Implementation of US Cap and Trade

Programs

Travis Johnson - US EPA

Santiago, Chile May 2009

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Accurate Emission Values

– Emission measurements are the “gold standard” underlying traded allowances

•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

It is important that a ton of emissions at one source is equal to a ton of emissions at any other source.

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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

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Good Data Quality

• Accuracy

• Quality Assurance

• Availability

• Accessibility and Timeliness

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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)

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Monitoring processEPA 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

Sources perform QA/QC testing for measurement equipment at prescribed intervals

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

EPA audits and verifies all emission data

•Electronic audit of every hour of emissions reported

•Independent field audits (random and targeted)

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Monitoring Options(Flexibility)

These are the Allowable Monitoring Options…

If an Affected Unit is Classified as…

CEMSMass

Balance

Load-based Emission Factors

Emission Factors

Coal-fired √

Oil- or gas-fired units

√ √ √

Oil- or gas-fired low-emitting units

√ √ √ √

Methods with less accuracy or greater uncertainty use conservative methods that do not underestimate emissions

36% of the units must use Continuous Emissions Monitors (CEMS) - but this accounts for 96% of the total SO2 emissions

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Emission Factors

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

This methodology provides an

alternative to CEMS for determining SO2

CO2, and NOx emissions.

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.

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

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.

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Emission Factors

CEMS Mass BalanceLoad Based Emission

FactorsEmission 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)

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Load-based Emission Factors

To qualify for use– Oil- or gas-fired; or low operation (peaking unit).

Peaking unit(1) An average annual capacity factor of 10% or less over the past

three years, and(2) An annual capacity factor of 20% or less in each of those three

years Annual capacity factor(1) The ratio of the unit’s actual annual electrical output to the

nameplate capacity times 8,760; or (2) The ratio of the unit’s actual annual heat input to the maximum

design heat input times 8,760.

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

To Determine: NOx emission rate

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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)

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

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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 BalanceLoad Based Emission

FactorsEmission Factors

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Mass Balance

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

• 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.

This methodology provides an

alternative to CEMS for determining

emissions.

To qualify for use:• Must be gas-fired or oil-fired (no solid fuels)

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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 BalanceLoad Based Emission

FactorsEmission Factors

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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 BalanceLoad Based Emission

FactorsEmission Factors

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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

Can be used to extend the interval between fuel accuracy tests to up to 5 years

Unit Load

Fuel F

low R

ate

10%

10%

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

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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.

CEMS Mass BalanceLoad Based Emission

FactorsEmission Factors

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Gaseous Fuel Sampling

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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 BalanceLoad Based Emission

FactorsEmission Factors

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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

2. Fuel Flowmeter and Fuel Sampling (mass balance)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 CEMS3. NOx emission rate determined using a NOx – diluent CEMS and heat input rate

determined using a fuel flowmeter4. NOx emission rate based on a load based emission factor and heat input rate determined

using a fuel flowmeter5. 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 factor3. Default emission rates

Heat Input 1. Stack flow monitor, diluent monitor, and F-factors2. Fuel Flowmeter and GCV Sampling3. Maximum heat input

Monitoring Methodologies Summary

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CEMS

• 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 BalanceLoad Based Emission

FactorsEmission Factors

Total emissions = (concentration) * (flow rate) * (conversion factor) * (time)

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Types of CEMS

• Conventional Extractive (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

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CEMS

• Two Components (SO2, NOx, and CO2):• 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• DAHS

– 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.

Total emissions = (concentration) * (flow rate) * (conversion factor) * (time)

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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

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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

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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)

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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

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Substitute Data

• 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%

• There are 4 “tiers” of substitute data for CEMS based on the Percent Monitor Availability (PMA)

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Substitute Data

Monitor Percent Availability

(PMA)Duration Method Lookback Period

>95% <24 Average Hour before and after

>24 Greater of:Average or90%

Hour before and after720 hours

>90% <8 Average Hour before and after

>8 Greater of:Average or 95%

Hour before and after720 hours

>80% >0 Maximum value 720 hours

<80% >0 Maximum potential none

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Emission reporting process

Emission

Report

EPA• Quality assure data• Audit data• Publish data

EPA & State Agencies• Audit measurement

systems and on-site records

Sources• Monitor fuel and/or

emissions• If necessary, take fuel

samples• Quality assure

measurement equipment• Report data to EPA

•EPA Feedback

EPA

Feedback

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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”

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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

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Compliance Assistance

• 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

Compliance Check

Petitions

QA Software

Informational Materials

Training

Over 99% Compliance

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Transparency

Account Name Facility ID (ORISPL)

Allowance (Vintage) Year

Block Totals

Evander Andrews Power Complex 

7953  2001  250 

Evander Andrews Power Complex 

7953  2001  150 

Rathdrum Power, LLC  55179  2006  2 

Rathdrum Power, LLC  55179  2006  8 

Bennett Mountain Power Project 

55733  2001  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 

KS  Cimarron River 

1230  2008  0.3  84.2  53,754.4 

904,482 

KS  Coffeyville  1271  2008  0.0  0.0  25.7  431 

KS  East 12th Street 

7013  2008  0.0  4.5  2,016.5 

34,209 

KS  Emporia Energy Center 

56502  2008  0.5  68.4  104,525.2 

1,758,812 

http://camddataandmaps.epa.gov/gdm/

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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

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Resources

• General CEMS Monitoring– 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