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Rule2024-07480

Energy Conservation Program: Energy Conservation Standards for Distribution Transformers

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Published

April 22, 2024

Effective

July 8, 2024

Issuing agencies

Energy Department

Abstract

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 review its existing standards to determine whether more stringent standards would be technologically feasible and economically justified, and would result in significant energy savings. In this final rule, DOE is adopting amended energy conservation standards for distribution transformers. It has determined that the amended energy conservation standards for these products would result in significant conservation of energy, and are technologically feasible and economically justified.

Full Text

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[Federal Register Volume 89, Number 78 (Monday, April 22, 2024)]
[Rules and Regulations]
[Pages 29834-30043]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-07480]

[[Page 29833]]

Vol. 89

Monday,

No. 78

April 22, 2024

Part III

Department of Energy

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10 CFR Part 431

Energy Conservation Program: Energy Conservation Standards for
Distribution Transformers; Final Rule

Federal Register / Vol. 89, No. 78 / Monday, April 22, 2024 / Rules
and Regulations

[[Page 29834]]

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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: Final rule.

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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 review its existing standards to determine whether more
stringent standards would be technologically feasible and economically
justified, and would result in significant energy savings. In this
final rule, DOE is adopting amended energy conservation standards for
distribution transformers. It has determined that the amended energy
conservation standards for these products would result in significant
conservation of energy, and are technologically feasible and
economically justified.

DATES: The effective date of this rule is July 8, 2024. Compliance with
the amended standards established for distribution transformers in this
final rule is required on and after April 23, 2029.

ADDRESSES: The docket for this rulemaking, which includes Federal
Register notices, public meeting attendee lists and transcripts,
comments, and other supporting documents/materials, is available for
review at <a href="http://www.regulations.gov">www.regulations.gov</a>. All documents in the docket are listed
in the <a href="http://www.regulations.gov">www.regulations.gov</a> 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 <a href="http://www.regulations.gov/docket/EERE-2019-BT-STD-0018">www.regulations.gov/docket/EERE-2019-BT-STD-0018</a>. The docket web page contains instructions on how
to access all documents, including public comments, in the docket.
For further information on how to review the docket, contact the
Appliance and Equipment Standards Program staff at (202) 287-1445 or by
email: <a href="/cdn-cgi/l/email-protection#470637372b2e2629242214332629232635233416322234332e2829340722226923282269202831">[email&#160;protected]</a>.

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. Email:
<a href="/cdn-cgi/l/email-protection#6d2c1d1d01040c030e083e190c03090c1f091e3c18081e190402031e2d080843090208430a021b">[email&#160;protected]</a>.
Mr. Matthew Schneider, U.S. Department of Energy, Office of the
General Counsel, GC-33, 1000 Independence Avenue SW, Washington, DC
20585-0121. Telephone: (202) 597-6265. Email:
<a href="/cdn-cgi/l/email-protection#2c414d585844495b025f4f4442494548495e6c445d02484349024b435a">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Synopsis of the Final 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
III. General Discussion
A. General Comments
B. Equipment Classes and Scope of Coverage
C. Test Procedure
D. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
E. Energy Savings
1. Determination of Savings
2. Significance of Savings
F. 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 Non-Ventilated Transformers
f. Step-Up Transformers
g. Uninterruptible Power Supply Transformers
h. Voltage Specification
i. kVA Range
2. Equipment Classes
a. Submersible Transformers
b. Large Single-Phase Transformers
c. Large Three-Phase Transformers With High-Currents
d. Multi-Voltage Capable Distribution Transformers
e. Data Center Distribution Transformers
f. BIL Rating
g. Other
3. Technology Options
4. Transformer Core Material Technology and Market Assessment
a. Amorphous Alloy Market and Technology
b. Grain-Oriented Electrical Steel Market and Technology
c. Transformer Core Production Dynamics
5. Distribution Transformer Supply Chain
B. Screening Analysis
1. Screened-Out Technologies
2. Remaining Technologies
C. Engineering Analysis
1. Efficiency Analysis
a. Representative Units
b. Data Validation
c. Baseline Energy Use
d. Higher Efficiency Levels
e. kVA Scaling
2. Cost Analysis
a. Electrical Steel Prices
b. Other Material Prices
3. Cost-Efficiency Results
D. Markups Analysis
E. Energy Use Analysis
1. Trial Standard Levels
2. Hourly Load Model
a. Low-Voltage and Medium-Voltage Dry-Type Distribution
Transformers Data Sources
3. Future Load Growth
a. Liquid-Immersed Distribution Transformers
F. Life-Cycle Cost and Payback Period Analysis
1. Equipment Cost
2. Efficiency Levels
3. Modeling Distribution Transformer Purchase Decision
a. Equipment Selection
b. Total Owning Cost and Evaluators
c. Non-Evaluators and First Cost Purchases
4. Installation Cost
a. Overall Size Increase
b. Liquid-Immersed
c. Overhead (Pole) Mounted Transformers
d. Surface (Pad) Mounted Transformers
e. Logistics and Hoisting
f. Installation of Ancillary Equipment: Gas Monitors and Fuses
g. Low-Voltage Dry-Type
5. Annual Energy Consumption
6. Energy Prices
7. Maintenance and Repair Costs
8. Transformer Service 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)
3. Rewound and Rebuilt Equipment

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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
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
c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
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 Subgroups of Manufacturers
e. Cumulative Regulatory Burden
3. National Impact Analysis
a. National 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 Transformer Standards
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-
Type Distribution Transformer Standards
3. Benefits and Burdens of TSLs Considered for Medium-Voltage
Dry-Type Distribution Transformer Standards
4. Annualized Benefits and Costs of the Adopted Standards for
Liquid-Immersed Distribution Transformers
5. Annualized Benefits and Costs of the Adopted Standards for
Low-Voltage Dry-Type Distribution Transformers
6. Annualized Benefits and Costs of the Adopted Standards for
Medium-Voltage Dry-Type Distribution Transformers
7. Benefits and Costs of the Proposed Standards for all
Considered Distribution Transformers
8. Severability
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866, 13563, and 14094
B. Review Under the Regulatory Flexibility Act
1. Need for, and Objectives of, Rule
2. Significant Issues Raised by Public Comments in Response to
the IRFA
3. Description and Estimated Number of Small Entities Affected
4. Description of Reporting, Recordkeeping, and Other Compliance
Requirements
5. Significant Alternatives Considered and Steps Taken To
Minimize Significant Economic Impacts on Small Entities
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
M. Congressional Notification
VII. Approval of the Office of the Secretary

I. Synopsis of the Final Rule

The Energy Policy and Conservation Act, Public Law 94-163, as
amended (EPCA),\1\ authorizes DOE to regulate the energy efficiency of
a number of consumer products and certain industrial equipment. (42
U.S.C. 6291-6317, as codified) Title III, Part B of EPCA \2\
established the Energy Conservation Program for Consumer Products Other
Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part C of the EPCA,
as amended,\3\ established the Energy Conservation Program for Certain
Industrial Equipment. (42 U.S.C. 6311-6317) 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 determined 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 (LVDT) distribution transformers. (42 U.S.C. 6295(y))
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\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 redesignated Part A.
\3\ For editorial reasons, upon codification in the U.S. Code,
Part C was redesignated 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.
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Pursuant to EPCA, DOE is required to review its existing energy
conservation standards for covered equipment no later than six years
after issuance of any final rule establishing or amending a standard.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1)) Pursuant to that statutory
provision, DOE must publish either a notification of determination that
standards for the product do not need to be amended, or a notice of
proposed rulemaking (NOPR) including new proposed energy conservation
standards (proceeding to a final rule, as appropriate). (Id.) 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 significant conservation of energy. (42 U.S.C.
6295(o)(3)(B)) DOE has conducted this review of the energy conservation
standards for distribution transformers under EPCA's six-year-lookback
authority. (Id.)
In accordance with these and other statutory provisions discussed
in this document, DOE analyzed the benefits and burdens of five trial
standard levels (TSLs) for liquid-immersed distribution transformers,
low-voltage dry-type and medium-voltage dry-type distribution
transformers. The TSLs and their associated benefits and burdens are
discussed in detail in sections V.A through V.C of this document. As
discussed in section V.C of this document, DOE has determined that TSL
3 for liquid-immersed distribution transformers, which corresponds to a
5 percent reduction in losses for single-phase transformers less than
or equal to 100 kVA and three-phase transformers greater than or equal
to 500 kVA and a 20 percent reduction in losses for single-phase
transformers greater than 100 kVA and three-phase transformers less
than 500 kVA, represents the maximum improvement in energy efficiency
that is technologically feasible and economically justified. For low-
voltage dry-type distribution transformers, DOE

[[Page 29836]]

has determined that TSL 3, corresponding to a 30 percent reduction in
losses for single-phase low-voltage dry-type distribution transformers,
20 percent reduction in losses for three-phase low-voltage dry-type
distribution transformers represents the maximum improvement in energy
efficiency that is technologically feasible and economically justified.
For medium-voltage dry-type distribution transformers, DOE has
determined that TSL 2 for medium-voltage dry-type (MVDT), corresponding
to a 20 percent reduction in losses, represents the maximum improvement
in energy efficiency that is technologically feasible and economically
justified. The adopted standards, which are expressed in efficiency as
a percentage, are shown in Table I.1 through Table I.3. These standards
apply to all equipment listed in Table I.1 through Table I.3 and
manufactured in, or imported into, the United States starting on April
23, 2029.
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A. Benefits and Costs to Consumers

Table I.4 summarizes DOE's evaluation of the economic impacts of
the adopted 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 equipment class
10 (e,g., medium-voltage, dry-type, three-phase with a BIL of greater
than 96 kV and kVA range of 225-5000), 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
final rule, the term <gr-thn-eq>consumer<gr-thn-eq> refers to different
populations that purchase and bear the operating costs of distribution
transformers. Consumers vary by transformer category: for medium-
voltage liquid-immersed distribution transformers, the term
<gr-thn-eq>consumer<gr-thn-eq> refers to electric utilities; for low-
and medium-voltage dry-type distribution transformers, the term
<gr-thn-eq>consumer<gr-thn-eq> refers to COMMERCIAL AND INDUSTRIAL
entities.
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\4\ The average LCC savings 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
(see section IV.F.10 of this document). The simple PBP, which is
designed to compare specific efficiency levels, is measured relative
to the baseline product (see section IV.C of this document).
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DOE's analysis of the impacts of the adopted 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 (2024-2058). Using a real discount rate of 7.4 percent
for liquid-immersed distribution transformers, 11.1 percent for LVDT
distribution transformers, and 9.0 percent for MVDT distribution
transformers, DOE estimates that the INPV for manufacturers of
distribution transformers in the case without amended standards is
$1,792 million in 2022 dollars for liquid-immersed distribution
transformers, $212 million in 2022 dollars for LVDT distribution
transformers, and $95 million in 2022 dollars for MVDT distribution
transformers. Under the adopted standards, the change in INPV is
estimated to range from -8.1 percent to -6.2 percent for liquid-
immersed distribution transformers which represents a change in INPV of
approximately -$145 million to -$111 million; from -12.8 percent to -
8.9 percent for LVDT distribution transformers, which represents a
change in INPV of approximately -$27.1 million to -$18.9 million; and -
4.7 percent to -2.5 percent for MVDT distribution transformers, which
represents a change in INPV of approximately -$4.4 million to -$2.3
million. In order to bring products into compliance with amended
standards, it is estimated that the industry would incur total
conversion costs of $187 million for liquid-immersed distribution
transformer, $36.1 million for LVDT distribution transformers, and $5.7
million for MVDT distribution transformers.
DOE's analysis of the impacts of the adopted standards on
manufacturers is described in sections IV.J and V.B.2 of this document.

