PERMIT APPLICATION REVIEW SUMMARY

Transcription

1 PERMIT APPLICATION REVIEW SUMMARY New Hampshire Department of Environmental Services Air Resources Division P.O. Box 95, 29 Hazen Drive Concord, NH Phone: Fax: AFS #: Application #: FY Date: March 4, 2008 Page 1 of 12 APPLICATION & OTHER COMMUNICATION Date Description 10/30/07 DES received a Temporary Permit application. The application contained a waiver request to install concrete footings for equipment contained in permit application. 11/1/07 DES granted the waiver request to install concrete footings only (not associated equipment). 11/20/07 Completeness letter sent to source. PROJECT DESCRIPTION Springfield Power LLC (Springfield Power) is proposing the installation and optional operation of nitrogen oxide (NOx) pollution control equipment to an existing wood-fired boiler for the purposes of generating renewable energy credits. New pollution control equipment to be installed includes an EcoJet overfire air system, Selective Non-Catalytic Reduction (SNCR) system and Selective Catalytic Reduction (SCR) system for control of nitrogen oxide (NOx) emissions from the wood-fired boiler. The SNCR system incorporates ammonia injection into the combustion zone of the existing boiler. The SCR is a system that utilizes ammonia (as a reagent) and a catalyst to reduce NOx to nitrogen and water prior to exiting the exhaust stack for the boiler. The existing electrostatic precipitator (ESP) will continue to be used for particulate matter control. Proposed SNCR and SCR System Descriptions Springfield Power has elected to install and optionally operate SNCR and SCR systems to reduce NOx emissions from the wood-fired boiler. The purpose of installing and operating both systems is to qualify for renewable energy programs in New England States such as Connecticut, and potentially, in New Hampshire. The SNCR system uses a non-catalytic process of injecting a reagent (ammonia) into the combustion zone of the boiler, converting NOx to reaction products nitrogen (N 2 ) and water (H 2 O). The SCR system to be installed is located after the particulate matter control equipment (multiclone and ESP). The SCR system removes NOx from the flue gas by using a catalytic process to achieve the desired level of NOx reduction. The process introduces a reagent (in this case, ammonia) to the flue gas stream to convert NOx to reaction products, nitrogen (N 2 ) and water (H 2 O). Optimum temperature for the chemical reaction to occur is at approximately 550 degrees F, but can occur between 350 F and 650 F. To summarize the chemistry involved in both the SCR & SNCR, the processes convert the NOx contained in the flue gas into N 2 and H 2 O with the use of ammonia (NH 3 ) as the reagent. The basic chemical reactions taking place are the following: 1. 4NO + 4NH 3 + oxygen (O 2 ) 4N 2 + 6H 2 O 2. 2NO 2 + 4NH 3 + 2O 2 3N 2 + 6H 2 O 3. 2NO 3 + 4NH 3 + O 2 3N 2 + 6H 2 O The following side reactions may occur on a small scale: 4. 4NH 3 + 3O 2 4N 2 + 6H 2 O 5. 4NH 3 + 5O 2 4NO + 6H 2 O

