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TECHNICAL SUPPORT DOCUMENT FOR 

EMISSIONS FROM ELECTRIC POWER 

EQUIPMENT USE: 

 PROPOSED RULE FOR MANDATORY 

REPORTING OF GREENHOUSE GASES 

Office of Air and Radiation 

U.S. Environmental Protection Agency 

March 22, 2010 
 

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Contents

1. Source Description........................................................................................................................................ 3

a. Total U.S. Emissions................................................................................................................................ 3

b. Emissions to be Reported.......................................................................................................................... 3

c. Facility Definition Characterization .......................................................................................................... 3

2. Options for Reporting Threshold ................................................................................................................... 5

3. Options for Monitoring Methods................................................................................................................... 6

4. Procedures for Estimating Missing Data ........................................................................................................ 7

5. QA/QC Requirements................................................................................................................................... 7

6. Reporting Procedures.................................................................................................................................... 8

7. References.................................................................................................................................................... 8
 

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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, equipment use, and equipment decommissioning and disposal. 

c. Facility Definition Characterization 

Typically, the various regulations under the Clean Air Act (CAA) define a facility as a group of emissions sources 

all located in a contiguous area and under the control of the same person (or persons under common control). 

Electrical equipment is used at numerous substations that are not contiguous to each other but are instead connected 

by electrical lines. Using the CAA definition of a facility could create many different electric power systems from 

equipment that is geographic 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 CAA definition is not considered appropriate or sufficient 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 which 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 substation would require setting up a separate mass-balance accounting system for each substation, 

which would involve significant labor and administrative burden and does not reflect the standard practice that 

utilities handle bulk gas across substations. Typically, gas is purchased and stored in a centralized fashion for use 

across multiple substations. Corporate-level reporting raises issues because the ownership structure in the electric 

power industry can be very complex. 

 

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. 
 

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EPA also evaluated the aggregation of total equipment by system. A “system” by definition includes the group of 

items that interact to form a unified whole or a network serving a common purpose. Within the electric power 

industry, the term “system” is widely used in reference to the complete network of lines and equipment necessary to 

move electricity from the point of generation to the ultimate customer. Electric power systems are further 

disaggregated into transmission and distribution networks based on the voltage. Reporting emissions from the 

aggregation of electrically connected equipment identifies a boundary of the facility as determined by physical 

interconnection and operational dependence, which is appropriate and analogous to the 40 CFR subpart A definition 

of a “facility” used for other source categories. System-level reporting is conducive for using IPCC’s Tier 3 utilitylevel mass-balance approach to emissions monitoring and is consistent with the way that most utilities track their 

SF6 use. 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 participate in EPA’s SF6 Emission Reduction Partnership for Electric Power 

Systems. Therefore, this level of reporting is a suitable choice with monitoring efficiency for the electric power 

system facility that must report emissions. 

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 

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 
 

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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: includes electricity generators, which is outside the scope of the electric power system 

subsection of the proposed mandatory reporting rule. 

• 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 does not define 

the physical assets that constitute an electric power system. 

Nonetheless these various definitions provide elements of an appropriate definition that addresses the need for clear 

boundaries, broad applicability, inclusiveness, and monitoring efficiency. To that end, the following definition for 

an electric power system, and hence a facility, was developed: all electric power equipment insulated with SF6 or 

PFCs regardless of location linked through electric power transmission or distribution lines and operated as an 

integrated unit by one electric power entity or several entities that have a single owner. In this definition, the term 

entity is introduced. To clearly define the term entity, EPA integrated the (EIA) definition (as shown in Table 1 

above), which lists examples of electric power entities, into the definition of a facility. 

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 (SF6 charge) 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 lbs 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. 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. 
 

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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. 

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. 

3. Options for Monitoring Methods 

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

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

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

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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 growth. 

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 close to 40% of 

the U.S. grid. 

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 (i.e., 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 correct records 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, 

emission rates 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 company’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. 
 

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• 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. 

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

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

• Adopt practices such as tracking cylinders leaving and entering storage with check-out sheets and 

weigh-in procedures before the cylinders are put back into storage. 

• 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). 

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 as of the beginning of the year. 

o New during the year. 

o Retired during the year. 

• Transmission miles. 

• SF6 and PFC sales and purchases. 

• SF6 and PFC destruction. 

• SF6 and PFC recycled: 

o Sent offsite. 

o Returned from offsite. 

7. References 

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. 

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
 

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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 

Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan. 

RGGI (2008) Regional Greenhouse Gas Initiative Model Rule. Revised December 31, 2008. Available at: 

http://www.rggi.org/docs/Model%20Rule%20Revised%2012.31.08.pdf. 

RAND (2004) RAND Environmental Science and Policy Center, “Trends in SF6 Sales and End-Use Applications: 

1961-2003,” Katie D. Smythe. International Conference on SF6 and the Environment: Emission Reduction 

Strategies. Scottsdale, AZ. December 1-3, 2004. 

UDI (2001) 2001 UDI Directory of Electric Power Producers and Distributors, 109P

th

P Edition, Platts. 

U.S. Electric Power Utility Representatives (2009) Personal communication between Deborah Harris, ICF 

International and representatives from companies that are Partners in EPA’s SF6 Emission Reduction Partnership to 

Electric Power Systems. October 2009.