TECHNICAL SUPPORT DOCUMENT FOR 

PROCESS EMISSIONS OF SULFUR 

HEXAFLUORIDE (SF6) AND PFCs FROM 

ELETRIC POWER SYSTEMS: 

 PROPOSED RULE FOR MANDATORY 

REPORTING OF GREENHOUSE GASES 

Revised November 2010 

Office of Air and Radiation 

U.S. Environmental Protection Agency 
 

Contents

1. Source Description...............................................................................................................................................1

a. Total U.S. Emissions.......................................................................................................................................1

b. Emissions to be Reported................................................................................................................................1

c. Facility Definition Characterization................................................................................................................1

2. Options for Reporting Threshold .........................................................................................................................4

6

7

7

9

9

3. Options for Monitoring Methods.........................................................................................................................

4. Procedures for Estimating Missing Data..............................................................................................................

5. QA/QC Requirements..........................................................................................................................................

6. Reporting Procedures...........................................................................................................................................

7. References............................................................................................................................................................
 

1. Source Description 

The largest use of SF6, both in the United States and internationally, is as an electrical insulator and interrupter in 

equipment that transmits and distributes electricity (RAND 2004). The gas has been employed by the electric power 

industry in the United States since the 1950s because of its dielectric strength and arc-quenching characteristics. It is 

used in gas-insulated substations, circuit breakers, other switchgear, and in gas-insulated lines. Sulfur hexafluoride 

has replaced flammable insulating oils in many applications and allows for more compact substations in dense urban 

areas. Currently, there are no available substitutes for SF6 in high voltage applications. 

Fugitive emissions of SF6 can escape from gas-insulated substations and switch gear through seals, especially from 

older equipment. The gas can also be released during equipment manufacturing, installation, servicing, and 

disposal. 

PFCs are sometimes used as dielectrics and heat transfer fluids in power transformers. PFCs are also used for 

retrofitting CFC-113 cooled transformers. One PFC used in this application is perfluorohexane (C6F14). In terms of 

both absolute and carbon-weighted emissions, PFC emissions from electrical equipment are generally believed to be 

much smaller than SF6 emissions from electrical equipment; however, there may be some exceptions to this pattern 

(IPCC, 2006). 

a. Total U.S. Emissions 

Emissions of SF6 from an estimated 1,364 electric power system utilities1 were estimated to be 12.4 Tg CO2 Eq. in 

2006 (EPA 2008). EPA does not have an estimate of PFC emissions from electric power system utilities. 

b. Emissions to be Reported 

EPA is requiring electric power systems to report all SF6 and PFC emissions, including those from equipment 

installation (once the title of equipment has been transferred to the equipment user), equipment use, and equipment 

decommissioning and disposal. 

c. Facility Definition Characterization 

The General Provisions for the Mandatory Reporting Rule, 40 CFR Part 98 Subpart A, define a facility as “any 

physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or 

adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way 

and under common ownership or common control, that emits or may emit any greenhouse gas.” But this definition 

is not suitable for an electric power system since the electrical equipment that comprises an electric power system is 

typically at numerous substations that are not contiguous to each other but are instead connected by electrical lines. 

Using the Subpart A definition of a facility could lead to an electric power system being subdivided into many 

different facilities due to equipment that is geographically separated from other equipment even if the equipment is 

connected by electrical lines. This could introduce confusion in calculating whether a facility exceeds the reporting 

threshold and in determining the boundary between facilities. Therefore, the Subpart A definition is not considered 

an appropriate definition for this source category. 

