Technical report No 29 The United States' Sulfur Dioxide Emissions Allowance Program: An Overview with Emphasis of Monitoring Requirements and Procedures and a summary report on U.S. experience with Environmental Trading Systems By: Jeffrey K. Mangis NorControl S.A. Infanta Mercedes, 31 28020 Madrid Spain Project Manager Paolo G. Meozzi European Environment Agency © EEA, Copenhagen 1998 Table of Contents The United States' Sulfur Dioxide Emissions Allowance Program: An Overview with Emphasis of Monitoring Requirements and Procedures..........................................................................................4 1. Introduction......................................................................................................................................................................4 2. Overview of the Program................................................................................................................................................4 3. Effected Units and the Allocation of Allowances...........................................................................................................4 4. Startup of Monitoring......................................................................................................................................................5 5. Basic Monitoring Requirements......................................................................................................................................5 5.1 Sulfur Dioxide.............................................................................................................................................................5 5.2 Oxides of Nitrogen.......................................................................................................................................................6 5.3 Carbon Dioxide...........................................................................................................................................................7 5.4 Opacity........................................................................................................................................................................8 5.5 Heat Input.....................................................................................................................................................................8 6. Quality Assurance............................................................................................................................................................9 6.1 Mechanical Provisions for Testing..............................................................................................................................9 6.2 Performance requirements...........................................................................................................................................9 6.2.1 Daily Calibration Test........................................................................................................................................10 6.2.2 Daily Linearity Check.........................................................................................................................................10 6.2.3 Relative Accuracy Test Audit (RATA)..............................................................................................................10 6.2.4 Bias Test.............................................................................................................................................................11 7. Certification and Recertification..................................................................................................................................11 8. Missing Data Procedures...............................................................................................................................................12 8.1 Initial Missing Data Procedures for SO2...................................................................................................................12 8.2 Initial Missing Data Procedures for NOX and Flow..................................................................................................12 8.3 Standard Missing Data Procedures for SO2..............................................................................................................13 8.4 Standard Missing Data Procedures for NOX and Flow.............................................................................................14 9. Submitting Data..............................................................................................................................................................15 Appendix................................................................................................................................................19 .............................................................................................................................................20 FACILITY INFORMATION ......................................................................................................................................................21 MONITORING DATA POLLUTANT GAS CONCENTRATIONS.....................................................................................................................21 