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

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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
3.	Options for Monitoring Methods	6
4.	Procedures for Estimating Missing Data	7
5.	Q A/QC Requirements	7
6.	Reporting Procedures	9
7.	References	9

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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 (C6Fi4). 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 C02 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.
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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
FERCa
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)
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)
NERC
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
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
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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)
aFERC 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.
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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 C02e, 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 C02 equivalent were covered by the threshold.
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Table 2: Options for Emissions and Capacity-Based Thresholds for Electric Power Systems
Emission Threshold
Level (mtC02e)
Total National SF6
Emissions (million
mtC02e)
Total
Number of
Facilities
Emissions Covered
Facilities Covered
Million
mtC02e
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 mtC02e 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.
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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 2006IPCC 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 fortius 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.
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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 ofSF6 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 ofSF6 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).
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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 ~ Re1ali\ e Fucerlai lilies of Emission Esli males for Various Scale Vcuracies (95% Confidence Tulei \ nil
l.c\cl ol';iccur;io iippliod Hi
iiiiiss-hiiliiniT inputs'
Marnier 1
Parmer 2
Pariuer '
Pariuer 4
\\ eraue
± 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)13
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).
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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
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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).
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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) 2006IPCC 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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nggip.iges.or.jp/public/2006gl/index.html.
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. Available at: http://www.epa.gov/electricpower-
sf6/documents/confD4_smythe.pdf.
UDI (2001) 2001 UDI Directory of Electric Power Producers and Distributors, 109th Edition, Platts. Available for
purchase at: http://www.platts.com/Products/electricpowerproducerdirectory
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. Available in EPA docket EPA-HQ-OAR-2009-0927.
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