To identify an appropriate definition of a facility, EPA first considered the following levels of reporting: per piece of 

equipment, per substation or switchyard, and corporate-level. Reporting per piece of equipment or per substation 

was deemed costly and highly impractical for reporters, primarily due to the high number of substations and pieces 

of equipment that are operated by a utility. A large utility can have thousands of substations that each include many 

pieces of SF6-insulated equipment. Reporting SF6 emissions from each piece of equipment would not only involve a 

significant labor burden, but could also overlook emissions that occur during SF6 handling. Reporting emissions by 

 

1 The estimated total number of electric power system (EPS) utilities includes all companies participating in the SF6 Emission 

Reduction Partnership for Electric Power Systems and the number includes non-partner utilities with non-zero transmission 

miles. The estimated total number of EPS utilities that emit SF6 likely underestimates the population, as some utilities may own 

high-voltage equipment yet not own transmission miles. However, the estimated number is consistent with the U.S. inventory 

methodology, in which only non-partner utilities with non-zero transmission miles and partner utilities are assumed to emit SF6. 

 November 2010 1 
 

substation would require setting up a separate mass-balance accounting system for each substation, which would 

involve a significant labor burden and does not reflect the way that utilities handle bulk gas across substations (gas is 

usually purchased and stored in a centralized fashion for use in numerous substations). Corporate-level reporting 

can raise issues because the ownership structure in the electric power industry can be very complex. In addition, 

utilities in the electric power industry are owned and operated by numerous types of public and private entities, 

which can include an investor-owned company, an electric cooperative, a public electric supply corporation, a 

federal government agency, a municipally owned electric department, an electric public utility district (PUD), and a 

jointly owned electric supply project (EIA 2007). These myriad and potentially complex ownership structures could 

introduce the potential for under reporting, double-counting, or other reporting issues if reporting is required on a 

corporate-level. 

EPA also considered electric power system level reporting, under which the electric power system would be 

considered an aggregation of equipment that is interconnected and shares a common owner or operator. Several 

advantages exist with this type of system level reporting. For example, system level reporting is consistent with the 

way that most utilities track their SF6 use and is conducive for using IPCC’s Tier 3 utility-level mass-balance 

approach to emissions monitoring. The Tier 3 utility-level mass balance approach has been proven to be a practical 

and reasonable approach for the more than 80 utilities that currently participate in EPA’s SF6 Emission Reduction 

Partnership for Electric Power Systems. Reporting emissions from the aggregation of electrically connected 

equipment also reduces the ambiguity associated with defining the boundary of the system by not making the 

boundary dependent on the different types of corporate or operational structures, which can be very complex. 

A variety of definitions were reviewed to identify a definition for an electric power system that best captures this 

aggregation of interconnected equipment in the context of mandatory reporting. As summarized in Table 1, EPA 

reviewed current definitions from the Federal Energy Regulatory Commission (FERC), North American Energy 

Reliability Corporation (NERC), California Air Resources Board (CARB), the Regional Greenhouse Gas Initiative 

(RGGI), and the Energy Information Administration of the Department of Energy (EIA). EPA also consulted with 

members of industry (U.S. Electric Power Utility Representatives, 2009) in addition to reviewing current regulations 

relevant to industry. 

Table 1: Alternative Options for Facility Definition 

Source Term Definition 

Transmission

“Moving bulk energy products from where they are 

produced or generated to distribution lines that carry the 

energy products to consumers.” (FERC 2010) 

Distribution 

“For natural gas - the act of distributing gas from the city 

gate or plant to the customer. For electric - the act of 

distributing electric power using low voltage transmission 

lines that deliver power to retail customers.” (FERC 2010) 

FERCa

Facility 

“A set of electrical equipment that operates as a single Bulk 

Electric System Element (e.g., a line, a generator, a shunt 

compensator, transformer, etc.).” (FERC 2010)

Distribution Provider 

“Provides and operates the “wires” between the 

transmission system and the end-use customer. For those 

end-use customers who are served at transmission voltages, 

the Transmission Owners also serves as the Distribution 

Provider. Thus, the Distribution Provider is not defined by 

a specific voltage, but rather as performing the Distribution NERC function at any voltage.” (NERC 2010) 

Transmission 

“An interconnected group of lines and associated 

equipment for the movement or transfer of electric energy 

between points of supply and points at which it is 

transformed for delivery to customers or is delivered to 

other electric systems.” (NERC 2010) 