C. National Benefits and Costs \5\
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\5\ All monetary values in this document are expressed in 2022
dollars and, where appropriate, are discounted to 2024 from the year
of compliance (2029) unless explicitly stated otherwise.
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1. Liquid-Immersed Distribution Transformers
DOE's analyses indicate that the adopted energy conservation
standards for 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 (2029-2058) amount to 2.73 quadrillion
British thermal units (Btu), or quads.\6\ This represents a savings of
13 percent relative to the energy use of these products in the case
without amended standards (referred to as the ``no-new-standards
case'').
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\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 of this document.
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The cumulative net present value (NPV) of total consumer benefits
of the standards for liquid-immersed distribution transformers ranges
from $0.56 billion (at a 7-percent discount rate) to $3.41 billion (at
a 3-percent discount rate). This NPV expresses the estimated total
value of future operating-cost savings minus the estimated increased
product and installation costs for distribution transformers purchased
in 2029-2058.
In addition, the adopted standards for liquid-immersed distribution
transformers are projected to yield significant environmental benefits.
DOE estimates that the standards will result in cumulative emission
reductions (over the same period as for energy savings) of 51.40
million metric tons (Mt) \7\ of carbon dioxide (CO<INF>2</INF>), 12.29
thousand tons of sulfur dioxide (SO<INF>2</INF>), 89.85 thousand tons
of nitrogen oxides (NO<INF>X</INF>), 416.15 thousand tons of methane
(CH<INF>4</INF>), 0.40 thousand tons of nitrous oxide (N<INF>2</INF>O),
and 0.08 tons of mercury (Hg).\8\
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\7\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO<INF>2</INF> 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 2023 (AEO2023). AEO2023 reflects, to the extent possible,
laws and regulations adopted through mid-November 2022, including
the Inflation Reduction Act. See section IV.K of this document for
further discussion of AEO2023 assumptions that affect air pollutant
emissions.
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DOE estimates the value of climate benefits from a reduction in
greenhouse gases (GHG) using four different estimates of the social
cost of CO<INF>2</INF> (SC-CO<INF>2</INF>), the social cost of methane
(SC-CH<INF>4</INF>), and the social cost of nitrous oxide (SC-
N<INF>2</INF>O).\9\ Together these represent the social cost of GHG
(SC-GHG). DOE used interim SC-GHG values (in terms of benefit-per-ton
of GHG avoided) developed by an Interagency Working Group on the Social
Cost of Greenhouse Gases (IWG).\10\ The derivation of these values is
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 estimated to be $1.85 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 sets of SC-GHG estimates.
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\9\ Estimated climate-related benefits are provided in
compliance with Executive Order 12866.
\10\ To monetize the benefits of reducing GHG emissions, this
analysis uses the interim estimates presented in the February 2021
SC-GHG TSD. <a href="http://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf">www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf</a>.

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[[Page 29839]]

DOE estimated the monetary health benefits of SO<INF>2</INF> and
NO<INF>X</INF> emissions reductions, using benefit-per-ton estimates
from the Environmental Protection Agency,\11\ as discussed in section
IV.L of this document. DOE estimated the present value of the health
benefits would be $1.11 billion using a 7-percent discount rate, and
$3.71 billion using a 3-percent discount rate.\12\ DOE is currently
only monetizing health benefits from changes in ambient fine
particulate matter (PM<INF>2.5</INF>) concentrations from two
precursors (SO<INF>2</INF> and NO<INF>X</INF>), and from changes in
ambient ozone from one precursor (NO<INF>X</INF>), but will continue to
assess the ability to monetize other effects such as health benefits
from reductions in direct PM<INF>2.5</INF> emissions.
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\11\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM<INF>2.5</INF>, PM<INF>2.5</INF> Precursors and
Ozone Precursors from 21 Sectors. Available at <a href="http://www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors">www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors</a>.
\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.
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Table I.5 summarizes the monetized benefits and costs expected to
result from the amended standards for liquid-immersed distribution
transformers. There are other important unquantified effects, including
certain unquantified climate benefits, unquantified public health
benefits from the reduction of toxic air pollutants and other
emissions, unquantified energy security benefits, and distributional
effects, among others.
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BILLING CODE 6450-01-C
The benefits and costs of the adopted 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 climate and health benefits
of emission reductions, all annualized.\13\
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\13\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, 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., 2020 or 2030), and then discounted the present value from
each year to 2024. 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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The national operating cost 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 distribution
transformers shipped in 2029-2058. The benefits associated with reduced
emissions achieved as a result of the adopted standards are also
calculated based on the lifetime of liquid-immersed distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\14\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
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\14\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
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Table I.6 presents the total estimated monetized benefits and costs
associated with the adopted standard, expressed in terms of annualized
values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO<INF>2</INF> reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
liquid-immersed distribution transformers is $151.1 million per year in
increased equipment installed costs, while the estimated annual
benefits are $210.2 million from reduced equipment operating costs,
$106.1 million in GHG reductions, and $117.0 million from reduced
NO<INF>X</INF> and SO<INF>2</INF> emissions. In this case, the net
benefit amounts to $282.3 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for liquid-immersed
distribution transformers is $152.6 million per year in increased
equipment costs, while the estimated annual benefits are $348.3 million
in reduced operating costs, $106.1 million from GHG reductions, and
$213.2 million from reduced NO<INF>X</INF> and SO<INF>2</INF>
emissions. In this case, the net benefit amounts to $515.1 million per
year.
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BILLING CODE 6450-01-C
2. Low-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted energy conservation
standards for 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 (2029-2058) amount to 1.71
quadrillion Btu, or quads.\15\ This represents a savings of 35 percent
relative to the energy use of these products in the no-new-standards
case.
---------------------------------------------------------------------------

\15\ The quantity refers to 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 of this document.
---------------------------------------------------------------------------

The cumulative NPV of total consumer benefits of the standards for
low-voltage dry-type distribution transformers ranges from $2.08
billion (at a 7-percent discount rate) to 6.68 billion (at a 3-percent
discount rate). This NPV expresses the estimated total value of future
operating-cost savings minus the estimated increased product and
installation costs for distribution transformers purchased in 2029-
2058.
In addition, the adopted standards for low-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the standards will result in
cumulative emission reductions (over the same period as for energy
savings) of 31.28 million Mt \16\ of CO<INF>2</INF>, 7.49 thousand tons
of SO<INF>2</INF>, 55.92 thousand tons of NO<INF>X</INF>, 259.96
thousand tons of CH<INF>4</INF>, 0.24 thousand tons of N<INF>2</INF>O,
and 0.05 tons of Hg.\17\
---------------------------------------------------------------------------

\16\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO<INF>2</INF> are presented in short tons.
\17\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the AEO2023.
AEO2023 reflects, to the extent possible, laws and regulations
adopted through mid-November 2022, including the Inflation Reduction
Act. See section IV.K of this document for further discussion of
AEO2023 assumptions that affect air pollutant emissions.
---------------------------------------------------------------------------

DOE estimates the value of climate benefits from a reduction in GHG
using four different estimates of the SC-<INF>CO2</INF>CO<INF>2</INF>,
the SC-CH<INF>4</INF>, and the SC-N<INF>2</INF>O. Together these
represent the SC-GHG. \DOE\ used interim SC-GHG values (in terms of
benefit per ton of GHG avoided) developed by an IWG.\18\ The derivation
of these values is 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 estimated to be $1.23
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 sets of SC-GHG estimates.
---------------------------------------------------------------------------

\18\ To monetize the benefits of reducing GHG emissions, this
analysis uses values that are based on the February 2021 SC-GHG TSD.
<a href="http://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf">www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf</a>.
---------------------------------------------------------------------------

[[Page 29844]]

small. DOE estimated the present value of the health benefits would be
$0.76 billion using a 7-percent discount rate, and $2.42 billion using
a 3-percent discount rate.\20\ DOE is currently only monetizing health
benefits from changes in ambient PM<INF>2.5</INF> concentrations from
two precursors (SO<INF>2</INF> and NO<INF>X</INF>), and from changes in
ambient ozone from one precursor (for NO<INF>X</INF>), but will
continue to assess the ability to monetize other effects such as health
benefits from reductions in direct PM<INF>2.5</INF> emissions.
---------------------------------------------------------------------------

\19\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM<INF>2.5</INF>, PM<INF>2.5</INF> Precursors and
Ozone Precursors from 21 Sectors. Available at <a href="http://www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors">www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors</a>.
\20\ 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 amended standards for low-voltage dry-type distribution
transformers. There are other important unquantified effects, including
certain unquantified climate benefits, unquantified public health
benefits from the reduction of toxic air pollutants and other
emissions, unquantified energy security benefits, and distributional
effects, among others.
BILLING CODE 6450-01-P
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[[Page 29845]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.510

BILLING CODE 6450-01-C
The benefits and costs of the adopted 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 climate and health benefits
of emission reductions, all annualized.\21\
---------------------------------------------------------------------------

\21\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, 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., 2020 or 2030), and then discounted the present value from
each year to 2024. 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.
---------------------------------------------------------------------------

The national operating cost 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 distribution
transformers shipped in 2029-2058. The benefits associated with reduced
emissions achieved as a result of the adopted standards are also
calculated based on the lifetime of low-voltage dry-type distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\22\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
---------------------------------------------------------------------------

\22\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
---------------------------------------------------------------------------

Table I.8 presents the total estimated monetized benefits and costs
associated with the adopted standard, expressed in terms of annualized
values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO<INF>2</INF> reductions, and the 3-percent discount rate case
for GHG social costs, the estimated cost of the adopted standards for
low-voltage dry-type is $66.6 million per year in increased equipment
installed costs, while the estimated annual benefits are $286.8 million
from reduced equipment operating costs, $70.4 million in GHG
reductions, and $80.3 million from reduced NO<INF>X</INF> and
SO<INF>2</INF> emissions. In this case, the net benefit amounts to
$370.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of

[[Page 29846]]

the adopted standards for low-voltage dry-type is $67.4 million per
year in increased equipment costs, while the estimated annual benefits
are $450.9 million in reduced operating costs, $70.4 million from GHG
reductions, and $139.1 million from reduced NO<INF>X</INF> and
SO<INF>2</INF> emissions. In this case, the net benefit amounts to
$593.0 million per year.
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BILLING CODE 6450-01-C
3. Medium-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted 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 distribution
transformers purchased in the 30-year period that begins in the
anticipated year of compliance with the amended standards (2029-2058)
amount to 0.14 quadrillion Btu, or quads.\23\ This represents a savings
of 9 percent relative to the energy use of these products in the no-
new-standards case.
---------------------------------------------------------------------------

\23\ The quantity refers to 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 of this document.
---------------------------------------------------------------------------

The cumulative NPV of total consumer benefits of the standards for
medium-voltage dry-type distribution transformers ranges from $0.03 (at
a 7-percent discount rate) to $0.22 (at a 3-percent discount rate).
This NPV expresses the estimated total value of future operating-cost
savings minus the estimated increased product and installation costs
for distribution transformers purchased in 2029-2058.
In addition, the adopted standards for medium-voltage dry-type
distribution transformers are projected to yield significant
environmental benefits. DOE estimates that the standards will result in
cumulative emission reductions (over the same period as for energy
savings) of 2.59 million Mt \24\ of CO<INF>2</INF>, 0.63 thousand tons
of SO<INF>2</INF>, 4.69 thousand tons of NO<INF>X</INF>, 21.86 thousand
tons of CH<INF>4</INF>, 0.02 thousand tons of N<INF>2</INF>O, and 0.00
tons of Hg.\25\
---------------------------------------------------------------------------

\24\ A metric ton is equivalent to 1.1 short tons. Results for
emissions other than CO<INF>2</INF> are presented in short tons.
\25\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the AEO2023.
AEO2023 reflects, to the extent possible, laws and regulations
adopted through mid-November 2022, including the Inflation Reduction
Act. See section IV.K of this document for further discussion of
AEO2023 assumptions that affect air pollutant emissions.
---------------------------------------------------------------------------

DOE estimates the value of climate benefits from a reduction in GHG
using four different estimates of the SC-CO<INF>2</INF>, the SC-
CH<INF>4</INF>, and the SC-N<INF>2</INF>O. Together these represent the
SC-GHG. DOE used interim SC-GHG values (in terms of benefit per ton of
GHG avoided) developed by an IWG.\26\ The derivation of these values is
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 estimated to be $0.10 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 sets of SC-GHG estimates.
---------------------------------------------------------------------------

\26\ To monetize the benefits of reducing GHG emissions, this
analysis uses values that are based on the February 2021 SC-GHG TSD.
<a href="http://www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf">www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf</a>.
---------------------------------------------------------------------------

DOE estimated the monetary health benefits of SO<INF>2</INF> and
NO<INF>X</INF> emissions reductions, using benefit per ton estimates
from the Environmental Protection Agency,\27\ as discussed in section
IV.L of this document. DOE did not monetize the reduction in mercury
emissions because the quantity is very small. DOE estimated the present
value of the health benefits would be $0.06 billion using a 7-percent
discount rate, and $0.20 billion using a 3-percent discount rate.\28\
DOE is currently only monetizing health benefits from changes in
ambient PM<INF>2.5</INF> concentrations from two precursors
(SO<INF>2</INF> and NO<INF>X</INF>), and from changes in ambient ozone
from one precursor (for NO<INF>X</INF>), but will continue to assess
the ability to monetize other

