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Greenhouse Gas Compliance--Frequently asked questions

What are the new Greenhouse Gas (GHG) reporting requirements?
How do “CO₂ equivalents” work?
Who is affected?
How do I know if this rule applies to my facility?
When does reporting need to begin?
Why is this reporting required?
What are the fines for non-compliance with these regulations?
How can my plant meet the requirements?
What is the accuracy requirement of fuel flow meters?
Are actual emissions from stacks measured?
Where are flow measurements required?
What products & features does Emerson offer that help satisfy these requirements?

1. What are the new Greenhouse Gas (GHG) reporting requirements?
The new rules are contained in 40 CFR 98 and other sections of federal regulations, which require affected plants or facilities to report their total annual emissions of the following GHGs:
CO₂ - Carbon Dioxide
CH₄ - Methane
N₂O - Nitrous Oxide
SF₆ - Sulfur Hexafluoride
PFCs - PerFluoroCarbons - (class of chemicals comprising 9 compounds)
HFCs - HydroFluoroCarbons - (class of chemicals comprising 19 compounds)

Plant personnel will use calculation methods outlined in the rules to report total and unit-level emissions of “CO₂ equivalents” (CO₂e) that represent the total of the above GHGs based on their fuel flow measurements and their production of these chemicals. The most significant parts of the new regulations for most plants apply to the emissions of CO₂, CH₄ and N₂O resulting from the burning of fossil fuels.

2. How do “CO₂ equivalents” work?
GHGs each have their own heat-trapping ability. GHGs other than CO₂ have a multiplier associated with them that accounts for their greater ability to trap heat. (This multiplier is called “Global Warming Potential”, or GWP). For example, CH₄ has a multiplier of 21, meaning 1 metric ton of CH₄ is the same as 21 metric tons of CO₂. Plant personnel will convert emissions of each GHG to CO₂e and add them together to see if they exceed the reporting threshold.

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3. Who is affected?
From a practical standpoint, every member of the process industry in the U.S. will have to report. ALL Refineries and Petrochemical manufacturers are subject to the new rules, regardless of their capacity. The same is true of any plant making: Adipic Acid, Aluminum, Ammonia, Cement, Lime, Nitric Acid, Phosphoric Acid, Silicon Carbide, Soda Ash, Titanium Dioxide, and several other chemicals. Other plants will have several “stationary combustion units” and will have to report if the aggregate emissions of all these units (boilers, furnaces, etc.) exceeds 25,000 metric tons/year CO₂e. This threshold is actually very low, meaning reporting is almost certain to be required of anyone with one or more average size boilers. Power plants have been subject to reporting under the Acid Rain Regulations (40 CFR 75) for many years and will continue to be. These new rules largely do not impose new reporting requirements on Power plants. Approximately 10,000 sites within the United States will have to determine their approximate emissions and if they are subject to the new rules.

4. How do I know if this rule applies to my facility?
There is an online applicability calculator at:

http://www.epa.gov/climatechange/emissions/GHG-calculator/categories.html

Using the EPA calculator, you will enter information about the amounts and types of fuel burned at your sites and the calculator will tell you if your facilities exceed the threshold (25,000 metric tons/year CO₂e). The EPA says if you are “close” to the threshold, “it might be prudent to report”. As noted above, most facilities will be well above the threshold.

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5. When does reporting need to begin?
The first report, covering calendar year 2010, must be submitted to the EPA by March 31^st 2011. Emissions data gathering must commence January 1^st 2010 using “best available methods” (engineering calculations & estimates). Plants that plan to use flow metering or are required to must ensure actual monitoring is in place by March 31^st 2010! Extensions will be granted but none beyond December 31^st 2010.

6. Why is this reporting required?
The EPA invoked sections 114 and 208 of the Clean Air Act (CAA) to require this new reporting. It is intended to “inform future climate change policies and programs”, which some believe to mean that this reporting serves as a baseline to “Cap & Trade” or other emission-reduction laws, if this legislation were to pass.

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7. What are the fines for non-compliance with these regulations?
Because it is related to the Clean Air Act, it can be enforced in exactly the same way. Maximum daily fines for the CAA are $32,500. It does not seem likely this amount would be commonly imposed, but it is allowed by law.

8. How can my plant meet the requirements?
The new rules outline four different “tiers” (methods) of reporting that depend on: size & fuel type for stationary combustion units, availability of fuel heating value analyses and presence of existing CEMS (Continuous Emissions Monitoring Systems). Tiers 1 & 2 allow the use of fuel bills as the main “measurement” of fuel usage. Tier 3 requires the use of new and existing flow meters. Tier 4 requires the use of CEMS.

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9. What is the accuracy requirement of fuel flow meters?
Flow meter accuracies need to be 5% or better and follow “manufacturer recommendations” for calibration intervals. Plant personnel are required to draft a written monitoring plan by April 1^st 2010, which does not need to be submitted to EPA but which could be audited by them. An automated reporting system will be in place in time for the first reports, allowing users to submit emissions reports electronically.

10. Are actual emissions from stacks measured?
Not in most cases. The vast majority of measurements will be made on fuel lines to boilers, furnaces and the like. Power plants and other similar facilities who already have CEMS are required to continue using them for the new reporting.

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11. Where are flow measurements required?
In some cases, at each combustion unit but there are rules for “aggregating” units that have a common fuel supply, like a natural gas line or fuel oil line feeding several boilers. Each fuel must be monitored separately. If a CEMS is present, units that use a common stack can all be reported using the CEMS for that stack.

12. What products & features does Emerson offer that help satisfy these requirements?
Many Emerson products can play a role in meeting these new measurement and reporting requirements. Plant operations must ensure that each meter is better than 5% accurate and it is realistic to expect that these requirements could tighten in the future or that emission reductions could be mandated. Metering equipment must be properly calibrated, easy to install and data should be easily gathered for annual reports.

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Emerson offers a broad range of flow, density and analytic technologies that can accurately and reliably measure the various liquid and gas fuels covered. Key capabilities from Emerson are:

High accuracy, reliable flow measurement:

MultiVariable ensures reporting accuracy under changing pressure, temperature & flow rate.
Ultra for Flow maximizes accurate range.
Reducer® Vortex maximizes accurate range and installs easily.
Conditioning Orifice corrects errors due to inadequate straight pipe runs.
Integrated DP Flow eliminates impulse line errors and installs easily.
Hot tap Annubars for metering without process shut-down
On-line meter verification (Coriolis, Vortex, Mag) dramatically reduces routine calibration costs and facilitates trouble-shooting.
Coriolis for highly accurate direct mass flow of liquids and gases over wide usable ranges
Coriolis ideal for changing molecular weight gases and can provide inferred BTU and scf measurement

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