CARB Electrical Power System 

“means the combination of electrical generators (i.e., power 

plants), transmission and distribution lines, equipment, 

circuits, and transformers used to generate and transport 

 November 2010 2 
 

electricity from the generator to consumption areas or to 

adjacent electrical power systems.” (CARB 2007)

RGGI Transmission and/or 

distribution entity 

“The assets and equipment used to transmit and distribute 

electricity from an electric generator to the electrical load of 

a customer. Includes all related assets and equipment 

located within the service territory of 

the entity, defined as the service territory of a load-serving 

entity specified by the applicable state regulatory agency.” 

(RGGI 2008) 

EIA Electrical Power System

“An individual electric power entity--a company; an 

electric cooperative; a public electric supply corporation as 

the Tennessee Valley authority; a similar Federal 

department or agency such as the Bonneville Power 

Administration; the Bureau of Reclamation or the Corps of 

Engineers; a municipally owned electric department 

offering service to the public; or an electric public utility 

district (a “PUD”); also a jointly owned electric supply 

project such as the Keystone.” (EIA 2007) a

FERC does not define electric power system; but rather, their glossary defers to the EIA energy glossary for 

this term. 

The alternative definitions listed in Table 1 do provide language that is inclusive of different types of electrical 

utilities as well as different types of transmission and distribution equipment. However, the alternative definitions 

lack the level of specificity and completeness required to be used on their own to define electric power systems for 

mandatory reporting. Specific issues regarding the alternative definitions and their applicability to mandatory 

reporting are as follows: 

• FERC: fragmented between transmission and distribution; unclear boundaries between systems. 

• NERC: fragmented between transmission and distribution; unclear boundaries between systems. 

• CARB: unclear boundaries between systems.. 

• RGGI: based on the service territory of the load-serving entity, but some SF6 insulated electrical 

equipment is used by owners/operators who do not have a service territory (i.e., transmission-only 

companies). 

• EIA: outlines different entities that can be considered electric power systems, but unclear about 

boundaries between systems as well as the physical assets that constitute an electric power system. 

After a thorough review of these alternative definitions, it became clear that an appropriate definition should address 

the need for clear boundaries, broad applicability, inclusiveness, and monitoring efficiency. In order to achieve these 

goals, EPA developed the following definition of an electric power system facility: 

[an electric power system is comprised of] all electric transmission and distribution equipment insulated 

with or containing SF6 or PFCs that is linked through electric power transmission or distribution lines and 

functions as an integrated unit, that is owned, serviced, or maintained by a single electric power 

transmission or distribution entity (or multiple entities with a common owner), and that is located between: 

(1) the point(s) at which electric energy is obtained from an electricity generating unit or a different electric 

power transmission or distribution entity that does not have a common owner, and (2) the point(s) at which 

any customer or another electric power transmission or distribution entity that does not have a common 

owner receives the electric energy. The facility also includes servicing inventory for such equipment that 

contains SF6 or PFCs. 

In this facility definition, the term “electric power transmission or distribution entity” is introduced. To maintain 

clarity, EPA developed a separate definition of “electric power transmission or distribution entity” largely based on 

the EIA definition shown in Table 1. The definition provided for “electric power transmission or distribution entity” 

is as follows. 

 November 2010 3 
 

any entity that transmits, distributes, or supplies electricity to a consumer or other user, including any 

company, electric cooperative, public electric supply corporation, a similar Federal department (including 

the Bureau of Reclamation or the Corps of Engineers), a municipally owned electric department offering 

service to the public, an electric public utility district, or a jointly owned electric supply project. 