DILUENT GAS CONCENTRATIONS...........................................................................................................................21 MOISTURE DATA.........................................................................................................................................................22 VOLUMETRIC FLOW....................................................................................................................................................22 DAILY CALIBRATION AND INTERFERENCE CHECK DATA AND RESULTS......................................................22 REFERENCE METHOD BACKUP QA DATA..............................................................................................................23 UNIT DATA.......................................................................................................................................................................25 UNIT OPERATING DATA.............................................................................................................................................25 SO MASS EMISSIONS..................................................................................................................................................26 2 NO EMISSION RATE....................................................................................................................................................28 x CO MASS EMISSIONS.................................................................................................................................................30 2 ....................................................................................................................................31 CONTROL EQUIPMENT DATA SO CONTROL EQUIPMENT OPERATING PARAMETERS......................................................................................31 2 NO CONTROL EQUIPMENT PARAMETERS............................................................................................................31 X QUALIFYING PHASE I SO CONTROL EQUIPMENT PARAMETERS.....................................................................31 2 ........................................................................................................................33 MONITORING PLAN INFORMATION ..........................................................................................................36 CERTIFICATION TEST DATA AND RESULTS CALIBRATION/ERROR TESTS....................................................................................................................................36 LINEARITY CHECKS....................................................................................................................................................36 LEAK CHECKS..............................................................................................................................................................36 RATA/BIAS TESTS........................................................................................................................................................37 CYCLE/RESPONSE TIME.............................................................................................................................................39 .....................................................................................................................................................40 TEST INFORMATION FUEL FLOW CALIBRATION.........................................................................................................................................40 ....................................................................................................41 ALTERNATIVE MONITORING PETITION DATA ......................................................................................................................................42 APPENDIX E TEST RECORDS Emissions Trading Experience in the United States..........................................................................44 Air Pollution Trading Programs........................................................................................................................................44 Nationwide Air pollution Trading Programs.....................................................................................................................44 Acid Rain Allowance Trading: Cap-and-Trade/Budget Program – Nationwide...........................................................44 CFC Production Allowance Trading: Cap-and-Trade/Budget Program – Nationwide..................................................45 Regional Air Emissions Trading Programs.......................................................................................................................46 NESCAUM/MARAMA: Cap-and-Trade/Budget Program – Northeastern and Midatlantic States............................46 OTC/OTAG Regional NOx Reduction Program: Cap-and-Trade/Budget Program – Northeastern U.S........................46 Open Market Trading: Command and Market – Regionally Around the U.S..................................................................47 Lead Credit Trading: Command and Market – Regionally Around the U.S....................................................................47 