Energy Conservation Program: Energy Conservation Standards for Distribution Transformers, 1722-1859 [2022-28590]
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
DEPARTMENT OF ENERGY
10 CFR Part 431
[EERE–2019–BT–STD–0018]
RIN 1904–AE12
Energy Conservation Program: Energy
Conservation Standards for
Distribution Transformers
Office of Energy Efficiency and
Renewable Energy, Department of
Energy.
ACTION: Notice of proposed rulemaking
and announcement of public meeting.
AGENCY:
The Energy Policy and
Conservation Act, as amended
(‘‘EPCA’’), prescribes energy
conservation standards for various
consumer products and certain
commercial and industrial equipment,
including distribution transformers.
EPCA also requires the U.S. Department
of Energy (‘‘DOE’’) to periodically
determine whether more-stringent,
standards would be technologically
feasible and economically justified, and
would result in significant energy
savings. In this notice of proposed
rulemaking (‘‘NOPR’’), DOE proposes
amended energy conservation standards
for distribution transformers, and also
announces a public meeting to receive
comment on these proposed standards
and associated analyses and results.
DATES: DOE will hold a public meeting
via webinar on Thursday, February 16,
2023, from 1:00 p.m. to 4:00 p.m. See
section VII, ‘‘Public Participation,’’ for
webinar registration information,
participant instructions and information
about the capabilities available to
webinar participants.
Comments: DOE will accept
comments, data, and information
regarding this NOPR no later than
March 13, 2023.
Comments regarding the likely
competitive impact of the proposed
standard should be sent to the
Department of Justice contact listed in
the ADDRESSES section on or before
February 10, 2023.
Interested persons are encouraged to
submit comments using the Federal
eRulemaking Portal at
www.regulations.gov. Follow the
instructions for submitting comments.
Alternatively, interested persons may
submit comments, identified by docket
number EERE–2019–BT–STD–0018, by
any of the following methods:
Email:
DistributionTransfromers2019STD
0018@ee.doe.gov. Include the docket
number EERE–2019–BT–STD–0018 in
the subject line of the message.
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SUMMARY:
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Postal Mail: Appliance and
Equipment Standards Program, U.S.
Department of Energy, Building
Technologies Office, Mailstop EE–5B,
1000 Independence Avenue SW,
Washington, DC 20585–0121.
Telephone: (202) 287–1445. If possible,
please submit all items on a compact
disc (‘‘CD’’), in which case it is not
necessary to include printed copies.
Hand Delivery/Courier: Appliance
and Equipment Standards Program, U.S.
Department of Energy, Building
Technologies Office, 950 L’Enfant Plaza
SW, 6th Floor, Washington, DC 20024.
Telephone: (202) 287–1445. If possible,
please submit all items on a CD, in
which case it is not necessary to include
printed copies.
No telefacsimiles (‘‘faxes’’) will be
accepted. For detailed instructions on
submitting comments and additional
information on this process, see section
IV of this document.
Docket: The docket for this activity,
which includes Federal Register
notices, comments, and other
supporting documents/materials, is
available for review at
www.regulations.gov. All documents in
the docket are listed in the
www.regulations.gov index. However,
not all documents listed in the index
may be publicly available, such as
information that is exempt from public
disclosure.
The docket web page can be found at
www.regulations.gov/docket/EERE2019-BT-STD-0018. The docket web
page contains instructions on how to
access all documents, including public
comments, in the docket. See section VII
of this document for information on
how to submit comments through
www.regulations.gov.
EPCA requires the Attorney General
to provide DOE a written determination
of whether the proposed standard is
likely to lessen competition. The U.S.
Department of Justice Antitrust Division
invites input from market participants
and other interested persons with views
on the likely competitive impact of the
proposed standard. Interested persons
may contact the Division at
energy.standards@usdoj.gov on or
before the date specified in the DATES
section. Please indicate in the ‘‘Subject’’
line of your email the title and Docket
Number of this proposed rule.
FOR FURTHER INFORMATION CONTACT:
Mr. Jeremy Dommu, U.S. Department
of Energy, Office of Energy Efficiency
and Renewable Energy, Building
Technologies Office, EE–5B, 1000
Independence Avenue SW, Washington,
DC 20585–0121. Telephone: (202) 586–
9870. Email: ApplianceStandards
Questions@ee.doe.gov.
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Mr. Matthew Ring, U.S. Department of
Energy, Office of the General Counsel,
GC–33, 1000 Independence Avenue SW,
Washington, DC 20585–0121.
Telephone: (202) 586–2555. Email:
matthew.ring@hq.doe.gov.
For further information on how to
submit a comment, review other public
comments and the docket, or participate
in the public meeting, contact the
Appliance and Equipment Standards
Program staff at (202) 287–1445 or by
email: ApplianceStandardsQuestions@
ee.doe.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Synopsis of the Proposed Rule
A. Benefits and Costs to Consumers
B. Impact on Manufacturers
C. National Benefits and Costs
1. Liquid-Immersed Distribution
Transformers
2. Low-Voltage Dry-Type Distribution
Transformers
3. Medium Voltage Dry-Type Distribution
Transformers
D. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for
Distribution Transformers
C. Deviation From Appendix A
III. General Discussion
A. Equipment Classes and Scope of
Coverage
B. Test Procedure
C. Technological Feasibility
1. General
2. Maximum Technologically Feasible
Levels
D. Energy Savings
1. Determination of Savings
2. Significance of Savings
E. Economic Justification
1. Specific Criteria
a. Economic Impact on Manufacturers and
Consumers
b. Savings in Operating Costs Compared to
Increase in Price (LCC and PBP)
c. Energy Savings
d. Lessening of Utility or Performance of
Products
e. Impact of Any Lessening of Competition
f. Need for National Energy Conservation
g. Other Factors
2. Rebuttable Presumption
IV. Methodology and Discussion of Related
Comments
A. Market and Technology Assessment
1. Scope of Coverage
a. Autotransformers
b. Drive (Isolation) Transformers
c. Special-Impedance Transformers
d. Tap Range of 20 Percent or More
e. Sealed and Nonventilated Transformers
f. Step-Up Transformers
g. Uninterruptible Power Supply
Transformers
h. Voltage Specification
i. kVA Range
2. Equipment Classes
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a. Pole- and Pad-Mounted Transformers
b. Submersible Transformers
c. Multi-Voltage-Capable Distribution
Transformers
d. High-Current Distribution Transformers
e. Data Center Distribution Transformer
f. BIL Rating
g. Other Types of Equipment
3. Test Procedure
4. Technology Options
5. Electrical Steel Technology and Market
Assessment
a. Amorphous Steel Market and
Technology
b. Grain-Oriented Electrical Steel Market
and Technology
6. Distribution Transformer Production
Market Dynamics
B. Screening Analysis
1. Screened-Out Technologies
2. Remaining Technologies
C. Engineering Analysis
1. Representative Units
2. Efficiency Analysis
a. Design Option Combinations
b. Data Validation
c. Baseline Energy Use
d. Higher Efficiency Levels
e. Load Loss Scaling
f. kVA Scaling
3. Cost Analysis
a. Electrical Steel Prices
b. Scrap Factor
c. Other Material Costs
d. Cost Mark-Ups
4. Cost-Efficiency Results
D. Markups Analysis
E. Energy Use Analysis
1. Hourly Load Model
a. Hourly Per-Unit Load (PUL)
b. Joint Probability Distribution Function
(JPDF)
2. Monthly Per-Unit Load (PUL)
3. Future Load Growth
4. Harmonic Content/Non-Linear Loads
F. Life-Cycle Cost and Payback Period
Analysis
1. Equipment Cost
2. Efficiency Levels
3. Modeling Distribution Transformer
Purchase Decision
a. Basecase Equipment Selection
b. Total Owning Cost (‘‘TOC’’) and
Evaluators
c. Non-Evaluators and First Cost Purchases
4. Installation Costs
5. Annual Energy Consumption
6. Electricity Prices
a. Hourly Electricity Costs
7. Maintenance and Repair Costs
8. Equipment Lifetime
9. Discount Rates
10. Energy Efficiency Distribution in the
No-New-Standards Case
11. Payback Period Analysis
G. Shipments Analysis
1. Equipment Switching
2. Trends in Distribution Transformer
Capacity (kVA)
H. National Impact Analysis
1. Equipment Efficiency Trends
2. National Energy Savings
3. Net Present Value Analysis
I. Consumer Subgroup Analysis
1. Utilities Serving Low Customer
Populations
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2. Utility Purchasers of Vault
(Underground) and Subsurface
Installations
J. Manufacturer Impact Analysis
1. Overview
2. Government Regulatory Impact Model
and Key Inputs
a. Manufacturer Production Costs
b. Shipments Projections
c. Product and Capital Conversion Costs
d. Manufacturer Markup Scenarios
3. Manufacturer Interviews
a. Material Shortages and Prices
b. Use of Amorphous Materials
c. Larger Distribution Transformers
4. Discussion of MIA Comments
a. Small Businesses
b. Capital Equipment
K. Emissions Analysis
1. Air Quality Regulations Incorporated in
DOE’s Analysis
L. Monetizing Emissions Impacts
1. Monetization of Greenhouse Gas
Emissions
a. Social Cost of Carbon
b. Social Cost of Methane and Nitrous
Oxide
2. Monetization of Other Emissions
Impacts
M. Utility Impact Analysis
N. Employment Impact Analysis
V. Analytical Results and Conclusions
A. Trial Standard Levels
B. Economic Justification and Energy
Savings
1. Economic Impacts on Individual
Consumers
a. Life-Cycle Cost and Payback Period
b. Consumer Subgroup Analysis
c. Rebuttable Presumption Payback
2. Economic Impacts on Manufacturers
a. Industry Cash Flow Analysis Results
b. Direct Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Competition
e. Impacts on Subgroups of Manufacturers
f. Cumulative Regulatory Burden
3. National Impact Analysis
a. Significance of Energy Savings
b. Net Present Value of Consumer Costs
and Benefits
c. Indirect Impacts on Employment
4. Impact on Utility or Performance of
Products
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
8. Summary of Economic Impacts
C. Conclusion
1. Benefits and Burdens of TSLs
Considered for Liquid-Immersed
Distribution Transformers Standards
2. Benefits and Burdens of TSLs
Considered for Low-Voltage Dry-Type
Distribution Transformers Standards
3. Benefits and Burdens of TSLs
Considered for Medium-Voltage DryType Distribution Transformers
Standards
4. Annualized Benefits and Costs of the
Proposed Standards for Liquid-Immersed
Distribution Transformers
5. Annualized Benefits and Costs of the
Proposed Standards for Low-Voltage
Distribution Transformers
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6. Annualized Benefits and Costs of the
Proposed Standards for Medium-Voltage
Distribution Transformers
7. Benefits and Costs of the Proposed
Standards for All Considered
Distribution Transformers
D. Reporting, Certification, and Sampling
Plan
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866
and 13563
B. Review Under the Regulatory Flexibility
Act
1. Description of Reasons Why Action Is
Being Considered
2. Objectives of, and Legal Basis for, Rule
3. Description on Estimated Number of
Small Entities Regulated
4. Description and Estimate of Compliance
Requirements Including Differences in
Cost, if Any, for Different Groups of
Small Entities
5. Duplication, Overlap, and Conflict With
Other Rules and Regulations
6. Significant Alternatives to the Rule
C. Review Under the Paperwork Reduction
Act
D. Review Under the National
Environmental Policy Act of 1969
E. Review Under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates
Reform Act of 1995
H. Review Under the Treasury and General
Government Appropriations Act, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General
Government Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Information Quality
VII. Public Participation
A. Attendance at the Public Meeting
B. Procedure for Submitting Prepared
General Statements for Distribution
C. Conduct of the Public Webinar
D. Submission of Comments
E. Issues on Which DOE Seeks Comment
VIII. Approval of the Office of the Secretary
I. Synopsis of the Proposed Rule
The EPCA,1 (42 U.S.C. 6291–6317, as
codified) authorizes DOE to regulate the
energy efficiency of a number of
consumer products and certain
industrial equipment. Title III, Part B 2
of EPCA (42 U.S.C. 6291–6309, as
codified), established the Energy
Conservation Program for ‘‘Consumer
Products Other Than Automobiles.’’
Title III, Part C 3 of EPCA (42 U.S.C.
1 All references to EPCA in this document refer
to the statute as amended through the Energy Act
of 2020, Public Law 116–260 (Dec. 27, 2020), which
reflect the last statutory amendments that impact
Parts A and A–1 of EPCA.
2 For editorial reasons, upon codification in the
U.S. Code, Part B was re-designated Part A.
3 For editorial reasons, upon codification in the
U.S. Code, Part C was re-designated Part A–1. While
EPCA includes provisions regarding distribution
transformers in both Part A and Part A–1, for
administrative convenience DOE has established
the test procedures and standards for distribution
transformers in 10 CFR part 431, Energy Efficiency
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
6311–6317, as codified), added by
Public Law 95–619, Title IV, section
411(a), established the Energy
Conservation Program for Certain
Industrial Equipment. The Energy
Policy Act of 1992, Public Law 102–486,
amended EPCA and directed DOE to
prescribe energy conservation standards
for those distribution transformers for
which DOE determines such standards
would be technologically feasible,
economically justified, and would result
in significant energy savings. (42 U.S.C.
6317(a)) The Energy Policy Act of 2005,
Public Law 109–58, amended EPCA to
establish energy conservation standards
for low-voltage dry-type distribution
transformers. (42 U.S.C. 6295(y))
Pursuant to EPCA, any new or
amended energy conservation standard
must be designed to achieve the
maximum improvement in energy
efficiency that DOE determines is
technologically feasible and
economically justified. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(2)(A))
Furthermore, the new or amended
standard must result in a significant
conservation of energy. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(B)) EPCA
also provides that not later than 6 years
after issuance of any final rule
establishing or amending a standard,
DOE must publish either a notice of
determination that standards for the
product do not need to be amended, or
a notice of proposed rulemaking
including new proposed energy
conservation standards (proceeding to a
final rule, as appropriate). (42 U.S.C.
6316(a); 42 U.S.C. 6295(m))
In accordance with these and other
statutory provisions discussed in this
document, DOE proposes amended
energy conservation standards for
distribution transformers. The proposed
standards, which are expressed in
efficiency as a percentage, are shown in
Table I.1 of this document. These
proposed standards, if adopted, would
apply to all distribution transformers
listed in Table I.1, Table I.2, and Table
I.3 manufactured in, or imported into,
the United States starting on the date 3
years after the publication of the final
rule for this rulemaking.
TABLE I.1—PROPOSED ENERGY CONSERVATION STANDARDS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS
Single-phase
Three-phase
Efficiency
(%)
kVA
15 ...........................................................................
25 ...........................................................................
37.5 ........................................................................
50 ...........................................................................
75 ...........................................................................
100 .........................................................................
167 .........................................................................
250 .........................................................................
333 .........................................................................
98.84
98.99
99.09
99.14
99.24
99.30
99.35
99.40
99.45
Efficiency
(%)
kVA
15 ...........................................................................
30 ...........................................................................
45 ...........................................................................
75 ...........................................................................
112.5 ......................................................................
150 .........................................................................
225 .........................................................................
300 .........................................................................
500 .........................................................................
750 .........................................................................
1,000 ......................................................................
98.72
98.93
99.03
99.16
99.24
99.29
99.36
99.41
99.48
99.54
99.57
TABLE I.2—PROPOSED ENERGY CONSERVATION STANDARDS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS
Single-phase
Three-phase
Efficiency
(%)
kVA
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10 ...........................................................................
15 ...........................................................................
25 ...........................................................................
37.5 ........................................................................
50 ...........................................................................
75 ...........................................................................
100 .........................................................................
167 .........................................................................
250 .........................................................................
333 .........................................................................
500 .........................................................................
667 .........................................................................
833 .........................................................................
Program for Certain Commercial and Industrial
Equipment. DOE refers to distribution transformers
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98.96
99.05
99.16
99.24
99.29
99.35
99.40
99.46
99.51
99.54
99.59
99.62
99.64
Efficiency
(%)
kVA
15 ...........................................................................
30 ...........................................................................
45 ...........................................................................
75 ...........................................................................
112.5 ......................................................................
150 .........................................................................
225 .........................................................................
300 .........................................................................
500 .........................................................................
750 .........................................................................
1,000 ......................................................................
1,500 ......................................................................
2,000 ......................................................................
2,500 ......................................................................
3,750 ......................................................................
5,000 ......................................................................
generally as ‘‘covered equipment’’ in this
document.
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98.92
99.06
99.13
99.22
99.29
99.33
99.38
99.42
99.48
99.52
99.54
99.58
99.61
99.62
99.66
99.68
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TABLE I.3—PROPOSED ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS
Single-phase
Three-phase
BIL *
kVA
BIL *
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ......................................
25 ......................................
37.5 ...................................
50 ......................................
75 ......................................
100 ....................................
167 ....................................
250 ....................................
333 ....................................
500 ....................................
667 ....................................
833 ....................................
98.29
98.49
98.64
98.74
98.86
98.94
99.06
99.16
99.23
99.30
99.34
99.38
98.07
98.30
98.47
98.58
98.71
98.80
98.95
99.05
99.13
99.21
99.26
99.31
....................
....................
....................
....................
98.68
98.77
98.92
99.02
99.09
99.18
99.23
99.28
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 .....................................
30 .....................................
45 .....................................
75 .....................................
112.5 ................................
150 ...................................
225 ...................................
300 ...................................
500 ...................................
750 ...................................
1,000 ................................
1,500 ................................
2,000 ................................
2,500 ................................
3,750 ................................
5,000 ................................
97.74
98.11
98.29
98.49
98.67
98.78
98.94
99.04
99.18
99.29
99.35
99.43
99.49
99.52
99.58
99.62
97.45
97.86
98.07
98.31
98.52
98.66
98.82
98.93
99.09
99.21
99.28
99.37
99.42
99.47
99.53
99.58
....................
....................
....................
....................
....................
....................
98.71
98.82
99.00
99.12
99.20
99.29
99.35
99.40
99.47
99.51
* BIL means basic impulse insulation level.
A. Benefits and Costs to Consumers
Table I.4 presents DOE’s evaluation of
the monetized impacts of the proposed
standards on consumers of distribution
transformers, as measured by the
average life-cycle cost (‘‘LCC’’) savings
and the simple payback period
(‘‘PBP’’).4 The average LCC savings are
positive for all equipment classes in all
cases, with the exception of
representative unit 14, and the PBP is
less than the average lifetime of
distribution transformers, which is
estimated to be 32 years (see section
IV.F.8 of this document).
In the context of this NOPR, the term
consumer refers to different populations
that purchase and bear the operating
costs of distribution transformers.
Consumers vary by transformer type; for
medium-voltage liquid-immersed
distribution transformers the term
consumer refers to electric utilities; for
low- and medium-voltage dry-type
distribution transformers the term
consumer refers to commercial and
industrial entities.
TABLE I.4—IMPACTS OF PROPOSED ENERGY CONSERVATION STANDARDS ON CONSUMERS OF DISTRIBUTION
TRANSFORMERS
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Average LCC
savings
(2021$)
Representative
unit
Equipment class
1 .......................................................................................................................................
1 .......................................................................................................................................
1 .......................................................................................................................................
2 .......................................................................................................................................
2 .......................................................................................................................................
2 .......................................................................................................................................
12 .....................................................................................................................................
12 .....................................................................................................................................
3 .......................................................................................................................................
4 .......................................................................................................................................
4 .......................................................................................................................................
6 .......................................................................................................................................
6 .......................................................................................................................................
8 .......................................................................................................................................
8 .......................................................................................................................................
8 .......................................................................................................................................
10 .....................................................................................................................................
10 .....................................................................................................................................
10 .....................................................................................................................................
1
2
3
4
5
17
15
16
6
7
8
9
10
11
12
18
13
14
19
Simple payback
period
(years)
72
131
1,029
511
1,543
6,594
* n.a.
* n.a.
147
564
722
887
653
226
3,051
22,797
228
¥2,856
8,082
* No-new standards are currently being proposed for equipment class 12, ‘‘n.a’’ indicates that there are no consumer savings.
4 The average LCC savings and simple PBP refer
to consumers that are affected by a standard and are
measured relative to the efficiency distribution in
the no-new-standards case, which depicts the
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market in the compliance year in the absence of
new or amended standards. The determination of
the distribution of efficiencies in the no-newstandards case is a function of the units selected
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from the consumer choice model. (see section
IV.F.3 of this document).
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16.0
10.1
12.2
11.9
13.8
15.8
* n.a.
* n.a.
11.7
8.9
11.8
2.4
11.4
11.9
1.1
8.1
12.4
26.1
11.3
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DOE’s analysis of the impacts of the
proposed standards on consumers is
described in section IV.F of this
document.
B. Impact on Manufacturers
The industry net present value
(‘‘INPV’’) is the sum of the discounted
cash flows to the industry from the base
year through the end of the analysis
period (2022–2056). Using a real
discount rate of 7.4 percent for liquidimmersed distribution transformers,
11.1 percent for low-voltage dry-type
(‘‘LVDT’’) distribution transformers, and
9.0 percent for medium-voltage dry-type
(‘‘MVDT’’) distribution transformers,
DOE estimates that the INPV for
manufacturers of distribution
transformers in the case without
amended standards is $1,384 million in
2021$ for liquid-immersed distribution
transformers, $194 million in 2021$ for
LVDT distribution transformers, and
$87 million in 2021$ for MVDT
distribution transformers. Under the
proposed standards, the change in INPV
is estimated to range from –18.1 percent
to –10.9 percent for liquid-immersed
distribution transformers which
represents a change in INPV of
approximately ¥$251.3 million to
¥$151.0 million; from –31.4 percent to
–17.2 percent for LVDT distribution
transformers, which represents a change
in INPV of approximately ¥$61.0
million to ¥$33.5 million; and –3.0
percent to –0.9 percent for MVDT
distribution transformers, which
represents a change in INPV of
approximately ¥$2.7 million to ¥$0.8
million. In order to bring products into
compliance with amended standards, it
is estimated that the industry would
incur total conversion costs of $270.6
million for liquid-immersed distribution
transformer, $69.4 million for LVDT
distribution transformers, and $3.1
million for MVDT distribution
transformers.
DOE’s analysis of the impacts of the
proposed standards on manufacturers is
described in section IV.J of this
document. The analytic results of the
manufacturer impact analysis (‘‘MIA’’)
are presented in section V.B.2 of this
document.
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C. National Benefits and Costs 5
1. Liquid-Immersed Distribution
Transformers
DOE’s analyses indicate that the
proposed energy conservation standards
for liquid-immersed distribution
transformers would save a significant
amount of energy. Relative to the case
5 All monetary values in this document are
expressed in 2021 dollars.
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without amended standards, the lifetime
energy savings for liquid-immersed
distribution transformers purchased in
the 30-year period that begins in the
anticipated year of compliance with the
amended standards (2027–2056) amount
to 8.02 quadrillion British thermal units
(‘‘Btu’’), or quads.6 This represents a
fleet savings of 36 percent relative to the
energy use of these products in the case
without amended standards (referred to
as the ‘‘no-new-standards case’’).
The cumulative net present value
(‘‘NPV’’) of total consumer benefits of
the proposed standards for distribution
transformers ranges from 0.26 billion
(2021$) (at a 7-percent discount rate) to
5.30 billion (2021$) (at a 3-percent
discount rate). This NPV expresses the
estimated total value of future
operating-cost savings minus the
estimated increased product costs for
distribution transformers purchased in
2027–2056.
In addition, the proposed standards
for liquid-immersed distribution
transformers are projected to yield
significant environmental benefits. DOE
estimates that the proposed standards
would result in cumulative emission
reductions (over the same period as for
energy savings) of 256.27 million metric
tons (‘‘Mt’’) 7 of carbon dioxide (‘‘CO2’’),
99.71 thousand tons of sulfur dioxide
(‘‘SO2’’), 403.57 thousand tons of
nitrogen oxides (‘‘NOX’’), 1,846.56
thousand tons of methane (‘‘CH4’’), 2.32
thousand tons of nitrous oxide (‘‘N2O’’),
and 0.65 tons of mercury (‘‘Hg’’).8
DOE estimates climate benefits from a
reduction in greenhouse gases (GHG)
using four different estimates of the
social cost of CO2 (‘‘SC–CO2’’), the
social cost of methane (‘‘SC–CH4’’), and
the social cost of nitrous oxide (‘‘SC–
N2O’’). Together these represent the
social cost of GHG (SC–GHG). DOE used
interim SC–GHG values developed by
an Interagency Working Group on the
Social Cost of Greenhouse Gases (IWG),9
6 The quantity refers to full-fuel-cycle (‘‘FFC’’)
energy savings. FFC energy savings includes the
energy consumed in extracting, processing, and
transporting primary fuels (i.e., coal, natural gas,
petroleum fuels), and, thus, presents a more
complete picture of the impacts of energy efficiency
standards. For more information on the FFC metric,
see section IV.H.2 of this document.
7 A metric ton is equivalent to 1.1 short tons.
Results for emissions other than CO2 are presented
in short tons.
8 DOE calculated emissions reductions relative to
the no-new-standards case, which reflects key
assumptions in the Annual Energy Outlook 2022
(‘‘AEO2022’’). AEO2022 represents current federal
and state legislation and final implementation of
regulations as of the time of its preparation. See
section IV.K of this document for further discussion
of AEO2022 assumptions that effect air pollutant
emissions.
9 See Interagency Working Group on Social Cost
of Greenhouse Gases, Technical Support Document:
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as discussed in section IV.L. of this
document. For presentational purposes,
the climate benefits associated with the
average SC–GHG at a 3-percent discount
rate are $8.66 billion. DOE does not
have a single central SC–GHG point
estimate and it emphasizes the
importance and value of considering the
benefits calculated using all four SC–
GHG estimates.10
DOE also estimates health benefits
from SO2 and NOX emissions
reductions.11 DOE estimates the present
value of the health benefits would be
$4.69 billion using a 7-percent discount
rate, and $15.57 billion using a 3percent discount rate.12 DOE is
currently only monetizing (for SO2 and
NOX) PM2.5 precursor health benefits
and (for NOX) ozone precursor health
benefits, but will continue to assess the
ability to monetize other effects such as
health benefits from reductions in direct
PM2.5 emissions.
Table I.5 summarizes the monetized
benefits and costs expected to result
from the proposed standards for liquidimmersed distribution transformers. In
the table, total benefits for both the 3percent and 7-percent cases are
presented using the average GHG social
costs with 3-percent discount rate, but
the Department emphasizes the
importance and value of considering the
benefits calculated using all four SC–
GHG cases. The estimated total net
benefits using each of the four cases are
Social Cost of Carbon, Methane, and Nitrous Oxide.
Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://
www.whitehouse.gov/wp-content/uploads/2021/02/
TechnicalSupportDocument_
SocialCostofCarbonMethaneNitrousOxide.pdf.
10 On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal
government’s emergency motion for stay pending
appeal of the February 11, 2022, preliminary
injunction issued in Louisiana v. Biden, No. 21–cv–
1074–JDC–KK (W.D. La.). As a result of the Fifth
Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal
government’s appeal of that injunction or a further
court order. Among other things, the preliminary
injunction enjoined the defendants in that case
from ‘‘adopting, employing, treating as binding, or
relying upon’’ the interim estimates of the social
cost of greenhouse gases—which were issued by the
Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021—to
monetize the benefits of reducing greenhouse gas
emissions. As reflected in this rule, DOE has
reverted to its approach prior to the injunction and
present monetized greenhouse gas abatement
benefits where appropriate and permissible under
law.
11 DOE estimated the monetized value of SO and
2
NOX emissions reductions associated with
electricity savings using benefit per ton estimates
from the EPA. e. See section IV.L.2 of this
document for further discussion.
12 DOE estimates the economic value of these
emissions reductions resulting from the considered
TSLs for the purpose of complying with the
requirements of Executive Order 12866.
E:\FR\FM\11JAP3.SGM
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1727
presented in section V.B.8 of this
document.
TABLE I.5—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS (TSL 4)
Billion
($2021)
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * .................................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
12.77
8.66
15.57
37.01
7.48
29.53
7% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
4.28
8.66
4.69
17.63
4.02
13.61
lotter on DSK11XQN23PROD with PROPOSALS3
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The monetary
values for the total annualized net
benefits are (1) the reduced consumer
operating costs, minus (2) the increase
in product purchase prices and
installation costs, plus (3) the value of
the benefits of GHG and NOX and SO2
emission reductions, all annualized.13
The national operating savings are
domestic private U.S. consumer
monetary savings that occur as a result
of purchasing the covered products and
are measured for the lifetime of
distribution transformers shipped in
2027–2056. The benefits associated with
reduced emissions achieved as a result
of the proposed standards are also
calculated based on the lifetime of
liquid-immersed distribution
transformers shipped in 2027–2056.
Estimates of annualized benefits and
costs of the proposed standards are
shown in Table I.6. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and health
benefits from reduced NOx and SO2
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
cost of the standards proposed in this
rule is $424.8 million per year in
increased equipment costs, while the
estimated annual benefits are $451.9
million in reduced equipment operating
costs, $497.4 million in climate benefits,
and $495.3 million in health benefits. In
this case. The net benefit would amount
to $1,019.8 million per year.
13 To convert the time-series of costs and benefits
into annualized values, DOE calculated a present
value in 2021, the year used for discounting the
NPV of total consumer costs and savings. For the
benefits, DOE calculated a present value associated
with each year’s shipments in the year in which the
shipments occur (e.g., 2030), and then discounted
the present value from each year to 2021. Using the
present value, DOE then calculated the fixed annual
payment over a 30-year period, starting in the
compliance year, that yields the same present value.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE I.6—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR LIQUIDIMMERSED DISTRIBUTION TRANSFORMERS (TSL 4)
Million
(2021$/year)
Category
Primary
estimate
Low-net-benefits
estimate
High-net-benefits
estimate
3% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * .........................................................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
733.5
497.4
894.3
2,125.3
429.5
1,695.8
686.9
478.9
860.5
2,026.3
449.0
1,577.3
789.9
519.5
934.8
2,244.2
413.2
1,831.0
451.9
497.4
495.3
1,444.7
424.8
1,019.8
425.7
478.9
477.9
1,382.5
442.1
940.5
482.2
519.5
515.3
1,517.0
409.9
1,107.2
7% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * (3% discount rate) ..........................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
lotter on DSK11XQN23PROD with PROPOSALS3
2. Low-Voltage Dry-Type Distribution
Transformers
DOE’s analyses indicate that the
proposed energy conservation standards
for low-voltage dry-type distribution
transformers would save a significant
amount of energy. Relative to the case
without amended standards, the lifetime
energy savings for low-voltage dry-type
distribution transformers purchased in
the 30-year period that begins in the
anticipated year of compliance with the
amended standards (2027–2056) amount
to 2.47 quadrillion British thermal units
(‘‘Btu’’), or quads.14 This represents a
14 The quantity refers to full-fuel-cycle (‘‘FFC’’)
energy savings. FFC energy savings includes the
energy consumed in extracting, processing, and
transporting primary fuels (i.e., coal, natural gas,
petroleum fuels), and, thus, presents a more
complete picture of the impacts of energy efficiency
standards. For more information on the FFC metric,
see section IV.H.2 of this document.
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fleet savings of 47 percent relative to the
energy use of these products in the case
without amended standards (referred to
as the ‘‘no-new-standards case’’).
The cumulative net present value
(‘‘NPV’’) of total consumer benefits of
the proposed standards for low-voltage
dry-type distribution transformers
ranges from 2.63 billion (2021$) (at a 7percent discount rate) to 9.63 billion
(2021$) (at a 3-percent discount rate).
This NPV expresses the estimated total
value of future operating-cost savings
minus the estimated increased product
costs for low-voltage dry-type
distribution transformers purchased in
2027–2056.
In addition, the proposed standards
for low-voltage dry-type distribution
transformers are projected to yield
significant environmental benefits. DOE
estimates that the proposed standards
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would result in cumulative emission
reductions (over the same period as for
energy savings) of 77.57 million metric
tons (‘‘Mt’’) 15 of carbon dioxide
(‘‘CO2’’), 92.81 thousand tons of sulfur
dioxide (‘‘SO2’’), 123.44 thousand tons
of nitrogen oxides (‘‘NOX’’), 567.30
thousand tons of methane (‘‘CH4’’), 0.70
thousand tons of nitrous oxide (‘‘N2O’’),
and 0.19 tons of mercury (‘‘Hg’’).16
15 A metric ton is equivalent to 1.1 short tons.
Results for emissions other than CO2 are presented
in short tons.
16 DOE calculated emissions reductions relative
to the no-new-standards case, which reflects key
assumptions in the Annual Energy Outlook 2022
(‘‘AEO2022’’). AEO2022 represents current federal
and state legislation and final implementation of
regulations as of the time of its preparation. See
section IV.K of this document for further discussion
of AEO2022 assumptions that effect air pollutant
emissions.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
DOE estimates climate benefits from a
reduction in greenhouse gases (GHG)
using four different estimates of the
social cost of CO2 (‘‘SC–CO2’’), the
social cost of methane (‘‘SC–CH4’’), and
the social cost of nitrous oxide (‘‘SC–
N2O’’). Together these represent the
social cost of GHG (SC–GHG). DOE used
interim SC–GHG values developed by
an Interagency Working Group on the
Social Cost of Greenhouse Gases
(IWG),17 as discussed in section IV.L of
this document. For presentational
purposes, the climate benefits
associated with the average SC–GHG at
a 3-percent discount rate are $2.77
billion. (DOE does not have a single
central SC–GHG point estimate and it
emphasizes the importance and value of
considering the benefits calculated
using all four SC–GHG estimates.)
DOE also estimates health benefits
from SO2 and NOX emissions
reductions.18 DOE estimates the present
value of the health benefits would be
$1.53 billion using a 7-percent discount
rate, and $4.91 billion using a 3-percent
discount rate.19 DOE is currently only
monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX)
ozone precursor health benefits, but will
continue to assess the ability to
monetize other effects such as health
1729
benefits from reductions in direct PM2.5
emissions.
Table I.7 summarizes the monetized
benefits and costs expected to result
from the proposed standards for lowvoltage dry-type distribution
transformers. In the table, total benefits
for both the 3-percent and 7-percent
cases are presented using the average
GHG social costs with 3-percent
discount rate, but the Department
emphasizes the importance and value of
considering the benefits calculated
using all four SC–GHG cases. The
estimated total net benefits using each
of the four cases are presented in section
V.B.8 of this document.
TABLE I.7—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS (TSL 5)
Billion
($2021)
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * .................................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
13.45
2.77
4.91
21.13
3.82
17.31
7% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
4.69
2.77
1.53
8.99
2.05
6.94
lotter on DSK11XQN23PROD with PROPOSALS3
Note: This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
17 See Interagency Working Group on Social Cost
of Greenhouse Gases, Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide.
Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://
www.whitehouse.gov/wp-content/uploads/2021/02/
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TechnicalSupportDocument_SocialCostofCarbon
MethaneNitrousOxide.pdf.
18 DOE estimated the monetized value of SO and
2
NOX emissions reductions associated with
electricity savings using benefit per ton estimates
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Fmt 4701
Sfmt 4702
from the EPA. See section IV.L.2 of this document
for further discussion.
19 DOE estimates the economic value of these
emissions reductions resulting from the considered
TSLs for the purpose of complying with the
requirements of Executive Order 12866.
E:\FR\FM\11JAP3.SGM
11JAP3
1730
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The monetary
values for the total annualized net
benefits are (1) the reduced consumer
operating costs, minus (2) the increase
in product purchase prices and
installation costs, plus (3) the value of
the benefits of GHG and NOX and SO2
emission reductions, all annualized.20
The national operating savings are
domestic private U.S. consumer
monetary savings that occur as a result
of purchasing the covered products and
are measured for the lifetime of lowvoltage dry-type distribution
transformers shipped in 2027–2056. The
benefits associated with reduced
emissions achieved as a result of the
proposed standards are also calculated
based on the lifetime of low-voltage drytype distribution transformers shipped
in 2027–2056.
Estimates of annualized benefits and
costs of the proposed standards are
shown in Table I.8. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and health
benefits from reduced NOX and SO2
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
cost of the standards proposed in this
rule is $216.9 million per year in
increased equipment costs, while the
estimated annual benefits are $495.0
million in reduced equipment operating
costs, $159.2 million in climate benefits,
and $162.1 million in health benefits. In
this case. The net benefit would amount
to $599.4 million per year.
TABLE I.8—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR LOW-VOLTAGE
DRY TYPE DISTRIBUTION TRANSFORMERS (TSL 5)
Million
(2021$/year)
Category
Primary
estimate
Low-net-benefits
estimate
High-net-benefits
estimate
3% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * .........................................................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
772.1
159.2
281.8
1,213.1
219.3
993.8
716.9
151.6
268.3
1,136.7
228.7
908.0
831.3
165.9
293.9
1,291.1
208.7
1,082.4
495.0
159.2
162.1
816.3
216.9
599.4
462.8
151.6
154.9
769.3
225.2
544.1
528.7
165.9
168.2
862.8
207.3
655.5
7% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * (3% discount rate) ..........................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
lotter on DSK11XQN23PROD with PROPOSALS3
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
3. Medium Voltage Dry-Type
Distribution Transformers
DOE’s analyses indicate that the
proposed energy conservation standards
20 To convert the time-series of costs and benefits
into annualized values, DOE calculated a present
value in 2021, the year used for discounting the
NPV of total consumer costs and savings. For the
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for medium-voltage dry-type
distribution transformers would save a
significant amount of energy. Relative to
the case without amended standards,
the lifetime energy savings for mediumvoltage dry-type distribution
transformers purchased in the 30-year
period that begins in the anticipated
benefits, DOE calculated a present value associated
with each year’s shipments in the year in which the
shipments occur (e.g., 2030), and then discounted
the present value from each year to 2021. Using the
present value, DOE then calculated the fixed annual
payment over a 30-year period, starting in the
compliance year, that yields the same present value.
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year of compliance with the amended
standards (2027–2056) amount to 0.12
quadrillion British thermal units
(‘‘Btu’’), or quads.21 This represents a
fleet savings of 24 percent relative to the
energy use of these products in the case
without amended standards (referred to
as the ‘‘no-new-standards case’’).
The cumulative net present value
(‘‘NPV’’) of total consumer benefits of
the proposed standards for mediumvoltage dry-type distribution
transformers ranges from 0.04 billion
(2021$) (at a 7-percent discount rate) to
0.21 billion (2021$) (at a 3-percent
discount rate). This NPV expresses the
estimated total value of future
operating-cost savings minus the
estimated increased product costs for
medium-voltage dry-type distribution
transformers purchased in 2027–2056.
In addition, the proposed standards
for medium-voltage dry-type
distribution transformers are projected
to yield significant environmental
benefits. DOE estimates that the
proposed standards would result in
cumulative emission reductions (over
the same period as for energy savings)
of 3.71 million metric tons (‘‘Mt’’) 22 of
carbon dioxide (‘‘CO2’’), 1.43 thousand
tons of sulfur dioxide (‘‘SO2’’), 5.93
thousand tons of nitrogen oxides
(‘‘NOX’’), 27.29 thousand tons of
methane (‘‘CH4’’), 0.03 thousand tons of
nitrous oxide (‘‘N2O’’), and 0.01 tons of
mercury (‘‘Hg’’).23
DOE estimates climate benefits from a
reduction in greenhouse gases (GHG)
using four different estimates of the
social cost of CO2 (‘‘SC–CO2’’), the
social cost of methane (‘‘SC–CH4’’), and
the social cost of nitrous oxide (‘‘SC–
N2O’’). Together these represent the
social cost of GHG (SC–GHG). DOE used
interim SC–GHG values developed by
an Interagency Working Group on the
Social Cost of Greenhouse Gases
(IWG),24 as discussed in IV.L of this
document. For presentational purposes,
the climate benefits associated with the
average SC–GHG at a 3-percent discount
rate are $0.13 billion. (DOE does not
have a single central SC–GHG point
estimate and it emphasizes the
importance and value of considering the
benefits calculated using all four SC–
GHG estimates.)
1731
DOE also estimates health benefits
from SO2 and NOX emissions
reductions.25 DOE estimates the present
value of the health benefits would be
$0.07 billion using a 7-percent discount
rate, and $0.24 billion using a 3-percent
discount rate.26 DOE is currently only
monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX)
ozone precursor health benefits, but will
continue to assess the ability to
monetize other effects such as health
benefits from reductions in direct PM2.5
emissions.
Table I.9 summarizes the monetized
benefits and costs expected to result
from the proposed standards for
medium-voltage dry-type distribution
transformers. In the table, total benefits
for both the 3-percent and 7-percent
cases are presented using the average
GHG social costs with 3-percent
discount rate, but the Department
emphasizes the importance and value of
considering the benefits calculated
using all four SC–GHG cases. The
estimated total net benefits using each
of the four cases are presented in section
V.B.8 of this document.
TABLE I.9—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS (TSL 2)
Billion
($2021)
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * .................................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
0.41
0.13
0.24
0.77
0.19
0.58
7% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
0.14
0.13
0.07
0.35
0.10
0.24
lotter on DSK11XQN23PROD with PROPOSALS3
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
21 The quantity refers to full-fuel-cycle (‘‘FFC’’)
energy savings. FFC energy savings includes the
energy consumed in extracting, processing, and
transporting primary fuels (i.e., coal, natural gas,
petroleum fuels), and, thus, presents a more
complete picture of the impacts of energy efficiency
standards. For more information on the FFC metric,
see section IV.H.2 of this document.
22 A metric ton is equivalent to 1.1 short tons.
Results for emissions other than CO2 are presented
in short tons.
23 DOE calculated emissions reductions relative
to the no-new-standards case, which reflects key
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assumptions in the Annual Energy Outlook 2022
(‘‘AEO2022’’). AEO2022 represents current federal
and state legislation and final implementation of
regulations as of the time of its preparation. See
section IV.K of this document for further discussion
of AEO2022 assumptions that effect air pollutant
emissions.
24 See Interagency Working Group on Social Cost
of Greenhouse Gases, Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide.
Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://
www.whitehouse.gov/wp-content/uploads/2021/02/
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TechnicalSupportDocument_
SocialCostofCarbonMethaneNitrousOxide.pdf.
25 DOE estimated the monetized value of SO and
2
NOX emissions reductions associated with
electricity savings using benefit per ton estimates
from the EPA. See section IV.L.2 of this document
for further discussion.
26 DOE estimates the economic value of these
emissions reductions resulting from the considered
TSLs for the purpose of complying with the
requirements of Executive Order 12866.
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* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The monetary
values for the total annualized net
benefits are (1) the reduced consumer
operating costs, minus (2) the increase
in product purchase prices and
installation costs, plus (3) the value of
the benefits of GHG and NOX and SO2
emission reductions, all annualized.27
The national operating savings are
domestic private U.S. consumer
monetary savings that occur as a result
of purchasing the covered equipment
benefits from reduced NOX and SO2
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
cost of the standards proposed in this
rule is $10.8 million per year in
increased equipment costs, while the
estimated annual benefits are $14.9
million in reduced equipment operating
costs, $7.6 million in climate benefits,
and $7.8 million in health benefits. The
net benefit would amount to $19.5
million per year.
and are measured for the lifetime of
medium-voltage dry-type distribution
transformers shipped in 2027–2056. The
benefits associated with reduced
emissions achieved as a result of the
proposed standards are also calculated
based on the lifetime of medium-voltage
dry-type distribution transformers
shipped in 2027–2056.
Estimates of annualized benefits and
costs of the proposed standards are
shown in Table I.10. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and health
TABLE I.10—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR MEDIUMVOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS (TSL 2)
Million
(2021$/year)
Category
Primary
estimate
Low-net-benefits
estimate
High-net-benefits
estimate
3% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * .........................................................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
23.3
7.6
13.5
44.4
11.0
33.5
22.2
7.5
13.2
42.9
11.7
31.1
25.8
8.2
14.5
48.5
10.7
37.7
14.9
7.6
7.8
30.3
10.8
19.5
14.3
7.5
7.6
29.4
11.6
17.9
16.4
8.2
8.3
32.9
10.6
22.2
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .............................................................................
Climate Benefits * (3% discount rate) ..........................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
27 To convert the time-series of costs and benefits
into annualized values, DOE calculated a present
value in 2021, the year used for discounting the
NPV of total consumer costs and savings. For the
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benefits, DOE calculated a present value associated
with each year’s shipments in the year in which the
shipments occur (e.g., 2030), and then discounted
the present value from each year to 2021. Using the
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present value, DOE then calculated the fixed annual
payment over a 30-year period, starting in the
compliance year, that yields the same present value.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
DOE’s analysis of the national impacts
of the proposed standards is described
in sections IV.H, IV.K and IV.L of this
document.
D. Conclusion
DOE has tentatively concluded that
the proposed standards represent the
maximum improvement in energy
efficiency that is technologically
feasible and economically justified, and
would result in the significant
conservation of energy. Specifically,
with regards to technological feasibility
products achieving these standard levels
are already commercially available for
all product classes covered by this
proposal. As for economic justification,
DOE’s analysis shows that for each
equipment class the benefits of the
proposed standards exceed the burdens
of the proposed standards. Using a 7percent discount rate for consumer
benefits and costs and NOX and SO2
reduction benefits, and a 3-percent
discount rate case for GHG social costs,
the estimated annual cost of the
proposed standards for distribution
transformers is $652.5 million per year
in increased distribution transformer
costs, while the estimated annual
benefits are $961.8 million in reduced
distribution transformer operating costs,
$664.2 million in climate benefits and
$665.2 million in health benefits. The
net benefit amounts to $1,638.7 million
per year.
TABLE I.11—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR ALL
DISTRIBUTION TRANSFORMERS AT PROPOSED STANDARD LEVELS
Million
(2021$/year)
Category
Primary
estimate
Low-net-benefits
estimate
High-net-benefits
estimate
3% discount rate
Consumer Operating Cost Savings .............................................................................
Climate Benefits * .........................................................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
1,528.9
664.2
1,189.6
3,382.8
659.8
2,723.1
1,426.0
638.0
1,142.0
3,205.9
689.4
2,516.4
1,647.0
693.6
1,243.2
3,583.8
632.6
2,951.1
961.8
664.2
665.2
2,291.3
652.5
1,638.7
902.8
638.0
640.4
2,181.2
678.9
1,502.5
1,027.3
693.6
691.8
2,412.7
627.8
1,784.9
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .............................................................................
Climate Benefits * (3% discount rate) ..........................................................................
Health Benefits ** .........................................................................................................
Total Benefits † ............................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................
Net Benefits .................................................................................................................
Note: This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
**Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
TABLE I.12—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
ALL DISTRIBUTION TRANSFORMERS AT PROPOSED STANDARD LEVELS
Billion
($2021)
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * .................................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
26.63
11.56
20.72
58.91
11.49
47.42
7% discount rate
Consumer Operating Cost Savings .....................................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................................
Health Benefits ** .................................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................................
Net Benefits .........................................................................................................................................................................................
9.11
11.56
6.29
26.97
6.17
20.79
lotter on DSK11XQN23PROD with PROPOSALS3
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
The significance of energy savings
offered by a new or amended energy
conservation standard cannot be
determined without knowledge of the
specific circumstances surrounding a
given rulemaking.28 For example, some
covered products and equipment,
including distribution transformers,
have substantial energy consumption
occur during periods of peak energy
demand. The impacts of these products
on the energy infrastructure can be more
pronounced than products with
28 Procedures, Interpretations, and Policies for
Consideration in New or Revised Energy
Conservation Standards and Test Procedures for
Consumer Products and Commercial/Industrial
Equipment, 86 FR 70892, 70901 (Dec. 13, 2021).
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relatively constant demand.
Accordingly, DOE evaluates the
significance of energy savings on a caseby-case basis.
As previously mentioned, the
standards are projected to result in
estimated national energy savings of
10.60 quad. Based on the amount of FFC
savings, the corresponding reduction in
GHG emissions, and need to confront
the global climate crisis, DOE has
initially determined the energy savings
from the proposed standard levels are
‘‘significant’’ within the meaning of 42
U.S.C. 6295(o)(3)(B). A more detailed
discussion of the basis for these
tentative conclusions is contained in the
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remainder of this document and the
accompanying TSD.
DOE also considered more-stringent
energy efficiency levels as potential
standards, and is still considering them
in this rulemaking. However, DOE has
tentatively concluded that the potential
burdens of the more-stringent energy
efficiency levels would outweigh the
projected benefits.
Based on consideration of the public
comments DOE receives in response to
this document and related information
collected and analyzed during the
course of this rulemaking effort, DOE
may adopt energy efficiency levels
presented in this document that are
either higher or lower than the proposed
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standards, or some combination of
level(s) that incorporate the proposed
standards in part.
lotter on DSK11XQN23PROD with PROPOSALS3
II. Introduction
The following section briefly
discusses the statutory authority
underlying this proposed rule, as well
as some of the relevant historical
background related to the establishment
of standards for distribution
transformers.
A. Authority
EPCA authorizes DOE to regulate the
energy efficiency of a number of
consumer products and certain
industrial equipment. Title III, Part B of
EPCA (42 U.S.C. 6291–6309, as
codified), established the Energy
Conservation Program for ‘‘Consumer
Products Other Than Automobiles.’’
Title III, Part C of EPCA (42 U.S.C.
6311–6317, as codified), added by
Public Law 95–619, Title IV, section
411(a), established the Energy
Conservation Program for Certain
Industrial Equipment. The Energy
Policy Act of 1992, Public Law 102–486,
amended EPCA and directed DOE to
prescribe energy conservation standards
for those distribution transformers for
which DOE determines such standards
would be technologically feasible,
economically justified, and would result
in significant energy savings. (42 U.S.C.
6317(a)) The Energy Policy Act of 2005,
Public Law 109–58, amended EPCA to
establish energy conservation standards
for low-voltage dry-type distribution
transformers. (42 U.S.C. 6295(y))
EPCA further provides that, not later
than 6 years after the issuance of any
final rule establishing or amending a
standard, DOE must publish either a
notice of determination that standards
for the product do not need to be
amended, or a NOPR including new
proposed energy conservation standards
(proceeding to a final rule, as
appropriate). (42 U.S.C. 6316(e)(1); 42
U.S.C. 6295(m)(1))
The energy conservation program
under EPCA consists essentially of four
parts: (1) testing, (2) labeling, (3) the
establishment of Federal energy
conservation standards, and (4)
certification and enforcement
procedures. Relevant provisions of
EPCA specifically include definitions
(42 U.S.C. 6311; 42 U.S.C. 6291), test
procedures (42 U.S.C. 6314; 42 U.S.C.
6293), labeling provisions (42 U.S.C.
6315; 42 U.S.C. 6294), energy
conservation standards (42 U.S.C. 6313;
42 U.S.C. 6295), and the authority to
require information and reports from
manufacturers (42 U.S.C. 6316; 42
U.S.C. 6296).
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Federal energy efficiency
requirements for covered equipment
established under EPCA generally
supersede State laws and regulations
concerning energy conservation testing,
labeling, and standards. (42 U.S.C.
6316(a) and (b); 42 U.S.C. 6297) DOE
may, however, grant waivers of Federal
preemption for particular State laws or
regulations, in accordance with the
procedures and other provisions set
forth under EPCA. (See 42 U.S.C.
6316(a) (applying the preemption
waiver provisions of 42 U.S.C. 6297))
Subject to certain criteria and
conditions, DOE is required to develop
test procedures to measure the energy
efficiency, energy use, or estimated
annual operating cost of each covered
equipment. (42 U.S.C. 6316(a), 42 U.S.C.
6295(o)(3)(A) and 42 U.S.C. 6295(r))
Manufacturers of covered equipment
must use the Federal test procedures as
the basis for: (1) certifying to DOE that
their equipment complies with the
applicable energy conservation
standards adopted pursuant to EPCA (42
U.S.C. 6316(a); 42 U.S.C. 6295(s)), and
(2) making representations about the
efficiency of that equipment (42 U.S.C.
6314(d)). Similarly, DOE must use these
test procedures to determine whether
the equipment complies with relevant
standards promulgated under EPCA. (42
U.S.C. 6316(a); 42 U.S.C. 6295(s)) The
DOE test procedures for distribution
transformers appear at title 10 of the
Code of Federal Regulations (‘‘CFR’’)
part 431, subpart K, appendix A.
DOE must follow specific statutory
criteria for prescribing new or amended
standards for covered equipment,
including distribution transformers.
Any new or amended standard for a
covered product must be designed to
achieve the maximum improvement in
energy efficiency that the Secretary of
Energy determines is technologically
feasible and economically justified. (42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)
and 42 U.S.C. 6295(o)(3)(B))
Furthermore, DOE may not adopt any
standard that would not result in the
significant conservation of energy. (42
U.S.C. 6295(o)(3))
Moreover, DOE may not prescribe a
standard: (1) for certain products,
including distribution transformers, if
no test procedure has been established
for the product, or (2) if DOE determines
by rule that the standard is not
technologically feasible or economically
justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(3)(A)–(B)) In deciding whether a
proposed standard is economically
justified, DOE must determine whether
the benefits of the standard exceed its
burdens. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)) DOE must make this
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determination after receiving comments
on the proposed standard, and by
considering, to the greatest extent
practicable, the following seven
statutory factors:
(1) The economic impact of the
standard on manufacturers and
consumers of the products subject to the
standard;
(2) The savings in operating costs
throughout the estimated average life of
the covered products in the type (or
class) compared to any increase in the
price, initial charges, or maintenance
expenses for the covered products that
are likely to result from the standard;
(3) The total projected amount of
energy (or as applicable, water) savings
likely to result directly from the
standard;
(4) Any lessening of the utility or the
performance of the covered products
likely to result from the standard;
(5) The impact of any lessening of
competition, as determined in writing
by the Attorney General, that is likely to
result from the standard;
(6) The need for national energy and
water conservation; and
(7) Other factors the Secretary of
Energy (‘‘Secretary’’) considers relevant.
(42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(I)–(VII))
Further, EPCA establishes a rebuttable
presumption that a standard is
economically justified if the Secretary
finds that the additional cost to the
consumer of purchasing a product
complying with an energy conservation
standard level will be less than three
times the value of the energy savings
during the first year that the consumer
will receive as a result of the standard,
as calculated under the applicable test
procedure. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(iii))
EPCA also contains what is known as
an ‘‘anti-backsliding’’ provision, which
prevents the Secretary from prescribing
any amended standard that either
increases the maximum allowable
energy use or decreases the minimum
required energy efficiency of a covered
product. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(1)) Also, the Secretary may not
prescribe an amended or new standard
if interested persons have established by
a preponderance of the evidence that
the standard is likely to result in the
unavailability in the United States in
any covered product type (or class) of
performance characteristics (including
reliability), features, sizes, capacities,
and volumes that are substantially the
same as those generally available in the
United States. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(4))
Additionally, EPCA specifies
requirements when promulgating an
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energy conservation standard for a
covered product that has two or more
product classes. DOE must specify a
different standard level for a type or
class of product that has the same
function or intended use, if DOE
determines that products within such
group: (A) consume a different kind of
energy from that consumed by other
covered products within such type (or
class); or (B) have a capacity or other
performance-related feature which other
products within such type (or class) do
not have and such feature justifies a
higher or lower standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q)(1)) In
determining whether a performancerelated feature justifies a different
standard for a group of products, DOE
must consider such factors as the utility
to the consumer of the feature and other
factors DOE deems appropriate. Id. Any
rule prescribing such a standard must
include an explanation of the basis on
which such higher or lower level was
established. (42 U.S.C. 6316(a); 42
U.S.C. 6295(q)(2))
B. Background
1. Current Standards
In a final rule published on April 18,
2013 (‘‘April 2013 Standards Final
Rule’’), DOE prescribed the current
energy conservation standards for
distribution transformers manufactured
on and after January 1, 2016. 78 FR
23336, 23433. These standards are set
forth in DOE’s regulations at 10 CFR
431.196 and are repeated in Table II.1,
Table II.2, Table II.3.
TABLE II.1—FEDERAL ENERGY CONSERVATION STANDARDS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS
Single-phase
Three-phase
Efficiency
(%)
kVA
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
97.70
98.00
98.20
98.30
98.50
98.60
98.70
98.80
98.90
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
97.89
98.23
98.40
98.60
98.74
98.83
98.94
99.02
99.14
99.23
99.28
TABLE II.2—FEDERAL ENERGY CONSERVATION STANDARDS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS
Single-phase
Three-phase
Efficiency
(%)
kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
98.70
98.82
98.95
99.05
99.11
99.19
99.25
99.33
99.39
99.43
99.49
99.52
99.55
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
98.65
98.83
98.92
99.03
99.11
99.16
99.23
99.27
99.35
99.40
99.43
99.48
99.51
99.52
TABLE II.3—FEDERAL ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS
Single-phase
Three-phase
BIL
lotter on DSK11XQN23PROD with PROPOSALS3
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
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98.33
98.49
98.6
98.73
98.82
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98.12
98.3
98.42
98.57
98.67
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........................
........................
........................
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98.63
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kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
97.5
97.9
98.1
98.33
98.52
98.65
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97.63
97.86
98.13
98.36
98.51
........................
........................
........................
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TABLE II.3—FEDERAL ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS—Continued
Single-phase
Three-phase
BIL
kVA
167
250
333
500
667
833
BIL
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
........................
........................
........................
........................
........................
........................
98.96
99.07
99.14
99.22
99.27
99.31
98.83
98.95
99.03
99.12
99.18
99.23
2. History of Standards Rulemaking for
Distribution Transformers
On June 18, 2019, DOE published
notice that it was initiating an early
assessment review to determine whether
any new or amended standards would
satisfy the relevant requirements of
EPCA for a new or amended energy
conservation standard for distribution
transformers and a request for
information (‘‘RFI’’). 84 FR 28239 (‘‘June
2019 Early Assessment Review RFI’’).
On August 27, 2021, DOE published
a notification of a webinar and
availability of a preliminary technical
support document, which announced
98.80
98.91
98.99
99.09
99.15
99.20
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
225 ........................
300 ........................
500 ........................
750 ........................
1,000 .....................
1,500 .....................
2,000 .....................
2,500 .....................
the availability of its analysis for
distribution transformers. 86 FR 48058
(‘‘August 2021 Preliminary Analysis’’)
The purpose of the August 2021
Preliminary Analysis was to make
publicly available the initial technical
and economic analyses conducted for
distribution transformers, and present
initial results of those analyses. DOE did
not propose new or amended standards
for distribution transformers at that
time. The initial technical support
document (‘‘TSD’’) and accompanying
analytical spreadsheets for the August
2021 Preliminary Analysis provided the
analyses DOE undertook to examine the
potential for amending energy
98.82
98.93
99.09
99.21
99.28
99.37
99.43
99.47
98.69
98.81
98.99
99.12
99.2
99.3
99.36
99.41
98.57
98.69
98.89
99.02
99.11
99.21
99.28
99.33
conservation standards for distribution
transformers and provided preliminary
discussions in response to a number of
issues raised by comments to the June
2019 Early Assessment Review RFI. It
described the analytical methodology
that DOE used, and each analysis DOE
had performed.
On November 11, 2021, DOE
published a notice reopening the
comment period an additional 30 days.
86 FR 63318.
DOE received comments in response
to the August 2021 Preliminary Analysis
from the interested parties listed in
Table II.4.
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE II.4—AUGUST 2021 PRELIMINARY ANALYSIS WRITTEN COMMENTS
Commenter(s)
Abbreviation
Electric Research and Manufacturing Cooperative, Inc ...........
Powersmiths, Inc .......................................................................
Copper Development Association ............................................
Schneider Electric .....................................................................
National Electrical Manufacturers Association .........................
Northwest Energy Efficiency Alliance .......................................
Appliance Standards Awareness Project, American Council
for an Energy-Efficient Economy, Natural Resources Defense Council.
Metglas, Inc ..............................................................................
Carte International, Inc .............................................................
Eaton Corporation .....................................................................
Edison Electric Institute ............................................................
Cleveland-Cliffs Steel Corporation ............................................
Greenville Electric Utility System ..............................................
Howard Industries, Inc ..............................................................
ERMCO ...................................
Powersmiths ...........................
CDA ........................................
Schneider ................................
NEMA ......................................
NEEA ......................................
Efficiency Advocates ...............
45
46
47
49
50
51
52
Manufacturer.
Manufacturer.
Trade Organization.
Manufacturer.
Trade Organization.
Efficiency Organization.
Efficiency Organization.
Metglas ...................................
Carte .......................................
Eaton .......................................
EEI ..........................................
Cliffs ........................................
GEUS ......................................
Howard ....................................
53
54
55
56
57
58
59
Steel Manufacturer.
Manufacturer.
Manufacturer.
Utilities.
Steel Manufacturer.
Utilities.
Manufacturer.
A parenthetical reference at the end of
a comment quotation or paraphrase
provides the location of the item in the
public record.29
29 The parenthetical reference provides a
reference for information located in the docket of
DOE’s rulemaking to develop energy conservation
standards for distribution transformers. (Docket No.
EERE–2019–BT–STD–0018, which is maintained at
www.regulations.gov). The references are arranged
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C. Deviation From Appendix A
In accordance with section 3(a) of 10
CFR part 430, subpart C, appendix A
(‘‘appendix A’’), DOE notes that it is
deviating from the provision in
appendix A regarding the NOPR stage
for an energy conservation standard
as follows: (commenter name, comment docket ID
number, page of that document).
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Docket No.
Commenter type
rulemaking. Section 6(f)(2) of appendix
A specifies that the length of the public
comment period for a NOPR will vary
depending upon the circumstances of
the particular rulemaking, but will not
be less than 75 calendar days. For this
NOPR, DOE is providing a 60-day
comment period, as required by EPCA.
42 U.S.C. 6316(a); 42 U.S.C. 6295(p). As
stated previously, DOE requested
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comment in the June 2019 Early
Assessment Review RFI on the technical
and economic analyses and provided
stakeholders a 45-day comment period.
84 FR 28239. Additionally, DOE
provided a 75-day comment period for
the August 2021 Preliminary Analysis.
86 FR 48058. DOE also reopened the
comment period for the August 2021
Preliminary Analysis for an additional
30-days. 86 FR 63318. DOE has relied
on many of the same analytical
assumptions and approaches as used in
the preliminary assessment presented in
the TSD. Therefore, DOE believes a 60day comment period is appropriate and
will provide interested parties with a
meaningful opportunity to comment on
the proposed rule.
lotter on DSK11XQN23PROD with PROPOSALS3
III. General Discussion
DOE developed this proposal after
considering oral and written comments,
data, and information from interested
parties that represent a variety of
interests. The following discussion
addresses issues raised by these
commenters.
A. Equipment Classes and Scope of
Coverage
When evaluating and establishing
energy conservation standards, DOE
divides covered products into
equipment classes by the type of energy
used or by capacity or other
performance-related features that justify
differing standards. In making a
determination whether a performancerelated feature justifies a different
standard, DOE must consider such
factors as the utility of the feature to the
consumer and other factors DOE
determines are appropriate. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q))
The distribution transformer
equipment classes considered in this
proposed rule are discussed in further
detail in section IV.A.2 of this
document. This proposed rule covers
distribution transformers which are
currently defined as a transformer that
(1) has an input voltage of 34.5 kV or
less; (2) has an output voltage of 600 V
or less; (3) is rated for operation at a
frequency of 60 Hz; and (4) Has a
capacity of 10 kVA to 2500 kVA for
liquid-immersed units and 15 kVA to
2500 kVA for dry-type units; but (5) The
term ‘‘distribution transformer’’ does
not include a transformer that is an
autotransformer, drive (isolation)
transformer, grounding transformer,
machine-tool (control transformer,
nonventilated transformer, rectified
transformer, regulating transformer,
sealed transformer, special-impedance
transformer, testing transformer,
transformer with tap range of 20 percent
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or more; uninterruptible power supply
transformer; or welding transformer. 10
CFR 431.192
The scope of coverage of this
proposed rule is discussed in further
detail in section IV.A.1 of this
document.
B. Test Procedure
EPCA sets forth generally applicable
criteria and procedures for DOE’s
adoption and amendment of test
procedures. (42 U.S.C. 6314(a))
Manufacturers of covered products must
use these test procedures to certify to
DOE that their product complies with
energy conservation standards and to
quantify the efficiency of their product.
DOE’s current energy conservation
standards for distribution transformers
are expressed in terms of percentage
efficiency at rated per-unit load (PUL).
(See 10 CFR 431.193; 10 CFR part 431,
subpart K, appendix A (‘‘appendix A’’).)
On September 14, 2021, DOE
published a test procedure final rule for
distribution transformers that revised
definitions for certain terms, updated
provisions based on the latest versions
of relevant industry test standards,
maintained PUL for the certification of
efficiency and added provisions for
representing efficiency at alternative
PULs and reference temperatures. 89 FR
51230 (‘‘September 2021 TP Final
Rule’’). DOE determined that the
amendments to the test procedure
adopted in the September 2021 TP Final
Rule do not alter the measured
efficiency of distribution transformers or
require retesting or recertification solely
as a result of DOE’s adoption of the
amendments to the test procedure. Id. at
89 FR 51249.
C. Technological Feasibility
1. General
In each energy conservation standards
rulemaking, DOE conducts a screening
analysis based on information gathered
on all current technology options and
prototype designs that could improve
the efficiency of the products or
equipment that are the subject of the
rulemaking. As the first step in such an
analysis, DOE develops a list of
technology options for consideration in
consultation with manufacturers, design
engineers, and other interested parties.
DOE then determines which of those
means for improving efficiency are
technologically feasible. DOE considers
technologies incorporated in
commercially available products or in
working prototypes to be
technologically feasible. 10 CFR 431.4;
10 CFR part 430, subpart C, appendix A,
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sections 6(b)(3)(i) and 7(b)(1) (‘‘Process
Rule’’).
After DOE has determined that
particular technology options are
technologically feasible, it further
evaluates each technology option in
light of the following additional
screening criteria: (1) practicability to
manufacture, install, and service; (2)
adverse impacts on product utility or
availability; (3) adverse impacts on
health or safety, and (4) unique-pathway
proprietary technologies. 10 CFR 431.4;
Sections 6(c)(3)(ii)–(v) and 7(b)(2)–(5) of
the Process Rule. Section IV.B of this
document discusses the results of the
screening analysis for distribution
transformers, particularly the designs
DOE considered, those it screened out,
and those that are the basis for the
standards considered in this proposed
rule. For further details on the screening
analysis for this proposed rule, see
chapter 4 of the NOPR technical support
document (‘‘TSD’’).
2. Maximum Technologically Feasible
Levels
When DOE proposes to adopt an
amended standard for a type or class of
covered product, it must determine the
maximum improvement in energy
efficiency or maximum reduction in
energy use that is technologically
feasible for such product. (42 U.S.C.
6316(a); 42 U.S.C. 6295(p)(1))
Accordingly, in the engineering
analysis, DOE determined the maximum
technologically feasible (‘‘max-tech’’)
improvements in energy efficiency for
distribution transformers, using the
design parameters for the most efficient
products available on the market or in
working prototypes. The max-tech
levels that DOE determined for this
rulemaking are described in section
IV.C.2.e of this proposed rule and in
chapter 5 of the NOPR TSD.
D. Energy Savings
1. Determination of Savings
For each trial standard level (‘‘TSL’’),
DOE projected energy savings from
application of the TSL to distribution
transformer purchased in the 30-year
period that begins in the year of
compliance with the proposed
standards (2027–2056).30 The savings
are measured over the entire lifetime of
distribution transformers purchased in
the previous 30-year period.31 DOE
30 Each TSL is composed of specific efficiency
levels for each product class. The TSLs considered
for this NOPR are described in section V.A of this
document. DOE conducted a sensitivity analysis
that considers impacts for products shipped in a 9year period.
31 Savings are determined for equipment shipped
over the 30-year analysis period of 2027 through
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quantified the energy savings
attributable to each TSL as the
difference in energy consumption
between each standards case and the nonew-standards case. The no-newstandards case represents a projection of
energy consumption that reflects how
the market for a product would likely
evolve in the absence of amended
energy conservation standards.
DOE used its national impact analysis
(‘‘NIA’’) model to estimate national
energy savings (‘‘NES’’) from potential
amended or new standards for
distribution transformers. The NIA
model (described in section IV.H of this
document) calculates energy savings in
terms of site energy, which is the energy
directly consumed by products at the
locations where they are used. For
electricity, DOE reports national energy
savings in terms of primary energy
savings, which is the savings in the
energy that is used to generate and
transmit the site electricity. DOE also
calculates NES in terms of FFC energy
savings. The FFC metric includes the
energy consumed in extracting,
processing, and transporting primary
fuels (i.e., coal, natural gas, petroleum
fuels), and thus presents a more
complete picture of the impacts of
energy conservation standards.32 DOE’s
approach is based on the calculation of
an FFC multiplier for each of the energy
types used by covered products or
equipment. For more information on
FFC energy savings, see section IV.H.2
of this document.
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2. Significance of Savings
To adopt any new or amended
standards for a covered product, DOE
must determine that such action would
result in significant energy savings. (42
U.S.C. 6295(o)(3)(B))
The significance of energy savings
offered by a new or amended energy
conservation standard cannot be
determined without knowledge of the
specific circumstances surrounding a
given rulemaking.33 For example, some
covered products and equipment have
most of their energy consumption occur
during periods of peak energy demand.
The impacts of these products on the
2056. Distribution transformers have a maximum
lifetime of 60 years; therefore savings are
determined for equipment that survive, and accrue
savings through 2115.
32 The FFC metric is discussed in DOE’s
statement of policy and notice of policy
amendment. 76 FR 51282 (Aug. 18, 2011), as
amended at 77 FR 49701 (Aug. 17, 2012).
33 The numeric threshold for determining the
significance of energy savings established in a final
rule published on February 14, 2020 (85 FR 8626,
8670), was subsequently eliminated in a final rule
published on December 12, 2021 (86 FR 70892,
70906).
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energy infrastructure can be more
pronounced than products with
relatively constant demand.
Accordingly, DOE evaluates the
significance of energy savings on a caseby-case basis, taking into account the
significance of cumulative FFC national
energy savings, the cumulative FFC
emissions reductions, and the need to
confront the global climate crisis, among
other factors. Based on the amount of
FFC savings, the corresponding
reduction in emissions, and need to
confront the global climate crisis, DOE
has initially determined the energy
savings from the proposed standard
levels are ‘‘significant’’ within the
meaning of 42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(3)(B).
E. Economic Justification
1. Specific Criteria
As noted previously, EPCA provides
seven factors to be evaluated in
determining whether a potential energy
conservation standard is economically
justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(I)–(VII))) The following
sections discuss how DOE has
addressed each of those seven factors in
this rulemaking.
a. Economic Impact on Manufacturers
and Consumers
In determining the impacts of a
potential amended standard on
manufacturers, DOE conducts an MIA,
as discussed in section IV.J of this
document. DOE first uses an annual
cash-flow approach to determine the
quantitative impacts. This step includes
both a short-term assessment—based on
the cost and capital requirements during
the period between when a regulation is
issued and when entities must comply
with the regulation—and a long-term
assessment over a 30-year period. The
industry-wide impacts analyzed include
(1) INPV, which values the industry on
the basis of expected future cash flows,
(2) cash flows by year, (3) changes in
revenue and income, and (4) other
measures of impact, as appropriate.
Second, DOE analyzes and reports the
impacts on different types of
manufacturers, including impacts on
small manufacturers. Third, DOE
considers the impact of standards on
domestic manufacturer employment and
manufacturing capacity, as well as the
potential for standards to result in plant
closures and loss of capital investment.
Finally, DOE takes into account
cumulative impacts of various DOE
regulations and other regulatory
requirements on manufacturers.
For individual consumers, measures
of economic impact include the changes
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in LCC and PBP associated with new or
amended standards. These measures are
discussed further in the following
section. For consumers in the aggregate,
DOE also calculates the national net
present value of the consumer costs and
benefits expected to result from
particular standards. DOE also evaluates
the impacts of potential standards on
identifiable subgroups of consumers
that may be affected disproportionately
by a standard.
b. Savings in Operating Costs Compared
To Increase in Price (LCC and PBP)
EPCA requires DOE to consider the
savings in operating costs throughout
the estimated average life of the covered
product in the type (or class) compared
to any increase in the price of, or in the
initial charges for, or maintenance
expenses of, the covered product that
are likely to result from a standard. (42
U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(II)) DOE conducts this
comparison in its LCC and PBP analysis.
The LCC is the sum of the purchase
price of a product (including its
installation) and the operating expense
(including energy, maintenance, and
repair expenditures) discounted over
the lifetime of the product. The LCC
analysis requires a variety of inputs,
such as product prices, product energy
consumption, energy prices,
maintenance and repair costs, product
lifetime, and discount rates appropriate
for consumers. To account for
uncertainty and variability in specific
inputs, such as product lifetime and
discount rate, DOE uses a distribution of
values, with probabilities attached to
each value.
The PBP is the estimated amount of
time (in years) it takes consumers to
recover the increased purchase cost
(including installation) of a moreefficient product through lower
operating costs. DOE calculates the PBP
by dividing the change in purchase cost
due to a more-stringent standard by the
change in annual operating cost for the
year that standards are assumed to take
effect.
For its LCC and PBP analysis, DOE
assumes that consumers will purchase
the covered products in the first year of
compliance with new or amended
standards. The LCC savings for the
considered efficiency levels are
calculated relative to the case that
reflects projected market trends in the
absence of new or amended standards.
DOE’s LCC and PBP analysis is
discussed in further detail in section
IV.F of this document.
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c. Energy Savings
Although significant conservation of
energy is a separate statutory
requirement for adopting an energy
conservation standard, EPCA requires
DOE, in determining the economic
justification of a standard, to consider
the total projected energy savings that
are expected to result directly from the
standard. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(III)) As discussed in
section III.D of this document, DOE uses
the NIA models to project national
energy savings.
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d. Lessening of Utility or Performance of
Products
In establishing product classes and in
evaluating design options and the
impact of potential standard levels, DOE
evaluates potential standards that would
not lessen the utility or performance of
the considered products. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(IV))
Based on data available to DOE, the
standards proposed in this document
would not reduce the utility or
performance of the products under
consideration in this rulemaking.
e. Impact of Any Lessening of
Competition
EPCA directs DOE to consider the
impact of any lessening of competition,
as determined in writing by the
Attorney General, that is likely to result
from a proposed standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(V)) It
also directs the Attorney General to
determine the impact, if any, of any
lessening of competition likely to result
from a proposed standard and to
transmit such determination to the
Secretary within 60 days of the
publication of a proposed rule, together
with an analysis of the nature and
extent of the impact. (42 U.S.C. 6316(a);
42 U.S.C. 6295(o)(2)(B)(ii)) DOE will
transmit a copy of this proposed rule to
the Attorney General with a request that
the Department of Justice (‘‘DOJ’’)
provide its determination on this issue.
DOE will publish and respond to the
Attorney General’s determination in the
final rule. DOE invites comment from
the public regarding the competitive
impacts that are likely to result from
this proposed rule. In addition,
stakeholders may also provide
comments separately to DOJ regarding
these potential impacts. See the
ADDRESSES section for information to
send comments to DOJ.
f. Need for National Energy
Conservation
DOE also considers the need for
national energy and water conservation
in determining whether a new or
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amended standard is economically
justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VI)) The energy savings
from the proposed standards are likely
to provide improvements to the security
and reliability of the Nation’s energy
system. Reductions in the demand for
electricity also may result in reduced
costs for maintaining the reliability of
the Nation’s electricity system. DOE
conducts a utility impact analysis to
estimate how standards may affect the
Nation’s needed power generation
capacity, as discussed in section IV.M of
this document.
DOE maintains that environmental
and public health benefits associated
with the more efficient use of energy are
important to take into account when
considering the need for national energy
conservation. The proposed standards
are likely to result in environmental
benefits in the form of reduced
emissions of air pollutants and
greenhouse gases (‘‘GHGs’’) associated
with energy production and use. DOE
conducts an emissions analysis to
estimate how potential standards may
affect these emissions, as discussed in
section IV.K; the estimated emissions
impacts are reported in section V.B.6 of
this document. DOE also estimates the
economic value of emissions reductions
resulting from the considered TSLs, as
discussed in section IV.L of this
document.
g. Other Factors
In determining whether an energy
conservation standard is economically
justified, DOE may consider any other
factors that the Secretary deems to be
relevant. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VII)) To the extent DOE
identifies any relevant information
regarding economic justification that
does not fit into the other categories
described previously, DOE could
consider such information under ‘‘other
factors.’’
2. Rebuttable Presumption
As set forth in 42 U.S.C.
6295(o)(2)(B)(iii), EPCA creates a
rebuttable presumption that an energy
conservation standard is economically
justified if the additional cost to the
consumer of a product that meets the
standard is less than three times the
value of the first year’s energy savings
resulting from the standard, as
calculated under the applicable DOE
test procedure. DOE’s LCC and PBP
analyses generate values used to
calculate the effects that proposed
energy conservation standards would
have on the payback period for
consumers. These analyses include, but
are not limited to, the 3-year payback
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period contemplated under the
rebuttable-presumption test. In addition,
DOE routinely conducts an economic
analysis that considers the full range of
impacts to consumers, manufacturers,
the Nation, and the environment, as
required under 42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(i). The results of
this analysis serve as the basis for DOE’s
evaluation of the economic justification
for a potential standard level (thereby
supporting or rebutting the results of
any preliminary determination of
economic justification). The rebuttable
presumption payback calculation is
discussed in section IV.F.11 of this
proposed rule.
IV. Methodology and Discussion of
Related Comments
This section addresses the analyses
DOE has performed for this rulemaking
with regard to distribution transformers.
Separate subsections address each
component of DOE’s analyses.
DOE used several analytical tools to
estimate the impact of the standards
proposed in this document. The first
tool is a model that calculates the LCC
savings and PBP of potential amended
or new energy conservation standards.
The national impacts analysis uses a
second model set that provides
shipments projections and calculates
national energy savings and net present
value of total consumer costs and
savings expected to result from potential
energy conservation standards. DOE
uses the third spreadsheet tool, the
Government Regulatory Impact Model
(‘‘GRIM’’), to assess manufacturer
impacts of potential standards. These
tools are available in the docket for this
rulemaking: www.regulations.gov/
docket/EERE-2019-T-STD-0018.
Additionally, DOE used output from the
latest version of the Energy Information
Administration’s (‘‘EIA’s’’) Annual
Energy Outlook (‘‘AEO’’), a widely
known energy projection for the United
States, for the emissions and utility
impact analyses.
A. Market and Technology Assessment
DOE develops information in the
market and technology assessment that
provides an overall picture of the
market for the products concerned,
including the purpose of the products,
the industry structure, manufacturers,
market characteristics, and technologies
used in the products. This activity
includes both quantitative and
qualitative assessments, based primarily
on publicly available information. The
subjects addressed in the market and
technology assessment for this
rulemaking include (1) a determination
of the scope of the rulemaking and
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a. Autotransformers
The EPCA definition of distribution
transformer excludes ‘‘a transformer that
is designed to be used in a special
purpose application and is unlikely to
be used in general purpose applications,
such as . . . [an] auto-transformer . . .’’
(42 U.S.C. 6291(35)(b)(ii)) In response to
comments received as part of the June
2019 Early Assessment Review RFI that
suggested DOE include ‘‘low-voltage
autotransformers’’ within the scope of
distribution transformers, DOE noted
that autotransformers do not provide
galvanic isolation 34 and thus would be
unlikely to be used in at least some
general-purpose applications. (August
2021 Preliminary Analysis TSD at p. 2–
5) In the August 2021 Preliminary
Analysis TSD, DOE requested comment
regarding the potential use of
autotransformers as substitutes for
general-purpose distribution
transformers. Id.
Schneider commented that while
voltage conversion can be done with an
autotransformer, autotransformers
cannot derive a neutral, lower source
impedance, or phase shift to remove
triplen (i.e., multiples-of-three)
harmonics, meaning an autotransformer
risks sacrificing power quality if used in
place of a general-purpose distribution
transformer. (Schneider, No. 59 at p. 2)
Schneider added that because of these
power quality concerns,
autotransformers would be unlikely to
be used in commercial buildings but
could be used in some subsegments and
smaller commercial jobs—a possibility
supported by manufacturers’ adding
autotransformers to standard product
catalogs. (Schneider, No. 49 at p. 2)
Schneider commented that it
recommends autotransformers in
subsegments that require wye-wye
connections 35 and that segment is
growing and will continue to grow if
autotransformers remain exempt.
(Schneider, No. 49 at p. 2) Schneider
commented that that are no technical
limitations for autotransformer to meet
standards and asserted that the
exclusion was related to how efficiency
was calculated and tested. Schneider
recommended subjecting them to the
current efficiency standards based on
their nameplate kVA. (Schneider, No. 49
at pp. 2–3) Schneider commented that
in typical applications (i.e., 480Y/277
and 208Y/120) autotransformers would
be 60 percent the size and 20–25
percent less expensive. In non-typical
applications, units would be 20 percent
the size and 50 percent less expensive.
(Schneider, No. 49 at p. 3)
NEMA commented that it is not aware
of autotransformers being used in place
of distribution transformers. (NEMA,
No. 50 at p. 3)
Stakeholder comments suggest that
there may be certain applications in
which an autotransformer may be
substitutable for an isolation
transformer. However, the comments
also suggest such substitution is limited
to specific applications (e.g., wye-wye
connections) and not common enough
to be regarded as general practice.
Further, DOE did not receive any
feedback counter to its statement in the
August 2021 Preliminary Analysis TSD
34 i.e., autotransformers contain a continuous,
current-carrying electrical pathway that ‘‘isolation’’
transformers do not, which is perceived as a safety
compromise in some applications.
35 Wye connection refers to four distribution
transformer terminals, three of which are connected
to one power phase and the fourth connected to all
three power phases.
product classes, (2) manufacturers and
industry structure, (3) existing
efficiency programs, (4) shipments
information, (5) market and industry
trends; and (6) technologies or design
options that could improve the energy
efficiency of distribution transformers.
The key findings of DOE’s market
assessment are summarized in the
following sections. See chapter 3 of the
NOPR TSD for further discussion of the
market and technology assessment.
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1. Scope of Coverage
The current definition for a
distribution transformer codified in 10
CFR 431.192 is the following:
Distribution transformer means a
transformer that—(1) Has an input
voltage of 34.5 kV or less; (2) Has an
output voltage of 600 V or less; (3) Is
rated for operation at a 60 Hz; and (4)
Has a capacity of 10 kVA to 2500 kVA
for liquid-immersed units and 15 kVA
to 2500 kVA for dry-type units; but (5)
The term ‘‘distribution transformer’’
does not include a transformer that is
an—(i) Autotransformer; (ii) Drive
(isolation) transformer; (iii) Grounding
transformer; (iv) Machine-tool (control)
transformer; (v) Nonventilated
transformer; (vi) Rectifier transformer;
(vii) Regulating transformer; (viii)
Sealed transformer; (ix) Specialimpedance transformer; (x) Testing
transformer; (xi) Transformer with tap
range of 20 percent or more; (xii)
Uninterruptible power supply
transformer; or (xiii) Welding
transformer.
DOE received several comments
regarding the definition of ‘‘distribution
transformer’’ and the definitions of
equipment excluded from the
definition. These detailed comments are
discussed below.
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that autotransformers do not provide
galvanic isolation and thus would be
unlikely to be used in at least some
general-purpose applications. Based on
this feedback, DOE is not proposing to
amend the exclusion of
autotransformers under the distribution
transformer definition. DOE will
monitor the market and may reevaluate
this exclusion if evidence exists to
support growing use of autotransformers
based on lower purchase price than
would be warranted by technical
considerations alone.
b. Drive (Isolation) Transformers
In the August 2021 Preliminary
Analysis TSD, DOE noted that the EPCA
definition of distribution transformers
excludes a transformer that is designed
to be used in a special purpose
application and is unlikely to be used in
general purpose applications, such as a
drive transformer. (42 U.S.C.
6291(35)(b)(ii)) DOE stated that it did
not have any data indicating that ‘‘drive
isolation transformers’’ were being
widely used in generally purpose
applications and as such, considered
them statutorily excluded. DOE
requested comment and data as to the
extent to which ‘‘drive isolation
transformers’’ are used in generally
purpose applications. (August 2021
Preliminary Analysis TSD at p. 2–6)
Schneider and Eaton commented that
drive isolation transformers have
historically been sold with nonstandard
low-voltage ratings, corresponding to
typical motor input voltages, and as
such are unlikely to be used in generalpurpose applications. (Schneider, No.
49 at p. 3; Eaton, No. 55 at p. 3) NEMA
commented that drive isolation
transformers are not sold in great
quantities and not widely used in
general purpose applications. (NEMA,
No. 50 at p. 3)
Schneider and Eaton commented that
recently there has been some increase in
drive isolation transformers specified as
having either a ‘‘480Y/277’’ or ‘‘208Y/
120’’ voltage secondary, making it more
difficult to ascertain whether these
transformers are being used in general
distribution applications. (Schneider
No. 49 at p. 3; Eaton, No. 55 at p. 3)
Schneider commented that only 6-pulse
drive isolation transformers 36 can serve
36 Drive-isolation transformers employ rectifier
diodes to mitigate drive harmonics by phase
shifting secondary voltages. The rectifier diode
results in two pulses per phase. In a standard threephase, drive-isolation transformer, application of a
rectifier would result in 6-pulses, two per 120°
phase shift. If additional harmonic mitigation is
needed, additional secondary windings are added
with differing connections phase shifted from one
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general purpose applications.
(Schneider, No. 49 at p. 4) Eaton added
that there is a minor concern that
consumers will increasingly discover
that drive isolation transformers can be
used in certain general-purpose
applications, putting manufacturers in
the position of suspecting but not being
able to ascertain circumvention without
being sure of end use. (Eaton, No. 55 at
p. 3) Eaton commented that a DOE
compliant general-purpose transformer
would be 16 percent more expensive
than a drive isolation transformer that
could be used in its place, while the
losses for the drive isolation transformer
at 50 percent PUL were 55 percent
greater. (Eaton, No. 55 at p. 3)
Eaton commented that pulse count is
somewhat hard to define as it is
generally more a function of the rectifier
that the drive isolation transformer is
connected to than the transformer itself.
(Eaton, No. 55 at p. 4) Eaton added that
12-pulse and 24-pulse drive isolation
transformers could, technically, be used
in general purpose applications but that
it would be less likely due to higher
cost. (Eaton, No. 55 at p. 3–4)
Schneider commented that 6-pulse
drive isolation transformers should be
included in the LVDT scope, as is
required in Canada. (Schneider, No. 49
at p. 4)
Commenters indicated that while
some drive isolation transformers could,
in theory be used in general purpose
applications, no evidence exists
suggesting this practice is common. As
such, DOE has concluded that drive
isolation transformers remain an
example of a transformer that is
designed to be used in special purpose
applications and is unlikely to be used
in general purpose applications. Given
that drive isolation transformers are
excluded by statute, including drive
isolation transformers would first
require a finding that they are being
used in general purpose applications,
which does not appear to be the case at
this time.
Schneider commented that drive
isolation transformers should only be
permitted at standard motor voltages
and not standard distribution voltages.
(Schneider, No. 49 at p. 3)
DOE tentatively finds, as supported
by comments from Schneider and Eaton,
that certain distribution transformers
that meet the current criteria of a ‘‘drive
isolation transformers’’ are likely to be
used in general-purpose applications
based on their voltage rating. The
overwhelming majority of equipment in
the US is designed to operate using
another. Manufacturers’ sell drive-isolation
transformers as 6-pulse, 12-pulse, or 24-pulse.
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either 208Y/120 or 480Y/277 voltage,
and therefore the overwhelming
majority of general-purpose distribution
transformers have a secondary voltage
rating that is one of these standard
voltage ratings. Drive-isolation
transformers, by contrast, are not
designed to power the majority of
equipment. Rather, they are designed to
work with a specific motor drive to
output a special purpose voltage, unique
to the application. As such, driveisolation transformers with a rated
secondary voltage of 208Y/120 or 480Y/
277 is considerably more likely to be
used in general purpose applications
rather than special purpose
applications.
EPCA excludes from the definition of
distribution transformer certain
transformers designed to be used in an
application other than a general-purpose
application. Specifically, ‘‘distribution
transformer’’ excludes a transformer that
is ‘‘designed to be used in a special
purpose application and is unlikely to
be used in general purpose applications,
such as a drive transformer, rectifier
transformer, auto-transformer,
Uninterruptible Power System
transformer, impedance transformer,
regulating transformer, sealed and
nonventilating transformer, machine
tool transformer, welding transformer,
grounding transformer, or testing
transformer[.]’’ (42 U.S.C.
6291(35)(b)(ii))
Drive (isolation) transformers are
defined as ‘‘a transformer that: (1)
Isolates an electric motor from the line;
(2) Accommodates the added loads of
drive-created harmonics; and (3) Is
designed to withstand the additional
mechanical stresses resulting from an
alternating current adjustable frequency
motor drive or a direct current motor
drive.’’ 10 CFR 431.192. In the product
catalogs reviewed by DOE, driveisolation transformers are frequently
listed at common motor voltages such as
‘‘460Y/266’’ and ‘‘230Y/133.’’. The
listing at common motor voltages
indicates that these drive-isolation
transformers are designed for use in
special purpose applications (i.e.,
isolating an electric motor from the line)
and are unlikely to be used in general
purpose distribution applications, on
account of not aligning with general
distribution voltages.
DOE has previously stated that it
intends to strictly and narrowly
construe the exclusions from the
definition of ‘‘distribution transformer.’’
84 FR 24972, 24979 (April 27, 2009). To
the extent that some transformers are
marketed as drive-isolation transformers
but with rated output voltages aligning
with common distribution voltages,
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DOE is unable to similarly conclude that
these transformers are used in special
purpose applications. Comments by
Eaton and Schneider confirm that while
these transformers are not sold in great
numbers, they are significantly more
likely to be used in general purpose
distribution applications. As such, DOE
has tentatively determined that such
distribution transformers are not drive
(isolation) transformers as that term
applies to the exclusions from the
definition of ‘‘distribution transformer.’’
In order to limit the definition of
drive isolation transformers to
distribution transformers designed for
use in special purpose applications and
not likely to be used in general purpose
applications, DOE proposes to amend
the definition to include the criterion
that drive isolation transformers have an
output voltage other than 208Y/120 or
480Y/277. DOE may consider additional
voltage limitations in the definition of
‘‘drive isolation transformer’’ should
DOE determine such voltages indicate a
design for use in general purpose
applications.
DOE requests comment on the
proposed amendment to the definition
of drive (isolation) transformer. DOE
requests comment on its tentative
determination that voltage ratings of
208Y/120 and 480Y/277 indicate a
design for use in general purpose
applications. DOE also requests
comment on other voltage ratings or
other characteristics that would indicate
a design for use in general purpose
applications.
c. Special-Impedance Transformers
Impedance is an electrical property
that relates voltage across and current
through a distribution transformer. It
may be selected to balance voltage drop,
overvoltage tolerance, and compatibility
with other elements of the local
electrical distribution system. A
transformer built to operate outside of
the normal impedance range for that
transformer’s kVA rating, as specified in
Tables 1 and 2 of 10 CFR 431.192 under
the definition of ‘‘special-impedance
transformer,’’ is excluded from the
definition of ‘‘distribution transformer.’’
10 CFR 431.192.
In the August 2021 Preliminary
Analysis TSD, DOE requested feedback
as to the number of nonstandard kVA
transformers sold and how
manufacturers are currently interpreting
the normal impedance range for
nonstandard kVA values. (August 2021
Preliminary Analysis TSD at p. 2–8)
NEMA and Eaton recommended that
the impedance values in Tables 1 and 2
of 10 CFR 431.192 under the definition
of ‘‘special-impedance transformer’’ be
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listed as a kVA range, to remove what
they stated is an ambiguity as to the
normal impedance of non-standard
transformer capacities (i.e., capacities
not explicitly included in the tables).
(Eaton, No. 55 at p. 4; NEMA, No. 50 at
p. 3–4) Eaton commented that there
were very few nonstandard kVA ratings
for single-phase transformers and just
under one percent of three-phase
transformers are rated for non-standard
kVAs. (Eaton, No. 55 at p. 4) Eaton
added that nonstandard kVAs are quite
common in the currently exempted
step-up transformers, making up 27
percent of three-phase step-up
transformers. (Eaton, No. 55 at p. 4)
Eaton stated that it currently uses the
impedance values of the adjacent
standard kVA ratings that result in the
largest normal impedance range and,
equivalently, the narrowest excluded
impedance range. (Eaton, No. 55 at p. 5)
NEMA commented that many, but not
all, customers specify the middle of the
normal impedance range. NEMA stated
that some customers specify a particular
impedance to compliment an
application, such as for protection
equipment or to match better with
sensitive loads. (NEMA, No. 50 at p. 4)
Schneider commented that it receives
few requests for distribution
transformers outside the normal
impedance range and few requests for
distribution transformers with
nonstandard kVAs and therefore
applied energy efficiency regulations to
special impedance transformers without
pursuing exemptions. (Schneider, No.
49 at p. 4) Schneider added that the
special impedance exemption could
potentially be removed, and thus reduce
potential abuse or the normal range
could be expanded for all distribution
transformers, regardless of kVA to be
from 0.5 percent to 15 percent.
(Schneider, No. 49 at p. 4) As another
alternative, Schneider recommended
either setting the mid-range impedance
as a threshold or using a linear
interpolation of the impedance values
immediately above and below that kVA
rating, similar to how efficiency
standards are applied for non-standard
kVA ratings. (Schneider, No. 49 at p. 4–
5)
As DOE noted in the August 2021
Preliminary Analysis TSD, its current
values for normal impedance are based
on NEMA TP 2–2005. (August 2021
Preliminary Analysis TSD at p. 2–8) The
current tables in the ‘‘special-impedance
transformer’’ definition do not explicitly
address how to treat nonstandard kVA
values.
DOE is proposing to amend the
definition of ‘‘special-impedance
transformer’’ to specify that
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‘‘distribution transformers with kVA
ratings not appearing in the tables shall
have their minimum normal impedance
and maximum normal impedance
determined by linear interpolation of
the kVA and minimum and maximum
impedances, respectively, of the values
immediately above and below that kVA
rating.’’. This proposed approach is
consistent with the recommendation
from Schneider. Moreover, this
approach is consistent with the
approach specified for determining the
required efficiency requirements of
distribution transformers of
nonstandard kVA rating (i.e., using a
linear interpolation from the nearest
bounding kVA values listed in the
table). See 10 CFR 431.196.
DOE requests comment on its
proposed amendment to the definition
of ‘‘special-impedance transformer’’ and
whether it provides sufficient clarity as
to how to treat the normal impedance
ranges for non-standard kVA
distribution transformers.
Carte commented that one of its
customers requires higher impedance
pole transformers, within the ‘‘normal’’
range, but in general the larger coils and
higher core losses associated with a
higher impedance can be disadvantaged
in meeting efficiency standards. (Carte,
No. 54 at p. 1)
DOE relies on the current definition of
‘‘special-impedance transformer’’ in its
engineering analysis. DOE does not
further consider impedance aside from
ensuring selectable models in the
analysis are within the ‘‘normal
impedance’’ range as currently defined.
DOE’s analyzed higher efficiency levels,
including those using amorphous steel,
span a range of impedance values and
therefore DOE has not considered
further separating distribution
transformers based on impedance.
d. Tap Range of 20 Percent or More
Transformers with multiple voltage
taps, the highest of which equals at least
20 percent more than the lowest,
computed based on the sum of the
deviations of the voltages of these taps
from the transformer’s nominal voltage,
are excluded from the definition of
distribution transformers. 10 CFR
431.192. (See also, 42 U.S.C.
6291(35)(B)(i)) In the August 2021
Preliminary Analysis TSD, DOE
requested comment as to whether only
full-power taps should count toward the
exclusion and how the choice of
nominal voltage would impact the
exclusion. (August 2021 Preliminary
Analysis TSD at p. 2–9)
In response, Schneider, NEMA and
Eaton commented that only full-power
taps should be permitted for tap range
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calculations. (Eaton, No. 55 at pp. 5–6;
Schneider, No. 49 at pp. 5–6; NEMA,
No. 50 at p. 4)
Eaton commented that nominal
voltage is selected by the consumer but
selecting one such that it excludes a
product can result in 17 percent lower
costs and 73 percent higher losses at 50
percent PUL. (Eaton, No. 55 at p. 6)
Schneider provided an example of how
the nominal voltage can impact whether
a product is subject to standards.
(Schneider, No. 49 at p. 6) Eaton
commented that of the three-phase units
it has built, only one unit was built as
having a tap range of 20 percent or more
while 112 units were built as DOE
compliant but could be moved out of
scope based on the choice of nominal
voltage. (Eaton, No. 55 at pp. 6–7)
Schneider added that another
complication to using nominal voltage
is a new type of distribution transformer
that has multiple-nominal voltages.
(Schneider, No. 49 at p. 6–8)
Eaton supported changing how the
tap range is calculated to remove
potential incentives to circumvent
standards. (Eaton, No. 55 at p. 6) NEMA
commented that it did not reach
consensus as to how to calculate tap
range. (NEMA, No. 50 at p. 4) Schneider
recommended DOE establish all
common system voltages as nominal
and have manufacturers justify tap
ranges according to the relative function
of each to the associated nominal in the
case of multiple nominals. (Schneider,
No. 49 at p. 8) Schneider added that if
it is too difficult to establish what
nominal should be, the 20 percent tap
range exclusion could be removed.
(Schneider, No. 49 at p. 8)
While the traditional industry
understanding of tap range is in
percentages relative to the nominal
voltage, stakeholder comments suggest
that such a calculation can be applied
differently by different manufacturers
such that two physically identical
distribution transformers can be inside
or outside of scope depending on the
choice of nominal voltage. To have a
consistent standard for physically
identical distribution transformers, DOE
proposes to modify the calculation of
tap range to only include full-power
capacity taps and calculate tap range
based on the transformer’s maximum
voltage rather than nominal voltage. The
amended definition would classify
transformers with tap ranges of 20
percent or more as ‘‘a transformer with
multiple full-power voltage taps, the
highest of which equals at least 20
percent more than the lowest, computed
based on the sum of the deviations of
these taps from the transformer’s
maximum full-power voltage.’’. Such a
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modification would ensure that all
distribution transformers capable of
operating across a similar voltage range,
regardless of what voltage is considered
nominal, are treated equally. Further,
the proposed modification removes
ambiguity as to what customers are
using as a nominal voltage and removes
incentives to change the nominal
voltage to move equipment into or out
of scope of the standards.
DOE requests comment on its
proposed definition for transformers
with a tap range of 20 percent or more.
e. Sealed and Nonventilated
Transformers
As discussed, the statutory definition
of distribution transformer excludes
transformers that are designed to be
used in a special purpose application
and are unlikely to be used in general
purpose applications, such as a ‘‘sealed
and nonventilating transformers.’’ (42
U.S.C. 6291(35)(b)(ii)) In the August
2021 Preliminary Analysis TSD, DOE
noted that the definition of sealed and
nonventilating transformers is
applicable only to dry-type
transformers. While liquid-immersed
transformers are technically also sealed,
DOE has explicitly included them in the
definition of a distribution transformer.
10 CFR 431.92. (August 2021
Preliminary Analysis TSD at p. 2–7)
In response, NEMA recommended
DOE add the words ‘‘dry-type’’ to the
definition of sealed and nonventilated
transformers. (NEMA, No. 50 at p. 3)
DOE agrees that the proposed
clarification would help clarify the
scope of the sealed and nonventilated
transformer exclusion and has proposed
to amend the definition as such.
DOE requests comment on its
proposed amendments to the definitions
of sealed and nonventilated
transformers.
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f. Step-Up Transformers
For transformers generally, the term
‘‘step-up’’ refers to the function of a
transformer providing greater output
voltage than input voltage. Step-up
transformers primarily service energy
producing applications, such as solar or
wind electricity generation, and input
source voltage, step-up the voltage in
the transformer, and output higher
voltages that feed into the electric grid.
The definition of ‘‘distribution
transformer’’ does not explicitly exclude
transformers designed for step-up
operation.
However, most step-up transformers
have an output voltage larger than the
600 V limit specified in the distribution
transformer definition. See 10 CFR
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431.192. (See also 42 U.S.C.
6291(35)(A)(ii))
DOE has acknowledged it is
technically possible to operate a step-up
transformer in a reverse manner, by
connecting the high-voltage to the
‘‘output’’ winding of a step-up
transformer and the low-voltage to the
‘‘input’’ winding of a step-up
transformer, such that it functions as a
distribution transformer. 78 FR 2336,
23354. However, DOE previously had
not identified this as a widespread
practice. Id. In the August 2021
Preliminary Analysis TSD, DOE
requested feedback as to what the
typical efficiency is of step-up
transformers, what fraction are being
used in traditional distribution
transformer applications, and what are
the typical input and output voltages of
step-up transformers. (August 2021
Preliminary Analysis TSD at p. 2–18)
NEMA commented that efficiency of
step-up transformers is dictated by
customers and is sometimes above and
sometimes below DOE efficiency levels
for distribution transformers. NEMA
added that they are not aware of stepup transformers being used in
distribution applications and they are
concerned that subjecting step-up
transformers to regulation may
negatively constrain design flexibility.
(NEMA, No. 50 at p. 5)
Eaton commented that step-up
transformers are almost exclusively
used in renewable energy applications
where low-voltages (typically less than
700 volts) are stepped up to mediumvoltage distribution applications
(typically up to 34.5 kV). Eaton added
that virtually all step-up transformers
are three-phase and there are maybe a
dozen single-phase step-up transformers
per year which may or may not be
possible circumvention scenarios.
(Eaton, No. 55 at p. 9) Eaton commented
that some step-up transformer
customers specify total owning cost,
maximum losses, or efficiency and
provided a table of average efficiency of
three-phase liquid-immersed step-up
transformers which showed the average
efficiency of step-up transformers
tended to be below DOE efficiency
standards. (Eaton, No. 55 at p. 9) Eaton
noted that many solar photovoltaic
inverter manufacturers have been using
higher input voltages that often require
non-standard voltages or winding
configurations and may decrease
likelihood of a step-up transformer
being used in a distribution application.
(Eaton, No. 55 at p. 9) Eaton stated that
31 percent of their three-phase step-up
transformers had common distribution
low-voltages, that could more easily be
used in distribution applications, but
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Eaton had no knowledge that step-up
transformers were being used in
traditional distribution applications.
(Eaton, No. 55 at p. 9) Eaton stated that
step-up voltages with common
distribution high and low-voltages
could possibly be operated in reverse in
distribution transformer applications.
(Eaton, No. 55 at p. 9)
The comments received support
DOE’s prior statements. While step-up
transformers could, in theory, be used in
distribution applications, DOE does not
have any data to indicate that this is a
common or widespread practice. Eaton’s
comments underscore that step-up
transformers serve a separate and
unique application, often in the
renewable energy field where
transformers designs may not be
optimized for the distribution market
but rather are optimized for integration
with other equipment, such as inverters.
Therefore, DOE is not proposing to
amend the definition of ‘‘distribution
transformer’’ to account for step-up
transformers. DOE may reevaluate this
conclusion in a future action if evidence
arises to suggest step-up transformers
are being used in distribution functions.
g. Uninterruptible Power Supply
Transformers
‘‘Uninterruptible power supply
transformer’’ is defined as a transformer
that is used within an uninterruptible
power system, which in turn supplies
power to loads that are sensitive to
power failure, power sags, over voltage,
switching transients, line noise, and
other power quality factors. 10 CFR
431.192. An uninterruptable power
supply transformer is excluded from the
definition of distribution transformer.
42 U.S.C. 6291(35)(B)(ii); 10 CFR
431.192. Such a system does not stepdown voltage, but rather it is a
component of a power conditioning
device and it is used as part of the
electric supply system for sensitive
equipment that cannot tolerate system
interruptions or distortions, and
counteracts such irregularities. 69 FR
45376, 45383. DOE has clarified that
uninterruptable power supply
transformers do not ‘‘supply power to’’
an uninterruptible power system, rather
they are ‘‘used within’’ the
uninterruptible power system. 72 FR
58190, 58204. This is consistent with
the reference in the definition to
transformers that are ‘‘within’’ the
uninterruptible power system. 10 CFR
431.192. Distribution transformers at the
input, output or bypass that are
supplying power to the uninterruptible
power system are not uninterruptable
power supply transformers.
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As stated, the definition of
‘‘distribution transformer’’ is based, in
part, on the voltage capacity of
equipment, i.e., has an input voltage of
34.5 kV or less; and has an output
voltage of 600 V or less. 10 CFR 431.192.
(42 U.S.C. 6291(35)(A)) Three-phase
distribution transformer voltage may be
described as either ‘‘line’’, i.e.,
measured across two lines, or ‘‘phase’’,
i.e., measured across one line and the
neutral conductor. For deltaconnected 37 distribution transformers,
line and phase voltages are equal. For
wye-connected distribution
transformers, line voltage is equal to
phase voltage multiplied by the square
root of three.
DOE notes that it has previously
stated that the definition of distribution
transformer applies to transformers
having an output voltage of 600 volts or
less, not having only an output voltage
of less than 600 volts. 78 FR 23336,
23353. For example, a three-phase
transformer for which the wye
connection is at or below 600 volts, but
the delta connection is above 600 volts
would satisfy the output criteria of the
distribution transformer definition.
DOE’s test procedure requires that the
measured efficiency for the purpose of
determining compliance be based on
testing in the configuration that
produces the greatest losses, regardless
of whether that configuration alone
would have placed the transformer atlarge within the scope of coverage. Id.
Similarly with input voltages, a
transformer is subject to standards if
either the ‘‘line’’ or ‘‘phase’’ voltages fall
within the voltage limits in the
definition of distribution transformers,
so long as the other requirements of the
definition are also met. Id.
Eaton commented that DOE flipped
the usage of wye and delta in its
example where one voltage complies
and the other does not because wye
voltage should be less than delta
voltage. (Eaton, No. 55 at p. 8) DOE has
updated its language above to correct
this.
Schneider commented that the
industry interpretation of input and
output voltage is likely line voltage but
using phase encompasses a larger scope
and DOE should clarify in the regulatory
text. (Schneider, No. 49 at p. 8) NEMA
commented that DOE should clarify the
interpretation of voltage in the
regulatory text. (NEMA, No. 50 at p. 4)
Eaton commented that using phase
voltage would deviate from industry
convention, but if DOE is choosing to
interpret language this way, it should
explicitly say so in the regulatory text.
(Eaton, No. 55 at pp. 7–8)
DOE notes that the voltage limits in
the definition of distribution
transformer established in EPCA do not
specify whether line or phase voltage is
to be used. 42 U.S.C. 6291(35). DOE has
previously stated that a distribution
transformer is required to comply if
either line or phase voltage is within the
scope of the distribution transformer
definition. 78 FR 23336, 23353. Upon
further evaluation, DOE notes that the
distribution transformer input voltage
limitation aligns with the common
maximum distribution circuit voltage of
34.5 kV.38 39 This common distribution
37 Delta connection refers to three distribution
transformer terminals, each one connected to two
power phases.
38 Pacific Northwest National Lab and U.S.
Department of Energy (2016), ‘‘Electricity
Distribution System Baseline Report.’’, p. 27.
In the August 2021 Preliminary
Analysis TSD, DOE requested comment
regarding how manufacturers are
applying the definition of
uninterruptable power supply
transformer and whether amendments
are needed. (August 2021 Preliminary
Analysis TSD at p. 2–10)
In response, NEMA commented that
manufacturers are applying the
definition appropriately and
clarification is not needed. (NEMA, No.
50 at p. 4) Schneider recommended
DOE explicitly state that transformers at
the input, output, or by-pass of an
uninterruptible power system are not
part of the uninterruptible power system
and as such are not excluded.
(Schneider, No. 49 at p. 8).
DOE agrees that explicitly stating that
transformers at the input, output, or
bypass of a distribution transformer are
not a part of the uninterruptable power
system would further clarify the
definition. As such, DOE is proposing to
amend the definition to make these
clarifications.
DOE requests comment on its
proposed amendment to the definition
of uninterruptable power supply
transformers.
Carte asked if network transformers
are considered uninterruptible power
supply transformers as the network grid
cannot go down. (Carte, No. 54 at p. 2)
DOE notes that the need for a reliable
operation does not make a distribution
transformer an uninterruptible power
supply transformer. As stated,
uninterruptible power supply
transformers are used within
uninterruptable power systems as a
power conditioning device, not as a
distribution transformer.
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h. Voltage Specification
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voltage aligns with the distribution line
voltage and implies that the intended
definition of distribution transformer in
EPCA was to specify the input and
output voltages based on the line
voltage. DOE has tentatively determined
that applying the phase voltage, as DOE
cited in the April 2013 Standards Final
Rule, would cover products not
traditionally understood to be
distribution transformers and not
intended to be within the scope of
distribution transformer as defined by
EPCA. For example, a transformer with
a line voltage of 46 kV, which is
commonly considered in industry to be
a subtransmission voltage (i.e., higher
than a distribution voltage), would have
a phase voltage less than 34.5 kV if sold
in a wye-connection. Despite this
transformer not being considered a
distribution transformer by industry,
interpreting DOE’s definition as either a
line or phase voltage would mean that
a 46 kV wye-connection is considered a
distribution transformer. As noted by
stakeholders, such an interpretation
would be out of step with common
industry practice and out of step with
the intended coverage of EPCA.
DOE notes that the common
distribution transformer voltages have
both line and phase voltages that are
within DOE’s scope, and therefore the
proposed change is not expected to
impact the scope of this rulemaking
aside from select, unique transformers
with uncommon voltages. In this NOPR,
DOE is proposing to modify the
definition of distribution transformer to
state explicitly that the input and output
voltage limits are based on the ‘‘line’’
voltage and not the phase voltage. This
amendment, while a slight
reinterpretation relative to the April
2013 Standards Final Rule, better aligns
with industry practice, minimizes
confusion, and does not impact any of
the commonly built distribution
transformer designs.
DOE requests comment as to whether
its proposed definition better aligns
with industries understanding on input
and output voltages.
Further, DOE requests comment and
data on whether the proposed
amendment would impact products that
are serving distribution applications,
and if so, the number of distribution
transformers impacted by the proposed
amendment.
Available at www.energy.gov/sites/prod/files/2017/
01/f34/Electricity%20Distribution
%20System%20Baseline%20Report.pdf.
39 U.S. Department of Energy (2015), ‘‘United
States Electricity Industry Primer.’’ Available at
www.energy.gov/sites/prod/files/2015/12/f28/
united-states-electricity-industry-primer.pdf.
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i. kVA Range
The EPCA definition for distribution
transformers does not include any
capacity range. In codifying the current
distribution transformer capacity ranges
in 10 CFR 431.192, DOE noted that
distribution transformers outside of
these ranges are not typically used for
electricity distribution. 71 FR 24972,
24975–24976. Further, DOE noted that
transformer capacity is to some extent
tied to its primary and secondary
voltages, meaning that the EPCA
definitions has the practical effect of
limiting the maximum capacity of
transformers that meet those voltage
limitations to approximately 3,750 to
5,000 kVA, or possibly slightly higher.
Id. However, DOE further stated the
inclusion of capacity limitations in the
definition of ‘‘distribution transformers’’
in 10 CFR 431.192 does not mean that
DOE has concluded that the EPCA
definition of ‘‘distribution transformer’’
includes such limitations and stated
that DOE intends to evaluate larger and
smaller capacities than those included
in the definition. Id.
DOE’s current definition of
distribution transformer specifies a
capacity of 10 kVA to 2,500 kVA for
liquid-immersed units and 15 kVA to
2,500 kVA for dry-type units. 10 CFR
431.192. The kVA ranges are consistent
with NEMA publications in place at the
time DOE adopted the range,
specifically NEMA TP–1 standard. 78
FR 23336, 23352. DOE cited these
documents as evidence that its kVA
scope is consistent with industry
understanding (i.e., NEMA TP–1 and
NEMA TP–2), but noted that it may
revise its understanding in the future as
the market evolves. 78 FR 23336, 23352.
Subsequent to the April 2013 Standards
Final Rule, establishing the current
energy conservation standards, NEMA
TP–1 standard was rescinded.
As noted above, the voltage
limitations included in EPCA
practically limit the size of distribution
transformers. However, several industry
sources suggest that those limitations
may be greater than the current 2,500
kVA limit included in DOE’s definition
in 10 CFR 431.192. For example,
Natural Resources Canada (‘‘NRCAN’’)
regulations include three-phase dry-type
distribution transformers with a
nominal power of 15 to 7,500 kVA.40
The European Union (‘‘EU’’) Ecodesign
requirements specify maximum load
losses and maximum no-load losses for
three-phase liquid-immersed
distribution transformers up to 3,150
kVA.41 IEEE C57.12.90 and C57.12.91
cite similar short circuit tests for threephase distribution transformers up to
5,000 kVA.
In the August 2021 Preliminary
Analysis TSD, DOE requested comment
regarding the quantity and efficiency of
distribution transformers outside of the
kVA range of the definition of
distribution transformer but with input
and output voltages that meet the
voltage criteria in said definition.
(August 2021 Preliminary Analysis TSD
at p. 2–11)
Regarding dry-type distribution
transformers, Schneider commented
that units below 15 kVA are typically
sealed or non-ventilated and as such
would be excluded from the definition
of distribution transformers. (Schneider,
No. 49 at p. 9) Eaton commented that
single-phase liquid immersed
distribution transformers less than 10
kVA were less than 1 percent of
shipments. (Eaton, No. 55 at p. 8)
DOE has not received any data or
information suggesting that expanding
the scope of the standards below 10
kVA for liquid-immersed distribution
transformers or below 15 kVA for drytype distribution transformers would
lead to significant energy savings. As
such, DOE is not proposing any changes
to the lower capacity limit in the
distribution transformer definition.
Regarding sales of distribution
transformers beyond the 2,500 kVA
scope, NEMA commented that while
there are sales of models over 2,500
kVA, they are not sold in significant
numbers as compared to in-scope
products and energy savings would be
limited. (NEMA, No. 50 at p. 5) Eaton
commented that 19.6 percent of their
three-phase liquid-immersed
transformers have input and output
voltage in-scope, but kVAs above 2500
kVA. (Eaton, No. 55 at p. 8) Eaton
provided average efficiencies for these
larger kVA distribution transformers.
(Eaton, No. 55 at p. 8) In interviews,
manufacturers commented that many of
the larger distribution transformers are
serving renewable applications as stepup transformers and would therefore be
outside the scope of the standards
regardless of the upper capacity of the
definition of distribution transformer.
However, while many larger
transformers may be step-up
transformers, stakeholder comments
suggest that there are also general
40 See NRCAN dry-type transformer energy
efficiency regulations at www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875.
41 Official Journal of the European Union,
Commission Regulation (EU) No. 548/2014, May 21,
2014, Available online at: https://eur-lex.europa.eu/
legal-content/EN/TXT/?uri=uriserv%3AOJ.L_
.2014.152.01.0001.01.ENG.
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purpose distribution transformers sold
above 2,500 kVA with primary and
secondary voltages that would still be
within the criteria of the definition of
distribution transformer. While NEMA
suggested sales of models above 2,500
kVA are small, Eaton’s comments
suggest that at least for some
manufacturers or markets they could be
notable. Further, some manufacturers in
interviews expressed concern that in the
presence of amended energy
conservation standards, there may be
increased incentive to build distribution
transformers that are just above the
existing scope (e.g., 2,501 kVA).
As such, it is appropriate for DOE to
consider all distribution transformers
that are serving general purpose
distribution applications, even if the
capacity of those distribution
transformers is larger than the common
unit. DOE is considering multiple
possible upper limits for distribution
transformer capacity. IEEE C57.12.00–
2015 lists the next three preferred
continuous kVA ratings above 2,500
kVA as 3,750 kVA, 5,000 kVA, and
7,500 kVA. Eaton’s comments suggest
that the upper end of their distribution
capacity is 3,750 kVA. In a prior
rulemaking, stakeholders commented
that their product lines include medium
voltage dry-type models up to around
5,000 kVA.42 Further, NRCAN
regulations cover dry-type distribution
transformers up to 7,500 kVA but
exclude distribution transformers with
low-voltage line currents of 4,000 amps
or more.
Taken together, these points suggest
there are some sales of general purpose
distribution transformers above 2,500
kVA, such as at 3,750 kVA and
5,000kVA. DOE does not have any data
or evidence that general purpose
distribution transformers are being sold
above 5,000 kVA and does have prior
public comment of 5,000 kVA
transformers with distribution voltages
being sold. Therefore, DOE is proposing
to expand the scope of the definition of
‘‘distribution transformer’’ in 10 CFR
431.192 for both liquid-immersed
distribution transformers and dry-type
distribution transformers to include
distribution transformers up to 5,000
kVA. DOE is also considering other
upper limits on the scope of distribution
transformer, including 3,750 kVA and
7,500 kVA.
DOE requests comment and data as to
whether 5,000 kVA represents the upper
end of what is considered distribution
42 See Federal Pacific comment on Docket No.
EERE–2006–STD–0099–0105. Available at
www.regulations.gov/comment/EERE-2006-STD0099-0105.
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transformers or if another value should
be used.
DOE has also estimated potential
energy savings associated with
expanding coverage of distribution
transformers between 2,500 and 5,000
kVA within scope. DOE relied on public
comments and confidential data sources
to estimate shipments between 2,500
kVA and 5,000 kVA. Further, DOE has
scaled its engineering analysis to
encompass these larger units. Although
the number of units shipped is
estimated to represent a fraction of a
percentage of total covered shipments,
DOE has designed these scaled models
as new representative units on account
of starting from an unregulated baseline,
as compared to the rest of the market,
for which the baseline transformer
complies with existing energy
conservation standards. For liquidimmersed distribution transformers,
representative unit 17 corresponds to a
three-phase 3,750 kVA unit. For
medium-voltage dry-type distribution
transformers, representative units 18
and 19 correspond to a three-phase
3,750 kVA unit with a BIL of 46–95 kV
and greater than 96 kV, respectively.
DOE has estimated the distribution
transformer efficiency by assuming
these out-of-scope units are purchased
based on lowest first cost and would
rely on similar grades of electrical steel
as the distribution transformers that are
currently in-scope units but would not
currently be meeting any efficiency
standard.
DOE requests comment and data as to
the number of shipments of three-phase,
liquid-immersed, distribution
transformers greater than 2,500 kVA that
would meet the in-scope voltage
limitations and the distribution of
efficiencies of those units.
DOE requests comment and data as to
the number of shipments of three-phase,
dry-type, distribution transformers
greater than 2,500 kVA that would meet
the in-scope voltage limitations and the
distribution of efficiencies of those
units.
2. Equipment Classes
DOE must specify a different standard
level for a type or class of product that
has the same function or intended use,
if DOE determines that products within
such group: (A) consume a different
kind of energy from that consumed by
other covered products within such type
(or class); or (B) have a capacity or other
performance-related feature which other
products within such type (or class) do
not have and such feature justifies a
higher or lower standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q)(1)) In
determining whether a performancerelated feature justifies a different
standard for a group of products, DOE
must consider such factors as the utility
to the consumer of the feature and other
factors DOE deems appropriate. Id. Any
rule prescribing such a standard must
include an explanation of the basis on
which such higher or lower level was
established. (42 U.S.C. 6316(a); 42
U.S.C. 6295(q)(2))
Eleven equipment classes are
established under the existing standards
for distribution transformers, one of
which (mining transformers 43) is not
subject to energy conservation
standards. 10 CFR 431.196. The
remaining ten equipment classes are
delineated according to the following
characteristics: (1) Type of transformer
insulation: Liquid-immersed or drytype, (2) Number of phases: single or
three, (3) Voltage class: low or medium
(for dry-type only), and (4) Basic
impulse insulation level (BIL) (for
MVDT only).
Table II.1 presents the eleven
equipment classes that exist in the
current energy conservation standards
and provides the kVA range associated
with each.
TABLE IV.1—CURRENT EQUIPMENT CLASSES FOR DISTRIBUTION TRANSFORMERS
EC * #
Insulation
Voltage
EC1 ...............
EC2 ...............
EC3 ...............
EC4 ...............
EC5 ...............
EC6 ...............
EC7 ...............
EC8 ...............
EC9 ...............
EC10 .............
Liquid-Immersed ..........
Liquid-Immersed ..........
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Dry-Type ......................
Medium ........................
Medium ........................
Low ..............................
Low ..............................
Medium ........................
Medium ........................
Medium ........................
Medium ........................
Medium ........................
Medium ........................
EC11 .............
Phase
Single
Three
Single
Three
Single
Three
Single
Three
Single
Three
...........................
...........................
...........................
...........................
...........................
...........................
...........................
...........................
...........................
...........................
BIL rating
......................................
......................................
......................................
......................................
20–45 kV BIL ...............
20–45 kV BIL ...............
46–95 kV BIL ...............
46–95 kV BIL ...............
≥96 kV BIL ...................
≥96 kV BIL ...................
kVA range
10–833 kVA
15–2500 kVA
15–333 kVA
15–1000 kVA
15–833 kVA
15–2500 kVA
15–833 kVA
15–2500 kVA
75–833 kVA
225–2500 kVA
Mining Transformers
* EC = Equipment Class.
In the August 2021 Preliminary
Analysis TSD, DOE requested comment
on a variety of other potential
equipment setting factors. (August 2021
Preliminary Analysis TSD at p. 2–16–
22) These comments are discussed in
detail below.
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a. Pole- and Pad-Mounted Transformers
43 A mining distribution transformer is a mediumvoltage dry-type distribution transformer that is
built only for installation in an underground mine
or surface mine, inside equipment for use in an
underground mine or surface mine, on-board
equipment for use in an underground mine or
surface mine, or for equipment used for digging,
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DOE currently does not divide poleand pad-mounted distribution
transformers into separate equipment
classes. In the August 2021 Preliminary
Analysis TSD, DOE requested comment
and data to characterize the effect of
mounting configuration on distribution
transformer efficiency, weight, volume,
and likelihood of introducing
ferroresonace.44 (August 2021
Preliminary Analysis TSD at p. 2–19)
Eaton commented that ferroresonance
is rare and only occurs in pad mounted
transformers. (Eaton, No. 55 at pp. 9–10)
Eaton added that ferroresonance is more
likely to occur in low no-load loss cores,
and commented that these effects can be
mitigated with certain core designs that
are slightly less efficient. (Eaton, No. 55
drilling, or tunneling underground or above ground,
and that has a nameplate which identifies the
transformer as being for this use only. 10 CFR
431.192.
44 Ferroresonance refers to the nonlinear
resonance resulting from the interaction of system
capacitive and inductive elements which can lead
to damaging high voltages in distribution
transformers. Pad-mounted distribution
transformers that are delta-connected are
particularly susceptible to ferroresonance effects.
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at pp. 9–10) Eaton added that it has
produced thousands of low-loss 5-leg
distribution transformers and is
unaware of a single occurrence of
ferroresonace. (Eaton, No. 55 at pp. 9–
10)
DOE did not receive any data
suggesting that pole- and pad-mounted
distribution transformers warrant
separate equipment classes. As such,
DOE has not proposed to amend the
current equipment class structure for
pole- and pad-mounted distribution
transformers. Further, DOE includes
both pole- and pad-mounted
representative units in its engineering
analysis.
b. Submersible Transformers
Certain distribution transformers are
installed underground and, accordingly,
may endure partial or total immersion
in water. This scenario commonly arises
for distribution transformers installed in
chambers called ‘‘vaults’’, which are
commonly made of concrete. Access is
typically, but not always, through an
opening in the top (‘‘ceiling’’) face of the
vault, through which the distribution
transformer can be lowered for
installation or replacement.
‘‘Submersible’’, ‘‘network’’ and
‘‘vault-based’’ are three attributes that
often all apply to a particular
distribution transformer unit, but which
carry distinct meanings. Informally,
‘‘submersible’’ refers to ability to
operate while submerged, ‘‘network’’
refers to ability to operate as part of a
network of interconnected secondary
windings as most typically occurs in
urban environments, and ‘‘vault-based’’
refers to siting within a vault, which
may be but is not necessarily below
grade. A given distribution transformer,
for example, may be installed within an
above-grade vault but not rated as
submersible. Similarly, a particular
network distribution transformer may
happen to be installed within a vault,
but able to operate as well outside of a
vault.
In the April 2013 Standards Final
Rule, DOE included additional costs for
vault replacements in the LCC analysis
but noted there was no technical barrier
that prevents network, vault-based and
submersible distribution transformers
from achieving the same efficiency
levels as other liquid-immersed
distribution transformers. 78 FR 23336,
23356–23357. In the August 2021
Preliminary Analysis TSD, DOE
preliminarily stated that it would take a
similar approach in applying the costs
of vault enlargement as a function of
increased distribution transformer
volume for RU4 and RU5. (August 2021
Preliminary Analysis TSD at p. 2–89)
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DOE requested comment on some of the
options a customer is likely to explore
before incurring the cost of vault
expansion, such as using a lower-loss
core steel, copper windings, or a lessflammable insulating fluid. (August
2021 Preliminary Analysis TSD at p. 2–
20)
NEMA commented that when trying
to fit into a given space, copper
windings may allow for a 20 percent
size reduction relative to aluminum and
higher-grade core steels can help, but it
is still sometimes very difficult to
reduce footprint while meeting
standards. (NEMA, No. 50 at p. 6) Carte
requested an exclusion for retro fit
designs. (Carte, No. 54 at p. 2)
Carte commented that most network
transformers are lightly loaded but
redundancy is quite important and as
such many customers require high
overload capabilities. (Carte, No. 54 at p.
1) Carte added that in certain
applications, with limited space, there
is reduced cooling which forces
manufacturers to lower load loss at the
expense of core loss to maintain reliable
operation. (Carte, No. 54 at pp. 1–2) EEI
recommended DOE include a separate
product class for vault transformers.
(EEI, No. 56 at p. 3)
As discussed, EPCA requires that a
rule prescribing an energy conservation
standard for a type of covered
equipment specify a level of energy use
or efficiency higher or lower than that
which applies (or would apply) to any
group of covered equipment that has the
same function or intended use, if the
Secretary determines that covered
equipment within such group:
(A) Consume a different kind of
energy from that consumed by other
covered products within such type (or
class); or
(B) Have a capacity or other
performance-related feature that other
products within such type (or class) do
not have and such feature justifies a
higher or lower standard from that
which applies (or will apply) to other
products within such type (or class).
(42 U.S.C. 6313(a); 42 U.S.C. 6295(q)(1))
In making a determination of whether
a performance-related feature justifies
the establishment of a higher or lower
standard, the Secretary must consider
such factors as the utility to the
consumer of such a feature, and such
other factors as the Secretary deems
appropriate. Id.
As noted, DOE previously determined
there was no technical barrier to vault
distribution transformers achieving
similar efficiency standards as other
similar distribution transformers. To the
extent significant costs arise for more-
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efficient units, they are generally
installation costs (i.e., expanding the
size of the vault in which the
distribution transformer is installed).
Installation costs are addressed in the
LCC and PBP analyses, as well as in
consumer subgroup-specific analyses.
These analyses account for the cost of
difficult (i.e., unusually costly)
installations, including those subgroups
of the population that may be
differentially impacted by DOE’s
consideration of amended energy
conservation standards (see section
IV.I.2 of this document).
Review of comments and the
equipment market indicates that certain
vault-based distribution transformers
also are designed to operate in
submersible applications. Because many
vaults are subterranean, distribution
transformers installed in such locations
often require ability to operate while
submerged. Installation below grade
makes more likely that distribution
transformers may operate while
submerged in water and with other runoff debris. Distribution transformers for
installation in such environments are
designed to withstand harsh conditions,
including corrosion.
The subterranean installation of
submersible distribution transformers
means that there is less circulation of
ambient air for shedding heat. Operation
while submerged in water and in
contact with run-off debris, further
impacts the ability of a distribution
transformer to transfer heat to the
environment and limits the alternative
approaches in the external environment
that can be used to increase cooling.
With respect to heat transfer, the
industry standards governing
submersible distribution transformers,
i.e., IEEE C57.12.23–2018 and
C57.12.24–2016, specify that
submersible distribution transformers,
amongst other requirements, have their
capacity rated for a maximum
temperature rise of 55°C but have their
insulation be rated for 65°C. IEEE
C57.12.80–2010 defines submersible
distribution transformer as ‘‘a
transformer so constructed as to be
successfully operable when submerged
in water under predetermined
conditions of pressure and time.’’
Distribution transformer temperature
rise tends to be governed by load losses.
Often, design options that reduce load
losses, increase no-load losses. While
no-load losses make up a relatively
small portion of losses at full load, noload losses contribute approximately
equally to load losses at 50 percent PUL,
at which manufacturers must certify
efficiency. The potentially reduced heat
transfer of the subterranean
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environment, combined with the
possibility of operating while
submerged, limits customers from
meeting the temperature rise limitations
through any choice other than reducing
load losses. Therefore, the design
choices needed to meet a lower
temperature rise, may tend to lead
manufacturers to increase no-load losses
and may make it more difficult to meet
a given efficiency standard at 50 percent
PUL.
DOE recognizes that distribution
transformers other than those designed
for submersible operation may be
derated (rated for a lower temperature
rise) for other reasons, such as
installation in ambient temperatures
over 40°C, greater harmonic currents, or
installation at altitudes above 1000
meters. However, the ability to improve
the efficiency of such distribution
transformers is not similarly limited as
submersible distribution transformers
because other options exist for
distribution transformers above grade
that would not be feasible in submerged
environments, namely the ability to
increase heat transfer, often with some
additional cost, as opposed to only
options that increase a distribution
transformer’s no-load losses. For
example, distribution transformers
installed above grade may be able to
have more air circulation through
radiators, improving the efficiency of
radiators to shed heat, or adding
external forced air cooling on a
distribution transformer radiator,
whereas such a measure would not be
able to function as intended in a
submerged environment.
Based on the foregoing discussion,
DOE has tentatively determined that
distribution transformers designed to
operate while submerged and in contact
with run-off debris have a performancerelated feature which other types of
distribution transformers do not have.
While at max-tech efficiency levels both
no-load and load losses are so low that
distribution transformers generally do
not meet their rated temperature rise, at
intermediate efficiency levels, trading
load losses for no-load losses allows
distribution transformers to be rated for
a lower temperature rise, however, it
also may make it more difficult to meet
any amended efficiency standard as noload losses contribute proportionally
more to efficiency at the test procedure
PUL as compared to rated temperature
rise. Therefore, DOE is proposing that
providing for operation in installation
locations at which the units are partially
or wholly submerged in water justifies
a different standard on account of the
additional constraint which forces
manufacturers to trade load losses for
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no-load losses. DOE has modeled the
derating of these distribution
transformers and the associated costs
associated with these submersible
distribution transformers, as described
in section IV.C.1 of this document.
In proposing separate equipment
classes, DOE relies on physical features
to distinguish one product class from
another. While the IEEE definition of
‘‘submersible transformer’’ described
how a submersible distribution
transformer should perform, it does not
include specific physical features that
would allow DOE to identify
submersible transformers from other
general purpose distribution
transformers. In reviewing industry
standards, DOE notes that submersible
distribution transformers are rated for a
temperature rise of 55°C, have
insulation rated for 65°C, have sealedtank construction, and have the tank,
cover, and all external appurtenances be
made of corrosion-resistant material.
Consistent with industry practice, DOE
is proposing to define submersible
distribution transformer as ‘‘a liquidimmersed distribution transformer so
constructed as to be successfully
operable when submerged in water
including the following features: (1) is
rated for a temperature rise of 55°C; (2)
has insulation rated for a temperature
rise of 65°C; (3) has sealed-tank
construction; and (4) has the tank,
cover, and all external appurtenances
made of corrosion-resistant material.’’
DOE notes that IEEE C57.12.80–2010
defines several other types of
distribution transformers that would
potentially also meet the proposed
definition of ‘‘submersible distribution
transformer.’’ IEEE C57.12.80–2010
defines ‘‘vault-type transformer’’ as ‘‘a
transformer that is so constructed as to
be suitable for occasional submerged
operation in water under specified
conditions of time and external
pressure.’’ Similarly, IEEE C57.12.80–
2010 defines ‘‘network transformer’’ as
‘‘a transformer designed for use in a
vault to feed a variable capacity system
of interconnected secondaries,’’ and
states that ‘‘a network transformer may
be of the submersible or of the vault
type.’’ To the extent network and vaulttype distribution transformers were to
meet the proposed definition of
submersible distribution transformer,
they would be included in the
submersible distribution transformer
equipment class.
DOE requests comment on its
understanding and proposed definition
of ‘‘submersible’’ distribution
transformer. Specifically, DOE requests
information on specific design
characteristics of distribution
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transformers that allow them to operate
while submerged in water, as well as
data on the impact to efficiency
resulting from such characteristics.
DOE requests comment and data as to
the impact that submersible
characteristics have on distribution
transformer efficiency.
c. Multi-Voltage-Capable Distribution
Transformers
DOE’s test procedure section 5.0 of
appendix A requires determining the
efficiency of multi-voltage-capable
distribution transformers in the
configuration in which the highest
losses occur. In the August 2021
Preliminary Analysis TSD, DOE
acknowledged that certain multi-voltage
distribution transformers, particularly
non-integer ratio 45 distribution
transformers could have a harder time
meeting an amended efficiency standard
as it results in an unused portion of a
winding when testing in the highest
losses configuration and therefore
reduces the measured efficiency.
(August 2021 Preliminary Analysis TSD
at p. 2–21) DOE requested comment on
the difference in losses associated with
multi-voltage distribution transformers.
(August 2021 Preliminary Analysis TSD
at p. 2–21)
Schneider commented that the higher
nominal voltage tends to be more
efficient, but the degree of increased
losses depends on the kVA and
difference between nominal voltages.
(Schneider, No. 49 at p. 9) Schneider
commented that the challenge for DOE
is ensuring manufacturers are testing in
worst case conditions and
recommended DOE require
manufacturers to identify these
transformers and/or requiring on the
distribution transformer nameplate.
(Schneider, No. 49 at pp. 10–12)
Schneider recommended DOE audit
these multi-voltage designs to ensure
they are testing under proper
conditions. (Schneider No. 49 at pp. 12–
13) Schneider expanded that these
products should not have a separate
equipment class but should be audited
by DOE. (Schneider, No. 49 at p. 13)
Schneider’s data indicates that the
degree of coil loss increase associated
with multi-voltage secondary
distribution transformers ranges from
3.7 percent to 10.8 percent of full-load
coil losses. (Schneider No. 49 at p. 10)
45 For example, a primary winding low voltage
configuration of 7200 V and a primary winding high
voltage configuration of 14400 V represents a 2
times increase in voltage. Whereas a primary
winding low voltage configuration of 7200 V and
a primary winding high voltage configuration of
13200 V represents a non-integer increase in voltage
leaving some portion of the coil unused.
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DOE notes that each efficiency level
considered offers a range of no-load and
load loss combinations for meeting
efficiency levels. While a multi-voltage
transformer may require manufacturers
to invest more in reducing no-load loss
relative to a similar single voltage
transformer, it would generally still be
able to serve those customers’ needs that
request a multi-voltage distribution
transformer.
ERMCO and NEMA acknowledged
that some multi-voltage units may have
a harder time achieving efficiency
standards but did not provide a
recommendation as to how to treat
them. (ERMCO, No. 45 at p. 1; NEMA,
No. 50 at p. 6) Eaton commented that
transformers with multiple voltage
rating and non-whole integer ratings
have unused turns and require
additional space in the core window
leading to higher losses. (Eaton, No. 55
at p. 12) Carte identified emergency use
distribution transformers which have
multiple high voltages and low voltages
and can be used anywhere in a system
until a proper replacement is added,
and asked how standards apply to them.
(Carte, No. 54 at p. 2)
As discussed, EPCA requires that a
rule prescribing an energy conservation
standard for a type of covered
equipment specify a level of energy use
or efficiency higher or lower than that
which applies (or would apply) to any
group of covered equipment that has the
same function or intended use, if the
Secretary determines that covered
equipment within such group:
(A) Consume a different kind of
energy from that consumed by other
covered products within such type (or
class); or
(B) Have a capacity or other
performance-related feature that other
products within such type (or class) do
not have and such feature justifies a
higher or lower standard from that
which applies (or will apply) to other
products within such type (or class).
(42 U.S.C. 6313(a); 42 U.S.C. 6295(q)(1))
In making a determination of whether
a performance-related feature justifies
the establishment of a higher or lower
standard, the Secretary must consider
such factors as the utility to the
consumer of such a feature, and such
other factors as the Secretary deems
appropriate. Id.
DOE acknowledges that multi-voltage
distribution transformers, specifically
those with non-integer ratios, offer the
performance feature of being able to be
installed in multiple locations within
the grid (such as in emergency
applications) and easily upgrade grid
voltages without replacing a distribution
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transformer. These transformers are
often used in upgrading distribution
line voltages and as such when the
distribution line voltage is upgraded,
these distribution transformers would
have greater efficiency than their
certified efficiency. These distribution
transformers have additional, unused
winding turns when operated at their
lower voltage which increase losses.
However, once the distribution grid has
been increased to the higher voltage, the
entire winding will be used, increasing
the efficiency of the product. However,
DOE lacks data as to the degree of noload loss and load loss increase
associated with transitioning from a
single primary and secondary voltage
distribution transformer to a multivoltage distribution transformer.
DOE notes that the NRCAN
regulations specify that ‘‘For a threephase transformer having multiple highvoltage windings and a voltage ratio
other than 2:1, the minimum energy
efficiency standard from the table or
interpolated is reduced by 0.11.’’
Similarly, EU regulations permit
between a 10 to 20 percent increase in
load losses for dual voltage transformers
and between 15 and 20 percent increase
in no-load losses, depending on the type
of dual voltage.
Schneider commented that multivoltage transformers do not need a
lesser standard as it is a manufacturers
choice to produce them. (Schneider, No.
49 at p. 10) Schneider added that they
have many non-integer multi-voltage
ratios offered and do not believe it is
necessary to create a new class for these
products. (Schneider, No. 49 at p. 10)
Stakeholder comments suggest that
the difference in voltages associated
with multi-voltage distribution
transformers is relatively small. Further,
technologies that increase the efficiency
of single-voltage distribution
transformers also increase the efficiency
of multi-voltage distribution
transformers. For these reasons, DOE
has not proposed a separate equipment
class for multi-voltage-capable
distribution transformers with a voltage
ratio other than 2:1.
However, DOE may consider a
separate product class if sufficient data
is provided to demonstrate that these
distribution transformers justify a
different energy conservation standard.
DOE notes that these distribution
transformers would not be permitted to
have a lesser standard than currently
applicable to them on account of
EPCA’s anti-backsliding provisions at 42
U.S.C. 6295(o).
DOE requests data on the difference in
load loss by kVA for distribution
transformers with multiple-voltage
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ratings and a voltage ratio other than
2:1.
DOE request data on the number of
shipments for each equipment class of
distribution transformers with multivoltage ratios other than 2:1.
d. High-Current Distribution
Transformers
Carte commented that low secondary
voltages with high currents can increase
the cost and weight of a distribution
transformer and may require switching
to copper. (Carte, No. 54 at p. 1) NEMA
commented that new production
machines may be needed for certain
winding configurations near technical
limits, such as large kVA distribution
transformers with 208 voltage
secondaries. (NEMA, No. 50 at p. 10)
Eaton commented that lower voltage
windings have higher currents which
may require rectangular conductors and
can make winding more complicated.
(Eaton, No. 55 at p. 12) Eaton added that
at some sizes, the conductor becomes
too thick to be used in a transformer.
(Eaton, No. 55 at p. 12) NEMA
commented that these designs are on the
cusp of max-tech today. (NEMA, No. 50
at p. 10)
Distribution transformers with high
currents tend to have increased stray
losses which can impact the efficiency
of distribution transformers. NEMA
cited a 2,000 kVA design with a 208V
secondary where buss losses contribute
approximately 12 percent to the full
load losses of the transformer. (NEMA,
No. 50 at p. 5) DOE notes that NRCAN
regulations exclude transformers with a
nominal low-voltage line current of
4000 A or more. In general, this
amperage limitation would impact large
distribution transformers with lowvoltage secondary windings.
DOE notes that in high-current
applications, while stray losses may be
slightly higher, manufacturers have the
option to use copper secondaries to
decrease load losses or a copper buss
bar. Technologies that increase the
efficiency of lower-current distribution
transformers also increase the efficiency
of high-current distribution
transformers. To the extent new
production machines would be needed
to accommodate the increased strip
widths associated with high-current
distribution transformers, those would
be accounted for in the manufacturer
impact analysis. For these reasons, DOE
has not proposed a separate equipment
class for high-current distribution
transformers.
However, DOE may consider a
separate product class if sufficient data
is provided to demonstrate that highcurrent distribution transformers justify
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a different energy conservation
standard. DOE notes that these
distribution transformers would not be
permitted to have a lesser standard than
currently applicable to them on account
of EPCA’s anti-backsliding provisions at
42 U.S.C. 6295(o).
DOE requests data on the difference in
load loss by kVA for distribution
transformers with higher currents and at
what current it becomes more difficult
to meet energy conservation standards.
DOE requests data as to the number of
shipments of distribution transformers
with the higher currents that would
have a more difficult time meeting
energy conservation standards.
e. Data Center Distribution Transformer
In the April 2013 Standard Final Rule,
DOE considered a separate equipment
class for data center distribution
transformers, defined as the following:
‘‘i. Data center transformer means a
three-phase low-voltage dry-type
distribution transformer that—
(i) Is designed for use in a data center
distribution system and has a nameplate
identifying the transformer as being for
this use only;
(ii) Has a maximum peak energizing
current (or in-rush current) less than or
equal to four times its rated full load
current multiplied by the square root of
2, as measured under the following
conditions—
1. During energizing of the
transformer without external devices
attached to the transformer that can
reduce inrush current;
2. The transformer shall be energized
at zero +/¥3 degrees voltage crossing of
a phase. Five consecutive energizing
tests shall be performed with peak
inrush current magnitudes of all phases
recorded in every test. The maximum
peak inrush current recorded in any test
shall be used;
3. The previously energized and then
de-energized transformer shall be
energized from a source having
available short circuit current not less
than 20 times the rated full load current
of the winding connected to the source;
and
4. The source voltage shall not be less
than 5 percent of the rated voltage of the
winding energized; and
(vii) Is manufactured with at least two
of the following other attributes:
1. Listed as a Nationally Recognized
Testing Laboratory (NRTL), under the
Occupational Safety and Health
Administration, U.S. Department of
Labor, for a K-factor rating greater than
K–4, as defined in Underwriters
Laboratories (UL) Standard 1561: 2011
Fourth Edition, Dry-Type General
Purpose and Power Transformers;
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2. Temperature rise less than 130 °C
with class 220 (25) insulation or
temperature rise less than 110 °C with
class 200 (26) insulation;
3. A secondary winding arrangement
that is not delta or wye (star);
4. Copper primary and secondary
windings;
5. An electrostatic shield; or
6. Multiple outputs at the same
voltage a minimum of 15° apart, which
when summed together equal the
transformer’s input kVA capacity.’’ 46
DOE did not adopt this definition of
‘‘data center distribution transformers’’
or establish a separate class for such
equipment for the following reasons: (1)
the considered definition listed several
factors unrelated to efficiency; (2) the
potential risk of circumvention of
standards and that a transformer may be
built to satisfy the data center definition
without significant added expense; (3)
operators of data centers are generally
interested in equipment with high
efficiencies because they often face large
electricity costs, and therefore may be
purchasing at or above the standard
established and unaffected by the rule;
and (4) data center operator can take
steps to limit in-rush current external to
the data center transformer. 78 FR
23336, 23358.
In the August 2021 Preliminary
Analysis TSD, DOE stated that data
center distribution transformers could
represent a potential equipment class
setting factor and requested additional
data about the data center distribution
transformer market, performance
characteristics, and any physical
features that could distinguish data
center distribution transformers from
general purpose distribution
transformers. (August 2021 Preliminary
Analysis TSD at p. 2–22)
DOE did not receive any comments as
to physical features that could
distinguish a data center distribution
transformer from a general-purpose
distribution transformer.
DOE requests comment as to what
modifications could be made to the
April 2013 Standard Final Rule data
center definition such that the
identifying features are related to
efficiency and would prevent a data
center transformer from being used in a
general purpose application.
NEMA commented that most data
center transformers are outside the
scope due to kVA range, but those still
within scope would likely have high
loading and would not be favored for
amorphous transformers. (NEMA, No.
50 at p. 6)
46 78
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Eaton commented that liquidimmersed distribution transformers are
increasingly being used in data center
applications. (Eaton, No. 55 at p. 10)
Eaton added that the quantity and
overall energy consumed in data center
applications has increased significantly.
(Eaton, No. 55 at p. 10) Eaton
commented that the lifespan of a data
center transformer would vary
depending on loading. (Eaton, No. 55 at
p. 11)
Eaton commented that liquidimmersed data center transformers are
designed to operate between 50–75
percent PUL and are typically specified
to meet DOE efficiency standards.
(Eaton, No. 55 at pp. 10–11)
DOE did not receive any comments
suggesting that data center distribution
transformers warrant a separate product
class. As such, DOE has not proposed a
definition for data center distribution
transformers and has not evaluated
them as a separate product class.
However, DOE may consider a separate
product class if sufficient data is
provided to demonstrate that data center
transformers warrant a different
efficiency level and can appropriately
be defined. Distribution transformers
used in data centers may sometimes, but
not necessarily, be subject to different
operating conditions and requirements
which carry greater concern
surrounding inrush current.
DOE requests comment regarding its
proposal not to establish a separate
equipment class for data center
distribution transformers. In particular,
DOE seeks comment regarding whether
data center distribution transformers are
able to reach the same efficiency levels
as distribution transformers generally
and the specific reasons why that may
be the case.
DOE requests comment regarding any
challenges that would exist if designing
a distribution transformer which uses
amorphous electrical steel in its core for
data center applications and whether
data center transformers have been built
which use amorphous electrical steel in
their cores.
DOE requests comment on the
interaction of inrush current and data
center distribution transformer design.
Specifically, DOE seeks information
regarding: (1) the range of inrush current
limit values in use in data center
distribution transformers; (2) any
challenges in meeting such inrush
current limit values when using
amorphous electrical steel in the core;
(3) whether using amorphous electrical
steel inherently increases inrush
current, and why; (4) how the
(magnetic) remanence of grain-oriented
electrical steel compares to that of
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amorphous steel; and (5) other strategies
or technologies than distribution
transformer design which could be used
to limit inrush current and the
respective costs of those measures.
f. BIL Rating
Distribution transformers are built to
carry different basic impulse level
(‘‘BIL’’) ratings. BIL ratings offer
increased resistance to large voltage
transients, for example, from lightning
strikes. Due to the additional winding
clearances required to achieve a higher
BIL rating, high BIL distribution
transformers tend to be less efficient,
leading to higher costs and be less able
to achieve higher efficiencies. DOE
separates medium-voltage dry-type
distribution transformers into
equipment classes based on BIL ratings.
10 CFR 431.196(c).
In the August 2021 Preliminary
Analysis TSD, DOE noted stakeholder
comments that evaluating additional
liquid-immersed distribution
transformers based on BIL rating would
add additional complications for minor
differences in losses. As such, DOE did
not consider BIL in its evaluation of
liquid-immersed distribution
transformers.
In response, Howard commented that
150 kV and 200 kV BIL units should not
have their efficiency standards
increased as these units are already too
large. (Howard, No. 59 at pp. 1–2) Carte
commented that 200 kV BIL
transformers have more insulation that
increases the size of the transformer and
therefore the losses of the transformer.
(Carte, No. 54 at p. 1) Eaton commented
that high BIL transformers can have a
harder time meeting efficiency
standards. (Eaton, No. 55 at p. 12)
Neither Eaton, Howard nor Carte
provided any data suggesting the degree
of efficiency difference as BIL is
increased. Based on the discussion in
the preceding paragraphs, DOE is not
proposing a separate equipment class
based on BIL rating for liquid-immersed
units but may consider it if sufficient
data is provided.
DOE requests data as to how a liquidimmersed distribution transformer
losses vary with BIL across the range of
kVA values within scope.
Regarding MVDTs, NEMA
commented that MVDT with BIL levels
above 150 kV are essentially nonexistent and would not represent a
significant amount of energy savings if
regulated. (NEMA, No. 50 at p. 7)
DOE notes that MVDTs above 150 kV
BIL are currently regulated. In the
August 2021 Preliminary Analysis TSD,
DOE requested data on the change in
efficiency associated with higher BIL
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ratings for distribution transformers and
the volume of dry-type distribution
transformers sold with BIL ratings above
199 kV. DOE did not receive any data
and therefore has maintained its current
equipment class separation of MVDTs.
g. Other Types of Equipment
Stakeholders identified several other
distribution transformer types that they
noted may have a harder time meeting
efficiency standards. NEMA commented
that MVDTs at high altitude may require
more air clearance and therefore must
accommodate higher core loss, and as
such, may warrant a separate equipment
class. (NEMA, No. 50 at p. 5) Carte
asked DOE to analyze main and teaser
and Scott connected transformers which
it stated are unique to certain industrial
grids and can be very difficult or
impossible to replace.47 (Carte, No. 54 at
p. 2)
Carte asked how efficiency standards
apply to duplex transformers which
have two kVA ratings on one
transformer.48 (Carte, No. 54 at p. 2)
Carte asked if three winding
simultaneous loading transformers used
in solar applications to isolate the lowvoltage qualify for an exemption. (Carte,
No. 54 at p. 2)
DOE did not receive any data as to the
degree of difference in efficiency
associated with these distribution
transformers. DOE has not considered
any of the noted products as separate
equipment classes in this NOPR
analysis due to lack of data as to the
shipments and reduction in efficiency
associated with certain designs.
Regarding how standards are applied to
certain equipment, DOE notes that
equipment that meets the definition of
distribution transformer is subject to
energy conservation standards at 10 CFR
431.196.
DOE requests comments and data on
any other types of equipment that may
have a harder time meeting energy
conservation standards. Specifically,
DOE requests comments as to how these
other equipment are identified based on
physical features from general purpose
distribution transformers, the number of
shipments of each unit, and the
possibility of these equipment being
used in place of generally purpose
distribution transformers.
47 Main and Teaser and Scott connected
transformers are a special type of transformer which
converts from three-phase energy to two phase
energy or vice versa using two electricallyconnected single-phase transformers
48 Duplex transformers consist of two singlephase transformers assembled in a single enclosure.
They are generally used to provide a large singlephase output in tandem with a smaller three-phase
output
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3. Test Procedure
The current test procedure for
measuring the energy consumption of
distribution transformers is established
at appendix A to subpart K of 10 CFR
part 431. In a September 2021 TP Final
Rule, DOE maintained that energy
efficiency be evaluated at 50 percent
PUL for liquid-immersed distribution
transformers and medium-voltage drytype distribution transformers and 35
percent PUL for low-voltage dry-type
distribution transformers. 86 FR 51230.
In the August 2021 Preliminary
Analysis TSD, DOE acknowledged that
its estimates for current root-meansquare (‘‘RMS’’) in-service loading is
less than the test procedure PUL but
noted there was uncertainty which
makes it preferential to overestimate
PUL rather than underestimate PUL.
DOE noted that any potential energy
savings that could be achieved by
changing the standard PUL could also
be achieved by increasing the stringency
of the energy conservation standards. As
such, DOE only considered distribution
transformers that would meet energy
conservation standards at DOE’s test
procedure loading, but evaluated energy
saving potential using in-service data
and load growth estimates.
In response, CDA agreed with the test
procedure loading and stated that they
believe the loading will match future
forecasts. (CDA, No. 47 at p. 2)
NEEA and the Efficiency Advocates
commented that the test procedure PUL
is too high and leads to designs that
over-invest in load losses, and as such,
DOE should reduce the test procedure
PUL. (Efficiency Advocates, No. 52 at
pp. 1–2; NEEA, No. 51 at pp. 7–8) The
Efficiency Advocates commented that
DOE’s preliminary analysis shows that
intermediate energy savings can be
achieved with small price increases if
transformer designs are optimized for
more realistic PULs and urged DOE to
consider revising its test procedure PUL,
given the preliminary analysis load
growth estimates. (Efficiency Advocates,
No. 52 at p. 2) The Efficiency Advocates
commented that the negative savings at
certain ELs reflect the fact that certain
ELs would be met by decreasing load
losses rather than no-load losses.
(Efficiency Advocates, No. 52 at pp. 2–
3) The Efficiency Advocates further
referenced DOE’s hourly load model
which they claim demonstrated a small
percentage of hours above 50 percent
PUL and indicates savings available at
lower PULs. (Efficiency Advocates, No.
52 at p. 4) The Efficiency Advocates
commented that a lower PUL permits
greater savings for less costs, claiming
that DOE’s data shows better optimizing
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a transformer could yield 23 percent
energy savings for only a 4 percent
increase in costs. (Efficiency Advocates,
No. 52 at pp. 4–5)
DOE notes that the potential energy
savings cited by the Efficiency
Advocates are based on a distribution
transformer that is optimized at 35
percent PUL and is meeting current
efficiency standards at 50 percent PUL.
In the scenario where an alternative test
procedure PUL is used, distribution
transformers would not have to meet the
current standard at 50 percent PUL, they
would only have to meet a new standard
at 35 percent PUL. DOE’s analysis of
energy conservation standards assumes
consumers select a range of distribution
transformers and applies a range of
unique customer loading profiles to
evaluate the impacts of amended energy
conservation standards. In a theoretical
evaluation of energy conservation
standards at 35 percent PUL, the whole
analysis would change as new
distribution transformers would be able
to be purchased by consumers that do
not meet current standards at 50 percent
PUL but may meet a standard at 35
percent PUL. Without doing a much
more detailed analysis, it is a vast
oversimplification to cite energy savings
from a single distribution transformer.
Further, DOE notes that many of the
distribution transformers optimized for
low PULs use amorphous cores and
represent the design options with the
highest efficiency at 50 percent PUL.
Powersmiths commented that
measuring LVDT efficiency at a single
load point is insufficient since the
efficiency varies dramatically over the
loading. (Powersmiths, No. 46 at p. 1)
Powersmiths added that 35 percent PUL
is not representative for LVDTs.
(Powersmiths, No. 46 at p. 1)
Powersmiths added that evaluating at 35
percent PUL enables manufacturers to
publish peak efficiency rather than how
their transformers perform in the real
world. (Powersmiths, No. 46 at p. 2)
Powersmiths commented that this
practice misleads customers into
thinking DOE compliant transformers
save them the most money, when
transformers optimized for lower
loading could save more energy and
money. (Powersmiths, No. 46 at p. 2)
Metglas commented that actual data
shows current loading is low and as
such, the liquid-immersed distribution
transformers should be evaluated at 35
percent load and LVDTs should be
evaluated at 20 percent load. (Metglas,
No. 53 at p. 1; Metglas, No. 53 at p. 6)
Powersmiths added that the 35
percent PUL for LVDTs produces
deceptively high savings estimates and
pushing up efficiency at that point is
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counterproductive. (Powersmiths, No.
46 at p. 2) Powersmiths recommended
DOE work with organizations to reduce
oversizing of distribution transformers.
(Powersmiths, No. 46 at p. 2)
DOE agrees with stakeholders that
current loading is lesser than the test
procedure PUL. As such, DOE relies on
the most accurate in-service PUL and
load growth estimates to calculate
energy savings potential. However, DOE
evaluates the efficiency of distribution
transformers and only includes
distribution transformer models that
would meet amended energy
conservation standards at the test
procedure PUL. The efficiency of
distribution transformers over the
duration of its lifetime and across all
installations cannot be fully represented
by a single PUL. A given transformer
may be highly loaded or lightly loaded
depending on its application or
variation in electrical demand
throughout the day. In the September
2021 TP Final Rule, DOE was unable to
conclude that any singular PUL would
be more representative than the current
test procedure PUL because of (1)
significant long-term uncertainty
regarding what standard PUL would
correspond to a representative average
use cycle for a distribution transformer
given their long lifetimes; and (2) given
the uncertainty of future loading, there
may be greater risk associated with
selecting a test procedure PUL that is
too low than a test procedure PUL that
is too high. 86 FR 51230, 51240.
Therefore, for purposes of evaluating the
proposed standards in this document,
DOE used the test procedure PUL. More
discussion of the test procedure PUL
may be found in the September 2021 TP
Final Rule.
DOE disagrees with commenters’
assertion that there is an inherent
benefit associated with distribution
transformers certified at an alternative
PUL as no energy conservation standard
exist at any alternative PUL. Further,
DOE believes any benefits associated
with a lower PUL are also achieved via
amended energy conservation
standards. DOE has presented plots in
chapter 3 of the TSD to demonstrate
how the design space of possible load
loss and no-load loss combinations
would change in the presence of
amended energy conservation standards
and if energy conservation standards
were evaluated at an alternative PUL
which helps demonstrate this
conclusion.