2. Options for Reporting Threshold 

EPA evaluated a range of threshold options for electric power systems. These included emission threshold options of 

1,000, 10,000, 25,000, and 100,000 metric tons CO2e, and nameplate capacity thresholds equivalent to these (713; 

7,128; 17, 820; and 71,280 lbs of SF6). These equivalencies were developed using historical (1999) data from 

utilities that participate in EPA’s SF6 Emission Reduction Partnership for Electric Power Systems (Partnership). To 

determine the nameplate capacity threshold level, the emissions threshold was converted to pounds of SF6 and 

divided by the 1999 weighted average annual leak rate (as a fraction of nameplate capacity) of the Partnership. This 

leak rate was developed by dividing the 1999 SF6 emissions reported by 42 partner utilities by the nameplate 

capacity reported by these partners.2 Partners with extraordinarily high or low leak rates (outliers) were excluded 

from the analysis. The Partners included in the analysis represented approximately 24 percent of U.S. transmission 

miles in 2000. 

Based on information from the Partnership and from the UDI database, EPA estimates that the 17,820 lbs of SF6

nameplate capacity threshold covers only a small percentage (10 percent or 141 utilities) of total utilities, while 

covering the majority (approximately 83 percent) of annual emissions. 

A capacity-based threshold permits sources to quickly determine whether they are covered. There have been many 

mergers and acquisitions in the electric power industry, which could complicate efforts to estimate recent emissions. 

In contrast, nameplate capacity is generally a known variable. A summary of these threshold options, the total 

national SF6 emissions, the total number of facilities, and the number of facilities and emissions falling above each 

threshold is presented in Table 2. 

 

2 EPA used 1999 weighted leak rates under the assumption that utilities who have not participated in the Partnership activities 

have not achieved the emission reductions from 1999-2008 that have been achieved by Partners who have taken voluntary actions 

to reduce emissions, In addition, it was essential that a non-emissions based threshold be conservative enough to ensure that 

sources emitting more than 25,000 metric tons of CO2 equivalent were covered by the threshold. 

 November 2010 4 
 

Table 2: Options for Emissions and Capacity-Based Thresholds for Electric Power Systems 

 Emissions Covered Facilities Covered 

Emission Threshold 

Level (mtCO2e) 

Total National SF6

Emissions (million 

mtCO2e) 

Total 

Number of 

Facilities 

Million 

mtCO2e Percent Facilities Percent 

1,000 12.4 1364 12.2 98.3 564 41.3 

10,000 12.4 1364 10.87 87.6 158 11.6 

25,000 12.4 1364 10.11 81.5 111 8.1 

100,000 12.4 1364 5.84 47.1 27 2 

Nameplate Capacity 

Threshold 

(lbs SF6) 

713 12.4 1364 12.19 98.3 578 42.4 

7,128 12.4 1364 10.96 88.3 183 13.4 

17,820 12.4 1364 10.32 83.2 141 10.3 

71,280 12.4 1364 5.95 48.0 35 2.6 

Transmission-Mile 

Threshold (miles) 

47 12.4 1364 12.20 98.3 584 42.8 

475 12.4 1364 10.86 87.5 186 13.6 

1,186 12.4 1364 8.74 70.4 140 10.3 

4,745 12.4 1364 4.53 36.5 34 2.5 

EPA also evaluated a threshold based on the length of the transmission lines, defined as the miles of lines carrying 

voltages above 34.5 kV, owned by electric power systems. Like the nameplate capacity threshold, the transmission 

mile threshold was developed by dividing the emissions threshold by an emission factor, this one expressing 

emissions in terms of transmission miles. The emission factor was developed using the 1999 SF6 emissions reported 

by 43 partner utilities (representing approximately 24 percent of U.S. transmission miles in 2000), and 2000 

transmission mileage data obtained from the 2001 UDI Directory of Electric Power Producers and Distributors (UDI 

2001). The transmission-mile threshold equivalent to 25,000 mtCO2e is 1,186 miles. 

