250

VOC 4

20.00 Ozone Transport Region

Holcim (US) Inc. 4-1926-00021

Mr. Graves 518-943-4040

Facility shutdown


Evolution Markets, LLC Mr. Ammirato 914-323-0255

VOC 5

13.40 Ozone Transport Reg.

Mallinckrodt Anesthesiology 5-5320-00006

Ms. Zeigler 314-654-6347

Emission point shutdown

VOC 5


Pliant Solutions Corp. 5-5330-00016

Mr. Shuder 757-820-0114

Facility shutdown

VOC 5


International Paper- Corinth 5-4126-00007

Mr. Lienert 901-419-3895

Facility shutdown

VOC 6


F.E. Hale Mfg. Co. 6-2130-00004

Mr. Benson 315-894-5490

Facility shutdown

VOC 7


Syracuse Power Co. 7-3132-00049

Mr. Ingalls 315-471-4420

Facility shutdown

VOC 7


Syracuse Terminal (Hess) 7-3115-00014

Mr. Haid 732-750-6555

Facility shutdown

VOC 7


Marsellus Casket Co. 7-3126-00093

Mr. Vredenburg 713-525-9054

Facility shutdown

VOC 7


St. Joseph's Hospital 8-2626-00047

Mr. Scicchitamo 315-448-5737


VOC 7


Sunoco, Inc.Syracuse Term. 7-3115-00150

Mr. McGill 215-246-8267

Facility shutdown


Greenidge Generation LLC 8-5736-00004

Mr. Irwin 315-536-2359 X3423

VOC 8


Erdle Perforating Co. 8-2626-00047

Mr. Rick 716-247-4700


VOC 8


RG&E, Beebee Station 8-2614-00448

Ms. Selbig 716-771-2145

Emission Unit shutdown

VOC 8


Monroe-Livingston Landfill 8-2656-00008

Mr. Moriera 603-929-3443

Emission Point(s) shutdown

VOC 8


RG&E, Russell Station 8-2628-00068

Ms. Sahler 585-724-8684

Facility shutdown

VOC 8


Monroe-Livingston Landfill 8-2656-00008

Mr. Chraston 585-889-9460

Emission point(s) Shutdown

VOC 9


Weber Knapp Co. 9-0608-00087

Mr. Monsen 716-484-9135


VOC 9


Delphi Harrison Th. Sys. 9-2909-00018

Ms. Harper 716-439-2955


VOC 9


Delphi Harrison Th. Sys. 9-2909-00018

Ms. Harper 716-439-2955

Source Reduction

VOC 9


Bush Industries Inc. 9-0454-00001

Mr. Newman 716-665-2000

Source Reduction

VOC 9


CWM Chemical serv. Inc. 9-2934-00022

Mr. Hino 716-754-0278


VOC 9

41.40 Ozone Transport

Valeo Engine cooling Inc.

Mr. Anderson 716-665-2620


Region 9-0608-00017

VOC 9


Occidental Chemical Corp. 9-2912-00041

Ms. Desmukh 972-404-3217

Facility shutdown

VOC 9

7.50 Marginal Ozone

The Colad Group, Inc. 9-1402-00009

Mr. Pelz 716-849-1776

35.00 tpy committed to Athens Gen. Fac.

VOC 9


Dunlop Tire Corporation 9-1464-00030

Mr. Pyanowski 716-879-8274



Holcim (US) Inc. 4-1040-00011

Ms. Garakani 734-529-4233


Tecumseh Redevelop. Inc.

Mr. Nagel 716-856-0635

VOC 9

1.10 Ozone Trans. Reg.

Limestone Compressor Fac. 9-0942-40027

Mr.Young 814-871-8657


VOC 9

1.80 Marginal Ozone

UCAR Carbon company 9-2911-00185

Ms. Bolton 931-380-4215

Facility shutdown

VOC 9


Dinaire, LLC 9-1402-00218

Mr. Schmitt 716-894-1201

Facility shutdown

VOC 9


United Refining Company 9-1464-00007

Mr. Roy 814-726-4859


VOC 9

22.70 Ozone Transport Reg

Medina Power Company 9-0484-00017

Mr. Pecnik 716-532-3371

Facility shutdown

VOC 9

4.22 Marginal Ozone

Saint-Gobain Abrasives 9-2940-00048

Mr. Fogarty 508-795-5860

Facility shutdown

VOC 9


SGL Carbon LLC 9-2911-00038

Mr. Higgs 704-593-5165

Facility shutdown

VOC 9


The Goodyear Tire and Rubber Co.