Powersmiths commented that the
current reporting system is flawed as
factors like sub-standard batches of steel
may result in noncompliant distribution
transformers being shipped, and
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1753
recommended DOE should require third
party testing of distribution
transformers. (Powersmiths, No. 46 at
pp. 6–7) DOE notes that it has no data
suggesting manufacturers are shipping
non-compliant distribution
transformers. DOE notes that in the case
of sub-standard steel batches, its
certification requirements permit some
degree of variability in equipment
performance, as described at 10 CFR
429.47.
Powersmiths commented that high
volume manufacturers optimize costs by
using higher loss core steel and lower
loss conductor material to meet the 35
percent legal limit. (Powersmiths, No.
46 at p. 2) Powersmiths recommended
lowering the LVDT test procedure PUL
or adding a core loss limit to secure real
world energy savings. (Powersmiths,
No. 46 at p. 2)
In the September 2021 TP Final Rule,
DOE noted that on account of
uncertainty associated with future
distribution transformer loading, DOE is
unable to conclude that any alternative
single-PUL efficiency metric is more
representative than the current standard
PUL. 86 FR 51230, 51240. Therefore,
DOE only evaluated distribution
transformers that would meet amended
efficiency standards at the current test
procedure PUL. In its evaluation of
energy savings, DOE used data
representative of current in-service
loading, as described in section IV.E.
DOE does not make assumptions as to
the maximum no-load or load losses of
a transformer and instead relies on the
consumer choice model, described in
section IV.F.3 of this document, to
evaluate the distribution transformers
that consumers are likely to purchase.
4. Technology Options
In the preliminary market analysis
and technology assessment, DOE
identified several technology options
that would be expected to improve the
efficiency of distribution transformers,
as measured by the DOE test procedure.
Increases in distribution transformer
efficiency are based on a reduction of
distribution transformer losses. There
are two primary varieties of loss in
distribution transformers: no-load losses
and load losses. No-load losses are
roughly constant with PUL and exist
whenever the distribution transformer is
energized (i.e., connected to electrical
power). Load losses, by contrast, are
zero at 0 percent PUL but grow
quadratically with PUL.
No-load losses occur primarily in the
transformer core, and for that reason the
terms ‘‘no-load loss’’ and ‘‘core loss’’ are
sometimes interchanged. Analogously,
‘‘winding loss’’ or ‘‘coil loss’’ is
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sometimes used in place of ‘‘load loss’’
because load loss arises chiefly in the
windings. For consistency and clarity,
DOE will use ‘‘no-load loss’’ and ‘‘load
loss’’ generally and reserve ‘‘core loss’’
and ‘‘coil loss’’ for when those
quantities expressly are meant.
CDA commented that copper is the
best conductor of electricity and enables
a more compact and economical
distribution transformer with a smaller
tank, less core, and reduced oil. (CDA,
No. 47 at p. 1) DOE notes that it has
included some copper windings in its
engineering analysis and recognizes that
while copper may be more expensive
than aluminum conductors, it
represents a technology option that
allows manufacturers to achieve smaller
footprints or higher efficiencies in
designs that are uniquely difficult to
meet energy conservation standards.
EEI commented that many
technologies that decrease no-load
losses, increase load losses and
therefore DOE should utilize accurate
projections of loading and recognize
lower-loss core materials can have
significantly higher load losses. (EEI,
No. 56 at p. 3)
Regarding amended energy
conservation standards generally,
Howard commented that no new
technology options have come onto the
market that would impact distribution
transformer efficiency since the April
2013 Standards Final Rule. (Howard,
No. 59 at p. 1) CDA commented that
there should be no new standards and
recommended DOE continue to evaluate
the inputs to its analysis and new
technologies. (CDA, No. 47 at p. 2)
Powermiths noted that the market is in
flux currently and recommended DOE
delay the rulemaking while the market
settles, require third party compliance
enforcement, and invite stakeholder into
DOE’s revision process. (Powersmiths,
No. 46 at p. 7)
With respect to analyzed inputs, in
the engineering analysis, DOE
considered various combinations of the
following technology options to
improve efficiency: (1) Higher grade
electrical core steels, (2) different
conductor types and materials, and (3)
adjustments to core and coil
configurations. With respect to
commenters’ suggestions that DOE delay
standards or not issue amended
standards, as noted previously, EPCA
requires DOE to periodically determine
whether more-stringent standards
would be technologically feasible and
economically justified, and would result
in significant energy savings. 42 U.S.C.
6316(a); 42 U.S.C. 6295(m). DOE has
tentatively concluded that the proposed
standards represent the maximum
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improvement in energy efficiency that is
technologically feasible and
economically justified, and would result
in the significant conservation of
energy. Specifically, with regards to
technological feasibility, products
achieving these standard levels are
already commercially available for all
product classes covered by this
proposal. Accordingly, DOE has
proceeded with the proposed standards.
5. Electrical Steel Technology and
Market Assessment
Distribution transformer cores are
constructed from a specialty kind of
steel known as electrical steel. Electrical
steel is an iron alloy which incorporates
small percentages of silicon to enhance
its magnetic properties, including
increasing its magnetic permeability and
reducing the iron losses associated with
magnetizing that steel. Electrical steel is
produced in thin laminations and either
wound or stacked into a distribution
transformer core shape.
Electrical steel used in distribution
transformer applications can broadly be
categorized as amorphous steel and
grain-oriented electrical steel (‘‘GOES’’).
There are many subcategories of steel
within both amorphous steel and grainoriented electrical steel. In the August
2021 Preliminary Analysis TSD, DOE
assigned designated names to identify
the various permutations of electrical
steel. (August 2021 Preliminary
Analysis TSD at pp. 2–31–36) DOE
requested comment on its proposed
naming convention. In response,
Schneider and NEMA commented that
the proposed naming convention used
by DOE in the preliminary analysis is
adequate. (Schneider, No. 49 at p. 13;
NEMA No. 50 at p. 8)
The various markets, technologies,
and naming conventions for amorphous
and GOES are discussed in the
following sections.
a. Amorphous Steel Market and
Technology
Amorphous steel is a type of electrical
steel that is produced by rapidly cooling
molten alloy such that crystals do not
form. The resulting product is thinner
than GOES and has lower core losses,
but it reaches magnetic saturation at a
lower flux density.
DOE has identified three subcategories of amorphous steel as
possible technology options. These
technology options and their DOE
naming shorthand are shown in Table
IV.2.
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TABLE IV.2—AMORPHOUS STEEL
TECHNOLOGY OPTIONS
DOE designator in
design options
Technology
am .........................
hibam ....................
Traditional Amorphous Steel.
High-Permeability Amorphous
Steel.
High-Permeability, Domain-Refined, Amorphous Steel.
hibam-dr ...............
In the August 2021 Preliminary
Analysis TSD, DOE requested comment
and data on the quality and differences
between the various amorphous steels
on the market. (August 2021
Preliminary Analysis TSD at p. 2–31)
In response, Metglas commented that
since amorphous steel was introduced,
the core loss and stacking factor of the
product has continually improved.
(Metglas, No. 53 at pp. 2–3) Metglas
stated that the current stacking factors
are between 88–90 percent, which
allows amorphous cores to be smaller
than they have historically been.
(Metglas, No. 53 at pp. 2–3) Eaton
commented that the hibam material uses
an 89 percent stacking factor and max
flux of 1.40–1.42 tesla (T), as compared
to traditional amorphous material which
uses 88 percent stacking factor and a
flux of 1.35–1.37 T. (Eaton, No. 55 at
p.11) NEMA commented that the
stacking factor of amorphous steel will
never be as high as grain-oriented
electrical steel. (NEMA, No. 50 at p. 8)
In the August 2021 Preliminary
Analysis TSD, DOE noted that it did not
include any designs specifically using
the high-permeability amorphous steel.
(August 2021 Preliminary Analysis TSD,
at p. 2–45) DOE stated while there are
some design flexibility advantages
associated with using the highpermeability amorphous steel, it is only
available from a single supplier. Id. In
interviews, manufacturers noted they
would be hesitant to rely on a single
supplier of amorphous material for any
higher volume unit. Id. DOE further
stated that high-permeability
amorphous steel can be integrated in
manufacturer existing amorphous
designs with minimal changes and
therefore, DOE’s amorphous designs
represent efficiencies that can be met
with any amorphous steel. Id. DOE
requested comment on its assumption
that high-permeability amorphous steel
could be used in existing amorphous
designs with minimal changes. Id.
In response, Metglas commented that
hibam can be used interchangeably with
the standard am designs. (Metglas, No.
53 at p. 4) Metglas added that many
transformers will maintain existing am
design and operate the hibam material
at the lower induction levels during
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initial conversion, however, once
designs are optimized for the hibam
material, they cannot substitute
standard am because standard am
cannot reach the higher induction
levels. (Metglas, No. 53 at p. 4) Metglas
added that there is not a reduction in
core losses when operating hibam at the
same induction levels as standard am.
(Metglas, No. 53 at p. 4)
NEMA and Eaton commented that
hibam does not necessarily have higher
efficiency than standard am at certain
flux densities, and it is not universally
true that hibam could be used in place
of standard am without other design
changes because at some flux densities,
standard am can have lower no-load
losses. (Eaton, No. 55 at p. 12–13;
NEMA, No. 50 at p. 10)
Stakeholder comments confirm DOE’s
assumption that hibam material can be
used in place of standard am designs,
generally, although some specific
applications may require redesigning.
As such, including only standard am
designs in the NOPR analysis is
appropriate to avoid setting efficiency
standards based on a steel type, hibam,
that is only available from a single
supplier. Under this approach,
manufacturers have the option to
achieve efficiency levels that require am
steel using either the standard am
material or the hibam material
depending on their sourcing practices
and preferences.
In the August 2021 Preliminary
Analysis TSD, DOE noted that it was
aware of a hibam material that uses
domain refinement (‘‘hibam-dr’’) to
further reduce core losses but did not
have sufficient data or details as to
whether it is commercially available.
(August 2021 Preliminary Analysis TSD,
at p. 2–31) In response, Metglas
commented that they have introduced a
mechanically domain refined hibam
material that lowers core losses by an
additional 20–30 percent in a finished
core at a constant operating induction
and there is a laser domain refined
hibam product in the Asian market that
Metglas is working to bring online in the
domestic market. (Metglas, No. 53 at p.
3) Metglas commented that hibam-dr
allows manufacturers to increase
operating induction, relative to standard
am, while reducing core losses by
approximately 14 percent relative to the
standard am operating induction.
(Metglas, No. 53 at p. 4)
DOE further investigated this product
in manufacturer interviews conducted
for this NOPR analysis. In these
interviews, DOE learned that the hibamdr product is not yet widely available
commercially. DOE has not included the
hibam-dr product in its analysis because
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this product has not been widely used
in commercial applications at this point,
DOE has not been able to verify that the
core loss reduction of this product is
maintained throughout the core
production process, and it is only
produced by one supplier.
In the April 2013 Standard Final Rule,
one concern DOE noted with efficiency
levels that would use amorphous steel
was that there was only one global
supplier of amorphous steel. 78 FR
23336, 23383. In the June 2019 Early
Assessment RFI, DOE estimated global
amorphous capacity of 190,000 metric
tons and noted that the capacity and
number of producers of amorphous steel
has grown since the April 2013
Standards Final Rule. 84 FR 28239,
28247
Metglas commented that it is the only
current producer of amorphous steel in
the United States, however, there is
current production in Japan and China
along with amorphous capacity in
Germany and South Korea. (Metglas,
No. 11 at p. 2) Eaton pointed out that
one barrier to steel manufacturers
producing amorphous is that it would
‘‘cannibalize’’ conventional electrical
steel manufacturers existing product
offering and reduce the equipment
utilization of existing equipment.
(Eaton, No. 12 at p. 6)
In the August 2021 Preliminary
Analysis TSD, DOE noted that it had
identified numerous companies capable
of producing amorphous material (of
standard am quality or better). DOE
stated that it did not apply any capacity
constraints on the number of amorphous
distribution transformers that could be
selected because amorphous capacity is
much greater than amorphous demand.
The Efficiency Advocates commented
that the preliminary analysis shows a
transition to amorphous material is cost
justified and would bring U.S. standards
in-line with other parts of the world.
(Efficiency Advocates, No. 52 at p. 1)
The Efficiency Advocates added that if
amorphous core availability is a
concern, DOE could require amorphous
cores for certain transformer types that
offer large savings. (Efficiency
Advocates, No. 52 at p. 8)
Metglas estimated global amorphous
capacity to be 150,000 metric tons
annually with domestic capacity of
45,000 metric tons and ready ability to
add another 75,000 metric tons within
18–24 months. (Metglas, No. 53 at p. 3)
Metglas commented that the highpermeability amorphous grades (hibam)
has been widely adopted by the North
American market, making up 80 percent
of their production, and allows for
higher operating inductions which
reduces amorphous core sizes. (Metglas,
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No. 53 at p. 3) NEMA commented that
amorphous steel sourced from China is
more variable in its stacking factor and
consistency. (NEMA, No. 50 at p. 8)
Stakeholder comments verify that
global amorphous capacity is much
greater than current demand and
amorphous is produced by a variety of
sources, although the quality may not be
as consistent from everybody. Through
manufacturer interviews, DOE learned
that amorphous production capacity
increased in response to the April 2013
Standards Final Rule, resulting in
excess capacity because demand for
amorphous steel did not
correspondingly increase. While
amorphous capacity today is currently
less than the total distribution
transformer total electrical steel usage,
amorphous producers’ response to the
April 2013 Standards Final Rule
demonstrates that if there was expected
to be a market demand for amorphous
steel, capacity would increase to meet
that demand.
In interviews, several manufacturers
noted that recent increases in prices,
and foreign produced GOES prices, in
particular, have led amorphous to be far
more cost competitive. However, the
industry has not necessarily seen an
increase in amorphous transformer
purchasing reflective of this pricing
situation. Manufacturers noted that
many of their processes are set-up to
produce and process GOES steel and as
such there is some degree of bias against
amorphous transformers, regardless of
what the first cost of a product is. In the
August 2021 Preliminary Analysis TSD,
DOE requested comment and data on
the current amorphous core making
capacity and the cost and time frame to
add amorphous core production
capacity. (August 2021 Preliminary
Analysis TSD at p. 2–33)
In response, Metglas estimated
amorphous core making capacity to be
approximately 20,000 to 25,000 metric
tons and noted that bringing on
additional amorphous core
manufacturing is relatively
straightforward and inexpensive.
(Metglas, No. 53 at p. 4) Metglas
commented that there are conversion
costs and capital costs associated with
producing an amorphous core from
amorphous steel laminations. (Metglas,
No. 53 at p. 5) Eaton commented that
the timeframe to add additional
amorphous transformer capacity is
dependent on whether additional design
qualification testing is needed versus
strictly capacity expansion and
estimated one years for the former and
one year for the latter. (Eaton, No. 55 at
p. 11)
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In the NOPR analysis, DOE has not
applied any constraints to standard am
steel purchasing in its evaluation of
higher efficiency levels. DOE did
constrain the selection of amorphous
steel under the no-new-standards
scenario to better match the current
market share of amorphous distribution
transformers, as discussed in section
IV.F.2 of this document. DOE notes that
any conversion costs associated with a
transition from GOES production to
amorphous distribution transformer
production would be accounted for in
the manufacturer impact analysis in
section IV.J.
b. Grain-Oriented Electrical Steel
Market and Technology
GOES is a type of electrical steel that
is processed with tight control over its
crystal orientation such that its
magnetic flux density is increased in the
direction of the grain-orientation. The
single-directional flow is well suited for
distribution transformer applications
and GOES is the dominant technology
in the manufacturing of distribution
transformer cores. GOES is produced in
a variety of thickness and with a variety
of loss characteristics and magnetic
saturation levels. In certain cases, steel
manufacturers may further enhance the
performance of electrical steel by
introducing local strain on the surface of
the steel, through a process known as
domain-refinement, such that core
losses are reduced. This can be done via
different methods, some of which
survive the distribution transformer core
annealing process.
In the August 2021 Preliminary
Analysis TSD, DOE identified four subcategories of GOES as possible
technology options. (August 2021
Preliminary Analysis TSD at p. 2–35)
These technology options and their DOE
naming short-hand are shown in Table
IV.3.
TABLE IV.3—GOES STEEL
TECHNOLOGY OPTIONS
DOE designator
in design options
Technology
M-Grades ...........
Conventional (not highpermeability) GOES.
High-Permeability GOES.
Non-Heat Proof, Laser
Domain-Refined, HighPermeability GOES.
Heat-Proof, Permanently
Domain-Refined, HighPermeability GOES.
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hib ......................
dr ........................
pdr ......................
DOE noted that for high-permeability
steels, steel manufacturers have largely
adopted a naming convention that
includes the steel’s thickness, a brand
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specific designator, followed by the
guaranteed core loss of that steel in W/
kg at 1.7 Tesla (‘‘T’’) and 50 Hz. Power
in the U.S. is delivered at 60 Hz and the
flux density can vary based on
distribution transformer design,
therefore the core losses reported in the
steel name are not identical to their
performance in the distribution
transformer. However, the naming
convention is generally a good indicator
of the relative performance of different
steels.
In the August 2021 Preliminary
Analysis TSD, DOE identified several
grades of GOES as potential technology
options for distribution transformers.
DOE requested comment and data on
the availability of those steels, the
ability to substitute various GOES
grades for one another, any potential
competition for steel supply for the
large power transformer market, and the
costs for steelmakers to add or convert
capacity to higher performing GOES.
(August 2021 Preliminary Analysis TSD
at pp. 2–36–37)
Regarding potential competition for
steel supply with the large power
transformer industry, Schneider
commented that power transformers and
medium-voltage distribution
transformers tend to be prioritized over
the needs of the LVDT market and
therefore supply issues can exist if
LVDT manufacturers need to purchase
the same core steel as medium-voltage
distribution transformers. (Schneider,
No. 49 at p. 14) Cliffs added that while
high-permeability GOES works well in
distribution transformers, it has
historically been sold as a laser DR
product to the power transformer
market. (Cliffs, No. 57 at p. 1)
Conversely, NEMA suggested that
electrical steels used in the large power
transformer industry cannot be used in
distribution applications, stating that
the packaging and coating of steels
targeting the large power transformer
industry are not compatible with
distribution transformer designs but
added that large power transformers do
compete for steel demand. (NEMA, No.
50 at p. 9)
Steel manufacturer literature
generally markets GOES, and in
particular hib and dr GOES, as suitable
for use in either power or distribution
transformers. Generally, a steel that is
suitable for use in a power transformer
may be suitable for use in a distribution
transformer. As Schneider noted, and
DOE confirmed in manufacturer
interviews, power transformers tend to
have priority and get the highest
performing GOES. The industry also is
volume driven and as such, the larger
volume of the liquid-immersed market
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tends to be served before the dry-type
distribution market.
Regarding availability of GOES more
generally, NEMA recommended DOE
review the DOC study for perspective on
steel availability. (NEMA, No. 50 at p.
8) NEMA and Powersmiths commented
that recently there has been a notable
increase in competition from the auto
industry for electrical steel to produce
electric motors in EVs. (NEMA, No. 50
at p. 9; Powersmiths, No. 46 at p. 5)
NEMA and Powersmiths stated that
some steel suppliers are shifting part of
their grain-oriented electrical steel
production capacity to non-oriented
electrical steel production—limiting the
availability and increasing prices of
transformer-grade steels. (NEMA, No. 50
at p. 9; Powersmiths, No. 46 at p. 5) At
the Public meeting, a representative
from Carte commented that one major
foreign steel manufacturer transitioned
50 percent of their grain-oriented
production lines to non-oriented.
(Zarnowski, Public Meeting Transcript,
No. 40 at p. 36) A representative from
LakeView Metals, commented that the
non-oriented market is skyrocketing and
there is an estimated global shortfall of
13 silicon production lines. (Looby,
Public Meeting Transcript, No. 40 at p.
37)
Powersmiths commented they are
currently experiencing diminished
availability of several grades of steel and
increased costs as steel suppliers are
shifting to serving the EV market
without plans to bring transformer-grade
steel capacity back. (Powersmiths, No.
46 at p. 5) ERMCO agreed that supply
of steel is currently limited and they
have been able to obtain M3 steel, some
hib, and am steel. (ERMCO, No. 45 at p.
1)
Recent supply issues and increases in
costs are likely associated with a
combination of general commodity
related supply chain issues and
competition from electric vehicles. DOE
notes that variability in electrical steel
prices and supply is not new and
historically, DOE averages prices to
come up with a representative value. As
part of the August 2021 Preliminary
Analysis TSD, DOE did evaluate
alternative price scenarios. DOE has
applied a 5-year average price in its base
case analysis and conducted
sensitivities for various other pricing
scenarios, as discussed in section
IV.C.3. DOE has also screened-out some
of the highest performing GOES, where
steel manufacturers are not able to mass
produce GOES of similar quality, as
discussed in section IV.B.
NEMA previously noted that there is
currently only one domestic producer of
GOES and that the sole domestic
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producer does not have the capacity of
high-grade electrical steel to serve the
entire U.S. market, meaning the U.S.
would be dependent on foreign
electrical steel producers. (NEMA, No.
13 at p. 6–7)
Powersmiths commented that many of
the high performing grades are only
available from overseas suppliers and
recent shipping and port access
challenges have increased market
uncertainty and availability to those
grades. (Powersmiths, No. 46 at p. 6)
Powersmiths stated that increased
domestic capacity for GOES would
require significant investment from
industry and take years to come on.
(Powersmiths, No. 46 at p. 6) Cliffs
added that high-permeability GOES is a
unique production line that would take
years of planning, installation, and
commissioning to convert existing M3
lines to high-permeability. (Cliffs, No.
57 at pp. 1–2) Cliffs stated that domestic
steel is currently well-suited to serve
distribution applications and higher
standards would negatively impact the
ability of domestic steel manufacturers
to serve the distribution transformer
market. (Cliffs, No. 57 at p. 2) Cliffs
commented that higher efficiency levels
would drastically hurt M3, and
correspondingly domestic
manufacturing, leaving the only
domestic products as M2 and some
high-permeability GOES grades. (Cliffs,
No. 57 at p. 1) Cliffs commented that its
electrical steel is produced with
recycled steel scrap in an electric arc
furnace, making it some of the greenest
steel in the world. (Cliffs, No. 57 at p.
1)
DOE did constrain the selection of
electrical steel under the no-newstandards scenario to better match the
current market share of electrical steel,
as discussed in section IV.F.2. In its
evaluation of future standards, DOE
assumed that steel manufacturers would
provide the electrical steel qualities
required by the market. In cases where
fewer steel suppliers offer a grade of
GOES, this is reflected by higher prices
in DOE’s analysis.
6. Distribution Transformer Production
Market Dynamics
Distribution transformer
manufacturers either make or buy
transformer cores; some do both.
Further, distribution transformer
manufacturers may choose to produce
transformers domestically or produce
them in a foreign country and import
them to the United States. This creates
three unique pathways for producing
distribution transformers: (1) producing
both the distribution transformer core
and finished transformer domestically;
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(2) producing the distribution
transformer core and finished
transformer in a foreign country and
importing into the United States; (3)
purchasing distribution transformer
cores and producing only the finished
transformer domestically. Each of these
pathways has unique advantages and
disadvantages which manufacturers
have employed to maintain a
competitive position.
First, manufacturers who produce
distribution transformer cores and
finished transformers domestically are
able to maintain greater control of their
lead times, potentially offering shorter
lead times to their customers. This is
particularly advantageous in servicing
emergency applications with unique
characteristics. This manufacturing
approach is more common in certain
liquid-immersed and medium-voltage
dry-type applications, where customers
may have unique voltage specifications
that may not be routinely produced by
all manufacturers but may be required
on short notice.
As discussed, however, there is
currently only one domestic
manufacturer of grain-oriented electrical
steel and one domestic manufacturer of
amorphous steel. Under the current
market dynamics with tariffs applied to
all, raw imported electrical steel, these
manufacturers are limited in where they
can source their raw steel. As such, they
may not have access to all of the types
of steels available in the global market
and may have different material prices
from foreign core producers. While in
theory, these manufacturers have the
option to purchase electrical steel from
foreign producers, they would be
subject to the 25-percent tariff.
Similarly, in theory, they have the
option to purchase either grain-oriented
electrical steel or amorphous electrical
steel domestically.
DOE assumes that in the presence of
amended standards, those
manufacturers currently producing both
cores and finished transformers
domestically would still value the
advantages of in-house domestic core
production and would change their inhouse production processes to
accommodate the required core
production equipment or required
electrical steel grades.
Second, for manufacturers producing
both the distribution transformer core
and finished transformer in a foreign
country and importing into the United
States, they are able to control the inhouse core production and therefore
have similar advantages to those
producing cores domestically. Further,
because finished transformer imports
are not currently subject to tariffs, they
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have access to the entire global market
of electrical steel types and prices
without the additional 25 percent tariff.
However, these manufacturers may
require increased management of
electrical steel supply chains, as they
are often purchasing electrical steel
from overseas producers which may
have longer lead times than sourcing
electrical steel from domestic sources.
Similar to domestic manufacturers,
DOE assumes that in the presence of
amended standards, those
manufacturers producing both cores and
transformers outside the United States
would still value the advantages of inhouse core production and would
change their in-house production
processes to accommodate the required
core production equipment or required
electrical steel grades.
Third, manufacturers who purchase
cores to manufacture distribution
transformers are able to avoid the labor
and capital equipment associated with
producing transformer cores. In part for
this reason, it is increasingly common
among small businesses. Further,
because distribution transformer cores
are not subject to tariffs, purchasing
cores also allows manufacturers to more
easily transition between various steel
grades and various steel suppliers, both
international and domestic. Similarly, it
is easier for manufacturers who
outsource cores to transition between
GOES and amorphous steel grades since
it eliminates the need to use different
core production equipment for each
steel type as the process of converting
a core into a transformer is relatively
similar for both GOES and amorphous
steels.
The primary disadvantages of
outsourcing cores are that (1)
transformer manufacturers may have
less control over core, and therefore
transformer, delivery lead times and (2)
transformer manufacturers will pay a
higher cost per pound of steel because
they are purchasing partially processed
products as compared to manufacturers
who are producing their own cores.
DOE assumes that in the presence of
amended standards, these
manufacturers would switch from
purchasing one grade of electrical steel
core to a higher grade of electrical steel
core.
In summary, DOE does not view any
one of these core and transformer
production pathways as necessarily
becoming more advantaged or
disadvantaged in light of the standards
proposed in this notice relative to the
present. In the current market, all three
pathways act as viable options for
manufacturers to find and maintain a
competitive position. DOE does not
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have a reason to believe that the
proposed standards would alter the
ways in which distribution transformer
manufacturers approach manufacturing
or their current sourcing decisions given
all three productions options continue
to be available. DOE seeks comment on
the distribution transformer market and
whether the standards proposed will
alter the current production pathways.
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B. Screening Analysis
DOE uses the following five screening
criteria to determine which technology
options are suitable for further
consideration in an energy conservation
standards rulemaking:
(1) Technological feasibility.
Technologies that are not incorporated
in commercial products or in working
prototypes will not be considered
further.
(2) Practicability to manufacture,
install, and service. If it is determined
that mass production and reliable
installation and servicing of a
technology in commercial products
could not be achieved on the scale
necessary to serve the relevant market at
the time of the projected compliance
date of the standard, then that
technology will not be considered
further.
(3) Impacts on product utility or
product availability. If it is determined
that a technology would have a
significant adverse impact on the utility
of the product for significant subgroups
of consumers or would result in the
unavailability of any covered product
type with performance characteristics
(including reliability), features, sizes,
capacities, and volumes that are
substantially the same as products
generally available in the United States
at the time, it will not be considered
further.
(4) Adverse impacts on health or
safety. If it is determined that a
technology would have significant
adverse impacts on health or safety, it
will not be considered further.
(5) Unique-Pathway Proprietary
Technologies. If a design option utilizes
proprietary technology that represents a
unique pathway to achieving a given
efficiency level, that technology will not
be considered further due to the
potential for monopolistic concerns.
10 CFR 431.4; 10 CFR part 430, subpart
C, appendix A, sections 6(b)(3) and 7(b)
(‘‘Process Rule’’).
In summary, if DOE determines that a
technology, or a combination of
technologies, fails to meet one or more
of the listed five criteria, it will be
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excluded from further consideration in
the engineering analysis. The reasons
for eliminating any technology are
discussed in the following sections.
The subsequent sections include
comments from interested parties
pertinent to the screening criteria,
DOE’s evaluation of each technology
option against the screening analysis
criteria, and whether DOE determined
that a technology option should be
excluded (‘‘screened out’’) based on the
screening criteria.
1. Screened-Out Technologies
In the August 2021 Preliminary
Analysis TSD, DOE identified core
deactivation as a potential technology
option to improve efficiency but noted
that it was not a generally accepted
practice and would be associated with
system wide savings, not savings as
measured by DOE’s test procedure.
In response, NEMA commented that
core deactivation would only be
beneficial in certain settings and there
are questions of reliability associated
with shifting load which could lead to
shorter lifetimes. (NEMA, No. 50 at p. 7)
NEEA commented that core deactivation
may impact maintenance of switchgear
and other connected equipment. (NEEA,
No. 51 at p. 5)
Due to the concerns cited by NEMA
and NEEA regarding impacts on product
lifetime and servicing of equipment,
along with the fact that core
deactivation would not impact the
efficiency as measured by the DOE test
procedure, DOE has screened-out core
deactivation as a potential technology
option.
DOE also identified less-flammable
insulating liquid-immersed distribution
transformer (‘‘LFLI’’) as a potential
technology by which manufacturers
could increase the capacity of a
distribution transformer without
increasing the size, potentially leading
to energy savings. In response, NEMA
commented that while LFLI is used by
some customers to reduce unit size,
particularly for pad mounts but rarely
for pole mounts, it is generally pursued
for greater reliability and not greater
efficiency. (NEMA, No. 50 at pp. 7–8)
DOE notes that while there may be
opportunity for a customer to maintain
distribution transformer lifespan while
increasing the loading on a transformer
with LFLI technology, this would not
impact the efficiency as measured by
DOE’s test procedure. Further, DOE
understands that there are potential
consumer safety concerns with
distribution transformers operating
notably hotter, namely that the touch
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temperature could be too high for
consumers to safely interact with.
Therefore, DOE has screened out LFLI
as a potential technology option.
Regarding evaluating efficiency
improvements associated with certain
high-performing GOES grades,
Powersmiths commented that the
stability of availability, cost, and batch
quality of some new steel grades is
unproven. (Powersmiths, No. 46 at p. 5)
Schneider expanded that steel mills are
not perfectly consistent and only a
portion of their production may meet a
target loss performance. As such, it may
not be feasible to set efficiency levels
based on premium grades, for example
an 075 or 070 grade steel, as steel
manufacturers may not be able to
consistently achieve the premium
performance. (Schneider, No. 49 at p.
14) Schneider added that some higher
performance steels are published in
steel maker catalogs but are not widely
available for commercial use.
(Schneider, No. 49 at p. 13)
In GOES production, the product steel
losses can vary somewhat between and
within batches. Because of this
variability in electrical steel, producers
typically offer two loss specifications for
their steels, a guaranteed core loss and
a typical core loss. While some of the
premium products identified in the
August 2021 Preliminary Analysis TSD
generally exist and are used in the
market, they represent the upper end of
the distribution of product performance.
As commenters suggested, without
further improvements in consistency of
batch quality, it may not be reasonable
to assume these products could be
widely used in industry. Therefore, DOE
has screened out certain highperforming GOES products.
Specifically, DOE removed 23pdr075
and 20dr070 electrical steels from its
engineering modeling due to concerns
with its practicability to manufacture.
DOE notes that these electrical steels
could be used in certain applications
but DOE has screened them out because
of concerns that mass production of
these products could not be achieved on
the scale necessary to serve the
distribution transformer market.
DOE listed several other technology
options in the August 2021 Preliminary
Analysis TSD for which it did not
receive any comment. As such, DOE has
retained those technology options as
screened out.
Technology options screened out are
listed in Table IV.4 with their bases for
screening.
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TABLE IV.4—SCREENED-OUT TECHNOLOGIES
Technology option
Basis for screening
Core Deactivation ...........................
Less-Flammable Insulating Liquids
Symmetric Core Design ..................
23pdr075 and 23dr070 GOES Steel
Silver as a Conductor Material .......
High-Temperature Superconductors
Amorphous Core Material in
Stacked Core Configuration.
Carbon Composite Materials for
Heat Removal.
High-Temperature Insulating Material.
Solid-State (Power Electronics)
Technology.
Nanotechnology Composites ..........
Practicability to manufacture, install, and service; Adverse Impacts on Product Utility or Product Availability.
Adverse Impacts on Health or Safety.
Practicability to manufacture, install, and service.
Practicability to manufacture, install, and service.
Practicability to manufacture, install, and service.
Technological feasibility; Practicability to manufacture, install and service.
Technological feasibility; Practicability to manufacture, install, and service.
Technological feasibility.
Technological feasibility.
Technological feasibility; Practicability to manufacture, install, and service.
Technological feasibility.
2. Remaining Technologies
Through a review of each technology,
DOE tentatively concludes that the
remaining combinations of core steels,
windings materials and core
configurations as combinations of
‘‘design options’’ for improving
distribution transformer efficiency met
all five screening criteria to be examined
further as design options in DOE’s
NOPR analysis.
DOE has initially determined that
these technology options are
technologically feasible because they are
being used or have previously been used
in commercially-available products or
working prototypes. DOE also finds that
all of the remaining technology options
meet the other screening criteria (i.e.,
practicable to manufacture, install, and
service and do not result in adverse
impacts on consumer utility, product
availability, health, or safety, uniquepathway proprietary technologies). For
additional details, see chapter 4 of the
NOPR TSD.
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C. Engineering Analysis
The purpose of the engineering
analysis is to establish the relationship
between the efficiency and cost of
distribution transformers. There are two
elements to consider in the engineering
analysis; the selection of efficiency
levels to analyze (i.e., the ‘‘efficiency
analysis’’) and the determination of
product cost at each efficiency level
(i.e., the ‘‘cost analysis’’). In determining
the performance of higher-efficiency
equipment, DOE considers technologies
and design option combinations not
eliminated by the screening analysis.
For each equipment class, DOE
estimates the baseline cost, as well as
the incremental cost for the equipment
at efficiency levels above the baseline.
The output of the engineering analysis
is a set of cost-efficiency ‘‘curves’’ that
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are used in downstream analyses (i.e.,
the LCC and PBP analyses and the NIA).
1. Representative Units
Distribution transformers are divided
into different equipment classes,
categorized by the physical
characteristics that affect equipment
efficiency. DOE’s current energy
conservation standards at 10 CFR
431.196 divide distribution transformers
based on the following characteristics:
(1) capacity (kVA rating), (2) voltage
rating, (3) phase count, (4) insulation
category (e.g., ‘‘liquid-immersed’’), and
(5) BIL rating.
Because it is impractical to conduct
detailed engineering analysis at every
kVA rating, DOE conducts detailed
modeling on ‘‘representative units’’
(‘‘RUs’’). These RUs are selected both to
represent the more common designs
found in the market and to include a
variety of design specification to enable
generalization of the results. In the
August 2021 Preliminary TSD, DOE
presented 14 representative units and
noted they were unchanged from the
April 2013 Standards Final Rule.
(August 2021 Preliminary TSD at p. 2–
41)
In response to the August 2021
Preliminary TSD, Howard commented
that RU3 is not a very good
representative unit because it is not
common and should be replaced with a
more common unit. (Howard, No. 59 at
p. 2) DOE agrees that RU3,
corresponding to a 500 kVA, singlephase, liquid-immersed distribution
transformer, is generally larger than the
more common capacities included in
equipment class 1. However, as noted,
DOE’s RUs are designed to include both
common units and units included to
improve generalization. RU3 is included
to improve scaling of results to the
larger units within the scope of
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equipment class 1. Therefore, RU3 has
been retained in this NOPR.
Carte commented that the
representative units used by DOE are
representative of common/typical sizes
but the extremes were not analyzed,
where meeting efficiency standards tend
to be the hardest. (Carte, No. 54 at p. 1)
Carte added that certain designs are
forced to use high-end grain-oriented
electrical steel and copper windings or
in certain cases are unable to be met by
Carte. (Carte, No. 54 at p. 1)
Eaton commented that the
representative units are good choices for
the highest volume transformers,
however, as efficiency standards
increase, efficiency standards may not
be achievable at the scope extremes.
(Eaton, No. 55 at p. 12)
It is true that certain extreme designs
may have more difficulty achieving
efficiency standards while still being
requested by consumers. Most
applications would generally be able to
use amorphous steel to achieve higher
efficiencies, including at efficiency
levels beyond DOE’s max-tech. DOE
selected design units to include both
large and small distribution
transformers across the various
representative units and DOE’s
modeling of the selected representative
units includes amorphous designs
which achieve efficiencies above DOE’s
max-tech for all RUs. This indicates that
there is room for even extreme designs
to meet efficiency standards using
technologies modeled by DOE.
DOE requests data demonstrating any
specific distribution transformer designs
that would have significantly different
cost-efficiency curves than those
representative units modeled by DOE.
To assess the impact of expanding the
scope of the definition of ‘‘distribution
transformer’’ in 10 CFR 431.192 to
include distribution transformers up to
5,000 kVA, DOE is evaluating three new
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RUs. DOE scaled the results for RU5,
RU12, and RU14 to represent RU17,
RU18, and RU19, respectively, each of
which are rated at 3,750 kVA. Results
were generated for RU17, RU18, and
RU19 using the scaling rules for
dimensions, transformer weight, no-load
losses, load losses, etc., as described in
Appendix 5C of the TSD.
DOE notes that it only includes
distribution transformers in the
downstream analysis that would meet or
exceed current energy conservation
standards. Because RU17, RU18, and
RU19 represent an expansion in scope,
they are not currently subject to energy
conservation standards. As such, all
modeled designs are included in the
downstream analysis, regardless of
efficiency and DOE relies on the
consumer choice model to determine
the efficiency of distribution
transformers selected at baseline. DOE
has described these results and shown
the cost-efficiency curves for these
scaled units in Chapter 5 of the TSD.
DOE requests comment on its
methodology for scaling RU5, RU12,
and RU14 to represent the efficiency of
units above 3,750 kVA.
Distribution transformers designed for
submersible applications may be
disadvantaged in meeting efficiency
standards on account of having to meet
efficiency standards with reduced
cooling ratings. To explore this
specification limitation, DOE has
proposed a definition for submersible
distribution transformers. In this NOPR,
DOE is evaluating those submersible
distribution transformers as a separate
equipment class. DOE has modified the
engineering results for RU4 and RU5 to
represent two new RUs, RU15 and
RU16. RU15 and RU16 represent
common three-phase submersible
distribution transformers. To account
for the thermal derating that is
associated with submersible distribution
transformers, DOE evaluated RU15 and
RU16 as having their nameplates
derated by one standard kVA size
relative to the efficiency of RU4 and
RU5. That is, while RU4 is a 150 kVA
three-phase, liquid-immersed
distribution transformer, RU15 is a
112.5 kVA three-phase, liquidimmersed, submersible distribution
transformer. Similarly, while RU5 is a
1,500 kVA three-phase, liquid-immersed
distribution transformer, RU16 is a
1,000 kVA three-phase, liquid-immersed
distribution transformer. DOE
calculated the efficiency of RU15 and
RU16 based on their new nameplate and
assuming no-load losses are the same
and load losses scale with the quadratic
of load. DOE also modified the cost of
the tank material from carbon steel to
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stainless steel to represent the corrosion
resistant properties of submersible
distribution transformers. All other
physical properties of the distribution
transformer are the same.
DOE requests comment on its
methodology for modifying the results
of RU4 and RU5 to represent the
efficiency of submersible liquidimmersed units. For other potentially
disadvantaged designs, DOE has
considered establishing equipment
classes to separate out those that would
have the most difficulty achieving
amended efficiency standards, as
discussed in section IV.A.2, but
ultimately has determined not to
include such separate equipment classes
in the proposed standards. However,
DOE requests data as to the degree of
reduction in efficiency associated with
various features.
2. Efficiency Analysis
DOE typically uses one of two
approaches to develop energy efficiency
levels for the engineering analysis: (1)
relying on observed efficiency levels in
the market (i.e., the efficiency-level
approach), or (2) determining the
incremental efficiency improvements
associated with incorporating specific
design options to a baseline model (i.e.,
the design-option approach). Using the
efficiency-level approach, the efficiency
levels established for the analysis are
determined based on the market
distribution of existing products (in
other words, based on the range of
efficiencies and efficiency level
‘‘clusters’’ that already exist on the
market). Using the design option
approach, the efficiency levels
established for the analysis are
determined through detailed
engineering calculations and/or
computer simulations of the efficiency
improvements from implementing
specific design options that have been
identified in the technology assessment.
DOE may also rely on a combination of
these two approaches. For example, the
efficiency-level approach (based on
actual products on the market) may be
extended using the design option
approach to ‘‘gap fill’’ levels (to bridge
large gaps between other identified
efficiency levels) and/or to extrapolate
to the max-tech level (particularly in
cases where the max-tech level exceeds
the maximum efficiency level currently
available on the market).
Howard commented that there were
inconsistencies in the efficiency levels
presented in the webinar and the
August 2021 Preliminary Analysis TSD.
(Howard, No. 59 at p. 2) DOE notes that
corrected values are presented in this
analysis.
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In this rulemaking, DOE relies on an
incremental efficiency (design-option)
approach. This approach allows DOE to
investigate the wide range of design
option combinations, including varying
the quantity of materials, the core steel
material, primary winding material,
secondary winding material, and core
manufacturing technique.
For each representative unit analyzed,
DOE generated hundreds of unique
designs by contracting with Optimized
Program Services, Inc. (‘‘OPS’’), a
software company specializing in
distribution transformer design. The
OPS software used two primary inputs:
(1) a design option combination, which
includes core steel grade, primary and
secondary conductor material, and core
configuration, and (2) a loss valuation.
DOE examined numerous design
option combinations for each
representative unit. The OPS software
generated 518 designs for each design
option combination based on unique
loss valuation combinations. Taking the
loss value combinations, known in the
industry as A and B values and
representing the commercial consumer’s
present value of future no-load and load
losses in a distribution transformer,
respectively, the OPS software sought to
generate the minimum total ownership
cost (‘‘TOC’’). TOC can be calculated
using the equation below.
TOC = Transformer Purchase Price + A
* [No Load Losses] + B * [Load
Losses]
From the OPS software, DOE received
thousands of different distribution
transformer designs, including physical
characteristics, loading and loss
behavior, and bill of materials. DOE
used these distribution transformer
designs, supplemented with
confidential and public manufacturer
data, to create a manufacturer selling
price (‘‘MSP’’). The MSP was generated
by applying material costs, labor
estimates, and various mark-ups to each
design given from OPS.
The engineering result included
hundreds of unique distribution
transformer designs, spanning a range of
efficiencies and MSPs. DOE used this
data as the cost versus efficiency
relationship for each representative
unit. DOE then extrapolated this
relationship, generated for each
representative unit, to all the other,
unanalyzed, kVA ratings within that
same equipment class.
In the August 2021 Preliminary
Analysis TSD, DOE stated that it
maintained the existing designs from
the previous rulemaking and updated
the material prices to get an updated
manufacturer selling price. (August
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45)
Howard commented that while
updating pricing to $2020 still gives
valid designs, reoptimizing with new
pricing would have given more accurate
results. (Howard, No. 59 at p. 2)
DOE agrees that the most accurate
results would be achieved by
reoptimizing designs under current
market practices. However, as
commenters have attested, prices for
many of the components making up
distribution transformers are varied.
Further, manufacturers may make
different optimization decisions
depending on their unique supply
chains and manufacturing capacities. It
would be impractical for DOE to
reoptimize all designs with every
change in material prices and to
represent the specific supply chains of
each manufacturer. To account for the
variability in designs, DOE relies on a
wide range of A and B values to initially
develop designs reflective of the whole
design space, not specific to any given
day’s pricing. DOE relies on 5-year
average material pricing in its base
analysis and conducts additional
sensitivities to encompass additional
pricing scenarios. Further, DOE’s
analysis of various efficiency levels
includes a consumer choice model that
selects a sub-set of designs based on the
minimum MSP within a band-ofequivalence for a given efficiency level.
As such, DOE’s efficiency levels are not
reflective of any one distribution
transformer, but rather are designed to
reflect the variety of distribution
transformers customers would purchase
at a given efficiency level.
In the August 2021 Preliminary
Analysis TSD, DOE noted that it
adapted models of grain-oriented
electrical steel to reflect some of the
lower loss steels that have come onto
the market since the previous
rulemaking. Specifically, DOE stated
that it estimated the core loss of a
similar design by multiplying the noload loss by the ratio of the core losses
at a given flux density between two
steels. DOE noted that while these
designs would not be true optimal
designs, given that lower loss steel
allows more flexibility in the load
losses, however, stated that because
DOE’s designs cover such a wide range
of A and B values, the results would be
sufficiently accurate. DOE requested
feedback on this approach. (August
2021 Preliminary Analysis TSD at p. 2–
46)
Schneider commented that assuming
the core losses of a swapped steel may
be accurate for small reductions in core
loss but bigger jumps could result in full
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redesigns. (Schneider, No. 49 at pp. 14–
15) Powersmiths and ERMCO
commented that this approach does not
lead to optimized designs.
(Powersmiths, No. 46 at p. 4; ERMCO,
No. 45 at p. 1) NEMA commented that
it is an oversimplification to assume
that substituting of lower loss steel will
lead to improved efficiency for a given
design. (NEMA, No. 50 at p. 10) NEEA
commented that DOE should not use
this approach because new material may
have different B–H curves and while it
may be possible to use a direct swap—
it generally isn’t an acceptable practice.
(NEEA, No. 51 at pp. 5–6) The
Efficiency Advocates recommended
DOE conduct new modeling as
manufacturers who didn’t optimize for
new material would be at a competitive
disadvantage. (Efficiency Advocates,
No. 52 at pp. 6–7)
In response to stakeholder feedback,
DOE ran new modeling for some design
option combinations included in the
NOPR. DOE compared this new
modeling to its models that were
established by swapping core steels and
has presented some of these
comparisons in chapter 5 of the TSD.
DOE notes that modeled designs may be
slightly different at a given A and B
value as compared to the direct swap of
core steels. However, across the range of
A and B values included in the
engineering analysis, and specifically at
the minimum MSP for a given
efficiency, the cost-efficiency curves are
very similar. While DOE intends to
update all the engineering designs to
newly modeled designs to instill greater
confidence in the analysis, some core
steel swap designs are still used in the
NOPR in order to ensure quick
publication of the NOPR. These designs
are noted in chapter 5 of the TSD. Given
the similarities between the modeled
designs and the direct swap of steel
designs, DOE believes the updated
modeling will not notably impact
analysis results.
a. Design Option Combinations
As discussed, for each representative
unit, DOE evaluates various design
option combinations, which includes
combinations of electrical steel,
conductor material, and core
construction techniques. In the August
2021 Preliminary Analysis TSD, DOE
presented the various design option
combinations it used for each
representative unit. DOE noted that
distributed gap wound cores typically
need a high-temperature annealing
process to relieve some of the stresses
associated with the core winding
process. (August 2021 Preliminary
Analysis TSD at p. 2–46) As a result of
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this annealing, laser-scribed domainrefined steels lose the core loss benefit
of the domain-refinement. As such, DOE
did not include any laser-scribed
domain-refined steels in distributed gap
wound core design option
combinations. DOE requested comment
on this decision.
In response, NEMA and Schneider
supported DOE’s decision not to include
laser DR products in wound core
constructions. (Schneider, No. 49 at p.
15; NEMA, No. 50 at p. 11) Similarly,
Eaton agreed with DOE’s decision not to
include laser-scribed domain-refined
steels in wound cores but noted that
larger, three-phase units may be able to
use laser-scribed domain-refined steels
in wound cores if an AEM Unicore
machine is used and the products are
not annealed. (Eaton, No. 55 at p. 13)
DOE agrees with Eaton that in certain
scenarios it may be possible to use laserscribed dr products in wound core. But
as Eaton described, the dr
characteristics are only maintained if
the core is not annealed. An unannealed
core is going to have greater losses
associated with the stresses from the
bending of the electrical steel. So, the
loss reduction associated with the better
performing laser dr product is going to
be countered by increased losses
associated with stresses from bending
the steel without annealing. As such,
this approach does not necessarily
reflect a higher efficiency product, but
rather a similar performing product to
using hib steel without domainrefinement and annealing the core. DOE
did not receive any opposition to its
decision to not include laser-scribed dr
steels in its wound core designs and
therefore maintained that approach in
the NOPR analysis.
Regarding some of the specific design
option combinations presented in the
August 2021 Preliminary Analysis TSD,
NEMA commented that GOES with
performance lower than M4 is not used
due to performance limitations. (NEMA,
No. 50 at p. 8) Eaton commented that
M5 isn’t really used anymore and can be
removed from RU4 engineering plots.
Eaton also commented that M4 isn’t
really used in RU5 designs and can be
removed from DOE’s engineering plots.
(Eaton, No. 55 at p. 20) Eaton
commented that an Evans core
transformer is not a valid option for
wye-wye distribution transformers but
noted that it was a moot point since the
costs are greater. (Eaton, No. 55 at p. 20)
DOE acknowledges that some designs
would be unlikely to be considered by
many purchasers, but the engineering
analysis is designed to explore the
whole design space. The specific
combinations identified by NEMA and
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Eaton generally do not impact the
analysis due to the first-cost of the
product being too high and are included
for completeness of the analysis.
Regarding use of thinner steels,
NEMA commented that thinner GOES is
more difficult to use, but not overly
burdensome, whereas amorphous is a
different thickness and width and
cannot be dropped in. (NEMA, No. 50
at p. 9) Cliffs added that while there are
specific applications where M2 is
suitable, nearly all EOMS have stated it
is not amenable to their manufacturing
processes as it is thin and prone to
folding and tearing in core making
equipment. (Cliffs, No. 57 at p. 1)
DOE includes additional costs
associated with handling of thinner
electrical steels, as described in chapter
5 of the TSD. While M2 is included in
the analysis, DOE has limited its
selection in the base case scenario as
described in section IV.F.3.a to be
reflective of its current market share. In
the presence of higher standards, M2
steel (or similarly performing hib steel
that wasn’t modeled but has similar
performance may be an option), may be
a feasible design option for
manufacturers although, it may not be
the lowest first cost option.
Regarding the burdens with using
amorphous steel, DOE has considered
those costs in the manufacturer impact
analysis in section IV.J of this
document.
Eaton noted that while DOE’s designs
span the current definition for normal
impedance range, if new designs are run
in the future, a narrower impedance
range should be used for RU4 and RU5
to align with IEEE C57.12.34, as too low
an impedance could permit extremely
high fault current in the event of a short
circuit. (Eaton, No. 55 at p. 16)
As Eaton noted, DOE’s impedance
ranges align with the current definition
for normal impedance range. The
narrower impedance range cited by
Eaton are achievable in DOE’s models
by all efficiency levels. DOE believes
aligning with the definition of normal
impedance range remains appropriate
given that a variety of impedances are
included at each efficiency level and
consumers may specify specific
impedances.
b. Data Validation
In the August 2021 Preliminary
Analysis TSD, DOE stated that it had
collected publicly available bid data for
a variety of distribution transformers.
DOE noted that the data was limited in
its ability to compare cost and efficiency
because the data was limited to liquidimmersed distribution transformers,
there was significant variability in
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primary voltages, the data didn’t span
the whole design space in all cases,
much of the data was prior to
implementation of the energy
conservation standards as amended in
the April 2013 Standards Final Rule
(Effective January 1, 2016), and there
was significant price variability at every
efficiency. (August 2021 Preliminary
Analysis TSD at p. 2–45) Rather than
drawing any conclusions from this data,
DOE relied on the reported no-load loss
and full-load loss to estimate efficiency.
DOE then presented the raw material
prices and attempted to correct the
material prices to show.
The Efficiency Advocates commented
that the bid data shows significant
differences in MSP and indicates that
the engineering analysis need to be
updated to reflect up-to-date materials,
costs, and designs. (Efficiency
Advocates, No. 52 at p. 7) Eaton
commented that the average selling
price in the plots comparing bid data
and DOE engineering show average
selling prices being much higher than
DOE’s analysis suggests. (Eaton, No. 55
at p. 22)
DOE is uncertain what significant
difference in MSP the stakeholders are
referring to as there is a wide range in
the bid data and many of the points
overlap between the bid data and DOE
designs. Regardless, DOE has updated
material costs in the NOPR analysis.
In presenting the bid data, DOE noted
that it only has full load efficiency at
rated operating temperature, and
therefore applied a quadratic scaling
and estimated temperature correction to
estimate the efficiency as measured
according to DOE’s test procedure.49
Eaton commented that DOE’s estimate
for correcting the load loss in the bid
data is insufficient. (Eaton, No. 55 at p.
20) Eaton expressed concern that a
similar method was used to calculate
DOE’s 50 percent load loss values from
the 100 percent load loss values. (Eaton,
No. 55 at p. 20)
DOE did not use the same method to
calculate 50 percent load loss values
from the 100 percent values in it
modeled data, it only did this in the bid
data because the bid data did not have
specifics as to how the equipment
temperature varies with load and
temperature correction was simply to
estimate efficiency for a general
comparison. DOE’s modeled data
included estimated load performance
and temperature at a variety of
transformer load points. DOE relied on
the modeled transformer load loss at 50
percent load and corrected from the
modeled operating temperature to
DOE’s reference temperature.
Rather than trying to estimate the
rated efficiency of the public utility bid
data from full load losses at rated
temperature rises and make
generalization as to how temperature
would influence efficiency at rated PUL,
DOE has looked at how the no-load and
full load losses of the bid data compare
to the full load losses of the DOE
modeled data. These comparisons are
shown in chapter 5 of the TSD. The
comparisons show that DOE’s modeled
data aligns well with the design space
of the public utility bid data.
In comparing DOE’s modeled results
to the public utility bid data, DOE
realized that for RU4 and RU5, DOE
models overestimated GOES no-load
losses, and accordingly assumed
manufacturers would need lower load
losses in order to meet efficiency
standards.
The process of converting electrical
steel from a sheet into a formed core
shape incurs some number of additional
losses, known as a destruction factor.
Eaton commented that when comparing
amorphous laminations to a finished
core, the destruction factor can be nontrivial and contribute an additional 40
percent to the core losses. (Eaton, No. 55
at p. 11) Similarly, in GOES cores, the
destruction factor can be significant and
varies by transformer type,
manufacturing technique, and electrical
steel type. In general, destruction factors
are much more significant for threephase distribution transformers than
single-phase distribution transformers.
The destruction factor for three-phase
wound core designs was originally
chosen to be conservative and assume
manufacturers would have higher
destruction factors. Through interviews,
DOE learned that manufacturers may be
able to reduce destruction factors in
wound cores using a Unicore design,
and this is more common in larger,
three-phase designs which tend to be
produced in lesser volumes. In the
NOPR analysis, DOE modified the
destruction factor of three-phase, liquidimmersed, wound core, GOES
distribution transformers to better align
with the marketed Unicore destruction
factors.50 The resulting designs better
align with the actual design space
observed in real world data, as shown
in chapter 5 of the TSD. The impact of
this change is that GOES transformers
achieve higher efficiency ratings for
RU4 and RU5 than the August 2021
49 See Chapter 5 of the NOPR TSD, available
online at www.regulations.gov/document/EERE2019-BT-STD-0018-0022.
50 Advertised destruction factors for Unicore
available at www.aemcores.com.au/technology/
annealing/overview-and-the-benefit-of-unicore/.
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Preliminary Analysis TSD suggested. It
also introduces new transformers to the
selectable design space which may have
a lower MSP than if DOE had not made
this change. While destruction factor
does vary by manufacturing technique
and manufactures may use different
methods, DOE believes that absent this
change, it would be overestimating the
cost of meeting efficiency standards
with a GOES core as compared to an
amorphous core.
Regarding DOE’s use of modeling
software, Powersmiths commented that
OPS software is used by them and many
manufacturers but noted that the eddy
and stray losses in OPS models are
‘‘guestimates’’ from the design engineer
and can vary largely. (Powersmiths, No.
46 at pp. 4–5) Powersmiths commented
that inadequate stray loss estimates
could result in simulation errors and
should be examined more closely
relative to transformer capacity.
(Powersmiths, No. 46 at p. 5)
NEMA commented that its members’
modeling programs account for stray,
eddy, and other losses that appear
largely absent from DOE models and
while this was noted in the April 2013
Standards Final Rule, the efficiency
levels in the preliminary analysis leave
little flexibility to meet efficiency
standards, making it more important
now. (NEMA, No. 50 at p. 2) NEMA
added by omitting these design factors,
DOE’s models do not represent true
design feasibility and DOE should
update models to add these losses.
(NEMA, No. 50 at p. 2) NEMA
commented specifically that in
applications with a large amount of buss
bars are required, efficiency standards
are more difficult to meet. (NEMA, No.
50 at p. 5)
DOE transformer models do include
estimates of stray and eddy losses. As
commenters noted, the amount that
these impact designs will be unique to
manufacturer and specific transformer
designs. In DOE’s comparison of its
liquid immersed designs to the design
space in public utility bid data, DOE
notes that its designs align relatively
well with what is being built on the
market. Further, DOE includes a bus
and lead correction factor to MVDT
designs based on an understanding that
substation-style designs are quite
common in the MVDT market.
DOE requests data as to how stray and
eddy losses at rated PUL vary with kVA
and rated voltages.
While certain unique designs may
have higher stray and eddy losses, the
incremental costs with meeting higher
efficiency standards tends to follow a
similar relationship. Particularly to the
extent that amended efficiency
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standards are met via a transition to
lower-loss GOES or amorphous steel,
the incremental cost to meet higher
efficiency standards tends to be similar.
In bid data, DOE observed that higher
current transformers, which are more
likely to have high stray losses, often
have more amorphous bids. This
suggests that transformers with high
buss losses may have more favorable
economics associated with meeting
amended efficiency standards via
amorphous steel.
Regarding validation of DOE’s
engineering analysis more generally,
NEMA commented that its members
cannot validate and offer corrections for
every RU but suggested DOE hold a
series of collaborative meetings where
models are made more accurate and
representative. (NEMA, No. 50 at p. 2)
Eaton requested DOE provide more
information about the distribution
transformer design so manufacturers can
confirm the designs align with their
modeling. (Eaton, No. 55 at p. 20–22)
DOE has included additional
engineering details in chapter 5 of the
TSD to better explain its modeling and
costing. Regarding NEMA’s suggestion
to hold collaborative meetings, DOE
notes that in addition to soliciting
public comment in a written format and
public interviews, DOE conducts
confidential manufacturer interviews
through which manufacturers are
invited to offer feedback. DOE has in the
past, and as part of this analysis, made
updates to its modeling to better reflect
manufacturer realities. DOE will
continue to update its analysis in
response to manufacturer feedback and
particularly to the extent modeling
deviates from real world design
constraints.
c. Baseline Energy Use
For each equipment class, DOE
generally selects a baseline model as a
reference point for each class, and
measures changes resulting from
potential energy conservation standards
against the baseline. The baseline model
in each product/equipment class
represents the characteristics of a
product/equipment typical of that class
(e.g., capacity, physical size). Generally,
a baseline model is one that just meets
current energy conservation standards,
or, if no standards are in place, the
baseline is typically the most common
or least efficient unit on the market.
DOE’s analysis for distribution
transformers generally relies on a
baseline approach. However, instead of
selecting a single unit for each
efficiency level, DOE selects a set of
units to reflect that different distribution
transformer purchasers may not choose
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distribution transformers with identical
characteristics because of difference in
applications and manufacturer
practices. The mechanics of the
customer choice model at baseline and
higher efficiency levels are discussed in
section IV.F.3 of this document.
d. Higher Efficiency Levels
DOE relies on a similar approach to
its baseline engineering in evaluating
higher efficiency levels. DOE’s modeled
units span the design space. In
evaluating a higher efficiency level up
until that maximum efficiency level that
DOE considers (‘‘max-tech’’), DOE
evaluates the modeled units that would
exceed the higher efficiency level. Then,
rather than selecting a single unit, DOE
applies a customer choice model to
evaluate the distribution transformers
that would be purchased if standards
were amended.
Howard commented that they looked
at the various RUs and believe the
current efficiency standards provide
excellent value to consumers. (Howard,
No. 59 at p. 2) Howard added that while
they don’t use OPS software, their
internal software says to remain at the
current efficiency levels and there is no
need to have a NOPR as current
standards are sufficient. (Howard, No.
59 at pp. 2–3) DOE appreciates
Howard’s comment but notes that they
have not provided data to justify the
results of their internal software. As
noted previously, DOE has tentatively
determined that the proposed standards
are technologically feasible (based on
models currently available in the
market) and economically justified, and
would result in significant energy
savings.
The Efficiency Advocates commented
that since DOE last revised its energy
conservation standards, major
economies around the world have set
new efficiency thresholds that exceed
U.S. energy conservation standards.
(Efficiency Advocates, No. 52 at pp. 7–
8) The Efficiency Advocates commented
that the U.S. should aim to be a world
leader in transformer efficiency.
(Efficiency Advocates, No. 52 at pp. 7–
8)
DOE notes that while it may look at
foreign efficiency standards to get a
better understanding of the global
distribution transformer market, the
U.S. has its own unique economic
conditions, energy costs, and legal
requirements. DOE has evaluated
amended energy conservation standards
based on the unique conditions of the
U.S. and DOE’s legal obligations under
EPCA.
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e. Load Loss Scaling
DOE energy conservations standards
apply only at a single PUL for a given
distribution transformer equipment
class (50 percent for liquid-immersed
distribution transformers and medium
voltage dry-type distribution
transformers and 35 percent for lowvoltage dry-type distribution
transformers). 10 CFR 431.196.
However, distribution transformers
exhibit varying efficiency with varying
PUL. Distribution transformer no-load
losses are generally constant with
loading, while load losses vary
approximately with the quadratic of the
PUL. In practice, efficiency deviates
slightly from this assumption as no-load
losses are not perfectly constant and
load losses are not perfectly quadratic.
DOE requested comment on
approximating load losses as a quadratic
function of PUL.
NEMA commented that the quadratic
approximation for load losses is
sufficient. (NEMA, No. 50 at p. 11)
OPS’ modeling includes details as to
how a distribution transformer’s loss
and temperature vary across select load
points. In determining the rated
efficiency of a transformer model as it
would be certified under DOE’s test
procedure, DOE relies on the modeled
load losses at the PUL at which
efficiency is calculated and corrects the
load losses from the modeled
temperature to the reference
temperature. This value is used to
calculate the rated efficiency of a
distribution transformer model.
In the downstream analysis of a
distribution transformer energy use and
costs, DOE relies on the calculated fullload loss values and applies a quadratic
approximation for what the load losses
would be under real world loading
conditions. Commenters have generally
agreed that this approach is sufficient.
DOE noted that the full-load loss
value DOE uses in its downstream
analysis is the full-load loss estimate at
the modeled transformer temperature.
Full-load loss in industry is often
reported at the rated temperature rise.
Lower loss distribution transformers
generally operate at lower temperatures,
as they have less losses of heat to
dissipate. Some transformers may
operate well below their rated
temperature even at full load. Therefore,
the full-load losses used in the
downstream analysis may be lower than
the reported full-load losses at rated
temperature rise.
NEEA commented that a quadratic
scaling of load losses would not apply
with harmonic frequencies and DOE
should include a harmonic dependent
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factor in its scaling model. (NEEA, No.
51 at p. 6) DOE notes that section 4.1 of
appendix A specifies testing using a
sinusoidal waveform. Therefore,
harmonics would not impact the rated
efficiency of a distribution transformer.
In DOE’s downstream analyses,
harmonics would generally lead to
greater losses. While nonlinear loads
exist, the impact of them is small and
DOE does not have data suggesting they
meaningfully impact system wide
savings to the point that a quadratic
approximation is inaccurate. Further,
while harmonics may increase losses,
relative to what a quadratic
approximation would estimate, lower
operating temperatures at low-loading,
where most distribution transformers
operate, would decrease losses relative
to the quadratic approximation.
While other factors may cause the loss
behavior of individual transformers in
specific applications to deviate slightly
from a true quadratic of the full-load
losses, stakeholders have generally
supported approximating load losses a
quadratic of PUL and have not provided
an alternative, more accurate method for
approximating losses. As such, DOE has
retained a quadratic load loss scaling in
its analysis.
f. kVA Scaling
NEMA commented that the 0.75
power scaling rule is overly simplistic
and has resulted in smaller kVA MVDTs
having a hard time meeting efficiency
standards. (NEMA, No. 50 at p. 9) Eaton
commented that DOE’s scaling rule as it
applied to height, width, and depth of
the core/coil assembly would not
always be accurate due to certain
bushing space requirements and design
trade-offs pertaining to bushing heights
relative to core/coil assembly heights.
(Eaton, No. 55 at p. 16)
DOE has not received any comment or
data suggesting an alternative method
for scaling kVA and therefore has
retained its scaling methods.
3. Cost Analysis
The cost analysis portion of the
engineering analysis is conducted using
one or a combination of cost
approaches. The selection of cost
approach depends on a suite of factors,
including the availability and reliability
of public information, characteristics of
the regulated product, the availability
and timeliness of purchasing the
equipment on the market. The cost
approaches are summarized as follows:
• Physical teardowns: Under this
approach, DOE physically dismantles a
commercially available product,
component-by-component, to develop a
detailed bill of materials for the product.
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• Catalog teardowns: In lieu of
physically deconstructing a product,
DOE identifies each component using
parts diagrams (available from
manufacturer websites or appliance
repair websites, for example) to develop
the bill of materials for the product.
• Price surveys: If neither a physical
nor catalog teardown is feasible (for
example, for tightly integrated products
such as fluorescent lamps, which are
infeasible to disassemble and for which
parts diagrams are unavailable) or costprohibitive and otherwise impractical
(e.g., large commercial boilers), DOE
conducts price surveys using publicly
available pricing data published on
major online retailer websites and/or by
soliciting prices from distributors and
other commercial channels.
In the present case, DOE conducted
the analysis by applying materials
prices to the distribution transformer
designs modeled by OPS. The resulting
bill of materials provides the basis for
the manufacturer production cost
(‘‘MPC’’) estimates to which mark-ups
are applied to generate manufacturer
selling prices (‘‘MSP’’). The primary
material costs in distribution
transformers come from electrical steel
used for the core and the aluminum or
copper conductor used for the primary
and secondary winding. DOE presented
preliminary costing data and
methodology in the August 2021
Preliminary Analysis TSD.
Regarding the cost analysis generally,
NEMA commented that the material
prices presented in the preliminary
analysis do not reflect the post-COVID
world and may be low by as much as
half. (NEMA, No. 50 at p. 2) Eaton
commented that PPI for power and
distribution transformers has increased
around 25 percent from 2020 levels and
so costs are going to be higher and
payback periods will be longer. (Eaton,
No. 55 at p. 13) Howard echoed the
concerns that Covid–19 has created
labor and supply chain issues. (Howard,
No. 59 at p. 1) Howard commented that
their internal studies showed
incremental MSPs as much as four times
higher than what DOE showed in their
preliminary analysis. (Howard, No. 59 at
p. 2) Carte commented that the cost of
both copper and aluminum have risen
substantially in the past year. (Carte, No.
54 at pp. 3–4) Powermiths added that
market megatrends, such as the
pandemic, decarbonization and electric
vehicles may impact the analysis and
create uncertainty. Powesmiths
recommended DOE delay changes until
these megatrends settle. (Powersmiths,
No. 46 at pp. 6–7) Powersmiths and
Carte commented that the market is in
a state of flux right now and it may be
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prudent to hold off any changes to
efficiency standards until prices settle.
(Carte, No. 54 at p. 4; Powersmiths, No.
46 at p. 7)
DOE data confirms that prices have
been up recently, however, it is difficult
to say for certain how those prices will
vary in the medium to long terms and
what those prices will be in the future.
Rather than trying to project future
prices, DOE relies on a five-year average
in its base case and evaluates how the
results would change with different
pricing sensitivities. The recent price
increases described by comments are
incorporated into this five-year average
and as a result, prices in the NOPR
analysis are higher than they were in the
August 2021 Preliminary Analysis TSD.
Eaton commented that in evaluating
amended energy conservation
standards, DOE should solicit
quotations from at least three
distribution transformer manufacturers
for each representative unit and create
a cost-down cost estimate to calibrate
the bottom-up estimates. (Eaton, No. 55
at p. 19)
As DOE noted in section IV.C.2.b,
DOE welcomes manufacturers to submit
design and costing data for distribution
transformers. DOE notes that in addition
to soliciting public comment in a
written format and public interviews,
DOE conducts confidential
manufacturer interviews through which
much of the pricing data is gathered.
DOE has made some updates to its cost
analysis in response to manufacturer
feedback, as described in the following
sections.
a. Electrical Steel Prices
Electrical steel is one of the primary
drivers of efficiency improvements and
the relative costs associated with
transitioning to lower loss steels can
impact the cost effectiveness of
amended efficiency standards. As noted,
in section IV.A.5, the sourcing practices
of individual manufacturers and
production locations can impact prices
as not all steel manufacturers produce
the same electrical steels and trade
actions have historically impacted the
industry. DOE presented pricing in the
August 2021 Preliminary Analysis TSD
and requested comment. (August 2021
Preliminary Analysis TSD at p. 2–53)
ERMCO commented that the core
steel costs presented in the preliminary
analysis seem reasonable, but market
growth in sectors, like EVs, may drive
future prices up. (ERMCO, No. 45 at p.
1) Powersmiths commented that smaller
manufacturers cannot access the DOE
costs because volume drives price.
Powersmiths noted that for one of the
pdr steels it uses, the price has
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increased as much as 61 percent and
they do not see them returning to their
lower prices. (Powersmiths, No. 46 at p.
6)
Carte commented that there is a global
shortage of electrical steel and the price
is up 20 percent in this year alone, with
current prices up 76 percent from the
2008 peak. (Carte, No. 54 at p. 3) Carte
noted that some industry sources expect
prices to far exceed their 2008 peaks.
(Carte, No 54 at p. 3)
Carte cited several reasons for the
increase in pricing. China has reduced
export of GOES in recent years. (Carte,
No. 54 at p. 3) Second, increased
competition from non-oriented
electrical steel serving the electric
vehicle industry which has encouraged
some steel manufacturers to convert
GOES production lines to non-oriented
electrical steel production lines. (Carte,
No. 54 at p. 3)
DOE has updated pricing in this
analysis in response to stakeholder
feedback and confidential manufacturer
interviews. Prices for electrical steel
have increased significantly in recent
years. Manufacturers noted that this
price increase was particularly high for
foreign electrical steel. DOE has applied
a 5-year average price in its base case
analysis. The prices in and conducted
sensitivities for various other pricing
scenarios, as discussed in section
IV.C.3.
EEI commented that higher standards
may significantly impact all nonamorphous cores and limit choice and
lead to higher prices for consumers
considering limited availability of
certain steel. (EEI, No. 56 at p. 3)
DOE generally assumes pricing to be
reflective of current market costs. While
higher standards could limit which
steels are available to meet standards,
DOE notes that a handful of highvolume steels currently dominate the
industry. Historically, when amended
standards have been adopted, steel
manufacturers have increased capacity
of the electrical steel grades needed to
meet amended efficiency standards.
These materials may have higher costs,
but they also tend to have higher costs
in the current market. Rather than trying
to predict what the cost and market
breakdown would be in the presence of
amended standards, DOE relies on a
five-year average and conducts price
sensitivities to ensure that energy
savings are cost effective under different
pricing structures.
Carte commented that while they
don’t purchase amorphous steel, DOE
may want to verify that amorphous steel
from China is still available and
questioned if there were any domestic
manufacturers of amorphous steel.
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(Carte, No. 54 at p. 3) DOE notes that
amorphous steel is produced
domestically, as well as in China and
Japan.
NEEA commented that its research
suggests amorphous cores are lower first
cost above 100 kVA single-phase or 500
kVA three-phase and there are several
utilities commonly purchasing
amorphous in the U.S. and Canada.
(NEEA, No. 51 at p. 8) Metglas
commented that its internal calculations
show that amorphous steel is not close
to price parity with GOES, using DOE’s
preliminary analysis assumed pricing.
(Metglas, No. 53 at p. 2) Metglas
commented that recent bid data shows
amorphous transformers typically need
an A value over $7 per Watt and A to
B ratio greater than $3 per Watt for
amorphous transformers to win on total
ownership cost bids. (Metglas, No. 53 at
p. 2) Metglas commented that DOE’s
preliminary analysis pricing of
amorphous is accurate for sourced
cores, but may be lesser for
manufacturers who produce their own
cores. (Metglas, No. 53 at p. 5)
Metglas commented that some
transformer manufacturers source cores
while other produce them internally.
(Metglas, No. 53 at p. 5) NEMA
disagreed with DOE’s assumption that
all amorphous cores are sourced and
deferred to individual NEMA members
as to their specific practices. (NEMA,
No. 50 at p. 11)
Pricing for amorphous steel has
increased slightly since the preliminary
analysis but less so than GOES steel,
and in particular foreign produced
GOES. As such, amorphous steel is
generally more competitive on first cost
than it was in the preliminary analysis.
As NEEA suggested, DOE did observe
instances where amorphous
transformers are lower first cost.
However, that has not necessarily led to
increased adoption, in part because
most manufacturers’ capital equipment
is set-up for GOES core production.
Amorphous transformer production
would require manufacturer investment
to fill high volume orders. As such, the
first cost competitiveness of amorphous
steel in certain applications has not
necessarily corresponded to equivalent
market share. DOE has continued to
assume sourced core pricing for
amorphous steel as most manufacturers
do not have the capacity to produce
cores in volume. While Metglas notes
that manufacturers producing their own
cores could have lesser costs, DOE notes
in that scenario they would likely have
additional retooling costs that would be
aggregated over unit volume and
increase core price relative to raw
materials. More details regarding DOE’s
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pricing of amorphous steel are included
in chapter 5 of the TSD.
For this NOPR, DOE’s analysis shows
that it is cost-effective to meet the
proposed standards for liquid-immersed
and low-voltage dry-type distribution
transformers fabricated with amorphous
steel cores. An energy conservation
standard that significantly increases
adoption of amorphous core distribution
transformers would represent a
substantial shift in the distribution
transformer market. Such a shift could
impact pricing and competition among
steel suppliers in ways that may not be
perfectly predictable, as the resulting
market equilibrium would depend on
decisions made by market participants
outside of DOE’s control. However, it is
important to emphasize that price
volatility in electrical steel and shifts in
the market’s competitive balance are not
limited to amorphous steel.
Substantial volatility has
characterized the U.S. steel market over
the last several decades. From 2000 to
2007, U.S. steel markets, and more
specifically the U.S. electrical steel
market, began to experience pressure
from several directions. Demand in
China and India for high-efficiency,
grain-oriented core steel contributed to
increased prices and reduced global
availability. Cost-cutting measures and
technical innovation at their respective
facilities, combined with the lower
value of the U.S. dollar enabled
domestic core steel suppliers to become
globally competitive exporters.
In late 2007, the U.S. steel market
began to decline with the onset of the
global economic crisis. U.S. steel
manufacturing declined to nearly 50
percent of production capacity
utilization in 2009 from almost 90
percent in 2008. Only in China and
India did the production and use of
electrical grade steel increase for 2009.51
In 2010, the price of steel began to
recover. However, the recovery was
driven more by increasing cost of
material inputs, such as iron ore and
coking coal, than broad demand
recovery.
In 2011, core steel prices again fell
considerably. At this time, China began
to transition from a net electrical steel
importer to a net electrical steel
exporter.52 Between 2005 and 2011,
China imported an estimated 253,000 to
353,000 tonnes of electrical steel.
51 International Trade Administration. Global
Steel Report. (Last accessed September 1, 2022)
https://legacy.trade.gov/steel/pdfs/global-monitorreport-2018.pdf.
52 Capital Trade Incorporated, Effective Trade
Relief on Transformer Cores and Laminations,
2020. Submitted as part of AK Steel comment at
Docket No. BIS–2020–0015–0075 at p. 168.
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During this time, China added
significant domestic electrical steel
production capacity, such that from
2016 to 2019 only about 22,000 tonnes
were imported to China annually. China
also exported nearly 200,000 tonnes of
electric steel annually by the late 2010’s.
Many of the exporters formerly
serving China sought new markets
around 2011, namely the United States.
The rise in U.S. imports at this time hurt
domestic U.S. steel manufacturers, such
that in 2013, domestic U.S. steel
stakeholders filed anti-dumping and
countervailing duty petitions with the
U.S. International Trade Commission.53
The resulting investigation found that
‘‘an industry in the United States is
neither materially injured nor
threatened with material injury by
reason of imports of grain-oriented
electrical steel . . . to be sold in the
United States at less than fair value.’’ 54
In the amorphous steel market, the
necessary manufacturing technology has
existed for many decades and has been
used in distribution transformers since
the late 1980s.55 In many countries,
amorphous steel is widely used in the
cores of distribution transformers.56
Significant amorphous steel use tends to
occur (1) in places with both
comparatively lower labor costs and
significant electrification (e.g., India,
China); and (2) in regions with relatively
high loss valuations on losses (e.g.,
certain provinces of Canada).
Beginning in 2018, the U.S.
government instituted a series of import
duties on aluminum and steel articles,
among other items. Steel and aluminum
articles were generally subject to
respective import duties of 25 and 10
percent ad valorem.57 83 FR 11619; 83
FR 11625. Since March 2018, several
presidential proclamations have created
or modified steel and aluminum tariffs,
including changes to the products
covered, countries subject to the tariffs,
exclusions, etc.58 Given the recency of
several publications, combined with the
53 U.S. International Trade Commission, GrainOriented Electrical Steel from Germany, Japan, and
Poland, Investigation Nos. 731–TA–1233, 1234, and
1236. September 2014.
54 Id.
55 DeCristofaro, N., Amorphous Metals in ElectricPower Distribution Applications, Material Research
Society, MRS Bulletin, Volume 23, Number 5, 1998.
56 BPA’s Emerging Technologies Initiative, Phase
1 report: High Efficiency Distribution Transformer
Technology Assessment, April 2020. Available
online at: https://www.bpa.gov/EE/NewsEvents/
presentations/Documents/
Transformer%20webinar%204-7-20%20Final.pdf.
57 Ad valorem tariffs are assessed in proportion to
an item’s monetary value.
58 Congressional Research Service, Section 232
Investigations: Overview and Issues for Congress,
May 18, 2021, Available online at: https://fas.org/
sgp/crs/misc/R45249.pdf.
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supply chain disruptions caused by the
Covid–19 pandemic, many of the price
effects that, directly or indirectly,
impact the pricing of distribution
transformers may still be stabilizing.
Another recent trend in distribution
transformer manufacturing is an
increase in rate of import or purchase of
finished core products. The impact of
electrical steel tariffs on manufacturers’
costs varies widely depending on if
manufacturers are purchasing raw
electrical steel and paying a 25-percent
tariff if the steel is imported, or if they
are importing finished transformer cores
which, along with distribution
transformer core laminations and
finished transformer imports, are not
subject to the tariffs. Some stakeholders
have argued that this trend toward
importing distribution transformer
cores, primarily from Mexico and
Canada, is a method of circumventing
tariffs, as electrical steel sold in the
global market has been less expensive
than domestic electrical steel on
account of being unfairly traded.59 60
Conversely, other stakeholders have
commented that this trend predated the
electrical steel tariffs and that
importation of transformer components
is often necessary to remain competitive
in the U.S. market, given the limited
number of domestic manufacturers that
produce transformer laminations and
cores.61 62
On May 19, 2020, the U.S.
Department of Commerce (DOC) opened
an investigation into the potential
circumvention of tariffs via imports of
finished distribution transformer cores
and laminations. 85 FR 29926. On
November 18, 2021, DOC published a
summary of the results of their
investigation in a notice to the Federal
Register. The report stated that
importation of both GOES laminations
and finished wound and stacked cores
has significantly increased in recent
years, with importation of laminations
increasing from $15 million in 2015 to
$33 million in 2019, and importation of
finished cores increasing from $22
million in 2015 to $167 million in 2019.
DOC attributed these increases, at least
in part, to the increased electrical steel
costs resulting from the imposed tariffs
on electrical steel. In response to their
investigation, DOC stated it is exploring
several options to shift the market
towards domestic production and
59 (AK Steel, Docket No. BIS–2020–0015–0075 at
pp. 43–58).
60 (American Iron and Steel Institute, Docket No.
BIS–2020–0015–0033 at pp. 2–5).
61 (Central Maloney Inc., Docket No. BIS–2020–
0015–0015 at pp. 1).
62 (NEMA, Docket No. BIS–2020–0015–0034 at
pp. 3–4).
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consumption of GOES, including
extending tariffs to include laminations
and finished cores. No trade action has
been taken at the time of publication of
this NOPR. 86 FR 64606.
More recently, DOE learned from
stakeholders during manufacturer
interviews and from public comments
that pricing of electrical steel has risen
such that in the current market, it is
similar between domestic and foreign
electrical steel (i.e., the price of foreign
electrical steel without any tariffs
applied). (Powersmiths, No. 46 at p. 6;
Carte, No. 54 at p. 3) These recent price
increases, particularly in foreign
produced electrical steel, were cited as
being a result of both general supply
chain complications and increased
demand for non-oriented electrical steel
(NOES) from electric motor
applications. (NEMA, No. 50 at p. 9;
Powersmiths, No. 46 at p. 5; Zarnowski,
Public Meeting Transcript, No. 40 at p.
36; Looby, Public Meeting Transcript,
No. 40 at p. 37)
Since 2016, there has been one
domestic supplier and multiple global
suppliers of GOES. The amorphous steel
market follows the same pattern, with
one domestic supplier and multiple
global suppliers. Further, although the
current foreign suppliers of amorphous
steel are primarily based in Japan and
China, DOE received feedback through
public comment and manufacturer
interviews that South Korean and
German steel suppliers have the
capabilities to expand their steel
production to include amorphous steel,
if demand for amorphous steel
increases. (Metglas, No. 11 at p. 2) DOE
does not have data suggesting that
amorphous steel is inherently more
expensive to produce than GOES. Both
varieties rely on similar inputs and both
are capital-intensive, therefore tending
to reduce per-pound production costs
with higher capacity utilizations.
Public comments by Metglas stated
that within two years of developing the
know-how to produce amorphous
ribbon, producers in China were able to
add 70,000 Mt of capacity.63 Public
statements from one manufacturer in
Europe note that since the expiration of
an initial patent related to amorphous
steel production, there have been a
number of additional amorphous
suppliers and material prices have been
stable.64 Given these historical
63 Metglas, Section 232 National Security
Investigation of Imports of Steel: Comments by
Metglas, Inc. Requesting the Inclusion of
Amorphous Steel, 2017. https://www.bis.doc.gov/
index.php/232-steel-public-comments/1835metglas-amorphous-public-comment.
64 Wilson Power Solutions, Amorphous Metal
Transformers—Myth Buster, 2018. https://
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examples with which manufacturers
have been able to quickly add
amorphous capacity, along with the
cited number of producers capable of
making amorphous steel, DOE’s view is
that it is reasonable to expect that if
there were insufficient amorphous steel
production capacity to meet amended
energy conservation standards, some
manufacturers with the expertise to
produce amorphous steel would enter
the market and manufacturers currently
without the expertise to manufacture
amorphous steel may invest in its
development.
Additionally, during manufacturer
interviews, stakeholders indicated that
in the current marketplace there are
shortages of GOES steel products,
leading to greater price levels and
volatility. Because GOES production
can be shifted to NOES products at
modest cost, these shortages are likely
driven at least in part by rising demands
for NOES in manufacture of motors and
electric vehicles. This demand creates
competition for GOES production
capacity. Given recent trends of
decarbonization initiatives and
industrial reshoring, the manufacture of
NOES for electric vehicle production
appears poised to put competitive
pressure on GOES production well into
the future.65
Further, there has been, and remains,
competition for available low-loss
grades of GOES between the power and
distribution transformer segments. Cliffs
commented that while highpermeability GOES works well in
distribution transformers, it has
historically been sold as a laser DR
product to the power transformer
market; NEMA commented that both
distribution and power transformers
compete for steel demand. (Cliffs, No.
57 at p. 1; NEMA, No. 50 at p. 9)
Therefore, it is likely that any energy
savings associated with use of lowerloss core steel, whether it be amorphous
or grain-oriented, would require
investment from steel manufacturing
industry at-large to increase capacity of
either lower-loss GOES steels or of
amorphous steel.
Rather than constructing sensitivity
analysis scenarios to reflect every
potential combination of factors that
may affect steel pricing (e.g., various
tariffs and quotas, competition from
NOES, decisions by steelmakers in
various countries to add production
capacity) or making assumptions
www.wilsonpowersolutions.co.uk/app/uploads/
2017/05/WPS_AMT_Myth_Buster_2018-2.pdf.
65 Example: California’s electric vehicle adoption
executive order: https://www.gov.ca.gov/wpcontent/uploads/2020/09/9.23.20-EO-N-79-20Climate.pdf, 2022.
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1767
regarding how changes in production
volume affect material prices, DOE
relies on a 5-year average pricing for its
core steel.
DOE requests comment on the current
and future market pressures influencing
the price of GOES. Specifically, DOE is
interested in the barriers to and costs
associated with converting a factory
production line from GOES to NOES.
DOE further requests comment
regarding how the prices of both GOES
and amorphous are expected to change
in the immediate and distant future.
DOE requests comment regarding the
barriers to converting current M3 or
23hib90 electrical steel production to
lower-loss GOES core steels.
DOE requests comment as to if there
are markets for amorphous ribbon,
similar to NOES competition from
GOES production, which would put
competitive pressures on the production
of amorphous ribbon for distribution
transformers.
DOE requests comment on how a
potentially limited supply of
transformer core steel, both of
amorphous and GOES, may affect core
steel price and availability. DOE seeks
comment on any factors which uniquely
affect specific steel grades (e.g.,
amorphous, M-grades, hib, dr, pdr).
Additionally, DOE seeks comment on
how it should model a potentially
concentrated domestic steel market in
its analysis, resulting from a limited
number of suppliers for the amorphous
market or from competition with NOES
for the GOES market, including any use
of game theoretic modeling as
appropriate.
b. Scrap Factor
In the August 2021 Preliminary
Analysis TSD, DOE noted that it applies
various scrap markups to distribution
transformer bills of materials (August
2021 Preliminary Analysis TSD at p. 2–
53). DOE requested comment on its
scrap factor markups. Metglas
commented that DOE should not apply
a scrap to a finished core because the
scrap would be included in the core
costs. (Metglas, No. 53 at p. 5)
DOE notes that a scrap factor is still
applied to prefabricated cores to
account for any potential breakage of
cores and any scrap associated with
assembling the windings or insulation
on the cores. However, a lesser factor is
used as compared to GOES because
much of the scrap costs would be priced
into the core production.
Metglas commented that the scrap
rate for GOES seemed low but did not
provide an alternative value. (Metglas,
No. 53 at p. 5) Eaton commented that it
is unclear which mark-ups are applied
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to which cores and DOE should clarify.
(Eaton, No. 55 at p. 14)
DOE has maintained the scrap factors
from the preliminary analysis as it did
not receive alternative values and has
updated the language in chapter 5 of the
TSD to better explain how scrap factors
were applied. DOE has added equations
in chapter 5 to walk through how the
material costs were translated to MSPs.
calculations but cabinet/enclosures are
and DOE should add these into the
analysis. (NEMA, No. 50 at p. 14)
DOE has modeled a cabinet and
enclosure in its sizing of distribution
transformer tanks. DOE has presented
these additional details in chapter 5 of
the TSD.
c. Other Material Costs
In the August 2021 Preliminary
Analysis TSD, DOE presented material
prices and requested comment on a
variety of additional materials used in
distribution transformer construction.
(August 2021 Preliminary Analysis TSD
at p. 2–50)
Eaton commented that while
windings combs and epoxy resin have
materials cost listed, they are not used
in liquid immersed transformers. (Eaton,
No. 55 at p. 14) DOE notes that it did
not apply either of those costs to liquidimmersed distribution transformers and
has made that more clear in the NOPR
TSD.
Eaton commented that mineral oil and
mild steel prices are higher than was
shown in the August 2021 Preliminary
Analysis TSD. (Eaton, No. 55 at p. 14)
Eaton commented that DOE may be
underestimating pricing, in part due to
underestimating the number and costs
of some of the fixed components, such
as the number of bushings for RU4 and
RU5. (Eaton, No. 55 at pp. 14–16) DOE
has made modifications to the pricing of
its fixed components and updated costs
to reflect generally price changes in the
underlying commodities. DOE notes
that the fixed-costs generally do not
vary with efficiency and as such, higher
pricing of these fixed-components
would not impact the pay-back periods
for more efficient distribution
transformers.
Specifically, regarding the cost of the
distribution transformer tank, Eaton
commented that the cost is too low and
appears to have omitted the cost of the
cabinet and associated labor. (Eaton, No.
55 at p. 15)
Part of the difference in tank costs
cited by Eaton, is likely associated with
the increase in tank steel that has
occurred between when the preliminary
analysis prices were gathered compared
to the NOPR prices. DOE has updated
tank steel prices, which has increased
the price of the distribution transformer
tank. DOE notes that weld time would
generally be included in calculation of
labor. DOE has added additional detail
as to calculation of tank cost in chapter
5 of the TSD.
NEMA commented that radiators are
not always included in footprint
Factory Overhead
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d. Cost Mark-Ups
In the August 2021 Preliminary
Analysis TSD, DOE noted that it used a
factory overhead markup to account for
all indirect costs associated with
production, indirect materials and
energy used, taxes, and insurance.
(August 2021 Preliminary Analysis TSD
at p. 2–57)
Eaton commented that it was unclear
what exactly the factory overhead
markup was applied to, for example, did
it include only materials the consumer
produced themselves or did it apply to
purchased parts as well. (Eaton, No. 55
at p. 15)
DOE applied the factory overhead
markup to all material costs, which
would include purchased parts. DOE
understands that purchased parts would
still require factory space, certain
equipment usage, taxes, and insurance.
DOE has added detail in chapter 5 of the
TSD as to how it applied the Factory
Overhead Mark-up.
Labor
Labor costs are an important aspect of
the cost of manufacturing a distribution
transformer. In the August 2021
Preliminary Analysis TSD, DOE
described how the number of labor
hours were derived for each distribution
transformer design. For liquid-immersed
distribution transformers, DOE generally
relied on a bottoms-up approach,
estimating the various hours associated
with the various steps in distribution
transformer manufacturing. For dry-type
distribution transformers, DOE relies on
a top-down approach to estimate the
total labor for a unit using equations
derived from manufacturer data. These
equations include a base labor charge
for a given unit and a variable charge
that varies with transformer size. DOE
notes in the August 2021 Preliminary
Analysis TSD, it mistakenly outlined a
bottom-up approach for LVDTs when in
fact a top-down labor estimate was used.
This discussion is modified in chapter
5 of the TSD, while the estimated labor
per unit is unchanged.
In response to the August 2021
Preliminary Analysis TSD, Eaton noted
that the estimates of labor hours for RU4
and RU5 appeared to notably
underestimate the required labor per
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unit and noted many specific areas in
the bottom-up approach that appeared
to underestimate labor. (Eaton, No. 55 at
p. 17–19) Eaton also noted that DOE
overestimated the RU5 additional
number of labor hours for building an
amorphous distribution transformer and
that the only difference would be that
an amorphous transformer would have
a split core assembly, which would
require above 1 hour of additional labor.
(Eaton, No. 55 at p. 20)
In manufacturer interviews, DOE
received concurring feedback that while
its estimates of labor per unit and
bottoms-up approach were
approximately accurate for its singlephase, liquid-immersed units, threephase units require substantially more
labor. DOE relied on manufacturer
interviews and confidential data to
develop estimates for labor hours for
RU4 and RU5 that assumes a base labor
number of hours and a variable that
scales with unit size, similar to what is
done for the dry-type distribution
transformers. These equations are
presented in chapter 5 of the TSD.
Eaton commented that it believes the
fully burdened cost of labor is way too
low and a value of $200/hour or more
seems more appropriate. (Eaton, No. 55
at p. 16)
DOE applies a labor cost per hour that
is generally derived from the U.S.
Bureau of Labor Statistic rates for North
American Industry Classification
System (‘‘NAICS’’) Code 335311—
‘‘Power, Distribution, and Specialty
Transformer Manufacturing’’ production
employee hourly rates and applied
mark-ups for indirect production,
overhead, fringe, assembly labor uptime, and a nonproduction mark-up to
get a fully burdened cost of labor. In the
preliminary analysis, DOE adjusted the
labor rate upward in response to
manufacturer feedback. While some
manufacturers may have different labor
costs, DOE generally considers the BLS
statistics approximately representative.
DOE has adjusted labor costs from the
preliminary analysis based on the ratio
of increased labor costs in NAICS code.
Shipping
In the August 2021 Preliminary
Analysis TSD, DOE noted that it used a
price per pound estimate to estimate the
shipping cost of distribution
transformers. DOE stated that while
shipping costs will vary depending on
several factors, including weight,
volume, footprint, order size,
destination, distance, and other, general
shipping costs (fuel prices, driver
wages, demand, etc.), the price-perpound estimate is an appropriate
approximation of shipping costs and
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reflects that there would be increased
shipping costs associated with larger
distribution transformers. DOE then
applied a non-production markup on
top of its shipping costs. DOE requested
comment on its methodology and the
shipping costs used in the preliminary
analysis. (August 2021 Preliminary
Analysis TSD at p. 2–56)
Howard commented that they have
their own shipping division and trucks
and optimize shipments to be most
efficient. (Howard, No. 59 at p. 3) Eaton
commented that shipping costs vary but
on average, DOE’s shipping cost
estimates are reasonable. (Eaton, No. 55
at p. 16)
DOE did not receive any comment or
data suggesting an alternative approach
to shipping costs, therefore DOE has
retained its price-per-pound mark-up to
account for shipping in the NOPR
analysis.
Manufacturer Markup
To account for the manufacturer’s
nonproduction costs and profit margin,
DOE applies a manufacturer markup to
the MPC. The resulting MSP is the price
at which the manufacturer distributes a
unit into commerce. In the preliminary
analysis, DOE applied a gross margin
percentage of 20 percent for all
distribution transformers.66
Eaton commented that its gross profit
margin was higher and a 20 percent
gross margin is too low for a publicly
traded corporation with obligations to
stakeholders.67 (Eaton, No. 55 at p. 16–
17)
DOE’s average gross margin was
developed by examining the annual
Securities and Exchange Commission
(SEC) 10–K reports filed by publiclytraded manufacturers primarily engaged
in distribution transformer
manufacturing and whose combined
product range includes distribution
transformers.
While some corporations may have
higher gross margins, the gross margin
is unchanged from the April 2013
Standards Final Rule and was presented
to manufacturers in confidential
interviews as part of both the
preliminary analysis and the NOPR
analysis. While some manufacturers
noted higher or lower gross margins,
depending on the product class, there
was generally agreement that the 20
percent gross margin was appropriate
for the industry. As such, DOE has
retained the 20 percent gross margin as
part of the NOPR analysis.
4. Cost-Efficiency Results
The results of the engineering analysis
are reported as cost-efficiency data (or
‘‘curves’’) in the form of energy
efficiency (in percentage) versus MSP
(in dollars), which form the basis for
subsequent analyses in the preliminary
analysis. DOE developed sixteen curves
representing the sixteen representative
units. DOE implemented design options
by analyzing a variety of core steel
material, winding material and core
construction method for each
representative unit and applying
manufacturer selling prices to the
output of the model for each design
option combination. See TSD chapter 5
for additional detail on the engineering
analysis.
Powersmiths commented that the
cost-efficiency plots show it is too cheap
to achieve higher efficiency and if it
were really that cheap, the market
would move there without legislation.
(Powersmiths, No. 46 at p. 5)
Conversely, Metglas commented that the
market does not evaluate based on
efficiency and the only way to see
efficiency improvements is via amended
energy conservation standards. (Metglas,
No. 53 at p. 8)
In general, DOE’s analysis assumes
most distribution transformer customers
purchase based on lowest first cost and
there is limited market above minimum
efficiency standards (see section
IV.F.3.c). Therefore, DOE does not have
data to support manufacturers will build
above minimum efficiency standards,
aside from certain select applications,
even if it were only modestly more
expensive.
The Efficiency Advocates commented
that the percentage of transformers core
steels purchased in the preliminary
analysis shows that too few GOES
transformers are being selected,
indicating a potential issue in the
1769
engineering analysis. (Efficiency
Advocates, No. 52 at p. 7)
DOE has acknowledged that aside
from lowest first cost, manufacturers
may be limited in their steel choice
under the base case. In certain cases, the
incremental cost to higher efficiency
standards may be low but assumes
access to suppliers of better performing
steel. DOE has updated its baseline
analysis to reflect the steel choices that
are currently made in the industry as
described in section IV.F.3.a.
D. Markups Analysis
The markups analysis develops
appropriate markups (e.g., retailer
markups, distributor markups,
contractor markups) in the distribution
chain and sales taxes to convert the
MSP estimates derived in the
engineering analysis to consumer prices,
which are then used in the LCC and PBP
analysis. At each step in the distribution
channel, companies mark up the price
of the product to cover costs. DOE’s
markup analysis assumes that the MSPs
estimated in the engineering analysis
(see section IV.C of this document) are
occurring in a competitive distribution
transformer market as discussed in
section V.B.2.d of this document.
For distribution transformers, the
main parties in the distribution chain
differ depending on the type of
distribution transformer being
purchased and by whom.
Liquid-immersed distribution
transformers are almost exclusively
purchased and installed by electrical
distribution companies, as such the
distribution chained assumed by DOE
reflect the different parties involved.
Dry-type distribution transformers are
used to step down voltages from
primary service into the building to
voltages used by different circuits
within a building, such as, plug loads,
lighting, and specialty equipment; as
such DOE modelled that dry-type
distribution transformers are purchased
by non-residential customers, i.e.,
commercial, and industrial customers.
DOE considered the following
distribution channel shown in Table
IV.5.
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TABLE IV.5—DISTRIBUTION CHANNELS FOR DISTRIBUTION TRANSFORMERS
Market share
(%)
Type
Consumer
Liquid-Immersed
Investor-owned utility .....................
LVDT ..................
Publicly-owned utility ......................
All ...................................................
66 The gross margin percentage of 20 percent is
based on a manufacturer markup of 1.25.
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82
18
100
100
Distribution channel
Manufacturer
Manufacturer
Manufacturer
Manufacturer
→
→
→
→
Consumer.
Distributor → Consumer.
Distributor → Consumer.
Distributor → Electrical contractor→ Consumer.
67 A 20 percent gross margin is equivalent to a
1.25 manufacturer markup.
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TABLE IV.5—DISTRIBUTION CHANNELS FOR DISTRIBUTION TRANSFORMERS—Continued
Market share
(%)
Type
Consumer
MVDT .................
All ...................................................
Howard commented that in in their
experience that liquid-immersed
distribution transformers are sold
directly (more than 80%) to the utilities
through our agents or manufacturing
representatives. (Howard, No. 59 at p. 2)
DOE notes that the distribution
channels used in the preliminary
analysis include a large fraction of sales
as being direct to purchases by utilities
that would encompass the
circumstances described by Howard, as
shown in Table IV.5.68 For this analysis
DOE maintained the distribution
channels distribution channels
described in its preliminary analysis.
Chapter 6 of the NOPR TSD provides
details on DOE’s development of
markups for distribution transformers.
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E. Energy Use Analysis
The energy use analysis produces
energy use estimates and end-use load
shapes for distribution transformers.
The energy use analysis estimates the
range of energy use of distribution
transformers in the field (i.e., as they are
used by consumers) enabling evaluation
of energy savings from the operation of
distribution transformer equipment at
various efficiency levels, while the enduse load characterization allows
evaluation of the impact on monthly
and peak demand for electricity. The
energy use analysis provides the basis
for other analyses DOE performed,
particularly assessments of the energy
savings and the savings in operating
costs that could result from adoption of
amended or new standards.
As presented in section IV.C
transformers losses can be categorized
as ‘‘no-load’’ or ‘‘load.’’ No-load losses
are roughly constant with the load on
the transformer and exist whenever the
distribution transformer is energized
(i.e., connected to electrical power).
Load losses, by contrast, are zero at
when the transformer is unloaded, but
grow quadratically with load on the
transformer.
Because the application of
distribution transformers varies
significantly by type of distribution
transformer (liquid-immersed or drytype) and ownership (electric utilities
own approximately 95 percent of liquid68 See:
Technical Support Document, chapter 2,
page 2–58. https://www.regulations.gov/document/
EERE-2019-BT-STD-0018-0040.
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100
Distribution channel
Manufacturer → Distributor → Electrical contractor→ Consumer.
immersed distribution transformers;
commercial/industrial entities use
mainly dry type), DOE performed two
separate end-use load analyses to
evaluate distribution transformer
efficiency. The analysis for liquidimmersed distribution transformers
assumes that these are owned by
utilities and uses hourly load and price
data to estimate the energy, peak
demand, and cost impacts of improved
efficiency. For dry-type distribution
transformers, the analysis assumes that
these are owned by commercial and
industrial (‘‘C&I’’) entities, so the energy
and cost savings estimates are based on
monthly building-level demand and
energy consumption data and marginal
electricity prices. In both cases, the
energy and cost savings are estimated
for individual distribution transformers
and aggregated to the national level
using weights derived from transformer
shipments data.
1. Hourly Load Model
For utilities, the cost of serving the
next increment of load varies as a
function of the current load on the
system. To appropriately estimate the
cost impacts of improved distribution
transformer efficiency in the Life-cycle
Cost (LCC) analysis, it is therefore
important to capture the correlation
between electric system loads and
operating costs and between individual
distribution transformer loads and
system loads. For this reason, DOE
estimated hourly loads on individual
liquid-immersed distribution
transformers using a statistical model
that simulates two relationships: (1) the
relationship between system load and
system marginal price; and (2) the
relationship between the distribution
transformer load and system load. Both
are estimated at a regional level.
Distribution transformer loading is an
important factor in determining which
types of distribution transformer designs
will deliver a specified efficiency, and
for calculating distribution transformer
losses, and the time dependent values of
those losses. To inform the hourly load
model DOE examined the data made
available through the IEEE Distribution
Transformer Subcommittee Task Force.
a. Hourly Per-Unit Load (PUL)
GEUS commented that because of
load diversity, individual distribution
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transformer capacity (kVA) per home
depends on the number of homes
connected to the transformer. For
example, GEUS will place a 15 kVA
transformer for a single 1200 square foot
home, but 8 of these homes can be
served by a single 50 kVA transformer.
GEUS further commented that to
balance transformer core (no-load)
losses and resistive (load) losses their
design strategy is to serve as many
homes as possible within a 300 feet
radius of the transformer. This design
reduces transformer core (no-load)
losses by reducing the transformer kVA/
home, thereby reducing the ratio of noload to load losses on each transformer.
(GEUS, No. 58 at p. 1) Howard
commented that it is their
understanding that in some rural areas,
there are transformers that are very
lightly loaded, and in other areas, some
units are loaded much more than 50
percent (Howard, No. 59 at p. 3) NEMA
commented that the in-situ PUL varies
widely from region to region and
customer to customer. (NEMA, No. 50 at
p. 12)
The Advocates asserted that DOE’s
estimation of PUL to be too high and
that if DOE decides to maintain these
PUL inputs at their current values, the
Department should provide a sensitivity
analysis that enables commenters to
evaluate the effect of PUL assumptions
on the overall energy savings and
economic analysis. (Efficiency
Advocates, No. 52 at p. 6) Additionally,
they commented that they believe DOE
may be overestimating initial PUL (sic)
in the preliminary analysis; this may
negatively affect higher EL designs that
prioritize core loss reductions and they
urged DOE to update its assumptions
based on recently available data.
(Efficiency Advocates, No. 52 at pp. 2,
5)
Metglas commented that it is not
possible to derive transformer PUL just
from the meter data. To get a
transformer’s PUL, one must associate
which meters are getting supplied from
which transformer. Further Metglas
commented that, the data has come from
only 127 zip codes adjacent to each
other. Metglas asserted that the sample
is too small to draw conclusions at the
National level, and suggested that DOE
base their ruling on data submitted by
Electric Utilities to the IEEE
Transformer Committee which indicates
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that the average PUL on transformers are
in the 0.1–0.2 values. (Metglas, No. 53
at p. 7–8)
NEEA further noted that the per-unit
bases for both the system and individual
transformer loads in the joint histogram
estimates are not related to the
transformer per-unit loads using
nameplate capacities as the basis. They
claim that this means that the loading
estimates obtained from the joint
histograms cannot be directly applied to
the cited transformer loss formula, since
the latter assumes a per-unit loading on
a capacity basis. (NEEA, No. 51 at p. 2–
3)
In this NOPR, DOE applied the same
approach it used in the August 2021
preliminary analysis where the hourly
PUL is a function of both the
transformer’s simulated load and initial
peak load (IPL). Where:
PUL = simulated loadhourly × IPL.
To capture the wide diversity in
distribution transformer loading that is
observed in the field, DOE used a twostep approach. Transformer load data
were used to develop a set of joint
probability distribution functions (JPDF)
which capture the relationship between
individual transformer loads and the
total system load.69 The transformer
loads were calculated as the sum load
of all connected meters on a given
transformer for each available hour of
the year. Because the system load is the
sum of the individual transformer loads,
the value of the system load in a given
hour conditions the probability of the
transformer load taking on a particular
value. To represent the full range of
system load conditions in the U.S., DOE
used FERC Form 714 70 data to compile
separate system load PDFs for each
census division. These system PDFs are
combined with a selected transformer
JPDF to generate a simulated load
appropriate to that system. As the
simulated transformer loads are scaled
to a maximum of one, to calculate the
losses, the load is multiplied by a
scaling factor selected from the
distribution of Initial Peak Loads (IPL),
and by the capacity of the representative
unit being modeled. In the August 2021
preliminary analysis, DOE defined the
IPL as a triangular distribution between
50 and 130 percent of a transformer’s
capacity with a mean of 85 percent. This
produces an hourly distribution of PUL
values from which hourly load losses
are determined. These distributions of
loads capture the variability of
distribution transformers load diversity,
from very low to very high loads, that
are seen in the field.
In response to the comments from the
Advocates and Metglas, DOE revised the
IPL assumptions in this NOPR to more
closely align the resulting PUL with data
made available through the IEEE
Distribution Transformer Subcommittee
Task Force. The revised mean PULs for
liquid-immersed representative unit
used in this NOPR are shown in Table
IV.6.
TABLE IV.6—DISTRIBUTION OF PER-UNIT-LOAD FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS
Mean
simulated
hourly load
Rep. unit
1
2
3
4
5
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
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b. Joint Probability Distribution
Function (JPDF)
NEEA commented that when
processing the load data into JPDF of
loads that observed hourly loads for
both commercial and residential
customers were scaled by corresponding
annual maxima prior to being counted
towards the joint histogram, so that the
observations may be treated as if on a
per-unit basis. This is inconsistent with
the per-unit notion in power systems,
but permissible in this context if so
stated. However, the problem of bias
applied to an entire set of observations
for a given transformer or ‘‘system’’ by
an abnormally large (or small) peak
observation is not acknowledged and
therefore not treated. (NEEA, No. 51 at
p. 2). DOE notes that the transformer
data were screened to remove outliers
before being used to construct JPDFs; a
small number of transformers in the
database may none-the-less have quite
large or quite small peak loads, but the
69 See: Distribution Transformer Load Simulation
Inputs, Technical Support Document, chapter 7.
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associated low probability leads to
minimal impact on the energy loss
calculations. The data will be reviewed
again to ensure that outliers have been
removed.
NEEA found issue with DOE’s
terminology in the TSD, which stated
that DOE applies the joint histogram as
a measure of correlation; and this is not
the typical interpretation of joint
probability. NEEA further recommended
that a covariance-based measure (e.g.,
correlation coefficient) is the
appropriate class of metric in this case
because the subject load processes will
necessarily be related as a consequence
of common influences, each of which is
in turn a stochastic process. (NEEA, No.
51 at pp. 2–3) In response, DOE agrees
with NEEA’s comment that the term
‘‘correlation’’ used in the TSD is not
appropriate. The system load is the sum
of the loads on individual transformers,
so the system load and transformer
loads are not independent random
variables. The relationship between the
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0.75
0.75
0.75
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0.22
0.20
0.24
0.20
0.23
two, represented by the JPDF, is a
conditional probability distribution.
DOE attempts to document its analyses
in plain language, and the term
correlation was used simply to indicate
that the relationship between the
transformer and system loads is not
random. For this NOPR DOE will
continue to use the term correlation to
describe the general relationship
between transformer and system loads,
using footnotes to provide technical
precision as needed.
On the topic of industrial loads for
liquid-immersed distribution
transformers NEEA asserted that as
describe in the TSD appendix 7A, that
in the case of industrial customers,
actual transformer load data were not
available and would be problematic for
the estimation of the subject joint
histograms. (NEEA, No. 18 at p. 2) At
the time of the August 2021 Preliminary
Analysis TSD, DOE was unable to
acquire the transformer loads from
industrial customers. As discussed in
70 https://www.ferc.gov/industries-data/electric/
general-information/electric-industry-forms/formno-714-annual-electric/data.
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TSD appendix 7A, DOE was able to
include the hourly meter loads from
industrial customers, which contain
hourly variability in load factor, as
proxies for transformer loads—which
were included in its database of JPDFs.
DOE requests comment or data
showing hourly transformer loads for
industrial customers.
NEEA additionally requested that
DOE rationalize the choice of bin
resolution in the joint histogram
estimates. (NEEA, No. 51 at p. 2) In the
August 2021 Preliminary Analysis TSD,
DOE applied the same methodology to
the creation and population of JPDFs as
it did in the April 2013 Standards Final
Rule. For the April 2013 Standards
Final Rule, DOE balanced the bin
resolution to 10 bins to ensure that each
bin contained sufficient data to be
sampled during its Monte Carlo
simulation (∼2 percent of samples per
bin), this was also balanced against the
computational limits of preforming this
model within an Excel spreadsheet. For
the August 2021 Preliminary Analysis
TSD, DOE considered increasing the bin
count, but after testing found that this
did not significantly alter the resulting
averages, as such DOE elected to
maintain the approach that stakeholders
were already familiar with. For this
NOPR, DOE will maintain the 10 bins
that were applied in the August 2021
Preliminary Analysis TSD.
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2. Monthly Per-Unit Load (PUL)
Powersmiths commented that, in the
context of low-voltage dry-type
distribution transformers, it has
consistently measured much lower
typical loading levels, across most
vertical markets, in the range of 15–25
percent of nameplate capacity, which is
in line with the publication in 1999
with the Cadmus Group Study and
supported frequently since then in
industry and at previous rulemaking
sessions. (Powersmiths, No. 46 at p. 1)
DOE received no further comments on
the in-field PUL for dry-type
distribution transformers. Since the
comments from Powersmiths align with
DOE’s analysis which shows an average
RMS PUL for dry-type transformers to
be in 16–27 percent of nameplate
capacity DOE did not make any changes
to its dry-type load model for this
NOPR.
3. Future Load Growth
In its August 2021 Preliminary
Analysis TSD, DOE applied an annual
load growth rate of 0.9 percent, based on
U.S. Energy Information Administration
(‘‘EIA’’), Annual Energy Outlook
(‘‘AEO’’) 2021 projected purchased
electricity: delivered electricity trend, to
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liquid-immersed transformers, and zero
percent for low- and medium-voltage
dry-type transformers.71 On the subject
of future load growth DOE received
comments from EEI, CDA, Howard,
Efficiency Advocates, Metglas. and
NEMA.
Both EEI and CDA commented that
they believe that loads on individual
liquid-immersed distribution
transformers will increase over the
equipment’s lifetimes due to several
factors. Both speculated that the
increase in loads will be driven by
evolving ‘‘mega trends’’ in the electric
utility industry, specifically increased
electric vehicle charging, and increased
building electrification. (EEI No. 56 at p.
2; CDA No. 47 at p. 1) The CDA further
commented that EEI has projected
loading increases of 10–50 percent over
the forecast period that will greatly
change operating practices in the
utilities. This suggests the increasing
importance of transformer load losses as
well as balance and minimization of
total losses. (CDA, No. 47 at p. 2)
Howard commented that we are at the
threshold of having many electric
vehicles (EV) that will require a lot of
energy use through the transformer.
How quickly this will happen, remains
to be seen. (Howard, No. 59 at p. 3)
NEMA commented that while they
could not state with certainty what the
appropriate load growth rate would be,
they disagreed with an assumption of
zero percent load growth. (NEMA, No.
50 at p. 13)
The Advocates, and Metglas
challenged DOE application of a 0.9
percent annual load growth for liquidimmersed distribution transformers.
Both asserted that the assumption of
load growth rate applied to liquidimmersed distribution transformers of
0.9 percent per year was not justified as
the National growth in electric demand
will be matched by increased
distribution capacity. They asserted that
the load growth rate assumed by DOE,
the average increase in annual
electricity sales from AEO, is not
entirely driven by increased electrical
load on existing liquid-immersed
distribution transformers, but in fact
driven by grid expansion. (Advocates,
No. 52 at pp. 5–6; Metglas, No. 53 at pp.
1, 5–6)
Additionally, the Advocates
commented that they believe utilities
will plan conservatively by installing
larger transformers capable of handling
rare peak demand events. Citing as
evidence the IEEE load data as
71 TSD chapter 2, p. 2–63, August 2021. https://
www.regulations.gov/document/EERE-2019-BTSTD-0018-0040.
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suggesting utilities are already doing
this as the reported average peak loads
were only 50 percent of nameplate
capacity. Utility decisions for how they
size transformers are unlikely to change
for new and replacement transformer
installations given the uncertainties
around future electricity demand.
(Efficiency Advocates, No. 52 at pp. 5–
6) This notion was supported by NEMA
who commented that as consumer
demand (for electricity) increases due to
the migration to all-electric homes and
buildings, and it stands to reason that
kVA sizes will increase over time as
utilities upgrade capacity to serve these
consumer demands. Likewise,
investments in renewable energy
generation will cause changes to
transformer shipments, unit sizes and
selections. (NEMA, No. 50 at p. 16)
As the August 2021 Preliminary
Analysis TSD indicated, and by the
comments received, there are many
factors that potentially impact future
distribution transformer load growth,
and that these factors may be in
opposition. At this time, many utilities,
states, and municipalities are pursuing
electric vehicle charging programs, it is
unclear the extent to which increases in
electricity demand for electric vehicle
charging, or other state level
decarbonization efforts will impact
current distribution transformer sizing
practices (for example, whether
distribution utilities plan to upgrade
their systems to increase the capacity of
connected distribution transformers—
thus maintaining current loads as a
function of distribution transformer
capacity; or if distribution utilities do
not plan to upgrade their systems and
will allow the loads on existing
distribution transformers to rise). EEI,
CDA, and Howard speculate that these
initiatives will increase the intensive
per-unit-load over time as a function of
per unit of installed capacity. However,
they did not provide any quantitative
evidence that this is indeed happening
on the distribution systems, or regions
which are moving forward with
decarbonization efforts. Further, the
hypothesis that intensive load growth
will be a factor in the future is not
supported by the available future trends
in AEO2022, as indicated by the
purchased electricity trend as it
represents the delivered electricity to
the customer. The Advocates and
Metglas asserted that the load growth
rate 0.9 percent per year was too great,
and that higher loads in response to
decarbonization initiatives would be
met with the extensive growth of the
distribution system, i.e., increasing the
total capacity of the distribution system
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through larger distribution transformers,
or greater shipments, or some
combination of both. Again, neither the
Advocates nor Metglas provided any
data to support their position. For this
NOPR, DOE finds that neither position
provides enough evidence to change its
assumptions from the August 2021
Preliminary Analysis TSD. For this
NOPR, DOE updated its load growth
assumption for liquid-immersed
distribution transformers based on the
change in average growth of AEO2022:
Purchased Electricity: Delivered
Electricity at 0.5 percent.72
To help inform DOE’s prediction of
future load growth trend, DOE seeks
data on the following for regions where
decarbonization efforts are ongoing.
DOE seeks hourly PUL data at the level
of the transformer bank for each of the
past five years to establish an
unambiguous relationship between
transformer loads and decarbonization
policy and inform if any intensive load
growth is indeed occurring.
Additionally, DOE seeks the average
capacity of shipment into regions where
decarbonization efforts are occurring
over the same five-year period to inform
the rate of any extensive load growth
that may be occurring in response to
these programs.
4. Harmonic Content/Non-Linear Loads
Harmonic current refers to electrical
power at alternating current frequencies
greater than the fundamental frequency.
Distribution transformers in service are
commonly subject to (and must tolerate)
harmonic current of a degree that varies
by application.
Powersmiths commented that the
effects of harmonic content on LVDT
can create significant customer risk due
to transformer overheating, particularly
when the transformer is under heavy
loads. This was primarily an issue when
general purpose transformers are
installed outside prescribed harmonic
limits. (Powersmiths No. 18 at p. 3)
Additionally, Powersmiths asserted
that because DOE does not account for
harmonic content in its loading analysis
that it misrepresents the impact of
additional heat on losses. Powersmiths
concluded that light loading means the
harmonic-related heat does not typically
threaten the transformer, but it is not an
excuse to leave this hidden risk unsaid
as the load on any given transformer
could be taken to full capacity based on
72 www.eia.gov/outlooks/aeo/data/browser/#/
?id=2-AEO2022®ion=10&cases=ref2022&start=2020&end=
2050&f=A&linechart=ref2022-d011222a.152-2AEO2022.1-0∼ref2022-d011222a.104-2-AEO2022.10&map=ref2022-d011222a.4-2-AEO2022.1-0
&ctype=linechart&sourcekey=0.
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its nameplate rating, and associated
protection, at any time during its long
life. (Powersmiths No. 18 at p. 3) NEEA
requested that for the next energy
conservation lookback that DOE include
harmonic content in its analysis (NEEA
No. 18 at p. 4)
In response to the commenters
regarding the inclusion of harmonic
content, DOE agrees with NEEA and
that in addition to determining the
necessary input to adequately model the
impacts of harmonic content at the
National level, DOE would also have to
consider how changes in transformer
design would affect the availability of
designs and the impacts on efficiency.
DOE further concurs with Powersmiths
that, on average, distribution
transformers are lightly loaded, as
shown in its analysis (see section IV.E.2)
and that harmonic heat would not
typically be an issue and would likely
have minimal impact on the
transformers covered by this NOPR. For
this NOPR DOE will not consider the
impacts of harmonic content but may
examine them at a future date.
DOE notes that the installation and
commissioning of distribution
transformers, either general purpose or
specialty equipment, falls outside the
Department’s authority and would be
under the purview of local building or
fire codes and ordinances.
Chapter 7 of the NOPR TSD provides
details on DOE’s energy use analysis for
distribution transformers.
F. Life-Cycle Cost and Payback Period
Analysis
DOE conducted LCC and PBP
analyses to evaluate the economic
impacts on individual consumers of
potential energy conservation standards
for distribution transformers. The effect
of new or amended energy conservation
standards on individual consumers
usually involves a reduction in
operating cost and an increase in
purchase cost. DOE used the following
two metrics to measure consumer
impacts:
b The LCC is the total consumer
expense of an appliance or product over
the life of that product, consisting of
total installed cost (manufacturer selling
price, distribution chain markups, sales
tax, and installation costs) plus
operating costs (expenses for energy use,
maintenance, and repair). To compute
the operating costs, DOE discounts
future operating costs to the time of
purchase and sums them over the
lifetime of the product.
b The PBP is the estimated amount
of time (in years) it takes consumers to
recover the increased purchase cost
(including installation) of a more-
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1773
efficient product through lower
operating costs. DOE calculates the PBP
by dividing the change in purchase cost
at higher efficiency levels by the change
in annual operating cost for the year that
amended or new standards are assumed
to take effect.
For any given efficiency level, DOE
measures the change in LCC relative to
the LCC in the no-new-standards case,
which reflects the estimated efficiency
distribution of distribution transformers
in the absence of new or amended
energy conservation standards. In
contrast, the PBP for a given efficiency
level is measured relative to the baseline
product.
For each considered efficiency level
in each product class, DOE calculated
the LCC and PBP for a nationally
representative set of electric distribution
utilities, and commercial and industrial
(‘‘C&I’’) customers. As stated previously,
DOE developed these customers
samples from various sources, including
utility data from the Federal Energy
Regulatory Commission (FERC), Energy
Information Agency (EIA); and C&I data
from the Commercial Building Energy
Consumption Survey (CBECS), and
Manufacturing Energy Consumption
Survey (MECS). For each sample, DOE
determined the energy consumption, in
terms of no-load and load losses for the
distribution transformers and the
appropriate electricity price. By
developing a representative sample of
consumer entities, the analysis captured
the variability in energy consumption
and energy prices associated with the
use of distribution transformer.
Inputs to the calculation of total
installed cost include the cost of the
equipment—which includes MSPs,
retailer and distributor markups, and
sales taxes—and installation costs.
Inputs to the calculation of operating
expenses include annual energy
consumption, electricity prices and
price projections, repair and
maintenance costs, equipment lifetimes,
and discount rates. DOE created
distributions of values for equipment
lifetime, discount rates, and sales taxes,
with probabilities attached to each
value, to account for their uncertainty
and variability.
The computer model DOE uses to
calculate the LCC and PBP relies on a
Monte Carlo simulation to incorporate
uncertainty and variability into the
analysis. The Monte Carlo simulations
randomly sample input values from the
probability distributions and
distribution transformer samples. For
this rulemaking, the Monte Carlo
approach is implemented as a computer
simulation. The model calculated the
LCC and PBP for products at each
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efficiency level for 10,000 individual
distribution transformer installations
per simulation run. The analytical
results include a distribution of 10,000
data points showing the range of LCC
savings for a given efficiency level
relative to the no-new-standards case
efficiency distribution. In performing an
iteration of the Monte Carlo simulation
for a given consumer, product efficiency
is as a function of the consumer choice
model described in section IV.F.3 of this
document. If the chosen equipment’s
efficiency is greater than or equal to the
efficiency of the standard level under
consideration, the LCC and PBP
calculation reveals that a consumer is
not impacted by the standard level. By
accounting for consumers who already
purchase more-efficient products, DOE
avoids overstating the potential benefits
from increasing product efficiency.
DOE calculated the LCC and PBP for
all consumers of distribution
transformers as if each were to purchase
a new equipment in the expected year
of required compliance with new or
amended standards. Amended
standards would apply to distribution
transformers manufactured 3 years after
the date on which any new or amended
standard is published. At this time, DOE
estimates publication of a final rule in
2024. Therefore, for purposes of its
analysis, DOE used 2027 as the first year
of compliance with any amended
standards for distribution transformers.
Table IV.7 summarizes the approach
and data DOE used to derive inputs to
the LCC and PBP calculations. The
subsections that follow provide further
discussion. Details of the model, and of
all the inputs to the LCC and PBP
analyses, are contained in chapter 8 of
the NOPR TSD and its appendices.
TABLE IV.7—SUMMARY OF INPUTS AND METHODS FOR THE LCC AND PBP ANALYSIS *
Inputs
Source/method
Equipment Cost ..............................
Derived by multiplying MPCs by manufacturer and retailer markups and sales tax, as appropriate. Used
historical data to derive a price scaling index to project product costs.
Assumed no change with efficiency level.
The total annual energy use multiplied by the hours per year. Average number of hours based on field
data.
Variability: Based on distribution transformer load data or customer load data.
Hourly Prices: Based on EIA’s Form 861 data for 2015, scaled to 2021 using AEO2022.
Variability: Regional variability is captured through individual price signals for each EMM region.
Monthly Prices: Based on an analysis of EEI average bills, and electricity tariffs from 2019, scaled to 2021
using AEO2022.
Variability: Regional variability is captured through individual price signals for each Census region.
Based on AEO2022 price projections.
Assumed no change with efficiency level.
Average: 32 years, with a maximum of 60 years.
Approach involves identifying all possible debt or asset classes that might be used to purchase the considered equipment or might be affected indirectly. Primary data source was the Federal Reserve Board’s
Survey of Consumer Finances.
2027.
Installation Costs .............................
Annual Energy Use .........................
Electricity Prices ..............................
Energy Price Trends .......................
Repair and Maintenance Costs ......
Product Lifetime ..............................
Discount Rates ................................
Compliance Date ............................
* References for the data sources mentioned in this table are provided in the sections following the table or in chapter 8 of the NOPR TSD.
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1. Equipment Cost
To calculate consumer product costs,
DOE multiplied the MPCs developed in
the engineering analysis by the markups
described previously (along with sales
taxes). DOE used different markups for
baseline products and higher-efficiency
products, because DOE applies an
incremental markup to the increase in
MSP associated with higher-efficiency
products.
To forecast a price trend for this
NOPR, DOE maintained the approach
employed in the August 2021
Preliminary Analysis TSD, where it
derived an inflation-adjusted index of
the Producer Price Index (‘‘PPI’’) for
electric power and specialty transformer
manufacturing from 1967 to 2019.73
These data show a long-term decline
from 1975 to 2003, and then increase
since then. There is considerable
uncertainty as to whether the recent
trend has peaked, and would be
followed by a return to the previous
long-term declining trend, or whether
73 For this NOPR DOE maintained its use of the
two Produce Price Indexes published by the U.S.
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the recent trend represents the
beginning of a long-term rising trend
due to global demand for distribution
transformers and rising commodity
costs for key distribution transformer
components. Given the uncertainty,
DOE chose to use constant prices (2021
levels) for both its LCC and PBP analysis
and the NIA. For the NIA, DOE also
analyzed the sensitivity of results to
alternative distribution transformer
price forecasts.
DOE did not receive any comments
regarding its determination of future
equipment costs and did not make any
changes for this NOPR.
2. Efficiency Levels
For this NOPR, DOE analyzed
different efficiency levels, these are
expressed as a function of loss reduction
over the equipment baseline. For units
greater than 2,500 kVA, there is not a
current baseline efficiency level that
must be met. Therefore, DOE
established EL1 for these units as if they
were aligning with the current energy
Bureau of Labor Statistics for: Electric power and
specialty transformer PPI (PCU335311335311), and
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conservation standards efficiency vs
kVA relationship, scaled to the larger
kVA sizes. To calculate this, DOE scaled
the maximum losses of the minimally
compliant 2,500 kVA unit to the 3,750
kVA size using the equipment class
specific scaling relationships in TSD
appendix 5C. For example, a 2,500 kVA
unit that meets current energy
conservation standards is 99.53 percent
efficient and has 5903 W of loss at 50
percent load. Using the 0.79 scaling
relationship for three-phase liquidimmersed distribution transformers,
described in appendix 5C, the losses of
a 3,750 kVA unit would be 8131 W,
corresponding to 99.57 percent efficient
at 50 percent load.
EL2 through EL5 align with the same
percentage reduction in loss as their
respective EC but rather than being
relative to a baseline level, efficiency
levels were established relative to EL1
levels.
Power and distribution transformers PPI
(PCU3353113353111).
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The rate of reduction is shown in
Table IV.8, and the corresponding
efficiency ratings in Table IV.9.
TABLE IV.8—EFFICIENCY LEVELS AS PERCENTAGE REDUCTION OF BASELINE LOSSES
EL
Equipment type
1
2
Liquid-immersed:
≤2,500 kVA ...................................................................
>2,500 kVA ...................................................................
Low-voltage Dry-type:
1j ..................................................................................
3j ..................................................................................
Medium-voltage Dry-type:
<46 kV BIL ....................................................................
≥46 and <96 kV BIL, and ≤2,500 kVA .........................
≥46 and <96 kV BIL, and >2,500 kVA .........................
≥96 kV BIL and ≤2,500 kVA .........................................
≥96 kV BIL and >2,500 kVA .........................................
3
5
(max-tech)
4
2.5
* 40
5
** 5
10
** 10
20
** 20
40
** 40
10
5
20
10
30
20
40
30
50
40
5
5
* 43
5
* 34
10
10
** 10
10
** 10
20
20
** 20
20
** 20
30
30
** 30
30
** 30
40
40
** 40
35
** 35
* Equipment currently not subject to standards. Therefore, reduction in losses relative to least efficient product on market.
** Reduction in losses relative to EL1.
TABLE IV.9—EFFICIENCY LEVELS
Efficiency level
Rep. unit
kVA
0
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1 ...................................
2 ...................................
3 ...................................
4 ...................................
5 ...................................
6 ...................................
7 ...................................
8 ...................................
9 ...................................
10 .................................
11 .................................
12 .................................
13 .................................
14 .................................
15 .................................
16 .................................
17 .................................
18 .................................
19 .................................
50
25
500
150
1,500
25
75
300
300
1,500
300
1,500
300
2,000
112.5
1,000
3,750
3,750
3,750
99.11
98.95
99.49
99.16
99.48
98.00
98.60
99.02
98.93
99.37
98.81
99.30
98.69
99.28
99.11
99.43
n.a.
n.a.
n.a.
DOE did not receive any comment
regarding the loss rates, nor the
efficiency levels applied in the
preliminary analysis, and continued
their use for this NOPR.
DOE requests comments on its
methodology for establishing the energy
efficiency levels for distribution
transformers greater than 2,500 kVA.
DOE request comment on its assumed
energy efficiency ratings.
3. Modeling Distribution Transformer
Purchase Decision
In the August 2021 Preliminary
Analysis TSD, DOE presented its
assumption on how distribution
transformers were purchased. DOE used
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1
2
99.13
98.98
99.50
99.18
99.49
98.20
98.67
99.07
98.98
99.40
98.87
99.33
98.75
99.32
99.13
99.44
99.57
99.48
99.41
3
99.15
99.00
99.52
99.20
99.51
98.39
98.74
99.12
99.04
99.43
98.93
99.37
98.82
99.35
99.15
99.46
99.59
99.53
99.47
an approach that focuses on the
selection criteria customers are known
to use when purchasing distribution
transformers. Those criteria include first
costs, as well as the Total-Owning Cost
(‘‘TOC’’) method. The TOC method
combines first costs with the cost of
losses. Purchasers of distribution
transformers, especially in the utility
sector, have historically used the TOC
method to determine which distribution
transformers to purchase. However,
comments received from stakeholders
responding to the 2012 ECS NOPR (77
FR 7323) and the June 2019 RFI (84 FR
28254) indicate that the widespread
practice of concluding the final
purchase of a distribution transformer
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99.20
99.05
99.54
99.24
99.53
98.60
98.88
99.22
99.14
99.50
99.05
99.44
98.95
99.42
99.20
99.49
99.61
99.58
99.53
5
99.29
99.16
99.59
99.33
99.58
98.79
99.02
99.31
99.25
99.56
99.16
99.51
99.08
99.49
99.29
99.54
99.66
99.64
99.59
99.46
99.37
99.69
99.49
99.69
98.99
99.16
99.41
99.36
99.62
99.28
99.58
99.14
99.53
99.46
99.66
99.74
99.69
99.62
based on TOC is rare, instead customers
have been purchasing the lowest first
cost transformer design regardless of its
loss performance.
The utility industry developed TOC
evaluation as a tool to reflect the unique
financial environment faced by each
distribution transformer purchaser. To
express variation in such factors as the
cost of electric energy, and capacity and
financing costs, the utility industry
developed a range of evaluation factors:
A and B values, to use in their
calculations.74 A and B are the
74 In modeling the purchase decision for
distribution transformers DOE developed a
probabilistic model of A and B values based on
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
equivalent first costs of the no-load and
load losses (in $/watt), respectively.
In response to the August 2021
Preliminary Analysis TSD, DOE
received the following comments
regarding the modeling of distribution
transformer purchases.
a. Basecase Equipment Selection
Regarding how engineering designs
were selected by the consumer choice
model in the LCC, DOE received
comments from Metglas and the
Efficiency Advocates. Metglas
commented that it did not agree with
the DOE purchase decision model.
Stating that the fraction of designs using
amorphous steel as a core material were
grossly overstated in the standards, and
no-new standards cases. Metglas further
stated that currently the fraction of
amorphous core distribution
transformers is on the order of 2–3
percent of the market and that this
fraction has been constant for the past
7 years. (Metglas, No. 53 at pp. 1–2)
Additionally, the Efficiency Advocates
recommended that DOE take ‘‘a hard
look at’’ the purchasing behaviors of
distribution transformers in the current
marketplace. (Efficiency Advocates, No.
40 at p. 83)
In response to these comments DOE
examined its responses received during
manufacturer interviews. From these
responses, DOE understands that in the
current market that amorphous core
distribution transformers (both liquidimmersed and dry-type) are shipped in
limited quantities, supporting Metglas’
claim. The reason for this is believed to
be limitations in amorphous core
fabricating capacity among
manufacturers. DOE’s research indicates
that distribution transformers can be
fabricated with amorphous core steels
that are cost competitive with
conventional steels as shown in the
engineering analysis (see section IV.C),
but they cannot currently be fabricated
in the quantities needed to meet the
large order requirement of electric
utilities, and as such, are limited to
niche products. Accordingly, DOE has
updated its customer choice model and,
in the no-new standards case has
limited type of core steel materials to
the ratios shown in Table IV.10.
TABLE IV.10—CORE MATERIAL LIMITS IN THE NO-NEW STANDARDS CASE
Baseline Steel for Liquid-Immersed:
• 87% M3 or 23hib090.
• 3% Amorphous (mostly in TOC applications above standards).
• 10% 23PDR085.
Based on interviews with
manufactures, and supporting research,
DOE finds that there are no global
supply constraints of amorphous ribbon
for fabrication into transformer cores.
And in the potential new-standards
case, DOE does not limit the selection
of the designs in the engineering
database by core material type. Further,
DOE understands that there are current
production limitations for turning
amorphous ribbons into transformer
cores that would require the capital
investment in ribbon cutting, and core
stacking machines at higher intensities
to meet the quantity requirements
placed on manufacturers by electric
utilities. The impacts of the additional
capital investment on manufacturers in
the potential new-standards case are
captured in manufacturer impact
analysis described in section IV.J of this
document.
lotter on DSK11XQN23PROD with PROPOSALS3
b. Total Owning Cost (‘‘TOC’’) and
Evaluators
In the August 2021 Preliminary
Analysis TSD, DOE used TOC
evaluation rates as follows: 10 percent
of liquid-immersed transformer
purchases were concluded using TOC,
and 0 percent of low-voltage dry-type
and medium-voltage dry-type
transformer purchases were concluded
using TOC. DOE received comment
utility requests for quotations when purchasing
distribution transformers. In the context of the LCC
the A and B model estimates the likely values that
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Baseline Steel for Dry-Type:
• 97% M4 or hib-M4 (M3 as modeled).
• 3% PDR.
• 0% AM.
from several stakeholders regarding the
rates at which TOC are practiced.
NEMA commented that the
experience among their members varies,
but in NEMA’s experience the
percentage of TOC use in purchasing
decisions for three-phase designs is
higher than 10 percent: varying between
15–20 percent, and for single-phase
designs, they believe the use of TOC in
purchasing decisions is closer to 40
percent. (NEMA, No. 50 at p. 13)
Additionally, NEMA responded to
DOE’s request for information relating
customer application of TOC as a
function of distribution transformer
capacity. NEMA responded that NEMA
did not have detailed information on
breakouts of TOC purchasing influence
by kVA and that their members are
investigating whether their customer
information can be analyzed for useful
insight on this subject (NEMA, No. 50
at pp. 13–14) Metglas commented that
few transformer purchasers are using
TOC evaluations, and 10 percent may be
a reasonable estimate for those still
using TOC. And in their experience the
few remaining TOC evaluators reveal
that they will abandon TOC as soon as
their existing tenders are delivered.;
leading to speculation that this practice
could be nearly extinct within the next
2–3 years. (Metglas, No. 53 at p. 6)
DOE estimated the rate of consumers
using TOC as a tool to inform the
purchase of a distribution transformer to
be 10 percent for liquid-immersed
distribution transformers. These rates
were established in response to
stakeholder comments in the February
2012 NOPR (77 FR 7323) to which DOE
received no adverse comments. Further,
these rates were again put forward for
comment in the June 2019 RFI (84 FR
28254) to which DOE did not receive
any adverse comments.75 In light of this
long history of established low rates of
TOC adoption for the purchase of
distribution transformers DOE finds the
comments received from NEMA to be
inconsistent with historical comments
from a wide range of stakeholders. Ibid.
For this NOPR, DOE is maintaining the
same rates of TOC evaluators
established in the August 2021 ECS
Preliminary Analysis TSD, however,
DOE recognizes that circumstances
change over time and has included in
this NOPR a LCC sensitivity case with
evaluation rates suggested by NEMA.
The result of this sensitivity analysis
can be found in appendix 8G of the
TSD.
Powersmiths commented that it is not
true that 100 percent of LVDT
distribution transformers are purchased
on minimum first cost, adding that their
market is selling only distribution
a utility might use when making a purchase
decision.
75 Please see the summary of comments regarding
the rate of evaluators in the August 2021 ECS
Preliminary Analysis, Technical Support
Document, p 2–69; https://www.regulations.gov/
document/EERE-2019-BT-STD-0018-0023.
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transformers that significantly exceed
minimum efficiency standards and the
NEMA Premium transformer market
existed prior to the 2016 energy
conservation standards. (Powersmiths,
No. 46 at pp. 3–4) Powersmiths
commented that minimum efficiency is
rarely the optimal choice for consumers
and there is value in both new
construction and retrofits that exceed
energy conservation standards.
(Powersmiths, No. 46 at p. 4)
Powersmiths added that trends toward
green buildings have increased the
number of consumers looking at value
beyond first cost which may increase
the value-added LVDT market.
(Powersmiths, No. 46 at p. 4)
DOE recognizes that distribution
transformers are purchased at different
efficiency levels depending on the
specific demands of consumers. For this
analysis DOE did not receive a specific
fraction of LVDT distribution
transformers that were sold above the
current standard, in the absence of such
information DOE relied on the
consumer choice model to determine
the equipment price in addition to the
fraction of equipment sold with higher
performance cores constructed from
PDR steel, as discussed in section
IV.F.3.a of this document.
lotter on DSK11XQN23PROD with PROPOSALS3
Band of Equivalents (‘‘BOE’’)
In the August 2021 Preliminary
Analysis TSD, DOE proposed the
following definition for Band of
Equivalents (‘‘BOE’’): as a method to
establish equivalency between a set of
transformer designs within a range of
similar TOC. BOE is defined as those
transformer designs within a range of
similar TOCs; the range of TOC varies
from utility to utility and is expressed
in percentage terms. In practice, the
purchaser would consider the TOC of
the transformer designs within the BOE
and would select the lowest first-cost
design from this set.
NEMA agreed with the Department’s
assumptions with respect to their
reflection of industry experiences and
practices. NEMA further stated that its
members are investigating whether their
customer information can be analyzed
for useful insight on this subject.
(NEMA, No. 50 at p. 13) Metglas
comment that BOE within a TOC
calculation is often used because the
assumptions within the TOC
calculations are estimates. BOE can be
up to 10 percent of TOC, meaning the
TOC evaluations within this band are
treated as equal, and when used in lieu
of TOC, the fraction of consumers who
evaluate using TOC drops to less than
5 percent. (Metglas, No. 53 at p. 7)
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Based on the comments received DOE
will maintain the definition previously
stated. However, for this NOPR, DOE
did not receive enough information or
data to apply BOE to a fraction of
transformer purchasers.
Evaluation Rates and High Electricity
Costs
In the August 2021 ECS Preliminary
Analysis TSD, DOE requested comment
on whether those consumers that
purchase distribution transformers
based on TOC are likely to pay higher
electricity costs. Howard commented
that certain utilities with high electricity
costs use the TOC (Total Owning Cost)
approach to minimize their overall
owning costs. And the manufacturer
will work with the user to determine the
best overall value to buy, and that this
is good approach in those areas.
(Howard, No. 59 at p. 3) NEMA
commented that it stands to reason that
consumers with higher electricity costs
are more likely to consider TOC in
purchasing decisions. (NEMA, No. 50 at
p. 13–14)
The comments DOE received on this
subject were supportive of the notion
that consumers who have higher
electricity costs would reasonably have
higher adoption of using TOC as a
purchasing tool. However, the
comments did not provide any
information, or data to support
including this relationship in this
NOPR. To relate higher electricity costs
with increased TOC use, DOE would
require from stakeholders the fraction of
transformers specified and shipped to
regions of higher electricity costs using
TOC or BOE.
DOE requests comment on its
assumed TOC adoption rate of 10
percent. Specifically, DOE requests
comment on the TOC rate suggested by
NEMA, that between 15 and 20 percent
of 3-phase liquid-immersed distribution
transformers are purchased using TOC,
and that 40 percent of 1-phase liquidimmersed distribution transformers are
purchased using TOC. DOE notes, that
it is seeking data related to concluded
sales based on lowest TOC in the
strictest sense, excluding those
transformers sold using band of
equivalents (see the section on band of
equivalents, above)
DOE requests comment on the
fraction of distribution transformers
purchased by customers using the BOE
methodology. DOE notes, that it is
seeking data related to concluded sales
based on lowest BOE in the strictest
sense, excluding those transformers sold
using total owning costs.
DOE request comment if the rates of
TOC or BOE vary by transformer
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1777
capacity or number of phases. Further,
DOE seeks the fraction of distribution
transformer sales using either method
into the different regions in order to
capture the believed relationship
between higher electricity costs and
purchase evaluation behavior.
c. Non-evaluators and First Cost
Purchases
DOE defined those consumers who do
not purchase based on TOC as those
who purchase based on lowest first
costs. NEMA commented that they
disagreed with DOE’s assumption that
purchasers who do not purchase based
on TOC purchase strictly on a first cost
basis. Stating, in relation to dry-type
distribution transformers, that
customers also care about production
times, availability, perceived quality,
design options and other factors relating
to timing and performance. Further, in
relation to liquid-immersed
transformers, improved tank steel
(stainless) or biodegradable immersion
oil are potential upgrades outside
electrical performance which NEMA
members have had requested by
customers. (NEMA, No. 50 at pp. 13–14)
DOE acknowledges that customers of
distribution transformers will specify
design aspects, or other criteria that will
impact the cost of a transformer when
making a purchasing decision that is not
related to distribution transformer
efficiency. As mentioned by NEMA in
their comment, customers may have
additional criteria when purchasing a
distribution transformer that would be
considered either an equipment upgrade
outside of the equipment’s electrical
performance, or operational
considerations that would affect the first
costs. The analysis conducted by the
Department in support of its energy
saving mission are limited to design
aspects that affect the quantification of
increased energy efficiency of the
equipment in question, in this case,
distribution transformers. These design
aspects are defined in the current test
procedure and quantified in the
engineering analysis. Since the aspects
listed by NEMA are outside of the
electrical, and efficiency performance of
distribution transformers, therefore they
are not considered in this analysis.
4. Installation Costs
Installation cost includes labor,
overhead, and any miscellaneous
materials and parts needed to install the
product. DOE used data from RSMeans
to estimate the baseline installation cost
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
for distribution transformers.76 In the
August 2021 Preliminary Analysis TSD,
DOE asserted that there would be no
difference in installation costs between
baseline and more efficient equipment.
DOE also asserted that 5 percent of
replacement installations would face
increased costs over baseline equipment
due to the need for site modifications.
DOE received comments from GEUS,
Carte, and NEMA of the subject of
installing distribution transformers.
GEUS expressed concern that higher
standards may increase transformer
weights such that 50 kVA transformers
can no longer be handled with standard
bucket trucks and would require a larger
truck to preform installations. (GEUS,
No. 58 at p. 1)
The load bearing capacity of vehicles
classified as a bucket truck typically
accommodate a wide range of lifting
capacity depending on each individual
truck. The analysis conducted for this
NOPR shows a maximum of weight for
a 50 kVA pole mounted liquidimmersed distribution of 1440 lbs. at the
maximum technology case. Without
knowing the specifics regarding the
equipment used by GEUS, DOE cannot
definitively say whether their existing
bucket trucks will be sufficient.
Transformers are typically installed
using a bucket truck, or crane truck.
DOE requests comment on the typical
maximum lifting capacity, and the
typical transformer capacity being
installed.
Additionally, Carte and NEMA
expressed concern over the increasing of
distribution transformer size in order to
meet a potential revised standard. Carte
commented that utilities are concerned
with the increase in size and weight
associated with efficiency standards,
with potential issues for pole
replacement, concrete load limits, and
vaults. (Carte, No. 54 at p. 2–3) NEMA
commented that when designing a new
transformer to fit an existing pad
footprint, the only way to add more
active material to raise efficiency is to
increase the height of the unit. This may
not be feasible in situations where
cables run underground. There may not
be sufficient length remaining in those
cables to reach a higher set of bushings
to connect the unit to the network.
(NEMA, No. 50 at p. 14)
As in the August 2021 Preliminary
Analysis TSD, DOE acknowledges that
there may be issues when installing a
replacement distribution transformer on
an existing pad, or underground
enclosure. However, as discussed in
76 Gordian, RSMeans Online, https://
www.rsmeans.com/products/online (Last accessed:
March 2022).
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appendix 7D of the August 2021
Preliminary Analysis TSD, many of
these issues can be avoided through
proper equipment specification at the
time of purchase. The issues that both
Carte and NEMA reference, apart from
vault replacement/renovation, can be
addressed during purchasing with
proper specifications. Given that no new
information has been put forward in
response to the August 2021
Preliminary Analysis TSD, DOE will
maintain its assumptions and approach
where increased installation costs over
the no-new standards case are
considered atypical and applied at a rate
of 5 percent of installations occurrences.
For this NOPR, DOE reiterates its
request for the following information.
DOE requests data and feedback on the
size limitations of pad-mounted
distribution transformers. Specifically,
what sizes, voltages, or other features
are currently unable to fit on current
pads, and the dimension of these pads.
DOE seeks data on the typical concrete
pad dimensions for 50 and 500 kVA
single-; and 500, and 1500 kVA threephase distribution transformers. DOE
seeks data on the typical service
lifetimes of supporting concrete pads.
5. Annual Energy Consumption
For each sampled customer, DOE
determined the energy consumption for
a distribution transformer at different
efficiency levels using the approach
described previously in section IV.E of
this document.
6. Electricity Prices
DOE derived average and marginal
electricity prices for distribution
transformers using two different
methodologies to reflect the differences
in how the electricity is paid for by
consumers of distribution transformers.
For liquid-immersed distribution
transformers, which are largely owned
and operated by electric distribution
companies, who purchase electricity
from a variety of markets, DOE
developed an hourly electricity costs
model. For low- and medium-voltage
dry-type, which are primarily owned
and operated by C&I entities, DOE
developed a monthly electricity cost
model.
a. Hourly Electricity Costs
To evaluate the electricity costs
associated with liquid-immersed
distribution transformers, DOE used
marginal electricity prices. Marginal
prices are those utilities pay for the last
kilowatt-hour of electricity produced
that may be higher or lower than the
average price, depending on the
relationships among capacity,
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generation, transmission, and
distribution costs. The general structure
of the hourly marginal cost methodology
divides the costs of electricity into
capacity components and energy cost
components. For each component, the
economic value for both no-load losses
and load losses is estimated. The
capacity components include generation
and transmission capacity; they also
include a reserve margin for ensuring
system reliability, with factors that
account for system losses. Energy cost
components include a marginal cost of
supply that varies by the hour.
The marginal costs methodology was
developed for each regional Balancing
Authority listed in EIA’s Form EIA–861
database (based on ‘‘Annual Electric
Power Industry Report’’).77 To calculate
the hourly price of electricity, DOE used
the day-ahead market clearing price for
regions having wholesale electricity
markets, and system lambda values for
all other regions. System lambda values,
which are roughly equal to the operating
cost of the next unit in line for dispatch,
are filed by control area operators under
FERC Form 714.78
EEI commented that the utilization of
2015 data and ‘‘scaling it’’ to the year of
analysis was misguided given the clean
energy progress the electric sector has
made in the intervening years. The mix
of resources used to generate electricity
in the United States has changed
dramatically over the last decade and is
increasingly cleaner. EEI commented
that, starting in 2016, natural gas
surpassed coal as the main source of
electricity generation in the United
States, and in 2020 natural gas-based
generation powered 40 percent of the
country’s electricity, compared to coalbased generation at 19 percent.
In response to EEI, DOE notes that it
scaled the cost of electricity from 2015
to the present using AEO2022 electricity
price trend, and that this trend accounts
for changes in the electricity supply mix
over this period.79 Additionally, DOE
captures the advances in reducing GHG
and other pollutants from the Nation’s
electricity generators in its Emissions
77 Available at https://www.eia.doe.gov/cneaf/
electricity/page/eia861.html.
78 https://www.ferc.gov/industries-data/electric/
general-information/electric-industry-forms/formno-714-annual-electric/overview.
79 U.S. Energy Information Administration,
Annual Energy Outlook 2022, Table 3. Energy
Prices by Sector and Source Case: AEO2022
Reference case | Region: United States, 2022
(Available at: https://www.eia.gov/outlooks/aeo/
data/browser/#/?id=3-AEO2022®ion=1-0&
cases=ref2022&start=2020&end=2050&f=A
&linechart=ref2022-d011222a.3-3-AEO2022.10∼ref2022-d011222a.55-3-AEO2022.1-0&
map=ref2022-d011222a.4-3-AEO2022.1-0
&ctype=linechart&sourcekey=0, Last access: June 1,
2022).
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Analysis, described in section IV.K.
This analysis captures both shift in
generation, and the reduction in coalbased generation, and resulting
emissions referenced by EEI, from 2027
through the end of this this NOPR’s
analysis period.
DOE received no further comment
regarding it electricity costs analysis
and maintained the approach used in
the August 2021 Preliminary Analysis
TSD for this NOPR.
7. Maintenance and Repair Costs
Repair costs are associated with
repairing or replacing product
components that have failed in an
appliance; maintenance costs are
associated with maintaining the
operation of the product. Typically,
small incremental increases in product
efficiency produce no, or only minor,
changes in repair and maintenance costs
compared to baseline efficiency
products. In the August 2021
Preliminary Analysis TSD, DOE asserted
that maintenance and repair costs do
not increase with transformer efficiency.
NEMA responded that they agree with
these assumptions. (NEMA, No. 50 at p.
16)
Based on this response DOE
continued its assumptions that
maintenance and repair costs do not
increase with transformer efficiency for
this NOPR analysis.
8. Equipment Lifetime
For distribution transformers, DOE
used a distribution of lifetimes, with an
estimated average of 32 years and
maximum 60 years.
NEMA commented that they have no
alternative lifetimes to suggest, and the
equipment lifetimes are suitably
representative. (NEMA, No. 50 at p. 16)
However, NEMA postulated that,
logically, increased (equipment) prices
will create pressure on some customers
to rebuild existing property. NEMA did
not provide the additional service life
that would be extended to rebuilt
equipment in this event, or to what
extent the average service lifetime of a
distribution transformer would increase.
As the average lifetime presented in the
August 2021 Preliminary Analysis TSD,
at 32 years, is quite long, for this NOPR,
DOE maintained the lifetime estimates
presented in the August 2021
Preliminary Analysis TSD.
DOE request the average extension of
distribution transformer service life that
can be achieved through rebuilding.
Additionally, DOE requests comment on
the fraction of transformer that are
repaired by their original purchasing
entity and returned to service, thereby
extending the transformer’s service
lifetime beyond the estimated lifetimes
of 32 years with a maximum of 60 years.
9. Discount Rates
The discount rate is the rate at which
future expenditures are discounted to
estimate their present value. DOE
employs a two-step approach in
calculating discount rates for analyzing
customer economic impacts (e.g., LCC).
The first step is to assume that the
actual cost of capital approximates the
appropriate customer discount rate. The
second step is to use the capital asset
pricing model (CAPM) to calculate the
equity capital component of the
customer discount rate. For this NOPR,
DOE estimated a statistical distribution
of commercial customer discount rates
that varied by distribution transformer
type, by calculating the cost of capital
1779
for the different types of distribution
transformer owners.
DOE’s method views the purchase of
a higher efficiency appliance as an
investment that yields a stream of
energy cost savings. DOE derived the
discount rates for the LCC analysis by
estimating the cost of capital for
companies or public entities that
purchase distribution transformers. For
private firms, the weighted average cost
of capital (WACC) is commonly used to
estimate the present value of cash flows
to be derived from a typical company
project or investment. Most companies
use both debt and equity capital to fund
investments, so their cost of capital is
the weighted average of the cost to the
firm of equity and debt financing, as
estimated from financial data for
publicly traded firms in the sectors that
purchase distribution transformers.80 As
discount rates can differ across
industries, DOE estimates separate
discount rate distributions for a number
of aggregate sectors with which
elements of the LCC building sample
can be associated.
EEI commented that DOE should
utilize up to date information to apply
an appropriate discount rate for electric
companies. (EEI, No. 56 at p. 4) DOE
understands that this comment is in
reference to DOE applying the Federal
Government discount rate to local
Municipal Utilities (MUNIs) consumers
in the LCC analysis in the August 2021
Preliminary Analysis TSD. This was in
error and has been corrected in this
NOPR; consumer impacts for MUNIs are
now calculated using the distribution of
state/local government discount rates
shown in Table IV.11. The mean WACC
for this distribution is 2.67 percent.81
TABLE IV.11—APPLIED DISCOUNT RATES FOR PUBLICLY OWNED UTILITIES
Rates
(%)
Rate bin
¥1.9
0.9
1.6
2.5
3.5
4.2
lotter on DSK11XQN23PROD with PROPOSALS3
<0% ..............................................................................................................................................
0–1% ............................................................................................................................................
1–2% ............................................................................................................................................
2–3% ............................................................................................................................................
3–4% ............................................................................................................................................
4–5% ............................................................................................................................................
DOE received no further comments on
its discount rate analysis and
maintained its approach for this NOPR.
See chapter 8 of the NOPR TSD for
further details on the development of
consumer discount rates.
80 Previously, Damodaran Online provided firmlevel data, but now only industry-level data is
available, as compiled from individual firm data,
for the period of 1998–2018. The data sets note the
number of firms included in the industry average
for each year.
81 Sources: For values through Q2 2016, Federal
Reserve Bank of Saint Louis, ‘‘State and Local
Bonds—Bond Buyer Go 20-Bond Municipal Bond
Index—Discontinued Series,’’ https://
fred.stlouisfed.org/series/WSLB20 (Last accessed
February 2022). For Q3 2016 through 2021, Bartel
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Weight
(%)
Observations
(quarters)
3.0
2.3
23.3
25.6
35.3
10.5
4
3
31
34
47
14
10. Energy Efficiency Distribution in the
No-New-Standards Case
To accurately estimate the share of
consumers that would be affected by a
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Associates LLC, ‘‘20 Year AA Municipal Bond
Quarterly Rates,’’ updated January 5, 2022, https://
bartel-associates.com/resources/select-gasb-67-68discount-rate-indices (Last accessed February 2022).
E:\FR\FM\11JAP3.SGM
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
potential energy conservation standard
at a particular efficiency level, DOE’s
LCC analysis considered the projected
distribution (market shares) of product
efficiencies under the no-new-standards
case (i.e., the case without amended or
new energy conservation standards). To
determine an appropriate basecase
against which to compare various
potential standard levels, DOE used the
purchase-decision model described in
section IV.F.3, where distribution
transformers are purchased based on
either lowest first cost, or, on lowest
TOC. In the no-new-standards case
distribution transformers are chosen
from among the entire range of available
distribution transformer designs for
each representative unit simulated in
the engineering analysis based on this
purchase-decision model. This selection
is constrained only by purchase-price in
the majority of cases (90 percent, and
100 percent for liquid-immerses, and all
dry-type transformers, respectively), and
reflect the MSPs of the available designs
determined in the engineering analysis
in section IV.C.1 of this document. The
resulting distribution of transformer
efficiency in the No-New-Standards
Case is shown in Table IV.12.
Comments received regarding the
energy efficiency distribution in the nonew-standards case are addressed in the
discussion regarding the modeling of
distribution transformer purchase
decisions, in section IV.F.2 of this
document.
See chapter 8 of the NOPR TSD for
further information on the derivation of
the efficiency distributions.
TABLE IV.12—APPLIED DISTRIBUTION OF EQUIPMENT EFFICIENCIES IN THE NO-NEW STANDARDS CASE, FRACTION OF
UNITS AT EACH EL (%)
Efficiency level
EC
Rep unit
0
1 ...................................
1 ...................................
1 ...................................
2 ...................................
2 ...................................
2 ...................................
12 .................................
12 .................................
3 ...................................
4 ...................................
4 ...................................
6 ...................................
6 ...................................
8 ...................................
8 ...................................
8 ...................................
10 .................................
10 .................................
10 .................................