The relationship between emissions and transmission miles, while strong, is not as strong as that between emissions 

and nameplate capacity. On the one hand, some utilities have far larger nameplate capacities and emissions than 

would be expected based on their transmission miles. This is the case for some urban utilities that have large 

volumes of SF6 in gas-insulated switchgear (GIS). On the other hand, some utilities have lower nameplate 

capacities and emissions than would be expected based on their transmission miles, because most of their 

transmission lines use lower voltages and typically use less SF6. 

a. Equipment under common ownership and control located outside the facility 

EPA considered that the definition of the electric power system facility could under certain circumstances result in a 

company dividing its assets into more than one facility that each fall below the threshold. For example, if a company 

owns two electric power systems as subsidiary companies and each subsidiary company owns and operates 

collections of SF6 insulated equipment that are in the same geographic vicinity but not electrically connected, then 

the two collections of equipment [owned by the subsidiary companies] would be considered separate reporting 

facilities. EPA considered whether or not in situations where the nameplate capacities for each of the subsidiary 

companies were below the reporting threshold of 17,820 pounds, these facilities would be required to report 

emissions if their combined nameplate capacities were above 17,820 pounds. 

 November 2010 5 
 

Given that the purpose of the reporting threshold is to capture the largest quantity of emissions while minimizing the 

burden to industry, allowing subsidiary companies in the example mentioned above to avoid reporting emissions 

when their combined nameplate capacities would fall above the threshold would be counter to the purpose of the 

threshold. Monitoring equipment such as cylinder scales, as well as recordkeeping technologies and procedures, are 

often shared among subsidiary companies to reduce the overall expense to the parent company. If numerous 

subsidiary companies with a single parent company are all separated as distinct facilities (because they are not 

connected electrically), then each could fall below the reporting threshold resulting in significant emissions going 

unreported to EPA even though much of the reporting burden could be shared among the subsidiary companies or 

absorbed by the parent company. 

To avoid this situation, it is necessary that electric power system facilities add their nameplate capacities to the 

nameplate capacities of other electric power transmission or distribution facilities with a common owner when 

determining whether they fall above or below the 17,820 pound nameplate capacity threshold. If facilities with a 

common owner collectively fall above the reporting threshold, then the emissions for each distinct facility must still 

be monitored and reported separately to EPA. 

b. Reporting emissions from SF6 and PFC insulated equipment located at electricity 

generating units (EGUs) 

Electricity generating units (EGUs) that report under Subpart D of the Mandatory Reporting Rule often contain 

relatively small amounts of SF6 and PFC insulated equipment. Under subpart A general provisions, EGU facilities 

that are required to report subpart D emissions must also report other source category emissions that occur at the 

facility location, including subpart DD emissions. 

In some cases, calculating emissions from SF6 and PFC insulated equipment located at EGU sites would be 

straightforward. However, in other cases where integrated utilities operate generation facilities as well as electrical 

equipment that transmits and distributes electricity from the generation facilities, it could be difficult to estimate 

emissions from equipment at the EGU sites separately from equipment outside of the EGU sites that are serviced by 

the same centralized SF6 stocks. Furthermore, there is a risk of double-counting emissions if EGUs include subpart 

DD emissions in their subpart D facility emission reports since those emissions might also be included in subpart 

DD electric power transmission or distribution facility reports. Since there are generally small amounts of SF6 and 

PFC insulated equipment located at EGUs relative to electric power transmission or distribution systems, the benefit 

of reporting emissions from equipment located at EGUs usually does not outweigh the potential issues cited above. 

The exception would be if there was a large amount of SF6 or PFC insulated equipment located at the EGU that 

could result in a large amount of emissions. Therefore, the final rule specifies that EGUs only need to include 

subpart DD emissions in their facility reports if the amount of SF6 or PFC containing equipment located within the 

subpart D facility exceeds a threshold of 17,820 pounds of nameplate capacity, which is the same reporting 

threshold applied to subpart DD electric power transmission or distribution system facilities. 