Mr. Jones 716-236-2635


9-2911-00036

VOC 9


Arcelormittal Lackawanna LLC 9-1499-00067

Mr. Nagel 330-659-9102

Facility shutdown

VOC 9


QG Printing Corporation 9-1430-00213

Mr. Estock 414-566-7617

Facility shutdown, 400 tpy trnfrd. to Mid-Atlantic Develop(PA), 55 tpy trnsfrd. to American Craft Brewing, PA

31.50 Severe Ozone

American National Power

Mr. Mussleman 508-382-9356

Ramapo changed name to ANP

VOC PA

73.02 Severe Ozone

GenOn Bowline LLC Mr. Konary 671-529-3874


26.00 Severe Ozone



5 tpy trnsfrd. to Calpine # 1-4722-02441


Holcim (US) Inc. 4-1040-00011


NOx ERCs as of Specified Date

Contaminant Region

Available (TPY)* Nonattainment

Area

Facility Name DEC ID

Contact Telephone #

Comments

NOx 1

20.50 Severe Ozone

Nationalgrid (Formerly KeySpan Gen. LLC.) 1-4722-00107

Mr. Teetz 516-391-6133

Name change (2007)

NOx 1

253.80 Severe Ozone

Nationalgrid (Formerly KeySpan Gen. LLC.) 1-2822-00481

Mr. Teetz 516-391-6133

Name change (2007), 225 tpy trnsfd. to Morgan Stanley

146.64 Caithness Long Mr. Grace

Severe Ozone Island II, LLC 917-472-4593

64.80 Severe Ozone

Nationalgrid (Spagnoli Rd. Energy Centre) 1-2824-00077

Mr. Teetz 516-391-6133

10.20 Severe Ozone

Nationalgrid (Spagnoli Rd. Energy Centre) 1-2820-00951

Mr. Teetz 516-391-6133

NOx 1

59.10 Severe Ozone

NYSOMH - Kings Park Psyc. Cntr. 1-4734-00103

Mr. Bard 518-473-5823

19.7 tpy DEC retained

NOx 1

54.40 Severe Ozone

Freeport Power Plant #2 1-2820-00358

Mr. Bianco 516-377-2200

Emission Pts. shutdown 18.10 tpy DEC retain

NOx 1


Suffolk County Dev. Ctr. #1-4726-00428

Mr. Bard 518-473-5823

NOx 2

682.12 Severe Ozone

Con Ed. - Astoria 2-6301-00006


133 tpy commtd to GenOn Bowline LLC; 148.9 tpy commtd to Brookhaven Energy; 425 tpy commtd to Astoria Energy,LLC, #2-6301-00647; 116.1 tpy trnsfrd. to Ramapo Energy

133.00 Severe Ozone

GenOn, Bowline LLC

Mr. Konary 671-529-3874


30.90 Severe Ozone

J.P. Morgan Vent. Energy Corp.

Mr. Woods 212-834-3568

118 tpy committed to Caithness LI Energy # 1-4722-04426

42.00 Severe Ozone

Calpine Stony Brook Enrgy Cntr.

NOx 2

316.30 Severe Ozone

Con Ed. - 59th St. 2-6202-00032



NOx 2

38.24 Severe Ozone

Greenpoint Municipal Incin. 2-6101-00022


Facility shutdown

NOx 2

189.00 Severe Ozone

SW Brooklyn Mun. Incin. 2-6106-00002

Mr. Beckowies 212-837-8383


NOx 2

126.22 Severe Ozone

Con Ed. - Waterside 2-6206-00038



NOx 2

481.30 Severe Ozone

Con Ed. - Waterside 2-6206-00038


Facility shutdown

NOx 2

00.00 Severe Ozone

Con Ed. - Hudson Ave. 2-6101-00042

Mr. Guastafeste 212-460-4858

25.82 tpy transfer to NRG Power Marketing Inc.

25.82 Severe Ozone

NRG Power Marketing Inc.

