Final Boiler MACT Rule Requirements Summary

Transcription

1 Federal Regulation: Final Boiler MACT Rule Requirements Summary NESHAP 40 CFR 63 Subpart DDDDD Proposed rule published 6/4/2010 Final rule signed 2/21/2011 Info at Affected Source: The affected source is: (1) the collection of all existing industrial, commercial, or institutional boilers or process heaters within a subcategory located at a major source facility that do not combust solid waste or (2) each new or reconstructed industrial, commercial, or institutional boiler or process heater located at a major source facility that do not combust solid waste, as that term is defined under RCRA. A boiler or process heater is new if you commence construction of the boiler or process heater after June 4, 2010, and you meet the applicability criteria at the time you commence construction. The affected source does not include boilers and process heaters that are subject to another standard under 40 CFR 63 or a standard established under CAA section 129. Exemptions: An electric utility steam generating unit (note that non-fossil fuel fired utility boilers and utility boilers <25 MW are covered). A recovery boiler or furnace covered by 40 CFR 63, subpart MM. A boiler or process heater that is used specifically for research and development. This does not include units that provide heat or steam to a process at a research and development facility. A hot water heater (<120 gal, <160 psig pressure, <210 F). A refining kettle covered by 40 CFR 63, subpart X. An ethylene cracking furnace covered by 40 CFR 63, subpart YY. Blast furnace stoves. Any boiler or process heater specifically listed as an affected source in another standard(s) under 40 CFR part 63. Any boiler or process heater that is used as a control device to comply with another subpart under Part 63, provided that at least 50 percent of the heat input to the boiler is provided by the gas stream that is regulated under another subpart. Temporary boilers (onsite less than 180 consecutive days). Blast furnace gas fuel-fired boilers and process heaters. Subcategories: (a) Pulverized coal/solid fossil fuel units. (b) Stokers designed to burn coal/solid fossil fuel. (c) Fluidized bed units designed to burn coal/solid fossil fuel. (d) Stokers designed to burn biomass/bio-based solid. (e) Fluidized bed units designed to burn biomass/bio-based solid. (f) Suspension burners/dutch Ovens designed to burn biomass/bio-based solid. (g) Fuel Cells designed to burn biomass/bio-based solid. (h) Hybrid suspension/grate burners designed to burn biomass/bio-based solid. (i) Units designed to burn solid fuel. (j) Units designed to burn liquid fuel. Page 1 of 10

2 (k) Units designed to burn liquid fuel in non-continental States or territories. (l) Units designed to burn natural gas, refinery gas or other gas 1 fuels. (m) Units designed to burn gas 2 (other) gases. (n) Metal process furnaces. (o) Limited-use boilers and process heaters. For the fuel based HAP (PM/mercury/HCl), if your new or existing unit combusts at least 10 percent solid fuel on an annual basis, your unit is subject to emission limits that are based on data from all of the solid fuel-fired combustor designs. If your new or existing boiler or process heater burns at least 10 percent biomass on an annual average heat input basis, the unit is in one of the biomass subcategories for CO and D/F. If your new or existing boiler or process heater burns at least 10 percent coal, on an annual average heat input basis, and less than 10 percent biomass, on an annual average heat input basis, the unit is in one of the coal subcategories for CO and D/F. If your new or existing boiler or process heater burns at least 10 percent liquid fuel (such as distillate oil, residual oil), and less than 10 percent solid fuel, on an annual heat input basis, the unit is in the liquid subcategory. If your facility is located outside of North America and your new or existing unit combusts at least 10 percent liquid fuel and less than 10 percent solid fuel, your unit is subject to the non-continental liquid fuel emission limits. If your unit combusts only natural gas, refinery gas, or equivalent fuel (other gas that qualifies as Gas 1 fuel), with limited exceptions for gas curtailment and emergencies, your unit is subject to a work practice standard that requires an annual tune-up in lieu of emission limits. Important Definitions: Biomass or bio-based solid fuel means any biomass-based solid fuel that is not a solid waste. This includes, but is not limited to, wood residue; wood products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust, sander dust, chips, scraps, slabs, millings, and shavings); animal manure, including litter and other bedding materials; vegetative agricultural and silvicultural materials, such as logging residues (slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut, rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean hulls and grounds. This definition of biomass is not intended to suggest that these materials are or are not solid waste. Boiler means an enclosed device using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water. Controlled flame combustion refers to a steady-state, or near steady-state, process wherein fuel and/or oxidizer feed rates are controlled. A device combusting solid waste, as defined in 241.3, is not a boiler unless the device is exempt from the definition of a solid waste incineration unit as provided in section 129(g)(1) of the Clean Air Act. Waste heat boilers are excluded from this definition. Coal means all solid fuels classifiable as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials in ASTM D388 05, Standard Classification of Coals by Rank (incorporated by reference, see 63.14), coal refuse, and petroleum coke. For the purposes of this subpart, this definition of coal includes synthetic fuels derived from coal for creating useful heat, including but not limited to, solvent-refined coal, coal-oil mixtures, and coal-water mixtures. Coal derived gases are excluded from this definition. Page 2 of 10