3. Options for Monitoring Methods 

EPA reviewed the 2006 IPCC Guidelines, the SF6 Emission Reduction Partnership for Electric Power Systems, the 

Inventory of U.S. Greenhouse Gas Emissions and Sinks, the Technical Guidelines for the Voluntary Reporting of 

Greenhouse Gases (1605(b)) Program, EPA’s Climate Leaders Program, and The Climate Registry for this analysis. 

These methods coalesce around the three options presented in the 2006 IPCC Guidelines. These include a Tier 1 

approach that estimates emissions by multiplying equipment nameplate capacity by default emission factors, a Tier 

2 approach that estimates emissions by multiplying equipment nameplate capacity by national emission factors, and 

a Tier 3 mass-balance approach that estimates emissions based on facility-specific data on SF6 consumption and 

nameplate capacity changes. 

Although the Tier 1 method is simple, the default emission factors have large uncertainty due to variability 

associated with handling and management practices, age of equipment, mix of equipment, and other similar factors. 

Utilities participating in EPA’s Partnership have reduced their emission factors to less than the Tier 1 default values. 

Less than 10 percent of U.S. utilities participate in this program, however, these utilities represent over 40% of the 

transmission miles in the U.S. 

 November 2010 6 
 

Tier 2 methods use country-specific emission factors, but the Partner utilities have demonstrated through calculating 

their own utility-level emission factors that there is large variability (less than one percent to greater than 35%) in 

utility-level emission factors across the nation. 

The Tier 3 approach is a utility-level mass-balance approach. This method is the approach used in EPA’s SF6

Emission Reduction Partnership for Electric Power Systems. The mass-balance approach works by tracking and 

systematically accounting for all utility uses of SF6 during the reporting year. The quantity of SF6 that cannot be 

accounted for is assumed to have been emitted to the atmosphere. 

The following equation describes the mass-balance approach. 

User Emissions = Decrease in SF6 Inventory + Acquisitions of SF6 – Disbursements of SF6 – Net Increase in Total 

Nameplate Capacity of Equipment 

where, 

Decrease in SF6 Inventory is SF6 stored in containers (but not in equipment) at the beginning of the 

year – SF6 stored in containers (but not in equipment) at the end of the year. 

Acquisitions of SF6 is SF6 purchased from chemical producers or distributors in bulk + SF6 purchased 

from equipment manufacturers or distributors with or inside of equipment + SF6 returned to site after 

off-site recycling. 

Disbursements of SF6 is SF6 in bulk and contained in equipment that is sold to other entities + SF6

returned to suppliers + SF6 sent off-site for recycling + SF6 sent to destruction facilities. 

Net Increase in Total Nameplate Capacity of Equipment is the nameplate capacity of new equipment – 

nameplate capacity of retiring equipment. (Note that nameplate capacity refers to the full and proper 

charge of equipment rather than to the actual charge, which may reflect leakage.) 

This method can also be applied to emissions of PFCs from power transformers. 

4. Procedures for Estimating Missing Data 

To be accurate, the mass-balance approach requires measured values for all inputs. Partner utilities missing inputs 

to the mass-balance approach have estimated emissions using other methods, such as assuming that all purchased 

SF6 is emitted. However, this method over-estimates emissions. Should the utility be missing records for a given 

input, it may be possible that the gas or equipment supplier has information in their records for the utility. 

Alternatively, values from previous years could be applied to the current year, but this approach introduces large 

uncertainties because emission rates vary from year to year. 

5. QA/QC Requirements 

QA/QC methods for reviewing completeness and accuracy of reporting include the following. 

• Review inputs to the mass balance equation to ensure inputs and outputs to the facility’s system 

are all accounted for in all appropriate sections. 

• Ensure no negative inputs are entered and negative emissions are not calculated. However, the 

change in storage inventory and nameplate capacity may be calculated as negative numbers. 

• Ensure that beginning of year inventory matches end of year inventory from previous year. 

• Ensure that in addition to SF6 purchased from bulk gas distributors, SF6 purchased from Original 

Equipment Manufacturers (OEM) and SF6 returned to the facility from off-site recycling are also 

accounted for among the total additions. 