Trading of Gasoline Constituents: Command and Market – Regionally Around the U.S................................................47 Heavy Duty Truck Engine Emissions Trading: Command and Market – Regionally Around the U.S.............................48 Hazardous Air Pollutants (HAPs) Trading – Early Reduction: Command and Market – Regionally Around the U.S....48 Hazardous Air Pollutants Trading (HAPs) – Petroleum Industry NESHAPS: Command and Market – Regionally Around the U.S.................................................................................................................................................................48 Hazardous Air Pollutants Trading (HAPs) – HON NESHAPS: Command and Market – Regionally Around the U.S...48 State Air Pollution Trading Programs..............................................................................................................................49 Regional Clean Air Incentives Market (RECLAIM): Cap-and-Trade/Budget Program – California............................49 Alternative Control Plan (ACP) Regulation: Command-and-Market Program – California.........................................49 Interchangeable Air Pollution Reduction Credits: Command-and-Market Program – California..................................50 New Source Review (NSR): Command-and-Market Program - California..................................................................50 Project SEED (Solutions for the Environment and Economic Development: Command-and-Market Program – California.........................................................................................................................................................................50 Credits for the Voluntary Repair of On-Road Motor Vehicles Identified through Remote Sensing Devices: Command- and-Market Program - California..................................................................................................................................51 Old Vehicle Scrapping: Command-and-Market Program – California..........................................................................51 Credits for Clean On-Road Vehicles: Command-and-Market Program – California.....................................................51 Credits for Clean Off-Road Vehicles: Command-and-Market Program – California....................................................52 Credits for Clean Lawn and Garden Equipment: Command-and-Market Program – California....................................52 Banking of Mobile Source Emission Reduction Credits (MERCs): Command-and-Market Program – California.......52 SCRAP South Coast Recycled Auto Program: Command-and-Market Program – California.......................................52 Generic Emissions Trading and Banking: Command-and-Market Program – Colorado................................................53 Wood Stove Permit Trading: Command and Market – Colorado, Regionally................................................................53 NOx Emissions Reduction Credit Trading Program: Command-and-Market Program – Connecticut...........................53 Emission Banking and Trading Program: Command-and-Market Program - Delaware.................................................53 Clean Fueled Fleets Program: Command-and-Market Program – Georgia....................................................................54 Chicago Emissions Reduction Credit Banking and Trading Program: Command-and-Market Program - Illinois.........54 Illinois Accelerated Vehicle Scrappage Program: Cap-and-Trade/Budget Program - Illinois......................................55 VOM Emissions Trading System: Cap-and-Trade/Budget Program – Illinois...............................................................55 Regulations on Control of Emissions through the use of Emission Reduction Credit Banking: Command-and-Market Program – Louisiana.......................................................................................................................................................56 Innovative Market Program for Air Credit Trading (IMPACT): Command-and-Market Program – Massachusetts......56 Offset Trading Program: Command-and-Market Program – Maine..............................................................................57 Emission Trading Program: Command-and-Market Program – Michigan.....................................................................57 Discrete Emissions Reductions Trading Program: Command-and-Market Program – New Hampshire........................58 Open Market Emissions Trading: Command-and-Market Program – New Jersey.........................................................58 NSR Emission Offset Program: Command-and-Market Program – New York..............................................................58 Nitrogen Oxides Allowance Requirements: Cap-and-Trade/Budget – Pennsylvania.....................................................59 Accelerated Vehicle Retirement Program: Command-and-Market Program – Texas....................................................59 Area Emission Reduction Credit Organizations (AERCOs): Command-and-Market Program – Texas........................60 Emissions Banking Program: Command-and-Market Program – Texas.........................................................................60 