1
2
3
4
5
17
15
16
6
7
8
9
10
11
12
18
13
14
19
1
90.6
99.1
96.5
65.0
93.5
97.7
64.8
93.9
31.4
83.4
49.0
28.0
87.5
76.2
90.6
100.0
90.4
100.0
100.0
2
6.1
0.3
1.0
30.7
4.2
0.2
31.4
3.9
46.4
15.1
45.1
50.0
12.5
23.8
9.4
0.0
9.7
0.0
0.0
3
0.3
0.4
2.2
1.2
1.7
0.3
0.8
1.6
21.3
1.5
6.0
22.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4
0.9
0.1
0.1
0.1
0.6
0.8
0.0
0.4
0.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5
1.6
0.0
0.2
2.1
0.0
0.8
2.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.4
0.0
0.1
0.9
0.0
0.2
0.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Note: may not sum to 100 due to rounding.
lotter on DSK11XQN23PROD with PROPOSALS3
11. Payback Period Analysis
The payback period is the amount of
time it takes the consumer to recover the
additional installed cost of moreefficient products, compared to baseline
products, through energy cost savings.
Payback periods are expressed in years.
Payback periods that exceed the life of
the product mean that the increased
total installed cost is not recovered in
reduced operating expenses.
The inputs to the PBP calculation for
each efficiency level are the change in
total installed cost of the product and
the change in the first-year annual
operating expenditures relative to the
baseline. The PBP calculation uses the
same inputs as the LCC analysis, except
that discount rates are not needed.
As noted previously, EPCA
establishes a rebuttable presumption
that a standard is economically justified
if the Secretary finds that the additional
cost to the consumer of purchasing a
product complying with an energy
conservation standard level will be less
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than three times the value of the first
year’s energy savings resulting from the
standard, as calculated under the
applicable test procedure. (42 U.S.C.
6295(o)(2)(B)(iii)) For each considered
efficiency level, DOE determined the
value of the first year’s energy savings
by calculating the energy savings in
accordance with the applicable DOE test
procedure, and multiplying those
savings by the average energy price
projection for the year in which
compliance with the amended standards
would be required. The results of this
analysis provide an important element
of DOE’s evaluation of the economic
justification for a potential standard
level (thereby supporting or rebutting
the results of any preliminary
determination of economic
justification). The rebuttable
presumption payback calculation is
discussed in section V.B.1.c of this
document.
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G. Shipments Analysis
DOE uses projections of annual
product shipments to calculate the
national impacts of potential amended
or new energy conservation standards
on energy use, NPV, and future
manufacturer cash flows.82 The
shipments model takes an accounting
approach, tracking market shares of
each product class and the vintage of
units in the stock. Stock accounting uses
product shipments as inputs to estimate
the age distribution of in-service
product stocks for all years. The age
distribution of in-service product stocks
is a key input to calculations of both the
NES and NPV, because operating costs
for any year depend on the age
distribution of the stock.
DOE projected distribution
transformer shipments for the no-new
standards case by assuming that long82 DOE uses data on manufacturer shipments as
a proxy for national sales, as aggregate data on sales
are lacking. In general one would expect a close
correspondence between shipments and sales.
E:\FR\FM\11JAP3.SGM
11JAP3
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
term growth in distribution transformer
shipments will be driven by long-term
growth in electricity consumption. DOE
developed its initial shipments inputs
based on data from the previous final
rule, and data submitted to DOE from
interested parties; these initial
shipments are shown for the assumed
compliance year, by distribution
transformer type, in Table IV.13 through
Table IV.15. For this NOPR, DOE
received additional data from
manufacturers via confidential
interviews, resulting in revised
shipments estimates for liquidimmersed distribution transformers.
DOE developed the shipments
projection for liquid-immersed
distribution transformers by assuming
that annual shipments growth is equal
to growth in electricity consumption for
all sectors, as given by the AEO2022
forecast through 2050. DOE’s model
assumed that growth in annual
1781
shipments of dry-type distribution
transformers would be equal to the
growth in electricity consumption for
commercial and industrial sectors,
respectively. The model starts with an
estimate of the overall growth in
distribution transformer capacity, and
then estimates shipments for particular
representative units and capacities
using estimates of the recent market
shares for different design and size
categories.
TABLE IV.13—ESTIMATED LIQUID-IMMERSED SHIPMENTS FOR 2027 (UNITS)
Single-phase
Capacity
(kVA)
Pad
Three-phase
OH
Pad
OH
NVS
10 .........................................................................................
15 .........................................................................................
25 .........................................................................................
30 .........................................................................................
38 .........................................................................................
45 .........................................................................................
50 .........................................................................................
75 .........................................................................................
100 .......................................................................................
113 .......................................................................................
150 .......................................................................................
167 .......................................................................................
225 .......................................................................................
250 .......................................................................................
300 .......................................................................................
333 .......................................................................................
500 .......................................................................................
667 .......................................................................................
750 .......................................................................................
833 .......................................................................................
1,000 ....................................................................................
1,500 ....................................................................................
2,000 ....................................................................................
2,500 ....................................................................................
3,750 ....................................................................................
5,000 ....................................................................................
677
4,679
44,873
0
8,184
0
79,074
42,684
32,830
0
0
8,272
0
134
0
4
3
6
0
70
0
0
0
0
0
0
71,325
147,344
329,589
0
45,629
0
149,710
24,149
20,537
0
0
5,926
0
508
0
890
488
0
0
21
0
0
0
0
0
0
0
0
0
10
0
714
0
6,523
0
1,773
13,066
0
2,972
0
13,061
0
9,867
13
6,057
39
5,426
5,886
2,349
3,701
286
95
0
0
0
68
0
692
0
661
0
95
787
0
16
0
268
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
13
49
39
127
150
103
359
0
0
Total ..............................................................................
221,490
796,116
71,838
2,587
843
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE IV.14—ESTIMATED LOW-VOLTAGE DRY-TYPE SHIPMENTS FOR 2027 (UNITS)
Capacity
(kVA)
Single-phase
Three-phase
10 .............................................................................................................................................................................
15 .............................................................................................................................................................................
25 .............................................................................................................................................................................
30 .............................................................................................................................................................................
37.5 ..........................................................................................................................................................................
45 .............................................................................................................................................................................
50 .............................................................................................................................................................................
75 .............................................................................................................................................................................
100 ...........................................................................................................................................................................
112.3 ........................................................................................................................................................................
150 ...........................................................................................................................................................................
167 ...........................................................................................................................................................................
225 ...........................................................................................................................................................................
250 ...........................................................................................................................................................................
300 ...........................................................................................................................................................................
333 ...........................................................................................................................................................................
500 ...........................................................................................................................................................................
667 ...........................................................................................................................................................................
750 ...........................................................................................................................................................................
833 ...........................................................................................................................................................................
1,000 ........................................................................................................................................................................
3
2,792
6,215
........................
3,777
........................
5,821
3,508
2,200
........................
........................
........................
........................
28
........................
........................
........................
........................
........................
........................
........................
........................
18,398
........................
44,689
........................
47,106
........................
62,205
........................
27,858
22,062
........................
7,828
........................
4,109
........................
2,527
........................
614
........................
17
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E:\FR\FM\11JAP3.SGM
11JAP3
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE IV.14—ESTIMATED LOW-VOLTAGE DRY-TYPE SHIPMENTS FOR 2027 (UNITS)—Continued
Capacity
(kVA)
Single-phase
Three-phase
1,500 ........................................................................................................................................................................
2,000 ........................................................................................................................................................................
2,500 ........................................................................................................................................................................
........................
........................
........................
11
........................
........................
Total ..................................................................................................................................................................
24,344
237,423
TABLE IV.15—ESTIMATED MEDIUM-VOLTAGE DRY-TYPE SHIPMENTS FOR 2027 (UNITS)
Single-phase
Capacity
(kVA)
20–45 kV BIL
≥96 kV BIL
20–45 kV BIL
46–95 kV BIL
≥96 kV BIL
10 .............................................................
15 .............................................................
25 .............................................................
30 .............................................................
38 .............................................................
45 .............................................................
50 .............................................................
75 .............................................................
100 ...........................................................
113 ...........................................................
150 ...........................................................
167 ...........................................................
225 ...........................................................
250 ...........................................................
300 ...........................................................
333 ...........................................................
500 ...........................................................
667 ...........................................................
750 ...........................................................
833 ...........................................................
1,000 ........................................................
1,500 ........................................................
2,000 ........................................................
2,500 ........................................................
3,750 ........................................................
5,000 ........................................................
250
250
60
0
60
0
30
30
12
0
0
7
0
15
15
12
0
0
0
0
0
0
0
0
0
0
180
180
40
0
40
0
20
20
20
0
0
10
0
20
0
20
0
0
0
0
0
0
0
0
0
0
60
60
20
0
20
0
10
10
6
0
0
3
0
3
0
4
0
0
0
0
0
0
0
0
0
0
0
5
0
10
0
10
0
4
0
30
35
0
29
0
91
0
177
0
72
0
45
0
0
0
0
0
0
0
0
0
0
0
0
2
0
4
5
0
12
0
30
0
85
0
121
0
242
363
605
605
12
4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
25
0
74
0
75
0
194
244
280
394
8
3
Total ..................................................
741
550
196
508
2,074
1,297
1. Equipment Switching
lotter on DSK11XQN23PROD with PROPOSALS3
46–95 kV BIL
Three-phase
In response to the shipments analysis
presented in the August 2021
Preliminary Analysis TSD, NEMA
commented that manufacturers have
had customers avoid liquid-immersed
entirely and use dry-type designs due to
local purchasing restrictions or policies.
(NEMA, No. 50 at p. 14)
DOE understands that mediumvoltage dry-type distribution
transformers (MVDT) can be used as
replacement for liquid-immersed
distribution transformers but DOE has
always considered it as an edge case due
to the differences in purchase price, and
consumer sensitivity to first costs. DOE
does not have sufficient data to model
the substitution of liquid-immersed
distribution transformers with MVDT.
DOE requests comment on which
liquid-immersed distribution
transformers capacities are typically
replaced with MVDT. DOE further
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requests data that would indicate a
trend in these substitutions. DOE further
requests data that would help it
determine which types of customers are
preforming these substitutions, e.g.,
industrial customers, invertor owned
utilities, MUNIs, etc.
2. Trends in Distribution Transformer
Capacity (kVA)
NEMA commented that as consumer
demand increases due to migration to
all-electric homes and buildings, it
stands to reason that kVA sizes will
increase over time as infrastructure
upgrades capacity to serve these
consumer demands. Likewise, NEMA
commented that investments in
renewable energy generation will cause
changes to transformer shipments, unit
sizes and selections, and, that DOE
should examine non-static capacity
scenarios, where kVA of units by type
increases over time as NEMA members
express growth in average kVA of
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ordered units over time in recent years,
presumably due to increased
electrification of consumer and
industrial applications. (NEMA, No. 50
at pp. 16–17)
DOE has limited data available to
conduct the sensitivity requested by
NEMA at this time. To do so DOE would
require the current average kVA
capacity for each of the representative
units analyzed in the engineering
analysis, section IV.C.1 of this
document. If DOE were to apply a shift
in growing capacity without input data
from stakeholders, it would have the
effect on inflating the energy savings
estimates. In response to NEMA’s
comment DOE requests data to inform a
shift in the capacity distribution to
larger capacity distribution
transformers. Additionally, DOE
requests information on the extent that
this increasing trend in capacity would
affect all types of distribution
E:\FR\FM\11JAP3.SGM
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
transformers, or only medium-voltage
distribution transformers.
H. National Impact Analysis
The NIA assesses the national energy
savings (‘‘NES’’) and the NPV from a
national perspective of total consumer
costs and savings that would be
expected to result from new or amended
standards at specific efficiency levels.83
(‘‘Consumer’’ in this context refers to
consumers of the product being
regulated.) DOE calculates the NES and
NPV for the potential standard levels
considered based on projections of
annual product shipments, along with
the annual energy consumption and
total installed cost data from the energy
use and LCC analyses. For the present
analysis, DOE projected the energy
savings, operating cost savings, product
costs, and NPV of consumer benefits
over the lifetime of distribution
transformers sold from 2027 through
2056.
DOE evaluates the impacts of new or
amended standards by comparing a case
without such standards with standardscase projections. The no-new-standards
case characterizes energy use and
consumer costs for each product class in
the absence of new or amended energy
conservation standards. For this
projection, DOE considers historical
trends in efficiency and various forces
that are likely to affect the mix of
efficiencies over time. DOE compares
the no-new-standards case with
projections characterizing the market for
each product class if DOE adopted new
or amended standards at specific energy
efficiency levels (i.e., the TSLs or
1783
standards cases) for that class. For the
standards cases, DOE considers how a
given standard would likely affect the
market shares of products with
efficiencies greater than the standard.
DOE uses a model to calculate the
energy savings and the national
consumer costs and savings from each
TSL. Interested parties can review
DOE’s analyses by changing various
input quantities within the model. The
NIA model uses typical values (as
opposed to probability distributions) as
inputs.
Table IV.16 summarizes the inputs
and methods DOE used for the NIA
analysis for the NOPR. Discussion of
these inputs and methods follows the
table. See chapter 10 of the NOPR TSD
for further details.
TABLE IV.16—SUMMARY OF INPUTS AND METHODS FOR THE NATIONAL IMPACT ANALYSIS
Inputs
Method
Shipments ...........................................................
Annual shipments from shipments model.
Initial Shipments: Market reports from HVOLT, stakeholder data, confidential manufacturer
data.
Future Shipments: Projection based on trends from AEO2022:
Liquid-immersed: Future electricity sales trends.
Low-, Medium-voltage Dry-type: Future commercial floor space and industrial output trends.
2027.
No-new-standards case: constant efficiency over time.
Standards cases: constant efficiency over time.
Annual weighted-average values are a function of energy use at each TSL.
Annual weighted-average values are a function of cost at each TSL.
Incorporates projection of future product prices based on historical data.
Annual weighted-average values as a function of the annual energy consumption per unit and
energy prices.
Annual values do not change with efficiency level.
AEO2022 projections (to 2050) and constant 2050 thereafter.
A time-series conversion factor based on AEO2022.
3 percent and 7 percent.
2022.
Compliance Date of Standard .............................
Efficiency Trends .................................................
Annual Energy Consumption per Unit ................
Total Installed Cost per Unit ...............................
Annual Energy Cost per Unit ..............................
Repair and Maintenance Cost per Unit ..............
Energy Price Trends ...........................................
Energy Site-to-Primary and FFC Conversion .....
Discount Rate ......................................................
Present Year .......................................................
lotter on DSK11XQN23PROD with PROPOSALS3
DOE projected the energy savings,
operating cost savings, product costs,
and NPV of consumer benefits over the
lifetime of distribution transformers
sold from 2027 through 2056 Given the
extremely durable nature of distribution
transformers, this creates an analytical
timeframe from 2027 through 2115. DOE
seeks comment on the current analytical
timeline, and potential alternative
analytical timeframes.
1. Equipment Efficiency Trends
A key component of the NIA is the
trend in energy efficiency projected for
the no-new-standards case and each of
the standards cases. Section IV.F.3of
this document describes how DOE
developed an energy efficiency
distribution for the no-new-standards
case for each of the considered
equipment classes for the year of
anticipated compliance with an
amended or new standard. As discussed
in section IV.F.3, DOE has found that
the vast majority of distribution
transformers are purchased based on
first cost. For both the no-new standards
case and amended standards case, DOE
used the results of the consumer choice
mode in the LCC, described in section
IV.F.3 to establish the shipmentweighted efficiency for the year of
potential standards are assumed to
become effective (2027). For this NOPR,
despite the availability of a wide range
of efficiencies, DOE modelled that these
efficiencies would remain static over
time because the purchase decision is
largely based on first-costs (see section
IV.F.3 of this document) and DOE’s
application of constant future
equipment costs (see section IV.F.1 of
this document).
2. National Energy Savings
The national energy savings analysis
involves a comparison of national
energy consumption of the considered
products between each potential
standards case (‘‘TSL’’) and the case
with no new or amended energy
conservation standards. DOE calculated
the national energy consumption by
multiplying the number of units (stock)
of each product (by vintage or age) by
the unit energy consumption (also by
vintage). DOE calculated annual NES
based on the difference in national
energy consumption for the no-new
standards case and for each higher
efficiency standard case. DOE estimated
83 The NIA accounts for impacts in the 50 states
and U.S. territories.
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energy consumption and savings based
on site energy and converted the
electricity consumption and savings to
primary energy (i.e., the energy
consumed by power plants to generate
site electricity) using annual conversion
factors derived from AEO2022.
Cumulative energy savings are the sum
of the NES for each year over the
timeframe of the analysis.
Use of higher-efficiency equipment is
occasionally associated with a direct
rebound effect, which refers to an
increase in utilization of the equipment
due to the increase in efficiency and its
lower operating cost. A distribution
transformer’s utilization is entirely
dependent on the aggregation of the
connected loads on the circuit the
distribution transformer serves. Greater
utilization would result in greater perunit load (PUL) on the distribution
transformer. Any increase in
distribution transformer PUL is
coincidental, and not related to rebound
effect.
DOE accounts for incidental load
growth on the distribution transformer
resulting from additional connections
not related to the rebound effect due to
increased equipment efficiency.in the
LCC analysis in the form of future load
growth. See section IV.E.3 for more
details on DOE approach to load growth.
Because DOE did not find any data to
support the inclusion of a rebound
effect specific to distribution
transformers, did not include a rebound
effect in this NOPR.
DOE requests comment on its
assumption that including a rebound
effect is inappropriate for distribution
transformers.
In 2011, in response to the
recommendations of a committee on
‘‘Point-of-Use and Full-Fuel-Cycle
Measurement Approaches to Energy
Efficiency Standards’’ appointed by the
National Academy of Sciences, DOE
announced its intention to use FFC
measures of energy use and greenhouse
gas and other emissions in the national
impact analyses and emissions analyses
included in future energy conservation
standards rulemakings. 76 FR 51281
(Aug. 18, 2011). After evaluating the
approaches discussed in the August 18,
2011 notice, DOE published a statement
of amended policy in which DOE
explained its determination that EIA’s
National Energy Modeling System
(‘‘NEMS’’) is the most appropriate tool
for its FFC analysis and its intention to
use NEMS for that purpose. 77 FR 49701
(Aug. 17, 2012). NEMS is a public
domain, multi-sector, partial
equilibrium model of the U.S. energy
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sector 84 that EIA uses to prepare its
Annual Energy Outlook. The FFC factors
incorporate losses in production and
delivery in the case of natural gas
(including fugitive emissions) and
additional energy used to produce and
deliver the various fuels used by power
plants. The approach used for deriving
FFC measures of energy use and
emissions is described in appendix 10B
of the NOPR TSD.
3. Net Present Value Analysis
The inputs for determining the NPV
of the total costs and benefits
experienced by consumers are (1) total
annual installed cost, (2) total annual
operating costs (energy costs and repair
and maintenance costs), and (3) a
discount factor to calculate the present
value of costs and savings. DOE
calculates net savings each year as the
difference between the no-newstandards case and each standards case
in terms of total savings in operating
costs versus total increases in installed
costs. DOE calculates operating cost
savings over the lifetime of each product
shipped during the projection period.
As discussed in section IV.F.1 of this
document, DOE developed distribution
transformers price trends based on
historical PPI data. DOE applied the
same trends to project prices for each
product class at each considered
efficiency level, which was a constant
price trend through the end of the
analysis period in 2056. DOE’s
projection of product prices is described
in appendix 10C of the NOPR TSD.
To evaluate the effect of uncertainty
regarding the price trend estimates, DOE
investigated the impact of different
product price projections on the
consumer NPV for the considered TSLs
for distribution transformers. In
addition to the default price trend, DOE
considered two product price sensitivity
cases: (1) a high price decline case based
on the years between 2003–2019 and (2)
a low price decline case based on the
years between 1967–2002. The
derivation of these price trends and the
results of these sensitivity cases are
described in appendix 10C of the NOPR
TSD.
The operating cost savings are energy
cost savings, which are calculated using
the estimated energy savings in each
year and the projected price of the
appropriate form of energy. To estimate
energy prices in future years, DOE
multiplied the average regional energy
prices by the projection of annual
84 For more information on NEMS, refer to The
National Energy Modeling System: An Overview
2009, DOE/EIA–0581(2009), October 2009.
Available at www.eia.gov/forecasts/aeo/index.cfm
(last accessed April 1, 2022).
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national-average electricity price
changes in the Reference case from
AEO2022, which has an end year of
2050. To estimate price trends after
2050, DOE maintained the price
constant at 2050 levels. As part of the
NIA, DOE also analyzed scenarios that
used inputs from variants of the
AEO2022 Reference case that have
lower and higher economic growth.
Those cases have lower and higher
energy price trends compared to the
Reference case. NIA results based on
these cases are presented in appendix
10C of the NOPR TSD.
In calculating the NPV, DOE
multiplies the net savings in future
years by a discount factor to determine
their present value. For this NOPR, DOE
estimated the NPV of consumer benefits
using both a 3-percent and a 7-percent
real discount rate. DOE uses these
discount rates in accordance with
guidance provided by the Office of
Management and Budget (‘‘OMB’’) to
Federal agencies on the development of
regulatory analysis.85 The discount rates
for the determination of NPV are in
contrast to the discount rates used in the
LCC analysis, which are designed to
reflect a consumer’s perspective. The 7percent real value is an estimate of the
average before-tax rate of return to
private capital in the U.S. economy. The
3-percent real value represents the
‘‘social rate of time preference,’’ which
is the rate at which society discounts
future consumption flows to their
present value.
I. Consumer Subgroup Analysis
In analyzing the potential impact of
new or amended energy conservation
standards on consumers, DOE evaluates
the impact on identifiable subgroups of
consumers that may be
disproportionately affected by a new or
amended national standard. The
purpose of a subgroup analysis is to
determine the extent of any such
disproportional impacts. DOE evaluates
impacts on particular subgroups of
consumers by analyzing the LCC
impacts and PBP for those particular
consumers from alternative standard
levels. For this NOPR, DOE analyzed the
impacts of the considered standard
levels on two subgroups: (1) utilities
serving low population densities and (2)
utility purchasers of vault
(underground) and subsurface
installations. DOE used the LCC and
PBP model to estimate the impacts of
the considered efficiency levels on these
85 United States Office of Management and
Budget. Circular A–4: Regulatory Analysis.
September 17, 2003. Section E. Available at
www.whitehouse.gov/omb/memoranda/m0321.html (last accessed April 1, 2022).
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subgroups. Chapter 11 in the NOPR TSD
describes the consumer subgroup
analysis.
1. Utilities Serving Low Customer
Populations
In rural areas, mostly served by
municipal utilities (MUNIs) the number
of customers per distribution
transformer is lower than in
metropolitan areas and may result in
lower PULs. For this NOPR, as in the
April 2013 Standards Final Rule, DOE
reduced the PUL by adjusting the
distribution of IPLs, as discussed in
section IV.E.1.a resulting in the PULs
shown below in Table IV.17. Further,
DOE altered the customer sample to
limit the distribution of discount rates
to those observed by State and local
governments discussed in IV.F.9. DOE
notes that while MUNIs deploy a range
of distribution transformers to serve
their customers, in low population
densities the most common unit is a 25
kVA pole overheard liquid-immersed
distribution transformer, which is
represented in this analysis as
representative unit 2.
TABLE IV.17—DISTRIBUTION OF PER-UNIT-LOAD FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS OWNED BY
UTILITIES SERVING LOW POPULATIONS
Rep. unit
1
2
3
4
5
Mean RMS
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
DOE requests comment on the mean
PUL applied to distribution
transformers owned and operated by
utilities serving low customer
populations.
2. Utility Purchasers of Vault
(Underground) and Subsurface
Installations
In some urban areas, utilities provide
service to customers by deploying parts
of their transformer fleet in subsurface
vaults, or other prefabricated
underground concrete structure,
referred to as vaults. At issue in the
potential amended standards case is that
as the volume (ft3) of the more efficient
replacement transformers may be too
large to fit into the existing vault, which
would have to be replaced to fit the new
equipment. This analysis is applied to
the representative units 15 and 16,
specifically defined in the engineering
analysis for vault and submersible
liquid-immersed distribution
transformers (see section IV.C.1).
NEMA commented that they agree
with the proposed approach to examine
utility costs regarding replacement of
existing vault and subsurface
transformers. (NEMA No 18 at p. 17).
DOE has not received any data from
stakeholders regarding the costs
associated with vault replacement due
increased distribution transformer
volume. For this subgroups analysis
DOE examined the National average
price of concrete vault construction
with 6-inch-thick walls for variously
sized vaults from RSMeans.86 DOE notes
that the costs required to install a new
vault can vary above the cost of the
prefabricated concrete vault. These
additional costs would include but are
0.29
0.27
0.32
0.26
0.31
Mean IPL
Mean PUL
0.60
0.60
0.60
0.60
0.60
0.18
0.16
0.19
0.15
0.19
not limited to, excavation and disposal
of the original vault, and backfilling.
While stakeholders have discussed that
these costs can be prohibitive, they have
not to date provided examples of such
costs, or itemized cost breakdowns
associated with vault replacement. Due
to this lack of information DOE has
taken a simple approach and multiplied
the costs from RSMeans by three to
provide a gross vault installation
estimate. This gross vault installation
estimate represents the labor time and
material costs associated with
excavation, vault installation, and
backfilling when replacing the no-newstandards vault with a new structure.
DOE applied the following simple linear
fit relating the cost of vault replacement
to transformer volume.
VaultReplacement = 24.201 ×
DTVolume + 4,930.8
TABLE IV.18—VAULT REPLACEMENT COSTS
[2021$]
Vault dimensions
(ft)
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5′
5′
6′
6′
6′
8′
×
×
×
×
×
×
10′
12′
10′
12′
13′
14′
×
×
×
×
×
×
6′
6′
6′
6′
6′
7′
high
high
high
high
high
high
......................................................................................................................................................
......................................................................................................................................................
......................................................................................................................................................
......................................................................................................................................................
......................................................................................................................................................
......................................................................................................................................................
DOE requests comment on its
assumed vault replacement costs
methodology. DOE seeks comment or
data regarding the installation
procedures associated with vault
replacement. vault expansion
(renovation), and vault transformer
installation and their respective costs
for replacement transformers.
Additionally, DOE seeks information on
86 RSMeans, Series: 330563130050,
330563130150, 330563130100, 330563130200,
330563130250, 330563130300, https://
www.rsmeans.com/ (Last access: March 15, 2022).
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Volume
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300
360
360
360
468
784
the typical expected lifetime of
underground concrete vaults.
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13,050
13,050
14,625
18,300
23,550
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J. Manufacturer Impact Analysis
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1. Overview
DOE performed an MIA to estimate
the financial impacts of amended energy
conservation standards on
manufacturers of distribution
transformers and to estimate the
potential impacts of such standards on
employment and manufacturing
capacity. The MIA has both quantitative
and qualitative aspects and includes
analyses of projected industry cash
flows, the INPV, investments in research
and development (‘‘R&D’’) and
manufacturing capital, and domestic
manufacturing employment.
Additionally, the MIA seeks to
determine how amended energy
conservation standards might affect
manufacturing employment, capacity,
and competition, as well as how
standards contribute to overall
regulatory burden. Finally, the MIA
serves to identify any disproportionate
impacts on manufacturer subgroups,
including small business manufacturers.
The quantitative part of the MIA
primarily relies on the Government
Regulatory Impact Model (‘‘GRIM’’), an
industry cash flow model with inputs
specific to this rulemaking. The key
GRIM inputs include data on the
industry cost structure, unit production
costs, product shipments, manufacturer
markups, and investments in R&D and
manufacturing capital required to
produce compliant equipment. The key
GRIM outputs are the INPV, which is
the sum of industry annual cash flows
over the analysis period, discounted
using the industry-weighted average
cost of capital, and the impact to
domestic manufacturing employment.
The model uses standard accounting
principles to estimate the impacts of
more-stringent energy conservation
standards on a given industry by
comparing changes in INPV and
domestic manufacturing employment
between a no-new-standards case and
the various standards cases (i.e., TSLs).
To capture the uncertainty relating to
manufacturer pricing strategies
following amended standards, the GRIM
estimates a range of possible impacts
under different scenarios.
The qualitative part of the MIA
addresses manufacturer characteristics
and market trends. Specifically, the MIA
considers such factors as a potential
standard’s impact on manufacturing
capacity, competition within the
industry, the cumulative impact of other
DOE and non-DOE regulations, and
impacts on manufacturer subgroups.
The complete MIA is outlined in
chapter 12 of the NOPR TSD.
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DOE conducted the MIA for this
rulemaking in three phases. In Phase 1
of the MIA, DOE prepared a profile of
the distribution transformer
manufacturing industry based on the
market and technology assessment,
preliminary manufacturer interviews,
and publicly available information. This
included a top-down analysis of
distribution transformer manufacturers
that DOE used to derive preliminary
financial inputs for the GRIM (e.g.,
revenues; materials, labor, overhead,
and depreciation expenses; selling,
general, and administrative expenses
(‘‘SG&A’’); and R&D expenses). DOE
also used public sources of information
to further calibrate its initial
characterization of the distribution
transformer manufacturing industry,
including information from the April
2013 Standards Final Rule, individual
company filings of form 10–K from the
SEC,87 corporate annual reports, the
U.S. Census Bureau’s Economic
Census,88 and reports from D&B
Hoovers.89
In Phase 2 of the MIA, DOE prepared
a framework industry cash-flow analysis
to quantify the potential impacts of
amended energy conservation
standards. The GRIM uses several
factors to determine a series of annual
cash flows starting with the
announcement of the standard and
extending over a 30-year period
following the compliance date of the
standard. These factors include annual
expected revenues, costs of sales, SG&A
and R&D expenses, taxes, and capital
expenditures. In general, energy
conservation standards can affect
manufacturer cash flow in three distinct
ways: (1) creating a need for increased
investment, (2) raising production costs
per unit, and (3) altering revenue due to
higher per-unit prices and changes in
sales volumes.
In addition, during Phase 2, DOE
developed interview guides to distribute
to manufacturers of distribution
transformers in order to develop other
key GRIM inputs, including product and
capital conversion costs, and to gather
additional information on the
anticipated effects of energy
conservation standards on revenues,
direct employment, capital assets,
industry competitiveness, industry
consolidation, and manufacturer
subgroup impacts.
In Phase 3 of the MIA, DOE
conducted structured, detailed
interviews with representative
manufacturers. During these interviews,
87 www.sec.gov/edgar.shtml.
88 www.census.gov/programs-surveys/asm.html.
89 www.app.avention.com.
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DOE discussed engineering,
manufacturing, procurement, and
financial topics to validate assumptions
used in the GRIM and to identify key
issues or concerns. See section IV.J.3 of
this document for a description of the
key issues raised by manufacturers
during the interviews. As part of Phase
3, DOE also evaluated subgroups of
manufacturers that may be
disproportionately impacted by
amended standards or that may not be
accurately represented by the average
cost assumptions used to develop the
industry cash flow analysis. Such
manufacturer subgroups may include
small business manufacturers, lowvolume manufacturers (‘‘LVMs’’), niche
players, and/or manufacturers
exhibiting a cost structure that largely
differs from the industry average. DOE
identified one subgroup for a separate
impact analysis: small business
manufacturers. The small business
subgroup is discussed in section VI.B,
‘‘Review under the Regulatory
Flexibility Act’’ and in chapter 12 of the
NOPR TSD.
2. Government Regulatory Impact Model
and Key Inputs
DOE uses the GRIM to quantify the
changes in cash flow due to amended
standards that result in a higher or
lower industry value. The GRIM uses a
standard, annual discounted cash-flow
analysis that incorporates manufacturer
costs, markups, shipments, and industry
financial information as inputs. The
GRIM models changes in costs,
distribution of shipments, investments,
and manufacturer margins that could
result from amended energy
conservation standards. The GRIM
spreadsheet uses the inputs to arrive at
a series of annual cash flows, beginning
in 2022 (the reference year of the
analysis) and continuing to 2056. DOE
calculated INPVs by summing the
stream of annual discounted cash flows
during this period. For manufacturers of
distribution transformers, DOE used a
real discount rate of 7.4 percent for
liquid-immersed distribution
transformers, 11.1 percent for lowvoltage dry-type distribution
transformers, and 9.0 percent for
medium-voltage dry-type distribution
transformers, which was derived from
the April 2013 Standards Final Rule and
then modified according to feedback
received during manufacturer
interviews.90
90 See Chapter 12 of the April 2013 Final Rule
TSD for discussion of where initial discount factors
were derived, available online at
www.regulations.gov/document/EERE-2010-BTSTD-0048-0760. For the April 2013 Final Rule, DOE
initially calculated a 9.1 percent discount rate,
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DOE requests comment on the real
discount rates used in this NOPR.
Specifically, if 7.4 percent for liquidimmersed distribution transformer
manufacturers, 11.1 percent for lowvoltage dry-type distribution
transformer manufacturers, and 9.0
percent for medium-voltage dry-type
distribution transformer manufacturers
are appropriate discount rates to use in
the GRIM.
The GRIM calculates cash flows using
standard accounting principles and
compares changes in INPV between the
no-new-standards case and each
standards case. The difference in INPV
between the no-new-standards case and
a standards case represents the financial
impact of amended energy conservation
standards on manufacturers. As
discussed previously, DOE developed
critical GRIM inputs using a number of
sources, including publicly available
data, results of the engineering analysis
and shipments analysis, and
information gathered from industry
stakeholders during the course of
manufacturer interviews. The GRIM
results are presented in section V.B.2.
Additional details about the GRIM, the
discount rate, and other financial
parameters can be found in chapter 12
of the NOPR TSD.
a. Manufacturer Production Costs
Manufacturing more efficient
equipment is typically more expensive
than manufacturing baseline equipment
due to the use of more complex
components, which are typically more
costly than baseline components. The
changes in the MPCs of covered
products can affect the revenues, gross
margins, and cash flow of the industry.
During the engineering analysis, DOE
used transformer design software to
create a database of designs spanning a
broad range of efficiencies for each of
the representative units. This design
software generated a bill of materials.
DOE then applied markups to allow for
scrap, handling, factory overhead, and
other non-production costs, as well as
profit, to estimate the MSP.
These designs and their MSPs are
subsequently inputted into the LCC
customer choice model. For each
efficiency level and within each
representative unit, the LCC model uses
a consumer choice model and criteria
described in section IV.F.3 to select a
subset of all the potential designs
however during manufacturer interviews conducted
for that rulemaking, manufacturers suggested using
different discount rates specific for each equipment
class group. During manufacturer interviews
conducted for this NOPR, manufacturers continued
to agree that using different discount rates for each
equipment class group is appropriate.
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options (and associated MSPs). This
subset is meant to represent those
designs that would actually be shipped
in the market under the various
analyzed TSLs. DOE inputted into the
GRIM the weighted average cost of the
designs selected by the LCC model and
scaled those MSPs to other selected
capacities in each design line’s KVA
range.
For a complete description of the
MSPs, see chapter 5 of the NOPR TSD.
b. Shipments Projections
The GRIM estimates manufacturer
revenues based on total unit shipment
projections and the distribution of those
shipments by efficiency level. Changes
in sales volumes and efficiency mix
over time can significantly affect
manufacturer finances. For this analysis,
the GRIM uses the NIA’s annual
shipment projections derived from the
shipments analysis from 2022 (the
reference year) to 2056 (the end year of
the analysis period). See chapter 9 of the
NOPR TSD for additional details.
c. Product and Capital Conversion Costs
Amended energy conservation
standards could cause manufacturers to
incur conversion costs to bring their
production facilities and equipment
designs into compliance. DOE evaluated
the level of conversion-related
expenditures that would be needed to
comply with each considered efficiency
level in each equipment class. For the
MIA, DOE classified these conversion
costs into two major groups: (1) product
conversion costs; and (2) capital
conversion costs. Product conversion
costs are investments in research,
development, testing, marketing, and
other non-capitalized costs necessary to
make product designs comply with
amended energy conservation
standards. Capital conversion costs are
investments in property, plant, and
equipment necessary to adapt or change
existing production facilities such that
new compliant equipment designs can
be fabricated and assembled.
For capital conversion costs, DOE
prepared bottom-up estimates of the
costs required to meet amended
standards at each TSL for each
representative unit. To do this, DOE
used equipment cost estimates from the
April 2013 Standards Final Rule and
from information provided by
manufacturers and equipment suppliers,
an understanding of the manufacturing
processes at distribution transformer
manufacturing facilities developed
during interviews and in consultation
with subject matter experts, and the
properties associated with different core
and winding materials. Major drivers of
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1787
capital conversion costs include
changes in core steel type (and
thickness), core weight, and core stack
height, all of which are interdependent
and can vary by efficiency level. DOE
uses estimates of the core steel
quantities needed by steel type for each
TSL to model the additional equipment
the industry would need to meet each
TSL.
Capital conversion costs are primarily
driven at each TSL by the potential need
for the industry to expand capacity for
amorphous production. Based on
interviews with manufacturers and
equipment suppliers, based on the
responses, DOE’s model assumed an
amorphous production line capable of
producing 1,200 tons annual of
amorphous cores would cost
approximately $1,000,000 in capital
investments. This includes costs
associated with purchasing annealing
ovens, core cutting machines, lacing
tables, and other miscellaneous
equipment. The quantity of amorphous
steel are outputs of the engineering
analysis and the LCC. At higher TSLs,
the percent of distribution transformers
selected in the LCC consumer choice
model that have amorphous cores
increases. Additionally, at the highest
TSLs, the quantity of amorphous steel
per distribution transformer also
increases. As the increasing stringency
of the TSLs drive the use of amorphous
cores in distribution transformers,
capital conversion costs increase.
For product conversion costs, DOE
understands the production of
amorphous cores requires unique
expertise and equipment. For
manufacturers without experience with
amorphous steel, a standard that would
likely be met using amorphous cores
would require the development or the
procurement of the technical knowledge
to produce cores. Because amorphous
steel is thinner and more brittle after
annealing, materials management, safety
measures, and design considerations
that are not associated with nonamorphous steels would need to be
implemented.
DOE estimated product conversion
costs would be equal to the annual
industry R&D expenses for those TSLs
where a majority of the market would be
expected to transition to amorphous
material. These one-time product
conversion costs would be in addition
to the annual R&D expenses normally
incurred by distribution transformer
manufacturers. These one-time
expenditures account for the design,
engineering, prototyping, and other R&D
efforts the industry would have to
undertake to move to a predominately
amorphous market. For TSLs that would
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not require the use of amorphous cores,
but would still require distribution
transformer models to be redesigned to
meet higher efficiency levels, DOE
estimated product conversion costs
would be equal to 50 percent the annual
industry R&D expenses. These one-time
product conversion costs would also be
in addition to the annual R&D expenses
normally incurred by distribution
transformer manufacturers.
Capital and product conversion costs
are key inputs into the GRIM and
directly impact the change in INPV
(which is outputted from the model)
due to analyzed amended standards.
The GRIM assumes all conversionrelated investments occur between the
year of publication of the final rule and
the year by which manufacturers must
comply with the amended standards.
The conversion cost figures used in the
GRIM can be found in section V.B.2 of
this document. For additional
information on the estimated capital
and product conversion costs, see
chapter 12 of the NOPR TSD.
d. Manufacturer Markup Scenarios
MSPs include direct manufacturing
production costs (i.e., labor, materials,
and overhead estimated in DOE’s MPCs)
and all non-production costs (i.e.,
SG&A, R&D, and interest), along with
profit. To calculate the MSPs in the
GRIM, DOE applied manufacturer
markups to the MPCs estimated in the
engineering analysis for each equipment
class and efficiency level. Modifying
these margins in the standards case
yields different sets of impacts on
manufacturers. For the MIA, DOE
modeled two standards-case scenarios
to represent uncertainty regarding the
potential impacts on prices and
profitability for manufacturers following
the implementation of amended energy
conservation standards: (1) a
preservation of gross margin percentage
markup scenario; and (2) a preservation
of operating profit scenario. These
scenarios lead to different margins that,
when applied to the MPCs, result in
varying revenue and cash flow impacts
on distribution transformer
manufacturers.
Under the preservation of gross
margin percentage scenario, DOE
applied the same single uniform ‘‘gross
margin percentage’’ that is used in the
no-new-standards case across all
efficiency levels in the standards cases.
This scenario assumes that
manufacturers would be able to
maintain the same amount of profit as
a percentage of revenues at all TSLs,
even as the MPCs increase in the
standards case. Based on data from the
April 2013 Standards Final Rule,
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publicly available financial information
for manufacturers of distribution
transformers, and comments made
during manufacturer interviews, DOE
estimated a gross margin percentage of
20 percent for all distribution
transformers.91 Because this scenario
assumes that manufacturers would be
able to maintain the same gross margin
percentage as MPCs increase in
response to the analyzed energy
conservation standards, it represents the
upper bound to industry profitability
under amended energy conservation
standards.
Under the preservation of operating
profit scenario, DOE modeled a
situation in which manufacturers are
not able to increase per-unit operating
profit in proportion to increases in
MPCs. Under this scenario, as the cost
of production (MPCs) increase,
manufacturers reduce their
manufacturer markups (on a percentage
basis) to a level that maintains the nonew-standards operating profit (in
absolute dollars). The implicit
assumption behind this scenario is that
the industry can only maintain its
operating profit in absolute dollars after
compliance with amended standards.
Therefore, operating margin in
percentage terms is reduced between the
no-new-standards case and the analyzed
standards cases. DOE adjusted the
manufacturer markups in the GRIM at
each TSL to yield approximately the
same earnings before interest and taxes
in the standards case in the year after
the compliance date of the amended
standards as in the no-new-standards
case. This scenario represents the lower
bound to industry profitability under
amended energy conservation
standards.
A comparison of industry financial
impacts under the two scenarios is
presented in section V.B.2.a of this
document.
3. Manufacturer Interviews
DOE interviewed manufacturers
representing approximately 60 percent
of the liquid-immersed distribution
transformer industry; approximately 50
percent of the LVDT distribution
transformer industry; and
approximately 60 percent of the MVDT
distribution transformer industry.
In interviews, DOE asked
manufacturers to describe their major
concerns regarding this rulemaking. The
following section highlights
manufacturer concerns that helped
inform the projected potential impacts
of an amended standard on the industry.
91 The gross margin percentage of 20 percent is
based on a manufacturer markup of 1.25.
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Manufacturer interviews are conducted
under non-disclosure agreements
(‘‘NDAs’’), so DOE does not document
these discussions in the same way that
it does public comments in the
comment summaries and DOE’s
responses throughout the rest of this
document.
a. Material Shortages and Prices
Throughout interviews and
comments, manufacturers noted
substantial material shortages leading to
both higher, more volatile prices and, at
points, an inability to procure certain
materials—particularly electrical steel.
Manufacturers noted that these
shortages reflect rising demand for
electrical steel domestically and
internationally as well as more general
supply chain issues caused by the
COVID–19 pandemic. Demand for steel,
according to manufacturers, appears to
be driven by the growing electric
vehicles and electric motors sectors
(prompting some steel producers to shift
production away from GOES suited for
core manufacturing to non-grainoriented steels suited for electric vehicle
production) as well as more general
rising demand for electrical steel abroad
(leading to foreign steel producers
reducing exports to the United States).
Manufacturers also noted that prices for
copper and aluminum have risen
substantially, though have not been
subject to allocations as electrical steel
has.
Manufacturers stated that higher
energy conservation standards will most
likely lead to greater demand for
materials necessary to build more
efficient transformers—potentially
leading to less material availability and
greater cost concerns, particularly for
manufacturers without long-term
relationships with suppliers. Further,
several manufacturers argued that
establishing more stringent energy
conservation standards during a period
of material price volatility may
undermine DOE’s analysis as it relates
to the short-term and long-term
economic impact of such a standard.
b. Use of Amorphous Materials
Manufacturers raised concerns about
energy conservation standards that
would require the use of amorphous
steel cores. Manufacturers who
currently make their own cores stated
that amorphous core production
requires a different manufacturing
process that would require a substantial
amount of new capital equipment and
retrofits of existing equipment that
could, additionally, require more
facility floor space. Some manufacturers
noted that they may need to switch to
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purchasing cores for products covered
by energy conservation standards.
Moving from a lower to a higher grade
of non-amorphous steel would result in
significantly less costs and most
manufacturers could continue to use the
same core production equipment.
Manufacturers that currently purchase
cores noted less capital conversion costs
associated with such an increase in
standards but did note that there is a
limited number of suppliers of
amorphous steel grades both in North
America and globally—potentially
meaning a limited supply of amorphous
steel in a market with relatively little
competition.
c. Larger Distribution Transformers
Manufacturers noted that energy
conservation standard increases, short
of requiring amorphous core usage,
would likely lead to larger distribution
transformers. Manufacturers stated that
larger transformer sizes could
complicate efforts to design
transformers to replace existing
transformers where space is limited.
Utilities, for example, have built vaults,
where distribution transformers are
placed, of a certain size. If a
replacement distribution transformer
cannot be designed to fit the current
vault space, then utilities will need to
build new vaults, increasing costs and
construction-related disruption
significantly. Manufacturers indicated
that this was not a significant issue with
new construction projects, where
infrastructure can be built around the
size of the distribution transformer.
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4. Discussion of MIA Comments
In response to the August 2021
Preliminary Analysis TSD, a few
interested parties made comments
regarding the MIA, including comments
on small businesses and capital
equipment. DOE addresses these
comments in this section.
a. Small Businesses
Powersmiths commented that large
manufacturers are likely to be able to
meet higher efficiency standards given
they will likely have the resources to
make the necessary capital investments
to comply with standards and would
likely gain additional revenue from the
higher per transformer prices. However,
if energy conservation standards require
large capital investments, these costs
could put small businesses out of
business. (Powersmiths, No.46 at p. 6)
While Schneider commented that there
is an increase in the number of
companies that produce assembled
cores for distribution transformer
manufacturers (as opposed to
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distribution transformer manufacturers
being required to fabricate their own
cores internally). Schneider continued
stating that the availability to purchase
assembled cores would not place a
disproportionate burden on small
businesses. (Schneider, No. 49 at p. 15)
DOE agrees that large capital and
production conversion costs could put
additional strains on all distribution
transformer manufacturers, and
especially small business. As part of the
MIA DOE calculates the expected
conversion costs (capital and product
conversion costs). The methodology for
calculating these conversion costs are
described in section IV.J.2.c and these
cost estimates are presented in section
V.B.2.a. Additionally, DOE specifically
examines the potential impact of small
businesses in section VI.B of this
document.
As stated in section IV.J.2.c,
conversion costs are primarily driven by
the costs associated with the production
of amorphous cores, and to a lesser
extent larger and more efficient GOES
cores. DOE agrees with Schneider’s
comment that small businesses could
mitigate larger conversion costs by
purchasing assembled cores as opposed
to making the investments to produce
more efficient GOES cores or
amorphous cores, in order to comply
with the analyzed standards.
b. Capital Equipment
ERMCO comments that larger cores
may require new or different
manufacturing equipment. (ERMCO, No.
45 at p. 1) DOE agrees that while capital
conversion costs are primarily driven by
the costs associated with the production
of amorphous cores, there are capital
conversion costs associated with
production of larger cores. DOE
accounts for the need for manufacturers
to purchase new or different equipment
in the capital conversion cost estimates
described in section IV.J.2.c, with these
cost estimates presented in section
V.B.2.a of this document.
K. Emissions Analysis
The emissions analysis consists of
two components. The first component
estimates the effect of potential energy
conservation standards on power sector
and site (where applicable) combustion
emissions of CO2, NOX, SO2, and Hg.
The second component estimates the
impacts of potential standards on
emissions of two additional greenhouse
gases, CH4 and N2O, as well as the
reductions to emissions of other gases
due to ‘‘upstream’’ activities in the fuel
production chain. These upstream
activities comprise extraction,
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processing, and transporting fuels to the
site of combustion.
The analysis of electric power sector
emissions of CO2, NOX, SO2, and Hg
uses emissions factors intended to
represent the marginal impacts of the
change in electricity consumption
associated with amended or new
standards. The methodology is based on
results published for the AEO, including
a set of side cases that implement a
variety of efficiency-related policies.
The methodology is described in
appendix 13A in the NOPR TSD. The
analysis presented in this notice uses
projections from AEO2022. Power sector
emissions of CH4 and N2O from fuel
combustion are estimated using
Emission Factors for Greenhouse Gas
Inventories published by the
Environmental Protection Agency
(EPA).92
FFC upstream emissions, which
include emissions from fuel combustion
during extraction, processing, and
transportation of fuels, and ‘‘fugitive’’
emissions (direct leakage to the
atmosphere) of CH4 and CO2, are
estimated based on the methodology
described in chapter 15 of the NOPR
TSD.
The emissions intensity factors are
expressed in terms of physical units per
MWh or MMBtu of site energy savings.
For power sector emissions, specific
emissions intensity factors are
calculated by sector and end use. Total
emissions reductions are estimated
using the energy savings calculated in
the national impact analysis.
1. Air Quality Regulations Incorporated
in DOE’s Analysis
DOE’s no-new-standards case for the
electric power sector reflects the AEO,
which incorporates the projected
impacts of existing air quality
regulations on emissions. AEO2022
generally represents current legislation
and environmental regulations,
including recent government actions,
that were in place at the time of
preparation of AEO2022, including the
emissions control programs discussed in
the following paragraphs.93
SO2 emissions from affected electric
generating units (‘‘EGUs’’) are subject to
nationwide and regional emissions capand-trade programs. Title IV of the
Clean Air Act sets an annual emissions
92 Available at www.epa.gov/sites/production/
files/2021-04/documents/emission-factors_
apr2021.pdf (last accessed July 12, 2021).
93 For further information, see the Assumptions to
AEO2022 report that sets forth the major
assumptions used to generate the projections in the
Annual Energy Outlook. Available at www.eia.gov/
outlooks/aeo/assumptions/ (last accessed June,
2022).
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cap on SO2 for affected EGUs in the 48
contiguous States and the District of
Columbia (DC). (42 U.S.C. 7651 et seq.)
SO2 emissions from numerous States in
the eastern half of the United States are
also limited under the Cross-State Air
Pollution Rule (‘‘CSAPR’’). 76 FR 48208
(Aug. 8, 2011). CSAPR requires these
States to reduce certain emissions,
including annual SO2 emissions, and
went into effect as of January 1,
2015.94 AEO2022 incorporates
implementation of CSAPR, including
the update to the CSAPR ozone season
program emission budgets and target
dates issued in 2016. 81 FR 74504 (Oct.
26, 2016).95 Compliance with CSAPR is
flexible among EGUs and is enforced
through the use of tradable emissions
allowances. Under existing EPA
regulations, for states subject to SO2
emissions limits under CSAPR, excess
SO2 emissions allowances resulting
from the lower electricity demand
caused by the adoption of an efficiency
standard could be used to permit
offsetting increases in SO2 emissions by
another regulated EGU.
However, beginning in 2016, SO2
emissions began to fall as a result of the
Mercury and Air Toxics Standards
(‘‘MATS’’) for power plants. 77 FR 9304
(Feb. 16, 2012). In the MATS final rule,
EPA established a standard for hydrogen
chloride as a surrogate for acid gas
hazardous air pollutants (‘‘HAP’’), and
also established a standard for SO2 (a
non-HAP acid gas) as an alternative
equivalent surrogate standard for acid
gas HAP. The same controls are used to
reduce HAP and non-HAP acid gas;
thus, SO2 emissions are being reduced
as a result of the control technologies
installed on coal-fired power plants to
comply with the MATS requirements
94 CSAPR requires states to address annual
emissions of SO2 and NOX, precursors to the
formation of fine particulate matter (PM2.5)
pollution, in order to address the interstate
transport of pollution with respect to the 1997 and
2006 PM2.5 National Ambient Air Quality Standards
(‘‘NAAQS’’). CSAPR also requires certain states to
address the ozone season (May–September)
emissions of NOX, a precursor to the formation of
ozone pollution, in order to address the interstate
transport of ozone pollution with respect to the
1997 ozone NAAQS. 76 FR 48208 (Aug. 8, 2011).
EPA subsequently issued a supplemental rule that
included an additional five states in the CSAPR
ozone season program; 76 FR 80760 (Dec. 27, 2011)
(Supplemental Rule), and EPA issued the CSAPR
Update for the 2008 ozone NAAQS. 81 FR 74504
(Oct. 26, 2016).
95 In Sept. 2019, the D.C. Court of Appeals
remanded the 2016 CSAPR Update to EPA. In April
2021, EPA finalized the 2021 CSAPR Update which
resolved the interstate transport obligations of 21
states for the 2008 ozone NAAQS. 86 FR 23054
(April 30, 2021); see also, 86 FR 29948 (June 4,
2021) (correction to preamble). The 2021 CSAPR
Update became effective on June 29, 2021. The
release of AEO 2021 in February 2021 predated the
2021 CSAPR Update.
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for acid gas. In order to continue
operating, coal power plants must have
either flue gas desulfurization or dry
sorbent injection systems installed. Both
technologies, which are used to reduce
acid gas emissions, also reduce SO2
emissions. Because of the emissions
reductions under the MATS, it is
unlikely that excess SO2 emissions
allowances resulting from the lower
electricity demand would be needed or
used to permit offsetting increases in
SO2 emissions by another regulated
EGU. Therefore, energy conservation
standards that decrease electricity
generation would generally reduce SO2
emissions. DOE estimated SO2
emissions reduction using emissions
factors based on AEO2022.
CSAPR also established limits on NOX
emissions for numerous States in the
eastern half of the United States. Energy
conservation standards would have
little effect on NOX emissions in those
States covered by CSAPR emissions
limits if excess NOX emissions
allowances resulting from the lower
electricity demand could be used to
permit offsetting increases in NOX
emissions from other EGUs. In such
case, NOX emissions would remain near
the limit even if electricity generation
goes down. A different case could
possibly result, depending on the
configuration of the power sector in the
different regions and the need for
allowances, such that NOX emissions
might not remain at the limit in the case
of lower electricity demand. In this case,
energy conservation standards might
reduce NOX emissions in covered
States. Despite this possibility, DOE has
chosen to be conservative in its analysis
and has maintained the assumption that
standards will not reduce NOX
emissions in States covered by CSAPR.
Energy conservation standards would be
expected to reduce NOX emissions in
the States not covered by CSAPR. DOE
used AEO2022 data to derive NOX
emissions factors for the group of States
not covered by CSAPR.
The MATS limit mercury emissions
from power plants, but they do not
include emissions caps and, as such,
DOE’s energy conservation standards
would be expected to slightly reduce Hg
emissions. DOE estimated mercury
emissions reduction using emissions
factors based on AEO2022, which
incorporates the MATS.
L. Monetizing Emissions Impacts
As part of the development of this
proposed rule, for the purpose of
complying with the requirements of
Executive Order 12866, DOE considered
the estimated monetary benefits from
the reduced emissions of CO2, CH4,
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N2O, NOX, and SO2 that are expected to
result from each of the TSLs considered.
In order to make this calculation
analogous to the calculation of the NPV
of consumer benefit, DOE considered
the reduced emissions expected to
result over the lifetime of products
shipped in the projection period for
each TSL. This section summarizes the
basis for the values used for monetizing
the emissions benefits and presents the
values considered in this NOPR.
On March 16, 2022, the Fifth Circuit
Court of Appeals (No. 22–30087)
granted the federal government’s
emergency motion for stay pending
appeal of the February 11, 2022,
preliminary injunction issued in
Louisiana v. Biden, No. 21–cv–1074–
JDC–KK (W.D. La.). As a result of the
Fifth Circuit’s order, the preliminary
injunction is no longer in effect,
pending resolution of the federal
government’s appeal of that injunction
or a further court order. Among other
things, the preliminary injunction
enjoined the defendants in that case
from ‘‘adopting, employing, treating as
binding, or relying upon’’ the interim
estimates of the social cost of
greenhouse gases—which were issued
by the Interagency Working Group on
the Social Cost of Greenhouse Gases on
February 26, 2021—to monetize the
benefits of reducing greenhouse gas
emissions. As reflected in this rule, DOE
has reverted to its approach prior to the
injunction and presents monetized
greenhouse gas abatement benefits
where appropriate and permissible
under law. DOE requests comment on
how to address the climate benefits and
non-monetized effects of the proposal.
1. Monetization of Greenhouse Gas
Emissions
For the purpose of complying with
the requirements of Executive Order
12866, DOE estimates the monetized
benefits of the reductions in emissions
of CO2, CH4, and N2O by using a
measure of the social cost (‘‘SC’’) of each
pollutant (e.g., SC–GHGs). These
estimates represent the monetary value
of the net harm to society associated
with a marginal increase in emissions of
these pollutants in a given year, or the
benefit of avoiding that increase. These
estimates are intended to include (but
are not limited to) climate-changerelated changes in net agricultural
productivity, human health, property
damages from increased flood risk,
disruption of energy systems, risk of
conflict, environmental migration, and
the value of ecosystem services. DOE
exercises its own judgment in
presenting monetized climate benefits
as recommended by applicable
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Executive orders and guidance, and
DOE would reach the same conclusion
presented in this proposed rulemaking
in the absence of the social cost of
greenhouse gases, including the
February 2021 Interim Estimates
presented by the Interagency Working
Group on the Social Cost of Greenhouse
Gases.
DOE estimated the global social
benefits of CO2, CH4, and N2O
reductions (i.e., SC–GHGs) using the
estimates presented in the Technical
Support Document: Social Cost of
Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive
Order 13990 published in February
2021 by the Interagency Working Group
on the Social Cost of Greenhouse Gases
(IWG) (IWG, 2021). The SC–GHGs is the
monetary value of the net harm to
society associated with a marginal
increase in emissions in a given year, or
the benefit of avoiding that increase. In
principle, SC–GHGs includes the value
of all climate change impacts, including
(but not limited to) changes in net
agricultural productivity, human health
effects, property damage from increased
flood risk and natural disasters,
disruption of energy systems, risk of
conflict, environmental migration, and
the value of ecosystem services. The
SC–GHGs therefore, reflects the societal
value of reducing emissions of the gas
in question by one metric ton. The SC–
GHGs is the theoretically appropriate
value to use in conducting benefit-cost
analyses of policies that affect CO2, N2O
and CH4 emissions. As a member of the
IWG involved in the development of the
February 2021 SC–GHG TSD), the DOE
agrees that the interim SC–GHG
estimates represent the most appropriate
estimate of the SC–GHG until revised
estimates have been developed
reflecting the latest, peer-reviewed
science.
The SC–GHGs estimates presented
here were developed over many years,
using transparent process, peerreviewed methodologies, the best
science available at the time of that
process, and with input from the public.
Specifically, in 2009, an interagency
working group (IWG) that included the
DOE and other executive branch
agencies and offices was established to
ensure that agencies were using the best
available science and to promote
consistency in the social cost of carbon
(SC–CO2) values used across agencies.
The IWG published SC–CO2 estimates
in 2010 that were developed from an
ensemble of three widely cited
integrated assessment models (IAMs)
that estimate global climate damages
using highly aggregated representations
of climate processes and the global
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economy combined into a single
modeling framework. The three IAMs
were run using a common set of input
assumptions in each model for future
population, economic, and CO2
emissions growth, as well as
equilibrium climate sensitivity (ECS)—a
measure of the globally averaged
temperature response to increased
atmospheric CO2 concentrations. These
estimates were updated in 2013 based
on new versions of each IAM. In August
2016 the IWG published estimates of the
social cost of methane (SC–CH4) and
nitrous oxide (SC–N2O) using
methodologies that are consistent with
the methodology underlying the SC–
CO2 estimates. The modeling approach
that extends the IWG SC–CO2
methodology to non-CO2 GHGs has
undergone multiple stages of peer
review. The SC–CH4 and SC–N2O
estimates were developed by Marten et
al. (2015) and underwent a standard
double-blind peer review process prior
to journal publication. In 2015, as part
of the response to public comments
received to a 2013 solicitation for
comments on the SC–CO2 estimates, the
IWG announced a National Academies
of Sciences, Engineering, and Medicine
review of the SC–CO2 estimates to offer
advice on how to approach future
updates to ensure that the estimates
continue to reflect the best available
science and methodologies. In January
2017, the National Academies released
their final report, Valuing Climate
Damages: Updating Estimation of the
Social Cost of Carbon Dioxide, and
recommended specific criteria for future
updates to the SC–CO2 estimates, a
modeling framework to satisfy the
specified criteria, and both near-term
updates and longer-term research needs
pertaining to various components of the
estimation process (National
Academies, 2017). Shortly thereafter, in
March 2017, President Trump issued
Executive Order 13783, which
disbanded the IWG, withdrew the
previous TSDs, and directed agencies to
ensure SC–CO2 estimates used in
regulatory analyses are consistent with
the guidance contained in OMB’s
Circular A–4, ‘‘including with respect to
the consideration of domestic versus
international impacts and the
consideration of appropriate discount
rates’’ (E.O. 13783, Section 5(c)).
Benefit-cost analyses following E.O.
13783 used SC–GHG estimates that
attempted to focus on the U.S.-specific
share of climate change damages as
estimated by the models and were
calculated using two discount rates
recommended by Circular A–4, 3
percent and 7 percent. All other
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methodological decisions and model
versions used in SC–GHG calculations
remained the same as those used by the
IWG in 2010 and 2013, respectively.
On January 20, 2021, President Biden
issued Executive Order 13990, which reestablished the IWG and directed it to
ensure that the U.S. Government’s
estimates of the social cost of carbon
and other greenhouse gases reflect the
best available science and the
recommendations of the National
Academies (2017). The IWG was tasked
with first reviewing the SC–GHG
estimates currently used in Federal
analyses and publishing interim
estimates within 30 days of the E.O. that
reflect the full impact of GHG
emissions, including by taking global
damages into account. The interim SC–
GHG estimates published in February
2021 are used here to estimate the
climate benefits for this proposed
rulemaking. The E.O. instructs the IWG
to undertake a fuller update of the SC–
GHG estimates by January 2022 that
takes into consideration the advice of
the National Academies (2017) and
other recent scientific literature. The
February 2021 SC–GHG TSD provides a
complete discussion of the IWG’s initial
review conducted under E.O. 13990. In
particular, the IWG found that the SC–
GHG estimates used under E.O. 13783
fail to reflect the full impact of GHG
emissions in multiple ways.
First, the IWG found that the SC–GHG
estimates used under E.O. 13783 fail to
fully capture many climate impacts that
affect the welfare of U.S. citizens and
residents, and those impacts are better
reflected by global measures of the SC–
GHG. Examples of effects omitted from
the E.O. 13783 estimates include direct
effects on U.S. citizens, assets, and
investments located abroad, supply
chains, U.S. military assets and interests
abroad, and tourism, and spillover
pathways such as economic and
political destabilization and global
migration that can lead to adverse
impacts on U.S. national security,
public health, and humanitarian
concerns. In addition, assessing the
benefits of U.S. GHG mitigation
activities requires consideration of how
those actions may affect mitigation
activities by other countries, as those
international mitigation actions will
provide a benefit to U.S. citizens and
residents by mitigating climate impacts
that affect U.S. citizens and residents. A
wide range of scientific and economic
experts have emphasized the issue of
reciprocity as support for considering
global damages of GHG emissions. If the
United States does not consider impacts
on other countries, it is difficult to
convince other countries to consider the
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impacts of their emissions on the United
States. The only way to achieve an
efficient allocation of resources for
emissions reduction on a global basis—
and so benefit the U.S. and its citizens—
is for all countries to base their policies
on global estimates of damages. As a
member of the IWG involved in the
development of the February 2021 SC–
GHG TSD, DOE agrees with this
assessment and, therefore, in this
proposed rule DOE centers attention on
a global measure of SC–GHG. This
approach is the same as that taken in
DOE regulatory analyses from 2012
through 2016. A robust estimate of
climate damages that accrue only to U.S.
citizens and residents does not currently
exist in the literature. As explained in
the February 2021 TSD, existing
estimates are both incomplete and an
underestimate of total damages that
accrue only to the citizens and residents
of the U.S. because they do not fully
capture the regional interactions and
spillovers discussed above, nor do they
include all of the important physical,
ecological, and economic impacts of
climate change recognized in the
climate change literature. As noted in
the February 2021 SC–GHG TSD, the
IWG will continue to review
developments in the literature,
including more robust methodologies
for estimating a U.S.-specific SC–GHG
value, and explore ways to better inform
the public of the full range of carbon
impacts. As a member of the IWG, DOE
will continue to follow developments in
the literature pertaining to this issue.
Second, the IWG found that the use of
the social rate of return on capital (7
percent under current OMB Circular A–
4 guidance) to discount the future
benefits of reducing GHG emissions
inappropriately underestimates the
impacts of climate change for the
purposes of estimating the SC–GHG.
Consistent with the findings of the
National Academies (2017) and the
economic literature, the IWG continued
to conclude that the consumption rate of
interest is the theoretically appropriate
discount rate in an intergenerational
context (IWG 2010, 2013, 2016a, 2016b),
and recommended that discount rate
uncertainty and relevant aspects of
intergenerational ethical considerations
be accounted for in selecting future
discount rates. As a member of the IWG
involved in the development of the
February 2021 SC–GHG TSD, DOE
agrees with this assessment and will
continue to follow developments in the
literature pertaining to this issue.
Furthermore, the damage estimates
developed for use in the SC–GHG are
estimated in consumption-equivalent
terms, and so an application of OMB
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Circular A–4’s guidance for regulatory
analysis would then use the
consumption discount rate to calculate
the SC–GHG. DOE agrees with this
assessment and will continue to follow
developments in the literature
pertaining to this issue. DOE also notes
that while OMB Circular A–4, as
published in 2003, recommends using
3% and 7% discount rates as ‘‘default’’
values, Circular A–4 also reminds
agencies that ‘‘different regulations may
call for different emphases in the
analysis, depending on the nature and
complexity of the regulatory issues and
the sensitivity of the benefit and cost
estimates to the key assumptions.’’ On
discounting, Circular A–4 recognizes
that ‘‘special ethical considerations arise
when comparing benefits and costs
across generations,’’ and Circular A–4
acknowledges that analyses may
appropriately ‘‘discount future costs and
consumption benefits . . . at a lower
rate than for intragenerational analysis.’’
In the 2015 Response to Comments on
the Social Cost of Carbon for Regulatory
Impact Analysis, OMB, DOE, and the
other IWG members recognized that
‘‘Circular A–4 is a living document’’ and
‘‘the use of 7 percent is not considered
appropriate for intergenerational
discounting. There is wide support for
this view in the academic literature, and
it is recognized in Circular A–4 itself.’’
Thus, DOE concludes that a 7%
discount rate is not appropriate to apply
to value the social cost of greenhouse
gases in the analysis presented in this
analysis. In this analysis, to calculate
the present and annualized values of
climate benefits, DOE uses the same
discount rate as the rate used to
discount the value of damages from
future GHG emissions, for internal
consistency. That approach to
discounting follows the same approach
that the February 2021 TSD
recommends ‘‘to ensure internal
consistency—i.e., future damages from
climate change using the SC–GHG at 2.5
percent should be discounted to the
base year of the analysis using the same
2.5 percent rate.’’ DOE has also
consulted the National Academies’ 2017
recommendations on how SC–GHG
estimates can ‘‘be combined in RIAs
with other cost and benefits estimates
that may use different discount rates.’’
The National Academies reviewed
‘‘several options,’’ including
‘‘presenting all discount rate
combinations of other costs and benefits
with [SC–GHG] estimates.’’
While the IWG works to assess how
best to incorporate the latest, peer
reviewed science to develop an updated
set of SC–GHG estimates, it set the
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Sfmt 4702
interim estimates to be the most recent
estimates developed by the IWG prior to
the group being disbanded in 2017. The
estimates rely on the same models and
harmonized inputs and are calculated
using a range of discount rates. As
explained in the February 2021 SC–
GHG TSD, the IWG has recommended
that agencies to revert to the same set of
four values drawn from the SC–GHG
distributions based on three discount
rates as were used in regulatory analyses
between 2010 and 2016 and subject to
public comment. For each discount rate,
the IWG combined the distributions
across models and socioeconomic
emissions scenarios (applying equal
weight to each) and then selected a set
of four values recommended for use in
benefit-cost analyses: an average value
resulting from the model runs for each
of three discount rates (2.5 percent, 3
percent, and 5 percent), plus a fourth
value, selected as the 95th percentile of
estimates based on a 3 percent discount
rate. The fourth value was included to
provide information on potentially
higher-than-expected economic impacts
from climate change. As explained in
the February 2021 SC–GHG TSD, and
DOE agrees, this update reflects the
immediate need to have an operational
SC–GHG for use in regulatory benefitcost analyses and other applications that
was developed using a transparent
process, peer-reviewed methodologies,
and the science available at the time of
that process. Those estimates were
subject to public comment in the
context of dozens of proposed
rulemakings as well as in a dedicated
public comment period in 2013.
There are a number of limitations and
uncertainties associated with the SC–
GHG estimates. First, the current
scientific and economic understanding
of discounting approaches suggests
discount rates appropriate for
intergenerational analysis in the context
of climate change are likely to be less
than 3 percent, near 2 percent or lower.
Second, the IAMs used to produce these
interim estimates do not include all of
the important physical, ecological, and
economic impacts of climate change
recognized in the climate change
literature and the science underlying
their ‘‘damage functions’’—i.e., the core
parts of the IAMs that map global mean
temperature changes and other physical
impacts of climate change into
economic (both market and nonmarket)
damages—lags behind the most recent
research. For example, limitations
include the incomplete treatment of
catastrophic and non-catastrophic
impacts in the integrated assessment
models, their incomplete treatment of
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adaptation and technological change,
the incomplete way in which interregional and intersectoral linkages are
modeled, uncertainty in the
extrapolation of damages to high
temperatures, and inadequate
representation of the relationship
between the discount rate and
uncertainty in economic growth over
long time horizons. Likewise, the
socioeconomic and emissions scenarios
used as inputs to the models do not
reflect new information from the last
decade of scenario generation or the full
range of projections. The modeling
limitations do not all work in the same
a. Social Cost of Carbon
direction in terms of their influence on
the SC–CO2 estimates. However, as
discussed in the February 2021 TSD, the
IWG has recommended that, taken
together, the limitations suggest that the
interim SC–GHG estimates used in this
final rule likely underestimate the
damages from GHG emissions. DOE
concurs with this assessment.
DOE’s derivations of the SC–GHG
(i.e., SC–CO2, SC–N2O, and SC–CH4)
values used for this NOPR are discussed
in the following sections, and the results
of DOE’s analyses estimating the
benefits of the reductions in emissions
of these pollutants are presented in
section V.B.6 of this document.
The SC–CO2 values used for this
NOPR were generated using the values
presented in the 2021 update from the
IWG’s February 2021 TSD. Table IV.19
shows the updated sets of SC–CO2
estimates from the latest interagency
update in 5-year increments from 2020
to 2050. The full set of annual values
used is presented in Appendix 14A of
the NOPR TSD. For purposes of
capturing the uncertainties involved in
regulatory impact analysis, DOE has
determined it is appropriate to include
all four sets of SC–CO2 values, as
recommended by the IWG.96
TABLE IV.19—ANNUAL SC–CO2 VALUES FROM 2021 INTERAGENCY UPDATE, 2020–2070
[2020$ per metric ton CO2]
Discount rate and statistics
Emissions year
2020
2025
2030
2035
2040
2045
2050
2055
2060
2065
2070
5%, average
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
.................................................................................................................
The SC–CO2 values used for this
NOPR were based on the values
presented in the 2021 update from the
IWG’s February 2021 SC–GHG TSD. For
2051 to 2070, DOE used estimates
published by EPA, adjusted to 2021$.97
These estimates are based on methods,
assumptions, and parameters identical
to the 2020–2050 estimates published
by the IWG. DOE expects additional
climate benefits to accrue for any
longer-life transformers post 2070, but a
lack of available SC–CO2 estimates for
emissions years beyond 2070 prevents
DOE from monetizing these potential
benefits in this analysis. If further
analysis of monetized climate benefits
3%, average
14
17
19
22
25
28
32
35
38
44
49
2.5%, average
51
56
62
67
73
79
84
89
93
100
108
beyond 2070 becomes available prior to
the publication of the final rule, DOE
will include that analysis in the final
rule. DOE multiplied the CO2 emissions
reduction estimated for each year by the
SC–CO2 value for that year in each of
the four cases. To calculate a present
value of the stream of monetary values,
DOE discounted the values in each of
the four cases using the specific
discount rate that had been used to
obtain the SC–CO2 values in each case.
3%, 95th
percentile
76
83
89
96
103
109
116
122
128
135
143
151
169
186
205
224
242
259
265
275
300
326
values presented in the February 2021
TSD. Table IV.20 shows the updated
sets of SC–CH4 and SC–N2O estimates
from the latest interagency update in 5year increments from 2020 to 2050. The
full set of annual values used is
presented in Appendix 14A of the
NOPR TSD. To capture the uncertainties
involved in regulatory impact analysis,
DOE has determined it is appropriate to
include all four sets of SC–CH4 and SC–
N2O values, as recommended by the
IWG.
b. Social Cost of Methane and Nitrous
Oxide
The SC–CH4 and SC–N2O values used
for this NOPR were generated using the
TABLE IV.20—ANNUAL SC–CH4 AND SC–N2O VALUES FROM 2021 INTERAGENCY UPDATE, 2020–2070
[2020$ per metric ton]
lotter on DSK11XQN23PROD with PROPOSALS3
SC–CH4—discount rate and statistic
Year
5%
3%
2.5%
3%
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
Average
Average
Average
95th percentile
2020 .........................
663
I
1,480
96 For example, the February 2021 TSD discusses
how the understanding of discounting approaches
suggests that discount rates appropriate for
VerDate Sep<11>2014
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I
1,946
I
3,893
5,760
intergenerational analysis in the context of climate
change may be lower than 3 percent.
97 See EPA, Revised 2023 and Later Model Year
Light-Duty Vehicle GHG Emissions Standards:
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I
18,342
I
27,037
48,090
Regulatory Impact Analysis, Washington, DC,
December 2021. Available at: www.epa.gov/system/
files/documents/2021-12/420r21028.pdf (last
accessed January 13, 2022).
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TABLE IV.20—ANNUAL SC–CH4 AND SC–N2O VALUES FROM 2021 INTERAGENCY UPDATE, 2020–2070—Continued
[2020$ per metric ton]
SC–CH4—discount rate and statistic
Year
2025
2030
2035
2040
2045
2050
2055
2060
2065
2070
5%
3%
2.5%
3%
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
Average
Average
Average
95th percentile
.........................
.........................
.........................
.........................
.........................
.........................
.........................
.........................
.........................
.........................
799
935
1,106
1,277
1,464
1,651
1,772
1,899
2,508
3,130
1,714
1,948
2,224
2,500
2,778
3,057
3,221
3,395
4,163
4,976
DOE multiplied the CH4 and N2O
emissions reduction estimated for each
year by the SC–CH4 and SC–N2O
estimates for that year in each of the
cases. To calculate a present value of the
stream of monetary values, DOE
discounted the values in each of the
cases using the specific discount rate
that had been used to obtain the SC–CH4
and SC–N2O estimates in each case.
lotter on DSK11XQN23PROD with PROPOSALS3
2. Monetization of Other Emissions
Impacts
For the NOPR, DOE estimated the
monetized value of NOX and SO2
emissions reductions from electricity
generation using the latest benefit per
ton estimates for that sector from the
EPA’s Benefits Mapping and Analysis
Program.98 DOE used EPA’s values for
PM2.5-related benefits associated with
NOX and SO2 and for ozone-related
benefits associated with NOX for 2025
2030, and 2040, calculated with
discount rates of 3 percent and 7
percent. DOE used linear interpolation
to define values for the years not given
in the 2025 to 2040 period; for years
beyond 2040 the values are held
constant. DOE derived values specific to
the sector for distribution transformer
using a method described in appendix
14B of the NOPR TSD.
DOE multiplied the site emissions
reduction (in tons) in each year by the
associated $/ton values, and then
discounted each series using discount
rates of 3 percent and 7 percent as
appropriate.
M. Utility Impact Analysis
The utility impact analysis estimates
several effects on the electric power
generation industry that would result
from the adoption of new or amended
98 Estimating the Benefit per Ton of Reducing
PM2.5 Precursors from 21 Sectors. www.epa.gov/
benmap/estimating-benefit-ton-reducing-pm25precursors-21-sectors.
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2,223
2,499
2,817
3,136
3,450
3,763
3,942
4,130
4,960
5,867
4,533
5,173
5,939
6,705
7,426
8,147
8,332
8,539
11,177
14,079
6,766
7,772
9,007
10,241
11,687
13,133
14,758
16,424
19,687
23,018
energy conservation standards. The
utility impact analysis estimates the
changes in installed electrical capacity
and generation that would result for
each TSL. The analysis is based on
published output from the NEMS
associated with AEO2022. NEMS
produces the AEO Reference case, as
well as a number of side cases that
estimate the economy-wide impacts of
changes to energy supply and demand.
For the current analysis, impacts are
quantified by comparing the levels of
electricity sector generation, installed
capacity, fuel consumption and
emissions in the AEO2022 Reference
case and various side cases. Details of
the methodology are provided in the
appendices to chapters 13 and 15 of the
NOPR TSD.
The output of this analysis is a set of
time-dependent coefficients that capture
the change in electricity generation,
primary fuel consumption, installed
capacity and power sector emissions
due to a unit reduction in demand for
a given end use. These coefficients are
multiplied by the stream of electricity
savings calculated in the NIA to provide
estimates of selected utility impacts of
potential new or amended energy
conservation standards.
N. Employment Impact Analysis
DOE considers employment impacts
in the domestic economy as one factor
in selecting a proposed standard.
Employment impacts from new or
amended energy conservation standards
include both direct and indirect
impacts. Direct employment impacts are
any changes in the number of
employees of manufacturers of the
products subject to standards, their
suppliers, and related service firms. The
MIA addresses those impacts. Indirect
employment impacts are changes in
national employment that occur due to
the shift in expenditures and capital
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20,520
22,698
25,149
27,600
30,238
32,875
35,539
38,300
42,625
47,072
29,811
32,585
35,632
38,678
41,888
45,098
48,236
51,507
56,397
61,428
54,108
60,125
66,898
73,670
80,766
87,863
94,117
100,845
115,590
130,928
investment caused by the purchase and
operation of more-efficient appliances.
Indirect employment impacts from
standards consist of the net jobs created
or eliminated in the national economy,
other than in the manufacturing sector
being regulated, caused by (1) reduced
spending by consumers on energy, (2)
reduced spending on new energy supply
by the utility industry, (3) increased
consumer spending on the products to
which the new standards apply and
other goods and services, and (4) the
effects of those three factors throughout
the economy.
One method for assessing the possible
effects on the demand for labor of such
shifts in economic activity is to compare
sector employment statistics developed
by the Labor Department’s Bureau of
Labor Statistics (‘‘BLS’’). BLS regularly
publishes its estimates of the number of
jobs per million dollars of economic
activity in different sectors of the
economy, as well as the jobs created
elsewhere in the economy by this same
economic activity. Data from BLS
indicate that expenditures in the utility
sector generally create fewer jobs (both
directly and indirectly) than
expenditures in other sectors of the
economy.99 There are many reasons for
these differences, including wage
differences and the fact that the utility
sector is more capital-intensive and less
labor-intensive than other sectors.
Energy conservation standards have the
effect of reducing consumer utility bills.
Because reduced consumer
expenditures for energy likely lead to
increased expenditures in other sectors
of the economy, the general effect of
99 See U.S. Department of Commerce–Bureau of
Economic Analysis. Regional Multipliers: A User
Handbook for the Regional Input-Output Modeling
System (RIMS II). 1997. U.S. Government Printing
Office: Washington, DC. Available at apps.bea.gov/
scb/pdf/regional/perinc/meth/rims2.pdf (last
accessed June 1, 2022).
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efficiency standards is to shift economic
activity from a less labor-intensive
sector (i.e., the utility sector) to more
labor-intensive sectors (e.g., the retail
and service sectors). Thus, the BLS data
suggest that net national employment
may increase due to shifts in economic
activity resulting from energy
conservation standards.
DOE estimated indirect national
employment impacts for the standard
levels considered in this NOPR using an
input/output model of the U.S. economy
called Impact of Sector Energy
Technologies version 4 (‘‘ImSET’’).100
ImSET is a special-purpose version of
the ‘‘U.S. Benchmark National InputOutput’’ (‘‘I–O’’) model, which was
designed to estimate the national
employment and income effects of
energy-saving technologies. The ImSET
software includes a computer-based I–O
model having structural coefficients that
characterize economic flows among 187
sectors most relevant to industrial,
commercial, and residential building
energy use.
DOE notes that ImSET is not a general
equilibrium forecasting model, and that
the uncertainties involved in projecting
employment impacts, especially
changes in the later years of the
analysis. Because ImSET does not
incorporate price changes, the
employment effects predicted by ImSET
may over-estimate actual job impacts
over the long run for this rule.
Therefore, DOE used ImSET only to
generate results for near-term
timeframes (2031), where these
uncertainties are reduced. For more
details on the employment impact
analysis, see chapter 16 of the NOPR
TSD.
V. Analytical Results and Conclusions
The following section addresses the
results from DOE’s analyses with
respect to the considered energy
conservation standards for distribution
transformers. It addresses the TSLs
examined by DOE, the projected
impacts of each of these levels if
adopted as energy conservation
standards for distribution transformers,
and the standards levels that DOE is
proposing to adopt in this NOPR.
Additional details regarding DOE’s
analyses are contained in the NOPR
TSD supporting this document.
A. Trial Standard Levels
In general, DOE typically evaluates
potential amended standards for
products and equipment by grouping
individual efficiency levels for each
class into TSLs. Use of TSLs allows DOE
to identify and consider manufacturer
cost interactions between the equipment
classes, to the extent that there are such
interactions, and market cross elasticity
from consumer purchasing decisions
that may change when different
standard levels are set. DOE presents the
results for the TSLs in this document,
while the results for all efficiency levels
that DOE analyzed are in the NOPR
TSD.
In the analysis conducted for this
NOPR, DOE analyzed the benefits and
burdens of five TSLs for distribution
transformers. DOE developed TSLs that
combine efficiency levels for each
analyzed representative unit and their
respective equipment classes. For this
NOPR, DOE defined its efficiency levels
as a percentage reduction in baseline
losses (see section IV.F.2). To create
TSLs, DOE maintained this approach
and directly mapped ELs to TSLs, with
the exception of liquid-immersed
submersible distribution transformers
which remain at baseline for all TSLs
except max-tech. For submersible
distribution transformers, being able to
fit in an existing vault is a consumer
feature of significant utility and these
transformers often serve high density
applications. DOE recognizes that
beyond some size increase a vault
replacement may be necessary,
however, DOE lacks sufficient data as to
where exactly that vault replacement is
needed. In order to maintain the
consumer utility associated with
submersible transformers, DOE has
taken the conservative approach of not
considering TSLs for submersible
transformers aside from max-tech. DOE
presents the results for the TSLs in this
document, while the results for all
efficiency levels that DOE analyzed are
in the NOPR TSD.
Table V.1 presents the TSLs and the
corresponding efficiency levels that
DOE has identified for potential
amended energy conservation standards
for distribution transformers. TSL 5
represents the maximum
technologically feasible (‘‘max-tech’’)
energy efficiency for all product classes.
TSL 4 represents a loss reduction over
baseline of 20 percent for liquidimmersed transformers, except
submersible liquid-immersed
transformers which remain at baseline;
a 40 and 30 percent reduction in
baseline losses for single-, and threephase low-voltage distribution
transformers, respectively; and a 30
percent reduction in baseline losses for
all medium-voltage dry-type
distribution transformers. TSL 3
represents a loss reduction over baseline
of 10 percent for liquid-immersed
transformers, except submersible liquidimmersed transformers which remain at
baseline; a 30 and 20 percent reduction
in baseline losses for single-, and threephase low-voltage distribution
transformers, respectively; and a 20
percent reduction in baseline losses for
all medium-voltage dry-type
distribution transformers. TSL 2
represents a loss reduction over baseline
of 5 percent for liquid-immersed
transformers, except submersible liquidimmersed transformers which remain at
baseline; a 20 and 10 percent reduction
in baseline losses for single-, and threephase low-voltage distribution
transformers, respectively; and a 10
percent reduction in baseline losses for
all medium-voltage dry-type
distribution transformers. TSL 1
represents a loss reduction over baseline
of 2.5 percent for liquid-immersed
transformers, except submersible liquidimmersed transformers which remain at
baseline; a 10 and 5 percent reduction
in baseline losses for single-, and threephase low-voltage distribution
transformers, respectively; and a 5
percent reduction in baseline losses for
all medium-voltage dry-type
distribution transformers.
TABLE V.1—EFFICIENCY LEVEL TO TRIAL STANDARD LEVEL MAPPING FOR DISTRIBUTION TRANSFORMERS
Trial standard level
lotter on DSK11XQN23PROD with PROPOSALS3
Equipment type
EC
RU
Phases
BIL
1
Liquid-immersed ................
1
1
1
2
1
2
3
4
100 Livingston, O.V., S.R. Bender, M.J. Scott, and
R.W. Schultz. ImSET 4.0: Impact of Sector Energy
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1
1
1
3
All
All
All
All
......................................
......................................
......................................
......................................
Technologies Model Description and User Guide.
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2
1
1
1
1
3
2
2
2
2
4
3
3
3
3
5
4
4
4
4
2015. Pacific Northwest National Laboratory:
Richland, WA. PNNL–24563.
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TABLE V.1—EFFICIENCY LEVEL TO TRIAL STANDARD LEVEL MAPPING FOR DISTRIBUTION TRANSFORMERS—Continued
Trial standard level
Equipment type
EC
RU
Phases
BIL
1
Low-voltage Dry-type ........
Medium-voltage Dry-type ..
2
2
12
12
3
4
4
5
5
6
6
7
7
8
8
8
9
9
10
10
10
5
17
15
16
6
7
8
* 9V
10V
9
10
11V
12V
11
12
18
13V
14V
13
14
19
DOE constructed the TSLs for this
NOPR to include ELs representative of
ELs with similar characteristics (i.e.,
using similar technologies and/or
efficiencies, and having roughly
comparable equipment availability). The
use of representative ELs provided for
greater distinction between the TSLs.
While representative ELs were included
in the TSLs, DOE considered all
efficiency levels as part of its
analysis.101
B. Economic Justification and Energy
Savings
1. Economic Impacts on Individual
Consumers
DOE analyzed the economic impacts
on distribution transformers consumers
3
3
3
3
1
3
3
1
1
3
3
1
1
3
3
3
1
1
3
3
3
All ......................................
All ......................................
All ......................................
All ......................................
All ......................................
All ......................................
All ......................................
<46 kV ..............................
<46 kV ..............................
<46 kV ..............................
<46 kV ..............................
≥46 and <96 kV ................
≥46 and <96 kV ................
≥46 and <96 kV ................
≥46 and <96 kV ................
≥46 and <96 kV ................
≥96 kV ..............................
≥96 kV ..............................
≥96 kV ..............................
≥96 kV ..............................
≥96 kV ..............................
by looking at the effects that potential
amended standards at each TSL would
have on the LCC and PBP. DOE also
examined the impacts of potential
standards on selected consumer
subgroups. These analyses are discussed
in the following sections.
a. Life-Cycle Cost and Payback Period
In general, higher-efficiency products
affect consumers in two ways: (1)
purchase price increases and (2) annual
operating costs decrease. Inputs used for
calculating the LCC and PBP include
total installed costs (i.e., product price
plus installation costs), and operating
costs (i.e., annual energy use, energy
prices, energy price trends, repair costs,
and maintenance costs). The LCC
calculation also uses product lifetime
2
1
1
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
3
2
2
0
0
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
4
3
3
0
0
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
5
4
4
0
0
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
and a discount rate. Because some
consumers purchase products with
higher efficiency in the no-newstandards case, the average savings are
less than the difference between the
average LCC of the baseline product and
the average LCC at each TSL. The
savings refer only to consumers who are
affected by a standard at a given TSL.
Those who already purchase a product
with efficiency at or above a given TSL
are not affected. Consumers for whom
the LCC increases at a given TSL
experience a net cost. Chapter 8 of the
NOPR TSD provides detailed
information on the LCC and PBP
analyses.
Liquid-Immersed Distribution
Transformers
TABLE V.2—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 1
Average costs
(2021$)
Standard level
lotter on DSK11XQN23PROD with PROPOSALS3
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating cost
2,917
2,983
3,073
3,294
3,279
4,080
Lifetime
operating
cost
67
66
65
48
45
39
LCC
1,346
1,328
1,299
969
913
778
4,263
4,311
4,373
4,263
4,192
4,859
Simple
payback
period
(years)
........................
86.7
73.0
19.2
16.0
40.9
Average
lifetime
(years)
31.9
31.9
31.9
31.9
31.9
31.9
Rep unit 1 represents 20.3 percent of liquid-immersed distribution transformers units shipped, and 21.8 percent of shipments for equipment
class 1 (single phase liquid-immersed).
101 Efficiency levels that were analyzed for this
NOPR are discussed in section IV.F.2 of this
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in TSD chapters 8, 10, and 12.
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11JAP3
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1797
TABLE V.3—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 1
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥53
¥114
0
72
¥599
68.8
85.5
47.4
33.7
95.6
Rep unit 1 represents 20.3 percent of liquid-immersed distribution transformers units shipped, and 21.8 percent of shipments for equipment
class 1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
TABLE V.4—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 2
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
1,805
1,805
1,810
1,857
1,951
2,347
Lifetime
operating
cost
41
33
30
29
27
23
LCC
818
673
613
580
541
452
2,623
2,478
2,423
2,437
2,492
2,799
Simple
payback
period
(years)
Average
lifetime
(years)
........................
0.1
0.5
4.1
10.1
29.1
31.9
31.9
31.9
31.9
31.9
31.9
Rep unit 2 represents 72.7 percent of liquid-immersed distribution transformers units shipped, and 78.0 percent of shipments for equipment
class 1 (single phase liquid-immersed).
TABLE V.5—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 2
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
21.9
9.6
9.3
13.3
84.3
146
201
186
131
¥176
Rep unit 2 represents 72.7 percent of liquid-immersed distribution transformers units shipped, and 78.0 percent of shipments for equipment
class 1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
TABLE V.6—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 3
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
10,728
11,269
11,304
11,754
12,568
14,920
Lifetime
operating
cost
427
335
323
305
275
234
LCC
8,523
6,900
6,668
6,284
5,656
4,744
19,251
18,169
17,972
18,038
18,225
19,664
Simple
payback
period
(years)
Average
lifetime
(years)
........................
5.9
5.6
8.4
12.2
21.8
31.8
31.8
31.8
31.8
31.8
31.8
lotter on DSK11XQN23PROD with PROPOSALS3
Rep unit 3 represents 0.2 percent of liquid-immersed distribution transformers units shipped, and 0.2 percent of shipments for equipment class
1 (single phase liquid-immersed).
TABLE V.7—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 3
% Consumers with
net cost
Standard level
1 .......................................................................................................................................................
2 .......................................................................................................................................................
3 .......................................................................................................................................................
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27.9
22.2
23.3
11JAP3
Average savings—
impacted consumers
(2021)$ *
1,121
1,312
1,216
1798
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.7—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 3—
Continued
% Consumers with
net cost
Standard level
4 .......................................................................................................................................................
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
22.5
64.5
1,029
¥414
Rep unit 3 represents 0.2 percent of liquid-immersed distribution transformers units shipped, and 0.2 percent of shipments for equipment class
1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
TABLE V.8—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 4
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
10,319
10,403
10,596
11,095
11,120
11,798
Lifetime
operating
cost
196
193
184
137
129
117
LCC
3,913
3,846
3,689
2,768
2,616
2,359
14,232
14,249
14,285
13,863
13,736
14,156
Simple
payback
period
(years)
Average
lifetime
(years)
........................
25.8
24.1
13.1
11.9
18.7
32.0
32.0
32.0
32.0
32.0
32.0
Rep unit 4 represents 4.6 percent of liquid-immersed distribution transformers units shipped, and 68.0 percent of shipments for equipment
class 2 (three phase liquid-immersed).
TABLE V.9—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 4
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥26
¥55
381
511
77
38.2
66.6
24.8
12.9
48.9
Rep unit 4 represents 4.6 percent of liquid-immersed distribution transformers units shipped, and 68.0 percent of shipments for equipment
class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
TABLE V.10—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 5
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
35,245
36,431
36,603
37,550
39,455
52,032
First year’s
operating
cost
Lifetime
operating
cost
1,195
1,079
1,006
966
891
744
LCC
23,754
21,647
20,349
19,573
18,002
14,880
58,999
58,078
56,952
57,123
57,457
66,912
Simple
payback
period
(years)
........................
10.2
7.2
10.0
13.8
37.2
Average
lifetime
(years)
31.7
31.7
31.7
31.7
31.7
31.7
Rep unit 5 represents 2.1 percent of liquid-immersed distribution transformers units shipped, and 31.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.11—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 5
% Consumers with
net cost
Standard level
1
2
3
4
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
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41.0
26.7
28.7
28.5
11JAP3
Average savings—
impacted consumers
(2021)$ *
986
2,095
1,888
1,543
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1799
TABLE V.11—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 5—
Continued
% Consumers with
net cost
Standard level
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥7,913
95.8
Rep unit 5 represents 2.1 percent of liquid-immersed distribution transformers units shipped, and 31.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
TABLE V.12—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 15
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
10,749
10,833
11,026
11,523
11,548
12,228
Lifetime
operating
cost
196
193
185
137
129
117
LCC
3,919
3,855
3,700
2,778
2,628
2,367
14,668
14,687
14,727
14,301
14,176
14,595
Simple
payback
period
(years)
........................
26.3
24.5
13.1
12.0
18.8
Average
lifetime
(years)
32.0
32.0
32.0
32.0
32.0
32.0
Rep unit 15 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.4 percent of equipment class 12
shipments.
TABLE V.13—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 15
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021$) *
¥30
¥61
379
507
74
38.3
67.3
24.5
12.8
49.4
Rep unit 15 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.4 percent of shipments for equipment
class 12 (three phase liquid-immersed submersible).
* The savings represent the average LCC for affected consumers.
TABLE V.14—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 16
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
35,814
37,015
37,183
38,135
40,044
52,622
First year’s
operating
cost
Lifetime
operating
cost
1,255
1,146
1,085
1,045
961
789
LCC
25,345
23,365
22,313
21,549
19,748
16,044
61,159
60,380
59,496
59,684
59,791
68,666
Simple
payback
period
(years)
........................
11.0
8.0
11.1
14.4
36.1
Average
lifetime
(years)
32.1
32.1
32.1
32.1
32.1
32.1
Rep unit 16 represents 0.1 percent of liquid-immersed distribution transformers units shipped, and 99.6 percent of shipments for equipment
class 12 (three phase liquid-immersed submersible).
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.15—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 16
% Consumers with
net cost
Standard level
1
2
3
4
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
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42.0
28.9
32.3
29.5
11JAP3
Average savings—
impacted consumers
(2021$) *
829
1,700
1,482
1,368
1800
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.15—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 16—
Continued
Average savings—
impacted consumers
(2021$) *
% Consumers with
net cost
Standard level
5 .......................................................................................................................................................
¥7,509
95.1
Rep unit 16 represents 0.1 percent of liquid-immersed distribution transformers units shipped, and 99.6 percent of shipments for equipment
class 12 (three phase liquid-immersed submersible).
* The savings represent the average LCC for affected consumers.
TABLE V.16—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 17
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
55,256
70,709
72,775
74,623
78,307
102,728
First year’s
operating
cost
Lifetime
operating
cost
3,485
2,485
2,283
2,208
2,028
1,650
71,294
50,618
47,047
45,574
41,715
33,556
LCC
126,550
121,327
119,822
120,197
120,023
136,283
Simple
payback
period
(years)
........................
15.5
14.6
15.2
15.8
25.9
Average
lifetime
(years)
32.1
32.1
32.1
32.1
32.1
32.1
Rep unit 17 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
TABLE V.17—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 17
1
2
3
4
5
Average savings—
impacted consumers
(2021$) *
% Consumers with
net cost
Standard level
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
42.8
34.2
36.8
41.5
73.9
5,346
6,873
6,472
6,594
¥9,755
Rep unit 17 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Low-Voltage Dry-Type Distribution
Transformers
TABLE V.18—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 6
Average costs
(2021$)
Standard level
Installed cost
lotter on DSK11XQN23PROD with PROPOSALS3
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
1,737
1,735
1,783
1,890
2,144
2,311
Lifetime
operating
cost
97
90
83
77
62
48
LCC
1,424
1,327
1,220
1,127
908
703
3,161
3,063
3,003
3,017
3,053
3,014
Simple
payback
period
(years)
........................
0.0
3.3
7.6
11.7
11.7
Average
lifetime
(years)
31.9
31.9
31.9
31.9
31.9
31.9
Rep unit 6 represents 9.3 percent of low-voltage dry-type distribution transformers units shipped, and 100.0 percent of shipments for equipment class 3 (single phase low-voltage dry-type).
TABLE V.19—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 6
1 .......................................................................................................................................................
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Average savings—impacted consumers
(2021$) *
% Consumers with
net cost
Standard level
Fmt 4701
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E:\FR\FM\11JAP3.SGM
1
11JAP3
312
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1801
TABLE V.19—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 6—
Continued
% Consumers with
net cost
Standard level
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—impacted consumers
(2021$) *
17
33
43
40
203
146
108
147
* The savings represent the average LCC for affected consumers.
Rep unit 6 represents 9.3 percent of low-voltage dry-type distribution transformers units shipped, and 100.0 percent of shipments for equipment class 3 (single phase low-voltage dry-type).
TABLE V.20—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 7
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
3,974
3,929
3,920
4,266
4,621
4,829
Lifetime
operating
cost
228
211
206
193
143
132
LCC
3,366
3,114
3,029
2,842
2,102
1,947
7,340
7,043
6,950
7,108
6,723
6,776
Simple
payback
period
(years)
........................
0.0
0.0
8.2
7.5
8.9
Average
lifetime
(years)
32.1
32.1
32.1
32.1
32.1
32.1
Rep unit 7 represents 84.9 percent of low-voltage dry-type distribution transformers units shipped, and 93.6 percent of shipments for equipment class 4 (three phase low-voltage dry-type).
TABLE V.21—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 7
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021$) *
8
7
28
9
15
357
397
233
617
564
* The savings represent the average LCC for affected consumers.
Rep unit 7 represents 84.9 percent of low-voltage dry-type distribution transformers units shipped, and 93.6 percent of shipments for equipment class 4 (three phase low-voltage dry-type).
TABLE V.22—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 8
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating
cost
9,252
9,348
9,746
10,620
12,297
12,297
Lifetime
operating
cost
632
613
588
542
373
373
LCC
9,207
8,937
8,570
7,898
5,439
5,439
18,459
18,285
18,316
18,517
17,737
17,737
Simple
payback
period (years)
........................
5.2
11.3
15.2
11.8
11.8
Average
lifetime
(years)
32.0
32.0
32.0
32.0
32.0
32.0
lotter on DSK11XQN23PROD with PROPOSALS3
Rep unit 8 represents 5.8 percent of low-voltage dry-type distribution transformers units shipped, and 6.4 percent of shipments for equipment
class 4 (three phase low-voltage dry-type).
TABLE V.23—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 8
% Consumers with
net cost
Standard level
1 .......................................................................................................................................................
2 .......................................................................................................................................................
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41
11JAP3
Average savings—
impacted consumers
(2021)$ *
355
152
1802
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.23—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 8—
Continued
% Consumers with
net cost
Standard level
3 .......................................................................................................................................................
4 .......................................................................................................................................................
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥58
722
722
57
31
31
* The savings represent the average LCC for affected consumers.
Rep unit 8 represents 5.8 percent of low-voltage dry-type distribution transformers units shipped, and 6.4 percent of shipments for equipment
class 4 (three phase low-voltage dry-type).
Medium-Voltage Dry-Type Distribution
Transformers
TABLE V.24—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 9
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
First year’s
operating cost
14,830
14,874
14,961
15,984
17,981
19,047
Lifetime
operating
cost
918
895
862
800
726
602
LCC
13,450
13,115
12,628
11,725
10,639
8,823
28,281
27,990
27,589
27,709
28,620
27,870
Simple
payback
period
(years)
........................
2.0
2.4
9.8
16.4
13.4
Average
lifetime
(years)
32.1
32.1
32.1
32.1
32.1
32.1
Rep unit 9 represents 7.3 percent of medium-voltage dry-type distribution transformers units shipped, and 77.0 percent of shipments for equipment class 6 (three phase medium-voltage dry-type, 20–45 kV BIL).
TABLE V.25—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 9
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
4
10
39
64
49
1,039
887
571
¥339
410
* The savings represent the average LCC for affected consumers.
Rep unit 9 represents 7.3 percent of medium-voltage dry-type distribution transformers units shipped, and 77.0 percent of shipments for equipment class 6 (three phase medium-voltage dry-type, 20–45 kV BIL).
TABLE V.26—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 10
Average costs
(2021$)
Standard level
lotter on DSK11XQN23PROD with PROPOSALS3
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
45,167
45,363
47,461
55,429
59,426
67,353
First year’s
operating
cost
Lifetime
operating
cost
2,799
2,674
2,597
2,276
2,039
1,838
LCC
41,003
39,185
38,056
33,366
29,887
26,950
86,169
84,548
85,516
88,794
89,313
94,303
Simple
payback
period
(years)
........................
1.6
11.4
19.7
18.8
23.1
Average
lifetime
(years)
32.0
32.0
32.0
32.0
32.0
32.0
Rep unit 10 represents 2.2 percent of medium-voltage dry-type distribution transformers units shipped, and 23.0 percent of shipments for
equipment class 6 (three phase medium-voltage dry-type, 20–45 kV BIL).
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1803
TABLE V.27—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 10
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
15
38
78
81
91
1,854
653
¥2,625
¥3,144
¥8,133
* The savings represent the average LCC for affected consumers.
Rep unit 10 represents 2.2 percent of medium-voltage dry-type distribution transformers units shipped, and 23.0 percent of shipments for
equipment class 6 (three phase medium-voltage dry-type, 20–45 kV BIL).
TABLE V.28—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 11
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
20,788
20,948
21,792
23,458
23,880
25,903
First year’s
operating
cost
Lifetime
operating
cost
1,190
1,156
1,106
951
859
769
LCC
17,353
16,859
16,123
13,870
12,516
11,216
38,141
37,807
37,915
37,328
36,396
37,119
Simple
payback
period
(years)
........................
4.7
11.9
11.2
9.3
12.2
Average
lifetime
(years)
32.0
32.0
32.0
32.0
32.0
32.0
Rep unit 11 represents 2.6 percent of medium-voltage dry-type distribution transformers units shipped, and 6.6 percent of shipments for equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.29—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 11
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
26
46
35
15
38
438
226
813
1,744
1,021
* The savings represent the average LCC for affected consumers.
Rep unit 11 represents 2.6 percent of medium-voltage dry-type distribution transformers units shipped, and 6.6 percent of shipments for equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.30—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 12
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
54,830
52,818
55,069
63,490
67,333
74,722
First year’s
operating
cost
Lifetime
operating
cost
3,290
3,138
3,063
2,659
2,430
2,206
47,795
45,595
44,505
38,639
35,311
32,055
LCC
102,625
98,413
99,574
102,129
102,644
106,777
Simple
payback
period
(years)
........................
0.0
1.1
13.7
14.5
18.4
Average
lifetime
(years)
32.0
32.0
32.0
32.0
32.0
32.0
lotter on DSK11XQN23PROD with PROPOSALS3
Rep unit 12 represents 36.0 percent of medium-voltage dry-type distribution transformers units shipped, and 92.6 percent of shipments for
equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.31—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 12
% Consumers with
net cost
Standard level
1 .......................................................................................................................................................
2 .......................................................................................................................................................
3 .......................................................................................................................................................
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1
9
49
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Average savings—
impacted consumers
(2021)$ *
4,649
3,051
496
1804
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.31—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 12—
Continued
% Consumers with
net cost
Standard level
4 .......................................................................................................................................................
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥19
¥4,152
54
80
* The savings represent the average LCC for affected consumers.
Rep unit 12 represents 36.0 percent of medium-voltage dry-type distribution transformers units shipped, and 92.6 percent of shipments for
equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.32—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 18
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
85,302
103,468
113,456
134,347
137,299
153,330
First year’s
operating
cost
Lifetime
operating
cost
9,986
6,764
6,493
5,429
5,289
4,864
145,749
98,728
94,798
79,221
77,183
71,007
LCC
231,051
202,196
208,254
213,567
214,481
224,338
Simple
payback
period
(years)
........................
5.6
8.1
10.8
11.1
13.3
Average
lifetime
(years)
32.2
32.2
32.2
32.2
32.2
32.2
Rep unit 18 represents 0.3 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.33—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 18
% Consumers with
net cost
Standard level
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Average savings—
impacted consumers
(2021$) *
5
12
24
26
44
28,855
22,797
17,483
16,570
6,713
* The savings represent the average LCC for affected consumers.
Rep unit 18 represents 0.3 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class 8 (three phase medium-voltage dry-type, 45–95 kV BIL).
TABLE V.34—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 13
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
24,894
25,304
26,181
28,454
31,436
31,983
First year’s
operating
cost
Lifetime
operating
cost
1,316
1,256
1,212
1,111
986
936
LCC
19,168
18,292
17,653
16,176
14,364
13,636
44,062
43,597
43,835
44,630
45,801
45,619
Simple
payback
period
(years)
........................
6.8
12.4
17.3
19.8
18.7
Average
lifetime
(years)
31.9
31.9
31.9
31.9
31.9
31.9
Rep unit 13 represents 1.8 percent of medium-voltage dry-type distribution transformers units shipped, and 7.6 percent of shipments for equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.35—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 13
% Consumers with
net cost
Standard level
1
2
3
4
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
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44
72
81
11JAP3
Average savings—
impacted consumers
(2021$) *
515
228
¥568
¥1,739
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1805
TABLE V.35—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 13—
Continued
% Consumers with
net cost
Standard level
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021$) *
¥1,557
80
* The savings represent the average LCC for affected consumers.
Rep unit 13 represents 1.8 percent of medium-voltage dry-type distribution transformers units shipped, and 7.6 percent of shipments for equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
TABLE V.36—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 14
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
63,684
66,945
70,089
80,939
85,714
93,684
First year’s
operating
cost
Lifetime
operating
cost
4,386
4,263
4,140
3,629
3,281
3,027
63,615
61,834
60,066
52,588
47,555
43,893
LCC
127,299
128,779
130,155
133,527
133,268
137,577
Simple
payback
period
(years)
Average
lifetime
(years)
........................
26.6
26.1
22.8
19.9
22.1
32.0
32.0
32.0
32.0
32.0
32.0
Rep unit 14 represents 22.1 percent of medium-voltage dry-type distribution transformers units shipped, and 91.5 percent of shipments for
equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
TABLE V.37—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 14
1
2
3
4
5
Average savings—
impacted
consumers
(2021$) *
% Consumers with
net cost
Standard level
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
¥1,480
¥2,856
¥6,228
¥5,969
¥10,278
88
87
78
82
93
* The savings represent the average LCC for affected consumers.
Rep unit 14 represents 22.1 percent of medium-voltage dry-type distribution transformers units shipped, and 91.5 percent of shipments for
equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
TABLE V.38—AVERAGE LCC AND PBP RESULTS FOR REPRESENTATIVE UNIT 19
Average costs
(2021$)
Standard level
Installed cost
0
1
2
3
4
5
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
...............................................................
88,951
107,573
117,299
137,304
142,539
154,646
First year’s
operating
cost
Lifetime
operating
cost
9,349
7,209
6,845
5,717
5,455
5,105
136,177
105,019
99,747
83,212
79,409
74,341
LCC
225,128
212,591
217,046
220,516
221,948
228,988
Simple
payback
period
(years)
........................
8.7
11.3
13.3
13.8
15.5
Average
lifetime
(years)
31.9
31.9
31.9
31.9
31.9
31.9
Rep unit 19 represents 0.2 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.39—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 19
% Consumers with
net cost
Standard level
1
2
3
4
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
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16
38
43
47
11JAP3
Average savings—
impacted consumers
(2021)$ *
12,536
8,082
4,611
3,180
1806
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.39—LCC SAVINGS RELATIVE TO THE BASE CASE EFFICIENCY DISTRIBUTION FOR REPRESENTATIVE UNIT 19—
Continued
% Consumers with
net cost
Standard level
5 .......................................................................................................................................................
Average savings—
impacted consumers
(2021)$ *
¥3,860
63
* The savings represent the average LCC for affected consumers.
Rep unit 19 represents 0.2 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class 10 (three phase medium-voltage dry-type, ≥96 kV BIL).
b. Consumer Subgroup Analysis
In the consumer subgroup analysis,
DOE estimated the impact of the
considered TSLs on utilities who deploy
distribution transformers in vaults or
other space constrained areas, and
utilities who serve low population
densities. Table V.40 compares the
average LCC savings and PBP at each
efficiency level for the consumer
subgroups with similar metrics for the
entire consumer sample for equipment
classes 1 and 2. Chapter 11 of the NOPR
TSD presents the complete LCC and
PBP results for the subgroups.
Utilities Serving Low Population
Densities
TABLE V.40—COMPARISON OF LCC SAVINGS AND PBP FOR UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP
AND ALL UTILITIES; REPRESENTATIVE UNIT 1
TSL
Serving low
population densities
All utilities
Average LCC Savings (2021$)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
¥53
¥114
0
72
¥599
¥55
¥112
90
178
¥497
78.6
69.2
19.3
16.2
40.5
120.6
86.0
19.0
15.8
42.2
69
86
47
34
96
66
82
33
20
92
Payback Period (years)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Consumers with Net Cost (%)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Rep unit 1 represents 20.3 percent of liquid-immersed distribution transformers units shipped, and 21.8 percent of shipments for equipment
class 1 (single phase liquid-immersed).
TABLE V.41—COMPARISON OF LCC SAVINGS AND PBP FOR UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP
AND ALL UTILITIES; REPRESENTATIVE UNIT 2
TSL
Serving low
population densities
All utilities
Average LCC Savings (2021$)
lotter on DSK11XQN23PROD with PROPOSALS3
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
146
201
186
131
¥176
189
267
253
199
¥107
0.0
0.4
4.1
10.1
29.3
0.0
0.3
3.9
9.9
30.2
Payback Period (years)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
1807
TABLE V.41—COMPARISON OF LCC SAVINGS AND PBP FOR UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP
AND ALL UTILITIES; REPRESENTATIVE UNIT 2—Continued
TSL
Serving low
population densities
All utilities
Consumers with Net Cost (%)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
22
10
9
13
84
21
7
7
10
72
Rep unit 2 represents 72.7 percent of liquid-immersed distribution transformers units shipped, and 78.0 percent of shipments for equipment
class 1 (single phase liquid-immersed).
TABLE V.42—COMPARISON OF LCC SAVINGS AND PBP FOR UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP
AND ALL UTILITIES; REPRESENTATIVE UNIT 3
TSL
Serving low
population densities
All utilities
Average LCC Savings (2021$)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
1,121
1,312
1,216
1,029
¥414
1,798
2,044
1,962
1,772
308
5.9
5.6
8.4
12.3
21.8
5.3
5.1
7.8
11.9
22.3
28
22
23
23
65
22
16
16
15
44
Payback Period (years)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Consumers with Net Cost (%)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Rep unit 3 represents 0.2 percent of liquid-immersed distribution transformers units shipped, and 0.2 percent of shipments for equipment class
1 (single phase liquid-immersed).
TABLE V.43—COMPARISON OF LCC SAVINGS AND PBP UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP AND
ALL UTILITIES; REPRESENTATIVE UNIT 4
TSL
Serving low population
densities
All utilities
Average LCC Savings (2021$)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
¥26
¥55
381
511
77
¥12
¥9
629
802
372
26.9
24.4
13.2
12.0
18.7
28.0
24.4
13.1
11.9
19.1
38
67
25
37
58
21
lotter on DSK11XQN23PROD with PROPOSALS3
Payback Period (years)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Consumers with Net Cost (%)
1 ...............................................................................................................................................
2 ...............................................................................................................................................
3 ...............................................................................................................................................
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.43—COMPARISON OF LCC SAVINGS AND PBP UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP AND
ALL UTILITIES; REPRESENTATIVE UNIT 4—Continued
TSL
Serving low population
densities
All utilities
4 ...............................................................................................................................................
5 ...............................................................................................................................................
13
49
9
32
Rep unit 4 represents 4.6 percent of liquid-immersed distribution transformers units shipped, and 68.0 percent of shipments for equipment
class 2 (three phase liquid-immersed).
TABLE V.44—COMPARISON OF LCC SAVINGS AND PBP FOR UTILITIES SERVING LOW POPULATION DENSITIES SUBGROUP
AND ALL UTILITIES; REPRESENTATIVE UNIT 5
TSL
Serving low
population densities
All utilities
Average LCC Savings (2021$)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
986
2,095
1,888
1,543
¥7,913
1,498
2,876
2,839
2,830
¥5,881
11.0
8.0
11.0
14.2
35.8
10.1
7.1
9.9
13.8
37.3
41
27
29
29
96
38
23
24
19
89
Payback Period (years)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Consumers with Net Cost (%)
1
2
3
4
5
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
...............................................................................................................................................
Rep unit 5 represents 2.1 percent of liquid-immersed distribution transformers units shipped, and 31.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
Utilities That Deploy Distribution
Transformers in Vaults or Other Space
Constrained Areas
As noted in section IV.C.1, for this
NOPR DOE considered submersible
distribution transformers and their
associated vault, or space constrained
installation costs with individual
representative units, 15 and 16. The
consumer results for these equipment
are presented in Table V.12 through
Table V.15.
lotter on DSK11XQN23PROD with PROPOSALS3
c. Rebuttable Presumption Payback
As discussed in section IV.F.11, EPCA
establishes a rebuttable presumption
that an energy conservation standard is
economically justified if the increased
purchase cost for a product that meets
the standard is less than three times the
value of the first-year energy savings
resulting from the standard. In
calculating a rebuttable presumption
payback period for each of the
considered standard level, DOE used
discrete values, and as required by
EPCA, based the energy use calculation
on the DOE test procedure for
distribution transformers. In contrast,
the PBPs presented in section V.B.1.a
were calculated using distributions that
reflect the range of energy use in the
field.
Table V.45 presents the rebuttablepresumption payback periods for the
considered standard level for
distribution transformers. While DOE
examined the rebuttable-presumption
criterion, it considered whether the
standard levels considered for the NOPR
are economically justified through a
more detailed analysis of the economic
impacts of those levels, pursuant to 42
U.S.C. 6295(o)(2)(B)(i), that considers
the full range of impacts to the
consumer, manufacturer, Nation, and
environment. The results of that
analysis serve as the basis for DOE to
definitively evaluate the economic
justification for a potential standard
level, thereby supporting or rebutting
the results of any preliminary
determination of economic justification.
TABLE V.45—REBUTTABLE-PRESUMPTION PAYBACK PERIODS
Trial standard level
EC
RU
1
1 ...............................................................
1 ...............................................................
1 ...............................................................
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25.3
9.3
74.6
11JAP3
5
22.1
12.1
19.1
25.7
19.7
17.9
1809
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.45—REBUTTABLE-PRESUMPTION PAYBACK PERIODS—Continued
Trial standard level
EC
RU
1
2 ...............................................................
2 ...............................................................
2 ...............................................................
3 ...............................................................
4 ...............................................................
6 ...............................................................
6 ...............................................................
8 ...............................................................
8 ...............................................................
8 ...............................................................
10 .............................................................
10 .............................................................
10 .............................................................
10 .............................................................
12 .............................................................
12 .............................................................
4
5
17
6
7
8
9
10
11
18
12
13
14
19
15
16
2. Economic Impacts on Manufacturers
DOE performed an MIA to estimate
the impact of amended energy
conservation standards on
manufacturers of distribution
transformers. The following section
describes the expected impacts on
manufacturers at each considered TSL.
Chapter 12 of the NOPR TSD explains
the analysis in further detail.
a. Industry Cash Flow Analysis Results
In this section, DOE provides GRIM
results from the analysis, which
examines changes in the industry that
would result from a standard. The
following tables summarize the
estimated financial impacts (represented
by changes in INPV) of potential
amended energy conservation standards
on manufacturers of distribution
transformers, as well as the conversion
costs that DOE estimates manufacturers
of distribution transformers would incur
at each TSL. DOE analyzes the potential
impacts on INPV separately for each
type of distribution transformer
manufacturers: liquid-immersed; LVDT;
and MVDT.
2
11.2
0
8.4
0
0
5.6
1.3
1.4
1.4
4.6
0
5.5
21.4
5.6
n.a.
n.a.
3
22.9
0
9.7
2.3
0
8.1
1.4
6.6
4.9
5.8
0.6
10.2
11.4
6.5
n.a.
n.a.
As discussed in section IV.J.2.d of this
document, DOE modeled two scenarios
to evaluate a range of cash flow impacts
on the distribution transformer industry:
(1) the preservation of gross margin
percentage scenario and (2) the
preservation of operating profit
scenario. In the preservation of gross
margin percentage scenario, distribution
transformer manufacturers are able to
maintain the same gross margin
percentage, even as the MPCs of
distribution transformers increase due
to energy conservation standards. In this
scenario, the same gross margin
percentage of 20 percent 102 is applied
across all efficiency levels. In the
preservation of operating profit
scenario, manufacturers do not earn
additional operating profit when
compared to the no-standards case
scenario. While manufacturers make the
necessary upfront investments required
to produce compliant equipment, perunit operating profit does not change in
absolute dollars. The preservation of
operating profit scenario results in the
lower (or more severe) bound to impacts
of potential amended standards on
industry.
4
14.2
0
10.3
4.3
3.8
9.7
4.6
18.4
8.9
9.7
63.2
12.5
¥67.7
12.7
n.a.
n.a.
5
13.2
21.1
10.0
8.7
8.1
10.6
7.9
15.4
8.7
9.6
18.2
43.4
39.4
12.0
n.a.
n.a.
14.1
26.1
14.6
8.7
6.9
10.6
9.7
16.0
8.7
10.2
15.4
25.3
24.4
12.0
14.1
26.2
Each of the modeled scenarios results
in a unique set of cash-flows and
corresponding industry values at each
TSL for each type of distribution
transformer manufacturers. In the
following discussion, the INPV results
refer to the difference in industry value
between the no-new-standards case and
each standards case resulting from the
sum of discounted cash-flows from 2022
through 2056. To provide perspective
on the short-run cash-flow impact, DOE
includes in the discussion of results a
comparison of free cash flow between
the no-new-standards case and the
standards case at each TSL in the year
before amended standards are required.
DOE presents the range in INPV for
liquid-immersed distribution
transformer manufacturers in Table V.46
and Table V.47; the range in INPV for
LVDT distribution transformer
manufacturers in Table V.48 and Table
V.49; and the range in INPV for MVDT
distribution transformer manufacturers
in Table V.50 and Table V.51.
Liquid-Immersed Distribution
Transformers
TABLE V.46—MANUFACTURER IMPACT ANALYSIS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS—PRESERVATION
OF GROSS MARGIN PERCENTAGE SCENARIO
lotter on DSK11XQN23PROD with PROPOSALS3
Units
INPV .............................................
Change in INPV ............................
Product Conversion Costs ............
Capital Conversion Costs .............
2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
2021$ millions ...............................
No-newstandards
case
Trial standard level
1
1,384
................
................
................
................
1,297
(87.1)
(6.3)
72.0
56.6
2
3
1,268
(116.5)
(8.4)
82.5
92.6
102 The gross margin percentage of 20 percent is
based on a manufacturer markup of 1.25.
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1,232
(152.1)
(11.0)
99.1
150.3
4
1,233
(151.0)
(10.9)
102.0
168.5
5
1,347
(37.2)
(2.7)
102.9
186.6
1810
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.46—MANUFACTURER IMPACT ANALYSIS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS—PRESERVATION
OF GROSS MARGIN PERCENTAGE SCENARIO—Continued
Units
Total Conversion Costs .........
2021$ millions ...............................
No-newstandards
case
Trial standard level
1
2
3
4
5
................
128.6
175.2
249.4
270.6
289.4
* Numbers in parentheses ‘‘( )’’ are negative. Some numbers might not round due to rounding.
TABLE V.47—MANUFACTURER IMPACT ANALYSIS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS—PRESERVATION
OF OPERATING PROFIT SCENARIO
No-newstandards
case
Units
INPV .............................................
Change in INPV ............................
Trial standard level
1
2
3
4
5
Product Conversion Costs ............
Capital Conversion Costs .............
2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
2021$ millions ...............................
1,384
................
................
................
................
1,283
(101.1)
(7.3)
72.0
56.6
1,242
(142.1)
(10.3)
82.5
92.6
1,166
(218.3)
(15.8)
99.1
150.3
1,133
(251.3)
(18.1)
102.0
168.5
1,004
(380.7)
(27.5)
102.9
186.6
Total Conversion Costs .........
2021$ millions ...............................
................
128.6
175.2
249.4
270.6
289.4
lotter on DSK11XQN23PROD with PROPOSALS3
* Numbers in parentheses ‘‘( )’’ are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts
on INPV for liquid-immersed
distribution transformer manufacturers
to range from ¥$101.1 million to
¥$87.1 million, corresponding to a
change in INPV of ¥7.3 percent to ¥6.3
percent. At TSL 1, industry free cash
flow is estimated to decrease by
approximately 56.0 percent to $40.2
million, compared to the no-newstandard case value of $91.2 million in
2026, the year before the estimated
compliance date.
TSL 1 would set the energy
conservation standard at EL 1 for all
liquid-immersed distribution
transformers except for submersible
liquid-immersed transformers
(Equipment Class 12, Rep. Unit 15 and
16), which would remain at baseline.
DOE estimates that approximately 4.3
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates liquid-immersed
distribution transformer manufacturers
would spend approximately $72.0
million in product conversion costs to
redesign transformers and
approximately $56.6 million in capital
conversion costs as some liquidimmersed distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 1, the shipment-weighted
average MPC for liquid-immersed
distribution transformers increases by
0.6 percent relative to the no-newstandards case shipment-weighted
average MPC in 2027. In the gross
margin percentage scenario,
manufacturers can fully pass on this
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slight cost increase to customers. The
slight increase in shipment-weighted
average MPC is outweighed by the
$128.6 million in conversion costs,
causing a negative change in INPV at
TSL 1 under the preservation of gross
margin percentage scenario.
Under the preservation of operating
profit scenario, manufacturers earn the
same per-unit operating profit as would
be earned in the no-new-standards case,
but manufacturers do not earn
additional profit from their investments
or higher MPCs. In this scenario, the 0.6
percent shipment-weighted average
MPC increase results in a reduction in
the margin after the analyzed
compliance year. This reduction in the
margin and the $128.6 million in
conversion costs incurred by
manufacturers cause a negative change
in INPV at TSL 1 under the preservation
of operating profit scenario.
At TSL 2, DOE estimates the impacts
on INPV for liquid-immersed
distribution transformer manufacturers
to range from ¥$142.1 million to
¥$116.5 million, corresponding to a
change in INPV of ¥10.3 percent to
¥8.4 percent. At TSL 2, industry free
cash flow is estimated to decrease by
approximately 77.8 percent to $20.2
million, compared to the no-newstandard case value of $91.2 million in
2026, the year before the estimated
compliance date.
TSL 2 would set the energy
conservation standard at EL 2 for all
liquid-immersed distribution
transformers except for submersible
liquid-immersed transformers
(Equipment Class 12, Rep. Unit 15 and
16), which would remain at baseline.
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DOE estimates that approximately 1.4
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates liquid-immersed
distribution transformer manufacturers
would spend approximately $82.5
million in product conversion costs to
redesign transformers and
approximately $92.6 million in capital
conversion costs as many liquidimmersed distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 2, the shipment-weighted
average MPC for liquid-immersed
distribution transformers increases by
1.7 percent relative to the no-newstandards case shipment-weighted
average MPC in 2027. The increase in
shipment-weighted average MPC is
outweighed by the $175.2 million in
conversion costs, causing a negative
change in INPV at TSL 2 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 1.7 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $175.2 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 2 under
the preservation of operating profit
scenario.
At TSL 3, DOE estimates the impacts
on INPV for liquid-immersed
distribution transformer manufacturers
to range from ¥$218.3 million to
¥$152.1 million, corresponding to a
change in INPV of ¥15.8 percent to
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
¥11.0 percent. At TSL 3, industry free
cash flow is estimated to decrease by
approximately 112.8 percent to ¥$11.6
million, compared to the no-newstandard case value of $91.2 million in
2026, the year before the estimated
compliance date.
TSL 3 would set the energy
conservation standard at EL 3 for all
liquid-immersed distribution
transformers except for submersible
liquid-immersed transformers
(Equipment Class 12, Rep. Unit 15 and
16), which would remain at baseline.
DOE estimates that approximately 0.9
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates liquid-immersed
distribution transformer manufacturers
would spend approximately $99.1
million in product conversion costs to
redesign transformers and
approximately $150.3 million in capital
conversion costs as most liquidimmersed distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 3, the shipment-weighted
average MPC for liquid-immersed
distribution transformers increases by
5.6 percent relative to the no-newstandards case shipment-weighted
average MPC in 2027. The moderate
increase in shipment-weighted average
MPC is outweighed by the $249.4
million in conversion costs, causing a
negative change in INPV at TSL 3 under
the preservation of gross margin
percentage scenario.
Under the preservation of operating
profit scenario, the 5.6 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $249.4 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 3 under
the preservation of operating profit
scenario.
At TSL 4, DOE estimates the impacts
on INPV for liquid-immersed
distribution transformer manufacturers
to range from ¥$251.3 million to
¥$151.0 million, corresponding to a
change in INPV of ¥18.1 percent to
¥10.9 percent. At TSL 4, industry free
cash flow is estimated to decrease by
approximately 122.9 percent to ¥$20.9
million, compared to the no-newstandard case value of $91.2 million in
2026, the year before the estimated
compliance date.
TSL 4 would set the energy
conservation standard at EL 4 for all
liquid-immersed distribution
transformers except for submersible
liquid-immersed transformers
(Equipment Class 12, Rep. Unit 15 and
16), which would remain at baseline.
DOE estimates that approximately 0.7
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates liquid-immersed
distribution transformer manufacturers
would spend approximately $102.0
million in product conversion costs to
redesign transformers and
approximately $168.5 million in capital
conversion costs as almost all liquidimmersed distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 4, the shipment-weighted
average MPC for liquid-immersed
distribution transformers increases by
8.9 percent relative to the no-newstandards case shipment-weighted
average MPC in 2027. The moderate
increase in shipment-weighted average
MPC is outweighed by the $270.6
million in conversion costs, causing a
negative change in INPV at TSL 4 under
the preservation of gross margin
percentage scenario.
Under the preservation of operating
profit scenario, the 8.9 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $270.6 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 4 under
the preservation of operating profit
scenario.
At TSL 5, DOE estimates the impacts
on INPV for liquid-immersed
distribution transformer manufacturers
to range from ¥$380.7 million to
¥$37.2 million, corresponding to a
change in INPV of ¥27.5 percent to
¥2.7 percent. At TSL 5, industry free
cash flow is estimated to decrease by
approximately 132.1 percent to ¥$29.3
million, compared to the no-newstandard case value of $91.2 million in
2026, the year before the estimated
compliance date.
TSL 5 would set the energy
conservation standard at EL 5, max-tech,
for all liquid-immersed distribution
transformers. DOE estimates that
approximately 0.2 percent of shipments
would meet these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates liquid-immersed
distribution transformer manufacturers
would spend approximately $102.9
million in product conversion costs to
redesign transformers and
approximately $186.6 million in capital
conversion costs as almost all liquidimmersed distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 5, the shipment-weighted
average MPC for liquid-immersed
distribution transformers increases by
33.3 percent relative to the no-newstandards case shipment-weighted
average MPC in 2027. The significant
increase in shipment-weighted average
MPC is outweighed by the $289.4
million in conversion costs, causing a
negative change in INPV at TSL 5 under
the preservation of gross margin
percentage scenario.
Under the preservation of operating
profit scenario, the 33.3 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $289.4 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 5 under
the preservation of operating profit
scenario.
Low-Voltage Dry-Type Distribution
Transformers
TABLE V.48—MANUFACTURER IMPACT ANALYSIS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF GROSS MARGIN PERCENTAGE SCENARIO
No-newstandards
case
lotter on DSK11XQN23PROD with PROPOSALS3
Units
INPV .............................................
Change in INPV ............................
Product Conversion Costs ............
Capital Conversion Costs .............
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2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
2021$ millions ...............................
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1
2
194
................
................
................
................
189
(5.4)
(2.8)
9.6
0.0
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189
(4.9)
(2.5)
9.6
0.0
11JAP3
3
4
5
177
(16.9)
(8.7)
14.5
19.1
168
(26.3)
(13.6)
18.9
37.2
161
(33.5)
(17.2)
19.1
50.3
1812
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.48—MANUFACTURER IMPACT ANALYSIS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF GROSS MARGIN PERCENTAGE SCENARIO—Continued
No-newstandards
case
Units
Total Conversion Costs .........
2021$ millions ...............................
Trial standard level
1
................
2
9.6
3
9.6
4
33.5
5
56.1
69.4
* Numbers in parentheses ‘‘( )’’ are negative. Some numbers might not round due to rounding.
TABLE V.49—MANUFACTURER IMPACT ANALYSIS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF OPERATING PROFIT SCENARIO
No-newstandards
case
Units
INPV .............................................
Change in INPV ............................
Trial standard level
1
2
3
4
5
Product Conversion Costs ............
Capital Conversion Costs .............
2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
2021$ millions ...............................
194
................
................
................
................
189
(5.4)
(2.8)
9.6
0.0
188
(5.9)
(3.0)
9.6
0.0
167
(27.0)
(13.9)
14.5
19.1
145
(49.1)
(25.3)
18.9
37.2
133
(61.0)
(31.4)
19.1
50.3
Total Conversion Costs .........
2021$ millions ...............................
................
9.6
9.6
33.5
56.1
69.4
lotter on DSK11XQN23PROD with PROPOSALS3
* Numbers in parentheses ‘‘( )’’ are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts
on INPV for LVDT distribution
transformer manufacturers to be
approximately ¥$5.4 million, which
corresponds to a change in INPV of –2.8
percent. At TSL 1, industry free cash
flow is estimated to decrease by
approximately 17.8 percent to $15.6
million, compared to the no-newstandard case value of $19.0 million in
2026, the year before the estimated
compliance date.
TSL 1 would set the energy
conservation standard at EL 1 for all
LVDT distribution transformers. DOE
estimates that approximately 22.7
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates LVDT
distribution transformer manufacturers
would spend approximately $9.6
million in product conversion costs to
redesign transformers but would not
have to make significant investments in
capital conversion costs as no LVDT
distribution transformer cores used are
expected to use amorphous steel.
At TSL 1, the shipment-weighted
average MPC for LVDT distribution
transformers does not increases relative
to the no-new-standards case shipmentweighted average MPC in 2027. The
preservation of gross margin percentage
scenario produces similar INPV results
as the preservation of operating profit
scenario due to the negligible change in
MPC at TSL 1. The change in IPNV is
driven exclusively by the $9.6 million
in conversion costs, causing a negative
change in INPV at TSL 1 under both
scenarios.
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At TSL 2, DOE estimates the impacts
on INPV for LVDT distribution
transformer manufacturers to range from
¥$5.9 million to ¥$4.9 million,
corresponding to a change in INPV of
¥2.8 percent to ¥2.5 percent. At TSL
2, industry free cash flow is estimated
to decrease by approximately 17.8
percent to $15.6 million, compared to
the no-new-standard case value of $19.0
million in 2026, the year before the
estimated compliance date.
TSL 2 would set the energy
conservation standard at EL 2 for all
LVDT distribution transformers. DOE
estimates that approximately 3.4 percent
of shipments would meet or exceed
these energy conservation standards in
the no-new-standards case in 2027. DOE
estimates LVDT distribution transformer
manufacturers would spend
approximately $9.6 million in product
conversion costs to redesign
transformers but would not have to
make significant investments in capital
conversion costs as no LVDT
distribution transformer cores used are
expected to use amorphous steel.
At TSL 2, the shipment-weighted
average MPC for LVDT distribution
transformers increases by 0.8 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The increase in shipmentweighted average MPC is outweighed by
the $9.6 million in conversion costs,
causing a negative change in INPV at
TSL 2 under the preservation of gross
margin percentage scenario.
Under the preservation of operating
profit scenario, the 0.8 percent
shipment-weighted average MPC
increase results in a reduction in the
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margin after the analyzed compliance
year. This reduction in the margin and
the $9.6 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 2 under
the preservation of operating profit
scenario.
At TSL 3, DOE estimates the impacts
on INPV for LVDT distribution
transformer manufacturers to range from
¥$27.0 million to ¥$16.9 million,
corresponding to a change in INPV of
¥13.9 percent to ¥8.7 percent. At TSL
3, industry free cash flow is estimated
to decrease by approximately 72.1
percent to $5.3 million, compared to the
no-new-standard case value of $19.0
million in 2026, the year before the
estimated compliance date.
TSL 3 would set the energy
conservation standard at EL 3 for all
LVDT distribution transformers. DOE
estimates that approximately 0.1 percent
of shipments would meet or exceed
these energy conservation standards in
the no-new-standards case in 2027. DOE
estimates LVDT distribution transformer
manufacturers would spend
approximately $14.5 million in product
conversion costs to redesign
transformers and approximately $19.1
million in capital conversion costs as
some LVDT distribution transformers
cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment-weighted
average MPC for LVDT distribution
transformers increases by 8.5 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The moderate increase in
shipment-weighted average MPC is
outweighed by the $33.5 million in
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conversion costs, causing a negative
change in INPV at TSL 3 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 8.5 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $33.5 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 3 under
the preservation of operating profit
scenario.
At TSL 4, DOE estimates the impacts
on INPV for LVDT distribution
transformer manufacturers to range from
¥$49.1 million to ¥$26.3 million,
corresponding to a change in INPV of
¥25.3 percent to ¥13.6 percent. At TSL
4, industry free cash flow is estimated
to decrease by approximately 123.2
percent to ¥$4.4 million, compared to
the no-new-standard case value of $19.0
million in 2026, the year before the
estimated compliance date.
TSL 4 would set the energy
conservation standard at EL 4 for all
LVDT distribution transformers. DOE
estimates that no shipments would meet
these energy conservation standards in
the no-new-standards case in 2027. DOE
estimates LVDT distribution transformer
manufacturers would spend
approximately $18.9 million in product
conversion costs to redesign all LVDT
transformers and approximately $37.2
million in capital conversion costs as
almost all LVDT distribution
transformer cores manufactured are
expected to use amorphous steel.
At TSL 4, the shipment-weighted
average MPC for LVDT distribution
transformers increases by 19.0 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The significant increase in
shipment-weighted average MPC is
outweighed by the $56.1 million in
conversion costs, causing a negative
change in INPV at TSL 4 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 19.0 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $56.1 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 4 under
the preservation of operating profit
scenario.
At TSL 5, DOE estimates the impacts
on INPV for LVDT distribution
transformer manufacturers to range from
¥$61.0 million to ¥$33.5 million,
corresponding to a change in INPV of
¥31.4 percent to ¥17.2 percent. At TSL
5, industry free cash flow is estimated
to decrease by approximately 154.4
percent to ¥$10.4 million, compared to
the no-new-standard case value of $19.0
million in 2026, the year before the
estimated compliance date.
TSL 5 would set the energy
conservation standard at EL 5, max-tech,
for all LVDT distribution transformers.
DOE estimates that no shipments would
meet these energy conservation
standards at TSL 5. DOE estimates
LVDT distribution transformer
manufacturers would spend
approximately $19.1 million in product
conversion costs to redesign all LVDT
distribution transformers and
approximately $37.2 million in capital
conversion costs as all LVDT
distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 5, the shipment-weighted
average MPC for LVDT distribution
transformers increases by 23.0 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The significant increase in
shipment-weighted average MPC is
outweighed by the $69.4 million in
conversion costs, causing a negative
change in INPV at TSL 5 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 23.0 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $69.4 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 5 under
the preservation of operating profit
scenario.
Medium-Voltage Dry-Type Distribution
Transformers
TABLE V.50—MANUFACTURER IMPACT ANALYSIS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF GROSS MARGIN PERCENTAGE MARKUP SCENARIO
No-newstandards
case
Units
INPV .............................................
Change in INPV ............................
Trial standard level
1
2
3
4
5
Product Conversion Costs ............
Capital Conversion Costs .............
2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
2021$ millions ...............................
87
................
................
................
................
85
(1.8)
(2.1)
3.1
0.0
86
(0.8)
(0.9)
3.1
0.0
80
(7.7)
(8.8)
6.0
11.9
80
(6.8)
(7.8)
6.1
13.1
82
(5.2)
(5.9)
6.2
15.1
Total Conversion Costs .........
2021$ millions ...............................
................
3.1
3.1
17.9
19.2
21.2
* Numbers in parentheses ‘‘()’’ are negative. Some numbers might not round due to rounding.
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.51—MANUFACTURER IMPACT ANALYSIS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF OPERATING PROFIT SCENARIO
No-newstandards
case
Units
INPV .............................................
Change in INPV ............................
Product Conversion Costs ............
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2021$ millions ...............................
2021$ millions ...............................
% ...................................................
2021$ millions ...............................
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Trial standard level
1
2
87
................
................
................
85
(1.9)
(2.1)
3.1
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85
(2.7)
(3.0)
3.1
11JAP3
3
4
5
71
(16.3)
(18.7)
6.0
69
(18.7)
(21.4)
6.1
65
(22.6)
(25.9)
6.2
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.51—MANUFACTURER IMPACT ANALYSIS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS—
PRESERVATION OF OPERATING PROFIT SCENARIO—Continued
No-newstandards
case
Units
Trial standard level
1
2
3
4
5
Capital Conversion Costs .............
2021$ millions ...............................
................
0.0
0.0
11.9
13.1
15.1
Total Conversion Costs .........
2021$ millions ...............................
................
3.1
3.1
17.9
19.2
21.2
lotter on DSK11XQN23PROD with PROPOSALS3
* Numbers in parentheses ‘‘( )’’ are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts
on INPV for MVDT distribution
transformer manufacturers to range from
¥$1.9 million to ¥$1.8 million, which
corresponds to a change in INPV of
approximately –2.1 percent in both
cases. At TSL 1, industry free cash flow
is estimated to decrease by
approximately 15.7 percent to $5.9
million, compared to the no-newstandard case value of $7.0 million in
2026, the year before the estimated
compliance date.
TSL 1 would set the energy
conservation standard at EL 1 for all
MVDT distribution transformers. DOE
estimates that approximately 21.2
percent of shipments would meet or
exceed these energy conservation
standards in the no-new-standards case
in 2027. DOE estimates MVDT
distribution transformer manufacturers
would spend approximately $3.1
million in product conversion costs to
redesign transformers but would not
have to make significant investments in
capital conversion costs as no MVDT
distribution transformer cores are
expected to use amorphous steel.
At TSL 1, the shipment-weighted
average MPC for MVDT distribution
transformers does not increases relative
to the no-new-standards case shipmentweighted average MPC in 2027. The
preservation of gross margin percentage
scenario produces similar INPV results
as the preservation of operating profit
scenario due to the negligible change in
MPC at TSL 1. The change in INPV is
almost exclusively driven by the $3.1
million in conversion costs, causing a
negative change in INPV at TSL 1 under
both scenarios.
At TSL 2, DOE estimates the impacts
on INPV for MVDT distribution
transformer manufacturers to range from
¥$2.7 million to ¥$0.8 million,
corresponding to a change in INPV of
¥3.0 percent to ¥0.9 percent. At TSL
2, industry free cash flow is estimated
to decrease by approximately 15.7
percent to $5.9 million, compared to the
no-new-standard case value of $7.0
million in 2026, the year before the
estimated compliance date.
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TSL 2 would set the energy
conservation standard at EL 2 for all
MVDT distribution transformers. DOE
estimates that approximately 4.2 percent
of shipments would meet or exceed
these energy conservation standards in
the no-new-standards case in 2027. DOE
estimates MVDT distribution
transformer manufacturers would spend
approximately $3.1 million in product
conversion costs to redesign
transformers but would not have to
make significant investments in capital
conversion costs as no MVDT
distribution transformer cores are
expected to use amorphous steel.
At TSL 2, the shipment-weighted
average MPC for MVDT distribution
transformers increases by 3.2 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The increase in shipmentweighted average MPC is outweighed by
the $3.1 million in conversion costs,
causing a negative change in INPV at
TSL 2 under the preservation of gross
margin percentage scenario.
Under the preservation of operating
profit scenario, the 3.2 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $3.1 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 2 under
the preservation of operating profit
scenario.
At TSL 3, DOE estimates the impacts
on INPV for MVDT distribution
transformer manufacturers to range from
¥$16.3 million to ¥$7.7 million,
corresponding to a change in INPV of
¥18.7 percent to ¥8.8 percent. At TSL
3, industry free cash flow is estimated
to decrease by approximately 107.1
percent to ¥$0.5 million, compared to
the no-new-standard case value of $7.0
million in 2026, the year before the
estimated compliance date.
TSL 3 would set the energy
conservation standard at EL 3 for all
MVDT distribution transformers. DOE
estimates that no shipments would meet
or exceed these energy conservation
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standards in the no-new-standards case
in 2027. DOE estimates MVDT
distribution transformer manufacturers
would spend approximately $6.0
million in product conversion costs to
redesign all MVDT distribution
transformers and approximately $11.9
million in capital conversion costs as
many MVDT distribution transformer
cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment-weighted
average MPC for MVDT distribution
transformers increases by 14.5 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The moderate increase in
shipment-weighted average MPC is
outweighed by the $17.9 million in
conversion costs, causing a negative
change in INPV at TSL 3 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 14.5 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $17.9 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 3 under
the preservation of operating profit
scenario.
At TSL 4, DOE estimates the impacts
on INPV for MVDT distribution
transformer manufacturers to range from
¥$18.7 million to ¥$6.8 million,
corresponding to a change in INPV of
¥21.4 percent to ¥7.8 percent. At TSL
4, industry free cash flow is estimated
to decrease by approximately 115.3
percent to ¥$1.1 million, compared to
the no-new-standard case value of $7.0
million in 2026, the year before the
estimated compliance date.
TSL 4 would set the energy
conservation standard at EL 4 for all
MVDT distribution transformers. DOE
estimates that no shipments would meet
these energy conservation standards in
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
the no-new-standards case in 2027. DOE
estimates MVDT distribution
transformer manufacturers would spend
approximately $6.1 million in product
conversion costs to redesign all MVDT
distribution transformers and
approximately $13.1 million in capital
conversion costs as most MVDT
distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 4, the shipment-weighted
average MPC for MVDT distribution
transformers increases by 20.0 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The significant increase in
shipment-weighted average MPC is
outweighed by the $19.2 million in
conversion costs, causing a negative
change in INPV at TSL 4 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 20.0 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $19.2 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 4 under
the preservation of operating profit
scenario.
At TSL 5, DOE estimates the impacts
on INPV for MVDT distribution
transformer manufacturers to range from
¥$22.6 million to ¥$5.2 million,
corresponding to a change in INPV of
–25.9 percent to ¥5.9 percent. At TSL
5, industry free cash flow is estimated
to decrease by approximately 128.4
percent to ¥$2.0 million, compared to
the no-new-standard case value of $7.0
million in 2026, the year before the
estimated compliance date.
TSL 5 would set the energy
conservation standard at EL 5, max-tech,
for all MVDT distribution transformers.
DOE estimates that no shipments would
meet these energy conservation
standards at TSL 5. DOE estimates
MVDT distribution transformer
manufacturers would spend
approximately $6.2 million in product
conversion costs to redesign all MVDT
distribution transformers and
approximately $15.1 million in capital
conversion costs as all MVDT
distribution transformer cores
manufactured are expected to use
amorphous steel.
At TSL 5, the shipment-weighted
average MPC for MVDT distribution
transformers increases by 29.4 percent
relative to the no-new-standards case
shipment-weighted average MPC in
2027. The significant increase in
shipment-weighted average MPC is
outweighed by the $21.2 million in
conversion costs, causing a negative
change in INPV at TSL 5 under the
preservation of gross margin percentage
scenario.
Under the preservation of operating
profit scenario, the 29.4 percent
shipment-weighted average MPC
increase results in a reduction in the
margin after the analyzed compliance
year. This reduction in the margin and
the $21.2 million in conversion costs
incurred by manufacturers cause a
negative change in INPV at TSL 5 under
the preservation of operating profit
scenario.
b. Direct Impacts on Employment
To quantitatively assess the potential
impacts of amended energy
conservation standards on direct
employment in the distribution
transformers industry, DOE used the
GRIM to estimate the domestic labor
expenditures and number of direct
employees in the no-new-standards case
and in each of the standards cases
(TSLs) during the analysis period.
Production employees are those who
are directly involved in fabricating and
assembling equipment within a
manufacturer facility. Workers
performing services that are closely
associated with production operations,
such as materials handling tasks using
forklifts, are included as production
labor, as well as line supervisors.
DOE used the GRIM to calculate the
number of production employees from
labor expenditures. DOE used statistical
data from the U.S. Census Bureau’s 2019
Annual Survey of Manufacturers
(‘‘ASM’’) and the results of the
engineering analysis to calculate
industry-wide labor expenditures. Labor
expenditures related to equipment
manufacturing depend on the labor
intensity of the product, the sales
volume, and an assumption that wages
remain fixed in real terms over time.
The total labor expenditures in the
GRIM were then converted to domestic
production employment levels by
dividing production labor expenditures
by the annual payment per production
worker.
Non-production employees account
for those workers that are not directly
engaged in the manufacturing of the
covered equipment. This could include
sales, human resources, engineering,
and management. DOE estimated nonproduction employment levels by
multiplying the number of distribution
transformer workers by a scaling factor.
The scaling factor is calculated by
taking the ratio of the total number of
employees, and the total production
workers associated with the industry
NAICS code 335311, which covers
power, distribution, and specialty
transformer manufacturing.
Using data from manufacturer
interviews and estimated market share
data, DOE estimates that approximately
85 percent of all liquid-immersed
distribution transformer manufacturing;
15 percent of all LVDT distribution
transformer manufacturing; and 75
percent of all MVDT distribution
transformer manufacturing takes place
domestically.
Liquid-Immersed Distribution
Transformers
TABLE V.52—DOMESTIC EMPLOYMENT FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS IN 2027
lotter on DSK11XQN23PROD with PROPOSALS3
No-newstandards
case
Trial standard level
1
2
3
4
5
Domestic Production Workers in 2027 ....
Domestic Non-Production Workers in
2027 ......................................................
5,164
5,193
5,251
5,453
5,624
6,885
1,830
1,840
1,861
1,932
1,993
2,440
Total Direct Employment in 2027 .....
Potential Changes in Total Direct Employment in 2027 ..................................
6,994
7,033
7,112
7,385
7,617
9,325
........................
(874)–39
(1,180)–118
(1,506)–391
(1,549)–623
(1,549)–2,331
Using the estimated labor content
from the GRIM combined with data
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from the 2019 ASM, DOE estimates that
there would be approximately 5,164
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domestic production workers, and 1,830
domestic non-production workers
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
increases, which causes the number of
direct employees to also increase. The
lower range of the ‘‘Potential Change in
Total Direct Employment in 2027’’
displayed in Table V.52, assumes that as
more amorphous cores are used to meet
higher energy conservation standards,
either the amorphous core production is
out-sourced to core only manufacturers
(manufacturers that specialize in
manufacturing cores used in
distribution transformers, but do not
actually manufacture entire distribution
transformers) which may be located in
foreign countries, or distribution
transformer manufacturing is re-located
to foreign countries. This lower range
assumes that 30 percent of distribution
transformers using amorphous cores are
re-located to foreign countries due to the
energy conservation standard. DOE
acknowledges that each distribution
transformer manufacturer would
individually make a business decision
involved in liquid-immersed
distribution transformer manufacturing
in 2027 in the absence of amended
energy conservation standards. Table
V.52 shows the range of the impacts of
energy conservation standards on U.S.
production on liquid-immersed
distribution transformers.
Amorphous core production is more
labor intensive and would require
additional labor expenditures. The
upper range of the ‘‘Potential Change in
Total Direct Employment in 2027’’
displayed in Table V.52, assumes that
all domestic liquid-immersed
distribution transformer manufacturing
remains in the U.S. For this scenario,
the additional labor expenditures
associated with amorphous core
production result in the number of total
direct employees to increase due to
energy conservation standards. At
higher TSLs, the estimated number of
amorphous cores used in liquidimmersed distribution transformers
to either make the substantial
investments to add or increase their
own amorphous core production
capabilities and continue to
manufacturer their own cores in-house;
outsource their amorphous core
production to another distribution core
manufacturer, which may or may not be
located in the U.S.; or re-locate some or
all of their distribution transformer
manufacturing to a foreign country. DOE
acknowledges there is a wide range of
potential domestic employment impacts
due to energy conservation standards,
especially at the higher TSLs. The
ranges in potential employment impacts
displayed in Table V.52 at each TSL
attempt to provide a reasonable upper
and lower bound to how liquidimmersed distribution transformer
manufacturers may respond to potential
energy conservation standards.
Low-Voltage Dry-Type Distribution
Transformers
TABLE V.53—DOMESTIC EMPLOYMENT FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS IN 2027
No-newstandards
case
Trial standard level
1
2
3
4
5
Domestic Production Workers in 2027 ....
Domestic Non-Production Workers in
2027 ......................................................
169
169
170
183
201
208
60
60
60
65
71
74
Total Direct Employment in 2027 .....
Potential Changes in Total Direct Employment in 2027 ..................................
229
229
230
248
272
282
........................
0
0–1
(28)–19
(49)–43
(51)–53
Using the estimated labor content
from the GRIM combined with data
from the 2019 ASM, DOE estimates that
there would be approximately 169
domestic production workers, and 60
domestic non-production workers
involved in LVDT distribution
transformer manufacturing in 2027 in
the absence of amended energy
conservation standards. Table V.53
shows the range of the impacts of energy
conservation standards on U.S.
production on LVDT distribution
transformers.
DOE used the same methodology to
estimate the potential impacts to
domestic employment for LVDT
distribution transformer manufacturing
that was used for liquid-immersed
distribution transformer manufacturing.
The upper range of the ‘‘Potential
Change in Total Direct Employment in
2027’’ displayed in Table V.53, assumes
that all LVDT distribution transformer
manufacturing remains in the U.S. The
lower range of the ‘‘Potential Change in
Total Direct Employment in 2027’’,
assumes that 30 percent of distribution
transformers using amorphous cores are
re-located to foreign countries, either
due to amorphous core production that
is outsourced to core only
manufacturers located in foreign
countries or LVDT distribution
transformer manufacturers re-locating
their distribution transformer
production to foreign countries.
Medium-Voltage Dry-Type Distribution
Transformers
TABLE V.54—DOMESTIC EMPLOYMENT FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS IN 2027
lotter on DSK11XQN23PROD with PROPOSALS3
No-new-standards case
Trial standard level
1
2
3
4
5
Domestic Production Workers in 2027 ....
Domestic Non-Production Workers in
2027 ......................................................
275
275
284
315
330
356
98
98
101
112
117
126
Total Direct Employment in 2027 .....
Potential Changes in Total Direct Employment in 2027 ..................................
373
373
385
427
447
482
........................
0
0–12
(63)–54
(69)–74
(83)–109
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
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Using the estimated labor content
from the GRIM combined with data
from the 2019 ASM, DOE estimates that
there would be approximately 275
domestic production workers, and 98
domestic non-production workers
involved in MVDT distribution
transformer manufacturing in 2027 in
the absence of amended energy
conservation standards. Table V.54
shows the range of the impacts of energy
conservation standards on U.S.
production on MVDT distribution
transformers.
DOE used the same methodology to
estimate the potential impacts to
domestic employment for MVDT
distribution transformer manufacturing
that was used for liquid-immersed
distribution transformer manufacturing.
The upper range of the ‘‘Potential
Change in Total Direct Employment in
2027’’ displayed in Table V.54, assumes
that all MVDT distribution transformer
manufacturing remains in the U.S. The
lower range of the ‘‘Potential Change in
Total Direct Employment in 2027’’,
assumes that 30 percent of distribution
transformers using amorphous cores are
re-located to foreign countries, either
due to amorphous core production that
is outsourced to core only
manufacturers located in foreign
countries or MVDT distribution
transformer manufacturers re-locating
their distribution transformer
production to foreign countries.
DOE requests comment on the
estimated potential domestic
employment impacts on distribution
transformer manufacturers presented in
this NOPR.
c. Impacts on Manufacturing Capacity
The prices of raw materials currently
used in distribution transformers, such
as GOES, copper, and aluminum, have
all experienced a significant increase in
price starting at the beginning of 2021.
The availability of these commodities
remains a significant concern with
distribution transformer manufacturers.
As previously stated in IV.J.3.a, steel
producers are shifting production away
from GOES suited for distribution
transformer core manufacturing to nongrain-oriented steels suited for electric
vehicle production. However,
amorphous steel has not seen the same
significant increase in price as GOES
since the beginning of 2021.
The availability of amorphous steel is
a concern for many distribution
transformer manufacturers. Based on
information received during
manufacturer interviews some
distribution transformer manufacturers
suggested that there would not be
enough amorphous steel available to be
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used in all or even most distribution
transformers currently sold in the U.S.
Other distribution transformer
manufacturers and steel suppliers
interviewed stated that, while the
current capacity of amorphous steel
does not exist to supply the majority of
the steel used in distribution
transformer cores, steel manufacturers
are capable of significantly increasing
their amorphous steel production if
there is sufficient market demand for
amorphous steel.
While the availability of both GOES
and amorphous steel is a concern for
many distribution transformer
manufacturers, steel suppliers should be
able to meet the market demand for
amorphous steel for all TSLs analyzed
given the three-year compliance period
for distribution transformers. Steel
manufacturers should be able to
significantly increase their supply of
amorphous steel if they know there will
be an increase in the demand for this
material due to energy conservation
standards for distribution transformers.
See section V.C for a more detailed
discussion of the global supply of steel.
DOE requests comment on the
potential availability of either
amorphous steel, grain-oriented
electrical steel, or any other materials
that may be needed to meet any of the
analyzed energy conservation standards
in this rulemaking. More specifically,
DOE requests comment on steel
manufacturers’ ability to increase
supply of amorphous steel in reaction to
increased demand for amorphous steel
as a result of increased energy
conservation standards for distribution
transformers.
d. Impacts on Competition
EPCA directs DOE to consider any
lessening of competition that is likely to
result from imposition of standards. It
further directs the Attorney General to
determine the impacts, if any, of any
lessening of competition. The
competitive analysis includes an
assessment of the impacts to smaller, yet
significant, manufacturers. DOE bases
its assessment on manufacturing cost
data and on information collected from
interviews with manufacturers. The
manufacturer interviews focus on
gathering information that would help
in assessing asymmetrical cost increases
to some manufacturers, increased
proportion of fixed costs potentially
increasing business risks, and potential
barriers to market entry (e.g., proprietary
technologies).
As discussed in section IV.J.3, DOE
interviewed a wide variety of
distribution transformer manufacturers,
including liquid-immersed distribution
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1817
transformer manufacturers, LVDT
distribution transformer manufacturers,
MVDT distribution transformer
manufacturers, small businesses, and
steel suppliers. During these
manufacturer interviews DOE asked
manufacturers if energy conservation
standards could result in a change in
industry competition. Some
manufacturers stated that there is a
possibility that smaller manufacturers
may exit the market or their market
share may decrease, if these businesses
are not able to make the investments to
upgrade their production equipment or
to create new equipment designs in
order to comply with energy
conservation standards. See section
VI.B, for a complete discussion on the
potential impacts to small businesses.
Based on the market and technology
assessment conducted for this NOPR
analysis, DOE identified 29
manufacturers of distribution
transformers covered by this
rulemaking. See chapter 3 of this NOPR
TSD for a complete list of the
distribution transformer manufacturers.
The distribution transformer market has
a handful of major manufacturers for
each equipment type (i.e., liquidimmersed, LVDT, MVDT). Transformer
core sourcing is a major driver of
transformer manufacturing strategy and
competitiveness which may be
impacted by the standards level.
Typically, manufacturers with larger
market shares produce most of their
own cores and manufacturers with
smaller market shares purchase the
cores used in their distribution
transformers. The Department does not
believe the proposed standard will alter
current core make-versus-buy decisions.