QA/QC methods should be employed throughout the year. Important checks/procedures include the following. 

• Ensure that cylinders returned to the vendor are weighed in a consistent manner on a scale that is 

certified to be accurate and precise to within 2 pounds of true weight and is periodically 

recalibrated per the manufacturer’s specifications. 

o Gas suppliers measure the amount of gas remaining in cylinders/tanks returned (residual gas). 

 November 2010 7 
 

o Gas suppliers can provide a detailed monthly spreadsheet with exact residual gas amounts 

returned. 

• Ensure all substations have provided information to the person responsible for compiling the 

emissions report (if it is not already handled through an electronic inventory system). 

a. Analysis to determine scale accuracy requirements 

A ±1 percent relative accuracy requirement for scales was originally proposed; however, based on comments EPA 

received during the public comment period indicating that the proposed requirement was too stringent, EPA 

reassessed the appropriate level of accuracy and precision for scales used to weigh cylinders. 

The first steps undertaken by EPA to reassess scale accuracy requirements were to research scale manufacturer Web 

sites and to contact scale manufacturers and electrical equipment users to better understand what scales are available 

on the market and the typical specifications of scales designed to weigh cylinders.3 

Additional discussion with industry occurred at EPA’s SF6 Partnership for Electric Power Systems Partner Meeting, 

from May 13-14, 2010, where Partners discussed what types of scales they currently use, the price of various types 

of scales, and recommendations on scale accuracy requirements. The recommendations varied among Partners, with 

some Partners recommending relative accuracy requirements in the ± 3-5% range and at least one Partner 

recommending an absolute accuracy requirement of ± 2 pounds of true weight (EPA Partner Meeting, 2010), EPA 

also contacted two representatives from the Partnership in follow up to these conversations (BPA, 2010; Oncor, 

2010). 

After consulting directly with industry and reviewing public comments, EPA performed a sensitivity analysis using 

a variety of scale accuracies to analyze what effect changes in scale accuracies would have on the relative 

uncertainty of emission estimates. The analysis was performed using 2008 reported data from four various sized 

Partners of EPA’s SF6 Emission Reduction Partnership for Electric Power Systems. Since the price of scales tends to 

increase as scale accuracy increases (all else being equal), EPA’s goal was to determine which scale accuracy 

requirement would result in the least cost burden while still providing emission estimates with reasonable 

uncertainty levels. The summary results from the sensitivity analysis are provided in Table 3 below.4

Table 3: Relative Uncertainties of Emission Estimates for Various Scale Accuracies (95% Confidence Interval) 

Level of accuracy applied to 

mass-balance inputsa Partner 1 Partner 2 Partner 3 Partner 4 Average 

± 1% (relative) 2.6% 4.1% 0.5% 2.6% 2.5% 

± 5% (relative) 9.8% 6.5% 2.6% 2.8% 5.4% 

± 1 pound (absolute) 2.5% 4.1% 0.5% 2.6% 2.4% 

± 2 pound (absolute) 4.1% 4.4% 1% 2.6% 3% 

± 1% of full scale (absolute)b 6.5% 5% 1.7% 2.6% 4% a

 The level of accuracy was applied to all inputs except for new and retiring nameplate capacities, which are not measured using

scales and were assumed to have 2% relative uncertainty. Calculations also were performed using relative uncertainties of 1% 

and 5% for new and retiring nameplate capacities; the entire analysis and corresponding results can be found in the public docket 

(Docket ID No. EPA-HQ-OAR-2009-0927). 

b

 Assuming full scale is equivalent to a scale capacity of 330 pounds. 