Mr. Karalus 612-373-5307

NOx 2

355.84 Severe Ozone

Con Ed.-Hudson Ave. 2-6101-00042

Mr. Ogunsola 212-460-1223


NOx 2

294.40 Severe Ozone

Newtown Creek WPCP 2-6101-00025

Mr. Lopez 718-595-5049

115.5 DEC retained, 50.7 tpy comtd to Fount. Ave. Landfill #2-6105-00687

NOx 2

80.00 Severe Ozone

Visy Paper, 2-6403-00107

Mr. Davey 718-370-1114

Emis. pt(s). Shutdown

NOx 2

21.40 Severe Ozone

East River Housing Corp., 2-6206-00096

Mr. Jacob 212-677-5858

1 tpy trnfrd to CVEC#3-1326-00275

NOx 2

220.00 Severe Ozone

Betts Ave. Mun. Incin., #2-6304-00093

Mr. Nabavi 917-237-5958

Facility Shutdown

NOx 2

59.30 Severe Ozone

American Sugar Refining, Inc., 2-6101-00152

Mr. Demone 732-590-1177


NOx 2

1554.00 Severe Ozone

Poletti Power Project 2-6301-00084

Mr. Rao 914-681-6387

Emission Source shutdown

NOx 2

137.20 Severe Ozone

NationalGrid Far Rockaway Power Station 2-6308-00040

Mr. Flannery 516-545-4875

Facility shutdown

NOx 3


Harlem Valley Psyc. Cntr. 3-1326-00023

Mr. Bard 518-473-5823

Source Reduction/Facility shutdown

NOx 3


A.G. Properties of Kingston, LLC, 3-5154-00153

Mr. Ginsberg 845-383-0400

Facility shutdown

NOx 3

4209.20 Severe Ozone

Lovett Generating Station, 3-3928-00010

Mr. Konary 617-529-3874

Facility shutdown

NOx 4


Glens Falls Lehigh Portland Cement Co 4-1926-00001

Mr. Matz 610-366-4752



Holcim (US) Inc. 4-1040-00011


NOx 4

52.6 Marginal Ozone

BASF Corporation 4-3814-00006

Ms. Roque 973-426-2662

Facility shutdown

NOx 4

7.57 Marginal Ozone

General Electric Power System 4-4215-00015

Mr. Oldi 518-385-3505

Facility shutdown

NOx 4


Holcim (US) Inc. 4-1926-00021

Mr. Graves 518-943-4040

Facility shutdown

NOx 5


Peckham Materials Corp. 5-5344-00009

Mr. Yaremko 914-949-2000


NOx 5


General Electric Silicone

Ms. Arisman 518-233-3540


5-4154-00002

NOx 5


Pactiv Corporation 5-0942-00014

Mr. Pettit 518-562-6110


NOx 5


Mohawk Paper Mills, Inc. 5-4154-00003

Mr. Milner 518-237-1740


NOx 5


International Paper- Corinth 5-4126-00007

Mr. Lienert 901-419-3895

Facility shutdown

NOx 6


NYSOMH - Mohawk Valley Psych Cntr. #6-3016-00138

Mr. Bard 518-473-5823

NOx 6

226.10 Ozone Trans. Region

Magan-Racine Facility 6-4022-00021

Mr. Megan 352-793-6565

Facility shutdown

NOx 6


NYSOMH - St. Lawrence Psych Cntr. #6-4012-00016

Mr. Bard 518-473-5823

NOx 7


Anitec Image Corp. 7-0302-00064

Mr. Markle 607-774-3375


NOx 7


NiMo Power Corp. 7-3512-00030

Mr. Russo 315-428-6798

233 tpy used by Corning Inc.

NOx 7


Heritage Power LLC 7-3556-00097

Mr. Dreisbach 518-385-9122

From Bethlehem Steel Corp., PA

NOx 7


Syracuse Power Co. 7-3132-00049

Mr. Ingalls 315-471-4420

Facility shutdown

NOx 496.00 Owens-Brockway Mr. Tussing Facility shutdown

7 Ozone Transport Region

Gls. Cont. Inc. 7-3558-00014

419-247-8682

NOx 7


Cornell Uni. Cent. Energy Plant 7-5007-00030

Ms. Brown 607-254-8687



Greenidge Generation LLC 8-5736-00004

Mr. Irwin 315-536-2359 X3423

NOx 8


NYSEG-Hickling Gen. Stn. 8-4638-00011

Mr. Malecki 607-762-7763

NOx 8


University of Rochester 8-2699-00059

Mr. Stillman 716-275-2056

source reduction

NOx 8


NYSOMH-Roch.Psy Ctr. #8-2614-00341

Mr. Bard 518-473-5823

NOx 8


RG&E, Beebee Station 8-2614-00448

Ms. Selbig 716-771-2145

18 tpy commtd to Besicorp-Recycling # 4-3814-00061 242 tpy commtd to Besicorp-Power # 4-3814-00052

NOx 8


Corning Inc.- Fall brook plant 8-4603-00008

Mr. Casolo 607-974-7031

Facility Shutdown

NOx 8


RG&E, Russell Station 8-2628-00068

Ms. Sahler 585-724-8684

Facility shutdown

NOx 9


Occidental Chemical Corp. 9-2912-00041

Ms. Desmukh 972-404-3217

Facility shutdown

NOx 9


LFG Energy Inc. 9-1432-00281

Mr. Zeliff 716-759-0366

Source Reduction


Holcim (US) Inc. 4-1040-00011


216.60 tpy trnsfrd. to Burgess Biopower (NH)


Tecumseh Redevelop. Inc.

Mr. Nagel 716-856-0635

NOx 9


Limestone Compressor Fac. 9-0942-40027

Mr. Young 814-871-8657


NOx 9


American Ref-fuel company of Niagara 9-2911-00113

Mr. Gleason 716-278-8509


NOx 9


E.I. Dupont 9-2911-00030

Mr. Jain 716-278-5502


NOx 9

165.10 Ozone Transport Reg

Medina Power Company 9-0484-00017

Mr. Pecnik 716-532-3371

Facility shutdown

NOx CT

207.00 Severe Ozone

GenOn, Bowline LLC

Mr. Konary 671-529-3874


200.00 Severe Ozone



Ramapo changed name to ANP


Holcim (US) Inc. 4-1040-00011


Attachment L

METEOROLOGICAL MONITORING PLAN FOR THE RENOVO ENERGY CENTER RENOVO, PA PLANT SITE Prepared by: Ambient Air Quality Services, Inc. 10 7 Hidden Fox Drive Suite 101A Lincoln University, PA 19352

REVISED MAY 2015

TABLE OF CONTENTS

1. INTRODUCTION .................................................................................................................... 1-1

2. OVERVIEW OF MONITORING PROGRAM.................................................................. 2-1

2.1 PURPOSE AND OBJECTIVES ....................................................................................... 2-1

2.2 SITE LOCATION ............................................................................................................... 2-1