The Department expects that
manufacturers with larger market shares
will make the large investments needed
to convert their core production to
amorphous steel. Manufacturers with
smaller market shares that do not invest
in amorphous core manufacturing will
continue to have the option to source
their cores. DOE does not anticipate a
significant change in competition due to
energy conservation standards as the
business model and competitive
position for most distribution
transformer manufacturers will remain
the same after compliance with energy
conservation standards.
e. Impacts on Subgroups of
Manufacturers
As discussed in section IV.J.1 of this
document, using average cost
assumptions to develop an industry
cash-flow estimate may not be adequate
for assessing differential impacts among
manufacturer subgroups. Small
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manufacturers, niche manufacturers,
and manufacturers exhibiting a cost
structure substantially different from the
industry average could be affected
disproportionately. DOE used the
results of the industry characterization
to group manufacturers exhibiting
similar characteristics. Consequently,
DOE considered four manufacturer
subgroups in the MIA: liquid-immersed,
LVDT, MVDT, and small manufacturers
as a subgroup for a separate impact
analysis. DOE discussed the potential
impacts on liquid-immersed, LVDT, and
MVDT distribution transformer
manufacturers separately in sections
V.B.2.a and V.B.2.b.
For the small business subgroup
analysis, DOE applied the small
business size standards published by
the Small Business Administration
(‘‘SBA’’) to determine whether a
company is considered a small business.
The size standards are codified at 13
CFR part 121. To be categorized as a
small business under NAICS code
335311, ‘‘power, distribution, and
specialty transformer manufacturing,’’ a
distribution transformer manufacturer
and its affiliates may employ a
maximum of 750 employees. The 750employee threshold includes all
employees in a business’s parent
company and any other subsidiaries.
For a discussion of the impacts on the
small manufacturer subgroup, see the
Regulatory Flexibility Analysis in
section VI.B.
f. Cumulative Regulatory Burden
One aspect of assessing manufacturer
burden involves looking at the
cumulative impact of multiple DOE
standards and the product-specific
regulatory actions of other Federal
agencies that affect the manufacturers of
a covered product or equipment. While
any one regulation may not impose a
significant burden on manufacturers,
the combined effects of several existing
or impending regulations may have
serious consequences for some
manufacturers, groups of manufacturers,
or an entire industry. Assessing the
impact of a single regulation may
overlook this cumulative regulatory
burden. In addition to energy
conservation standards, other
regulations can significantly affect
manufacturers’ financial operations.
Multiple regulations affecting the same
manufacturer can strain profits and lead
companies to abandon product lines or
markets with lower expected future
returns than competing products. For
these reasons, DOE conducts an analysis
of cumulative regulatory burden as part
of its rulemakings pertaining to
appliance efficiency. DOE requests
information regarding the impact of
cumulative regulatory burden on
manufacturers of distribution
transformers associated with multiple
DOE standards or product-specific
regulatory actions of other Federal
agencies.
DOE evaluates product-specific
regulations that will take effect
approximately 3 years before or after the
estimated 2027 compliance date of any
amended energy conservation standards
for distribution transformers. This
information is presented in Table V.55.
TABLE V.55—COMPLIANCE DATES AND EXPECTED CONVERSION EXPENSES OF FEDERAL ENERGY CONSERVATION
STANDARDS AFFECTING DISTRIBUTION TRANSFORMER MANUFACTURERS
Number of
manufacturers *
Federal energy conservation standard
Dedicated-Purpose Pool Pump Motors, 87 FR 37122
(June 21, 2022) ............................................................
Number of
manufacturers
affected from
this rule **
Approx.
standards year
1
2026
5
Industry
conversion
costs
(millions)
Industry
conversion
costs/product
revenue ***
$46.2
(2020$)
2.8%
* This column presents the total number of manufacturers identified in the energy conservation standard rule contributing to cumulative regulatory burden.
** This column presents the number of manufacturers producing distribution transformers that are also listed as manufacturers in the listed energy conservation standard contributing to cumulative regulatory burden.
*** This column presents industry conversion costs as a percentage of product revenue during the conversion period. Industry conversion costs
are the upfront investments manufacturers must make to sell compliant products/equipment. The revenue used for this calculation is the revenue
from just the covered product/equipment associated with each row. The conversion period is the time frame over which conversion costs are
made and lasts from the publication year of the final rule to the compliance year of the energy conservation standard. The conversion period
typically ranges from 3 to 5 years, depending on the rulemaking.
In addition to the rulemaking listed in
Table V.55, DOE has ongoing
rulemakings for other products or
equipment that distribution transformer
manufacturers produce, including
battery chargers; 103 external power
supplies; 104 ceiling fan light kits; 105
electric motors; 106 residential
conventional cooking products; 107
lotter on DSK11XQN23PROD with PROPOSALS3
103 www.regulations.gov/docket/EERE-2008-BT-
STD-0005.
104 www.regulations.gov/docket/EERE-2020-BTSTD-0006.
105 www.regulations.gov/docket/EERE-2019-BTSTD-0040.
106 www.regulations.gov/docket/EERE-2020-BTSTD-0007.
107 www.regulations.gov/docket/EERE-2014-BTSTD-0005.
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dishwashers; 108 dehumidifiers; 109
miscellaneous refrigeration products; 110
and residential clothes washers.111 If
DOE proposes or finalizes any energy
conservation standards for these
products or equipment prior to
finalizing energy conservation standards
for distribution transformers, DOE will
include the energy conservation
standards for these other products or
equipment as part of the cumulative
108 www.regulations.gov/docket/EERE-2019-BTSTD-0039.
109 www.regulations.gov/docket/EERE-2019-BTSTD-0043.
110 www.regulations.gov/docket/EERE-2020-BTSTD-0039.
111 www.regulations.gov/docket/EERE-2017-BTSTD-0014.
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regulatory burden for the distribution
transformers final rule.
3. National Impact Analysis
This section presents DOE’s estimates
of the national energy savings and the
NPV of consumer benefits that would
result from each of the TSLs considered
as potential amended standards.
a. Significance of Energy Savings
To estimate the energy savings
attributable to potential amended
standards for distribution transformers,
DOE compared their energy
consumption under the no-newstandards case to their anticipated
energy consumption under each TSL.
The savings are measured over the
entire lifetime of products purchased in
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the 30-year period that begins in the
first full year of anticipated compliance
with amended standards (2027–2056).
Table V.56 presents DOE’s projections
of the national energy savings for each
TSL considered for distribution
transformers, the results showing DOE’s
proposed standard are in bold. Savings
are reported for each of the equipment
classes as defined in Section IV.A.2. The
savings were calculated using the
approach described in section IV.H of
this document.
TABLE V.56—CUMULATIVE NATIONAL ENERGY SOURCES FOR DISTRIBUTION TRANSFORMERS BY EQUIPMENT CLASS; 30
YEARS OF SHIPMENT, (2027–2056)
Standard level
1
2
3
4
5
Primary Energy Savings (Quads)
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
2.16
0.91
n.a.
3.16
1.65
n.a.
4.45
2.63
n.a.
4.75
2.97
n.a.
4.89
3.17
0.08
Liquid-Immersed Total ...........................................
3.06
4.80
7.09
7.72
8.14
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.02
0.34
0.03
0.48
0.05
0.77
0.09
2.10
0.12
2.25
Low-Voltage Dry-Type Total ..................................
0.35
0.52
0.82
2.19
2.37
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.00
0.00
0.00
0.05
0.00
0.02
0.00
0.00
0.00
0.07
0.00
0.04
0.00
0.01
0.00
0.23
0.00
0.14
0.00
0.02
0.00
0.29
0.00
0.19
0.00
0.03
0.00
0.35
0.00
0.22
Medium-Voltage Dry-Type Total ...........................
0.08
0.11
0.39
0.51
0.61
lotter on DSK11XQN23PROD with PROPOSALS3
FFC Energy Savings (Quads)
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
2.24
0.94
0.00
3.28
1.71
0.00
4.63
2.73
0.00
4.94
3.08
0.00
5.08
3.29
0.09
Liquid-Immersed Total ...........................................
3.18
4.99
7.36
8.02
8.45
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.02
0.35
0.03
0.50
0.05
0.80
0.09
2.19
0.12
2.34
Low-Voltage Dry-Type Total ..................................
0.37
0.54
0.85
2.28
2.47
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.00
0.00
0.00
0.05
0.00
0.02
0.00
0.00
0.00
0.07
0.00
0.04
0.00
0.01
0.00
0.24
0.00
0.15
0.00
0.02
0.00
0.30
0.00
0.20
0.00
0.03
0.00
0.36
0.00
0.23
Medium-Voltage Dry-Type Total ...........................
0.08
0.12
0.40
0.53
0.63
OMB Circular A–4 112 requires
agencies to present analytical results,
including separate schedules of the
monetized benefits and costs that show
the type and timing of benefits and
112 U.S. Office of Management and Budget.
Circular A–4: Regulatory Analysis. September 17,
2003. https://www.whitehouse.gov/wp-content/
uploads/legacy_drupal_files/omb/circulars/A4/a4.pdf (last accessed August 26, 2022).
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costs. Circular A–4 also directs agencies
to consider the variability of key
elements underlying the estimates of
benefits and costs. For this rulemaking,
DOE undertook a sensitivity analysis
using 9 years, rather than 30 years, of
product shipments. The choice of a 9year period is a proxy for the timeline
in EPCA for the review of certain energy
conservation standards and potential
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revision of and compliance with such
revised standards.113 The review
113 Section 325(m) of EPCA requires DOE to
review its standards at least once every 6 years, and
requires, for certain products, a 3-year period after
any new standard is promulgated before
compliance is required, except that in no case may
any new standards be required within 6 years of the
compliance date of the previous standards. While
adding a 6-year review to the 3-year compliance
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timeframe established in EPCA is
generally not synchronized with the
product lifetime, product manufacturing
cycles, or other factors specific to
distribution transformers. Thus, such
results are presented for informational
lifetime of distribution transformers
purchased in 2027–2036, the results
showing DOE’s proposed standard are
in bold.
purposes only and are not indicative of
any change in DOE’s analytical
methodology. The NES sensitivity
analysis results based on a 9-year
analytical period are presented in Table
V.57. The impacts are counted over the
TABLE V.57—CUMULATIVE NATIONAL ENERGY SAVINGS FOR DISTRIBUTION TRANSFORMERS; 9 YEARS OF SHIPMENTS,
(2027–2036)
Standard level
1
2
3
4
5
Primary Energy Savings (Quads)
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
0.62
0.26
n.a.
0.90
0.47
n.a.
1.27
0.75
n.a.
1.36
0.85
n.a.
1.39
0.90
0.02
Liquid-Immersed Total ...........................................
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.87
1.37
2.02
2.20
2.32
0.00
0.10
0.01
0.14
0.01
0.22
0.02
0.60
0.03
0.64
Low-Voltage Dry-Type Total ..................................
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.10
0.15
0.23
0.63
0.68
0.00
0.00
0.00
0.01
0.00
0.01
0.00
0.00
0.00
0.02
0.00
0.01
0.00
0.00
0.00
0.07
0.00
0.04
0.00
0.01
0.00
0.08
0.00
0.05
0.00
0.01
0.00
0.10
0.00
0.06
Medium-Voltage Dry-Type Total ...........................
0.02
0.03
0.11
0.14
0.17
0.64
0.27
n.a.
0.93
0.49
n.a.
1.32
0.78
n.a.
1.41
0.88
n.a.
1.45
0.94
0.03
Liquid-Immersed Total ...........................................
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.91
1.42
2.10
2.29
2.41
0.00
0.10
0.01
0.14
0.01
0.23
0.03
0.62
0.04
0.67
Low-Voltage Dry-Type Total ..................................
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.11
0.15
0.24
0.65
0.70
0.00
0.00
0.00
0.02
0.00
0.01
0.00
0.00
0.00
0.02
0.00
0.01
0.00
0.00
0.00
0.07
0.00
0.04
0.00
0.01
0.00
0.09
0.00
0.06
0.00
0.01
0.00
0.10
0.00
0.07
Medium-Voltage Dry-Type Total ...........................
0.02
0.03
0.12
0.15
0.18
FFC Energy Savings (Quads)
Liquid-Immersed:
Equipment Class 1 ...............................................................
Equipment Class 2 ...............................................................
Equipment Class 12 .............................................................
lotter on DSK11XQN23PROD with PROPOSALS3
b. Net Present Value of Consumer Costs
and Benefits
DOE estimated the cumulative NPV of
the total costs and savings for
consumers that would result from the
TSLs considered for distribution
transformers. In accordance with OMB’s
guidelines on regulatory analysis,114
DOE calculated NPV using both a 7percent and a 3-percent real discount
rate. Table V.58 shows the consumer
NPV results with impacts counted over
the lifetime of products purchased in
2027–2056, the results showing DOE’s
proposed standard are in bold.
period adds up to 9 years, DOE notes that it may
undertake reviews at any time within the 6 year
period and that the 3-year compliance date may
yield to the 6-year backstop. A 9-year analysis
period may not be appropriate given the variability
that occurs in the timing of standards reviews and
the fact that for some products, the compliance
period is 5 years rather than 3 years.
114 U.S. Office of Management and Budget.
Circular A–4: Regulatory Analysis. September 17,
2003. www.whitehouse.gov/omb/circulars_a004_a4/ (last accessed April 15, 2022).
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TABLE V.58—CUMULATIVE NET PRESENT VALUE OF CONSUMER BENEFITS FOR DISTRIBUTION TRANSFORMERS; 30 YEARS
OF SHIPMENTS, BILLION 2021$, (2027–2056)
Standard level
1
2
3
4
5
3 percent Discount Rate
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
2.55
0.43
n.a.
3.34
0.81
n.a.
4.00
1.50
n.a.
3.45
1.84
n.a.
¥4.04
¥2.10
¥0.10
Liquid-Immersed Total ...........................................
2.98
4.15
5.50
5.30
¥6.25
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.07
1.41
0.13
1.98
0.15
1.72
0.31
9.41
0.52
9.11
Low-Voltage Dry-Type Total ..................................
1.48
2.11
1.87
9.72
9.63
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.00
0.01
0.00
0.25
0.00
0.00
0.00
0.01
0.00
0.22
0.00
¥0.02
0.00
0.02
0.00
0.76
0.00
0.46
0.00
0.02
0.01
0.77
0.00
0.50
0.01
0.04
0.01
0.54
0.00
0.36
Medium-Voltage Dry-Type Total ...........................
0.26
0.21
1.25
1.30
0.96
7 percent Discount Rate
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
0.78
0.00
n.a.
0.94
0.06
n.a.
0.82
0.07
n.a.
0.24
0.01
n.a.
¥4.41
¥2.60
¥0.10
Liquid-Immersed Total ...........................................
0.78
1.00
0.89
0.26
¥7.11
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.02
0.50
0.04
0.70
0.04
0.35
0.07
2.72
0.13
2.50
Low-Voltage Dry-Type Total ..................................
0.53
0.74
0.39
2.79
2.63
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.00
0.00
0.00
0.10
0.00
0.01
0.00
0.00
0.00
0.07
0.00
¥0.04
0.00
0.00
0.00
0.18
0.00
0.08
0.00
0.00
0.00
0.15
0.00
0.08
0.00
0.00
0.00
0.01
0.00
0.00
Medium-Voltage Dry-Type Total ...........................
0.09
0.04
0.27
0.23
0.00
The NPV results based on the
aforementioned 9-year analytical period
are presented in Table V.59. The
impacts are counted over the lifetime of
products purchased in 2027–2036. As
mentioned previously, such results are
presented for informational purposes
only and are not indicative of any
change in DOE’s analytical methodology
or decision criteria.
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.59—CUMULATIVE NET PRESENT VALUE OF CONSUMER BENEFITS FOR DISTRIBUTION TRANSFORMERS; 9 YEARS
OF SHIPMENTS, BILLION 2021$, (2027–2036)
Standard level
1
2
3
4
5
3 percent Discount Rate
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
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¥0.78
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.59—CUMULATIVE NET PRESENT VALUE OF CONSUMER BENEFITS FOR DISTRIBUTION TRANSFORMERS; 9 YEARS
OF SHIPMENTS, BILLION 2021$, (2027–2036)—Continued
Standard level
1
2
3
4
5
Equipment Class 12 .....................................................
n.a.
n.a.
n.a.
n.a.
¥0.04
Liquid-Immersed Total ...........................................
1.16
1.62
2.15
2.09
¥2.32
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.03
0.55
0.05
0.77
0.06
0.68
0.12
3.69
0.20
3.57
Low-Voltage Dry-Type Total ..................................
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.58
0.82
0.74
3.81
3.77
0.00
0.00
0.00
0.10
0.00
0.00
0.00
0.00
0.00
0.09
0.00
¥0.01
0.00
0.01
0.00
0.30
0.00
0.18
0.00
0.01
0.00
0.30
0.00
0.20
0.00
0.02
0.00
0.22
0.00
0.15
Medium-Voltage Dry-Type Total ...........................
0.10
0.08
0.49
0.51
0.39
0.40
0.00
n.a.
0.49
0.03
n.a.
0.43
0.04
n.a.
0.14
0.02
n.a.
¥2.24
¥1.32
¥0.05
Liquid-Immersed Total ...........................................
Low-Voltage Dry-Type:
Equipment Class 3 .......................................................
Equipment Class 4 .......................................................
0.41
0.52
0.48
0.15
¥3.61
0.01
0.26
0.02
0.36
0.02
0.19
0.04
1.43
0.07
1.32
Low-Voltage Dry-Type Total ..................................
0.27
0.39
0.21
1.46
1.38
Medium-Voltage Dry-Type:
Equipment Class 5 .......................................................
Equipment Class 6 .......................................................
Equipment Class 7 .......................................................
Equipment Class 8 .......................................................
Equipment Class 9 .......................................................
Equipment Class 10 .....................................................
0.00
0.00
0.00
0.05
0.00
¥0.01
0.00
0.00
0.00
0.04
0.00
¥0.02
0.00
0.00
0.00
0.10
0.00
0.05
0.00
0.00
0.00
0.08
0.00
0.04
0.00
0.00
0.00
0.01
0.00
0.00
Medium-Voltage Dry-Type Total ...........................
0.04
0.02
0.14
0.12
0.01
7 percent Discount Rate
lotter on DSK11XQN23PROD with PROPOSALS3
Liquid-Immersed:
Equipment Class 1 .......................................................
Equipment Class 2 .......................................................
Equipment Class 12 .....................................................
The previous results reflect the use of
a default trend to estimate the change in
price for distribution transformers over
the analysis period (see section IV.F.1 of
this document). DOE also conducted a
sensitivity analysis that considered one
scenario with a lower rate of price
decline than the reference case and one
scenario with a higher rate of price
decline than the reference case. The
results of these alternative cases are
presented in appendix 10C of the NOPR
TSD. In the high-price-decline case, the
NPV of consumer benefits is higher than
in the default case. In the low-pricedecline case, the NPV of consumer
benefits is lower than in the default
case.
c. Indirect Impacts on Employment
It is estimated that that amended
energy conservation standards for
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distribution transformers would reduce
energy expenditures for consumers of
those products, with the resulting net
savings being redirected to other forms
of economic activity. These expected
shifts in spending and economic activity
could affect the demand for labor. As
described in section IV.N of this
document, DOE used an input/output
model of the U.S. economy to estimate
indirect employment impacts of the
TSLs that DOE considered. There are
uncertainties involved in projecting
employment impacts, especially
changes in the later years of the
analysis. Therefore, DOE generated
results for near-term timeframes (2027–
2031), where these uncertainties are
reduced.
The results suggest that the proposed
standards would be likely to have a
negligible impact on the net demand for
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labor in the economy. The net change in
jobs is so small that it would be
imperceptible in national labor statistics
and might be offset by other,
unanticipated effects on employment.
Chapter 16 of the NOPR TSD presents
detailed results regarding anticipated
indirect employment impacts.
4. Impact on Utility or Performance of
Products
As discussed in section IV.C.1.b of
this document, DOE has tentatively
concluded that the standards proposed
in this NOPR would not lessen the
utility or performance of the
distribution transformers under
consideration in this rulemaking.
Manufacturers of these products
currently offer units that meet or exceed
the proposed standards.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
5. Impact of Any Lessening of
Competition
DOE considered any lessening of
competition that would be likely to
result from new or amended standards.
As part of this consideration, DOE
weighed the effects on markets for both
component parts (see IV.C.3.a) and
distribution transformer equipment (see
IV.A.6). DOE’s preliminary finding is
that this rule, if finalized as proposed,
would not significantly affect
competition in the market for
distribution transformers. See section
V.B.5 for a complete discussion on
industry competition. As discussed in
section III.E.1.e, the Attorney General
determines the impact, if any, of any
lessening of competition likely to result
from a proposed standard, and transmits
such determination in writing to the
Secretary, together with an analysis of
the nature and extent of such impact. To
assist the Attorney General in making
this determination, DOE has provided
DOJ with copies of this NOPR and the
accompanying TSD for review. DOE will
consider DOJ’s comments on the
proposed rule in determining whether
to proceed to a final rule. DOE will
publish and respond to DOJ’s comments
in that document. DOE invites comment
from the public regarding the
competitive impacts that are likely to
result from this proposed rule. In
addition, stakeholders may also provide
comments separately to DOJ regarding
these potential impacts. See the
ADDRESSES section for information to
send comments to DOJ.
6. Need of the Nation to Conserve
Energy
Enhanced energy efficiency, where
economically justified, improves the
Nation’s energy security, strengthens the
economy, and reduces the
environmental impacts (costs) of energy
production. Reduced electricity demand
due to energy conservation standards is
also likely to reduce the cost of
maintaining the reliability of the
electricity system, particularly during
peak-load periods. Chapter 15 in the
NOPR TSD presents the estimated
impacts on electricity generating
capacity, relative to the no-newstandards case, for the TSLs that DOE
considered in this rulemaking.
Energy conservation resulting from
potential energy conservation standards
for distribution transformers is expected
to yield environmental benefits in the
form of reduced emissions of certain air
pollutants and greenhouse gases. Table
V.60 through Table V.63 provides DOE’s
estimate of cumulative emissions
reductions expected to result from the
TSLs considered in this rulemaking.
The emissions were calculated using the
multipliers discussed in section IV.K.
DOE reports annual emissions
reductions for each TSL in chapter 13 of
the NOPR TSD.
TABLE V.60—CUMULATIVE EMISSIONS REDUCTION FOR ALL DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056 AT
PROPOSED STANDARD LEVELS
Power Sector Emissions
CO2 (million metric tons) .........................................................................................................................................................
CH4 (thousand tons) ................................................................................................................................................................
N2O (thousand tons) ................................................................................................................................................................
NOX (thousand tons) ...............................................................................................................................................................
SO2 (thousand tons) ................................................................................................................................................................
Hg (tons) ..................................................................................................................................................................................
312.0
21.3
2.9
146.0
129.2
0.8
Upstream Emissions
CO2 (million metric tons) .........................................................................................................................................................
CH4 (thousand tons) ................................................................................................................................................................
N2O (thousand tons) ................................................................................................................................................................
NOX (thousand tons) ...............................................................................................................................................................
SO2 (thousand tons) ................................................................................................................................................................
Hg (tons) ..................................................................................................................................................................................
25.5
2419.9
0.1
386.9
1.7
0.0
Total FFC Emissions
CO2 (million metric tons) .........................................................................................................................................................
CH4 (thousand tons) ................................................................................................................................................................
N2O (thousand tons) ................................................................................................................................................................
NOX (thousand tons) ...............................................................................................................................................................
SO2 (thousand tons) ................................................................................................................................................................
Hg (tons) ..................................................................................................................................................................................
337.6
2441.2
3.0
532.9
130.9
0.9
Negative values refer to an increase in emissions.
TABLE V.61—CUMULATIVE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS FOR LIQUID-IMMERSED
DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056
lotter on DSK11XQN23PROD with PROPOSALS3
Trial standard level
1
2
3
4
5
Power Sector Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
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217.7
14.8
2.0
101.9
90.5
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16.2
2.2
110.9
98.4
249.4
17.0
2.3
116.7
103.5
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.61—CUMULATIVE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS FOR LIQUID-IMMERSED
DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056—Continued
Trial standard level
1
2
Hg (tons) ..............................................................................
0.3
3
4
5
0.4
0.6
0.6
0.7
12.0
1139.8
0.1
182.2
0.8
0.0
17.7
1680.6
0.1
268.7
1.2
0.0
19.3
1830.4
0.1
292.7
1.3
0.0
20.3
1929.9
0.1
308.6
1.3
0.0
159.8
1149.8
1.4
251.4
62.2
0.4
235.4
1695.5
2.1
370.6
91.6
0.6
256.3
1846.6
2.3
403.6
99.7
0.7
269.7
1946.9
2.4
425.2
104.8
0.7
Upstream Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
7.7
726.6
0.0
116.2
0.5
0.0
Total FFC Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
101.9
733.1
0.9
160.3
39.7
0.3
I
I
I
Negative values refer to an increase in emissions.
TABLE V.62—CUMULATIVE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS FOR LOW-VOLTAGE DRY-TYPE
DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056
Trial standard level
1
2
3
4
5
Power Sector Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
10.7
0.7
0.1
5.0
4.4
0.0
15.6
1.1
0.1
7.3
6.4
0.0
24.8
1.7
0.2
11.6
10.2
0.1
66.1
4.5
0.6
30.9
27.1
0.2
71.6
4.9
0.7
33.5
29.4
0.2
1.3
122.4
0.0
19.6
0.1
0.0
2.0
194.5
0.0
31.1
0.1
0.0
5.5
519.1
0.0
83.0
0.4
0.0
5.9
562.4
0.0
89.9
0.4
0.0
16.9
123.4
0.2
26.9
6.5
0.0
26.8
196.2
0.2
42.7
10.3
0.1
71.6
523.5
0.6
113.9
27.5
0.2
77.6
567.3
0.7
123.4
29.8
0.2
Upstream Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
0.9
84.0
0.0
13.4
0.1
0.0
Total FFC Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
11.6
84.8
0.1
18.4
4.5
0.0
I
I
I
Negative values refer to an increase in emissions.
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.63—CUMULATIVE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS FOR MEDIUM-VOLTAGE DRY-TYPE
DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056
Trial Standard Level
1
2
3
4
5
Power Sector Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
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0.1
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0.1
18.2
1.2
0.2
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.63—CUMULATIVE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS FOR MEDIUM-VOLTAGE DRY-TYPE
DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056—Continued
Trial Standard Level
1
2
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
3
1.1
1.0
0.0
4
5
1.6
1.4
0.0
5.5
4.8
0.0
7.1
6.2
0.0
8.5
7.5
0.0
0.3
27.1
0.0
4.3
0.0
0.0
1.0
92.3
0.0
14.8
0.1
0.0
1.3
120.0
0.0
19.2
0.1
0.0
1.5
143.7
0.0
23.0
0.1
0.0
3.7
27.3
0.0
5.9
1.4
0.0
12.7
93.1
0.1
20.2
4.9
0.0
16.5
121.1
0.1
26.3
6.3
0.0
19.7
144.9
0.2
31.5
7.6
0.0
Upstream Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
0.2
18.4
0.0
2.9
0.0
0.0
Total FFC Emissions
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
2.5
18.6
0.0
4.0
1.0
0.0
Negative values refer to an increase in emissions.
As part of the analysis for this
rulemaking, DOE estimated monetary
benefits likely to result from the
reduced emissions of CO2 that DOE
estimated for each of the considered
TSLs for distribution transformers.
Section IV.L of this document discusses
the SC–CO2 values that DOE used. Table
V.64 presents the value of CO2
emissions reduction at each TSL for
each of the SC–CO2 cases. The timeseries of annual values is presented for
the proposed TSL in chapter 14 of the
NOPR TSD.
TABLE V.64—PRESENT VALUE OF CO2 EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–
2056
SC–CO2 Case
Discount rate and statistics
(million 2021$)
TSL
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
Liquid-immersed Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
603.2
946.1
1,394.3
1,517.6
1,597.1
2,773.2
4,350.2
6,410.7
6,977.6
7,343.2
4,425.4
6,941.9
10,229.9
11,134.6
11,718.0
8,386.0
13,154.7
19,385.3
21,099.8
22,205.4
333.0
484.8
770.4
2,056.9
2,228.8
530.3
772.1
1,227.0
3,276.0
3,549.8
1,007.4
1,466.7
2,330.8
6,223.1
6,743.2
72.7
106.7
364.4
473.6
566.7
115.8
169.9
580.4
754.2
902.5
220.0
322.7
1,102.5
1,432.7
1,714.4
Low-voltage Dry Type Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
72.9
106.1
168.6
450.3
487.9
lotter on DSK11XQN23PROD with PROPOSALS3
Medium-voltage Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
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23.3
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124.0
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
As discussed in section IV.L.2, DOE
estimated the climate benefits likely to
result from the reduced emissions of
methane and N2O that DOE estimated
for each of the considered TSLs for
distribution transformers. Table V.65
presents the value of the CH4 emissions
reduction at each TSL, and Table V.66
presents the value of the N2O emissions
reduction at each TSL. The time-series
of annual values is presented for the
proposed TSL in chapter 14 of the
NOPR TSD.
TABLE V.65—PRESENT VALUE OF METHANE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS SHIPPED IN
2027–2056
SC–CH4 Case
Discount rate and statistics
(million 2021$)
TSL
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
Liquid-immersed Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
202.8
318.1
469.0
510.8
538.6
659.9
1,035.0
1,526.2
1,662.2
1,752.5
939.6
1,473.7
2,173.0
2,366.7
2,495.3
1,748.1
2,741.9
4,042.9
4,403.2
4,642.6
80.1
116.7
185.5
494.9
536.3
113.9
165.8
263.6
703.4
762.2
212.2
309.0
491.3
1,310.8
1,420.4
17.6
25.8
88.0
114.5
137.0
25.0
36.7
125.1
162.7
194.7
46.6
68.3
233.2
303.1
362.8
Low-voltage Dry Type Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
24.8
36.2
57.5
153.4
166.2
Medium-voltage Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
5.4
8.0
27.3
35.5
42.4
TABLE V.66—PRESENT VALUE OF NITROUS OXIDE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS SHIPPED IN
2027–2056
SC–N2O Case
Discount rate and statistics
(million 2021$)
TSL
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
Liquid-immersed Distribution Transformers
1
2
3
4
5
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
.......................................................................................................................
2.1
3.4
4.9
5.4
5.7
9.2
14.4
21.2
23.1
24.3
14.5
22.7
33.5
36.5
38.4
24.5
38.5
56.7
61.7
64.9
1.1
1.6
2.5
6.8
7.3
1.7
2.5
4.0
10.6
11.5
2.9
4.2
6.8
18.0
19.5
0.2
0.4
1.2
1.6
0.4
0.6
1.9
2.4
0.6
0.9
3.2
4.2
lotter on DSK11XQN23PROD with PROPOSALS3
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1
2
3
4
5
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0.3
0.4
0.6
1.6
1.7
Medium-voltage Distribution Transformers
1
2
3
4
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.66—PRESENT VALUE OF NITROUS OXIDE EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS SHIPPED IN
2027–2056—Continued
SC–N2O Case
Discount rate and statistics
(million 2021$)
TSL
5%
3%
2.5%
3%
Average
Average
Average
95th percentile
5 .......................................................................................................................
DOE is well aware that scientific and
economic knowledge about the
contribution of CO2 and other GHG
emissions to changes in the future
global climate and the potential
resulting damages to the global and U.S.
economy continues to evolve rapidly.
Thus, any value placed on reduced GHG
emissions in this proposed rulemaking
is subject to change. That said, because
of omitted damages, DOE agrees with
the IWG that these estimates most likely
underestimate the climate benefits of
greenhouse gas reductions. DOE,
together with other Federal agencies,
will continue to review methodologies
0.4
for estimating the monetary value of
reductions in CO2 and other GHG
emissions. This ongoing review will
consider the comments on this subject
that are part of the public record for this
and other rulemakings, as well as other
methodological assumptions and issues.
DOE notes that the proposed standards
would be economically justified even
without inclusion of monetized benefits
of reduced GHG emissions.
DOE also estimated the monetary
value of the health benefits associated
with NOX and SO2 emissions reductions
anticipated to result from the
considered TSLs for distribution
1.9
2.9
5.0
transformers. The dollar-per-ton values
that DOE used are discussed in section
IV.L of this document. Table V.67
presents the present value for NOX
emissions reduction for each TSL
calculated using 7-percent and 3percent discount rates, and Table V.68
presents similar results for SO2
emissions reductions. The results in
these tables reflect application of EPA’s
low dollar-per-ton values, which DOE
used to be conservative. The time-series
of annual values is presented for the
proposed TSL in chapter 14 of the
NOPR TSD.
TABLE V.67—PRESENT VALUE OF NOX EMISSIONS REDUCTION FOR DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–
2056
3% Discount rate
7% Discount rate
Million 2021$
Million 2021$
TSL
Liquid-Immersed Distribution Transformers
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
1,385.3
2,172.9
3,203.1
3,487.6
3,674.0
4,631.4
7,264.6
10,709.0
11,660.1
12,283.6
171.4
249.5
396.6
1,058.5
1,147.0
552.0
803.7
1,277.5
3,409.6
3,694.6
37.5
55.0
187.9
244.3
292.4
120.8
177.3
605.4
786.9
941.7
Low-voltage Dry-Type Distribution Transformers
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Medium-voltage Dry-Type Distribution Transformers
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
lotter on DSK11XQN23PROD with PROPOSALS3
TABLE V.68—PRESENT VALUE OF SO2 EMISSIONS REDUCTION DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056
3% Discount rate
7% Discount rate
Million 2021$
Million 2021$
TSL
Liquid-immersed Distribution Transformers
1 .......................................................................................................................................................
2 .......................................................................................................................................................
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.68—PRESENT VALUE OF SO2 EMISSIONS REDUCTION DISTRIBUTION TRANSFORMERS SHIPPED IN 2027–2056—
Continued
3% Discount rate
7% Discount rate
Million 2021$
Million 2021$
TSL
3 .......................................................................................................................................................
4 .......................................................................................................................................................
5 .......................................................................................................................................................
1,104.1
1,201.2
1,262.4
3,597.5
3,913.9
4,113.2
57.8
84.2
133.8
357.3
387.1
181.3
263.9
419.3
1,119.8
1,213.4
12.6
18.5
63.2
82.1
98.3
39.5
57.9
198.1
257.4
307.9
Low-voltage Dry-Type Distribution Transformers
1
2
3
4
5
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
.......................................................................................................................................................
Medium-voltage Dry-Type Distribution Transformers
1
2
3
4
5
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.......................................................................................................................................................
.......................................................................................................................................................
7. Other Factors
8. Summary of Economic Impacts
The Secretary of Energy, in
determining whether a standard is
economically justified, may consider
any other factors that the Secretary
deems to be relevant. (42 U.S.C.
6295(o)(2)(B)(i)(VII)) No other factors
were considered in this analysis.
Table V.69 presents the NPV values
that result from adding the estimates of
the potential economic benefits
resulting from reduced GHG and NOX
and SO2 emissions to the NPV of
consumer benefits calculated for each
TSL considered in this rulemaking. The
consumer benefits are domestic U.S.
monetary savings that occur as a result
of purchasing the covered distribution
transformers, and are measured for the
lifetime of products shipped in 2027–
2056. The benefits associated with
reduced GHG emissions resulting from
the adopted standards are global
benefits, and are also calculated based
on the lifetime of distribution
transformers shipped in 2027–2056.
While many of the benefits from this
proposed standard extend through 2115,
the monetized benefits from GHG
reductions are capped at end of 2070.
TABLE V.69—CONSUMER NPV COMBINED WITH PRESENT VALUE OF CLIMATE AND HEALTH BENEFITS
Category
TSL 1
TSL 2
TSL 3
TSL 4
TSL 5
Liquid-immersed Distribution Transformers
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
10.0
12.6
14.5
19.3
15.1
19.3
22.3
29.8
21.7
27.8
32.2
43.3
22.9
29.5
34.4
46.4
12.3
19.3
24.4
37.1
7.0
13.6
18.5
30.5
0.0
6.9
12.1
24.7
14.9
16.8
18.2
21.8
15.2
17.3
18.9
22.7
4.8
6.8
4.8
6.9
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
3.4
6.1
8.0
12.8
5.2
9.3
12.4
19.9
7.1
13.2
17.6
28.7
Low-voltage Distribution Transformers
lotter on DSK11XQN23PROD with PROPOSALS3
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
2.3
2.6
2.9
3.4
3.3
3.8
4.1
5.0
3.8
4.5
5.1
6.4
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
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TABLE V.69—CONSUMER NPV COMBINED WITH PRESENT VALUE OF CLIMATE AND HEALTH BENEFITS—Continued
Category
TSL 1
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
TSL 2
1.4
2.0
TSL 3
2.0
2.9
TSL 4
2.4
3.7
TSL 5
8.2
11.8
8.5
12.3
2.5
2.9
3.3
4.1
2.4
2.9
3.3
4.3
0.7
1.1
1.5
2.3
0.6
1.1
1.5
2.5
Medium-voltage Distribution Transformers
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
0.4
0.5
0.6
0.7
0.5
0.6
0.7
0.8
2.2
2.5
2.8
3.4
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
5% Average SC–GHG case ................................................
3% Average SC–GHG case ................................................
2.5% Average SC–GHG case .............................................
3% 95th percentile SC–GHG case ......................................
lotter on DSK11XQN23PROD with PROPOSALS3
C. Conclusion
When considering new or amended
energy conservation standards, the
standards that DOE adopts for any type
(or class) of covered equipment must be
designed to achieve the maximum
improvement in energy efficiency that
the Secretary determines is
technologically feasible and
economically justified. (42 U.S.C.
6295(o)(2)(A)) In determining whether a
standard is economically justified, the
Secretary must determine whether the
benefits of the standard exceed its
burdens by, to the greatest extent
practicable, considering the seven
statutory factors discussed previously.
(42 U.S.C. 6295(o)(2)(B)(i)) The new or
amended standard must also result in
significant conservation of energy. (42
U.S.C. 6295(o)(3)(B))
For this NOPR, DOE considered the
impacts of amended standards for each
type of distribution transformer at each
TSL, beginning with the maximum
technologically feasible level, to
determine whether that level was
economically justified. Where the maxtech level was not justified, DOE then
considered the next most efficient level
and undertook the same evaluation until
it reached the highest efficiency level
that is both technologically feasible and
economically justified and saves a
significant amount of energy.
To aid the reader as DOE discusses
the benefits and/or burdens for each
type of equipment for each TSL, tables
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0.2
0.3
0.4
0.1
0.2
0.3
0.5
in this section present a summary of the
results of DOE’s quantitative analysis for
each TSL. In addition to the quantitative
results presented in the tables, DOE also
considers other burdens and benefits
that affect economic justification. These
include the impacts on identifiable
subgroups of consumers who may be
disproportionately affected by a national
standard and impacts on employment.
DOE also notes that the economics
literature provides a wide-ranging
discussion of how consumers trade off
upfront costs and energy savings in the
absence of government intervention.
Much of this literature attempts to
explain why consumers appear to
undervalue energy efficiency
improvements. There is evidence that
consumers undervalue future energy
savings as a result of (1) entrenched
purchasing practices, (2) a lack of
sufficient salience of the long-term or
aggregate benefits, (3) a lack of sufficient
savings to warrant delaying or altering
purchases, (4) excessive focus on the
short term, in the form of inconsistent
weighting of future energy cost savings
relative to available returns on other
investments, (5) computational or other
difficulties associated with the
evaluation of relevant tradeoffs, and (6)
a divergence in incentives. For example,
in the case of dry-type distribution
transformers the purchaser is often not
the operator of the equipment. Instead,
they are often installed at the time of
building construction and operated by
tenants. In other circumstances where
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the owner is the operator, distribution
transformers are often purchased based
on lowest first cost (see section IV.F.3)
rather than equipment efficiency.
Having less than perfect foresight and a
high degree of uncertainty about the
future, consumers may trade off these
types of investments at a higher than
expected rate between current
consumption and uncertain future
energy cost savings.
1. Benefits and Burdens of TSLs
Considered for Liquid-Immersed
Distribution Transformers Standards
Table V.70 and Table V.71 summarize
the quantitative impacts estimated for
each TSL for liquid-immersed
distribution transformers. The national
impacts are measured over the lifetime
of distribution transformers purchased
in the 30-year period that begins in the
anticipated year of compliance with
amended standards (2027–2056). The
energy savings, emissions reductions,
and value of emissions reductions refer
to full-fuel-cycle results. The efficiency
levels contained in each TSL are
described in section V.A of this
document. Table V.71 shows the
consumer impacts as equipment classes,
which are the shipment weighted
average results of each equipment
class’s representative units. The
consumer results for each representative
unit and information on the fraction of
shipments they represent are shown in
section B.1.
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
TABLE V.70—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS TSLS: NATIONAL
IMPACTS
Category
TSL 1
TSL 2
TSL 3
TSL 4
TSL 5
Cumulative FFC National Energy Savings
Quads ...................................................................................
3.22
5.06
7.43
8.02
8.45
235.44
1695.46
2.14
370.62
91.65
0.60
256.27
1846.56
2.32
403.57
99.71
0.65
269.69
1946.92
2.44
425.24
104.82
0.68
12.77
8.66
15.57
37.01
7.48
5.30
29.53
18.51
9.12
16.40
44.03
24.76
¥6.25
19.27
4.28
8.66
4.69
17.63
4.02
0.26
13.61
6.20
9.12
4.94
20.26
13.31
¥7.11
6.95
Cumulative FFC Emissions Reduction
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
101.85
733.07
0.92
160.27
39.65
0.26
159.77
1149.83
1.45
251.40
62.21
0.41
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
Total Net Benefits ................................................................
4.06
3.44
6.19
13.70
1.09
2.98
12.61
6.08
5.40
9.71
21.19
1.93
4.15
19.26
10.17
7.96
14.31
32.43
4.67
5.50
27.76
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
Total Net Benefits ................................................................
1.36
3.44
1.86
6.67
0.58
0.78
6.08
2.04
5.40
2.92
10.36
1.04
1.00
9.32
3.40
7.96
4.31
15.67
2.51
0.89
13.16
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the equipment shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-percent and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central SC–GHG point estimate.
DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates. See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
TABLE V.71—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS TSLS:
MANUFACTURER AND CONSUMER IMPACTS
Category
TSL 1 *
TSL 2 *
TSL 3 *
TSL 4 *
TSL 5 *
1,166 to 1,232
(15.8) to (11.0)
1,133 to 1,233
(18.1) to
(10.9)
1,004 to 1,347
(27.5) to (2.7)
147
887
n.a.
120
868
n.a.
(269)
(2,493)
(7,482)
lotter on DSK11XQN23PROD with PROPOSALS3
Manufacturer Impacts
Industry NPV (million 2021$) (No-new-standards case
INPV = $1,384 million) .....................................................
Industry NPV (% change) ....................................................
1,283 to 1,297
(7.3) to (6.3)
1,242 to 1,268
(10.3) to (8.4)
Consumer Average LCC Savings (2021$)
Equipment Class 1 * .............................................................
Equipment Class 2 * .............................................................
Equipment Class 12 * ...........................................................
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TABLE V.71—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS TSLS:
MANUFACTURER AND CONSUMER IMPACTS—Continued
Category
TSL 1 *
Shipment-Weighted Average ** ............................................
TSL 2 *
120
TSL 3 *
TSL 4 *
TSL 5 *
172
199
172
(425)
16.3
18.7
n.a.
16
7.4
12.1
n.a.
8
11.4
12.5
n.a.
12
31.7
24.6
36.0
31
17
26
n.a.
21
18
19
n.a.
18
87
64
95
70
Consumer Simple PBP (years)
Equipment Class 1 ...............................................................
Equipment Class 2 ...............................................................
Equipment Class 12 .............................................................
Shipment-Weighted Average ** ............................................
19.0
20.8
n.a.
19
Percent of Consumers that Experience a Net Cost
Equipment Class 1 ...............................................................
Equipment Class 2 ...............................................................
Equipment Class 12 .............................................................
Shipment-Weighted Average ** ............................................
32
39
n.a.
28
27
54
n.a.
21
lotter on DSK11XQN23PROD with PROPOSALS3
Parentheses indicate negative (¥) values. The entry ‘‘n.a.’’ means not applicable because there is no change in the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class’s representative units. The consumer results for each representative unit and information on the fraction of shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment class in total projected
shipments in 2022.
First, DOE considered TSL 5, which
represents the max-tech efficiency
levels. TSL 5 would save an estimated
8.45 quads of energy, an amount DOE
considers significant. Under TSL 5, the
NPV of consumer benefit would be
$¥7.11 billion using a discount rate of
7 percent, and $¥6.25 billion using a
discount rate of 3 percent.
The cumulative emissions reductions
at TSL 5 are 269.69 Mt of CO2, 104.82
thousand tons of SO2, 425.24 thousand
tons of NOX, 0.68 tons of Hg, 1946.92
thousand tons of CH4, and 2.44
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 5 is
$9.12 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
5 is $4.94 billion using a 7-percent
discount rate and $16.40 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 5 is $6.95 billion.
Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 5 is $19.27 billion.
At TSL 5, the average LCC impact
ranges from $–269 for equipment class
1 to $–7,482 for equipment class 12. The
median PBP ranges from 24.6 years for
equipment class 2 to 36.0 for equipment
class 12. The fraction of consumers
experiencing a net LCC cost ranges from
64 percent for equipment class 2 to 95
percent for equipment class 12.
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At TSL 5, the projected change in
INPV ranges from a decrease of $380.7
million to a decrease of $37.2 million,
which corresponds to a change in INPV
of –27.5 percent and –2.7 percent,
respectively. DOE estimates that
industry must invest $289.4 million to
comply with standards set at TSL 5.
The Secretary tentatively concludes
that at TSL 5 for liquid-immersed
distribution transformers, the benefits of
energy savings, emission reductions,
and the estimated monetary value of the
emissions reductions would be
outweighed by the economic burden on
many consumers as indicated by
lengthy PBPs, the percentage of
customers who would experience LCC
increases, negative consumer NPV at
both 3 and 7 percent discount rates, and
the capital and engineering costs that
would result in a reduction in INPV for
manufacturers. At TSL 5, the LCC
savings are negative for most liquidimmersed distribution transformers,
indicating there is a substantial risk that
a disproportionate number of consumers
will incur increased costs; these costs
are also reflected in simple payback
period estimates that approach or
exceed average lifetimes. NPVs are
calculated for equipment shipped over
the period of 2027 through 2056 (see
section IV.H.3). Distribution
transformers are durable equipment
with a maximum lifetime estimated at
60 years (see section IV.F.8), accruing
operating cost savings through 2115.
When considered over this time period,
the discounted value of the incremental
equipment costs outweigh the
discounted value of the operating costs
savings. Incremental equipment costs
are incurred in the first year of
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equipment life, while operating cost
savings occur throughout the equipment
lifetime, with later years heavily
discounted. Further, there is risk of
greater reduction in INPV at max-tech if
manufacturers maintain their operating
profit in the presence of amended
efficiency standards on account of
having higher costs but similar profits.
The benefits of max-tech efficiency
levels for liquid-immersed distribution
transformer do not outweigh the
negative impacts to consumers and
manufacturers. Consequently, the
Secretary has tentatively concluded that
TSL 5 is not economically justified.
Next, DOE considered TSL 4, which
would save an estimated 8.02 quads of
energy, an amount DOE considers
significant. Under TSL 4, the NPV of
consumer benefit would be $0.26 billion
using a discount rate of 7 percent, and
$5.30 billion using a discount rate of 3
percent.
The cumulative emissions reductions
at TSL 4 are 256.27 Mt of CO2, 99.71
thousand tons of SO2, 403.57 thousand
tons of NOX, 0.65 tons of Hg, 1,846.56
thousand tons of CH4, and 2.32
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 4 is
$8.66 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
4 is $4.69 billion using a 7-percent
discount rate and $15.57 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
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rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 4 is $13.61 billion.
Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 4 is $29.53 billion.
At TSL 4, the average LCC impact
ranges from $120 for equipment class 1
to $868 for equipment class 2. The mean
PBP ranges from 11.4 years for
equipment class 1 to 12.5 years for
equipment class 2, well below the
average lifetime of 32 years. The fraction
of consumers experiencing a net LCC
cost ranges is 18 percent for equipment
classes 1 and 2.
At TSL 4, the projected change in
INPV ranges from a decrease of $251.3
million to a decrease of $151.0 million,
which corresponds to decreases of 18.1
percent and 10.9 percent, respectively.
DOE estimates that industry must invest
$270.6 million to comply with
standards set at TSL 4.
After considering the analysis and
weighing the benefits and burdens, the
Secretary has tentatively concluded that
a standard set at TSL 4 for liquidimmersed distribution transformers
would be economically justified.
Notably, the benefits to consumers
outweigh the cost to manufacturers. At
this TSL, the average LCC savings are
positive across all equipment classes.
An estimated 18 percent of liquidimmersed distribution transformer
consumers experience a net cost. The
FFC national energy savings are
significant and the NPV of consumer
benefits is positive using both a 3percent and 7-percent discount rate. At
TSL 4, the NPV of consumer benefits,
even measured at the more conservative
discount rate of 7 percent is larger than
the maximum estimated manufacturers’
loss in INPV. The standard levels at TSL
4 are economically justified even
without weighing the estimated
monetary value of emissions reductions.
When those emissions reductions are
included—representing $8.66 billion in
climate benefits (associated with the
average SC–GHG at a 3-percent discount
rate), and $15.57 billion (using a 3percent discount rate) or $4.69 billion
(using a 7-percent discount rate) in
health benefits—the rationale becomes
stronger still.
The energy savings under TSL 4 are
primarily achievable by using
amorphous steel. Both global and
domestic capacity of amorphous steel is
greater than it was during the
consideration of the April 2013
Standards Final Rule and global
capacity of amorphous steel (estimated
to be approximately 150,000–250,000
metric tons) is approximately equal to
the U.S. demand for electrical steel in
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distribution transformer applications
(estimated to be approximately 225,000
metric tons). Further, amorphous
capacity grew in response to the April
2013 Standards Final Rule, although
market demand did not necessarily
grow in-kind. Further, amorphous steel
manufacturers’ response to the April
2013 Standards Final Rule demonstrates
that amorphous capacity can be added
quickly and would be added in response
to an amended standard. Stakeholders
have expressed willingness to increase
supply to match any potential demand
created by an amended efficiency
standard. In the current market,
increased capacity of amorphous steel is
limited more by the demand for
amorphous steel rather than any
constraints on potential production
capacity. Therefore, in the presence of
an amended standard, it is expected that
amorphous capacity would quickly rise
to meet demand before the effective date
of any amended energy conservation
standards.
While there has historically been
concern over the fact that there is only
a single domestic supplier of amorphous
steel, the GOES market is also served by
a single domestic supplier. Stakeholders
have noted that sufficient domestic
supply of GOES is available only for M3
steel. Any efficiency standard that
requires steel with lower no-load losses
than M3 would not be able to be served
entirely by a domestic source without
further investment. The current market
of electrical steel in distribution
transformer applications is very much a
global market at present.
Further, while some stakeholders
have expressed concern as to whether
amorphous supply would be sufficient
to serve the entire market, stakeholders
have also expressed supply concerns
regarding GOES. Notably, stakeholders
have identified increased competition
for non-oriented electrical steel to serve
the electric vehicle market. This
competing demand is not expected to
disappear in the near term and
stakeholders have already seen supply
challenges for many of the higher
performing GOES grades. Amorphous
steel has not been commercialized in
electric motor applications and as such,
does not experience the same competing
demand for electric vehicle
applications. The increased demand for
non-oriented electrical steel also offers
an alternative for current producers of
GOES steel to transition their
production to non-oriented electrical
steel, meeting a needed market demand.
The consistent practice of distribution
transformer customers to lightly-load
their distribution transformers (see
section IV.E.1.a), means that the
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majority of energy savings are associated
with reducing no-load losses. While
higher grades of GOES may have
slightly improved no-load loss
characteristics, amorphous steel tends to
reduce no-load losses by over 60
percent. Meaning, even if the best
performing grades of GOES were
available in unlimited quantities,
amorphous steel would still lead to
significant energy savings. Further, by
nature of DOE evaluating efficiency of
liquid-immersed distribution
transformers at 50 percent load, even if
loading increases such that in-service
RMS average PUL is 50 percent, the
distribution transformers produced
under the amended efficiency standard
would be more efficient than minimally
efficient transformers on the market
today.
The transition from GOES cores to
amorphous cores does require some
amount of investment on the part of the
distribution transformer manufacturer if
they produce their own cores. While
these costs are not trivial, the benefit to
consumers vastly outweighs the cost to
manufacturers. Further, the increased
practice of outsourcing distribution
transformer core production means that
there is little burden on small
businesses, who overwhelmingly
purchase prefabricated distribution
transformer cores, rather than producing
them in-house. As stated, DOE conducts
the ‘‘walk-down’’ analysis to determine
the TSL that represents the maximum
improvement in energy efficiency that is
technologically feasible and
economically justified as required under
EPCA. The walk-down is not a
comparative analysis, as a comparative
analysis would result in the
maximization of net benefits instead of
energy savings that are technologically
feasible and economically justified,
which would be contrary to the statute.
86 FR 70892, 70908.
Although DOE considered proposed
amended standard levels for
distribution transformers by grouping
the efficiency levels for each equipment
class into TSLs, DOE evaluates all
analyzed efficiency levels in its
analysis. The TSLs constructed by DOE
to examine the impacts of amended
energy efficiency standards for liquidimmersed distribution transformers
align with the corresponding ELs
defined in the engineering analysis. For
the ELs above baseline that compose
TSL 4 DOE finds that LCC savings are
positive for all equipment classes, with
simple paybacks well below the average
equipment lifetimes. DOE also finds that
the estimated fraction of consumers who
would be negatively impacted from a
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standard at TSL 4 to be 18 percent for
all equipment classes.
For liquid-immersed distribution
transformers (including single-phase
and three-phase equipment) TSL 4 (i.e.,
the proposed TSL) represents a 20
percent reduction in losses over the
liquid-immersed distribution
transformers at TSL 4. The proposed
amended energy conservation standards
for distribution transformers, which are
expressed as percentage efficiency at 50
percent PUL are shown in Table V.72.
current standard, with the exception of
submersible liquid-immersed
distribution transformers (equipment
class 12) which remain at baseline.
Therefore, based on the previous
considerations, DOE proposes to adopt
the energy conservation standards for
TABLE V.72—PROPOSED AMENDED ENERGY CONSERVATION STANDARDS FOR LIQUID-IMMERSED DISTRIBUTION
TRANSFORMERS
Electrical efficiency by kVA and Equipment class
Equipment class 1
Equipment class 2
Single-phase
Three-phase
kVA
Equipment class 12
Single-phase submersible
kVA
10 .................................
15 .................................
25 .................................
37.5 ..............................
50 .................................
75 .................................
100 ...............................
167 ...............................
250 ...............................
333 ...............................
500 ...............................
667 ...............................
833 ...............................
98.96
99.05
99.16
99.24
99.29
99.35
99.40
99.46
99.51
99.54
99.59
99.62
99.64
kVA
15
30
45
75
112.5
150
225
300
500
750
1,000
1,500
2,000
2,500
3,750
5,000
2. Benefits and Burdens of TSLs
Considered for Low-Voltage Dry-Type
Distribution Transformers Standards
Table V.73 and Table V.74 summarize
the quantitative impacts estimated for
each TSL for low-voltage dry-type
distribution transformers. The national
impacts are measured over the lifetime
98.92
99.06
99.13
99.22
99.29
99.33
99.38
99.42
99.48
99.52
99.54
99.58
99.61
99.62
99.66
99.68
Three-phase submersible
kVA
10
15
25
37.5
50
75
100
167
250
333
500
667
833
........................
........................
........................
98.70
98.82
98.95
99.05
99.11
99.19
99.25
99.33
99.39
99.43
99.49
99.52
99.55
........................
........................
........................
of distribution transformers purchased
in the 30-year period that begins in the
anticipated year of compliance with
amended standards (2027–2056). The
energy savings, emissions reductions,
and value of emissions reductions refer
to full-fuel-cycle results. The efficiency
levels contained in each TSL are
described in section V.A of this
15
30
45
75
112.5
150
225
300
500
750
1,000
1,500
2,000
2,500
........................
........................
98.65
98.83
98.92
99.03
99.11
99.16
99.23
99.27
99.35
99.40
99.43
99.48
99.51
99.53
........................
........................
document. Table V.74 shows the
consumer impacts as Equipment classes,
which are the shipment weighted
average results of each Equipment
class’s representative units. The
consumer results for each representative
unit and information on the fraction of
shipments they represent are shown in
section B.1.
TABLE V.73—SUMMARY OF ANALYTICAL RESULTS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS TSLS:
NATIONAL IMPACTS
Category
TSL 1
TSL 2
TSL 3
TSL 4
TSL 5
Cumulative FFC National Energy Savings
Quads ...................................................................................
0.37
0.54
0.85
2.28
2.47
26.81
196.22
0.24
42.69
10.30
0.07
71.58
523.53
0.64
113.91
27.51
0.18
77.57
567.30
0.70
123.44
29.81
0.19
12.88
2.56
4.53
19.97
3.16
9.72
13.45
2.77
4.91
21.13
3.82
9.63
Cumulative FFC Emissions Reduction
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CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
11.59
84.76
0.10
18.44
4.45
0.03
16.87
123.42
0.15
26.85
6.48
0.04
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
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0.41
0.73
2.57
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0.60
1.07
3.74
¥0.03
2.11
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1.70
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1.39
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TABLE V.73—SUMMARY OF ANALYTICAL RESULTS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS TSLS:
NATIONAL IMPACTS—Continued
Category
TSL 1
Total Net Benefits ................................................................
TSL 2
2.63
TSL 3
3.78
TSL 4
4.52
TSL 5
16.81
17.31
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
0.50
0.41
0.23
1.14
¥0.03
0.53
0.72
0.60
0.33
1.66
¥0.02
0.74
1.14
0.96
0.53
2.63
0.75
0.39
4.49
2.56
1.42
8.46
1.70
2.79
4.69
2.77
1.53
8.99
2.05
2.63
Total Net Benefits ................................................................
1.17
1.68
1.88
6.77
6.94
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the equipment shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-percent and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central SC–GHG point estimate.
DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates. See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
TABLE V.74—SUMMARY OF ANALYTICAL RESULTS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS TSLS:
MANUFACTURER AND CONSUMER IMPACTS
Category
TSL 1 *
TSL 2 *
TSL 3 *
TSL 4 *
TSL 5 *
167 to 177
(13.9) to (8.7)
145 to 168
(25.3) to (13.6)
133 to 161
(31.4) to
(17.2)
203
381
315
146
214
179
108
624
492
147
574
459
3.3
0.7
1.0
7.6
8.6
7.6
11.7
7.8
7.4
11.7
9.1
8.4
33
30
27
43
10
13
40
16
17
Manufacturer Impacts
Industry NPV (million 2021$) (No-new-standards case
INPV = $194 million .........................................................
Industry NPV (% change) ....................................................
189
(2.8)
188 to 189
(3.0) to (2.5)
Consumer Average LCC Savings (2021$)
Equipment Class 3 * .............................................................
Equipment Class 4 * .............................................................
Shipment-Weighted Average ** ............................................
312
357
311
Consumer Simple PBP (years)
Equipment Class 3 * .............................................................
Equipment Class 4 * .............................................................
Shipment-Weighted Average ** ............................................
0.0
0.3
0.3
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Percent of Consumers that Experience a Net Cost
Equipment Class 3 * .............................................................
Equipment Class 4 * .............................................................
Shipment-Weighted Average ** ............................................
1
8
7
17
9
9
Parentheses indicate negative (¥) values. The entry ‘‘n.a.’’ means not applicable because there is no change in the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class’s representative units. The consumer results for each representative unit and information on the fraction of shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment class in total projected
shipments in 2022
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Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
First, DOE considered TSL 5, which
represents the max-tech efficiency
levels. TSL 5 would save an estimated
2.47 quads of energy, an amount DOE
considers significant. Under TSL 5, the
NPV of consumer benefit would be
$2.63 billion using a discount rate of 7
percent, and $9.63 billion using a
discount rate of 3 percent.
The cumulative emissions reductions
at TSL 5 are 77.57 Mt of CO2, 29.81
thousand tons of SO2, 123.44 thousand
tons of NOX, 0.19 tons of Hg, 567.30
thousand tons of CH4, and 0.70
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 5 is
$2.77 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
5 is $1.53 billion using a 7-percent
discount rate and $4.91 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 5 is $6.94 billion.
Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 5 is $17.31 billion.
At TSL 5, the average LCC impact
ranges from $147 for equipment class 3
to $574 for equipment class 4. The
median PBP ranges from 9.1 years for
equipment class 4 to 11.7 years for
equipment class 3. The fraction of
consumers experiencing a net LCC cost
ranges from 16 percent for equipment
class 4 to 40 percent for equipment class
3.
At TSL 5, the projected change in
INPV ranges from a decrease of $61.0
million to a decrease of $33.5 million,
which corresponds to decreases of 31.4
percent and 17.2 percent, respectively.
DOE estimates that industry must invest
$69.4 million to comply with standards
set at TSL 5.
After considering the analysis and
weighing the benefits and burdens, the
Secretary has tentatively concluded that
at a standard set at TSL 5 for lowvoltage dry-type distribution
transformers would be economically
justified. At this TSL, the average LCC
savings are positive across all
equipment classes. An estimated 16
percent of equipment class 4 to 40
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percent of equipment class 3 lowvoltage dry-type distribution
transformer consumers experience a net
cost. The FFC national energy savings
are significant and the NPV of consumer
benefits is positive using both a 3percent and 7-percent discount rate.
Notably, the benefits to consumers
vastly outweigh the cost to
manufacturers. At TSL 5, the NPV of
consumer benefits, even measured at the
more conservative discount rate of 7
percent is over 43.15 times higher than
the maximum estimated manufacturers’
loss in INPV. The standard levels at TSL
5 are economically justified even
without weighing the estimated
monetary value of emissions reductions.
When those emissions reductions are
included—representing $2.77 billion in
climate benefits (associated with the
average SC–GHG at a 3-percent discount
rate), and $4.91 billion (using a 3percent discount rate) or $1.53 billion
(using a 7-percent discount rate) in
health benefits—the rationale becomes
stronger still.
The energy savings under TSL 5 are
primarily achievable by using
amorphous steel. Both global and
domestic capacity of amorphous steel is
greater than it was during the
consideration of the April 2013
Standards Final Rule and global
capacity of amorphous (estimated to be
approximately 150,000–250,000 metric
tons) is approximately equal to the U.S.
demand for electrical steel in
distribution transformer applications
(estimated to be approximately 225,000
metric tons). Further, amorphous
capacity grew in response to the April
2013 Standards Final Rule, although
market demand did not necessarily
grow in-kind. As such, there is currently
excess amorphous steel capacity.
Amorphous manufacturers response to
the April 2013 Standards Final Rule
demonstrates that amorphous capacity
can be added quickly and is limited
more by the market demand for
amorphous steel rather that the ability
to build out new supply. Stakeholders
have expressed willingness to increase
supply to match any potential demand
created by an amended efficiency
standard. The majority of electrical steel
use in distribution transformer
applications is associated with liquidimmersed distribution transformer.
Therefore, a proposed standard for
liquid-immersed distribution
transformers that requires amorphous
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1835
steel would result in amorphous
capacity quickly rising to meet demand
before the effective date of any amended
energy conservation standards. The
increased amorphous capacity would
then be able to serve both the liquidimmersed and the low-voltage dry-type
market.
As discussed in section V.C.1, the
consistent practice of distribution
transformer customers to lightly-load
their distribution transformers, means
that the majority of energy savings are
associated with reducing no-load losses.
While higher grades of GOES may have
slightly improved no-load loss
characteristics, amorphous steel tends to
reduce no-load losses by over 60
percent. By nature of DOE evaluating
efficiency of low-voltage dry-type
distribution transformers at 35 percent
load, even if loading increases such that
in-service RMS average PUL is 35
percent, the distribution transformers
produced under the amended efficiency
standard would be more efficient than
minimally efficient transformers on the
market today.
As stated, DOE conducts the walkdown analysis to determine the TSL that
represents the maximum improvement
in energy efficiency that is
technologically feasible and
economically justified as required under
EPCA.
Although DOE considered proposed
amended standard levels for
distribution transformers by grouping
the efficiency levels (ELs) for each
equipment class into TSLs, DOE
evaluates all analyzed efficiency levels
in its analysis. For low-voltage dry-type
distribution transformers, TSL 5 (i.e.,
the proposed TSL) maps directly to EL
5 for each equipment class and
represents a 50 percent reduction in
losses over the current standard for
single-phase distribution transformers,
and a 40 percent reduction in losses
over the current standard for threephase distribution transformers.
Therefore, based on the previous
considerations, DOE proposes to adopt
the energy conservation standards for
low-voltage dry-type distribution
transformers at TSL 5. The proposed
amended energy conservation standards
for low-voltage dry-type distribution
transformers, which are expressed as
percentage efficiency at 35 percent PUL
are shown in Table V.75.
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TABLE V.75—PROPOSED AMENDED ENERGY CONSERVATION STANDARDS FOR LOW-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS
Equipment class 3
Equipment class 4
Single-phase
Three-phase
kVA
kVA
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
3. Benefits and Burdens of TSLs
Considered for Medium-Voltage DryType Distribution Transformers
Standards
Table V.76 and Table V.77 summarize
the quantitative impacts estimated for
each TSL for medium-voltage dry-type
distribution transformers. The national
impacts are measured over the lifetime
98.84
98.99
99.09
99.14
99.24
99.30
99.35
99.40
99.45
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
of distribution transformers purchased
in the 30-year period that begins in the
anticipated year of compliance with
amended standards (2027–2056). The
energy savings, emissions reductions,
and value of emissions reductions refer
to full-fuel-cycle results. The efficiency
levels contained in each TSL are
described in section V.A of this
98.72
98.93
99.03
99.16
99.24
99.29
99.36
99.41
99.48
99.54
99.57
document. Table V.77 shows the
consumer impacts as equipment classes,
which are the shipment weighted
average results of each equipment
class’s representative units. The
consumer results for each representative
unit and information on the fraction of
shipments they represent are shown in
section B.1.
TABLE V.76—SUMMARY OF ANALYTICAL RESULTS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS
TSLS: NATIONAL IMPACTS
Category
TSL 1
TSL 2
TSL 3
TSL 4
TSL 5
Cumulative FFC National Energy Savings
Quads ...................................................................................
0.08
0.12
0.40
0.53
0.63
12.68
93.13
0.11
20.24
4.87
0.03
16.48
121.07
0.15
26.31
6.33
0.04
19.72
144.90
0.18
31.49
7.58
0.05
2.50
0.59
1.04
4.13
1.19
1.30
2.94
2.72
0.71
1.25
4.67
1.76
0.96
2.92
0.87
0.59
0.33
1.79
0.64
0.23
1.14
0.95
0.71
0.39
2.04
0.94
0.00
1.10
Cumulative FFC Emissions Reduction
CO2 (million metric tons) .....................................................
CH4 (thousand tons) ............................................................
N2O (thousand tons) ............................................................
NOX (thousand tons) ...........................................................
SO2 (thousand tons) ............................................................
Hg (tons) ..............................................................................
2.53
18.59
0.02
4.04
0.97
0.01
3.71
27.29
0.03
5.93
1.43
0.01
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
Total Net Benefits ................................................................
0.28
0.09
0.16
0.53
0.02
0.26
0.51
0.41
0.13
0.24
0.77
0.19
0.21
0.58
2.12
0.45
0.80
3.38
0.87
1.25
2.50
lotter on DSK11XQN23PROD with PROPOSALS3
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
Consumer Operating Cost Savings .....................................
Climate Benefits * .................................................................
Health Benefits ** .................................................................
Total Benefits † ....................................................................
Consumer Incremental Product Costs ‡ ..............................
Consumer Net Benefits ........................................................
Total Net Benefits ................................................................
0.10
0.09
0.05
0.24
0.01
0.09
0.23
0.14
0.13
0.07
0.35
0.10
0.04
0.24
0.74
0.45
0.25
1.44
0.47
0.27
0.97
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the equipment shipped in 2027–2056.
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* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21-cv-1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-percent and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central SC–GHG point estimate. .
DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates. See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
TABLE V.77—SUMMARY OF ANALYTICAL RESULTS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION TRANSFORMERS
TSLS: MANUFACTURER AND CONSUMER IMPACTS
Category
TSL 1 *
TSL 2 *
TSL 3 *
TSL 4 *
TSL 5 *
71 to 80
(18.7) to (8.8)
69 to 80
(21.4) to (7.8)
65 to 82
(25.9) to (5.9)
(165)
647
(5,704)
(1,139)
(985)
224
(5,569)
(1,348)
(1,557)
(3,727)
(9,558)
(3,898)
12.1
13.5
22.3
14.1
17.0
14.1
19.8
13.7
15.6
18.0
21.8
16.3
48
48
77
42
68
51
82
46
59
77
92
58
Manufacturer Impacts
Industry NPV (million 2021$) (No-new-standards case
INPV = $87 million ...........................................................
Industry NPV ( % change) ...................................................
85
(2.1)
85 to 86
(3.0) to (0.9)
Consumer Average LCC Savings (2021$)
Equipment Class 6 * .............................................................
Equipment Class 8 * .............................................................
Equipment Class 10 * ...........................................................
Shipment-Weighted Average ** ............................................
1,227
4,556
(1,209)
1,594
833
3,016
(2,528)
641
Consumer Simple PBP (years)
Equipment Class 6 * .............................................................
Equipment Class 8 * .............................................................
Equipment Class 10 * ...........................................................
Shipment-Weighted Average ** ............................................
1.9
0.4
24.9
7.9
4.5
1.9
24.9
8.9
Percent of Consumers that Experience a Net Cost
Equipment Class 6 * .............................................................
Equipment Class 8 * .............................................................
Equipment Class 10 * ...........................................................
Shipment-Weighted Average ** ............................................
7
3
83
22
16
11
83
26
lotter on DSK11XQN23PROD with PROPOSALS3
The entry ‘‘n.a.’’ means not applicable because there is no change in the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class’s representative units. The consumer results for each representative unit and information on the fraction of shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment class in total projected
shipments in 2022.
First, DOE considered TSL 5, which
represents the max-tech efficiency
levels. TSL 5 would save an estimated
0.63 quads of energy, an amount DOE
considers significant. Under TSL 5, the
NPV of consumer benefit would be $3
million using a discount rate of 7
percent, and $0.96 billion using a
discount rate of 3 percent.
The cumulative emissions reductions
at TSL 5 are 19.72 Mt of CO2, 7.58
thousand tons of SO2, 31.49 thousand
tons of NOX, 0.05 tons of Hg, 144.90
thousand tons of CH4, and 0.18
thousand tons of N2O. The estimated
monetary value of the climate benefits
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from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 5 is
$0.71 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
5 is $0.39 billion using a 7-percent
discount rate and $1.25 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 5 is $1.10 billion.
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Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 5 is $2.92 billion.
At TSL 5, the average LCC impact
ranges from $¥9,558 for equipment
class 10 to $¥1557 for equipment class
6. The mean PBP ranges from 15.6 years
for equipment class 6 to 21.8 years for
equipment class 10. The fraction of
consumers experiencing a net LCC cost
ranges from 92 percent for equipment
class 10 to 59 percent for equipment
class 6.
At TSL 5, the projected change in
INPV ranges from a decrease of $22.6
million to a decrease of $5.2 million,
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which corresponds to decreases of 25.9
percent and 5.9 percent, respectively.
DOE estimates that industry must invest
$21.2 million to comply with standards
set at TSL 5.
The Secretary tentatively concludes
that at TSL 5 for medium-voltage drytype distribution transformers, the
benefits of energy savings, emission
reductions, and the estimated monetary
value of the emissions reductions would
be outweighed by the economic burden
on many consumers as indicated by the
negative LCCs for many equipment
classes, the percentage of customers
who would experience LCC increases,
and the capital and engineering costs
that could result in a reduction in INPV
for manufacturers. At TSL 5 DOE is
estimating negative benefits for a
disproportionate fraction of
consumers—a shipment weighted
average of 58 percent. Further DOE
estimates that there is a substantial risk
to consumers, with a shipment weighted
LCC savings for all MVDT equipment of
¥$3,898. Consequently, the Secretary
has tentatively concluded that TSL 5 is
not economically justified.
Next, DOE considered TSL 4, which
would save an estimated 0.53 quads of
energy, an amount DOE considers
significant. Under TSL 4, the NPV of
consumer benefit would be $0.23 billion
using a discount rate of 7 percent, and
$1.30 billion using a discount rate of 3
percent.
The cumulative emissions reductions
at TSL 4 are 16.48 Mt of CO2, 6.33
thousand tons of SO2, 26.31 thousand
tons of NOX, 0.04 tons of Hg, 121.07
thousand tons of CH4, and 0.15
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 4 is
$0.59 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
4 is $0.33 billion using a 7-percent
discount rate and $1.04 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 4 is $1.14 billion.
Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 4 is $2.94 billion.
At TSL 4, the average LCC impact
ranges from $¥5,569 for equipment
class 10 to $224 for equipment class 8.
The mean PBP ranges from 14.1 years
for equipment class 8 to 19.8 years for
equipment class 10. The fraction of
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consumers experiencing a net LCC cost
ranges from 51 percent for equipment
class 8 to 82 percent for equipment class
10.
At TSL 4, the projected change in
INPV ranges from a decrease of $18.7
million to a decrease of $6.8 million,
which corresponds to decreases of 21.4
percent and 7.8 percent, respectively.
DOE estimates that industry must invest
$19.2 million to comply with standards
set at TSL 4.
The Secretary tentatively concludes
that at TSL 4 for medium-voltage drytype distribution transformers, the
benefits of energy savings, emission
reductions, and the estimated monetary
value of the emissions reductions would
be outweighed by the economic burden
on many consumers as indicated by the
negative LCCs for many equipment
classes, the percentage of customers
who would experience LCC increases,
and the capital and engineering costs
that could result iyn a reduction in
INPV for manufacturers. At TSL 4 DOE
is estimating negative benefits for a
disproportionate fraction of consumers
shipment weighted average of 53
percent. Further DOE estimates that
there a substantial risk to consumers
with a shipment weighted LCC savings
for all MVDT equipment of ¥$1,348.
Consequently, the Secretary has
tentatively concluded that TSL 4 is not
economically justified.
Next, DOE considered TSL 3, which
would save an estimated 0.40 quads of
energy, an amount DOE considers
significant. Under TSL 3, the NPV of
consumer benefit would be $0.27 billion
using a discount rate of 7 percent, and
$1.25 billion using a discount rate of 3
percent.
The cumulative emissions reductions
at TSL 3 are 12.68 Mt of CO2, 4.87
thousand tons of SO2, 20.24 thousand
tons of NOX, 0.03 tons of Hg, 93.13
thousand tons of CH4, and 0.11
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 4 is
$0.45 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
3 is $0.25 billion using a 7-percent
discount rate and $0.80 billion using a
3-percent discount rate.
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 3 is $0.97 billion.
Using a 3-percent discount rate for all
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benefits and costs, the estimated total
NPV at TSL 3 is $2.50 billion.
At TSL 3, the average LCC impact
ranges from $¥5,704 for equipment
class 10 to $647 for equipment class 8.
The mean PBP ranges from 12.1years for
equipment class 6 to 22.3 years for
equipment class 10. The fraction of
consumers experiencing a net LCC cost
ranges from 77 percent for 10 to 48
percent for both equipment class 6 and
8.
At TSL 3, the projected change in
INPV ranges from a decrease of $16.3
million to a decrease of $7.7 million,
which corresponds to decreases of 18.7
percent and 8.8 percent, respectively.
DOE estimates that industry must invest
$17.9 million to comply with standards
set at TSL 3.
The Secretary tentatively concludes
that at TSL 3 for medium-voltage drytype distribution transformers, the
benefits of energy savings, emission
reductions, and the estimated monetary
value of the emissions reductions would
be outweighed by the economic burden
on many consumers as indicated by the
negative LCCs for many equipment
classes, the percentage of customers
who would experience LCC increases,
and the capital and engineering costs
that could result in a reduction in INPV
for manufacturers. At TSL 3 DOE is
estimating negative benefits for a
disproportionate fraction of consumers
shipment weighted average of 50
percent. Further DOE estimates that
there a substantial risk to consumers
with a shipment weighted LCC savings
for all MVDT equipment of ¥$1,139.
Consequently, the Secretary has
tentatively concluded that TSL 3 is not
economically justified.
Next, DOE considered TSL 2, which
would save an estimated 0.12 quads of
energy, an amount DOE considers
significant. Under TSL 2, the NPV of
consumer benefit would be $0.04 billion
using a discount rate of 7 percent, and
$0.21 billion using a discount rate of 3
percent.
The cumulative emissions reductions
at TSL 2 are 3.71 Mt of CO2, 1.43
thousand tons of SO2, 5.93 thousand
tons of NOX, 0.01 tons of Hg, 27.29
thousand tons of CH4, and 0.03
thousand tons of N2O. The estimated
monetary value of the climate benefits
from reduced GHG emissions
(associated with the average SC–GHG at
a 3-percent discount rate) at TSL 4 is
$0.13 billion. The estimated monetary
value of the health benefits from
reduced SO2 and NOX emissions at TSL
2 is $0.07 billion using a 7-percent
discount rate and $0.24 billion using a
3-percent discount rate.
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average of consumers who experience a
net cost is 26 percent. The FFC national
energy savings are significant and the
NPV of consumer benefits is positive
using both a 3-percent and 7-percent
discount rate. Notably, the benefits to
consumers outweigh the cost to
manufacturers. At TSL 2, the NPV of
consumer benefits, even measured at the
more conservative discount rate of 7
percent is over 38.3 times higher than
the maximum estimated manufacturers’
loss in INPV. The standard levels at TSL
2 are economically justified even
without weighing the estimated
monetary value of emissions reductions.
When those emissions reductions are
included—representing $0.13 billion in
climate benefits (associated with the
average SC–GHG at a 3-percent discount
rate), and $0.24 billion (using a 3percent discount rate) or $0.07 billion
(using a 7-percent discount rate) in
health benefits—the rationale becomes
stronger still.
As stated, DOE conducts the walkdown analysis to determine the TSL that
represents the maximum improvement
in energy efficiency that is
technologically feasible and
economically justified as required under
EPCA.
Although DOE considered proposed
amended standard levels for
distribution by grouping the efficiency
levels for each equipment class into
TSLs, DOE evaluates all analyzed
efficiency levels in its analysis. For
medium-voltage dry-type distribution
transformer the TSL 2 maps directly to
EL 2 for all equipment classes. EL 2
represents a 10 percent reduction in
losses over the current standard. While
the consumer benefits for equipment
class 10 are negative at EL 2 at ¥$2,528,
they are positive for all other equipment
Using a 7-percent discount rate for
consumer benefits and costs, health
benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
rate case for climate benefits from
reduced GHG emissions, the estimated
total NPV at TSL 2 is $0.24 billion.
Using a 3-percent discount rate for all
benefits and costs, the estimated total
NPV at TSL 2 is $0.58 billion.
At TSL 2, the average LCC impact
ranges from ¥$2,528 for equipment
class 10 to $3,016 for equipment class
8. The mean PBP ranges from 1.9 years
for equipment class 8 to 24.9 years for
equipment class 10, which is below the
mean lifetime of 32 years. The fraction
of consumers experiencing a net LCC
cost ranges from 11 percent for
equipment class 8 to 83 percent for
equipment class 10.
At TSL 2, the projected change in
INPV ranges from a decrease of $2.7
million to a decrease of $0.8 million,
which corresponds to decreases of 3.0
percent and 0.9 percent, respectively.
DOE estimates that industry must invest
$3.1 million to comply with standards
set at TSL 2.
After considering the analysis and
weighing the benefits and burdens, the
Secretary has tentatively concluded that
at a standard set at TSL 2 for mediumvoltage distribution transformers would
be economically justified. At this TSL,
the average LCC savings are positive
across all equipment classes except for
equipment class 10, with a shipment
weighed average LCC for all mediumvoltage dry-type distribution
transformers of $641. An estimated 11
percent of equipment class 8 to 83
percent of equipment class 10 mediumvoltage dry-type distribution
transformer consumers experience a net
cost, while the shipment weighted
1839
representing 78 percent of all MVDT
units shipped, additionally the
consumer benefits at EL 2, excluding
equipment class 10, increases from $641
to $1,271 in LCC savings Further, the EL
2 represent an improvement in
efficiency where the FFC national
energy savings is maximized, with
positive NPVs at both 3 and 7 percent,
and the shipment weighted average
consumer benefit at EL 2 is positive.
The shipment weighted consumer
benefits for TSL, and EL 2 are shown in
Table V.77.
As discussed previously, at the maxtech efficiency levels (TSL 5), TSL 4,
and TSL 3 for all medium-voltage drytype distribution transformers there is a
substantial risk to consumers due to
negative LCC savings for most
equipment, with a shipment weighted
average consumer benefit of ¥$3,898,
¥$1,348, and ¥$1,139, respectively,
while at TSL 2 it is $641. Therefore,
DOE has tentatively concluded that the
efficiency levels above TSL 2 are not
justified. Additionally, at the examined
efficiency levels greater than TSL 2 DOE
is estimating that a disproportionate
fraction of consumers would be
negatively impacted by these efficiency
levels. DOE estimates that shipment
weighted fraction of negatively
impacted consumers for TSL 3, TSL 4,
and TSL 5 (max-tech) to be 42, 46, and
58 percent, respectively.
Therefore, based on the previous
considerations, DOE proposes to adopt
the energy conservation standards for
medium-voltage dry-type distribution
transformers at TSL 2. The proposed
amended energy conservation standards
for medium-voltage dry-type
distribution transformers, which are
expressed as percentage efficiency at 50
percent PUL are shown in Table V.78.
TABLE V.78—PROPOSED AMENDED ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS
[Electrical efficiency by kVA and equipment class]
Single-phase
Three-phase
BIL
BIL
kVA
lotter on DSK11XQN23PROD with PROPOSALS3
Equipment class
20–45 kV
46–95 kV
≥96 kV
EC5
EC7
EC9
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
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98.49
98.64
98.74
98.86
98.94
99.06
99.16
99.23
99.30
99.34
99.38
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98.07
98.30
98.47
98.58
98.71
98.80
98.95
99.05
99.13
99.21
99.26
99.31
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........................
........................
........................
98.68
98.77
98.92
99.02
99.09
99.18
99.23
99.28
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kVA
20–45 kV
46–95 kV
≥96 kV
EC6
EC8
EC10
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1000 ......................
1500 ......................
97.74
98.11
98.29
98.49
98.67
98.78
98.94
99.04
99.18
99.29
99.35
99.43
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97.45
97.86
98.07
98.31
98.52
98.66
98.82
98.93
99.09
99.21
99.28
99.37
........................
........................
........................
........................
........................
........................
98.71
98.82
99.00
99.12
99.20
99.29
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TABLE V.78—PROPOSED AMENDED ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE DRY-TYPE DISTRIBUTION
TRANSFORMERS—Continued
[Electrical efficiency by kVA and equipment class]
Single-phase
Three-phase
BIL
BIL
kVA
Equipment class
20–45 kV
46–95 kV
≥96 kV
EC5
EC7
EC9
kVA
2000
2500
3750
5000
4. Annualized Benefits and Costs of the
Proposed Standards for LiquidImmersed Distribution Transformers
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The annualized
net benefit is (1) the annualized national
economic value (expressed in 2021$) of
the benefits from operating products
that meet the proposed standards
(consisting primarily of operating cost
savings from using less energy, minus
increases in product purchase costs, and
(2) the annualized monetary value of the
climate and health benefits from
emission reductions.
20–45 kV
46–95 kV
≥96 kV
EC6
EC8
EC10
......................
......................
......................
......................
Table V.79 shows the annualized
values for the proposed standards for
distribution transformers, expressed in
2021$. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and NOX
and SO2 reduction benefits, and a 3percent discount rate case for GHG
social costs, the estimated cost of the
proposed standards for distribution
transformers is $424.8 million per year
in increased equipment costs, while the
estimated annual benefits are $451.9
million from reduced equipment
operating costs, $497.4 million from
99.49
99.52
99.58
99.62
99.42
99.47
99.53
99.58
99.35
99.40
99.47
99.51
GHG reductions, and $495.3million
from reduced NOX and SO2 emissions.
In this case, the net benefit amounts to
$1,019.8 million per year.
Using a 3-percent discount rate for all
benefits and costs, the estimated cost of
the proposed standards for distribution
transformers is $429.5 million per year
in increased equipment costs, while the
estimated annual benefits are $7,33.5
million in reduced operating costs,
$497.4 million from GHG reductions,
and $894.3 million from reduced NOX
and SO2 emissions. In this case, the net
benefit amounts to $1,695.8 million per
year.
TABLE V.79—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR LIQUIDIMMERSED DISTRIBUTION TRANSFORMERS (TSL 4)
Million
2021$/year
Category
Primary estimate
Low-net-benefits estimate
High-net-benefits estimate
733.5
497.4
894.3
2,125.3
429.5
1,695.8
686.9
478.9
860.5
2,026.3
449.0
1,577.3
789.9
519.5
934.8
2,244.2
413.2
1,831.0
451.9
497.4
495.3
1,444.7
424.8
1,019.8
425.7
478.9
477.9
1,382.5
442.1
940.5
482.2
519.5
515.3
1,517.0
409.9
1,107.2
3% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * .........................................................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Equipment Costs ‡ .................................................................................
Net Benefits .................................................................................................................................
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * (3% discount rate) ..........................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Equipment Costs ‡ .................................................................................
Net Benefits .................................................................................................................................
This table presents the annualized costs and benefits associated with liquid-immersed distribution transformers equipment shipped in 2027–
2056. These results include benefits to consumers which accrue after 2055 from the products purchased in 2027–2056.
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* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing PM2.5 and (for NOX) ozone
precursor health benefits, but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
5. Annualized Benefits and Costs of the
Proposed Standards for Low-Voltage
Distribution Transformers
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The annualized
net benefit is (1) the annualized national
economic value (expressed in 2021$) of
the benefits from operating products
that meet the proposed standards
(consisting primarily of operating cost
savings from using less energy, minus
increases in product purchase costs, and
(2) the annualized monetary value of the
climate and health benefits from
emission reductions.
Table V.80 shows the annualized
values for the proposed standards for
distribution transformers, expressed in
2021$. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and NOX
and SO2 reduction benefits, and a 3percent discount rate case for GHG
social costs, the estimated cost of the
proposed standards for distribution
transformers is $216.9 million per year
in increased equipment costs, while the
estimated annual benefits are $495.0
million from reduced equipment
operating costs, $159.2 million from
GHG reductions, and $162.1 million
from reduced NOX and SO2 emissions.
In this case, the net benefit amounts to
$599.4 million per year.
Using a 3-percent discount rate for all
benefits and costs, the estimated cost of
the proposed standards for distribution
transformers is $219.3 million per year
in increased equipment costs, while the
estimated annual benefits are $772.1
million in reduced operating costs,
$159.2 million from GHG reductions,
and $281.8 million from reduced NOX
and SO2 emissions. In this case, the net
benefit amounts to $993.8 million per
year.
TABLE V.80—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR LOW-VOLTAGE
DISTRIBUTION TRANSFORMERS (TSL 5)
Million
2021$/year
Category
Primary estimate
Low-net-benefits estimate
High-net-benefits estimate
772.1
159.2
281.8
1,213.1
219.3
993.8
716.9
151.6
268.3
1,136.7
228.7
908.0
831.3
165.9
293.9
1,291.1
208.7
1,082.4
495.0
159.2
162.1
816.3
216.9
599.4
462.8
151.6
154.9
769.3
225.2
544.1
528.7
165.9
168.2
862.8
207.3
655.5
3% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * .........................................................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * (3% discount rate) ..........................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
This table presents the annualized costs and benefits associated with low-voltage dry-type distribution transformers equipment shipped in
2027–2056. These results include benefits to consumers which accrue after 2055 from the products purchased in 2027–2056.
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* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing PM2.5 and (for NOX) ozone
precursor health benefits, but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
6. Annualized Benefits and Costs of the
Proposed Standards for Medium-Voltage
Distribution Transformers
The benefits and costs of the proposed
standards can also be expressed in terms
of annualized values. The annualized
net benefit is (1) the annualized national
economic value (expressed in 2021$) of
the benefits from operating products
that meet the proposed standards
(consisting primarily of operating cost
savings from using less energy, minus
increases in product purchase costs, and
(2) the annualized monetary value of the
climate and health benefits from
emission reductions.
Table V.81 shows the annualized
values for the proposed standards for
distribution transformers, expressed in
2021$. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for
consumer benefits and costs and NOX
and SO2 reduction benefits, and a 3percent discount rate case for GHG
social costs, the estimated cost of the
proposed standards for distribution
transformers is $10.8 million per year in
increased equipment costs, while the
estimated annual benefits are $14.9
million from reduced equipment
operating costs, $7.6 million from GHG
reductions, and $7.8 million from
reduced NOX and SO2 emissions. In this
case, the net benefit amounts to $19.5
million per year.
Using a 3-percent discount rate for all
benefits and costs, the estimated cost of
the proposed standards for distribution
transformers is $11.0 million per year in
increased equipment costs, while the
estimated annual benefits are $23.3
million in reduced operating costs, $7.6
million from GHG reductions, and $13.5
million from reduced NOX and SO2
emissions. In this case, the net benefit
amounts to $33.5 million per year.
TABLE V.81—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR MEDIUMVOLTAGE DISTRIBUTION TRANSFORMERS (TSL 2)
Million
2021$/year
Category
Primary estimate
Low-net-benefits estimate
High-net-benefits estimate
23.3
7.6
13.5
44.4
11.0
33.5
22.2
7.5
13.2
42.9
11.7
31.1
25.8
8.2
14.5
48.5
10.7
37.7
14.9
7.6
7.8
30.3
10.8
19.5
14.3
7.5
7.6
29.4
11.6
17.9
16.4
8.2
8.3
32.9
10.6
22.2
3% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * .........................................................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * (3% discount rate) ..........................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
This table presents the annualized costs and benefits associated with medium-voltage dry-type distribution transformers equipment shipped in
2027¥2056. These results include benefits to consumers which accrue after 2055 from the products purchased in 2027¥2056.
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Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule, DOE has reverted to its approach prior to
the injunction and present monetized greenhouse gas abatement benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing PM2.5 and (for NOX) ozone
precursor health benefits, but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
7. Benefits and Costs of the Proposed
Standards for all Considered
Distribution Transformers
As described in sections V.C.1
through V.C.6, for this NOPR DOE is
proposing TSL 4 for liquid-immersed,
TSL 5 for low-voltage dry-type, and TSL
2 for medium-voltage dry-type
distribution transformers. Table VI.1
shows the combined cumulative
benefits, and Table V.83 shows the
combined annualized benefits for the
proposed levels for all distribution
transformers.
TABLE V.82—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
ALL DISTRIBUTION TRANSFORMERS AT PROPOSED STANDARD LEVELS
Billion $2021
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................
Climate Benefits * .................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................
Net Benefits .........................................................................................................................................................................
26.63
11.56
20.72
58.91
11.49
47.42
7% discount rate
lotter on DSK11XQN23PROD with PROPOSALS3
Consumer Operating Cost Savings .....................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................
Health Benefits ** .................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................
Net Benefits .........................................................................................................................................................................
9.11
11.56
6.29
26.97
6.17
20.79
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
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TABLE V.8384—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR ALL
DISTRIBUTION TRANSFORMERS AT PROPOSED STANDARD LEVELS
Million
2021$/year
Category
Primary estimate
Low-net-benefits estimate
High-net-benefits estimate
1,528.9
664.2
1,189.6
3,382.8
659.8
2,723.1
1,426.0
638.0
1,142.0
3,205.9
689.4
2,516.4
1,647.0
693.6
1,243.2
3,583.8
632.6
2,951.1
961.8
664.2
665.2
2,291.3
652.5
1,638.7
902.8
638.0
640.4
2,181.2
678.9
1,502.5
1,027.3
693.6
691.8
2,412.7
627.8
1,784.9
3% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * .........................................................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
7% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * (3% discount rate) ..........................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
D. Reporting, Certification, and
Sampling Plan
lotter on DSK11XQN23PROD with PROPOSALS3
Manufacturers, including importers,
must use product-specific certification
templates to certify compliance to DOE.
For distribution transformers, the
certification template reflects the
general certification requirements
specified at 10 CFR 429.12 and the
product-specific requirements specified
at 10 CFR 429.47. As discussed in the
previous paragraphs, DOE is not
proposing to amend the product-specific
certification requirements for this
equipment.
VI. Procedural Issues and Regulatory
Review
A. Review Under Executive Orders
12866 and 13563
Executive Order (‘‘E.O.’’)12866,
‘‘Regulatory Planning and Review,’’ as
supplemented and reaffirmed by E.O.
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13563, ‘‘Improving Regulation and
Regulatory Review, 76 FR 3821 (Jan. 21,
2011), requires agencies, to the extent
permitted by law, to (1) propose or
adopt a regulation only upon a reasoned
determination that its benefits justify its
costs (recognizing that some benefits
and costs are difficult to quantify); (2)
tailor regulations to impose the least
burden on society, consistent with
obtaining regulatory objectives, taking
into account, among other things, and to
the extent practicable, the costs of
cumulative regulations; (3) select, in
choosing among alternative regulatory
approaches, those approaches that
maximize net benefits (including
potential economic, environmental,
public health and safety, and other
advantages; distributive impacts; and
equity); (4) to the extent feasible, specify
performance objectives, rather than
specifying the behavior or manner of
compliance that regulated entities must
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adopt; and (5) identify and assess
available alternatives to direct
regulation, including providing
economic incentives to encourage the
desired behavior, such as user fees or
marketable permits, or providing
information upon which choices can be
made by the public. DOE emphasizes as
well that E.O. 13563 requires agencies to
use the best available techniques to
quantify anticipated present and future
benefits and costs as accurately as
possible. In its guidance, the Office of
Information and Regulatory Affairs
(‘‘OIRA’’) in the Office of Management
and Budget (‘‘OMB’’) has emphasized
that such techniques may include
identifying changing future compliance
costs that might result from
technological innovation or anticipated
behavioral changes. For the reasons
stated in the preamble, this proposed/
final regulatory action is consistent with
these principles.
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Section 6(a) of E.O. 12866 also
requires agencies to submit ‘‘significant
regulatory actions’’ to OIRA for review.
OIRA has determined that this proposed
regulatory action constitutes an
economically significant regulatory
action under section 3(f) of E.O. 12866.
Accordingly, pursuant to section
6(a)(3)(C) of E.O. 12866, DOE has
provided to OIRA an assessment,
including the underlying analysis, of
benefits and costs anticipated from the
proposed regulatory action, together
with, to the extent feasible, a
quantification of those costs; and an
assessment, including the underlying
analysis, of costs and benefits of
potentially effective and reasonably
feasible alternatives to the planned
regulation, and an explanation why the
planned regulatory action is preferable
to the identified potential alternatives.
These assessments are summarized in
this preamble and further detail can be
found in the technical support
document for this rulemaking. A
summary of the potential costs and
benefits of the regulatory action is
presented in Table VI.1 and Table VI.2.
TABLE VI.1—SUMMARY OF MONETIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR
ALL DISTRIBUTION TRANSFORMERS AND PROPOSED STANDARD LEVELS
Billion $2021
3% discount rate
Consumer Operating Cost Savings .....................................................................................................................................
Climate Benefits * .................................................................................................................................................................
Health Benefits ** .................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................
Net Benefits .........................................................................................................................................................................
26.63
11.56
20.72
58.91
11.49
47.42
7% discount rate
Consumer Operating Cost Savings .....................................................................................................................................
Climate Benefits * (3% discount rate) ..................................................................................................................................
Health Benefits ** .................................................................................................................................................................
Total Benefits † ....................................................................................................................................................................
Consumer Incremental Product Costs ‡ ..............................................................................................................................
Net Benefits .........................................................................................................................................................................
9.11
11.56
6.29
26.97
6.17
20.79
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to monetize other effects such as
health benefits from reductions in direct PM2.5 emissions. The health benefits are presented at real discount rates of 3 and 7 percent. See section IV.L of this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
TABLE VI.2—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR ALL
DISTRIBUTION TRANSFORMERS AND PROPOSED STANDARD LEVELS
Million 2021$/year
Category
Primary estimate
Low-net-benefits estimate
High-net-benefits estimate
1,528.9
664.2
1,189.6
3,382.8
659.8
2,723.1
1,426.0
638.0
1,142.0
3,205.9
689.4
2,516.4
1,647.0
693.6
1,243.2
3,583.8
632.6
2,951.1
961.8
902.8
1,027.3
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3% discount rate
Consumer Operating Cost Savings .............................................................................................
Climate Benefits * .........................................................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
7% discount rate
Consumer Operating Cost Savings .............................................................................................
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TABLE VI.2—ANNUALIZED BENEFITS AND COSTS OF PROPOSED ENERGY CONSERVATION STANDARDS FOR ALL
DISTRIBUTION TRANSFORMERS AND PROPOSED STANDARD LEVELS—Continued
Million 2021$/year
Category
Primary estimate
Climate Benefits * (3% discount rate) ..........................................................................................
Health Benefits ** .........................................................................................................................
Total Benefits † ............................................................................................................................
Consumer Incremental Product Costs ‡ ......................................................................................
Net Benefits .................................................................................................................................
664.2
665.2
2,291.3
652.5
1,638.7
Low-net-benefits estimate
High-net-benefits estimate
638.0
640.4
2,181.2
678.9
1,502.5
693.6
691.8
2,412.7
627.8
1,784.9
This table presents the costs and benefits associated with distribution transformers shipped in 2027–2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027–2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC–CO2), methane (SC–CH4), and nitrous oxide
(SC–N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate), as shown in Table
V.73, Table V.74, and Table V.75. Together these represent the global social cost of greenhouse gases (SC–GHG). For presentational purposes
of this table, the climate benefits associated with the average SC–GHG at a 3 percent discount rate are shown, but the Department does not
have a single central SC–GHG point estimate. See section. IV.L of this document for more details. On March 16, 2022, the Fifth Circuit Court of
Appeals (No. 22–30087) granted the Federal government’s emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana v. Biden, No. 21–cv–1074–JDC–KK (W.D. La.). As a result of the Fifth Circuit’s order, the preliminary injunction is no
longer in effect, pending resolution of the Federal government’s appeal of that injunction or a further court order. Among other things, the preliminary injunction enjoined the defendants in that case from ‘‘adopting, employing, treating as binding, or relying upon’’ the interim estimates of the
social cost of greenhouse gases—which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on February
26, 2021—to monetize the benefits of reducing greenhouse gas emissions. In the absence of further intervening court orders, DOE will revert to
its approach prior to the injunction and present monetized benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low estimates of the monetized
value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health benefits and (for NOX) ozone precursor health benefits, but
will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
† Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total and net benefits for both the 3-percent
and 7-percent cases are presented using the average SC–GHG with 3-percent discount rate, but the Department does not have a single central
SC–GHG point estimate. DOE emphasizes the importance and value of considering the benefits calculated using all four SC–GHG estimates.
See Table V.69 for net benefits using all four SC–GHG estimates.
‡ Costs include incremental equipment costs as well as installation costs.
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B. Review Under the Regulatory
Flexibility Act
The Regulatory Flexibility Act (5
U.S.C. 601 et seq.) requires preparation
of an initial regulatory flexibility
analysis (‘‘IRFA’’) for any rule that by
law must be proposed for public
comment, unless the agency certifies
that the rule, if promulgated, will not
have a significant economic impact on
a substantial number of small entities.
As required by E.O. 13272, ‘‘Proper
Consideration of Small Entities in
Agency Rulemaking,’’ 67 FR 53461
(Aug. 16, 2002), DOE published
procedures and policies on February 19,
2003, to ensure that the potential
impacts of its rules on small entities are
properly considered during the
rulemaking process. 68 FR 7990. DOE
has made its procedures and policies
available on the Office of the General
Counsel’s website www.energy.gov/gc/
office-general-counsel. DOE has
prepared the following IRFA for the
products that are the subject of this
rulemaking.
For manufacturers of distribution
transformers, the SBA has set a size
threshold, which defines those entities
classified as ‘‘small businesses’’ for the
purposes of the statute. DOE used the
SBA’s small business size standards to
determine whether any small entities
would be subject to the requirements of
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the rule. (See 13 CFR part 121.) The size
standards are listed by North American
Industry Classification System
(‘‘NAICS’’) code and industry
description and are available at
www.sba.gov/document/support--tablesize-standards. Manufacturing of
distribution transformers is classified
under NAICS 335311, ‘‘Power,
Distribution, and Specialty Transformer
Manufacturing.’’ The SBA sets a
threshold of 750 employees or fewer for
an entity to be considered as a small
business for this category.
1. Description of Reasons Why Action Is
Being Considered
EPCA requires that, not later than 6
years after the issuance of any final rule
establishing or amending a standard,
DOE must publish either a notice of
determination that standards for the
product do not need to be amended, or
a NOPR including new proposed energy
conservation standards (proceeding to a
final rule, as appropriate). (42 U.S.C.
6316(e)(1); 42 U.S.C. 6295(m)(1)).
2. Objectives of, and Legal Basis for,
Rule
DOE must follow specific statutory
criteria for prescribing new or amended
standards for covered equipment,
including distribution transformers.
Any new or amended standard for a
covered product must be designed to
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achieve the maximum improvement in
energy efficiency that the Secretary of
Energy determines is technologically
feasible and economically justified. (42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)
and 42 U.S.C. 6295(o)(3)(B)).
3. Description on Estimated Number of
Small Entities Regulated
DOE conducted a more focused
inquiry of the companies that could be
small businesses that manufacture
distribution transformers covered by
this rulemaking. DOE used publicly
available information to identify
potential small businesses. DOE’s
research involved industry trade
association membership directories
(including NEMA), DOE’s publicly
available Compliance Certification
Database (‘‘CCD’’), California Energy
Commission’s MAEDBS database to
create a list of companies that
manufacture or sell distribution
transformers covered by this
rulemaking. DOE also asked
stakeholders and industry
representatives if they were aware of
any other small businesses during
manufacturer interviews. DOE contacted
select companies on its list, as
necessary, to determine whether they
met the SBA’s definition of a small
business that manufacturers distribution
transformers covered by this
rulemaking. DOE screened out
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companies that did not offer products
covered by this rulemaking, did not
meet the definition of a ‘‘small
business,’’ or are foreign owned and
operated.
DOE’s analysis identified 29
companies that sell or manufacture
distribution transformers coved by this
rulemaking in the U.S. market. At least
two of these companies are not the
original equipment manufacturers
(‘‘OEM’’) and instead privately label
distribution transformers that are
manufactured by another distribution
transformer manufacturer. Of the 27
companies that are OEMs, DOE
identified 10 potential companies that
have fewer than 750 total employees
and are not entirely foreign owned and
operated. There are three small
businesses that manufacture liquidimmersed distribution transformers;
there are three small businesses that
manufacture LVDT and MVDT
distribution transformers; and there are
four small businesses that only
manufacture LVDT distribution
transformers.115
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Liquid-Immersed
Liquid-immersed distribution
transformers account for over 80 percent
of all distribution transformer
shipments covered by this rulemaking.
Six major manufacturers supply more
than 80 percent of the market for liquidimmersed distribution transformers
covered by this rulemaking. None of
these six major manufacturers of liquidimmersed distribution transformers are
small businesses. Most liquid-immersed
distribution transformers are
manufactured domestically. Electric
utilities compose the customer base and
typically buy on a first-cost basis. Many
small manufacturers position
themselves towards the higher end of
the market or in particular product
niches, such as network transformers or
harmonic mitigating transformers, but,
in general, competition is based on price
after a given unit’s specs are prescribed
by a customer. None of the three small
businesses have a market share larger
than five percent of the liquid-immersed
distribution transformer market.
Low-Voltage Dry Type
LVDT distribution transformers
account for approximately 18 percent of
all distribution shipments covered by
this rulemaking. Four major
manufacturers supply more than 80
percent of the market for LVDT
115 Therefore, there are a total of seven small
businesses that manufacture LVDT distribution
transformers. Four that exclusively manufacture
LVDT and three that manufacture both LVDT and
MVDT.
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distribution transformers covered by
this rulemaking. None of these four
major LVDT distribution transformer
manufacturers are small businesses. The
majority of LVDT distribution
transformers are manufactured outside
the U.S., mostly in Canada and Mexico.
The customer base rarely purchases on
efficiency and is very first-cost
conscious, which, in turn, places a
premium on economies of scale in
manufacturing. However, there are
universities and other buildings that
purchase LVDT based on efficiency as
more and more organizations are
striving to get to reduced or net-zero
emission targets.
In the LVDT market, lower volume
manufacturers typically do not compete
directly with larger volume
manufacturers, as these lower volume
manufacturers are frequently not able to
compete on a first cost basis. However,
there are lower volume manufactures
that do serve customers that purchase
more efficient LVDT distribution
transformers. Lastly, there are some
smaller firms that focus on the
engineering and design of LVDT
distribution transformers and source the
production of some parts of the
distribution transformer, most
frequently the cores, to another
company that manufactures those
components.
Medium-Voltage Dry-Type
MVDT distribution transformers
account for less than one percent of all
distribution transformer shipments
covered by this rulemaking. There is
one large MVDT distribution
transformer manufacturer with a
substantial share of the market. The rest
of MVDT distribution transformer
market is served by a mix of large and
small manufactures. Most MVDT
distribution transformers are
manufactured domestically. Electric
utilities and industrial users make up
most of the customer base and typically
buy on first-cost or features other than
efficiency.
4. Description and Estimate of
Compliance Requirements Including
Differences in Cost, if Any, for Different
Groups of Small Entities
Liquid-Immersed and Low-Voltage DryType
DOE is proposing to amend energy
conservation standards to be at TSL 4
for liquid-immersed distribution
transformers and TSL 5 for LVDT
distribution transformers. This
corresponds to EL 4 for most liquidimmersed distribution transformer
equipment classes and EL 5 for all
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1847
LVDT distribution transformer
equipment classes.
Based on the LCC consumer choice
model, DOE anticipates that most, if not
all, liquid-immersed and LVDT
distribution transformer manufacturers
would use amorphous cores in their
distribution transformers to meet these
proposed amended energy conservation
standards. While DOE anticipates that
several large liquid-immersed and LVDT
distribution transformer manufacturers
would make significant capital
investments to accommodate the
production of amorphous cores, DOE
does not anticipate that any small
businesses will make these capital
investments to be able to produce their
own amorphous cores, based on the
large capital investments need to be able
to make amorphous cores and the
limited ability for small businesses to
access large capital investments. Based
on manufacturer interviews and market
research, DOE was able to identify one
LVDT small business that manufactures
their own cores and was not able to
identify any liquid-immersed small
businesses that manufacture their own
cores. The one LVDT small business
that is currently manufacturing their
own cores would have to make a
business decision to either make a
significant capital investment to be able
to make amorphous cores or to outsource the production of their LVDT
cores. Out-sourcing the production of
their cores would be a significant
change in their production process and
could result in a reduction in this small
business’ market share in the LVDT
distribution transformer market.
DOE acknowledges that there is
uncertainty if these small businesses
will be able to find core manufacturers
that will supply them with amorphous
cores in order to comply with the
proposed energy conservation standards
for liquid-immersed and LVDT
distribution transformers. DOE
anticipates that there will be an increase
in the number of large liquid-immersed
and LVDT distribution transformer
manufacturers that will out-source the
production of their cores to core
manufacturers capable of producing
amorphous cores. This could increase
the competition for small businesses to
procure amorphous cores for their
distribution transformers. Small
businesses manufacturing liquidimmersed and LVDT distribution
transformers must be able to procure
amorphous cores suitable for their
distribution transformers at a cost that
allows them to continue to be
competitive in the market.
Based on feedback received during
manufacturer interviews, DOE does not
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anticipate that small businesses that are
currently not producing their own cores
would have to make a significant capital
investment in their production lines to
be able to use amorphous cores, that are
purchased from a core manufacturer, in
the distribution transformers that they
manufacture. There will be some
additional product conversion costs, in
the form of additional R&D and testing,
that will need to be incurred by small
businesses that manufacture liquidimmersed and LVDT distribution
transformers, even if they do not
manufacture their own cores. The
methodology used to calculate product
conversion costs, described in section
IV.J.2.c, estimates that manufacturers
would incur approximately one
additional year of R&D expenditure to
redesign their distribution transformers
to be capable of accommodating the use
of an amorphous core. Based on the
financial parameters used in the GRIM,
DOE estimated that the normal annual
R&D is approximately 3.0 percent of
annual revenue. Therefore, liquidimmersed and LVDT small businesses
would incur an additional 3.0 percent of
annual revenue to redesign their
distribution transformers to be able to
accommodate using amorphous cores
there were purchased from core
manufacturers.
Medium-Voltage Dry-Type
DOE is proposing to amend energy
conservation standards to be at TSL 2
for MVDT distribution transformers.
This corresponds to EL 2 for all MVDT
distribution transformer equipment
classes. Based on the LCC consumer
choice model, DOE does not anticipate
that any MVDT distribution transformer
manufacturers would use amorphous
cores in their MVDT distribution
transformers to meet these proposed
energy conservation standards. DOE
does not anticipate that MVDT
manufacturers would make significant
investments to either be able to produce
cores capable of meeting these proposed
amended energy conservation standards
or be able to integrate more efficient
purchased cores from core
manufacturers. There will be some
additional product conversion costs, in
the form of additional R&D and testing,
that will need to be incurred by small
businesses that manufacture MVDT
distribution transformers, even if they
do not manufacture their own cores.
The methodology used to calculate
product conversion costs, described in
section IV.J.2.c, estimates that
manufacturers would incur
approximately a half of a year of
additional R&D expenditure to redesign
their distribution transformers to higher
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efficiency levels, while not using
amorphous cores. Based on the financial
parameters used in the GRIM, DOE
estimated that the normal annual R&D is
approximately 3.0 percent of annual
revenue. Therefore, MVDT small
businesses would include an additional
1.5 percent of annual revenue to
redesign, MVDT distribution
transformers to higher efficiency levels
that could be met without using
amorphous cores.
DOE requests comment on the
number of small businesses identified
that manufacture distribution
transformers covered by this rulemaking
(three small liquid-immersed and seven
LVDT small businesses; three of which
also manufacture MVDT). Additionally,
DOE requests comment on its initial
assumption that only one LVDT small
business and no liquid-immersed small
businesses manufacturer their own
cores used in their distribution
transformers.
5. Duplication, Overlap, and Conflict
With Other Rules and Regulations
Starting in 2018, imports of raw
electrical steel have been subject to a 25
percent ad valorem tariff. This tariff
does not apply to products made from
electrical steel, such as transformer
laminations and finished cores. In a
report published on November 18, 2021,
the Department of Commerce presented
its conclusions and potential options to
ensure the domestic supply chain of
electrical steel and transformer
components. 86 FR 64606 However, no
modifications to the tariff structure have
been made at the time of publication of
this NOPR. As discussed in section
IV.A.5, modification to the tariff
structure could impact the pricing and
availability of certain electrical steel
grades depending on each
manufacturer’s given supply chain and
sourcing practices.
DOE is not aware of any other rules
or regulations that duplicate, overlap, or
conflict with the rule being considered
today.
6. Significant Alternatives to the Rule
The discussion in the previous
section analyzes impacts on small
businesses that would result from DOE’s
proposed rule, represented by TSL 4 for
liquid-immersed distribution
transformer equipment classes; TSL 5
for LVDT equipment classes; and TSL 2
for MVDT equipment classes. In
reviewing alternatives to the proposed
rule, DOE examined energy
conservation standards set at lower
efficiency levels. While lower TSLs
would reduce the impacts on small
business manufacturers, it would come
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at the expense of a reduction in energy
savings. For liquid-immersed equipment
classes TSL 1 achieves 60 percent lower
energy savings compared to the energy
savings at TSL 4; TSL 2 achieves 37
percent lower energy savings compared
to the energy savings at TSL 4. For
LVDT equipment classes TSL 1 achieves
85 percent lower energy savings
compared to the energy savings at TSL
5; TSL 2 achieves 78 percent lower
energy savings compared to the energy
savings at TSL 5; TSL 3 achieves 66
percent lower energy savings compared
to the energy savings at TSL 5; and TSL
4 achieves 8 percent lower energy
savings compared to the energy savings
at TSL 5. For MVDT equipment classes
TSL 1 achieves 33 percent lower energy
savings compared to the energy savings
at TSL 2.
Based on the presented discussion,
DOE tentatively concludes that the
benefits of the energy savings from TSL
4 for liquid-immersed equipment
classes; TSL 5 for LVDT equipment
classes; and TSL 2 for MVDT equipment
classes exceed the potential burdens
placed on distribution transformers
manufacturers, including small business
manufacturers. Accordingly, DOE does
not propose one of the other TSLs
considered in the analysis, or the other
policy alternatives examined as part of
the regulatory impact analysis and
included in chapter 17 of the NOPR
TSD.
Additional compliance flexibilities
may be available through other means.
EPCA provides that a manufacturer
whose annual gross revenue from all of
its operations does not exceed $8
million may apply for an exemption
from all or part of an energy
conservation standard for a period not
longer than 24 months after the effective
date of a final rule establishing the
standard. (42 U.S.C. 6295(t))
Additionally, manufacturers subject to
DOE’s energy efficiency standards may
apply to DOE’s Office of Hearings and
Appeals for exception relief under
certain circumstances. Manufacturers
should refer to 10 CFR part 430, subpart
E, and 10 CFR part 1003 for additional
details.
C. Review Under the Paperwork
Reduction Act
Manufacturers of distribution
transformers must certify to DOE that
their products comply with any
applicable energy conservation
standards. In certifying compliance,
manufacturers must test their products
according to the DOE test procedures for
distribution transformers, including any
amendments adopted for those test
procedures. DOE has established
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regulations for the certification and
recordkeeping requirements for all
covered consumer products and
commercial equipment, including
distribution transformers. (See generally
10 CFR part 429). The collection-ofinformation requirement for the
certification and recordkeeping is
subject to review and approval by OMB
under the Paperwork Reduction Act
(‘‘PRA’’). This requirement has been
approved by OMB under OMB control
number 1910–1400. Public reporting
burden for the certification is estimated
to average 35 hours per response,
including the time for reviewing
instructions, searching existing data
sources, gathering and maintaining the
data needed, and completing and
reviewing the collection of information.
Notwithstanding any other provision
of the law, no person is required to
respond to, nor shall any person be
subject to a penalty for failure to comply
with, a collection of information subject
to the requirements of the PRA, unless
that collection of information displays a
currently valid OMB Control Number.
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D. Review Under the National
Environmental Policy Act of 1969
DOE is analyzing this proposed
regulation in accordance with the
National Environmental Policy Act of
1969 (‘‘NEPA’’) and DOE’s NEPA
implementing regulations (10 CFR part
1021). DOE’s regulations include a
categorical exclusion for rulemakings
that establish energy conservation
standards for consumer products or
industrial equipment. 10 CFR part 1021,
subpart D, appendix B5.1. DOE
anticipates that this rulemaking
qualifies for categorical exclusion B5.1
because it is a rulemaking that
establishes energy conservation
standards for consumer products or
industrial equipment, none of the
exceptions identified in categorical
exclusion B5.1(b) apply, no
extraordinary circumstances exist that
require further environmental analysis,
and it otherwise meets the requirements
for application of a categorical
exclusion. See 10 CFR 1021.410. DOE
will complete its NEPA review before
issuing the final rule.
E. Review Under Executive Order 13132
E.O. 13132, ‘‘Federalism,’’ 64 FR
43255 (Aug. 10, 1999), imposes certain
requirements on Federal agencies
formulating and implementing policies
or regulations that preempt State law or
that have federalism implications. The
Executive order requires agencies to
examine the constitutional and statutory
authority supporting any action that
would limit the policymaking discretion
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of the States and to carefully assess the
necessity for such actions. The
Executive order also requires agencies to
have an accountable process to ensure
meaningful and timely input by State
and local officials in the development of
regulatory policies that have federalism
implications. On March 14, 2000, DOE
published a statement of policy
describing the intergovernmental
consultation process it will follow in the
development of such regulations. 65 FR
13735. DOE has examined this proposed
rule and has tentatively determined that
it would not have a substantial direct
effect on the States, on the relationship
between the national government and
the States, or on the distribution of
power and responsibilities among the
various levels of government. EPCA
governs and prescribes Federal
preemption of State regulations as to
energy conservation for the equipment
that are the subject of this proposed
rule. States can petition DOE for
exemption from such preemption to the
extent, and based on criteria, set forth in
EPCA. (42 U.S.C. 6297) Therefore, no
further action is required by Executive
Order 13132.
F. Review Under Executive Order 12988
With respect to the review of existing
regulations and the promulgation of
new regulations, section 3(a) of E.O.
12988, ‘‘Civil Justice Reform,’’ imposes
on Federal agencies the general duty to
adhere to the following requirements:
(1) eliminate drafting errors and
ambiguity, (2) write regulations to
minimize litigation, (3) provide a clear
legal standard for affected conduct
rather than a general standard, and (4)
promote simplification and burden
reduction. 61 FR 4729 (Feb. 7, 1996).
Regarding the review required by
section 3(a), section 3(b) of E.O. 12988
specifically requires that Executive
agencies make every reasonable effort to
ensure that the regulation: (1) clearly
specifies the preemptive effect, if any,
(2) clearly specifies any effect on
existing Federal law or regulation, (3)
provides a clear legal standard for
affected conduct while promoting
simplification and burden reduction, (4)
specifies the retroactive effect, if any, (5)
adequately defines key terms, and (6)
addresses other important issues
affecting clarity and general
draftsmanship under any guidelines
issued by the Attorney General. Section
3(c) of Executive Order 12988 requires
Executive agencies to review regulations
in light of applicable standards in
section 3(a) and section 3(b) to
determine whether they are met or it is
unreasonable to meet one or more of
them. DOE has completed the required
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1849
review and determined that, to the
extent permitted by law, this proposed
rule meets the relevant standards of E.O.
12988.
G. Review Under the Unfunded
Mandates Reform Act of 1995
Title II of the Unfunded Mandates
Reform Act of 1995 (‘‘UMRA’’) requires
each Federal agency to assess the effects
of Federal regulatory actions on State,
local, and Tribal governments and the
private sector. Public Law 104–4,
section 201 (codified at 2 U.S.C. 1531).
For a proposed regulatory action likely
to result in a rule that may cause the
expenditure by State, local, and Tribal
governments, in the aggregate, or by the
private sector of $100 million or more
in any one year (adjusted annually for
inflation), section 202 of UMRA requires
a Federal agency to publish a written
statement that estimates the resulting
costs, benefits, and other effects on the
national economy. (2 U.S.C. 1532(a), (b))
The UMRA also requires a Federal
agency to develop an effective process
to permit timely input by elected
officers of State, local, and Tribal
governments on a proposed ‘‘significant
intergovernmental mandate,’’ and
requires an agency plan for giving notice
and opportunity for timely input to
potentially affected small governments
before establishing any requirements
that might significantly or uniquely
affect them. On March 18, 1997, DOE
published a statement of policy on its
process for intergovernmental
consultation under UMRA. 62 FR
12820. DOE’s policy statement is also
available at www.energy.gov/sites/prod/
files/gcprod/documents/umra_97.pdf.
Although this proposed rule does not
contain a Federal intergovernmental
mandate, it may require expenditures of
$100 million or more in any one year by
the private sector. Such expenditures
may include: (1) investment in research
and development and in capital
expenditures by distribution
transformers manufacturers in the years
between the final rule and the
compliance date for the new standards
and (2) incremental additional
expenditures by consumers to purchase
higher-efficiency distribution
transformers, starting at the compliance
date for the applicable standard.
Section 202 of UMRA authorizes a
Federal agency to respond to the content
requirements of UMRA in any other
statement or analysis that accompanies
the proposed rule. (2 U.S.C. 1532(c))
The content requirements of section
202(b) of UMRA relevant to a private
sector mandate substantially overlap the
economic analysis requirements that
apply under section 325(o) of EPCA and
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Executive Order 12866. The
section of
this NOPR and the TSD for this
proposed rule respond to those
requirements.
Under section 205 of UMRA, the
Department is obligated to identify and
consider a reasonable number of
regulatory alternatives before
promulgating a rule for which a written
statement under section 202 is required.
(2 U.S.C. 1535(a)) DOE is required to
select from those alternatives the most
cost-effective and least burdensome
alternative that achieves the objectives
of the proposed rule unless DOE
publishes an explanation for doing
otherwise, or the selection of such an
alternative is inconsistent with law. As
required by 42 U.S.C. 6295(m) [or a
product-specific directive in 42 U.S.C.
6295 or 42 U.S.C. 6313], this proposed
rule would establish amended energy
conservation standards for distribution
transformers that are designed to
achieve the maximum improvement in
energy efficiency that DOE has
determined to be both technologically
feasible and economically justified, as
required by 42 U.S.C. 6295(o)(2)(A) and
42 U.S.C. 6295(o)(3)(B). A full
discussion of the alternatives
considered by DOE is presented in
chapter 17 of the TSD for this proposed
rule.
SUPPLEMENTARY INFORMATION
I. Review Under Executive Order 12630
Pursuant to E.O. 12630,
‘‘Governmental Actions and Interference
with Constitutionally Protected Property
Rights,’’ 53 FR 8859 (Mar. 15, 1988),
DOE has determined that this proposed
rule would not result in any takings that
might require compensation under the
Fifth Amendment to the U.S.
Constitution.
K. Review Under Executive Order 13211
E.O. 13211, ‘‘Actions Concerning
Regulations That Significantly Affect
Energy Supply, Distribution, or Use,’’ 66
FR 28355 (May 22, 2001), requires
Federal agencies to prepare and submit
to OIRA at OMB, a Statement of Energy
Effects for any proposed significant
energy action. A ‘‘significant energy
action’’ is defined as any action by an
agency that promulgates or is expected
to lead to promulgation of a final rule,
and that (1) is a significant regulatory
action under Executive Order 12866, or
any successor order; and (2) is likely to
have a significant adverse effect on the
supply, distribution, or use of energy, or
(3) is designated by the Administrator of
OIRA as a significant energy action. For
any proposed significant energy action,
the agency must give a detailed
statement of any adverse effects on
energy supply, distribution, or use
should the proposal be implemented,
and of reasonable alternatives to the
action and their expected benefits on
energy supply, distribution, and use.
DOE has tentatively concluded that
this regulatory action, which proposes
amended energy conservation standards
for distribution transformers, is not a
significant energy action because the
proposed standards are not likely to
have a significant adverse effect on the
supply, distribution, or use of energy,
nor has it been designated as such by
the Administrator at OIRA. Accordingly,
DOE has not prepared a Statement of
Energy Effects on this proposed rule.
J. Review Under the Treasury and
General Government Appropriations
Act, 2001
Section 515 of the Treasury and
General Government Appropriations
Act, 2001 (44 U.S.C. 3516 note) provides
L. Information Quality
On December 16, 2004, OMB, in
consultation with the Office of Science
and Technology Policy (‘‘OSTP’’),
issued its Final Information Quality
Bulletin for Peer Review (‘‘the
H. Review Under the Treasury and
General Government Appropriations
Act, 1999
Section 654 of the Treasury and
General Government Appropriations
Act, 1999 (Pub. L. 105–277) requires
Federal agencies to issue a Family
Policymaking Assessment for any rule
that may affect family well-being. This
proposed rule would not have any
impact on the autonomy or integrity of
the family as an institution.
Accordingly, DOE has concluded that it
is not necessary to prepare a Family
Policymaking Assessment.
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for Federal agencies to review most
disseminations of information to the
public under information quality
guidelines established by each agency
pursuant to general guidelines issued by
OMB. OMB’s guidelines were published
at 67 FR 8452 (Feb. 22, 2002), and
DOE’s guidelines were published at 67
FR 62446 (Oct. 7, 2002). Pursuant to
OMB Memorandum M–19–15,
Improving Implementation of the
Information Quality Act (April 24,
2019), DOE published updated
guidelines which are available at
www.energy.gov/sites/prod/files/2019/
12/f70/DOE%20Final
%20Updated%20IQA
%20Guidelines%20Dec%202019.pdf.
DOE has reviewed this NOPR under the
OMB and DOE guidelines and has
concluded that it is consistent with
applicable policies in those guidelines.
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Bulletin’’). 70 FR 2664 (Jan. 14, 2005).
The Bulletin establishes that certain
scientific information shall be peer
reviewed by qualified specialists before
it is disseminated by the Federal
Government, including influential
scientific information related to agency
regulatory actions. The purpose of the
bulletin is to enhance the quality and
credibility of the Government’s
scientific information. Under the
Bulletin, the energy conservation
standards rulemaking analyses are
‘‘influential scientific information,’’
which the Bulletin defines as ‘‘scientific
information the agency reasonably can
determine will have, or does have, a
clear and substantial impact on
important public policies or private
sector decisions.’’ 70 FR 2664, 2667.
In response to OMB’s Bulletin, DOE
conducted formal peer reviews of the
energy conservation standards
development process and the analyses
that are typically used and has prepared
a report describing that peer review.116
Generation of this report involved a
rigorous, formal, and documented
evaluation using objective criteria and
qualified and independent reviewers to
make a judgment as to the technical/
scientific/business merit, the actual or
anticipated results, and the productivity
and management effectiveness of
programs and/or projects. Because
available data, models, and
technological understanding have
changed since 2007, DOE has engaged
with the National Academy of Sciences
to review DOE’s analytical
methodologies to ascertain whether
modifications are needed to improve the
Department’s analyses. DOE is in the
process of evaluating the resulting
report.117
VII. Public Participation
A. Attendance at the Public Meeting
The time and date of the webinar
meeting are listed in the DATES section
at the beginning of this document.
Webinar registration information,
participant instructions, and
information about the capabilities
available to webinar participants will be
published on DOE’s website:
www.eere.energy.gov/buildings/
appliance_standards/
standards.aspx?productid=55.
116 The 2007 ‘‘Energy Conservation Standards
Rulemaking Peer Review Report’’ is available at the
following website: energy.gov/eere/buildings/
downloads/energy-conservation-standardsrulemaking-peer-review-report-0 (last accessed
January 2022).
117 The report is available at
www.nationalacademies.org/our-work/review-ofmethods-for-setting-building-and-equipmentperformance-standards.
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Participants are responsible for ensuring
their systems are compatible with the
webinar software.
B. Procedure for Submitting Prepared
General Statements for Distribution
Any person who has an interest in the
topics addressed in this proposed rule,
or who is representative of a group or
class of persons that has an interest in
these issues, may request an
opportunity to make an oral
presentation at the webinar. Such
persons may submit to
ApplianceStandardsQuestions@
ee.doe.gov. Persons who wish to speak
should include with their request a
computer file in WordPerfect, Microsoft
Word, PDF, or text (ASCII) file format
that briefly describes the nature of their
interest in this rulemaking and the
topics they wish to discuss. Such
persons should also provide a daytime
telephone number where they can be
reached.
DOE requests persons selected to
make an oral presentation to submit an
advance copy of their statements at least
two weeks before the webinar. At its
discretion, DOE may permit persons
who cannot supply an advance copy of
their statement to participate, if those
persons have made advance alternative
arrangements with the Building
Technologies Office. As necessary,
requests to give an oral presentation
should ask for such alternative
arrangements.
DOE will designate a DOE official to
preside at the webinar/public meeting
and may also use a professional
facilitator to aid discussion. The
meeting will not be a judicial or
evidentiary-type public hearing, but
DOE will conduct it in accordance with
section 336 of EPCA (42 U.S.C. 6306). A
court reporter will be present to record
the proceedings and prepare a
transcript. DOE reserves the right to
schedule the order of presentations and
to establish the procedures governing
the conduct of the webinar. There shall
not be discussion of proprietary
information, costs or prices, market
share, or other commercial matters
regulated by U.S. anti-trust laws. After
the webinar and until the end of the
comment period, interested parties may
submit further comments on the
proceedings and any aspect of the
rulemaking.
The webinar will be conducted in an
informal, conference style. DOE will a
general overview of the topics addressed
in this rulemaking, allow time for
prepared general statements by
participants, and encourage all
interested parties to share their views on
issues affecting this rulemaking. Each
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participant will be allowed to make a
general statement (within time limits
determined by DOE), before the
discussion of specific topics. DOE will
permit, as time permits, other
participants to comment briefly on any
general statements.
At the end of all prepared statements
on a topic, DOE will permit participants
to clarify their statements briefly.
Participants should be prepared to
answer questions by DOE and by other
participants concerning these issues.
DOE representatives may also ask
questions of participants concerning
other matters relevant to this proposed
rule. The official conducting the
webinar/public meeting will accept
additional comments or questions from
those attending, as time permits. The
presiding official will announce any
further procedural rules or modification
of the above procedures that may be
needed for the proper conduct of the
webinar.
A transcript of the webinar will be
included in the docket, which can be
viewed as described in the Docket
section at the beginning of this proposed
rule. In addition, any person may buy a
copy of the transcript from the
transcribing reporter.
C. Conduct of the Public Webinar
DOE will designate a DOE official to
preside at the webinar/public meeting
and may also use a professional
facilitator to aid discussion. The
meeting will not be a judicial or
evidentiary-type public hearing, but
DOE will conduct it in accordance with
section 336 of EPCA (42 U.S.C. 6306). A
court reporter will be present to record
the proceedings and prepare a
transcript. DOE reserves the right to
schedule the order of presentations and
to establish the procedures governing
the conduct of the webinar. There shall
not be discussion of proprietary
information, costs or prices, market
share, or other commercial matters
regulated by U.S. anti-trust laws. After
the webinar and until the end of the
comment period, interested parties may
submit further comments on the
proceedings and any aspect of the
rulemaking.
The webinar will be conducted in an
informal, conference style. DOE will a
general overview of the topics addressed
in this rulemaking, allow time for
prepared general statements by
participants, and encourage all
interested parties to share their views on
issues affecting this rulemaking. Each
participant will be allowed to make a
general statement (within time limits
determined by DOE), before the
discussion of specific topics. DOE will
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1851
permit, as time permits, other
participants to comment briefly on any
general statements.
At the end of all prepared statements
on a topic, DOE will permit participants
to clarify their statements briefly.
Participants should be prepared to
answer questions by DOE and by other
participants concerning these issues.
DOE representatives may also ask
questions of participants concerning
other matters relevant to this
rulemaking. The official conducting the
webinar/public meeting will accept
additional comments or questions from
those attending, as time permits. The
presiding official will announce any
further procedural rules or modification
of the above procedures that may be
needed for the proper conduct of the
webinar.
A transcript of the webinar will be
included in the docket, which can be
viewed as described in the Docket
section at the beginning of this proposed
rule. In addition, any person may buy a
copy of the transcript from the
transcribing reporter.
D. Submission of Comments
DOE will accept comments, data, and
information regarding this proposed
rule before or after the public meeting,
but no later than the date provided in
the DATES section at the beginning of
this proposed rule. Interested parties
may submit comments, data, and other
information using any of the methods
described in the ADDRESSES section at
the beginning of this document.
Submitting comments via
www.regulations.gov. The
www.regulations.gov web page will
require you to provide your name and
contact information. Your contact
information will be viewable to DOE
Building Technologies staff only. Your
contact information will not be publicly
viewable except for your first and last
names, organization name (if any), and
submitter representative name (if any).
If your comment is not processed
properly because of technical
difficulties, DOE will use this
information to contact you. If DOE
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, DOE may not be
able to consider your comment.
However, your contact information
will be publicly viewable if you include
it in the comment itself or in any
documents attached to your comment.
Any information that you do not want
to be publicly viewable should not be
included in your comment, nor in any
document attached to your comment.
Otherwise, persons viewing comments
will see only first and last names,
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organization names, correspondence
containing comments, and any
documents submitted with the
comments.
Do not submit to www.regulations.gov
information for which disclosure is
restricted by statute, such as trade
secrets and commercial or financial
information (hereinafter referred to as
Confidential Business Information
(‘‘CBI’’)). Comments submitted through
www.regulations.gov cannot be claimed
as CBI. Comments received through the
website will waive any CBI claims for
the information submitted. For
information on submitting CBI, see the
Confidential Business Information
section.
DOE processes submissions made
through www.regulations.gov before
posting. Normally, comments will be
posted within a few days of being
submitted. However, if large volumes of
comments are being processed
simultaneously, your comment may not
be viewable for up to several weeks.
Please keep the comment tracking
number that www.regulations.gov
provides after you have successfully
uploaded your comment.
Submitting comments via email.
Comments and documents submitted
via email also will be posted to
www.regulations.gov. If you do not want
your personal contact information to be
publicly viewable, do not include it in
your comment or any accompanying
documents. Instead, provide your
contact information in a cover letter.
Include your first and last names, email
address, telephone number, and
optional mailing address. The cover
letter will not be publicly viewable as
long as it does not include any
comments.
Include contact information each time
you submit comments, data, documents,
and other information to DOE. No
telefacsimiles (‘‘faxes’’) will be
accepted.
Comments, data, and other
information submitted to DOE
electronically should be provided in
PDF (preferred), Microsoft Word or
Excel, WordPerfect, or text (ASCII) file
format. Provide documents that are not
secured, that are written in English, and
that are free of any defects or viruses.
Documents should not contain special
characters or any form of encryption
and, if possible, they should carry the
electronic signature of the author.
Campaign form letters. Please submit
campaign form letters by the originating
organization in batches of between 50 to
500 form letters per PDF or as one form
letter with a list of supporters’ names
compiled into one or more PDFs. This
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reduces comment processing and
posting time.
Confidential Business Information.
Pursuant to 10 CFR 1004.11, any person
submitting information that he or she
believes to be confidential and exempt
by law from public disclosure should
submit via email two well-marked
copies: one copy of the document
marked ‘‘confidential’’ including all the
information believed to be confidential,
and one copy of the document marked
‘‘non-confidential’’ with the information
believed to be confidential deleted. DOE
will make its own determination about
the confidential status of the
information and treat it according to its
determination.
It is DOE’s policy that all comments
may be included in the public docket,
without change and as received,
including any personal information
provided in the comments (except
information deemed to be exempt from
public disclosure).
E. Issues on Which DOE Seeks Comment
Although DOE welcomes comments
on any aspect of this proposal, DOE is
particularly interested in receiving
comments and views of interested
parties concerning the following issues:
(1) DOE requests comment on the
proposed amendment to the definition
of drive (isolation) transformer. DOE
requests comment on its tentative
determination that voltage ratings of
208Y/120 and 480Y/277 indicate a
design for use in general purpose
applications. DOE also requests
comment on other voltage ratings or
other characteristics that would indicate
a design for use in general purpose
applications.
(2) DOE requests comment on its
proposed amendment to the definition
of ‘‘special-impedance transformer’’ and
whether it provides sufficient clarity as
to how to treat the normal impedance
ranges for non-standard kVA
distribution transformers.
(3) DOE requests comment on its
proposed definition for transformers
with a tap range of 20 percent or more.
(4) DOE requests comment on its
proposed amendments to the definitions
of sealed and nonventilated
transformers.
(5) DOE requests comment on its
proposed amendment to the definition
of uninterruptable power supply
transformers.
(6) DOE requests comment as to
whether its proposed definition better
aligns with industries understanding on
input and output voltages
(7) Further, DOE requests comment
and data on whether the proposed
amendment would impact products that
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are serving distribution applications,
and if so, the number of distribution
transformers impacted by the proposed
amendment.
(8) DOE requests comment and data as
to whether 5,000 kVA represents the
upper end of what is considered
distribution transformers or if another
value should be used.
(9) DOE requests comment and data as
to the number of shipments of threephase, liquid-immersed, distribution
transformers greater than 2,500 kVA that
would meet the in-scope voltage
limitations and the distribution of
efficiencies of those units.
(10) DOE requests comment and data
as to the number of shipments of threephase, dry-type, distribution
transformers greater than 2,500 kVA that
would meet the in-scope voltage
limitations and the distribution of
efficiencies of those units.
(11) DOE requests comment on its
understanding and proposed definition
of ‘‘submersible’’ distribution
transformer. Specifically, DOE requests
information on specific design
characteristics of distribution
transformers that allow them to operate
while submerged in water, as well as
data on the impact to efficiency
resulting from such characteristics.
(12) DOE requests comment and data
as to the impact that submersible
characteristics have on distribution
transformer efficiency.
(13) DOE requests data on the
difference in load loss by kVA for
distribution transformers with multiplevoltage ratings and a voltage ratio other
than 2:1.
(14) DOE request data on the number
of shipments for each equipment class
of distribution transformers with multivoltage ratios other than 2:1.
(15) DOE requests data on the
difference in load loss by kVA for
distribution transformers with higher
currents and at what current it becomes
more difficult to meet energy
conservation standards.
(16) DOE requests data as to the
number of shipments of distribution
transformers with the higher currents
that would have a more difficult time
meeting energy conservation standards.
(17) DOE requests comment as to
what modifications could be made to
the April 2013 Standard Final Rule data
center definition such that the
identifying features are related to
efficiency and would prevent a data
center transformer from being used in a
general purpose application.
(18) DOE requests comment regarding
its proposal not to establish a separate
equipment class for data center
distribution transformers. In particular,
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DOE seeks comment regarding whether
data center distribution transformers are
able to reach the same efficiency levels
as distribution transformers generally
and the specific reasons why that may
be the case.
(19) DOE requests comment regarding
any challenges that would exist if
designing a distribution transformer
which uses amorphous electrical steel
in its core for data center applications
and whether data center transformers
have been built which use amorphous
electrical steel in their cores.
(20) DOE requests comment on the
interaction of inrush current and data
center distribution transformer design.
Specifically, DOE seeks information
regarding: (1) the range of inrush current
limit values in use in data center
distribution transformers; (2) any
challenges in meeting such inrush
current limit values when using
amorphous electrical steel in the core;
(3) whether using amorphous electrical
steel inherently increases inrush
current, and why; (4) how the
(magnetic) remanence of grain-oriented
electrical steel compares to that of
amorphous steel; and (5) other strategies
or technologies than distribution
transformer design which could be used
to limit inrush current and the
respective costs of those measures.
(21) DOE requests data as to how a
liquid-immersed distribution
transformer losses vary with BIL across
the range of kVA values within scope.
(22) DOE requests comments and data
on any other types of equipment that
may have a harder time meeting energy
conservation standards. Specifically,
DOE requests comments as to how these
other equipment are identified based on
physical features from general purpose
distribution transformers, the number of
shipments of each unit, and the
possibility of these equipment being
used in place of generally purpose
distribution transformers.
(23) DOE requests data demonstrating
any specific distribution transformer
designs that would have significantly
different cost-efficiency curves than
those representative units modeled by
DOE.
(24) DOE requests comment on its
methodology for scaling RU5, RU12,
and RU14 to represent the efficiency of
units above 3,750 kVA.
(25) DOE requests comment on its
methodology for modifying the results
of RU4 and RU5 to represent the
efficiency of submersible liquidimmersed units. For other potentially
disadvantaged designs, DOE has
considered establishing equipment
classes to separate out those that would
have the most difficulty achieving
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amended efficiency standards, as
discussed in section IV.A.2 of this
document, but ultimately has
determined not to include such separate
equipment classes in the proposed
standards. However, DOE requests data
as to the degree of reduction in
efficiency associated with various
features.
(26) DOE requests data as to how stray
and eddy losses at rated PUL vary with
kVA and rated voltages.
(27) DOE requests comment on the
current and future market pressures
influencing the price of GOES.
Specifically, DOE is interested in the
barriers to and costs associated with
converting a factory production line
from GOES to NOES.
(28) DOE further requests comment
regarding how the prices of both GOES
and amorphous are expected to change
in the immediate and distant future.
(29) DOE requests comment regarding
the barriers to converting current M3 or
23hib90 electrical steel production to
lower-loss GOES core steels.
(30) DOE requests comment as to if
there are markets for amorphous ribbon,
similar to NOES competition from
GOES production, which would put
competitive pressures on the production
of amorphous ribbon for distribution
transformers.
(31) DOE requests comment on how a
potentially limited supply of
transformer core steel, both of
amorphous and GOES, may affect core
steel price and availability. DOE seeks
comment on any factors which uniquely
affect specific steel grades (e.g.,
amorphous, M-grades, hib, dr, pdr).
Additionally, DOE seeks comment on
how it should model a potentially
concentrated domestic steel market in
its analysis, resulting from a limited
number of suppliers for the amorphous
market or from competition with NOES
for the GOES market, including any use
of game theoretic modeling as
appropriate.
(32) DOE requests comment or data
showing hourly transformer loads for
industrial customers.
(33) To help inform DOE’s prediction
of future load growth trend, DOE seeks
data on the following for regions where
decarbonization efforts are ongoing.
DOE seeks hourly PUL data at the level
of the transformer bank for each of the
past five years to establish an
unambiguous relationship between
transformer loads and decarbonization
policy and inform if any intensive load
growth is indeed occurring.
Additionally, DOE seeks the average
capacity of shipment into regions where
decarbonization efforts are occurring
over the same five-year period to inform
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1853
the rate of any extensive load growth
that may be occurring in response to
these programs.
(34) DOE requests comments on its
methodology for establishing the energy
efficiency levels for distribution
transformers greater than 2500 kVA.
DOE request comment on its assumed
energy efficiency ratings.
(35) DOE requests comment on its
assumed TOC adoption rate of 10
percent. Specifically, DOE requests
comment on the TOC rate suggested by
NEMA, that between 15 and 20 percent
of 3-phase liquid-immersed distribution
transformers are purchased using TOC,
and that 40 percent of 1-phase liquidimmersed distribution transformers are
purchased using TOC. DOE notes, that
it is seeking data related to concluded
sales based on lowest TOC in the
strictest sense, excluding those
transformers sold using band of
equivalents (see the section on band of
equivalents, above)
(36) DOE requests comment on the
fraction of distribution transformers
purchased by customers using the BOE
methodology. DOE notes, that it is
seeking data related to concluded sales
based on lowest BOE in the strictest
sense, excluding those transformers sold
using total owning costs.
(37) DOE request comment if the rates
of TOC or BOE vary by transformer
capacity or number of phases. Further,
DOE seeks the fraction of distribution
transformer sales using either method
into the different regions in order to
capture the believed relationship
between higher electricity costs and
purchase evaluation behavior.
(38) Transformers are typically
installed using a bucket truck, or crane
truck. DOE requests comment on the
typical maximum lifting capacity, and
the typical transformer capacity being
installed.
(39) For this NOPR, DOE reiterates its
request for the following information.
DOE requests data and feedback on the
size limitations of pad-mounted
distribution transformers. Specifically,
what sizes, voltages, or other features
are currently unable to fit on current
pads, and the dimension of these pads.
DOE seeks data on the typical concrete
pad dimensions for 50 and 500 kVA
single-; and 500, and 1500 kVA threephase distribution transformers. DOE
seeks data on the typical service
lifetimes of supporting concrete pads.
(40) DOE request the average
extension of distribution transformer
service life that can be achieved through
rebuilding. Additionally, DOE requests
comment on the fraction of transformer
that are repaired by their original
purchasing entity and returned to
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service, thereby extending the
transformer’s service lifetime beyond
the estimated lifetimes of 32 years with
a maximum of 60 years.
(41) DOE requests comment on which
liquid-immersed distribution
transformers capacities are typically
replaced with MVDT. DOE further
requests data that would indicate a
trend in these substitutions. DOE further
requests data that would help it
determine which types of customers are
preforming these substitutions, e.g.,
industrial customers, invertor owned
utilities, MUNIs, etc.
(42) In response to NEMA’s comment
DOE requests data to inform a shift in
the capacity distribution to larger
capacity distribution transformers.
Additionally, DOE requests information
on the extent that this increasing trend
in capacity would affect all types of
distribution transformers, or only
medium-voltage distribution
transformers.
(43) DOE projected the energy
savings, operating cost savings, product
costs, and NPV of consumer benefits
over the lifetime of distribution
transformers sold from 2027 through
2056. Given the extremely durable
nature of distribution transformers, this
creates an analytical timeframe from
2027 through 2115. DOE seeks comment
on the current analytical timeline, and
potential alternative analytical
timeframes.
(44) DOE requests comment on its
assumption that including a rebound
effect is inappropriate for distribution
transformers.
(45) DOE requests comment on the
mean PUL applied to distribution
transformers owned and operated by
utilities serving low customer
populations.
(46) DOE requests comment on its
assumed vault replacement costs
methodology. DOE seeks comment or
data regarding the installation
procedures associated with vault
replacement, vault expansion
(renovation), and vault transformer
installation and their respective costs
for replacement transformers.
Additionally, DOE seeks information on
the typical expected lifetime of
underground concrete vaults.
(47) DOE requests comment on the
real discount rates used in this NOPR.
Specifically, if 7.4 percent for liquidimmersed distribution transformer
manufacturers, 11.1 percent for lowvoltage dry-type distribution
transformer manufacturers, and 9.0
percent for medium-voltage dry-type
distribution transformer manufacturers
are appropriate discount rates to use in
the GRIM.
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(48) DOE requests comment on the
estimated potential domestic
employment impacts on distribution
transformer manufacturers presented in
this NOPR.
(49) DOE requests comment on the
potential availability of either
amorphous steel, grain-oriented
electrical steel, or any other materials
that may be needed to meet any of the
analyzed energy conservation standards
in this rulemaking. More specifically,
DOE requests comment on steel
manufacturers’ ability to increase
supply of amorphous steel in reaction to
increased demand for amorphous steel
as a result of increased energy
conservation standards for distribution
transformers.
(50) DOE requests comment on the
number of small businesses identified
that manufacture distribution
transformers covered by this rulemaking
(three small liquid-immersed and seven
LVDT small businesses; three of which
also manufacture MVDT). Additionally,
DOE requests comment on its initial
assumption that only one LVDT small
business and no liquid-immersed small
businesses manufacturer their own
cores used in their distribution
transformers.
(51) Additionally, DOE welcomes
comments on other issues relevant to
the conduct of this rulemaking that may
not specifically be identified in this
document.
VIII. Approval of the Office of the
Secretary
The Secretary of Energy has approved
publication of this notice of proposed
rulemaking and announcement of
public meeting.
List of Subjects in 10 CFR Part 431
Administrative practice and
procedure, Confidential business
information, Energy conservation test
procedures, and Reporting and
recordkeeping requirements.
Signing Authority
This document of the Department of
Energy was signed on December 28,
2022, by Francisco Alejandro Moreno,
Acting Assistant Secretary for Energy
Efficiency and Renewable Energy,
pursuant to delegated authority from the
Secretary of Energy. That document
with the original signature and date is
maintained by DOE. For administrative
purposes only, and in compliance with
requirements of the Office of the Federal
Register, the undersigned DOE Federal
Register Liaison Officer has been
authorized to sign and submit the
document in electronic format for
publication, as an official document of
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the Department of Energy. This
administrative process in no way alters
the legal effect of this document upon
publication in the Federal Register.
Signed in Washington, DC, on December
29, 2022.
Treena V. Garrett,
Federal Register Liaison Officer, U.S.
Department of Energy
For the reasons set forth in the
preamble, DOE proposes to amend part
431 of chapter II, of title 10 of the Code
of Federal Regulations, as set forth
below:
PART 431—ENERGY EFFICIENCY
PROGRAM FOR CERTAIN
COMMERCIAL AND INDUSTRIAL
EQUIPMENT
1. The authority citation for part 431
continues to read as follows:
■
Authority: 42 U.S.C. 6291–6317; 28 U.S.C.
2461 note.
2. Section 431.192 is amended by:
a. Revising the definitions of
‘‘Distribution transformer’’, ‘‘Drive
(isolation) transformer’’, ‘‘Nonventilated
transformer’’, ‘‘Sealed transformer’’,
‘‘Special-impedance transformer’’,
‘‘Transformer with a tap range of 20
percent or more’’, ‘‘Uninterruptible
power supply transformer’’; and
■ b. Adding in alphabetical order,
definition for ‘‘Submersible distribution
transformer’’
The revisions and addition read as
follows:
■
■
§ 431.19
Definitions.
*
*
*
*
*
Distribution transformer means a
transformer that:
(1) Has an input line voltage of 34.5
kV or less;
(2) Has an output line voltage of 600
V or less;
(3) Is rated for operation at a
frequency of 60 Hz; and
(4) Has a capacity of 10 kVA to 5000
kVA for liquid-immersed units and 15
kVA to 5000 kVA for dry-type units; but
(5) The term ‘‘distribution
transformer’’ does not include a
transformer that is an –
(i) Autotransfromer;
(ii) Drive (isolation) transformer;
(iii) Grounding transformer;
(iv) Machine-tool (control
transformer);
(v) Nonventilated transformer;
(vi) Rectified transformer;
(vii) Regulating transformer;
(viii) Sealed transformer;
(ix) Special-impedance transformer;
(x) Testing transformer;
(xi) Transformer with tap range of 20
percent or more;
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(xii) Uninterruptible power supply
transformer; or
(xiii) Welding transformer.
Drive (isolation) transformer means a
transformer that:
(1) Isolates an electric motor from the
line;
(2) Accommodates the added loads of
drive-created harmonics;
(3) Is designed to withstand the
additional mechanical stressed resulting
from an alternating current adjustable
frequency motor drive or a direct
current motor drive; and
(4) Has a rated output voltage that is
neither ‘‘208Y/120’’ nor ‘‘480Y/277’’.
*
*
*
*
*
Nonventilated transformer means a
dry-type transformer constructed so as
to prevent external air circulation
through the coils of the transformer
while operating at zero gauge pressure.
*
*
*
*
*
Sealed transformer means a dry-type
transformer designed to remain
hermetically sealed under specified
condition of temperature and pressure.
Special-impedance transformer
means a transformer built to operate at
1855
an impedance outside of the normal
impedance range for that transformer’s
kVA rating. The normal impedance
range for each kVA rating for liquidimmersed and dry-type transformers is
show in Tables 1 and 2, respectively.
Distribution transformers with kVA
ratings not appearing in the tables shall
have their minimum normal impedance
and maximum normal impedance
determined by linear interpolation of
the kVA and minimum and maximum
impedances, respectively, of the values
immediately above and below that kVA
rating.
TABLE 1—NORMAL IMPEDANCE RANGES FOR LIQUID-IMMERSED TRANSFORMERS
Single-phase
Three-phase
Impedance
(%)
kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
1.0–4.5
1.0–4.5
1.0–4.5
1.0–4.5
1.5–4.5
1.5–4.5
1.5–4.5
1.5–4.5
1.5–6.0
1.5–6.0
1.5–7.0
5.0–7.5
5.0–7.5
Impedance
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
3,750 ............................................................................
5,000 ............................................................................
1.0–4.5
1.0–4.5
1.0–4.5
1.0–5.0
1.2–6.0
1.2–6.0
1.2–6.0
1.2–6.0
1.5–7.0
5.0–7.5
5.0–7.5
5.0–7.5
5.0–7.5
5.0–7.5
5.0–7.5
5.0–7.5
TABLE 2—NORMAL IMPEDANCE RANGES FOR DRY-TYPE TRANSFORMERS
Single-phase
Three-phase
Impedance
(%)
kVA
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15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
Submersible Distribution Transformer
means a liquid-immersed distribution
transformer so constructed as to be
successfully operable when submerged
in water including the following
features:
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1.5–6.0
1.5–6.0
1.5–6.0
1.5–6.0
2.0–7.0
2.0–7.0
2.5–8.0
3.5–8.0
3.5–8.0
3.5–8.0
5.0–8.0
5.0–8.0
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
3,750 ............................................................................
5,000 ............................................................................
(1) Is rated for a temperature rise of
55°C;
(2) Has insulation rated for a
temperature rise of 65°C;
(3) Has sealed-tank construction; and
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Impedance
(%)
kVA
Sfmt 4702
1.5–6.0
1.5–6.0
1.5–6.0
1.5–6.0
1.5–6.0
1.5–6.0
3.0–7.0
3.0–7.0
4.5–8.0
5.0–8.0
5.0–8.0
5.0–8.0
5.0–8.0
5.0–8.0
5.0–8.0
5.0–8.0
(4) Has the tank, cover, and all
external appurtenances made of
corrosion-resistant material.
*
*
*
*
*
Transformer with tap range of 20
percent or more means a transformer
with multiple full-power voltage taps,
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the highest of which equals at least 20
percent more than the lowest, computed
based on the sum of the deviations of
these taps from the transformer’s
maximum full-power voltage.
Uninterruptible power supply
transformer means a transformer that is
used within an uninterruptible power
system, which in turn supplies power to
loads that are sensitive to power failure,
power sages, over voltage, switching
transients, line notice, and other power
quality factors. It does not include
distribution transformers at the input,
output, or by-pass of an uninterruptible
power system.
*
*
*
*
*
■ 3. Amend § 431.196 by:
■ a. Revising paragraph (a)(2) and
adding paragraph (a)(3),
■ b. Revising paragraph (b)(2) and
adding paragraphs (b)(3) through (4),
and
■ c. Revising paragraph (c)(2) and
adding paragraph (c)(3).
The revisions and additions read as
follows:
§ 431.196 Energy conservation standards
and their effective dates.
(2) The efficiency of a low-voltage,
dry-type distribution transformer
manufactured on or after January 1,
2016, but before January 1, 2027, shall
be no less than that required for the
applicable kVA rating in the table
below. Low-voltage dry-type
distribution transformers with kVA
ratings not appearing in the table shall
have their minimum efficiency level
determined by linear interpolation of
the kVA and efficiency values
immediately above and below that kVA
rating.
(a) * * *
Single-phase
Three-phase
kVA
kVA
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
97.70
98.00
98.20
98.30
98.50
98.60
98.70
98.80
98.90
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1000 .............................................................................
97.89
98.23
98.40
98.60
98.74
98.83
98.94
99.02
99.14
99.23
99.28
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy
Consumption of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
(3) The efficiency of a low-voltage
dry-type distribution transformer
manufactured on or after January 1,
2027, shall be no less than that required
for their kVA rating in the table below.
Low-voltage dry-type distribution
transformers with kVA ratings not
appearing in the table shall have their
Single-phase
minimum efficiency level determined
by linear interpolation of the kVA and
efficiency values immediately above
and below that kVA rating.
Three-phase
Efficiency
(%)
kVA
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
98.84
98.99
99.09
99.14
99.24
99.30
99.35
99.40
99.45
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1000 .............................................................................
98.72
98.93
99.03
99.16
99.24
99.29
99.36
99.41
99.48
99.54
99.57
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Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy
Consumption of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
(b) * * *
(2) The efficiency of a liquidimmersed distribution transformer,
including submersible distribution
transformers, manufactured on or after
January 1, 2016, but before January 1,
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2027, shall be no less than that required
for their kVA rating in the table below.
Liquid-immersed distribution
transformers, including submersible
distribution transformers, with kVA
ratings not appearing in the table shall
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have their minimum efficiency level
determined by linear interpolation of
the kVA and efficiency values
immediately above and below that kVA
rating.
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Single-phase
1857
Three-phase
kVA
Efficiency (%)
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
98.70
98.82
98.95
99.05
99.11
99.19
99.25
99.33
99.39
99.43
99.49
99.52
99.55
kVA
Efficiency (%)
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
98.65
98.83
98.92
99.03
99.11
99.16
99.23
99.27
99.35
99.40
99.43
99.48
99.51
99.53
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-Procedure, appendix A to subpart
K of 10 CFR part 431.
(3) The efficiency of a liquidimmersed distribution transformer, that
is not a submersible distribution
transformer, manufactured on or after
January 1, 2027, shall be no less than
that required for their kVA rating in the
table below. Liquid-immersed
distribution transformers with kVA
ratings not appearing in the table shall
have their minimum efficiency level
Single-phase
determined by linear interpolation of
the kVA and efficiency values
immediately above and below that kVA
rating.
Three-phase
Efficiency
(%)
kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
98.96
99.05
99.16
99.24
99.29
99.35
99.40
99.46
99.51
99.54
99.59
99.62
99.64
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
3,750 ............................................................................
5,000 ............................................................................
98.92
99.06
99.13
99.22
99.29
99.33
99.38
99.42
99.48
99.52
99.54
99.58
99.61
99.62
99.66
99.68
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy
Consumption of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
(4) The efficiency of a submersible
distribution transformer, manufactured
on or after January 1, 2027, shall be no
less than that required for their kVA
rating in the table below. Submersible
distribution transformers with kVA
ratings not appearing in the table shall
have their minimum efficiency level
Single-phase
Three-phase
Efficiency
(%)
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kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
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determined by linear interpolation of
the kVA and efficiency values
immediately above and below that kVA
rating.
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98.95
99.05
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99.19
99.25
99.33
99.39
99.43
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Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1,000 ............................................................................
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11JAP3
98.65
98.83
98.92
99.03
99.11
99.16
99.23
99.27
99.35
99.40
99.43
1858
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
Single-phase
Three-phase
Efficiency
(%)
kVA
667 ................................................................................
833 ................................................................................
99.52
99.55
Efficiency
(%)
kVA
1,500 ............................................................................
2,000 ............................................................................
2,500 ............................................................................
99.48
99.51
99.53
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-Procedure appendix A to subpart
K of 10 CFT part 431.