2 AFS #: Application #: FY Date: March 4, 2008 Page 2 of 12 In order to achieve a sufficient chemical reaction rate at the designed operating temperature of the catalyst bed of the SCR, specifically formulated catalysts have to be used. The SCR contains several layers or beds of catalyst, which can be mixtures of various compounds such as titanium, tungsten, vanadium, and other compounds. Before the flue gas enters the SCR catalyst beds, ammonia is added and mixed with the flue gases in such a way that a homogenous distribution of ammonia and all the gaseous species in the flue gas is achieved. In addition, the gas temperature and gas velocity are also made uniform. The flue gas then flows through the beds of catalyst material, in which the NOx is converted in accordance with the chemical reactions described above. Previous NOx emissions data from the continuous emissions monitors on the boiler showed NOx emissions = 0.26 lb NOx/MMBtu firing wood chips without any add-on NOx pollution controls. The combination of the EcoJet system, SNCR, and SCR will remove approximately 65 to 75% of NOx emissions in order to meet the lb NOx/MMBtu emission limit to qualify for renewable energy credits in Connecticut, and possibly other New England states. FACILITY DESCRIPTION The Springfield Power facility in Springfield is a small electric power generating facility, producing 16 megawatts electricity net rated capacity. The Springfield Power facility has a 220 MMBtu/hr wood-fired boiler, which is a Babcock & Wilcox design, spreader stoker vibrating grate type boiler with an associated Cooling Tower. In addition, the facility has a 625 HP chipper motor and a 470 HP diesel generator that provides emergency power to the facility. There is also a small emergency diesel fire pump rated at 2.4 MMBtu/hr gross heat input rate (187 HP) located at the facility for fire prevention. This facility is a major source for NOx and CO emissions and currently operates under Title V Operating Permit TV-OP- 016 issued on September 1, The Title V Operating Permit was transferred to Springfield Power (via an administrative permit amendment) on November 7, The facility has requested approval (through this temporary permit application) to install a Selective Non-Catalytic Reduction (SNCR) System with an Ecojet overfire air system and a Selective Catalytic Reduction (SCR) System to reduce emissions of nitrogen oxides from the Wood-Fired boiler. The facility commenced operation in 1987 and has been in operation since that time. PROCESS/DEVICE DESCRIPTION Table 1 Significant Activities Emission Unit Number Description of Emission Unit Install Date Manufacturers Rated Maximum Design Capacity EU1 Babcock and Wilcox Wood-fired Boiler Serial No Maximum Firing Rate MMBTU/hr for wood equivalent to: a) 160,000 lb/hr of steam averaged over 24-hour period at 900 F and 885 psig; and b) 252,000 tpy for wood chips at 55% moisture. 1. Maximum Firing Rate MMBTU/hr equivalent to 31.2 gal/hr 2. Rated Output HP EU2 Caterpillar 3412 Diesel Chipper Engine 1987 Serial No EU3 Cummins Diesel Emergency Generator Serial No Maximum Firing Rate MMBTU/hr equivalent to 25.5 gal/hr 2. Rated Output HP 3. EU3 shall be limited to less than 500 hours during any consecutive 12-month period.

3 AFS #: Application #: FY Date: March 4, 2008 Page 3 of 12 Table 1 Significant Activities Emission Unit Number Description of Emission Unit Install Date Manufacturers Rated Maximum Design Capacity EU4 Cummins Diesel Fire Pump Serial No EU5 Cooling Tower 1987 The facility is a true minor source of HAP emissions. 1. Maximum Firing Rate MMBTU/hr equivalent to 17.5 gal/hr; 2. Rated Output HP 3. EU4 shall be limited to less than 500 hours during any consecutive 12-month period. 1. Drift Factor = %; and 2. Circulation Rate = 11,473 gpm POLLUTION CONTROL EQUIPMENT Pollution Control Equipment ID Table 2: Pollution Control Equipment/Method Identification Description of Equipment/Method for Primary Pollutants Controlled Each Emission Unit PC1 Multiclone Primary Particulate Matter Control for EU1 PC2 Electrostatic Precipitator (ESP) Secondary Particulate Matter Control for EU1 PC3 Selective Catalytic Reduction (SCR) Nitrogen Oxides (NOx) System PC4 Selective Non-Catalytic Reduction (SNCR) System Nitrogen Oxides (NOx) Below is a brief discussion of key operating parameters for each of the four pieces of air pollution control equipment for the wood-fired Boiler and the facility s targeted operating parameter ranges for maintaining the pollutant removal efficiencies required to meet emissions limitations contained in this operating permit. Please note that the Tables 6A and 6B Compliance Assurance Monitoring (CAM) 40 CFR 64 in the facility s current Title V Operating Permit contain a more detailed listing of the key indicators of operation of the multiclone and ESP, including the indicator ranges and performance criteria (data representativeness, QA/QC practices, monitoring frequency, data collection procedures, and averaging periods). Multiclone Pressure differential or pressure drop measured = difference between the inlet pressure and outlet pressure. Too high of a differential pressure indicates the multiclone is plugged. The facility operates the multiclone in the 2 to 5 inch water column range for optimum large particulate matter removal. Pressure differential (pressure drop) is measured continuously and recorded once per shift. An excursion outside the 2 to 5 inch range triggers an inspection, corrective action, and a reporting requirement. When differential pressure measurements are outside of the 2 to 5 inch range, an alarm goes off and qualified personnel perform an inspection of the multiclone to determine if there is an operational problem that needs to be corrected. Pressure gauges/transmitters are calibrated bi-annually. Annual inspections and maintenance shall be performed according to O/M checklists, which include inspecting the inlet and outlet vanes and boots for any kind of buildup of caked dust and removal of the caked dust if it is present. Once per shift inspections are conducted checking for any apparent abnormalities or damage that would cause air leakage into the unit, with maintenance performed as needed. See Table 6B in the Title V Operating Permit for the compliance assurance monitoring (CAM) requirements for the multiclone.