Texas Clean Fleet Program: Command-and-Market Program – Texas..........................................................................61 Grass Burning Permit Trading: Command and Market – Washington.............................................................................62 Emissions Trading Program: Command-and-Market Program – Wisconsin..................................................................62 The United States' Sulfur Dioxide Emissions Allowance Program: An Overview with Emphasis of Monitoring Requirements and Procedures 1. Introduction This paper provides a succinct overview of the SO2 trading program with particular emphasis on the emissions monitoring program. Accurate monitoring is the essential foundation of the SO2 trading program. It is also the most complex and costly component of the trading program. Assigning and trading allowances is elementary, but it is no simple task to monitor the several thousand effected utility units. Trading places an economic value on emissions and emission reduction, increasing the need for accurate monitoring. The consequence monetary value is a requirement for continuous emissions monitoring, with redundant capacity. This summary reviews the SO2 program with specific emphasis on the monitoring procedures required to accomplish SO2 trading. Many details are omitted, however, as the procedures for monitoring are exceedingly complex, particularly in the application of the general rules to complex configurations. The only definitive reference is Section 40 of the US Code of Federal Regulations, Part 75 (p. 3701-3766), and the body of documents issued by the EPA Acid Rain Division (part of the Office of Air and Radiation) to expand and clarify the rules. 2. Overview of the Program The SO2 trading program in the US is the most successful market based environmental program to date. The concept is simple. A total annual emissions budget (measured in tons of SO2) was established by Congress for the year 1995 and every year following. The emissions level declines in a number of steps from 1995 through 2020, then remains flat subsequent to 2020. Emissions allowances (in the form of one ton certificates) are issued to generating units on the basis of their emissions in 1985, for each year from either 1995 onward for 200+ units or 2000 onward for 2000+ units. The number of allowances quickly falls short of the emissions that would occur without measures to reduce emissions. Emissions are monitored continuously. At the end of the each year, the emissions for each unit are totaled. The owner of the unit must then surrender an allowance for each ton of SO2 emitted. The allowance may be a current year allowance (one issued for the year in which the emissions occurred) or a prior year allowance that was banked (not used in a prior year). Substantial, but not punitive fees are incurred if sufficient allowances can be produced. The key to the program is that allowances can be traded between units. In this way, units that have cost efficient control options can reduce their emissions below the allowance level, and sell their excess allowances to units that can not find economical ways to meet the requirements. In this way, investments can be made where they can do the most good, more capital is available for sensible environmental projects, and there is no need to retire aging facilities soley because of prohibitive environmental costs. Trading promotes efficient use of capital. This, of course, is a very simple overview of the acid rain program. Every stack and duct of every large coal and oil fired unit in the US has at least one monitor each for SO2, NOX, flow rate, and either O2 or CO2. Every monitoring plan was reviewed and approved before acceptance by the EPA and before the equipment was installed. Once installed, each system went through a lengthy series of certification tests. Every monitor is calibrated daily. All calibration data and all monitoring data are recorded electronically along with a vast amount of other operations data that can be used to check the monitoring results. All of the monitoring data (30 gigabytes annually) are submitted to EPA electronically every quarter, upon which, every record is checked within a day of its arrival at EPA. More than 200 checks are performed looking for simple formatting problems, uncorrected calibration errors, errors in calculating emissions, or failure in applying the complex missing data substitution algorithm. The EPA engages in an active dialog with the operators of all of the effected units to work out problems in data collection and submission to obtain the most accurate data possible. At the end of year, each unit's operator identifies allowances to offset the final tally of emissions from his facility. 3. Effected Units and the Allocation of Allowances Allowances are allocated for each year beginning in 1995. The SO2 allowance program is directed at generating "units". A unit in this case combustor or set of combustors driving a generator. In Phase I, EPA allocates allowances to each unit at an emission rate of 2. 