(c) * * *
(2) The efficiency of a mediumvoltage dry-type distribution
transformer manufactured on or after
January 1, 2016, but before January 1,
2027, shall be no less than that required
for their kVA and BIL rating in the table
below. Medium-voltage dry-type
distribution transformers with kVA
ratings not appearing in the table shall
Single-phase
have their minimum efficiency level
determined by linear interpolation of
the kVA and efficiency values
immediately above and below that kVA
rating.
Three-phase
BIL
kVA
BIL
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
98.10
98.33
98.49
98.60
98.73
98.82
98.96
99.07
99.14
99.22
99.27
99.31
97.86
98.12
98.30
98.42
98.57
98.67
98.83
98.95
99.03
99.12
99.18
99.23
........................
........................
........................
........................
98.53
98.63
98.80
98.91
98.99
99.09
99.15
99.20
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1,000 .....................
1,500 .....................
2,000 .....................
2,500 .....................
97.50
97.90
98.10
98.33
98.52
98.65
98.82
98.93
99.09
99.21
99.28
99.37
99.43
99.47
97.18
97.63
97.86
98.13
98.36
98.51
98.69
98.81
98.99
99.12
99.20
99.30
99.36
99.41
........................
........................
........................
........................
........................
........................
98.57
98.69
98.89
99.02
99.11
99.21
99.28
99.33
* BIL means basic impulse insulation level
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy
Consumption of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
(3) The efficiency of a mediumvoltage dry-type distribution
transformer manufactured on or after
January 1, 2027, shall be no less than
that required for their kVA and BIL
rating in the table below. Mediumvoltage dry-type distribution
transformers with kVA ratings not
appearing in the table shall have their
minimum efficiency level determined
Single-phase
by linear interpolation of the kVA and
efficiency values immediately above
and below that kVA rating.
Three-phase
BIL
lotter on DSK11XQN23PROD with PROPOSALS3
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
VerDate Sep<11>2014
BIL
19:08 Jan 10, 2023
98.29
98.49
98.64
98.74
98.86
98.94
99.06
99.16
99.23
99.30
99.34
99.38
Jkt 259001
98.07
98.30
98.47
98.58
98.71
98.80
98.95
99.05
99.13
99.21
99.26
99.31
PO 00000
........................
........................
........................
........................
98.68
98.77
98.92
99.02
99.09
99.18
99.23
99.28
Frm 00138
Fmt 4701
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1,000 .....................
1,500 .....................
2,000 .....................
2,500 .....................
97.74
98.11
98.29
98.49
98.67
98.78
98.94
99.04
99.18
99.29
99.35
99.43
99.49
99.52
Sfmt 4702
11JAP3
E:\FR\FM\11JAP3.SGM
97.45
97.86
98.07
98.31
98.52
98.66
98.82
98.93
99.09
99.21
99.28
99.37
99.42
99.47
........................
........................
........................
........................
........................
........................
98.71
98.82
99.00
99.12
99.20
99.29
99.35
99.40
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 / Proposed Rules
Single-phase
Three-phase
BIL
kVA
1859
BIL
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
kVA
20–45 kV
46–95 kV
≥96 kV
Efficiency
(%)
Efficiency
(%)
Efficiency
(%)
3,750 .....................
5,000 .....................
99.58
99.62
99.53
99.58
99.47
99.51
* BIL means basic impulse insulation level
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy
Consumption of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
*
*
*
*
*
[FR Doc. 2022–28590 Filed 1–10–23; 8:45 am]
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BILLING CODE 6450–01–P
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11JAP3
]]>Agencies
[Federal Register Volume 88, Number 7 (Wednesday, January 11, 2023)]
[Proposed Rules]
[Pages 1722-1859]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-28590]
[[Page 1721]]
Vol. 88
Wednesday,
No. 7
January 11, 2023
Part III
Department of Energy
-----------------------------------------------------------------------
10 CFR Part 431
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers; Proposed Rule
Federal Register / Vol. 88, No. 7 / Wednesday, January 11, 2023 /
Proposed Rules
[[Page 1722]]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
10 CFR Part 431
[EERE-2019-BT-STD-0018]
RIN 1904-AE12
Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers
AGENCY: Office of Energy Efficiency and Renewable Energy, Department of
Energy.
ACTION: Notice of proposed rulemaking and announcement of public
meeting.
-----------------------------------------------------------------------
SUMMARY: The Energy Policy and Conservation Act, as amended (``EPCA''),
prescribes energy conservation standards for various consumer products
and certain commercial and industrial equipment, including distribution
transformers. EPCA also requires the U.S. Department of Energy
(``DOE'') to periodically determine whether more-stringent, standards
would be technologically feasible and economically justified, and would
result in significant energy savings. In this notice of proposed
rulemaking (``NOPR''), DOE proposes amended energy conservation
standards for distribution transformers, and also announces a public
meeting to receive comment on these proposed standards and associated
analyses and results.
DATES: DOE will hold a public meeting via webinar on Thursday, February
16, 2023, from 1:00 p.m. to 4:00 p.m. See section VII, ``Public
Participation,'' for webinar registration information, participant
instructions and information about the capabilities available to
webinar participants.
Comments: DOE will accept comments, data, and information regarding
this NOPR no later than March 13, 2023.
Comments regarding the likely competitive impact of the proposed
standard should be sent to the Department of Justice contact listed in
the ADDRESSES section on or before February 10, 2023.
Interested persons are encouraged to submit comments using the
Federal eRulemaking Portal at www.regulations.gov. Follow the
instructions for submitting comments. Alternatively, interested persons
may submit comments, identified by docket number EERE-2019-BT-STD-0018,
by any of the following methods:
Email: [email protected]. Include the
docket number EERE-2019-BT-STD-0018 in the subject line of the message.
Postal Mail: Appliance and Equipment Standards Program, U.S.
Department of Energy, Building Technologies Office, Mailstop EE-5B,
1000 Independence Avenue SW, Washington, DC 20585-0121. Telephone:
(202) 287-1445. If possible, please submit all items on a compact disc
(``CD''), in which case it is not necessary to include printed copies.
Hand Delivery/Courier: Appliance and Equipment Standards Program,
U.S. Department of Energy, Building Technologies Office, 950 L'Enfant
Plaza SW, 6th Floor, Washington, DC 20024. Telephone: (202) 287-1445.
If possible, please submit all items on a CD, in which case it is not
necessary to include printed copies.
No telefacsimiles (``faxes'') will be accepted. For detailed
instructions on submitting comments and additional information on this
process, see section IV of this document.
Docket: The docket for this activity, which includes Federal
Register notices, comments, and other supporting documents/materials,
is available for review at www.regulations.gov. All documents in the
docket are listed in the www.regulations.gov index. However, not all
documents listed in the index may be publicly available, such as
information that is exempt from public disclosure.
The docket web page can be found at www.regulations.gov/docket/EERE-2019-BT-STD-0018. The docket web page contains instructions on how
to access all documents, including public comments, in the docket. See
section VII of this document for information on how to submit comments
through www.regulations.gov.
EPCA requires the Attorney General to provide DOE a written
determination of whether the proposed standard is likely to lessen
competition. The U.S. Department of Justice Antitrust Division invites
input from market participants and other interested persons with views
on the likely competitive impact of the proposed standard. Interested
persons may contact the Division at [email protected] on or
before the date specified in the DATES section. Please indicate in the
``Subject'' line of your email the title and Docket Number of this
proposed rule.
FOR FURTHER INFORMATION CONTACT:
Mr. Jeremy Dommu, U.S. Department of Energy, Office of Energy
Efficiency and Renewable Energy, Building Technologies Office, EE-5B,
1000 Independence Avenue SW, Washington, DC 20585-0121. Telephone:
(202) 586-9870. Email: [email protected].
Mr. Matthew Ring, U.S. Department of Energy, Office of the General
Counsel, GC-33, 1000 Independence Avenue SW, Washington, DC 20585-0121.
Telephone: (202) 586-2555. Email: [email protected].
For further information on how to submit a comment, review other
public comments and the docket, or participate in the public meeting,
contact the Appliance and Equipment Standards Program staff at (202)
287-1445 or by email: [email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Synopsis of the Proposed Rule
A. Benefits and Costs to Consumers
B. Impact on Manufacturers
C. National Benefits and Costs
1. Liquid-Immersed Distribution Transformers
2. Low-Voltage Dry-Type Distribution Transformers
3. Medium Voltage Dry-Type Distribution Transformers
D. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
C. Deviation From Appendix A
III. General Discussion
A. Equipment Classes and Scope of Coverage
B. Test Procedure
C. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
D. Energy Savings
1. Determination of Savings
2. Significance of Savings
E. Economic Justification
1. Specific Criteria
a. Economic Impact on Manufacturers and Consumers
b. Savings in Operating Costs Compared to Increase in Price (LCC
and PBP)
c. Energy Savings
d. Lessening of Utility or Performance of Products
e. Impact of Any Lessening of Competition
f. Need for National Energy Conservation
g. Other Factors
2. Rebuttable Presumption
IV. Methodology and Discussion of Related Comments
A. Market and Technology Assessment
1. Scope of Coverage
a. Autotransformers
b. Drive (Isolation) Transformers
c. Special-Impedance Transformers
d. Tap Range of 20 Percent or More
e. Sealed and Nonventilated Transformers
f. Step-Up Transformers
g. Uninterruptible Power Supply Transformers
h. Voltage Specification
i. kVA Range
2. Equipment Classes
[[Page 1723]]
a. Pole- and Pad-Mounted Transformers
b. Submersible Transformers
c. Multi-Voltage-Capable Distribution Transformers
d. High-Current Distribution Transformers
e. Data Center Distribution Transformer
f. BIL Rating
g. Other Types of Equipment
3. Test Procedure
4. Technology Options
5. Electrical Steel Technology and Market Assessment
a. Amorphous Steel Market and Technology
b. Grain-Oriented Electrical Steel Market and Technology
6. Distribution Transformer Production Market Dynamics
B. Screening Analysis
1. Screened-Out Technologies
2. Remaining Technologies
C. Engineering Analysis
1. Representative Units
2. Efficiency Analysis
a. Design Option Combinations
b. Data Validation
c. Baseline Energy Use
d. Higher Efficiency Levels
e. Load Loss Scaling
f. kVA Scaling
3. Cost Analysis
a. Electrical Steel Prices
b. Scrap Factor
c. Other Material Costs
d. Cost Mark-Ups
4. Cost-Efficiency Results
D. Markups Analysis
E. Energy Use Analysis
1. Hourly Load Model
a. Hourly Per-Unit Load (PUL)
b. Joint Probability Distribution Function (JPDF)
2. Monthly Per-Unit Load (PUL)
3. Future Load Growth
4. Harmonic Content/Non-Linear Loads
F. Life-Cycle Cost and Payback Period Analysis
1. Equipment Cost
2. Efficiency Levels
3. Modeling Distribution Transformer Purchase Decision
a. Basecase Equipment Selection
b. Total Owning Cost (``TOC'') and Evaluators
c. Non-Evaluators and First Cost Purchases
4. Installation Costs
5. Annual Energy Consumption
6. Electricity Prices
a. Hourly Electricity Costs
7. Maintenance and Repair Costs
8. Equipment Lifetime
9. Discount Rates
10. Energy Efficiency Distribution in the No-New-Standards Case
11. Payback Period Analysis
G. Shipments Analysis
1. Equipment Switching
2. Trends in Distribution Transformer Capacity (kVA)
H. National Impact Analysis
1. Equipment Efficiency Trends
2. National Energy Savings
3. Net Present Value Analysis
I. Consumer Subgroup Analysis
1. Utilities Serving Low Customer Populations
2. Utility Purchasers of Vault (Underground) and Subsurface
Installations
J. Manufacturer Impact Analysis
1. Overview
2. Government Regulatory Impact Model and Key Inputs
a. Manufacturer Production Costs
b. Shipments Projections
c. Product and Capital Conversion Costs
d. Manufacturer Markup Scenarios
3. Manufacturer Interviews
a. Material Shortages and Prices
b. Use of Amorphous Materials
c. Larger Distribution Transformers
4. Discussion of MIA Comments
a. Small Businesses
b. Capital Equipment
K. Emissions Analysis
1. Air Quality Regulations Incorporated in DOE's Analysis
L. Monetizing Emissions Impacts
1. Monetization of Greenhouse Gas Emissions
a. Social Cost of Carbon
b. Social Cost of Methane and Nitrous Oxide
2. Monetization of Other Emissions Impacts
M. Utility Impact Analysis
N. Employment Impact Analysis
V. Analytical Results and Conclusions
A. Trial Standard Levels
B. Economic Justification and Energy Savings
1. Economic Impacts on Individual Consumers
a. Life-Cycle Cost and Payback Period
b. Consumer Subgroup Analysis
c. Rebuttable Presumption Payback
2. Economic Impacts on Manufacturers
a. Industry Cash Flow Analysis Results
b. Direct Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Competition
e. Impacts on Subgroups of Manufacturers
f. Cumulative Regulatory Burden
3. National Impact Analysis
a. Significance of Energy Savings
b. Net Present Value of Consumer Costs and Benefits
c. Indirect Impacts on Employment
4. Impact on Utility or Performance of Products
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
8. Summary of Economic Impacts
C. Conclusion
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed
Distribution Transformers Standards
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-
Type Distribution Transformers Standards
3. Benefits and Burdens of TSLs Considered for Medium-Voltage
Dry-Type Distribution Transformers Standards
4. Annualized Benefits and Costs of the Proposed Standards for
Liquid-Immersed Distribution Transformers
5. Annualized Benefits and Costs of the Proposed Standards for
Low-Voltage Distribution Transformers
6. Annualized Benefits and Costs of the Proposed Standards for
Medium-Voltage Distribution Transformers
7. Benefits and Costs of the Proposed Standards for All
Considered Distribution Transformers
D. Reporting, Certification, and Sampling Plan
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866 and 13563
B. Review Under the Regulatory Flexibility Act
1. Description of Reasons Why Action Is Being Considered
2. Objectives of, and Legal Basis for, Rule
3. Description on Estimated Number of Small Entities Regulated
4. Description and Estimate of Compliance Requirements Including
Differences in Cost, if Any, for Different Groups of Small Entities
5. Duplication, Overlap, and Conflict With Other Rules and
Regulations
6. Significant Alternatives to the Rule
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act of 1969
E. Review Under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government
Appropriations Act, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government
Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Information Quality
VII. Public Participation
A. Attendance at the Public Meeting
B. Procedure for Submitting Prepared General Statements for
Distribution
C. Conduct of the Public Webinar
D. Submission of Comments
E. Issues on Which DOE Seeks Comment
VIII. Approval of the Office of the Secretary
I. Synopsis of the Proposed Rule
The EPCA,\1\ (42 U.S.C. 6291-6317, as codified) authorizes DOE to
regulate the energy efficiency of a number of consumer products and
certain industrial equipment. Title III, Part B \2\ of EPCA (42 U.S.C.
6291-6309, as codified), established the Energy Conservation Program
for ``Consumer Products Other Than Automobiles.'' Title III, Part C \3\
of EPCA (42 U.S.C.
[[Page 1724]]
6311-6317, as codified), added by Public Law 95-619, Title IV, section
411(a), established the Energy Conservation Program for Certain
Industrial Equipment. The Energy Policy Act of 1992, Public Law 102-
486, amended EPCA and directed DOE to prescribe energy conservation
standards for those distribution transformers for which DOE determines
such standards would be technologically feasible, economically
justified, and would result in significant energy savings. (42 U.S.C.
6317(a)) The Energy Policy Act of 2005, Public Law 109-58, amended EPCA
to establish energy conservation standards for low-voltage dry-type
distribution transformers. (42 U.S.C. 6295(y))
---------------------------------------------------------------------------
\1\ All references to EPCA in this document refer to the statute
as amended through the Energy Act of 2020, Public Law 116-260 (Dec.
27, 2020), which reflect the last statutory amendments that impact
Parts A and A-1 of EPCA.
\2\ For editorial reasons, upon codification in the U.S. Code,
Part B was re-designated Part A.
\3\ For editorial reasons, upon codification in the U.S. Code,
Part C was re-designated Part A-1. While EPCA includes provisions
regarding distribution transformers in both Part A and Part A-1, for
administrative convenience DOE has established the test procedures
and standards for distribution transformers in 10 CFR part 431,
Energy Efficiency Program for Certain Commercial and Industrial
Equipment. DOE refers to distribution transformers generally as
``covered equipment'' in this document.
---------------------------------------------------------------------------
Pursuant to EPCA, any new or amended energy conservation standard
must be designed to achieve the maximum improvement in energy
efficiency that DOE determines is technologically feasible and
economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A))
Furthermore, the new or amended standard must result in a significant
conservation of energy. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B))
EPCA also provides that not later than 6 years after issuance of any
final rule establishing or amending a standard, DOE must publish either
a notice of determination that standards for the product do not need to
be amended, or a notice of proposed rulemaking including new proposed
energy conservation standards (proceeding to a final rule, as
appropriate). (42 U.S.C. 6316(a); 42 U.S.C. 6295(m))
In accordance with these and other statutory provisions discussed
in this document, DOE proposes amended energy conservation standards
for distribution transformers. The proposed standards, which are
expressed in efficiency as a percentage, are shown in Table I.1 of this
document. These proposed standards, if adopted, would apply to all
distribution transformers listed in Table I.1, Table I.2, and Table I.3
manufactured in, or imported into, the United States starting on the
date 3 years after the publication of the final rule for this
rulemaking.
Table I.1--Proposed Energy Conservation Standards for Low-Voltage Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
15........................................ 98.84 15........................... 98.72
25........................................ 98.99 30........................... 98.93
37.5...................................... 99.09 45........................... 99.03
50........................................ 99.14 75........................... 99.16
75........................................ 99.24 112.5........................ 99.24
100....................................... 99.30 150.......................... 99.29
167....................................... 99.35 225.......................... 99.36
250....................................... 99.40 300.......................... 99.41
333....................................... 99.45 500.......................... 99.48
750.......................... 99.54
1,000........................ 99.57
----------------------------------------------------------------------------------------------------------------
Table I.2--Proposed Energy Conservation Standards for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................ 98.96 15........................... 98.92
15........................................ 99.05 30........................... 99.06
25........................................ 99.16 45........................... 99.13
37.5...................................... 99.24 75........................... 99.22
50........................................ 99.29 112.5........................ 99.29
75........................................ 99.35 150.......................... 99.33
100....................................... 99.40 225.......................... 99.38
167....................................... 99.46 300.......................... 99.42
250....................................... 99.51 500.......................... 99.48
333....................................... 99.54 750.......................... 99.52
500....................................... 99.59 1,000........................ 99.54
667....................................... 99.62 1,500........................ 99.58
833....................................... 99.64 2,000........................ 99.61
2,500........................ 99.62
3,750........................ 99.66
5,000........................ 99.68
----------------------------------------------------------------------------------------------------------------
[[Page 1725]]
Table I.3--Proposed Energy Conservation Standards for Medium-Voltage Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL * BIL *
---------------------------------------- --------------------------------------
20-45 kV 46-95 kV >=96 kV 20-45 kV 46-95 kV >=96 kV
kVA ---------------------------------------- kVA --------------------------------------
Efficiency Efficiency Efficiency Efficiency Efficiency Efficiency
(%) (%) (%) (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15........................................ 98.29 98.07 ............ 15........................... 97.74 97.45 ...........
25........................................ 98.49 98.30 ............ 30........................... 98.11 97.86 ...........
37.5...................................... 98.64 98.47 ............ 45........................... 98.29 98.07 ...........
50........................................ 98.74 98.58 ............ 75........................... 98.49 98.31 ...........
75........................................ 98.86 98.71 98.68 112.5........................ 98.67 98.52 ...........
100....................................... 98.94 98.80 98.77 150.......................... 98.78 98.66 ...........
167....................................... 99.06 98.95 98.92 225.......................... 98.94 98.82 98.71
250....................................... 99.16 99.05 99.02 300.......................... 99.04 98.93 98.82
333....................................... 99.23 99.13 99.09 500.......................... 99.18 99.09 99.00
500....................................... 99.30 99.21 99.18 750.......................... 99.29 99.21 99.12
667....................................... 99.34 99.26 99.23 1,000........................ 99.35 99.28 99.20
833....................................... 99.38 99.31 99.28 1,500........................ 99.43 99.37 99.29
2,000........................ 99.49 99.42 99.35
2,500........................ 99.52 99.47 99.40
3,750........................ 99.58 99.53 99.47
5,000........................ 99.62 99.58 99.51
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means basic impulse insulation level.
A. Benefits and Costs to Consumers
Table I.4 presents DOE's evaluation of the monetized impacts of the
proposed standards on consumers of distribution transformers, as
measured by the average life-cycle cost (``LCC'') savings and the
simple payback period (``PBP'').\4\ The average LCC savings are
positive for all equipment classes in all cases, with the exception of
representative unit 14, and the PBP is less than the average lifetime
of distribution transformers, which is estimated to be 32 years (see
section IV.F.8 of this document).
---------------------------------------------------------------------------
\4\ The average LCC savings and simple PBP refer to consumers
that are affected by a standard and are measured relative to the
efficiency distribution in the no-new-standards case, which depicts
the market in the compliance year in the absence of new or amended
standards. The determination of the distribution of efficiencies in
the no-new-standards case is a function of the units selected from
the consumer choice model. (see section IV.F.3 of this document).
---------------------------------------------------------------------------
In the context of this NOPR, the term consumer refers to different
populations that purchase and bear the operating costs of distribution
transformers. Consumers vary by transformer type; for medium-voltage
liquid-immersed distribution transformers the term consumer refers to
electric utilities; for low- and medium-voltage dry-type distribution
transformers the term consumer refers to commercial and industrial
entities.
Table I.4--Impacts of Proposed Energy Conservation Standards on Consumers of Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Representative Average LCC Simple payback
Equipment class unit savings (2021$) period (years)
----------------------------------------------------------------------------------------------------------------
1......................................................... 1 72 16.0
1......................................................... 2 131 10.1
1......................................................... 3 1,029 12.2
2......................................................... 4 511 11.9
2......................................................... 5 1,543 13.8
2......................................................... 17 6,594 15.8
12........................................................ 15 * n.a. * n.a.
12........................................................ 16 * n.a. * n.a.
3......................................................... 6 147 11.7
4......................................................... 7 564 8.9
4......................................................... 8 722 11.8
6......................................................... 9 887 2.4
6......................................................... 10 653 11.4
8......................................................... 11 226 11.9
8......................................................... 12 3,051 1.1
8......................................................... 18 22,797 8.1
10........................................................ 13 228 12.4
10........................................................ 14 -2,856 26.1
10........................................................ 19 8,082 11.3
----------------------------------------------------------------------------------------------------------------
* No-new standards are currently being proposed for equipment class 12, ``n.a'' indicates that there are no
consumer savings.
[[Page 1726]]
DOE's analysis of the impacts of the proposed standards on
consumers is described in section IV.F of this document.
B. Impact on Manufacturers
The industry net present value (``INPV'') is the sum of the
discounted cash flows to the industry from the base year through the
end of the analysis period (2022-2056). Using a real discount rate of
7.4 percent for liquid-immersed distribution transformers, 11.1 percent
for low-voltage dry-type (``LVDT'') distribution transformers, and 9.0
percent for medium-voltage dry-type (``MVDT'') distribution
transformers, DOE estimates that the INPV for manufacturers of
distribution transformers in the case without amended standards is
$1,384 million in 2021$ for liquid-immersed distribution transformers,
$194 million in 2021$ for LVDT distribution transformers, and $87
million in 2021$ for MVDT distribution transformers. Under the proposed
standards, the change in INPV is estimated to range from -18.1 percent
to -10.9 percent for liquid-immersed distribution transformers which
represents a change in INPV of approximately -$251.3 million to -$151.0
million; from -31.4 percent to -17.2 percent for LVDT distribution
transformers, which represents a change in INPV of approximately -$61.0
million to -$33.5 million; and -3.0 percent to -0.9 percent for MVDT
distribution transformers, which represents a change in INPV of
approximately -$2.7 million to -$0.8 million. In order to bring
products into compliance with amended standards, it is estimated that
the industry would incur total conversion costs of $270.6 million for
liquid-immersed distribution transformer, $69.4 million for LVDT
distribution transformers, and $3.1 million for MVDT distribution
transformers.
DOE's analysis of the impacts of the proposed standards on
manufacturers is described in section IV.J of this document. The
analytic results of the manufacturer impact analysis (``MIA'') are
presented in section V.B.2 of this document.
C. National Benefits and Costs \5\
---------------------------------------------------------------------------
\5\ All monetary values in this document are expressed in 2021
dollars.
---------------------------------------------------------------------------
1. Liquid-Immersed Distribution Transformers
DOE's analyses indicate that the proposed energy conservation
standards for liquid-immersed distribution transformers would save a
significant amount of energy. Relative to the case without amended
standards, the lifetime energy savings for liquid-immersed distribution
transformers purchased in the 30-year period that begins in the
anticipated year of compliance with the amended standards (2027-2056)
amount to 8.02 quadrillion British thermal units (``Btu''), or
quads.\6\ This represents a fleet savings of 36 percent relative to the
energy use of these products in the case without amended standards
(referred to as the ``no-new-standards case'').
---------------------------------------------------------------------------
\6\ The quantity refers to full-fuel-cycle (``FFC'') energy
savings. FFC energy savings includes the energy consumed in
extracting, processing, and transporting primary fuels (i.e., coal,
natural gas, petroleum fuels), and, thus, presents a more complete
picture of the impacts of energy efficiency standards. For more
information on the FFC metric, see section IV.H.2 of this document.
---------------------------------------------------------------------------
The cumulative net present value (``NPV'') of total consumer
benefits of the proposed standards for distribution transformers ranges
from 0.26 billion (2021$) (at a 7-percent discount rate) to 5.30
billion (2021$) (at a 3-percent discount rate). This NPV expresses the
estimated total value of future operating-cost savings minus the
estimated increased product costs for distribution transformers
purchased in 2027-2056.
In addition, the proposed standards for liquid-immersed
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the proposed standards would
result in cumulative emission reductions (over the same period as for
energy savings) of 256.27 million metric tons (``Mt'') \7\ of carbon
dioxide (``CO2''), 99.71 thousand tons of sulfur dioxide
(``SO2''), 403.57 thousand tons of nitrogen oxides
(``NOX''), 1,846.56 thousand tons of methane
(``CH4''), 2.32 thousand tons of nitrous oxide
(``N2O''), and 0.65 tons of mercury (``Hg'').\8\
---------------------------------------------------------------------------
\7\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\8\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the Annual Energy
Outlook 2022 (``AEO2022''). AEO2022 represents current federal and
state legislation and final implementation of regulations as of the
time of its preparation. See section IV.K of this document for
further discussion of AEO2022 assumptions that effect air pollutant
emissions.
---------------------------------------------------------------------------
DOE estimates climate benefits from a reduction in greenhouse gases
(GHG) using four different estimates of the social cost of
CO2 (``SC-CO2''), the social cost of methane
(``SC-CH4''), and the social cost of nitrous oxide (``SC-
N2O''). Together these represent the social cost of GHG (SC-
GHG). DOE used interim SC-GHG values developed by an Interagency
Working Group on the Social Cost of Greenhouse Gases (IWG),\9\ as
discussed in section IV.L. of this document. For presentational
purposes, the climate benefits associated with the average SC-GHG at a
3-percent discount rate are $8.66 billion. DOE does not have a single
central SC-GHG point estimate and it emphasizes the importance and
value of considering the benefits calculated using all four SC-GHG
estimates.\10\
---------------------------------------------------------------------------
\9\ See Interagency Working Group on Social Cost of Greenhouse
Gases, Technical Support Document: Social Cost of Carbon, Methane,
and Nitrous Oxide. Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
\10\ On March 16, 2022, the Fifth Circuit Court of Appeals (No.
22-30087) granted the federal government's emergency motion for stay
pending appeal of the February 11, 2022, preliminary injunction
issued in Louisiana v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a
result of the Fifth Circuit's order, the preliminary injunction is
no longer in effect, pending resolution of the federal government's
appeal of that injunction or a further court order. Among other
things, the preliminary injunction enjoined the defendants in that
case from ``adopting, employing, treating as binding, or relying
upon'' the interim estimates of the social cost of greenhouse
gases--which were issued by the Interagency Working Group on the
Social Cost of Greenhouse Gases on February 26, 2021--to monetize
the benefits of reducing greenhouse gas emissions. As reflected in
this rule, DOE has reverted to its approach prior to the injunction
and present monetized greenhouse gas abatement benefits where
appropriate and permissible under law.
---------------------------------------------------------------------------
DOE also estimates health benefits from SO2 and
NOX emissions reductions.\11\ DOE estimates the present
value of the health benefits would be $4.69 billion using a 7-percent
discount rate, and $15.57 billion using a 3-percent discount rate.\12\
DOE is currently only monetizing (for SO2 and
NOX) PM2.5 precursor health benefits and (for
NOX) ozone precursor health benefits, but will continue to
assess the ability to monetize other effects such as health benefits
from reductions in direct PM2.5 emissions.
---------------------------------------------------------------------------
\11\ DOE estimated the monetized value of SO2 and
NOX emissions reductions associated with electricity
savings using benefit per ton estimates from the EPA. e. See section
IV.L.2 of this document for further discussion.
\12\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
---------------------------------------------------------------------------
Table I.5 summarizes the monetized benefits and costs expected to
result from the proposed standards for liquid-immersed distribution
transformers. In the table, total benefits for both the 3-percent and
7-percent cases are presented using the average GHG social costs with
3-percent discount rate, but the Department emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
cases. The estimated total net benefits using each of the four cases
are
[[Page 1727]]
presented in section V.B.8 of this document.
Table I.5--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for Liquid-Immersed Distribution Transformers
(TSL 4)
------------------------------------------------------------------------
Billion
($2021)
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 12.77
Climate Benefits *...................................... 8.66
Health Benefits **...................................... 15.57
Total Benefits [dagger]................................. 37.01
Consumer Incremental Product Costs [Dagger]............. 7.48
Net Benefits............................................ 29.53
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 4.28
Climate Benefits * (3% discount rate)................... 8.66
Health Benefits **...................................... 4.69
Total Benefits [dagger]................................. 17.63
Consumer Incremental Product Costs [Dagger]............. 4.02
Net Benefits............................................ 13.61
------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution
transformers shipped in 2027-2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027-
2056.
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. As reflected in this rule, DOE has
reverted to its approach prior to the injunction and present monetized
greenhouse gas abatement benefits where appropriate and permissible
under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of the benefits of GHG and
NOX and SO2 emission reductions, all
annualized.\13\ The national operating savings are domestic private
U.S. consumer monetary savings that occur as a result of purchasing the
covered products and are measured for the lifetime of distribution
transformers shipped in 2027-2056. The benefits associated with reduced
emissions achieved as a result of the proposed standards are also
calculated based on the lifetime of liquid-immersed distribution
transformers shipped in 2027-2056.
---------------------------------------------------------------------------
\13\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2021, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2030), and then discounted the present value from each year
to 2021. Using the present value, DOE then calculated the fixed
annual payment over a 30-year period, starting in the compliance
year, that yields the same present value.
---------------------------------------------------------------------------
Estimates of annualized benefits and costs of the proposed
standards are shown in Table I.6. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
health benefits from reduced NOx and SO2 emissions, and the
3-percent discount rate case for climate benefits from reduced GHG
emissions, the estimated cost of the standards proposed in this rule is
$424.8 million per year in increased equipment costs, while the
estimated annual benefits are $451.9 million in reduced equipment
operating costs, $497.4 million in climate benefits, and $495.3 million
in health benefits. In this case. The net benefit would amount to
$1,019.8 million per year.
[[Page 1728]]
Table I.6--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Liquid-Immersed
Distribution Transformers (TSL 4)
----------------------------------------------------------------------------------------------------------------
Million (2021$/year)
-------------------------------------------------------
Category Primary Low-net-benefits High-net-benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 733.5 686.9 789.9
Climate Benefits *...................................... 497.4 478.9 519.5
Health Benefits **...................................... 894.3 860.5 934.8
Total Benefits [dagger]................................. 2,125.3 2,026.3 2,244.2
Consumer Incremental Product Costs [Dagger]............. 429.5 449.0 413.2
Net Benefits............................................ 1,695.8 1,577.3 1,831.0
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 451.9 425.7 482.2
Climate Benefits * (3% discount rate)................... 497.4 478.9 519.5
Health Benefits **...................................... 495.3 477.9 515.3
Total Benefits [dagger]................................. 1,444.7 1,382.5 1,517.0
Consumer Incremental Product Costs [Dagger]............. 424.8 442.1 409.9
Net Benefits............................................ 1,019.8 940.5 1,107.2
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
2. Low-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the proposed energy conservation
standards for low-voltage dry-type distribution transformers would save
a significant amount of energy. Relative to the case without amended
standards, the lifetime energy savings for low-voltage dry-type
distribution transformers purchased in the 30-year period that begins
in the anticipated year of compliance with the amended standards (2027-
2056) amount to 2.47 quadrillion British thermal units (``Btu''), or
quads.\14\ This represents a fleet savings of 47 percent relative to
the energy use of these products in the case without amended standards
(referred to as the ``no-new-standards case'').
---------------------------------------------------------------------------
\14\ The quantity refers to full-fuel-cycle (``FFC'') energy
savings. FFC energy savings includes the energy consumed in
extracting, processing, and transporting primary fuels (i.e., coal,
natural gas, petroleum fuels), and, thus, presents a more complete
picture of the impacts of energy efficiency standards. For more
information on the FFC metric, see section IV.H.2 of this document.
---------------------------------------------------------------------------
The cumulative net present value (``NPV'') of total consumer
benefits of the proposed standards for low-voltage dry-type
distribution transformers ranges from 2.63 billion (2021$) (at a 7-
percent discount rate) to 9.63 billion (2021$) (at a 3-percent discount
rate). This NPV expresses the estimated total value of future
operating-cost savings minus the estimated increased product costs for
low-voltage dry-type distribution transformers purchased in 2027-2056.
In addition, the proposed standards for low-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the proposed standards would
result in cumulative emission reductions (over the same period as for
energy savings) of 77.57 million metric tons (``Mt'') \15\ of carbon
dioxide (``CO2''), 92.81 thousand tons of sulfur dioxide
(``SO2''), 123.44 thousand tons of nitrogen oxides
(``NOX''), 567.30 thousand tons of methane
(``CH4''), 0.70 thousand tons of nitrous oxide
(``N2O''), and 0.19 tons of mercury (``Hg'').\16\
---------------------------------------------------------------------------
\15\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\16\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the Annual Energy
Outlook 2022 (``AEO2022''). AEO2022 represents current federal and
state legislation and final implementation of regulations as of the
time of its preparation. See section IV.K of this document for
further discussion of AEO2022 assumptions that effect air pollutant
emissions.
---------------------------------------------------------------------------
[[Page 1729]]
DOE estimates climate benefits from a reduction in greenhouse gases
(GHG) using four different estimates of the social cost of
CO2 (``SC-CO2''), the social cost of methane
(``SC-CH4''), and the social cost of nitrous oxide (``SC-
N2O''). Together these represent the social cost of GHG (SC-
GHG). DOE used interim SC-GHG values developed by an Interagency
Working Group on the Social Cost of Greenhouse Gases (IWG),\17\ as
discussed in section IV.L of this document. For presentational
purposes, the climate benefits associated with the average SC-GHG at a
3-percent discount rate are $2.77 billion. (DOE does not have a single
central SC-GHG point estimate and it emphasizes the importance and
value of considering the benefits calculated using all four SC-GHG
estimates.)
---------------------------------------------------------------------------
\17\ See Interagency Working Group on Social Cost of Greenhouse
Gases, Technical Support Document: Social Cost of Carbon, Methane,
and Nitrous Oxide. Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------
DOE also estimates health benefits from SO2 and
NOX emissions reductions.\18\ DOE estimates the present
value of the health benefits would be $1.53 billion using a 7-percent
discount rate, and $4.91 billion using a 3-percent discount rate.\19\
DOE is currently only monetizing (for SO2 and
NOX) PM2.5 precursor health benefits and (for
NOX) ozone precursor health benefits, but will continue to
assess the ability to monetize other effects such as health benefits
from reductions in direct PM2.5 emissions.
---------------------------------------------------------------------------
\18\ DOE estimated the monetized value of SO2 and
NOX emissions reductions associated with electricity
savings using benefit per ton estimates from the EPA. See section
IV.L.2 of this document for further discussion.
\19\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
---------------------------------------------------------------------------
Table I.7 summarizes the monetized benefits and costs expected to
result from the proposed standards for low-voltage dry-type
distribution transformers. In the table, total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with 3-percent discount rate, but the Department emphasizes the
importance and value of considering the benefits calculated using all
four SC-GHG cases. The estimated total net benefits using each of the
four cases are presented in section V.B.8 of this document.
Table I.7--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for Low-Voltage Dry-Type Distribution
Transformers (TSL 5)
------------------------------------------------------------------------
Billion
($2021)
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 13.45
Climate Benefits *...................................... 2.77
Health Benefits **...................................... 4.91
Total Benefits [dagger]................................. 21.13
Consumer Incremental Product Costs [Dagger]............. 3.82
Net Benefits............................................ 17.31
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 4.69
Climate Benefits * (3% discount rate)................... 2.77
Health Benefits **...................................... 1.53
Total Benefits [dagger]................................. 8.99
Consumer Incremental Product Costs [Dagger]............. 2.05
Net Benefits............................................ 6.94
------------------------------------------------------------------------
Note: This table presents the costs and benefits associated with
distribution transformers shipped in 2027-2056. These results include
benefits to consumers which accrue after 2056 from the products
shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. As reflected in this rule, DOE has
reverted to its approach prior to the injunction and present monetized
greenhouse gas abatement benefits where appropriate and permissible
under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
[[Page 1730]]
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of the benefits of GHG and
NOX and SO2 emission reductions, all
annualized.\20\ The national operating savings are domestic private
U.S. consumer monetary savings that occur as a result of purchasing the
covered products and are measured for the lifetime of low-voltage dry-
type distribution transformers shipped in 2027-2056. The benefits
associated with reduced emissions achieved as a result of the proposed
standards are also calculated based on the lifetime of low-voltage dry-
type distribution transformers shipped in 2027-2056.
---------------------------------------------------------------------------
\20\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2021, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2030), and then discounted the present value from each year
to 2021. Using the present value, DOE then calculated the fixed
annual payment over a 30-year period, starting in the compliance
year, that yields the same present value.
---------------------------------------------------------------------------
Estimates of annualized benefits and costs of the proposed
standards are shown in Table I.8. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
health benefits from reduced NOX and SO2
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated cost of the standards
proposed in this rule is $216.9 million per year in increased equipment
costs, while the estimated annual benefits are $495.0 million in
reduced equipment operating costs, $159.2 million in climate benefits,
and $162.1 million in health benefits. In this case. The net benefit
would amount to $599.4 million per year.
Table I.8--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Low-Voltage Dry Type
Distribution Transformers (TSL 5)
----------------------------------------------------------------------------------------------------------------
Million (2021$/year)
-------------------------------------------------------
Category Primary Low-net-benefits High-net-benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 772.1 716.9 831.3
Climate Benefits *...................................... 159.2 151.6 165.9
Health Benefits **...................................... 281.8 268.3 293.9
Total Benefits [dagger]................................. 1,213.1 1,136.7 1,291.1
Consumer Incremental Product Costs [Dagger]............. 219.3 228.7 208.7
Net Benefits............................................ 993.8 908.0 1,082.4
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 495.0 462.8 528.7
Climate Benefits * (3% discount rate)................... 159.2 151.6 165.9
Health Benefits **...................................... 162.1 154.9 168.2
Total Benefits [dagger]................................. 816.3 769.3 862.8
Consumer Incremental Product Costs [Dagger]............. 216.9 225.2 207.3
Net Benefits............................................ 599.4 544.1 655.5
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
3. Medium Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the proposed energy conservation
standards for medium-voltage dry-type distribution transformers would
save a significant amount of energy. Relative to the case without
amended standards, the lifetime energy savings for medium-voltage dry-
type distribution transformers purchased in the 30-year period that
begins in the anticipated
[[Page 1731]]
year of compliance with the amended standards (2027-2056) amount to
0.12 quadrillion British thermal units (``Btu''), or quads.\21\ This
represents a fleet savings of 24 percent relative to the energy use of
these products in the case without amended standards (referred to as
the ``no-new-standards case'').
---------------------------------------------------------------------------
\21\ The quantity refers to full-fuel-cycle (``FFC'') energy
savings. FFC energy savings includes the energy consumed in
extracting, processing, and transporting primary fuels (i.e., coal,
natural gas, petroleum fuels), and, thus, presents a more complete
picture of the impacts of energy efficiency standards. For more
information on the FFC metric, see section IV.H.2 of this document.
---------------------------------------------------------------------------
The cumulative net present value (``NPV'') of total consumer
benefits of the proposed standards for medium-voltage dry-type
distribution transformers ranges from 0.04 billion (2021$) (at a 7-
percent discount rate) to 0.21 billion (2021$) (at a 3-percent discount
rate). This NPV expresses the estimated total value of future
operating-cost savings minus the estimated increased product costs for
medium-voltage dry-type distribution transformers purchased in 2027-
2056.
In addition, the proposed standards for medium-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the proposed standards would
result in cumulative emission reductions (over the same period as for
energy savings) of 3.71 million metric tons (``Mt'') \22\ of carbon
dioxide (``CO2''), 1.43 thousand tons of sulfur dioxide
(``SO2''), 5.93 thousand tons of nitrogen oxides
(``NOX''), 27.29 thousand tons of methane
(``CH4''), 0.03 thousand tons of nitrous oxide
(``N2O''), and 0.01 tons of mercury (``Hg'').\23\
---------------------------------------------------------------------------
\22\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO2 are presented in short tons.
\23\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the Annual Energy
Outlook 2022 (``AEO2022''). AEO2022 represents current federal and
state legislation and final implementation of regulations as of the
time of its preparation. See section IV.K of this document for
further discussion of AEO2022 assumptions that effect air pollutant
emissions.
---------------------------------------------------------------------------
DOE estimates climate benefits from a reduction in greenhouse gases
(GHG) using four different estimates of the social cost of
CO2 (``SC-CO2''), the social cost of methane
(``SC-CH4''), and the social cost of nitrous oxide (``SC-
N2O''). Together these represent the social cost of GHG (SC-
GHG). DOE used interim SC-GHG values developed by an Interagency
Working Group on the Social Cost of Greenhouse Gases (IWG),\24\ as
discussed in IV.L of this document. For presentational purposes, the
climate benefits associated with the average SC-GHG at a 3-percent
discount rate are $0.13 billion. (DOE does not have a single central
SC-GHG point estimate and it emphasizes the importance and value of
considering the benefits calculated using all four SC-GHG estimates.)
---------------------------------------------------------------------------
\24\ See Interagency Working Group on Social Cost of Greenhouse
Gases, Technical Support Document: Social Cost of Carbon, Methane,
and Nitrous Oxide. Interim Estimates Under Executive Order 13990,
Washington, DC, February 2021. https://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------
DOE also estimates health benefits from SO2 and
NOX emissions reductions.\25\ DOE estimates the present
value of the health benefits would be $0.07 billion using a 7-percent
discount rate, and $0.24 billion using a 3-percent discount rate.\26\
DOE is currently only monetizing (for SO2 and
NOX) PM2.5 precursor health benefits and (for
NOX) ozone precursor health benefits, but will continue to
assess the ability to monetize other effects such as health benefits
from reductions in direct PM2.5 emissions.
---------------------------------------------------------------------------
\25\ DOE estimated the monetized value of SO2 and
NOX emissions reductions associated with electricity
savings using benefit per ton estimates from the EPA. See section
IV.L.2 of this document for further discussion.
\26\ DOE estimates the economic value of these emissions
reductions resulting from the considered TSLs for the purpose of
complying with the requirements of Executive Order 12866.
---------------------------------------------------------------------------
Table I.9 summarizes the monetized benefits and costs expected to
result from the proposed standards for medium-voltage dry-type
distribution transformers. In the table, total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with 3-percent discount rate, but the Department emphasizes the
importance and value of considering the benefits calculated using all
four SC-GHG cases. The estimated total net benefits using each of the
four cases are presented in section V.B.8 of this document.
Table I.9--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for Medium-Voltage Dry-Type Distribution
Transformers (TSL 2)
------------------------------------------------------------------------
Billion
($2021)
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 0.41
Climate Benefits *...................................... 0.13
Health Benefits **...................................... 0.24
Total Benefits [dagger]................................. 0.77
Consumer Incremental Product Costs [Dagger]............. 0.19
Net Benefits............................................ 0.58
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 0.14
Climate Benefits * (3% discount rate)................... 0.13
Health Benefits **...................................... 0.07
Total Benefits [dagger]................................. 0.35
Consumer Incremental Product Costs [Dagger]............. 0.10
Net Benefits............................................ 0.24
------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution
transformers shipped in 2027-2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027-
2056.
[[Page 1732]]
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. As reflected in this rule, DOE has
reverted to its approach prior to the injunction and present monetized
greenhouse gas abatement benefits where appropriate and permissible
under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The monetary values for the
total annualized net benefits are (1) the reduced consumer operating
costs, minus (2) the increase in product purchase prices and
installation costs, plus (3) the value of the benefits of GHG and
NOX and SO2 emission reductions, all
annualized.\27\ The national operating savings are domestic private
U.S. consumer monetary savings that occur as a result of purchasing the
covered equipment and are measured for the lifetime of medium-voltage
dry-type distribution transformers shipped in 2027-2056. The benefits
associated with reduced emissions achieved as a result of the proposed
standards are also calculated based on the lifetime of medium-voltage
dry-type distribution transformers shipped in 2027-2056.
---------------------------------------------------------------------------
\27\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2021, the year
used for discounting the NPV of total consumer costs and savings.
For the benefits, DOE calculated a present value associated with
each year's shipments in the year in which the shipments occur
(e.g., 2030), and then discounted the present value from each year
to 2021. Using the present value, DOE then calculated the fixed
annual payment over a 30-year period, starting in the compliance
year, that yields the same present value.
---------------------------------------------------------------------------
Estimates of annualized benefits and costs of the proposed
standards are shown in Table I.10. The results under the primary
estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
health benefits from reduced NOX and SO2
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated cost of the standards
proposed in this rule is $10.8 million per year in increased equipment
costs, while the estimated annual benefits are $14.9 million in reduced
equipment operating costs, $7.6 million in climate benefits, and $7.8
million in health benefits. The net benefit would amount to $19.5
million per year.
Table I.10--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Medium-Voltage Dry-Type
Distribution Transformers (TSL 2)
----------------------------------------------------------------------------------------------------------------
Million (2021$/year)
-------------------------------------------------------
Category Primary Low-net-benefits High-net-benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 23.3 22.2 25.8
Climate Benefits *...................................... 7.6 7.5 8.2
Health Benefits **...................................... 13.5 13.2 14.5
Total Benefits [dagger]................................. 44.4 42.9 48.5
Consumer Incremental Product Costs [Dagger]............. 11.0 11.7 10.7
Net Benefits............................................ 33.5 31.1 37.7
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 14.9 14.3 16.4
Climate Benefits * (3% discount rate)................... 7.6 7.5 8.2
Health Benefits **...................................... 7.8 7.6 8.3
Total Benefits [dagger]................................. 30.3 29.4 32.9
Consumer Incremental Product Costs [Dagger]............. 10.8 11.6 10.6
Net Benefits............................................ 19.5 17.9 22.2
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
[[Page 1733]]
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
DOE's analysis of the national impacts of the proposed standards is
described in sections IV.H, IV.K and IV.L of this document.
D. Conclusion
DOE has tentatively concluded that the proposed standards represent
the maximum improvement in energy efficiency that is technologically
feasible and economically justified, and would result in the
significant conservation of energy. Specifically, with regards to
technological feasibility products achieving these standard levels are
already commercially available for all product classes covered by this
proposal. As for economic justification, DOE's analysis shows that for
each equipment class the benefits of the proposed standards exceed the
burdens of the proposed standards. Using a 7-percent discount rate for
consumer benefits and costs and NOX and SO2
reduction benefits, and a 3-percent discount rate case for GHG social
costs, the estimated annual cost of the proposed standards for
distribution transformers is $652.5 million per year in increased
distribution transformer costs, while the estimated annual benefits are
$961.8 million in reduced distribution transformer operating costs,
$664.2 million in climate benefits and $665.2 million in health
benefits. The net benefit amounts to $1,638.7 million per year.
Table I.11--Annualized Benefits and Costs of Proposed Energy Conservation Standards for All Distribution
Transformers at Proposed Standard Levels
----------------------------------------------------------------------------------------------------------------
Million (2021$/year)
-------------------------------------------------------
Category Primary Low-net-benefits High-net-benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 1,528.9 1,426.0 1,647.0
Climate Benefits *...................................... 664.2 638.0 693.6
Health Benefits **...................................... 1,189.6 1,142.0 1,243.2
Total Benefits [dagger]................................. 3,382.8 3,205.9 3,583.8
Consumer Incremental Product Costs [Dagger]............. 659.8 689.4 632.6
Net Benefits............................................ 2,723.1 2,516.4 2,951.1
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 961.8 902.8 1,027.3
Climate Benefits * (3% discount rate)................... 664.2 638.0 693.6
Health Benefits **...................................... 665.2 640.4 691.8
Total Benefits [dagger]................................. 2,291.3 2,181.2 2,412.7
Consumer Incremental Product Costs [Dagger]............. 652.5 678.9 627.8
Net Benefits............................................ 1,638.7 1,502.5 1,784.9
----------------------------------------------------------------------------------------------------------------
Note: This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056.
These results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the Federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the Federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the injunction and present monetized
benefits where appropriate and permissible under law.
[[Page 1734]]
**Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the low
estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor health
benefits and (for NOX) ozone precursor health benefits but will continue to assess the ability to monetize
other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of this
document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
Table I.12--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for All Distribution Transformers at Proposed
Standard Levels
------------------------------------------------------------------------
Billion
($2021)
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 26.63
Climate Benefits *...................................... 11.56
Health Benefits **...................................... 20.72
Total Benefits [dagger]................................. 58.91
Consumer Incremental Product Costs [Dagger]............. 11.49
Net Benefits............................................ 47.42
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings......................... 9.11
Climate Benefits * (3% discount rate)................... 11.56
Health Benefits **...................................... 6.29
Total Benefits [dagger]................................. 26.97
Consumer Incremental Product Costs [Dagger]............. 6.17
Net Benefits............................................ 20.79
------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution
transformers shipped in 2027-2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027-
2056.
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
Federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the Federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the
injunction and present monetized benefits where appropriate and
permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
The significance of energy savings offered by a new or amended
energy conservation standard cannot be determined without knowledge of
the specific circumstances surrounding a given rulemaking.\28\ For
example, some covered products and equipment, including distribution
transformers, have substantial energy consumption occur during periods
of peak energy demand. The impacts of these products on the energy
infrastructure can be more pronounced than products with relatively
constant demand. Accordingly, DOE evaluates the significance of energy
savings on a case-by-case basis.
---------------------------------------------------------------------------
\28\ Procedures, Interpretations, and Policies for Consideration
in New or Revised Energy Conservation Standards and Test Procedures
for Consumer Products and Commercial/Industrial Equipment, 86 FR
70892, 70901 (Dec. 13, 2021).
---------------------------------------------------------------------------
As previously mentioned, the standards are projected to result in
estimated national energy savings of 10.60 quad. Based on the amount of
FFC savings, the corresponding reduction in GHG emissions, and need to
confront the global climate crisis, DOE has initially determined the
energy savings from the proposed standard levels are ``significant''
within the meaning of 42 U.S.C. 6295(o)(3)(B). A more detailed
discussion of the basis for these tentative conclusions is contained in
the remainder of this document and the accompanying TSD.
DOE also considered more-stringent energy efficiency levels as
potential standards, and is still considering them in this rulemaking.
However, DOE has tentatively concluded that the potential burdens of
the more-stringent energy efficiency levels would outweigh the
projected benefits.
Based on consideration of the public comments DOE receives in
response to this document and related information collected and
analyzed during the course of this rulemaking effort, DOE may adopt
energy efficiency levels presented in this document that are either
higher or lower than the proposed
[[Page 1735]]
standards, or some combination of level(s) that incorporate the
proposed standards in part.
II. Introduction
The following section briefly discusses the statutory authority
underlying this proposed rule, as well as some of the relevant
historical background related to the establishment of standards for
distribution transformers.
A. Authority
EPCA authorizes DOE to regulate the energy efficiency of a number
of consumer products and certain industrial equipment. Title III, Part
B of EPCA (42 U.S.C. 6291-6309, as codified), established the Energy
Conservation Program for ``Consumer Products Other Than Automobiles.''
Title III, Part C of EPCA (42 U.S.C. 6311-6317, as codified), added by
Public Law 95-619, Title IV, section 411(a), established the Energy
Conservation Program for Certain Industrial Equipment. The Energy
Policy Act of 1992, Public Law 102-486, amended EPCA and directed DOE
to prescribe energy conservation standards for those distribution
transformers for which DOE determines such standards would be
technologically feasible, economically justified, and would result in
significant energy savings. (42 U.S.C. 6317(a)) The Energy Policy Act
of 2005, Public Law 109-58, amended EPCA to establish energy
conservation standards for low-voltage dry-type distribution
transformers. (42 U.S.C. 6295(y))
EPCA further provides that, not later than 6 years after the
issuance of any final rule establishing or amending a standard, DOE
must publish either a notice of determination that standards for the
product do not need to be amended, or a NOPR including new proposed
energy conservation standards (proceeding to a final rule, as
appropriate). (42 U.S.C. 6316(e)(1); 42 U.S.C. 6295(m)(1))
The energy conservation program under EPCA consists essentially of
four parts: (1) testing, (2) labeling, (3) the establishment of Federal
energy conservation standards, and (4) certification and enforcement
procedures. Relevant provisions of EPCA specifically include
definitions (42 U.S.C. 6311; 42 U.S.C. 6291), test procedures (42
U.S.C. 6314; 42 U.S.C. 6293), labeling provisions (42 U.S.C. 6315; 42
U.S.C. 6294), energy conservation standards (42 U.S.C. 6313; 42 U.S.C.
6295), and the authority to require information and reports from
manufacturers (42 U.S.C. 6316; 42 U.S.C. 6296).
Federal energy efficiency requirements for covered equipment
established under EPCA generally supersede State laws and regulations
concerning energy conservation testing, labeling, and standards. (42
U.S.C. 6316(a) and (b); 42 U.S.C. 6297) DOE may, however, grant waivers
of Federal preemption for particular State laws or regulations, in
accordance with the procedures and other provisions set forth under
EPCA. (See 42 U.S.C. 6316(a) (applying the preemption waiver provisions
of 42 U.S.C. 6297))
Subject to certain criteria and conditions, DOE is required to
develop test procedures to measure the energy efficiency, energy use,
or estimated annual operating cost of each covered equipment. (42
U.S.C. 6316(a), 42 U.S.C. 6295(o)(3)(A) and 42 U.S.C. 6295(r))
Manufacturers of covered equipment must use the Federal test procedures
as the basis for: (1) certifying to DOE that their equipment complies
with the applicable energy conservation standards adopted pursuant to
EPCA (42 U.S.C. 6316(a); 42 U.S.C. 6295(s)), and (2) making
representations about the efficiency of that equipment (42 U.S.C.
6314(d)). Similarly, DOE must use these test procedures to determine
whether the equipment complies with relevant standards promulgated
under EPCA. (42 U.S.C. 6316(a); 42 U.S.C. 6295(s)) The DOE test
procedures for distribution transformers appear at title 10 of the Code
of Federal Regulations (``CFR'') part 431, subpart K, appendix A.
DOE must follow specific statutory criteria for prescribing new or
amended standards for covered equipment, including distribution
transformers. Any new or amended standard for a covered product must be
designed to achieve the maximum improvement in energy efficiency that
the Secretary of Energy determines is technologically feasible and
economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A) and
42 U.S.C. 6295(o)(3)(B)) Furthermore, DOE may not adopt any standard
that would not result in the significant conservation of energy. (42
U.S.C. 6295(o)(3))
Moreover, DOE may not prescribe a standard: (1) for certain
products, including distribution transformers, if no test procedure has
been established for the product, or (2) if DOE determines by rule that
the standard is not technologically feasible or economically justified.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(A)-(B)) In deciding whether a
proposed standard is economically justified, DOE must determine whether
the benefits of the standard exceed its burdens. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(i)) DOE must make this determination after
receiving comments on the proposed standard, and by considering, to the
greatest extent practicable, the following seven statutory factors:
(1) The economic impact of the standard on manufacturers and
consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated average
life of the covered products in the type (or class) compared to any
increase in the price, initial charges, or maintenance expenses for the
covered products that are likely to result from the standard;
(3) The total projected amount of energy (or as applicable, water)
savings likely to result directly from the standard;
(4) Any lessening of the utility or the performance of the covered
products likely to result from the standard;
(5) The impact of any lessening of competition, as determined in
writing by the Attorney General, that is likely to result from the
standard;
(6) The need for national energy and water conservation; and
(7) Other factors the Secretary of Energy (``Secretary'') considers
relevant. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(I)-(VII))
Further, EPCA establishes a rebuttable presumption that a standard
is economically justified if the Secretary finds that the additional
cost to the consumer of purchasing a product complying with an energy
conservation standard level will be less than three times the value of
the energy savings during the first year that the consumer will receive
as a result of the standard, as calculated under the applicable test
procedure. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(iii))
EPCA also contains what is known as an ``anti-backsliding''
provision, which prevents the Secretary from prescribing any amended
standard that either increases the maximum allowable energy use or
decreases the minimum required energy efficiency of a covered product.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(1)) Also, the Secretary may not
prescribe an amended or new standard if interested persons have
established by a preponderance of the evidence that the standard is
likely to result in the unavailability in the United States in any
covered product type (or class) of performance characteristics
(including reliability), features, sizes, capacities, and volumes that
are substantially the same as those generally available in the United
States. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(4))
Additionally, EPCA specifies requirements when promulgating an
[[Page 1736]]
energy conservation standard for a covered product that has two or more
product classes. DOE must specify a different standard level for a type
or class of product that has the same function or intended use, if DOE
determines that products within such group: (A) consume a different
kind of energy from that consumed by other covered products within such
type (or class); or (B) have a capacity or other performance-related
feature which other products within such type (or class) do not have
and such feature justifies a higher or lower standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q)(1)) In determining whether a performance-
related feature justifies a different standard for a group of products,
DOE must consider such factors as the utility to the consumer of the
feature and other factors DOE deems appropriate. Id. Any rule
prescribing such a standard must include an explanation of the basis on
which such higher or lower level was established. (42 U.S.C. 6316(a);
42 U.S.C. 6295(q)(2))
B. Background
1. Current Standards
In a final rule published on April 18, 2013 (``April 2013 Standards
Final Rule''), DOE prescribed the current energy conservation standards
for distribution transformers manufactured on and after January 1,
2016. 78 FR 23336, 23433. These standards are set forth in DOE's
regulations at 10 CFR 431.196 and are repeated in Table II.1, Table
II.2, Table II.3.
Table II.1--Federal Energy Conservation Standards for Low-Voltage Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
15......................................... 97.70 15................................ 97.89
25......................................... 98.00 30................................ 98.23
37.5....................................... 98.20 45................................ 98.40
50......................................... 98.30 75................................ 98.60
75......................................... 98.50 112.5............................. 98.74
100........................................ 98.60 150............................... 98.83
167........................................ 98.70 225............................... 98.94
250........................................ 98.80 300............................... 99.02
333........................................ 98.90 500............................... 99.14
750............................... 99.23
1,000............................. 99.28
----------------------------------------------------------------------------------------------------------------
Table II.2--Federal Energy Conservation Standards for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10......................................... 98.70 15................................ 98.65
15......................................... 98.82 30................................ 98.83
25......................................... 98.95 45................................ 98.92
37.5....................................... 99.05 75................................ 99.03
50......................................... 99.11 112.5............................. 99.11
75......................................... 99.19 150............................... 99.16
100........................................ 99.25 225............................... 99.23
167........................................ 99.33 300............................... 99.27
250........................................ 99.39 500............................... 99.35
333........................................ 99.43 750............................... 99.40
500........................................ 99.49 1,000............................. 99.43
667........................................ 99.52 1,500............................. 99.48
833........................................ 99.55 2,000............................. 99.51
2,500............................. 99.52
----------------------------------------------------------------------------------------------------------------
Table II.3--Federal Energy Conservation Standards for Medium-Voltage Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL BIL
------------------------------------------------- -----------------------------------------------
kVA 20-45 kV 46-95 kV >=96 kV kVA 20-45 kV 46-95 kV >=96 kV
------------------------------------------------- -----------------------------------------------
Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 98.1 97.86 ............... 15.................. 97.5 97.18 ..............
25............................... 98.33 98.12 ............... 30.................. 97.9 97.63 ..............
37.5............................. 98.49 98.3 ............... 45.................. 98.1 97.86 ..............
50............................... 98.6 98.42 ............... 75.................. 98.33 98.13 ..............
75............................... 98.73 98.57 98.53 112.5............... 98.52 98.36 ..............
100.............................. 98.82 98.67 98.63 150................. 98.65 98.51 ..............
[[Page 1737]]
167.............................. 98.96 98.83 98.80 225................. 98.82 98.69 98.57
250.............................. 99.07 98.95 98.91 300................. 98.93 98.81 98.69
333.............................. 99.14 99.03 98.99 500................. 99.09 98.99 98.89
500.............................. 99.22 99.12 99.09 750................. 99.21 99.12 99.02
667.............................. 99.27 99.18 99.15 1,000............... 99.28 99.2 99.11
833.............................. 99.31 99.23 99.20 1,500............... 99.37 99.3 99.21
2,000............... 99.43 99.36 99.28
2,500............... 99.47 99.41 99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
2. History of Standards Rulemaking for Distribution Transformers
On June 18, 2019, DOE published notice that it was initiating an
early assessment review to determine whether any new or amended
standards would satisfy the relevant requirements of EPCA for a new or
amended energy conservation standard for distribution transformers and
a request for information (``RFI''). 84 FR 28239 (``June 2019 Early
Assessment Review RFI'').
On August 27, 2021, DOE published a notification of a webinar and
availability of a preliminary technical support document, which
announced the availability of its analysis for distribution
transformers. 86 FR 48058 (``August 2021 Preliminary Analysis'') The
purpose of the August 2021 Preliminary Analysis was to make publicly
available the initial technical and economic analyses conducted for
distribution transformers, and present initial results of those
analyses. DOE did not propose new or amended standards for distribution
transformers at that time. The initial technical support document
(``TSD'') and accompanying analytical spreadsheets for the August 2021
Preliminary Analysis provided the analyses DOE undertook to examine the
potential for amending energy conservation standards for distribution
transformers and provided preliminary discussions in response to a
number of issues raised by comments to the June 2019 Early Assessment
Review RFI. It described the analytical methodology that DOE used, and
each analysis DOE had performed.
On November 11, 2021, DOE published a notice reopening the comment
period an additional 30 days. 86 FR 63318.
DOE received comments in response to the August 2021 Preliminary
Analysis from the interested parties listed in Table II.4.
Table II.4--August 2021 Preliminary Analysis Written Comments
----------------------------------------------------------------------------------------------------------------
Commenter(s) Abbreviation Docket No. Commenter type
----------------------------------------------------------------------------------------------------------------
Electric Research and Manufacturing ERMCO..................... 45 Manufacturer.
Cooperative, Inc.
Powersmiths, Inc........................ Powersmiths............... 46 Manufacturer.
Copper Development Association.......... CDA....................... 47 Trade Organization.
Schneider Electric...................... Schneider................. 49 Manufacturer.
National Electrical Manufacturers NEMA...................... 50 Trade Organization.
Association.
Northwest Energy Efficiency Alliance.... NEEA...................... 51 Efficiency Organization.
Appliance Standards Awareness Project, Efficiency Advocates...... 52 Efficiency Organization.
American Council for an Energy-
Efficient Economy, Natural Resources
Defense Council.
Metglas, Inc............................ Metglas................... 53 Steel Manufacturer.
Carte International, Inc................ Carte..................... 54 Manufacturer.
Eaton Corporation....................... Eaton..................... 55 Manufacturer.
Edison Electric Institute............... EEI....................... 56 Utilities.
Cleveland-Cliffs Steel Corporation...... Cliffs.................... 57 Steel Manufacturer.
Greenville Electric Utility System...... GEUS...................... 58 Utilities.
Howard Industries, Inc.................. Howard.................... 59 Manufacturer.
----------------------------------------------------------------------------------------------------------------
A parenthetical reference at the end of a comment quotation or
paraphrase provides the location of the item in the public record.\29\
---------------------------------------------------------------------------
\29\ The parenthetical reference provides a reference for
information located in the docket of DOE's rulemaking to develop
energy conservation standards for distribution transformers. (Docket
No. EERE-2019-BT-STD-0018, which is maintained at
www.regulations.gov). The references are arranged as follows:
(commenter name, comment docket ID number, page of that document).
---------------------------------------------------------------------------
C. Deviation From Appendix A
In accordance with section 3(a) of 10 CFR part 430, subpart C,
appendix A (``appendix A''), DOE notes that it is deviating from the
provision in appendix A regarding the NOPR stage for an energy
conservation standard rulemaking. Section 6(f)(2) of appendix A
specifies that the length of the public comment period for a NOPR will
vary depending upon the circumstances of the particular rulemaking, but
will not be less than 75 calendar days. For this NOPR, DOE is providing
a 60-day comment period, as required by EPCA. 42 U.S.C. 6316(a); 42
U.S.C. 6295(p). As stated previously, DOE requested
[[Page 1738]]
comment in the June 2019 Early Assessment Review RFI on the technical
and economic analyses and provided stakeholders a 45-day comment
period. 84 FR 28239. Additionally, DOE provided a 75-day comment period
for the August 2021 Preliminary Analysis. 86 FR 48058. DOE also
reopened the comment period for the August 2021 Preliminary Analysis
for an additional 30-days. 86 FR 63318. DOE has relied on many of the
same analytical assumptions and approaches as used in the preliminary
assessment presented in the TSD. Therefore, DOE believes a 60-day
comment period is appropriate and will provide interested parties with
a meaningful opportunity to comment on the proposed rule.
III. General Discussion
DOE developed this proposal after considering oral and written
comments, data, and information from interested parties that represent
a variety of interests. The following discussion addresses issues
raised by these commenters.
A. Equipment Classes and Scope of Coverage
When evaluating and establishing energy conservation standards, DOE
divides covered products into equipment classes by the type of energy
used or by capacity or other performance-related features that justify
differing standards. In making a determination whether a performance-
related feature justifies a different standard, DOE must consider such
factors as the utility of the feature to the consumer and other factors
DOE determines are appropriate. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q))
The distribution transformer equipment classes considered in this
proposed rule are discussed in further detail in section IV.A.2 of this
document. This proposed rule covers distribution transformers which are
currently defined as a transformer that (1) has an input voltage of
34.5 kV or less; (2) has an output voltage of 600 V or less; (3) is
rated for operation at a frequency of 60 Hz; and (4) Has a capacity of
10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for
dry-type units; but (5) The term ``distribution transformer'' does not
include a transformer that is an autotransformer, drive (isolation)
transformer, grounding transformer, machine-tool (control transformer,
nonventilated transformer, rectified transformer, regulating
transformer, sealed transformer, special-impedance transformer, testing
transformer, transformer with tap range of 20 percent or more;
uninterruptible power supply transformer; or welding transformer. 10
CFR 431.192
The scope of coverage of this proposed rule is discussed in further
detail in section IV.A.1 of this document.
B. Test Procedure
EPCA sets forth generally applicable criteria and procedures for
DOE's adoption and amendment of test procedures. (42 U.S.C. 6314(a))
Manufacturers of covered products must use these test procedures to
certify to DOE that their product complies with energy conservation
standards and to quantify the efficiency of their product. DOE's
current energy conservation standards for distribution transformers are
expressed in terms of percentage efficiency at rated per-unit load
(PUL). (See 10 CFR 431.193; 10 CFR part 431, subpart K, appendix A
(``appendix A'').)
On September 14, 2021, DOE published a test procedure final rule
for distribution transformers that revised definitions for certain
terms, updated provisions based on the latest versions of relevant
industry test standards, maintained PUL for the certification of
efficiency and added provisions for representing efficiency at
alternative PULs and reference temperatures. 89 FR 51230 (``September
2021 TP Final Rule''). DOE determined that the amendments to the test
procedure adopted in the September 2021 TP Final Rule do not alter the
measured efficiency of distribution transformers or require retesting
or recertification solely as a result of DOE's adoption of the
amendments to the test procedure. Id. at 89 FR 51249.
C. Technological Feasibility
1. General
In each energy conservation standards rulemaking, DOE conducts a
screening analysis based on information gathered on all current
technology options and prototype designs that could improve the
efficiency of the products or equipment that are the subject of the
rulemaking. As the first step in such an analysis, DOE develops a list
of technology options for consideration in consultation with
manufacturers, design engineers, and other interested parties. DOE then
determines which of those means for improving efficiency are
technologically feasible. DOE considers technologies incorporated in
commercially available products or in working prototypes to be
technologically feasible. 10 CFR 431.4; 10 CFR part 430, subpart C,
appendix A, sections 6(b)(3)(i) and 7(b)(1) (``Process Rule'').
After DOE has determined that particular technology options are
technologically feasible, it further evaluates each technology option
in light of the following additional screening criteria: (1)
practicability to manufacture, install, and service; (2) adverse
impacts on product utility or availability; (3) adverse impacts on
health or safety, and (4) unique-pathway proprietary technologies. 10
CFR 431.4; Sections 6(c)(3)(ii)-(v) and 7(b)(2)-(5) of the Process
Rule. Section IV.B of this document discusses the results of the
screening analysis for distribution transformers, particularly the
designs DOE considered, those it screened out, and those that are the
basis for the standards considered in this proposed rule. For further
details on the screening analysis for this proposed rule, see chapter 4
of the NOPR technical support document (``TSD'').
2. Maximum Technologically Feasible Levels
When DOE proposes to adopt an amended standard for a type or class
of covered product, it must determine the maximum improvement in energy
efficiency or maximum reduction in energy use that is technologically
feasible for such product. (42 U.S.C. 6316(a); 42 U.S.C. 6295(p)(1))
Accordingly, in the engineering analysis, DOE determined the maximum
technologically feasible (``max-tech'') improvements in energy
efficiency for distribution transformers, using the design parameters
for the most efficient products available on the market or in working
prototypes. The max-tech levels that DOE determined for this rulemaking
are described in section IV.C.2.e of this proposed rule and in chapter
5 of the NOPR TSD.
D. Energy Savings
1. Determination of Savings
For each trial standard level (``TSL''), DOE projected energy
savings from application of the TSL to distribution transformer
purchased in the 30-year period that begins in the year of compliance
with the proposed standards (2027-2056).\30\ The savings are measured
over the entire lifetime of distribution transformers purchased in the
previous 30-year period.\31\ DOE
[[Page 1739]]
quantified the energy savings attributable to each TSL as the
difference in energy consumption between each standards case and the
no-new-standards case. The no-new-standards case represents a
projection of energy consumption that reflects how the market for a
product would likely evolve in the absence of amended energy
conservation standards.
---------------------------------------------------------------------------
\30\ Each TSL is composed of specific efficiency levels for each
product class. The TSLs considered for this NOPR are described in
section V.A of this document. DOE conducted a sensitivity analysis
that considers impacts for products shipped in a 9-year period.
\31\ Savings are determined for equipment shipped over the 30-
year analysis period of 2027 through 2056. Distribution transformers
have a maximum lifetime of 60 years; therefore savings are
determined for equipment that survive, and accrue savings through
2115.
---------------------------------------------------------------------------
DOE used its national impact analysis (``NIA'') model to estimate
national energy savings (``NES'') from potential amended or new
standards for distribution transformers. The NIA model (described in
section IV.H of this document) calculates energy savings in terms of
site energy, which is the energy directly consumed by products at the
locations where they are used. For electricity, DOE reports national
energy savings in terms of primary energy savings, which is the savings
in the energy that is used to generate and transmit the site
electricity. DOE also calculates NES in terms of FFC energy savings.
The FFC metric includes the energy consumed in extracting, processing,
and transporting primary fuels (i.e., coal, natural gas, petroleum
fuels), and thus presents a more complete picture of the impacts of
energy conservation standards.\32\ DOE's approach is based on the
calculation of an FFC multiplier for each of the energy types used by
covered products or equipment. For more information on FFC energy
savings, see section IV.H.2 of this document.
---------------------------------------------------------------------------
\32\ The FFC metric is discussed in DOE's statement of policy
and notice of policy amendment. 76 FR 51282 (Aug. 18, 2011), as
amended at 77 FR 49701 (Aug. 17, 2012).
---------------------------------------------------------------------------
2. Significance of Savings
To adopt any new or amended standards for a covered product, DOE
must determine that such action would result in significant energy
savings. (42 U.S.C. 6295(o)(3)(B))
The significance of energy savings offered by a new or amended
energy conservation standard cannot be determined without knowledge of
the specific circumstances surrounding a given rulemaking.\33\ For
example, some covered products and equipment have most of their energy
consumption occur during periods of peak energy demand. The impacts of
these products on the energy infrastructure can be more pronounced than
products with relatively constant demand.
---------------------------------------------------------------------------
\33\ The numeric threshold for determining the significance of
energy savings established in a final rule published on February 14,
2020 (85 FR 8626, 8670), was subsequently eliminated in a final rule
published on December 12, 2021 (86 FR 70892, 70906).
---------------------------------------------------------------------------
Accordingly, DOE evaluates the significance of energy savings on a
case-by-case basis, taking into account the significance of cumulative
FFC national energy savings, the cumulative FFC emissions reductions,
and the need to confront the global climate crisis, among other
factors. Based on the amount of FFC savings, the corresponding
reduction in emissions, and need to confront the global climate crisis,
DOE has initially determined the energy savings from the proposed
standard levels are ``significant'' within the meaning of 42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(B).
E. Economic Justification
1. Specific Criteria
As noted previously, EPCA provides seven factors to be evaluated in
determining whether a potential energy conservation standard is
economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(I)-(VII))) The following sections discuss how DOE has
addressed each of those seven factors in this rulemaking.
a. Economic Impact on Manufacturers and Consumers
In determining the impacts of a potential amended standard on
manufacturers, DOE conducts an MIA, as discussed in section IV.J of
this document. DOE first uses an annual cash-flow approach to determine
the quantitative impacts. This step includes both a short-term
assessment--based on the cost and capital requirements during the
period between when a regulation is issued and when entities must
comply with the regulation--and a long-term assessment over a 30-year
period. The industry-wide impacts analyzed include (1) INPV, which
values the industry on the basis of expected future cash flows, (2)
cash flows by year, (3) changes in revenue and income, and (4) other
measures of impact, as appropriate. Second, DOE analyzes and reports
the impacts on different types of manufacturers, including impacts on
small manufacturers. Third, DOE considers the impact of standards on
domestic manufacturer employment and manufacturing capacity, as well as
the potential for standards to result in plant closures and loss of
capital investment. Finally, DOE takes into account cumulative impacts
of various DOE regulations and other regulatory requirements on
manufacturers.
For individual consumers, measures of economic impact include the
changes in LCC and PBP associated with new or amended standards. These
measures are discussed further in the following section. For consumers
in the aggregate, DOE also calculates the national net present value of
the consumer costs and benefits expected to result from particular
standards. DOE also evaluates the impacts of potential standards on
identifiable subgroups of consumers that may be affected
disproportionately by a standard.
b. Savings in Operating Costs Compared To Increase in Price (LCC and
PBP)
EPCA requires DOE to consider the savings in operating costs
throughout the estimated average life of the covered product in the
type (or class) compared to any increase in the price of, or in the
initial charges for, or maintenance expenses of, the covered product
that are likely to result from a standard. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(i)(II)) DOE conducts this comparison in its LCC
and PBP analysis.
The LCC is the sum of the purchase price of a product (including
its installation) and the operating expense (including energy,
maintenance, and repair expenditures) discounted over the lifetime of
the product. The LCC analysis requires a variety of inputs, such as
product prices, product energy consumption, energy prices, maintenance
and repair costs, product lifetime, and discount rates appropriate for
consumers. To account for uncertainty and variability in specific
inputs, such as product lifetime and discount rate, DOE uses a
distribution of values, with probabilities attached to each value.
The PBP is the estimated amount of time (in years) it takes
consumers to recover the increased purchase cost (including
installation) of a more-efficient product through lower operating
costs. DOE calculates the PBP by dividing the change in purchase cost
due to a more-stringent standard by the change in annual operating cost
for the year that standards are assumed to take effect.
For its LCC and PBP analysis, DOE assumes that consumers will
purchase the covered products in the first year of compliance with new
or amended standards. The LCC savings for the considered efficiency
levels are calculated relative to the case that reflects projected
market trends in the absence of new or amended standards. DOE's LCC and
PBP analysis is discussed in further detail in section IV.F of this
document.
[[Page 1740]]
c. Energy Savings
Although significant conservation of energy is a separate statutory
requirement for adopting an energy conservation standard, EPCA requires
DOE, in determining the economic justification of a standard, to
consider the total projected energy savings that are expected to result
directly from the standard. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(III)) As discussed in section III.D of this document,
DOE uses the NIA models to project national energy savings.
d. Lessening of Utility or Performance of Products
In establishing product classes and in evaluating design options
and the impact of potential standard levels, DOE evaluates potential
standards that would not lessen the utility or performance of the
considered products. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(IV)) Based on data available to DOE, the standards
proposed in this document would not reduce the utility or performance
of the products under consideration in this rulemaking.
e. Impact of Any Lessening of Competition
EPCA directs DOE to consider the impact of any lessening of
competition, as determined in writing by the Attorney General, that is
likely to result from a proposed standard. (42 U.S.C. 6316(a); 42
U.S.C. 6295(o)(2)(B)(i)(V)) It also directs the Attorney General to
determine the impact, if any, of any lessening of competition likely to
result from a proposed standard and to transmit such determination to
the Secretary within 60 days of the publication of a proposed rule,
together with an analysis of the nature and extent of the impact. (42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(ii)) DOE will transmit a copy
of this proposed rule to the Attorney General with a request that the
Department of Justice (``DOJ'') provide its determination on this
issue. DOE will publish and respond to the Attorney General's
determination in the final rule. DOE invites comment from the public
regarding the competitive impacts that are likely to result from this
proposed rule. In addition, stakeholders may also provide comments
separately to DOJ regarding these potential impacts. See the ADDRESSES
section for information to send comments to DOJ.
f. Need for National Energy Conservation
DOE also considers the need for national energy and water
conservation in determining whether a new or amended standard is
economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VI)) The energy savings from the proposed standards
are likely to provide improvements to the security and reliability of
the Nation's energy system. Reductions in the demand for electricity
also may result in reduced costs for maintaining the reliability of the
Nation's electricity system. DOE conducts a utility impact analysis to
estimate how standards may affect the Nation's needed power generation
capacity, as discussed in section IV.M of this document.
DOE maintains that environmental and public health benefits
associated with the more efficient use of energy are important to take
into account when considering the need for national energy
conservation. The proposed standards are likely to result in
environmental benefits in the form of reduced emissions of air
pollutants and greenhouse gases (``GHGs'') associated with energy
production and use. DOE conducts an emissions analysis to estimate how
potential standards may affect these emissions, as discussed in section
IV.K; the estimated emissions impacts are reported in section V.B.6 of
this document. DOE also estimates the economic value of emissions
reductions resulting from the considered TSLs, as discussed in section
IV.L of this document.
g. Other Factors
In determining whether an energy conservation standard is
economically justified, DOE may consider any other factors that the
Secretary deems to be relevant. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(VII)) To the extent DOE identifies any relevant
information regarding economic justification that does not fit into the
other categories described previously, DOE could consider such
information under ``other factors.''
2. Rebuttable Presumption
As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a
rebuttable presumption that an energy conservation standard is
economically justified if the additional cost to the consumer of a
product that meets the standard is less than three times the value of
the first year's energy savings resulting from the standard, as
calculated under the applicable DOE test procedure. DOE's LCC and PBP
analyses generate values used to calculate the effects that proposed
energy conservation standards would have on the payback period for
consumers. These analyses include, but are not limited to, the 3-year
payback period contemplated under the rebuttable-presumption test. In
addition, DOE routinely conducts an economic analysis that considers
the full range of impacts to consumers, manufacturers, the Nation, and
the environment, as required under 42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i). The results of this analysis serve as the basis for
DOE's evaluation of the economic justification for a potential standard
level (thereby supporting or rebutting the results of any preliminary
determination of economic justification). The rebuttable presumption
payback calculation is discussed in section IV.F.11 of this proposed
rule.
IV. Methodology and Discussion of Related Comments
This section addresses the analyses DOE has performed for this
rulemaking with regard to distribution transformers. Separate
subsections address each component of DOE's analyses.
DOE used several analytical tools to estimate the impact of the
standards proposed in this document. The first tool is a model that
calculates the LCC savings and PBP of potential amended or new energy
conservation standards. The national impacts analysis uses a second
model set that provides shipments projections and calculates national
energy savings and net present value of total consumer costs and
savings expected to result from potential energy conservation
standards. DOE uses the third spreadsheet tool, the Government
Regulatory Impact Model (``GRIM''), to assess manufacturer impacts of
potential standards. These tools are available in the docket for this
rulemaking: www.regulations.gov/docket/EERE-2019-T-STD-0018.
Additionally, DOE used output from the latest version of the Energy
Information Administration's (``EIA's'') Annual Energy Outlook
(``AEO''), a widely known energy projection for the United States, for
the emissions and utility impact analyses.
A. Market and Technology Assessment
DOE develops information in the market and technology assessment
that provides an overall picture of the market for the products
concerned, including the purpose of the products, the industry
structure, manufacturers, market characteristics, and technologies used
in the products. This activity includes both quantitative and
qualitative assessments, based primarily on publicly available
information. The subjects addressed in the market and technology
assessment for this rulemaking include (1) a determination of the scope
of the rulemaking and
[[Page 1741]]
product classes, (2) manufacturers and industry structure, (3) existing
efficiency programs, (4) shipments information, (5) market and industry
trends; and (6) technologies or design options that could improve the
energy efficiency of distribution transformers. The key findings of
DOE's market assessment are summarized in the following sections. See
chapter 3 of the NOPR TSD for further discussion of the market and
technology assessment.
1. Scope of Coverage
The current definition for a distribution transformer codified in
10 CFR 431.192 is the following:
Distribution transformer means a transformer that--(1) Has an input
voltage of 34.5 kV or less; (2) Has an output voltage of 600 V or less;
(3) Is rated for operation at a 60 Hz; and (4) Has a capacity of 10 kVA
to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-
type units; but (5) The term ``distribution transformer'' does not
include a transformer that is an--(i) Autotransformer; (ii) Drive
(isolation) transformer; (iii) Grounding transformer; (iv) Machine-tool
(control) transformer; (v) Nonventilated transformer; (vi) Rectifier
transformer; (vii) Regulating transformer; (viii) Sealed transformer;
(ix) Special-impedance transformer; (x) Testing transformer; (xi)
Transformer with tap range of 20 percent or more; (xii) Uninterruptible
power supply transformer; or (xiii) Welding transformer.
DOE received several comments regarding the definition of
``distribution transformer'' and the definitions of equipment excluded
from the definition. These detailed comments are discussed below.
a. Autotransformers
The EPCA definition of distribution transformer excludes ``a
transformer that is designed to be used in a special purpose
application and is unlikely to be used in general purpose applications,
such as . . . [an] auto-transformer . . .'' (42 U.S.C. 6291(35)(b)(ii))
In response to comments received as part of the June 2019 Early
Assessment Review RFI that suggested DOE include ``low-voltage
autotransformers'' within the scope of distribution transformers, DOE
noted that autotransformers do not provide galvanic isolation \34\ and
thus would be unlikely to be used in at least some general-purpose
applications. (August 2021 Preliminary Analysis TSD at p. 2-5) In the
August 2021 Preliminary Analysis TSD, DOE requested comment regarding
the potential use of autotransformers as substitutes for general-
purpose distribution transformers. Id.
---------------------------------------------------------------------------
\34\ i.e., autotransformers contain a continuous, current-
carrying electrical pathway that ``isolation'' transformers do not,
which is perceived as a safety compromise in some applications.
---------------------------------------------------------------------------
Schneider commented that while voltage conversion can be done with
an autotransformer, autotransformers cannot derive a neutral, lower
source impedance, or phase shift to remove triplen (i.e., multiples-of-
three) harmonics, meaning an autotransformer risks sacrificing power
quality if used in place of a general-purpose distribution transformer.
(Schneider, No. 59 at p. 2) Schneider added that because of these power
quality concerns, autotransformers would be unlikely to be used in
commercial buildings but could be used in some subsegments and smaller
commercial jobs--a possibility supported by manufacturers' adding
autotransformers to standard product catalogs. (Schneider, No. 49 at p.
2) Schneider commented that it recommends autotransformers in
subsegments that require wye-wye connections \35\ and that segment is
growing and will continue to grow if autotransformers remain exempt.
(Schneider, No. 49 at p. 2) Schneider commented that that are no
technical limitations for autotransformer to meet standards and
asserted that the exclusion was related to how efficiency was
calculated and tested. Schneider recommended subjecting them to the
current efficiency standards based on their nameplate kVA. (Schneider,
No. 49 at pp. 2-3) Schneider commented that in typical applications
(i.e., 480Y/277 and 208Y/120) autotransformers would be 60 percent the
size and 20-25 percent less expensive. In non-typical applications,
units would be 20 percent the size and 50 percent less expensive.
(Schneider, No. 49 at p. 3)
---------------------------------------------------------------------------
\35\ Wye connection refers to four distribution transformer
terminals, three of which are connected to one power phase and the
fourth connected to all three power phases.
---------------------------------------------------------------------------
NEMA commented that it is not aware of autotransformers being used
in place of distribution transformers. (NEMA, No. 50 at p. 3)
Stakeholder comments suggest that there may be certain applications
in which an autotransformer may be substitutable for an isolation
transformer. However, the comments also suggest such substitution is
limited to specific applications (e.g., wye-wye connections) and not
common enough to be regarded as general practice. Further, DOE did not
receive any feedback counter to its statement in the August 2021
Preliminary Analysis TSD that autotransformers do not provide galvanic
isolation and thus would be unlikely to be used in at least some
general-purpose applications. Based on this feedback, DOE is not
proposing to amend the exclusion of autotransformers under the
distribution transformer definition. DOE will monitor the market and
may reevaluate this exclusion if evidence exists to support growing use
of autotransformers based on lower purchase price than would be
warranted by technical considerations alone.
b. Drive (Isolation) Transformers
In the August 2021 Preliminary Analysis TSD, DOE noted that the
EPCA definition of distribution transformers excludes a transformer
that is designed to be used in a special purpose application and is
unlikely to be used in general purpose applications, such as a drive
transformer. (42 U.S.C. 6291(35)(b)(ii)) DOE stated that it did not
have any data indicating that ``drive isolation transformers'' were
being widely used in generally purpose applications and as such,
considered them statutorily excluded. DOE requested comment and data as
to the extent to which ``drive isolation transformers'' are used in
generally purpose applications. (August 2021 Preliminary Analysis TSD
at p. 2-6)
Schneider and Eaton commented that drive isolation transformers
have historically been sold with nonstandard low-voltage ratings,
corresponding to typical motor input voltages, and as such are unlikely
to be used in general-purpose applications. (Schneider, No. 49 at p. 3;
Eaton, No. 55 at p. 3) NEMA commented that drive isolation transformers
are not sold in great quantities and not widely used in general purpose
applications. (NEMA, No. 50 at p. 3)
Schneider and Eaton commented that recently there has been some
increase in drive isolation transformers specified as having either a
``480Y/277'' or ``208Y/120'' voltage secondary, making it more
difficult to ascertain whether these transformers are being used in
general distribution applications. (Schneider No. 49 at p. 3; Eaton,
No. 55 at p. 3) Schneider commented that only 6-pulse drive isolation
transformers \36\ can serve
[[Page 1742]]
general purpose applications. (Schneider, No. 49 at p. 4) Eaton added
that there is a minor concern that consumers will increasingly discover
that drive isolation transformers can be used in certain general-
purpose applications, putting manufacturers in the position of
suspecting but not being able to ascertain circumvention without being
sure of end use. (Eaton, No. 55 at p. 3) Eaton commented that a DOE
compliant general-purpose transformer would be 16 percent more
expensive than a drive isolation transformer that could be used in its
place, while the losses for the drive isolation transformer at 50
percent PUL were 55 percent greater. (Eaton, No. 55 at p. 3)
---------------------------------------------------------------------------
\36\ Drive-isolation transformers employ rectifier diodes to
mitigate drive harmonics by phase shifting secondary voltages. The
rectifier diode results in two pulses per phase. In a standard
three-phase, drive-isolation transformer, application of a rectifier
would result in 6-pulses, two per 120[deg] phase shift. If
additional harmonic mitigation is needed, additional secondary
windings are added with differing connections phase shifted from one
another. Manufacturers' sell drive-isolation transformers as 6-
pulse, 12-pulse, or 24-pulse.
---------------------------------------------------------------------------
Eaton commented that pulse count is somewhat hard to define as it
is generally more a function of the rectifier that the drive isolation
transformer is connected to than the transformer itself. (Eaton, No. 55
at p. 4) Eaton added that 12-pulse and 24-pulse drive isolation
transformers could, technically, be used in general purpose
applications but that it would be less likely due to higher cost.
(Eaton, No. 55 at p. 3-4)
Schneider commented that 6-pulse drive isolation transformers
should be included in the LVDT scope, as is required in Canada.
(Schneider, No. 49 at p. 4)
Commenters indicated that while some drive isolation transformers
could, in theory be used in general purpose applications, no evidence
exists suggesting this practice is common. As such, DOE has concluded
that drive isolation transformers remain an example of a transformer
that is designed to be used in special purpose applications and is
unlikely to be used in general purpose applications. Given that drive
isolation transformers are excluded by statute, including drive
isolation transformers would first require a finding that they are
being used in general purpose applications, which does not appear to be
the case at this time.
Schneider commented that drive isolation transformers should only
be permitted at standard motor voltages and not standard distribution
voltages. (Schneider, No. 49 at p. 3)
DOE tentatively finds, as supported by comments from Schneider and
Eaton, that certain distribution transformers that meet the current
criteria of a ``drive isolation transformers'' are likely to be used in
general-purpose applications based on their voltage rating. The
overwhelming majority of equipment in the US is designed to operate
using either 208Y/120 or 480Y/277 voltage, and therefore the
overwhelming majority of general-purpose distribution transformers have
a secondary voltage rating that is one of these standard voltage
ratings. Drive-isolation transformers, by contrast, are not designed to
power the majority of equipment. Rather, they are designed to work with
a specific motor drive to output a special purpose voltage, unique to
the application. As such, drive-isolation transformers with a rated
secondary voltage of 208Y/120 or 480Y/277 is considerably more likely
to be used in general purpose applications rather than special purpose
applications.
EPCA excludes from the definition of distribution transformer
certain transformers designed to be used in an application other than a
general-purpose application. Specifically, ``distribution transformer''
excludes a transformer that is ``designed to be used in a special
purpose application and is unlikely to be used in general purpose
applications, such as a drive transformer, rectifier transformer, auto-
transformer, Uninterruptible Power System transformer, impedance
transformer, regulating transformer, sealed and nonventilating
transformer, machine tool transformer, welding transformer, grounding
transformer, or testing transformer[.]'' (42 U.S.C. 6291(35)(b)(ii))
Drive (isolation) transformers are defined as ``a transformer that:
(1) Isolates an electric motor from the line; (2) Accommodates the
added loads of drive-created harmonics; and (3) Is designed to
withstand the additional mechanical stresses resulting from an
alternating current adjustable frequency motor drive or a direct
current motor drive.'' 10 CFR 431.192. In the product catalogs reviewed
by DOE, drive-isolation transformers are frequently listed at common
motor voltages such as ``460Y/266'' and ``230Y/133.''. The listing at
common motor voltages indicates that these drive-isolation transformers
are designed for use in special purpose applications (i.e., isolating
an electric motor from the line) and are unlikely to be used in general
purpose distribution applications, on account of not aligning with
general distribution voltages.
DOE has previously stated that it intends to strictly and narrowly
construe the exclusions from the definition of ``distribution
transformer.'' 84 FR 24972, 24979 (April 27, 2009). To the extent that
some transformers are marketed as drive-isolation transformers but with
rated output voltages aligning with common distribution voltages, DOE
is unable to similarly conclude that these transformers are used in
special purpose applications. Comments by Eaton and Schneider confirm
that while these transformers are not sold in great numbers, they are
significantly more likely to be used in general purpose distribution
applications. As such, DOE has tentatively determined that such
distribution transformers are not drive (isolation) transformers as
that term applies to the exclusions from the definition of
``distribution transformer.''
In order to limit the definition of drive isolation transformers to
distribution transformers designed for use in special purpose
applications and not likely to be used in general purpose applications,
DOE proposes to amend the definition to include the criterion that
drive isolation transformers have an output voltage other than 208Y/120
or 480Y/277. DOE may consider additional voltage limitations in the
definition of ``drive isolation transformer'' should DOE determine such
voltages indicate a design for use in general purpose applications.
DOE requests comment on the proposed amendment to the definition of
drive (isolation) transformer. DOE requests comment on its tentative
determination that voltage ratings of 208Y/120 and 480Y/277 indicate a
design for use in general purpose applications. DOE also requests
comment on other voltage ratings or other characteristics that would
indicate a design for use in general purpose applications.
c. Special-Impedance Transformers
Impedance is an electrical property that relates voltage across and
current through a distribution transformer. It may be selected to
balance voltage drop, overvoltage tolerance, and compatibility with
other elements of the local electrical distribution system. A
transformer built to operate outside of the normal impedance range for
that transformer's kVA rating, as specified in Tables 1 and 2 of 10 CFR
431.192 under the definition of ``special-impedance transformer,'' is
excluded from the definition of ``distribution transformer.'' 10 CFR
431.192.
In the August 2021 Preliminary Analysis TSD, DOE requested feedback
as to the number of nonstandard kVA transformers sold and how
manufacturers are currently interpreting the normal impedance range for
nonstandard kVA values. (August 2021 Preliminary Analysis TSD at p. 2-
8)
NEMA and Eaton recommended that the impedance values in Tables 1
and 2 of 10 CFR 431.192 under the definition of ``special-impedance
transformer'' be
[[Page 1743]]
listed as a kVA range, to remove what they stated is an ambiguity as to
the normal impedance of non-standard transformer capacities (i.e.,
capacities not explicitly included in the tables). (Eaton, No. 55 at p.
4; NEMA, No. 50 at p. 3-4) Eaton commented that there were very few
nonstandard kVA ratings for single-phase transformers and just under
one percent of three-phase transformers are rated for non-standard
kVAs. (Eaton, No. 55 at p. 4) Eaton added that nonstandard kVAs are
quite common in the currently exempted step-up transformers, making up
27 percent of three-phase step-up transformers. (Eaton, No. 55 at p. 4)
Eaton stated that it currently uses the impedance values of the
adjacent standard kVA ratings that result in the largest normal
impedance range and, equivalently, the narrowest excluded impedance
range. (Eaton, No. 55 at p. 5)
NEMA commented that many, but not all, customers specify the middle
of the normal impedance range. NEMA stated that some customers specify
a particular impedance to compliment an application, such as for
protection equipment or to match better with sensitive loads. (NEMA,
No. 50 at p. 4)
Schneider commented that it receives few requests for distribution
transformers outside the normal impedance range and few requests for
distribution transformers with nonstandard kVAs and therefore applied
energy efficiency regulations to special impedance transformers without
pursuing exemptions. (Schneider, No. 49 at p. 4) Schneider added that
the special impedance exemption could potentially be removed, and thus
reduce potential abuse or the normal range could be expanded for all
distribution transformers, regardless of kVA to be from 0.5 percent to
15 percent. (Schneider, No. 49 at p. 4) As another alternative,
Schneider recommended either setting the mid-range impedance as a
threshold or using a linear interpolation of the impedance values
immediately above and below that kVA rating, similar to how efficiency
standards are applied for non-standard kVA ratings. (Schneider, No. 49
at p. 4-5)
As DOE noted in the August 2021 Preliminary Analysis TSD, its
current values for normal impedance are based on NEMA TP 2-2005.
(August 2021 Preliminary Analysis TSD at p. 2-8) The current tables in
the ``special-impedance transformer'' definition do not explicitly
address how to treat nonstandard kVA values.
DOE is proposing to amend the definition of ``special-impedance
transformer'' to specify that ``distribution transformers with kVA
ratings not appearing in the tables shall have their minimum normal
impedance and maximum normal impedance determined by linear
interpolation of the kVA and minimum and maximum impedances,
respectively, of the values immediately above and below that kVA
rating.''. This proposed approach is consistent with the recommendation
from Schneider. Moreover, this approach is consistent with the approach
specified for determining the required efficiency requirements of
distribution transformers of nonstandard kVA rating (i.e., using a
linear interpolation from the nearest bounding kVA values listed in the
table). See 10 CFR 431.196.
DOE requests comment on its proposed amendment to the definition of
``special-impedance transformer'' and whether it provides sufficient
clarity as to how to treat the normal impedance ranges for non-standard
kVA distribution transformers.
Carte commented that one of its customers requires higher impedance
pole transformers, within the ``normal'' range, but in general the
larger coils and higher core losses associated with a higher impedance
can be disadvantaged in meeting efficiency standards. (Carte, No. 54 at
p. 1)
DOE relies on the current definition of ``special-impedance
transformer'' in its engineering analysis. DOE does not further
consider impedance aside from ensuring selectable models in the
analysis are within the ``normal impedance'' range as currently
defined. DOE's analyzed higher efficiency levels, including those using
amorphous steel, span a range of impedance values and therefore DOE has
not considered further separating distribution transformers based on
impedance.
d. Tap Range of 20 Percent or More
Transformers with multiple voltage taps, the highest of which
equals at least 20 percent more than the lowest, computed based on the
sum of the deviations of the voltages of these taps from the
transformer's nominal voltage, are excluded from the definition of
distribution transformers. 10 CFR 431.192. (See also, 42 U.S.C.
6291(35)(B)(i)) In the August 2021 Preliminary Analysis TSD, DOE
requested comment as to whether only full-power taps should count
toward the exclusion and how the choice of nominal voltage would impact
the exclusion. (August 2021 Preliminary Analysis TSD at p. 2-9)
In response, Schneider, NEMA and Eaton commented that only full-
power taps should be permitted for tap range calculations. (Eaton, No.
55 at pp. 5-6; Schneider, No. 49 at pp. 5-6; NEMA, No. 50 at p. 4)
Eaton commented that nominal voltage is selected by the consumer
but selecting one such that it excludes a product can result in 17
percent lower costs and 73 percent higher losses at 50 percent PUL.
(Eaton, No. 55 at p. 6) Schneider provided an example of how the
nominal voltage can impact whether a product is subject to standards.
(Schneider, No. 49 at p. 6) Eaton commented that of the three-phase
units it has built, only one unit was built as having a tap range of 20
percent or more while 112 units were built as DOE compliant but could
be moved out of scope based on the choice of nominal voltage. (Eaton,
No. 55 at pp. 6-7) Schneider added that another complication to using
nominal voltage is a new type of distribution transformer that has
multiple-nominal voltages. (Schneider, No. 49 at p. 6-8)
Eaton supported changing how the tap range is calculated to remove
potential incentives to circumvent standards. (Eaton, No. 55 at p. 6)
NEMA commented that it did not reach consensus as to how to calculate
tap range. (NEMA, No. 50 at p. 4) Schneider recommended DOE establish
all common system voltages as nominal and have manufacturers justify
tap ranges according to the relative function of each to the associated
nominal in the case of multiple nominals. (Schneider, No. 49 at p. 8)
Schneider added that if it is too difficult to establish what nominal
should be, the 20 percent tap range exclusion could be removed.
(Schneider, No. 49 at p. 8)
While the traditional industry understanding of tap range is in
percentages relative to the nominal voltage, stakeholder comments
suggest that such a calculation can be applied differently by different
manufacturers such that two physically identical distribution
transformers can be inside or outside of scope depending on the choice
of nominal voltage. To have a consistent standard for physically
identical distribution transformers, DOE proposes to modify the
calculation of tap range to only include full-power capacity taps and
calculate tap range based on the transformer's maximum voltage rather
than nominal voltage. The amended definition would classify
transformers with tap ranges of 20 percent or more as ``a transformer
with multiple full-power voltage taps, the highest of which equals at
least 20 percent more than the lowest, computed based on the sum of the
deviations of these taps from the transformer's maximum full-power
voltage.''. Such a
[[Page 1744]]
modification would ensure that all distribution transformers capable of
operating across a similar voltage range, regardless of what voltage is
considered nominal, are treated equally. Further, the proposed
modification removes ambiguity as to what customers are using as a
nominal voltage and removes incentives to change the nominal voltage to
move equipment into or out of scope of the standards.
DOE requests comment on its proposed definition for transformers
with a tap range of 20 percent or more.
e. Sealed and Nonventilated Transformers
As discussed, the statutory definition of distribution transformer
excludes transformers that are designed to be used in a special purpose
application and are unlikely to be used in general purpose
applications, such as a ``sealed and nonventilating transformers.'' (42
U.S.C. 6291(35)(b)(ii)) In the August 2021 Preliminary Analysis TSD,
DOE noted that the definition of sealed and nonventilating transformers
is applicable only to dry-type transformers. While liquid-immersed
transformers are technically also sealed, DOE has explicitly included
them in the definition of a distribution transformer. 10 CFR 431.92.
(August 2021 Preliminary Analysis TSD at p. 2-7)
In response, NEMA recommended DOE add the words ``dry-type'' to the
definition of sealed and nonventilated transformers. (NEMA, No. 50 at
p. 3)
DOE agrees that the proposed clarification would help clarify the
scope of the sealed and nonventilated transformer exclusion and has
proposed to amend the definition as such.
DOE requests comment on its proposed amendments to the definitions
of sealed and nonventilated transformers.
f. Step-Up Transformers
For transformers generally, the term ``step-up'' refers to the
function of a transformer providing greater output voltage than input
voltage. Step-up transformers primarily service energy producing
applications, such as solar or wind electricity generation, and input
source voltage, step-up the voltage in the transformer, and output
higher voltages that feed into the electric grid. The definition of
``distribution transformer'' does not explicitly exclude transformers
designed for step-up operation.
However, most step-up transformers have an output voltage larger
than the 600 V limit specified in the distribution transformer
definition. See 10 CFR 431.192. (See also 42 U.S.C. 6291(35)(A)(ii))
DOE has acknowledged it is technically possible to operate a step-
up transformer in a reverse manner, by connecting the high-voltage to
the ``output'' winding of a step-up transformer and the low-voltage to
the ``input'' winding of a step-up transformer, such that it functions
as a distribution transformer. 78 FR 2336, 23354. However, DOE
previously had not identified this as a widespread practice. Id. In the
August 2021 Preliminary Analysis TSD, DOE requested feedback as to what
the typical efficiency is of step-up transformers, what fraction are
being used in traditional distribution transformer applications, and
what are the typical input and output voltages of step-up transformers.
(August 2021 Preliminary Analysis TSD at p. 2-18)
NEMA commented that efficiency of step-up transformers is dictated
by customers and is sometimes above and sometimes below DOE efficiency
levels for distribution transformers. NEMA added that they are not
aware of step-up transformers being used in distribution applications
and they are concerned that subjecting step-up transformers to
regulation may negatively constrain design flexibility. (NEMA, No. 50
at p. 5)
Eaton commented that step-up transformers are almost exclusively
used in renewable energy applications where low-voltages (typically
less than 700 volts) are stepped up to medium-voltage distribution
applications (typically up to 34.5 kV). Eaton added that virtually all
step-up transformers are three-phase and there are maybe a dozen
single-phase step-up transformers per year which may or may not be
possible circumvention scenarios. (Eaton, No. 55 at p. 9) Eaton
commented that some step-up transformer customers specify total owning
cost, maximum losses, or efficiency and provided a table of average
efficiency of three-phase liquid-immersed step-up transformers which
showed the average efficiency of step-up transformers tended to be
below DOE efficiency standards. (Eaton, No. 55 at p. 9) Eaton noted
that many solar photovoltaic inverter manufacturers have been using
higher input voltages that often require non-standard voltages or
winding configurations and may decrease likelihood of a step-up
transformer being used in a distribution application. (Eaton, No. 55 at
p. 9) Eaton stated that 31 percent of their three-phase step-up
transformers had common distribution low-voltages, that could more
easily be used in distribution applications, but Eaton had no knowledge
that step-up transformers were being used in traditional distribution
applications. (Eaton, No. 55 at p. 9) Eaton stated that step-up
voltages with common distribution high and low-voltages could possibly
be operated in reverse in distribution transformer applications.
(Eaton, No. 55 at p. 9)
The comments received support DOE's prior statements. While step-up
transformers could, in theory, be used in distribution applications,
DOE does not have any data to indicate that this is a common or
widespread practice. Eaton's comments underscore that step-up
transformers serve a separate and unique application, often in the
renewable energy field where transformers designs may not be optimized
for the distribution market but rather are optimized for integration
with other equipment, such as inverters. Therefore, DOE is not
proposing to amend the definition of ``distribution transformer'' to
account for step-up transformers. DOE may reevaluate this conclusion in
a future action if evidence arises to suggest step-up transformers are
being used in distribution functions.
g. Uninterruptible Power Supply Transformers
``Uninterruptible power supply transformer'' is defined as a
transformer that is used within an uninterruptible power system, which
in turn supplies power to loads that are sensitive to power failure,
power sags, over voltage, switching transients, line noise, and other
power quality factors. 10 CFR 431.192. An uninterruptable power supply
transformer is excluded from the definition of distribution
transformer. 42 U.S.C. 6291(35)(B)(ii); 10 CFR 431.192. Such a system
does not step-down voltage, but rather it is a component of a power
conditioning device and it is used as part of the electric supply
system for sensitive equipment that cannot tolerate system
interruptions or distortions, and counteracts such irregularities. 69
FR 45376, 45383. DOE has clarified that uninterruptable power supply
transformers do not ``supply power to'' an uninterruptible power
system, rather they are ``used within'' the uninterruptible power
system. 72 FR 58190, 58204. This is consistent with the reference in
the definition to transformers that are ``within'' the uninterruptible
power system. 10 CFR 431.192. Distribution transformers at the input,
output or bypass that are supplying power to the uninterruptible power
system are not uninterruptable power supply transformers.
[[Page 1745]]
In the August 2021 Preliminary Analysis TSD, DOE requested comment
regarding how manufacturers are applying the definition of
uninterruptable power supply transformer and whether amendments are
needed. (August 2021 Preliminary Analysis TSD at p. 2-10)
In response, NEMA commented that manufacturers are applying the
definition appropriately and clarification is not needed. (NEMA, No. 50
at p. 4) Schneider recommended DOE explicitly state that transformers
at the input, output, or by-pass of an uninterruptible power system are
not part of the uninterruptible power system and as such are not
excluded. (Schneider, No. 49 at p. 8).
DOE agrees that explicitly stating that transformers at the input,
output, or bypass of a distribution transformer are not a part of the
uninterruptable power system would further clarify the definition. As
such, DOE is proposing to amend the definition to make these
clarifications.
DOE requests comment on its proposed amendment to the definition of
uninterruptable power supply transformers.
Carte asked if network transformers are considered uninterruptible
power supply transformers as the network grid cannot go down. (Carte,
No. 54 at p. 2) DOE notes that the need for a reliable operation does
not make a distribution transformer an uninterruptible power supply
transformer. As stated, uninterruptible power supply transformers are
used within uninterruptable power systems as a power conditioning
device, not as a distribution transformer.
h. Voltage Specification
As stated, the definition of ``distribution transformer'' is based,
in part, on the voltage capacity of equipment, i.e., has an input
voltage of 34.5 kV or less; and has an output voltage of 600 V or less.
10 CFR 431.192. (42 U.S.C. 6291(35)(A)) Three-phase distribution
transformer voltage may be described as either ``line'', i.e., measured
across two lines, or ``phase'', i.e., measured across one line and the
neutral conductor. For delta-connected \37\ distribution transformers,
line and phase voltages are equal. For wye-connected distribution
transformers, line voltage is equal to phase voltage multiplied by the
square root of three.
---------------------------------------------------------------------------
\37\ Delta connection refers to three distribution transformer
terminals, each one connected to two power phases.
---------------------------------------------------------------------------
DOE notes that it has previously stated that the definition of
distribution transformer applies to transformers having an output
voltage of 600 volts or less, not having only an output voltage of less
than 600 volts. 78 FR 23336, 23353. For example, a three-phase
transformer for which the wye connection is at or below 600 volts, but
the delta connection is above 600 volts would satisfy the output
criteria of the distribution transformer definition. DOE's test
procedure requires that the measured efficiency for the purpose of
determining compliance be based on testing in the configuration that
produces the greatest losses, regardless of whether that configuration
alone would have placed the transformer at-large within the scope of
coverage. Id. Similarly with input voltages, a transformer is subject
to standards if either the ``line'' or ``phase'' voltages fall within
the voltage limits in the definition of distribution transformers, so
long as the other requirements of the definition are also met. Id.
Eaton commented that DOE flipped the usage of wye and delta in its
example where one voltage complies and the other does not because wye
voltage should be less than delta voltage. (Eaton, No. 55 at p. 8) DOE
has updated its language above to correct this.
Schneider commented that the industry interpretation of input and
output voltage is likely line voltage but using phase encompasses a
larger scope and DOE should clarify in the regulatory text. (Schneider,
No. 49 at p. 8) NEMA commented that DOE should clarify the
interpretation of voltage in the regulatory text. (NEMA, No. 50 at p.
4) Eaton commented that using phase voltage would deviate from industry
convention, but if DOE is choosing to interpret language this way, it
should explicitly say so in the regulatory text. (Eaton, No. 55 at pp.
7-8)
DOE notes that the voltage limits in the definition of distribution
transformer established in EPCA do not specify whether line or phase
voltage is to be used. 42 U.S.C. 6291(35). DOE has previously stated
that a distribution transformer is required to comply if either line or
phase voltage is within the scope of the distribution transformer
definition. 78 FR 23336, 23353. Upon further evaluation, DOE notes that
the distribution transformer input voltage limitation aligns with the
common maximum distribution circuit voltage of 34.5 kV.38 39
This common distribution voltage aligns with the distribution line
voltage and implies that the intended definition of distribution
transformer in EPCA was to specify the input and output voltages based
on the line voltage. DOE has tentatively determined that applying the
phase voltage, as DOE cited in the April 2013 Standards Final Rule,
would cover products not traditionally understood to be distribution
transformers and not intended to be within the scope of distribution
transformer as defined by EPCA. For example, a transformer with a line
voltage of 46 kV, which is commonly considered in industry to be a
subtransmission voltage (i.e., higher than a distribution voltage),
would have a phase voltage less than 34.5 kV if sold in a wye-
connection. Despite this transformer not being considered a
distribution transformer by industry, interpreting DOE's definition as
either a line or phase voltage would mean that a 46 kV wye-connection
is considered a distribution transformer. As noted by stakeholders,
such an interpretation would be out of step with common industry
practice and out of step with the intended coverage of EPCA.
---------------------------------------------------------------------------
\38\ Pacific Northwest National Lab and U.S. Department of
Energy (2016), ``Electricity Distribution System Baseline Report.'',
p. 27. Available at www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf.
\39\ U.S. Department of Energy (2015), ``United States
Electricity Industry Primer.'' Available at www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf.
---------------------------------------------------------------------------
DOE notes that the common distribution transformer voltages have
both line and phase voltages that are within DOE's scope, and therefore
the proposed change is not expected to impact the scope of this
rulemaking aside from select, unique transformers with uncommon
voltages. In this NOPR, DOE is proposing to modify the definition of
distribution transformer to state explicitly that the input and output
voltage limits are based on the ``line'' voltage and not the phase
voltage. This amendment, while a slight reinterpretation relative to
the April 2013 Standards Final Rule, better aligns with industry
practice, minimizes confusion, and does not impact any of the commonly
built distribution transformer designs.
DOE requests comment as to whether its proposed definition better
aligns with industries understanding on input and output voltages.
Further, DOE requests comment and data on whether the proposed
amendment would impact products that are serving distribution
applications, and if so, the number of distribution transformers
impacted by the proposed amendment.
[[Page 1746]]
i. kVA Range
The EPCA definition for distribution transformers does not include
any capacity range. In codifying the current distribution transformer
capacity ranges in 10 CFR 431.192, DOE noted that distribution
transformers outside of these ranges are not typically used for
electricity distribution. 71 FR 24972, 24975-24976. Further, DOE noted
that transformer capacity is to some extent tied to its primary and
secondary voltages, meaning that the EPCA definitions has the practical
effect of limiting the maximum capacity of transformers that meet those
voltage limitations to approximately 3,750 to 5,000 kVA, or possibly
slightly higher. Id. However, DOE further stated the inclusion of
capacity limitations in the definition of ``distribution transformers''
in 10 CFR 431.192 does not mean that DOE has concluded that the EPCA
definition of ``distribution transformer'' includes such limitations
and stated that DOE intends to evaluate larger and smaller capacities
than those included in the definition. Id.
DOE's current definition of distribution transformer specifies a
capacity of 10 kVA to 2,500 kVA for liquid-immersed units and 15 kVA to
2,500 kVA for dry-type units. 10 CFR 431.192. The kVA ranges are
consistent with NEMA publications in place at the time DOE adopted the
range, specifically NEMA TP-1 standard. 78 FR 23336, 23352. DOE cited
these documents as evidence that its kVA scope is consistent with
industry understanding (i.e., NEMA TP-1 and NEMA TP-2), but noted that
it may revise its understanding in the future as the market evolves. 78
FR 23336, 23352. Subsequent to the April 2013 Standards Final Rule,
establishing the current energy conservation standards, NEMA TP-1
standard was rescinded.
As noted above, the voltage limitations included in EPCA
practically limit the size of distribution transformers. However,
several industry sources suggest that those limitations may be greater
than the current 2,500 kVA limit included in DOE's definition in 10 CFR
431.192. For example, Natural Resources Canada (``NRCAN'') regulations
include three-phase dry-type distribution transformers with a nominal
power of 15 to 7,500 kVA.\40\ The European Union (``EU'') Ecodesign
requirements specify maximum load losses and maximum no-load losses for
three-phase liquid-immersed distribution transformers up to 3,150
kVA.\41\ IEEE C57.12.90 and C57.12.91 cite similar short circuit tests
for three-phase distribution transformers up to 5,000 kVA.
---------------------------------------------------------------------------
\40\ See NRCAN dry-type transformer energy efficiency
regulations at www.nrcan.gc.ca/energy-efficiency/energy-efficiency-regulations/guide-canadas-energy-efficiency-regulations/dry-type-transformers/6875.
\41\ Official Journal of the European Union, Commission
Regulation (EU) No. 548/2014, May 21, 2014, Available online at:
https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=uriserv%3AOJ.L_.2014.152.01.0001.01.ENG.
---------------------------------------------------------------------------
In the August 2021 Preliminary Analysis TSD, DOE requested comment
regarding the quantity and efficiency of distribution transformers
outside of the kVA range of the definition of distribution transformer
but with input and output voltages that meet the voltage criteria in
said definition. (August 2021 Preliminary Analysis TSD at p. 2-11)
Regarding dry-type distribution transformers, Schneider commented
that units below 15 kVA are typically sealed or non-ventilated and as
such would be excluded from the definition of distribution
transformers. (Schneider, No. 49 at p. 9) Eaton commented that single-
phase liquid immersed distribution transformers less than 10 kVA were
less than 1 percent of shipments. (Eaton, No. 55 at p. 8)
DOE has not received any data or information suggesting that
expanding the scope of the standards below 10 kVA for liquid-immersed
distribution transformers or below 15 kVA for dry-type distribution
transformers would lead to significant energy savings. As such, DOE is
not proposing any changes to the lower capacity limit in the
distribution transformer definition.
Regarding sales of distribution transformers beyond the 2,500 kVA
scope, NEMA commented that while there are sales of models over 2,500
kVA, they are not sold in significant numbers as compared to in-scope
products and energy savings would be limited. (NEMA, No. 50 at p. 5)
Eaton commented that 19.6 percent of their three-phase liquid-immersed
transformers have input and output voltage in-scope, but kVAs above
2500 kVA. (Eaton, No. 55 at p. 8) Eaton provided average efficiencies
for these larger kVA distribution transformers. (Eaton, No. 55 at p. 8)
In interviews, manufacturers commented that many of the larger
distribution transformers are serving renewable applications as step-up
transformers and would therefore be outside the scope of the standards
regardless of the upper capacity of the definition of distribution
transformer.
However, while many larger transformers may be step-up
transformers, stakeholder comments suggest that there are also general
purpose distribution transformers sold above 2,500 kVA with primary and
secondary voltages that would still be within the criteria of the
definition of distribution transformer. While NEMA suggested sales of
models above 2,500 kVA are small, Eaton's comments suggest that at
least for some manufacturers or markets they could be notable. Further,
some manufacturers in interviews expressed concern that in the presence
of amended energy conservation standards, there may be increased
incentive to build distribution transformers that are just above the
existing scope (e.g., 2,501 kVA).
As such, it is appropriate for DOE to consider all distribution
transformers that are serving general purpose distribution
applications, even if the capacity of those distribution transformers
is larger than the common unit. DOE is considering multiple possible
upper limits for distribution transformer capacity. IEEE C57.12.00-2015
lists the next three preferred continuous kVA ratings above 2,500 kVA
as 3,750 kVA, 5,000 kVA, and 7,500 kVA. Eaton's comments suggest that
the upper end of their distribution capacity is 3,750 kVA. In a prior
rulemaking, stakeholders commented that their product lines include
medium voltage dry-type models up to around 5,000 kVA.\42\ Further,
NRCAN regulations cover dry-type distribution transformers up to 7,500
kVA but exclude distribution transformers with low-voltage line
currents of 4,000 amps or more.
---------------------------------------------------------------------------
\42\ See Federal Pacific comment on Docket No. EERE-2006-STD-
0099-0105. Available at www.regulations.gov/comment/EERE-2006-STD-0099-0105.
---------------------------------------------------------------------------
Taken together, these points suggest there are some sales of
general purpose distribution transformers above 2,500 kVA, such as at
3,750 kVA and 5,000kVA. DOE does not have any data or evidence that
general purpose distribution transformers are being sold above 5,000
kVA and does have prior public comment of 5,000 kVA transformers with
distribution voltages being sold. Therefore, DOE is proposing to expand
the scope of the definition of ``distribution transformer'' in 10 CFR
431.192 for both liquid-immersed distribution transformers and dry-type
distribution transformers to include distribution transformers up to
5,000 kVA. DOE is also considering other upper limits on the scope of
distribution transformer, including 3,750 kVA and 7,500 kVA.
DOE requests comment and data as to whether 5,000 kVA represents
the upper end of what is considered distribution
[[Page 1747]]
transformers or if another value should be used.
DOE has also estimated potential energy savings associated with
expanding coverage of distribution transformers between 2,500 and 5,000
kVA within scope. DOE relied on public comments and confidential data
sources to estimate shipments between 2,500 kVA and 5,000 kVA. Further,
DOE has scaled its engineering analysis to encompass these larger
units. Although the number of units shipped is estimated to represent a
fraction of a percentage of total covered shipments, DOE has designed
these scaled models as new representative units on account of starting
from an unregulated baseline, as compared to the rest of the market,
for which the baseline transformer complies with existing energy
conservation standards. For liquid-immersed distribution transformers,
representative unit 17 corresponds to a three-phase 3,750 kVA unit. For
medium-voltage dry-type distribution transformers, representative units
18 and 19 correspond to a three-phase 3,750 kVA unit with a BIL of 46-
95 kV and greater than 96 kV, respectively.
DOE has estimated the distribution transformer efficiency by
assuming these out-of-scope units are purchased based on lowest first
cost and would rely on similar grades of electrical steel as the
distribution transformers that are currently in-scope units but would
not currently be meeting any efficiency standard.
DOE requests comment and data as to the number of shipments of
three-phase, liquid-immersed, distribution transformers greater than
2,500 kVA that would meet the in-scope voltage limitations and the
distribution of efficiencies of those units.
DOE requests comment and data as to the number of shipments of
three-phase, dry-type, distribution transformers greater than 2,500 kVA
that would meet the in-scope voltage limitations and the distribution
of efficiencies of those units.
2. Equipment Classes
DOE must specify a different standard level for a type or class of
product that has the same function or intended use, if DOE determines
that products within such group: (A) consume a different kind of energy
from that consumed by other covered products within such type (or
class); or (B) have a capacity or other performance-related feature
which other products within such type (or class) do not have and such
feature justifies a higher or lower standard. (42 U.S.C. 6316(a); 42
U.S.C. 6295(q)(1)) In determining whether a performance-related feature
justifies a different standard for a group of products, DOE must
consider such factors as the utility to the consumer of the feature and
other factors DOE deems appropriate. Id. Any rule prescribing such a
standard must include an explanation of the basis on which such higher
or lower level was established. (42 U.S.C. 6316(a); 42 U.S.C.
6295(q)(2))
Eleven equipment classes are established under the existing
standards for distribution transformers, one of which (mining
transformers \43\) is not subject to energy conservation standards. 10
CFR 431.196. The remaining ten equipment classes are delineated
according to the following characteristics: (1) Type of transformer
insulation: Liquid-immersed or dry-type, (2) Number of phases: single
or three, (3) Voltage class: low or medium (for dry-type only), and (4)
Basic impulse insulation level (BIL) (for MVDT only).
---------------------------------------------------------------------------
\43\ A mining distribution transformer is a medium-voltage dry-
type distribution transformer that is built only for installation in
an underground mine or surface mine, inside equipment for use in an
underground mine or surface mine, on-board equipment for use in an
underground mine or surface mine, or for equipment used for digging,
drilling, or tunneling underground or above ground, and that has a
nameplate which identifies the transformer as being for this use
only. 10 CFR 431.192.
---------------------------------------------------------------------------
Table II.1 presents the eleven equipment classes that exist in the
current energy conservation standards and provides the kVA range
associated with each.
Table IV.1--Current Equipment Classes for Distribution Transformers
----------------------------------------------------------------------------------------------------------------
EC * # Insulation Voltage Phase BIL rating kVA range
----------------------------------------------------------------------------------------------------------------
EC1............... Liquid-Immersed.. Medium........... Single........... ................. 10-833 kVA
EC2............... Liquid-Immersed.. Medium........... Three............ ................. 15-2500 kVA
EC3............... Dry-Type......... Low.............. Single........... ................. 15-333 kVA
EC4............... Dry-Type......... Low.............. Three............ ................. 15-1000 kVA
EC5............... Dry-Type......... Medium........... Single........... 20-45 kV BIL..... 15-833 kVA
EC6............... Dry-Type......... Medium........... Three............ 20-45 kV BIL..... 15-2500 kVA
EC7............... Dry-Type......... Medium........... Single........... 46-95 kV BIL..... 15-833 kVA
EC8............... Dry-Type......... Medium........... Three............ 46-95 kV BIL..... 15-2500 kVA
EC9............... Dry-Type......... Medium........... Single........... >=96 kV BIL...... 75-833 kVA
EC10.............. Dry-Type......... Medium........... Three............ >=96 kV BIL...... 225-2500 kVA
---------------------------------------------------------------------------------------------
EC11.............. Mining Transformers
----------------------------------------------------------------------------------------------------------------
* EC = Equipment Class.
In the August 2021 Preliminary Analysis TSD, DOE requested comment
on a variety of other potential equipment setting factors. (August 2021
Preliminary Analysis TSD at p. 2-16-22) These comments are discussed in
detail below.
a. Pole- and Pad-Mounted Transformers
DOE currently does not divide pole- and pad-mounted distribution
transformers into separate equipment classes. In the August 2021
Preliminary Analysis TSD, DOE requested comment and data to
characterize the effect of mounting configuration on distribution
transformer efficiency, weight, volume, and likelihood of introducing
ferroresonace.\44\ (August 2021 Preliminary Analysis TSD at p. 2-19)
---------------------------------------------------------------------------
\44\ Ferroresonance refers to the nonlinear resonance resulting
from the interaction of system capacitive and inductive elements
which can lead to damaging high voltages in distribution
transformers. Pad-mounted distribution transformers that are delta-
connected are particularly susceptible to ferroresonance effects.
---------------------------------------------------------------------------
Eaton commented that ferroresonance is rare and only occurs in pad
mounted transformers. (Eaton, No. 55 at pp. 9-10) Eaton added that
ferroresonance is more likely to occur in low no-load loss cores, and
commented that these effects can be mitigated with certain core designs
that are slightly less efficient. (Eaton, No. 55
[[Page 1748]]
at pp. 9-10) Eaton added that it has produced thousands of low-loss 5-
leg distribution transformers and is unaware of a single occurrence of
ferroresonace. (Eaton, No. 55 at pp. 9-10)
DOE did not receive any data suggesting that pole- and pad-mounted
distribution transformers warrant separate equipment classes. As such,
DOE has not proposed to amend the current equipment class structure for
pole- and pad-mounted distribution transformers. Further, DOE includes
both pole- and pad-mounted representative units in its engineering
analysis.
b. Submersible Transformers
Certain distribution transformers are installed underground and,
accordingly, may endure partial or total immersion in water. This
scenario commonly arises for distribution transformers installed in
chambers called ``vaults'', which are commonly made of concrete. Access
is typically, but not always, through an opening in the top
(``ceiling'') face of the vault, through which the distribution
transformer can be lowered for installation or replacement.
``Submersible'', ``network'' and ``vault-based'' are three
attributes that often all apply to a particular distribution
transformer unit, but which carry distinct meanings. Informally,
``submersible'' refers to ability to operate while submerged,
``network'' refers to ability to operate as part of a network of
interconnected secondary windings as most typically occurs in urban
environments, and ``vault-based'' refers to siting within a vault,
which may be but is not necessarily below grade. A given distribution
transformer, for example, may be installed within an above-grade vault
but not rated as submersible. Similarly, a particular network
distribution transformer may happen to be installed within a vault, but
able to operate as well outside of a vault.
In the April 2013 Standards Final Rule, DOE included additional
costs for vault replacements in the LCC analysis but noted there was no
technical barrier that prevents network, vault-based and submersible
distribution transformers from achieving the same efficiency levels as
other liquid-immersed distribution transformers. 78 FR 23336, 23356-
23357. In the August 2021 Preliminary Analysis TSD, DOE preliminarily
stated that it would take a similar approach in applying the costs of
vault enlargement as a function of increased distribution transformer
volume for RU4 and RU5. (August 2021 Preliminary Analysis TSD at p. 2-
89) DOE requested comment on some of the options a customer is likely
to explore before incurring the cost of vault expansion, such as using
a lower-loss core steel, copper windings, or a less-flammable
insulating fluid. (August 2021 Preliminary Analysis TSD at p. 2-20)
NEMA commented that when trying to fit into a given space, copper
windings may allow for a 20 percent size reduction relative to aluminum
and higher-grade core steels can help, but it is still sometimes very
difficult to reduce footprint while meeting standards. (NEMA, No. 50 at
p. 6) Carte requested an exclusion for retro fit designs. (Carte, No.
54 at p. 2)
Carte commented that most network transformers are lightly loaded
but redundancy is quite important and as such many customers require
high overload capabilities. (Carte, No. 54 at p. 1) Carte added that in
certain applications, with limited space, there is reduced cooling
which forces manufacturers to lower load loss at the expense of core
loss to maintain reliable operation. (Carte, No. 54 at pp. 1-2) EEI
recommended DOE include a separate product class for vault
transformers. (EEI, No. 56 at p. 3)
As discussed, EPCA requires that a rule prescribing an energy
conservation standard for a type of covered equipment specify a level
of energy use or efficiency higher or lower than that which applies (or
would apply) to any group of covered equipment that has the same
function or intended use, if the Secretary determines that covered
equipment within such group:
(A) Consume a different kind of energy from that consumed by other
covered products within such type (or class); or
(B) Have a capacity or other performance-related feature that other
products within such type (or class) do not have and such feature
justifies a higher or lower standard from that which applies (or will
apply) to other products within such type (or class).
(42 U.S.C. 6313(a); 42 U.S.C. 6295(q)(1))
In making a determination of whether a performance-related feature
justifies the establishment of a higher or lower standard, the
Secretary must consider such factors as the utility to the consumer of
such a feature, and such other factors as the Secretary deems
appropriate. Id.
As noted, DOE previously determined there was no technical barrier
to vault distribution transformers achieving similar efficiency
standards as other similar distribution transformers. To the extent
significant costs arise for more-efficient units, they are generally
installation costs (i.e., expanding the size of the vault in which the
distribution transformer is installed). Installation costs are
addressed in the LCC and PBP analyses, as well as in consumer subgroup-
specific analyses. These analyses account for the cost of difficult
(i.e., unusually costly) installations, including those subgroups of
the population that may be differentially impacted by DOE's
consideration of amended energy conservation standards (see section
IV.I.2 of this document).
Review of comments and the equipment market indicates that certain
vault-based distribution transformers also are designed to operate in
submersible applications. Because many vaults are subterranean,
distribution transformers installed in such locations often require
ability to operate while submerged. Installation below grade makes more
likely that distribution transformers may operate while submerged in
water and with other run-off debris. Distribution transformers for
installation in such environments are designed to withstand harsh
conditions, including corrosion.
The subterranean installation of submersible distribution
transformers means that there is less circulation of ambient air for
shedding heat. Operation while submerged in water and in contact with
run-off debris, further impacts the ability of a distribution
transformer to transfer heat to the environment and limits the
alternative approaches in the external environment that can be used to
increase cooling.
With respect to heat transfer, the industry standards governing
submersible distribution transformers, i.e., IEEE C57.12.23-2018 and
C57.12.24-2016, specify that submersible distribution transformers,
amongst other requirements, have their capacity rated for a maximum
temperature rise of 55[deg]C but have their insulation be rated for
65[deg]C. IEEE C57.12.80-2010 defines submersible distribution
transformer as ``a transformer so constructed as to be successfully
operable when submerged in water under predetermined conditions of
pressure and time.''
Distribution transformer temperature rise tends to be governed by
load losses. Often, design options that reduce load losses, increase
no-load losses. While no-load losses make up a relatively small portion
of losses at full load, no-load losses contribute approximately equally
to load losses at 50 percent PUL, at which manufacturers must certify
efficiency. The potentially reduced heat transfer of the subterranean
[[Page 1749]]
environment, combined with the possibility of operating while
submerged, limits customers from meeting the temperature rise
limitations through any choice other than reducing load losses.
Therefore, the design choices needed to meet a lower temperature rise,
may tend to lead manufacturers to increase no-load losses and may make
it more difficult to meet a given efficiency standard at 50 percent
PUL.
DOE recognizes that distribution transformers other than those
designed for submersible operation may be derated (rated for a lower
temperature rise) for other reasons, such as installation in ambient
temperatures over 40[deg]C, greater harmonic currents, or installation
at altitudes above 1000 meters. However, the ability to improve the
efficiency of such distribution transformers is not similarly limited
as submersible distribution transformers because other options exist
for distribution transformers above grade that would not be feasible in
submerged environments, namely the ability to increase heat transfer,
often with some additional cost, as opposed to only options that
increase a distribution transformer's no-load losses. For example,
distribution transformers installed above grade may be able to have
more air circulation through radiators, improving the efficiency of
radiators to shed heat, or adding external forced air cooling on a
distribution transformer radiator, whereas such a measure would not be
able to function as intended in a submerged environment.
Based on the foregoing discussion, DOE has tentatively determined
that distribution transformers designed to operate while submerged and
in contact with run-off debris have a performance-related feature which
other types of distribution transformers do not have. While at max-tech
efficiency levels both no-load and load losses are so low that
distribution transformers generally do not meet their rated temperature
rise, at intermediate efficiency levels, trading load losses for no-
load losses allows distribution transformers to be rated for a lower
temperature rise, however, it also may make it more difficult to meet
any amended efficiency standard as no-load losses contribute
proportionally more to efficiency at the test procedure PUL as compared
to rated temperature rise. Therefore, DOE is proposing that providing
for operation in installation locations at which the units are
partially or wholly submerged in water justifies a different standard
on account of the additional constraint which forces manufacturers to
trade load losses for no-load losses. DOE has modeled the derating of
these distribution transformers and the associated costs associated
with these submersible distribution transformers, as described in
section IV.C.1 of this document.
In proposing separate equipment classes, DOE relies on physical
features to distinguish one product class from another. While the IEEE
definition of ``submersible transformer'' described how a submersible
distribution transformer should perform, it does not include specific
physical features that would allow DOE to identify submersible
transformers from other general purpose distribution transformers. In
reviewing industry standards, DOE notes that submersible distribution
transformers are rated for a temperature rise of 55[deg]C, have
insulation rated for 65[deg]C, have sealed-tank construction, and have
the tank, cover, and all external appurtenances be made of corrosion-
resistant material. Consistent with industry practice, DOE is proposing
to define submersible distribution transformer as ``a liquid-immersed
distribution transformer so constructed as to be successfully operable
when submerged in water including the following features: (1) is rated
for a temperature rise of 55[deg]C; (2) has insulation rated for a
temperature rise of 65[deg]C; (3) has sealed-tank construction; and (4)
has the tank, cover, and all external appurtenances made of corrosion-
resistant material.''
DOE notes that IEEE C57.12.80-2010 defines several other types of
distribution transformers that would potentially also meet the proposed
definition of ``submersible distribution transformer.'' IEEE C57.12.80-
2010 defines ``vault-type transformer'' as ``a transformer that is so
constructed as to be suitable for occasional submerged operation in
water under specified conditions of time and external pressure.''
Similarly, IEEE C57.12.80-2010 defines ``network transformer'' as ``a
transformer designed for use in a vault to feed a variable capacity
system of interconnected secondaries,'' and states that ``a network
transformer may be of the submersible or of the vault type.'' To the
extent network and vault-type distribution transformers were to meet
the proposed definition of submersible distribution transformer, they
would be included in the submersible distribution transformer equipment
class.
DOE requests comment on its understanding and proposed definition
of ``submersible'' distribution transformer. Specifically, DOE requests
information on specific design characteristics of distribution
transformers that allow them to operate while submerged in water, as
well as data on the impact to efficiency resulting from such
characteristics.
DOE requests comment and data as to the impact that submersible
characteristics have on distribution transformer efficiency.
c. Multi-Voltage-Capable Distribution Transformers
DOE's test procedure section 5.0 of appendix A requires determining
the efficiency of multi-voltage-capable distribution transformers in
the configuration in which the highest losses occur. In the August 2021
Preliminary Analysis TSD, DOE acknowledged that certain multi-voltage
distribution transformers, particularly non-integer ratio \45\
distribution transformers could have a harder time meeting an amended
efficiency standard as it results in an unused portion of a winding
when testing in the highest losses configuration and therefore reduces
the measured efficiency. (August 2021 Preliminary Analysis TSD at p. 2-
21) DOE requested comment on the difference in losses associated with
multi-voltage distribution transformers. (August 2021 Preliminary
Analysis TSD at p. 2-21)
---------------------------------------------------------------------------
\45\ For example, a primary winding low voltage configuration of
7200 V and a primary winding high voltage configuration of 14400 V
represents a 2 times increase in voltage. Whereas a primary winding
low voltage configuration of 7200 V and a primary winding high
voltage configuration of 13200 V represents a non-integer increase
in voltage leaving some portion of the coil unused.
---------------------------------------------------------------------------
Schneider commented that the higher nominal voltage tends to be
more efficient, but the degree of increased losses depends on the kVA
and difference between nominal voltages. (Schneider, No. 49 at p. 9)
Schneider commented that the challenge for DOE is ensuring
manufacturers are testing in worst case conditions and recommended DOE
require manufacturers to identify these transformers and/or requiring
on the distribution transformer nameplate. (Schneider, No. 49 at pp.
10-12) Schneider recommended DOE audit these multi-voltage designs to
ensure they are testing under proper conditions. (Schneider No. 49 at
pp. 12-13) Schneider expanded that these products should not have a
separate equipment class but should be audited by DOE. (Schneider, No.
49 at p. 13)
Schneider's data indicates that the degree of coil loss increase
associated with multi-voltage secondary distribution transformers
ranges from 3.7 percent to 10.8 percent of full-load coil losses.
(Schneider No. 49 at p. 10)
[[Page 1750]]
DOE notes that each efficiency level considered offers a range of no-
load and load loss combinations for meeting efficiency levels. While a
multi-voltage transformer may require manufacturers to invest more in
reducing no-load loss relative to a similar single voltage transformer,
it would generally still be able to serve those customers' needs that
request a multi-voltage distribution transformer.
ERMCO and NEMA acknowledged that some multi-voltage units may have
a harder time achieving efficiency standards but did not provide a
recommendation as to how to treat them. (ERMCO, No. 45 at p. 1; NEMA,
No. 50 at p. 6) Eaton commented that transformers with multiple voltage
rating and non-whole integer ratings have unused turns and require
additional space in the core window leading to higher losses. (Eaton,
No. 55 at p. 12) Carte identified emergency use distribution
transformers which have multiple high voltages and low voltages and can
be used anywhere in a system until a proper replacement is added, and
asked how standards apply to them. (Carte, No. 54 at p. 2)
As discussed, EPCA requires that a rule prescribing an energy
conservation standard for a type of covered equipment specify a level
of energy use or efficiency higher or lower than that which applies (or
would apply) to any group of covered equipment that has the same
function or intended use, if the Secretary determines that covered
equipment within such group:
(A) Consume a different kind of energy from that consumed by other
covered products within such type (or class); or
(B) Have a capacity or other performance-related feature that other
products within such type (or class) do not have and such feature
justifies a higher or lower standard from that which applies (or will
apply) to other products within such type (or class).
(42 U.S.C. 6313(a); 42 U.S.C. 6295(q)(1))
In making a determination of whether a performance-related feature
justifies the establishment of a higher or lower standard, the
Secretary must consider such factors as the utility to the consumer of
such a feature, and such other factors as the Secretary deems
appropriate. Id.
DOE acknowledges that multi-voltage distribution transformers,
specifically those with non-integer ratios, offer the performance
feature of being able to be installed in multiple locations within the
grid (such as in emergency applications) and easily upgrade grid
voltages without replacing a distribution transformer. These
transformers are often used in upgrading distribution line voltages and
as such when the distribution line voltage is upgraded, these
distribution transformers would have greater efficiency than their
certified efficiency. These distribution transformers have additional,
unused winding turns when operated at their lower voltage which
increase losses. However, once the distribution grid has been increased
to the higher voltage, the entire winding will be used, increasing the
efficiency of the product. However, DOE lacks data as to the degree of
no-load loss and load loss increase associated with transitioning from
a single primary and secondary voltage distribution transformer to a
multi-voltage distribution transformer.
DOE notes that the NRCAN regulations specify that ``For a three-
phase transformer having multiple high-voltage windings and a voltage
ratio other than 2:1, the minimum energy efficiency standard from the
table or interpolated is reduced by 0.11.'' Similarly, EU regulations
permit between a 10 to 20 percent increase in load losses for dual
voltage transformers and between 15 and 20 percent increase in no-load
losses, depending on the type of dual voltage.
Schneider commented that multi-voltage transformers do not need a
lesser standard as it is a manufacturers choice to produce them.
(Schneider, No. 49 at p. 10) Schneider added that they have many non-
integer multi-voltage ratios offered and do not believe it is necessary
to create a new class for these products. (Schneider, No. 49 at p. 10)
Stakeholder comments suggest that the difference in voltages
associated with multi-voltage distribution transformers is relatively
small. Further, technologies that increase the efficiency of single-
voltage distribution transformers also increase the efficiency of
multi-voltage distribution transformers. For these reasons, DOE has not
proposed a separate equipment class for multi-voltage-capable
distribution transformers with a voltage ratio other than 2:1.
However, DOE may consider a separate product class if sufficient
data is provided to demonstrate that these distribution transformers
justify a different energy conservation standard. DOE notes that these
distribution transformers would not be permitted to have a lesser
standard than currently applicable to them on account of EPCA's anti-
backsliding provisions at 42 U.S.C. 6295(o).
DOE requests data on the difference in load loss by kVA for
distribution transformers with multiple-voltage ratings and a voltage
ratio other than 2:1.
DOE request data on the number of shipments for each equipment
class of distribution transformers with multi-voltage ratios other than
2:1.
d. High-Current Distribution Transformers
Carte commented that low secondary voltages with high currents can
increase the cost and weight of a distribution transformer and may
require switching to copper. (Carte, No. 54 at p. 1) NEMA commented
that new production machines may be needed for certain winding
configurations near technical limits, such as large kVA distribution
transformers with 208 voltage secondaries. (NEMA, No. 50 at p. 10)
Eaton commented that lower voltage windings have higher currents which
may require rectangular conductors and can make winding more
complicated. (Eaton, No. 55 at p. 12) Eaton added that at some sizes,
the conductor becomes too thick to be used in a transformer. (Eaton,
No. 55 at p. 12) NEMA commented that these designs are on the cusp of
max-tech today. (NEMA, No. 50 at p. 10)
Distribution transformers with high currents tend to have increased
stray losses which can impact the efficiency of distribution
transformers. NEMA cited a 2,000 kVA design with a 208V secondary where
buss losses contribute approximately 12 percent to the full load losses
of the transformer. (NEMA, No. 50 at p. 5) DOE notes that NRCAN
regulations exclude transformers with a nominal low-voltage line
current of 4000 A or more. In general, this amperage limitation would
impact large distribution transformers with low-voltage secondary
windings.
DOE notes that in high-current applications, while stray losses may
be slightly higher, manufacturers have the option to use copper
secondaries to decrease load losses or a copper buss bar. Technologies
that increase the efficiency of lower-current distribution transformers
also increase the efficiency of high-current distribution transformers.
To the extent new production machines would be needed to accommodate
the increased strip widths associated with high-current distribution
transformers, those would be accounted for in the manufacturer impact
analysis. For these reasons, DOE has not proposed a separate equipment
class for high-current distribution transformers.
However, DOE may consider a separate product class if sufficient
data is provided to demonstrate that high-current distribution
transformers justify
[[Page 1751]]
a different energy conservation standard. DOE notes that these
distribution transformers would not be permitted to have a lesser
standard than currently applicable to them on account of EPCA's anti-
backsliding provisions at 42 U.S.C. 6295(o).
DOE requests data on the difference in load loss by kVA for
distribution transformers with higher currents and at what current it
becomes more difficult to meet energy conservation standards.
DOE requests data as to the number of shipments of distribution
transformers with the higher currents that would have a more difficult
time meeting energy conservation standards.
e. Data Center Distribution Transformer
In the April 2013 Standard Final Rule, DOE considered a separate
equipment class for data center distribution transformers, defined as
the following:
``i. Data center transformer means a three-phase low-voltage dry-
type distribution transformer that--
(i) Is designed for use in a data center distribution system and
has a nameplate identifying the transformer as being for this use only;
(ii) Has a maximum peak energizing current (or in-rush current)
less than or equal to four times its rated full load current multiplied
by the square root of 2, as measured under the following conditions--
1. During energizing of the transformer without external devices
attached to the transformer that can reduce inrush current;
2. The transformer shall be energized at zero +/-3 degrees voltage
crossing of a phase. Five consecutive energizing tests shall be
performed with peak inrush current magnitudes of all phases recorded in
every test. The maximum peak inrush current recorded in any test shall
be used;
3. The previously energized and then de-energized transformer shall
be energized from a source having available short circuit current not
less than 20 times the rated full load current of the winding connected
to the source; and
4. The source voltage shall not be less than 5 percent of the rated
voltage of the winding energized; and
(vii) Is manufactured with at least two of the following other
attributes:
1. Listed as a Nationally Recognized Testing Laboratory (NRTL),
under the Occupational Safety and Health Administration, U.S.
Department of Labor, for a K-factor rating greater than K-4, as defined
in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition,
Dry-Type General Purpose and Power Transformers;
2. Temperature rise less than 130 [deg]C with class 220 \(25)\
insulation or temperature rise less than 110 [deg]C with class 200
\(26)\ insulation;
3. A secondary winding arrangement that is not delta or wye (star);
4. Copper primary and secondary windings;
5. An electrostatic shield; or
6. Multiple outputs at the same voltage a minimum of 15[deg] apart,
which when summed together equal the transformer's input kVA
capacity.'' \46\
---------------------------------------------------------------------------
\46\ 78 FR 23336, 23358.
---------------------------------------------------------------------------
DOE did not adopt this definition of ``data center distribution
transformers'' or establish a separate class for such equipment for the
following reasons: (1) the considered definition listed several factors
unrelated to efficiency; (2) the potential risk of circumvention of
standards and that a transformer may be built to satisfy the data
center definition without significant added expense; (3) operators of
data centers are generally interested in equipment with high
efficiencies because they often face large electricity costs, and
therefore may be purchasing at or above the standard established and
unaffected by the rule; and (4) data center operator can take steps to
limit in-rush current external to the data center transformer. 78 FR
23336, 23358.
In the August 2021 Preliminary Analysis TSD, DOE stated that data
center distribution transformers could represent a potential equipment
class setting factor and requested additional data about the data
center distribution transformer market, performance characteristics,
and any physical features that could distinguish data center
distribution transformers from general purpose distribution
transformers. (August 2021 Preliminary Analysis TSD at p. 2-22)
DOE did not receive any comments as to physical features that could
distinguish a data center distribution transformer from a general-
purpose distribution transformer.
DOE requests comment as to what modifications could be made to the
April 2013 Standard Final Rule data center definition such that the
identifying features are related to efficiency and would prevent a data
center transformer from being used in a general purpose application.
NEMA commented that most data center transformers are outside the
scope due to kVA range, but those still within scope would likely have
high loading and would not be favored for amorphous transformers.
(NEMA, No. 50 at p. 6)
Eaton commented that liquid-immersed distribution transformers are
increasingly being used in data center applications. (Eaton, No. 55 at
p. 10) Eaton added that the quantity and overall energy consumed in
data center applications has increased significantly. (Eaton, No. 55 at
p. 10) Eaton commented that the lifespan of a data center transformer
would vary depending on loading. (Eaton, No. 55 at p. 11)
Eaton commented that liquid-immersed data center transformers are
designed to operate between 50-75 percent PUL and are typically
specified to meet DOE efficiency standards. (Eaton, No. 55 at pp. 10-
11)
DOE did not receive any comments suggesting that data center
distribution transformers warrant a separate product class. As such,
DOE has not proposed a definition for data center distribution
transformers and has not evaluated them as a separate product class.
However, DOE may consider a separate product class if sufficient data
is provided to demonstrate that data center transformers warrant a
different efficiency level and can appropriately be defined.
Distribution transformers used in data centers may sometimes, but not
necessarily, be subject to different operating conditions and
requirements which carry greater concern surrounding inrush current.
DOE requests comment regarding its proposal not to establish a
separate equipment class for data center distribution transformers. In
particular, DOE seeks comment regarding whether data center
distribution transformers are able to reach the same efficiency levels
as distribution transformers generally and the specific reasons why
that may be the case.
DOE requests comment regarding any challenges that would exist if
designing a distribution transformer which uses amorphous electrical
steel in its core for data center applications and whether data center
transformers have been built which use amorphous electrical steel in
their cores.
DOE requests comment on the interaction of inrush current and data
center distribution transformer design. Specifically, DOE seeks
information regarding: (1) the range of inrush current limit values in
use in data center distribution transformers; (2) any challenges in
meeting such inrush current limit values when using amorphous
electrical steel in the core; (3) whether using amorphous electrical
steel inherently increases inrush current, and why; (4) how the
(magnetic) remanence of grain-oriented electrical steel compares to
that of
[[Page 1752]]
amorphous steel; and (5) other strategies or technologies than
distribution transformer design which could be used to limit inrush
current and the respective costs of those measures.
f. BIL Rating
Distribution transformers are built to carry different basic
impulse level (``BIL'') ratings. BIL ratings offer increased resistance
to large voltage transients, for example, from lightning strikes. Due
to the additional winding clearances required to achieve a higher BIL
rating, high BIL distribution transformers tend to be less efficient,
leading to higher costs and be less able to achieve higher
efficiencies. DOE separates medium-voltage dry-type distribution
transformers into equipment classes based on BIL ratings. 10 CFR
431.196(c).
In the August 2021 Preliminary Analysis TSD, DOE noted stakeholder
comments that evaluating additional liquid-immersed distribution
transformers based on BIL rating would add additional complications for
minor differences in losses. As such, DOE did not consider BIL in its
evaluation of liquid-immersed distribution transformers.
In response, Howard commented that 150 kV and 200 kV BIL units
should not have their efficiency standards increased as these units are
already too large. (Howard, No. 59 at pp. 1-2) Carte commented that 200
kV BIL transformers have more insulation that increases the size of the
transformer and therefore the losses of the transformer. (Carte, No. 54
at p. 1) Eaton commented that high BIL transformers can have a harder
time meeting efficiency standards. (Eaton, No. 55 at p. 12) Neither
Eaton, Howard nor Carte provided any data suggesting the degree of
efficiency difference as BIL is increased. Based on the discussion in
the preceding paragraphs, DOE is not proposing a separate equipment
class based on BIL rating for liquid-immersed units but may consider it
if sufficient data is provided.
DOE requests data as to how a liquid-immersed distribution
transformer losses vary with BIL across the range of kVA values within
scope.
Regarding MVDTs, NEMA commented that MVDT with BIL levels above 150
kV are essentially non-existent and would not represent a significant
amount of energy savings if regulated. (NEMA, No. 50 at p. 7)
DOE notes that MVDTs above 150 kV BIL are currently regulated. In
the August 2021 Preliminary Analysis TSD, DOE requested data on the
change in efficiency associated with higher BIL ratings for
distribution transformers and the volume of dry-type distribution
transformers sold with BIL ratings above 199 kV. DOE did not receive
any data and therefore has maintained its current equipment class
separation of MVDTs.
g. Other Types of Equipment
Stakeholders identified several other distribution transformer
types that they noted may have a harder time meeting efficiency
standards. NEMA commented that MVDTs at high altitude may require more
air clearance and therefore must accommodate higher core loss, and as
such, may warrant a separate equipment class. (NEMA, No. 50 at p. 5)
Carte asked DOE to analyze main and teaser and Scott connected
transformers which it stated are unique to certain industrial grids and
can be very difficult or impossible to replace.\47\ (Carte, No. 54 at
p. 2)
---------------------------------------------------------------------------
\47\ Main and Teaser and Scott connected transformers are a
special type of transformer which converts from three-phase energy
to two phase energy or vice versa using two electrically-connected
single-phase transformers
---------------------------------------------------------------------------
Carte asked how efficiency standards apply to duplex transformers
which have two kVA ratings on one transformer.\48\ (Carte, No. 54 at p.
2) Carte asked if three winding simultaneous loading transformers used
in solar applications to isolate the low-voltage qualify for an
exemption. (Carte, No. 54 at p. 2)
---------------------------------------------------------------------------
\48\ Duplex transformers consist of two single-phase
transformers assembled in a single enclosure. They are generally
used to provide a large single-phase output in tandem with a smaller
three-phase output
---------------------------------------------------------------------------
DOE did not receive any data as to the degree of difference in
efficiency associated with these distribution transformers. DOE has not
considered any of the noted products as separate equipment classes in
this NOPR analysis due to lack of data as to the shipments and
reduction in efficiency associated with certain designs. Regarding how
standards are applied to certain equipment, DOE notes that equipment
that meets the definition of distribution transformer is subject to
energy conservation standards at 10 CFR 431.196.
DOE requests comments and data on any other types of equipment that
may have a harder time meeting energy conservation standards.
Specifically, DOE requests comments as to how these other equipment are
identified based on physical features from general purpose distribution
transformers, the number of shipments of each unit, and the possibility
of these equipment being used in place of generally purpose
distribution transformers.
3. Test Procedure
The current test procedure for measuring the energy consumption of
distribution transformers is established at appendix A to subpart K of
10 CFR part 431. In a September 2021 TP Final Rule, DOE maintained that
energy efficiency be evaluated at 50 percent PUL for liquid-immersed
distribution transformers and medium-voltage dry-type distribution
transformers and 35 percent PUL for low-voltage dry-type distribution
transformers. 86 FR 51230. In the August 2021 Preliminary Analysis TSD,
DOE acknowledged that its estimates for current root-mean-square
(``RMS'') in-service loading is less than the test procedure PUL but
noted there was uncertainty which makes it preferential to overestimate
PUL rather than underestimate PUL. DOE noted that any potential energy
savings that could be achieved by changing the standard PUL could also
be achieved by increasing the stringency of the energy conservation
standards. As such, DOE only considered distribution transformers that
would meet energy conservation standards at DOE's test procedure
loading, but evaluated energy saving potential using in-service data
and load growth estimates.
In response, CDA agreed with the test procedure loading and stated
that they believe the loading will match future forecasts. (CDA, No. 47
at p. 2)
NEEA and the Efficiency Advocates commented that the test procedure
PUL is too high and leads to designs that over-invest in load losses,
and as such, DOE should reduce the test procedure PUL. (Efficiency
Advocates, No. 52 at pp. 1-2; NEEA, No. 51 at pp. 7-8) The Efficiency
Advocates commented that DOE's preliminary analysis shows that
intermediate energy savings can be achieved with small price increases
if transformer designs are optimized for more realistic PULs and urged
DOE to consider revising its test procedure PUL, given the preliminary
analysis load growth estimates. (Efficiency Advocates, No. 52 at p. 2)
The Efficiency Advocates commented that the negative savings at certain
ELs reflect the fact that certain ELs would be met by decreasing load
losses rather than no-load losses. (Efficiency Advocates, No. 52 at pp.
2-3) The Efficiency Advocates further referenced DOE's hourly load
model which they claim demonstrated a small percentage of hours above
50 percent PUL and indicates savings available at lower PULs.
(Efficiency Advocates, No. 52 at p. 4) The Efficiency Advocates
commented that a lower PUL permits greater savings for less costs,
claiming that DOE's data shows better optimizing
[[Page 1753]]
a transformer could yield 23 percent energy savings for only a 4
percent increase in costs. (Efficiency Advocates, No. 52 at pp. 4-5)
DOE notes that the potential energy savings cited by the Efficiency
Advocates are based on a distribution transformer that is optimized at
35 percent PUL and is meeting current efficiency standards at 50
percent PUL. In the scenario where an alternative test procedure PUL is
used, distribution transformers would not have to meet the current
standard at 50 percent PUL, they would only have to meet a new standard
at 35 percent PUL. DOE's analysis of energy conservation standards
assumes consumers select a range of distribution transformers and
applies a range of unique customer loading profiles to evaluate the
impacts of amended energy conservation standards. In a theoretical
evaluation of energy conservation standards at 35 percent PUL, the
whole analysis would change as new distribution transformers would be
able to be purchased by consumers that do not meet current standards at
50 percent PUL but may meet a standard at 35 percent PUL. Without doing
a much more detailed analysis, it is a vast oversimplification to cite
energy savings from a single distribution transformer. Further, DOE
notes that many of the distribution transformers optimized for low PULs
use amorphous cores and represent the design options with the highest
efficiency at 50 percent PUL.
Powersmiths commented that measuring LVDT efficiency at a single
load point is insufficient since the efficiency varies dramatically
over the loading. (Powersmiths, No. 46 at p. 1) Powersmiths added that
35 percent PUL is not representative for LVDTs. (Powersmiths, No. 46 at
p. 1) Powersmiths added that evaluating at 35 percent PUL enables
manufacturers to publish peak efficiency rather than how their
transformers perform in the real world. (Powersmiths, No. 46 at p. 2)
Powersmiths commented that this practice misleads customers into
thinking DOE compliant transformers save them the most money, when
transformers optimized for lower loading could save more energy and
money. (Powersmiths, No. 46 at p. 2)
Metglas commented that actual data shows current loading is low and
as such, the liquid-immersed distribution transformers should be
evaluated at 35 percent load and LVDTs should be evaluated at 20
percent load. (Metglas, No. 53 at p. 1; Metglas, No. 53 at p. 6)
Powersmiths added that the 35 percent PUL for LVDTs produces
deceptively high savings estimates and pushing up efficiency at that
point is counterproductive. (Powersmiths, No. 46 at p. 2) Powersmiths
recommended DOE work with organizations to reduce oversizing of
distribution transformers. (Powersmiths, No. 46 at p. 2)
DOE agrees with stakeholders that current loading is lesser than
the test procedure PUL. As such, DOE relies on the most accurate in-
service PUL and load growth estimates to calculate energy savings
potential. However, DOE evaluates the efficiency of distribution
transformers and only includes distribution transformer models that
would meet amended energy conservation standards at the test procedure
PUL. The efficiency of distribution transformers over the duration of
its lifetime and across all installations cannot be fully represented
by a single PUL. A given transformer may be highly loaded or lightly
loaded depending on its application or variation in electrical demand
throughout the day. In the September 2021 TP Final Rule, DOE was unable
to conclude that any singular PUL would be more representative than the
current test procedure PUL because of (1) significant long-term
uncertainty regarding what standard PUL would correspond to a
representative average use cycle for a distribution transformer given
their long lifetimes; and (2) given the uncertainty of future loading,
there may be greater risk associated with selecting a test procedure
PUL that is too low than a test procedure PUL that is too high. 86 FR
51230, 51240. Therefore, for purposes of evaluating the proposed
standards in this document, DOE used the test procedure PUL. More
discussion of the test procedure PUL may be found in the September 2021
TP Final Rule.