3 Electric utility steam generating unit means a fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is considered an electric utility steam generating unit. Gaseous fuel includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast furnace gas is exempted from this definition. Liquid fuel includes, but is not limited to, distillate oil, residual oil, on-spec used oil, and biodiesel. Limited-use boiler or process heater means any boiler or process heater that burns any amount of solid, liquid, or gaseous fuels, has a rated capacity of greater than 10 MMBtu per hour heat input, and has a federally enforceable limit of no more than 876 hours per year of operation. Metal process furnaces include natural gas-fired annealing furnaces, preheat furnaces, reheat furnaces, aging furnaces, heat treat furnaces, and homogenizing furnaces. Process heater means an enclosed device using controlled flame, and the unit's primary purpose is to transfer heat indirectly to a process material (liquid, gas, or solid) or to a heat transfer material for use in a process unit, instead of generating steam. Process heaters are devices in which the combustion gases do not come into direct contact with process materials. A device combusting solid waste, as defined in 241.3, is not a process heater unless the device is exempt from the definition of a solid waste incineration unit as provided in section 129(g)(1) of the Clean Air Act. Process heaters do not include units used for comfort heat or space heat, food preparation for on-site consumption, or autoclaves. Temporary boiler means any gaseous or liquid fuel boiler that is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A boiler is not a temporary boiler if any one of the following conditions exists: o o o o The equipment is attached to a foundation. The boiler or a replacement remains at a location for more than 12 consecutive months. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period. The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year. The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition. Emissions Limits and Work Practices: Emission limits were developed for new and existing sources for 15 subcategories, which EPA developed based on unit design. Fuel based emission limits for PM, HCl, Hg Fuel and boiler design based limits for CO, dioxin/furan Page 3 of 10

4 Limits for existing sources are based on top 12% of units for which EPA has data in subcategories with population greater than or equal to 30 units, and top 5 units in subcategories with population less than 30 units. Limits for new sources are based on the top performing unit in each subcategory. Variability was taken into account using a 99 percent upper prediction level (99.9 UPL for CO) and a fuel content variability adjustment for mercury and chloride. Emissions averaging is allowed for existing affected sources in the same subcategory (solid, liquid, or gas) for PM, HCl, and Hg, but the average emissions have to be within 90 percent of the allowable emissions. Facilities using this approach cannot increase emissions over emission levels achieved upon the effective date of the rule or begin using a less effective control technology than the technology that was in place upon the effective date of the rule. HAP/Fuel Proposal Final Proposal Final Units Output Based (lb/mmbtu steam output) Existing Boilers New Boilers Existing New Hg Biomass lb/tbtu 4.50E E-06 PM Biomass lb/mmbtu HCl Biomass lb/mmbtu Hg Coal lb/tbtu 4.50E E-06 PM Coal lb/mmbtu HCl Coal lb/mmbtu Hg Oil lb/tbtu 3.30E E-07 Hg Oil non-continental lb/tbtu 8.00E E-07 PM Oil lb/mmbtu HCl Oil lb/mmbtu Hg Gas lb/tbtu 7.80E E-07 PM Gas lb/mmbtu HCl Gas lb/mmbtu Hg Hg content content <40 <40 NA µg/m 3 NA µg/m 3 - NA NA Or clean gas 2 can opt in to Gas 1 work practice if prior to combustion: H 2S content <4ppmv H 2S content <4ppmv - NA NA CO Biomass stoker ppm at 3%O CO Biomass FB ppm at 3%O CO Biomass Dutch/ Suspension ppm at 3%O CO Biomass Fuel Cell ppm at 3%O CO Biomass Hybrid Suspension/ Grate NA 3500 NA 1500 ppm at 3%O Page 4 of 10