5 pounds of SO2/mmBtu (million British thermal units) of heat input, multiplied by the unit's baseline mmBtu (the average fossil fuel consumed from 1985 through 1987). Alternative or additional allowance allocations are made for various units, including affected units in Illinois, Indiana, and Ohio, which were allocated a pro rata share of 200,000 additional allowances each year from 1995 to 1999. In Phase II, which begins in the year 2000, the limits imposed on Phase I plants are tightened, and emissions limits are also imposed on smaller, cleaner units. Allowance allocation calculations are made for various types of units, such as coal and gas-fired units with low and high emissions rates or low fuel consumption. EPA allocates allowances to each unit at an emission rate of 1. 2 pounds of SO2/mmBtu of heat input, multiplied by the unit's baseline. During Phase II, the Act places a cap at 8. 95 million on the number of allowances issued to units each year. This effectively caps emissions at 8. 95 million tons annually and ensures that the mandated emissions reductions are maintained over time. In addition to annual allocations, allowances are also available upon application to three EPA reserves. In Phase I, units can apply for and receive additional allowances by installing qualifying Phase I technology (a technology that can be demonstrated to remove at least 90 percent of the unit's SO2 emissions) or by reassigning their reduction requirements among other units employing such technology. A second reserve provides allowances as incentives for units achieving SO2 emissions reductions through customer-oriented conservation measures or renewable energy generation. The third reserve contains allowances set aside for auctions, which are sponsored yearly by EPA. In addition, allowances are given as incentives for utilities that replace boilers with new, cleaner and more efficient technologies. The incentives also apply to small diesel fuel refiners that have exceeded the Clean Air Act requirements to remove sulfur from fuels. Units that began operating in 1996 or later will not be allocated allowances. Instead, they will have to purchase allowances from the market or from the EPA auctions and direct sales to cover their SO2 emissions. 4. Startup of Monitoring Monitoring requirements were phased in over a number of years. Covered units were divided into two groups. About 200 units were designated Phase I units. These were required to begin monitoring on November 15, 1993. Official tracking of emissions did not begin until January 1, 1994, allowing six weeks to utilities and the EPA to test their respective parts of the monitoring system together. The emissions offset program did not start until January 1, 1995 so the emissions data collected in 1994, while officially collected and recorded by the EPA, did not require allowances, so there was effectively no penalty for error. The Phase I units were large units owned by large utility companies. They were presumed to be better able to design and integrate the monitoring and data acquisition and handling systems. The Phase I period provided an opportunity for the more capable companies and for the equipment, computer, and information system providers to test and improve the individual components and integrated systems. It also provided the EPA with an opportunity to test and refine its systems to received, store, and validate the emissions data. The experience on both sides was absolutely essential to the startup of the program. Fully one third of the files received in the first round of submissions contained errors, and EPA processing was slow and difficult. Problems on both sides were largely resolved in time for the 1995 startup of the emissions program. The monitoring program was extended to over 2000 Phase II units on January 1, 1995, but emissions allowances are not needed until 2000. Despite the 10-fold expansion of the program, the expansion went relatively smoothly, in large measure due to the equipment vendors', the utilities', and the EPA's experience in Phase I. 5. Basic Monitoring Requirements The general monitoring requirements under the acid rain program are for sulfur dioxide (SO2), oxides of nitrogen (NOX), carbon dioxide (CO2) and opacity. All monitoring systems must have a cycle time of 15 minutes or less. The specific requirements are as follows: 5.1 Sulfur Dioxide The owner of an affected unit must install and operate an SO2 continuous emissions monitoring system consisting of: (cid:131)(cid:3)an SO2 concentration monitor, (cid:131)(cid:3)a flow monitor, and (cid:131)(cid:3)a data acquisition and handling system (DAHS) to (cid:224)(cid:3)record SO2 concentration in parts per million (ppm) (cid:224)(cid:3)record flow in cubic feet per hour (scfh), (cid:224)(cid:3)calculate SO2 mass emissions in pound per hour (lb/hr), and (cid:224)(cid:3)report the above data in the format specified in the next session of this report. When SO2 concentration is measured on a dry basis, the operator must either monitor and report the moisture content of the flue gas or correct the volumetric flow for moisture content on a continuous basis. Hourly, quarterly, and annual emissions are calculated according to the following formula: Eh = K * Chp * Qhr (100-%H2O) / 100 Where Eh = Hourly emissions (lb/hr) K = 1.660E-7 (lb/scf)/ppm Chp = Hourly average SO2 concentration, dry (ppm) Qhr = Hourly average volumetric flow rate, wet (scfh) %H2O = Hourly average stack moisture content (percent by volume) Emissions for the quarter and the year are the sum of emissions in each respective period. 