[[Page 29849]]

effects such as health benefits from reductions in direct
PM<INF>2.5</INF> emissions.
---------------------------------------------------------------------------

\27\ U.S. EPA. Estimating the Benefit per Ton of Reducing
Directly Emitted PM<INF>2.5</INF>, PM<INF>2.5</INF> Precursors and
Ozone Precursors from 21 Sectors. Available at <a href="http://www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors">www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors</a>.
\28\ 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 amended standards for medium-voltage dry-type
distribution transformers. There are other important unquantified
effects, including certain unquantified climate benefits, unquantified
public health benefits from the reduction of toxic air pollutants and
other emissions, unquantified energy security benefits, and
distributional effects, among others.
BILLING CODE 6450-01-P

[[Page 29850]]

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[[Page 29851]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.514

BILLING CODE 6450-01-C
The benefits and costs of the adopted 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 climate and health benefits
of emission reductions, all annualized.\29\
---------------------------------------------------------------------------

\29\ To convert the time-series of costs and benefits into
annualized values, DOE calculated a present value in 2024, 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., 2020 or 2030), and then discounted the present value from
each year to 2024. 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.
---------------------------------------------------------------------------

The national operating cost 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 2029-2058. The benefits
associated with reduced emissions achieved as a result of the adopted
standards are also calculated based on the lifetime of distribution
transformers shipped in 2029-2058. Total benefits for both the 3-
percent and 7-percent cases are presented using the average GHG social
costs with a 3-percent discount rate.\30\ Estimates of total benefits
are presented for all four SC-GHG discount rates in section IV.L of
this document.
---------------------------------------------------------------------------

\30\ As discussed in section IV.L.1 of this document, DOE agrees
with the IWG that using consumption-based discount rates e.g., 3
percent) is appropriate when discounting the value of climate
impacts. Combining climate effects discounted at an appropriate
consumption-based discount rate with other costs and benefits
discounted at a capital-based rate (i.e., 7 percent) is reasonable
because of the different nature of the types of benefits being
measured.
---------------------------------------------------------------------------

Table I.10 presents the total estimated monetized benefits and
costs associated with the adopted standard, expressed in terms of
annualized values. The results under the primary estimate are as
follows.
Using a 7-percent discount rate for consumer benefits and costs and
NO<INF>X</INF> and SO<INF>2</INF> reductions, and the 3-percent
discount rate case for GHG social costs, the estimated cost of the
adopted standards for medium-voltage dry-type is $12.5 million per year
in increased equipment installed costs, while the estimated annual
benefits are $15.9 million from reduced equipment operating costs, $5.9
million in GHG reductions, and $6.7 million from reduced NO<INF>X</INF>
and SO<INF>2</INF> emissions. In this case, the net benefit amounts to
$16.0 million per year.
Using a 3-percent discount rate for all benefits and costs, the
estimated cost of the adopted standards for medium-voltage dry-type
distribution transformers is $12.7 million per year in increased
equipment costs, while the estimated annual benefits are $25.1 million
in reduced operating costs, $5.9 million from GHG reductions, and $11.7
million from reduced NO<INF>X</INF> and SO<INF>2</INF> emissions. In
this case, the net benefit amounts to $29.9 million per year.
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[[Page 29853]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.516

BILLING CODE 6450-01-C
DOE's analysis of the national impacts of the adopted standards is
described in sections IV.H, IV.K, and IV.L of this document.

D. Conclusion

DOE concludes that the standards adopted in this final rule
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 are already commercially
available which either achieve these standard levels or utilize the
technologies required to achieve these standard levels for all product
classes covered by this proposal. As for economic justification, DOE's
analysis shows that the benefits of the standards exceed, to a great
extent, the burdens of the standards.
Table I.11 shows the annualized values for all distribution
transformers under amended standards, expressed in 2022$. The results
under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and
NOx and SO<INF>2</INF> reduction benefits, and a 3-percent discount
rate case for GHG social costs, the estimated cost of the standards for
distribution transformers is $ 230.3 million per year in increased
distribution transformers costs, while the estimated annual benefits
are $512.9 million in reduced distribution transformers operating
costs, $182.4 million in climate benefits, and $204.1 million in health
benefits. The net benefit amounts to $669.1 million per year. DOE notes
that the net benefits are substantial even in the absence of the
climate benefits,\31\ and DOE would adopt the same standards in the
absence of such benefits.
---------------------------------------------------------------------------

\31\ The information on climate benefits is provided in
compliance with Executive Order 12866.
---------------------------------------------------------------------------

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.\32\ 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. Accordingly, DOE evaluates
the significance of energy savings on a case-by-case basis.
---------------------------------------------------------------------------

\32\ 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 4.58 quads full fuel cycle (FFC),
the equivalent of the primary annual energy use of 49.2 million homes.
In addition, they are projected to reduce cumulative CO<INF>2</INF>
emissions by 85.27 Mt. Based on these findings, DOE has determined the
energy savings from the standard levels

[[Page 29854]]

adopted in this final rule are ``significant'' within the meaning of 42
U.S.C. 6295(o)(3)(B). A more detailed discussion of the basis for these
conclusions is contained in the remainder of this document and the
accompanying TSD.
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[[Page 29856]]

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[[Page 29858]]

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BILLING CODE 6450-01-C

II. Introduction

The following section briefly discusses the statutory authority
underlying this final 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. (42 U.S.C. 6291-
6317, as codified) Title III, Part B of EPCA established the Energy
Conservation Program for Consumer Products Other Than Automobiles. (42
U.S.C. 6291-6309) Title III, Part C of EPCA,\33\ as amended,
established the Energy Conservation Program for Certain Industrial
Equipment. (42 U.S.C. 6311-6317) 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,
also amended EPCA to establish energy conservation standards for low-
voltage dry-type distribution transformers. (42 U.S.C. 6295(y))
---------------------------------------------------------------------------

\33\ As noted previously, for editorial reasons, upon
codification in the U.S. Code, Part C was redesignated Part A-1.
---------------------------------------------------------------------------

EPCA further provides that, not later than six 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(a); 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 include definitions (42 U.S.C.
6311), test procedures (42 U.S.C. 6314), labeling provisions (42 U.S.C.
6315), energy conservation standards (42 U.S.C. 6313), and the
authority to require information and reports from manufacturers (42
U.S.C. 6316).
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 42 U.S.C. 6316(b); 42 U.S.C. 6297) DOE may, however,
grant waivers of Federal preemption in limited instances for particular
State laws or regulations, in accordance with the procedures and other
provisions set

[[Page 29859]]

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 product. (See 42
U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(A) and (r).) Manufacturers of
covered equipment must use the Federal test procedures as the basis for
certifying to DOE that their equipment complies with the applicable
energy conservation standards and as the basis for any representations
regarding the energy use or energy efficiency of the equipment. (42
U.S.C. 6316(a); 42 U.S.C. 6295(s); 42 U.S.C. 6314(d)). Similarly, DOE
must use these test procedures to evaluate whether a basic model
complies with the applicable energy conservation standard(s). (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 (``Secretary'') determines is technologically
feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(A)) Furthermore, DOE may not adopt any standard that would
not result in the significant conservation of energy. (42 U.S.C.
6316(a); 42 U.S.C. 6295(o)(3)(B))
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 establishment of such standard will not result in significant
conservation of energy (or, for certain products, water), or 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. Id. 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 equipment in the type (or class) compared to any
increase in the price, initial charges, or maintenance expenses for the
covered equipment 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
equipment 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 considers relevant.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(I)-(VII))
Further, EPCA, as codified, 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, as codified, 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
energy conservation standard for a covered product that has two or more
subcategories. A rule prescribing an energy conservation standard for a
type (or class) of product must specify a different standard level for
a type or class of products 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 equipment
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 considers such factors as the utility to
the consumer of such a 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
DOE most recently completed a review of its distribution
transformer standards in a final rule published on April 18, 2013
(``April 2013 Standards Final Rule''), through which 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, and Table II.3.
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BILLING CODE 6450-01-C
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 (TSD), which
announced the availability of its analysis for distribution
transformers. 86 FR 48058 (``August 2021 Preliminary Analysis TSD'').
The purpose of the August 2021 Preliminary Analysis TSD 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 TSD and
accompanying analytical spreadsheets for the August 2021 Preliminary
Analysis TSD provided the analyses DOE used to examine the potential
for amending energy conservation standards for distribution
transformers and provided preliminary discussions in response to a
number of issues raised in comments to the June 2019 Early Assessment
Review RFI. It described the analytical methodology that DOE used and
each analysis DOE performed.
On January 11, 2023, DOE published a NOPR and public meeting
announcement, in which DOE proposed amended energy conservation
standards for distribution transformers. 88 FR 1722 (``January 2023
NOPR''). DOE proposed amended standards for liquid-immersed, low-
voltage dry-type, and MVDT distribution transformers. DOE additionally
proposed to establish a separate equipment class for submersible
distribution transformers, with standards maintained at the levels
prescribed by the April 2013 Standards Final Rule. Id. On February 16,
2023, DOE presented the proposed standards and accompanying analysis in
a public meeting.
On February 22, 2023, DOE published a notice extending the comment
period for the January 2023 NOPR by an additional 14 days. 88 FR 10856.
DOE received 93 comments in response to the January 2023 NOPR from
the interested parties listed in Table II.4.
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BILLING CODE 6450-01-C
A parenthetical reference at the end of a comment quotation or
paraphrase provides the location of the item in the public record.\34\
To the extent that interested parties have provided written comments
that are substantively consistent with any oral comments provided
during the February 16, 2023, public meeting, DOE cites the written
comments throughout this final rule. Any oral comments provided during
the webinar that are not substantively addressed by written comments
are summarized and cited separately throughout this final rule.
---------------------------------------------------------------------------

\34\ 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
<a href="http://www.regulations.gov">www.regulations.gov</a>). The references are arranged as follows:
(commenter name, comment docket ID number, page of that document).
---------------------------------------------------------------------------

III. General Discussion

DOE developed this final rule after a review of the market for the
subject distribution transformers. DOE also considered comments, data,
and information from interested parties that represent a variety of
interests. This notice addresses issues raised by these commenters.

A. General Comments

This section summarizes general comments received from interested
parties regarding rulemaking timing and process.
DOE received several comments recommending DOE pursue policies for
saving energy or strengthening the supply chain either in place of or
in addition to revised distribution transformer efficiency standards.
Specifically, Standards Michigan commented that distribution
transformers are oversized and recommended DOE work with electrical
code committees to encourage proper distribution transformer sizing.
(Standards Michigan, No. 109 at p. 1) APPA recommended DOE consider
other efficiency measures to conserve energy, such as improving
building codes and increasing the size of service conductors to reduce
transmission losses. (APPA, No. 103 at p. 3) Pugh Consulting commented
that DOE should

[[Page 29866]]

work with the U.S. Environmental Protection Agency (EPA) to accelerate
the permitting process under the Clean Air Act and Clean Water Act and
to allow steel and transformer manufacturers to engage in nitrogen
oxide (NOx) emission trading under EPA's Good Neighbor Plan. (Pugh
Consulting, No. 117 at p. 7) Pugh Consulting further recommended DOE
remove tariffs from friendly nations and explore agreements to increase
electrical steel imports from these nations. (Pugh Consulting, No. 117
at p. 7) EVgo commented that DOE should use Defense Production Act
investments to increase transformer supply to accommodate the increases
in demand that are supporting administration electrification goals.
(EVgo, No. 111 at p. 2)
DOE notes that this final rule pertains only to energy conservation
standards for distribution transformers, and any efforts to amend
national electrical codes, building codes, or other Federal regulatory
programs and policies are beyond the scope of this rulemaking. DOE
notes it is actively working with fellow government agencies and
industry to better address the current supply chain challenges
impacting the distribution transformer market, as well as the broader
electricity industry.\35\
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\35\ See Department of Energy. DOE Actions to Unlock
Transformers and Grid Component Production. Available at
<a href="http://www.energy.gov/policy/articles/doe-actions-unlock-transformer-and-grid-component-production">www.energy.gov/policy/articles/doe-actions-unlock-transformer-and-grid-component-production</a> (accessed Oct. 27, 2023).
---------------------------------------------------------------------------