5 HAP/Fuel Proposal Final Proposal Final Units Output Based (lb/mmbtu steam output) Existing Boilers New Boilers Existing New CO Coal pulverized ppm at 3%O CO Coal stoker ppm at 3%O CO Coal FB ppm at 3%O CO Oil ppm at 3%O CO Oil non-continental ppm at 3%O CO Gas ppm at 3%O D/F Biomass stoker %O2 4.40E E-12 D/F Biomass FB %O2 1.80E E-11 D/F Biomass Dutch/ Suspension %O2 1.80E E-10 D/F Biomass Fuel Cell %O2 3.50E E-12 D/F Biomass Hybrid Suspension/Grate NA 0.2 NA 0.2 7%O2 1.80E E-10 D/F Coal pulverized %O2 3.70E E-12 D/F Coal stoker %O2 2.80E E-12 D/F Coal FB %O2 1.80E E-12 D/F Oil %O2 9.20E E-12 D/F Gas %O2 3.90E E-12 A work practice applies during periods of startup and shutdown. You must follow the manufacturer s recommended procedures for minimizing periods of startup and shutdown. The emissions and operating limits apply during malfunction periods. You may use the affirmative defense provision to justify excess emissions during malfunction periods that meet the 9 criteria in the rule. Limited-use boilers and process heaters must complete a biennial tune-up. They are not subject to the emission limits, the annual tune-up requirement, or the operating limits. Major sources that have limited-use boilers and process heaters must complete an energy assessment only if the source has other existing boilers subject to this subpart that are not limited-use boilers. Page 5 of 10

6 Work practices are required for all new and existing units less than 10 MMBtu/hr in size (biennial tune-up) and for all natural gas/refinery gas units and metal process furnace units (annual tune-up for gas units >10 MMBtu/hr). If the unit is not operating on the required date of the tune-up, it must be conducted within one week of startup. 1. Inspect the burner, and clean or replace any components of the burner as necessary (you may delay burner inspection until next scheduled unit shutdown, but must inspect burner at least once per 36 months), 2. Inspect the flame pattern, as applicable, and make any adjustments to the burner necessary to optimize the flame pattern consistent with the manufacturer s specifications, 3. Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly, 4. Optimize total emissions of CO consistent with the manufacturer s specifications, 5. Measure the concentrations in the effluent stream of CO in ppmv and O 2 in percent, before and after the adjustments are made, 6. Maintain a report containing the concentrations of CO in the effluent stream in ppmv, and oxygen in percent, measured before and after the adjustments of the boiler, a description of any corrective actions taken as a part of the combustion adjustment, and the type and amount of fuel used over the 12 months prior to the annual adjustment if the unit is capable of burning more than one fuel. As provided in 63.6(g), EPA may approve use of an alternative to the work practice standards in the rule. A beyond the floor requirement is also included for all existing major source facilities having affected boilers or process heaters that would require the performance of a one-time energy assessment by qualified personnel on the affected boilers and energy use system to identify any cost-effective energy conservation measures (cost effective means items having a payback period of 2 years or less). The facility must also implement an energy management program. Energy assessment means an in-depth assessment of a facility to identify immediate and longterm opportunities to save energy, focusing on the steam and process heating systems, which involves a thorough examination of potential savings from energy efficiency improvements, waste minimization and pollution prevention, and productivity improvement. Energy assessment for facilities with affected boilers and process heaters using less than 0.3 trillion Btu per year heat input will be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a one-day energy assessment. The Energy assessment for facilities with affected boilers and process heaters using 0.3 to 1.0 trillion Btu per year will be 3 days in length maximum. The boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a 3-day energy assessment. In the Energy assessment for facilities with affected boilers and process heaters using greater than 1.0 trillion Btu per year, the boiler system and any energy use system accounting for at least 20 percent of the energy output will be evaluated to identify energy savings opportunities. Page 6 of 10

