Implementation of US Cap and Trade Programs Travis Johnson - US EPA Santiago, Chile May 2009

Accurate Emission Values Emission measurements are the “gold standard” underlying traded allowances It is important that a ton of emissions at one source is equal to a ton of emissions at any other source. A level playing field for participants in the program Strong foundation upon which a market can operate Establishes integrity of currency Assures accountability & results Provides accurate information for future regulations

Emissions Measurement Goals Complete accounting of mass emissions with no underestimation Consistent measurements Continuous improvement Cost effectiveness Efficient, effective, and consistent administration Transparency and public access to data

Good Data Quality Accuracy Quality Assurance Availability Accessibility and Timeliness Accuracy – The required accuracy of the monitoring method should be identified in the program regulation either directly or by reference to performance specifications or consensus standards. Quality Assurance – The program regulation should include quality assurance requirements to ensure continuing data quality after the installation of the monitoring equipment. The requirements can specify ongoing quality assurance testing performed by the sou7rc, and/or the development by the source of quality control/quality assurance plan that describes quality assurance testing and activities. Availability – The program regulation should stipulate data availability specifications for the measurement method. For a CEMS, and example availability requirement would be to provide valid hourly average data for 95% or more of the unit’s operating hours during a year. For mass emission programs, the regulation should also specify what substitute values to use when quality assured data are not available. Accessibility and Timeliness – The emissions data should be accessible in a timely manner. The program regulations should specify recordkeeping and reporting requirements for emissions data.

Reporting requirements Hourly data SO2, NOX, and CO2 (or O2) concentrations Heat input Operating Time Operating load (MWh) Oil and gas fuel flow Stack Volumetric Flow Rate Quality assurance test data Monitoring system certifications and maintenance event data Fuel data Control equipment information Facility information (industry codes, boiler types) Monitoring plans (methodologies and equipment)

Monitoring process EPA specifies measurement methodologies and QA/QC requirements Equipment performance standards Quality assurance tests Documented procedures and methodologies Mechanisms to solve unique monitoring and reporting issues Sources develop monitoring plan consistent with selected measurement methodology Sources install, certify, and maintain measurement equipment EPA audits and verifies all emission data Electronic audit of every hour of emissions reported Independent field audits (random and targeted) Sources report emission and activity data to EPA SO2, NOX, CO2 emissions; heat input; operating load (MWh); fuel consumption Quality assurance test data Monitoring plans Sources perform QA/QC testing for measurement equipment at prescribed intervals Emphasize monitoring plan

Monitoring Options (Flexibility) These are the Allowable Monitoring Options… If an Affected Unit is Classified as… CEMS Mass Balance Load-based Emission Factors Emission Factors Coal-fired √ Oil- or gas-fired units Oil- or gas-fired low-emitting units 36% of the units must use Continuous Emissions Monitors (CEMS) - but this accounts for 96% of the total SO2 emissions Methods with less accuracy or greater uncertainty use conservative methods that do not underestimate emissions

Load Based Emission Factors This methodology provides an alternative to CEMS for determining SO2 CO2, and NOx emissions. To qualify for use: Must be gas-fired or oil-fired (no solid fuels) SO2 emissions ≤ 25 tons per year, and NOx emissions < 100 tons per year Demonstration: In each of the 3 years immediately preceding the year of the application, the SO2 and NOx emissions did not exceed the annual and or seasonal threshold limits. Emissions data from historical CEMS must be used, where these data are available, In the absence of historical CEMS, conservative and reliable estimates of the unit’s emissions for the previous 3 years (or ozone seasons) must be provided, or An enforceable permit restriction. The estimates may be based on on records of unit operation, fuel usage, representative emission test data, CEM data, fuel sampling data, etc. Conservative default values may also be used in the calculations (e.g., the rates from Tables LM-1 through LM-3 in §75.19, the unit’s maximum rated heat input, etc. For units with less than 3 years of operating history, projected emissions estimates may be used. Annual Qualification: If the source exceeded the threshold, the unit can no longer use the emission factor methodology, must install CEMS by the following year. May qualify again with three years of CEMS data. CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors SO2,NOx, and CO2 Default emission factors based on either fuel type or combustion technologies or site-specific default emission rates determined in accordance with established procedures. Heat Input Maximum rated unit heat input for each hour Long Term Fuel Flow Heat Input Method Fuel Flow Fuel billing records, prescribed fuel measurement procedures (i.e., tank drop), or an acceptable fuel flowmeter GCV Accepted sampling and analysis procedures, or default GCVs Mass emissions = Emission Rate x Hourly heat input (kg) (kg/mmBtu) (mmBtu) CEMS Mass Balance Load Based Emission Factors Emission Factors