Several commenters disagreed with DOE's assessment that the
proposed standards are technologically feasible and economically
justified generally.
Cliffs commented that DOE standards are not economically justified.
(Cliffs, No. 105 at pp. 13-14) NAHB commented that the proposed
standards are not economically justified because the benefits do not
outweigh the costs. NAHB added that DOE's designation of economic
justification is subjective and would be impacted by regulations from
other agencies. (NAHB, No. 106 at pp. 2-3) SBA commented that the
proposed standards are not economically justified due to the additional
costs associated with amorphous cores and the significant shock to the
market from a lack of market competition. (SBA, No. 100 at pp. 6-7)
NRECA commented that the proposed standards are neither economically
justified nor technologically feasible because DOE's NOPR is based on
flawed assumptions. (NRECA, No. 98 at pp. 1-2) Pugh Consulting
commented that DOE's proposal does not properly consider the
requirements established under the Energy Policy Act of 2005. (Pugh
Consulting, No. 117 at p. 2)
APPA commented that DOE's requests for comment in the January 2023
NOPR indicate some technical questions are unresolved and, therefore,
DOE should address these questions before issuing any final rule.
(APPA, No. 103 at pp. 17-18) Cliffs commented that insufficient
collaboration with stakeholders was conducted prior to publication of
the NOPR and because of that, the NOPR contains flawed assumptions and
oversteps DOE's authority. (Cliffs, No. 105 at p. 2)
Entergy recommended that instead of finalizing the proposed rule,
DOE should (1) adopt a standard that does not require a full move to
amorphous or (2) use its authority to issue a determination that no new
standard is required, which would allow DOE to work with industry
through the Electricity Subsector Coordinating Council (ESCC) to
further study the cost and benefits of enacting this rule and return
with recommendations prior to 2027. (Entergy, No. 114 at p. 4)
CEC commented that DOE should ensure it adopts a final rule by June
30, 2024, because EPCA required DOE to update this standard by April
2019. (CEC, No. 124 at p. 2)
As stated, DOE has provided numerous notices with extensive comment
periods to ensure stakeholders have an opportunity to provide data and
to identify or correct any concerns in DOE's analysis of amended energy
conservation standards. DOE has reviewed the many comments, data, and
feedback received in response to the January 2023 NOPR and updated its
analysis based on this information, as discussed throughout this final
rule. In this final rule, DOE is adopting efficiency standards based
on, but importantly different from, those proposed in the January 2023
NOPR. DOE is adopting standards that are expected to require
significantly less amorphous material and extend the compliance period
by two years, relative to what was proposed, which will reduce the
burden on manufacturers and allow manufacturers considerable
flexibility to meet standards without near-term supply chain impacts.
DOE has concluded that the amended standards adopted in this final rule
are technologically feasible and economically justified. A detailed
discussion of DOE's analysis and conclusion is provided in section V.C
of this document.
Specific comments regarding DOE's analysis are discussed in further
detail below.

B. Equipment Classes and Scope of Coverage

This final rule covers the COMMERCIAL AND INDUSTRIAL equipment that
meet the definition of ``distribution transformer'' as codified at 10
CFR 431.192.
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
different standards. In making a determination whether a performance-
related feature justifies a different standard, DOE must consider 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 final
rule are discussed in detail in section IV.A.2 of this document.
This final 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;
non-ventilated transformer; rectifier 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.
See section IV.A.1 of this document for discussion of the scope of
coverage and product classes analyzed in this final rule.

C. 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 equipment must use these test procedures as
the basis for certifying to DOE that their product complies with the
applicable energy conservation standards and as the basis for any
representations regarding the energy use or energy efficiency of the
equipment. (42 U.S.C. 6316(e)(1); 42 U.S.C. 6295(s); and 42 U.S.C.
6314(d)). Similarly, DOE must use these test procedures to evaluate
whether a basic model complies with

[[Page 29867]]

the applicable energy conservation standard(s). 10 CFR 429.110(e). The
current test procedure for distribution transformers is codified at 10
CFR part 431, subpart K, appendix A (``appendix A''). Appendix A
includes provisions for determining percentage efficiency at rated per-
unit load (PUL), the metric on which current standards are based. 10
CFR 431.193.
On September 14, 2021, DOE published a test procedure final rule
for distribution transformers that contained 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. 86 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. 86 FR 51230, 51249.
Carte commented that they are not sure how to report data for a
transformer with a dual-rated kVA based on the division of single-phase
and three-phase power. (Carte, No. 140 at p. 9)
For distribution transformers, efficiency must be determined for
each basic model, as defined in 10 CFR 431.192. Questions regarding how
to report data for a specific unit can be submitted to
<a href="/cdn-cgi/l/email-protection#0c4d7c7c60656d626f695f786d62686d7e687f5d79697f786563627f4c696922686369226b637a">[email&#160;protected]</a>.
Eaton commented that if DOE adopts higher efficiency standards, DOE
should revisit the alternative methods for determining energy
efficiency and energy use (AEDM) tolerance requirements in 10 CFR
429.70, because the original tolerances were based on a much higher
number of absolute losses and amended standards would be based on a
much smaller number of losses. (Eaton, No. 137 at pp. 29-30) Therefore,
even though the difference in watts of loss could be similar, the
percentage difference in losses may exceed the current requirements in
10 CFR 429.70. Id.
DOE notes that AEDM requirements are handled in a separate
rulemaking that spans all certification, labeling, and enforcement
provisions across many products and equipment (see Docket No. EERE-
2023-BT-CE-0001). AEDMs are widely used in certifying the efficiency of
distribution transformers and DOE intends to continue to allow this
under amended efficiency standards. DOE encourages stakeholders to
submit any comment and data regarding distribution transformer AEDM
tolerances to the docket referenced above.

D. Technological Feasibility

1. General
As discussed, 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))
To determine whether potential amended standards would be
technologically feasible, DOE first develops a list of all known
technologies and design options that could improve the efficiency of
the products or equipment that are the subject of the rulemaking. DOE
considers technologies incorporated in commercially available products
or in working prototypes to be ``technologically feasible.'' 10 CFR
431.4; 10 CFR 430, subpart C, appendix A, sections 6(b)(3)(i) and
7(b)(1). Section IV.A.3 of this document discusses the technology
options identified by DOE for this analysis. For further details on the
technology assessment conducted for this final rule, see chapter 3 of
the final rule TSD.
After DOE has determined which, if any, technologies and design
options are technologically feasible, it further evaluates each
technology and design 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; 10 CFR 430, subpart C, appendix A, sections
6(b)(3)(ii) through(v) and 7(b)(2) through(5). Those technology options
that are ``screened out'' based on these criteria are not considered
further. Those technology and design options that are not screened out
are considered as the basis for higher efficiency levels that DOE could
consider for potential amended standards. Section IV.B of this document
discusses the results of this screening analysis conducted for this
final rule. For further details on the screening analysis conducted for
this final rule, see chapter 4 of the final rule TSD.
2. Maximum Technologically Feasible Levels
EPCA requires that for any proposed rule that prescribes an amended
or new energy conservation standard, or prescribes no amendment or no
new standard for a type (or class) of covered product, DOE must
determine the maximum improvement in energy efficiency or maximum
reduction in energy use that is technologically feasible for each type
(or class) of covered products. (42 U.S.C. 6313(a); 42 U.S.C.
6295(p)(1)). Accordingly, in the engineering analysis, DOE identifies
the maximum efficiency level currently available on the market. DOE
also defines a ``max-tech'' efficiency level, representing the maximum
theoretical efficiency that can be achieved through the application of
all available technology options retained from the screening
analysis.\36\ In many cases, the max-tech efficiency level is not
commercially available because it is not currently economically
feasible.
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\36\ In applying these design options, DOE would only include
those that are compatible with each other that when combined, would
represent the theoretical maximum possible efficiency.
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E. Energy Savings

1. Determination of Savings
For each trial standard level (TSL), DOE projected energy savings
from application of the TSL to distribution transformers purchased in
the 30-year period that begins in the year of compliance with the
amended standards (2029-2058).\37\ The savings are measured over the
entire lifetime of equipment purchased in the 30-year analysis period.
DOE 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.
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\37\ DOE also presents a sensitivity analysis that considers
impacts for products shipped in a 9-year period. See section V.B.3
of this document for additional detail.
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DOE used its national impact analysis (NIA) spreadsheet models to
estimate national energy savings (NES) from potential amended standards
for distribution transformers. The NIA spreadsheet 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. For natural gas, the primary energy savings are considered
to be

[[Page 29868]]

equal to the site energy savings. 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.\38\ 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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\38\ 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).
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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.\39\ 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. 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.
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\39\ 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 13, 2021 (86 FR 70892).
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As stated, the standard levels adopted in this final rule for all
distribution transformers are projected to result in national energy
savings of 4.58 quad, the equivalent of the primary annual energy use
of 49.2 million homes . Based on the amount of FFC savings, the
corresponding reduction in emissions, and the need to confront the
global climate crisis, DOE has determined the energy savings from the
standard levels adopted in this final rule are ``significant'' within
the meaning of 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B).

F. 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 potential new or amended standards on
manufacturers, DOE conducts an MIA, as discussed in section IV.J. 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 cost (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 equipment 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.
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 IV.H, DOE uses the NIA
spreadsheet models to project national energy savings.
d. Lessening of Utility or Performance of Products
In establishing equipment 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

[[Page 29869]]

the considered equipment. (42 U.S.C. 6316(a); 42 U.S.C.
6295(o)(2)(B)(i)(IV)) Based on data available to DOE, the standards
adopted in this document would not reduce the utility or performance of
the equipment 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 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 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))
NAHB expressed concern that DOE has not published the determination
made by the Attorney General on the impact of any lessening of
competition that may result from this rule and recommended DOE withdraw
its proposal until stakeholders have had the opportunity to review this
document. (NAHB, No. 106 at p. 2)
Under EPCA, the Attorney General is required to make a
determination of the impact, if any, of any lessening of competition
likely to result from such standard no later than 60 days after
publication of the proposed rule. DOE is then required to publish any
such determination in the Federal Register. To assist the Department of
Justice (DOJ) in making such a determination, DOE transmitted copies of
its proposed rule and the NOPR TSD to the Attorney General for review,
with a request that the DOJ provide its determination on this issue. In
its assessment letter responding to DOE, DOJ concluded that the
proposed energy conservation standards for distribution transformers
are unlikely to have a significant adverse impact on competition. In
accordance with EPCA, DOE is publishing the Attorney General's
assessment at the end of this final rule.
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 adopted 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 adopted standards are likely to result in
environmental benefits in the form of reduced emissions of air
pollutants and 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 of this document;
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
EPCA creates a rebuttable presumption that an energy conservation
standard is economically justified if the additional cost to the
equipment 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. (42 U.S.C. 6316(a);
42 U.S.C. 6295(o)(2)(B)(iii)) DOE's LCC and PBP analyses generate
values used to calculate the effect potential amended energy
conservation standards would have on the PBP for consumers. These
analyses include, but are not limited to, the 3-year PBP 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 final 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 considered in this document. The first tool is a spreadsheet
that calculates the LCC savings and PBP of potential amended or new
energy conservation standards. The national impacts analysis uses a
second spreadsheet 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 three spreadsheet tools are
available on the DOE website for this rulemaking: <a href="http://www.regulations.gov/docket/EERE-2019-BT-STD-0018">www.regulations.gov/docket/EERE-2019-BT-STD-0018</a>. Additionally, DOE used output from the
latest version of the Energy Information Administration's (EIA's)
Annual Energy Outlook (AEO) 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 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.