After reviewing the results of the sensitivity analysis as well as public comments submitted by electrical equipment 

users, EPA determined that a ±2 pound absolute accuracy requirement offered the best balance between the accuracy 

of emission estimates and the burden incurred by electric power system facilities. Therefore, the final rule requires 

scales to be accurate within ±2 pounds of true weight. This absolute accuracy requirement is less stringent than the 

±1 percent relative accuracy requirement that was originally proposed. Scales with accuracy less than ±2 pounds 

absolute were associated with emission estimate uncertainties of greater than 5%, which is too high for yielding data 

 

3 Documentation of the internet research and correspondence with scale manufacturers can be found in the docket for this rule 

(Docket ID No. EPA-HQ-OAR-2009-0927). 

4 The analysis in its entirety is provided in the docket for this rule (Docket ID No. EPA-HQ-OAR-2009-0927). 

 November 2010 8 
 

that is useful to policymaking. In addition, numerous commenters recommended an absolute scale accuracy 

requirement of ±2 pounds as a way to reduce the financial burden to equipment users.5 

6. Reporting Procedures 

The following supplemental data would be useful for confirming emissions calculations and/or calculating emission 

rates that could be compared across facilities for quality control purposes: 

• Nameplate capacity: 

o Existing at the beginning of the year. 

o New during the year. 

o Retired during the year. 

• Transmission miles (length of lines carrying voltages above 35 kV). 

• Distribution miles (length of lines carrying voltages at or below 35 kV). 

• SF6 and PFC stored in containers, but not in energized equipment, at the beginning of the year. 

• SF6 and PFC stored in containers, but not in energized equipment, at the end of the year. 

• SF6 and PFC purchased in bulk from chemical producers or distributors 

• SF6 and PFC purchased from equipment manufacturers or distributors with or inside equipment 

• SF6 and PFC returned to facility after off-site recycling. 

• SF6 and PFC in bulk and contained in equipment sold to other entities. 

• SF6 and PFC returned to suppliers. 

• SF6 and PFC sent off-site for recycling. 

• SF6 and PFC sent off-site for destruction. 

7. References 

BPA (2010). Personal correspondence between Steve Lowder of Bonneville Power Administration (BPA) and Paul 

Stewart of ICF International, June 30, 2010. Available in EPA docket EPA-HQ-OAR-2009-0927. 

CARB (2007) Proposed Regulation Order Division 3. AIR RESOURCES Chapter 1. AIR RESOURCES BOARD 

Subchapter 10. Climate Change Article 4. Regulations to Achieve Greenhouse Gas Emission Reductions Subarticle 

3.1. Regulation for Reducing Sulfur Hexafluoride Emissions from Gas Insulated Switchgear. June 21, 2007. 

Available at: http://www.arb.ca.gov/regact/2010/sf6elec/appa.pdf 

FERC (2010) Glossary. Federal Energy Regulatory Commission, Washington, DC. Available at: 

http://www.ferc.gov/help/glossary.asp 

EIA (2007) Electric Power Industry Overview. Energy Information Administration, Washington, DC. Available at: 

http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html 

EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. U.S. Environmental Protection 

Agency, Washington, DC. Available at: http://www.epa.gov/climatechange/emissions/downloads/08_CR.pdf 

EPA Partner Meeting (2010). EPA’s SF6 Emission Reduction Partnership for Electric Power Systems Partner 

Meeting. Dallas, TX. May 13 and 14, 2010. Meeting notes available in EPA docket EPA-HQ-OAR-2009-0927. 

NERC (2010) Glossary of Terms Used in Reliability Standards. North American Electric Reliability Corporation, 

Washington, DC. Available at: http://www.nerc.com/docs/standards/rs/Glossary_2009April20.pdf 

 

5 For a summary of public comments relating to scale accuracy, see the response-to-comment document for subpart DD in the 

docket for this rule (Docket ID No. EPA-HQ-OAR-2009-0927). 

 November 2010 9 
 

 November 2010 10 

Oncor (2010). Personal correspondence among Ray Averitt, Deborah Boyle, and Lauren Casey of Oncor and Paul 

Stewart of ICF International. June 30, 2010. Available in EPA docket EPA-HQ-OAR-2009-0927.. 

IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas 

Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T 

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