Load-based Emission Factors To Determine: NOx emission rate To qualify for use Oil- or gas-fired; or low operation (peaking unit). Peaking unit An average annual capacity factor of 10% or less over the past three years, and An annual capacity factor of 20% or less in each of those three years Annual capacity factor The ratio of the unit’s actual annual electrical output to the nameplate capacity times 8,760; or The ratio of the unit’s actual annual heat input to the maximum design heat input times 8,760. CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors NOx Correlation Curve NOx Testing at four evenly spaced loads Over entire operation range Average of three tests at each load level Determine heat input from fuel heat content samples and a fuel flow meter Monitor the unit operating time and parameters indicative of the unit’s NOx formation characteristics (e.g., water-to-fuel ratio) For boilers – Methods 7E and 3A, for turbines – Method 20 CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors Quality Assurance Parameter Monitoring Hourly monitoring of the parameters tht were monitored during the baseline emission testing (i.e., excess O2 for boilers) If the parametric data is missing, invalid or outside the acceptable ranges, missing data substitution must be used. Re-testing Once every 5 years, or If a different mixture of fuel is used QA Plan The data and results from the initial and most recent NOx emission rate testing, including the parametric data, A written record of the procedures used to perform the NOx emission rate testing, and The parameters that are monitored and the acceptable values and ranges of those parameters. CEMS Mass Balance Load Based Emission Factors Emission Factors

This methodology provides an alternative to CEMS for determining Mass Balance This methodology provides an alternative to CEMS for determining emissions. To qualify for use: Must be gas-fired or oil-fired (no solid fuels) Mass balance can be cost effective and accurate when Fuel composition is uniform, Fuel use is easily measured, and Products of combustion are well known. CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors SO2 Mass Balance Principle: SO2 mass emissions = Fuel flow rate * fuel sulfur content * units conversion factor * unit operating time Heat input = Fuel Flow Rate * heat content * conversion factor Requires Monitoring of: Hourly Fuel Usage (fuel flowmeters) Heat content and Sulfur content of the fuel CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors Fuel Flow Rate Hourly averages of fuel flow Meters must be certified to meet an accuracy of 2.0% of the upper range value By design (i.e., orifice, nozzle, or venturi) Measurement under laboratory conditions In-line comparison against a reference “master meter” flowmeter Billing meter may be used without certification CEMS Mass Balance Load Based Emission Factors Emission Factors

Fuel Flow Rate Quality Assurance Accuracy recertification every 4 calendar quarters, unless… The measured fuel is burned less than 168 hours per quarter The optional flow-to-load ratio test is performed and passed For orifice-, nozzle-, and venturi-type flowmeters Transmitter or transducer accuracy test every 4 “operating quarters” (i.e., a calendar quarter with over 168 hours of fuel use) Primary element visual inspection every 12 calendar quarters Unit Load Fuel Flow Rate 10% Can be used to extend the interval between fuel accuracy tests to up to 5 years CEMS Mass Balance Load Based Emission Factors Emission Factors

Load Based Emission Factors Gaseous Fuel Sampling For natural gas, annual sampling of the total sulfur content is required, or the maximum total sulfur content specified in the fuel contract (often 20 gr/100 scf). The heat content of natural gas must be determined monthly, with certain exceptions for units that operate infrequently. For other gaseous fuels transmitted by pipeline, the required frequency of total sulfur sampling is hourly, unless the results of a 720-hour demonstration show that the fuel qualifies for less frequent (i.e., daily or annual) sampling. The heat content of other gaseous fuels transmitted by pipeline must be determined daily, or hourly unless the fuel is demonstrated to have a low GCV variability, in which case monthly sampling is sufficient. For other gaseous fuels delivered in shipments or lots, each shipment or lot must be sampled for sulfur content and GCV. Acceptable ASTM Methods CEMS Mass Balance Load Based Emission Factors Emission Factors

Gaseous Fuel Sampling

Load Based Emission Factors Oil Sampling Daily Sampling, or Composite sampling for up to 168 hours, using hourly flow-proportional sampling or drip sampling, or Sampling after each addition to the tank, or Sampling each delivery CEMS Mass Balance Load Based Emission Factors Emission Factors