4 AFS #: Application #: FY Date: March 4, 2008 Page 4 of 12 Electrostatic Precipitator Secondary voltage applied to the plates of the electrostatic precipitator (ESP) is the key operating parameter. The optimum secondary voltage operating range has been determined to be between 15 and 60 kilovolts. Voltage readings outside this range indicate a malfunction of the ESP and require immediate operator correction. Operators monitor this operating parameter and record their observations once per shift. Observations of operating parameters outside these ranges are recorded, investigated, and corrected immediately. Operators are required to inspect the ESP once per shift. The casing, piping, and ducts are inspected for leaks, abnormal noise, hot spots, and fires. Selective Catalytic Reduction (SCR) System & Selective Non-Catalytic Reduction (SNCR) System Ammonia flow and the SCR system catalyst bed temperature are the two key operating parameters for NOx removal. The optimum SCR catalyst bed temperature ranges between 350 to 650 degrees F. Ammonia flow to the combustion zone for the SNCR and to the SCR is critical to removal of NOx and its addition rate is dependent on the heat input of the Boiler and good mixing of air for combustion in the combustion zone of the Boiler. Once the boiler is in operation, the facility may develop typical ammonia flow (gal/hr) to outgoing NOx (lb/hr) ratio setpoints for optimum NOx removal. Boiler Visible Emissions Check Operators make daily visible emissions observations of the Boiler and air pollution control equipment serving the Boiler to check for leaks in any of the components and abnormal Boiler operation. If visible emissions are detected, plant personnel take corrective actions or perform a Method 9 opacity observation to determine compliance with the opacity limits of 20 and 27% opacity. Plant personnel record the information concerning the visible emissions observation in a logbook and corrective actions taken, if any. EMISSION CALCULATIONS Table 3: Emissions from Wood Boiler Heat input 220 MMBtu/hr Wood chips usage in ,084 tons/yr Wood chip max usage 251,922 tons/yr Moisture content of fuel 50 % 220 MMBtu/hr/ MMBtu/lb = 57,516 lb/hr = 251,922 tpy of wood Pollutant Emission Factor (lb/mmbtu) Emission Factor (lb/ton) lb/hr Actual tpy tpy ( ) ( ) PT (controlled)* SO NOx** CO** VOC (total) * Emission factor from stack test done on 5/27/04 ** Factor based on CEM data All other emission factors are AP-42 (5th ed) Values highlighted in blue are facility-wide permit limits taken to limit potential to emit (to maintain synthetic minor PSD program status for NOx, CO).

5 AFS #: Application #: FY Date: March 4, 2008 Page 5 of 12 Table 4: Emissions from Wood Chipper Engine 624 HP Heat input 4.29 MMBtu/hr Fuel usage in ,195 gal/yr Fuel flow rate 31.3 gal/hr Fuel HV Diesel lb/hr tpy** Pollutant EF lb/kgal Actual tpy ( ) PT SO NOx* CO* VOC * Stack test done on 7/18/01 ** emissions are based on 500 hr/yr All other emission factors are AP-42 (5th ed) Table 5: Emissions from Emergency Generator Engine 470 HP Heat input 3.49 MMBtu/hr Fuel usage in gal/yr diesel Fuel flow rate 25.5 gal/hr Fuel Diesel MMBTU/gal Pollutant EF lb/kgal Actual tpy lb/hr tpy* ( ) PT SO NOx** CO VOC * emissions based on 500 hr/yr. ** DES emission factor used in lieu of AP-42 factor for NOx