7 Energy management program means the set of practices and procedures designed to manage energy use that are demonstrated by the facility s energy policies, a facility energy manager and other staffing responsibilities, energy performance measurement and tracking methods, an energy saving goal, action plans, operating procedures, internal reporting requirements, and periodic review intervals used at the facility. Testing Requirements for Units with Emission Limits: Affected sources must demonstrate initial compliance within 180 days of the compliance date or within 180 days of startup. Testing must be conducted during representative operating load conditions. Future operating load must not exceed 110 percent of load during testing. Sources that cease burning solid waste and become regulated under Boiler MACT must demonstrate initial compliance within 60 days of the effective date of the waste to fuel switch. (1) Conduct initial and annual stack tests to determine compliance with the PM emission limits using EPA Method 5 or 17. (Note that if a unit is >250 MMBtu and burns solid fuel or residual oil, PM CEMS are required, which require extensive calibration testing.) (2) Conduct initial and annual stack tests to determine compliance with the mercury emission limits using EPA method 29, 101A, or ASTM-D (Ontario Hydro Method). (3) Conduct initial and annual stack tests to determine compliance with the HCl emission limits using EPA Method 26A or EPA Method 26 (if no entrained water droplets in the sample). (4) Use EPA Method 19 to convert measured concentration values to pound per million Btu values. (5) Conduct initial and annual test to determine compliance with the CO emission limits using EPA Method 10. (6) Conduct initial test to determine compliance with the D/F emission limits using EPA Method 23. Conduct HCl and Hg performance tests while operating at representative operating load and burning the fuel mixture that has the highest content of Hg and chlorine (may have to do 2 tests). Develop maximum Cl and Hg fuel input limits based on fuel sampling and operating parameter monitoring ranges based on initial performance testing. If you are only burning one type of fuel, you are exempt from fuel sampling requirements. You can conduct performance stack tests less often for a given pollutant if your performance stack tests for the pollutant for at least 2 consecutive years show that your emissions are at or below 75 percent of the emission limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions. In this case, you can conduct a performance test every 3 years, but no more than 37 months after the last performance test. If a performance test shows emissions greater than 75 percent of the applicable emission limit, then you revert to annual performance testing for the next 2 years. The reduced testing frequency cannot be used if you are using emissions averaging. If you are demonstrating compliance using fuel analysis for mercury or HCl, fuel analysis must be performed monthly and before burning a new type of fuel. You are not required to conduct fuel analysis for fuels used only for startup, shutdown, or transient flame stability purposes. If 12 consecutive monthly fuel analyses demonstrate compliance, you may request decreased fuel analysis frequency by applying to the EPA Administrator for approval of alternative monitoring under 63.8(f). Page 7 of 10

8 If you are demonstrating that a gaseous fuel meets the H 2 S and Hg specifications of an other gas 1 fuel, you must conduct an initial fuel specification analysis. If your gas could vary above the specifications, you must conduct monthly testing and maintain records. Report results of all stack tests and fuel analyses within 60 days of completion. Stack test reports must verify that operating limits have not changed or provide documentation of revised operating limits. Results must be reported to the EPA s online ERT. Use of Output Based Limits and Emission Credits from Energy Conservation Measures You can comply with the output based emission limits and take credit for implementing energy conservation measures identified in the energy assessment. To use this approach, you must establish an emissions benchmark, calculate and document the emission credits, develop an implementation plan, comply with the general reporting requirements, and apply the following emission credit procedures: Establish a benchmark for each affected boiler in terms of trillion Btu per year heat input. The benchmark is established for the one-year period prior to the energy demand reduction. Determine the starting point from which to measure progress. Inventory all fuel purchased and generated onsite. Document all uses of energy from the affected boiler. Collect data to normalize the benchmark to current operations. Emissions credits can be generated if the energy conservation measures were implemented after January 14, 2011 and if sufficient information is available to determine the value of the credits. Boilers that are shutdown cannot be used to generate credits. Credits are generated by the difference between the benchmark that is established for each boiler and the actual energy demand reductions. The credit is equal to the energy input savings divided by the baseline energy input. Adjusted emission level for each boiler = (measured emissions, lb/mmbtu)x(1-credit) Operating Limits: Control Device Wet scrubber control Fabric filter control (for sources not using PM CEMS) ESP (dry control system, sources not using PM CEMS) ESP (followed by wet scrubber, sources not using PM CEMS) Operating Limits Minimum 12-hour average pressure drop and liquid flow is 90 percent of performance test average (3-hour average for sources using emissions averaging); For HCl control, minimum 12-hour average ph is 90 percent of performance test average. Operate bag leak detection system and fabric filter such that alarms are less than 5% of the operating time during a semi-annual period, initiate corrective action within 1 hour of an alarm; OR Maintain daily block average opacity <10% Maintain daily block average opacity <10% Minimum 12-hour average voltage and current or 12- hour average minimum power is 90 percent of performance test average Dry scrubber Minimum 12-hour average sorbent injection rate is 90 percent of performance test average (adjusted for load) Page 8 of 10