Monitoring Methodologies Summary Pollutant Option SO2 Mass Emissions 1. SO2 concentration CEMS and stack flow monitor 2. Fuel Flowmeter and Fuel Sampling (mass balance) 3. Default SO2 emission rate and heat input rate from a flow monitor and a diluent CEMS 4. Default emission rates CO2 Mass Emissions 1. CO2 concentration CEMS and stack flow monitor 3. Default emission rates NOx Mass Emissions 1. NOx concentration CEMS and stack flow monitor 2. NOx emission rate determined using a NOx – diluent CEMS and heat input rate determined using a flow monitor and diluent CEMS 3. NOx emission rate determined using a NOx – diluent CEMS and heat input rate determined using a fuel flowmeter 4. NOx emission rate based on a load based emission factor and heat input rate determined using a fuel flowmeter 5. Default Emission Rates and heat input rate determined using a fuel flowmeter NOx Emission Rate 1. NOx – diluent CEMS with F-factor 2. Load based emission factor Heat Input 1. Stack flow monitor, diluent monitor, and F-factors 2. Fuel Flowmeter and GCV Sampling 3. Maximum heat input

Load Based Emission Factors CEMS Total emissions = (concentration) * (flow rate) * (conversion factor) * (time) A “Continuous Emissions Monitoring System (CEMS)” is all of the equipment required to sample, analyze, and record stack emissions in the appropriate reporting format. Probe Sample lines Filters Moisture removal system or a dilution probe Pump Analyzer Representative sample of the flue gas is continuously withdrawn from the stack, transported to a CEMS shelter, and analyzed Direct measurement of SO2, CO2, and NOX emissions Best monitoring option when concentration or flow rate (or both) are highly variable, or when the variability is not known Measurement of Heat Input from Stack Flow and Diluent (CO2 or O2) measurements All data collected as hourly averages CEMS Mass Balance Load Based Emission Factors Emission Factors

Types of CEMS Conventional Extractive Dilution Extractive In-situ (Wet or Dry Basis Measurement) Hot Wet Cool Dry with condenser Dilution Extractive (Wet Basis Measurement) In Stack Dilution Out of Stack Dilution In-situ (Wet Basis measurement in the stack) Point Path Wont get into the various types, it doesn’t mater what the source uses – they just have to meet performance specifications.

CEMS Two Components (SO2, NOx, and CO2): Three Components (NOx) concentration analyzer DAHS Used with stack flow monitor to determine the mass emissions (lb/hr) Three Components (NOx) NOx concentration analyzer CO2 or O2 concentration analyzer as the Diluent Use appropriate F-factors to convert NOx concentration (ppm) and diluent concentration (%) into NOx emission rates (lb/mmBtu) Can be used in combination with the heat input rate to determine NOx mass emissions. The F-factor is the ratio of the stoichiometric volume of gas generated for complete combustion of a given fuel with air to the amount of heat produced. Total emissions = (concentration) * (flow rate) * (conversion factor) * (time)

Stack Flow Two components Flow monitor DAHS Used with SO2, NOx, or CO2 monitors to determine mass emissions Also can be used with diluent (CO2 or O2) monitors to determine Heat Input Rate

CEMS Certification Initial certification Relative Accuracy Testing (RATA) and Bias test – comparison of CEM data against same-time EPA reference measurement. If a low bias is detected, a bias adjustment must be made to all subsequent data collected until the next RATA. Linearity Check – injection of protocol gas standards to the measurement system at 3 levels over the measurement range Other test for certification events are: 7-day calibration error test; cycle response Test; leak checks; flow interference checks Data Acquisition and Handling System (DAHS) validation Results are reported to EPA electronically

CEMS Certification Re-certification is required whenever a replacement, modification, or change is made to: A certified CEM system that may significantly affect the ability of the system to accurately measure or record data The flue gas handling system or the unit operation that may significantly change the flow or concentration profile Examples of changes which require recertification include: Replacement of the analyzer; Change in location or orientation of the sampling probe or site; Complete replacement of an existing CEM system; and Adjustment of stack flow parameters (K-factors)

CEMS Data Validation Ongoing QA/QC testing requirements “Daily” Calibration Error Check - injection of zero level and upscale protocol gas standard “Daily” Flow Interference Checks – Check functionality of flow monitors electronics “Annual” Relative Accuracy Testing (RATA) – comparison of CEM data against same-time EPA reference measurement. “Quarterly” Linearity Check – injection of protocol gas standards to the measurement system at 3 levels over the measurement range; “Quarterly” Stack Flow to Load – Data evaluation comparing the flow to load ratio during the last RATA to the hourly data; Leak checks

Substitute Data There are 4 “tiers” of substitute data for CEMS based on the Percent Monitor Availability (PMA) As the PMA decreases the required substitute data becomes more conservative (i.e., overestimates) Designed to encourage a complete data record through high PMA ARP PMA typically exceeds 99% When one of the tests fails, or is not done.