[[Page 29870]]

The key findings of DOE's market assessment are summarized in the
following sections. See chapter 3 of the final rule 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) non-ventilated; (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.
In the January 2023 NOPR, DOE discussed and proposed minor edits to
the definitions of equipment excluded from the definition of
distribution transformer. In response to the January 2023 NOPR, DOE
received additional comments on its proposed definitional edits. 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)) DOE has defined autotransformer as ``a transformer
that: (1) has one physical winding that consists of a series winding
part and a common winding part; (2) has no isolation between its
primary and secondary circuits; and (3) during step-down operation, has
a primary voltage that is equal to the total of the series and common
winding voltages, and a secondary voltage that is equal to the common
winding voltage.'' 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that, while stakeholders
suggested that there may be certain applications for which
autotransformers may be substitutable for an isolation transformer,
these substitutions would be limited to specific applications and not
common enough to regard as general practice. 88 FR 1722, 1741. Further,
DOE stated that, because autotransformers do not provide galvanic
isolation, they are unlikely to be used in at least some general-
purpose applications. DOE did not propose to amend the exclusion of
autotransformers under the distribution transformer definition. Id.
Schneider commented that autotransformers were used in the 1970's
for distribution application. However, they do not allow for the
creation of a neutral on the secondary side of the transformer nor do
they allow for isolating the secondary and primary windings for power
quality benefits. (Schneider, No. 101 at p. 15) Schneider commented
that for applications with small loads, based on the increased purchase
price and footprints at the proposed efficiency levels, the market will
begin evaluating autotransformers and applying them to certain
distribution applications. Id. Schneider recommended the statutory
definition of low-voltage transformer be modified through legislation
to subject autotransformers to energy conservation standards. Id. at p.
17.
DOE agrees that in certain applications, autotransformers may be
capable of serving as a replacement for general purpose transformers.
However, as discussed, the isolation and power quality benefits of
distribution transformers make it unlikely that autotransformers would
be widely viewed or used as a substitute for most general purpose
distribution transformers. DOE notes that manufacturer literature
already markets autotransformers as an ``economical alternative to
general purpose distribution isolation transformers to adjust the
supply voltage to match specific load requirements when load isolation
from the supply line is not required.'' \40\ As noted in the marketing,
autotransformers are only suitable in transformer applications where
load isolation is not required.
---------------------------------------------------------------------------

\40\ Hammond Power Solutions. Autotransformers, 2023.
<a href="http://documents.hammondpowersolutions.com/documents/Literature/Specialty/HPS-Autotransformers-Brochure.pdf?_gl=1*db1907*_ga*NTA0ODk1MjQzLjE2NzExMzEzMTM.*_ga_RTZEGSXND8*MTY4MzIxNTc5My42Ni4xLjE2ODMyMTcyNjcuNTguMC4w">documents.hammondpowersolutions.com/documents/Literature/Specialty/HPS-Autotransformers-Brochure.pdf?_gl=1*db1907*_ga*NTA0ODk1MjQzLjE2NzExMzEzMTM.*_ga_RTZEGSXND8*MTY4MzIxNTc5My42Ni4xLjE2ODMyMTcyNjcuNTguMC4w</a>.
---------------------------------------------------------------------------

Despite autotransformers being less expensive, having a smaller
footprint than general purpose distribution transformers, and being
marketed as suitable in certain applications, autotransformers have not
seen widespread use in general purpose applications and their use has
been limited to special purposes. While autotransformers may be capable
of meeting similar efficiency regulations as general purpose
distribution transformers, they are statutorily excluded from the
definition of distribution transformer on account of being reserved for
special purpose applications. Further, stakeholder comments reiterate
that there are legitimate shortcomings of autotransformer that makes
significant substitution unlikely. Based on this feedback, DOE has
concluded that autotransformers are designed to be used in a special
purpose application and are unlikely to be used in general purpose
applications due to these shortcomings. Therefore, DOE is not amending
the exclusion of autotransformers under the distribution transformer
definition. DOE will continue to evaluate the extent to which
autotransformers are used in general purpose applications in future
rulemakings.
b. Drive (Isolation) Transformers
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 drive transformers. (42 U.S.C. 6291(35)(b)(ii)). DOE defines a
drive (isolation) transformer 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
mechanical stresses resulting from an alternating current adjustable
frequency motor drive or a direct current motor drive.'' 10 CFR
431.192.
In the January 2023 NOPR, DOE responded to comments by Schneider
and Eaton submitted on the August 2021 Preliminary Analysis TSD that
claimed drive-isolation transformers have historically been sold with
non-standard low-voltage ratings corresponding to typical motor input
voltages, and as such were unlikely to be used in general-purpose
applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3)
Schneider and Eaton commented that they had seen a recent 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 were being used in general purpose
applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3)
In response to these comments, DOE noted that while some drive-
isolation transformers could, in theory, be used in general purpose
applications, no evidence exists to suggest this is common practice. 88
FR 1722, 1742.

[[Page 29871]]

Therefore, DOE concluded that drive-isolation transformers remain an
example of a transformer that is designed to be used in special purpose
applications and excluded by statute. However, DOE also noted that the
overwhelming majority of general purpose applications use either 208Y/
120 or 480Y/277 voltage while the overwhelming majority of drive-
isolation transformers are designed with alternative voltages designed
to match specific motor drives. Id. Therefore, DOE stated that a drive-
isolation transformer with a rated secondary voltage of 208Y/120 or
480Y/277 is considerably more likely to be used in general purpose
applications.
DOE proposed to amend the definition of drive (isolation)
transformer to include the criterion that drive-isolation transformers
have an output voltage other than 208Y/120 and 480Y/277. 88 FR 1722,
1742. DOE requested comment on its determination that a drive-isolation
transformer with these common voltage ratings is likely to be used in
general purpose applications and if any other common voltage ratings
would indicate likely use in general purpose applications. Id.
In response, Schneider commented that it agrees with the evaluation
completed by DOE and the proposed definition. (Schneider, No. 101 at p.
3) Schneider recommended Congress modify the statutory definition of
LVDT distribution transformer to include all six-pulse drive-isolation
transformers. (Schneider, No. 101 at p. 17) Schneider further commented
that even if customers do need a secondary 208Y/120 or 480Y/277 voltage
for their drive applications, they would still be able to purchase a
transformer, but it would just be an energy efficient model.
(Schneider, No. 101 at p. 3) Schneider has previously commented that
six-pulse drive-isolation transformers are within the LVDT scope in
Canada and their energy conservation standards align with current DOE
energy conservation standards. (Schneider, No. 49 at p. 4) Therefore,
energy efficient models are readily available for purchase.
NEMA commented that voltage ratings are a poor measure to capture
the distinction between general purpose applications and special
purpose applications. (NEMA, No. 141 at p. 7) NEMA did not provide an
alternative recommendation.
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). Drive-isolation
transformers are excluded from the definition of distribution
transformers because 42 U.S.C. 6291 lists them as a special purpose
product unlikely to be used in general purpose applications. (42 U.S.C.
6291(35)(b)(ii)) Therefore, even if all six-pulse drive-isolation
transformers may be able to meet energy conservation standards, most
drive-isolation transformers remain statutorily excluded since they are
designed to be used in special purpose applications and are unlikely to
be used in a general purpose application. To the extent that some
transformers are marketed as drive-isolation transformers with rated
output voltages aligning with common distribution voltages, DOE is
unable to similarly conclude that these transformers are designed to be
used in special purpose applications and are unlikely to be used in
general purpose applications.
While NEMA commented that relying on output voltages may not
capture the distinctions between all drive-isolation transformers and
distribution transformers, NEMA did not provide any data to refute
DOE's tentative determination that a transformer marketed as a drive-
isolation transformer with rated output voltages aligning with common
distribution voltages would be significantly more likely to be used in
general purpose distribution applications. Further, as stated by
Schneider, DOE's proposal does not prevent consumers that need these
secondary voltages for their drive applications from purchasing a
suitable product, it only requires them to purchase a product that
meets energy conservation standards.
Based on the foregoing discussion, DOE is finalizing its proposed
definition for drive (isolation) transformer to mean ``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 stresses 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'.''
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 January 2023 NOPR, DOE noted that the current tables in the
``special-impedance transformer'' definition do not explicitly address
how to treat non-standard kVA values (e.g., kVA values between those
listed in the ``special-impedance transformer'' definition). 88 FR
1722, 1742-1743. DOE proposed 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.'' Id. DOE noted that this approach was consistent with the
approach specified for determining the efficiency requirements of
distribution transformers of non-standard kVA rating (i.e., using a
linear interpolation from the nearest bounding kVA values listed in the
table). See 10 CFR 431.196. DOE requested comment on this proposed
amendment and whether it provided sufficient clarity as to how to treat
the normal impedance ranges for non-standard kVA distribution
transformers. Id.
In response to the January 2023 NOPR, Prolec GE commented that the
proposed definition is a helpful clarification. (Prolec GE, No. 120 at
p. 5). NEMA, Howard, and Eaton all recommended DOE specify normal
impedance for kVA ranges rather than using a linear interpolation
method. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at pp. 6-7; Eaton,
No. 137 at pp. 5-11)
Eaton further commented that the industry assumption was that a
given impedance range was intended to apply to all non-standard kVA
ratings occurring between two standard kVA ratings and the confusion
was as to whether the impedance ranged corresponding to the lower, or
the upper preferred kVA rating should be used. (Eaton, No. 137 at p. 5)
Eaton identified two potential approaches, the ascending approach,
wherein the impedance range is intended to change only upon reaching
the next higher preferred kVA, and the descending approach, wherein the
impedance range is intended to change immediately upon exceeding the
lower kVA rating. (Eaton, No. 137 at pp. 5-7). Eaton commented that the
normal impedance ranges change gradually with the only significant jump
being between 500 to 666 kVA single-phase

[[Page 29872]]

and 500 to 749 kVA three-phase, where the lower bound of the normal
impedance range jumps from 1.0 percent to 5.0 percent. (Eaton, No. 137
at p. 7)
Eaton provided shipment data for years 2016 through 2022 for non-
standard kVAs that coincide with this jump in the lower-bound of normal
impedance. (Eaton, No. 137 at pp. 7-8) Eaton commented that they built
zero non-standard kVA single-phase units between 501 and 666 kVA and 80
non-standard kVA three-phase units. Eaton added that of those 80 units,
57 were outside of scope regardless of the impedance, while the
remaining 23 units were treated as within DOE's scope of coverage. Id.
Of those units, only seven units were between 1.5 and 5.0 percent
impedance. Meaning under the ascending interpretation, these seven
units would be in-scope and under the descending interpretation, these
seven units would be out of scope. Eaton provided the impedance for all
23 units. Id. DOE notes that all 23 units would be within scope under
both the ascending interpretation and the proposed linear interpolation
method, as the unit impedance values fall within the normal impedance
range of both the ascending interpretation and the proposed linear
interpolation method.
Eaton commented that current industry standards do not provide a
clear answer but in comparing the ascending interpretation and the
proposed linear interpolation, the linear interpolation is somewhat
more computationally cumbersome and more confusing to audit. (Eaton,
No. 137 at pp. 8-11) For these reasons, Eaton recommended DOE adopt
normal-impedance tables with an ascending interpretation on kVA ranges.
(Eaton, No. 137 at p. 11).
While Howard and NEMA didn't explicitly discuss the differences
between the ascending interpretation, descending interpretation, and
linear-interpolation methods, both recommended tables that apply the
ascending interpretation. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at
pp. 6-7)
As noted, DOE has not previously stated what the normal impedance
ranges for non-standard kVA transformers are intended to be. While DOE
proposed a linear interpolation, Eaton's data suggested that adopting
an ascending interpretation would include an identical number of
transformers within scope of the distribution transformer rulemaking.
Further, multiple stakeholders preferred the simplicity of the
ascending interpretation. Given that the number of impacted
transformers is unchanged, the simplicity of defining normal impedance
based on kVA ranges, and stakeholder support for the ascending
interpretation, DOE is adopting amended tables to specify the normal
impedance ranges for non-standard kVA transformers using an ascending
interpretation. The adopted normal impedance ranges for each kVA range
are given in Table IV.1 and Table IV.2.
[GRAPHIC] [TIFF OMITTED] TR22AP24.528

[GRAPHIC] [TIFF OMITTED] TR22AP24.529

d. Tap Range of 20 Percent or More
Distribution transformers are commonly sold with voltage taps that
allow manufacturers to adjust for minor differences in the input or
output voltage. 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 response to the August 2021 Preliminary Analysis TSD,
Schneider, NEMA, and Eaton recommended 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) Schneider and Eaton
commented that the nominal voltage by which the tap range is calculated
is a consumer choice and could result in two physically identical
transformers being subject to standards or not, depending on the choice
of nominal voltage. (Schneider No. 49 at p. 6; Eaton No. 55 at pp. 6-7)
In the January 2023 NOPR, DOE noted that, while traditional
industry understanding of tap range is in percentages relative to the
nominal voltage, stakeholder comments suggest that such a calculation
can be applied such that two physically identical distribution
transformers can be inside or outside of scope depending on the choice
of nominal voltage. 88 FR 1722. To have a consistent standard for
physically identical distribution