9 Control Device Operating Limits Carbon injection Minimum 12-hour average sorbent injection rate is 90 percent of performance test average (adjusted for load) Other dry control system (sources Maintain daily block average opacity <10% not using PM CEMS) Operating load (if demonstrating Maintain 12-hour average operating load at or below 110 compliance using stack testing) percent of load during performance test Oxygen concentration (for boilers Measure the oxygen concentration in the flue gas during and process heaters that are the initial CO and dioxin/furan performance test. The subject to a CO and a dioxin/furan lowest hourly average oxygen concentration during the emission limit) most recent performance test is your operating limit, and your unit must operate at or above your operating limit on a 12-hour average basis. Fuel analysis option Maintain fuel type or fuel mixture such that the calculated emission rate is less than the applicable emission limit. For units combusting coal, biomass, or residual oil with heat input capacities of 250 MMBtu/hr or greater, PM CEMS must be installed and operated such that PM levels (30-day rolling average) are maintained below the applicable PM limit. If PM CEMS are used, no PM pollution control device or opacity operating parameter limits apply. Operating above established maximum or below established minimum operating limits is a deviation except during performance tests conducted to determine compliance with the emission limits or to establish new operating limits. Development of Plans: Site specific monitoring plan Site specific test plan Site specific fuel analysis plan Emissions averaging plan (if applicable) Output based limits emission credits implementation plan (if applicable) Continuous Compliance/Monitoring Requirements: Continuously monitor control device parameters for which operating limits have been developed, 12-hour block averages. For boilers subject to CO and D/F limits, must install an O2 CEMS, 12-hour averaging period for operating limit. For solid fuel or residual oil-fired boilers with dry control devices not using PM CEMS or bag leak detectors, install COMS and maintain opacity <10%, daily block average. If burning multiple fuels, maintain fuel mixture Hg and Cl content at or below the maximum fuel input levels established during initial performance test. For boilers >250 MMBtu/hr burning coal, biomass, or residual oil, must install a PM CEMS, 30-day averaging period. Follow applicable plans, including QA requirements for monitoring systems. Notifications: Page 9 of 10

10 Initial Notification no later than 120 calendar days after you become subject to the rule (even if you submitted one under the 2004 rule); Notification of intent to conduct performance test at least 60 days prior to any compliance demonstration; Notification of compliance status within 60 days of completion of any compliance demonstration; For natural gas fired units that intend to fire an alternative fuel during a curtailment period or supply interruption, a Notification of alternative fuel use within 48 hours of the declaration of a period of natural gas curtailment of supply interruption. For boilers that choose to commence or recommence burning solid waste, must provide 30 day notice. If you intend to switch fuels and change subcategories, provide 30 days notice. Recordkeeping Requirements: Records demonstrating compliance with above requirements. Records documenting malfunctions and deviations. Hours of operation for each limited use unit. Monthly fuel use records. Documentation that you are not burning solid waste. Owners or operators of sources with units with heat input capacity of less than 10 MMBtu/hr, units combusting natural gas or other clean gas, metal process furnaces, and limited use units must keep records of the dates and the results of each required boiler tune-up. Page 10 of 10