6 AFS #: Application #: FY Date: March 4, 2008 Page 6 of 12 Table 6: Emissions from Fire Pump 187 HP Heat input 2.40 MMBtu/hr Fuel usage in gal/yr diesel Fuel flow rate 17.5 gal/hr Fuel Diesel MMBTU/gal Actual tpy lb/hr tpy* Pollutant EF lb/kgal ( ) PT SO NOx CO VOC * emissions based on 500 hr/yr. ** DES emission factor used in lieu of AP-42 factor for NOx Table 7: Facility-Wide Emissions Pollutant 2006 Actual tpy tpy PT SO NOx * CO * VOC * Facility-wide synthetic minor limits taken for PSD avoidance 1. Hazardous Air Pollutants (regulated under Section 112, Clean Air Act) Based on data obtained from previous stack testing at this facility for hydrogen chloride and from testing performed at another comparably-sized boiler (Bridgewater Power Co.) for benzene, acrolein, and styrene, it was concluded that the facility is a true minor source of HAPs. 2. Emissions from Cooling Towers a. Particulate Matter Conductivity = 20,000 micro-ohms Circulation rate = 11,473 gpm or MMgal/day Total liquid drift = % or lb drift/kgal, based on EPA AP-42 emission factors. (Eq 1): Conductivity * 2/3 is essentially TDS in ppm 20,000 micro-mhos * 2/3= ppm TDS= ppm/1x10 6 = fraction of TDS in water

7 AFS #: Application #: FY Date: March 4, 2008 Page 7 of Emissions from Cooling Towers (cont d) (Eq 2): Annual Drift= Circulation rate* Drift factor = 11,473 gpm * 60 min/hr * 8760 hrs/yr * 7.3x10-5 lb drift/gal = 440,190 lb drift/yr or 1,206 lb drift/day (Eq 3): PM emissions = Annual Drift * TDS = 440,190 lb drift/yr * = lb/yr = 2.86 tpy b. Regulated Toxic Air Pollutants (Env-A 1400) Sulfuric Acid Drift Losses H 2 SO 4 Consumption: 1,500 gal/yr or 4.1 gal/day % by wt of H 2 SO 4 =93% Daily drift = 1,206 lb drift/day TDS (H 2 SO 4 concentration in ppm) = Daily consumption/daily flow rate = = (4.1 gal/day*0.93)/ MMgal/day = 0.23 ppm Daily H 2 SO 4 emissions = Daily drift * TDS = = 1,206 lb drift/day*(0.23 ppm/1x10 6) = 2.8x10-4 lb/day Sodium Hydroxide Drift Losses Caustic Soda consumption: 4,000 gal/yr or gal/day 50% by wt of NaOH Inhibitor AZ8104 consumption: 1,000 gal/yr or 2.74 gal/day 100%by wt of NaOH Daily Drift: 1,206 lb drift/day TDS (NaOH concentration in ppm) = {(10.96 gal/day*0.5) gal/day}/ MMgal/day = ppm Daily NaOH emissions = Daily drift * TDS = 1,206 lb drift/day *0.498 ppm/1x10 6 = 6.0x10-4 lb/day Table 8: Summary of RTAP Emissions from Cooling Tower CAS # Compound Emissions lb/day Emissions lb/yr 24-hr Deminimus lb/day Sulfuric Acid 2.8x Annual Deminimus lb/yr Sodium Hydroxide 6.0x Conclusion: Based on the above analysis, RTAP emissions from the cooling towers are below the respective daily and annual deminimus values listed in Env-A 1400.