[[Page 29873]]

transformers, DOE proposed 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.
Prolec GE and NEMA commented that the proposed amendment to the
calculation of a tap range of 20 percent or more was clear and removed
ambiguity. (Prolec GE, No. 120 at p. 5; NEMA, No. 141 at p. 8) Howard
and Eaton supported the proposed definition but recommended DOE make
clarifying edits to avoid any confusion. (Howard, No. 116 at pp. 7-8;
Eaton, No. 137 at p. 12)
Specifically, Eaton recommended changing DOE's proposal to use
``full-power voltage taps'' to read ``a transformer with multiple
voltage taps, each capable of operating at full, rated capacity (kVA) .
. .'' (Eaton, No. 137 at p. 12) Eaton commented that this clarification
aligned with how full-power taps are more commonly described and
clarified that full-capacity refers to kVA. Id.
Eaton and Howard also both noted that the description of how to
calculate the tap range is confusing. Specifically, Eaton and Howard
identified the text where DOE proposed to state ``the highest of which
equals at least 20% more than the lowest, computed based on the sum of
the deviations of these taps from the transformer's maximum full-power
voltage.'' (Howard, No. 116 at pp. 7-8; Eaton, No. 137 at p. 12) Howard
recommended DOE state ``where the difference between the highest tap
voltage and the lowest tap voltage is 20 percent or more of the highest
tap voltage.'' (Howard, No. 116 at pp.7-8) Eaton recommended DOE state
``whose range, defined as the maximum tap voltage minus minimum tap
voltage, is 20 percent or more of the maximum tap voltage rating
appearing on the product nameplate.'' (Eaton, No. 137 at p. 12)
Schneider commented that the proposed definition does clearly
define how to calculate the tap percentage, but it does not address the
fact that common LVDT products meet these criteria. (Schneider, No. 101
at p. 3) Schneider identified certain LVDT products designed to span
multiple nominal voltages as having a tap-range greater than 20
percent. Id. Schneider recommended DOE modify the definition to allow
for only one standard nominal voltage rating (e.g., a transformer
spanning 480V and 600V would not be exempted because it includes two
standard voltage systems). Id.
Regarding Eaton's editorial suggestion as to how DOE specifies that
only full-power taps are used, DOE agrees that Eaton's wording is
clearer and better aligns with how industry addresses full-power taps.
Therefore, DOE is adopting language that using full-power taps means
``each capable of operating at full, rated capacity (kVA)''.
Regarding Eaton and Howard's editorial suggestion as to how DOE
communicates the calculation for the tap range, DOE notes that the
proposed definition simply modified the current definition in the CFR
to be based on the transformer's maximum full-power voltage, rather
than the nominal voltage. However, DOE agrees that, with more explicit
directions as to how to compute the tap range, the phrasing ``the
highest of which equals at least 20 percent more than the lowest''
could be redundant and confusing. Therefore, DOE is simplifying the
wording, in accordance with Howard and Eaton's suggestions to read that
``whose range, defined as the difference between the highest tap
voltage and lowest tap voltage, is 20 percent or more of the highest
tap voltage.''
Regarding Schneider's comment recommending that DOE only consider
``standard'' nominal voltage ratings to be eligible, DOE notes that the
adopted test procedure for measuring the energy consumption of
distribution transformers specifies how to handle reconfigurable
nominal windings in the case of a dual- or multi-voltage capable
transformers. (See appendix A to subpart K of 10 CFR part 431).
Transformer taps are intended to offer consumers the ability to
conduct minor corrections to system voltage. The addition of voltage
taps generally adds to a manufacturer's costs and reduces the
efficiency of a product due to requiring additional winding material.
Therefore, EPCA listed transformers with a tap range of 20 percent or
more as excluded from the scope of the distribution transformer
rulemaking. (See 42 U.S.C. 6291(35)(B)(i)) DOE's proposed amendment to
the definition of a transformer with a tap range of 20 percent or more
is only intended to clarify the provisions established under EPCA as to
how this tap range is to be calculated across physically identical
products. Transformers with tap ranges greater than 20 percent, are not
within the scope of distribution transformers as defined in this final
rule.
Based on the foregoing discussion, DOE is adopting a definition for
transformer with a tap range of 20 percent or more to mean ``a
transformer with multiple voltage taps, each capable of operating at
full, rated capacity (kVA), whose range, defined as the difference
between the highest voltage tap and the lowest voltage tap, is 20
percent or more of the highest voltage tap.''
e. Sealed and Non-Ventilated Transformers
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 ``sealed and non-ventilated transformers.'' (42
U.S.C. 6291(356)(b)(ii)) DOE defines sealed transformer and non-
ventilated transformer at 10 CFR 431.192.
In the January 2023 NOPR, DOE proposed to modify the definitions of
sealed and non-ventilated transformers to clarify that only certain
``dry-type'' transformers meet the definition of sealed and non-
ventilated transformers. 88 FR 1722, 1744 DOE requested comment on this
proposed amendment. Id.
Eaton and NEMA commented that the amendment provides clarity and
agreed with including it in the definition. (Eaton, No. 137 at p. 13;
NEMA, No. 141 at p. 8) DOE received no further comment on the proposed
definition and is finalizing the clarification that sealed and non-
ventilated transformers only include ``dry-type'' transformers.
Regarding the statutory exclusion of non-ventilated transformers
broadly, Schneider commented that the original rationale for excluding
non-ventilated transformers from EPCA was because non-ventilated
transformers have higher core losses, which makes it difficult to meet
efficiency standards at 35-percent loading, and because their inclusion
would not drive significant energy savings. (Schneider, No. 101 at pp.
8-9) DOE notes that, because non-ventilated transformers do not have
airflow or oil surrounding the core and coil, they have a harder time
dissipating heat than general purpose dry-type distribution
transformers. Transformer thermal limitations are governed by total
losses at full load (i.e., 100-percent PUL), where load losses make up
a much higher percentage of total losses. As such, manufacturers of
sealed and non-ventilated transformers typically increase no-load
losses to decrease load losses, and therefore meet temperature rise
limitations.
Schneider commented that while non-ventilated transformers are
typically used in specialty applications,\41\ there is

[[Page 29874]]

nothing inherent about non-ventilated transformers that would prevent
them from being used in general purpose applications. (Schneider, No.
101 at pp. 8-9)
---------------------------------------------------------------------------

\41\ Nonventilated transformers are typically marketed for
specific hazardous environment applications where airborne
contaminants or large quantities of particles would potentially harm
the performance of a traditional ventilated distribution
transformer.
---------------------------------------------------------------------------

Schneider commented that non-ventilated transformers are typically
larger and higher priced than general purpose LVDTs, which has
historically discouraged consumers from using them in general purpose
applications. (Schneider, No. 101 at p. 16) However, Schneider noted
that if the proposed standards are adopted, specifically standards
requiring amorphous cores, the increased volume and cost of general
purpose LVDT units could become higher than non-ventilated units. Id.
Schneider commented that if that were the case, manufacturers may
choose to market non-ventilated transformer for general purpose
applications to avoid the capital investment required to produce
transformers with amorphous cores. Id. Schneider commented that if the
proposed standards are finalized, it expects 50 percent of the LVDT
market to purchase non-ventilated transformers instead of more
efficient products. Schneider stated that because non-ventilated
products are excluded from standards, the efficiency is likely to be
very low, which would have a negative impact on any potential savings
associated with LVDT transformers. Id. DOE notes that Schneider did not
provide any specific data as to the relative increase in weight or
production cost expected between non-ventilated transformers and
general purpose distribution transformers to demonstrate how Schneider
derived the 50 percent expected market share for non-ventilated
transformers.
Schneider recommended that manufacturers work with Congress to
modify the definition of low-voltage distribution transformer to remove
the exclusion for non-ventilated transformers. (Schneider, No. 101 at
p. 17)
DOE agrees that there are no technical features preventing a non-
ventilated transformer from being used in general purpose applications.
However, as described by Schneider, this substitution generally does
not occur in industry because of the challenges associated with
dissipating heat for non-ventilated transformers, which leads to non-
ventilated transformers being larger and more expensive than a
ventilated transformer of identical kVA. Further, dissipating heat
becomes more of a challenge as the size of the transformer increases
due to the significant amount of energy that larger transformers need
to shed. As a result, the percentage increase in weight and cost of a
non-ventilated transformer relative to a general purpose LVDT unit is
greater for larger kVA transformers.
DOE reviewed manufacturer websites that listed product
specifications and prices for both general purpose LVDTs and non-
ventilated transformers (See Chapter 3 of the TSD). In general, DOE
observed that the relatively higher cost and weight for non-ventilated
transformers was considerably more than the modeled increase in cost
and weight for even max-tech general purpose LVDTs. Therefore, non-
ventilated distribution transformers are unlikely to become cost-
competitive with more efficient, general purpose distribution
transformers. Further, under the adopted standards, amorphous core
transformers are not required for LVDTs. Therefore, it is unlikely for
manufacturers to sell non-ventilated transformers into general purpose
applications. As such, DOE maintains that non-ventilated transformers
are statutorily excluded from the definition of distribution
transformer on account of being used only in special purpose
applications.
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. In these
applications, transformers accept an 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))
In the January 2023 NOPR, DOE discussed how 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. 88
FR 1722, 1744. However, DOE has also previously identified that this is
not a widespread practice. 78 FR 2336, 23354. Comments received in
response to the 2021 Preliminary Analysis TSD confirmed that, while
step-up transformers are typically less efficient than DOE standards
would mandate and step-up transformers could, in theory, be used in
distribution applications, this is not a common practice. 88 FR 1722,
1744. Feedback from stakeholders indicated that step-up transformers
typically serve a separate and unique application, often in the
renewable energy field where transformer designs may not be optimized
for the distribution market but rather are optimized for integration
with other equipment, such as inverters. Id. As such, DOE did not
propose to amend the definition of ``distribution transformer'' to
account for step-up transformers. Id.
DOE received additional comments specifically regarding low-voltage
step-up transformers in response to the January 2023 NOPR.
Schneider commented that there is confusion as to whether low-
voltage step-up transformers are included in scope and recommended DOE
explicitly state in the LVDT definition that both step-up and step-down
transformers are within scope. (Schneider, No. 101 at p. 4) NEMA
recommended clarifying that step-up LVDT transformers are within scope
since both the input and output voltages meet the definition of
distribution transformers. (NEMA, No. 141 at p. 9)
As previously noted, the definition of ``distribution transformer''
specifies that a transformer ``has an output voltage of 600 V or less''
and the definition of a low-voltage distribution transformer specifies
``a distribution transformer that has an input voltage of 600 volts or
less''. See 10 CFR 431.192. Any step-up transformer with a primary
input and output voltage less than our equal to 600 volts would
therefore meet the definition of a low-voltage dry-type distribution
transformer.
Any product meeting the definition of low-voltage dry-type
distribution transformer, would be subject to DOE standards. DOE is not
amending the definition of low-voltage dry-type distribution
transformer to specifically include step-up transformers as this could
be confusing to manufacturers of step-up transformers that do not meet
the voltage limits (and therefore are not within the scope of
distribution transformer efficiency standards). Further, as described
in the foregoing discussion, these low-voltage dry-type products are
already included within the definition of low-voltage dry-type
distribution transformer.

[[Page 29875]]

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 uninterruptible 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 to counteract such irregularities. 69 FR
45376, 45383. DOE has clarified that uninterruptible 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 clarification is consistent with the
reference in the definition to transformers that are ``within'' the
uninterruptible power system. 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that transformers at the input,
output or bypass that are supplying power to an uninterruptible power
system are not uninterruptible power supply transformers. 88 FR 1722,
1745. Accordingly, DOE proposed to amend the definition of
``uninterruptible power supply transformer'' to explicitly state that
transformers at the input, output, or bypass of a distribution
transformer are not a part of the uninterruptible power system and
requested comment on the proposed amendment. Id.
In response, NEMA recommended that DOE include in the definition of
an uninterruptible power supply transformer that these transformers
must include a core with an air gap and/or a shunt core. NEMA stated
these features prevent uninterruptible power supply transformers from
meeting the proposed efficiency standards and transformers that do not
include at least one of these attributes would not meet the definition
of an uninterruptible power supply transformer. (NEMA, No. 141 at p. 8)
Prolec GE commented that the proposed amendment to the definition
provides helpful clarification, but suggested DOE confirm its usage of
the terms ``uninterruptable'' and ``uninterruptible''. (Prolec GE, No.
120 at p. 5)
DOE notes that its usage of ``uninterruptable'' in the January 2023
NOPR was an inadvertent typographical error. In this final rule, all
instances of ``uninterruptable'' have been corrected to
``uninterruptible.''
Regarding NEMA's recommendation to include a requirement for a core
with an air gap and/or a shunt core, DOE reviewed available literature
to evaluate the relevance of these design features, specifically
regarding how prevalent they are in the design of uninterruptible power
supply transformers and how they may impact the efficiency of a
distribution transformer. Based on its review, DOE interprets the terms
``magnetic shunt'' and ``air gap'' as they appear in NEMA's comment to
refer to the definitions prescribed in in IEEE Standard 449-1998
(R2007) ``IEEE Standard for Ferroresonant Voltage Regulators'' (``IEEE
449'').\42\ IEEE 449 defines a magnetic shunt as ``the section of the
core of the ferroresonant transformer that provides the major path for
flux generated by the primary winding current that does not link the
secondary winding''; IEEE 449 defines an air gap as ``the space between
the magnetic shunt and the core, used to establish the required
reluctance of the shunt flux path.'' DOE understands these features to
provide a high reluctance pathway for excess magnetic flux such that
the secondary voltage will remain constant, even when the primary side
voltage fluctuates unexpectedly. This functionality would be
particularly useful in uninterruptible power supply transformers, which
provide a smooth and continuous supply of electricity to avoid damaging
any downstream equipment.
---------------------------------------------------------------------------