5.2 Oxides of Nitrogen The owner of an affected unit must and operate a continuous NOX emissions monitoring system consisting of: (cid:131)(cid:3)A NOX concentration monitor, (cid:131)(cid:3)An O2 or CO2 diluent gas monitor, (cid:131)(cid:3)A data acquisition and handling system (DAHS) to (cid:224)(cid:3)record NOX concentration monitor in parts per million (ppm), (cid:224)(cid:3)calculate NOX emissions rates in pounds per million Btu (lb/mmBtu). The NOX emissions rates is calculated from the NOX concentration and diluent monitor as follows Case 1: O2 is the diluent E = K*Ck*F*(20.9/(20.9-PCTO2) there Where E = Emissions of NOX in lb/MMBtu K = 1.19E-7 (lb/dscf)/ppm NOX Ck = average hourly pollutant concentration in ppm PCTO2 = percent concentration of O2 F is fuel specific, defined in the table below Fuel F Factor (dscf/MMBtu) Anthracite Coal 10,100 Bituminous Coal 9,780 Subbituminous Coal 9,780 Lignite 9,860 Oil 9,190 Natural Gas 8,710 Propane 8,710 Butane 8,710 Wood Bark 9,600 Wood residue 9,240 F represents the ratio of the volume of the dry flue gas generated to the caloric heat content of the fuel combusted. Note that all measurements must be on a dry basis or converted to a dry basis. Case 2: CO2 is the diluent E = K*Ck*Fc * (100/PCTCO2) Where: PCTCO2 = percent concentration of CO2 Fc is fuel specific, defined below. It represents a ratio of the volume of CO2 generated to the caloric content of the fuel combusted. Fuel Fc Factor (scf CO2 /MMBtu) Anthracite Coal 1,970 Bituminous Coal 1,800 Subbituminous Coal 1,800 Lignite 1,910 Oil 1,420 Natural Gas 1,040 Propane 1,190 Butane 1,250 Wood Bark 1,920 Wood residue 1,830 Units have the option of using an Fc factor calculated according to the formula below, if the table factor does not accurately represent their specific fuel. Fc = 3.21E5 * PctC / GCV where PctC = percent carbon content of the fuel GCV = gross calorific content of the fuel (Btu/lb) calculated according to ASTM1 standards specific to the fuel. Mixed Fuels If the unit burns a mixed fuel, the calculation is the same as described above for CO2 and O2 diluents, but the F and Fc factors are weighted average values, where the weighting factors are each fuel's fraction of GCV. If a unit burns different fuels (or mixes of fuels) at different times during the year, the emissions rate for the year is the weighted sum of the emissions rates for each fuel or mixture. The weighting factor is the fraction of the year each fuel or mixture of fuels is used. 5.3 Carbon Dioxide Each unit must have a system for monitoring or estimating CO2 emissions consistent using one of the following options: (cid:131)(cid:3)A CO2 continuous emissions monitoring system consisting of: (cid:224)(cid:3)A CO2 concentration monitor, (cid:224)(cid:3)A flow monitor, and a (cid:224)(cid:3)DAHS that records CO2 in ppm, records flow in scfh, and calculates CO2 mass emissions in tons/hour. (cid:131)(cid:3)Calculation of CO2 emissions based on the measured carbon content of the fuel (in tons per day) based on procedures describe later, or (cid:131)(cid:3)An O2 concentration monitor from which CO2 emissions are estimated by a procedure that will be described later. Case 1: when CO2 is measured on a wet basis Hourly emissions are calculated according to the following equation 1 American Society for Testing and Materials Eh = K*Ch*Qh Where : Eh = Hourly CO2 mass emissions (tons/hr) K = 5.7E-7 for Co2 ((tons/scf)/%CO2) Ch = Hourly average CO2 concentration, wet basis (%CO2) Qh = Hourly average volumetric flow rate, wet basis (scfh) Emissions for the quarter and year are the sum of the hourly emissions for the appropriate period. Case 2: When O2 is monitored using and O2 diluent monitor Hourly concentration is calculated according to the formula: CO2H = 100*(Fc/F)*((20.9-O2H)/20.9) Where: CO2H = Hourly percent CO2 concentration on a wet basis (% by volume) Fc & F = Values as listed for oxides of nitrogen above (dscf/MMBtu) O2H = Average hourly O2 concentration on a dry basis (% by volume) 20.9 5.4 Opacity Each unit must have a system to monitor the opacity of the flue gas and a DAHS to calculate and report percent capacity. 5.5 Heat Input The heat input from all fuels must be recorded for each hour or part of an hour that the unit is operating. For units with a flow monitor, different methods are used to calculate heat input depending on whether CO2 or O2 are measured and whether the measurements are on a wet basis of dry basis. The methods are listed below. Oil and gas units are not required to have flow monitors. When there is no flow monitor, heat content can be calculated from analysis of the fuels. Case 1: CO2 measurements on a wet basis Heat input is calculated as follows: HI = QW * (1/Fc) * (%CO2/100) Where HI = Heat input (mmBtu/hr) Qw = Average hourly flow rate, wet basis (scfh) Fc = Factor listed previously, specific to the fuel type %CO2w= Percent CO2 concentration on a wet basis Case 2: CO2 measurements on a dry basis HI = Qh*((100-$H2O)/(100&Fc)*(%CO2D/100) Where: HI = Heat input (mmBtu/hr) Qh = Average hourly flow rate, dry basis (scfh) Fc = Factor listed previously, specific to