8 AFS #: Application #: FY Date: March 4, 2008 Page 8 of 12 STACK INFORMATION Stack # Emission Unit # Table 9: Stack Information Minimum Stack Height Above Base Elevation (Ft) Maximum Stack Diameter or (Ft) Stack 1 Boiler Stack 2 Chipper Diesel Engine MODELING An ambient air dispersion modeling analysis is not required as part of this permit application. Emissions of criteria pollutants will not increase, and NOx (and potentially CO) emissions are expected to decrease. The one new pollutant that will be emitted as a result of this project is ammonia. Ammonia may be emitted in small amounts as a result of ammonia slip from excess, unreacted ammonia used in the SNCR/SCR reactions. The applicant demonstrated compliance with the daily and annual ambient air limits (AALs) established for ammonia under Env-A 1400, Regulated Toxic Air Pollutants. Modeling was not required for this demonstration, as the applicant was able to demonstrate compliance by calculating the adjusted in-stack concentration of ammonia and showing that it was below both the daily and annual AALs. The ammonia slip emission limit of 20 parts per million equates to an in-stack concentration of 14,000 ug/m3. Using a dilution factor of 400 (as provided for in Env-A ), the adjusted in-stack calculation was determined to be 35 ug/m 3, well below the daily and annual AALs of 100 ug/m 3. Therefore, ammonia emissions will be in compliance with the requirements of Env-A The Wood-fired Boiler was previously modeled. This modeling showed no exceedances of the National Ambient Air Quality Standards for criteria pollutants. EMISSION TESTING Ammonia slip testing is required for demonstrating compliance with the 20 ppmvd at 6% oxygen emission limit. After the initial performance test, ammonia slip testing will be done on an annual basis. The facility conducted emissions testing on May 27, 2004 in order to determine if it was a major source of federal hazardous air pollutants (HAPs). Hydrogen chloride has the highest emission rate from wood-fired boilers of all the HAPs and hence, this facility and all of the other wood-fired Boilers in the state conducted testing for hydrogen chloride. In addition, Bridgewater Power (a similarly sized wood boiler) had testing conducted for benzene, acrolein, and styrene. The results from the test at Bridgewater Power should be representative of HAP emissions from Springfield Power. Emissions test results are listed in the Table below. Table 10: Wood-Fired Boiler Stack Test Data Pollutant Emissions from Boiler lb/mmbtu Emissions from Boiler lb/hr Particulate Matter Hydrogen Chloride Benzene Acrolein Styrene <0.004 <0.004 Based upon these emissions tests and use of NCASI and USEPA AP-42 emissions factors for hazardous air pollutants, the facility is a true minor source of HAPs.

9 AFS #: Application #: FY Date: March 4, 2008 Page 9 of 12 EMISSIONS MONITORING EQUIPMENT 40 CFR 60 Subpart Db requires Springfield Power to operate a continuous opacity monitoring system (COMS). In that the facility is choosing to limit its potential to emit NOx and CO below the major source thresholds of 250 tpy, respectively, by accepting federally enforceable emissions limitations below these thresholds, DES has determined it is necessary to require continuous emissions monitoring systems for NOx and CO and diluent gas, O2 or CO2, to ensure that these emissions limitations are not violated, as provided for by Env-A (a)(2) Applicability. SITE VISITS/INSPECTIONS Date Description 07/26/07 On-site full compliance evaluation. No problems noted during this full compliance evaluation of this facility (the facility was under the prior ownership at time of inspection). 06/01/05 Off-site full compliance evaluation. No problems noted with the facility s recordkeeping. Facility is complying with all of their permit terms and conditions (was under the prior ownership at time of inspection). REPORTS/FEES Annual Emission Reports DES received the 2006 annual emissions report on March 26, Below is a summary Table of facility wide emissions for 2002 through PT (tons) SO2 (tons) NOx (tons) CO (tons) VOC (tons) Total (tons) Fees The facility is up to date on reporting and payment of emission based fees. PERMITTING HISTORY 1. On April 7, 1999, Title V Permit (TV-OP-016) was issued to Thermo Ecotek Corporation for Hemphill Power and Light facility for the following devices: a. Wood-fired Boiler; b. Emergency diesel generator; and c. Diesel chipper engine. 2. On November 15, 1999, the Title V permit was amended to correct typographical errors in the designation of authority for conditions 6, 7, and 8 in Sec. VIII.C. The three conditions (Env-A , (e)(2) and (f) were moved to State-Only Section. 3. On April 13, 2000, the Title V permit was amended to correct typographical errors in the numbering scheme on pg 11, Sec. VIII.C. and the General Title V Operating Conditions. 4. On June 26, 2001, the Title V permit was amended to reflect the change in the name of the owner/operator and technical contact on pg On November 16, 2001, the Title V permit was amended to reflect the change in the parent company from Hemphill Power and Light to AES Ecotec Holdings LLC.