11 COMPARISON OF FINAL FEB 2011 BOILER MACT LIMITS TO JUN 2010 PROPOSED BOILER MACT LIMITS Output Based Factor Factor Proposal Final Proposal Final Units (lb/mmbtu steam HAP/Fuel Better Better output) Existing Boilers New Boilers Existing New Hg Biomass lb/tbtu 4.50E E-06 PM Biomass lb/mmbtu HCl Biomass lb/mmbtu Hg Coal lb/tbtu 4.50E E-06 PM Coal lb/mmbtu HCl Coal lb/mmbtu Hg Oil lb/tbtu 3.30E E-07 Hg Oil non-continental lb/tbtu 8.00E E-07 PM Oil lb/mmbtu HCl Oil lb/mmbtu Hg Gas lb/tbtu 7.80E E-07 PM Gas lb/mmbtu HCl Gas lb/mmbtu Or clean gas 2 can opt in to Gas 1 work practice if: NA Hg content <40 ug/m3 H 2 S content <4ppmv NA Hg content <40 ug/m3 H 2 S content <4ppmv - NA NA - NA NA CO Biomass stoker CO Biomass FB CO Biomass Dutch/ Suspension CO Biomass Fuel Cell CO Biomass Hybrid Suspension/ Grate NA 3500 NA NA 1500 NA CO Coal pulverized CO Coal stoker CO Coal FB CO Oil CO Oil non-continental CO Gas ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O ppm at 3%O D/F Biomass stoker D/F Biomass FB D/F Biomass Dutch/ Suspension D/F Biomass Fuel Cell D/F Biomass Hybrid Suspension/Grate NA 0.2 NA NA 0.2 NA D/F Coal pulverized D/F Coal stoker D/F Coal FB D/F Oil D/F Gas %O2 4.40E E-12 7%O2 1.80E E-11 7%O2 1.80E E-10 7%O2 3.50E E-12 7%O2 1.80E E-10 7%O2 3.70E E-12 7%O2 2.80E E-12 7%O2 1.80E E-12 7%O2 9.20E E-12 7%O2 3.90E E-12 Follow manufacturer's recommended procedures for minimizing periods of startup and shutdown. Emission limits are 30-day averages where CEMS are used (e.g., PM CEMS for residual oil or solid fuel units >250 MMBtu/hr).

12 Comparison of Emission Limits between CISWI and Major Boiler Rules Major Boiler Limits CISWI Limits for ERUs HAP/Fuel Final Final Units Final Final Units Higher Higher Existing New Existing New Existing New Hg Biomass lb/tbtu lb/tbtu MACT MACT PM Biomass lb/mmbtu lb/mmbtu CISWI CISWI HCl Biomass lb/mmbtu lb/mmbtu MACT MACT Hg Coal lb/tbtu lb/tbtu MACT MACT PM Coal lb/mmbtu lb/mmbtu CISWI CISWI HCl Coal lb/mmbtu lb/mmbtu MACT MACT Hg Oil lb/tbtu lb/tbtu MACT CISWI Hg Oil noncontinental lb/tbtu lb/tbtu CISWI MACT PM Oil lb/mmbtu lb/mmbtu CISWI CISWI HCl Oil lb/mmbtu lb/mmbtu CISWI CISWI Hg Gas lb/tbtu lb/tbtu MACT MACT PM Gas lb/mmbtu lb/mmbtu CISWI CISWI HCl Gas lb/mmbtu lb/mmbtu CISWI CISWI CO Biomass stoker ppm at 3%O ppm at 3%O2 CISWI CISWI CO Biomass FB ppm at 3%O ppm at 3%O2 CISWI MACT CO Biomass Dutch/ Suspension ppm at 3%O2 ppm at 3%O2 CISWI MACT CO Biomass Fuel Cell ppm at 3%O ppm at 3%O2 MACT MACT CO Biomass Hybrid Suspension/ Grate ppm at 3%O2 ppm at 3%O2 MACT MACT CO Coal pulverized ppm at 3%O ppm at 3%O2 MACT CISWI CO Coal stoker ppm at 3%O ppm at 3%O2 MACT CISWI CO Coal FB ppm at 3%O ppm at 3%O2 MACT CISWI CO Oil 10 3 ppm at 3%O ppm at 3%O2 CISWI CISWI CO Oil noncontinental ppm at 3%O ppm at 3%O2 MACT MACT CO Gas2 9 3 ppm at 3%O ppm at 3%O2 CISWI CISWI D/F Biomass stoker D/F Biomass FB D/F Biomass Dutch/ Suspension D/F Biomass Fuel Cell D/F Biomass Hybrid Suspension/Grate D/F Coal pulverized at 7%O2 at 7%O at 7%O at 7%O D/F Coal stoker D/F Coal FB D/F Oil D/F Gas at 7%O at 7%O at 7%O at 7%O at 7%O at 7%O %O2 CISWI CISWI 7%O2 CISWI MACT %O2 MACT MACT %O2 MACT CISWI 7%O2 MACT MACT 7%O2 CISWI CISWI 7%O2 CISWI CISWI 7%O2 CISWI CISWI 7%O2 MACT CISWI 7%O2 CISWI MACT