2.3 MONITORING STARTUP AND DURATION ........................................................2-5

3. MONITORING PARAMETERS AND EQUIPMENT ..................................................... 3-1

3.1 MONITORING PARAMETERS ................................................................................... 3-1

3.2 MONITORING EQUIPMENT ...................................................................................... 3-1 3.2.1 WIND SPEED SENSOR ................................................................................................... 3-1 3.2.2 WIND DIRECTION SENSOR ....................................................................................... 3-1 3.2.3 BAROMETRIC PRESSURE ........................................................................................... 3-2 3.2.4 SOLAR SENSORS .............................................................................................................. 3-2 3.2.5 NET RADIATION SENSOR ........................................................................................... 3-2 3.2.6 TEMPERATURE AND DELTA TEMPERATURE .................................................. 3-2 3.2.7 METEOROLOGICAL TOWER .................................................................................... 3-2 3.2.8 DOPPLER SODAR ............................................................................................................. 3-2 3.2.9 DATA LOGGER ................................................................................................................. 3-2 3.2.10 EQUIPMENT ENCLOSURE .......................................................................................... 3-3 3.2.11 RELATIVE HUMIDITY ................................................................................................... 3-3

4. DATA COLLECTION AND MANAGEMENT ................................................................ 4-1

4.1 DATA COLLECTION ....................................................................................................... 4-1

5. ROUTINE SITE OPERATION AND MAINTENANCE ................................................. 5-1

6. QUALITY ASSURANCE/CONTROL ................................................................................. 6-1

6.1 AUDIT PROCEDURES .................................................................................................... 6-1 6.1.1 WIND SPEED AUDIT PROCEDURES (HORIZONTAL AND VERTICAL) . 6-1 6.1.2 WIND DIRECTION AUDIT PROCEDURES .......................................................... 6-2 6.1.3 TEMPERATURE AND DELTA TEMPERATURE AUDIT PROCEDURES .. 6-2 6.1.4 SOLAR AND NET RADIATION AUDIT PROCEDURES ................................... 6-2 6.1.5 BAROMETRIC PRESSURE AUDIT PROCEDURES ........................................... 6-2 6.1.6 RELATIVE HUMIDITY AUDIT PROCEDURES .................................................... 6-3 6.1.7 DOPPLER SODAR AUDIT PROCEDURES .............................................................. 6-3

6.2 STANDARD OPERATION PROCEDURES .............................................................. 6-3

7. PROJECT ORGANIZATION ................................................................................................ 7-1

i

LIST OF FIGURES Figure 2-1 Location of the Proposed Renovo Energy Center Renovo, PA ......................................... 2-2 Figure 2-2 Location of Meteorological Monitoring Site .......................................................................... 2-3 Figure 3-1 Photograph of Meteorological Monitoring Site North and East Views .......................... 3-4 Figure 3-2 Photograph of Meteorological Monitoring Site South and West Views ........................3-5

ii

LIST OF TABLES Table 2-1 Coordinates for Renovo Energy Center ..................................................................................... 2-4 Table 3-1 Comparison of Meteorological Sensor Specification to USEPA Criteria ......................... 3-6 Table 5-1 Meteorological Monitoring Site Routine Site Checks ......................................................... 5-2

iii

1. INTRODUCTION

Renovo Energy Center, LLC (REC) proposes to construct a nominally rated 926 MW (net) natural gas 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 (CT) and a steam turbine to produce electricity for distribution into the transmission grid system. Each combined cycle system consists of a natural gas fired combustion turbine and a heat recovery steam generator (HRSG). The steam from the HRSGs is routed through the condensing steam turbine generator. With the exception of one OEM option, each HRSG has a gas fired duct burner (DB) for supplemental firing. The primary fuel for the plant is natural gas with oil as back up.

The proposed REC facility will also include for each power block an auxiliary boiler, an emergency generator, a turbine air inlet conditioner, a natural gas heater and an air cooled condenser. The REC will also have one fire water pump. The HRSG DBs, auxiliary boiler and fuel gas heater will primarily combust pipeline quality natural gas. The emergency firewater pump and emergency generator will combust ultra-low sulfur diesel fuel oil.

The construction of the power plant will require REC to prepare and submit an air quality Plan Approval Application including an air quality modeling analysis. In anticipation of the requirement for an air quality modeling analysis REC has undertaken a one year onsite meteorological monitoring program to collect the required meteorological data for regulatory air quality modeling purposes.

This document is a meteorological monitoring plan which describes the site, purpose, equipment, data collection methods and Quality Assurance/Quality Control procedures of the REC meteorological monitoring program. The monitoring plan has been developed to support the use of the meteorological data in a regulatory air quality modeling analysis by REC for the Renovo, PA site. REC plans to use the meteorological data in an air quality modeling analysis to support a Prevention of Significant Deterioration (PSD)/New Source Review (NSR) air permit application.