10 AFS #: Application #: FY Date: March 4, 2008 Page 10 of On November 1, 2007, DES granted a waiver to Springfield Power to allow them to construct concrete footings for the proposed NOx control equipment before ground freezes (construction is at the risk of the applicant in the event that a permit is not granted for this equipment). 7. On November 7, 2007, the Title V permit was amended to reflect the change in ownership from AES Ecotec Holdings LLC to Springfield Power, LLC. KEY CHANGES FROM PREVIOUS PERMIT a. Addition of Selective Non-Catalytic Reduction and Selective Catalytic Reduction systems for NOx control. b. Added the ammonia slip emissions limit of 20 ppmvd at 6% oxygen. REVIEW OF REGULATIONS State Regulations Env-A 305 & 306 Applicable to Boiler (EU1) Primary and Secondary Air Quality Standards for CO. Env-A (a)(1) Applicable facility wide Facility is a true minor source of SO2 and VOC emissions, i.e., facility wide potential emissions of SO2 are below 100 tons per year and potential emissions of VOC are below 50 tons per year. Env-A (n) Applicable to EU1 and facility wide A temporary permit is required for a stationary source choosing to limit its potential to emit by accepting enforceable permit conditions. Env-A (q) Applicable to EU1 A temporary permit is required for a device subject to new source performance standards contained in 40 CFR 60. Env-A (x) Applicable to EU1 A temporary permit is required for a device subject to RACT requirements. EU1 is subject to NOx RACT requirements contained in Env-A Env-A 619 & 40 CFR 52.21(b)(1)(i)(b) (PSD avoidance) Applicable facility wide - DES has included 250 tpy NOx and CO emission limits facility-wide to keep the facility out of the PSD program requirements contained in 40 CFR Env-A 700 Applicable Facility Wide Emissions-based fees Env-A 800 Applicable to EU1 - Stack testing and CEM/COM requirements Env-A 900 Applicable Facility Wide Owner and Operator Recordkeeping and Reporting Requirements Env-A 1000 Applicable Facility Wide Prevention, Abatement, and Control of Open Source Air Pollution Env-A 1211 Applicable to EU1 NOx RACT Requirements Env-A 1400 Applicable to EU1 Regulated Toxic Air Pollutants program requirements - The adjusted in-stack concentration method was used to verify compliance with Env-A 1400 for ammonia emissions from the SCR and SNCR. Also, RTAPs emitted from the cooling tower were previously verified to be in compliance with Env-A Env-A 1600 Applicable Facility Wide Sulfur Content in Fuel Requirements Env-A 2000 Applicable Facility Wide Opacity and particulate matter emissions limitations Env-A 3700 Not applicable. While the facility has an emergency generator, this rule exempts emergency generators.

11 AFS #: Application #: FY Date: March 4, 2008 Page 11 of 12 RSA 125-I:5 IV Applicable facility wide If DES revises its values of ambient air limits for regulated toxic air pollutants for a compound that is emitted by the facility, e.g., for ammonia, the owner or operator is required to file a permit application within 90 days of this change being filed in the state register. Federal Regulations 40 CFR 52.21(b)(1)(i)(b) Applicable to EU1 Prevention of Significant Deterioration (PSD) program avoidance limits of 250 tpy for NOx and CO emissions to stay out of this program. 40 CFR 60 Appendix B Applicable to COM and CEMs on EU1 Performance Specifications for COMS and CEMs 40 CFR 60 Subpart Db New Source Performance Standards (NSPS) for Industrial-Commercial-Institutional Steam Generating Units that commence construction, modification, or reconstruction after June 19, 1984 and that has a heat input capacity from fuels combusted in the steam generating unit of greater than 100 MMBtu/hr Applicable to EU1, since it was constructed and operated after this date. 40 CFR 60 Subpart A Section 60.11(d) General Provisions of 40 CFR 60 Applicable to EU1 General operation and maintenance requirements. 40 CFR 60 Subpart A Section 60.7(b) General Provisions of 40 CFR 60 Applicable to EU1 Keep records of each startup, shutdown, and malfunction for the Boiler and any of its air pollution control equipment. 40 CFR 60 Subpart A Section 60.7(f) - General Provisions of 40 CFR 60 Applicable to EU1 NSPS General Recordkeeping Requirements 40 CFR 60 Subpart Db Section 60.42b Not applicable to EU1 SO 2 emissions limits are not applicable to facilities that fire less than 10% very low sulfur oil (less than 0.5% by weight). 40 CFR 60 Subpart Db Section 60.43b(c)(1) Applicable to EU lb PM/MMBtu total suspended particulate matter emission limit 40 CFR 60 Subpart Db Section 60.43b(f) Applicable to EU1-20% opacity limit and allowance for one continuous 6- minute period in any 60-minute period of 27% opacity. 40 CFR 60 Subpart Db Section 60.43b(g) & 60.46b(a) Applicable to EU1 Particulate matter and opacity standards do not apply during periods of startup, shutdown, or malfunction 40 CFR 60 Subpart Db Section 60.44b Not applicable to EU1 Nitrogen oxide emissions limits do not apply to EU1 because it has an annual capacity factor of less than 10% for fuel oil and on-spec used oil allowed by (j) and (k). 40 CFR 60 Subpart Db Section 60.48b(a) & (e)(1) Applicable to EU1 Continuous opacity monitoring (COM) system requirements for the boiler and span value for the opacity COM shall be between 60 and 80 percent 40 CFR 60 Subpart Db Section 60.49b(d) Applicable to EU1 Daily records of fuel consumption by the boiler 40 CFR 60 Subpart Db Section 60.49b(e) Applicable to EU1 Maintain records of nitrogen content in fuels 40 CFR 60 Subpart Db Section 60.49b(f) Applicable to EU1- Maintain records of opacity monitoring for 5 years from the date of measurement, this is because our state regulation Env-A requires records kept 5 years versus the less stringent 2 year requirement of 40 CFR 60.