DOE disagrees with commenters' assertion that there is an inherent
benefit associated with distribution transformers certified at an
alternative PUL as no energy conservation standard exist at any
alternative PUL. Further, DOE believes any benefits associated with a
lower PUL are also achieved via amended energy conservation standards.
DOE has presented plots in chapter 3 of the TSD to demonstrate how the
design space of possible load loss and no-load loss combinations would
change in the presence of amended energy conservation standards and if
energy conservation standards were evaluated at an alternative PUL
which helps demonstrate this conclusion.
Powersmiths commented that the current reporting system is flawed
as factors like sub-standard batches of steel may result in
noncompliant distribution transformers being shipped, and recommended
DOE should require third party testing of distribution transformers.
(Powersmiths, No. 46 at pp. 6-7) DOE notes that it has no data
suggesting manufacturers are shipping non-compliant distribution
transformers. DOE notes that in the case of sub-standard steel batches,
its certification requirements permit some degree of variability in
equipment performance, as described at 10 CFR 429.47.
Powersmiths commented that high volume manufacturers optimize costs
by using higher loss core steel and lower loss conductor material to
meet the 35 percent legal limit. (Powersmiths, No. 46 at p. 2)
Powersmiths recommended lowering the LVDT test procedure PUL or adding
a core loss limit to secure real world energy savings. (Powersmiths,
No. 46 at p. 2)
In the September 2021 TP Final Rule, DOE noted that on account of
uncertainty associated with future distribution transformer loading,
DOE is unable to conclude that any alternative single-PUL efficiency
metric is more representative than the current standard PUL. 86 FR
51230, 51240. Therefore, DOE only evaluated distribution transformers
that would meet amended efficiency standards at the current test
procedure PUL. In its evaluation of energy savings, DOE used data
representative of current in-service loading, as described in section
IV.E. DOE does not make assumptions as to the maximum no-load or load
losses of a transformer and instead relies on the consumer choice
model, described in section IV.F.3 of this document, to evaluate the
distribution transformers that consumers are likely to purchase.
4. Technology Options
In the preliminary market analysis and technology assessment, DOE
identified several technology options that would be expected to improve
the efficiency of distribution transformers, as measured by the DOE
test procedure.
Increases in distribution transformer efficiency are based on a
reduction of distribution transformer losses. There are two primary
varieties of loss in distribution transformers: no-load losses and load
losses. No-load losses are roughly constant with PUL and exist whenever
the distribution transformer is energized (i.e., connected to
electrical power). Load losses, by contrast, are zero at 0 percent PUL
but grow quadratically with PUL.
No-load losses occur primarily in the transformer core, and for
that reason the terms ``no-load loss'' and ``core loss'' are sometimes
interchanged. Analogously, ``winding loss'' or ``coil loss'' is
[[Page 1754]]
sometimes used in place of ``load loss'' because load loss arises
chiefly in the windings. For consistency and clarity, DOE will use
``no-load loss'' and ``load loss'' generally and reserve ``core loss''
and ``coil loss'' for when those quantities expressly are meant.
CDA commented that copper is the best conductor of electricity and
enables a more compact and economical distribution transformer with a
smaller tank, less core, and reduced oil. (CDA, No. 47 at p. 1) DOE
notes that it has included some copper windings in its engineering
analysis and recognizes that while copper may be more expensive than
aluminum conductors, it represents a technology option that allows
manufacturers to achieve smaller footprints or higher efficiencies in
designs that are uniquely difficult to meet energy conservation
standards.
EEI commented that many technologies that decrease no-load losses,
increase load losses and therefore DOE should utilize accurate
projections of loading and recognize lower-loss core materials can have
significantly higher load losses. (EEI, No. 56 at p. 3)
Regarding amended energy conservation standards generally, Howard
commented that no new technology options have come onto the market that
would impact distribution transformer efficiency since the April 2013
Standards Final Rule. (Howard, No. 59 at p. 1) CDA commented that there
should be no new standards and recommended DOE continue to evaluate the
inputs to its analysis and new technologies. (CDA, No. 47 at p. 2)
Powermiths noted that the market is in flux currently and recommended
DOE delay the rulemaking while the market settles, require third party
compliance enforcement, and invite stakeholder into DOE's revision
process. (Powersmiths, No. 46 at p. 7)
With respect to analyzed inputs, in the engineering analysis, DOE
considered various combinations of the following technology options to
improve efficiency: (1) Higher grade electrical core steels, (2)
different conductor types and materials, and (3) adjustments to core
and coil configurations. With respect to commenters' suggestions that
DOE delay standards or not issue amended standards, as noted
previously, EPCA requires DOE to periodically determine whether more-
stringent standards would be technologically feasible and economically
justified, and would result in significant energy savings. 42 U.S.C.
6316(a); 42 U.S.C. 6295(m). DOE has tentatively concluded that the
proposed standards represent the maximum improvement in energy
efficiency that is technologically feasible and economically justified,
and would result in the significant conservation of energy.
Specifically, with regards to technological feasibility, products
achieving these standard levels are already commercially available for
all product classes covered by this proposal. Accordingly, DOE has
proceeded with the proposed standards.
5. Electrical Steel Technology and Market Assessment
Distribution transformer cores are constructed from a specialty
kind of steel known as electrical steel. Electrical steel is an iron
alloy which incorporates small percentages of silicon to enhance its
magnetic properties, including increasing its magnetic permeability and
reducing the iron losses associated with magnetizing that steel.
Electrical steel is produced in thin laminations and either wound or
stacked into a distribution transformer core shape.
Electrical steel used in distribution transformer applications can
broadly be categorized as amorphous steel and grain-oriented electrical
steel (``GOES''). There are many subcategories of steel within both
amorphous steel and grain-oriented electrical steel. In the August 2021
Preliminary Analysis TSD, DOE assigned designated names to identify the
various permutations of electrical steel. (August 2021 Preliminary
Analysis TSD at pp. 2-31-36) DOE requested comment on its proposed
naming convention. In response, Schneider and NEMA commented that the
proposed naming convention used by DOE in the preliminary analysis is
adequate. (Schneider, No. 49 at p. 13; NEMA No. 50 at p. 8)
The various markets, technologies, and naming conventions for
amorphous and GOES are discussed in the following sections.
a. Amorphous Steel Market and Technology
Amorphous steel is a type of electrical steel that is produced by
rapidly cooling molten alloy such that crystals do not form. The
resulting product is thinner than GOES and has lower core losses, but
it reaches magnetic saturation at a lower flux density.
DOE has identified three sub-categories of amorphous steel as
possible technology options. These technology options and their DOE
naming shorthand are shown in Table IV.2.
Table IV.2--Amorphous Steel Technology Options
------------------------------------------------------------------------
DOE designator in design options Technology
------------------------------------------------------------------------
am........................................ Traditional Amorphous Steel.
hibam..................................... High-Permeability Amorphous
Steel.
hibam-dr.................................. High-Permeability, Domain-
Refined, Amorphous Steel.
------------------------------------------------------------------------
In the August 2021 Preliminary Analysis TSD, DOE requested comment
and data on the quality and differences between the various amorphous
steels on the market. (August 2021 Preliminary Analysis TSD at p. 2-31)
In response, Metglas commented that since amorphous steel was
introduced, the core loss and stacking factor of the product has
continually improved. (Metglas, No. 53 at pp. 2-3) Metglas stated that
the current stacking factors are between 88-90 percent, which allows
amorphous cores to be smaller than they have historically been.
(Metglas, No. 53 at pp. 2-3) Eaton commented that the hibam material
uses an 89 percent stacking factor and max flux of 1.40-1.42 tesla (T),
as compared to traditional amorphous material which uses 88 percent
stacking factor and a flux of 1.35-1.37 T. (Eaton, No. 55 at p.11) NEMA
commented that the stacking factor of amorphous steel will never be as
high as grain-oriented electrical steel. (NEMA, No. 50 at p. 8)
In the August 2021 Preliminary Analysis TSD, DOE noted that it did
not include any designs specifically using the high-permeability
amorphous steel. (August 2021 Preliminary Analysis TSD, at p. 2-45) DOE
stated while there are some design flexibility advantages associated
with using the high-permeability amorphous steel, it is only available
from a single supplier. Id. In interviews, manufacturers noted they
would be hesitant to rely on a single supplier of amorphous material
for any higher volume unit. Id. DOE further stated that high-
permeability amorphous steel can be integrated in manufacturer existing
amorphous designs with minimal changes and therefore, DOE's amorphous
designs represent efficiencies that can be met with any amorphous
steel. Id. DOE requested comment on its assumption that high-
permeability amorphous steel could be used in existing amorphous
designs with minimal changes. Id.
In response, Metglas commented that hibam can be used
interchangeably with the standard am designs. (Metglas, No. 53 at p. 4)
Metglas added that many transformers will maintain existing am design
and operate the hibam material at the lower induction levels during
[[Page 1755]]
initial conversion, however, once designs are optimized for the hibam
material, they cannot substitute standard am because standard am cannot
reach the higher induction levels. (Metglas, No. 53 at p. 4) Metglas
added that there is not a reduction in core losses when operating hibam
at the same induction levels as standard am. (Metglas, No. 53 at p. 4)
NEMA and Eaton commented that hibam does not necessarily have
higher efficiency than standard am at certain flux densities, and it is
not universally true that hibam could be used in place of standard am
without other design changes because at some flux densities, standard
am can have lower no-load losses. (Eaton, No. 55 at p. 12-13; NEMA, No.
50 at p. 10)
Stakeholder comments confirm DOE's assumption that hibam material
can be used in place of standard am designs, generally, although some
specific applications may require redesigning. As such, including only
standard am designs in the NOPR analysis is appropriate to avoid
setting efficiency standards based on a steel type, hibam, that is only
available from a single supplier. Under this approach, manufacturers
have the option to achieve efficiency levels that require am steel
using either the standard am material or the hibam material depending
on their sourcing practices and preferences.
In the August 2021 Preliminary Analysis TSD, DOE noted that it was
aware of a hibam material that uses domain refinement (``hibam-dr'') to
further reduce core losses but did not have sufficient data or details
as to whether it is commercially available. (August 2021 Preliminary
Analysis TSD, at p. 2-31) In response, Metglas commented that they have
introduced a mechanically domain refined hibam material that lowers
core losses by an additional 20-30 percent in a finished core at a
constant operating induction and there is a laser domain refined hibam
product in the Asian market that Metglas is working to bring online in
the domestic market. (Metglas, No. 53 at p. 3) Metglas commented that
hibam-dr allows manufacturers to increase operating induction, relative
to standard am, while reducing core losses by approximately 14 percent
relative to the standard am operating induction. (Metglas, No. 53 at p.
4)
DOE further investigated this product in manufacturer interviews
conducted for this NOPR analysis. In these interviews, DOE learned that
the hibam-dr product is not yet widely available commercially. DOE has
not included the hibam-dr product in its analysis because this product
has not been widely used in commercial applications at this point, DOE
has not been able to verify that the core loss reduction of this
product is maintained throughout the core production process, and it is
only produced by one supplier.
In the April 2013 Standard Final Rule, one concern DOE noted with
efficiency levels that would use amorphous steel was that there was
only one global supplier of amorphous steel. 78 FR 23336, 23383. In the
June 2019 Early Assessment RFI, DOE estimated global amorphous capacity
of 190,000 metric tons and noted that the capacity and number of
producers of amorphous steel has grown since the April 2013 Standards
Final Rule. 84 FR 28239, 28247
Metglas commented that it is the only current producer of amorphous
steel in the United States, however, there is current production in
Japan and China along with amorphous capacity in Germany and South
Korea. (Metglas, No. 11 at p. 2) Eaton pointed out that one barrier to
steel manufacturers producing amorphous is that it would
``cannibalize'' conventional electrical steel manufacturers existing
product offering and reduce the equipment utilization of existing
equipment. (Eaton, No. 12 at p. 6)
In the August 2021 Preliminary Analysis TSD, DOE noted that it had
identified numerous companies capable of producing amorphous material
(of standard am quality or better). DOE stated that it did not apply
any capacity constraints on the number of amorphous distribution
transformers that could be selected because amorphous capacity is much
greater than amorphous demand.
The Efficiency Advocates commented that the preliminary analysis
shows a transition to amorphous material is cost justified and would
bring U.S. standards in-line with other parts of the world. (Efficiency
Advocates, No. 52 at p. 1) The Efficiency Advocates added that if
amorphous core availability is a concern, DOE could require amorphous
cores for certain transformer types that offer large savings.
(Efficiency Advocates, No. 52 at p. 8)
Metglas estimated global amorphous capacity to be 150,000 metric
tons annually with domestic capacity of 45,000 metric tons and ready
ability to add another 75,000 metric tons within 18-24 months.
(Metglas, No. 53 at p. 3) Metglas commented that the high-permeability
amorphous grades (hibam) has been widely adopted by the North American
market, making up 80 percent of their production, and allows for higher
operating inductions which reduces amorphous core sizes. (Metglas, No.
53 at p. 3) NEMA commented that amorphous steel sourced from China is
more variable in its stacking factor and consistency. (NEMA, No. 50 at
p. 8)
Stakeholder comments verify that global amorphous capacity is much
greater than current demand and amorphous is produced by a variety of
sources, although the quality may not be as consistent from everybody.
Through manufacturer interviews, DOE learned that amorphous production
capacity increased in response to the April 2013 Standards Final Rule,
resulting in excess capacity because demand for amorphous steel did not
correspondingly increase. While amorphous capacity today is currently
less than the total distribution transformer total electrical steel
usage, amorphous producers' response to the April 2013 Standards Final
Rule demonstrates that if there was expected to be a market demand for
amorphous steel, capacity would increase to meet that demand.
In interviews, several manufacturers noted that recent increases in
prices, and foreign produced GOES prices, in particular, have led
amorphous to be far more cost competitive. However, the industry has
not necessarily seen an increase in amorphous transformer purchasing
reflective of this pricing situation. Manufacturers noted that many of
their processes are set-up to produce and process GOES steel and as
such there is some degree of bias against amorphous transformers,
regardless of what the first cost of a product is. In the August 2021
Preliminary Analysis TSD, DOE requested comment and data on the current
amorphous core making capacity and the cost and time frame to add
amorphous core production capacity. (August 2021 Preliminary Analysis
TSD at p. 2-33)
In response, Metglas estimated amorphous core making capacity to be
approximately 20,000 to 25,000 metric tons and noted that bringing on
additional amorphous core manufacturing is relatively straightforward
and inexpensive. (Metglas, No. 53 at p. 4) Metglas commented that there
are conversion costs and capital costs associated with producing an
amorphous core from amorphous steel laminations. (Metglas, No. 53 at p.
5) Eaton commented that the timeframe to add additional amorphous
transformer capacity is dependent on whether additional design
qualification testing is needed versus strictly capacity expansion and
estimated one years for the former and one year for the latter. (Eaton,
No. 55 at p. 11)
[[Page 1756]]
In the NOPR analysis, DOE has not applied any constraints to
standard am steel purchasing in its evaluation of higher efficiency
levels. DOE did constrain the selection of amorphous steel under the
no-new-standards scenario to better match the current market share of
amorphous distribution transformers, as discussed in section IV.F.2 of
this document. DOE notes that any conversion costs associated with a
transition from GOES production to amorphous distribution transformer
production would be accounted for in the manufacturer impact analysis
in section IV.J.
b. Grain-Oriented Electrical Steel Market and Technology
GOES is a type of electrical steel that is processed with tight
control over its crystal orientation such that its magnetic flux
density is increased in the direction of the grain-orientation. The
single-directional flow is well suited for distribution transformer
applications and GOES is the dominant technology in the manufacturing
of distribution transformer cores. GOES is produced in a variety of
thickness and with a variety of loss characteristics and magnetic
saturation levels. In certain cases, steel manufacturers may further
enhance the performance of electrical steel by introducing local strain
on the surface of the steel, through a process known as domain-
refinement, such that core losses are reduced. This can be done via
different methods, some of which survive the distribution transformer
core annealing process.
In the August 2021 Preliminary Analysis TSD, DOE identified four
sub-categories of GOES as possible technology options. (August 2021
Preliminary Analysis TSD at p. 2-35) These technology options and their
DOE naming short-hand are shown in Table IV.3.
Table IV.3--GOES Steel Technology Options
------------------------------------------------------------------------
DOE designator in design options Technology
------------------------------------------------------------------------
M-Grades.................................. Conventional (not high-
permeability) GOES.
hib....................................... High-Permeability GOES.
dr........................................ Non-Heat Proof, Laser Domain-
Refined, High-Permeability
GOES.
pdr....................................... Heat-Proof, Permanently
Domain-Refined, High-
Permeability GOES.
------------------------------------------------------------------------
DOE noted that for high-permeability steels, steel manufacturers
have largely adopted a naming convention that includes the steel's
thickness, a brand specific designator, followed by the guaranteed core
loss of that steel in W/kg at 1.7 Tesla (``T'') and 50 Hz. Power in the
U.S. is delivered at 60 Hz and the flux density can vary based on
distribution transformer design, therefore the core losses reported in
the steel name are not identical to their performance in the
distribution transformer. However, the naming convention is generally a
good indicator of the relative performance of different steels.
In the August 2021 Preliminary Analysis TSD, DOE identified several
grades of GOES as potential technology options for distribution
transformers. DOE requested comment and data on the availability of
those steels, the ability to substitute various GOES grades for one
another, any potential competition for steel supply for the large power
transformer market, and the costs for steelmakers to add or convert
capacity to higher performing GOES. (August 2021 Preliminary Analysis
TSD at pp. 2-36-37)
Regarding potential competition for steel supply with the large
power transformer industry, Schneider commented that power transformers
and medium-voltage distribution transformers tend to be prioritized
over the needs of the LVDT market and therefore supply issues can exist
if LVDT manufacturers need to purchase the same core steel as medium-
voltage distribution transformers. (Schneider, No. 49 at p. 14) Cliffs
added that while high-permeability GOES works well in distribution
transformers, it has historically been sold as a laser DR product to
the power transformer market. (Cliffs, No. 57 at p. 1)
Conversely, NEMA suggested that electrical steels used in the large
power transformer industry cannot be used in distribution applications,
stating that the packaging and coating of steels targeting the large
power transformer industry are not compatible with distribution
transformer designs but added that large power transformers do compete
for steel demand. (NEMA, No. 50 at p. 9)
Steel manufacturer literature generally markets GOES, and in
particular hib and dr GOES, as suitable for use in either power or
distribution transformers. Generally, a steel that is suitable for use
in a power transformer may be suitable for use in a distribution
transformer. As Schneider noted, and DOE confirmed in manufacturer
interviews, power transformers tend to have priority and get the
highest performing GOES. The industry also is volume driven and as
such, the larger volume of the liquid-immersed market tends to be
served before the dry-type distribution market.
Regarding availability of GOES more generally, NEMA recommended DOE
review the DOC study for perspective on steel availability. (NEMA, No.
50 at p. 8) NEMA and Powersmiths commented that recently there has been
a notable increase in competition from the auto industry for electrical
steel to produce electric motors in EVs. (NEMA, No. 50 at p. 9;
Powersmiths, No. 46 at p. 5) NEMA and Powersmiths stated that some
steel suppliers are shifting part of their grain-oriented electrical
steel production capacity to non-oriented electrical steel production--
limiting the availability and increasing prices of transformer-grade
steels. (NEMA, No. 50 at p. 9; Powersmiths, No. 46 at p. 5) At the
Public meeting, a representative from Carte commented that one major
foreign steel manufacturer transitioned 50 percent of their grain-
oriented production lines to non-oriented. (Zarnowski, Public Meeting
Transcript, No. 40 at p. 36) A representative from LakeView Metals,
commented that the non-oriented market is skyrocketing and there is an
estimated global shortfall of 13 silicon production lines. (Looby,
Public Meeting Transcript, No. 40 at p. 37)
Powersmiths commented they are currently experiencing diminished
availability of several grades of steel and increased costs as steel
suppliers are shifting to serving the EV market without plans to bring
transformer-grade steel capacity back. (Powersmiths, No. 46 at p. 5)
ERMCO agreed that supply of steel is currently limited and they have
been able to obtain M3 steel, some hib, and am steel. (ERMCO, No. 45 at
p. 1)
Recent supply issues and increases in costs are likely associated
with a combination of general commodity related supply chain issues and
competition from electric vehicles. DOE notes that variability in
electrical steel prices and supply is not new and historically, DOE
averages prices to come up with a representative value. As part of the
August 2021 Preliminary Analysis TSD, DOE did evaluate alternative
price scenarios. DOE has applied a 5-year average price in its base
case analysis and conducted sensitivities for various other pricing
scenarios, as discussed in section IV.C.3. DOE has also screened-out
some of the highest performing GOES, where steel manufacturers are not
able to mass produce GOES of similar quality, as discussed in section
IV.B.
NEMA previously noted that there is currently only one domestic
producer of GOES and that the sole domestic
[[Page 1757]]
producer does not have the capacity of high-grade electrical steel to
serve the entire U.S. market, meaning the U.S. would be dependent on
foreign electrical steel producers. (NEMA, No. 13 at p. 6-7)
Powersmiths commented that many of the high performing grades are
only available from overseas suppliers and recent shipping and port
access challenges have increased market uncertainty and availability to
those grades. (Powersmiths, No. 46 at p. 6) Powersmiths stated that
increased domestic capacity for GOES would require significant
investment from industry and take years to come on. (Powersmiths, No.
46 at p. 6) Cliffs added that high-permeability GOES is a unique
production line that would take years of planning, installation, and
commissioning to convert existing M3 lines to high-permeability.
(Cliffs, No. 57 at pp. 1-2) Cliffs stated that domestic steel is
currently well-suited to serve distribution applications and higher
standards would negatively impact the ability of domestic steel
manufacturers to serve the distribution transformer market. (Cliffs,
No. 57 at p. 2) Cliffs commented that higher efficiency levels would
drastically hurt M3, and correspondingly domestic manufacturing,
leaving the only domestic products as M2 and some high-permeability
GOES grades. (Cliffs, No. 57 at p. 1) Cliffs commented that its
electrical steel is produced with recycled steel scrap in an electric
arc furnace, making it some of the greenest steel in the world.
(Cliffs, No. 57 at p. 1)
DOE did constrain the selection of electrical steel under the no-
new-standards scenario to better match the current market share of
electrical steel, as discussed in section IV.F.2. In its evaluation of
future standards, DOE assumed that steel manufacturers would provide
the electrical steel qualities required by the market. In cases where
fewer steel suppliers offer a grade of GOES, this is reflected by
higher prices in DOE's analysis.
6. Distribution Transformer Production Market Dynamics
Distribution transformer manufacturers either make or buy
transformer cores; some do both. Further, distribution transformer
manufacturers may choose to produce transformers domestically or
produce them in a foreign country and import them to the United States.
This creates three unique pathways for producing distribution
transformers: (1) producing both the distribution transformer core and
finished transformer domestically; (2) producing the distribution
transformer core and finished transformer in a foreign country and
importing into the United States; (3) purchasing distribution
transformer cores and producing only the finished transformer
domestically. Each of these pathways has unique advantages and
disadvantages which manufacturers have employed to maintain a
competitive position.
First, manufacturers who produce distribution transformer cores and
finished transformers domestically are able to maintain greater control
of their lead times, potentially offering shorter lead times to their
customers. This is particularly advantageous in servicing emergency
applications with unique characteristics. This manufacturing approach
is more common in certain liquid-immersed and medium-voltage dry-type
applications, where customers may have unique voltage specifications
that may not be routinely produced by all manufacturers but may be
required on short notice.
As discussed, however, there is currently only one domestic
manufacturer of grain-oriented electrical steel and one domestic
manufacturer of amorphous steel. Under the current market dynamics with
tariffs applied to all, raw imported electrical steel, these
manufacturers are limited in where they can source their raw steel. As
such, they may not have access to all of the types of steels available
in the global market and may have different material prices from
foreign core producers. While in theory, these manufacturers have the
option to purchase electrical steel from foreign producers, they would
be subject to the 25-percent tariff. Similarly, in theory, they have
the option to purchase either grain-oriented electrical steel or
amorphous electrical steel domestically.
DOE assumes that in the presence of amended standards, those
manufacturers currently producing both cores and finished transformers
domestically would still value the advantages of in-house domestic core
production and would change their in-house production processes to
accommodate the required core production equipment or required
electrical steel grades.
Second, for manufacturers producing both the distribution
transformer core and finished transformer in a foreign country and
importing into the United States, they are able to control the in-house
core production and therefore have similar advantages to those
producing cores domestically. Further, because finished transformer
imports are not currently subject to tariffs, they have access to the
entire global market of electrical steel types and prices without the
additional 25 percent tariff. However, these manufacturers may require
increased management of electrical steel supply chains, as they are
often purchasing electrical steel from overseas producers which may
have longer lead times than sourcing electrical steel from domestic
sources.
Similar to domestic manufacturers, DOE assumes that in the presence
of amended standards, those manufacturers producing both cores and
transformers outside the United States would still value the advantages
of in-house core production and would change their in-house production
processes to accommodate the required core production equipment or
required electrical steel grades.
Third, manufacturers who purchase cores to manufacture distribution
transformers are able to avoid the labor and capital equipment
associated with producing transformer cores. In part for this reason,
it is increasingly common among small businesses. Further, because
distribution transformer cores are not subject to tariffs, purchasing
cores also allows manufacturers to more easily transition between
various steel grades and various steel suppliers, both international
and domestic. Similarly, it is easier for manufacturers who outsource
cores to transition between GOES and amorphous steel grades since it
eliminates the need to use different core production equipment for each
steel type as the process of converting a core into a transformer is
relatively similar for both GOES and amorphous steels.
The primary disadvantages of outsourcing cores are that (1)
transformer manufacturers may have less control over core, and
therefore transformer, delivery lead times and (2) transformer
manufacturers will pay a higher cost per pound of steel because they
are purchasing partially processed products as compared to
manufacturers who are producing their own cores.
DOE assumes that in the presence of amended standards, these
manufacturers would switch from purchasing one grade of electrical
steel core to a higher grade of electrical steel core.
In summary, DOE does not view any one of these core and transformer
production pathways as necessarily becoming more advantaged or
disadvantaged in light of the standards proposed in this notice
relative to the present. In the current market, all three pathways act
as viable options for manufacturers to find and maintain a competitive
position. DOE does not
[[Page 1758]]
have a reason to believe that the proposed standards would alter the
ways in which distribution transformer manufacturers approach
manufacturing or their current sourcing decisions given all three
productions options continue to be available. DOE seeks comment on the
distribution transformer market and whether the standards proposed will
alter the current production pathways.
B. Screening Analysis
DOE uses the following five screening criteria to determine which
technology options are suitable for further consideration in an energy
conservation standards rulemaking:
(1) Technological feasibility. Technologies that are not
incorporated in commercial products or in working prototypes will not
be considered further.
(2) Practicability to manufacture, install, and service. If it is
determined that mass production and reliable installation and servicing
of a technology in commercial products could not be achieved on the
scale necessary to serve the relevant market at the time of the
projected compliance date of the standard, then that technology will
not be considered further.
(3) Impacts on product utility or product availability. If it is
determined that a technology would have a significant adverse impact on
the utility of the product for significant subgroups of consumers or
would result in the unavailability of any covered product type with
performance characteristics (including reliability), features, sizes,
capacities, and volumes that are substantially the same as products
generally available in the United States at the time, it will not be
considered further.
(4) Adverse impacts on health or safety. If it is determined that a
technology would have significant adverse impacts on health or safety,
it will not be considered further.
(5) Unique-Pathway Proprietary Technologies. If a design option
utilizes proprietary technology that represents a unique pathway to
achieving a given efficiency level, that technology will not be
considered further due to the potential for monopolistic concerns.
10 CFR 431.4; 10 CFR part 430, subpart C, appendix A, sections 6(b)(3)
and 7(b) (``Process Rule'').
In summary, if DOE determines that a technology, or a combination
of technologies, fails to meet one or more of the listed five criteria,
it will be excluded from further consideration in the engineering
analysis. The reasons for eliminating any technology are discussed in
the following sections.
The subsequent sections include comments from interested parties
pertinent to the screening criteria, DOE's evaluation of each
technology option against the screening analysis criteria, and whether
DOE determined that a technology option should be excluded (``screened
out'') based on the screening criteria.
1. Screened-Out Technologies
In the August 2021 Preliminary Analysis TSD, DOE identified core
deactivation as a potential technology option to improve efficiency but
noted that it was not a generally accepted practice and would be
associated with system wide savings, not savings as measured by DOE's
test procedure.
In response, NEMA commented that core deactivation would only be
beneficial in certain settings and there are questions of reliability
associated with shifting load which could lead to shorter lifetimes.
(NEMA, No. 50 at p. 7) NEEA commented that core deactivation may impact
maintenance of switchgear and other connected equipment. (NEEA, No. 51
at p. 5)
Due to the concerns cited by NEMA and NEEA regarding impacts on
product lifetime and servicing of equipment, along with the fact that
core deactivation would not impact the efficiency as measured by the
DOE test procedure, DOE has screened-out core deactivation as a
potential technology option.
DOE also identified less-flammable insulating liquid-immersed
distribution transformer (``LFLI'') as a potential technology by which
manufacturers could increase the capacity of a distribution transformer
without increasing the size, potentially leading to energy savings. In
response, NEMA commented that while LFLI is used by some customers to
reduce unit size, particularly for pad mounts but rarely for pole
mounts, it is generally pursued for greater reliability and not greater
efficiency. (NEMA, No. 50 at pp. 7-8)
DOE notes that while there may be opportunity for a customer to
maintain distribution transformer lifespan while increasing the loading
on a transformer with LFLI technology, this would not impact the
efficiency as measured by DOE's test procedure. Further, DOE
understands that there are potential consumer safety concerns with
distribution transformers operating notably hotter, namely that the
touch temperature could be too high for consumers to safely interact
with. Therefore, DOE has screened out LFLI as a potential technology
option.
Regarding evaluating efficiency improvements associated with
certain high-performing GOES grades, Powersmiths commented that the
stability of availability, cost, and batch quality of some new steel
grades is unproven. (Powersmiths, No. 46 at p. 5) Schneider expanded
that steel mills are not perfectly consistent and only a portion of
their production may meet a target loss performance. As such, it may
not be feasible to set efficiency levels based on premium grades, for
example an 075 or 070 grade steel, as steel manufacturers may not be
able to consistently achieve the premium performance. (Schneider, No.
49 at p. 14) Schneider added that some higher performance steels are
published in steel maker catalogs but are not widely available for
commercial use. (Schneider, No. 49 at p. 13)
In GOES production, the product steel losses can vary somewhat
between and within batches. Because of this variability in electrical
steel, producers typically offer two loss specifications for their
steels, a guaranteed core loss and a typical core loss. While some of
the premium products identified in the August 2021 Preliminary Analysis
TSD generally exist and are used in the market, they represent the
upper end of the distribution of product performance. As commenters
suggested, without further improvements in consistency of batch
quality, it may not be reasonable to assume these products could be
widely used in industry. Therefore, DOE has screened out certain high-
performing GOES products. Specifically, DOE removed 23pdr075 and
20dr070 electrical steels from its engineering modeling due to concerns
with its practicability to manufacture. DOE notes that these electrical
steels could be used in certain applications but DOE has screened them
out because of concerns that mass production of these products could
not be achieved on the scale necessary to serve the distribution
transformer market.
DOE listed several other technology options in the August 2021
Preliminary Analysis TSD for which it did not receive any comment. As
such, DOE has retained those technology options as screened out.
Technology options screened out are listed in Table IV.4 with their
bases for screening.
[[Page 1759]]
Table IV.4--Screened-Out Technologies
------------------------------------------------------------------------
Technology option Basis for screening
------------------------------------------------------------------------
Core Deactivation................. Practicability to manufacture,
install, and service; Adverse
Impacts on Product Utility or
Product Availability.
Less-Flammable Insulating Liquids. Adverse Impacts on Health or Safety.
Symmetric Core Design............. Practicability to manufacture,
install, and service.
23pdr075 and 23dr070 GOES Steel... Practicability to manufacture,
install, and service.
Silver as a Conductor Material.... Practicability to manufacture,
install, and service.
High-Temperature Superconductors.. Technological feasibility;
Practicability to manufacture,
install and service.
Amorphous Core Material in Stacked Technological feasibility;
Core Configuration. Practicability to manufacture,
install, and service.
Carbon Composite Materials for Technological feasibility.
Heat Removal.
High-Temperature Insulating Technological feasibility.
Material.
Solid-State (Power Electronics) Technological feasibility;
Technology. Practicability to manufacture,
install, and service.
Nanotechnology Composites......... Technological feasibility.
------------------------------------------------------------------------
2. Remaining Technologies
Through a review of each technology, DOE tentatively concludes that
the remaining combinations of core steels, windings materials and core
configurations as combinations of ``design options'' for improving
distribution transformer efficiency met all five screening criteria to
be examined further as design options in DOE's NOPR analysis.
DOE has initially determined that these technology options are
technologically feasible because they are being used or have previously
been used in commercially-available products or working prototypes. DOE
also finds that all of the remaining technology options meet the other
screening criteria (i.e., practicable to manufacture, install, and
service and do not result in adverse impacts on consumer utility,
product availability, health, or safety, unique-pathway proprietary
technologies). For additional details, see chapter 4 of the NOPR TSD.
C. Engineering Analysis
The purpose of the engineering analysis is to establish the
relationship between the efficiency and cost of distribution
transformers. There are two elements to consider in the engineering
analysis; the selection of efficiency levels to analyze (i.e., the
``efficiency analysis'') and the determination of product cost at each
efficiency level (i.e., the ``cost analysis''). In determining the
performance of higher-efficiency equipment, DOE considers technologies
and design option combinations not eliminated by the screening
analysis. For each equipment class, DOE estimates the baseline cost, as
well as the incremental cost for the equipment at efficiency levels
above the baseline. The output of the engineering analysis is a set of
cost-efficiency ``curves'' that are used in downstream analyses (i.e.,
the LCC and PBP analyses and the NIA).
1. Representative Units
Distribution transformers are divided into different equipment
classes, categorized by the physical characteristics that affect
equipment efficiency. DOE's current energy conservation standards at 10
CFR 431.196 divide distribution transformers based on the following
characteristics: (1) capacity (kVA rating), (2) voltage rating, (3)
phase count, (4) insulation category (e.g., ``liquid-immersed''), and
(5) BIL rating.
Because it is impractical to conduct detailed engineering analysis
at every kVA rating, DOE conducts detailed modeling on ``representative
units'' (``RUs''). These RUs are selected both to represent the more
common designs found in the market and to include a variety of design
specification to enable generalization of the results. In the August
2021 Preliminary TSD, DOE presented 14 representative units and noted
they were unchanged from the April 2013 Standards Final Rule. (August
2021 Preliminary TSD at p. 2-41)
In response to the August 2021 Preliminary TSD, Howard commented
that RU3 is not a very good representative unit because it is not
common and should be replaced with a more common unit. (Howard, No. 59
at p. 2) DOE agrees that RU3, corresponding to a 500 kVA, single-phase,
liquid-immersed distribution transformer, is generally larger than the
more common capacities included in equipment class 1. However, as
noted, DOE's RUs are designed to include both common units and units
included to improve generalization. RU3 is included to improve scaling
of results to the larger units within the scope of equipment class 1.
Therefore, RU3 has been retained in this NOPR.
Carte commented that the representative units used by DOE are
representative of common/typical sizes but the extremes were not
analyzed, where meeting efficiency standards tend to be the hardest.
(Carte, No. 54 at p. 1) Carte added that certain designs are forced to
use high-end grain-oriented electrical steel and copper windings or in
certain cases are unable to be met by Carte. (Carte, No. 54 at p. 1)
Eaton commented that the representative units are good choices for
the highest volume transformers, however, as efficiency standards
increase, efficiency standards may not be achievable at the scope
extremes. (Eaton, No. 55 at p. 12)
It is true that certain extreme designs may have more difficulty
achieving efficiency standards while still being requested by
consumers. Most applications would generally be able to use amorphous
steel to achieve higher efficiencies, including at efficiency levels
beyond DOE's max-tech. DOE selected design units to include both large
and small distribution transformers across the various representative
units and DOE's modeling of the selected representative units includes
amorphous designs which achieve efficiencies above DOE's max-tech for
all RUs. This indicates that there is room for even extreme designs to
meet efficiency standards using technologies modeled by DOE.
DOE requests data demonstrating any specific distribution
transformer designs that would have significantly different cost-
efficiency curves than those representative units modeled by DOE.
To assess the impact of expanding the scope of the definition of
``distribution transformer'' in 10 CFR 431.192 to include distribution
transformers up to 5,000 kVA, DOE is evaluating three new
[[Page 1760]]
RUs. DOE scaled the results for RU5, RU12, and RU14 to represent RU17,
RU18, and RU19, respectively, each of which are rated at 3,750 kVA.
Results were generated for RU17, RU18, and RU19 using the scaling rules
for dimensions, transformer weight, no-load losses, load losses, etc.,
as described in Appendix 5C of the TSD.
DOE notes that it only includes distribution transformers in the
downstream analysis that would meet or exceed current energy
conservation standards. Because RU17, RU18, and RU19 represent an
expansion in scope, they are not currently subject to energy
conservation standards. As such, all modeled designs are included in
the downstream analysis, regardless of efficiency and DOE relies on the
consumer choice model to determine the efficiency of distribution
transformers selected at baseline. DOE has described these results and
shown the cost-efficiency curves for these scaled units in Chapter 5 of
the TSD.
DOE requests comment on its methodology for scaling RU5, RU12, and
RU14 to represent the efficiency of units above 3,750 kVA.
Distribution transformers designed for submersible applications may
be disadvantaged in meeting efficiency standards on account of having
to meet efficiency standards with reduced cooling ratings. To explore
this specification limitation, DOE has proposed a definition for
submersible distribution transformers. In this NOPR, DOE is evaluating
those submersible distribution transformers as a separate equipment
class. DOE has modified the engineering results for RU4 and RU5 to
represent two new RUs, RU15 and RU16. RU15 and RU16 represent common
three-phase submersible distribution transformers. To account for the
thermal derating that is associated with submersible distribution
transformers, DOE evaluated RU15 and RU16 as having their nameplates
derated by one standard kVA size relative to the efficiency of RU4 and
RU5. That is, while RU4 is a 150 kVA three-phase, liquid-immersed
distribution transformer, RU15 is a 112.5 kVA three-phase, liquid-
immersed, submersible distribution transformer. Similarly, while RU5 is
a 1,500 kVA three-phase, liquid-immersed distribution transformer, RU16
is a 1,000 kVA three-phase, liquid-immersed distribution transformer.
DOE calculated the efficiency of RU15 and RU16 based on their new
nameplate and assuming no-load losses are the same and load losses
scale with the quadratic of load. DOE also modified the cost of the
tank material from carbon steel to stainless steel to represent the
corrosion resistant properties of submersible distribution
transformers. All other physical properties of the distribution
transformer are the same.
DOE requests comment on its methodology for modifying the results
of RU4 and RU5 to represent the efficiency of submersible liquid-
immersed units. For other potentially disadvantaged designs, DOE has
considered establishing equipment classes to separate out those that
would have the most difficulty achieving amended efficiency standards,
as discussed in section IV.A.2, but ultimately has determined not to
include such separate equipment classes in the proposed standards.
However, DOE requests data as to the degree of reduction in efficiency
associated with various features.
2. Efficiency Analysis
DOE typically uses one of two approaches to develop energy
efficiency levels for the engineering analysis: (1) relying on observed
efficiency levels in the market (i.e., the efficiency-level approach),
or (2) determining the incremental efficiency improvements associated
with incorporating specific design options to a baseline model (i.e.,
the design-option approach). Using the efficiency-level approach, the
efficiency levels established for the analysis are determined based on
the market distribution of existing products (in other words, based on
the range of efficiencies and efficiency level ``clusters'' that
already exist on the market). Using the design option approach, the
efficiency levels established for the analysis are determined through
detailed engineering calculations and/or computer simulations of the
efficiency improvements from implementing specific design options that
have been identified in the technology assessment. DOE may also rely on
a combination of these two approaches. For example, the efficiency-
level approach (based on actual products on the market) may be extended
using the design option approach to ``gap fill'' levels (to bridge
large gaps between other identified efficiency levels) and/or to
extrapolate to the max-tech level (particularly in cases where the max-
tech level exceeds the maximum efficiency level currently available on
the market).
Howard commented that there were inconsistencies in the efficiency
levels presented in the webinar and the August 2021 Preliminary
Analysis TSD. (Howard, No. 59 at p. 2) DOE notes that corrected values
are presented in this analysis.
In this rulemaking, DOE relies on an incremental efficiency
(design-option) approach. This approach allows DOE to investigate the
wide range of design option combinations, including varying the
quantity of materials, the core steel material, primary winding
material, secondary winding material, and core manufacturing technique.
For each representative unit analyzed, DOE generated hundreds of
unique designs by contracting with Optimized Program Services, Inc.
(``OPS''), a software company specializing in distribution transformer
design. The OPS software used two primary inputs: (1) a design option
combination, which includes core steel grade, primary and secondary
conductor material, and core configuration, and (2) a loss valuation.
DOE examined numerous design option combinations for each
representative unit. The OPS software generated 518 designs for each
design option combination based on unique loss valuation combinations.
Taking the loss value combinations, known in the industry as A and B
values and representing the commercial consumer's present value of
future no-load and load losses in a distribution transformer,
respectively, the OPS software sought to generate the minimum total
ownership cost (``TOC''). TOC can be calculated using the equation
below.
TOC = Transformer Purchase Price + A * [No Load Losses] + B * [Load
Losses]
From the OPS software, DOE received thousands of different
distribution transformer designs, including physical characteristics,
loading and loss behavior, and bill of materials. DOE used these
distribution transformer designs, supplemented with confidential and
public manufacturer data, to create a manufacturer selling price
(``MSP''). The MSP was generated by applying material costs, labor
estimates, and various mark-ups to each design given from OPS.
The engineering result included hundreds of unique distribution
transformer designs, spanning a range of efficiencies and MSPs. DOE
used this data as the cost versus efficiency relationship for each
representative unit. DOE then extrapolated this relationship, generated
for each representative unit, to all the other, unanalyzed, kVA ratings
within that same equipment class.
In the August 2021 Preliminary Analysis TSD, DOE stated that it
maintained the existing designs from the previous rulemaking and
updated the material prices to get an updated manufacturer selling
price. (August
[[Page 1761]]
2021 Preliminary Analysis TSD, at p. 2-45)
Howard commented that while updating pricing to $2020 still gives
valid designs, reoptimizing with new pricing would have given more
accurate results. (Howard, No. 59 at p. 2)
DOE agrees that the most accurate results would be achieved by
reoptimizing designs under current market practices. However, as
commenters have attested, prices for many of the components making up
distribution transformers are varied. Further, manufacturers may make
different optimization decisions depending on their unique supply
chains and manufacturing capacities. It would be impractical for DOE to
reoptimize all designs with every change in material prices and to
represent the specific supply chains of each manufacturer. To account
for the variability in designs, DOE relies on a wide range of A and B
values to initially develop designs reflective of the whole design
space, not specific to any given day's pricing. DOE relies on 5-year
average material pricing in its base analysis and conducts additional
sensitivities to encompass additional pricing scenarios. Further, DOE's
analysis of various efficiency levels includes a consumer choice model
that selects a sub-set of designs based on the minimum MSP within a
band-of-equivalence for a given efficiency level. As such, DOE's
efficiency levels are not reflective of any one distribution
transformer, but rather are designed to reflect the variety of
distribution transformers customers would purchase at a given
efficiency level.
In the August 2021 Preliminary Analysis TSD, DOE noted that it
adapted models of grain-oriented electrical steel to reflect some of
the lower loss steels that have come onto the market since the previous
rulemaking. Specifically, DOE stated that it estimated the core loss of
a similar design by multiplying the no-load loss by the ratio of the
core losses at a given flux density between two steels. DOE noted that
while these designs would not be true optimal designs, given that lower
loss steel allows more flexibility in the load losses, however, stated
that because DOE's designs cover such a wide range of A and B values,
the results would be sufficiently accurate. DOE requested feedback on
this approach. (August 2021 Preliminary Analysis TSD at p. 2-46)
Schneider commented that assuming the core losses of a swapped
steel may be accurate for small reductions in core loss but bigger
jumps could result in full redesigns. (Schneider, No. 49 at pp. 14-15)
Powersmiths and ERMCO commented that this approach does not lead to
optimized designs. (Powersmiths, No. 46 at p. 4; ERMCO, No. 45 at p. 1)
NEMA commented that it is an oversimplification to assume that
substituting of lower loss steel will lead to improved efficiency for a
given design. (NEMA, No. 50 at p. 10) NEEA commented that DOE should
not use this approach because new material may have different B-H
curves and while it may be possible to use a direct swap--it generally
isn't an acceptable practice. (NEEA, No. 51 at pp. 5-6) The Efficiency
Advocates recommended DOE conduct new modeling as manufacturers who
didn't optimize for new material would be at a competitive
disadvantage. (Efficiency Advocates, No. 52 at pp. 6-7)
In response to stakeholder feedback, DOE ran new modeling for some
design option combinations included in the NOPR. DOE compared this new
modeling to its models that were established by swapping core steels
and has presented some of these comparisons in chapter 5 of the TSD.
DOE notes that modeled designs may be slightly different at a given A
and B value as compared to the direct swap of core steels. However,
across the range of A and B values included in the engineering
analysis, and specifically at the minimum MSP for a given efficiency,
the cost-efficiency curves are very similar. While DOE intends to
update all the engineering designs to newly modeled designs to instill
greater confidence in the analysis, some core steel swap designs are
still used in the NOPR in order to ensure quick publication of the
NOPR. These designs are noted in chapter 5 of the TSD. Given the
similarities between the modeled designs and the direct swap of steel
designs, DOE believes the updated modeling will not notably impact
analysis results.
a. Design Option Combinations
As discussed, for each representative unit, DOE evaluates various
design option combinations, which includes combinations of electrical
steel, conductor material, and core construction techniques. In the
August 2021 Preliminary Analysis TSD, DOE presented the various design
option combinations it used for each representative unit. DOE noted
that distributed gap wound cores typically need a high-temperature
annealing process to relieve some of the stresses associated with the
core winding process. (August 2021 Preliminary Analysis TSD at p. 2-46)
As a result of this annealing, laser-scribed domain-refined steels lose
the core loss benefit of the domain-refinement. As such, DOE did not
include any laser-scribed domain-refined steels in distributed gap
wound core design option combinations. DOE requested comment on this
decision.
In response, NEMA and Schneider supported DOE's decision not to
include laser DR products in wound core constructions. (Schneider, No.
49 at p. 15; NEMA, No. 50 at p. 11) Similarly, Eaton agreed with DOE's
decision not to include laser-scribed domain-refined steels in wound
cores but noted that larger, three-phase units may be able to use
laser-scribed domain-refined steels in wound cores if an AEM Unicore
machine is used and the products are not annealed. (Eaton, No. 55 at p.
13)
DOE agrees with Eaton that in certain scenarios it may be possible
to use laser-scribed dr products in wound core. But as Eaton described,
the dr characteristics are only maintained if the core is not annealed.
An unannealed core is going to have greater losses associated with the
stresses from the bending of the electrical steel. So, the loss
reduction associated with the better performing laser dr product is
going to be countered by increased losses associated with stresses from
bending the steel without annealing. As such, this approach does not
necessarily reflect a higher efficiency product, but rather a similar
performing product to using hib steel without domain-refinement and
annealing the core. DOE did not receive any opposition to its decision
to not include laser-scribed dr steels in its wound core designs and
therefore maintained that approach in the NOPR analysis.
Regarding some of the specific design option combinations presented
in the August 2021 Preliminary Analysis TSD, NEMA commented that GOES
with performance lower than M4 is not used due to performance
limitations. (NEMA, No. 50 at p. 8) Eaton commented that M5 isn't
really used anymore and can be removed from RU4 engineering plots.
Eaton also commented that M4 isn't really used in RU5 designs and can
be removed from DOE's engineering plots. (Eaton, No. 55 at p. 20) Eaton
commented that an Evans core transformer is not a valid option for wye-
wye distribution transformers but noted that it was a moot point since
the costs are greater. (Eaton, No. 55 at p. 20)
DOE acknowledges that some designs would be unlikely to be
considered by many purchasers, but the engineering analysis is designed
to explore the whole design space. The specific combinations identified
by NEMA and
[[Page 1762]]
Eaton generally do not impact the analysis due to the first-cost of the
product being too high and are included for completeness of the
analysis.
Regarding use of thinner steels, NEMA commented that thinner GOES
is more difficult to use, but not overly burdensome, whereas amorphous
is a different thickness and width and cannot be dropped in. (NEMA, No.
50 at p. 9) Cliffs added that while there are specific applications
where M2 is suitable, nearly all EOMS have stated it is not amenable to
their manufacturing processes as it is thin and prone to folding and
tearing in core making equipment. (Cliffs, No. 57 at p. 1)
DOE includes additional costs associated with handling of thinner
electrical steels, as described in chapter 5 of the TSD. While M2 is
included in the analysis, DOE has limited its selection in the base
case scenario as described in section IV.F.3.a to be reflective of its
current market share. In the presence of higher standards, M2 steel (or
similarly performing hib steel that wasn't modeled but has similar
performance may be an option), may be a feasible design option for
manufacturers although, it may not be the lowest first cost option.
Regarding the burdens with using amorphous steel, DOE has
considered those costs in the manufacturer impact analysis in section
IV.J of this document.
Eaton noted that while DOE's designs span the current definition
for normal impedance range, if new designs are run in the future, a
narrower impedance range should be used for RU4 and RU5 to align with
IEEE C57.12.34, as too low an impedance could permit extremely high
fault current in the event of a short circuit. (Eaton, No. 55 at p. 16)
As Eaton noted, DOE's impedance ranges align with the current
definition for normal impedance range. The narrower impedance range
cited by Eaton are achievable in DOE's models by all efficiency levels.
DOE believes aligning with the definition of normal impedance range
remains appropriate given that a variety of impedances are included at
each efficiency level and consumers may specify specific impedances.
b. Data Validation
In the August 2021 Preliminary Analysis TSD, DOE stated that it had
collected publicly available bid data for a variety of distribution
transformers. DOE noted that the data was limited in its ability to
compare cost and efficiency because the data was limited to liquid-
immersed distribution transformers, there was significant variability
in primary voltages, the data didn't span the whole design space in all
cases, much of the data was prior to implementation of the energy
conservation standards as amended in the April 2013 Standards Final
Rule (Effective January 1, 2016), and there was significant price
variability at every efficiency. (August 2021 Preliminary Analysis TSD
at p. 2-45) Rather than drawing any conclusions from this data, DOE
relied on the reported no-load loss and full-load loss to estimate
efficiency. DOE then presented the raw material prices and attempted to
correct the material prices to show.
The Efficiency Advocates commented that the bid data shows
significant differences in MSP and indicates that the engineering
analysis need to be updated to reflect up-to-date materials, costs, and
designs. (Efficiency Advocates, No. 52 at p. 7) Eaton commented that
the average selling price in the plots comparing bid data and DOE
engineering show average selling prices being much higher than DOE's
analysis suggests. (Eaton, No. 55 at p. 22)
DOE is uncertain what significant difference in MSP the
stakeholders are referring to as there is a wide range in the bid data
and many of the points overlap between the bid data and DOE designs.
Regardless, DOE has updated material costs in the NOPR analysis.
In presenting the bid data, DOE noted that it only has full load
efficiency at rated operating temperature, and therefore applied a
quadratic scaling and estimated temperature correction to estimate the
efficiency as measured according to DOE's test procedure.\49\
---------------------------------------------------------------------------
\49\ See Chapter 5 of the NOPR TSD, available online at
www.regulations.gov/document/EERE-2019-BT-STD-0018-0022.
---------------------------------------------------------------------------
Eaton commented that DOE's estimate for correcting the load loss in
the bid data is insufficient. (Eaton, No. 55 at p. 20) Eaton expressed
concern that a similar method was used to calculate DOE's 50 percent
load loss values from the 100 percent load loss values. (Eaton, No. 55
at p. 20)
DOE did not use the same method to calculate 50 percent load loss
values from the 100 percent values in it modeled data, it only did this
in the bid data because the bid data did not have specifics as to how
the equipment temperature varies with load and temperature correction
was simply to estimate efficiency for a general comparison. DOE's
modeled data included estimated load performance and temperature at a
variety of transformer load points. DOE relied on the modeled
transformer load loss at 50 percent load and corrected from the modeled
operating temperature to DOE's reference temperature.
Rather than trying to estimate the rated efficiency of the public
utility bid data from full load losses at rated temperature rises and
make generalization as to how temperature would influence efficiency at
rated PUL, DOE has looked at how the no-load and full load losses of
the bid data compare to the full load losses of the DOE modeled data.
These comparisons are shown in chapter 5 of the TSD. The comparisons
show that DOE's modeled data aligns well with the design space of the
public utility bid data.
In comparing DOE's modeled results to the public utility bid data,
DOE realized that for RU4 and RU5, DOE models overestimated GOES no-
load losses, and accordingly assumed manufacturers would need lower
load losses in order to meet efficiency standards.
The process of converting electrical steel from a sheet into a
formed core shape incurs some number of additional losses, known as a
destruction factor. Eaton commented that when comparing amorphous
laminations to a finished core, the destruction factor can be non-
trivial and contribute an additional 40 percent to the core losses.
(Eaton, No. 55 at p. 11) Similarly, in GOES cores, the destruction
factor can be significant and varies by transformer type, manufacturing
technique, and electrical steel type. In general, destruction factors
are much more significant for three-phase distribution transformers
than single-phase distribution transformers.
The destruction factor for three-phase wound core designs was
originally chosen to be conservative and assume manufacturers would
have higher destruction factors. Through interviews, DOE learned that
manufacturers may be able to reduce destruction factors in wound cores
using a Unicore design, and this is more common in larger, three-phase
designs which tend to be produced in lesser volumes. In the NOPR
analysis, DOE modified the destruction factor of three-phase, liquid-
immersed, wound core, GOES distribution transformers to better align
with the marketed Unicore destruction factors.\50\ The resulting
designs better align with the actual design space observed in real
world data, as shown in chapter 5 of the TSD. The impact of this change
is that GOES transformers achieve higher efficiency ratings for RU4 and
RU5 than the August 2021
[[Page 1763]]
Preliminary Analysis TSD suggested. It also introduces new transformers
to the selectable design space which may have a lower MSP than if DOE
had not made this change. While destruction factor does vary by
manufacturing technique and manufactures may use different methods, DOE
believes that absent this change, it would be overestimating the cost
of meeting efficiency standards with a GOES core as compared to an
amorphous core.
---------------------------------------------------------------------------
\50\ Advertised destruction factors for Unicore available at
www.aemcores.com.au/technology/annealing/overview-and-the-benefit-
of-unicore/.
---------------------------------------------------------------------------
Regarding DOE's use of modeling software, Powersmiths commented
that OPS software is used by them and many manufacturers but noted that
the eddy and stray losses in OPS models are ``guestimates'' from the
design engineer and can vary largely. (Powersmiths, No. 46 at pp. 4-5)
Powersmiths commented that inadequate stray loss estimates could result
in simulation errors and should be examined more closely relative to
transformer capacity. (Powersmiths, No. 46 at p. 5)
NEMA commented that its members' modeling programs account for
stray, eddy, and other losses that appear largely absent from DOE
models and while this was noted in the April 2013 Standards Final Rule,
the efficiency levels in the preliminary analysis leave little
flexibility to meet efficiency standards, making it more important now.
(NEMA, No. 50 at p. 2) NEMA added by omitting these design factors,
DOE's models do not represent true design feasibility and DOE should
update models to add these losses. (NEMA, No. 50 at p. 2) NEMA
commented specifically that in applications with a large amount of buss
bars are required, efficiency standards are more difficult to meet.
(NEMA, No. 50 at p. 5)
DOE transformer models do include estimates of stray and eddy
losses. As commenters noted, the amount that these impact designs will
be unique to manufacturer and specific transformer designs. In DOE's
comparison of its liquid immersed designs to the design space in public
utility bid data, DOE notes that its designs align relatively well with
what is being built on the market. Further, DOE includes a bus and lead
correction factor to MVDT designs based on an understanding that
substation-style designs are quite common in the MVDT market.
DOE requests data as to how stray and eddy losses at rated PUL vary
with kVA and rated voltages.
While certain unique designs may have higher stray and eddy losses,
the incremental costs with meeting higher efficiency standards tends to
follow a similar relationship. Particularly to the extent that amended
efficiency standards are met via a transition to lower-loss GOES or
amorphous steel, the incremental cost to meet higher efficiency
standards tends to be similar. In bid data, DOE observed that higher
current transformers, which are more likely to have high stray losses,
often have more amorphous bids. This suggests that transformers with
high buss losses may have more favorable economics associated with
meeting amended efficiency standards via amorphous steel.
Regarding validation of DOE's engineering analysis more generally,
NEMA commented that its members cannot validate and offer corrections
for every RU but suggested DOE hold a series of collaborative meetings
where models are made more accurate and representative. (NEMA, No. 50
at p. 2) Eaton requested DOE provide more information about the
distribution transformer design so manufacturers can confirm the
designs align with their modeling. (Eaton, No. 55 at p. 20-22)
DOE has included additional engineering details in chapter 5 of the
TSD to better explain its modeling and costing. Regarding NEMA's
suggestion to hold collaborative meetings, DOE notes that in addition
to soliciting public comment in a written format and public interviews,
DOE conducts confidential manufacturer interviews through which
manufacturers are invited to offer feedback. DOE has in the past, and
as part of this analysis, made updates to its modeling to better
reflect manufacturer realities. DOE will continue to update its
analysis in response to manufacturer feedback and particularly to the
extent modeling deviates from real world design constraints.
c. Baseline Energy Use
For each equipment class, DOE generally selects a baseline model as
a reference point for each class, and measures changes resulting from
potential energy conservation standards against the baseline. The
baseline model in each product/equipment class represents the
characteristics of a product/equipment typical of that class (e.g.,
capacity, physical size). Generally, a baseline model is one that just
meets current energy conservation standards, or, if no standards are in
place, the baseline is typically the most common or least efficient
unit on the market.
DOE's analysis for distribution transformers generally relies on a
baseline approach. However, instead of selecting a single unit for each
efficiency level, DOE selects a set of units to reflect that different
distribution transformer purchasers may not choose distribution
transformers with identical characteristics because of difference in
applications and manufacturer practices. The mechanics of the customer
choice model at baseline and higher efficiency levels are discussed in
section IV.F.3 of this document.
d. Higher Efficiency Levels
DOE relies on a similar approach to its baseline engineering in
evaluating higher efficiency levels. DOE's modeled units span the
design space. In evaluating a higher efficiency level up until that
maximum efficiency level that DOE considers (``max-tech''), DOE
evaluates the modeled units that would exceed the higher efficiency
level. Then, rather than selecting a single unit, DOE applies a
customer choice model to evaluate the distribution transformers that
would be purchased if standards were amended.
Howard commented that they looked at the various RUs and believe
the current efficiency standards provide excellent value to consumers.
(Howard, No. 59 at p. 2) Howard added that while they don't use OPS
software, their internal software says to remain at the current
efficiency levels and there is no need to have a NOPR as current
standards are sufficient. (Howard, No. 59 at pp. 2-3) DOE appreciates
Howard's comment but notes that they have not provided data to justify
the results of their internal software. As noted previously, DOE has
tentatively determined that the proposed standards are technologically
feasible (based on models currently available in the market) and
economically justified, and would result in significant energy savings.
The Efficiency Advocates commented that since DOE last revised its
energy conservation standards, major economies around the world have
set new efficiency thresholds that exceed U.S. energy conservation
standards. (Efficiency Advocates, No. 52 at pp. 7-8) The Efficiency
Advocates commented that the U.S. should aim to be a world leader in
transformer efficiency. (Efficiency Advocates, No. 52 at pp. 7-8)
DOE notes that while it may look at foreign efficiency standards to
get a better understanding of the global distribution transformer
market, the U.S. has its own unique economic conditions, energy costs,
and legal requirements. DOE has evaluated amended energy conservation
standards based on the unique conditions of the U.S. and DOE's legal
obligations under EPCA.
[[Page 1764]]
e. Load Loss Scaling
DOE energy conservations standards apply only at a single PUL for a
given distribution transformer equipment class (50 percent for liquid-
immersed distribution transformers and medium voltage dry-type
distribution transformers and 35 percent for low-voltage dry-type
distribution transformers). 10 CFR 431.196. However, distribution
transformers exhibit varying efficiency with varying PUL. Distribution
transformer no-load losses are generally constant with loading, while
load losses vary approximately with the quadratic of the PUL. In
practice, efficiency deviates slightly from this assumption as no-load
losses are not perfectly constant and load losses are not perfectly
quadratic. DOE requested comment on approximating load losses as a
quadratic function of PUL.
NEMA commented that the quadratic approximation for load losses is
sufficient. (NEMA, No. 50 at p. 11)
OPS' modeling includes details as to how a distribution
transformer's loss and temperature vary across select load points. In
determining the rated efficiency of a transformer model as it would be
certified under DOE's test procedure, DOE relies on the modeled load
losses at the PUL at which efficiency is calculated and corrects the
load losses from the modeled temperature to the reference temperature.
This value is used to calculate the rated efficiency of a distribution
transformer model.
In the downstream analysis of a distribution transformer energy use
and costs, DOE relies on the calculated full-load loss values and
applies a quadratic approximation for what the load losses would be
under real world loading conditions. Commenters have generally agreed
that this approach is sufficient.
DOE noted that the full-load loss value DOE uses in its downstream
analysis is the full-load loss estimate at the modeled transformer
temperature. Full-load loss in industry is often reported at the rated
temperature rise. Lower loss distribution transformers generally
operate at lower temperatures, as they have less losses of heat to
dissipate. Some transformers may operate well below their rated
temperature even at full load. Therefore, the full-load losses used in
the downstream analysis may be lower than the reported full-load losses
at rated temperature rise.
NEEA commented that a quadratic scaling of load losses would not
apply with harmonic frequencies and DOE should include a harmonic
dependent factor in its scaling model. (NEEA, No. 51 at p. 6) DOE notes
that section 4.1 of appendix A specifies testing using a sinusoidal
waveform. Therefore, harmonics would not impact the rated efficiency of
a distribution transformer.
In DOE's downstream analyses, harmonics would generally lead to
greater losses. While nonlinear loads exist, the impact of them is
small and DOE does not have data suggesting they meaningfully impact
system wide savings to the point that a quadratic approximation is
inaccurate. Further, while harmonics may increase losses, relative to
what a quadratic approximation would estimate, lower operating
temperatures at low-loading, where most distribution transformers
operate, would decrease losses relative to the quadratic approximation.
While other factors may cause the loss behavior of individual
transformers in specific applications to deviate slightly from a true
quadratic of the full-load losses, stakeholders have generally
supported approximating load losses a quadratic of PUL and have not
provided an alternative, more accurate method for approximating losses.
As such, DOE has retained a quadratic load loss scaling in its
analysis.
f. kVA Scaling
NEMA commented that the 0.75 power scaling rule is overly
simplistic and has resulted in smaller kVA MVDTs having a hard time
meeting efficiency standards. (NEMA, No. 50 at p. 9) Eaton commented
that DOE's scaling rule as it applied to height, width, and depth of
the core/coil assembly would not always be accurate due to certain
bushing space requirements and design trade-offs pertaining to bushing
heights relative to core/coil assembly heights. (Eaton, No. 55 at p.
16)
DOE has not received any comment or data suggesting an alternative
method for scaling kVA and therefore has retained its scaling methods.
3. Cost Analysis
The cost analysis portion of the engineering analysis is conducted
using one or a combination of cost approaches. The selection of cost
approach depends on a suite of factors, including the availability and
reliability of public information, characteristics of the regulated
product, the availability and timeliness of purchasing the equipment on
the market. The cost approaches are summarized as follows:
Physical teardowns: Under this approach, DOE physically
dismantles a commercially available product, component-by-component, to
develop a detailed bill of materials for the product.
Catalog teardowns: In lieu of physically deconstructing a
product, DOE identifies each component using parts diagrams (available
from manufacturer websites or appliance repair websites, for example)
to develop the bill of materials for the product.
Price surveys: If neither a physical nor catalog teardown
is feasible (for example, for tightly integrated products such as
fluorescent lamps, which are infeasible to disassemble and for which
parts diagrams are unavailable) or cost-prohibitive and otherwise
impractical (e.g., large commercial boilers), DOE conducts price
surveys using publicly available pricing data published on major online
retailer websites and/or by soliciting prices from distributors and
other commercial channels.
In the present case, DOE conducted the analysis by applying
materials prices to the distribution transformer designs modeled by
OPS. The resulting bill of materials provides the basis for the
manufacturer production cost (``MPC'') estimates to which mark-ups are
applied to generate manufacturer selling prices (``MSP''). The primary
material costs in distribution transformers come from electrical steel
used for the core and the aluminum or copper conductor used for the
primary and secondary winding. DOE presented preliminary costing data
and methodology in the August 2021 Preliminary Analysis TSD.
Regarding the cost analysis generally, NEMA commented that the
material prices presented in the preliminary analysis do not reflect
the post-COVID world and may be low by as much as half. (NEMA, No. 50
at p. 2) Eaton commented that PPI for power and distribution
transformers has increased around 25 percent from 2020 levels and so
costs are going to be higher and payback periods will be longer.
(Eaton, No. 55 at p. 13) Howard echoed the concerns that Covid-19 has
created labor and supply chain issues. (Howard, No. 59 at p. 1) Howard
commented that their internal studies showed incremental MSPs as much
as four times higher than what DOE showed in their preliminary
analysis. (Howard, No. 59 at p. 2) Carte commented that the cost of
both copper and aluminum have risen substantially in the past year.
(Carte, No. 54 at pp. 3-4) Powermiths added that market megatrends,
such as the pandemic, decarbonization and electric vehicles may impact
the analysis and create uncertainty. Powesmiths recommended DOE delay
changes until these megatrends settle. (Powersmiths, No. 46 at pp. 6-7)
Powersmiths and Carte commented that the market is in a state of flux
right now and it may be
[[Page 1765]]
prudent to hold off any changes to efficiency standards until prices
settle. (Carte, No. 54 at p. 4; Powersmiths, No. 46 at p. 7)
DOE data confirms that prices have been up recently, however, it is
difficult to say for certain how those prices will vary in the medium
to long terms and what those prices will be in the future. Rather than
trying to project future prices, DOE relies on a five-year average in
its base case and evaluates how the results would change with different
pricing sensitivities. The recent price increases described by comments
are incorporated into this five-year average and as a result, prices in
the NOPR analysis are higher than they were in the August 2021
Preliminary Analysis TSD.
Eaton commented that in evaluating amended energy conservation
standards, DOE should solicit quotations from at least three
distribution transformer manufacturers for each representative unit and
create a cost-down cost estimate to calibrate the bottom-up estimates.
(Eaton, No. 55 at p. 19)
As DOE noted in section IV.C.2.b, DOE welcomes manufacturers to
submit design and costing data for distribution transformers. DOE notes
that in addition to soliciting public comment in a written format and
public interviews, DOE conducts confidential manufacturer interviews
through which much of the pricing data is gathered. DOE has made some
updates to its cost analysis in response to manufacturer feedback, as
described in the following sections.
a. Electrical Steel Prices
Electrical steel is one of the primary drivers of efficiency
improvements and the relative costs associated with transitioning to
lower loss steels can impact the cost effectiveness of amended
efficiency standards. As noted, in section IV.A.5, the sourcing
practices of individual manufacturers and production locations can
impact prices as not all steel manufacturers produce the same
electrical steels and trade actions have historically impacted the
industry. DOE presented pricing in the August 2021 Preliminary Analysis
TSD and requested comment. (August 2021 Preliminary Analysis TSD at p.
2-53)
ERMCO commented that the core steel costs presented in the
preliminary analysis seem reasonable, but market growth in sectors,
like EVs, may drive future prices up. (ERMCO, No. 45 at p. 1)
Powersmiths commented that smaller manufacturers cannot access the DOE
costs because volume drives price. Powersmiths noted that for one of
the pdr steels it uses, the price has increased as much as 61 percent
and they do not see them returning to their lower prices. (Powersmiths,
No. 46 at p. 6)
Carte commented that there is a global shortage of electrical steel
and the price is up 20 percent in this year alone, with current prices
up 76 percent from the 2008 peak. (Carte, No. 54 at p. 3) Carte noted
that some industry sources expect prices to far exceed their 2008
peaks. (Carte, No 54 at p. 3)
Carte cited several reasons for the increase in pricing. China has
reduced export of GOES in recent years. (Carte, No. 54 at p. 3) Second,
increased competition from non-oriented electrical steel serving the
electric vehicle industry which has encouraged some steel manufacturers
to convert GOES production lines to non-oriented electrical steel
production lines. (Carte, No. 54 at p. 3)
DOE has updated pricing in this analysis in response to stakeholder
feedback and confidential manufacturer interviews. Prices for
electrical steel have increased significantly in recent years.
Manufacturers noted that this price increase was particularly high for
foreign electrical steel. DOE has applied a 5-year average price in its
base case analysis. The prices in and conducted sensitivities for
various other pricing scenarios, as discussed in section IV.C.3.
EEI commented that higher standards may significantly impact all
non-amorphous cores and limit choice and lead to higher prices for
consumers considering limited availability of certain steel. (EEI, No.
56 at p. 3)
DOE generally assumes pricing to be reflective of current market
costs. While higher standards could limit which steels are available to
meet standards, DOE notes that a handful of high-volume steels
currently dominate the industry. Historically, when amended standards
have been adopted, steel manufacturers have increased capacity of the
electrical steel grades needed to meet amended efficiency standards.
These materials may have higher costs, but they also tend to have
higher costs in the current market. Rather than trying to predict what
the cost and market breakdown would be in the presence of amended
standards, DOE relies on a five-year average and conducts price
sensitivities to ensure that energy savings are cost effective under
different pricing structures.
Carte commented that while they don't purchase amorphous steel, DOE
may want to verify that amorphous steel from China is still available
and questioned if there were any domestic manufacturers of amorphous
steel. (Carte, No. 54 at p. 3) DOE notes that amorphous steel is
produced domestically, as well as in China and Japan.
NEEA commented that its research suggests amorphous cores are lower
first cost above 100 kVA single-phase or 500 kVA three-phase and there
are several utilities commonly purchasing amorphous in the U.S. and
Canada. (NEEA, No. 51 at p. 8) Metglas commented that its internal
calculations show that amorphous steel is not close to price parity
with GOES, using DOE's preliminary analysis assumed pricing. (Metglas,
No. 53 at p. 2) Metglas commented that recent bid data shows amorphous
transformers typically need an A value over $7 per Watt and A to B
ratio greater than $3 per Watt for amorphous transformers to win on
total ownership cost bids. (Metglas, No. 53 at p. 2) Metglas commented
that DOE's preliminary analysis pricing of amorphous is accurate for
sourced cores, but may be lesser for manufacturers who produce their
own cores. (Metglas, No. 53 at p. 5)
Metglas commented that some transformer manufacturers source cores
while other produce them internally. (Metglas, No. 53 at p. 5) NEMA
disagreed with DOE's assumption that all amorphous cores are sourced
and deferred to individual NEMA members as to their specific practices.
(NEMA, No. 50 at p. 11)
Pricing for amorphous steel has increased slightly since the
preliminary analysis but less so than GOES steel, and in particular
foreign produced GOES. As such, amorphous steel is generally more
competitive on first cost than it was in the preliminary analysis. As
NEEA suggested, DOE did observe instances where amorphous transformers
are lower first cost. However, that has not necessarily led to
increased adoption, in part because most manufacturers' capital
equipment is set-up for GOES core production. Amorphous transformer
production would require manufacturer investment to fill high volume
orders. As such, the first cost competitiveness of amorphous steel in
certain applications has not necessarily corresponded to equivalent
market share. DOE has continued to assume sourced core pricing for
amorphous steel as most manufacturers do not have the capacity to
produce cores in volume. While Metglas notes that manufacturers
producing their own cores could have lesser costs, DOE notes in that
scenario they would likely have additional retooling costs that would
be aggregated over unit volume and increase core price relative to raw
materials. More details regarding DOE's
[[Page 1766]]
pricing of amorphous steel are included in chapter 5 of the TSD.
For this NOPR, DOE's analysis shows that it is cost-effective to
meet the proposed standards for liquid-immersed and low-voltage dry-
type distribution transformers fabricated with amorphous steel cores.
An energy conservation standard that significantly increases adoption
of amorphous core distribution transformers would represent a
substantial shift in the distribution transformer market. Such a shift
could impact pricing and competition among steel suppliers in ways that
may not be perfectly predictable, as the resulting market equilibrium
would depend on decisions made by market participants outside of DOE's
control. However, it is important to emphasize that price volatility in
electrical steel and shifts in the market's competitive balance are not
limited to amorphous steel.
Substantial volatility has characterized the U.S. steel market over
the last several decades. From 2000 to 2007, U.S. steel markets, and
more specifically the U.S. electrical steel market, began to experience
pressure from several directions. Demand in China and India for high-
efficiency, grain-oriented core steel contributed to increased prices
and reduced global availability. Cost-cutting measures and technical
innovation at their respective facilities, combined with the lower
value of the U.S. dollar enabled domestic core steel suppliers to
become globally competitive exporters.
In late 2007, the U.S. steel market began to decline with the onset
of the global economic crisis. U.S. steel manufacturing declined to
nearly 50 percent of production capacity utilization in 2009 from
almost 90 percent in 2008. Only in China and India did the production
and use of electrical grade steel increase for 2009.\51\ In 2010, the
price of steel began to recover. However, the recovery was driven more
by increasing cost of material inputs, such as iron ore and coking
coal, than broad demand recovery.
---------------------------------------------------------------------------
\51\ International Trade Administration. Global Steel Report.
(Last accessed September 1, 2022) https://legacy.trade.gov/steel/pdfs/global-monitor-report-2018.pdf.
---------------------------------------------------------------------------
In 2011, core steel prices again fell considerably. At this time,
China began to transition from a net electrical steel importer to a net
electrical steel exporter.\52\ Between 2005 and 2011, China imported an
estimated 253,000 to 353,000 tonnes of electrical steel. During this
time, China added significant domestic electrical steel production
capacity, such that from 2016 to 2019 only about 22,000 tonnes were
imported to China annually. China also exported nearly 200,000 tonnes
of electric steel annually by the late 2010's.
---------------------------------------------------------------------------
\52\ Capital Trade Incorporated, Effective Trade Relief on
Transformer Cores and Laminations, 2020. Submitted as part of AK
Steel comment at Docket No. BIS-2020-0015-0075 at p. 168.
---------------------------------------------------------------------------
Many of the exporters formerly serving China sought new markets
around 2011, namely the United States. The rise in U.S. imports at this
time hurt domestic U.S. steel manufacturers, such that in 2013,
domestic U.S. steel stakeholders filed anti-dumping and countervailing
duty petitions with the U.S. International Trade Commission.\53\ The
resulting investigation found that ``an industry in the United States
is neither materially injured nor threatened with material injury by
reason of imports of grain-oriented electrical steel . . . to be sold
in the United States at less than fair value.'' \54\
---------------------------------------------------------------------------
\53\ U.S. International Trade Commission, Grain-Oriented
Electrical Steel from Germany, Japan, and Poland, Investigation Nos.
731-TA-1233, 1234, and 1236. September 2014.
\54\ Id.
---------------------------------------------------------------------------
In the amorphous steel market, the necessary manufacturing
technology has existed for many decades and has been used in
distribution transformers since the late 1980s.\55\ In many countries,
amorphous steel is widely used in the cores of distribution
transformers.\56\ Significant amorphous steel use tends to occur (1) in
places with both comparatively lower labor costs and significant
electrification (e.g., India, China); and (2) in regions with
relatively high loss valuations on losses (e.g., certain provinces of
Canada).
---------------------------------------------------------------------------
\55\ DeCristofaro, N., Amorphous Metals in Electric-Power
Distribution Applications, Material Research Society, MRS Bulletin,
Volume 23, Number 5, 1998.
\56\ BPA's Emerging Technologies Initiative, Phase 1 report:
High Efficiency Distribution Transformer Technology Assessment,
April 2020. Available online at: https://www.bpa.gov/EE/NewsEvents/presentations/Documents/Transformer%20webinar%204-7-20%20Final.pdf.
---------------------------------------------------------------------------
Beginning in 2018, the U.S. government instituted a series of
import duties on aluminum and steel articles, among other items. Steel
and aluminum articles were generally subject to respective import
duties of 25 and 10 percent ad valorem.\57\ 83 FR 11619; 83 FR 11625.
Since March 2018, several presidential proclamations have created or
modified steel and aluminum tariffs, including changes to the products
covered, countries subject to the tariffs, exclusions, etc.\58\ Given
the recency of several publications, combined with the supply chain
disruptions caused by the Covid-19 pandemic, many of the price effects
that, directly or indirectly, impact the pricing of distribution
transformers may still be stabilizing.
---------------------------------------------------------------------------
\57\ Ad valorem tariffs are assessed in proportion to an item's
monetary value.
\58\ Congressional Research Service, Section 232 Investigations:
Overview and Issues for Congress, May 18, 2021, Available online at:
https://fas.org/sgp/crs/misc/R45249.pdf.
---------------------------------------------------------------------------
Another recent trend in distribution transformer manufacturing is
an increase in rate of import or purchase of finished core products.
The impact of electrical steel tariffs on manufacturers' costs varies
widely depending on if manufacturers are purchasing raw electrical
steel and paying a 25-percent tariff if the steel is imported, or if
they are importing finished transformer cores which, along with
distribution transformer core laminations and finished transformer
imports, are not subject to the tariffs. Some stakeholders have argued
that this trend toward importing distribution transformer cores,
primarily from Mexico and Canada, is a method of circumventing tariffs,
as electrical steel sold in the global market has been less expensive
than domestic electrical steel on account of being unfairly
traded.59 60 Conversely, other stakeholders have commented
that this trend predated the electrical steel tariffs and that
importation of transformer components is often necessary to remain
competitive in the U.S. market, given the limited number of domestic
manufacturers that produce transformer laminations and
cores.61 62
---------------------------------------------------------------------------
\59\ (AK Steel, Docket No. BIS-2020-0015-0075 at pp. 43-58).
\60\ (American Iron and Steel Institute, Docket No. BIS-2020-
0015-0033 at pp. 2-5).
\61\ (Central Maloney Inc., Docket No. BIS-2020-0015-0015 at pp.
1).
\62\ (NEMA, Docket No. BIS-2020-0015-0034 at pp. 3-4).
---------------------------------------------------------------------------
On May 19, 2020, the U.S. Department of Commerce (DOC) opened an
investigation into the potential circumvention of tariffs via imports
of finished distribution transformer cores and laminations. 85 FR
29926. On November 18, 2021, DOC published a summary of the results of
their investigation in a notice to the Federal Register. The report
stated that importation of both GOES laminations and finished wound and
stacked cores has significantly increased in recent years, with
importation of laminations increasing from $15 million in 2015 to $33
million in 2019, and importation of finished cores increasing from $22
million in 2015 to $167 million in 2019. DOC attributed these
increases, at least in part, to the increased electrical steel costs
resulting from the imposed tariffs on electrical steel. In response to
their investigation, DOC stated it is exploring several options to
shift the market towards domestic production and
[[Page 1767]]
consumption of GOES, including extending tariffs to include laminations
and finished cores. No trade action has been taken at the time of
publication of this NOPR. 86 FR 64606.
More recently, DOE learned from stakeholders during manufacturer
interviews and from public comments that pricing of electrical steel
has risen such that in the current market, it is similar between
domestic and foreign electrical steel (i.e., the price of foreign
electrical steel without any tariffs applied). (Powersmiths, No. 46 at
p. 6; Carte, No. 54 at p. 3) These recent price increases, particularly
in foreign produced electrical steel, were cited as being a result of
both general supply chain complications and increased demand for non-
oriented electrical steel (NOES) from electric motor applications.
(NEMA, No. 50 at p. 9; Powersmiths, No. 46 at p. 5; Zarnowski, Public
Meeting Transcript, No. 40 at p. 36; Looby, Public Meeting Transcript,
No. 40 at p. 37)
Since 2016, there has been one domestic supplier and multiple
global suppliers of GOES. The amorphous steel market follows the same
pattern, with one domestic supplier and multiple global suppliers.
Further, although the current foreign suppliers of amorphous steel are
primarily based in Japan and China, DOE received feedback through
public comment and manufacturer interviews that South Korean and German
steel suppliers have the capabilities to expand their steel production
to include amorphous steel, if demand for amorphous steel increases.
(Metglas, No. 11 at p. 2) DOE does not have data suggesting that
amorphous steel is inherently more expensive to produce than GOES. Both
varieties rely on similar inputs and both are capital-intensive,
therefore tending to reduce per-pound production costs with higher
capacity utilizations.
Public comments by Metglas stated that within two years of
developing the know-how to produce amorphous ribbon, producers in China
were able to add 70,000 Mt of capacity.\63\ Public statements from one
manufacturer in Europe note that since the expiration of an initial
patent related to amorphous steel production, there have been a number
of additional amorphous suppliers and material prices have been
stable.\64\ Given these historical examples with which manufacturers
have been able to quickly add amorphous capacity, along with the cited
number of producers capable of making amorphous steel, DOE's view is
that it is reasonable to expect that if there were insufficient
amorphous steel production capacity to meet amended energy conservation
standards, some manufacturers with the expertise to produce amorphous
steel would enter the market and manufacturers currently without the
expertise to manufacture amorphous steel may invest in its development.
---------------------------------------------------------------------------
\63\ Metglas, Section 232 National Security Investigation of
Imports of Steel: Comments by Metglas, Inc. Requesting the Inclusion
of Amorphous Steel, 2017. https://www.bis.doc.gov/index.php/232-steel-public-comments/1835-metglas-amorphous-public-comment.
\64\ Wilson Power Solutions, Amorphous Metal Transformers--Myth
Buster, 2018. https://www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf.
---------------------------------------------------------------------------
Additionally, during manufacturer interviews, stakeholders
indicated that in the current marketplace there are shortages of GOES
steel products, leading to greater price levels and volatility. Because
GOES production can be shifted to NOES products at modest cost, these
shortages are likely driven at least in part by rising demands for NOES
in manufacture of motors and electric vehicles. This demand creates
competition for GOES production capacity. Given recent trends of
decarbonization initiatives and industrial reshoring, the manufacture
of NOES for electric vehicle production appears poised to put
competitive pressure on GOES production well into the future.\65\
---------------------------------------------------------------------------
\65\ Example: California's electric vehicle adoption executive
order: https://www.gov.ca.gov/wp-content/uploads/2020/09/9.23.20-EO-N-79-20-Climate.pdf, 2022.
---------------------------------------------------------------------------
Further, there has been, and remains, competition for available
low-loss grades of GOES between the power and distribution transformer
segments. Cliffs commented that while high-permeability GOES works well
in distribution transformers, it has historically been sold as a laser
DR product to the power transformer market; NEMA commented that both
distribution and power transformers compete for steel demand. (Cliffs,
No. 57 at p. 1; NEMA, No. 50 at p. 9) Therefore, it is likely that any
energy savings associated with use of lower-loss core steel, whether it
be amorphous or grain-oriented, would require investment from steel
manufacturing industry at-large to increase capacity of either lower-
loss GOES steels or of amorphous steel.
Rather than constructing sensitivity analysis scenarios to reflect
every potential combination of factors that may affect steel pricing
(e.g., various tariffs and quotas, competition from NOES, decisions by
steelmakers in various countries to add production capacity) or making
assumptions regarding how changes in production volume affect material
prices, DOE relies on a 5-year average pricing for its core steel.
DOE requests comment on the current and future market pressures
influencing the price of GOES. Specifically, DOE is interested in the
barriers to and costs associated with converting a factory production
line from GOES to NOES.
DOE further requests comment regarding how the prices of both GOES
and amorphous are expected to change in the immediate and distant
future.
DOE requests comment regarding the barriers to converting current
M3 or 23hib90 electrical steel production to lower-loss GOES core
steels.
DOE requests comment as to if there are markets for amorphous
ribbon, similar to NOES competition from GOES production, which would
put competitive pressures on the production of amorphous ribbon for
distribution transformers.
DOE requests comment on how a potentially limited supply of
transformer core steel, both of amorphous and GOES, may affect core
steel price and availability. DOE seeks comment on any factors which
uniquely affect specific steel grades (e.g., amorphous, M-grades, hib,
dr, pdr). Additionally, DOE seeks comment on how it should model a
potentially concentrated domestic steel market in its analysis,
resulting from a limited number of suppliers for the amorphous market
or from competition with NOES for the GOES market, including any use of
game theoretic modeling as appropriate.
b. Scrap Factor
In the August 2021 Preliminary Analysis TSD, DOE noted that it
applies various scrap markups to distribution transformer bills of
materials (August 2021 Preliminary Analysis TSD at p. 2-53). DOE
requested comment on its scrap factor markups. Metglas commented that
DOE should not apply a scrap to a finished core because the scrap would
be included in the core costs. (Metglas, No. 53 at p. 5)
DOE notes that a scrap factor is still applied to prefabricated
cores to account for any potential breakage of cores and any scrap
associated with assembling the windings or insulation on the cores.
However, a lesser factor is used as compared to GOES because much of
the scrap costs would be priced into the core production.
Metglas commented that the scrap rate for GOES seemed low but did
not provide an alternative value. (Metglas, No. 53 at p. 5) Eaton
commented that it is unclear which mark-ups are applied
[[Page 1768]]
to which cores and DOE should clarify. (Eaton, No. 55 at p. 14)
DOE has maintained the scrap factors from the preliminary analysis
as it did not receive alternative values and has updated the language
in chapter 5 of the TSD to better explain how scrap factors were
applied. DOE has added equations in chapter 5 to walk through how the
material costs were translated to MSPs.
c. Other Material Costs
In the August 2021 Preliminary Analysis TSD, DOE presented material
prices and requested comment on a variety of additional materials used
in distribution transformer construction. (August 2021 Preliminary
Analysis TSD at p. 2-50)
Eaton commented that while windings combs and epoxy resin have
materials cost listed, they are not used in liquid immersed
transformers. (Eaton, No. 55 at p. 14) DOE notes that it did not apply
either of those costs to liquid-immersed distribution transformers and
has made that more clear in the NOPR TSD.
Eaton commented that mineral oil and mild steel prices are higher
than was shown in the August 2021 Preliminary Analysis TSD. (Eaton, No.
55 at p. 14) Eaton commented that DOE may be underestimating pricing,
in part due to underestimating the number and costs of some of the
fixed components, such as the number of bushings for RU4 and RU5.
(Eaton, No. 55 at pp. 14-16) DOE has made modifications to the pricing
of its fixed components and updated costs to reflect generally price
changes in the underlying commodities. DOE notes that the fixed-costs
generally do not vary with efficiency and as such, higher pricing of
these fixed-components would not impact the pay-back periods for more
efficient distribution transformers.
Specifically, regarding the cost of the distribution transformer
tank, Eaton commented that the cost is too low and appears to have
omitted the cost of the cabinet and associated labor. (Eaton, No. 55 at
p. 15)
Part of the difference in tank costs cited by Eaton, is likely
associated with the increase in tank steel that has occurred between
when the preliminary analysis prices were gathered compared to the NOPR
prices. DOE has updated tank steel prices, which has increased the
price of the distribution transformer tank. DOE notes that weld time
would generally be included in calculation of labor. DOE has added
additional detail as to calculation of tank cost in chapter 5 of the
TSD.
NEMA commented that radiators are not always included in footprint
calculations but cabinet/enclosures are and DOE should add these into
the analysis. (NEMA, No. 50 at p. 14)
DOE has modeled a cabinet and enclosure in its sizing of
distribution transformer tanks. DOE has presented these additional
details in chapter 5 of the TSD.
d. Cost Mark-Ups
Factory Overhead
In the August 2021 Preliminary Analysis TSD, DOE noted that it used
a factory overhead markup to account for all indirect costs associated
with production, indirect materials and energy used, taxes, and
insurance. (August 2021 Preliminary Analysis TSD at p. 2-57)
Eaton commented that it was unclear what exactly the factory
overhead markup was applied to, for example, did it include only
materials the consumer produced themselves or did it apply to purchased
parts as well. (Eaton, No. 55 at p. 15)
DOE applied the factory overhead markup to all material costs,
which would include purchased parts. DOE understands that purchased
parts would still require factory space, certain equipment usage,
taxes, and insurance. DOE has added detail in chapter 5 of the TSD as
to how it applied the Factory Overhead Mark-up.
Labor
Labor costs are an important aspect of the cost of manufacturing a
distribution transformer. In the August 2021 Preliminary Analysis TSD,
DOE described how the number of labor hours were derived for each
distribution transformer design. For liquid-immersed distribution
transformers, DOE generally relied on a bottoms-up approach, estimating
the various hours associated with the various steps in distribution
transformer manufacturing. For dry-type distribution transformers, DOE
relies on a top-down approach to estimate the total labor for a unit
using equations derived from manufacturer data. These equations include
a base labor charge for a given unit and a variable charge that varies
with transformer size. DOE notes in the August 2021 Preliminary
Analysis TSD, it mistakenly outlined a bottom-up approach for LVDTs
when in fact a top-down labor estimate was used. This discussion is
modified in chapter 5 of the TSD, while the estimated labor per unit is
unchanged.
In response to the August 2021 Preliminary Analysis TSD, Eaton
noted that the estimates of labor hours for RU4 and RU5 appeared to
notably underestimate the required labor per unit and noted many
specific areas in the bottom-up approach that appeared to underestimate
labor. (Eaton, No. 55 at p. 17-19) Eaton also noted that DOE
overestimated the RU5 additional number of labor hours for building an
amorphous distribution transformer and that the only difference would
be that an amorphous transformer would have a split core assembly,
which would require above 1 hour of additional labor. (Eaton, No. 55 at
p. 20)
In manufacturer interviews, DOE received concurring feedback that
while its estimates of labor per unit and bottoms-up approach were
approximately accurate for its single-phase, liquid-immersed units,
three-phase units require substantially more labor. DOE relied on
manufacturer interviews and confidential data to develop estimates for
labor hours for RU4 and RU5 that assumes a base labor number of hours
and a variable that scales with unit size, similar to what is done for
the dry-type distribution transformers. These equations are presented
in chapter 5 of the TSD.
Eaton commented that it believes the fully burdened cost of labor
is way too low and a value of $200/hour or more seems more appropriate.
(Eaton, No. 55 at p. 16)
DOE applies a labor cost per hour that is generally derived from
the U.S. Bureau of Labor Statistic rates for North American Industry
Classification System (``NAICS'') Code 335311--``Power, Distribution,
and Specialty Transformer Manufacturing'' production employee hourly
rates and applied mark-ups for indirect production, overhead, fringe,
assembly labor up-time, and a nonproduction mark-up to get a fully
burdened cost of labor. In the preliminary analysis, DOE adjusted the
labor rate upward in response to manufacturer feedback. While some
manufacturers may have different labor costs, DOE generally considers
the BLS statistics approximately representative. DOE has adjusted labor
costs from the preliminary analysis based on the ratio of increased
labor costs in NAICS code.
Shipping
In the August 2021 Preliminary Analysis TSD, DOE noted that it used
a price per pound estimate to estimate the shipping cost of
distribution transformers. DOE stated that while shipping costs will
vary depending on several factors, including weight, volume, footprint,
order size, destination, distance, and other, general shipping costs
(fuel prices, driver wages, demand, etc.), the price-per-pound estimate
is an appropriate approximation of shipping costs and
[[Page 1769]]
reflects that there would be increased shipping costs associated with
larger distribution transformers. DOE then applied a non-production
markup on top of its shipping costs. DOE requested comment on its
methodology and the shipping costs used in the preliminary analysis.
(August 2021 Preliminary Analysis TSD at p. 2-56)
Howard commented that they have their own shipping division and
trucks and optimize shipments to be most efficient. (Howard, No. 59 at
p. 3) Eaton commented that shipping costs vary but on average, DOE's
shipping cost estimates are reasonable. (Eaton, No. 55 at p. 16)
DOE did not receive any comment or data suggesting an alternative
approach to shipping costs, therefore DOE has retained its price-per-
pound mark-up to account for shipping in the NOPR analysis.
Manufacturer Markup
To account for the manufacturer's nonproduction costs and profit
margin, DOE applies a manufacturer markup to the MPC. The resulting MSP
is the price at which the manufacturer distributes a unit into
commerce. In the preliminary analysis, DOE applied a gross margin
percentage of 20 percent for all distribution transformers.\66\
---------------------------------------------------------------------------
\66\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
Eaton commented that its gross profit margin was higher and a 20
percent gross margin is too low for a publicly traded corporation with
obligations to stakeholders.\67\ (Eaton, No. 55 at p. 16-17)
---------------------------------------------------------------------------
\67\ A 20 percent gross margin is equivalent to a 1.25
manufacturer markup.
---------------------------------------------------------------------------
DOE's average gross margin was developed by examining the annual
Securities and Exchange Commission (SEC) 10-K reports filed by
publicly-traded manufacturers primarily engaged in distribution
transformer manufacturing and whose combined product range includes
distribution transformers.
While some corporations may have higher gross margins, the gross
margin is unchanged from the April 2013 Standards Final Rule and was
presented to manufacturers in confidential interviews as part of both
the preliminary analysis and the NOPR analysis. While some
manufacturers noted higher or lower gross margins, depending on the
product class, there was generally agreement that the 20 percent gross
margin was appropriate for the industry. As such, DOE has retained the
20 percent gross margin as part of the NOPR analysis.
4. Cost-Efficiency Results
The results of the engineering analysis are reported as cost-
efficiency data (or ``curves'') in the form of energy efficiency (in
percentage) versus MSP (in dollars), which form the basis for
subsequent analyses in the preliminary analysis. DOE developed sixteen
curves representing the sixteen representative units. DOE implemented
design options by analyzing a variety of core steel material, winding
material and core construction method for each representative unit and
applying manufacturer selling prices to the output of the model for
each design option combination. See TSD chapter 5 for additional detail
on the engineering analysis.
Powersmiths commented that the cost-efficiency plots show it is too
cheap to achieve higher efficiency and if it were really that cheap,
the market would move there without legislation. (Powersmiths, No. 46
at p. 5) Conversely, Metglas commented that the market does not
evaluate based on efficiency and the only way to see efficiency
improvements is via amended energy conservation standards. (Metglas,
No. 53 at p. 8)
In general, DOE's analysis assumes most distribution transformer
customers purchase based on lowest first cost and there is limited
market above minimum efficiency standards (see section IV.F.3.c).
Therefore, DOE does not have data to support manufacturers will build
above minimum efficiency standards, aside from certain select
applications, even if it were only modestly more expensive.
The Efficiency Advocates commented that the percentage of
transformers core steels purchased in the preliminary analysis shows
that too few GOES transformers are being selected, indicating a
potential issue in the engineering analysis. (Efficiency Advocates, No.
52 at p. 7)
DOE has acknowledged that aside from lowest first cost,
manufacturers may be limited in their steel choice under the base case.
In certain cases, the incremental cost to higher efficiency standards
may be low but assumes access to suppliers of better performing steel.
DOE has updated its baseline analysis to reflect the steel choices that
are currently made in the industry as described in section IV.F.3.a.
D. Markups Analysis
The markups analysis develops appropriate markups (e.g., retailer
markups, distributor markups, contractor markups) in the distribution
chain and sales taxes to convert the MSP estimates derived in the
engineering analysis to consumer prices, which are then used in the LCC
and PBP analysis. At each step in the distribution channel, companies
mark up the price of the product to cover costs. DOE's markup analysis
assumes that the MSPs estimated in the engineering analysis (see
section IV.C of this document) are occurring in a competitive
distribution transformer market as discussed in section V.B.2.d of this
document.
For distribution transformers, the main parties in the distribution
chain differ depending on the type of distribution transformer being
purchased and by whom.
Liquid-immersed distribution transformers are almost exclusively
purchased and installed by electrical distribution companies, as such
the distribution chained assumed by DOE reflect the different parties
involved. Dry-type distribution transformers are used to step down
voltages from primary service into the building to voltages used by
different circuits within a building, such as, plug loads, lighting,
and specialty equipment; as such DOE modelled that dry-type
distribution transformers are purchased by non-residential customers,
i.e., commercial, and industrial customers.
DOE considered the following distribution channel shown in Table
IV.5.
Table IV.5--Distribution Channels for Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Market share
Type Consumer (%) Distribution channel
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed....................... Investor-owned utility... 82 Manufacturer [rarr] Consumer.
18 Manufacturer [rarr]
Distributor [rarr] Consumer.
Publicly-owned utility... 100 Manufacturer [rarr]
Distributor [rarr] Consumer.
LVDT.................................. All...................... 100 Manufacturer [rarr]
Distributor [rarr]
Electrical contractor[rarr]
Consumer.
[[Page 1770]]
MVDT.................................. All...................... 100 Manufacturer [rarr]
Distributor [rarr]
Electrical contractor[rarr]
Consumer.
----------------------------------------------------------------------------------------------------------------
Howard commented that in in their experience that liquid-immersed
distribution transformers are sold directly (more than 80%) to the
utilities through our agents or manufacturing representatives. (Howard,
No. 59 at p. 2) DOE notes that the distribution channels used in the
preliminary analysis include a large fraction of sales as being direct
to purchases by utilities that would encompass the circumstances
described by Howard, as shown in Table IV.5.\68\ For this analysis DOE
maintained the distribution channels distribution channels described in
its preliminary analysis.
---------------------------------------------------------------------------
\68\ See: Technical Support Document, chapter 2, page 2-58.
https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0040.
---------------------------------------------------------------------------
Chapter 6 of the NOPR TSD provides details on DOE's development of
markups for distribution transformers.
E. Energy Use Analysis
The energy use analysis produces energy use estimates and end-use
load shapes for distribution transformers. The energy use analysis
estimates the range of energy use of distribution transformers in the
field (i.e., as they are used by consumers) enabling evaluation of
energy savings from the operation of distribution transformer equipment
at various efficiency levels, while the end-use load characterization
allows evaluation of the impact on monthly and peak demand for
electricity. The energy use analysis provides the basis for other
analyses DOE performed, particularly assessments of the energy savings
and the savings in operating costs that could result from adoption of
amended or new standards.
As presented in section IV.C transformers losses can be categorized
as ``no-load'' or ``load.'' No-load losses are roughly constant with
the load on the transformer and exist whenever the distribution
transformer is energized (i.e., connected to electrical power). Load
losses, by contrast, are zero at when the transformer is unloaded, but
grow quadratically with load on the transformer.
Because the application of distribution transformers varies
significantly by type of distribution transformer (liquid-immersed or
dry-type) and ownership (electric utilities own approximately 95
percent of liquid-immersed distribution transformers; commercial/
industrial entities use mainly dry type), DOE performed two separate
end-use load analyses to evaluate distribution transformer efficiency.
The analysis for liquid-immersed distribution transformers assumes that
these are owned by utilities and uses hourly load and price data to
estimate the energy, peak demand, and cost impacts of improved
efficiency. For dry-type distribution transformers, the analysis
assumes that these are owned by commercial and industrial (``C&I'')
entities, so the energy and cost savings estimates are based on monthly
building-level demand and energy consumption data and marginal
electricity prices. In both cases, the energy and cost savings are
estimated for individual distribution transformers and aggregated to
the national level using weights derived from transformer shipments
data.
1. Hourly Load Model
For utilities, the cost of serving the next increment of load
varies as a function of the current load on the system. To
appropriately estimate the cost impacts of improved distribution
transformer efficiency in the Life-cycle Cost (LCC) analysis, it is
therefore important to capture the correlation between electric system
loads and operating costs and between individual distribution
transformer loads and system loads. For this reason, DOE estimated
hourly loads on individual liquid-immersed distribution transformers
using a statistical model that simulates two relationships: (1) the
relationship between system load and system marginal price; and (2) the
relationship between the distribution transformer load and system load.
Both are estimated at a regional level. Distribution transformer
loading is an important factor in determining which types of
distribution transformer designs will deliver a specified efficiency,
and for calculating distribution transformer losses, and the time
dependent values of those losses. To inform the hourly load model DOE
examined the data made available through the IEEE Distribution
Transformer Subcommittee Task Force.
a. Hourly Per-Unit Load (PUL)
GEUS commented that because of load diversity, individual
distribution transformer capacity (kVA) per home depends on the number
of homes connected to the transformer. For example, GEUS will place a
15 kVA transformer for a single 1200 square foot home, but 8 of these
homes can be served by a single 50 kVA transformer. GEUS further
commented that to balance transformer core (no-load) losses and
resistive (load) losses their design strategy is to serve as many homes
as possible within a 300 feet radius of the transformer. This design
reduces transformer core (no-load) losses by reducing the transformer
kVA/home, thereby reducing the ratio of no-load to load losses on each
transformer. (GEUS, No. 58 at p. 1) Howard commented that it is their
understanding that in some rural areas, there are transformers that are
very lightly loaded, and in other areas, some units are loaded much
more than 50 percent (Howard, No. 59 at p. 3) NEMA commented that the
in-situ PUL varies widely from region to region and customer to
customer. (NEMA, No. 50 at p. 12)
The Advocates asserted that DOE's estimation of PUL to be too high
and that if DOE decides to maintain these PUL inputs at their current
values, the Department should provide a sensitivity analysis that
enables commenters to evaluate the effect of PUL assumptions on the
overall energy savings and economic analysis. (Efficiency Advocates,
No. 52 at p. 6) Additionally, they commented that they believe DOE may
be overestimating initial PUL (sic) in the preliminary analysis; this
may negatively affect higher EL designs that prioritize core loss
reductions and they urged DOE to update its assumptions based on
recently available data. (Efficiency Advocates, No. 52 at pp. 2, 5)
Metglas commented that it is not possible to derive transformer PUL
just from the meter data. To get a transformer's PUL, one must
associate which meters are getting supplied from which transformer.
Further Metglas commented that, the data has come from only 127 zip
codes adjacent to each other. Metglas asserted that the sample is too
small to draw conclusions at the National level, and suggested that DOE
base their ruling on data submitted by Electric Utilities to the IEEE
Transformer Committee which indicates
[[Page 1771]]
that the average PUL on transformers are in the 0.1-0.2 values.
(Metglas, No. 53 at p. 7-8)
NEEA further noted that the per-unit bases for both the system and
individual transformer loads in the joint histogram estimates are not
related to the transformer per-unit loads using nameplate capacities as
the basis. They claim that this means that the loading estimates
obtained from the joint histograms cannot be directly applied to the
cited transformer loss formula, since the latter assumes a per-unit
loading on a capacity basis. (NEEA, No. 51 at p. 2-3)
In this NOPR, DOE applied the same approach it used in the August
2021 preliminary analysis where the hourly PUL is a function of both
the transformer's simulated load and initial peak load (IPL). Where:
PUL = simulated loadhourly x IPL.
To capture the wide diversity in distribution transformer loading
that is observed in the field, DOE used a two-step approach.
Transformer load data were used to develop a set of joint probability
distribution functions (JPDF) which capture the relationship between
individual transformer loads and the total system load.\69\ The
transformer loads were calculated as the sum load of all connected
meters on a given transformer for each available hour of the year.
Because the system load is the sum of the individual transformer loads,
the value of the system load in a given hour conditions the probability
of the transformer load taking on a particular value. To represent the
full range of system load conditions in the U.S., DOE used FERC Form
714 \70\ data to compile separate system load PDFs for each census
division. These system PDFs are combined with a selected transformer
JPDF to generate a simulated load appropriate to that system. As the
simulated transformer loads are scaled to a maximum of one, to
calculate the losses, the load is multiplied by a scaling factor
selected from the distribution of Initial Peak Loads (IPL), and by the
capacity of the representative unit being modeled. In the August 2021
preliminary analysis, DOE defined the IPL as a triangular distribution
between 50 and 130 percent of a transformer's capacity with a mean of
85 percent. This produces an hourly distribution of PUL values from
which hourly load losses are determined. These distributions of loads
capture the variability of distribution transformers load diversity,
from very low to very high loads, that are seen in the field.
---------------------------------------------------------------------------
\69\ See: Distribution Transformer Load Simulation Inputs,
Technical Support Document, chapter 7.
\70\ https://www.ferc.gov/industries-data/electric/general-information/electric-industry-forms/form-no-714-annual-electric/data.
---------------------------------------------------------------------------
In response to the comments from the Advocates and Metglas, DOE
revised the IPL assumptions in this NOPR to more closely align the
resulting PUL with data made available through the IEEE Distribution
Transformer Subcommittee Task Force. The revised mean PULs for liquid-
immersed representative unit used in this NOPR are shown in Table IV.6.
Table IV.6--Distribution of Per-Unit-Load for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Mean
Rep. unit simulated Mean IPL Mean PUL
hourly load
----------------------------------------------------------------------------------------------------------------
1............................................................... 0.29 0.75 0.22
2............................................................... 0.27 0.75 0.20
3............................................................... 0.32 0.75 0.24
4............................................................... 0.26 0.75 0.20
5............................................................... 0.31 0.75 0.23
----------------------------------------------------------------------------------------------------------------
b. Joint Probability Distribution Function (JPDF)
NEEA commented that when processing the load data into JPDF of
loads that observed hourly loads for both commercial and residential
customers were scaled by corresponding annual maxima prior to being
counted towards the joint histogram, so that the observations may be
treated as if on a per-unit basis. This is inconsistent with the per-
unit notion in power systems, but permissible in this context if so
stated. However, the problem of bias applied to an entire set of
observations for a given transformer or ``system'' by an abnormally
large (or small) peak observation is not acknowledged and therefore not
treated. (NEEA, No. 51 at p. 2). DOE notes that the transformer data
were screened to remove outliers before being used to construct JPDFs;
a small number of transformers in the database may none-the-less have
quite large or quite small peak loads, but the associated low
probability leads to minimal impact on the energy loss calculations.
The data will be reviewed again to ensure that outliers have been
removed.
NEEA found issue with DOE's terminology in the TSD, which stated
that DOE applies the joint histogram as a measure of correlation; and
this is not the typical interpretation of joint probability. NEEA
further recommended that a covariance-based measure (e.g., correlation
coefficient) is the appropriate class of metric in this case because
the subject load processes will necessarily be related as a consequence
of common influences, each of which is in turn a stochastic process.
(NEEA, No. 51 at pp. 2-3) In response, DOE agrees with NEEA's comment
that the term ``correlation'' used in the TSD is not appropriate. The
system load is the sum of the loads on individual transformers, so the
system load and transformer loads are not independent random variables.
The relationship between the two, represented by the JPDF, is a
conditional probability distribution. DOE attempts to document its
analyses in plain language, and the term correlation was used simply to
indicate that the relationship between the transformer and system loads
is not random. For this NOPR DOE will continue to use the term
correlation to describe the general relationship between transformer
and system loads, using footnotes to provide technical precision as
needed.
On the topic of industrial loads for liquid-immersed distribution
transformers NEEA asserted that as describe in the TSD appendix 7A,
that in the case of industrial customers, actual transformer load data
were not available and would be problematic for the estimation of the
subject joint histograms. (NEEA, No. 18 at p. 2) At the time of the
August 2021 Preliminary Analysis TSD, DOE was unable to acquire the
transformer loads from industrial customers. As discussed in
[[Page 1772]]
TSD appendix 7A, DOE was able to include the hourly meter loads from
industrial customers, which contain hourly variability in load factor,
as proxies for transformer loads--which were included in its database
of JPDFs.
DOE requests comment or data showing hourly transformer loads for
industrial customers.
NEEA additionally requested that DOE rationalize the choice of bin
resolution in the joint histogram estimates. (NEEA, No. 51 at p. 2) In
the August 2021 Preliminary Analysis TSD, DOE applied the same
methodology to the creation and population of JPDFs as it did in the
April 2013 Standards Final Rule. For the April 2013 Standards Final
Rule, DOE balanced the bin resolution to 10 bins to ensure that each
bin contained sufficient data to be sampled during its Monte Carlo
simulation (~2 percent of samples per bin), this was also balanced
against the computational limits of preforming this model within an
Excel spreadsheet. For the August 2021 Preliminary Analysis TSD, DOE
considered increasing the bin count, but after testing found that this
did not significantly alter the resulting averages, as such DOE elected
to maintain the approach that stakeholders were already familiar with.
For this NOPR, DOE will maintain the 10 bins that were applied in the
August 2021 Preliminary Analysis TSD.
2. Monthly Per-Unit Load (PUL)
Powersmiths commented that, in the context of low-voltage dry-type
distribution transformers, it has consistently measured much lower
typical loading levels, across most vertical markets, in the range of
15-25 percent of nameplate capacity, which is in line with the
publication in 1999 with the Cadmus Group Study and supported
frequently since then in industry and at previous rulemaking sessions.
(Powersmiths, No. 46 at p. 1)
DOE received no further comments on the in-field PUL for dry-type
distribution transformers. Since the comments from Powersmiths align
with DOE's analysis which shows an average RMS PUL for dry-type
transformers to be in 16-27 percent of nameplate capacity DOE did not
make any changes to its dry-type load model for this NOPR.
3. Future Load Growth
In its August 2021 Preliminary Analysis TSD, DOE applied an annual
load growth rate of 0.9 percent, based on U.S. Energy Information
Administration (``EIA''), Annual Energy Outlook (``AEO'') 2021
projected purchased electricity: delivered electricity trend, to
liquid-immersed transformers, and zero percent for low- and medium-
voltage dry-type transformers.\71\ On the subject of future load growth
DOE received comments from EEI, CDA, Howard, Efficiency Advocates,
Metglas. and NEMA.
---------------------------------------------------------------------------
\71\ TSD chapter 2, p. 2-63, August 2021. https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0040.
---------------------------------------------------------------------------
Both EEI and CDA commented that they believe that loads on
individual liquid-immersed distribution transformers will increase over
the equipment's lifetimes due to several factors. Both speculated that
the increase in loads will be driven by evolving ``mega trends'' in the
electric utility industry, specifically increased electric vehicle
charging, and increased building electrification. (EEI No. 56 at p. 2;
CDA No. 47 at p. 1) The CDA further commented that EEI has projected
loading increases of 10-50 percent over the forecast period that will
greatly change operating practices in the utilities. This suggests the
increasing importance of transformer load losses as well as balance and
minimization of total losses. (CDA, No. 47 at p. 2) Howard commented
that we are at the threshold of having many electric vehicles (EV) that
will require a lot of energy use through the transformer. How quickly
this will happen, remains to be seen. (Howard, No. 59 at p. 3)
NEMA commented that while they could not state with certainty what
the appropriate load growth rate would be, they disagreed with an
assumption of zero percent load growth. (NEMA, No. 50 at p. 13)
The Advocates, and Metglas challenged DOE application of a 0.9
percent annual load growth for liquid-immersed distribution
transformers. Both asserted that the assumption of load growth rate
applied to liquid-immersed distribution transformers of 0.9 percent per
year was not justified as the National growth in electric demand will
be matched by increased distribution capacity. They asserted that the
load growth rate assumed by DOE, the average increase in annual
electricity sales from AEO, is not entirely driven by increased
electrical load on existing liquid-immersed distribution transformers,
but in fact driven by grid expansion. (Advocates, No. 52 at pp. 5-6;
Metglas, No. 53 at pp. 1, 5-6)
Additionally, the Advocates commented that they believe utilities
will plan conservatively by installing larger transformers capable of
handling rare peak demand events. Citing as evidence the IEEE load data
as suggesting utilities are already doing this as the reported average
peak loads were only 50 percent of nameplate capacity. Utility
decisions for how they size transformers are unlikely to change for new
and replacement transformer installations given the uncertainties
around future electricity demand. (Efficiency Advocates, No. 52 at pp.
5-6) This notion was supported by NEMA who commented that as consumer
demand (for electricity) increases due to the migration to all-electric
homes and buildings, and it stands to reason that kVA sizes will
increase over time as utilities upgrade capacity to serve these
consumer demands. Likewise, investments in renewable energy generation
will cause changes to transformer shipments, unit sizes and selections.
(NEMA, No. 50 at p. 16)
As the August 2021 Preliminary Analysis TSD indicated, and by the
comments received, there are many factors that potentially impact
future distribution transformer load growth, and that these factors may
be in opposition. At this time, many utilities, states, and
municipalities are pursuing electric vehicle charging programs, it is
unclear the extent to which increases in electricity demand for
electric vehicle charging, or other state level decarbonization efforts
will impact current distribution transformer sizing practices (for
example, whether distribution utilities plan to upgrade their systems
to increase the capacity of connected distribution transformers--thus
maintaining current loads as a function of distribution transformer
capacity; or if distribution utilities do not plan to upgrade their
systems and will allow the loads on existing distribution transformers
to rise). EEI, CDA, and Howard speculate that these initiatives will
increase the intensive per-unit-load over time as a function of per
unit of installed capacity. However, they did not provide any
quantitative evidence that this is indeed happening on the distribution
systems, or regions which are moving forward with decarbonization
efforts. Further, the hypothesis that intensive load growth will be a
factor in the future is not supported by the available future trends in
AEO2022, as indicated by the purchased electricity trend as it
represents the delivered electricity to the customer. The Advocates and
Metglas asserted that the load growth rate 0.9 percent per year was too
great, and that higher loads in response to decarbonization initiatives
would be met with the extensive growth of the distribution system,
i.e., increasing the total capacity of the distribution system
[[Page 1773]]
through larger distribution transformers, or greater shipments, or some
combination of both. Again, neither the Advocates nor Metglas provided
any data to support their position. For this NOPR, DOE finds that
neither position provides enough evidence to change its assumptions
from the August 2021 Preliminary Analysis TSD. For this NOPR, DOE
updated its load growth assumption for liquid-immersed distribution
transformers based on the change in average growth of AEO2022:
Purchased Electricity: Delivered Electricity at 0.5 percent.\72\
---------------------------------------------------------------------------
\72\ www.eia.gov/outlooks/aeo/data/browser/#/?id=2-
AEO2022®ion=1-
0&cases=ref2022&start=2020&end=2050&f=A&linechart=ref2022-
d011222a.152-2-AEO2022.1-0~ref2022-d011222a.104-2-AEO2022.1-
0&map=ref2022-d011222a.4-2-AEO2022.1-0&ctype=linechart&sourcekey=0.
---------------------------------------------------------------------------
To help inform DOE's prediction of future load growth trend, DOE
seeks data on the following for regions where decarbonization efforts
are ongoing. DOE seeks hourly PUL data at the level of the transformer
bank for each of the past five years to establish an unambiguous
relationship between transformer loads and decarbonization policy and
inform if any intensive load growth is indeed occurring. Additionally,
DOE seeks the average capacity of shipment into regions where
decarbonization efforts are occurring over the same five-year period to
inform the rate of any extensive load growth that may be occurring in
response to these programs.
4. Harmonic Content/Non-Linear Loads
Harmonic current refers to electrical power at alternating current
frequencies greater than the fundamental frequency. Distribution
transformers in service are commonly subject to (and must tolerate)
harmonic current of a degree that varies by application.
Powersmiths commented that the effects of harmonic content on LVDT
can create significant customer risk due to transformer overheating,
particularly when the transformer is under heavy loads. This was
primarily an issue when general purpose transformers are installed
outside prescribed harmonic limits. (Powersmiths No. 18 at p. 3)
Additionally, Powersmiths asserted that because DOE does not
account for harmonic content in its loading analysis that it
misrepresents the impact of additional heat on losses. Powersmiths
concluded that light loading means the harmonic-related heat does not
typically threaten the transformer, but it is not an excuse to leave
this hidden risk unsaid as the load on any given transformer could be
taken to full capacity based on its nameplate rating, and associated
protection, at any time during its long life. (Powersmiths No. 18 at p.
3) NEEA requested that for the next energy conservation lookback that
DOE include harmonic content in its analysis (NEEA No. 18 at p. 4)
In response to the commenters regarding the inclusion of harmonic
content, DOE agrees with NEEA and that in addition to determining the
necessary input to adequately model the impacts of harmonic content at
the National level, DOE would also have to consider how changes in
transformer design would affect the availability of designs and the
impacts on efficiency. DOE further concurs with Powersmiths that, on
average, distribution transformers are lightly loaded, as shown in its
analysis (see section IV.E.2) and that harmonic heat would not
typically be an issue and would likely have minimal impact on the
transformers covered by this NOPR. For this NOPR DOE will not consider
the impacts of harmonic content but may examine them at a future date.
DOE notes that the installation and commissioning of distribution
transformers, either general purpose or specialty equipment, falls
outside the Department's authority and would be under the purview of
local building or fire codes and ordinances.
Chapter 7 of the NOPR TSD provides details on DOE's energy use
analysis for distribution transformers.
F. Life-Cycle Cost and Payback Period Analysis
DOE conducted LCC and PBP analyses to evaluate the economic impacts
on individual consumers of potential energy conservation standards for
distribution transformers. The effect of new or amended energy
conservation standards on individual consumers usually involves a
reduction in operating cost and an increase in purchase cost. DOE used
the following two metrics to measure consumer impacts:
[ballot] The LCC is the total consumer expense of an appliance or
product over the life of that product, consisting of total installed
cost (manufacturer selling price, distribution chain markups, sales
tax, and installation costs) plus operating costs (expenses for energy
use, maintenance, and repair). To compute the operating costs, DOE
discounts future operating costs to the time of purchase and sums them
over the lifetime of the product.
[ballot] The PBP is the estimated amount of time (in years) it
takes consumers to recover the increased purchase cost (including
installation) of a more-efficient product through lower operating
costs. DOE calculates the PBP by dividing the change in purchase cost
at higher efficiency levels by the change in annual operating cost for
the year that amended or new standards are assumed to take effect.
For any given efficiency level, DOE measures the change in LCC
relative to the LCC in the no-new-standards case, which reflects the
estimated efficiency distribution of distribution transformers in the
absence of new or amended energy conservation standards. In contrast,
the PBP for a given efficiency level is measured relative to the
baseline product.
For each considered efficiency level in each product class, DOE
calculated the LCC and PBP for a nationally representative set of
electric distribution utilities, and commercial and industrial
(``C&I'') customers. As stated previously, DOE developed these
customers samples from various sources, including utility data from the
Federal Energy Regulatory Commission (FERC), Energy Information Agency
(EIA); and C&I data from the Commercial Building Energy Consumption
Survey (CBECS), and Manufacturing Energy Consumption Survey (MECS). For
each sample, DOE determined the energy consumption, in terms of no-load
and load losses for the distribution transformers and the appropriate
electricity price. By developing a representative sample of consumer
entities, the analysis captured the variability in energy consumption
and energy prices associated with the use of distribution transformer.
Inputs to the calculation of total installed cost include the cost
of the equipment--which includes MSPs, retailer and distributor
markups, and sales taxes--and installation costs. Inputs to the
calculation of operating expenses include annual energy consumption,
electricity prices and price projections, repair and maintenance costs,
equipment lifetimes, and discount rates. DOE created distributions of
values for equipment lifetime, discount rates, and sales taxes, with
probabilities attached to each value, to account for their uncertainty
and variability.
The computer model DOE uses to calculate the LCC and PBP relies on
a Monte Carlo simulation to incorporate uncertainty and variability
into the analysis. The Monte Carlo simulations randomly sample input
values from the probability distributions and distribution transformer
samples. For this rulemaking, the Monte Carlo approach is implemented
as a computer simulation. The model calculated the LCC and PBP for
products at each
[[Page 1774]]
efficiency level for 10,000 individual distribution transformer
installations per simulation run. The analytical results include a
distribution of 10,000 data points showing the range of LCC savings for
a given efficiency level relative to the no-new-standards case
efficiency distribution. In performing an iteration of the Monte Carlo
simulation for a given consumer, product efficiency is as a function of
the consumer choice model described in section IV.F.3 of this document.
If the chosen equipment's efficiency is greater than or equal to the
efficiency of the standard level under consideration, the LCC and PBP
calculation reveals that a consumer is not impacted by the standard
level. By accounting for consumers who already purchase more-efficient
products, DOE avoids overstating the potential benefits from increasing
product efficiency.
DOE calculated the LCC and PBP for all consumers of distribution
transformers as if each were to purchase a new equipment in the
expected year of required compliance with new or amended standards.
Amended standards would apply to distribution transformers manufactured
3 years after the date on which any new or amended standard is
published. At this time, DOE estimates publication of a final rule in
2024. Therefore, for purposes of its analysis, DOE used 2027 as the
first year of compliance with any amended standards for distribution
transformers.
Table IV.7 summarizes the approach and data DOE used to derive
inputs to the LCC and PBP calculations. The subsections that follow
provide further discussion. Details of the model, and of all the inputs
to the LCC and PBP analyses, are contained in chapter 8 of the NOPR TSD
and its appendices.
Table IV.7--Summary of Inputs and Methods for the LCC and PBP Analysis *
------------------------------------------------------------------------
Inputs Source/method
------------------------------------------------------------------------
Equipment Cost.................... Derived by multiplying MPCs by
manufacturer and retailer markups
and sales tax, as appropriate. Used
historical data to derive a price
scaling index to project product
costs.
Installation Costs................ Assumed no change with efficiency
level.
Annual Energy Use................. The total annual energy use
multiplied by the hours per year.
Average number of hours based on
field data.
Variability: Based on distribution
transformer load data or customer
load data.
Electricity Prices................ Hourly Prices: Based on EIA's Form
861 data for 2015, scaled to 2021
using AEO2022.
Variability: Regional variability is
captured through individual price
signals for each EMM region.
Monthly Prices: Based on an analysis
of EEI average bills, and
electricity tariffs from 2019,
scaled to 2021 using AEO2022.
Variability: Regional variability is
captured through individual price
signals for each Census region.
Energy Price Trends............... Based on AEO2022 price projections.
Repair and Maintenance Costs...... Assumed no change with efficiency
level.
Product Lifetime.................. Average: 32 years, with a maximum of
60 years.
Discount Rates.................... Approach involves identifying all
possible debt or asset classes that
might be used to purchase the
considered equipment or might be
affected indirectly. Primary data
source was the Federal Reserve
Board's Survey of Consumer
Finances.
Compliance Date................... 2027.
------------------------------------------------------------------------
* References for the data sources mentioned in this table are provided
in the sections following the table or in chapter 8 of the NOPR TSD.
1. Equipment Cost
To calculate consumer product costs, DOE multiplied the MPCs
developed in the engineering analysis by the markups described
previously (along with sales taxes). DOE used different markups for
baseline products and higher-efficiency products, because DOE applies
an incremental markup to the increase in MSP associated with higher-
efficiency products.
To forecast a price trend for this NOPR, DOE maintained the
approach employed in the August 2021 Preliminary Analysis TSD, where it
derived an inflation-adjusted index of the Producer Price Index
(``PPI'') for electric power and specialty transformer manufacturing
from 1967 to 2019.\73\ These data show a long-term decline from 1975 to
2003, and then increase since then. There is considerable uncertainty
as to whether the recent trend has peaked, and would be followed by a
return to the previous long-term declining trend, or whether the recent
trend represents the beginning of a long-term rising trend due to
global demand for distribution transformers and rising commodity costs
for key distribution transformer components. Given the uncertainty, DOE
chose to use constant prices (2021 levels) for both its LCC and PBP
analysis and the NIA. For the NIA, DOE also analyzed the sensitivity of
results to alternative distribution transformer price forecasts.
---------------------------------------------------------------------------
\73\ For this NOPR DOE maintained its use of the two Produce
Price Indexes published by the U.S. Bureau of Labor Statistics for:
Electric power and specialty transformer PPI (PCU335311335311), and
Power and distribution transformers PPI (PCU3353113353111).
---------------------------------------------------------------------------
DOE did not receive any comments regarding its determination of
future equipment costs and did not make any changes for this NOPR.
2. Efficiency Levels
For this NOPR, DOE analyzed different efficiency levels, these are
expressed as a function of loss reduction over the equipment baseline.
For units greater than 2,500 kVA, there is not a current baseline
efficiency level that must be met. Therefore, DOE established EL1 for
these units as if they were aligning with the current energy
conservation standards efficiency vs kVA relationship, scaled to the
larger kVA sizes. To calculate this, DOE scaled the maximum losses of
the minimally compliant 2,500 kVA unit to the 3,750 kVA size using the
equipment class specific scaling relationships in TSD appendix 5C. For
example, a 2,500 kVA unit that meets current energy conservation
standards is 99.53 percent efficient and has 5903 W of loss at 50
percent load. Using the 0.79 scaling relationship for three-phase
liquid-immersed distribution transformers, described in appendix 5C,
the losses of a 3,750 kVA unit would be 8131 W, corresponding to 99.57
percent efficient at 50 percent load.
EL2 through EL5 align with the same percentage reduction in loss as
their respective EC but rather than being relative to a baseline level,
efficiency levels were established relative to EL1 levels.
[[Page 1775]]
The rate of reduction is shown in Table IV.8, and the corresponding
efficiency ratings in Table IV.9.
Table IV.8--Efficiency Levels as Percentage Reduction of Baseline Losses
----------------------------------------------------------------------------------------------------------------
EL
Equipment type -------------------------------------------------------------------------------
1 2 3 4 5 (max-tech)
----------------------------------------------------------------------------------------------------------------
Liquid-immersed:
<=2,500 kVA................. 2.5 5 10 20 40
>2,500 kVA.................. * 40 ** 5 ** 10 ** 20 ** 40
Low-voltage Dry-type:
1[phis]..................... 10 20 30 40 50
3[phis]..................... 5 10 20 30 40
----------------------------------------------------------------------------------------------------------------
Medium-voltage Dry-type:
<46 kV BIL.................. 5 10 20 30 40
>=46 and <96 kV BIL, and 5 10 20 30 40
<=2,500 kVA................
>=46 and <96 kV BIL, and * 43 ** 10 ** 20 ** 30 ** 40
>2,500 kVA.................
>=96 kV BIL and <=2,500 kVA. 5 10 20 30 35
>=96 kV BIL and >2,500 kVA.. * 34 ** 10 ** 20 ** 30 ** 35
----------------------------------------------------------------------------------------------------------------
* Equipment currently not subject to standards. Therefore, reduction in losses relative to least efficient
product on market.
** Reduction in losses relative to EL1.
Table IV.9--Efficiency Levels
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency level
Rep. unit kVA -----------------------------------------------------------------------------------------------
0 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
1....................................... 50 99.11 99.13 99.15 99.20 99.29 99.46
2....................................... 25 98.95 98.98 99.00 99.05 99.16 99.37
3....................................... 500 99.49 99.50 99.52 99.54 99.59 99.69
4....................................... 150 99.16 99.18 99.20 99.24 99.33 99.49
5....................................... 1,500 99.48 99.49 99.51 99.53 99.58 99.69
6....................................... 25 98.00 98.20 98.39 98.60 98.79 98.99
7....................................... 75 98.60 98.67 98.74 98.88 99.02 99.16
8....................................... 300 99.02 99.07 99.12 99.22 99.31 99.41
9....................................... 300 98.93 98.98 99.04 99.14 99.25 99.36
10...................................... 1,500 99.37 99.40 99.43 99.50 99.56 99.62
11...................................... 300 98.81 98.87 98.93 99.05 99.16 99.28
12...................................... 1,500 99.30 99.33 99.37 99.44 99.51 99.58
13...................................... 300 98.69 98.75 98.82 98.95 99.08 99.14
14...................................... 2,000 99.28 99.32 99.35 99.42 99.49 99.53
15...................................... 112.5 99.11 99.13 99.15 99.20 99.29 99.46
16...................................... 1,000 99.43 99.44 99.46 99.49 99.54 99.66
17...................................... 3,750 n.a. 99.57 99.59 99.61 99.66 99.74
18...................................... 3,750 n.a. 99.48 99.53 99.58 99.64 99.69
19...................................... 3,750 n.a. 99.41 99.47 99.53 99.59 99.62
--------------------------------------------------------------------------------------------------------------------------------------------------------
DOE did not receive any comment regarding the loss rates, nor the
efficiency levels applied in the preliminary analysis, and continued
their use for this NOPR.
DOE requests comments on its methodology for establishing the
energy efficiency levels for distribution transformers greater than
2,500 kVA. DOE request comment on its assumed energy efficiency
ratings.
3. Modeling Distribution Transformer Purchase Decision
In the August 2021 Preliminary Analysis TSD, DOE presented its
assumption on how distribution transformers were purchased. DOE used an
approach that focuses on the selection criteria customers are known to
use when purchasing distribution transformers. Those criteria include
first costs, as well as the Total-Owning Cost (``TOC'') method. The TOC
method combines first costs with the cost of losses. Purchasers of
distribution transformers, especially in the utility sector, have
historically used the TOC method to determine which distribution
transformers to purchase. However, comments received from stakeholders
responding to the 2012 ECS NOPR (77 FR 7323) and the June 2019 RFI (84
FR 28254) indicate that the widespread practice of concluding the final
purchase of a distribution transformer based on TOC is rare, instead
customers have been purchasing the lowest first cost transformer design
regardless of its loss performance.
The utility industry developed TOC evaluation as a tool to reflect
the unique financial environment faced by each distribution transformer
purchaser. To express variation in such factors as the cost of electric
energy, and capacity and financing costs, the utility industry
developed a range of evaluation factors: A and B values, to use in
their calculations.\74\ A and B are the
[[Page 1776]]
equivalent first costs of the no-load and load losses (in $/watt),
respectively.
---------------------------------------------------------------------------
\74\ In modeling the purchase decision for distribution
transformers DOE developed a probabilistic model of A and B values
based on utility requests for quotations when purchasing
distribution transformers. In the context of the LCC the A and B
model estimates the likely values that a utility might use when
making a purchase decision.
---------------------------------------------------------------------------
In response to the August 2021 Preliminary Analysis TSD, DOE
received the following comments regarding the modeling of distribution
transformer purchases.
a. Basecase Equipment Selection
Regarding how engineering designs were selected by the consumer
choice model in the LCC, DOE received comments from Metglas and the
Efficiency Advocates. Metglas commented that it did not agree with the
DOE purchase decision model. Stating that the fraction of designs using
amorphous steel as a core material were grossly overstated in the
standards, and no-new standards cases. Metglas further stated that
currently the fraction of amorphous core distribution transformers is
on the order of 2-3 percent of the market and that this fraction has
been constant for the past 7 years. (Metglas, No. 53 at pp. 1-2)
Additionally, the Efficiency Advocates recommended that DOE take ``a
hard look at'' the purchasing behaviors of distribution transformers in
the current marketplace. (Efficiency Advocates, No. 40 at p. 83)
In response to these comments DOE examined its responses received
during manufacturer interviews. From these responses, DOE understands
that in the current market that amorphous core distribution
transformers (both liquid-immersed and dry-type) are shipped in limited
quantities, supporting Metglas' claim. The reason for this is believed
to be limitations in amorphous core fabricating capacity among
manufacturers. DOE's research indicates that distribution transformers
can be fabricated with amorphous core steels that are cost competitive
with conventional steels as shown in the engineering analysis (see
section IV.C), but they cannot currently be fabricated in the
quantities needed to meet the large order requirement of electric
utilities, and as such, are limited to niche products. Accordingly, DOE
has updated its customer choice model and, in the no-new standards case
has limited type of core steel materials to the ratios shown in Table
IV.10.
Table IV.10--Core Material Limits in the No-New Standards Case
------------------------------------------------------------------------
------------------------------------------------------------------------
Baseline Steel for Liquid-Immersed: Baseline Steel for Dry-Type:
87% M3 or 23hib090. 97% M4 or hib-M4 (M3 as
modeled).
3% Amorphous (mostly 3% PDR.
in TOC applications above
standards).
10% 23PDR085. 0% AM.
------------------------------------------------------------------------
Based on interviews with manufactures, and supporting research, DOE
finds that there are no global supply constraints of amorphous ribbon
for fabrication into transformer cores. And in the potential new-
standards case, DOE does not limit the selection of the designs in the
engineering database by core material type. Further, DOE understands
that there are current production limitations for turning amorphous
ribbons into transformer cores that would require the capital
investment in ribbon cutting, and core stacking machines at higher
intensities to meet the quantity requirements placed on manufacturers
by electric utilities. The impacts of the additional capital investment
on manufacturers in the potential new-standards case are captured in
manufacturer impact analysis described in section IV.J of this
document.
b. Total Owning Cost (``TOC'') and Evaluators
In the August 2021 Preliminary Analysis TSD, DOE used TOC
evaluation rates as follows: 10 percent of liquid-immersed transformer
purchases were concluded using TOC, and 0 percent of low-voltage dry-
type and medium-voltage dry-type transformer purchases were concluded
using TOC. DOE received comment from several stakeholders regarding the
rates at which TOC are practiced.
NEMA commented that the experience among their members varies, but
in NEMA's experience the percentage of TOC use in purchasing decisions
for three-phase designs is higher than 10 percent: varying between 15-
20 percent, and for single-phase designs, they believe the use of TOC
in purchasing decisions is closer to 40 percent. (NEMA, No. 50 at p.
13) Additionally, NEMA responded to DOE's request for information
relating customer application of TOC as a function of distribution
transformer capacity. NEMA responded that NEMA did not have detailed
information on breakouts of TOC purchasing influence by kVA and that
their members are investigating whether their customer information can
be analyzed for useful insight on this subject (NEMA, No. 50 at pp. 13-
14) Metglas commented that few transformer purchasers are using TOC
evaluations, and 10 percent may be a reasonable estimate for those
still using TOC. And in their experience the few remaining TOC
evaluators reveal that they will abandon TOC as soon as their existing
tenders are delivered.; leading to speculation that this practice could
be nearly extinct within the next 2-3 years. (Metglas, No. 53 at p. 6)
DOE estimated the rate of consumers using TOC as a tool to inform
the purchase of a distribution transformer to be 10 percent for liquid-
immersed distribution transformers. These rates were established in
response to stakeholder comments in the February 2012 NOPR (77 FR 7323)
to which DOE received no adverse comments. Further, these rates were
again put forward for comment in the June 2019 RFI (84 FR 28254) to
which DOE did not receive any adverse comments.\75\ In light of this
long history of established low rates of TOC adoption for the purchase
of distribution transformers DOE finds the comments received from NEMA
to be inconsistent with historical comments from a wide range of
stakeholders. Ibid. For this NOPR, DOE is maintaining the same rates of
TOC evaluators established in the August 2021 ECS Preliminary Analysis
TSD, however, DOE recognizes that circumstances change over time and
has included in this NOPR a LCC sensitivity case with evaluation rates
suggested by NEMA. The result of this sensitivity analysis can be found
in appendix 8G of the TSD.
---------------------------------------------------------------------------
\75\ Please see the summary of comments regarding the rate of
evaluators in the August 2021 ECS Preliminary Analysis, Technical
Support Document, p 2-69; https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0023.
---------------------------------------------------------------------------
Powersmiths commented that it is not true that 100 percent of LVDT
distribution transformers are purchased on minimum first cost, adding
that their market is selling only distribution
[[Page 1777]]
transformers that significantly exceed minimum efficiency standards and
the NEMA Premium transformer market existed prior to the 2016 energy
conservation standards. (Powersmiths, No. 46 at pp. 3-4) Powersmiths
commented that minimum efficiency is rarely the optimal choice for
consumers and there is value in both new construction and retrofits
that exceed energy conservation standards. (Powersmiths, No. 46 at p.
4) Powersmiths added that trends toward green buildings have increased
the number of consumers looking at value beyond first cost which may
increase the value-added LVDT market. (Powersmiths, No. 46 at p. 4)
DOE recognizes that distribution transformers are purchased at
different efficiency levels depending on the specific demands of
consumers. For this analysis DOE did not receive a specific fraction of
LVDT distribution transformers that were sold above the current
standard, in the absence of such information DOE relied on the consumer
choice model to determine the equipment price in addition to the
fraction of equipment sold with higher performance cores constructed
from PDR steel, as discussed in section IV.F.3.a of this document.
Band of Equivalents (``BOE'')
In the August 2021 Preliminary Analysis TSD, DOE proposed the
following definition for Band of Equivalents (``BOE''): as a method to
establish equivalency between a set of transformer designs within a
range of similar TOC. BOE is defined as those transformer designs
within a range of similar TOCs; the range of TOC varies from utility to
utility and is expressed in percentage terms. In practice, the
purchaser would consider the TOC of the transformer designs within the
BOE and would select the lowest first-cost design from this set.
NEMA agreed with the Department's assumptions with respect to their
reflection of industry experiences and practices. NEMA further stated
that its members are investigating whether their customer information
can be analyzed for useful insight on this subject. (NEMA, No. 50 at p.
13) Metglas comment that BOE within a TOC calculation is often used
because the assumptions within the TOC calculations are estimates. BOE
can be up to 10 percent of TOC, meaning the TOC evaluations within this
band are treated as equal, and when used in lieu of TOC, the fraction
of consumers who evaluate using TOC drops to less than 5 percent.
(Metglas, No. 53 at p. 7)
Based on the comments received DOE will maintain the definition
previously stated. However, for this NOPR, DOE did not receive enough
information or data to apply BOE to a fraction of transformer
purchasers.
Evaluation Rates and High Electricity Costs
In the August 2021 ECS Preliminary Analysis TSD, DOE requested
comment on whether those consumers that purchase distribution
transformers based on TOC are likely to pay higher electricity costs.
Howard commented that certain utilities with high electricity costs use
the TOC (Total Owning Cost) approach to minimize their overall owning
costs. And the manufacturer will work with the user to determine the
best overall value to buy, and that this is good approach in those
areas. (Howard, No. 59 at p. 3) NEMA commented that it stands to reason
that consumers with higher electricity costs are more likely to
consider TOC in purchasing decisions. (NEMA, No. 50 at p. 13-14)
The comments DOE received on this subject were supportive of the
notion that consumers who have higher electricity costs would
reasonably have higher adoption of using TOC as a purchasing tool.
However, the comments did not provide any information, or data to
support including this relationship in this NOPR. To relate higher
electricity costs with increased TOC use, DOE would require from
stakeholders the fraction of transformers specified and shipped to
regions of higher electricity costs using TOC or BOE.
DOE requests comment on its assumed TOC adoption rate of 10
percent. Specifically, DOE requests comment on the TOC rate suggested
by NEMA, that between 15 and 20 percent of 3-phase liquid-immersed
distribution transformers are purchased using TOC, and that 40 percent
of 1-phase liquid-immersed distribution transformers are purchased
using TOC. DOE notes, that it is seeking data related to concluded
sales based on lowest TOC in the strictest sense, excluding those
transformers sold using band of equivalents (see the section on band of
equivalents, above)
DOE requests comment on the fraction of distribution transformers
purchased by customers using the BOE methodology. DOE notes, that it is
seeking data related to concluded sales based on lowest BOE in the
strictest sense, excluding those transformers sold using total owning
costs.
DOE request comment if the rates of TOC or BOE vary by transformer
capacity or number of phases. Further, DOE seeks the fraction of
distribution transformer sales using either method into the different
regions in order to capture the believed relationship between higher
electricity costs and purchase evaluation behavior.
c. Non-evaluators and First Cost Purchases
DOE defined those consumers who do not purchase based on TOC as
those who purchase based on lowest first costs. NEMA commented that
they disagreed with DOE's assumption that purchasers who do not
purchase based on TOC purchase strictly on a first cost basis. Stating,
in relation to dry-type distribution transformers, that customers also
care about production times, availability, perceived quality, design
options and other factors relating to timing and performance. Further,
in relation to liquid-immersed transformers, improved tank steel
(stainless) or biodegradable immersion oil are potential upgrades
outside electrical performance which NEMA members have had requested by
customers. (NEMA, No. 50 at pp. 13-14)
DOE acknowledges that customers of distribution transformers will
specify design aspects, or other criteria that will impact the cost of
a transformer when making a purchasing decision that is not related to
distribution transformer efficiency. As mentioned by NEMA in their
comment, customers may have additional criteria when purchasing a
distribution transformer that would be considered either an equipment
upgrade outside of the equipment's electrical performance, or
operational considerations that would affect the first costs. The
analysis conducted by the Department in support of its energy saving
mission are limited to design aspects that affect the quantification of
increased energy efficiency of the equipment in question, in this case,
distribution transformers. These design aspects are defined in the
current test procedure and quantified in the engineering analysis.
Since the aspects listed by NEMA are outside of the electrical, and
efficiency performance of distribution transformers, therefore they are
not considered in this analysis.
4. Installation Costs
Installation cost includes labor, overhead, and any miscellaneous
materials and parts needed to install the product. DOE used data from
RSMeans to estimate the baseline installation cost
[[Page 1778]]
for distribution transformers.\76\ In the August 2021 Preliminary
Analysis TSD, DOE asserted that there would be no difference in
installation costs between baseline and more efficient equipment. DOE
also asserted that 5 percent of replacement installations would face
increased costs over baseline equipment due to the need for site
modifications.
---------------------------------------------------------------------------
\76\ Gordian, RSMeans Online, https://www.rsmeans.com/products/online (Last accessed: March 2022).
---------------------------------------------------------------------------
DOE received comments from GEUS, Carte, and NEMA of the subject of
installing distribution transformers.
GEUS expressed concern that higher standards may increase
transformer weights such that 50 kVA transformers can no longer be
handled with standard bucket trucks and would require a larger truck to
preform installations. (GEUS, No. 58 at p. 1)
The load bearing capacity of vehicles classified as a bucket truck
typically accommodate a wide range of lifting capacity depending on
each individual truck. The analysis conducted for this NOPR shows a
maximum of weight for a 50 kVA pole mounted liquid-immersed
distribution of 1440 lbs. at the maximum technology case. Without
knowing the specifics regarding the equipment used by GEUS, DOE cannot
definitively say whether their existing bucket trucks will be
sufficient.
Transformers are typically installed using a bucket truck, or crane
truck. DOE requests comment on the typical maximum lifting capacity,
and the typical transformer capacity being installed.
Additionally, Carte and NEMA expressed concern over the increasing
of distribution transformer size in order to meet a potential revised
standard. Carte commented that utilities are concerned with the
increase in size and weight associated with efficiency standards, with
potential issues for pole replacement, concrete load limits, and
vaults. (Carte, No. 54 at p. 2-3) NEMA commented that when designing a
new transformer to fit an existing pad footprint, the only way to add
more active material to raise efficiency is to increase the height of
the unit. This may not be feasible in situations where cables run
underground. There may not be sufficient length remaining in those
cables to reach a higher set of bushings to connect the unit to the
network. (NEMA, No. 50 at p. 14)
As in the August 2021 Preliminary Analysis TSD, DOE acknowledges
that there may be issues when installing a replacement distribution
transformer on an existing pad, or underground enclosure. However, as
discussed in appendix 7D of the August 2021 Preliminary Analysis TSD,
many of these issues can be avoided through proper equipment
specification at the time of purchase. The issues that both Carte and
NEMA reference, apart from vault replacement/renovation, can be
addressed during purchasing with proper specifications. Given that no
new information has been put forward in response to the August 2021
Preliminary Analysis TSD, DOE will maintain its assumptions and
approach where increased installation costs over the no-new standards
case are considered atypical and applied at a rate of 5 percent of
installations occurrences.
For this NOPR, DOE reiterates its request for the following
information. DOE requests data and feedback on the size limitations of
pad-mounted distribution transformers. Specifically, what sizes,
voltages, or other features are currently unable to fit on current
pads, and the dimension of these pads. DOE seeks data on the typical
concrete pad dimensions for 50 and 500 kVA single-; and 500, and 1500
kVA three-phase distribution transformers. DOE seeks data on the
typical service lifetimes of supporting concrete pads.
5. Annual Energy Consumption
For each sampled customer, DOE determined the energy consumption
for a distribution transformer at different efficiency levels using the
approach described previously in section IV.E of this document.
6. Electricity Prices
DOE derived average and marginal electricity prices for
distribution transformers using two different methodologies to reflect
the differences in how the electricity is paid for by consumers of
distribution transformers. For liquid-immersed distribution
transformers, which are largely owned and operated by electric
distribution companies, who purchase electricity from a variety of
markets, DOE developed an hourly electricity costs model. For low- and
medium-voltage dry-type, which are primarily owned and operated by C&I
entities, DOE developed a monthly electricity cost model.
a. Hourly Electricity Costs
To evaluate the electricity costs associated with liquid-immersed
distribution transformers, DOE used marginal electricity prices.
Marginal prices are those utilities pay for the last kilowatt-hour of
electricity produced that may be higher or lower than the average
price, depending on the relationships among capacity, generation,
transmission, and distribution costs. The general structure of the
hourly marginal cost methodology divides the costs of electricity into
capacity components and energy cost components. For each component, the
economic value for both no-load losses and load losses is estimated.
The capacity components include generation and transmission capacity;
they also include a reserve margin for ensuring system reliability,
with factors that account for system losses. Energy cost components
include a marginal cost of supply that varies by the hour.
The marginal costs methodology was developed for each regional
Balancing Authority listed in EIA's Form EIA-861 database (based on
``Annual Electric Power Industry Report'').\77\ To calculate the hourly
price of electricity, DOE used the day-ahead market clearing price for
regions having wholesale electricity markets, and system lambda values
for all other regions. System lambda values, which are roughly equal to
the operating cost of the next unit in line for dispatch, are filed by
control area operators under FERC Form 714.\78\
---------------------------------------------------------------------------
\77\ Available at https://www.eia.doe.gov/cneaf/electricity/page/eia861.html.
\78\ https://www.ferc.gov/industries-data/electric/general-information/electric-industry-forms/form-no-714-annual-electric/overview.
---------------------------------------------------------------------------
EEI commented that the utilization of 2015 data and ``scaling it''
to the year of analysis was misguided given the clean energy progress
the electric sector has made in the intervening years. The mix of
resources used to generate electricity in the United States has changed
dramatically over the last decade and is increasingly cleaner. EEI
commented that, starting in 2016, natural gas surpassed coal as the
main source of electricity generation in the United States, and in 2020
natural gas-based generation powered 40 percent of the country's
electricity, compared to coal-based generation at 19 percent.
In response to EEI, DOE notes that it scaled the cost of
electricity from 2015 to the present using AEO2022 electricity price
trend, and that this trend accounts for changes in the electricity
supply mix over this period.\79\ Additionally, DOE captures the
advances in reducing GHG and other pollutants from the Nation's
electricity generators in its Emissions
[[Page 1779]]
Analysis, described in section IV.K. This analysis captures both shift
in generation, and the reduction in coal-based generation, and
resulting emissions referenced by EEI, from 2027 through the end of
this this NOPR's analysis period.
---------------------------------------------------------------------------
\79\ U.S. Energy Information Administration, Annual Energy
Outlook 2022, Table 3. Energy Prices by Sector and Source Case:
AEO2022 Reference case [verbar] Region: United States, 2022
(Available at: https://www.eia.gov/outlooks/aeo/data/browser/#/
?id=3-AEO2022®ion=1-
0&cases=ref2022&start=2020&end=2050&f=A&linechart=ref2022-
d011222a.3-3-AEO2022.1-0~ref2022-d011222a.55-3-AEO2022.1-
0&map=ref2022-d011222a.4-3-AEO2022.1-0&ctype=linechart&sourcekey=0,
Last access: June 1, 2022).
---------------------------------------------------------------------------
DOE received no further comment regarding it electricity costs
analysis and maintained the approach used in the August 2021
Preliminary Analysis TSD for this NOPR.
7. Maintenance and Repair Costs
Repair costs are associated with repairing or replacing product
components that have failed in an appliance; maintenance costs are
associated with maintaining the operation of the product. Typically,
small incremental increases in product efficiency produce no, or only
minor, changes in repair and maintenance costs compared to baseline
efficiency products. In the August 2021 Preliminary Analysis TSD, DOE
asserted that maintenance and repair costs do not increase with
transformer efficiency. NEMA responded that they agree with these
assumptions. (NEMA, No. 50 at p. 16)
Based on this response DOE continued its assumptions that
maintenance and repair costs do not increase with transformer
efficiency for this NOPR analysis.
8. Equipment Lifetime
For distribution transformers, DOE used a distribution of
lifetimes, with an estimated average of 32 years and maximum 60 years.
NEMA commented that they have no alternative lifetimes to suggest,
and the equipment lifetimes are suitably representative. (NEMA, No. 50
at p. 16) However, NEMA postulated that, logically, increased
(equipment) prices will create pressure on some customers to rebuild
existing property. NEMA did not provide the additional service life
that would be extended to rebuilt equipment in this event, or to what
extent the average service lifetime of a distribution transformer would
increase. As the average lifetime presented in the August 2021
Preliminary Analysis TSD, at 32 years, is quite long, for this NOPR,
DOE maintained the lifetime estimates presented in the August 2021
Preliminary Analysis TSD.
DOE request the average extension of distribution transformer
service life that can be achieved through rebuilding. Additionally, DOE
requests comment on the fraction of transformer that are repaired by
their original purchasing entity and returned to service, thereby
extending the transformer's service lifetime beyond the estimated
lifetimes of 32 years with a maximum of 60 years.
9. Discount Rates
The discount rate is the rate at which future expenditures are
discounted to estimate their present value. DOE employs a two-step
approach in calculating discount rates for analyzing customer economic
impacts (e.g., LCC). The first step is to assume that the actual cost
of capital approximates the appropriate customer discount rate. The
second step is to use the capital asset pricing model (CAPM) to
calculate the equity capital component of the customer discount rate.
For this NOPR, DOE estimated a statistical distribution of commercial
customer discount rates that varied by distribution transformer type,
by calculating the cost of capital for the different types of
distribution transformer owners.
DOE's method views the purchase of a higher efficiency appliance as
an investment that yields a stream of energy cost savings. DOE derived
the discount rates for the LCC analysis by estimating the cost of
capital for companies or public entities that purchase distribution
transformers. For private firms, the weighted average cost of capital
(WACC) is commonly used to estimate the present value of cash flows to
be derived from a typical company project or investment. Most companies
use both debt and equity capital to fund investments, so their cost of
capital is the weighted average of the cost to the firm of equity and
debt financing, as estimated from financial data for publicly traded
firms in the sectors that purchase distribution transformers.\80\ As
discount rates can differ across industries, DOE estimates separate
discount rate distributions for a number of aggregate sectors with
which elements of the LCC building sample can be associated.
---------------------------------------------------------------------------
\80\ Previously, Damodaran Online provided firm-level data, but
now only industry-level data is available, as compiled from
individual firm data, for the period of 1998-2018. The data sets
note the number of firms included in the industry average for each
year.
---------------------------------------------------------------------------
EEI commented that DOE should utilize up to date information to
apply an appropriate discount rate for electric companies. (EEI, No. 56
at p. 4) DOE understands that this comment is in reference to DOE
applying the Federal Government discount rate to local Municipal
Utilities (MUNIs) consumers in the LCC analysis in the August 2021
Preliminary Analysis TSD. This was in error and has been corrected in
this NOPR; consumer impacts for MUNIs are now calculated using the
distribution of state/local government discount rates shown in Table
IV.11. The mean WACC for this distribution is 2.67 percent.\81\
---------------------------------------------------------------------------
\81\ Sources: For values through Q2 2016, Federal Reserve Bank
of Saint Louis, ``State and Local Bonds--Bond Buyer Go 20-Bond
Municipal Bond Index--Discontinued Series,'' https://fred.stlouisfed.org/series/WSLB20 (Last accessed February 2022). For
Q3 2016 through 2021, Bartel Associates LLC, ``20 Year AA Municipal
Bond Quarterly Rates,'' updated January 5, 2022, https://bartel-associates.com/resources/select-gasb-67-68-discount-rate-indices
(Last accessed February 2022).
Table IV.11--Applied Discount Rates for Publicly Owned Utilities
----------------------------------------------------------------------------------------------------------------
Observations
Rate bin Rates (%) Weight (%) (quarters)
----------------------------------------------------------------------------------------------------------------
<0%............................................................. -1.9 3.0 4
0-1%............................................................ 0.9 2.3 3
1-2%............................................................ 1.6 23.3 31
2-3%............................................................ 2.5 25.6 34
3-4%............................................................ 3.5 35.3 47
4-5%............................................................ 4.2 10.5 14
----------------------------------------------------------------------------------------------------------------
DOE received no further comments on its discount rate analysis and
maintained its approach for this NOPR. See chapter 8 of the NOPR TSD
for further details on the development of consumer discount rates.
10. Energy Efficiency Distribution in the No-New-Standards Case
To accurately estimate the share of consumers that would be
affected by a
[[Page 1780]]
potential energy conservation standard at a particular efficiency
level, DOE's LCC analysis considered the projected distribution (market
shares) of product efficiencies under the no-new-standards case (i.e.,
the case without amended or new energy conservation standards). To
determine an appropriate basecase against which to compare various
potential standard levels, DOE used the purchase-decision model
described in section IV.F.3, where distribution transformers are
purchased based on either lowest first cost, or, on lowest TOC. In the
no-new-standards case distribution transformers are chosen from among
the entire range of available distribution transformer designs for each
representative unit simulated in the engineering analysis based on this
purchase-decision model. This selection is constrained only by
purchase-price in the majority of cases (90 percent, and 100 percent
for liquid-immerses, and all dry-type transformers, respectively), and
reflect the MSPs of the available designs determined in the engineering
analysis in section IV.C.1 of this document. The resulting distribution
of transformer efficiency in the No-New-Standards Case is shown in
Table IV.12.
Comments received regarding the energy efficiency distribution in
the no-new-standards case are addressed in the discussion regarding the
modeling of distribution transformer purchase decisions, in section
IV.F.2 of this document.
See chapter 8 of the NOPR TSD for further information on the
derivation of the efficiency distributions.
Table IV.12--Applied Distribution of Equipment Efficiencies in the No-New Standards Case, Fraction of Units at Each EL (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency level
EC Rep unit -----------------------------------------------------------------------------------------------
0 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
1....................................... 1 90.6 6.1 0.3 0.9 1.6 0.4
1....................................... 2 99.1 0.3 0.4 0.1 0.0 0.0
1....................................... 3 96.5 1.0 2.2 0.1 0.2 0.1
2....................................... 4 65.0 30.7 1.2 0.1 2.1 0.9
2....................................... 5 93.5 4.2 1.7 0.6 0.0 0.0
2....................................... 17 97.7 0.2 0.3 0.8 0.8 0.2
12...................................... 15 64.8 31.4 0.8 0.0 2.1 0.9
12...................................... 16 93.9 3.9 1.6 0.4 0.0 0.0
3....................................... 6 31.4 46.4 21.3 0.9 0.0 0.0
4....................................... 7 83.4 15.1 1.5 0.0 0.0 0.0
4....................................... 8 49.0 45.1 6.0 0.0 0.0 0.0
6....................................... 9 28.0 50.0 22.0 0.0 0.0 0.0
6....................................... 10 87.5 12.5 0.0 0.0 0.0 0.0
8....................................... 11 76.2 23.8 0.0 0.0 0.0 0.0
8....................................... 12 90.6 9.4 0.0 0.0 0.0 0.0
8....................................... 18 100.0 0.0 0.0 0.0 0.0 0.0
10...................................... 13 90.4 9.7 0.0 0.0 0.0 0.0
10...................................... 14 100.0 0.0 0.0 0.0 0.0 0.0
10...................................... 19 100.0 0.0 0.0 0.0 0.0 0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: may not sum to 100 due to rounding.
11. Payback Period Analysis
The payback period is the amount of time it takes the consumer to
recover the additional installed cost of more-efficient products,
compared to baseline products, through energy cost savings. Payback
periods are expressed in years. Payback periods that exceed the life of
the product mean that the increased total installed cost is not
recovered in reduced operating expenses.
The inputs to the PBP calculation for each efficiency level are the
change in total installed cost of the product and the change in the
first-year annual operating expenditures relative to the baseline. The
PBP calculation uses the same inputs as the LCC analysis, except that
discount rates are not needed.
As noted previously, EPCA establishes a rebuttable presumption that
a standard is economically justified if the Secretary finds that the
additional cost to the consumer of purchasing a product complying with
an energy conservation standard level will be less than three times the
value of the first year's energy savings resulting from the standard,
as calculated under the applicable test procedure. (42 U.S.C.
6295(o)(2)(B)(iii)) For each considered efficiency level, DOE
determined the value of the first year's energy savings by calculating
the energy savings in accordance with the applicable DOE test
procedure, and multiplying those savings by the average energy price
projection for the year in which compliance with the amended standards
would be required. The results of this analysis provide an important
element of DOE's evaluation of the economic justification for a
potential standard level (thereby supporting or rebutting the results
of any preliminary determination of economic justification). The
rebuttable presumption payback calculation is discussed in section
V.B.1.c of this document.