The meteorological monitoring program has been designed to meet or exceed all United States Environmental Protection Agency (USEPA) and Pennsylvania Department of Environmental Protection (PADEP) monitoring guidelines and requirements. All equipment selected for the monitoring program meets or exceeds the criteria for PSD monitoring programs. This monitoring plan was developed using the guidance in the “Ambient Monitoring Guidelines for Prevention of Significant Deterioration” (USEPA, 1987), the “Quality Assurance Handbook for Air Pollution Measurement Systems”, (USEPA 2008) and “Meteorological Monitoring Guidance for Regulatory Modeling Applications”, (USEPA February, 2000). The remainder of the monitoring plan includes the following sections:

• Section 2 - Overview of the Monitoring Program • Section 3 - Monitoring Parameters and Equipment • Section 4 - Data Collection and Management Procedure • Section 5 - Site Operations and Maintenance • Section 6 - Quality Assurance/Quality Control Procedures • Section 7 - Project Personnel

1-1

2. OVERVIEW OF MONITORING PROGRAM

2.1 PURPOSE AND OBJECTIVES

The purpose and objective of the meteorological monitoring program is to collect 12 months of onsite meteorological monitoring data to support the use of USEPA approved air quality models such as AERMOD in an air quality modeling analysis. The meteorological monitoring program has been designed to collect hourly meteorological parameters at or above stack release heights for the emission sources at the REC. The height for the combustion turbines’ stacks are currently designed for approximately 250 ft. but may ultimately be slightly lower based upon final design of the plant.

The meteorological monitoring site was selected to satisfy the following USEPA siting and instrument exposure criteria and to collect meteorological measurements representative of the REC site including:

Wind Speed and Direction: Sensors for wind speed and wind direction should be located over level, open terrain at a height of 10 m above ground level and at a distance at least ten times the height of nearby obstructions. For elevated releases, additional measurements should be made at stack top or 100 m, whichever is lower.

Ambient Temperature and Relative Humidity: Temperature and relative humidity sensors should be mounted over a plot of open level ground at least 9 m in diameter. The ground surface should be covered with non-irrigated short grass. The standard height for the sensor is 1.5 to 2 m, but different heights may be used depending on the air quality study. Probe placement for temperature difference measurements depend on the application. For this application the temperatures will be measured at 2 and 20 meters. Temperature and relative humidity sensors should be shielded to protect them from thermal radiation and any significant heat sources or sinks and adequately ventilated using aspirated shields.

Solar Radiation: Pyranometers used for measuring incoming (solar) radiation should be located with an unrestricted 360 degree view of the sky without significant obstacles. The sensor should be placed so that shadows will not be cast onto the sensor. Sensor height is not critical for pyranometers; a tall platform or rooftop is an acceptable location.

Net Radiation: The ground cover under a net radiometer should be representative of the general site area. The given application will govern the collection of solar or net radiation data.

Barometric Pressure: The sensor should be placed where there is solid vertical mounting and will be protected against rough handling. The sensor should be shielded from direct sunshine.

2.2 SITE LOCATION

The Renovo Energy Center is located in Renovo Borough, Clinton County, PA approximately 28 miles (45 km) northwest of Lock Haven, PA along the West Branch Susquehanna River. The location of the REC site is shown in Figure 2-1. The location of the meteorological monitoring site and the site coordinates are presented in Figures 2-1 and Table 2-1, respectively. The topography of the area surrounding the Renovo Energy Center is considered

2-1

Figure 2-1 Location of the Proposed Renovo Energy Center

Renovo, PA

Renovo, PA

Lock Haven, PA

2-2

Figure 2-2 Location of Meteorological Monitoring Site

Proposed Meteorological Tower Location

2-3

Table 2-1 Coordinates for Renovo Energy Center

Renovo, PA Meteorological Monitoring Site

Latitude 41°19'42.42"N Longitude 77°45'18.44"W UTM North meters 4,578,881.488 UTM East meters 269,432.549 Zone 18 Datum 1983

2-4

complex terrain for air quality modeling purposes since the surrounding terrain exceeds the proposed combustion turbine stack height.

The elevations in the area range from approximately 700 feet above mean sea level (amsl) at the REC site to 2,000 ft. above mean sea level (amsl) on terrain within 2 miles south of the site. The highest terrain within 2 miles north of the site is approximately 1,700 ft. amsl. This information is based upon the United States Geological Survey (USGS) 1:24,000 scale topographic map of the area (Renovo West and Renovo East, 2013).

2.3 MONITORING STARTUP AND DURATION

Meteorological data collection is anticipated to begin in June 2015 and continue for at least 12 months.

2-5

3. MONITORING PARAMETERS AND EQUIPMENT

This section discusses the monitoring parameters and equipment of the Renovo Energy Center meteorological monitoring program.

3.1 MONITORING PARAMETERS

The meteorological monitoring program will site consist of a 20 meter tower and a Doppler SODAR system. The meteorological tower will be instrumented to measure the following parameters:

• Horizontal and vertical wind speed and horizontal wind direction and temperature at 20-meters

• Temperature and barometric pressure at 2-meters • Solar and net radiation at 1 meter

All equipment selected will meet or exceed the specifications for meteorological monitoring equipment in the “Meteorological Monitoring Guidance for Regulatory Modeling Applications, (USEPA, 2000). Table 3-1 provides a comparison of the monitoring sensor specifications with the USEPA criteria.

Photographs of the meteorological monitoring site from the north, east, south and west are shown in Figures 3-1 and 3-2. There were no trees, or other structures that will affect the monitoring location or exposure of the monitoring sensors. All wind sensors will be heated to avoid ice buildup during freezing precipitation events. The temperature sensors will be located in motor aspirated temperature shields.