\42\ IEEE SA. (1998). IEEE 449-1998--IEEE Standard for
Ferroresonant Voltage Regulators (Accessed on 09/15/2023). Available
online at: <a href="http://standards.ieee.org/ieee/449/675/">standards.ieee.org/ieee/449/675/</a>.
---------------------------------------------------------------------------

However, DOE notes that the definitions of ``air gap'' and
``magnetic shunt'' as they are presented in IEEE 449 do not appear to
be the only examples of these features as they appear in transformer
design. For example, stacked core designs have inherent air gaps that
do not provide the same high reluctance pathway for magnetic flux.
Additionally, DOE observed transformer designs advertised as having
``magnetic shunts,'' consisting of laminated steel sheets installed on
or surrounding the transformer core to prevent leakage flux from
affecting the transformer tank or other surrounding components. These
alternative applications for these features could create confusion as
to which transformers would meet the definition of an uninterruptible
power supply transformer.
While inclusion of either an ``air gap'' or ``shunt core'' may be
useful features in identifying uninterruptible power supply
transformers, DOE lacks sufficient data to properly characterize these
attributes. DOE also has not received sufficient feedback from
stakeholders to indicate that these features are exclusive to
uninterruptible power supply transformers or if they would encompass
many other transformers not intended to be uninterruptible power supply
transformers. Further, NEMA has previously commented that manufacturers
are applying the definition of uninterruptible power supply transformer
appropriately and clarification is not needed. (NEMA, No. 50 at p. 4)
DOE notes that the proposed definition only sought to codify DOE's
existing interpretation that uninterruptible power supply transformers
must be ``within'' an uninterruptible power system and not at the
``input, output, or bypass'' of an uninterruptible power system.
Therefore, in this final rule, DOE is finalizing the proposed
definition of ``uninterruptible power supply 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 \43\ 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.
---------------------------------------------------------------------------

\43\ Delta connection refers to three distribution transformer
terminals, each one connected to two power phases.
---------------------------------------------------------------------------

DOE notes that it 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.'' \44\ 78 FR 23336, 23353. For example, a three-phase
wye-connected transformer for which the output phase voltage is at or
below 600 V, but the output line voltage is above

[[Page 29876]]

600 V 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
---------------------------------------------------------------------------

\44\ Inclusive of a transformer at 600 volts.
---------------------------------------------------------------------------

In response to the August 2021 Preliminary Analysis TSD, DOE
received feedback that it should clarify the interpretation of voltage
in the regulatory text. (Schneider, No. 49 at p. 8; NEMA, No. 50 at p.
4; Eaton, No. 55 at pp. 7-8). In the January 2023 NOPR, DOE noted 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. 88 FR 1722, 1745; 42 U.S.C. 6291(35). However, DOE also
discussed that, upon further evaluation, the distribution transformer
input voltage limitation aligns with the common maximum distribution
circuit voltage of 34.5 kV.45 46 This common distribution
voltage aligns with the distribution line voltage, implying that the
intended definition of distribution transformer in EPCA was to specify
the input and output voltages based on the line voltage. Accordingly,
DOE 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. 88 FR 1722, 1745. DOE also noted in the January 2023 NOPR 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. Id. Accordingly,
DOE proposed 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.
---------------------------------------------------------------------------

\45\ Pacific Northwest National Lab and U.S. Department of
Energy (2016), ``Electricity Distribution System Baseline Report.'',
p. 27. Available at <a href="http://www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf">www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf</a>.
\46\ U.S. Department of Energy (2015), ``United States
Electricity Industry Primer.'' Available at <a href="http://www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf">www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf</a>.
---------------------------------------------------------------------------

In response, Eaton commented that DOE's revised interpretation of
input and output voltages better aligns with industry. (Eaton, No. 137
at p. 13). NEMA commented that the addition of line voltage removes
ambiguity and clearly defines products that need to be in compliance.
(NEMA, No. 141 at p. 9). NEMA further recommended that the LVDT
definition should also be updated to clarify that the voltage
specifications are line voltages. (NEMA, No. 141 at p. 8) Schneider
also supported DOE's clarification that input and output voltages are
line voltages and recommended adding a similar clarification to the
LVDT definition. (Schneider, No. 101 at p. 4)
Howard commented that clarifying that voltage refers to line
voltage is an improvement to the definition of input and output
voltage. However, Howard further stated that it is more common in
industry to refer to line voltage as the ``nominal system'' voltage.
Howard recommended that rather than using ``line'' voltages, DOE should
use ''nominal system voltage,'' which is used in many industry
standards, and proposed defining ``nominal system voltage.'' Howard
additionally supported DOE's assessment that the revised definitions of
input and output voltage would only impact products not considered by
industry to be serving distribution applications. (Howard, No. 116 at
p. 8-9)
DOE reviewed relevant industry standards to assess Howard's
recommendation. Based on this review, DOE found that, while the term
``nominal system voltage'' has been adopted in several standards, its
usage is not ubiquitous. For example, IEEE standard C57.91-2020
interchangeably uses the terms ``nominal voltage,'' ``line voltage,''
and ``line-to-line voltage'' to specify transformer voltage
ratings.\47\ Other standards similarly specify voltage ratings using
the terms ``phase-to-phase,'' ``line-to-ground nominal system
voltage,'' or ``nominal line-to-line system voltage.'' Further, DOE
reviewed manufacturer catalogs for distribution transformers and
observed that it is more common to specify transformer voltage ratings
according to the ``line voltage,'' as opposed to the ``nominal system
voltage.'' The comments received from Eaton and NEMA additionally
indicate that the term ``line voltage'' is well understood in industry
and sufficiently clarifies the definitions of input and output voltage.
---------------------------------------------------------------------------

\47\ IEEE SA. (2020). IEEE C57.12.91-2020--IEEE Standard Test
Code for Dry-Type Distribution and Power Transformers. Available at
<a href="http://standards.ieee.org/standard/C57_12_91-2020.html">standards.ieee.org/standard/C57_12_91-2020.html</a> (last accessed June
21, 2023).
---------------------------------------------------------------------------

Therefore, for the reasons discussed, DOE is modifying the
definition of distribution transformer in this final rule to state
explicitly that the input and output voltage limits are based on the
``line'' voltage and not the phase voltage. Similarly, in accordance
with the feedback submitted by NEMA and Schneider, DOE is similarly
amending the definition of ``low-voltage dry-type distribution
transformer'' to state a transformer that has ``an input line voltage
of 600 volts or less''.
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, (10 kVA to 2500 kVA for liquid-
immersed units and 15 kVA to 2500 kVA for dry-type units), 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 definition
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. DOE established the
current kVA range for distribution transformers by aligning with NEMA
publications in place at the time that DOE adopted the range,
specifically the 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 2336, 23352.
In the January 2023 NOPR, DOE noted that several industry sources
suggest that the distribution transformer kVA range may exceed 2,500
kVA. 88 FR 1722, 1746. Specifically, DOE cited Natural Resources Canada
(NRCAN) regulations that include dry-type distribution transformers up
to 7,500 kVA.\48\ The European Union (EU) Ecodesign requirements also
specify maximum load losses and maximum no-load losses for three-phase
liquid-

[[Page 29877]]

immersed distribution transformers up to 3,150 kVA.\49\
---------------------------------------------------------------------------

\48\ See NRCAN dry-type transformer energy efficiency
regulations at <a href="http://www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875">www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875</a>.
\49\ Official Journal of the European Union, Commission
Regulation (EU) No. 548/2014, May 21, 2014, Available at eur-
lex.europa.eu/legal-content/EN/TXT/
?uri=uriserv%3AOJ.L_.2014.152.01.0001.01.ENG.
---------------------------------------------------------------------------

DOE noted that manufacturers in interviews had stated that
transformers beyond 2,500 kVA are typically step-up transformers
serving renewable applications, which would be outside the scope of
standards on account of exceeding the output voltage limit. 88 FR 1722,
1746. However, DOE cited comments by NEMA and Eaton, which suggested
that some number of general purpose distribution transformers are sold
beyond 2,500 kVA. (NEMA, No. 50 at p. 5; Eaton, No. 55 at p. 8).
Further, DOE noted that some manufacturers expressed concern in
interviews 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).
88 FR 1722, 1746.
In response to this feedback, DOE proposed to expand the scope of
the definition of distribution transformer to 5,000 kVA. DOE requested
comment as to whether 5,000 kVA represented the upper limit for
distribution transformers. Id. at 88 FR 1747.
DOE also estimated energy savings for transformers greater than
2,500 kVA but less than or equal to 5,000 kVA by scaling certain
representative units. In estimating energy savings, DOE assumed these
units are purchased based on lowest first cost and use similar grades
of electrical steel as in-scope units but are not required to meet any
efficiency standards. DOE requested comment on the number of shipments
and distribution of efficiency for these large three-phase distribution
transformers. Id.
NAHB submitted data showing that imports for liquid-immersed
transformers with ratings above 2500 kVA have increased significantly
in the past decade and expressed concern that the proposed standards
would negatively impact the import market for these products. (NAHB,
No. 106 at pp. 8-9) DOE notes that the data cited by NAHB is for all
transformers greater than 2,500 kVA without considering their secondary
voltage. Most transformers greater than 2,500 kVA would be substation
or large power transformers with output voltages that vastly exceed
600V. Due to the voltage limitations, virtually all transformers cited
by NAHB would not be subject to DOE efficiency regulations regardless
of the kVA range for the definition of distribution transformer.
Howard commented that transformers beyond 2,500 kVA are not within
the technical scope of what is considered a distribution transformer
and should not be a part of distribution transformer regulations.
(Howard, No. 116 at pp. 9, 19) Howard stated that they produce a very
small number of 3,000, 3,750, and 5,000 kVA transformers per year that
are primarily used for unique and specialized applications, not as a
means to circumvent DOE regulations. Id. Howard referred DOE to IEEE
C57.12.34 and C57.12.36 industry standards, which Howard stated do not
specify an impedance value for 5,000 kVA transformers with a low-
voltage rating of 600 V and below.\50\ Id. Prolec GE commented that
transformers between 2,500 kVA and 5,000 kVA may maintain certain
characteristics as distribution transformers but are mainly specified
and purchased by industrial customers and not intended for general
purpose applications. (Prolec GE, No. 120 at p. 5)
---------------------------------------------------------------------------

\50\ See Table 2 of IEEE Std C57.12.34-2022 and Table 5 of IEEE
Std C57.12.36-2017.
---------------------------------------------------------------------------

Eaton commented that between 2016 and 2022, it built zero
transformers above a kVA rating of 5,000 kVA that also had an output
voltage of 600 V or less. (Eaton, No. 137 at p. 13) Howard commented
that units above 2,500 kVA with secondary voltages of 600 V or less
represent less than one percent of Howard's annual three-phase pad
mounted transformer shipments. (Howard, No. 116 at p. 10) Howard stated
that units over 2,500 kVA have very few shipments, representing a very
small number of specialized units. (Howard, No. 116 a p. 19)
Howard stated that the average efficiency of these units is 99.4
percent and achieving lower losses than this becomes difficult due to
the very high currents that lead to significant stray and eddy losses.
(Howard, No. 116 at p. 10) Howard stated that if DOE elects to include
these high-kVA units, their efficiencies should not be on-par with
smaller units due to the unique challenges associated with high-kVA
units. (Howard, No. 116 at p. 19)
Eaton commented that because the scaling relationships do not hold
with high-kVA units, DOE should work with manufacturers to identify
more accurate max-tech efficiency levels for high-kVA transformers.
(Eaton, No. 137 at p. 28) Eaton provided data showing what their design
software calculated as max-tech for 3-phase distribution transformers
at various voltages across a range of kVA values. (Eaton, No. 137 at p.
28)
Prolec GE commented that the proposed standards for transformers
above 2,500 kVA result in a much larger increase in standards than all
other transformers because they are not currently subject to efficiency
standards and therefore the baseline transformer is less efficient than
transformers that are in-scope today. (Prolec GE, No. 120 at p. 12)
Hammond commented that the 5,000 kVA limit is preferrable for
medium-voltage dry-type distribution transformer units; however, the
high-currents of these designs may make efficiency standards infeasible
and, therefore, it may be necessary to apply an exclusion for high-
current units, similar to the NRCAN regulations. (Hammond, No. 142 at
p. 3)
In reviewing the technical challenges associated with meeting
energy conservation standards for large three-phase units, DOE agrees
that the presence of both very high kVA ratings and an output voltage
of 600V could lead to very high currents that would inherently lead to
manufacturing challenges, making it more costly to meet a given
efficiency standard. However, DOE notes that industry standards
recommend minimum low-voltage ratings that vary based on kVA.\51\ As a
result, larger kVA transformer tend to have higher secondary voltages.
While maintaining these recommended voltage ratings does not entirely
eliminate the challenges faced by high-current transformers, as further
discussed in section IV.A.2.c, it generally helps maintain a reasonable
current.
---------------------------------------------------------------------------

