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

2. 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

3. 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

4. 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.

5. 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)

6. 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

7. 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

8. 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

9. 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

10. 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

11. 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

12. 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

13. 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

14. 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

15. 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

16. 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

17. 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

18. Gaseous Fuel Sampling

19. 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

20. 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

21. 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

22. 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.

23. 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)

24. 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

25. 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

26. 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)

27. 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

28. 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.

29. 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

30. 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

31. 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”

32. 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

33. 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 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

34. 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 

35. 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

36. Resources General CEMS Monitoring Fuel flowmeter QA/QC Field Audits
Plain English Guide to Part 75
Fuel flowmeter QA/QC
40 CFR Part 75, Appendix D
Field Audits
Fundamentals of Successful Monitoring, Reporting, and Verification under a Cap and Trade Program
Electronic Audit Software
US EPA Clean Air Markets Division
Travis Johnson, US EPA