In addition to the meteorological tower a REMTECH PA0 Doppler SODAR will be installed and operated. The SODAR will collect measurements of wind speed (horizontal and vertical) wind and direction every 30 meters starting at 20 meters and extending to at least 450 meters.

3.2 MONITORING EQUIPMENT

A brief described of the principal of operation of the meteorological equipment and instrumentation is provided in this section.

3.2.1 Wind Speed Sensor

The horizontal and vertical wind speed sensors are cup and propeller anemometers, respectively, to produce a signal proportional to the wind speed. The horizontal wind speed sensor will use a three cup anemometer. The anemometer assemblies are shaft mounted on a frictionless transducer. The wind speed sensors will be heated to prevent freezing of the sensors. The horizontal and vertical wind speed sensors will meet or exceed the specification shown in Table 3-1.

3.2.2 Wind Direction Sensor

The wind direction sensor will use a wind vane to produce a signal proportional to the direction azimuth. The wind direction sensor will be heated to prevent freezing of the sensors. The wind direction sensor will meet or exceed the specification shown in Table 3-1.

3-1

3.2.3 Barometric Pressure

The barometric pressure sensor will be an electronic type using a silicon piezoresistive sensor and will be temperature compensating. The sensor will be installed inside a NEMA enclosure. The sensor will meet or exceed the specifications in Table 3-1.

3.2.4 Solar Sensors

The solar sensor will use photodiode detector to create a voltage output that is proportional to the incoming radiation (solar). The sensor will be mounted and leveled on the meteorological tower. The sensor will meet or exceed the specifications in Table 3-1.

3.2.5 Net Radiation Sensor

The net radiation sensor uses two black conical and is based on a thermopile sensor. The voltage is proportional to the net radiation. The sensor will be mounted and leveled on the meteorological tower. The sensor will meet or exceed the specifications in Table 3-1.

3.2.6 Temperature and Delta Temperature

The temperature sensors will be a thermistor bead in stainless steel. The sensor transfers heat rapidly yielding typical time constant of 3.6 seconds. The sensors will be housed inside motor aspirated temperature shields.

The temperature difference between 20 and 2 meters will be calculated by the data logger.

3.2.7 Meteorological Tower

The meteorological tower will be a 20 meter, multi-section, crank down and tiltable tower. A Rohn 55FK or equivalent tower will be installed.

3.2.8 Doppler SODAR

Doppler SODAR systems use Doppler shift technologies (frequency shift as a function of speed) to measure air movement as a function of the temperature discontinuity in the atmosphere. A Doppler SODAR system consists of antennas (speakers) that transmit and receive acoustic signals. A mono-static system uses the same antenna for transmitting and receiving and determines atmospheric scattering by temperature fluctuations. A mono-static phase array SODAR system will be used to measure wind speed at and above the stack height every 30 meter starting at 20 meters above the ground and extending to at least 450 meters.

3.2.9 Data Logger

All sensors will be wired to a Campbell Scientific CR1000 data logger which will scan each sensor once per second. The data logger will record 5 minute, 15 minute and hourly average values of the meteorological parameters. The data logger will be stored in a NEMA enclosure.

3-2

3.2.10 Equipment Enclosure

The Doppler SODAR electronic box and laptop will be stored in a climate controlled (heated/air conditioned) equipment enclosure.

3.2.11 Relative Humidity

The relative humidity sensor is a capacitive thin-film polymer sensor consisting of a substrate on which a thin film of polymer is deposited between two conductive electrodes. The thin-film polymer either absorbs or releases water vapor as the relative humidity of the ambient air rises or falls. The dielectric properties of the polymer film depend on the amount of absorbed water. As the relative humidity around the sensor changes, the dielectric properties of the polymer film change, and so does the capacitance of the sensor. The instrument’s electronics measure the capacitance of the sensor and convert it into a humidity reading.

3-3

Figure 3-1 Photograph of Meteorological Monitoring Site

North and East Views

Looking North from Site

Looking East from Site

3-4

Figure 3-2 Photograph of Meteorological Monitoring Site

South and West Views

Looking South from Site

Looking West from Site

3-5

Table 3-1

Comparison of Meteorological Sensor Specification to USEPA Criteria

Sensor (Meteorological

Variable)

Sensor

Variable

Recommended EPA System Response Characteristicsa

Site System

Specification

Horizontal Wind Speed Starting Threshold Distant Constant Accuracyb Measurement Resolution

≤ 0.5 mps ≤ 5 m

± 0.2 mps + 5% of observed 0.1 mps

0.22 mps < 1.5 m

± 0.07 m/s or 1% of observed 0.07 mps

Vertical Wind Speed Starting Threshold Distant Constant Accuracyb Measurement Resolution