G. Shipments Analysis
DOE uses projections of annual product shipments to calculate the
national impacts of potential amended or new energy conservation
standards on energy use, NPV, and future manufacturer cash flows.\82\
The shipments model takes an accounting approach, tracking market
shares of each product class and the vintage of units in the stock.
Stock accounting uses product shipments as inputs to estimate the age
distribution of in-service product stocks for all years. The age
distribution of in-service product stocks is a key input to
calculations of both the NES and NPV, because operating costs for any
year depend on the age distribution of the stock.
---------------------------------------------------------------------------
\82\ DOE uses data on manufacturer shipments as a proxy for
national sales, as aggregate data on sales are lacking. In general
one would expect a close correspondence between shipments and sales.
---------------------------------------------------------------------------
DOE projected distribution transformer shipments for the no-new
standards case by assuming that long-
[[Page 1781]]
term growth in distribution transformer shipments will be driven by
long-term growth in electricity consumption. DOE developed its initial
shipments inputs based on data from the previous final rule, and data
submitted to DOE from interested parties; these initial shipments are
shown for the assumed compliance year, by distribution transformer
type, in Table IV.13 through Table IV.15. For this NOPR, DOE received
additional data from manufacturers via confidential interviews,
resulting in revised shipments estimates for liquid-immersed
distribution transformers. DOE developed the shipments projection for
liquid-immersed distribution transformers by assuming that annual
shipments growth is equal to growth in electricity consumption for all
sectors, as given by the AEO2022 forecast through 2050. DOE's model
assumed that growth in annual shipments of dry-type distribution
transformers would be equal to the growth in electricity consumption
for commercial and industrial sectors, respectively. The model starts
with an estimate of the overall growth in distribution transformer
capacity, and then estimates shipments for particular representative
units and capacities using estimates of the recent market shares for
different design and size categories.
Table IV.13--Estimated Liquid-Immersed Shipments for 2027 (Units)
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
Capacity (kVA) -------------------------------------------------------------------------------
Pad OH Pad OH NVS
----------------------------------------------------------------------------------------------------------------
10.............................. 677 71,325 0 0 0
15.............................. 4,679 147,344 0 0 0
25.............................. 44,873 329,589 0 0 0
30.............................. 0 0 10 68 0
38.............................. 8,184 45,629 0 0 0
45.............................. 0 0 714 692 0
50.............................. 79,074 149,710 0 0 0
75.............................. 42,684 24,149 6,523 661 0
100............................. 32,830 20,537 0 0 0
113............................. 0 0 1,773 95 0
150............................. 0 0 13,066 787 0
167............................. 8,272 5,926 0 0 0
225............................. 0 0 2,972 16 0
250............................. 134 508 0 0 0
300............................. 0 0 13,061 268 0
333............................. 4 890 0 0 0
500............................. 3 488 9,867 0 3
667............................. 6 0 13 0 13
750............................. 0 0 6,057 0 49
833............................. 70 21 39 0 39
1,000........................... 0 0 5,426 0 127
1,500........................... 0 0 5,886 0 150
2,000........................... 0 0 2,349 0 103
2,500........................... 0 0 3,701 0 359
3,750........................... 0 0 286 0 0
5,000........................... 0 0 95 0 0
-------------------------------------------------------------------------------
Total....................... 221,490 796,116 71,838 2,587 843
----------------------------------------------------------------------------------------------------------------
Table IV.14--Estimated Low-Voltage Dry-Type Shipments for 2027 (Units)
------------------------------------------------------------------------
Capacity (kVA) Single-phase Three-phase
------------------------------------------------------------------------
10...................................... 3 ..............
15...................................... 2,792 18,398
25...................................... 6,215 ..............
30...................................... .............. 44,689
37.5.................................... 3,777 ..............
45...................................... .............. 47,106
50...................................... 5,821 ..............
75...................................... 3,508 62,205
100..................................... 2,200 ..............
112.3................................... .............. 27,858
150..................................... .............. 22,062
167..................................... .............. ..............
225..................................... .............. 7,828
250..................................... 28 ..............
300..................................... .............. 4,109
333..................................... .............. ..............
500..................................... .............. 2,527
667..................................... .............. ..............
750..................................... .............. 614
833..................................... .............. ..............
1,000................................... .............. 17
[[Page 1782]]
1,500................................... .............. 11
2,000................................... .............. ..............
2,500................................... .............. ..............
-------------------------------
Total............................... 24,344 237,423
------------------------------------------------------------------------
Table IV.15--Estimated Medium-Voltage Dry-Type Shipments for 2027 (Units)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
Capacity (kVA) -----------------------------------------------------------------------------------------------
20-45 kV BIL 46-95 kV BIL >=96 kV BIL 20-45 kV BIL 46-95 kV BIL >=96 kV BIL
--------------------------------------------------------------------------------------------------------------------------------------------------------
10...................................................... 250 180 60 0 0 0
15...................................................... 250 180 60 5 0 0
25...................................................... 60 40 20 0 0 0
30...................................................... 0 0 0 10 0 0
38...................................................... 60 40 20 0 0 0
45...................................................... 0 0 0 10 0 0
50...................................................... 30 20 10 0 0 0
75...................................................... 30 20 10 4 2 0
100..................................................... 12 20 6 0 0 0
113..................................................... 0 0 0 30 4 0
150..................................................... 0 0 0 35 5 0
167..................................................... 7 10 3 0 0 0
225..................................................... 0 0 0 29 12 0
250..................................................... 15 20 3 0 0 0
300..................................................... 15 0 0 91 30 25
333..................................................... 12 20 4 0 0 0
500..................................................... 0 0 0 177 85 74
667..................................................... 0 0 0 0 0 0
750..................................................... 0 0 0 72 121 75
833..................................................... 0 0 0 0 0 0
1,000................................................... 0 0 0 45 242 194
1,500................................................... 0 0 0 0 363 244
2,000................................................... 0 0 0 0 605 280
2,500................................................... 0 0 0 0 605 394
3,750................................................... 0 0 0 0 12 8
5,000................................................... 0 0 0 0 4 3
-----------------------------------------------------------------------------------------------
Total............................................... 741 550 196 508 2,074 1,297
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Equipment Switching
In response to the shipments analysis presented in the August 2021
Preliminary Analysis TSD, NEMA commented that manufacturers have had
customers avoid liquid-immersed entirely and use dry-type designs due
to local purchasing restrictions or policies. (NEMA, No. 50 at p. 14)
DOE understands that medium-voltage dry-type distribution
transformers (MVDT) can be used as replacement for liquid-immersed
distribution transformers but DOE has always considered it as an edge
case due to the differences in purchase price, and consumer sensitivity
to first costs. DOE does not have sufficient data to model the
substitution of liquid-immersed distribution transformers with MVDT.
DOE requests comment on which liquid-immersed distribution
transformers capacities are typically replaced with MVDT. DOE further
requests data that would indicate a trend in these substitutions. DOE
further requests data that would help it determine which types of
customers are preforming these substitutions, e.g., industrial
customers, invertor owned utilities, MUNIs, etc.
2. Trends in Distribution Transformer Capacity (kVA)
NEMA commented that as consumer demand increases due to migration
to all-electric homes and buildings, it stands to reason that kVA sizes
will increase over time as infrastructure upgrades capacity to serve
these consumer demands. Likewise, NEMA commented that investments in
renewable energy generation will cause changes to transformer
shipments, unit sizes and selections, and, that DOE should examine non-
static capacity scenarios, where kVA of units by type increases over
time as NEMA members express growth in average kVA of ordered units
over time in recent years, presumably due to increased electrification
of consumer and industrial applications. (NEMA, No. 50 at pp. 16-17)
DOE has limited data available to conduct the sensitivity requested
by NEMA at this time. To do so DOE would require the current average
kVA capacity for each of the representative units analyzed in the
engineering analysis, section IV.C.1 of this document. If DOE were to
apply a shift in growing capacity without input data from stakeholders,
it would have the effect on inflating the energy savings estimates. In
response to NEMA's comment DOE requests data to inform a shift in the
capacity distribution to larger capacity distribution transformers.
Additionally, DOE requests information on the extent that this
increasing trend in capacity would affect all types of distribution
[[Page 1783]]
transformers, or only medium-voltage distribution transformers.
H. National Impact Analysis
The NIA assesses the national energy savings (``NES'') and the NPV
from a national perspective of total consumer costs and savings that
would be expected to result from new or amended standards at specific
efficiency levels.\83\ (``Consumer'' in this context refers to
consumers of the product being regulated.) DOE calculates the NES and
NPV for the potential standard levels considered based on projections
of annual product shipments, along with the annual energy consumption
and total installed cost data from the energy use and LCC analyses. For
the present analysis, DOE projected the energy savings, operating cost
savings, product costs, and NPV of consumer benefits over the lifetime
of distribution transformers sold from 2027 through 2056.
---------------------------------------------------------------------------
\83\ The NIA accounts for impacts in the 50 states and U.S.
territories.
---------------------------------------------------------------------------
DOE evaluates the impacts of new or amended standards by comparing
a case without such standards with standards-case projections. The no-
new-standards case characterizes energy use and consumer costs for each
product class in the absence of new or amended energy conservation
standards. For this projection, DOE considers historical trends in
efficiency and various forces that are likely to affect the mix of
efficiencies over time. DOE compares the no-new-standards case with
projections characterizing the market for each product class if DOE
adopted new or amended standards at specific energy efficiency levels
(i.e., the TSLs or standards cases) for that class. For the standards
cases, DOE considers how a given standard would likely affect the
market shares of products with efficiencies greater than the standard.
DOE uses a model to calculate the energy savings and the national
consumer costs and savings from each TSL. Interested parties can review
DOE's analyses by changing various input quantities within the model.
The NIA model uses typical values (as opposed to probability
distributions) as inputs.
Table IV.16 summarizes the inputs and methods DOE used for the NIA
analysis for the NOPR. Discussion of these inputs and methods follows
the table. See chapter 10 of the NOPR TSD for further details.
Table IV.16--Summary of Inputs and Methods for the National Impact
Analysis
------------------------------------------------------------------------
Inputs Method
------------------------------------------------------------------------
Shipments......................... Annual shipments from shipments
model.
Initial Shipments: Market reports
from HVOLT, stakeholder data,
confidential manufacturer data.
Future Shipments: Projection based
on trends from AEO2022:
Liquid-immersed: Future electricity
sales trends.
Low-, Medium-voltage Dry-type:
Future commercial floor space and
industrial output trends.
Compliance Date of Standard....... 2027.
Efficiency Trends................. No-new-standards case: constant
efficiency over time.
Standards cases: constant efficiency
over time.
Annual Energy Consumption per Unit Annual weighted-average values are a
function of energy use at each TSL.
Total Installed Cost per Unit..... Annual weighted-average values are a
function of cost at each TSL.
Incorporates projection of future
product prices based on historical
data.
Annual Energy Cost per Unit....... Annual weighted-average values as a
function of the annual energy
consumption per unit and energy
prices.
Repair and Maintenance Cost per Annual values do not change with
Unit. efficiency level.
Energy Price Trends............... AEO2022 projections (to 2050) and
constant 2050 thereafter.
Energy Site-to-Primary and FFC A time-series conversion factor
Conversion. based on AEO2022.
Discount Rate..................... 3 percent and 7 percent.
Present Year...................... 2022.
------------------------------------------------------------------------
DOE projected the energy savings, operating cost savings, product
costs, and NPV of consumer benefits over the lifetime of distribution
transformers sold from 2027 through 2056 Given the extremely durable
nature of distribution transformers, this creates an analytical
timeframe from 2027 through 2115. DOE seeks comment on the current
analytical timeline, and potential alternative analytical timeframes.
1. Equipment Efficiency Trends
A key component of the NIA is the trend in energy efficiency
projected for the no-new-standards case and each of the standards
cases. Section IV.F.3of this document describes how DOE developed an
energy efficiency distribution for the no-new-standards case for each
of the considered equipment classes for the year of anticipated
compliance with an amended or new standard. As discussed in section
IV.F.3, DOE has found that the vast majority of distribution
transformers are purchased based on first cost. For both the no-new
standards case and amended standards case, DOE used the results of the
consumer choice mode in the LCC, described in section IV.F.3 to
establish the shipment-weighted efficiency for the year of potential
standards are assumed to become effective (2027). For this NOPR,
despite the availability of a wide range of efficiencies, DOE modelled
that these efficiencies would remain static over time because the
purchase decision is largely based on first-costs (see section IV.F.3
of this document) and DOE's application of constant future equipment
costs (see section IV.F.1 of this document).
2. National Energy Savings
The national energy savings analysis involves a comparison of
national energy consumption of the considered products between each
potential standards case (``TSL'') and the case with no new or amended
energy conservation standards. DOE calculated the national energy
consumption by multiplying the number of units (stock) of each product
(by vintage or age) by the unit energy consumption (also by vintage).
DOE calculated annual NES based on the difference in national energy
consumption for the no-new standards case and for each higher
efficiency standard case. DOE estimated
[[Page 1784]]
energy consumption and savings based on site energy and converted the
electricity consumption and savings to primary energy (i.e., the energy
consumed by power plants to generate site electricity) using annual
conversion factors derived from AEO2022. Cumulative energy savings are
the sum of the NES for each year over the timeframe of the analysis.
Use of higher-efficiency equipment is occasionally associated with
a direct rebound effect, which refers to an increase in utilization of
the equipment due to the increase in efficiency and its lower operating
cost. A distribution transformer's utilization is entirely dependent on
the aggregation of the connected loads on the circuit the distribution
transformer serves. Greater utilization would result in greater per-
unit load (PUL) on the distribution transformer. Any increase in
distribution transformer PUL is coincidental, and not related to
rebound effect.
DOE accounts for incidental load growth on the distribution
transformer resulting from additional connections not related to the
rebound effect due to increased equipment efficiency.in the LCC
analysis in the form of future load growth. See section IV.E.3 for more
details on DOE approach to load growth.
Because DOE did not find any data to support the inclusion of a
rebound effect specific to distribution transformers, did not include a
rebound effect in this NOPR.
DOE requests comment on its assumption that including a rebound
effect is inappropriate for distribution transformers.
In 2011, in response to the recommendations of a committee on
``Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy
Efficiency Standards'' appointed by the National Academy of Sciences,
DOE announced its intention to use FFC measures of energy use and
greenhouse gas and other emissions in the national impact analyses and
emissions analyses included in future energy conservation standards
rulemakings. 76 FR 51281 (Aug. 18, 2011). After evaluating the
approaches discussed in the August 18, 2011 notice, DOE published a
statement of amended policy in which DOE explained its determination
that EIA's National Energy Modeling System (``NEMS'') is the most
appropriate tool for its FFC analysis and its intention to use NEMS for
that purpose. 77 FR 49701 (Aug. 17, 2012). NEMS is a public domain,
multi-sector, partial equilibrium model of the U.S. energy sector \84\
that EIA uses to prepare its Annual Energy Outlook. The FFC factors
incorporate losses in production and delivery in the case of natural
gas (including fugitive emissions) and additional energy used to
produce and deliver the various fuels used by power plants. The
approach used for deriving FFC measures of energy use and emissions is
described in appendix 10B of the NOPR TSD.
---------------------------------------------------------------------------
\84\ For more information on NEMS, refer to The National Energy
Modeling System: An Overview 2009, DOE/EIA-0581(2009), October 2009.
Available at www.eia.gov/forecasts/aeo/index.cfm (last accessed
April 1, 2022).
---------------------------------------------------------------------------
3. Net Present Value Analysis
The inputs for determining the NPV of the total costs and benefits
experienced by consumers are (1) total annual installed cost, (2) total
annual operating costs (energy costs and repair and maintenance costs),
and (3) a discount factor to calculate the present value of costs and
savings. DOE calculates net savings each year as the difference between
the no-new-standards case and each standards case in terms of total
savings in operating costs versus total increases in installed costs.
DOE calculates operating cost savings over the lifetime of each product
shipped during the projection period.
As discussed in section IV.F.1 of this document, DOE developed
distribution transformers price trends based on historical PPI data.
DOE applied the same trends to project prices for each product class at
each considered efficiency level, which was a constant price trend
through the end of the analysis period in 2056. DOE's projection of
product prices is described in appendix 10C of the NOPR TSD.
To evaluate the effect of uncertainty regarding the price trend
estimates, DOE investigated the impact of different product price
projections on the consumer NPV for the considered TSLs for
distribution transformers. In addition to the default price trend, DOE
considered two product price sensitivity cases: (1) a high price
decline case based on the years between 2003-2019 and (2) a low price
decline case based on the years between 1967-2002. The derivation of
these price trends and the results of these sensitivity cases are
described in appendix 10C of the NOPR TSD.
The operating cost savings are energy cost savings, which are
calculated using the estimated energy savings in each year and the
projected price of the appropriate form of energy. To estimate energy
prices in future years, DOE multiplied the average regional energy
prices by the projection of annual national-average electricity price
changes in the Reference case from AEO2022, which has an end year of
2050. To estimate price trends after 2050, DOE maintained the price
constant at 2050 levels. As part of the NIA, DOE also analyzed
scenarios that used inputs from variants of the AEO2022 Reference case
that have lower and higher economic growth. Those cases have lower and
higher energy price trends compared to the Reference case. NIA results
based on these cases are presented in appendix 10C of the NOPR TSD.
In calculating the NPV, DOE multiplies the net savings in future
years by a discount factor to determine their present value. For this
NOPR, DOE estimated the NPV of consumer benefits using both a 3-percent
and a 7-percent real discount rate. DOE uses these discount rates in
accordance with guidance provided by the Office of Management and
Budget (``OMB'') to Federal agencies on the development of regulatory
analysis.\85\ The discount rates for the determination of NPV are in
contrast to the discount rates used in the LCC analysis, which are
designed to reflect a consumer's perspective. The 7-percent real value
is an estimate of the average before-tax rate of return to private
capital in the U.S. economy. The 3-percent real value represents the
``social rate of time preference,'' which is the rate at which society
discounts future consumption flows to their present value.
---------------------------------------------------------------------------
\85\ United States Office of Management and Budget. Circular A-
4: Regulatory Analysis. September 17, 2003. Section E. Available at
www.whitehouse.gov/omb/memoranda/m03-21.html (last accessed April 1,
2022).
---------------------------------------------------------------------------
I. Consumer Subgroup Analysis
In analyzing the potential impact of new or amended energy
conservation standards on consumers, DOE evaluates the impact on
identifiable subgroups of consumers that may be disproportionately
affected by a new or amended national standard. The purpose of a
subgroup analysis is to determine the extent of any such
disproportional impacts. DOE evaluates impacts on particular subgroups
of consumers by analyzing the LCC impacts and PBP for those particular
consumers from alternative standard levels. For this NOPR, DOE analyzed
the impacts of the considered standard levels on two subgroups: (1)
utilities serving low population densities and (2) utility purchasers
of vault (underground) and subsurface installations. DOE used the LCC
and PBP model to estimate the impacts of the considered efficiency
levels on these
[[Page 1785]]
subgroups. Chapter 11 in the NOPR TSD describes the consumer subgroup
analysis.
1. Utilities Serving Low Customer Populations
In rural areas, mostly served by municipal utilities (MUNIs) the
number of customers per distribution transformer is lower than in
metropolitan areas and may result in lower PULs. For this NOPR, as in
the April 2013 Standards Final Rule, DOE reduced the PUL by adjusting
the distribution of IPLs, as discussed in section IV.E.1.a resulting in
the PULs shown below in Table IV.17. Further, DOE altered the customer
sample to limit the distribution of discount rates to those observed by
State and local governments discussed in IV.F.9. DOE notes that while
MUNIs deploy a range of distribution transformers to serve their
customers, in low population densities the most common unit is a 25 kVA
pole overheard liquid-immersed distribution transformer, which is
represented in this analysis as representative unit 2.
Table IV.17--Distribution of Per-Unit-Load for Liquid-Immersed Distribution Transformers Owned by Utilities
Serving Low Populations
----------------------------------------------------------------------------------------------------------------
Rep. unit Mean RMS Mean IPL Mean PUL
----------------------------------------------------------------------------------------------------------------
1............................................................... 0.29 0.60 0.18
2............................................................... 0.27 0.60 0.16
3............................................................... 0.32 0.60 0.19
4............................................................... 0.26 0.60 0.15
5............................................................... 0.31 0.60 0.19
----------------------------------------------------------------------------------------------------------------
DOE requests comment on the mean PUL applied to distribution
transformers owned and operated by utilities serving low customer
populations.
2. Utility Purchasers of Vault (Underground) and Subsurface
Installations
In some urban areas, utilities provide service to customers by
deploying parts of their transformer fleet in subsurface vaults, or
other prefabricated underground concrete structure, referred to as
vaults. At issue in the potential amended standards case is that as the
volume (ft\3\) of the more efficient replacement transformers may be
too large to fit into the existing vault, which would have to be
replaced to fit the new equipment. This analysis is applied to the
representative units 15 and 16, specifically defined in the engineering
analysis for vault and submersible liquid-immersed distribution
transformers (see section IV.C.1).
NEMA commented that they agree with the proposed approach to
examine utility costs regarding replacement of existing vault and
subsurface transformers. (NEMA No 18 at p. 17).
DOE has not received any data from stakeholders regarding the costs
associated with vault replacement due increased distribution
transformer volume. For this subgroups analysis DOE examined the
National average price of concrete vault construction with 6-inch-thick
walls for variously sized vaults from RSMeans.\86\ DOE notes that the
costs required to install a new vault can vary above the cost of the
prefabricated concrete vault. These additional costs would include but
are not limited to, excavation and disposal of the original vault, and
backfilling. While stakeholders have discussed that these costs can be
prohibitive, they have not to date provided examples of such costs, or
itemized cost breakdowns associated with vault replacement. Due to this
lack of information DOE has taken a simple approach and multiplied the
costs from RSMeans by three to provide a gross vault installation
estimate. This gross vault installation estimate represents the labor
time and material costs associated with excavation, vault installation,
and backfilling when replacing the no-new-standards vault with a new
structure. DOE applied the following simple linear fit relating the
cost of vault replacement to transformer volume.
---------------------------------------------------------------------------
\86\ RSMeans, Series: 330563130050, 330563130150, 330563130100,
330563130200, 330563130250, 330563130300, https://www.rsmeans.com/
(Last access: March 15, 2022).
VaultReplacement = 24.201 x DTVolume + 4,930.8
Table IV.18--Vault Replacement Costs
[2021$]
------------------------------------------------------------------------
Replacement
Vault dimensions (ft) Volume (ft\3\) cost (2021$)
------------------------------------------------------------------------
5' x 10' x 6' high...................... 300 12,450
5' x 12' x 6' high...................... 360 13,050
6' x 10' x 6' high...................... 360 13,050
6' x 12' x 6' high...................... 360 14,625
6' x 13' x 6' high...................... 468 18,300
8' x 14' x 7' high...................... 784 23,550
------------------------------------------------------------------------
DOE requests comment on its assumed vault replacement costs
methodology. DOE seeks comment or data regarding the installation
procedures associated with vault replacement. vault expansion
(renovation), and vault transformer installation and their respective
costs for replacement transformers. Additionally, DOE seeks information
on the typical expected lifetime of underground concrete vaults.
[[Page 1786]]
J. Manufacturer Impact Analysis
1. Overview
DOE performed an MIA to estimate the financial impacts of amended
energy conservation standards on manufacturers of distribution
transformers and to estimate the potential impacts of such standards on
employment and manufacturing capacity. The MIA has both quantitative
and qualitative aspects and includes analyses of projected industry
cash flows, the INPV, investments in research and development (``R&D'')
and manufacturing capital, and domestic manufacturing employment.
Additionally, the MIA seeks to determine how amended energy
conservation standards might affect manufacturing employment, capacity,
and competition, as well as how standards contribute to overall
regulatory burden. Finally, the MIA serves to identify any
disproportionate impacts on manufacturer subgroups, including small
business manufacturers.
The quantitative part of the MIA primarily relies on the Government
Regulatory Impact Model (``GRIM''), an industry cash flow model with
inputs specific to this rulemaking. The key GRIM inputs include data on
the industry cost structure, unit production costs, product shipments,
manufacturer markups, and investments in R&D and manufacturing capital
required to produce compliant equipment. The key GRIM outputs are the
INPV, which is the sum of industry annual cash flows over the analysis
period, discounted using the industry-weighted average cost of capital,
and the impact to domestic manufacturing employment. The model uses
standard accounting principles to estimate the impacts of more-
stringent energy conservation standards on a given industry by
comparing changes in INPV and domestic manufacturing employment between
a no-new-standards case and the various standards cases (i.e., TSLs).
To capture the uncertainty relating to manufacturer pricing strategies
following amended standards, the GRIM estimates a range of possible
impacts under different scenarios.
The qualitative part of the MIA addresses manufacturer
characteristics and market trends. Specifically, the MIA considers such
factors as a potential standard's impact on manufacturing capacity,
competition within the industry, the cumulative impact of other DOE and
non-DOE regulations, and impacts on manufacturer subgroups. The
complete MIA is outlined in chapter 12 of the NOPR TSD.
DOE conducted the MIA for this rulemaking in three phases. In Phase
1 of the MIA, DOE prepared a profile of the distribution transformer
manufacturing industry based on the market and technology assessment,
preliminary manufacturer interviews, and publicly available
information. This included a top-down analysis of distribution
transformer manufacturers that DOE used to derive preliminary financial
inputs for the GRIM (e.g., revenues; materials, labor, overhead, and
depreciation expenses; selling, general, and administrative expenses
(``SG&A''); and R&D expenses). DOE also used public sources of
information to further calibrate its initial characterization of the
distribution transformer manufacturing industry, including information
from the April 2013 Standards Final Rule, individual company filings of
form 10-K from the SEC,\87\ corporate annual reports, the U.S. Census
Bureau's Economic Census,\88\ and reports from D&B Hoovers.\89\
---------------------------------------------------------------------------
\87\ www.sec.gov/edgar.shtml.
\88\ www.census.gov/programs-surveys/asm.html.
\89\ www.app.avention.com.
---------------------------------------------------------------------------
In Phase 2 of the MIA, DOE prepared a framework industry cash-flow
analysis to quantify the potential impacts of amended energy
conservation standards. The GRIM uses several factors to determine a
series of annual cash flows starting with the announcement of the
standard and extending over a 30-year period following the compliance
date of the standard. These factors include annual expected revenues,
costs of sales, SG&A and R&D expenses, taxes, and capital expenditures.
In general, energy conservation standards can affect manufacturer cash
flow in three distinct ways: (1) creating a need for increased
investment, (2) raising production costs per unit, and (3) altering
revenue due to higher per-unit prices and changes in sales volumes.
In addition, during Phase 2, DOE developed interview guides to
distribute to manufacturers of distribution transformers in order to
develop other key GRIM inputs, including product and capital conversion
costs, and to gather additional information on the anticipated effects
of energy conservation standards on revenues, direct employment,
capital assets, industry competitiveness, industry consolidation, and
manufacturer subgroup impacts.
In Phase 3 of the MIA, DOE conducted structured, detailed
interviews with representative manufacturers. During these interviews,
DOE discussed engineering, manufacturing, procurement, and financial
topics to validate assumptions used in the GRIM and to identify key
issues or concerns. See section IV.J.3 of this document for a
description of the key issues raised by manufacturers during the
interviews. As part of Phase 3, DOE also evaluated subgroups of
manufacturers that may be disproportionately impacted by amended
standards or that may not be accurately represented by the average cost
assumptions used to develop the industry cash flow analysis. Such
manufacturer subgroups may include small business manufacturers, low-
volume manufacturers (``LVMs''), niche players, and/or manufacturers
exhibiting a cost structure that largely differs from the industry
average. DOE identified one subgroup for a separate impact analysis:
small business manufacturers. The small business subgroup is discussed
in section VI.B, ``Review under the Regulatory Flexibility Act'' and in
chapter 12 of the NOPR TSD.
2. Government Regulatory Impact Model and Key Inputs
DOE uses the GRIM to quantify the changes in cash flow due to
amended standards that result in a higher or lower industry value. The
GRIM uses a standard, annual discounted cash-flow analysis that
incorporates manufacturer costs, markups, shipments, and industry
financial information as inputs. The GRIM models changes in costs,
distribution of shipments, investments, and manufacturer margins that
could result from amended energy conservation standards. The GRIM
spreadsheet uses the inputs to arrive at a series of annual cash flows,
beginning in 2022 (the reference year of the analysis) and continuing
to 2056. DOE calculated INPVs by summing the stream of annual
discounted cash flows during this period. For manufacturers of
distribution transformers, DOE used a real discount rate of 7.4 percent
for liquid-immersed distribution transformers, 11.1 percent for low-
voltage dry-type distribution transformers, and 9.0 percent for medium-
voltage dry-type distribution transformers, which was derived from the
April 2013 Standards Final Rule and then modified according to feedback
received during manufacturer interviews.\90\
---------------------------------------------------------------------------
\90\ See Chapter 12 of the April 2013 Final Rule TSD for
discussion of where initial discount factors were derived, available
online at www.regulations.gov/document/EERE-2010-BT-STD-0048-0760.
For the April 2013 Final Rule, DOE initially calculated a 9.1
percent discount rate, however during manufacturer interviews
conducted for that rulemaking, manufacturers suggested using
different discount rates specific for each equipment class group.
During manufacturer interviews conducted for this NOPR,
manufacturers continued to agree that using different discount rates
for each equipment class group is appropriate.
---------------------------------------------------------------------------
[[Page 1787]]
DOE requests comment on the real discount rates used in this NOPR.
Specifically, if 7.4 percent for liquid-immersed distribution
transformer manufacturers, 11.1 percent for low-voltage dry-type
distribution transformer manufacturers, and 9.0 percent for medium-
voltage dry-type distribution transformer manufacturers are appropriate
discount rates to use in the GRIM.
The GRIM calculates cash flows using standard accounting principles
and compares changes in INPV between the no-new-standards case and each
standards case. The difference in INPV between the no-new-standards
case and a standards case represents the financial impact of amended
energy conservation standards on manufacturers. As discussed
previously, DOE developed critical GRIM inputs using a number of
sources, including publicly available data, results of the engineering
analysis and shipments analysis, and information gathered from industry
stakeholders during the course of manufacturer interviews. The GRIM
results are presented in section V.B.2. Additional details about the
GRIM, the discount rate, and other financial parameters can be found in
chapter 12 of the NOPR TSD.
a. Manufacturer Production Costs
Manufacturing more efficient equipment is typically more expensive
than manufacturing baseline equipment due to the use of more complex
components, which are typically more costly than baseline components.
The changes in the MPCs of covered products can affect the revenues,
gross margins, and cash flow of the industry.
During the engineering analysis, DOE used transformer design
software to create a database of designs spanning a broad range of
efficiencies for each of the representative units. This design software
generated a bill of materials. DOE then applied markups to allow for
scrap, handling, factory overhead, and other non-production costs, as
well as profit, to estimate the MSP.
These designs and their MSPs are subsequently inputted into the LCC
customer choice model. For each efficiency level and within each
representative unit, the LCC model uses a consumer choice model and
criteria described in section IV.F.3 to select a subset of all the
potential designs options (and associated MSPs). This subset is meant
to represent those designs that would actually be shipped in the market
under the various analyzed TSLs. DOE inputted into the GRIM the
weighted average cost of the designs selected by the LCC model and
scaled those MSPs to other selected capacities in each design line's
KVA range.
For a complete description of the MSPs, see chapter 5 of the NOPR
TSD.
b. Shipments Projections
The GRIM estimates manufacturer revenues based on total unit
shipment projections and the distribution of those shipments by
efficiency level. Changes in sales volumes and efficiency mix over time
can significantly affect manufacturer finances. For this analysis, the
GRIM uses the NIA's annual shipment projections derived from the
shipments analysis from 2022 (the reference year) to 2056 (the end year
of the analysis period). See chapter 9 of the NOPR TSD for additional
details.
c. Product and Capital Conversion Costs
Amended energy conservation standards could cause manufacturers to
incur conversion costs to bring their production facilities and
equipment designs into compliance. DOE evaluated the level of
conversion-related expenditures that would be needed to comply with
each considered efficiency level in each equipment class. For the MIA,
DOE classified these conversion costs into two major groups: (1)
product conversion costs; and (2) capital conversion costs. Product
conversion costs are investments in research, development, testing,
marketing, and other non-capitalized costs necessary to make product
designs comply with amended energy conservation standards. Capital
conversion costs are investments in property, plant, and equipment
necessary to adapt or change existing production facilities such that
new compliant equipment designs can be fabricated and assembled.
For capital conversion costs, DOE prepared bottom-up estimates of
the costs required to meet amended standards at each TSL for each
representative unit. To do this, DOE used equipment cost estimates from
the April 2013 Standards Final Rule and from information provided by
manufacturers and equipment suppliers, an understanding of the
manufacturing processes at distribution transformer manufacturing
facilities developed during interviews and in consultation with subject
matter experts, and the properties associated with different core and
winding materials. Major drivers of capital conversion costs include
changes in core steel type (and thickness), core weight, and core stack
height, all of which are interdependent and can vary by efficiency
level. DOE uses estimates of the core steel quantities needed by steel
type for each TSL to model the additional equipment the industry would
need to meet each TSL.
Capital conversion costs are primarily driven at each TSL by the
potential need for the industry to expand capacity for amorphous
production. Based on interviews with manufacturers and equipment
suppliers, based on the responses, DOE's model assumed an amorphous
production line capable of producing 1,200 tons annual of amorphous
cores would cost approximately $1,000,000 in capital investments. This
includes costs associated with purchasing annealing ovens, core cutting
machines, lacing tables, and other miscellaneous equipment. The
quantity of amorphous steel are outputs of the engineering analysis and
the LCC. At higher TSLs, the percent of distribution transformers
selected in the LCC consumer choice model that have amorphous cores
increases. Additionally, at the highest TSLs, the quantity of amorphous
steel per distribution transformer also increases. As the increasing
stringency of the TSLs drive the use of amorphous cores in distribution
transformers, capital conversion costs increase.
For product conversion costs, DOE understands the production of
amorphous cores requires unique expertise and equipment. For
manufacturers without experience with amorphous steel, a standard that
would likely be met using amorphous cores would require the development
or the procurement of the technical knowledge to produce cores. Because
amorphous steel is thinner and more brittle after annealing, materials
management, safety measures, and design considerations that are not
associated with non-amorphous steels would need to be implemented.
DOE estimated product conversion costs would be equal to the annual
industry R&D expenses for those TSLs where a majority of the market
would be expected to transition to amorphous material. These one-time
product conversion costs would be in addition to the annual R&D
expenses normally incurred by distribution transformer manufacturers.
These one-time expenditures account for the design, engineering,
prototyping, and other R&D efforts the industry would have to undertake
to move to a predominately amorphous market. For TSLs that would
[[Page 1788]]
not require the use of amorphous cores, but would still require
distribution transformer models to be redesigned to meet higher
efficiency levels, DOE estimated product conversion costs would be
equal to 50 percent the annual industry R&D expenses. These one-time
product conversion costs would also be in addition to the annual R&D
expenses normally incurred by distribution transformer manufacturers.
Capital and product conversion costs are key inputs into the GRIM
and directly impact the change in INPV (which is outputted from the
model) due to analyzed amended standards. The GRIM assumes all
conversion-related investments occur between the year of publication of
the final rule and the year by which manufacturers must comply with the
amended standards. The conversion cost figures used in the GRIM can be
found in section V.B.2 of this document. For additional information on
the estimated capital and product conversion costs, see chapter 12 of
the NOPR TSD.
d. Manufacturer Markup Scenarios
MSPs include direct manufacturing production costs (i.e., labor,
materials, and overhead estimated in DOE's MPCs) and all non-production
costs (i.e., SG&A, R&D, and interest), along with profit. To calculate
the MSPs in the GRIM, DOE applied manufacturer markups to the MPCs
estimated in the engineering analysis for each equipment class and
efficiency level. Modifying these margins in the standards case yields
different sets of impacts on manufacturers. For the MIA, DOE modeled
two standards-case scenarios to represent uncertainty regarding the
potential impacts on prices and profitability for manufacturers
following the implementation of amended energy conservation standards:
(1) a preservation of gross margin percentage markup scenario; and (2)
a preservation of operating profit scenario. These scenarios lead to
different margins that, when applied to the MPCs, result in varying
revenue and cash flow impacts on distribution transformer
manufacturers.
Under the preservation of gross margin percentage scenario, DOE
applied the same single uniform ``gross margin percentage'' that is
used in the no-new-standards case across all efficiency levels in the
standards cases. This scenario assumes that manufacturers would be able
to maintain the same amount of profit as a percentage of revenues at
all TSLs, even as the MPCs increase in the standards case. Based on
data from the April 2013 Standards Final Rule, publicly available
financial information for manufacturers of distribution transformers,
and comments made during manufacturer interviews, DOE estimated a gross
margin percentage of 20 percent for all distribution transformers.\91\
Because this scenario assumes that manufacturers would be able to
maintain the same gross margin percentage as MPCs increase in response
to the analyzed energy conservation standards, it represents the upper
bound to industry profitability under amended energy conservation
standards.
---------------------------------------------------------------------------
\91\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
Under the preservation of operating profit scenario, DOE modeled a
situation in which manufacturers are not able to increase per-unit
operating profit in proportion to increases in MPCs. Under this
scenario, as the cost of production (MPCs) increase, manufacturers
reduce their manufacturer markups (on a percentage basis) to a level
that maintains the no-new-standards operating profit (in absolute
dollars). The implicit assumption behind this scenario is that the
industry can only maintain its operating profit in absolute dollars
after compliance with amended standards. Therefore, operating margin in
percentage terms is reduced between the no-new-standards case and the
analyzed standards cases. DOE adjusted the manufacturer markups in the
GRIM at each TSL to yield approximately the same earnings before
interest and taxes in the standards case in the year after the
compliance date of the amended standards as in the no-new-standards
case. This scenario represents the lower bound to industry
profitability under amended energy conservation standards.
A comparison of industry financial impacts under the two scenarios
is presented in section V.B.2.a of this document.
3. Manufacturer Interviews
DOE interviewed manufacturers representing approximately 60 percent
of the liquid-immersed distribution transformer industry; approximately
50 percent of the LVDT distribution transformer industry; and
approximately 60 percent of the MVDT distribution transformer industry.
In interviews, DOE asked manufacturers to describe their major
concerns regarding this rulemaking. The following section highlights
manufacturer concerns that helped inform the projected potential
impacts of an amended standard on the industry. Manufacturer interviews
are conducted under non-disclosure agreements (``NDAs''), so DOE does
not document these discussions in the same way that it does public
comments in the comment summaries and DOE's responses throughout the
rest of this document.
a. Material Shortages and Prices
Throughout interviews and comments, manufacturers noted substantial
material shortages leading to both higher, more volatile prices and, at
points, an inability to procure certain materials--particularly
electrical steel. Manufacturers noted that these shortages reflect
rising demand for electrical steel domestically and internationally as
well as more general supply chain issues caused by the COVID-19
pandemic. Demand for steel, according to manufacturers, appears to be
driven by the growing electric vehicles and electric motors sectors
(prompting some steel producers to shift production away from GOES
suited for core manufacturing to non-grain-oriented steels suited for
electric vehicle production) as well as more general rising demand for
electrical steel abroad (leading to foreign steel producers reducing
exports to the United States). Manufacturers also noted that prices for
copper and aluminum have risen substantially, though have not been
subject to allocations as electrical steel has.
Manufacturers stated that higher energy conservation standards will
most likely lead to greater demand for materials necessary to build
more efficient transformers--potentially leading to less material
availability and greater cost concerns, particularly for manufacturers
without long-term relationships with suppliers. Further, several
manufacturers argued that establishing more stringent energy
conservation standards during a period of material price volatility may
undermine DOE's analysis as it relates to the short-term and long-term
economic impact of such a standard.
b. Use of Amorphous Materials
Manufacturers raised concerns about energy conservation standards
that would require the use of amorphous steel cores. Manufacturers who
currently make their own cores stated that amorphous core production
requires a different manufacturing process that would require a
substantial amount of new capital equipment and retrofits of existing
equipment that could, additionally, require more facility floor space.
Some manufacturers noted that they may need to switch to
[[Page 1789]]
purchasing cores for products covered by energy conservation standards.
Moving from a lower to a higher grade of non-amorphous steel would
result in significantly less costs and most manufacturers could
continue to use the same core production equipment. Manufacturers that
currently purchase cores noted less capital conversion costs associated
with such an increase in standards but did note that there is a limited
number of suppliers of amorphous steel grades both in North America and
globally--potentially meaning a limited supply of amorphous steel in a
market with relatively little competition.
c. Larger Distribution Transformers
Manufacturers noted that energy conservation standard increases,
short of requiring amorphous core usage, would likely lead to larger
distribution transformers. Manufacturers stated that larger transformer
sizes could complicate efforts to design transformers to replace
existing transformers where space is limited. Utilities, for example,
have built vaults, where distribution transformers are placed, of a
certain size. If a replacement distribution transformer cannot be
designed to fit the current vault space, then utilities will need to
build new vaults, increasing costs and construction-related disruption
significantly. Manufacturers indicated that this was not a significant
issue with new construction projects, where infrastructure can be built
around the size of the distribution transformer.
4. Discussion of MIA Comments
In response to the August 2021 Preliminary Analysis TSD, a few
interested parties made comments regarding the MIA, including comments
on small businesses and capital equipment. DOE addresses these comments
in this section.
a. Small Businesses
Powersmiths commented that large manufacturers are likely to be
able to meet higher efficiency standards given they will likely have
the resources to make the necessary capital investments to comply with
standards and would likely gain additional revenue from the higher per
transformer prices. However, if energy conservation standards require
large capital investments, these costs could put small businesses out
of business. (Powersmiths, No.46 at p. 6) While Schneider commented
that there is an increase in the number of companies that produce
assembled cores for distribution transformer manufacturers (as opposed
to distribution transformer manufacturers being required to fabricate
their own cores internally). Schneider continued stating that the
availability to purchase assembled cores would not place a
disproportionate burden on small businesses. (Schneider, No. 49 at p.
15)
DOE agrees that large capital and production conversion costs could
put additional strains on all distribution transformer manufacturers,
and especially small business. As part of the MIA DOE calculates the
expected conversion costs (capital and product conversion costs). The
methodology for calculating these conversion costs are described in
section IV.J.2.c and these cost estimates are presented in section
V.B.2.a. Additionally, DOE specifically examines the potential impact
of small businesses in section VI.B of this document.
As stated in section IV.J.2.c, conversion costs are primarily
driven by the costs associated with the production of amorphous cores,
and to a lesser extent larger and more efficient GOES cores. DOE agrees
with Schneider's comment that small businesses could mitigate larger
conversion costs by purchasing assembled cores as opposed to making the
investments to produce more efficient GOES cores or amorphous cores, in
order to comply with the analyzed standards.
b. Capital Equipment
ERMCO comments that larger cores may require new or different
manufacturing equipment. (ERMCO, No. 45 at p. 1) DOE agrees that while
capital conversion costs are primarily driven by the costs associated
with the production of amorphous cores, there are capital conversion
costs associated with production of larger cores. DOE accounts for the
need for manufacturers to purchase new or different equipment in the
capital conversion cost estimates described in section IV.J.2.c, with
these cost estimates presented in section V.B.2.a of this document.
K. Emissions Analysis
The emissions analysis consists of two components. The first
component estimates the effect of potential energy conservation
standards on power sector and site (where applicable) combustion
emissions of CO2, NOX, SO2, and Hg.
The second component estimates the impacts of potential standards on
emissions of two additional greenhouse gases, CH4 and
N2O, as well as the reductions to emissions of other gases
due to ``upstream'' activities in the fuel production chain. These
upstream activities comprise extraction, processing, and transporting
fuels to the site of combustion.
The analysis of electric power sector emissions of CO2,
NOX, SO2, and Hg uses emissions factors intended
to represent the marginal impacts of the change in electricity
consumption associated with amended or new standards. The methodology
is based on results published for the AEO, including a set of side
cases that implement a variety of efficiency-related policies. The
methodology is described in appendix 13A in the NOPR TSD. The analysis
presented in this notice uses projections from AEO2022. Power sector
emissions of CH4 and N2O from fuel combustion are
estimated using Emission Factors for Greenhouse Gas Inventories
published by the Environmental Protection Agency (EPA).\92\
---------------------------------------------------------------------------
\92\ Available at www.epa.gov/sites/production/files/2021-04/documents/emission-factors_apr2021.pdf (last accessed July 12,
2021).
---------------------------------------------------------------------------
FFC upstream emissions, which include emissions from fuel
combustion during extraction, processing, and transportation of fuels,
and ``fugitive'' emissions (direct leakage to the atmosphere) of
CH4 and CO2, are estimated based on the
methodology described in chapter 15 of the NOPR TSD.
The emissions intensity factors are expressed in terms of physical
units per MWh or MMBtu of site energy savings. For power sector
emissions, specific emissions intensity factors are calculated by
sector and end use. Total emissions reductions are estimated using the
energy savings calculated in the national impact analysis.
1. Air Quality Regulations Incorporated in DOE's Analysis
DOE's no-new-standards case for the electric power sector reflects
the AEO, which incorporates the projected impacts of existing air
quality regulations on emissions. AEO2022 generally represents current
legislation and environmental regulations, including recent government
actions, that were in place at the time of preparation of AEO2022,
including the emissions control programs discussed in the following
paragraphs.\93\
---------------------------------------------------------------------------
\93\ For further information, see the Assumptions to AEO2022
report that sets forth the major assumptions used to generate the
projections in the Annual Energy Outlook. Available at www.eia.gov/outlooks/aeo/assumptions/ (last accessed June, 2022).
---------------------------------------------------------------------------
SO2 emissions from affected electric generating units
(``EGUs'') are subject to nationwide and regional emissions cap-and-
trade programs. Title IV of the Clean Air Act sets an annual emissions
[[Page 1790]]
cap on SO2 for affected EGUs in the 48 contiguous States and
the District of Columbia (DC). (42 U.S.C. 7651 et seq.) SO2
emissions from numerous States in the eastern half of the United States
are also limited under the Cross-State Air Pollution Rule (``CSAPR'').
76 FR 48208 (Aug. 8, 2011). CSAPR requires these States to reduce
certain emissions, including annual SO2 emissions, and went
into effect as of January 1, 2015.\94\ AEO2022 incorporates
implementation of CSAPR, including the update to the CSAPR ozone season
program emission budgets and target dates issued in 2016. 81 FR 74504
(Oct. 26, 2016).\95\ Compliance with CSAPR is flexible among EGUs and
is enforced through the use of tradable emissions allowances. Under
existing EPA regulations, for states subject to SO2
emissions limits under CSAPR, excess SO2 emissions
allowances resulting from the lower electricity demand caused by the
adoption of an efficiency standard could be used to permit offsetting
increases in SO2 emissions by another regulated EGU.
---------------------------------------------------------------------------
\94\ CSAPR requires states to address annual emissions of
SO2 and NOX, precursors to the formation of
fine particulate matter (PM2.5) pollution, in order to
address the interstate transport of pollution with respect to the
1997 and 2006 PM2.5 National Ambient Air Quality
Standards (``NAAQS''). CSAPR also requires certain states to address
the ozone season (May-September) emissions of NOX, a
precursor to the formation of ozone pollution, in order to address
the interstate transport of ozone pollution with respect to the 1997
ozone NAAQS. 76 FR 48208 (Aug. 8, 2011). EPA subsequently issued a
supplemental rule that included an additional five states in the
CSAPR ozone season program; 76 FR 80760 (Dec. 27, 2011)
(Supplemental Rule), and EPA issued the CSAPR Update for the 2008
ozone NAAQS. 81 FR 74504 (Oct. 26, 2016).
\95\ In Sept. 2019, the D.C. Court of Appeals remanded the 2016
CSAPR Update to EPA. In April 2021, EPA finalized the 2021 CSAPR
Update which resolved the interstate transport obligations of 21
states for the 2008 ozone NAAQS. 86 FR 23054 (April 30, 2021); see
also, 86 FR 29948 (June 4, 2021) (correction to preamble). The 2021
CSAPR Update became effective on June 29, 2021. The release of AEO
2021 in February 2021 predated the 2021 CSAPR Update.
---------------------------------------------------------------------------
However, beginning in 2016, SO2 emissions began to fall
as a result of the Mercury and Air Toxics Standards (``MATS'') for
power plants. 77 FR 9304 (Feb. 16, 2012). In the MATS final rule, EPA
established a standard for hydrogen chloride as a surrogate for acid
gas hazardous air pollutants (``HAP''), and also established a standard
for SO2 (a non-HAP acid gas) as an alternative equivalent
surrogate standard for acid gas HAP. The same controls are used to
reduce HAP and non-HAP acid gas; thus, SO2 emissions are
being reduced as a result of the control technologies installed on
coal-fired power plants to comply with the MATS requirements for acid
gas. In order to continue operating, coal power plants must have either
flue gas desulfurization or dry sorbent injection systems installed.
Both technologies, which are used to reduce acid gas emissions, also
reduce SO2 emissions. Because of the emissions reductions
under the MATS, it is unlikely that excess SO2 emissions
allowances resulting from the lower electricity demand would be needed
or used to permit offsetting increases in SO2 emissions by
another regulated EGU. Therefore, energy conservation standards that
decrease electricity generation would generally reduce SO2
emissions. DOE estimated SO2 emissions reduction using
emissions factors based on AEO2022.
CSAPR also established limits on NOX emissions for
numerous States in the eastern half of the United States. Energy
conservation standards would have little effect on NOX
emissions in those States covered by CSAPR emissions limits if excess
NOX emissions allowances resulting from the lower
electricity demand could be used to permit offsetting increases in
NOX emissions from other EGUs. In such case, NOX
emissions would remain near the limit even if electricity generation
goes down. A different case could possibly result, depending on the
configuration of the power sector in the different regions and the need
for allowances, such that NOX emissions might not remain at
the limit in the case of lower electricity demand. In this case, energy
conservation standards might reduce NOX emissions in covered
States. Despite this possibility, DOE has chosen to be conservative in
its analysis and has maintained the assumption that standards will not
reduce NOX emissions in States covered by CSAPR. Energy
conservation standards would be expected to reduce NOX
emissions in the States not covered by CSAPR. DOE used AEO2022 data to
derive NOX emissions factors for the group of States not
covered by CSAPR.
The MATS limit mercury emissions from power plants, but they do not
include emissions caps and, as such, DOE's energy conservation
standards would be expected to slightly reduce Hg emissions. DOE
estimated mercury emissions reduction using emissions factors based on
AEO2022, which incorporates the MATS.
L. Monetizing Emissions Impacts
As part of the development of this proposed rule, for the purpose
of complying with the requirements of Executive Order 12866, DOE
considered the estimated monetary benefits from the reduced emissions
of CO2, CH4, N2O, NOX, and
SO2 that are expected to result from each of the TSLs
considered. In order to make this calculation analogous to the
calculation of the NPV of consumer benefit, DOE considered the reduced
emissions expected to result over the lifetime of products shipped in
the projection period for each TSL. This section summarizes the basis
for the values used for monetizing the emissions benefits and presents
the values considered in this NOPR.
On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-
30087) granted the federal government's emergency motion for stay
pending appeal of the February 11, 2022, preliminary injunction issued
in Louisiana v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of
the Fifth Circuit's order, the preliminary injunction is no longer in
effect, pending resolution of the federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. As reflected in this rule, DOE has
reverted to its approach prior to the injunction and presents monetized
greenhouse gas abatement benefits where appropriate and permissible
under law. DOE requests comment on how to address the climate benefits
and non-monetized effects of the proposal.
1. Monetization of Greenhouse Gas Emissions
For the purpose of complying with the requirements of Executive
Order 12866, DOE estimates the monetized benefits of the reductions in
emissions of CO2, CH4, and N2O by
using a measure of the social cost (``SC'') of each pollutant (e.g.,
SC-GHGs). These estimates represent the monetary value of the net harm
to society associated with a marginal increase in emissions of these
pollutants in a given year, or the benefit of avoiding that increase.
These estimates are intended to include (but are not limited to)
climate-change-related changes in net agricultural productivity, human
health, property damages from increased flood risk, disruption of
energy systems, risk of conflict, environmental migration, and the
value of ecosystem services. DOE exercises its own judgment in
presenting monetized climate benefits as recommended by applicable
[[Page 1791]]
Executive orders and guidance, and DOE would reach the same conclusion
presented in this proposed rulemaking in the absence of the social cost
of greenhouse gases, including the February 2021 Interim Estimates
presented by the Interagency Working Group on the Social Cost of
Greenhouse Gases.
DOE estimated the global social benefits of CO2,
CH4, and N2O reductions (i.e., SC-GHGs) using the
estimates presented in the Technical Support Document: Social Cost of
Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive
Order 13990 published in February 2021 by the Interagency Working Group
on the Social Cost of Greenhouse Gases (IWG) (IWG, 2021). The SC-GHGs
is the monetary value of the net harm to society associated with a
marginal increase in emissions in a given year, or the benefit of
avoiding that increase. In principle, SC-GHGs includes the value of all
climate change impacts, including (but not limited to) changes in net
agricultural productivity, human health effects, property damage from
increased flood risk and natural disasters, disruption of energy
systems, risk of conflict, environmental migration, and the value of
ecosystem services. The SC-GHGs therefore, reflects the societal value
of reducing emissions of the gas in question by one metric ton. The SC-
GHGs is the theoretically appropriate value to use in conducting
benefit-cost analyses of policies that affect CO2,
N2O and CH4 emissions. As a member of the IWG
involved in the development of the February 2021 SC-GHG TSD), the DOE
agrees that the interim SC-GHG estimates represent the most appropriate
estimate of the SC-GHG until revised estimates have been developed
reflecting the latest, peer-reviewed science.
The SC-GHGs estimates presented here were developed over many
years, using transparent process, peer-reviewed methodologies, the best
science available at the time of that process, and with input from the
public. Specifically, in 2009, an interagency working group (IWG) that
included the DOE and other executive branch agencies and offices was
established to ensure that agencies were using the best available
science and to promote consistency in the social cost of carbon (SC-
CO2) values used across agencies. The IWG published SC-
CO2 estimates in 2010 that were developed from an ensemble
of three widely cited integrated assessment models (IAMs) that estimate
global climate damages using highly aggregated representations of
climate processes and the global economy combined into a single
modeling framework. The three IAMs were run using a common set of input
assumptions in each model for future population, economic, and
CO2 emissions growth, as well as equilibrium climate
sensitivity (ECS)--a measure of the globally averaged temperature
response to increased atmospheric CO2 concentrations. These
estimates were updated in 2013 based on new versions of each IAM. In
August 2016 the IWG published estimates of the social cost of methane
(SC-CH4) and nitrous oxide (SC-N2O) using
methodologies that are consistent with the methodology underlying the
SC-CO2 estimates. The modeling approach that extends the IWG
SC-CO2 methodology to non-CO2 GHGs has undergone
multiple stages of peer review. The SC-CH4 and SC-
N2O estimates were developed by Marten et al. (2015) and
underwent a standard double-blind peer review process prior to journal
publication. In 2015, as part of the response to public comments
received to a 2013 solicitation for comments on the SC-CO2
estimates, the IWG announced a National Academies of Sciences,
Engineering, and Medicine review of the SC-CO2 estimates to
offer advice on how to approach future updates to ensure that the
estimates continue to reflect the best available science and
methodologies. In January 2017, the National Academies released their
final report, Valuing Climate Damages: Updating Estimation of the
Social Cost of Carbon Dioxide, and recommended specific criteria for
future updates to the SC-CO2 estimates, a modeling framework
to satisfy the specified criteria, and both near-term updates and
longer-term research needs pertaining to various components of the
estimation process (National Academies, 2017). Shortly thereafter, in
March 2017, President Trump issued Executive Order 13783, which
disbanded the IWG, withdrew the previous TSDs, and directed agencies to
ensure SC-CO2 estimates used in regulatory analyses are
consistent with the guidance contained in OMB's Circular A-4,
``including with respect to the consideration of domestic versus
international impacts and the consideration of appropriate discount
rates'' (E.O. 13783, Section 5(c)). Benefit-cost analyses following
E.O. 13783 used SC-GHG estimates that attempted to focus on the U.S.-
specific share of climate change damages as estimated by the models and
were calculated using two discount rates recommended by Circular A-4, 3
percent and 7 percent. All other methodological decisions and model
versions used in SC-GHG calculations remained the same as those used by
the IWG in 2010 and 2013, respectively.
On January 20, 2021, President Biden issued Executive Order 13990,
which re-established the IWG and directed it to ensure that the U.S.
Government's estimates of the social cost of carbon and other
greenhouse gases reflect the best available science and the
recommendations of the National Academies (2017). The IWG was tasked
with first reviewing the SC-GHG estimates currently used in Federal
analyses and publishing interim estimates within 30 days of the E.O.
that reflect the full impact of GHG emissions, including by taking
global damages into account. The interim SC-GHG estimates published in
February 2021 are used here to estimate the climate benefits for this
proposed rulemaking. The E.O. instructs the IWG to undertake a fuller
update of the SC-GHG estimates by January 2022 that takes into
consideration the advice of the National Academies (2017) and other
recent scientific literature. The February 2021 SC-GHG TSD provides a
complete discussion of the IWG's initial review conducted under E.O.
13990. In particular, the IWG found that the SC-GHG estimates used
under E.O. 13783 fail to reflect the full impact of GHG emissions in
multiple ways.
First, the IWG found that the SC-GHG estimates used under E.O.
13783 fail to fully capture many climate impacts that affect the
welfare of U.S. citizens and residents, and those impacts are better
reflected by global measures of the SC-GHG. Examples of effects omitted
from the E.O. 13783 estimates include direct effects on U.S. citizens,
assets, and investments located abroad, supply chains, U.S. military
assets and interests abroad, and tourism, and spillover pathways such
as economic and political destabilization and global migration that can
lead to adverse impacts on U.S. national security, public health, and
humanitarian concerns. In addition, assessing the benefits of U.S. GHG
mitigation activities requires consideration of how those actions may
affect mitigation activities by other countries, as those international
mitigation actions will provide a benefit to U.S. citizens and
residents by mitigating climate impacts that affect U.S. citizens and
residents. A wide range of scientific and economic experts have
emphasized the issue of reciprocity as support for considering global
damages of GHG emissions. If the United States does not consider
impacts on other countries, it is difficult to convince other countries
to consider the
[[Page 1792]]
impacts of their emissions on the United States. The only way to
achieve an efficient allocation of resources for emissions reduction on
a global basis--and so benefit the U.S. and its citizens--is for all
countries to base their policies on global estimates of damages. As a
member of the IWG involved in the development of the February 2021 SC-
GHG TSD, DOE agrees with this assessment and, therefore, in this
proposed rule DOE centers attention on a global measure of SC-GHG. This
approach is the same as that taken in DOE regulatory analyses from 2012
through 2016. A robust estimate of climate damages that accrue only to
U.S. citizens and residents does not currently exist in the literature.
As explained in the February 2021 TSD, existing estimates are both
incomplete and an underestimate of total damages that accrue only to
the citizens and residents of the U.S. because they do not fully
capture the regional interactions and spillovers discussed above, nor
do they include all of the important physical, ecological, and economic
impacts of climate change recognized in the climate change literature.
As noted in the February 2021 SC-GHG TSD, the IWG will continue to
review developments in the literature, including more robust
methodologies for estimating a U.S.-specific SC-GHG value, and explore
ways to better inform the public of the full range of carbon impacts.
As a member of the IWG, DOE will continue to follow developments in the
literature pertaining to this issue.
Second, the IWG found that the use of the social rate of return on
capital (7 percent under current OMB Circular A-4 guidance) to discount
the future benefits of reducing GHG emissions inappropriately
underestimates the impacts of climate change for the purposes of
estimating the SC-GHG. Consistent with the findings of the National
Academies (2017) and the economic literature, the IWG continued to
conclude that the consumption rate of interest is the theoretically
appropriate discount rate in an intergenerational context (IWG 2010,
2013, 2016a, 2016b), and recommended that discount rate uncertainty and
relevant aspects of intergenerational ethical considerations be
accounted for in selecting future discount rates. As a member of the
IWG involved in the development of the February 2021 SC-GHG TSD, DOE
agrees with this assessment and will continue to follow developments in
the literature pertaining to this issue.
Furthermore, the damage estimates developed for use in the SC-GHG
are estimated in consumption-equivalent terms, and so an application of
OMB Circular A-4's guidance for regulatory analysis would then use the
consumption discount rate to calculate the SC-GHG. DOE agrees with this
assessment and will continue to follow developments in the literature
pertaining to this issue. DOE also notes that while OMB Circular A-4,
as published in 2003, recommends using 3% and 7% discount rates as
``default'' values, Circular A-4 also reminds agencies that ``different
regulations may call for different emphases in the analysis, depending
on the nature and complexity of the regulatory issues and the
sensitivity of the benefit and cost estimates to the key assumptions.''
On discounting, Circular A-4 recognizes that ``special ethical
considerations arise when comparing benefits and costs across
generations,'' and Circular A-4 acknowledges that analyses may
appropriately ``discount future costs and consumption benefits . . . at
a lower rate than for intragenerational analysis.'' In the 2015
Response to Comments on the Social Cost of Carbon for Regulatory Impact
Analysis, OMB, DOE, and the other IWG members recognized that
``Circular A-4 is a living document'' and ``the use of 7 percent is not
considered appropriate for intergenerational discounting. There is wide
support for this view in the academic literature, and it is recognized
in Circular A-4 itself.'' Thus, DOE concludes that a 7% discount rate
is not appropriate to apply to value the social cost of greenhouse
gases in the analysis presented in this analysis. In this analysis, to
calculate the present and annualized values of climate benefits, DOE
uses the same discount rate as the rate used to discount the value of
damages from future GHG emissions, for internal consistency. That
approach to discounting follows the same approach that the February
2021 TSD recommends ``to ensure internal consistency--i.e., future
damages from climate change using the SC-GHG at 2.5 percent should be
discounted to the base year of the analysis using the same 2.5 percent
rate.'' DOE has also consulted the National Academies' 2017
recommendations on how SC-GHG estimates can ``be combined in RIAs with
other cost and benefits estimates that may use different discount
rates.'' The National Academies reviewed ``several options,'' including
``presenting all discount rate combinations of other costs and benefits
with [SC-GHG] estimates.''
While the IWG works to assess how best to incorporate the latest,
peer reviewed science to develop an updated set of SC-GHG estimates, it
set the interim estimates to be the most recent estimates developed by
the IWG prior to the group being disbanded in 2017. The estimates rely
on the same models and harmonized inputs and are calculated using a
range of discount rates. As explained in the February 2021 SC-GHG TSD,
the IWG has recommended that agencies to revert to the same set of four
values drawn from the SC-GHG distributions based on three discount
rates as were used in regulatory analyses between 2010 and 2016 and
subject to public comment. For each discount rate, the IWG combined the
distributions across models and socioeconomic emissions scenarios
(applying equal weight to each) and then selected a set of four values
recommended for use in benefit-cost analyses: an average value
resulting from the model runs for each of three discount rates (2.5
percent, 3 percent, and 5 percent), plus a fourth value, selected as
the 95th percentile of estimates based on a 3 percent discount rate.
The fourth value was included to provide information on potentially
higher-than-expected economic impacts from climate change. As explained
in the February 2021 SC-GHG TSD, and DOE agrees, this update reflects
the immediate need to have an operational SC-GHG for use in regulatory
benefit-cost analyses and other applications that was developed using a
transparent process, peer-reviewed methodologies, and the science
available at the time of that process. Those estimates were subject to
public comment in the context of dozens of proposed rulemakings as well
as in a dedicated public comment period in 2013.
There are a number of limitations and uncertainties associated with
the SC-GHG estimates. First, the current scientific and economic
understanding of discounting approaches suggests discount rates
appropriate for intergenerational analysis in the context of climate
change are likely to be less than 3 percent, near 2 percent or lower.
Second, the IAMs used to produce these interim estimates do not include
all of the important physical, ecological, and economic impacts of
climate change recognized in the climate change literature and the
science underlying their ``damage functions''--i.e., the core parts of
the IAMs that map global mean temperature changes and other physical
impacts of climate change into economic (both market and nonmarket)
damages--lags behind the most recent research. For example, limitations
include the incomplete treatment of catastrophic and non-catastrophic
impacts in the integrated assessment models, their incomplete treatment
of
[[Page 1793]]
adaptation and technological change, the incomplete way in which inter-
regional and intersectoral linkages are modeled, uncertainty in the
extrapolation of damages to high temperatures, and inadequate
representation of the relationship between the discount rate and
uncertainty in economic growth over long time horizons. Likewise, the
socioeconomic and emissions scenarios used as inputs to the models do
not reflect new information from the last decade of scenario generation
or the full range of projections. The modeling limitations do not all
work in the same direction in terms of their influence on the SC-CO2
estimates. However, as discussed in the February 2021 TSD, the IWG has
recommended that, taken together, the limitations suggest that the
interim SC-GHG estimates used in this final rule likely underestimate
the damages from GHG emissions. DOE concurs with this assessment.
DOE's derivations of the SC-GHG (i.e., SC-CO2, SC-
N2O, and SC-CH4) values used for this NOPR are
discussed in the following sections, and the results of DOE's analyses
estimating the benefits of the reductions in emissions of these
pollutants are presented in section V.B.6 of this document.
a. Social Cost of Carbon
The SC-CO2 values used for this NOPR were generated
using the values presented in the 2021 update from the IWG's February
2021 TSD. Table IV.19 shows the updated sets of SC-CO2
estimates from the latest interagency update in 5-year increments from
2020 to 2050. The full set of annual values used is presented in
Appendix 14A of the NOPR TSD. For purposes of capturing the
uncertainties involved in regulatory impact analysis, DOE has
determined it is appropriate to include all four sets of SC-
CO2 values, as recommended by the IWG.\96\
---------------------------------------------------------------------------
\96\ For example, the February 2021 TSD discusses how the
understanding of discounting approaches suggests that discount rates
appropriate for intergenerational analysis in the context of climate
change may be lower than 3 percent.
Table IV.19--Annual SC-CO2 Values From 2021 Interagency Update, 2020-2070
[2020$ per metric ton CO2]
----------------------------------------------------------------------------------------------------------------
Discount rate and statistics
-----------------------------------------------------------------------------------------------------------------
3%, 95th
Emissions year 5%, average 3%, average 2.5%, average percentile
----------------------------------------------------------------------------------------------------------------
2020............................................ 14 51 76 151
2025............................................ 17 56 83 169
2030............................................ 19 62 89 186
2035............................................ 22 67 96 205
2040............................................ 25 73 103 224
2045............................................ 28 79 109 242
2050............................................ 32 84 116 259
2055............................................ 35 89 122 265
2060............................................ 38 93 128 275
2065............................................ 44 100 135 300
2070............................................ 49 108 143 326
----------------------------------------------------------------------------------------------------------------
The SC-CO2 values used for this NOPR were based on the
values presented in the 2021 update from the IWG's February 2021 SC-GHG
TSD. For 2051 to 2070, DOE used estimates published by EPA, adjusted to
2021$.\97\ These estimates are based on methods, assumptions, and
parameters identical to the 2020-2050 estimates published by the IWG.
DOE expects additional climate benefits to accrue for any longer-life
transformers post 2070, but a lack of available SC-CO2
estimates for emissions years beyond 2070 prevents DOE from monetizing
these potential benefits in this analysis. If further analysis of
monetized climate benefits beyond 2070 becomes available prior to the
publication of the final rule, DOE will include that analysis in the
final rule. DOE multiplied the CO2 emissions reduction
estimated for each year by the SC-CO2 value for that year in
each of the four cases. To calculate a present value of the stream of
monetary values, DOE discounted the values in each of the four cases
using the specific discount rate that had been used to obtain the SC-
CO2 values in each case.
---------------------------------------------------------------------------
\97\ See EPA, Revised 2023 and Later Model Year Light-Duty
Vehicle GHG Emissions Standards: Regulatory Impact Analysis,
Washington, DC, December 2021. Available at: www.epa.gov/system/files/documents/2021-12/420r21028.pdf (last accessed January 13,
2022).
---------------------------------------------------------------------------
b. Social Cost of Methane and Nitrous Oxide
The SC-CH4 and SC-N2O values used for this
NOPR were generated using the values presented in the February 2021
TSD. Table IV.20 shows the updated sets of SC-CH4 and SC-
N2O estimates from the latest interagency update in 5-year
increments from 2020 to 2050. The full set of annual values used is
presented in Appendix 14A of the NOPR TSD. To capture the uncertainties
involved in regulatory impact analysis, DOE has determined it is
appropriate to include all four sets of SC-CH4 and SC-
N2O values, as recommended by the IWG.
Table IV.20--Annual SC-CH4 and SC-N2O Values From 2021 Interagency Update, 2020-2070
[2020$ per metric ton]
--------------------------------------------------------------------------------------------------------------------------------------------------------
SC-CH4--discount rate and statistic SC-N2O--discount rate and statistic
-------------------------------------------------------------------------------------------------------------
5% 3% 2.5% 3% 5% 3% 2.5% 3%
Year -------------------------------------------------------------------------------------------------------------
95th 95th
Average Average Average percentile Average Average Average percentile
--------------------------------------------------------------------------------------------------------------------------------------------------------
2020...................................... 663 1,480 1,946 3,893 5,760 18,342 27,037 48,090
[[Page 1794]]
2025...................................... 799 1,714 2,223 4,533 6,766 20,520 29,811 54,108
2030...................................... 935 1,948 2,499 5,173 7,772 22,698 32,585 60,125
2035...................................... 1,106 2,224 2,817 5,939 9,007 25,149 35,632 66,898
2040...................................... 1,277 2,500 3,136 6,705 10,241 27,600 38,678 73,670
2045...................................... 1,464 2,778 3,450 7,426 11,687 30,238 41,888 80,766
2050...................................... 1,651 3,057 3,763 8,147 13,133 32,875 45,098 87,863
2055...................................... 1,772 3,221 3,942 8,332 14,758 35,539 48,236 94,117
2060...................................... 1,899 3,395 4,130 8,539 16,424 38,300 51,507 100,845
2065...................................... 2,508 4,163 4,960 11,177 19,687 42,625 56,397 115,590
2070...................................... 3,130 4,976 5,867 14,079 23,018 47,072 61,428 130,928
--------------------------------------------------------------------------------------------------------------------------------------------------------
DOE multiplied the CH4 and N2O emissions
reduction estimated for each year by the SC-CH4 and SC-
N2O estimates for that year in each of the cases. To
calculate a present value of the stream of monetary values, DOE
discounted the values in each of the cases using the specific discount
rate that had been used to obtain the SC-CH4 and SC-
N2O estimates in each case.
2. Monetization of Other Emissions Impacts
For the NOPR, DOE estimated the monetized value of NOX
and SO2 emissions reductions from electricity generation
using the latest benefit per ton estimates for that sector from the
EPA's Benefits Mapping and Analysis Program.\98\ DOE used EPA's values
for PM2.5-related benefits associated with NOX
and SO2 and for ozone-related benefits associated with
NOX for 2025 2030, and 2040, calculated with discount rates
of 3 percent and 7 percent. DOE used linear interpolation to define
values for the years not given in the 2025 to 2040 period; for years
beyond 2040 the values are held constant. DOE derived values specific
to the sector for distribution transformer using a method described in
appendix 14B of the NOPR TSD.
---------------------------------------------------------------------------
\98\ Estimating the Benefit per Ton of Reducing PM2.5 Precursors
from 21 Sectors. www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
---------------------------------------------------------------------------
DOE multiplied the site emissions reduction (in tons) in each year
by the associated $/ton values, and then discounted each series using
discount rates of 3 percent and 7 percent as appropriate.
M. Utility Impact Analysis
The utility impact analysis estimates several effects on the
electric power generation industry that would result from the adoption
of new or amended energy conservation standards. The utility impact
analysis estimates the changes in installed electrical capacity and
generation that would result for each TSL. The analysis is based on
published output from the NEMS associated with AEO2022. NEMS produces
the AEO Reference case, as well as a number of side cases that estimate
the economy-wide impacts of changes to energy supply and demand. For
the current analysis, impacts are quantified by comparing the levels of
electricity sector generation, installed capacity, fuel consumption and
emissions in the AEO2022 Reference case and various side cases. Details
of the methodology are provided in the appendices to chapters 13 and 15
of the NOPR TSD.
The output of this analysis is a set of time-dependent coefficients
that capture the change in electricity generation, primary fuel
consumption, installed capacity and power sector emissions due to a
unit reduction in demand for a given end use. These coefficients are
multiplied by the stream of electricity savings calculated in the NIA
to provide estimates of selected utility impacts of potential new or
amended energy conservation standards.
N. Employment Impact Analysis
DOE considers employment impacts in the domestic economy as one
factor in selecting a proposed standard. Employment impacts from new or
amended energy conservation standards include both direct and indirect
impacts. Direct employment impacts are any changes in the number of
employees of manufacturers of the products subject to standards, their
suppliers, and related service firms. The MIA addresses those impacts.
Indirect employment impacts are changes in national employment that
occur due to the shift in expenditures and capital investment caused by
the purchase and operation of more-efficient appliances. Indirect
employment impacts from standards consist of the net jobs created or
eliminated in the national economy, other than in the manufacturing
sector being regulated, caused by (1) reduced spending by consumers on
energy, (2) reduced spending on new energy supply by the utility
industry, (3) increased consumer spending on the products to which the
new standards apply and other goods and services, and (4) the effects
of those three factors throughout the economy.
One method for assessing the possible effects on the demand for
labor of such shifts in economic activity is to compare sector
employment statistics developed by the Labor Department's Bureau of
Labor Statistics (``BLS''). BLS regularly publishes its estimates of
the number of jobs per million dollars of economic activity in
different sectors of the economy, as well as the jobs created elsewhere
in the economy by this same economic activity. Data from BLS indicate
that expenditures in the utility sector generally create fewer jobs
(both directly and indirectly) than expenditures in other sectors of
the economy.\99\ There are many reasons for these differences,
including wage differences and the fact that the utility sector is more
capital-intensive and less labor-intensive than other sectors. Energy
conservation standards have the effect of reducing consumer utility
bills. Because reduced consumer expenditures for energy likely lead to
increased expenditures in other sectors of the economy, the general
effect of
[[Page 1795]]
efficiency standards is to shift economic activity from a less labor-
intensive sector (i.e., the utility sector) to more labor-intensive
sectors (e.g., the retail and service sectors). Thus, the BLS data
suggest that net national employment may increase due to shifts in
economic activity resulting from energy conservation standards.
---------------------------------------------------------------------------
\99\ See U.S. Department of Commerce-Bureau of Economic
Analysis. Regional Multipliers: A User Handbook for the Regional
Input-Output Modeling System (RIMS II). 1997. U.S. Government
Printing Office: Washington, DC. Available at apps.bea.gov/scb/pdf/regional/perinc/meth/rims2.pdf (last accessed June 1, 2022).
---------------------------------------------------------------------------
DOE estimated indirect national employment impacts for the standard
levels considered in this NOPR using an input/output model of the U.S.
economy called Impact of Sector Energy Technologies version 4
(``ImSET'').\100\ ImSET is a special-purpose version of the ``U.S.
Benchmark National Input-Output'' (``I-O'') model, which was designed
to estimate the national employment and income effects of energy-saving
technologies. The ImSET software includes a computer-based I-O model
having structural coefficients that characterize economic flows among
187 sectors most relevant to industrial, commercial, and residential
building energy use.
---------------------------------------------------------------------------
\100\ Livingston, O.V., S.R. Bender, M.J. Scott, and R.W.
Schultz. ImSET 4.0: Impact of Sector Energy Technologies Model
Description and User Guide. 2015. Pacific Northwest National
Laboratory: Richland, WA. PNNL-24563.
---------------------------------------------------------------------------
DOE notes that ImSET is not a general equilibrium forecasting
model, and that the uncertainties involved in projecting employment
impacts, especially changes in the later years of the analysis. Because
ImSET does not incorporate price changes, the employment effects
predicted by ImSET may over-estimate actual job impacts over the long
run for this rule. Therefore, DOE used ImSET only to generate results
for near-term timeframes (2031), where these uncertainties are reduced.
For more details on the employment impact analysis, see chapter 16 of
the NOPR TSD.
V. Analytical Results and Conclusions
The following section addresses the results from DOE's analyses
with respect to the considered energy conservation standards for
distribution transformers. It addresses the TSLs examined by DOE, the
projected impacts of each of these levels if adopted as energy
conservation standards for distribution transformers, and the standards
levels that DOE is proposing to adopt in this NOPR. Additional details
regarding DOE's analyses are contained in the NOPR TSD supporting this
document.
A. Trial Standard Levels
In general, DOE typically evaluates potential amended standards for
products and equipment by grouping individual efficiency levels for
each class into TSLs. Use of TSLs allows DOE to identify and consider
manufacturer cost interactions between the equipment classes, to the
extent that there are such interactions, and market cross elasticity
from consumer purchasing decisions that may change when different
standard levels are set. DOE presents the results for the TSLs in this
document, while the results for all efficiency levels that DOE analyzed
are in the NOPR TSD.
In the analysis conducted for this NOPR, DOE analyzed the benefits
and burdens of five TSLs for distribution transformers. DOE developed
TSLs that combine efficiency levels for each analyzed representative
unit and their respective equipment classes. For this NOPR, DOE defined
its efficiency levels as a percentage reduction in baseline losses (see
section IV.F.2). To create TSLs, DOE maintained this approach and
directly mapped ELs to TSLs, with the exception of liquid-immersed
submersible distribution transformers which remain at baseline for all
TSLs except max-tech. For submersible distribution transformers, being
able to fit in an existing vault is a consumer feature of significant
utility and these transformers often serve high density applications.
DOE recognizes that beyond some size increase a vault replacement may
be necessary, however, DOE lacks sufficient data as to where exactly
that vault replacement is needed. In order to maintain the consumer
utility associated with submersible transformers, DOE has taken the
conservative approach of not considering TSLs for submersible
transformers aside from max-tech. DOE presents the results for the TSLs
in this document, while the results for all efficiency levels that DOE
analyzed are in the NOPR TSD.
Table V.1 presents the TSLs and the corresponding efficiency levels
that DOE has identified for potential amended energy conservation
standards for distribution transformers. TSL 5 represents the maximum
technologically feasible (``max-tech'') energy efficiency for all
product classes. TSL 4 represents a loss reduction over baseline of 20
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 40 and 30 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 30 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 3 represents a loss reduction over baseline of 10
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 30 and 20 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 20 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 2 represents a loss reduction over baseline of 5
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 20 and 10 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 10 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers. TSL 1 represents a loss reduction over baseline of 2.5
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 10 and 5 percent
reduction in baseline losses for single-, and three-phase low-voltage
distribution transformers, respectively; and a 5 percent reduction in
baseline losses for all medium-voltage dry-type distribution
transformers.
Table V.1--Efficiency Level to Trial Standard Level Mapping for Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Equipment type EC RU Phases BIL -------------------------------------------------
1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-immersed........................... 1 1 1 All......................... 1 2 3 4 5
1 2 1 All......................... 1 2 3 4 5
1 3 1 All......................... 1 2 3 4 5
2 4 3 All......................... 1 2 3 4 5
[[Page 1796]]
2 5 3 All......................... 1 2 3 4 5
2 17 3 All......................... 1 2 3 4 5
12 15 3 All......................... 0 0 0 0 5
12 16 3 All......................... 0 0 0 0 5
Low-voltage Dry-type...................... 3 6 1 All......................... 1 2 3 4 5
4 7 3 All......................... 1 2 3 4 5
4 8 3 All......................... 1 2 3 4 5
Medium-voltage Dry-type................... 5 * 9V 1 <46 kV...................... 1 2 3 4 5
5 10V 1 <46 kV...................... 1 2 3 4 5
6 9 3 <46 kV...................... 1 2 3 4 5
6 10 3 <46 kV...................... 1 2 3 4 5
7 11V 1 >=46 and <96 kV............. 1 2 3 4 5
7 12V 1 >=46 and <96 kV............. 1 2 3 4 5
8 11 3 >=46 and <96 kV............. 1 2 3 4 5
8 12 3 >=46 and <96 kV............. 1 2 3 4 5
8 18 3 >=46 and <96 kV............. 1 2 3 4 5
9 13V 1 >=96 kV..................... 1 2 3 4 5
9 14V 1 >=96 kV..................... 1 2 3 4 5
10 13 3 >=96 kV..................... 1 2 3 4 5
10 14 3 >=96 kV..................... 1 2 3 4 5
10 19 3 >=96 kV..................... 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
DOE constructed the TSLs for this NOPR to include ELs
representative of ELs with similar characteristics (i.e., using similar
technologies and/or efficiencies, and having roughly comparable
equipment availability). The use of representative ELs provided for
greater distinction between the TSLs. While representative ELs were
included in the TSLs, DOE considered all efficiency levels as part of
its analysis.\101\
---------------------------------------------------------------------------
\101\ Efficiency levels that were analyzed for this NOPR are
discussed in section IV.F.2 of this document. Results by efficiency
level are presented in TSD chapters 8, 10, and 12.
---------------------------------------------------------------------------
B. Economic Justification and Energy Savings
1. Economic Impacts on Individual Consumers
DOE analyzed the economic impacts on distribution transformers
consumers by looking at the effects that potential amended standards at
each TSL would have on the LCC and PBP. DOE also examined the impacts
of potential standards on selected consumer subgroups. These analyses
are discussed in the following sections.
a. Life-Cycle Cost and Payback Period
In general, higher-efficiency products affect consumers in two
ways: (1) purchase price increases and (2) annual operating costs
decrease. Inputs used for calculating the LCC and PBP include total
installed costs (i.e., product price plus installation costs), and
operating costs (i.e., annual energy use, energy prices, energy price
trends, repair costs, and maintenance costs). The LCC calculation also
uses product lifetime and a discount rate. Because some consumers
purchase products with higher efficiency in the no-new-standards case,
the average savings are less than the difference between the average
LCC of the baseline product and the average LCC at each TSL. The
savings refer only to consumers who are affected by a standard at a
given TSL. Those who already purchase a product with efficiency at or
above a given TSL are not affected. Consumers for whom the LCC
increases at a given TSL experience a net cost. Chapter 8 of the NOPR
TSD provides detailed information on the LCC and PBP analyses.
Liquid-Immersed Distribution Transformers
Table V.2--Average LCC and PBP Results for Representative Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 2,917 67 1,346 4,263 .............. 31.9
1....................................................... 2,983 66 1,328 4,311 86.7 31.9
2....................................................... 3,073 65 1,299 4,373 73.0 31.9
3....................................................... 3,294 48 969 4,263 19.2 31.9
4....................................................... 3,279 45 913 4,192 16.0 31.9
5....................................................... 4,080 39 778 4,859 40.9 31.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 1 represents 20.3 percent of liquid-immersed distribution transformers units shipped, and 21.8 percent of shipments for equipment class 1
(single phase liquid-immersed).
[[Page 1797]]
Table V.3--LCC Savings Relative to the Base Case Efficiency Distribution
for Representative Unit 1
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 68.8 -53
2........................... 85.5 -114
3........................... 47.4 0
4........................... 33.7 72
5........................... 95.6 -599
------------------------------------------------------------------------
Rep unit 1 represents 20.3 percent of liquid-immersed distribution
transformers units shipped, and 21.8 percent of shipments for
equipment class 1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Table V.4--Average LCC and PBP Results for Representative Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 1,805 41 818 2,623 .............. 31.9
1....................................................... 1,805 33 673 2,478 0.1 31.9
2....................................................... 1,810 30 613 2,423 0.5 31.9
3....................................................... 1,857 29 580 2,437 4.1 31.9
4....................................................... 1,951 27 541 2,492 10.1 31.9
5....................................................... 2,347 23 452 2,799 29.1 31.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 2 represents 72.7 percent of liquid-immersed distribution transformers units shipped, and 78.0 percent of shipments for equipment class 1
(single phase liquid-immersed).
Table V.5--LCC Savings Relative to the Base Case Efficiency Distribution
for Representative Unit 2
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 21.9 146
2........................... 9.6 201
3........................... 9.3 186
4........................... 13.3 131
5........................... 84.3 -176
------------------------------------------------------------------------
Rep unit 2 represents 72.7 percent of liquid-immersed distribution
transformers units shipped, and 78.0 percent of shipments for
equipment class 1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Table V.6--Average LCC and PBP Results for Representative Unit 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 10,728 427 8,523 19,251 .............. 31.8
1....................................................... 11,269 335 6,900 18,169 5.9 31.8
2....................................................... 11,304 323 6,668 17,972 5.6 31.8
3....................................................... 11,754 305 6,284 18,038 8.4 31.8
4....................................................... 12,568 275 5,656 18,225 12.2 31.8
5....................................................... 14,920 234 4,744 19,664 21.8 31.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 3 represents 0.2 percent of liquid-immersed distribution transformers units shipped, and 0.2 percent of shipments for equipment class 1 (single
phase liquid-immersed).
Table V.7--LCC Savings Relative to the Base Case Efficiency Distribution
for Representative Unit 3
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 27.9 1,121
2........................... 22.2 1,312
3........................... 23.3 1,216
[[Page 1798]]
4........................... 22.5 1,029
5........................... 64.5 -414
------------------------------------------------------------------------
Rep unit 3 represents 0.2 percent of liquid-immersed distribution
transformers units shipped, and 0.2 percent of shipments for equipment
class 1 (single phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Table V.8--Average LCC and PBP Results for Representative Unit 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 10,319 196 3,913 14,232 .............. 32.0
1....................................................... 10,403 193 3,846 14,249 25.8 32.0
2....................................................... 10,596 184 3,689 14,285 24.1 32.0
3....................................................... 11,095 137 2,768 13,863 13.1 32.0
4....................................................... 11,120 129 2,616 13,736 11.9 32.0
5....................................................... 11,798 117 2,359 14,156 18.7 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 4 represents 4.6 percent of liquid-immersed distribution transformers units shipped, and 68.0 percent of shipments for equipment class 2 (three
phase liquid-immersed).
Table V.9--LCC Savings Relative to the Base Case Efficiency Distribution
for Representative Unit 4
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 38.2 -26
2........................... 66.6 -55
3........................... 24.8 381
4........................... 12.9 511
5........................... 48.9 77
------------------------------------------------------------------------
Rep unit 4 represents 4.6 percent of liquid-immersed distribution
transformers units shipped, and 68.0 percent of shipments for
equipment class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Table V.10--Average LCC and PBP Results for Representative Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 35,245 1,195 23,754 58,999 .............. 31.7
1....................................................... 36,431 1,079 21,647 58,078 10.2 31.7
2....................................................... 36,603 1,006 20,349 56,952 7.2 31.7
3....................................................... 37,550 966 19,573 57,123 10.0 31.7
4....................................................... 39,455 891 18,002 57,457 13.8 31.7
5....................................................... 52,032 744 14,880 66,912 37.2 31.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 5 represents 2.1 percent of liquid-immersed distribution transformers units shipped, and 31.5 percent of shipments for equipment class 2 (three
phase liquid-immersed).
Table V.11--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 5
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 41.0 986
2........................... 26.7 2,095
3........................... 28.7 1,888
4........................... 28.5 1,543
[[Page 1799]]
5........................... 95.8 -7,913
------------------------------------------------------------------------
Rep unit 5 represents 2.1 percent of liquid-immersed distribution
transformers units shipped, and 31.5 percent of shipments for
equipment class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Table V.12--Average LCC and PBP Results for Representative Unit 15
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple Average
Standard level First year's Lifetime payback lifetime
Installed cost operating operating LCC period (years)
cost cost (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 10,749 196 3,919 14,668 .............. 32.0
1....................................................... 10,833 193 3,855 14,687 26.3 32.0
2....................................................... 11,026 185 3,700 14,727 24.5 32.0
3....................................................... 11,523 137 2,778 14,301 13.1 32.0
4....................................................... 11,548 129 2,628 14,176 12.0 32.0
5....................................................... 12,228 117 2,367 14,595 18.8 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 15 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.4 percent of equipment class 12 shipments.
Table V.13--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 15
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021$) *
------------------------------------------------------------------------
1........................... 38.3 -30
2........................... 67.3 -61
3........................... 24.5 379
4........................... 12.8 507
5........................... 49.4 74
------------------------------------------------------------------------
Rep unit 15 represents <0.1 percent of liquid-immersed distribution
transformers units shipped, and 0.4 percent of shipments for equipment
class 12 (three phase liquid-immersed submersible).
* The savings represent the average LCC for affected consumers.
Table V.14--Average LCC and PBP Results for Representative Unit 16
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple Average
Standard level First year's Lifetime payback lifetime
Installed cost operating operating LCC period (years)
cost cost (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 35,814 1,255 25,345 61,159 .............. 32.1
1....................................................... 37,015 1,146 23,365 60,380 11.0 32.1
2....................................................... 37,183 1,085 22,313 59,496 8.0 32.1
3....................................................... 38,135 1,045 21,549 59,684 11.1 32.1
4....................................................... 40,044 961 19,748 59,791 14.4 32.1
5....................................................... 52,622 789 16,044 68,666 36.1 32.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 16 represents 0.1 percent of liquid-immersed distribution transformers units shipped, and 99.6 percent of shipments for equipment class 12
(three phase liquid-immersed submersible).
Table V.15--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 16
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021$) *
------------------------------------------------------------------------
1........................... 42.0 829
2........................... 28.9 1,700
3........................... 32.3 1,482
4........................... 29.5 1,368
[[Page 1800]]
5........................... 95.1 -7,509
------------------------------------------------------------------------
Rep unit 16 represents 0.1 percent of liquid-immersed distribution
transformers units shipped, and 99.6 percent of shipments for
equipment class 12 (three phase liquid-immersed submersible).
* The savings represent the average LCC for affected consumers.
Table V.16--Average LCC and PBP Results for Representative Unit 17
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple Average
Standard level First year's Lifetime payback lifetime
Installed cost operating operating LCC period (years)
cost cost (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 55,256 3,485 71,294 126,550 .............. 32.1
1....................................................... 70,709 2,485 50,618 121,327 15.5 32.1
2....................................................... 72,775 2,283 47,047 119,822 14.6 32.1
3....................................................... 74,623 2,208 45,574 120,197 15.2 32.1
4....................................................... 78,307 2,028 41,715 120,023 15.8 32.1
5....................................................... 102,728 1,650 33,556 136,283 25.9 32.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 17 represents <0.1 percent of liquid-immersed distribution transformers units shipped, and 0.5 percent of shipments for equipment class 2
(three phase liquid-immersed).
Table V.17--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 17
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021$) *
------------------------------------------------------------------------
1........................... 42.8 5,346
2........................... 34.2 6,873
3........................... 36.8 6,472
4........................... 41.5 6,594
5........................... 73.9 -9,755
------------------------------------------------------------------------
Rep unit 17 represents <0.1 percent of liquid-immersed distribution
transformers units shipped, and 0.5 percent of shipments for equipment
class 2 (three phase liquid-immersed).
* The savings represent the average LCC for affected consumers.
Low-Voltage Dry-Type Distribution Transformers
Table V.18--Average LCC and PBP Results for Representative Unit 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple Average
Standard level First year's Lifetime payback lifetime
Installed cost operating operating LCC period (years)
cost cost (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 1,737 97 1,424 3,161 .............. 31.9
1....................................................... 1,735 90 1,327 3,063 0.0 31.9
2....................................................... 1,783 83 1,220 3,003 3.3 31.9
3....................................................... 1,890 77 1,127 3,017 7.6 31.9
4....................................................... 2,144 62 908 3,053 11.7 31.9
5....................................................... 2,311 48 703 3,014 11.7 31.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 6 represents 9.3 percent of low-voltage dry-type distribution transformers units shipped, and 100.0 percent of shipments for equipment class 3
(single phase low-voltage dry-type).
Table V.19--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 6
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021$) *
------------------------------------------------------------------------
1........................... 1 312
[[Page 1801]]
2........................... 17 203
3........................... 33 146
4........................... 43 108
5........................... 40 147
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 6 represents 9.3 percent of low-voltage dry-type distribution
transformers units shipped, and 100.0 percent of shipments for
equipment class 3 (single phase low-voltage dry-type).
Table V.20--Average LCC and PBP Results for Representative Unit 7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple Average
Standard level First year's Lifetime payback lifetime
Installed cost operating operating LCC period (years)
cost cost (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 3,974 228 3,366 7,340 .............. 32.1
1....................................................... 3,929 211 3,114 7,043 0.0 32.1
2....................................................... 3,920 206 3,029 6,950 0.0 32.1
3....................................................... 4,266 193 2,842 7,108 8.2 32.1
4....................................................... 4,621 143 2,102 6,723 7.5 32.1
5....................................................... 4,829 132 1,947 6,776 8.9 32.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 7 represents 84.9 percent of low-voltage dry-type distribution transformers units shipped, and 93.6 percent of shipments for equipment class 4
(three phase low-voltage dry-type).
Table V.21--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 7
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021$) *
------------------------------------------------------------------------
1........................... 8 357
2........................... 7 397
3........................... 28 233
4........................... 9 617
5........................... 15 564
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 7 represents 84.9 percent of low-voltage dry-type distribution
transformers units shipped, and 93.6 percent of shipments for
equipment class 4 (three phase low-voltage dry-type).
Table V.22--Average LCC and PBP Results for Representative Unit 8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 9,252 632 9,207 18,459 .............. 32.0
1....................................................... 9,348 613 8,937 18,285 5.2 32.0
2....................................................... 9,746 588 8,570 18,316 11.3 32.0
3....................................................... 10,620 542 7,898 18,517 15.2 32.0
4....................................................... 12,297 373 5,439 17,737 11.8 32.0
5....................................................... 12,297 373 5,439 17,737 11.8 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 8 represents 5.8 percent of low-voltage dry-type distribution transformers units shipped, and 6.4 percent of shipments for equipment class 4
(three phase low-voltage dry-type).
Table V.23--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 8
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 12 355
2........................... 41 152
[[Page 1802]]
3........................... 57 -58
4........................... 31 722
5........................... 31 722
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 8 represents 5.8 percent of low-voltage dry-type distribution
transformers units shipped, and 6.4 percent of shipments for equipment
class 4 (three phase low-voltage dry-type).
Medium-Voltage Dry-Type Distribution Transformers
Table V.24--Average LCC and PBP Results for Representative Unit 9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 14,830 918 13,450 28,281 .............. 32.1
1....................................................... 14,874 895 13,115 27,990 2.0 32.1
2....................................................... 14,961 862 12,628 27,589 2.4 32.1
3....................................................... 15,984 800 11,725 27,709 9.8 32.1
4....................................................... 17,981 726 10,639 28,620 16.4 32.1
5....................................................... 19,047 602 8,823 27,870 13.4 32.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 9 represents 7.3 percent of medium-voltage dry-type distribution transformers units shipped, and 77.0 percent of shipments for equipment class
6 (three phase medium-voltage dry-type, 20-45 kV BIL).
Table V.25--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 9
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 4 1,039
2........................... 10 887
3........................... 39 571
4........................... 64 -339
5........................... 49 410
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 9 represents 7.3 percent of medium-voltage dry-type
distribution transformers units shipped, and 77.0 percent of shipments
for equipment class 6 (three phase medium-voltage dry-type, 20-45 kV
BIL).
Table V.26--Average LCC and PBP Results for Representative Unit 10
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 45,167 2,799 41,003 86,169 .............. 32.0
1....................................................... 45,363 2,674 39,185 84,548 1.6 32.0
2....................................................... 47,461 2,597 38,056 85,516 11.4 32.0
3....................................................... 55,429 2,276 33,366 88,794 19.7 32.0
4....................................................... 59,426 2,039 29,887 89,313 18.8 32.0
5....................................................... 67,353 1,838 26,950 94,303 23.1 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 10 represents 2.2 percent of medium-voltage dry-type distribution transformers units shipped, and 23.0 percent of shipments for equipment class
6 (three phase medium-voltage dry-type, 20-45 kV BIL).
[[Page 1803]]
Table V.27--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 10
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 15 1,854
2........................... 38 653
3........................... 78 -2,625
4........................... 81 -3,144
5........................... 91 -8,133
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 10 represents 2.2 percent of medium-voltage dry-type
distribution transformers units shipped, and 23.0 percent of shipments
for equipment class 6 (three phase medium-voltage dry-type, 20-45 kV
BIL).
Table V.28--Average LCC and PBP Results for Representative Unit 11
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 20,788 1,190 17,353 38,141 .............. 32.0
1....................................................... 20,948 1,156 16,859 37,807 4.7 32.0
2....................................................... 21,792 1,106 16,123 37,915 11.9 32.0
3....................................................... 23,458 951 13,870 37,328 11.2 32.0
4....................................................... 23,880 859 12,516 36,396 9.3 32.0
5....................................................... 25,903 769 11,216 37,119 12.2 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 11 represents 2.6 percent of medium-voltage dry-type distribution transformers units shipped, and 6.6 percent of shipments for equipment class
8 (three phase medium-voltage dry-type, 45-95 kV BIL).
Table V.29--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 11
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 26 438
2........................... 46 226
3........................... 35 813
4........................... 15 1,744
5........................... 38 1,021
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 11 represents 2.6 percent of medium-voltage dry-type
distribution transformers units shipped, and 6.6 percent of shipments
for equipment class 8 (three phase medium-voltage dry-type, 45-95 kV
BIL).
Table V.30--Average LCC and PBP Results for Representative Unit 12
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 54,830 3,290 47,795 102,625 .............. 32.0
1....................................................... 52,818 3,138 45,595 98,413 0.0 32.0
2....................................................... 55,069 3,063 44,505 99,574 1.1 32.0
3....................................................... 63,490 2,659 38,639 102,129 13.7 32.0
4....................................................... 67,333 2,430 35,311 102,644 14.5 32.0
5....................................................... 74,722 2,206 32,055 106,777 18.4 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 12 represents 36.0 percent of medium-voltage dry-type distribution transformers units shipped, and 92.6 percent of shipments for equipment
class 8 (three phase medium-voltage dry-type, 45-95 kV BIL).
Table V.31--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 12
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021)$ *
------------------------------------------------------------------------
1........................... 1 4,649
2........................... 9 3,051
3........................... 49 496
[[Page 1804]]
4........................... 54 -19
5........................... 80 -4,152
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 12 represents 36.0 percent of medium-voltage dry-type
distribution transformers units shipped, and 92.6 percent of shipments
for equipment class 8 (three phase medium-voltage dry-type, 45-95 kV
BIL).
Table V.32--Average LCC and PBP Results for Representative Unit 18
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 85,302 9,986 145,749 231,051 .............. 32.2
1....................................................... 103,468 6,764 98,728 202,196 5.6 32.2
2....................................................... 113,456 6,493 94,798 208,254 8.1 32.2
3....................................................... 134,347 5,429 79,221 213,567 10.8 32.2
4....................................................... 137,299 5,289 77,183 214,481 11.1 32.2
5....................................................... 153,330 4,864 71,007 224,338 13.3 32.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 18 represents 0.3 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class
8 (three phase medium-voltage dry-type, 45-95 kV BIL).
Table V.33--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 18
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021$) *
------------------------------------------------------------------------
1........................... 5 28,855
2........................... 12 22,797
3........................... 24 17,483
4........................... 26 16,570
5........................... 44 6,713
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 18 represents 0.3 percent of medium-voltage dry-type
distribution transformers units shipped, and 0.8 percent of shipments
for equipment class 8 (three phase medium-voltage dry-type, 45-95 kV
BIL).
Table V.34--Average LCC and PBP Results for Representative Unit 13
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 24,894 1,316 19,168 44,062 .............. 31.9
1....................................................... 25,304 1,256 18,292 43,597 6.8 31.9
2....................................................... 26,181 1,212 17,653 43,835 12.4 31.9
3....................................................... 28,454 1,111 16,176 44,630 17.3 31.9
4....................................................... 31,436 986 14,364 45,801 19.8 31.9
5....................................................... 31,983 936 13,636 45,619 18.7 31.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 13 represents 1.8 percent of medium-voltage dry-type distribution transformers units shipped, and 7.6 percent of shipments for equipment class
10 (three phase medium-voltage dry-type, >=96 kV BIL).
Table V.35--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 13
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021$) *
------------------------------------------------------------------------
1........................... 24 515
2........................... 44 228
3........................... 72 -568
4........................... 81 -1,739
[[Page 1805]]
5........................... 80 -1,557
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 13 represents 1.8 percent of medium-voltage dry-type
distribution transformers units shipped, and 7.6 percent of shipments
for equipment class 10 (three phase medium-voltage dry-type, >=96 kV
BIL).
Table V.36--Average LCC and PBP Results for Representative Unit 14
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 63,684 4,386 63,615 127,299 .............. 32.0
1....................................................... 66,945 4,263 61,834 128,779 26.6 32.0
2....................................................... 70,089 4,140 60,066 130,155 26.1 32.0
3....................................................... 80,939 3,629 52,588 133,527 22.8 32.0
4....................................................... 85,714 3,281 47,555 133,268 19.9 32.0
5....................................................... 93,684 3,027 43,893 137,577 22.1 32.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 14 represents 22.1 percent of medium-voltage dry-type distribution transformers units shipped, and 91.5 percent of shipments for equipment
class 10 (three phase medium-voltage dry-type, >=96 kV BIL).
Table V.37--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 14
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with net impacted consumers
cost (2021$) *
------------------------------------------------------------------------
1........................... 88 -1,480
2........................... 87 -2,856
3........................... 78 -6,228
4........................... 82 -5,969
5........................... 93 -10,278
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 14 represents 22.1 percent of medium-voltage dry-type
distribution transformers units shipped, and 91.5 percent of shipments
for equipment class 10 (three phase medium-voltage dry-type, >=96 kV
BIL).
Table V.38--Average LCC and PBP Results for Representative Unit 19
--------------------------------------------------------------------------------------------------------------------------------------------------------
Average costs (2021$)
---------------------------------------------------------------- Simple payback Average
Standard level First year's Lifetime period (years) lifetime
Installed cost operating cost operating cost LCC (years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0....................................................... 88,951 9,349 136,177 225,128 .............. 31.9
1....................................................... 107,573 7,209 105,019 212,591 8.7 31.9
2....................................................... 117,299 6,845 99,747 217,046 11.3 31.9
3....................................................... 137,304 5,717 83,212 220,516 13.3 31.9
4....................................................... 142,539 5,455 79,409 221,948 13.8 31.9
5....................................................... 154,646 5,105 74,341 228,988 15.5 31.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rep unit 19 represents 0.2 percent of medium-voltage dry-type distribution transformers units shipped, and 0.8 percent of shipments for equipment class
10 (three phase medium-voltage dry-type, >=96 kV BIL).
Table V.39--LCC Savings Relative to the Base Case Efficiency
Distribution for Representative Unit 19
------------------------------------------------------------------------
Average savings--
Standard level % Consumers with impacted consumers
net cost (2021)$ *
------------------------------------------------------------------------
1........................... 16 12,536
2........................... 38 8,082
3........................... 43 4,611
4........................... 47 3,180
[[Page 1806]]
5........................... 63 -3,860
------------------------------------------------------------------------
* The savings represent the average LCC for affected consumers.
Rep unit 19 represents 0.2 percent of medium-voltage dry-type
distribution transformers units shipped, and 0.8 percent of shipments
for equipment class 10 (three phase medium-voltage dry-type, >=96 kV
BIL).
b. Consumer Subgroup Analysis
In the consumer subgroup analysis, DOE estimated the impact of the
considered TSLs on utilities who deploy distribution transformers in
vaults or other space constrained areas, and utilities who serve low
population densities. Table V.40 compares the average LCC savings and
PBP at each efficiency level for the consumer subgroups with similar
metrics for the entire consumer sample for equipment classes 1 and 2.
Chapter 11 of the NOPR TSD presents the complete LCC and PBP results
for the subgroups.
Utilities Serving Low Population Densities
Table V.40--Comparison of LCC Savings and PBP for Utilities Serving Low Population Densities Subgroup and All
Utilities; Representative Unit 1
----------------------------------------------------------------------------------------------------------------
Serving low population
TSL All utilities densities
----------------------------------------------------------------------------------------------------------------
Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
1............................................................. -53 -55
2............................................................. -114 -112
3............................................................. 0 90
4............................................................. 72 178
5............................................................. -599 -497
----------------------------------------------------------------------------------------------------------------
Payback Period (years)
----------------------------------------------------------------------------------------------------------------
1............................................................. 78.6 120.6
2............................................................. 69.2 86.0
3............................................................. 19.3 19.0
4............................................................. 16.2 15.8
5............................................................. 40.5 42.2
----------------------------------------------------------------------------------------------------------------
Consumers with Net Cost (%)
----------------------------------------------------------------------------------------------------------------
1............................................................. 69 66
2............................................................. 86 82
3............................................................. 47 33
4............................................................. 34 20
5............................................................. 96 92
----------------------------------------------------------------------------------------------------------------
Rep unit 1 represents 20.3 percent of liquid-immersed distribution transformers units shipped, and 21.8 percent
of shipments for equipment class 1 (single phase liquid-immersed).
Table V.41--Comparison of LCC Savings and PBP for Utilities Serving Low Population Densities Subgroup and All
Utilities; Representative Unit 2
----------------------------------------------------------------------------------------------------------------
Serving low population
TSL All utilities densities
----------------------------------------------------------------------------------------------------------------
Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
1............................................................. 146 189
2............................................................. 201 267
3............................................................. 186 253
4............................................................. 131 199
5............................................................. -176 -107
----------------------------------------------------------------------------------------------------------------
Payback Period (years)
----------------------------------------------------------------------------------------------------------------
1............................................................. 0.0 0.0
2............................................................. 0.4 0.3
3............................................................. 4.1 3.9
4............................................................. 10.1 9.9
5............................................................. 29.3 30.2
----------------------------------------------------------------------------------------------------------------
[[Page 1807]]
Consumers with Net Cost (%)
----------------------------------------------------------------------------------------------------------------
1............................................................. 22 21
2............................................................. 10 7
3............................................................. 9 7
4............................................................. 13 10
5............................................................. 84 72
----------------------------------------------------------------------------------------------------------------
Rep unit 2 represents 72.7 percent of liquid-immersed distribution transformers units shipped, and 78.0 percent
of shipments for equipment class 1 (single phase liquid-immersed).
Table V.42--Comparison of LCC Savings and PBP for Utilities Serving Low Population Densities Subgroup and All
Utilities; Representative Unit 3
----------------------------------------------------------------------------------------------------------------
Serving low population
TSL All utilities densities
----------------------------------------------------------------------------------------------------------------
Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
1............................................................. 1,121 1,798
2............................................................. 1,312 2,044
3............................................................. 1,216 1,962
4............................................................. 1,029 1,772
5............................................................. -414 308
----------------------------------------------------------------------------------------------------------------
Payback Period (years)
----------------------------------------------------------------------------------------------------------------
1............................................................. 5.9 5.3
2............................................................. 5.6 5.1
3............................................................. 8.4 7.8
4............................................................. 12.3 11.9
5............................................................. 21.8 22.3
----------------------------------------------------------------------------------------------------------------
Consumers with Net Cost (%)
----------------------------------------------------------------------------------------------------------------
1............................................................. 28 22
2............................................................. 22 16
3............................................................. 23 16
4............................................................. 23 15
5............................................................. 65 44
----------------------------------------------------------------------------------------------------------------
Rep unit 3 represents 0.2 percent of liquid-immersed distribution transformers units shipped, and 0.2 percent of
shipments for equipment class 1 (single phase liquid-immersed).
Table V.43--Comparison of LCC Savings and PBP Utilities Serving Low Population Densities Subgroup and All
Utilities; Representative Unit 4
----------------------------------------------------------------------------------------------------------------
Serving low population
TSL All utilities densities
----------------------------------------------------------------------------------------------------------------
Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
1............................................................. -26 -12
2............................................................. -55 -9
3............................................................. 381 629
4............................................................. 511 802
5............................................................. 77 372
----------------------------------------------------------------------------------------------------------------
Payback Period (years)
----------------------------------------------------------------------------------------------------------------
1............................................................. 26.9 28.0
2............................................................. 24.4 24.4
3............................................................. 13.2 13.1
4............................................................. 12.0 11.9
5............................................................. 18.7 19.1
----------------------------------------------------------------------------------------------------------------
Consumers with Net Cost (%)
----------------------------------------------------------------------------------------------------------------
1............................................................. 38 37
2............................................................. 67 58
3............................................................. 25 21
[[Page 1808]]
4............................................................. 13 9
5............................................................. 49 32
----------------------------------------------------------------------------------------------------------------
Rep unit 4 represents 4.6 percent of liquid-immersed distribution transformers units shipped, and 68.0 percent
of shipments for equipment class 2 (three phase liquid-immersed).
Table V.44--Comparison of LCC Savings and PBP for Utilities Serving Low Population Densities Subgroup and All
Utilities; Representative Unit 5
----------------------------------------------------------------------------------------------------------------
Serving low population
TSL All utilities densities
----------------------------------------------------------------------------------------------------------------
Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
1............................................................. 986 1,498
2............................................................. 2,095 2,876
3............................................................. 1,888 2,839
4............................................................. 1,543 2,830
5............................................................. -7,913 -5,881
----------------------------------------------------------------------------------------------------------------
Payback Period (years)
----------------------------------------------------------------------------------------------------------------
1............................................................. 11.0 10.1
2............................................................. 8.0 7.1
3............................................................. 11.0 9.9
4............................................................. 14.2 13.8
5............................................................. 35.8 37.3
----------------------------------------------------------------------------------------------------------------
Consumers with Net Cost (%)
----------------------------------------------------------------------------------------------------------------
1............................................................. 41 38
2............................................................. 27 23
3............................................................. 29 24
4............................................................. 29 19
5............................................................. 96 89
----------------------------------------------------------------------------------------------------------------
Rep unit 5 represents 2.1 percent of liquid-immersed distribution transformers units shipped, and 31.5 percent
of shipments for equipment class 2 (three phase liquid-immersed).
Utilities That Deploy Distribution Transformers in Vaults or Other
Space Constrained Areas
As noted in section IV.C.1, for this NOPR DOE considered
submersible distribution transformers and their associated vault, or
space constrained installation costs with individual representative
units, 15 and 16. The consumer results for these equipment are
presented in Table V.12 through Table V.15.
c. Rebuttable Presumption Payback
As discussed in section IV.F.11, EPCA establishes a rebuttable
presumption that an energy conservation standard is economically
justified if the increased purchase cost for a product that meets the
standard is less than three times the value of the first-year energy
savings resulting from the standard. In calculating a rebuttable
presumption payback period for each of the considered standard level,
DOE used discrete values, and as required by EPCA, based the energy use
calculation on the DOE test procedure for distribution transformers. In
contrast, the PBPs presented in section V.B.1.a were calculated using
distributions that reflect the range of energy use in the field.
Table V.45 presents the rebuttable-presumption payback periods for
the considered standard level for distribution transformers. While DOE
examined the rebuttable-presumption criterion, it considered whether
the standard levels considered for the NOPR are economically justified
through a more detailed analysis of the economic impacts of those
levels, pursuant to 42 U.S.C. 6295(o)(2)(B)(i), that considers the full
range of impacts to the consumer, manufacturer, Nation, and
environment. The results of that analysis serve as the basis for DOE to
definitively evaluate the economic justification for a potential
standard level, thereby supporting or rebutting the results of any
preliminary determination of economic justification.
Table V.45--Rebuttable-Presumption Payback Periods
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
EC RU -------------------------------------------------------------------------------
1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
1....................................................... 1 15.9 19.9 25.3 22.1 25.7
1....................................................... 2 0.1 6.4 9.3 12.1 19.7
1....................................................... 3 0 0 74.6 19.1 17.9
[[Page 1809]]
2....................................................... 4 11.2 22.9 14.2 13.2 14.1
2....................................................... 5 0 0 0 21.1 26.1
2....................................................... 17 8.4 9.7 10.3 10.0 14.6
3....................................................... 6 0 2.3 4.3 8.7 8.7
4....................................................... 7 0 0 3.8 8.1 6.9
6....................................................... 8 5.6 8.1 9.7 10.6 10.6
6....................................................... 9 1.3 1.4 4.6 7.9 9.7
8....................................................... 10 1.4 6.6 18.4 15.4 16.0
8....................................................... 11 1.4 4.9 8.9 8.7 8.7
8....................................................... 18 4.6 5.8 9.7 9.6 10.2
10...................................................... 12 0 0.6 63.2 18.2 15.4
10...................................................... 13 5.5 10.2 12.5 43.4 25.3
10...................................................... 14 21.4 11.4 -67.7 39.4 24.4
10...................................................... 19 5.6 6.5 12.7 12.0 12.0
12...................................................... 15 n.a. n.a. n.a. n.a. 14.1
12...................................................... 16 n.a. n.a. n.a. n.a. 26.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
2. Economic Impacts on Manufacturers
DOE performed an MIA to estimate the impact of amended energy
conservation standards on manufacturers of distribution transformers.
The following section describes the expected impacts on manufacturers
at each considered TSL. Chapter 12 of the NOPR TSD explains the
analysis in further detail.
a. Industry Cash Flow Analysis Results
In this section, DOE provides GRIM results from the analysis, which
examines changes in the industry that would result from a standard. The
following tables summarize the estimated financial impacts (represented
by changes in INPV) of potential amended energy conservation standards
on manufacturers of distribution transformers, as well as the
conversion costs that DOE estimates manufacturers of distribution
transformers would incur at each TSL. DOE analyzes the potential
impacts on INPV separately for each type of distribution transformer
manufacturers: liquid-immersed; LVDT; and MVDT.
As discussed in section IV.J.2.d of this document, DOE modeled two
scenarios to evaluate a range of cash flow impacts on the distribution
transformer industry: (1) the preservation of gross margin percentage
scenario and (2) the preservation of operating profit scenario. In the
preservation of gross margin percentage scenario, distribution
transformer manufacturers are able to maintain the same gross margin
percentage, even as the MPCs of distribution transformers increase due
to energy conservation standards. In this scenario, the same gross
margin percentage of 20 percent \102\ is applied across all efficiency
levels. In the preservation of operating profit scenario, manufacturers
do not earn additional operating profit when compared to the no-
standards case scenario. While manufacturers make the necessary upfront
investments required to produce compliant equipment, per-unit operating
profit does not change in absolute dollars. The preservation of
operating profit scenario results in the lower (or more severe) bound
to impacts of potential amended standards on industry.
---------------------------------------------------------------------------
\102\ The gross margin percentage of 20 percent is based on a
manufacturer markup of 1.25.
---------------------------------------------------------------------------
Each of the modeled scenarios results in a unique set of cash-flows
and corresponding industry values at each TSL for each type of
distribution transformer manufacturers. In the following discussion,
the INPV results refer to the difference in industry value between the
no-new-standards case and each standards case resulting from the sum of
discounted cash-flows from 2022 through 2056. To provide perspective on
the short-run cash-flow impact, DOE includes in the discussion of
results a comparison of free cash flow between the no-new-standards
case and the standards case at each TSL in the year before amended
standards are required.
DOE presents the range in INPV for liquid-immersed distribution
transformer manufacturers in Table V.46 and Table V.47; the range in
INPV for LVDT distribution transformer manufacturers in Table V.48 and
Table V.49; and the range in INPV for MVDT distribution transformer
manufacturers in Table V.50 and Table V.51.
Liquid-Immersed Distribution Transformers
Table V.46--Manufacturer Impact Analysis for Liquid-Immersed Distribution Transformers--Preservation of Gross
Margin Percentage Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 1,384 1,297 1,268 1,232 1,233 1,347
Change in INPV............... 2021$ millions. ......... (87.1) (116.5) (152.1) (151.0) (37.2)
%.............. ......... (6.3) (8.4) (11.0) (10.9) (2.7)
Product Conversion Costs..... 2021$ millions. ......... 72.0 82.5 99.1 102.0 102.9
Capital Conversion Costs..... 2021$ millions. ......... 56.6 92.6 150.3 168.5 186.6
[[Page 1810]]
Total Conversion Costs... 2021$ millions. ......... 128.6 175.2 249.4 270.6 289.4
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``( )'' are negative. Some numbers might not round due to rounding.
Table V.47--Manufacturer Impact Analysis for Liquid-Immersed Distribution Transformers--Preservation of
Operating Profit Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 1,384 1,283 1,242 1,166 1,133 1,004
Change in INPV............... 2021$ millions. ......... (101.1) (142.1) (218.3) (251.3) (380.7)
%.............. ......... (7.3) (10.3) (15.8) (18.1) (27.5)
Product Conversion Costs..... 2021$ millions. ......... 72.0 82.5 99.1 102.0 102.9
Capital Conversion Costs..... 2021$ millions. ......... 56.6 92.6 150.3 168.5 186.6
-----------------------------------------------------------------
Total Conversion Costs... 2021$ millions. ......... 128.6 175.2 249.4 270.6 289.4
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``( )'' are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$101.1 million to
-$87.1 million, corresponding to a change in INPV of -7.3 percent to -
6.3 percent. At TSL 1, industry free cash flow is estimated to decrease
by approximately 56.0 percent to $40.2 million, compared to the no-new-
standard case value of $91.2 million in 2026, the year before the
estimated compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
liquid-immersed distribution transformers except for submersible
liquid-immersed transformers (Equipment Class 12, Rep. Unit 15 and 16),
which would remain at baseline. DOE estimates that approximately 4.3
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates liquid-
immersed distribution transformer manufacturers would spend
approximately $72.0 million in product conversion costs to redesign
transformers and approximately $56.6 million in capital conversion
costs as some liquid-immersed distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 1, the shipment-weighted average MPC for liquid-immersed
distribution transformers increases by 0.6 percent relative to the no-
new-standards case shipment-weighted average MPC in 2027. In the gross
margin percentage scenario, manufacturers can fully pass on this slight
cost increase to customers. The slight increase in shipment-weighted
average MPC is outweighed by the $128.6 million in conversion costs,
causing a negative change in INPV at TSL 1 under the preservation of
gross margin percentage scenario.
Under the preservation of operating profit scenario, manufacturers
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit
from their investments or higher MPCs. In this scenario, the 0.6
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $128.6 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 1 under the
preservation of operating profit scenario.
At TSL 2, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$142.1 million to
-$116.5 million, corresponding to a change in INPV of -10.3 percent to
-8.4 percent. At TSL 2, industry free cash flow is estimated to
decrease by approximately 77.8 percent to $20.2 million, compared to
the no-new-standard case value of $91.2 million in 2026, the year
before the estimated compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
liquid-immersed distribution transformers except for submersible
liquid-immersed transformers (Equipment Class 12, Rep. Unit 15 and 16),
which would remain at baseline. DOE estimates that approximately 1.4
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates liquid-
immersed distribution transformer manufacturers would spend
approximately $82.5 million in product conversion costs to redesign
transformers and approximately $92.6 million in capital conversion
costs as many liquid-immersed distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 2, the shipment-weighted average MPC for liquid-immersed
distribution transformers increases by 1.7 percent relative to the no-
new-standards case shipment-weighted average MPC in 2027. The increase
in shipment-weighted average MPC is outweighed by the $175.2 million in
conversion costs, causing a negative change in INPV at TSL 2 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 1.7
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $175.2 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 2 under the
preservation of operating profit scenario.
At TSL 3, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$218.3 million to
-$152.1 million, corresponding to a change in INPV of -15.8 percent to
[[Page 1811]]
-11.0 percent. At TSL 3, industry free cash flow is estimated to
decrease by approximately 112.8 percent to -$11.6 million, compared to
the no-new-standard case value of $91.2 million in 2026, the year
before the estimated compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all
liquid-immersed distribution transformers except for submersible
liquid-immersed transformers (Equipment Class 12, Rep. Unit 15 and 16),
which would remain at baseline. DOE estimates that approximately 0.9
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates liquid-
immersed distribution transformer manufacturers would spend
approximately $99.1 million in product conversion costs to redesign
transformers and approximately $150.3 million in capital conversion
costs as most liquid-immersed distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 3, the shipment-weighted average MPC for liquid-immersed
distribution transformers increases by 5.6 percent relative to the no-
new-standards case shipment-weighted average MPC in 2027. The moderate
increase in shipment-weighted average MPC is outweighed by the $249.4
million in conversion costs, causing a negative change in INPV at TSL 3
under the preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 5.6
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $249.4 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 3 under the
preservation of operating profit scenario.
At TSL 4, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$251.3 million to
-$151.0 million, corresponding to a change in INPV of -18.1 percent to
-10.9 percent. At TSL 4, industry free cash flow is estimated to
decrease by approximately 122.9 percent to -$20.9 million, compared to
the no-new-standard case value of $91.2 million in 2026, the year
before the estimated compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
liquid-immersed distribution transformers except for submersible
liquid-immersed transformers (Equipment Class 12, Rep. Unit 15 and 16),
which would remain at baseline. DOE estimates that approximately 0.7
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates liquid-
immersed distribution transformer manufacturers would spend
approximately $102.0 million in product conversion costs to redesign
transformers and approximately $168.5 million in capital conversion
costs as almost all liquid-immersed distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 4, the shipment-weighted average MPC for liquid-immersed
distribution transformers increases by 8.9 percent relative to the no-
new-standards case shipment-weighted average MPC in 2027. The moderate
increase in shipment-weighted average MPC is outweighed by the $270.6
million in conversion costs, causing a negative change in INPV at TSL 4
under the preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 8.9
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $270.6 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 4 under the
preservation of operating profit scenario.
At TSL 5, DOE estimates the impacts on INPV for liquid-immersed
distribution transformer manufacturers to range from -$380.7 million to
-$37.2 million, corresponding to a change in INPV of -27.5 percent to -
2.7 percent. At TSL 5, industry free cash flow is estimated to decrease
by approximately 132.1 percent to -$29.3 million, compared to the no-
new-standard case value of $91.2 million in 2026, the year before the
estimated compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all liquid-immersed distribution transformers. DOE estimates that
approximately 0.2 percent of shipments would meet these energy
conservation standards in the no-new-standards case in 2027. DOE
estimates liquid-immersed distribution transformer manufacturers would
spend approximately $102.9 million in product conversion costs to
redesign transformers and approximately $186.6 million in capital
conversion costs as almost all liquid-immersed distribution transformer
cores manufactured are expected to use amorphous steel.
At TSL 5, the shipment-weighted average MPC for liquid-immersed
distribution transformers increases by 33.3 percent relative to the no-
new-standards case shipment-weighted average MPC in 2027. The
significant increase in shipment-weighted average MPC is outweighed by
the $289.4 million in conversion costs, causing a negative change in
INPV at TSL 5 under the preservation of gross margin percentage
scenario.
Under the preservation of operating profit scenario, the 33.3
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $289.4 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 5 under the
preservation of operating profit scenario.
Low-Voltage Dry-Type Distribution Transformers
Table V.48--Manufacturer Impact Analysis for Low-Voltage Dry-Type Distribution Transformers--Preservation of
Gross Margin Percentage Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 194 189 189 177 168 161
Change in INPV............... 2021$ millions. ......... (5.4) (4.9) (16.9) (26.3) (33.5)
%.............. ......... (2.8) (2.5) (8.7) (13.6) (17.2)
Product Conversion Costs..... 2021$ millions. ......... 9.6 9.6 14.5 18.9 19.1
Capital Conversion Costs..... 2021$ millions. ......... 0.0 0.0 19.1 37.2 50.3
-----------------------------------------------------------------
[[Page 1812]]
Total Conversion Costs... 2021$ millions. ......... 9.6 9.6 33.5 56.1 69.4
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``( )'' are negative. Some numbers might not round due to rounding.
Table V.49--Manufacturer Impact Analysis for Low-Voltage Dry-Type Distribution Transformers--Preservation of
Operating Profit Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 194 189 188 167 145 133
Change in INPV............... 2021$ millions. ......... (5.4) (5.9) (27.0) (49.1) (61.0)
%.............. ......... (2.8) (3.0) (13.9) (25.3) (31.4)
Product Conversion Costs..... 2021$ millions. ......... 9.6 9.6 14.5 18.9 19.1
Capital Conversion Costs..... 2021$ millions. ......... 0.0 0.0 19.1 37.2 50.3
-----------------------------------------------------------------
Total Conversion Costs... 2021$ millions. ......... 9.6 9.6 33.5 56.1 69.4
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``( )'' are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to be approximately -$5.4 million, which
corresponds to a change in INPV of -2.8 percent. At TSL 1, industry
free cash flow is estimated to decrease by approximately 17.8 percent
to $15.6 million, compared to the no-new-standard case value of $19.0
million in 2026, the year before the estimated compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
LVDT distribution transformers. DOE estimates that approximately 22.7
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates LVDT
distribution transformer manufacturers would spend approximately $9.6
million in product conversion costs to redesign transformers but would
not have to make significant investments in capital conversion costs as
no LVDT distribution transformer cores used are expected to use
amorphous steel.
At TSL 1, the shipment-weighted average MPC for LVDT distribution
transformers does not increases relative to the no-new-standards case
shipment-weighted average MPC in 2027. The preservation of gross margin
percentage scenario produces similar INPV results as the preservation
of operating profit scenario due to the negligible change in MPC at TSL
1. The change in IPNV is driven exclusively by the $9.6 million in
conversion costs, causing a negative change in INPV at TSL 1 under both
scenarios.
At TSL 2, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$5.9 million to -$4.9 million,
corresponding to a change in INPV of -2.8 percent to -2.5 percent. At
TSL 2, industry free cash flow is estimated to decrease by
approximately 17.8 percent to $15.6 million, compared to the no-new-
standard case value of $19.0 million in 2026, the year before the
estimated compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
LVDT distribution transformers. DOE estimates that approximately 3.4
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates LVDT
distribution transformer manufacturers would spend approximately $9.6
million in product conversion costs to redesign transformers but would
not have to make significant investments in capital conversion costs as
no LVDT distribution transformer cores used are expected to use
amorphous steel.
At TSL 2, the shipment-weighted average MPC for LVDT distribution
transformers increases by 0.8 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The increase in shipment-
weighted average MPC is outweighed by the $9.6 million in conversion
costs, causing a negative change in INPV at TSL 2 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 0.8
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $9.6 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 2 under the
preservation of operating profit scenario.
At TSL 3, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$27.0 million to -$16.9
million, corresponding to a change in INPV of -13.9 percent to -8.7
percent. At TSL 3, industry free cash flow is estimated to decrease by
approximately 72.1 percent to $5.3 million, compared to the no-new-
standard case value of $19.0 million in 2026, the year before the
estimated compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all
LVDT distribution transformers. DOE estimates that approximately 0.1
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates LVDT
distribution transformer manufacturers would spend approximately $14.5
million in product conversion costs to redesign transformers and
approximately $19.1 million in capital conversion costs as some LVDT
distribution transformers cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment-weighted average MPC for LVDT distribution
transformers increases by 8.5 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The moderate increase in
shipment-weighted average MPC is outweighed by the $33.5 million in
[[Page 1813]]
conversion costs, causing a negative change in INPV at TSL 3 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 8.5
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $33.5 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 3 under the
preservation of operating profit scenario.
At TSL 4, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$49.1 million to -$26.3
million, corresponding to a change in INPV of -25.3 percent to -13.6
percent. At TSL 4, industry free cash flow is estimated to decrease by
approximately 123.2 percent to -$4.4 million, compared to the no-new-
standard case value of $19.0 million in 2026, the year before the
estimated compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
LVDT distribution transformers. DOE estimates that no shipments would
meet these energy conservation standards in the no-new-standards case
in 2027. DOE estimates LVDT distribution transformer manufacturers
would spend approximately $18.9 million in product conversion costs to
redesign all LVDT transformers and approximately $37.2 million in
capital conversion costs as almost all LVDT distribution transformer
cores manufactured are expected to use amorphous steel.
At TSL 4, the shipment-weighted average MPC for LVDT distribution
transformers increases by 19.0 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The significant increase in
shipment-weighted average MPC is outweighed by the $56.1 million in
conversion costs, causing a negative change in INPV at TSL 4 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 19.0
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $56.1 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 4 under the
preservation of operating profit scenario.
At TSL 5, DOE estimates the impacts on INPV for LVDT distribution
transformer manufacturers to range from -$61.0 million to -$33.5
million, corresponding to a change in INPV of -31.4 percent to -17.2
percent. At TSL 5, industry free cash flow is estimated to decrease by
approximately 154.4 percent to -$10.4 million, compared to the no-new-
standard case value of $19.0 million in 2026, the year before the
estimated compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all LVDT distribution transformers. DOE estimates that no shipments
would meet these energy conservation standards at TSL 5. DOE estimates
LVDT distribution transformer manufacturers would spend approximately
$19.1 million in product conversion costs to redesign all LVDT
distribution transformers and approximately $37.2 million in capital
conversion costs as all LVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 5, the shipment-weighted average MPC for LVDT distribution
transformers increases by 23.0 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The significant increase in
shipment-weighted average MPC is outweighed by the $69.4 million in
conversion costs, causing a negative change in INPV at TSL 5 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 23.0
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $69.4 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 5 under the
preservation of operating profit scenario.
Medium-Voltage Dry-Type Distribution Transformers
Table V.50--Manufacturer Impact Analysis for Medium-Voltage Dry-Type Distribution Transformers--Preservation of
Gross Margin Percentage Markup Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 87 85 86 80 80 82
Change in INPV............... 2021$ millions. ......... (1.8) (0.8) (7.7) (6.8) (5.2)
%.............. ......... (2.1) (0.9) (8.8) (7.8) (5.9)
Product Conversion Costs..... 2021$ millions. ......... 3.1 3.1 6.0 6.1 6.2
Capital Conversion Costs..... 2021$ millions. ......... 0.0 0.0 11.9 13.1 15.1
----------------------------------------------------------------------------------
Total Conversion Costs... 2021$ millions. ......... 3.1 3.1 17.9 19.2 21.2
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``()'' are negative. Some numbers might not round due to rounding.
Table V.51--Manufacturer Impact Analysis for Low-Voltage Dry-Type Distribution Transformers--Preservation of
Operating Profit Scenario
----------------------------------------------------------------------------------------------------------------
No-new- Trial standard level
Units standards ------------------------------------------------------
case 1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
INPV......................... 2021$ millions. 87 85 85 71 69 65
Change in INPV............... 2021$ millions. ......... (1.9) (2.7) (16.3) (18.7) (22.6)
%.............. ......... (2.1) (3.0) (18.7) (21.4) (25.9)
Product Conversion Costs..... 2021$ millions. ......... 3.1 3.1 6.0 6.1 6.2
[[Page 1814]]
Capital Conversion Costs..... 2021$ millions. ......... 0.0 0.0 11.9 13.1 15.1
----------------------------------------------------------------------------------
Total Conversion Costs... 2021$ millions. ......... 3.1 3.1 17.9 19.2 21.2
----------------------------------------------------------------------------------------------------------------
* Numbers in parentheses ``( )'' are negative. Some numbers might not round due to rounding.
At TSL 1, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$1.9 million to -$1.8 million,
which corresponds to a change in INPV of approximately -2.1 percent in
both cases. At TSL 1, industry free cash flow is estimated to decrease
by approximately 15.7 percent to $5.9 million, compared to the no-new-
standard case value of $7.0 million in 2026, the year before the
estimated compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all
MVDT distribution transformers. DOE estimates that approximately 21.2
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates MVDT
distribution transformer manufacturers would spend approximately $3.1
million in product conversion costs to redesign transformers but would
not have to make significant investments in capital conversion costs as
no MVDT distribution transformer cores are expected to use amorphous
steel.
At TSL 1, the shipment-weighted average MPC for MVDT distribution
transformers does not increases relative to the no-new-standards case
shipment-weighted average MPC in 2027. The preservation of gross margin
percentage scenario produces similar INPV results as the preservation
of operating profit scenario due to the negligible change in MPC at TSL
1. The change in INPV is almost exclusively driven by the $3.1 million
in conversion costs, causing a negative change in INPV at TSL 1 under
both scenarios.
At TSL 2, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$2.7 million to -$0.8 million,
corresponding to a change in INPV of -3.0 percent to -0.9 percent. At
TSL 2, industry free cash flow is estimated to decrease by
approximately 15.7 percent to $5.9 million, compared to the no-new-
standard case value of $7.0 million in 2026, the year before the
estimated compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all
MVDT distribution transformers. DOE estimates that approximately 4.2
percent of shipments would meet or exceed these energy conservation
standards in the no-new-standards case in 2027. DOE estimates MVDT
distribution transformer manufacturers would spend approximately $3.1
million in product conversion costs to redesign transformers but would
not have to make significant investments in capital conversion costs as
no MVDT distribution transformer cores are expected to use amorphous
steel.
At TSL 2, the shipment-weighted average MPC for MVDT distribution
transformers increases by 3.2 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The increase in shipment-
weighted average MPC is outweighed by the $3.1 million in conversion
costs, causing a negative change in INPV at TSL 2 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 3.2
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $3.1 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 2 under the
preservation of operating profit scenario.
At TSL 3, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$16.3 million to -$7.7
million, corresponding to a change in INPV of -18.7 percent to -8.8
percent. At TSL 3, industry free cash flow is estimated to decrease by
approximately 107.1 percent to -$0.5 million, compared to the no-new-
standard case value of $7.0 million in 2026, the year before the
estimated compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all
MVDT distribution transformers. DOE estimates that no shipments would
meet or exceed these energy conservation standards in the no-new-
standards case in 2027. DOE estimates MVDT distribution transformer
manufacturers would spend approximately $6.0 million in product
conversion costs to redesign all MVDT distribution transformers and
approximately $11.9 million in capital conversion costs as many MVDT
distribution transformer cores manufactured are expected to use
amorphous steel.
At TSL 3, the shipment-weighted average MPC for MVDT distribution
transformers increases by 14.5 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The moderate increase in
shipment-weighted average MPC is outweighed by the $17.9 million in
conversion costs, causing a negative change in INPV at TSL 3 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 14.5
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $17.9 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 3 under the
preservation of operating profit scenario.
At TSL 4, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$18.7 million to -$6.8
million, corresponding to a change in INPV of -21.4 percent to -7.8
percent. At TSL 4, industry free cash flow is estimated to decrease by
approximately 115.3 percent to -$1.1 million, compared to the no-new-
standard case value of $7.0 million in 2026, the year before the
estimated compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all
MVDT distribution transformers. DOE estimates that no shipments would
meet these energy conservation standards in
[[Page 1815]]
the no-new-standards case in 2027. DOE estimates MVDT distribution
transformer manufacturers would spend approximately $6.1 million in
product conversion costs to redesign all MVDT distribution transformers
and approximately $13.1 million in capital conversion costs as most
MVDT distribution transformer cores manufactured are expected to use
amorphous steel.
At TSL 4, the shipment-weighted average MPC for MVDT distribution
transformers increases by 20.0 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The significant increase in
shipment-weighted average MPC is outweighed by the $19.2 million in
conversion costs, causing a negative change in INPV at TSL 4 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 20.0
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $19.2 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 4 under the
preservation of operating profit scenario.
At TSL 5, DOE estimates the impacts on INPV for MVDT distribution
transformer manufacturers to range from -$22.6 million to -$5.2
million, corresponding to a change in INPV of -25.9 percent to -5.9
percent. At TSL 5, industry free cash flow is estimated to decrease by
approximately 128.4 percent to -$2.0 million, compared to the no-new-
standard case value of $7.0 million in 2026, the year before the
estimated compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech,
for all MVDT distribution transformers. DOE estimates that no shipments
would meet these energy conservation standards at TSL 5. DOE estimates
MVDT distribution transformer manufacturers would spend approximately
$6.2 million in product conversion costs to redesign all MVDT
distribution transformers and approximately $15.1 million in capital
conversion costs as all MVDT distribution transformer cores
manufactured are expected to use amorphous steel.
At TSL 5, the shipment-weighted average MPC for MVDT distribution
transformers increases by 29.4 percent relative to the no-new-standards
case shipment-weighted average MPC in 2027. The significant increase in
shipment-weighted average MPC is outweighed by the $21.2 million in
conversion costs, causing a negative change in INPV at TSL 5 under the
preservation of gross margin percentage scenario.
Under the preservation of operating profit scenario, the 29.4
percent shipment-weighted average MPC increase results in a reduction
in the margin after the analyzed compliance year. This reduction in the
margin and the $21.2 million in conversion costs incurred by
manufacturers cause a negative change in INPV at TSL 5 under the
preservation of operating profit scenario.
b. Direct Impacts on Employment
To quantitatively assess the potential impacts of amended energy
conservation standards on direct employment in the distribution
transformers industry, DOE used the GRIM to estimate the domestic labor
expenditures and number of direct employees in the no-new-standards
case and in each of the standards cases (TSLs) during the analysis
period.
Production employees are those who are directly involved in
fabricating and assembling equipment within a manufacturer facility.
Workers performing services that are closely associated with production
operations, such as materials handling tasks using forklifts, are
included as production labor, as well as line supervisors.
DOE used the GRIM to calculate the number of production employees
from labor expenditures. DOE used statistical data from the U.S. Census
Bureau's 2019 Annual Survey of Manufacturers (``ASM'') and the results
of the engineering analysis to calculate industry-wide labor
expenditures. Labor expenditures related to equipment manufacturing
depend on the labor intensity of the product, the sales volume, and an
assumption that wages remain fixed in real terms over time. The total
labor expenditures in the GRIM were then converted to domestic
production employment levels by dividing production labor expenditures
by the annual payment per production worker.
Non-production employees account for those workers that are not
directly engaged in the manufacturing of the covered equipment. This
could include sales, human resources, engineering, and management. DOE
estimated non-production employment levels by multiplying the number of
distribution transformer workers by a scaling factor. The scaling
factor is calculated by taking the ratio of the total number of
employees, and the total production workers associated with the
industry NAICS code 335311, which covers power, distribution, and
specialty transformer manufacturing.
Using data from manufacturer interviews and estimated market share
data, DOE estimates that approximately 85 percent of all liquid-
immersed distribution transformer manufacturing; 15 percent of all LVDT
distribution transformer manufacturing; and 75 percent of all MVDT
distribution transformer manufacturing takes place domestically.
Liquid-Immersed Distribution Transformers
Table V.52--Domestic Employment for Liquid-Immersed Distribution Transformers in 2027
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
No-new- -------------------------------------------------------------------------------
standards case 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Domestic Production Workers in 2027..................... 5,164 5,193 5,251 5,453 5,624 6,885
Domestic Non-Production Workers in 2027................. 1,830 1,840 1,861 1,932 1,993 2,440
-----------------------------------------------------------------------------------------------
Total Direct Employment in 2027..................... 6,994 7,033 7,112 7,385 7,617 9,325
Potential Changes in Total Direct Employment in 2027.... .............. (874)-39 (1,180)-118 (1,506)-391 (1,549)-623 (1,549)-2,331
--------------------------------------------------------------------------------------------------------------------------------------------------------
Using the estimated labor content from the GRIM combined with data
from the 2019 ASM, DOE estimates that there would be approximately
5,164 domestic production workers, and 1,830 domestic non-production
workers
[[Page 1816]]
involved in liquid-immersed distribution transformer manufacturing in
2027 in the absence of amended energy conservation standards. Table
V.52 shows the range of the impacts of energy conservation standards on
U.S. production on liquid-immersed distribution transformers.
Amorphous core production is more labor intensive and would require
additional labor expenditures. The upper range of the ``Potential
Change in Total Direct Employment in 2027'' displayed in Table V.52,
assumes that all domestic liquid-immersed distribution transformer
manufacturing remains in the U.S. For this scenario, the additional
labor expenditures associated with amorphous core production result in
the number of total direct employees to increase due to energy
conservation standards. At higher TSLs, the estimated number of
amorphous cores used in liquid-immersed distribution transformers
increases, which causes the number of direct employees to also
increase. The lower range of the ``Potential Change in Total Direct
Employment in 2027'' displayed in Table V.52, assumes that as more
amorphous cores are used to meet higher energy conservation standards,
either the amorphous core production is out-sourced to core only
manufacturers (manufacturers that specialize in manufacturing cores
used in distribution transformers, but do not actually manufacture
entire distribution transformers) which may be located in foreign
countries, or distribution transformer manufacturing is re-located to
foreign countries. This lower range assumes that 30 percent of
distribution transformers using amorphous cores are re-located to
foreign countries due to the energy conservation standard. DOE
acknowledges that each distribution transformer manufacturer would
individually make a business decision to either make the substantial
investments to add or increase their own amorphous core production
capabilities and continue to manufacturer their own cores in-house;
outsource their amorphous core production to another distribution core
manufacturer, which may or may not be located in the U.S.; or re-locate
some or all of their distribution transformer manufacturing to a
foreign country. DOE acknowledges there is a wide range of potential
domestic employment impacts due to energy conservation standards,
especially at the higher TSLs. The ranges in potential employment
impacts displayed in Table V.52 at each TSL attempt to provide a
reasonable upper and lower bound to how liquid-immersed distribution
transformer manufacturers may respond to potential energy conservation
standards.
Low-Voltage Dry-Type Distribution Transformers
Table V.53--Domestic Employment for Low-Voltage Dry-Type Distribution Transformers in 2027
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
No-new- -------------------------------------------------------------------------------
standards case 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Domestic Production Workers in 2027..................... 169 169 170 183 201 208
Domestic Non-Production Workers in 2027................. 60 60 60 65 71 74
-----------------------------------------------------------------------------------------------
Total Direct Employment in 2027..................... 229 229 230 248 272 282
Potential Changes in Total Direct Employment in 2027.... .............. 0 0-1 (28)-19 (49)-43 (51)-53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Using the estimated labor content from the GRIM combined with data
from the 2019 ASM, DOE estimates that there would be approximately 169
domestic production workers, and 60 domestic non-production workers
involved in LVDT distribution transformer manufacturing in 2027 in the
absence of amended energy conservation standards. Table V.53 shows the
range of the impacts of energy conservation standards on U.S.
production on LVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to
domestic employment for LVDT distribution transformer manufacturing
that was used for liquid-immersed distribution transformer
manufacturing. The upper range of the ``Potential Change in Total
Direct Employment in 2027'' displayed in Table V.53, assumes that all
LVDT distribution transformer manufacturing remains in the U.S. The
lower range of the ``Potential Change in Total Direct Employment in
2027'', assumes that 30 percent of distribution transformers using
amorphous cores are re-located to foreign countries, either due to
amorphous core production that is outsourced to core only manufacturers
located in foreign countries or LVDT distribution transformer
manufacturers re-locating their distribution transformer production to
foreign countries.
Medium-Voltage Dry-Type Distribution Transformers
Table V.54--Domestic Employment for Medium-Voltage Dry-Type Distribution Transformers in 2027
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
No-new- -------------------------------------------------------------------------------
standards case 1 2 3 4 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Domestic Production Workers in 2027..................... 275 275 284 315 330 356
Domestic Non-Production Workers in 2027................. 98 98 101 112 117 126
-----------------------------------------------------------------------------------------------
Total Direct Employment in 2027..................... 373 373 385 427 447 482
Potential Changes in Total Direct Employment in 2027.... .............. 0 0-12 (63)-54 (69)-74 (83)-109
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 1817]]
Using the estimated labor content from the GRIM combined with data
from the 2019 ASM, DOE estimates that there would be approximately 275
domestic production workers, and 98 domestic non-production workers
involved in MVDT distribution transformer manufacturing in 2027 in the
absence of amended energy conservation standards. Table V.54 shows the
range of the impacts of energy conservation standards on U.S.
production on MVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to
domestic employment for MVDT distribution transformer manufacturing
that was used for liquid-immersed distribution transformer
manufacturing. The upper range of the ``Potential Change in Total
Direct Employment in 2027'' displayed in Table V.54, assumes that all
MVDT distribution transformer manufacturing remains in the U.S. The
lower range of the ``Potential Change in Total Direct Employment in
2027'', assumes that 30 percent of distribution transformers using
amorphous cores are re-located to foreign countries, either due to
amorphous core production that is outsourced to core only manufacturers
located in foreign countries or MVDT distribution transformer
manufacturers re-locating their distribution transformer production to
foreign countries.
DOE requests comment on the estimated potential domestic employment
impacts on distribution transformer manufacturers presented in this
NOPR.
c. Impacts on Manufacturing Capacity
The prices of raw materials currently used in distribution
transformers, such as GOES, copper, and aluminum, have all experienced
a significant increase in price starting at the beginning of 2021. The
availability of these commodities remains a significant concern with
distribution transformer manufacturers. As previously stated in
IV.J.3.a, steel producers are shifting production away from GOES suited
for distribution transformer core manufacturing to non-grain-oriented
steels suited for electric vehicle production. However, amorphous steel
has not seen the same significant increase in price as GOES since the
beginning of 2021.
The availability of amorphous steel is a concern for many
distribution transformer manufacturers. Based on information received
during manufacturer interviews some distribution transformer
manufacturers suggested that there would not be enough amorphous steel
available to be used in all or even most distribution transformers
currently sold in the U.S. Other distribution transformer manufacturers
and steel suppliers interviewed stated that, while the current capacity
of amorphous steel does not exist to supply the majority of the steel
used in distribution transformer cores, steel manufacturers are capable
of significantly increasing their amorphous steel production if there
is sufficient market demand for amorphous steel.
While the availability of both GOES and amorphous steel is a
concern for many distribution transformer manufacturers, steel
suppliers should be able to meet the market demand for amorphous steel
for all TSLs analyzed given the three-year compliance period for
distribution transformers. Steel manufacturers should be able to
significantly increase their supply of amorphous steel if they know
there will be an increase in the demand for this material due to energy
conservation standards for distribution transformers. See section V.C
for a more detailed discussion of the global supply of steel.
DOE requests comment on the potential availability of either
amorphous steel, grain-oriented electrical steel, or any other
materials that may be needed to meet any of the analyzed energy
conservation standards in this rulemaking. More specifically, DOE
requests comment on steel manufacturers' ability to increase supply of
amorphous steel in reaction to increased demand for amorphous steel as
a result of increased energy conservation standards for distribution
transformers.
d. Impacts on Competition
EPCA directs DOE to consider any lessening of competition that is
likely to result from imposition of standards. It further directs the
Attorney General to determine the impacts, if any, of any lessening of
competition. The competitive analysis includes an assessment of the
impacts to smaller, yet significant, manufacturers. DOE bases its
assessment on manufacturing cost data and on information collected from
interviews with manufacturers. The manufacturer interviews focus on
gathering information that would help in assessing asymmetrical cost
increases to some manufacturers, increased proportion of fixed costs
potentially increasing business risks, and potential barriers to market
entry (e.g., proprietary technologies).
As discussed in section IV.J.3, DOE interviewed a wide variety of
distribution transformer manufacturers, including liquid-immersed
distribution transformer manufacturers, LVDT distribution transformer
manufacturers, MVDT distribution transformer manufacturers, small
businesses, and steel suppliers. During these manufacturer interviews
DOE asked manufacturers if energy conservation standards could result
in a change in industry competition. Some manufacturers stated that
there is a possibility that smaller manufacturers may exit the market
or their market share may decrease, if these businesses are not able to
make the investments to upgrade their production equipment or to create
new equipment designs in order to comply with energy conservation
standards. See section VI.B, for a complete discussion on the potential
impacts to small businesses.
Based on the market and technology assessment conducted for this
NOPR analysis, DOE identified 29 manufacturers of distribution
transformers covered by this rulemaking. See chapter 3 of this NOPR TSD
for a complete list of the distribution transformer manufacturers. The
distribution transformer market has a handful of major manufacturers
for each equipment type (i.e., liquid-immersed, LVDT, MVDT).
Transformer core sourcing is a major driver of transformer
manufacturing strategy and competitiveness which may be impacted by the
standards level. Typically, manufacturers with larger market shares
produce most of their own cores and manufacturers with smaller market
shares purchase the cores used in their distribution transformers. The
Department does not believe the proposed standard will alter current
core make-versus-buy decisions. The Department expects that
manufacturers with larger market shares will make the large investments
needed to convert their core production to amorphous steel.
Manufacturers with smaller market shares that do not invest in
amorphous core manufacturing will continue to have the option to source
their cores. DOE does not anticipate a significant change in
competition due to energy conservation standards as the business model
and competitive position for most distribution transformer
manufacturers will remain the same after compliance with energy
conservation standards.
e. Impacts on Subgroups of Manufacturers
As discussed in section IV.J.1 of this document, using average cost
assumptions to develop an industry cash-flow estimate may not be
adequate for assessing differential impacts among manufacturer
subgroups. Small
[[Page 1818]]
manufacturers, niche manufacturers, and manufacturers exhibiting a cost
structure substantially different from the industry average could be
affected disproportionately. DOE used the results of the industry
characterization to group manufacturers exhibiting similar
characteristics. Consequently, DOE considered four manufacturer
subgroups in the MIA: liquid-immersed, LVDT, MVDT, and small
manufacturers as a subgroup for a separate impact analysis. DOE
discussed the potential impacts on liquid-immersed, LVDT, and MVDT
distribution transformer manufacturers separately in sections V.B.2.a
and V.B.2.b.
For the small business subgroup analysis, DOE applied the small
business size standards published by the Small Business Administration
(``SBA'') to determine whether a company is considered a small
business. The size standards are codified at 13 CFR part 121. To be
categorized as a small business under NAICS code 335311, ``power,
distribution, and specialty transformer manufacturing,'' a distribution
transformer manufacturer and its affiliates may employ a maximum of 750
employees. The 750-employee threshold includes all employees in a
business's parent company and any other subsidiaries. For a discussion
of the impacts on the small manufacturer subgroup, see the Regulatory
Flexibility Analysis in section VI.B.
f. Cumulative Regulatory Burden
One aspect of assessing manufacturer burden involves looking at the
cumulative impact of multiple DOE standards and the product-specific
regulatory actions of other Federal agencies that affect the
manufacturers of a covered product or equipment. While any one
regulation may not impose a significant burden on manufacturers, the
combined effects of several existing or impending regulations may have
serious consequences for some manufacturers, groups of manufacturers,
or an entire industry. Assessing the impact of a single regulation may
overlook this cumulative regulatory burden. In addition to energy
conservation standards, other regulations can significantly affect
manufacturers' financial operations. Multiple regulations affecting the
same manufacturer can strain profits and lead companies to abandon
product lines or markets with lower expected future returns than
competing products. For these reasons, DOE conducts an analysis of
cumulative regulatory burden as part of its rulemakings pertaining to
appliance efficiency. DOE requests information regarding the impact of
cumulative regulatory burden on manufacturers of distribution
transformers associated with multiple DOE standards or product-specific
regulatory actions of other Federal agencies.
DOE evaluates product-specific regulations that will take effect
approximately 3 years before or after the estimated 2027 compliance
date of any amended energy conservation standards for distribution
transformers. This information is presented in Table V.55.
Table V.55--Compliance Dates and Expected Conversion Expenses of Federal Energy Conservation Standards Affecting
Distribution Transformer Manufacturers
----------------------------------------------------------------------------------------------------------------
Number of Industry Industry
Federal energy conservation Number of manufacturers Approx. conversion conversion
standard manufacturers * affected from standards year costs costs/product
this rule ** (millions) revenue ***
----------------------------------------------------------------------------------------------------------------
Dedicated-Purpose Pool Pump 5 1 2026 $46.2 2.8%
Motors, 87 FR 37122 (June 21, (2020$)
2022)........................
----------------------------------------------------------------------------------------------------------------
* This column presents the total number of manufacturers identified in the energy conservation standard rule
contributing to cumulative regulatory burden.
** This column presents the number of manufacturers producing distribution transformers that are also listed as
manufacturers in the listed energy conservation standard contributing to cumulative regulatory burden.
*** This column presents industry conversion costs as a percentage of product revenue during the conversion
period. Industry conversion costs are the upfront investments manufacturers must make to sell compliant
products/equipment. The revenue used for this calculation is the revenue from just the covered product/
equipment associated with each row. The conversion period is the time frame over which conversion costs are
made and lasts from the publication year of the final rule to the compliance year of the energy conservation
standard. The conversion period typically ranges from 3 to 5 years, depending on the rulemaking.
In addition to the rulemaking listed in Table V.55, DOE has ongoing
rulemakings for other products or equipment that distribution
transformer manufacturers produce, including battery chargers; \103\
external power supplies; \104\ ceiling fan light kits; \105\ electric
motors; \106\ residential conventional cooking products; \107\
dishwashers; \108\ dehumidifiers; \109\ miscellaneous refrigeration
products; \110\ and residential clothes washers.\111\ If DOE proposes
or finalizes any energy conservation standards for these products or
equipment prior to finalizing energy conservation standards for
distribution transformers, DOE will include the energy conservation
standards for these other products or equipment as part of the
cumulative regulatory burden for the distribution transformers final
rule.
---------------------------------------------------------------------------
\103\ www.regulations.gov/docket/EERE-2008-BT-STD-0005.
\104\ www.regulations.gov/docket/EERE-2020-BT-STD-0006.
\105\ www.regulations.gov/docket/EERE-2019-BT-STD-0040.
\106\ www.regulations.gov/docket/EERE-2020-BT-STD-0007.
\107\ www.regulations.gov/docket/EERE-2014-BT-STD-0005.
\108\ www.regulations.gov/docket/EERE-2019-BT-STD-0039.
\109\ www.regulations.gov/docket/EERE-2019-BT-STD-0043.
\110\ www.regulations.gov/docket/EERE-2020-BT-STD-0039.
\111\ www.regulations.gov/docket/EERE-2017-BT-STD-0014.
---------------------------------------------------------------------------
3. National Impact Analysis
This section presents DOE's estimates of the national energy
savings and the NPV of consumer benefits that would result from each of
the TSLs considered as potential amended standards.
a. Significance of Energy Savings
To estimate the energy savings attributable to potential amended
standards for distribution transformers, DOE compared their energy
consumption under the no-new-standards case to their anticipated energy
consumption under each TSL. The savings are measured over the entire
lifetime of products purchased in
[[Page 1819]]
the 30-year period that begins in the first full year of anticipated
compliance with amended standards (2027-2056). Table V.56 presents
DOE's projections of the national energy savings for each TSL
considered for distribution transformers, the results showing DOE's
proposed standard are in bold. Savings are reported for each of the
equipment classes as defined in Section IV.A.2. The savings were
calculated using the approach described in section IV.H of this
document.
Table V.56--Cumulative National Energy Sources for Distribution Transformers by Equipment Class; 30 Years of
Shipment, (2027-2056)
----------------------------------------------------------------------------------------------------------------
Standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Primary Energy Savings (Quads)
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 2.16 3.16 4.45 4.75 4.89
Equipment Class 2........... 0.91 1.65 2.63 2.97 3.17
Equipment Class 12.......... n.a. n.a. n.a. n.a. 0.08
-------------------------------------------------------------------------------
Liquid-Immersed Total... 3.06 4.80 7.09 7.72 8.14
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type:
Equipment Class 3........... 0.02 0.03 0.05 0.09 0.12
Equipment Class 4........... 0.34 0.48 0.77 2.10 2.25
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.35 0.52 0.82 2.19 2.37
Total..................
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.01 0.02 0.03
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.05 0.07 0.23 0.29 0.35
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.02 0.04 0.14 0.19 0.22
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.08 0.11 0.39 0.51 0.61
Total..................
----------------------------------------------------------------------------------------------------------------
FFC Energy Savings (Quads)
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 2.24 3.28 4.63 4.94 5.08
Equipment Class 2........... 0.94 1.71 2.73 3.08 3.29
Equipment Class 12.......... 0.00 0.00 0.00 0.00 0.09
-------------------------------------------------------------------------------
Liquid-Immersed Total... 3.18 4.99 7.36 8.02 8.45
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type:
Equipment Class 3........... 0.02 0.03 0.05 0.09 0.12
Equipment Class 4........... 0.35 0.50 0.80 2.19 2.34
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.37 0.54 0.85 2.28 2.47
Total..................
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.01 0.02 0.03
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.05 0.07 0.24 0.30 0.36
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.02 0.04 0.15 0.20 0.23
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.08 0.12 0.40 0.53 0.63
Total..................
----------------------------------------------------------------------------------------------------------------
OMB Circular A-4 \112\ requires agencies to present analytical
results, including separate schedules of the monetized benefits and
costs that show the type and timing of benefits and costs. Circular A-4
also directs agencies to consider the variability of key elements
underlying the estimates of benefits and costs. For this rulemaking,
DOE undertook a sensitivity analysis using 9 years, rather than 30
years, of product shipments. The choice of a 9-year period is a proxy
for the timeline in EPCA for the review of certain energy conservation
standards and potential revision of and compliance with such revised
standards.\113\ The review
[[Page 1820]]
timeframe established in EPCA is generally not synchronized with the
product lifetime, product manufacturing cycles, or other factors
specific to distribution transformers. Thus, such results are presented
for informational purposes only and are not indicative of any change in
DOE's analytical methodology. The NES sensitivity analysis results
based on a 9-year analytical period are presented in Table V.57. The
impacts are counted over the lifetime of distribution transformers
purchased in 2027-2036, the results showing DOE's proposed standard are
in bold.