Monitor Percent Availability Substitute Data Monitor Percent Availability (PMA) Duration Method Lookback Period >95% <24 Average Hour before and after >24 Greater of: Average or 90% 720 hours >90% <8 >8 95% >80% >0 Maximum value <80% Maximum potential none

Emission reporting process EPA Feedback Emission Report EPA Feedback EPA Quality assure data Audit data Publish data Sources Monitor fuel and/or emissions If necessary, take fuel samples Quality assure measurement equipment Report data to EPA EPA & State Agencies Audit measurement systems and on-site records

Data Verification Electronic Audits Compare monitoring plans, QA test history, and emissions data to rule requirements Look for mathematical and methodological errors Look for statistical anomalies Ad hoc or “spot check”

Data Verification Field Audits Identify “suspect” facilities or perform random audits Witness CEMS operation, on-site records, and maintenance logs. Invite local, State, or EPA regional personnel Opportunity for sources to gain knowledge and ask questions

Compliance Assistance Compliance Check Training They’re our customers Our job is to keep them in compliance We’re not trying to “catch them” Work together to get quality data and an efficient program Point of Contact - Calls from sources, State personnel, EPA regional staff, and the public. Answer questions, provide guidance, supply information, ect. Compliance Check - Before “true-up”, we run a hypothetical compliance check and notify sources if there are any problems Petitions - For situations where the facility can’t or didn’t follow the regulations Quality assurance and reporting software - Source can pre-check their data anytime. During the submission period, automated email feedback is send every few days Informational Materials - Plain English Guide, Policy Manual, Field Audit Manual Training – For sources, and enforcers Petitions Informational Materials QA Software Point of contact Over 99% Compliance

Transparency http://camddataandmaps.epa.gov/gdm/ Account Name Facility ID (ORISPL) Allowance (Vintage) Year Block Totals Evander Andrews Power Complex  7953  2001  250  150  Rathdrum Power, LLC  55179  2006  2  8  Bennett Mountain Power Project  55733  99    509  State Facility Name Facility ID (ORISPL) Year SO2 Tons NOx Tons CO2 Tons Heat Input (mmBtu) KS  Chanute 2  1268  2008  0.1  28.2  16,183.9  274,266  Cimarron River  1230  0.3  84.2  53,754.4  904,482  Coffeyville  1271  0.0  25.7  431  East 12th Street  7013  4.5  2,016.5  34,209  Emporia Energy Center  56502  0.5  68.4  104,525.2  1,758,812  http://camddataandmaps.epa.gov/gdm/

Lessons Learned Measurement flexibility can reduce costs, but it is not appropriate for all sources or sectors Adequate fuel or emission samples are needed to characterize the fuel and operating conditions, and capture emission variations. Properly designed incentives can improve emission data accuracy Frequent measurements (e.g., hourly) allow for better analysis and QA Procedures that don’t underestimate emissions Frequent reporting (e.g., quarterly) provides opportunities for government and industry to correct problems before the problems affect compliance Publically available data in a timely manner Automatic and clear penalties Software should be provided for checking and reporting data Monitoring plan requirements Prescribed QA/QC procedures Clear, consistent, and prescriptive rules for addressing missing or invalid data reduce underreporting Monitor traceability to gas standards and ASTM fuel sampling procedures Unambiguous regulations Electronic reporting reduces burden on industry and government, increases timeliness of data, and facilitates electronic QA/QC and auditing Electronic and field audit data verification Measurement programs must adapt to new information, instrumentation, and science Measurement programs must have mechanisms to deal with unusual or unique situations

Resources General CEMS Monitoring Fuel flowmeter QA/QC Field Audits Plain English Guide to Part 75 http://www.epa.gov/airmarkets/emissions/docs/plain_english_guide_part75_rule.pdf Fuel flowmeter QA/QC 40 CFR Part 75, Appendix D http://www.epa.gov/airmarkets/emissions/consolidated.html Field Audits http://www.epa.gov/airmarkets/emissions/audit-manual.html Fundamentals of Successful Monitoring, Reporting, and Verification under a Cap and Trade Program http://www.epa.gov/airmarkets/cap-trade/docs/fundamentals.pdf Electronic Audit Software http://www.epa.gov/airmarkets/emissions/mdc-software.html US EPA Clean Air Markets Division http://www.epa.gov/airmarkets/ Travis Johnson, US EPA Johnson.Travis@epa.gov