≤ 0.25 mps ≤ 5 m

± 0.2 mps + 5% of observed 0.1 mps

0.25 mps < 1 m

± 0.07 m/s or 1% of observed 0.1 mps

Wind Direction Starting Threshold Distant Constant Accuracyb

Measurement Resolution

≤ 0.5 mps at 10° deflection ≤ 5 m

± 5 degrees 1 degree

0.22 mps <1.0 m

± 2 degrees 1 degree

Ambient Temperature Time Constant Accuracyb


≤ 1 minute ± 0.5°C

0.1°C

≤ 3.6 seconds ± 0.05°C

0.1°C

Delta Temperature Time Constant Accuracyb


≤ 1 minute ± 0.1°C 0.02°C

3.6 seconds ± 0.1°C 0.01°C

Solar Radiation Time Constant Accuracyb


≤ 5 seconds ± 5% of observed

10 Watts/square meter

≤ 10 seconds ± 5%

0.1 Watts/square meter

Barometric Pressure Accuracyb


± 3.0 Millibars 0.5 Millibars

± 0.1% 0.1 Millibars

(a) “Meteorological Monitoring Guidance for Regulatory Modeling Applications”, USEPA-450/R-99-005, February 2000 (b)The data logger accuracy is 0.1% of the full-scale voltage. It has been included as part of the system accuracy specifications

3-6

4. DATA COLLECTION AND MANAGEMENT

This section discusses the data collection and data management which will be used during the REC meteorological monitoring program.

4.1 DATA COLLECTION

The data collection system for the meteorological monitoring program included a data logger for the meteorological tower sensors and a laptop computer for the Doppler SODAR system. The meteorological tower data from the 20-meter, 2-meter and surface measurements will be stored as 5-, 15- and 60-minute averages and the Doppler SODAR data will be stored as 15-minute data for every level of valid measurements, typically every 30 meters to 450 meters.

The meteorological data from the meteorological tower data logger and the Doppler SODAR laptop computer will be downloaded via cellular phone modems on a daily basis and reviewed by AAQS staff meteorologists (Monday through Friday). Data will be stored at AAQS offices on dedicated hard drives and to an internet cloud backup server.

PA DEP will be provided a copy of the hourly data (in Excel spreadsheet format) within 30 days after the end of each calendar quarter.

4-1

5. ROUTINE SITE OPERATION AND MAINTENANCE

The meteorological monitoring site will be routinely visited by AAQS staff personnel to check the security of the site, check the conditions of the tower, sensors and cabling, and maintain the site area. A list of the site checks to be made by the project personnel is presented in Table 5-1. In addition to a startup audit a complete audit will be performed on the meteorological tower instrumentation every six months. The specific quality assurance and control procedures to be used during the monitoring program including the performance audits are discussed in the Section 6.

5-1

Table 5-1 Meteorological Monitoring Site

Routine Site Checks

External External Internal

Tower Sensors Equipment Enclosure Tower Sections Winch motor and cabling Junction Boxes Boom arms Lighting rod and cable Grounding rod NEMA Enclosure

Wind speed cups Wind direction vane Aspirator motors Radiation sensor dome Sensor cables and connections

Uninterruptible power supply Heating and air conditioning

5-2

6. QUALITY ASSURANCE/CONTROL

This section of the monitoring plan describes the specific procedures that will be followed to implement the Quality Assurance/Quality Control (QA/QC) of the meteorological monitoring. The QA/QC procedures include system and performance audits of the monitoring site and the use of Standard Operating Procedures (SOP) by site personnel.

The purpose of the QA/QC procedures is to maximize data capture to ensure that 12 months of meteorological monitoring data can be deemed acceptable by PADEP and USEPA for future regulatory air quality modeling purposes. Specifically, the monitoring program QA/QC procedures have been designed to achieve

• 4 consecutive quarters with 90 percent recovery.

• 90 percent recovery of each of the variables wind direction, wind speed, relative humidity, barometric pressure, solar radiation, and temperature.

• 90 percent joint recovery of wind direction, wind speed, and solar radiation and temperature difference.

6.1 AUDIT PROCEDURES

The specific audit procedures are based on the quality assurance recommendations contained in the USEPA “Quality Assurance Handbook for Air Pollution Measurement Systems Volume IV – Meteorological Measurements (USEPA, 2008). These are described in the following sections. Performance audits will be performed at startup, after 6 months and after 12 months of monitoring.

PA DEP will be given written notification of the planned performance audits within 1 month prior to each audit. The performance audit reports will be submitted to PA DEP within 1 month of the completion of each audit.

6.1.1 Wind Speed Audit Procedures (Horizontal and Vertical)

The wind speed audit will include procedures to test the accuracy of the wind speed sensor measurements at a range of wind speed conditions. A direct current (dc) voltage motor will be used to generate a known rate of rotation that corresponded to a known wind speed. The motor will be attached to the shaft of the sensor and the sensor’s response will be monitored. For the vertical wind speed sensors the sensor will be audited in both clockwise and counter clockwise directions. A torque wheel will be used to measure qualitatively the starting threshold of the wind speed sensor (i.e. the lowest wind speed at which the sensor will physically operate). The torque wheel will be attached to the shaft of the sensor and 0.1 gram (g) weights will be applied at 1 centimeter (cm) intervals from the center of the torque wheel. The resulting torque (g-cm) gives a qualitative indication of the starting wind speed threshold. The difference between the known wind speed and the response wind speed will be compared to the USEPA accuracy criteria of 0.45 mile per hour (mph) ±5.0% of the known. The starting torque will be compared to the manufacturer’s sensor specification to give a qualitative assessment of the starting wind speed. It should be noted that the starting threshold of a sensor can only be determined by a wind tunnel test.