12 AFS #: Application #: FY Date: March 4, 2008 Page 12 of CFR 63 National Emissions Standards for Hazardous Air Pollutants (NESHAP) - Not applicable Facility Wide The facility is a true minor source for HAPs. Therefore, Subpart DDDD for Industrial, Commercial and Industrial Boilers and Process Heaters and Subpart ZZZZ for Stationary Reciprocating Internal Combustion Engines are not applicable to the facility. Stack tests conducted for this facility and similar facilities (i.e., wood fired boilers) showed that AP-42 emission factors (Chapter 1.6, Wood Residue Combustion, Table 1.6-3) substantially overestimate the HAP emissions from wood-fired boilers. For example, the AP-42 emission factor for Hydrochloric acid is lb/mmbtu. The stack test conducted at the facility in May 2004 showed that HCl emissions were on the order of lb/mmbtu. Stack test conducted on June 10, 2004 at the Bridgewater Power facility provided the following emission rates for HAPS: Benzene = lbs/hr [compare this to 4.2 x lbs/mmbtu (AP-42 factor) x 250 MMBTU/hr = 1.05 lbs/hr]; Acrolein = lbs/hr [compare this to 4.0 x lbs/mmbtu (AP-42 factor) x 250 MMBTU/hr = 1 lbs/hr]; Styrene = lbs/hr [compare this to 1.9 x lbs/mmbtu (AP-42 factor) x 250 MMBTU/hr = lbs/hr]. Hence based on stack test results at comparable wood-fired boiler facilities, the Springfield Power facility is not a major source for HAPs. 40 CFR 64 Compliance Assurance Monitoring (CAM) Applicable to EU1 for particulate matter. CAM requirements are contained in the facility s current Title V Permit. NON-ATTAINMENT NEW SOURCE REVIEW (NSR) AND PREVENTION OF SIGNIFICANT DETERIORATION (PSD) PROGRAMS The Non-Attainment New Source Review (NSR) program does not apply to this Boiler, as it is an existing unit and the proposed modification will not result in any increases in emissions of criteria pollutants. For purposes of the PSD program, the uncontrolled potential to emit for criteria pollutants CO and TSP are above the 250 tons per year threshold from the wood-fired Boiler. However, the facility has a multiclone and electrostatic precipitator in place for particulate matter control and stack testing on May 27, 2004 has confirmed the unit emits lb TSP/MMBtu gross heat input rate, which translates to a controlled potential to emit of 15.7 tpy TSP. With respect to CO emissions, the facility initially installed a fuel distribution system, over-fire air control system, and under-grate air control system for optimum control of CO emissions, operates the Boiler as efficiently as practical, and has never exceeded 250 tpy CO emissions since startup of the unit. Hence, the PSD program requirements in Env-A 619 and 40 CFR do not apply to the facility. SUMMARY AND CONCLUSIONS Springfield Power has demonstrated that it meets all applicable regulations and DES has prepared a Temporary Permit for issuance to the facility.