---------------------------------------------------------------------------
\112\ U.S. Office of Management and Budget. Circular A-4:
Regulatory Analysis. September 17, 2003. https://www.whitehouse.gov/wp-content/uploads/legacy_drupal_files/omb/circulars/A4/a-4.pdf
(last accessed August 26, 2022).
\113\ Section 325(m) of EPCA requires DOE to review its
standards at least once every 6 years, and requires, for certain
products, a 3-year period after any new standard is promulgated
before compliance is required, except that in no case may any new
standards be required within 6 years of the compliance date of the
previous standards. While adding a 6-year review to the 3-year
compliance period adds up to 9 years, DOE notes that it may
undertake reviews at any time within the 6 year period and that the
3-year compliance date may yield to the 6-year backstop. A 9-year
analysis period may not be appropriate given the variability that
occurs in the timing of standards reviews and the fact that for some
products, the compliance period is 5 years rather than 3 years.
Table V.57--Cumulative National Energy Savings for Distribution Transformers; 9 Years of Shipments, (2027-2036)
----------------------------------------------------------------------------------------------------------------
Standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Primary Energy Savings (Quads)
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 0.62 0.90 1.27 1.36 1.39
Equipment Class 2........... 0.26 0.47 0.75 0.85 0.90
Equipment Class 12.......... n.a. n.a. n.a. n.a. 0.02
-------------------------------------------------------------------------------
Liquid-Immersed Total... 0.87 1.37 2.02 2.20 2.32
Low-Voltage Dry-Type:
Equipment Class 3........... 0.00 0.01 0.01 0.02 0.03
Equipment Class 4........... 0.10 0.14 0.22 0.60 0.64
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.10 0.15 0.23 0.63 0.68
Total..................
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.00 0.01 0.01
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.01 0.02 0.07 0.08 0.10
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.01 0.01 0.04 0.05 0.06
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.02 0.03 0.11 0.14 0.17
Total..................
----------------------------------------------------------------------------------------------------------------
FFC Energy Savings (Quads)
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1............... 0.64 0.93 1.32 1.41 1.45
Equipment Class 2............... 0.27 0.49 0.78 0.88 0.94
Equipment Class 12.............. n.a. n.a. n.a. n.a. 0.03
-------------------------------------------------------------------------------
Liquid-Immersed Total... 0.91 1.42 2.10 2.29 2.41
Low-Voltage Dry-Type:
Equipment Class 3........... 0.00 0.01 0.01 0.03 0.04
Equipment Class 4........... 0.10 0.14 0.23 0.62 0.67
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.11 0.15 0.24 0.65 0.70
Total..................
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.00 0.01 0.01
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.02 0.02 0.07 0.09 0.10
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.01 0.01 0.04 0.06 0.07
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.02 0.03 0.12 0.15 0.18
Total..................
----------------------------------------------------------------------------------------------------------------
b. Net Present Value of Consumer Costs and Benefits
DOE estimated the cumulative NPV of the total costs and savings for
consumers that would result from the TSLs considered for distribution
transformers. In accordance with OMB's guidelines on regulatory
analysis,\114\ DOE calculated NPV using both a 7-percent and a 3-
percent real discount rate. Table V.58 shows the consumer NPV results
with impacts counted over the lifetime of products purchased in 2027-
2056, the results showing DOE's proposed standard are in bold.
---------------------------------------------------------------------------
\114\ U.S. Office of Management and Budget. Circular A-4:
Regulatory Analysis. September 17, 2003. www.whitehouse.gov/omb/circulars_a004_a-4/ (last accessed April 15, 2022).
[[Page 1821]]
Table V.58--Cumulative Net Present Value of Consumer Benefits for Distribution Transformers; 30 Years of
Shipments, Billion 2021$, (2027-2056)
----------------------------------------------------------------------------------------------------------------
Standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
3 percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 2.55 3.34 4.00 3.45 -4.04
Equipment Class 2........... 0.43 0.81 1.50 1.84 -2.10
Equipment Class 12.......... n.a. n.a. n.a. n.a. -0.10
-------------------------------------------------------------------------------
Liquid-Immersed Total... 2.98 4.15 5.50 5.30 -6.25
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type:
Equipment Class 3........... 0.07 0.13 0.15 0.31 0.52
Equipment Class 4........... 1.41 1.98 1.72 9.41 9.11
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 1.48 2.11 1.87 9.72 9.63
Total..................
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.01
Equipment Class 6........... 0.01 0.01 0.02 0.02 0.04
Equipment Class 7........... 0.00 0.00 0.00 0.01 0.01
Equipment Class 8........... 0.25 0.22 0.76 0.77 0.54
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.00 -0.02 0.46 0.50 0.36
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.26 0.21 1.25 1.30 0.96
Total..................
----------------------------------------------------------------------------------------------------------------
7 percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 0.78 0.94 0.82 0.24 -4.41
Equipment Class 2........... 0.00 0.06 0.07 0.01 -2.60
Equipment Class 12.......... n.a. n.a. n.a. n.a. -0.10
-------------------------------------------------------------------------------
Liquid-Immersed Total... 0.78 1.00 0.89 0.26 -7.11
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type:
Equipment Class 3........... 0.02 0.04 0.04 0.07 0.13
Equipment Class 4........... 0.50 0.70 0.35 2.72 2.50
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.53 0.74 0.39 2.79 2.63
Total..................
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.10 0.07 0.18 0.15 0.01
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.01 -0.04 0.08 0.08 0.00
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.09 0.04 0.27 0.23 0.00
Total..................
----------------------------------------------------------------------------------------------------------------
The NPV results based on the aforementioned 9-year analytical
period are presented in Table V.59. The impacts are counted over the
lifetime of products purchased in 2027-2036. As mentioned previously,
such results are presented for informational purposes only and are not
indicative of any change in DOE's analytical methodology or decision
criteria.
Table V.59--Cumulative Net Present Value of Consumer Benefits for Distribution Transformers; 9 Years of
Shipments, Billion 2021$, (2027-2036)
----------------------------------------------------------------------------------------------------------------
Standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
3 percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 0.99 1.30 1.56 1.36 -1.50
Equipment Class 2........... 0.17 0.32 0.59 0.73 -0.78
[[Page 1822]]
Equipment Class 12.......... n.a. n.a. n.a. n.a. -0.04
-------------------------------------------------------------------------------
Liquid-Immersed Total... 1.16 1.62 2.15 2.09 -2.32
----------------------------------------------------------------------------------------------------------------
Low-Voltage Dry-Type:
Equipment Class 3........... 0.03 0.05 0.06 0.12 0.20
Equipment Class 4........... 0.55 0.77 0.68 3.69 3.57
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.58 0.82 0.74 3.81 3.77
Total..................
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.01 0.01 0.02
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.10 0.09 0.30 0.30 0.22
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... 0.00 -0.01 0.18 0.20 0.15
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.10 0.08 0.49 0.51 0.39
Total..................
----------------------------------------------------------------------------------------------------------------
7 percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed:
Equipment Class 1........... 0.40 0.49 0.43 0.14 -2.24
Equipment Class 2........... 0.00 0.03 0.04 0.02 -1.32
Equipment Class 12.......... n.a. n.a. n.a. n.a. -0.05
-------------------------------------------------------------------------------
Liquid-Immersed Total... 0.41 0.52 0.48 0.15 -3.61
Low-Voltage Dry-Type:
Equipment Class 3........... 0.01 0.02 0.02 0.04 0.07
Equipment Class 4........... 0.26 0.36 0.19 1.43 1.32
-------------------------------------------------------------------------------
Low-Voltage Dry-Type 0.27 0.39 0.21 1.46 1.38
Total..................
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type:
Equipment Class 5........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 6........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 7........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 8........... 0.05 0.04 0.10 0.08 0.01
Equipment Class 9........... 0.00 0.00 0.00 0.00 0.00
Equipment Class 10.......... -0.01 -0.02 0.05 0.04 0.00
-------------------------------------------------------------------------------
Medium-Voltage Dry-Type 0.04 0.02 0.14 0.12 0.01
Total..................
----------------------------------------------------------------------------------------------------------------
The previous results reflect the use of a default trend to estimate
the change in price for distribution transformers over the analysis
period (see section IV.F.1 of this document). DOE also conducted a
sensitivity analysis that considered one scenario with a lower rate of
price decline than the reference case and one scenario with a higher
rate of price decline than the reference case. The results of these
alternative cases are presented in appendix 10C of the NOPR TSD. In the
high-price-decline case, the NPV of consumer benefits is higher than in
the default case. In the low-price-decline case, the NPV of consumer
benefits is lower than in the default case.
c. Indirect Impacts on Employment
It is estimated that that amended energy conservation standards for
distribution transformers would reduce energy expenditures for
consumers of those products, with the resulting net savings being
redirected to other forms of economic activity. These expected shifts
in spending and economic activity could affect the demand for labor. As
described in section IV.N of this document, DOE used an input/output
model of the U.S. economy to estimate indirect employment impacts of
the TSLs that DOE considered. There are uncertainties involved in
projecting employment impacts, especially changes in the later years of
the analysis. Therefore, DOE generated results for near-term timeframes
(2027-2031), where these uncertainties are reduced.
The results suggest that the proposed standards would be likely to
have a negligible impact on the net demand for labor in the economy.
The net change in jobs is so small that it would be imperceptible in
national labor statistics and might be offset by other, unanticipated
effects on employment. Chapter 16 of the NOPR TSD presents detailed
results regarding anticipated indirect employment impacts.
4. Impact on Utility or Performance of Products
As discussed in section IV.C.1.b of this document, DOE has
tentatively concluded that the standards proposed in this NOPR would
not lessen the utility or performance of the distribution transformers
under consideration in this rulemaking. Manufacturers of these products
currently offer units that meet or exceed the proposed standards.
[[Page 1823]]
5. Impact of Any Lessening of Competition
DOE considered any lessening of competition that would be likely to
result from new or amended standards. As part of this consideration,
DOE weighed the effects on markets for both component parts (see
IV.C.3.a) and distribution transformer equipment (see IV.A.6). DOE's
preliminary finding is that this rule, if finalized as proposed, would
not significantly affect competition in the market for distribution
transformers. See section V.B.5 for a complete discussion on industry
competition. As discussed in section III.E.1.e, the Attorney General
determines the impact, if any, of any lessening of competition likely
to result from a proposed standard, and transmits such determination in
writing to the Secretary, together with an analysis of the nature and
extent of such impact. To assist the Attorney General in making this
determination, DOE has provided DOJ with copies of this NOPR and the
accompanying TSD for review. DOE will consider DOJ's comments on the
proposed rule in determining whether to proceed to a final rule. DOE
will publish and respond to DOJ's comments in that document. DOE
invites comment from the public regarding the competitive impacts that
are likely to result from this proposed rule. In addition, stakeholders
may also provide comments separately to DOJ regarding these potential
impacts. See the ADDRESSES section for information to send comments to
DOJ.
6. Need of the Nation to Conserve Energy
Enhanced energy efficiency, where economically justified, improves
the Nation's energy security, strengthens the economy, and reduces the
environmental impacts (costs) of energy production. Reduced electricity
demand due to energy conservation standards is also likely to reduce
the cost of maintaining the reliability of the electricity system,
particularly during peak-load periods. Chapter 15 in the NOPR TSD
presents the estimated impacts on electricity generating capacity,
relative to the no-new-standards case, for the TSLs that DOE considered
in this rulemaking.
Energy conservation resulting from potential energy conservation
standards for distribution transformers is expected to yield
environmental benefits in the form of reduced emissions of certain air
pollutants and greenhouse gases. Table V.60 through Table V.63 provides
DOE's estimate of cumulative emissions reductions expected to result
from the TSLs considered in this rulemaking. The emissions were
calculated using the multipliers discussed in section IV.K. DOE reports
annual emissions reductions for each TSL in chapter 13 of the NOPR TSD.
Table V.60--Cumulative Emissions Reduction for All Distribution
Transformers Shipped in 2027-2056 at Proposed Standard Levels
------------------------------------------------------------------------
------------------------------------------------------------------------
Power Sector Emissions
------------------------------------------------------------------------
CO2 (million metric tons)......................... 312.0
CH4 (thousand tons)............................... 21.3
N2O (thousand tons)............................... 2.9
NOX (thousand tons)............................... 146.0
SO2 (thousand tons)............................... 129.2
Hg (tons)......................................... 0.8
------------------------------------------------------------------------
Upstream Emissions
------------------------------------------------------------------------
CO2 (million metric tons)......................... 25.5
CH4 (thousand tons)............................... 2419.9
N2O (thousand tons)............................... 0.1
NOX (thousand tons)............................... 386.9
SO2 (thousand tons)............................... 1.7
Hg (tons)......................................... 0.0
------------------------------------------------------------------------
Total FFC Emissions
------------------------------------------------------------------------
CO2 (million metric tons)......................... 337.6
CH4 (thousand tons)............................... 2441.2
N2O (thousand tons)............................... 3.0
NOX (thousand tons)............................... 532.9
SO2 (thousand tons)............................... 130.9
Hg (tons)......................................... 0.9
------------------------------------------------------------------------
Negative values refer to an increase in emissions.
Table V.61--Cumulative Emissions Reduction for Distribution Transformers for Liquid-Immersed Distribution
Transformers Shipped in 2027-2056
----------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Power Sector Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 94.2 147.8 217.7 237.0 249.4
CH4 (thousand tons)............. 6.4 10.1 14.8 16.2 17.0
N2O (thousand tons)............. 0.9 1.4 2.0 2.2 2.3
NOX (thousand tons)............. 44.1 69.2 101.9 110.9 116.7
SO2 (thousand tons)............. 39.1 61.4 90.5 98.4 103.5
[[Page 1824]]
Hg (tons)....................... 0.3 0.4 0.6 0.6 0.7
----------------------------------------------------------------------------------------------------------------
Upstream Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 7.7 12.0 17.7 19.3 20.3
CH4 (thousand tons)............. 726.6 1139.8 1680.6 1830.4 1929.9
N2O (thousand tons)............. 0.0 0.1 0.1 0.1 0.1
NOX (thousand tons)............. 116.2 182.2 268.7 292.7 308.6
SO2 (thousand tons)............. 0.5 0.8 1.2 1.3 1.3
Hg (tons)....................... 0.0 0.0 0.0 0.0 0.0
----------------------------------------------------------------------------------------------------------------
Total FFC Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 101.9 159.8 235.4 256.3 269.7
CH4 (thousand tons)............. 733.1 1149.8 1695.5 1846.6 1946.9
N2O (thousand tons)............. 0.9 1.4 2.1 2.3 2.4
NOX (thousand tons)............. 160.3 251.4 370.6 403.6 425.2
SO2 (thousand tons)............. 39.7 62.2 91.6 99.7 104.8
Hg (tons)....................... 0.3 0.4 0.6 0.7 0.7
----------------------------------------------------------------------------------------------------------------
Negative values refer to an increase in emissions.
Table V.62--Cumulative Emissions Reduction for Distribution Transformers for Low-Voltage Dry-Type Distribution
Transformers Shipped in 2027-2056
----------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Power Sector Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 10.7 15.6 24.8 66.1 71.6
CH4 (thousand tons)............. 0.7 1.1 1.7 4.5 4.9
N2O (thousand tons)............. 0.1 0.1 0.2 0.6 0.7
NOX (thousand tons)............. 5.0 7.3 11.6 30.9 33.5
SO2 (thousand tons)............. 4.4 6.4 10.2 27.1 29.4
Hg (tons)....................... 0.0 0.0 0.1 0.2 0.2
----------------------------------------------------------------------------------------------------------------
Upstream Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 0.9 1.3 2.0 5.5 5.9
CH4 (thousand tons)............. 84.0 122.4 194.5 519.1 562.4
N2O (thousand tons)............. 0.0 0.0 0.0 0.0 0.0
NOX (thousand tons)............. 13.4 19.6 31.1 83.0 89.9
SO2 (thousand tons)............. 0.1 0.1 0.1 0.4 0.4
Hg (tons)....................... 0.0 0.0 0.0 0.0 0.0
----------------------------------------------------------------------------------------------------------------
Total FFC Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 11.6 16.9 26.8 71.6 77.6
CH4 (thousand tons)............. 84.8 123.4 196.2 523.5 567.3
N2O (thousand tons)............. 0.1 0.2 0.2 0.6 0.7
NOX (thousand tons)............. 18.4 26.9 42.7 113.9 123.4
SO2 (thousand tons)............. 4.5 6.5 10.3 27.5 29.8
Hg (tons)....................... 0.0 0.0 0.1 0.2 0.2
----------------------------------------------------------------------------------------------------------------
Negative values refer to an increase in emissions.
Table V.63--Cumulative Emissions Reduction for Distribution Transformers for Medium-Voltage Dry-Type
Distribution Transformers Shipped in 2027-2056
----------------------------------------------------------------------------------------------------------------
Trial Standard Level
-------------------------------------------------------------------------------
1 2 3 4 5
----------------------------------------------------------------------------------------------------------------
Power Sector Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 2.3 3.4 11.7 15.2 18.2
CH4 (thousand tons)............. 0.2 0.2 0.8 1.0 1.2
N2O (thousand tons)............. 0.0 0.0 0.1 0.1 0.2
[[Page 1825]]
NOX (thousand tons)............. 1.1 1.6 5.5 7.1 8.5
SO2 (thousand tons)............. 1.0 1.4 4.8 6.2 7.5
Hg (tons)....................... 0.0 0.0 0.0 0.0 0.0
----------------------------------------------------------------------------------------------------------------
Upstream Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 0.2 0.3 1.0 1.3 1.5
CH4 (thousand tons)............. 18.4 27.1 92.3 120.0 143.7
N2O (thousand tons)............. 0.0 0.0 0.0 0.0 0.0
NOX (thousand tons)............. 2.9 4.3 14.8 19.2 23.0
SO2 (thousand tons)............. 0.0 0.0 0.1 0.1 0.1
Hg (tons)....................... 0.0 0.0 0.0 0.0 0.0
----------------------------------------------------------------------------------------------------------------
Total FFC Emissions
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 2.5 3.7 12.7 16.5 19.7
CH4 (thousand tons)............. 18.6 27.3 93.1 121.1 144.9
N2O (thousand tons)............. 0.0 0.0 0.1 0.1 0.2
NOX (thousand tons)............. 4.0 5.9 20.2 26.3 31.5
SO2 (thousand tons)............. 1.0 1.4 4.9 6.3 7.6
Hg (tons)....................... 0.0 0.0 0.0 0.0 0.0
----------------------------------------------------------------------------------------------------------------
Negative values refer to an increase in emissions.
As part of the analysis for this rulemaking, DOE estimated monetary
benefits likely to result from the reduced emissions of CO2
that DOE estimated for each of the considered TSLs for distribution
transformers. Section IV.L of this document discusses the SC-
CO2 values that DOE used. Table V.64 presents the value of
CO2 emissions reduction at each TSL for each of the SC-
CO2 cases. The time-series of annual values is presented for
the proposed TSL in chapter 14 of the NOPR TSD.
Table V.64--Present Value of CO2 Emissions Reduction for Distribution Transformers Shipped in 2027-2056
----------------------------------------------------------------------------------------------------------------
SC-CO2 Case
---------------------------------------------------------------
Discount rate and statistics (million 2021$)
---------------------------------------------------------------
TSL 5% 3% 2.5% 3%
---------------------------------------------------------------
95th
Average Average Average percentile
----------------------------------------------------------------------------------------------------------------
Liquid-immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 603.2 2,773.2 4,425.4 8,386.0
2............................................... 946.1 4,350.2 6,941.9 13,154.7
3............................................... 1,394.3 6,410.7 10,229.9 19,385.3
4............................................... 1,517.6 6,977.6 11,134.6 21,099.8
5............................................... 1,597.1 7,343.2 11,718.0 22,205.4
----------------------------------------------------------------------------------------------------------------
Low-voltage Dry Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 72.9 333.0 530.3 1,007.4
2............................................... 106.1 484.8 772.1 1,466.7
3............................................... 168.6 770.4 1,227.0 2,330.8
4............................................... 450.3 2,056.9 3,276.0 6,223.1
5............................................... 487.9 2,228.8 3,549.8 6,743.2
----------------------------------------------------------------------------------------------------------------
Medium-voltage Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 15.9 72.7 115.8 220.0
2............................................... 23.3 106.7 169.9 322.7
3............................................... 79.8 364.4 580.4 1,102.5
4............................................... 103.7 473.6 754.2 1,432.7
5............................................... 124.0 566.7 902.5 1,714.4
----------------------------------------------------------------------------------------------------------------
[[Page 1826]]
As discussed in section IV.L.2, DOE estimated the climate benefits
likely to result from the reduced emissions of methane and
N2O that DOE estimated for each of the considered TSLs for
distribution transformers. Table V.65 presents the value of the
CH4 emissions reduction at each TSL, and Table V.66 presents
the value of the N2O emissions reduction at each TSL. The
time-series of annual values is presented for the proposed TSL in
chapter 14 of the NOPR TSD.
Table V.65--Present Value of Methane Emissions Reduction for Distribution Transformers Shipped in 2027-2056
----------------------------------------------------------------------------------------------------------------
SC-CH4 Case
---------------------------------------------------------------
Discount rate and statistics (million 2021$)
---------------------------------------------------------------
TSL 5% 3% 2.5% 3%
---------------------------------------------------------------
95th
Average Average Average percentile
----------------------------------------------------------------------------------------------------------------
Liquid-immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 202.8 659.9 939.6 1,748.1
2............................................... 318.1 1,035.0 1,473.7 2,741.9
3............................................... 469.0 1,526.2 2,173.0 4,042.9
4............................................... 510.8 1,662.2 2,366.7 4,403.2
5............................................... 538.6 1,752.5 2,495.3 4,642.6
----------------------------------------------------------------------------------------------------------------
Low-voltage Dry Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 24.8 80.1 113.9 212.2
2............................................... 36.2 116.7 165.8 309.0
3............................................... 57.5 185.5 263.6 491.3
4............................................... 153.4 494.9 703.4 1,310.8
5............................................... 166.2 536.3 762.2 1,420.4
----------------------------------------------------------------------------------------------------------------
Medium-voltage Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 5.4 17.6 25.0 46.6
2............................................... 8.0 25.8 36.7 68.3
3............................................... 27.3 88.0 125.1 233.2
4............................................... 35.5 114.5 162.7 303.1
5............................................... 42.4 137.0 194.7 362.8
----------------------------------------------------------------------------------------------------------------
Table V.66--Present Value of Nitrous Oxide Emissions Reduction for Distribution Transformers Shipped in 2027-
2056
----------------------------------------------------------------------------------------------------------------
SC-N2O Case
---------------------------------------------------------------
Discount rate and statistics (million 2021$)
---------------------------------------------------------------
TSL 5% 3% 2.5% 3%
---------------------------------------------------------------
95th
Average Average Average percentile
----------------------------------------------------------------------------------------------------------------
Liquid-immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 2.1 9.2 14.5 24.5
2............................................... 3.4 14.4 22.7 38.5
3............................................... 4.9 21.2 33.5 56.7
4............................................... 5.4 23.1 36.5 61.7
5............................................... 5.7 24.3 38.4 64.9
----------------------------------------------------------------------------------------------------------------
Low-voltage Dry Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 0.3 1.1 1.7 2.9
2............................................... 0.4 1.6 2.5 4.2
3............................................... 0.6 2.5 4.0 6.8
4............................................... 1.6 6.8 10.6 18.0
5............................................... 1.7 7.3 11.5 19.5
----------------------------------------------------------------------------------------------------------------
Medium-voltage Distribution Transformers
----------------------------------------------------------------------------------------------------------------
1............................................... 0.1 0.2 0.4 0.6
2............................................... 0.1 0.4 0.6 0.9
3............................................... 0.3 1.2 1.9 3.2
4............................................... 0.4 1.6 2.4 4.2
[[Page 1827]]
5............................................... 0.4 1.9 2.9 5.0
----------------------------------------------------------------------------------------------------------------
DOE is well aware that scientific and economic knowledge about the
contribution of CO2 and other GHG emissions to changes in
the future global climate and the potential resulting damages to the
global and U.S. economy continues to evolve rapidly. Thus, any value
placed on reduced GHG emissions in this proposed rulemaking is subject
to change. That said, because of omitted damages, DOE agrees with the
IWG that these estimates most likely underestimate the climate benefits
of greenhouse gas reductions. DOE, together with other Federal
agencies, will continue to review methodologies for estimating the
monetary value of reductions in CO2 and other GHG emissions.
This ongoing review will consider the comments on this subject that are
part of the public record for this and other rulemakings, as well as
other methodological assumptions and issues. DOE notes that the
proposed standards would be economically justified even without
inclusion of monetized benefits of reduced GHG emissions.
DOE also estimated the monetary value of the health benefits
associated with NOX and SO2 emissions reductions
anticipated to result from the considered TSLs for distribution
transformers. The dollar-per-ton values that DOE used are discussed in
section IV.L of this document. Table V.67 presents the present value
for NOX emissions reduction for each TSL calculated using 7-
percent and 3-percent discount rates, and Table V.68 presents similar
results for SO2 emissions reductions. The results in these
tables reflect application of EPA's low dollar-per-ton values, which
DOE used to be conservative. The time-series of annual values is
presented for the proposed TSL in chapter 14 of the NOPR TSD.
Table V.67--Present Value of NOX Emissions Reduction for Distribution
Transformers Shipped in 2027-2056
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
TSL -------------------------------------------
Million 2021$ Million 2021$
------------------------------------------------------------------------
Liquid-Immersed Distribution Transformers
------------------------------------------------------------------------
1........................... 1,385.3 4,631.4
2........................... 2,172.9 7,264.6
3........................... 3,203.1 10,709.0
4........................... 3,487.6 11,660.1
5........................... 3,674.0 12,283.6
------------------------------------------------------------------------
Low-voltage Dry-Type Distribution Transformers
------------------------------------------------------------------------
1........................... 171.4 552.0
2........................... 249.5 803.7
3........................... 396.6 1,277.5
4........................... 1,058.5 3,409.6
5........................... 1,147.0 3,694.6
------------------------------------------------------------------------
Medium-voltage Dry-Type Distribution Transformers
------------------------------------------------------------------------
1........................... 37.5 120.8
2........................... 55.0 177.3
3........................... 187.9 605.4
4........................... 244.3 786.9
5........................... 292.4 941.7
------------------------------------------------------------------------
Table V.68--Present Value of SO2 Emissions Reduction Distribution
Transformers Shipped in 2027-2056
------------------------------------------------------------------------
3% Discount rate 7% Discount rate
TSL -------------------------------------------
Million 2021$ Million 2021$
------------------------------------------------------------------------
Liquid-immersed Distribution Transformers
------------------------------------------------------------------------
1........................... 477.8 1,556.7
2........................... 749.5 2,442.2
[[Page 1828]]
3........................... 1,104.1 3,597.5
4........................... 1,201.2 3,913.9
5........................... 1,262.4 4,113.2
------------------------------------------------------------------------
Low-voltage Dry-Type Distribution Transformers
------------------------------------------------------------------------
1........................... 57.8 181.3
2........................... 84.2 263.9
3........................... 133.8 419.3
4........................... 357.3 1,119.8
5........................... 387.1 1,213.4
------------------------------------------------------------------------
Medium-voltage Dry-Type Distribution Transformers
------------------------------------------------------------------------
1........................... 12.6 39.5
2........................... 18.5 57.9
3........................... 63.2 198.1
4........................... 82.1 257.4
5........................... 98.3 307.9
------------------------------------------------------------------------
7. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, may consider any other factors that the
Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) No
other factors were considered in this analysis.
8. Summary of Economic Impacts
Table V.69 presents the NPV values that result from adding the
estimates of the potential economic benefits resulting from reduced GHG
and NOX and SO2 emissions to the NPV of consumer
benefits calculated for each TSL considered in this rulemaking. The
consumer benefits are domestic U.S. monetary savings that occur as a
result of purchasing the covered distribution transformers, and are
measured for the lifetime of products shipped in 2027-2056. The
benefits associated with reduced GHG emissions resulting from the
adopted standards are global benefits, and are also calculated based on
the lifetime of distribution transformers shipped in 2027-2056. While
many of the benefits from this proposed standard extend through 2115,
the monetized benefits from GHG reductions are capped at end of 2070.
Table V.69--Consumer NPV Combined With Present Value of Climate and Health Benefits
----------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
----------------------------------------------------------------------------------------------------------------
Liquid-immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 10.0 15.1 21.7 22.9 12.3
3% Average SC-GHG case.......... 12.6 19.3 27.8 29.5 19.3
2.5% Average SC-GHG case........ 14.5 22.3 32.2 34.4 24.4
3% 95th percentile SC-GHG case.. 19.3 29.8 43.3 46.4 37.1
----------------------------------------------------------------------------------------------------------------
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 3.4 5.2 7.1 7.0 0.0
3% Average SC-GHG case.......... 6.1 9.3 13.2 13.6 6.9
2.5% Average SC-GHG case........ 8.0 12.4 17.6 18.5 12.1
3% 95th percentile SC-GHG case.. 12.8 19.9 28.7 30.5 24.7
----------------------------------------------------------------------------------------------------------------
Low-voltage Distribution Transformers
----------------------------------------------------------------------------------------------------------------
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 2.3 3.3 3.8 14.9 15.2
3% Average SC-GHG case.......... 2.6 3.8 4.5 16.8 17.3
2.5% Average SC-GHG case........ 2.9 4.1 5.1 18.2 18.9
3% 95th percentile SC-GHG case.. 3.4 5.0 6.4 21.8 22.7
----------------------------------------------------------------------------------------------------------------
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 0.9 1.2 1.1 4.8 4.8
3% Average SC-GHG case.......... 1.2 1.7 1.9 6.8 6.9
[[Page 1829]]
2.5% Average SC-GHG case........ 1.4 2.0 2.4 8.2 8.5
3% 95th percentile SC-GHG case.. 2.0 2.9 3.7 11.8 12.3
----------------------------------------------------------------------------------------------------------------
Medium-voltage Distribution Transformers
----------------------------------------------------------------------------------------------------------------
3% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 0.4 0.5 2.2 2.5 2.4
3% Average SC-GHG case.......... 0.5 0.6 2.5 2.9 2.9
2.5% Average SC-GHG case........ 0.6 0.7 2.8 3.3 3.3
3% 95th percentile SC-GHG case.. 0.7 0.8 3.4 4.1 4.3
----------------------------------------------------------------------------------------------------------------
7% discount rate for Consumer NPV and Health Benefits (billion 2021$)
----------------------------------------------------------------------------------------------------------------
5% Average SC-GHG case.......... 0.2 0.1 0.6 0.7 0.6
3% Average SC-GHG case.......... 0.2 0.2 1.0 1.1 1.1
2.5% Average SC-GHG case........ 0.3 0.3 1.2 1.5 1.5
3% 95th percentile SC-GHG case.. 0.4 0.5 1.9 2.3 2.5
----------------------------------------------------------------------------------------------------------------
C. Conclusion
When considering new or amended energy conservation standards, the
standards that DOE adopts for any type (or class) of covered equipment
must be designed to achieve the maximum improvement in energy
efficiency that the Secretary determines is technologically feasible
and economically justified. (42 U.S.C. 6295(o)(2)(A)) In determining
whether a standard is economically justified, the Secretary must
determine whether the benefits of the standard exceed its burdens by,
to the greatest extent practicable, considering the seven statutory
factors discussed previously. (42 U.S.C. 6295(o)(2)(B)(i)) The new or
amended standard must also result in significant conservation of
energy. (42 U.S.C. 6295(o)(3)(B))
For this NOPR, DOE considered the impacts of amended standards for
each type of distribution transformer at each TSL, beginning with the
maximum technologically feasible level, to determine whether that level
was economically justified. Where the max-tech level was not justified,
DOE then considered the next most efficient level and undertook the
same evaluation until it reached the highest efficiency level that is
both technologically feasible and economically justified and saves a
significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens for
each type of equipment for each TSL, tables in this section present a
summary of the results of DOE's quantitative analysis for each TSL. In
addition to the quantitative results presented in the tables, DOE also
considers other burdens and benefits that affect economic
justification. These include the impacts on identifiable subgroups of
consumers who may be disproportionately affected by a national standard
and impacts on employment.
DOE also notes that the economics literature provides a wide-
ranging discussion of how consumers trade off upfront costs and energy
savings in the absence of government intervention. Much of this
literature attempts to explain why consumers appear to undervalue
energy efficiency improvements. There is evidence that consumers
undervalue future energy savings as a result of (1) entrenched
purchasing practices, (2) a lack of sufficient salience of the long-
term or aggregate benefits, (3) a lack of sufficient savings to warrant
delaying or altering purchases, (4) excessive focus on the short term,
in the form of inconsistent weighting of future energy cost savings
relative to available returns on other investments, (5) computational
or other difficulties associated with the evaluation of relevant
tradeoffs, and (6) a divergence in incentives. For example, in the case
of dry-type distribution transformers the purchaser is often not the
operator of the equipment. Instead, they are often installed at the
time of building construction and operated by tenants. In other
circumstances where the owner is the operator, distribution
transformers are often purchased based on lowest first cost (see
section IV.F.3) rather than equipment efficiency. Having less than
perfect foresight and a high degree of uncertainty about the future,
consumers may trade off these types of investments at a higher than
expected rate between current consumption and uncertain future energy
cost savings.
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed
Distribution Transformers Standards
Table V.70 and Table V.71 summarize the quantitative impacts
estimated for each TSL for liquid-immersed distribution transformers.
The national impacts are measured over the lifetime of distribution
transformers purchased in the 30-year period that begins in the
anticipated year of compliance with amended standards (2027-2056). The
energy savings, emissions reductions, and value of emissions reductions
refer to full-fuel-cycle results. The efficiency levels contained in
each TSL are described in section V.A of this document. Table V.71
shows the consumer impacts as equipment classes, which are the shipment
weighted average results of each equipment class's representative
units. The consumer results for each representative unit and
information on the fraction of shipments they represent are shown in
section B.1.
[[Page 1830]]
Table V.70--Summary of Analytical Results for Liquid-Immersed Distribution Transformers TSLs: National Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
----------------------------------------------------------------------------------------------------------------
Cumulative FFC National Energy Savings
----------------------------------------------------------------------------------------------------------------
Quads........................... 3.22 5.06 7.43 8.02 8.45
----------------------------------------------------------------------------------------------------------------
Cumulative FFC Emissions Reduction
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 101.85 159.77 235.44 256.27 269.69
CH4 (thousand tons)............. 733.07 1149.83 1695.46 1846.56 1946.92
N2O (thousand tons)............. 0.92 1.45 2.14 2.32 2.44
NOX (thousand tons)............. 160.27 251.40 370.62 403.57 425.24
SO2 (thousand tons)............. 39.65 62.21 91.65 99.71 104.82
Hg (tons)....................... 0.26 0.41 0.60 0.65 0.68
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 4.06 6.08 10.17 12.77 18.51
Climate Benefits *.............. 3.44 5.40 7.96 8.66 9.12
Health Benefits **.............. 6.19 9.71 14.31 15.57 16.40
Total Benefits [dagger]......... 13.70 21.19 32.43 37.01 44.03
Consumer Incremental Product 1.09 1.93 4.67 7.48 24.76
Costs [Dagger].................
Consumer Net Benefits........... 2.98 4.15 5.50 5.30 -6.25
Total Net Benefits.............. 12.61 19.26 27.76 29.53 19.27
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 1.36 2.04 3.40 4.28 6.20
Climate Benefits *.............. 3.44 5.40 7.96 8.66 9.12
Health Benefits **.............. 1.86 2.92 4.31 4.69 4.94
Total Benefits [dagger]......... 6.67 10.36 15.67 17.63 20.26
Consumer Incremental Product 0.58 1.04 2.51 4.02 13.31
Costs [Dagger].................
Consumer Net Benefits........... 0.78 1.00 0.89 0.26 -7.11
Total Net Benefits.............. 6.08 9.32 13.16 13.61 6.95
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the equipment shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-
percent and 7-percent cases are presented using the average SC-GHG with 3-percent discount rate, but the
Department does not have a single central SC-GHG point estimate. DOE emphasizes the importance and value of
considering the benefits calculated using all four SC-GHG estimates. See Table V.69 for net benefits using all
four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
Table V.71--Summary of Analytical Results for Liquid-Immersed Distribution Transformers TSLs: Manufacturer and
Consumer Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 * TSL 2 * TSL 3 * TSL 4 * TSL 5 *
----------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
----------------------------------------------------------------------------------------------------------------
Industry NPV (million 2021$) (No- 1,283 to 1,297 1,242 to 1,268 1,166 to 1,232 1,133 to 1,233 1,004 to 1,347
new-standards case INPV =
$1,384 million)................
Industry NPV (% change)......... (7.3) to (6.3) (10.3) to (15.8) to (18.1) to (27.5) to
(8.4) (11.0) (10.9) (2.7)
----------------------------------------------------------------------------------------------------------------
Consumer Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
Equipment Class 1 *............. 105 135 147 120 (269)
Equipment Class 2 *............. 321 658 887 868 (2,493)
Equipment Class 12 *............ n.a. n.a. n.a. n.a. (7,482)
[[Page 1831]]
Shipment-Weighted Average **.... 120 172 199 172 (425)
----------------------------------------------------------------------------------------------------------------
Consumer Simple PBP (years)
----------------------------------------------------------------------------------------------------------------
Equipment Class 1............... 19.0 16.3 7.4 11.4 31.7
Equipment Class 2............... 20.8 18.7 12.1 12.5 24.6
Equipment Class 12.............. n.a. n.a. n.a. n.a. 36.0
Shipment-Weighted Average **.... 19 16 8 12 31
----------------------------------------------------------------------------------------------------------------
Percent of Consumers that Experience a Net Cost
----------------------------------------------------------------------------------------------------------------
Equipment Class 1............... 32 27 17 18 87
Equipment Class 2............... 39 54 26 19 64
Equipment Class 12.............. n.a. n.a. n.a. n.a. 95
Shipment-Weighted Average **.... 28 21 21 18 70
----------------------------------------------------------------------------------------------------------------
Parentheses indicate negative (-) values. The entry ``n.a.'' means not applicable because there is no change in
the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class's
representative units. The consumer results for each representative unit and information on the fraction of
shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment
class in total projected shipments in 2022.
First, DOE considered TSL 5, which represents the max-tech
efficiency levels. TSL 5 would save an estimated 8.45 quads of energy,
an amount DOE considers significant. Under TSL 5, the NPV of consumer
benefit would be $-7.11 billion using a discount rate of 7 percent, and
$-6.25 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 269.69 Mt of
CO2, 104.82 thousand tons of SO2, 425.24 thousand
tons of NOX, 0.68 tons of Hg, 1946.92 thousand tons of
CH4, and 2.44 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $9.12 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $4.94 billion using a 7-percent discount rate and $16.40
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $6.95
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $19.27 billion.
At TSL 5, the average LCC impact ranges from $-269 for equipment
class 1 to $-7,482 for equipment class 12. The median PBP ranges from
24.6 years for equipment class 2 to 36.0 for equipment class 12. The
fraction of consumers experiencing a net LCC cost ranges from 64
percent for equipment class 2 to 95 percent for equipment class 12.
At TSL 5, the projected change in INPV ranges from a decrease of
$380.7 million to a decrease of $37.2 million, which corresponds to a
change in INPV of -27.5 percent and -2.7 percent, respectively. DOE
estimates that industry must invest $289.4 million to comply with
standards set at TSL 5.
The Secretary tentatively concludes that at TSL 5 for liquid-
immersed distribution transformers, the benefits of energy savings,
emission reductions, and the estimated monetary value of the emissions
reductions would be outweighed by the economic burden on many consumers
as indicated by lengthy PBPs, the percentage of customers who would
experience LCC increases, negative consumer NPV at both 3 and 7 percent
discount rates, and the capital and engineering costs that would result
in a reduction in INPV for manufacturers. At TSL 5, the LCC savings are
negative for most liquid-immersed distribution transformers, indicating
there is a substantial risk that a disproportionate number of consumers
will incur increased costs; these costs are also reflected in simple
payback period estimates that approach or exceed average lifetimes.
NPVs are calculated for equipment shipped over the period of 2027
through 2056 (see section IV.H.3). Distribution transformers are
durable equipment with a maximum lifetime estimated at 60 years (see
section IV.F.8), accruing operating cost savings through 2115. When
considered over this time period, the discounted value of the
incremental equipment costs outweigh the discounted value of the
operating costs savings. Incremental equipment costs are incurred in
the first year of equipment life, while operating cost savings occur
throughout the equipment lifetime, with later years heavily discounted.
Further, there is risk of greater reduction in INPV at max-tech if
manufacturers maintain their operating profit in the presence of
amended efficiency standards on account of having higher costs but
similar profits. The benefits of max-tech efficiency levels for liquid-
immersed distribution transformer do not outweigh the negative impacts
to consumers and manufacturers. Consequently, the Secretary has
tentatively concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4, which would save an estimated 8.02
quads of energy, an amount DOE considers significant. Under TSL 4, the
NPV of consumer benefit would be $0.26 billion using a discount rate of
7 percent, and $5.30 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 256.27 Mt of
CO2, 99.71 thousand tons of SO2, 403.57 thousand
tons of NOX, 0.65 tons of Hg, 1,846.56 thousand tons of
CH4, and 2.32 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $8.66 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 4 is $4.69 billion using a 7-percent discount rate and $15.57
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount
[[Page 1832]]
rate case for climate benefits from reduced GHG emissions, the
estimated total NPV at TSL 4 is $13.61 billion. Using a 3-percent
discount rate for all benefits and costs, the estimated total NPV at
TSL 4 is $29.53 billion.
At TSL 4, the average LCC impact ranges from $120 for equipment
class 1 to $868 for equipment class 2. The mean PBP ranges from 11.4
years for equipment class 1 to 12.5 years for equipment class 2, well
below the average lifetime of 32 years. The fraction of consumers
experiencing a net LCC cost ranges is 18 percent for equipment classes
1 and 2.
At TSL 4, the projected change in INPV ranges from a decrease of
$251.3 million to a decrease of $151.0 million, which corresponds to
decreases of 18.1 percent and 10.9 percent, respectively. DOE estimates
that industry must invest $270.6 million to comply with standards set
at TSL 4.
After considering the analysis and weighing the benefits and
burdens, the Secretary has tentatively concluded that a standard set at
TSL 4 for liquid-immersed distribution transformers would be
economically justified. Notably, the benefits to consumers outweigh the
cost to manufacturers. At this TSL, the average LCC savings are
positive across all equipment classes. An estimated 18 percent of
liquid-immersed distribution transformer consumers experience a net
cost. The FFC national energy savings are significant and the NPV of
consumer benefits is positive using both a 3-percent and 7-percent
discount rate. At TSL 4, the NPV of consumer benefits, even measured at
the more conservative discount rate of 7 percent is larger than the
maximum estimated manufacturers' loss in INPV. The standard levels at
TSL 4 are economically justified even without weighing the estimated
monetary value of emissions reductions. When those emissions reductions
are included--representing $8.66 billion in climate benefits
(associated with the average SC-GHG at a 3-percent discount rate), and
$15.57 billion (using a 3-percent discount rate) or $4.69 billion
(using a 7-percent discount rate) in health benefits--the rationale
becomes stronger still.
The energy savings under TSL 4 are primarily achievable by using
amorphous steel. Both global and domestic capacity of amorphous steel
is greater than it was during the consideration of the April 2013
Standards Final Rule and global capacity of amorphous steel (estimated
to be approximately 150,000-250,000 metric tons) is approximately equal
to the U.S. demand for electrical steel in distribution transformer
applications (estimated to be approximately 225,000 metric tons).
Further, amorphous capacity grew in response to the April 2013
Standards Final Rule, although market demand did not necessarily grow
in-kind. Further, amorphous steel manufacturers' response to the April
2013 Standards Final Rule demonstrates that amorphous capacity can be
added quickly and would be added in response to an amended standard.
Stakeholders have expressed willingness to increase supply to match any
potential demand created by an amended efficiency standard. In the
current market, increased capacity of amorphous steel is limited more
by the demand for amorphous steel rather than any constraints on
potential production capacity. Therefore, in the presence of an amended
standard, it is expected that amorphous capacity would quickly rise to
meet demand before the effective date of any amended energy
conservation standards.
While there has historically been concern over the fact that there
is only a single domestic supplier of amorphous steel, the GOES market
is also served by a single domestic supplier. Stakeholders have noted
that sufficient domestic supply of GOES is available only for M3 steel.
Any efficiency standard that requires steel with lower no-load losses
than M3 would not be able to be served entirely by a domestic source
without further investment. The current market of electrical steel in
distribution transformer applications is very much a global market at
present.
Further, while some stakeholders have expressed concern as to
whether amorphous supply would be sufficient to serve the entire
market, stakeholders have also expressed supply concerns regarding
GOES. Notably, stakeholders have identified increased competition for
non-oriented electrical steel to serve the electric vehicle market.
This competing demand is not expected to disappear in the near term and
stakeholders have already seen supply challenges for many of the higher
performing GOES grades. Amorphous steel has not been commercialized in
electric motor applications and as such, does not experience the same
competing demand for electric vehicle applications. The increased
demand for non-oriented electrical steel also offers an alternative for
current producers of GOES steel to transition their production to non-
oriented electrical steel, meeting a needed market demand.
The consistent practice of distribution transformer customers to
lightly-load their distribution transformers (see section IV.E.1.a),
means that the majority of energy savings are associated with reducing
no-load losses. While higher grades of GOES may have slightly improved
no-load loss characteristics, amorphous steel tends to reduce no-load
losses by over 60 percent. Meaning, even if the best performing grades
of GOES were available in unlimited quantities, amorphous steel would
still lead to significant energy savings. Further, by nature of DOE
evaluating efficiency of liquid-immersed distribution transformers at
50 percent load, even if loading increases such that in-service RMS
average PUL is 50 percent, the distribution transformers produced under
the amended efficiency standard would be more efficient than minimally
efficient transformers on the market today.
The transition from GOES cores to amorphous cores does require some
amount of investment on the part of the distribution transformer
manufacturer if they produce their own cores. While these costs are not
trivial, the benefit to consumers vastly outweighs the cost to
manufacturers. Further, the increased practice of outsourcing
distribution transformer core production means that there is little
burden on small businesses, who overwhelmingly purchase prefabricated
distribution transformer cores, rather than producing them in-house. As
stated, DOE conducts the ``walk-down'' analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA. The walk-down is not a comparative analysis, as a comparative
analysis would result in the maximization of net benefits instead of
energy savings that are technologically feasible and economically
justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE considered proposed amended standard levels for
distribution transformers by grouping the efficiency levels for each
equipment class into TSLs, DOE evaluates all analyzed efficiency levels
in its analysis. The TSLs constructed by DOE to examine the impacts of
amended energy efficiency standards for liquid-immersed distribution
transformers align with the corresponding ELs defined in the
engineering analysis. For the ELs above baseline that compose TSL 4 DOE
finds that LCC savings are positive for all equipment classes, with
simple paybacks well below the average equipment lifetimes. DOE also
finds that the estimated fraction of consumers who would be negatively
impacted from a
[[Page 1833]]
standard at TSL 4 to be 18 percent for all equipment classes.
For liquid-immersed distribution transformers (including single-
phase and three-phase equipment) TSL 4 (i.e., the proposed TSL)
represents a 20 percent reduction in losses over the current standard,
with the exception of submersible liquid-immersed distribution
transformers (equipment class 12) which remain at baseline.
Therefore, based on the previous considerations, DOE proposes to
adopt the energy conservation standards for liquid-immersed
distribution transformers at TSL 4. The proposed amended energy
conservation standards for distribution transformers, which are
expressed as percentage efficiency at 50 percent PUL are shown in Table
V.72.
Table V.72--Proposed Amended Energy Conservation Standards for Liquid-Immersed Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electrical efficiency by kVA and Equipment class
---------------------------------------------------------------------------------------------------------------------------------------------------------
Equipment class 1 Equipment class 2 Equipment class 12
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase Single-phase submersible Three-phase submersible
--------------------------------------------------------------------------------------------------------------------------------------------------------
kVA kVA kVA kVA
--------------------------------------------------------------------------------------------------------------------------------------------------------
10...................................... 98.96 15 98.92 10 98.70 15 98.65
15...................................... 99.05 30 99.06 15 98.82 30 98.83
25...................................... 99.16 45 99.13 25 98.95 45 98.92
37.5.................................... 99.24 75 99.22 37.5 99.05 75 99.03
50...................................... 99.29 112.5 99.29 50 99.11 112.5 99.11
75...................................... 99.35 150 99.33 75 99.19 150 99.16
100..................................... 99.40 225 99.38 100 99.25 225 99.23
167..................................... 99.46 300 99.42 167 99.33 300 99.27
250..................................... 99.51 500 99.48 250 99.39 500 99.35
333..................................... 99.54 750 99.52 333 99.43 750 99.40
500..................................... 99.59 1,000 99.54 500 99.49 1,000 99.43
667..................................... 99.62 1,500 99.58 667 99.52 1,500 99.48
833..................................... 99.64 2,000 99.61 833 99.55 2,000 99.51
2,500 99.62 .............. .............. 2,500 99.53
3,750 99.66 .............. .............. .............. ..............
5,000 99.68 .............. .............. .............. ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-Type
Distribution Transformers Standards
Table V.73 and Table V.74 summarize the quantitative impacts
estimated for each TSL for low-voltage dry-type distribution
transformers. The national impacts are measured over the lifetime of
distribution transformers purchased in the 30-year period that begins
in the anticipated year of compliance with amended standards (2027-
2056). The energy savings, emissions reductions, and value of emissions
reductions refer to full-fuel-cycle results. The efficiency levels
contained in each TSL are described in section V.A of this document.
Table V.74 shows the consumer impacts as Equipment classes, which are
the shipment weighted average results of each Equipment class's
representative units. The consumer results for each representative unit
and information on the fraction of shipments they represent are shown
in section B.1.
Table V.73--Summary of Analytical Results for Low-Voltage Dry-Type Distribution Transformers TSLs: National
Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
----------------------------------------------------------------------------------------------------------------
Cumulative FFC National Energy Savings
----------------------------------------------------------------------------------------------------------------
Quads........................... 0.37 0.54 0.85 2.28 2.47
----------------------------------------------------------------------------------------------------------------
Cumulative FFC Emissions Reduction
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 11.59 16.87 26.81 71.58 77.57
CH4 (thousand tons)............. 84.76 123.42 196.22 523.53 567.30
N2O (thousand tons)............. 0.10 0.15 0.24 0.64 0.70
NOX (thousand tons)............. 18.44 26.85 42.69 113.91 123.44
SO2 (thousand tons)............. 4.45 6.48 10.30 27.51 29.81
Hg (tons)....................... 0.03 0.04 0.07 0.18 0.19
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 1.42 2.07 3.26 12.88 13.45
Climate Benefits *.............. 0.41 0.60 0.96 2.56 2.77
Health Benefits **.............. 0.73 1.07 1.70 4.53 4.91
Total Benefits [dagger]......... 2.57 3.74 5.92 19.97 21.13
Consumer Incremental Product -0.06 -0.03 1.39 3.16 3.82
Costs [Dagger].................
Consumer Net Benefits........... 1.48 2.11 1.87 9.72 9.63
[[Page 1834]]
Total Net Benefits.............. 2.63 3.78 4.52 16.81 17.31
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 0.50 0.72 1.14 4.49 4.69
Climate Benefits *.............. 0.41 0.60 0.96 2.56 2.77
Health Benefits **.............. 0.23 0.33 0.53 1.42 1.53
Total Benefits [dagger]......... 1.14 1.66 2.63 8.46 8.99
Consumer Incremental Product -0.03 -0.02 0.75 1.70 2.05
Costs [Dagger].................
Consumer Net Benefits........... 0.53 0.74 0.39 2.79 2.63
-------------------------------------------------------------------------------
Total Net Benefits.............. 1.17 1.68 1.88 6.77 6.94
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the equipment shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-
percent and 7-percent cases are presented using the average SC-GHG with 3-percent discount rate, but the
Department does not have a single central SC-GHG point estimate. DOE emphasizes the importance and value of
considering the benefits calculated using all four SC-GHG estimates. See Table V.69 for net benefits using all
four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
Table V.74--Summary of Analytical Results for Low-Voltage Dry-Type Distribution Transformers TSLs: Manufacturer
and Consumer Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 * TSL 2 * TSL 3 * TSL 4 * TSL 5 *
----------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
----------------------------------------------------------------------------------------------------------------
Industry NPV (million 2021$) (No- 189 188 to 189 167 to 177 145 to 168 133 to 161
new-standards case INPV = $194
million........................
Industry NPV (% change)......... (2.8) (3.0) to (2.5) (13.9) to (25.3) to (31.4) to
(8.7) (13.6) (17.2)
----------------------------------------------------------------------------------------------------------------
Consumer Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
Equipment Class 3 *............. 312 203 146 108 147
Equipment Class 4 *............. 357 381 214 624 574
Shipment-Weighted Average **.... 311 315 179 492 459
----------------------------------------------------------------------------------------------------------------
Consumer Simple PBP (years)
----------------------------------------------------------------------------------------------------------------
Equipment Class 3 *............. 0.0 3.3 7.6 11.7 11.7
Equipment Class 4 *............. 0.3 0.7 8.6 7.8 9.1
Shipment-Weighted Average **.... 0.3 1.0 7.6 7.4 8.4
----------------------------------------------------------------------------------------------------------------
Percent of Consumers that Experience a Net Cost
----------------------------------------------------------------------------------------------------------------
Equipment Class 3 *............. 1 17 33 43 40
Equipment Class 4 *............. 8 9 30 10 16
Shipment-Weighted Average **.... 7 9 27 13 17
----------------------------------------------------------------------------------------------------------------
Parentheses indicate negative (-) values. The entry ``n.a.'' means not applicable because there is no change in
the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class's
representative units. The consumer results for each representative unit and information on the fraction of
shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment
class in total projected shipments in 2022
[[Page 1835]]
First, DOE considered TSL 5, which represents the max-tech
efficiency levels. TSL 5 would save an estimated 2.47 quads of energy,
an amount DOE considers significant. Under TSL 5, the NPV of consumer
benefit would be $2.63 billion using a discount rate of 7 percent, and
$9.63 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 77.57 Mt of
CO2, 29.81 thousand tons of SO2, 123.44 thousand
tons of NOX, 0.19 tons of Hg, 567.30 thousand tons of
CH4, and 0.70 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $2.77 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $1.53 billion using a 7-percent discount rate and $4.91
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $6.94
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $17.31 billion.
At TSL 5, the average LCC impact ranges from $147 for equipment
class 3 to $574 for equipment class 4. The median PBP ranges from 9.1
years for equipment class 4 to 11.7 years for equipment class 3. The
fraction of consumers experiencing a net LCC cost ranges from 16
percent for equipment class 4 to 40 percent for equipment class 3.
At TSL 5, the projected change in INPV ranges from a decrease of
$61.0 million to a decrease of $33.5 million, which corresponds to
decreases of 31.4 percent and 17.2 percent, respectively. DOE estimates
that industry must invest $69.4 million to comply with standards set at
TSL 5.
After considering the analysis and weighing the benefits and
burdens, the Secretary has tentatively concluded that at a standard set
at TSL 5 for low-voltage dry-type distribution transformers would be
economically justified. At this TSL, the average LCC savings are
positive across all equipment classes. An estimated 16 percent of
equipment class 4 to 40 percent of equipment class 3 low-voltage dry-
type distribution transformer consumers experience a net cost. The FFC
national energy savings are significant and the NPV of consumer
benefits is positive using both a 3-percent and 7-percent discount
rate. Notably, the benefits to consumers vastly outweigh the cost to
manufacturers. At TSL 5, the NPV of consumer benefits, even measured at
the more conservative discount rate of 7 percent is over 43.15 times
higher than the maximum estimated manufacturers' loss in INPV. The
standard levels at TSL 5 are economically justified even without
weighing the estimated monetary value of emissions reductions. When
those emissions reductions are included--representing $2.77 billion in
climate benefits (associated with the average SC-GHG at a 3-percent
discount rate), and $4.91 billion (using a 3-percent discount rate) or
$1.53 billion (using a 7-percent discount rate) in health benefits--the
rationale becomes stronger still.
The energy savings under TSL 5 are primarily achievable by using
amorphous steel. Both global and domestic capacity of amorphous steel
is greater than it was during the consideration of the April 2013
Standards Final Rule and global capacity of amorphous (estimated to be
approximately 150,000-250,000 metric tons) is approximately equal to
the U.S. demand for electrical steel in distribution transformer
applications (estimated to be approximately 225,000 metric tons).
Further, amorphous capacity grew in response to the April 2013
Standards Final Rule, although market demand did not necessarily grow
in-kind. As such, there is currently excess amorphous steel capacity.
Amorphous manufacturers response to the April 2013 Standards Final Rule
demonstrates that amorphous capacity can be added quickly and is
limited more by the market demand for amorphous steel rather that the
ability to build out new supply. Stakeholders have expressed
willingness to increase supply to match any potential demand created by
an amended efficiency standard. The majority of electrical steel use in
distribution transformer applications is associated with liquid-
immersed distribution transformer. Therefore, a proposed standard for
liquid-immersed distribution transformers that requires amorphous steel
would result in amorphous capacity quickly rising to meet demand before
the effective date of any amended energy conservation standards. The
increased amorphous capacity would then be able to serve both the
liquid-immersed and the low-voltage dry-type market.
As discussed in section V.C.1, the consistent practice of
distribution transformer customers to lightly-load their distribution
transformers, means that the majority of energy savings are associated
with reducing no-load losses. While higher grades of GOES may have
slightly improved no-load loss characteristics, amorphous steel tends
to reduce no-load losses by over 60 percent. By nature of DOE
evaluating efficiency of low-voltage dry-type distribution transformers
at 35 percent load, even if loading increases such that in-service RMS
average PUL is 35 percent, the distribution transformers produced under
the amended efficiency standard would be more efficient than minimally
efficient transformers on the market today.
As stated, DOE conducts the walk-down analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA.
Although DOE considered proposed amended standard levels for
distribution transformers by grouping the efficiency levels (ELs) for
each equipment class into TSLs, DOE evaluates all analyzed efficiency
levels in its analysis. For low-voltage dry-type distribution
transformers, TSL 5 (i.e., the proposed TSL) maps directly to EL 5 for
each equipment class and represents a 50 percent reduction in losses
over the current standard for single-phase distribution transformers,
and a 40 percent reduction in losses over the current standard for
three-phase distribution transformers.
Therefore, based on the previous considerations, DOE proposes to
adopt the energy conservation standards for low-voltage dry-type
distribution transformers at TSL 5. The proposed amended energy
conservation standards for low-voltage dry-type distribution
transformers, which are expressed as percentage efficiency at 35
percent PUL are shown in Table V.75.
[[Page 1836]]
Table V.75--Proposed Amended Energy Conservation Standards for Low-Voltage Dry-Type Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Equipment class 3 Equipment class 4
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA kVA
----------------------------------------------------------------------------------------------------------------
15........................................... 98.84 15.............................. 98.72
25........................................... 98.99 30.............................. 98.93
37.5......................................... 99.09 45.............................. 99.03
50........................................... 99.14 75.............................. 99.16
75........................................... 99.24 112.5........................... 99.24
100.......................................... 99.30 150............................. 99.29
167.......................................... 99.35 225............................. 99.36
250.......................................... 99.40 300............................. 99.41
333.......................................... 99.45 500............................. 99.48
750............................. 99.54
1,000........................... 99.57
----------------------------------------------------------------------------------------------------------------
3. Benefits and Burdens of TSLs Considered for Medium-Voltage Dry-Type
Distribution Transformers Standards
Table V.76 and Table V.77 summarize the quantitative impacts
estimated for each TSL for medium-voltage dry-type distribution
transformers. The national impacts are measured over the lifetime of
distribution transformers purchased in the 30-year period that begins
in the anticipated year of compliance with amended standards (2027-
2056). The energy savings, emissions reductions, and value of emissions
reductions refer to full-fuel-cycle results. The efficiency levels
contained in each TSL are described in section V.A of this document.
Table V.77 shows the consumer impacts as equipment classes, which are
the shipment weighted average results of each equipment class's
representative units. The consumer results for each representative unit
and information on the fraction of shipments they represent are shown
in section B.1.
Table V.76--Summary of Analytical Results for Medium-Voltage Dry-Type Distribution Transformers TSLs: National
Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5
----------------------------------------------------------------------------------------------------------------
Cumulative FFC National Energy Savings
----------------------------------------------------------------------------------------------------------------
Quads........................... 0.08 0.12 0.40 0.53 0.63
----------------------------------------------------------------------------------------------------------------
Cumulative FFC Emissions Reduction
----------------------------------------------------------------------------------------------------------------
CO2 (million metric tons)....... 2.53 3.71 12.68 16.48 19.72
CH4 (thousand tons)............. 18.59 27.29 93.13 121.07 144.90
N2O (thousand tons)............. 0.02 0.03 0.11 0.15 0.18
NOX (thousand tons)............. 4.04 5.93 20.24 26.31 31.49
SO2 (thousand tons)............. 0.97 1.43 4.87 6.33 7.58
Hg (tons)....................... 0.01 0.01 0.03 0.04 0.05
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (3% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 0.28 0.41 2.12 2.50 2.72
Climate Benefits *.............. 0.09 0.13 0.45 0.59 0.71
Health Benefits **.............. 0.16 0.24 0.80 1.04 1.25
Total Benefits [dagger]......... 0.53 0.77 3.38 4.13 4.67
Consumer Incremental Product 0.02 0.19 0.87 1.19 1.76
Costs [Dagger].................
Consumer Net Benefits........... 0.26 0.21 1.25 1.30 0.96
Total Net Benefits.............. 0.51 0.58 2.50 2.94 2.92
----------------------------------------------------------------------------------------------------------------
Present Value of Benefits and Costs (7% discount rate, billion 2021$)
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings. 0.10 0.14 0.74 0.87 0.95
Climate Benefits *.............. 0.09 0.13 0.45 0.59 0.71
Health Benefits **.............. 0.05 0.07 0.25 0.33 0.39
Total Benefits [dagger]......... 0.24 0.35 1.44 1.79 2.04
Consumer Incremental Product 0.01 0.10 0.47 0.64 0.94
Costs [Dagger].................
Consumer Net Benefits........... 0.09 0.04 0.27 0.23 0.00
Total Net Benefits.............. 0.23 0.24 0.97 1.14 1.10
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the equipment shipped in 2027-2056.
[[Page 1837]]
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SO2 and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. Total benefits for both the 3-
percent and 7-percent cases are presented using the average SC-GHG with 3-percent discount rate, but the
Department does not have a single central SC-GHG point estimate. . DOE emphasizes the importance and value of
considering the benefits calculated using all four SC-GHG estimates. See Table V.69 for net benefits using all
four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
Table V.77--Summary of Analytical Results for Medium-Voltage Dry-Type Distribution Transformers TSLs:
Manufacturer and Consumer Impacts
----------------------------------------------------------------------------------------------------------------
Category TSL 1 * TSL 2 * TSL 3 * TSL 4 * TSL 5 *
----------------------------------------------------------------------------------------------------------------
Manufacturer Impacts
----------------------------------------------------------------------------------------------------------------
Industry NPV (million 2021$) (No- 85 85 to 86 71 to 80 69 to 80 65 to 82
new-standards case INPV = $87
million........................
Industry NPV ( % change)........ (2.1) (3.0) to (0.9) (18.7) to (21.4) to (25.9) to
(8.8) (7.8) (5.9)
----------------------------------------------------------------------------------------------------------------
Consumer Average LCC Savings (2021$)
----------------------------------------------------------------------------------------------------------------
Equipment Class 6 *............. 1,227 833 (165) (985) (1,557)
Equipment Class 8 *............. 4,556 3,016 647 224 (3,727)
Equipment Class 10 *............ (1,209) (2,528) (5,704) (5,569) (9,558)
Shipment-Weighted Average \**\.. 1,594 641 (1,139) (1,348) (3,898)
----------------------------------------------------------------------------------------------------------------
Consumer Simple PBP (years)
----------------------------------------------------------------------------------------------------------------
Equipment Class 6 *............. 1.9 4.5 12.1 17.0 15.6
Equipment Class 8 *............. 0.4 1.9 13.5 14.1 18.0
Equipment Class 10 *............ 24.9 24.9 22.3 19.8 21.8
Shipment-Weighted Average **.... 7.9 8.9 14.1 13.7 16.3
----------------------------------------------------------------------------------------------------------------
Percent of Consumers that Experience a Net Cost
----------------------------------------------------------------------------------------------------------------
Equipment Class 6 *............. 7 16 48 68 59
Equipment Class 8 *............. 3 11 48 51 77
Equipment Class 10 *............ 83 83 77 82 92
Shipment-Weighted Average \**\.. 22 26 42 46 58
----------------------------------------------------------------------------------------------------------------
The entry ``n.a.'' means not applicable because there is no change in the standard at certain TSLs.
* The equipment classes, shown here are the shipment weighted average results of each equipment class's
representative units. The consumer results for each representative unit and information on the fraction of
shipments they represent are shown in section B.1.
** Scaled across the representative capacities of each equipment class and weighted by shares of each equipment
class in total projected shipments in 2022.
First, DOE considered TSL 5, which represents the max-tech
efficiency levels. TSL 5 would save an estimated 0.63 quads of energy,
an amount DOE considers significant. Under TSL 5, the NPV of consumer
benefit would be $3 million using a discount rate of 7 percent, and
$0.96 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 19.72 Mt of
CO2, 7.58 thousand tons of SO2, 31.49 thousand
tons of NOX, 0.05 tons of Hg, 144.90 thousand tons of
CH4, and 0.18 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 5 is $0.71 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 5 is $0.39 billion using a 7-percent discount rate and $1.25
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 5 is $1.10
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 5 is $2.92 billion.
At TSL 5, the average LCC impact ranges from $-9,558 for equipment
class 10 to $-1557 for equipment class 6. The mean PBP ranges from 15.6
years for equipment class 6 to 21.8 years for equipment class 10. The
fraction of consumers experiencing a net LCC cost ranges from 92
percent for equipment class 10 to 59 percent for equipment class 6.
At TSL 5, the projected change in INPV ranges from a decrease of
$22.6 million to a decrease of $5.2 million,
[[Page 1838]]
which corresponds to decreases of 25.9 percent and 5.9 percent,
respectively. DOE estimates that industry must invest $21.2 million to
comply with standards set at TSL 5.
The Secretary tentatively concludes that at TSL 5 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the economic burden on many
consumers as indicated by the negative LCCs for many equipment classes,
the percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result in a reduction in INPV
for manufacturers. At TSL 5 DOE is estimating negative benefits for a
disproportionate fraction of consumers--a shipment weighted average of
58 percent. Further DOE estimates that there is a substantial risk to
consumers, with a shipment weighted LCC savings for all MVDT equipment
of -$3,898. Consequently, the Secretary has tentatively concluded that
TSL 5 is not economically justified.
Next, DOE considered TSL 4, which would save an estimated 0.53
quads of energy, an amount DOE considers significant. Under TSL 4, the
NPV of consumer benefit would be $0.23 billion using a discount rate of
7 percent, and $1.30 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 16.48 Mt of
CO2, 6.33 thousand tons of SO2, 26.31 thousand
tons of NOX, 0.04 tons of Hg, 121.07 thousand tons of
CH4, and 0.15 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $0.59 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 4 is $0.33 billion using a 7-percent discount rate and $1.04
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 4 is $1.14
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 4 is $2.94 billion.
At TSL 4, the average LCC impact ranges from $-5,569 for equipment
class 10 to $224 for equipment class 8. The mean PBP ranges from 14.1
years for equipment class 8 to 19.8 years for equipment class 10. The
fraction of consumers experiencing a net LCC cost ranges from 51
percent for equipment class 8 to 82 percent for equipment class 10.
At TSL 4, the projected change in INPV ranges from a decrease of
$18.7 million to a decrease of $6.8 million, which corresponds to
decreases of 21.4 percent and 7.8 percent, respectively. DOE estimates
that industry must invest $19.2 million to comply with standards set at
TSL 4.
The Secretary tentatively concludes that at TSL 4 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the economic burden on many
consumers as indicated by the negative LCCs for many equipment classes,
the percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result iyn a reduction in INPV
for manufacturers. At TSL 4 DOE is estimating negative benefits for a
disproportionate fraction of consumers shipment weighted average of 53
percent. Further DOE estimates that there a substantial risk to
consumers with a shipment weighted LCC savings for all MVDT equipment
of -$1,348. Consequently, the Secretary has tentatively concluded that
TSL 4 is not economically justified.
Next, DOE considered TSL 3, which would save an estimated 0.40
quads of energy, an amount DOE considers significant. Under TSL 3, the
NPV of consumer benefit would be $0.27 billion using a discount rate of
7 percent, and $1.25 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 12.68 Mt of
CO2, 4.87 thousand tons of SO2, 20.24 thousand
tons of NOX, 0.03 tons of Hg, 93.13 thousand tons of
CH4, and 0.11 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $0.45 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 3 is $0.25 billion using a 7-percent discount rate and $0.80
billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 3 is $0.97
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 3 is $2.50 billion.
At TSL 3, the average LCC impact ranges from $-5,704 for equipment
class 10 to $647 for equipment class 8. The mean PBP ranges from
12.1years for equipment class 6 to 22.3 years for equipment class 10.
The fraction of consumers experiencing a net LCC cost ranges from 77
percent for 10 to 48 percent for both equipment class 6 and 8.
At TSL 3, the projected change in INPV ranges from a decrease of
$16.3 million to a decrease of $7.7 million, which corresponds to
decreases of 18.7 percent and 8.8 percent, respectively. DOE estimates
that industry must invest $17.9 million to comply with standards set at
TSL 3.
The Secretary tentatively concludes that at TSL 3 for medium-
voltage dry-type distribution transformers, the benefits of energy
savings, emission reductions, and the estimated monetary value of the
emissions reductions would be outweighed by the economic burden on many
consumers as indicated by the negative LCCs for many equipment classes,
the percentage of customers who would experience LCC increases, and the
capital and engineering costs that could result in a reduction in INPV
for manufacturers. At TSL 3 DOE is estimating negative benefits for a
disproportionate fraction of consumers shipment weighted average of 50
percent. Further DOE estimates that there a substantial risk to
consumers with a shipment weighted LCC savings for all MVDT equipment
of -$1,139. Consequently, the Secretary has tentatively concluded that
TSL 3 is not economically justified.
Next, DOE considered TSL 2, which would save an estimated 0.12
quads of energy, an amount DOE considers significant. Under TSL 2, the
NPV of consumer benefit would be $0.04 billion using a discount rate of
7 percent, and $0.21 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 2 are 3.71 Mt of
CO2, 1.43 thousand tons of SO2, 5.93 thousand
tons of NOX, 0.01 tons of Hg, 27.29 thousand tons of
CH4, and 0.03 thousand tons of N2O. The estimated
monetary value of the climate benefits from reduced GHG emissions
(associated with the average SC-GHG at a 3-percent discount rate) at
TSL 4 is $0.13 billion. The estimated monetary value of the health
benefits from reduced SO2 and NOX emissions at
TSL 2 is $0.07 billion using a 7-percent discount rate and $0.24
billion using a 3-percent discount rate.
[[Page 1839]]
Using a 7-percent discount rate for consumer benefits and costs,
health benefits from reduced SO2 and NOX
emissions, and the 3-percent discount rate case for climate benefits
from reduced GHG emissions, the estimated total NPV at TSL 2 is $0.24
billion. Using a 3-percent discount rate for all benefits and costs,
the estimated total NPV at TSL 2 is $0.58 billion.
At TSL 2, the average LCC impact ranges from -$2,528 for equipment
class 10 to $3,016 for equipment class 8. The mean PBP ranges from 1.9
years for equipment class 8 to 24.9 years for equipment class 10, which
is below the mean lifetime of 32 years. The fraction of consumers
experiencing a net LCC cost ranges from 11 percent for equipment class
8 to 83 percent for equipment class 10.
At TSL 2, the projected change in INPV ranges from a decrease of
$2.7 million to a decrease of $0.8 million, which corresponds to
decreases of 3.0 percent and 0.9 percent, respectively. DOE estimates
that industry must invest $3.1 million to comply with standards set at
TSL 2.
After considering the analysis and weighing the benefits and
burdens, the Secretary has tentatively concluded that at a standard set
at TSL 2 for medium-voltage distribution transformers would be
economically justified. At this TSL, the average LCC savings are
positive across all equipment classes except for equipment class 10,
with a shipment weighed average LCC for all medium-voltage dry-type
distribution transformers of $641. An estimated 11 percent of equipment
class 8 to 83 percent of equipment class 10 medium-voltage dry-type
distribution transformer consumers experience a net cost, while the
shipment weighted average of consumers who experience a net cost is 26
percent. The FFC national energy savings are significant and the NPV of
consumer benefits is positive using both a 3-percent and 7-percent
discount rate. Notably, the benefits to consumers outweigh the cost to
manufacturers. At TSL 2, the NPV of consumer benefits, even measured at
the more conservative discount rate of 7 percent is over 38.3 times
higher than the maximum estimated manufacturers' loss in INPV. The
standard levels at TSL 2 are economically justified even without
weighing the estimated monetary value of emissions reductions. When
those emissions reductions are included--representing $0.13 billion in
climate benefits (associated with the average SC-GHG at a 3-percent
discount rate), and $0.24 billion (using a 3-percent discount rate) or
$0.07 billion (using a 7-percent discount rate) in health benefits--the
rationale becomes stronger still.
As stated, DOE conducts the walk-down analysis to determine the TSL
that represents the maximum improvement in energy efficiency that is
technologically feasible and economically justified as required under
EPCA.
Although DOE considered proposed amended standard levels for
distribution by grouping the efficiency levels for each equipment class
into TSLs, DOE evaluates all analyzed efficiency levels in its
analysis. For medium-voltage dry-type distribution transformer the TSL
2 maps directly to EL 2 for all equipment classes. EL 2 represents a 10
percent reduction in losses over the current standard. While the
consumer benefits for equipment class 10 are negative at EL 2 at -
$2,528, they are positive for all other equipment representing 78
percent of all MVDT units shipped, additionally the consumer benefits
at EL 2, excluding equipment class 10, increases from $641 to $1,271 in
LCC savings Further, the EL 2 represent an improvement in efficiency
where the FFC national energy savings is maximized, with positive NPVs
at both 3 and 7 percent, and the shipment weighted average consumer
benefit at EL 2 is positive. The shipment weighted consumer benefits
for TSL, and EL 2 are shown in Table V.77.
As discussed previously, at the max-tech efficiency levels (TSL 5),
TSL 4, and TSL 3 for all medium-voltage dry-type distribution
transformers there is a substantial risk to consumers due to negative
LCC savings for most equipment, with a shipment weighted average
consumer benefit of -$3,898, -$1,348, and -$1,139, respectively, while
at TSL 2 it is $641. Therefore, DOE has tentatively concluded that the
efficiency levels above TSL 2 are not justified. Additionally, at the
examined efficiency levels greater than TSL 2 DOE is estimating that a
disproportionate fraction of consumers would be negatively impacted by
these efficiency levels. DOE estimates that shipment weighted fraction
of negatively impacted consumers for TSL 3, TSL 4, and TSL 5 (max-tech)
to be 42, 46, and 58 percent, respectively.
Therefore, based on the previous considerations, DOE proposes to
adopt the energy conservation standards for medium-voltage dry-type
distribution transformers at TSL 2. The proposed amended energy
conservation standards for medium-voltage dry-type distribution
transformers, which are expressed as percentage efficiency at 50
percent PUL are shown in Table V.78.
Table V.78--Proposed Amended Energy Conservation Standards for Medium-Voltage Dry-Type Distribution Transformers
[Electrical efficiency by kVA and equipment class]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL BIL
kVA ------------------------------------------------- kVA -----------------------------------------------
20-45 kV 46-95 kV >=96 kV 20-45 kV 46-95 kV >=96 kV
Equipment class EC5 EC7 EC9 .................... EC6 EC8 EC10
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 98.29 98.07 ............... 15.................. 97.74 97.45 ..............
25............................... 98.49 98.30 ............... 30.................. 98.11 97.86 ..............
37.5............................. 98.64 98.47 ............... 45.................. 98.29 98.07 ..............
50............................... 98.74 98.58 ............... 75.................. 98.49 98.31 ..............
75............................... 98.86 98.71 98.68 112.5............... 98.67 98.52 ..............
100.............................. 98.94 98.80 98.77 150................. 98.78 98.66 ..............
167.............................. 99.06 98.95 98.92 225................. 98.94 98.82 98.71
250.............................. 99.16 99.05 99.02 300................. 99.04 98.93 98.82
333.............................. 99.23 99.13 99.09 500................. 99.18 99.09 99.00
500.............................. 99.30 99.21 99.18 750................. 99.29 99.21 99.12
667.............................. 99.34 99.26 99.23 1000................ 99.35 99.28 99.20
833.............................. 99.38 99.31 99.28 1500................ 99.43 99.37 99.29
[[Page 1840]]
2000................ 99.49 99.42 99.35
2500................ 99.52 99.47 99.40
3750................ 99.58 99.53 99.47
5000................ 99.62 99.58 99.51
--------------------------------------------------------------------------------------------------------------------------------------------------------
4. Annualized Benefits and Costs of the Proposed Standards for Liquid-
Immersed Distribution Transformers
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2021$) of the
benefits from operating products that meet the proposed standards
(consisting primarily of operating cost savings from using less energy,
minus increases in product purchase costs, and (2) the annualized
monetary value of the climate and health benefits from emission
reductions.
Table V.79 shows the annualized values for the proposed standards
for distribution transformers, expressed in 2021$. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOX and SO2 reduction benefits, and a 3-percent
discount rate case for GHG social costs, the estimated cost of the
proposed standards for distribution transformers is $424.8 million per
year in increased equipment costs, while the estimated annual benefits
are $451.9 million from reduced equipment operating costs, $497.4
million from GHG reductions, and $495.3million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $1,019.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the proposed standards for distribution transformers
is $429.5 million per year in increased equipment costs, while the
estimated annual benefits are $7,33.5 million in reduced operating
costs, $497.4 million from GHG reductions, and $894.3 million from
reduced NOX and SO2 emissions. In this case, the
net benefit amounts to $1,695.8 million per year.
Table V.79--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Liquid-Immersed
Distribution Transformers (TSL 4)
----------------------------------------------------------------------------------------------------------------
Million 2021$/year
-----------------------------------------------
Category Low-net- High-net-
Primary benefits benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 733.5 686.9 789.9
Climate Benefits *.............................................. 497.4 478.9 519.5
Health Benefits **.............................................. 894.3 860.5 934.8
Total Benefits [dagger]......................................... 2,125.3 2,026.3 2,244.2
Consumer Incremental Equipment Costs [Dagger]................... 429.5 449.0 413.2
Net Benefits.................................................... 1,695.8 1,577.3 1,831.0
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 451.9 425.7 482.2
Climate Benefits * (3% discount rate)........................... 497.4 478.9 519.5
Health Benefits **.............................................. 495.3 477.9 515.3
Total Benefits [dagger]......................................... 1,444.7 1,382.5 1,517.0
Consumer Incremental Equipment Costs [Dagger]................... 424.8 442.1 409.9
Net Benefits.................................................... 1,019.8 940.5 1,107.2
----------------------------------------------------------------------------------------------------------------
This table presents the annualized costs and benefits associated with liquid-immersed distribution transformers
equipment shipped in 2027-2056. These results include benefits to consumers which accrue after 2055 from the
products purchased in 2027-2056.
[[Page 1841]]
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing
PM2.5 and (for NOX) ozone precursor health benefits, but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5 emissions. The health benefits are presented
at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
5. Annualized Benefits and Costs of the Proposed Standards for Low-
Voltage Distribution Transformers
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2021$) of the
benefits from operating products that meet the proposed standards
(consisting primarily of operating cost savings from using less energy,
minus increases in product purchase costs, and (2) the annualized
monetary value of the climate and health benefits from emission
reductions.
Table V.80 shows the annualized values for the proposed standards
for distribution transformers, expressed in 2021$. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOX and SO2 reduction benefits, and a 3-percent
discount rate case for GHG social costs, the estimated cost of the
proposed standards for distribution transformers is $216.9 million per
year in increased equipment costs, while the estimated annual benefits
are $495.0 million from reduced equipment operating costs, $159.2
million from GHG reductions, and $162.1 million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $599.4 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the proposed standards for distribution transformers
is $219.3 million per year in increased equipment costs, while the
estimated annual benefits are $772.1 million in reduced operating
costs, $159.2 million from GHG reductions, and $281.8 million from
reduced NOX and SO2 emissions. In this case, the
net benefit amounts to $993.8 million per year.
Table V.80--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Low-Voltage Distribution
Transformers (TSL 5)
----------------------------------------------------------------------------------------------------------------
Million 2021$/year
-----------------------------------------------
Category Low-net- High-net-
Primary benefits benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 772.1 716.9 831.3
Climate Benefits *.............................................. 159.2 151.6 165.9
Health Benefits **.............................................. 281.8 268.3 293.9
Total Benefits [dagger]......................................... 1,213.1 1,136.7 1,291.1
Consumer Incremental Product Costs [Dagger]..................... 219.3 228.7 208.7
Net Benefits.................................................... 993.8 908.0 1,082.4
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 495.0 462.8 528.7
Climate Benefits * (3% discount rate)........................... 159.2 151.6 165.9
Health Benefits **.............................................. 162.1 154.9 168.2
Total Benefits [dagger]......................................... 816.3 769.3 862.8
Consumer Incremental Product Costs [Dagger]..................... 216.9 225.2 207.3
Net Benefits.................................................... 599.4 544.1 655.5
----------------------------------------------------------------------------------------------------------------
This table presents the annualized costs and benefits associated with low-voltage dry-type distribution
transformers equipment shipped in 2027-2056. These results include benefits to consumers which accrue after
2055 from the products purchased in 2027-2056.
[[Page 1842]]
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing
PM2.5 and (for NOX) ozone precursor health benefits, but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5 emissions. The health benefits are presented
at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
6. Annualized Benefits and Costs of the Proposed Standards for Medium-
Voltage Distribution Transformers
The benefits and costs of the proposed standards can also be
expressed in terms of annualized values. The annualized net benefit is
(1) the annualized national economic value (expressed in 2021$) of the
benefits from operating products that meet the proposed standards
(consisting primarily of operating cost savings from using less energy,
minus increases in product purchase costs, and (2) the annualized
monetary value of the climate and health benefits from emission
reductions.
Table V.81 shows the annualized values for the proposed standards
for distribution transformers, expressed in 2021$. The results under
the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOX and SO2 reduction benefits, and a 3-percent
discount rate case for GHG social costs, the estimated cost of the
proposed standards for distribution transformers is $10.8 million per
year in increased equipment costs, while the estimated annual benefits
are $14.9 million from reduced equipment operating costs, $7.6 million
from GHG reductions, and $7.8 million from reduced NOX and
SO2 emissions. In this case, the net benefit amounts to
$19.5 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the proposed standards for distribution transformers
is $11.0 million per year in increased equipment costs, while the
estimated annual benefits are $23.3 million in reduced operating costs,
$7.6 million from GHG reductions, and $13.5 million from reduced
NOX and SO2 emissions. In this case, the net
benefit amounts to $33.5 million per year.
Table V.81--Annualized Benefits and Costs of Proposed Energy Conservation Standards for Medium-Voltage
Distribution Transformers (TSL 2)
----------------------------------------------------------------------------------------------------------------
Million 2021$/year
-----------------------------------------------
Category Low-net- High-net-
Primary benefits benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 23.3 22.2 25.8
Climate Benefits *.............................................. 7.6 7.5 8.2
Health Benefits **.............................................. 13.5 13.2 14.5
Total Benefits [dagger]......................................... 44.4 42.9 48.5
Consumer Incremental Product Costs [Dagger]..................... 11.0 11.7 10.7
Net Benefits.................................................... 33.5 31.1 37.7
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 14.9 14.3 16.4
Climate Benefits * (3% discount rate)........................... 7.6 7.5 8.2
Health Benefits **.............................................. 7.8 7.6 8.3
Total Benefits [dagger]......................................... 30.3 29.4 32.9
Consumer Incremental Product Costs [Dagger]..................... 10.8 11.6 10.6
Net Benefits.................................................... 19.5 17.9 22.2
----------------------------------------------------------------------------------------------------------------
This table presents the annualized costs and benefits associated with medium-voltage dry-type distribution
transformers equipment shipped in 2027-2056. These results include benefits to consumers which accrue after
2055 from the products purchased in 2027-2056.
[[Page 1843]]
Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. As reflected in this rule,
DOE has reverted to its approach prior to the injunction and present monetized greenhouse gas abatement
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. DOE is currently only monetizing
PM2.5 and (for NOX) ozone precursor health benefits, but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5 emissions. The health benefits are presented
at real discount rates of 3 and 7 percent. See section IV.L.2 of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
7. Benefits and Costs of the Proposed Standards for all Considered
Distribution Transformers
As described in sections V.C.1 through V.C.6, for this NOPR DOE is
proposing TSL 4 for liquid-immersed, TSL 5 for low-voltage dry-type,
and TSL 2 for medium-voltage dry-type distribution transformers. Table
VI.1 shows the combined cumulative benefits, and Table V.83 shows the
combined annualized benefits for the proposed levels for all
distribution transformers.
Table V.82--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for all Distribution Transformers at Proposed
Standard Levels
------------------------------------------------------------------------
Billion $2021
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings................ 26.63
Climate Benefits *............................. 11.56
Health Benefits **............................. 20.72
Total Benefits [dagger]........................ 58.91
Consumer Incremental Product Costs [Dagger].... 11.49
Net Benefits................................... 47.42
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings................ 9.11
Climate Benefits * (3% discount rate).......... 11.56
Health Benefits **............................. 6.29
Total Benefits [dagger]........................ 26.97
Consumer Incremental Product Costs [Dagger].... 6.17
Net Benefits................................... 20.79
------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution
transformers shipped in 2027-2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027-
2056.
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
Federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the Federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the
injunction and present monetized benefits where appropriate and
permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits, but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
[[Page 1844]]
Table V.8384--Annualized Benefits and Costs of Proposed Energy Conservation Standards for all Distribution
Transformers at Proposed Standard Levels
----------------------------------------------------------------------------------------------------------------
Million 2021$/year
-----------------------------------------------
Category Low-net- High-net-
Primary benefits benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 1,528.9 1,426.0 1,647.0
Climate Benefits *.............................................. 664.2 638.0 693.6
Health Benefits **.............................................. 1,189.6 1,142.0 1,243.2
Total Benefits [dagger]......................................... 3,382.8 3,205.9 3,583.8
Consumer Incremental Product Costs [Dagger]..................... 659.8 689.4 632.6
Net Benefits.................................................... 2,723.1 2,516.4 2,951.1
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 961.8 902.8 1,027.3
Climate Benefits * (3% discount rate)........................... 664.2 638.0 693.6
Health Benefits **.............................................. 665.2 640.4 691.8
Total Benefits [dagger]......................................... 2,291.3 2,181.2 2,412.7
Consumer Incremental Product Costs [Dagger]..................... 652.5 678.9 627.8
Net Benefits.................................................... 1,638.7 1,502.5 1,784.9
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the Federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the Federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the injunction and present monetized
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
D. Reporting, Certification, and Sampling Plan
Manufacturers, including importers, must use product-specific
certification templates to certify compliance to DOE. For distribution
transformers, the certification template reflects the general
certification requirements specified at 10 CFR 429.12 and the product-
specific requirements specified at 10 CFR 429.47. As discussed in the
previous paragraphs, DOE is not proposing to amend the product-specific
certification requirements for this equipment.
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866 and 13563
Executive Order (``E.O.'')12866, ``Regulatory Planning and
Review,'' as supplemented and reaffirmed by E.O. 13563, ``Improving
Regulation and Regulatory Review, 76 FR 3821 (Jan. 21, 2011), requires
agencies, to the extent permitted by law, to (1) propose or adopt a
regulation only upon a reasoned determination that its benefits justify
its costs (recognizing that some benefits and costs are difficult to
quantify); (2) tailor regulations to impose the least burden on
society, consistent with obtaining regulatory objectives, taking into
account, among other things, and to the extent practicable, the costs
of cumulative regulations; (3) select, in choosing among alternative
regulatory approaches, those approaches that maximize net benefits
(including potential economic, environmental, public health and safety,
and other advantages; distributive impacts; and equity); (4) to the
extent feasible, specify performance objectives, rather than specifying
the behavior or manner of compliance that regulated entities must
adopt; and (5) identify and assess available alternatives to direct
regulation, including providing economic incentives to encourage the
desired behavior, such as user fees or marketable permits, or providing
information upon which choices can be made by the public. DOE
emphasizes as well that E.O. 13563 requires agencies to use the best
available techniques to quantify anticipated present and future
benefits and costs as accurately as possible. In its guidance, the
Office of Information and Regulatory Affairs (``OIRA'') in the Office
of Management and Budget (``OMB'') has emphasized that such techniques
may include identifying changing future compliance costs that might
result from technological innovation or anticipated behavioral changes.
For the reasons stated in the preamble, this proposed/final regulatory
action is consistent with these principles.
[[Page 1845]]
Section 6(a) of E.O. 12866 also requires agencies to submit
``significant regulatory actions'' to OIRA for review. OIRA has
determined that this proposed regulatory action constitutes an
economically significant regulatory action under section 3(f) of E.O.
12866. Accordingly, pursuant to section 6(a)(3)(C) of E.O. 12866, DOE
has provided to OIRA an assessment, including the underlying analysis,
of benefits and costs anticipated from the proposed regulatory action,
together with, to the extent feasible, a quantification of those costs;
and an assessment, including the underlying analysis, of costs and
benefits of potentially effective and reasonably feasible alternatives
to the planned regulation, and an explanation why the planned
regulatory action is preferable to the identified potential
alternatives. These assessments are summarized in this preamble and
further detail can be found in the technical support document for this
rulemaking. A summary of the potential costs and benefits of the
regulatory action is presented in Table VI.1 and Table VI.2.
Table VI.1--Summary of Monetized Benefits and Costs of Proposed Energy
Conservation Standards for all Distribution Transformers and Proposed
Standard Levels
------------------------------------------------------------------------
Billion $2021
------------------------------------------------------------------------
3% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings................ 26.63
Climate Benefits *............................. 11.56
Health Benefits **............................. 20.72
Total Benefits [dagger]........................ 58.91
Consumer Incremental Product Costs [Dagger].... 11.49
Net Benefits................................... 47.42
------------------------------------------------------------------------
7% discount rate
------------------------------------------------------------------------
Consumer Operating Cost Savings................ 9.11
Climate Benefits * (3% discount rate).......... 11.56
Health Benefits **............................. 6.29
Total Benefits [dagger]........................ 26.97
Consumer Incremental Product Costs [Dagger].... 6.17
Net Benefits................................... 20.79
------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution
transformers shipped in 2027-2056. These results include benefits to
consumers which accrue after 2056 from the products shipped in 2027-
2056.
* Climate benefits are calculated using four different estimates of the
social cost of carbon (SC-CO2), methane (SC-CH4), and nitrous oxide
(SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate), as shown
in Table V.73, Table V.74, and Table V.75. Together these represent
the global social cost of greenhouse gases (SC-GHG). For
presentational purposes of this table, the climate benefits associated
with the average SC-GHG at a 3 percent discount rate are shown, but
the Department does not have a single central SC-GHG point estimate.
See section. IV.L of this document for more details. On March 16,
2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the
Federal government's emergency motion for stay pending appeal of the
February 11, 2022, preliminary injunction issued in Louisiana v.
Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth
Circuit's order, the preliminary injunction is no longer in effect,
pending resolution of the Federal government's appeal of that
injunction or a further court order. Among other things, the
preliminary injunction enjoined the defendants in that case from
``adopting, employing, treating as binding, or relying upon'' the
interim estimates of the social cost of greenhouse gases--which were
issued by the Interagency Working Group on the Social Cost of
Greenhouse Gases on February 26, 2021--to monetize the benefits of
reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the
injunction and present monetized benefits where appropriate and
permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX
and SO2. DOE is currently only monetizing (for SO2 and NOX) PM2.5
precursor health benefits and (for NOX) ozone precursor health
benefits, but will continue to assess the ability to monetize other
effects such as health benefits from reductions in direct PM2.5
emissions. The health benefits are presented at real discount rates of
3 and 7 percent. See section IV.L of this document for more details.
[dagger] Total and net benefits include consumer, climate, and health
benefits. For presentation purposes, total and net benefits for both
the 3-percent and 7-percent cases are presented using the average SC-
GHG with 3-percent discount rate, but the Department does not have a
single central SC-GHG point estimate. DOE emphasizes the importance
and value of considering the benefits calculated using all four SC-GHG
estimates. See Table V.69 for net benefits using all four SC-GHG
estimates.
[Dagger] Costs include incremental equipment costs as well as
installation costs.
Table VI.2--Annualized Benefits and Costs of Proposed Energy Conservation Standards for all Distribution
Transformers and Proposed Standard Levels
----------------------------------------------------------------------------------------------------------------
Million 2021$/year
-----------------------------------------------
Category Low-net- High-net-
Primary benefits benefits
estimate estimate estimate
----------------------------------------------------------------------------------------------------------------
3% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 1,528.9 1,426.0 1,647.0
Climate Benefits *.............................................. 664.2 638.0 693.6
Health Benefits **.............................................. 1,189.6 1,142.0 1,243.2
Total Benefits [dagger]......................................... 3,382.8 3,205.9 3,583.8
Consumer Incremental Product Costs [Dagger]..................... 659.8 689.4 632.6
Net Benefits.................................................... 2,723.1 2,516.4 2,951.1
----------------------------------------------------------------------------------------------------------------
7% discount rate
----------------------------------------------------------------------------------------------------------------
Consumer Operating Cost Savings................................. 961.8 902.8 1,027.3
[[Page 1846]]
Climate Benefits * (3% discount rate)........................... 664.2 638.0 693.6
Health Benefits **.............................................. 665.2 640.4 691.8
Total Benefits [dagger]......................................... 2,291.3 2,181.2 2,412.7
Consumer Incremental Product Costs [Dagger]..................... 652.5 678.9 627.8
Net Benefits.................................................... 1,638.7 1,502.5 1,784.9
----------------------------------------------------------------------------------------------------------------
This table presents the costs and benefits associated with distribution transformers shipped in 2027-2056. These
results include benefits to consumers which accrue after 2056 from the products shipped in 2027-2056.
* Climate benefits are calculated using four different estimates of the social cost of carbon (SC-CO2), methane
(SC-CH4), and nitrous oxide (SC-N2O) (model average at 2.5 percent, 3 percent, and 5 percent discount rates;
95th percentile at 3 percent discount rate), as shown in Table V.73, Table V.74, and Table V.75. Together
these represent the global social cost of greenhouse gases (SC-GHG). For presentational purposes of this
table, the climate benefits associated with the average SC-GHG at a 3 percent discount rate are shown, but the
Department does not have a single central SC-GHG point estimate. See section. IV.L of this document for more
details. On March 16, 2022, the Fifth Circuit Court of Appeals (No. 22-30087) granted the Federal government's
emergency motion for stay pending appeal of the February 11, 2022, preliminary injunction issued in Louisiana
v. Biden, No. 21-cv-1074-JDC-KK (W.D. La.). As a result of the Fifth Circuit's order, the preliminary
injunction is no longer in effect, pending resolution of the Federal government's appeal of that injunction or
a further court order. Among other things, the preliminary injunction enjoined the defendants in that case
from ``adopting, employing, treating as binding, or relying upon'' the interim estimates of the social cost of
greenhouse gases--which were issued by the Interagency Working Group on the Social Cost of Greenhouse Gases on
February 26, 2021--to monetize the benefits of reducing greenhouse gas emissions. In the absence of further
intervening court orders, DOE will revert to its approach prior to the injunction and present monetized
benefits where appropriate and permissible under law.
** Health benefits are calculated using benefit-per-ton values for NOX and SO2. The benefits are based on the
low estimates of the monetized value. DOE is currently only monetizing (for SOX and NOX) PM2.5 precursor
health benefits and (for NOX) ozone precursor health benefits, but will continue to assess the ability to
monetize other effects such as health benefits from reductions in direct PM2.5 emissions. See section IV.L of
this document for more details.
[dagger] Total and net benefits include consumer, climate, and health benefits. For presentation purposes, total
and net benefits for both the 3-percent and 7-percent cases are presented using the average SC-GHG with 3-
percent discount rate, but the Department does not have a single central SC-GHG point estimate. DOE emphasizes
the importance and value of considering the benefits calculated using all four SC-GHG estimates. See Table
V.69 for net benefits using all four SC-GHG estimates.
[Dagger] Costs include incremental equipment costs as well as installation costs.
B. Review Under the Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
preparation of an initial regulatory flexibility analysis (``IRFA'')
for any rule that by law must be proposed for public comment, unless
the agency certifies that the rule, if promulgated, will not have a
significant economic impact on a substantial number of small entities.
As required by E.O. 13272, ``Proper Consideration of Small Entities in
Agency Rulemaking,'' 67 FR 53461 (Aug. 16, 2002), DOE published
procedures and policies on February 19, 2003, to ensure that the
potential impacts of its rules on small entities are properly
considered during the rulemaking process. 68 FR 7990. DOE has made its
procedures and policies available on the Office of the General
Counsel's website www.energy.gov/gc/office-general-counsel. DOE has
prepared the following IRFA for the products that are the subject of
this rulemaking.
For manufacturers of distribution transformers, the SBA has set a
size threshold, which defines those entities classified as ``small
businesses'' for the purposes of the statute. DOE used the SBA's small
business size standards to determine whether any small entities would
be subject to the requirements of the rule. (See 13 CFR part 121.) The
size standards are listed by North American Industry Classification
System (``NAICS'') code and industry description and are available at
www.sba.gov/document/support--table-size-standards. Manufacturing of
distribution transformers is classified under NAICS 335311, ``Power,
Distribution, and Specialty Transformer Manufacturing.'' The SBA sets a
threshold of 750 employees or fewer for an entity to be considered as a
small business for this category.
1. Description of Reasons Why Action Is Being Considered
EPCA requires that, not later than 6 years after the issuance of
any final rule establishing or amending a standard, DOE must publish
either a notice of determination that standards for the product do not
need to be amended, or a NOPR including new proposed energy
conservation standards (proceeding to a final rule, as appropriate).
(42 U.S.C. 6316(e)(1); 42 U.S.C. 6295(m)(1)).
2. Objectives of, and Legal Basis for, Rule
DOE must follow specific statutory criteria for prescribing new or
amended standards for covered equipment, including distribution
transformers. Any new or amended standard for a covered product must be
designed to achieve the maximum improvement in energy efficiency that
the Secretary of Energy determines is technologically feasible and
economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A) and
42 U.S.C. 6295(o)(3)(B)).
3. Description on Estimated Number of Small Entities Regulated
DOE conducted a more focused inquiry of the companies that could be
small businesses that manufacture distribution transformers covered by
this rulemaking. DOE used publicly available information to identify
potential small businesses. DOE's research involved industry trade
association membership directories (including NEMA), DOE's publicly
available Compliance Certification Database (``CCD''), California
Energy Commission's MAEDBS database to create a list of companies that
manufacture or sell distribution transformers covered by this
rulemaking. DOE also asked stakeholders and industry representatives if
they were aware of any other small businesses during manufacturer
interviews. DOE contacted select companies on its list, as necessary,
to determine whether they met the SBA's definition of a small business
that manufacturers distribution transformers covered by this
rulemaking. DOE screened out
[[Page 1847]]
companies that did not offer products covered by this rulemaking, did
not meet the definition of a ``small business,'' or are foreign owned
and operated.
DOE's analysis identified 29 companies that sell or manufacture
distribution transformers coved by this rulemaking in the U.S. market.
At least two of these companies are not the original equipment
manufacturers (``OEM'') and instead privately label distribution
transformers that are manufactured by another distribution transformer
manufacturer. Of the 27 companies that are OEMs, DOE identified 10
potential companies that have fewer than 750 total employees and are
not entirely foreign owned and operated. There are three small
businesses that manufacture liquid-immersed distribution transformers;
there are three small businesses that manufacture LVDT and MVDT
distribution transformers; and there are four small businesses that
only manufacture LVDT distribution transformers.\115\
---------------------------------------------------------------------------
\115\ Therefore, there are a total of seven small businesses
that manufacture LVDT distribution transformers. Four that
exclusively manufacture LVDT and three that manufacture both LVDT
and MVDT.
---------------------------------------------------------------------------
Liquid-Immersed
Liquid-immersed distribution transformers account for over 80
percent of all distribution transformer shipments covered by this
rulemaking. Six major manufacturers supply more than 80 percent of the
market for liquid-immersed distribution transformers covered by this
rulemaking. None of these six major manufacturers of liquid-immersed
distribution transformers are small businesses. Most liquid-immersed
distribution transformers are manufactured domestically. Electric
utilities compose the customer base and typically buy on a first-cost
basis. Many small manufacturers position themselves towards the higher
end of the market or in particular product niches, such as network
transformers or harmonic mitigating transformers, but, in general,
competition is based on price after a given unit's specs are prescribed
by a customer. None of the three small businesses have a market share
larger than five percent of the liquid-immersed distribution
transformer market.
Low-Voltage Dry Type
LVDT distribution transformers account for approximately 18 percent
of all distribution shipments covered by this rulemaking. Four major
manufacturers supply more than 80 percent of the market for LVDT
distribution transformers covered by this rulemaking. None of these
four major LVDT distribution transformer manufacturers are small
businesses. The majority of LVDT distribution transformers are
manufactured outside the U.S., mostly in Canada and Mexico. The
customer base rarely purchases on efficiency and is very first-cost
conscious, which, in turn, places a premium on economies of scale in
manufacturing. However, there are universities and other buildings that
purchase LVDT based on efficiency as more and more organizations are
striving to get to reduced or net-zero emission targets.
In the LVDT market, lower volume manufacturers typically do not
compete directly with larger volume manufacturers, as these lower
volume manufacturers are frequently not able to compete on a first cost
basis. However, there are lower volume manufactures that do serve
customers that purchase more efficient LVDT distribution transformers.
Lastly, there are some smaller firms that focus on the engineering and
design of LVDT distribution transformers and source the production of
some parts of the distribution transformer, most frequently the cores,
to another company that manufactures those components.
Medium-Voltage Dry-Type
MVDT distribution transformers account for less than one percent of
all distribution transformer shipments covered by this rulemaking.
There is one large MVDT distribution transformer manufacturer with a
substantial share of the market. The rest of MVDT distribution
transformer market is served by a mix of large and small manufactures.
Most MVDT distribution transformers are manufactured domestically.
Electric utilities and industrial users make up most of the customer
base and typically buy on first-cost or features other than efficiency.
4. Description and Estimate of Compliance Requirements Including
Differences in Cost, if Any, for Different Groups of Small Entities
Liquid-Immersed and Low-Voltage Dry-Type
DOE is proposing to amend energy conservation standards to be at
TSL 4 for liquid-immersed distribution transformers and TSL 5 for LVDT
distribution transformers. This corresponds to EL 4 for most liquid-
immersed distribution transformer equipment classes and EL 5 for all
LVDT distribution transformer equipment classes.
Based on the LCC consumer choice model, DOE anticipates that most,
if not all, liquid-immersed and LVDT distribution transformer
manufacturers would use amorphous cores in their distribution
transformers to meet these proposed amended energy conservation
standards. While DOE anticipates that several large liquid-immersed and
LVDT distribution transformer manufacturers would make significant
capital investments to accommodate the production of amorphous cores,
DOE does not anticipate that any small businesses will make these
capital investments to be able to produce their own amorphous cores,
based on the large capital investments need to be able to make
amorphous cores and the limited ability for small businesses to access
large capital investments. Based on manufacturer interviews and market
research, DOE was able to identify one LVDT small business that
manufactures their own cores and was not able to identify any liquid-
immersed small businesses that manufacture their own cores. The one
LVDT small business that is currently manufacturing their own cores
would have to make a business decision to either make a significant
capital investment to be able to make amorphous cores or to out-source
the production of their LVDT cores. Out-sourcing the production of
their cores would be a significant change in their production process
and could result in a reduction in this small business' market share in
the LVDT distribution transformer market.
DOE acknowledges that there is uncertainty if these small
businesses will be able to find core manufacturers that will supply
them with amorphous cores in order to comply with the proposed energy
conservation standards for liquid-immersed and LVDT distribution
transformers. DOE anticipates that there will be an increase in the
number of large liquid-immersed and LVDT distribution transformer
manufacturers that will out-source the production of their cores to
core manufacturers capable of producing amorphous cores. This could
increase the competition for small businesses to procure amorphous
cores for their distribution transformers. Small businesses
manufacturing liquid-immersed and LVDT distribution transformers must
be able to procure amorphous cores suitable for their distribution
transformers at a cost that allows them to continue to be competitive
in the market.
Based on feedback received during manufacturer interviews, DOE does
not
[[Page 1848]]
anticipate that small businesses that are currently not producing their
own cores would have to make a significant capital investment in their
production lines to be able to use amorphous cores, that are purchased
from a core manufacturer, in the distribution transformers that they
manufacture. There will be some additional product conversion costs, in
the form of additional R&D and testing, that will need to be incurred
by small businesses that manufacture liquid-immersed and LVDT
distribution transformers, even if they do not manufacture their own
cores. The methodology used to calculate product conversion costs,
described in section IV.J.2.c, estimates that manufacturers would incur
approximately one additional year of R&D expenditure to redesign their
distribution transformers to be capable of accommodating the use of an
amorphous core. Based on the financial parameters used in the GRIM, DOE
estimated that the normal annual R&D is approximately 3.0 percent of
annual revenue. Therefore, liquid-immersed and LVDT small businesses
would incur an additional 3.0 percent of annual revenue to redesign
their distribution transformers to be able to accommodate using
amorphous cores there were purchased from core manufacturers.
Medium-Voltage Dry-Type
DOE is proposing to amend energy conservation standards to be at
TSL 2 for MVDT distribution transformers. This corresponds to EL 2 for
all MVDT distribution transformer equipment classes. Based on the LCC
consumer choice model, DOE does not anticipate that any MVDT
distribution transformer manufacturers would use amorphous cores in
their MVDT distribution transformers to meet these proposed energy
conservation standards. DOE does not anticipate that MVDT manufacturers
would make significant investments to either be able to produce cores
capable of meeting these proposed amended energy conservation standards
or be able to integrate more efficient purchased cores from core
manufacturers. There will be some additional product conversion costs,
in the form of additional R&D and testing, that will need to be
incurred by small businesses that manufacture MVDT distribution
transformers, even if they do not manufacture their own cores. The
methodology used to calculate product conversion costs, described in
section IV.J.2.c, estimates that manufacturers would incur
approximately a half of a year of additional R&D expenditure to
redesign their distribution transformers to higher efficiency levels,
while not using amorphous cores. Based on the financial parameters used
in the GRIM, DOE estimated that the normal annual R&D is approximately
3.0 percent of annual revenue. Therefore, MVDT small businesses would
include an additional 1.5 percent of annual revenue to redesign, MVDT
distribution transformers to higher efficiency levels that could be met
without using amorphous cores.
DOE requests comment on the number of small businesses identified
that manufacture distribution transformers covered by this rulemaking
(three small liquid-immersed and seven LVDT small businesses; three of
which also manufacture MVDT). Additionally, DOE requests comment on its
initial assumption that only one LVDT small business and no liquid-
immersed small businesses manufacturer their own cores used in their
distribution transformers.
5. Duplication, Overlap, and Conflict With Other Rules and Regulations
Starting in 2018, imports of raw electrical steel have been subject
to a 25 percent ad valorem tariff. This tariff does not apply to
products made from electrical steel, such as transformer laminations
and finished cores. In a report published on November 18, 2021, the
Department of Commerce presented its conclusions and potential options
to ensure the domestic supply chain of electrical steel and transformer
components. 86 FR 64606 However, no modifications to the tariff
structure have been made at the time of publication of this NOPR. As
discussed in section IV.A.5, modification to the tariff structure could
impact the pricing and availability of certain electrical steel grades
depending on each manufacturer's given supply chain and sourcing
practices.
DOE is not aware of any other rules or regulations that duplicate,
overlap, or conflict with the rule being considered today.
6. Significant Alternatives to the Rule
The discussion in the previous section analyzes impacts on small
businesses that would result from DOE's proposed rule, represented by
TSL 4 for liquid-immersed distribution transformer equipment classes;
TSL 5 for LVDT equipment classes; and TSL 2 for MVDT equipment classes.
In reviewing alternatives to the proposed rule, DOE examined energy
conservation standards set at lower efficiency levels. While lower TSLs
would reduce the impacts on small business manufacturers, it would come
at the expense of a reduction in energy savings. For liquid-immersed
equipment classes TSL 1 achieves 60 percent lower energy savings
compared to the energy savings at TSL 4; TSL 2 achieves 37 percent
lower energy savings compared to the energy savings at TSL 4. For LVDT
equipment classes TSL 1 achieves 85 percent lower energy savings
compared to the energy savings at TSL 5; TSL 2 achieves 78 percent
lower energy savings compared to the energy savings at TSL 5; TSL 3
achieves 66 percent lower energy savings compared to the energy savings
at TSL 5; and TSL 4 achieves 8 percent lower energy savings compared to
the energy savings at TSL 5. For MVDT equipment classes TSL 1 achieves
33 percent lower energy savings compared to the energy savings at TSL
2.
Based on the presented discussion, DOE tentatively concludes that
the benefits of the energy savings from TSL 4 for liquid-immersed
equipment classes; TSL 5 for LVDT equipment classes; and TSL 2 for MVDT
equipment classes exceed the potential burdens placed on distribution
transformers manufacturers, including small business manufacturers.
Accordingly, DOE does not propose one of the other TSLs considered in
the analysis, or the other policy alternatives examined as part of the
regulatory impact analysis and included in chapter 17 of the NOPR TSD.
Additional compliance flexibilities may be available through other
means. EPCA provides that a manufacturer whose annual gross revenue
from all of its operations does not exceed $8 million may apply for an
exemption from all or part of an energy conservation standard for a
period not longer than 24 months after the effective date of a final
rule establishing the standard. (42 U.S.C. 6295(t)) Additionally,
manufacturers subject to DOE's energy efficiency standards may apply to
DOE's Office of Hearings and Appeals for exception relief under certain
circumstances. Manufacturers should refer to 10 CFR part 430, subpart
E, and 10 CFR part 1003 for additional details.
C. Review Under the Paperwork Reduction Act
Manufacturers of distribution transformers must certify to DOE that
their products comply with any applicable energy conservation
standards. In certifying compliance, manufacturers must test their
products according to the DOE test procedures for distribution
transformers, including any amendments adopted for those test
procedures. DOE has established
[[Page 1849]]
regulations for the certification and recordkeeping requirements for
all covered consumer products and commercial equipment, including
distribution transformers. (See generally 10 CFR part 429). The
collection-of-information requirement for the certification and
recordkeeping is subject to review and approval by OMB under the
Paperwork Reduction Act (``PRA''). This requirement has been approved
by OMB under OMB control number 1910-1400. Public reporting burden for
the certification is estimated to average 35 hours per response,
including the time for reviewing instructions, searching existing data
sources, gathering and maintaining the data needed, and completing and
reviewing the collection of information.
Notwithstanding any other provision of the law, no person is
required to respond to, nor shall any person be subject to a penalty
for failure to comply with, a collection of information subject to the
requirements of the PRA, unless that collection of information displays
a currently valid OMB Control Number.
D. Review Under the National Environmental Policy Act of 1969
DOE is analyzing this proposed regulation in accordance with the
National Environmental Policy Act of 1969 (``NEPA'') and DOE's NEPA
implementing regulations (10 CFR part 1021). DOE's regulations include
a categorical exclusion for rulemakings that establish energy
conservation standards for consumer products or industrial equipment.
10 CFR part 1021, subpart D, appendix B5.1. DOE anticipates that this
rulemaking qualifies for categorical exclusion B5.1 because it is a
rulemaking that establishes energy conservation standards for consumer
products or industrial equipment, none of the exceptions identified in
categorical exclusion B5.1(b) apply, no extraordinary circumstances
exist that require further environmental analysis, and it otherwise
meets the requirements for application of a categorical exclusion. See
10 CFR 1021.410. DOE will complete its NEPA review before issuing the
final rule.
E. Review Under Executive Order 13132
E.O. 13132, ``Federalism,'' 64 FR 43255 (Aug. 10, 1999), imposes
certain requirements on Federal agencies formulating and implementing
policies or regulations that preempt State law or that have federalism
implications. The Executive order requires agencies to examine the
constitutional and statutory authority supporting any action that would
limit the policymaking discretion of the States and to carefully assess
the necessity for such actions. The Executive order also requires
agencies to have an accountable process to ensure meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications. On March 14, 2000, DOE
published a statement of policy describing the intergovernmental
consultation process it will follow in the development of such
regulations. 65 FR 13735. DOE has examined this proposed rule and has
tentatively determined that it would not have a substantial direct
effect on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government. EPCA governs
and prescribes Federal preemption of State regulations as to energy
conservation for the equipment that are the subject of this proposed
rule. States can petition DOE for exemption from such preemption to the
extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297)
Therefore, no further action is required by Executive Order 13132.
F. Review Under Executive Order 12988
With respect to the review of existing regulations and the
promulgation of new regulations, section 3(a) of E.O. 12988, ``Civil
Justice Reform,'' imposes on Federal agencies the general duty to
adhere to the following requirements: (1) eliminate drafting errors and
ambiguity, (2) write regulations to minimize litigation, (3) provide a
clear legal standard for affected conduct rather than a general
standard, and (4) promote simplification and burden reduction. 61 FR
4729 (Feb. 7, 1996). Regarding the review required by section 3(a),
section 3(b) of E.O. 12988 specifically requires that Executive
agencies make every reasonable effort to ensure that the regulation:
(1) clearly specifies the preemptive effect, if any, (2) clearly
specifies any effect on existing Federal law or regulation, (3)
provides a clear legal standard for affected conduct while promoting
simplification and burden reduction, (4) specifies the retroactive
effect, if any, (5) adequately defines key terms, and (6) addresses
other important issues affecting clarity and general draftsmanship
under any guidelines issued by the Attorney General. Section 3(c) of
Executive Order 12988 requires Executive agencies to review regulations
in light of applicable standards in section 3(a) and section 3(b) to
determine whether they are met or it is unreasonable to meet one or
more of them. DOE has completed the required review and determined
that, to the extent permitted by law, this proposed rule meets the
relevant standards of E.O. 12988.
G. Review Under the Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (``UMRA'')
requires each Federal agency to assess the effects of Federal
regulatory actions on State, local, and Tribal governments and the
private sector. Public Law 104-4, section 201 (codified at 2 U.S.C.
1531). For a proposed regulatory action likely to result in a rule that
may cause the expenditure by State, local, and Tribal governments, in
the aggregate, or by the private sector of $100 million or more in any
one year (adjusted annually for inflation), section 202 of UMRA
requires a Federal agency to publish a written statement that estimates
the resulting costs, benefits, and other effects on the national
economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal
agency to develop an effective process to permit timely input by
elected officers of State, local, and Tribal governments on a proposed
``significant intergovernmental mandate,'' and requires an agency plan
for giving notice and opportunity for timely input to potentially
affected small governments before establishing any requirements that
might significantly or uniquely affect them. On March 18, 1997, DOE
published a statement of policy on its process for intergovernmental
consultation under UMRA. 62 FR 12820. DOE's policy statement is also
available at www.energy.gov/sites/prod/files/gcprod/documents/umra_97.pdf.
Although this proposed rule does not contain a Federal
intergovernmental mandate, it may require expenditures of $100 million
or more in any one year by the private sector. Such expenditures may
include: (1) investment in research and development and in capital
expenditures by distribution transformers manufacturers in the years
between the final rule and the compliance date for the new standards
and (2) incremental additional expenditures by consumers to purchase
higher-efficiency distribution transformers, starting at the compliance
date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the
content requirements of UMRA in any other statement or analysis that
accompanies the proposed rule. (2 U.S.C. 1532(c)) The content
requirements of section 202(b) of UMRA relevant to a private sector
mandate substantially overlap the economic analysis requirements that
apply under section 325(o) of EPCA and
[[Page 1850]]
Executive Order 12866. The SUPPLEMENTARY INFORMATION section of this
NOPR and the TSD for this proposed rule respond to those requirements.
Under section 205 of UMRA, the Department is obligated to identify
and consider a reasonable number of regulatory alternatives before
promulgating a rule for which a written statement under section 202 is
required. (2 U.S.C. 1535(a)) DOE is required to select from those
alternatives the most cost-effective and least burdensome alternative
that achieves the objectives of the proposed rule unless DOE publishes
an explanation for doing otherwise, or the selection of such an
alternative is inconsistent with law. As required by 42 U.S.C. 6295(m)
[or a product-specific directive in 42 U.S.C. 6295 or 42 U.S.C. 6313],
this proposed rule would establish amended energy conservation
standards for distribution transformers that are designed to achieve
the maximum improvement in energy efficiency that DOE has determined to
be both technologically feasible and economically justified, as
required by 42 U.S.C. 6295(o)(2)(A) and 42 U.S.C. 6295(o)(3)(B). A full
discussion of the alternatives considered by DOE is presented in
chapter 17 of the TSD for this proposed rule.
H. Review Under the Treasury and General Government Appropriations Act,
1999
Section 654 of the Treasury and General Government Appropriations
Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family
Policymaking Assessment for any rule that may affect family well-being.
This proposed rule would not have any impact on the autonomy or
integrity of the family as an institution. Accordingly, DOE has
concluded that it is not necessary to prepare a Family Policymaking
Assessment.
I. Review Under Executive Order 12630
Pursuant to E.O. 12630, ``Governmental Actions and Interference
with Constitutionally Protected Property Rights,'' 53 FR 8859 (Mar. 15,
1988), DOE has determined that this proposed rule would not result in
any takings that might require compensation under the Fifth Amendment
to the U.S. Constitution.
J. Review Under the Treasury and General Government Appropriations Act,
2001
Section 515 of the Treasury and General Government Appropriations
Act, 2001 (44 U.S.C. 3516 note) provides for Federal agencies to review
most disseminations of information to the public under information
quality guidelines established by each agency pursuant to general
guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452
(Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446
(Oct. 7, 2002). Pursuant to OMB Memorandum M-19-15, Improving
Implementation of the Information Quality Act (April 24, 2019), DOE
published updated guidelines which are available at www.energy.gov/sites/prod/files/2019/12/f70/DOE%20Final%20Updated%20IQA%20Guidelines%20Dec%202019.pdf. DOE has
reviewed this NOPR under the OMB and DOE guidelines and has concluded
that it is consistent with applicable policies in those guidelines.
K. Review Under Executive Order 13211
E.O. 13211, ``Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use,'' 66 FR 28355 (May 22,
2001), requires Federal agencies to prepare and submit to OIRA at OMB,
a Statement of Energy Effects for any proposed significant energy
action. A ``significant energy action'' is defined as any action by an
agency that promulgates or is expected to lead to promulgation of a
final rule, and that (1) is a significant regulatory action under
Executive Order 12866, or any successor order; and (2) is likely to
have a significant adverse effect on the supply, distribution, or use
of energy, or (3) is designated by the Administrator of OIRA as a
significant energy action. For any proposed significant energy action,
the agency must give a detailed statement of any adverse effects on
energy supply, distribution, or use should the proposal be implemented,
and of reasonable alternatives to the action and their expected
benefits on energy supply, distribution, and use.
DOE has tentatively concluded that this regulatory action, which
proposes amended energy conservation standards for distribution
transformers, is not a significant energy action because the proposed
standards are not likely to have a significant adverse effect on the
supply, distribution, or use of energy, nor has it been designated as
such by the Administrator at OIRA. Accordingly, DOE has not prepared a
Statement of Energy Effects on this proposed rule.
L. Information Quality
On December 16, 2004, OMB, in consultation with the Office of
Science and Technology Policy (``OSTP''), issued its Final Information
Quality Bulletin for Peer Review (``the Bulletin''). 70 FR 2664 (Jan.
14, 2005). The Bulletin establishes that certain scientific information
shall be peer reviewed by qualified specialists before it is
disseminated by the Federal Government, including influential
scientific information related to agency regulatory actions. The
purpose of the bulletin is to enhance the quality and credibility of
the Government's scientific information. Under the Bulletin, the energy
conservation standards rulemaking analyses are ``influential scientific
information,'' which the Bulletin defines as ``scientific information
the agency reasonably can determine will have, or does have, a clear
and substantial impact on important public policies or private sector
decisions.'' 70 FR 2664, 2667.
In response to OMB's Bulletin, DOE conducted formal peer reviews of
the energy conservation standards development process and the analyses
that are typically used and has prepared a report describing that peer
review.\116\ Generation of this report involved a rigorous, formal, and
documented evaluation using objective criteria and qualified and
independent reviewers to make a judgment as to the technical/
scientific/business merit, the actual or anticipated results, and the
productivity and management effectiveness of programs and/or projects.
Because available data, models, and technological understanding have
changed since 2007, DOE has engaged with the National Academy of
Sciences to review DOE's analytical methodologies to ascertain whether
modifications are needed to improve the Department's analyses. DOE is
in the process of evaluating the resulting report.\117\
---------------------------------------------------------------------------
\116\ The 2007 ``Energy Conservation Standards Rulemaking Peer
Review Report'' is available at the following website: energy.gov/eere/buildings/downloads/energy-conservation-standards-rulemaking-peer-review-report-0 (last accessed January 2022).
\117\ The report is available at www.nationalacademies.org/our-work/review-of-methods-for-setting-building-and-equipment-performance-standards.
---------------------------------------------------------------------------
VII. Public Participation
A. Attendance at the Public Meeting
The time and date of the webinar meeting are listed in the DATES
section at the beginning of this document. Webinar registration
information, participant instructions, and information about the
capabilities available to webinar participants will be published on
DOE's website: www.eere.energy.gov/buildings/appliance_standards/standards.aspx?productid=55.
[[Page 1851]]
Participants are responsible for ensuring their systems are compatible
with the webinar software.
B. Procedure for Submitting Prepared General Statements for
Distribution
Any person who has an interest in the topics addressed in this
proposed rule, or who is representative of a group or class of persons
that has an interest in these issues, may request an opportunity to
make an oral presentation at the webinar. Such persons may submit to
[email protected]. Persons who wish to speak
should include with their request a computer file in WordPerfect,
Microsoft Word, PDF, or text (ASCII) file format that briefly describes
the nature of their interest in this rulemaking and the topics they
wish to discuss. Such persons should also provide a daytime telephone
number where they can be reached.
DOE requests persons selected to make an oral presentation to
submit an advance copy of their statements at least two weeks before
the webinar. At its discretion, DOE may permit persons who cannot
supply an advance copy of their statement to participate, if those
persons have made advance alternative arrangements with the Building
Technologies Office. As necessary, requests to give an oral
presentation should ask for such alternative arrangements.
DOE will designate a DOE official to preside at the webinar/public
meeting and may also use a professional facilitator to aid discussion.
The meeting will not be a judicial or evidentiary-type public hearing,
but DOE will conduct it in accordance with section 336 of EPCA (42
U.S.C. 6306). A court reporter will be present to record the
proceedings and prepare a transcript. DOE reserves the right to
schedule the order of presentations and to establish the procedures
governing the conduct of the webinar. There shall not be discussion of
proprietary information, costs or prices, market share, or other
commercial matters regulated by U.S. anti-trust laws. After the webinar
and until the end of the comment period, interested parties may submit
further comments on the proceedings and any aspect of the rulemaking.
The webinar will be conducted in an informal, conference style. DOE
will a general overview of the topics addressed in this rulemaking,
allow time for prepared general statements by participants, and
encourage all interested parties to share their views on issues
affecting this rulemaking. Each participant will be allowed to make a
general statement (within time limits determined by DOE), before the
discussion of specific topics. DOE will permit, as time permits, other
participants to comment briefly on any general statements.
At the end of all prepared statements on a topic, DOE will permit
participants to clarify their statements briefly. Participants should
be prepared to answer questions by DOE and by other participants
concerning these issues. DOE representatives may also ask questions of
participants concerning other matters relevant to this proposed rule.
The official conducting the webinar/public meeting will accept
additional comments or questions from those attending, as time permits.
The presiding official will announce any further procedural rules or
modification of the above procedures that may be needed for the proper
conduct of the webinar.
A transcript of the webinar will be included in the docket, which
can be viewed as described in the Docket section at the beginning of
this proposed rule. In addition, any person may buy a copy of the
transcript from the transcribing reporter.
C. Conduct of the Public Webinar
DOE will designate a DOE official to preside at the webinar/public
meeting and may also use a professional facilitator to aid discussion.
The meeting will not be a judicial or evidentiary-type public hearing,
but DOE will conduct it in accordance with section 336 of EPCA (42
U.S.C. 6306). A court reporter will be present to record the
proceedings and prepare a transcript. DOE reserves the right to
schedule the order of presentations and to establish the procedures
governing the conduct of the webinar. There shall not be discussion of
proprietary information, costs or prices, market share, or other
commercial matters regulated by U.S. anti-trust laws. After the webinar
and until the end of the comment period, interested parties may submit
further comments on the proceedings and any aspect of the rulemaking.
The webinar will be conducted in an informal, conference style. DOE
will a general overview of the topics addressed in this rulemaking,
allow time for prepared general statements by participants, and
encourage all interested parties to share their views on issues
affecting this rulemaking. Each participant will be allowed to make a
general statement (within time limits determined by DOE), before the
discussion of specific topics. DOE will permit, as time permits, other
participants to comment briefly on any general statements.
At the end of all prepared statements on a topic, DOE will permit
participants to clarify their statements briefly. Participants should
be prepared to answer questions by DOE and by other participants
concerning these issues. DOE representatives may also ask questions of
participants concerning other matters relevant to this rulemaking. The
official conducting the webinar/public meeting will accept additional
comments or questions from those attending, as time permits. The
presiding official will announce any further procedural rules or
modification of the above procedures that may be needed for the proper
conduct of the webinar.
A transcript of the webinar will be included in the docket, which
can be viewed as described in the Docket section at the beginning of
this proposed rule. In addition, any person may buy a copy of the
transcript from the transcribing reporter.
D. Submission of Comments
DOE will accept comments, data, and information regarding this
proposed rule before or after the public meeting, but no later than the
date provided in the DATES section at the beginning of this proposed
rule. Interested parties may submit comments, data, and other
information using any of the methods described in the ADDRESSES section
at the beginning of this document.
Submitting comments via www.regulations.gov. The
www.regulations.gov web page will require you to provide your name and
contact information. Your contact information will be viewable to DOE
Building Technologies staff only. Your contact information will not be
publicly viewable except for your first and last names, organization
name (if any), and submitter representative name (if any). If your
comment is not processed properly because of technical difficulties,
DOE will use this information to contact you. If DOE cannot read your
comment due to technical difficulties and cannot contact you for
clarification, DOE may not be able to consider your comment.
However, your contact information will be publicly viewable if you
include it in the comment itself or in any documents attached to your
comment. Any information that you do not want to be publicly viewable
should not be included in your comment, nor in any document attached to
your comment. Otherwise, persons viewing comments will see only first
and last names,
[[Page 1852]]
organization names, correspondence containing comments, and any
documents submitted with the comments.
Do not submit to www.regulations.gov information for which
disclosure is restricted by statute, such as trade secrets and
commercial or financial information (hereinafter referred to as
Confidential Business Information (``CBI'')). Comments submitted
through www.regulations.gov cannot be claimed as CBI. Comments received
through the website will waive any CBI claims for the information
submitted. For information on submitting CBI, see the Confidential
Business Information section.
DOE processes submissions made through www.regulations.gov before
posting. Normally, comments will be posted within a few days of being
submitted. However, if large volumes of comments are being processed
simultaneously, your comment may not be viewable for up to several
weeks. Please keep the comment tracking number that www.regulations.gov
provides after you have successfully uploaded your comment.
Submitting comments via email. Comments and documents submitted via
email also will be posted to www.regulations.gov. If you do not want
your personal contact information to be publicly viewable, do not
include it in your comment or any accompanying documents. Instead,
provide your contact information in a cover letter. Include your first
and last names, email address, telephone number, and optional mailing
address. The cover letter will not be publicly viewable as long as it
does not include any comments.
Include contact information each time you submit comments, data,
documents, and other information to DOE. No telefacsimiles (``faxes'')
will be accepted.
Comments, data, and other information submitted to DOE
electronically should be provided in PDF (preferred), Microsoft Word or
Excel, WordPerfect, or text (ASCII) file format. Provide documents that
are not secured, that are written in English, and that are free of any
defects or viruses. Documents should not contain special characters or
any form of encryption and, if possible, they should carry the
electronic signature of the author.
Campaign form letters. Please submit campaign form letters by the
originating organization in batches of between 50 to 500 form letters
per PDF or as one form letter with a list of supporters' names compiled
into one or more PDFs. This reduces comment processing and posting
time.
Confidential Business Information. Pursuant to 10 CFR 1004.11, any
person submitting information that he or she believes to be
confidential and exempt by law from public disclosure should submit via
email two well-marked copies: one copy of the document marked
``confidential'' including all the information believed to be
confidential, and one copy of the document marked ``non-confidential''
with the information believed to be confidential deleted. DOE will make
its own determination about the confidential status of the information
and treat it according to its determination.
It is DOE's policy that all comments may be included in the public
docket, without change and as received, including any personal
information provided in the comments (except information deemed to be
exempt from public disclosure).
E. Issues on Which DOE Seeks Comment
Although DOE welcomes comments on any aspect of this proposal, DOE
is particularly interested in receiving comments and views of
interested parties concerning the following issues:
(1) DOE requests comment on the proposed amendment to the
definition of drive (isolation) transformer. DOE requests comment on
its tentative determination that voltage ratings of 208Y/120 and 480Y/
277 indicate a design for use in general purpose applications. DOE also
requests comment on other voltage ratings or other characteristics that
would indicate a design for use in general purpose applications.
(2) DOE requests comment on its proposed amendment to the
definition of ``special-impedance transformer'' and whether it provides
sufficient clarity as to how to treat the normal impedance ranges for
non-standard kVA distribution transformers.
(3) DOE requests comment on its proposed definition for
transformers with a tap range of 20 percent or more.
(4) DOE requests comment on its proposed amendments to the
definitions of sealed and nonventilated transformers.
(5) DOE requests comment on its proposed amendment to the
definition of uninterruptable power supply transformers.
(6) DOE requests comment as to whether its proposed definition
better aligns with industries understanding on input and output
voltages
(7) Further, DOE requests comment and data on whether the proposed
amendment would impact products that are serving distribution
applications, and if so, the number of distribution transformers
impacted by the proposed amendment.
(8) DOE requests comment and data as to whether 5,000 kVA
represents the upper end of what is considered distribution
transformers or if another value should be used.
(9) DOE requests comment and data as to the number of shipments of
three-phase, liquid-immersed, distribution transformers greater than
2,500 kVA that would meet the in-scope voltage limitations and the
distribution of efficiencies of those units.
(10) DOE requests comment and data as to the number of shipments of
three-phase, dry-type, distribution transformers greater than 2,500 kVA
that would meet the in-scope voltage limitations and the distribution
of efficiencies of those units.
(11) DOE requests comment on its understanding and proposed
definition of ``submersible'' distribution transformer. Specifically,
DOE requests information on specific design characteristics of
distribution transformers that allow them to operate while submerged in
water, as well as data on the impact to efficiency resulting from such
characteristics.
(12) DOE requests comment and data as to the impact that
submersible characteristics have on distribution transformer
efficiency.
(13) DOE requests data on the difference in load loss by kVA for
distribution transformers with multiple-voltage ratings and a voltage
ratio other than 2:1.
(14) DOE request data on the number of shipments for each equipment
class of distribution transformers with multi-voltage ratios other than
2:1.
(15) DOE requests data on the difference in load loss by kVA for
distribution transformers with higher currents and at what current it
becomes more difficult to meet energy conservation standards.
(16) DOE requests data as to the number of shipments of
distribution transformers with the higher currents that would have a
more difficult time meeting energy conservation standards.
(17) DOE requests comment as to what modifications could be made to
the April 2013 Standard Final Rule data center definition such that the
identifying features are related to efficiency and would prevent a data
center transformer from being used in a general purpose application.
(18) DOE requests comment regarding its proposal not to establish a
separate equipment class for data center distribution transformers. In
particular,
[[Page 1853]]
DOE seeks comment regarding whether data center distribution
transformers are able to reach the same efficiency levels as
distribution transformers generally and the specific reasons why that
may be the case.
(19) DOE requests comment regarding any challenges that would exist
if designing a distribution transformer which uses amorphous electrical
steel in its core for data center applications and whether data center
transformers have been built which use amorphous electrical steel in
their cores.
(20) DOE requests comment on the interaction of inrush current and
data center distribution transformer design. Specifically, DOE seeks
information regarding: (1) the range of inrush current limit values in
use in data center distribution transformers; (2) any challenges in
meeting such inrush current limit values when using amorphous
electrical steel in the core; (3) whether using amorphous electrical
steel inherently increases inrush current, and why; (4) how the
(magnetic) remanence of grain-oriented electrical steel compares to
that of amorphous steel; and (5) other strategies or technologies than
distribution transformer design which could be used to limit inrush
current and the respective costs of those measures.
(21) DOE requests data as to how a liquid-immersed distribution
transformer losses vary with BIL across the range of kVA values within
scope.
(22) DOE requests comments and data on any other types of equipment
that may have a harder time meeting energy conservation standards.
Specifically, DOE requests comments as to how these other equipment are
identified based on physical features from general purpose distribution
transformers, the number of shipments of each unit, and the possibility
of these equipment being used in place of generally purpose
distribution transformers.
(23) DOE requests data demonstrating any specific distribution
transformer designs that would have significantly different cost-
efficiency curves than those representative units modeled by DOE.
(24) DOE requests comment on its methodology for scaling RU5, RU12,
and RU14 to represent the efficiency of units above 3,750 kVA.
(25) DOE requests comment on its methodology for modifying the
results of RU4 and RU5 to represent the efficiency of submersible
liquid-immersed units. For other potentially disadvantaged designs, DOE
has considered establishing equipment classes to separate out those
that would have the most difficulty achieving amended efficiency
standards, as discussed in section IV.A.2 of this document, but
ultimately has determined not to include such separate equipment
classes in the proposed standards. However, DOE requests data as to the
degree of reduction in efficiency associated with various features.
(26) DOE requests data as to how stray and eddy losses at rated PUL
vary with kVA and rated voltages.
(27) DOE requests comment on the current and future market
pressures influencing the price of GOES. Specifically, DOE is
interested in the barriers to and costs associated with converting a
factory production line from GOES to NOES.
(28) DOE further requests comment regarding how the prices of both
GOES and amorphous are expected to change in the immediate and distant
future.
(29) DOE requests comment regarding the barriers to converting
current M3 or 23hib90 electrical steel production to lower-loss GOES
core steels.
(30) DOE requests comment as to if there are markets for amorphous
ribbon, similar to NOES competition from GOES production, which would
put competitive pressures on the production of amorphous ribbon for
distribution transformers.
(31) DOE requests comment on how a potentially limited supply of
transformer core steel, both of amorphous and GOES, may affect core
steel price and availability. DOE seeks comment on any factors which
uniquely affect specific steel grades (e.g., amorphous, M-grades, hib,
dr, pdr). Additionally, DOE seeks comment on how it should model a
potentially concentrated domestic steel market in its analysis,
resulting from a limited number of suppliers for the amorphous market
or from competition with NOES for the GOES market, including any use of
game theoretic modeling as appropriate.
(32) DOE requests comment or data showing hourly transformer loads
for industrial customers.
(33) To help inform DOE's prediction of future load growth trend,
DOE seeks data on the following for regions where decarbonization
efforts are ongoing. DOE seeks hourly PUL data at the level of the
transformer bank for each of the past five years to establish an
unambiguous relationship between transformer loads and decarbonization
policy and inform if any intensive load growth is indeed occurring.
Additionally, DOE seeks the average capacity of shipment into regions
where decarbonization efforts are occurring over the same five-year
period to inform the rate of any extensive load growth that may be
occurring in response to these programs.
(34) DOE requests comments on its methodology for establishing the
energy efficiency levels for distribution transformers greater than
2500 kVA. DOE request comment on its assumed energy efficiency ratings.
(35) DOE requests comment on its assumed TOC adoption rate of 10
percent. Specifically, DOE requests comment on the TOC rate suggested
by NEMA, that between 15 and 20 percent of 3-phase liquid-immersed
distribution transformers are purchased using TOC, and that 40 percent
of 1-phase liquid-immersed distribution transformers are purchased
using TOC. DOE notes, that it is seeking data related to concluded
sales based on lowest TOC in the strictest sense, excluding those
transformers sold using band of equivalents (see the section on band of
equivalents, above)
(36) DOE requests comment on the fraction of distribution
transformers purchased by customers using the BOE methodology. DOE
notes, that it is seeking data related to concluded sales based on
lowest BOE in the strictest sense, excluding those transformers sold
using total owning costs.
(37) DOE request comment if the rates of TOC or BOE vary by
transformer capacity or number of phases. Further, DOE seeks the
fraction of distribution transformer sales using either method into the
different regions in order to capture the believed relationship between
higher electricity costs and purchase evaluation behavior.
(38) Transformers are typically installed using a bucket truck, or
crane truck. DOE requests comment on the typical maximum lifting
capacity, and the typical transformer capacity being installed.
(39) For this NOPR, DOE reiterates its request for the following
information. DOE requests data and feedback on the size limitations of
pad-mounted distribution transformers. Specifically, what sizes,
voltages, or other features are currently unable to fit on current
pads, and the dimension of these pads. DOE seeks data on the typical
concrete pad dimensions for 50 and 500 kVA single-; and 500, and 1500
kVA three-phase distribution transformers. DOE seeks data on the
typical service lifetimes of supporting concrete pads.
(40) DOE request the average extension of distribution transformer
service life that can be achieved through rebuilding. Additionally, DOE
requests comment on the fraction of transformer that are repaired by
their original purchasing entity and returned to
[[Page 1854]]
service, thereby extending the transformer's service lifetime beyond
the estimated lifetimes of 32 years with a maximum of 60 years.
(41) DOE requests comment on which liquid-immersed distribution
transformers capacities are typically replaced with MVDT. DOE further
requests data that would indicate a trend in these substitutions. DOE
further requests data that would help it determine which types of
customers are preforming these substitutions, e.g., industrial
customers, invertor owned utilities, MUNIs, etc.
(42) In response to NEMA's comment DOE requests data to inform a
shift in the capacity distribution to larger capacity distribution
transformers. Additionally, DOE requests information on the extent that
this increasing trend in capacity would affect all types of
distribution transformers, or only medium-voltage distribution
transformers.
(43) DOE projected the energy savings, operating cost savings,
product costs, and NPV of consumer benefits over the lifetime of
distribution transformers sold from 2027 through 2056. Given the
extremely durable nature of distribution transformers, this creates an
analytical timeframe from 2027 through 2115. DOE seeks comment on the
current analytical timeline, and potential alternative analytical
timeframes.
(44) DOE requests comment on its assumption that including a
rebound effect is inappropriate for distribution transformers.
(45) DOE requests comment on the mean PUL applied to distribution
transformers owned and operated by utilities serving low customer
populations.
(46) DOE requests comment on its assumed vault replacement costs
methodology. DOE seeks comment or data regarding the installation
procedures associated with vault replacement, vault expansion
(renovation), and vault transformer installation and their respective
costs for replacement transformers. Additionally, DOE seeks information
on the typical expected lifetime of underground concrete vaults.
(47) DOE requests comment on the real discount rates used in this
NOPR. Specifically, if 7.4 percent for liquid-immersed distribution
transformer manufacturers, 11.1 percent for low-voltage dry-type
distribution transformer manufacturers, and 9.0 percent for medium-
voltage dry-type distribution transformer manufacturers are appropriate
discount rates to use in the GRIM.
(48) DOE requests comment on the estimated potential domestic
employment impacts on distribution transformer manufacturers presented
in this NOPR.
(49) DOE requests comment on the potential availability of either
amorphous steel, grain-oriented electrical steel, or any other
materials that may be needed to meet any of the analyzed energy
conservation standards in this rulemaking. More specifically, DOE
requests comment on steel manufacturers' ability to increase supply of
amorphous steel in reaction to increased demand for amorphous steel as
a result of increased energy conservation standards for distribution
transformers.
(50) DOE requests comment on the number of small businesses
identified that manufacture distribution transformers covered by this
rulemaking (three small liquid-immersed and seven LVDT small
businesses; three of which also manufacture MVDT). Additionally, DOE
requests comment on its initial assumption that only one LVDT small
business and no liquid-immersed small businesses manufacturer their own
cores used in their distribution transformers.
(51) Additionally, DOE welcomes comments on other issues relevant
to the conduct of this rulemaking that may not specifically be
identified in this document.
VIII. Approval of the Office of the Secretary
The Secretary of Energy has approved publication of this notice of
proposed rulemaking and announcement of public meeting.
List of Subjects in 10 CFR Part 431
Administrative practice and procedure, Confidential business
information, Energy conservation test procedures, and Reporting and
recordkeeping requirements.
Signing Authority
This document of the Department of Energy was signed on December
28, 2022, by Francisco Alejandro Moreno, Acting Assistant Secretary for
Energy Efficiency and Renewable Energy, pursuant to delegated authority
from the Secretary of Energy. That document with the original signature
and date is maintained by DOE. For administrative purposes only, and in
compliance with requirements of the Office of the Federal Register, the
undersigned DOE Federal Register Liaison Officer has been authorized to
sign and submit the document in electronic format for publication, as
an official document of the Department of Energy. This administrative
process in no way alters the legal effect of this document upon
publication in the Federal Register.
Signed in Washington, DC, on December 29, 2022.
Treena V. Garrett,
Federal Register Liaison Officer, U.S. Department of Energy
For the reasons set forth in the preamble, DOE proposes to amend
part 431 of chapter II, of title 10 of the Code of Federal Regulations,
as set forth below:
PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND
INDUSTRIAL EQUIPMENT
0
1. The authority citation for part 431 continues to read as follows:
Authority: 42 U.S.C. 6291-6317; 28 U.S.C. 2461 note.
0
2. Section 431.192 is amended by:
0
a. Revising the definitions of ``Distribution transformer'', ``Drive
(isolation) transformer'', ``Nonventilated transformer'', ``Sealed
transformer'', ``Special-impedance transformer'', ``Transformer with a
tap range of 20 percent or more'', ``Uninterruptible power supply
transformer''; and
0
b. Adding in alphabetical order, definition for ``Submersible
distribution transformer''
The revisions and addition read as follows:
Sec. 431.19 Definitions.
* * * * *
Distribution transformer means a transformer that:
(1) Has an input line voltage of 34.5 kV or less;
(2) Has an output line voltage of 600 V or less;
(3) Is rated for operation at a frequency of 60 Hz; and
(4) Has a capacity of 10 kVA to 5000 kVA for liquid-immersed units
and 15 kVA to 5000 kVA for dry-type units; but
(5) The term ``distribution transformer'' does not include a
transformer that is an -
(i) Autotransfromer;
(ii) Drive (isolation) transformer;
(iii) Grounding transformer;
(iv) Machine-tool (control transformer);
(v) Nonventilated transformer;
(vi) Rectified transformer;
(vii) Regulating transformer;
(viii) Sealed transformer;
(ix) Special-impedance transformer;
(x) Testing transformer;
(xi) Transformer with tap range of 20 percent or more;
[[Page 1855]]
(xii) Uninterruptible power supply transformer; or
(xiii) Welding transformer.
Drive (isolation) transformer means a transformer that:
(1) Isolates an electric motor from the line;
(2) Accommodates the added loads of drive-created harmonics;
(3) Is designed to withstand the additional mechanical stressed
resulting from an alternating current adjustable frequency motor drive
or a direct current motor drive; and
(4) Has a rated output voltage that is neither ``208Y/120'' nor
``480Y/277''.
* * * * *
Nonventilated transformer means a dry-type transformer constructed
so as to prevent external air circulation through the coils of the
transformer while operating at zero gauge pressure.
* * * * *
Sealed transformer means a dry-type transformer designed to remain
hermetically sealed under specified condition of temperature and
pressure.
Special-impedance transformer means a transformer built to operate
at an impedance outside of the normal impedance range for that
transformer's kVA rating. The normal impedance range for each kVA
rating for liquid-immersed and dry-type transformers is show in Tables
1 and 2, respectively. Distribution transformers with kVA ratings not
appearing in the tables shall have their minimum normal impedance and
maximum normal impedance determined by linear interpolation of the kVA
and minimum and maximum impedances, respectively, of the values
immediately above and below that kVA rating.
Table 1--Normal Impedance Ranges for Liquid-Immersed Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Impedance (%) kVA Impedance (%)
----------------------------------------------------------------------------------------------------------------
10........................................... 1.0-4.5 15.............................. 1.0-4.5
15........................................... 1.0-4.5 30.............................. 1.0-4.5
25........................................... 1.0-4.5 45.............................. 1.0-4.5
37.5......................................... 1.0-4.5 75.............................. 1.0-5.0
50........................................... 1.5-4.5 112.5........................... 1.2-6.0
75........................................... 1.5-4.5 150............................. 1.2-6.0
100.......................................... 1.5-4.5 225............................. 1.2-6.0
167.......................................... 1.5-4.5 300............................. 1.2-6.0
250.......................................... 1.5-6.0 500............................. 1.5-7.0
333.......................................... 1.5-6.0 750............................. 5.0-7.5
500.......................................... 1.5-7.0 1,000........................... 5.0-7.5
667.......................................... 5.0-7.5 1,500........................... 5.0-7.5
833.......................................... 5.0-7.5 2,000........................... 5.0-7.5
2,500........................... 5.0-7.5
3,750........................... 5.0-7.5
5,000........................... 5.0-7.5
----------------------------------------------------------------------------------------------------------------
Table 2--Normal Impedance Ranges for Dry-Type Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Impedance (%) kVA Impedance (%)
----------------------------------------------------------------------------------------------------------------
15........................................... 1.5-6.0 15.............................. 1.5-6.0
25........................................... 1.5-6.0 30.............................. 1.5-6.0
37.5......................................... 1.5-6.0 45.............................. 1.5-6.0
50........................................... 1.5-6.0 75.............................. 1.5-6.0
75........................................... 2.0-7.0 112.5........................... 1.5-6.0
100.......................................... 2.0-7.0 150............................. 1.5-6.0
167.......................................... 2.5-8.0 225............................. 3.0-7.0
250.......................................... 3.5-8.0 300............................. 3.0-7.0
333.......................................... 3.5-8.0 500............................. 4.5-8.0
500.......................................... 3.5-8.0 750............................. 5.0-8.0
667.......................................... 5.0-8.0 1,000........................... 5.0-8.0
833.......................................... 5.0-8.0 1,500........................... 5.0-8.0
2,000........................... 5.0-8.0
2,500........................... 5.0-8.0
3,750........................... 5.0-8.0
5,000........................... 5.0-8.0
----------------------------------------------------------------------------------------------------------------
Submersible Distribution Transformer means a liquid-immersed
distribution transformer so constructed as to be successfully operable
when submerged in water including the following features:
(1) Is rated for a temperature rise of 55[deg]C;
(2) Has insulation rated for a temperature rise of 65[deg]C;
(3) Has sealed-tank construction; and
(4) Has the tank, cover, and all external appurtenances made of
corrosion-resistant material.
* * * * *
Transformer with tap range of 20 percent or more means a
transformer with multiple full-power voltage taps,
[[Page 1856]]
the highest of which equals at least 20 percent more than the lowest,
computed based on the sum of the deviations of these taps from the
transformer's maximum full-power voltage.
Uninterruptible power supply transformer means a transformer that
is used within an uninterruptible power system, which in turn supplies
power to loads that are sensitive to power failure, power sages, over
voltage, switching transients, line notice, and other power quality
factors. It does not include distribution transformers at the input,
output, or by-pass of an uninterruptible power system.
* * * * *
0
3. Amend Sec. 431.196 by:
0
a. Revising paragraph (a)(2) and adding paragraph (a)(3),
0
b. Revising paragraph (b)(2) and adding paragraphs (b)(3) through (4),
and
0
c. Revising paragraph (c)(2) and adding paragraph (c)(3).
The revisions and additions read as follows:
Sec. 431.196 Energy conservation standards and their effective dates.
(a) * * *
(2) The efficiency of a low-voltage, dry-type distribution
transformer manufactured on or after January 1, 2016, but before
January 1, 2027, shall be no less than that required for the applicable
kVA rating in the table below. Low-voltage dry-type distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA kVA
----------------------------------------------------------------------------------------------------------------
15........................................... 97.70 15.............................. 97.89
25........................................... 98.00 30.............................. 98.23
37.5......................................... 98.20 45.............................. 98.40
50........................................... 98.30 75.............................. 98.60
75........................................... 98.50 112.5........................... 98.74
100.......................................... 98.60 150............................. 98.83
167.......................................... 98.70 225............................. 98.94
250.......................................... 98.80 300............................. 99.02
333.......................................... 98.90 500............................. 99.14
750............................. 99.23
1000............................ 99.28
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test
Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to subpart K of 10
CFR part 431.
(3) The efficiency of a low-voltage dry-type distribution
transformer manufactured on or after January 1, 2027, shall be no less
than that required for their kVA rating in the table below. Low-voltage
dry-type distribution transformers with kVA ratings not appearing in
the table shall have their minimum efficiency level determined by
linear interpolation of the kVA and efficiency values immediately above
and below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
15........................................... 98.84 15.............................. 98.72
25........................................... 98.99 30.............................. 98.93
37.5......................................... 99.09 45.............................. 99.03
50........................................... 99.14 75.............................. 99.16
75........................................... 99.24 112.5........................... 99.24
100.......................................... 99.30 150............................. 99.29
167.......................................... 99.35 225............................. 99.36
250.......................................... 99.40 300............................. 99.41
333.......................................... 99.45 500............................. 99.48
750............................. 99.54
1000............................ 99.57
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test
Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to subpart K of 10
CFR part 431.
(b) * * *
(2) The efficiency of a liquid-immersed distribution transformer,
including submersible distribution transformers, manufactured on or
after January 1, 2016, but before January 1, 2027, shall be no less
than that required for their kVA rating in the table below. Liquid-
immersed distribution transformers, including submersible distribution
transformers, with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
[[Page 1857]]
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................... 98.70 15.............................. 98.65
15........................................... 98.82 30.............................. 98.83
25........................................... 98.95 45.............................. 98.92
37.5......................................... 99.05 75.............................. 99.03
50........................................... 99.11 112.5........................... 99.11
75........................................... 99.19 150............................. 99.16
100.......................................... 99.25 225............................. 99.23
167.......................................... 99.33 300............................. 99.27
250.......................................... 99.39 500............................. 99.35
333.......................................... 99.43 750............................. 99.40
500.......................................... 99.49 1,000........................... 99.43
667.......................................... 99.52 1,500........................... 99.48
833.......................................... 99.55 2,000........................... 99.51
2,500........................... 99.53
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-
Procedure, appendix A to subpart K of 10 CFR part 431.
(3) The efficiency of a liquid-immersed distribution transformer,
that is not a submersible distribution transformer, manufactured on or
after January 1, 2027, shall be no less than that required for their
kVA rating in the table below. Liquid-immersed distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................... 98.96 15.............................. 98.92
15........................................... 99.05 30.............................. 99.06
25........................................... 99.16 45.............................. 99.13
37.5......................................... 99.24 75.............................. 99.22
50........................................... 99.29 112.5........................... 99.29
75........................................... 99.35 150............................. 99.33
100.......................................... 99.40 225............................. 99.38
167.......................................... 99.46 300............................. 99.42
250.......................................... 99.51 500............................. 99.48
333.......................................... 99.54 750............................. 99.52
500.......................................... 99.59 1,000........................... 99.54
667.......................................... 99.62 1,500........................... 99.58
833.......................................... 99.64 2,000........................... 99.61
2,500........................... 99.62
3,750........................... 99.66
5,000........................... 99.68
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test
Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to subpart K of 10
CFR part 431.
(4) The efficiency of a submersible distribution transformer,
manufactured on or after January 1, 2027, shall be no less than that
required for their kVA rating in the table below. Submersible
distribution transformers with kVA ratings not appearing in the table
shall have their minimum efficiency level determined by linear
interpolation of the kVA and efficiency values immediately above and
below that kVA rating.
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
kVA Efficiency (%) kVA Efficiency (%)
----------------------------------------------------------------------------------------------------------------
10........................................... 98.70 15.............................. 98.65
15........................................... 98.82 30.............................. 98.83
25........................................... 98.95 45.............................. 98.92
37.5......................................... 99.05 75.............................. 99.03
50........................................... 99.11 112.5........................... 99.11
75........................................... 99.19 150............................. 99.16
100.......................................... 99.25 225............................. 99.23
167.......................................... 99.33 300............................. 99.27
250.......................................... 99.39 500............................. 99.35
333.......................................... 99.43 750............................. 99.40
500.......................................... 99.49 1,000........................... 99.43
[[Page 1858]]
667.......................................... 99.52 1,500........................... 99.48
833.......................................... 99.55 2,000........................... 99.51
2,500........................... 99.53
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-
Procedure appendix A to subpart K of 10 CFT part 431.
(c) * * *
(2) The efficiency of a medium-voltage dry-type distribution
transformer manufactured on or after January 1, 2016, but before
January 1, 2027, shall be no less than that required for their kVA and
BIL rating in the table below. Medium-voltage dry-type distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL BIL
------------------------------------------------- -----------------------------------------------
kVA 20-45 kV 46-95 kV >=96 kV kVA 20-45 kV 46-95 kV >=96 kV
------------------------------------------------- -----------------------------------------------
Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 98.10 97.86 ............... 15.................. 97.50 97.18 ..............
25............................... 98.33 98.12 ............... 30.................. 97.90 97.63 ..............
37.5............................. 98.49 98.30 ............... 45.................. 98.10 97.86 ..............
50............................... 98.60 98.42 ............... 75.................. 98.33 98.13 ..............
75............................... 98.73 98.57 98.53 112.5............... 98.52 98.36 ..............
100.............................. 98.82 98.67 98.63 150................. 98.65 98.51 ..............
167.............................. 98.96 98.83 98.80 225................. 98.82 98.69 98.57
250.............................. 99.07 98.95 98.91 300................. 98.93 98.81 98.69
333.............................. 99.14 99.03 98.99 500................. 99.09 98.99 98.89
500.............................. 99.22 99.12 99.09 750................. 99.21 99.12 99.02
667.............................. 99.27 99.18 99.15 1,000............... 99.28 99.20 99.11
833.............................. 99.31 99.23 99.20 1,500............... 99.37 99.30 99.21
2,000............... 99.43 99.36 99.28
2,500............... 99.47 99.41 99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means basic impulse insulation level
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
(3) The efficiency of a medium- voltage dry-type distribution
transformer manufactured on or after January 1, 2027, shall be no less
than that required for their kVA and BIL rating in the table below.
Medium-voltage dry-type distribution transformers with kVA ratings not
appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
BIL BIL
------------------------------------------------- -----------------------------------------------
kVA 20-45 kV 46-95 kV >=96 kV kVA 20-45 kV 46-95 kV >=96 kV
------------------------------------------------- -----------------------------------------------
Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%) Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 98.29 98.07 ............... 15.................. 97.74 97.45 ..............
25............................... 98.49 98.30 ............... 30.................. 98.11 97.86 ..............
37.5............................. 98.64 98.47 ............... 45.................. 98.29 98.07 ..............
50............................... 98.74 98.58 ............... 75.................. 98.49 98.31 ..............
75............................... 98.86 98.71 98.68 112.5............... 98.67 98.52 ..............
100.............................. 98.94 98.80 98.77 150................. 98.78 98.66 ..............
167.............................. 99.06 98.95 98.92 225................. 98.94 98.82 98.71
250.............................. 99.16 99.05 99.02 300................. 99.04 98.93 98.82
333.............................. 99.23 99.13 99.09 500................. 99.18 99.09 99.00
500.............................. 99.30 99.21 99.18 750................. 99.29 99.21 99.12
667.............................. 99.34 99.26 99.23 1,000............... 99.35 99.28 99.20
833.............................. 99.38 99.31 99.28 1,500............... 99.43 99.37 99.29
2,000............... 99.49 99.42 99.35
2,500............... 99.52 99.47 99.40
[[Page 1859]]
3,750............... 99.58 99.53 99.47
5,000............... 99.62 99.58 99.51
--------------------------------------------------------------------------------------------------------------------------------------------------------
* BIL means basic impulse insulation level
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
of Distribution Transformers under appendix A to subpart K of 10 CFR part 431.
* * * * *
[FR Doc. 2022-28590 Filed 1-10-23; 8:45 am]
BILLING CODE 6450-01-P