13 Health based Compliance Approach How Major Issues are Addressed in the Final Boiler MACT Rule Issue Recommendation Outcome Include for both HCl and Mn and allow facility specific assessment using look-up table Source based limits instead of pollutant by pollutant Combination boilers (biomass and coal) Dioxin work practice Performance Variability Subcategorization Biomass Look at boiler performance holistically and not HAP by HAP for PM, Hg, and HCl Apply biomass limits for combustion byproducts (CO/D/F) and coal limits for fuel contaminant HAPs (Hg, PM and HCl) Replace limits set below limit of detection with good combustion practices; we don t know how to predict or control D/F Raise various limits to account for greater variability in fuels, designs, processes and products based on new emission data. Use CO CEMS data to set limits to account for CO variability. Adopt additional subcategories for limited use, dry/wet biomass, coal types, liquid types. Don t disadvantage biomass boilers Rejected citing lack of data on co-located sources and need to set standard, specifically reject Mn limit Support HAP by HAP, criticize source based and toxicity weighting; acknowledge control conflicts but other changes improve achievability Biomass and coal merged for fuel based HAPs into a solid fuel subcategory; combustion based HAPs in biomass subcategories when burning >10 biomass no matter how much coal Had to set D/F limit because had some detects. Initial compliance test then set 90% of average oxygen concentration during initial test as ongoing limit (also for CO), must follow good combustion practices; non-detects from Method 23 treated as zero. Rejects focusing only on the congeners specifically listed as HAP because all D/F are POM and POM is a listed HAP. Not using other data sources, only stack test data; looked at fuel variability factor (no control efficiency adjustment and different outlier consideration); considered load for CO using 99.9 UPL; new data increasing limits; more use of fuel analysis (Hg oil); don t have CEM data for CO thus stack tests (CO CEMS requirement gone) 15 now (12 before). Did not add subcategories by coal or liquid type. Combined biomass/coal into one solid fuel subcategory for fuel based HAPs. Added non-continental (for refineries), limited use (tune up only), and hybrid suspension grate (bagasse). Helped by merger with coal for fuel based HAPs scrubbers no longer needed for all biomass boilers. Page 1 of 5

14 Issue Recommendation Outcome Retain natural gas work practices and expand to Gas II units Gas work practices Energy Audits Limit of Detection Biased Data Set Data quality Realistic new source limits Surrogates Set TSM limit Drop audits as unjustified Adjust limits by three fold to account for practical quantitation limits of methods for Hg and D/F Use alternative statistical approaches that reflect biased HAP testing and data base. Augment with other available data. Found many errors in data set. Set achievable limits that do not discourage investment in new systems. Need to be able to get guarantees from vendors. Retain existing PM, HCl and CO surrogates, but set more reasonable CO limits (ultra low CO doesn t guarantee ultra low HAP) Work practices for natural gas, refinery gas and other equivalent clean gases (Hg <40 ug/m 3 and H 2 S <4 ppmv); Remaining Gas 2 has limits; all new and existing <10 MMBTU boilers have work practices One time energy audit but ongoing energy management program required; set duration and requirements for energy saving opportunities 1. <0.3 trillion Btu/yr look at 50% of output, 1 day max length to 1 trillion look at 33% of output, 3 days max length 3. >1 trillion - examine 20% of energy output Cost effective energy conservation measure has 2 year payback. Can take credit for recent audits. Inappropriate to set floor below MDL; if floor is >3x representative MDL then limit OK, otherwise set at 3x representative MDL. 99% UPL still except 99.9% for CO; using Bhaumik-Gibson approach; mix of confidence intervals; blame industry for not doing more testing, use available data; reject idea that always need at least 5 sources in floor EPA has developed memo cataloguing all changes made to database. Some higher, a few lower still set on a pollutant by pollutant basis from lowest emitting boilers in subcategories, still likely unachievable as a whole. Kept proposed surrogates, did not propose any others (e.g., THC, TSM), replaced CO CEMS and ongoing D/F testing with O2 CEMS. Considered measurement capabilities of Method 10, used 99.9 UPL to improve CO limits. Set metals standard in No TSM limits, no Mn HBCA addition to PM limit; also critical to Mn HBCA Page 2 of 5