the fuel type %CO2d = Percent CO2 concentration on a dry basis Case 3: O2 measurements on a wet basis HI = Qw*(1/F)*(0.209*(100-%H20)-%O2w)/20.9 Where HI = Hourly heat input (mmBtu/hr) Qw = Hourly average flow rate, wet basis, (scfh) F = Dry basis F factor, listed previously, specific to the fuel type %O2w = Hourly concentration of O2 on a wet basis %H2O = Hourly percent moisture content by volume Case 4: O2 measurements on a dry basis HI = Qw* ((100-%H2O)/(100*F)) * ((20.9-%O2D)/20.9) Where HI = Hourly heat input (mmBtu/hr) Qw = Hourly average flow rate, wet basis, (scfh) F = Dry basis F factor, listed previously, specific to the fuel type %O2d = Hourly concentration of O2 on a dry basis %H2O = Hourly percent moisture content by volume 6. Quality Assurance Extensive requirements are established to insure they demonstrate the accuracy of the monitoring systems. The staring point is a quality control program. This must include a detailed, step-by-step procedure for: 1. Calibration error tests 2. Linearity check procedures 3. Adjustment of calibration 4. Adjustment of linearity 5. Preventive maintenance 6. Audit 7. Recordkeeping and procedures, and 8. Frequency of testing. 6.1 Mechanical Provisions for Testing Each Pollutant, CO2, and O2 monitor must be designed with a calibration gas injection port that allows for the entire measurement system to be checked when calibration as is introduced. For extraction and dilution type monitors, the test system must allow the evaluation of all components, including lines, scrubbers, filers, etc) that are exposed to the sample gas. For SO2, NOX, CO2, and O2, the test system must allow for testing over the entire range of the monitors. For flow monitors, the test system must allow for daily testing over 0% to 20% of span and 50% to 70% of span. Testing must be for all components form the probe tip to the data acquisition and handling system. The flow meter must have provisions to ensure that the entire range of moisture possible at the monitoring point will not interfere with the monitoring system. The system must be designed to allow detection pluggage of all lines and sensing ports, and possible malfunction of each resistance temperature detector. Differential pressure flow monitors must provide for an automatic period back purging of both lines or an equivalent measure of sufficient force to keep the lines sufficiently free of obstruction to obtain accurate measurements. The cleaning must be done on a daily basis. Thermal flow and ultrasonic monitors must include provisions to keep the problems sufficiently clean to maintain their accuracy. 6.2 Performance requirements Specific daily tests are set for each type of monitor. Each test must be passed once or more each day. A monitor which fails any test is deemed to be "out of control" and all data collected with it are not deemed to be quality assured until the monitor passes all tests. A monitor that passes all tests is deemed to be calibrated for the hour of the test and 23 successive hours. Operators may test more frequently than once a day. 6.2.1 Daily Calibration Test The maximum daily calibration error for SO2 and NOX monitors is 2.5% or 5ppm, whichever is greater. The maximum error for CO2 and O2 monitors is The maximum error for flow is 3.0%. Calibration error is calculated as follows: CE = 100 * Abs(R-A) / S Where CE = calibration error R = reference value of zero of high-level calibration gas A = actual measurement in response to calibration gas S = span of the instrument 6.2.2 Daily Linearity Check The linearity check measures the linear response of the monitors over the span range. Linearity error is defined as follows: LE = 100 * Abs(R-A) / R Where all variables are defined as for the calibration error. For SO2 and NOX, the maximum linearity error is the max of 5.0% for tests done with low, medium, and high concentration calibration gases. For monitors with a ranges of 200ppm for less, the monitor is deemed to have a passed the linearity test if Abs(R-A) is less than or equal to 5ppm. For CO2 and O2 monitors the linearity error must be less than 5% for all three calibration gases or the average of the three errors must be less than 0.5%. 6.2.3 Relative Accuracy Test Audit (RATA) The relative accuracy test specifies that the measurements of the continuous emissions monitoring system be consistent reference test methods. The standards by monitoring system are as follows: SO2 10.0% variance, except where the test value is less than or equal to 250ppm or, for SO2 diluent monitors, 0.5lb/mmBtu, in which case, the standard is +/1 15.0 ppm or +/- 0.03lb/mmBtu for diluent monitors NOX 10% variance or 0.02 lb/mmBtu, which ever is larger. CO2 10% variance Flow 15% until January 1, 2000, 10% thereafter except for flows of 10fps or less, in which case the allowable error is 2fps. O2 No comparable reference method test The relative accuracy is calculated as follows: 1. For a series of tests versus reference methods, calculate the arithmetic average of the differences between the measured and reference methods (d) 2. Calculate the standard deviation of the difference (Sd) 3. Calculate the 97.5% confidence level for the error using a T table, as follows: CC = T * Sd / Sqrt(N) Where T = t value for 0.025 from table below