6-1

6.1.2 Wind Direction Audit Procedures

The wind direction audit will include procedures to determine the accuracy of the alignment of the wind direction sensor and the linearity of the sensor. In addition, the starting threshold of the sensor will be qualitatively determined in a fashion similar to the wind speed sensor. A field compass will be used to determine the True North alignment of the crossarm on which the wind direction sensor is mounted. The wind direction vane will be then aligned along the crossarm and the response will be recorded. A linearity test fixture will be used to determine the accuracy of the sensor over a range of wind directions. The linearity test fixture will be attached to the shaft of the sensor and used to orient the wind sensor to a minimum of four directions. The differences from the alignment audit and the linearity audit will be added together and a combined error will be determined. The combined error will be compared to the USEPA accuracy criteria of ±5.0. In addition to the sensor’s alignment and linearity, the starting torque of the wind speed sensor will be also qualified. The torque wheel will be attached to the shaft of the sensor and 0.1 g weights will be applied at 1 cm intervals from the center of the torque wheel. The resulting torque (g-cm) gives a qualitative indication of the starting wind direction threshold. The starting torque will be compared to the manufacturer’s sensor specification to give a qualitative assessment of the wind speed at which the wind direction sensor will begin to respond. It should be noted that the starting threshold of a sensor can only be determined by a wind tunnel test.

6.1.3 Temperature and Delta Temperature Audit Procedures

The temperature audit will consist of comparing the sensors’ responses to known temperatures. A warm water bath and an ice bath are used with NIST calibrated temperature probes to test the temperature sensors’ accuracy. The temperature sensors are placed first in an ice bath and allowed to equilibrate before a response was recorded. The same approach will also be used for a warm water bath. Distilled water will be used for the ice and warm water baths. The U.S. EPA accuracy limit for temperature measurement is ±0.9˚ F. In addition to auditing the ambient temperature sensors, the temperature difference, or delta temperature, between the levels will also be audited. The delta temperature audit is performed by immersing the sensors in the water baths and observing the temperature difference between the sensors. For delta temperature, the 2-meter temperature response is subtracted from the 10-meter temperature response and should equal 0.00˚ F. The U.S. EPA accuracy criterion for delta temperature is ±0.18° F.

6.1.4 Solar and Net Radiation Audit Procedures

The solar and net radiation audit will consist of a side-by-side comparison between the site solar and net radiation sensors and independent sensors with a NIST or a WRR (World Radiometric Reference) calibration, which will be connected to a Campbell Scientific data logger. The radiation audit will be conducted over several hours so that a meaningful number of 5-minute measurement periods are available. A comparison will be made between the 5-minute data collected by the audit sensors and the site sensors. A percent difference will be calculated for each 5-minute period and all of the percent differences will be averaged and compared to the USEPA acceptance criterion of ±5%.

6.1.5 Barometric Pressure Audit Procedures

The barometric pressure audit will consist of a side-by-side comparison between the site barometric pressure sensor and an independent sensor with an NIST calibration, which will be

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connected to a Campbell Scientific data logger. The barometric pressure audit will be conducted over several hours so that a meaningful number of 5-minute measurement periods will be available. A comparison will be made between the 5-minute data collected by the audit sensor and the site sensor. A percent difference will be calculated for each 5-minute period and all of the percent differences will be averaged and compared to the USEPA acceptance criterion of ±3 millibars (mb) or ±0.09 inches of mercury (in Hg).

6.1.6 Relative Humidity Audit Procedures

The relative humidity audit will consist of comparing the sensor’s response at ambient conditions to calibrated wet bulb and dry bulb temperature probes at the same ambient conditions or comparison with a co-located relative humidity sensor. A comparison between the calibrated temperature probes relative humidity values and audit devices are used to determine the accuracy of the site relative humidity sensor. AAQS will utilize equipment that will either directly calculate relative humidity or collect dry and wet bulb temperatures and calculate or direct relative humidity values.

6.1.7 Doppler SODAR Audit Procedures

The planned audit procedure of the Doppler SODAR will follow the recommendation described in MMG Section 9.6.2.2 which is briefly provided below. Comparison of the SODAR wind measurement will be made with data from the 20 meter level of the adjacent tall tower. The tower and SODAR data will be reviewed continuously throughout the monitoring program by AAQS’s meteorologists. The tower data will be time averaged to correspond to the SODAR averaging interval.

6.2 STANDARD OPERATION PROCEDURES

AAQS Standard Operating Procedures (SOP) for meteorological monitoring systems will be followed by project personnel including designing, installing, operating and maintaining the meteorological monitoring site.

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7. PROJECT ORGANIZATION

The following is a list of the key project members of the Renovo Energy Center meteorological monitoring program and their role/responsibility during the project.

Personnel Position Responsibility

Mr. Louis Militana Project Director Overall project management, and installation

Mr. Philip Samulewicz

Technical Director

Design, operation, data collection and data management of meteorological tower

Ms. Sharon Gill Project Meteorologist Data review and processing

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Attachment M

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

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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

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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.

Documents

Renovo Energy Center Plan Approval Application