15 Issue Recommendation Outcome Size cutoffs Raise cutoffs from 10 to Stayed at 10, but added work practices for 30 MM Btu new units <10 MMBtu/hr (were subject to Emission Averaging Averaging Periods SSM CO load issue Encourage by eliminating discount factor and allowing averaging for all pollutants across all subcategories Averaging periods for CPMS should be longer, 30 day averaging for CEMS good Include exemptions for SSM If use CO CEMS, can t meet limits during SS due to high O2. Exclude data at <50% load from compliance. limits in proposal) Kept discount factor, no averaging with new units; averaging only within subcategory but solid fuel category will allow coal-biomass averaging for fuel based HAP Retained 30 day averaging for CEMS, only 12-hour averaging for CPMS. For startup/shutdown follow manufacturer s procedures for minimizing time during startup/shutdown, affirmative defense for malfunction. Only using stack test data to set limits. Used 99.9UPL to increase variability. No more CO CEMS only O2 monitoring as operating parameter limit. CEMS Drop or restrict PM CEMS for >250 MMBtu/hr solid fuel and residual oil units maintained (but 30 day avg instead of daily); no CO CEMS (O2 monitoring instead) One MACT No double coverage Agreed boilers that are affected sources in other MACTs are exempt, also specified that boilers burning streams as control devices for other MACTs are exempt as long as those streams make up 50% of heat input. Flexibility Provide other options for limits, like % reduction Did not have enough data for % reduction option. Added output based option so facilities can take credit for efficiency improvements pound per MMbtu of steam output., but not sure at this point who benefits. Page 3 of 5

16 Issue Recommendation Outcome Costs Costs are understated by factor of two Still understated by factor of two; EPA says $5.1 billion, ($1.8 billion annually, $400M less with energy savings) and URS estimates $11B (EPA refutes URS detailed points, with higher Hg limits activated carbon not likely, CO catalyst proprietary so could not include, still assuming packed bed scrubbers). Little cost assigned to new Job Impacts Benefits Tune ups Allowance for oil firing during curtailment Boiler design ERT Compliance timeframe Argued significant jobs at risk due to potential mill closures due to higher costs Should not claim PM and SO2 benefits for MACT rule Should not tune based on CO. May not shut down annually to accommodate tune up. Procedures specified may not apply to all units. Should not limit the amount of oil that a gasfired boiler can burn during curtailment. Boilers are not designed to burn one fuel. ERT should not be required A longer timeframe for compliance should be required. units EPA claims job gains for pollutant controls and operation offset losses (2000 gained); using macro model based on old information and fails to disaggregate forest products industry $22-55 billion in benefits (17-41 before); include SO2 and VOC/ozone benefits in addition to PM (SO2 still biggest value); 2,500 to 6,500 lives saved Requirement is to record beginning and ending CO, not minimize CO. Frequency still annual for units >10 MMBtu/hr. Agreed no limit to oil firing during natural gas curtailment, just keep records and report. Boilers can be considered single fuel if they have a different startup fuel than that fired during normal operations. Solid fuel boilers have been combined into one category for the fuel based HAP. ERT is required No additional time is given. Page 4 of 5

17 Issue Recommendation Outcome Solid waste Units should be able to switch back and forth between 112 and 129 depending on whether they are burning solid waste. Incidental burning of solid waste should be allowed. CPMS QA/QC Requirements are too onerous, should be site specific Definitions Refinery gas and natural gas Fuel analysis Should not be required for each supplier, only for each fuel type. If not stack testing, monthly fuel analysis is too frequent, with limits so low no one will be able to use. Stack Testing Definition of EGU Annual testing should not be required, not necessary when continuous monitoring is performed. Should be allowed to test one unit if representative of many. Four hour runs not necessary. Specify handling of non-detects. Need to make clear what units are covered here and what units covered under Utility MACT Units can come back under 112 if they stop burning solid waste but can only go back and forth every 6 months. Incidental burning of solid waste is not allowed. Requirements for QA/QC for CPMS are still specified, rather than left to site specific monitoring plans. Added definition of refinery gas, corrected definition of natural gas. Sampling is now required per fuel type, not per fuel supplier. Still monthly fuel analysis. With better HCl and Hg limits more facilities may be able to use instead of stack testing. Initial test only for D/F. Can test every 3 years if <75% of the limit for the first 2 years of testing, unless you are using emissions averaging then testing still annual. No allowance for similar units. Test run time of 4 hours for everything not specified in final rule, but sample volumes are. D/F non-detects can be zero. New limitation to operate below 110% of load during compliance test. Electric utility steam generating unit means a fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A fossil fuel fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is considered an electric utility steam generating unit. They did not specify net output as requested. Biomass utility boilers will be under this rule. Page 5 of 5