\51\ See Table 3 of IEEE Std C57.12.36-2017.
---------------------------------------------------------------------------

DOE notes that one of the primary reasons it cited for proposing to
include higher kVA distribution transformer within the scope of the
distribution transformer rulemaking was concern from manufacturers
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). 88 FR 1722, 1746.
NEMA commented in response to the January 2023 NOPR that some
customers have requested units just beyond the scope of regulations
(e.g. 2,501 kVA). (NEMA, No. 141 at p. 9) The Efficiency Advocates
commented that they support DOE's proposal to include capacities up to
5,000 KVA based on manufacturer comment that some products are sold
here that meet the voltage limits and to eliminate the potential
incentive to build transformers just beyond the current scope in the

[[Page 29878]]

presence of amended standards. (Efficiency Advocates, No. 121 at p.7)
Stakeholder comments indicate that losses for high-kVA transformers
increase at a faster rate than modeled by the scaling relationships
used in the January 2023 NOPR, causing the proposed standards for these
high-kVA units to be beyond what is technologically feasible. Based on
the feedback received, DOE conducted additional investigation into the
interaction between capacity, current, and efficiency standards, as
discussed in sections IV.A.2.c and IV.C.1.e. Based on the feedback
received from manufacturers and this additional technical
investigation, DOE has determined that the primary challenge associated
with meeting efficiency standards for higher kVA distribution
transformers is related to the high-current associated with those
transformers.
If built per the minimum voltage recommendations of IEEE Std
C57.12.36-2017, 5,000 kVA transformers would never have an output
voltage less than or equal to 600V, and 3,750 kVA transformers would
also typically be larger than 600V. This indicates that 3,750 kVA or
5,000 kVA transformers would likely not have output voltages that meet
the definition of distribution transformers subject to energy
conservation standards, if built per industry standards.
However, stakeholder comments also suggest that consumers have
requested transformers just beyond 2,500 kVA (i.e., 2,501 kVA), that
are not built per industry standard kVA ranges to use in general
purpose applications, which could increase in the presence of amended
efficiency standards. As such, DOE is finalizing an expansion to
include distribution transformers less than or equal to 5,000 kVA, as
proposed in the January 2023 NOPR. However, DOE requested comment on
its modeling of high-kVA units (88 FR 1722, 1760) and based on
stakeholder feedback has modified its modeling (as discussed in section
IV.C.1.e) and adopted efficiency levels for these high-kVA units to
reflect the challenges associated with high-currents in distribution
transformers.
DOE notes that this finalized definition reduces the risk of non-
standard kVA transformers being built just beyond the scope of
regulations in an effort to circumvent efficiency requirements, while
accommodating the legitimate challenges associated with high-current
transformers. DOE discusses the specific comments related to high-
current transformers in section IV.A.2.c of this document.
2. Equipment Classes
When evaluating and establishing or amending energy conservation
standards, DOE may establish separate standards for a group of covered
equipment (i.e., establish a separate equipment class) if DOE
determines that separate standards are justified based on the type of
energy used, or if DOE determines that a product's capacity or other
performance-related feature justifies a different standard. (42 U.S.C.
6316(a); 42 U.S.C. 6295(q)) In making a determination whether a
performance-related feature justifies a different standard, DOE
considers such factors as the utility of the feature to the consumer
and other factors DOE determines are appropriate. (Id.)
Eleven equipment classes are established under the existing
standards for distribution transformers, one of which (mining
transformers \52\) 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).
---------------------------------------------------------------------------

\52\ 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 identified the transformer as being for this use
only. 10 CFR 431.192.
---------------------------------------------------------------------------

Table IV.3 presents the eleven equipment classes that exist in the
current energy conservation standards and provides the kVA range
associated with each.
[GRAPHIC] [TIFF OMITTED] TR22AP24.530

DOE notes that across the existing transformer equipment classes,
numerous factors can impact the cost and efficiency of a distribution
transformer. Certain factors like primary voltage, secondary voltage,
insulation material, specific impedance designs, voltage taps, etc.,
can all increase the price of a given transformer and lead to an
increase in transformer losses, which may make meeting any given
efficiency standard more difficult. Distribution transformers are
frequently customized by consumers to add features, safety margins,
etc. However, DOE has

[[Page 29879]]

determined that in general these differences are not sufficient to
warrant separate equipment classes. Having a different equipment class
for all possible kVA and voltage combinations is infeasible, would add
complexity to optimization software, and was not suggested by any
stakeholders. Within a given equipment class and efficiency standard,
there is typically sufficient ``margin'' such that all small
variabilities in design can meet efficiency standards without reaching
an ``efficiency wall'' wherein any additional efficiency gains become
substantially more expensive. However, certain design variabilities may
warrant separation into additional equipment classes such that the
product features remain on the market. In the January 2023 NOPR, DOE
requested comment and data on a variety of other potential equipment
features that may warrant a separate equipment class. 88 FR 1722, 1747.
These comments are discussed in detail below.
a. Submersible Transformers
Certain distribution transformers are installed underground and,
accordingly, may endure partial or total immersion in water. In the
January 2023 NOPR, DOE stated that the subterranean installation of
submersible distribution transformers means that there is less
circulation of ambient air for shedding heat. 88 FR 1722, 1748.
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 (e.g., adding
radiators).
DOE noted that distribution transformer temperature rise tends to
be governed by load losses and that it is typical for design options
that reduce load losses to increase no-load losses. 88 FR 1722, 1748.
While no-load losses make up a relatively small portion of losses at
full load, no-load losses can contribute a significant portion of total
losses at 50-percent PUL, at which manufacturers must certify
efficiency. However, due to the potentially reduced heat transfer of a
subterranean environment, combined with the possibility of operating
while submerged, customers must reduce load losses to meet temperature
rise limitations. Therefore, the design choices needed to meet a lower
temperature rise may lead manufacturers to increase no-load losses and
may make it more difficult to meet a given efficiency standard at 50-
percent PUL.
In the January 2023 NOPR, DOE tentatively determined that
distribution transformers designed to operate while submerged and in
contact with run-off debris constitutes a performance-related feature
which other types of distribution transformers do not have. 88 FR 1722,
1748. At max-tech efficiency levels, both no-load and load losses are
low enough that distribution transformers generally do not meet their
rated temperature rise. However, at intermediate efficiency levels,
trading load losses for no-load losses allows distribution transformers
to be rated for a lower temperature rise. This 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 at the rated temperature rise. Id.
In defining a submersible distribution transformer, DOE noted that
the IEEE C57.12.80-2010 includes numerous definitions for transformers
designed to operate in partial or total submersion. Id. DOE attempted
to identify the physical features that would distinguish transformers
capable of operating in a submersible operation by reviewing industry
standards IEEE C57.12.23-2018 and IEEE C57.12.24-2016. Id. DOE proposed
to define a 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.'' Id. DOE noted that this definition
sought to incorporate the physical features associated with submersible
transformers that are included in industry standards. DOE requested
comment on its definition of submersible distribution transformer and
information regarding the specific design characteristics that limit
efficiency. Id.
APPA supported creating a separate equipment class for vault,
submersible, or special installation transformers and supported DOE's
proposal not to establish higher efficiency standards for those units.
(APPA, No. 103 at p. 3)
Howard supported a separate equipment class for submersible
distribution transformers because of their lack of cooling, higher
ambient temperatures, and higher installation costs. (Howard, No. 116
at p. 11) Howard commented that comparing its submersible transformers
to its non-submersible transformers requires a 10- to 12-percent
increase in no-load losses and comparable reduction in load losses to
meet maximum temperature rise characteristics. (Howard, No. 116 at p.
11) Howard added that in addition to the reduced cooling, submersible
transformers also frequently have bushings, switches, tap changers, and
other accessories mounted on the cover, which increases lead lengths
and therefore increases losses. (Howard, No. 116 at p. 11)
Prolec GE and NEMA commented that submersible transformers are
limited in their ability to meet higher efficiency levels on account of
needing to meet the strict dimensional requirements associated with
fitting in existing vaults, their limited heat transformer on account
of needing to operate in dirty water, and their need to have corrosion-
resistant construction, which is thicker and reduces the transformer's
ability to remove heat. (NEMA, No. 141 at p. 10; Prolec GE, No. 120 at
p. 9) Due to these limitations, Prolec GE supported DOE establishing a
separate equipment class for submersible transformers and not
increasing efficiency standards. (Prolec GE, No. 120 at p. 9) Carte
supported establishing a separate equipment class for submersible
transformers and not establishing higher efficiency levels because of
the strict dimensional constraints associated with installations in
vault locations. (Carte, No. 140 at p. 7)
WEC commented that DOE's proposed equipment class and no-new-
standard determination for submersible distribution transformers would
not cover WEC's more cost effective approach of using pad mounted
transformers in certain vault applications. (WEC, No. 118 at p. 2) DOE
notes that in cases where utilities are using traditional pad-mounted
distribution transformers in vault applications, there are not going to
be the same thermal limitations that represent the technical features
identified by stakeholders as warranting a separate equipment class.
Regarding DOE's proposed definition of submersible distribution
transformer, Carte commented that some utilities in unique locations
use a 65 [deg]C temperature rise in their transformer vaults. (Carte,
No. 140 at p. 7) Prolec GE and NEMA commented that submersible
distribution transformer is already defined per IEEE standards
C57.12.24 and C57.12.40. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at
pp. 9-10) Prolec GE and NEMA further commented that the unique design
and characteristics of submersible transformers makes them rarely
compatible with above ground

[[Page 29880]]

installation. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10)
Prolec GE and NEMA commented that IEEE C57.12.80 identifies
installation in a vault as a common characteristic for submersible,
subway, and network transformers. (Prolec GE, No. 120 at p. 6; NEMA,
No. 141 at pp. 9-10)
Howard commented that DOE should align the definition with IEEE
standards C57.12.23, C57.12.24, and C57.12.40. Howard added that if DOE
elects not to align with IEEE standards, DOE should modify feature (4)
of the definition to clarify that copper-bearing steel with minimum
specified thicknesses for tanks, covers, and auxiliary coolers is an
acceptable alternative to stainless steel as a ``corrosion-resistant
material.'' (Howard, No. 116 at p. 10) Prolec GE and NEMA recommended
submersible distribution transformer be defined as ``a liquid-immersed
distribution transformer, so constructed as to be operable when fully
submerged in water including the following feature: (1) has sealed tank
construction; (2) has the tank, cover and all external appurtenances
made of corrosion-resistance material or with appropriate corrosion-
resistance surface treatment to induce the components surface to be
corrosion resistant; and (3) is designed for installation in an
underground vault.'' (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp.
9-10)
In reviewing the nuances NEMA, Prolec GE, and Howard described as
to the different approaches manufacturers may take to ensure their
distribution transformer is constructed to operate when submerged in
water, DOE agrees that different insulating fluids may modify the exact
temperature rise of a given submersible distribution transformer and
the primary physical features associated with submersible transformers
include having sealed tank construction and corrosion resistant
surroundings. As noted, DOE described the physical features identified
in the NOPR based on a review of these industry standards and intended
to align its definition with the physical features identified in these
standards.
Therefore, DOE is adopting a definition for submersible
distribution transformer to mean ``a liquid-immersed distribution
transformer, so constructed as to be operable when fully or partially
submerged in water including the following features: (1) has sealed-
tank construction; and (2) has the tank, cover, and all external
appurtenances made of corrosion-resistant material or with appropriate
corrosion resistant surface treatment to induce the components surface
to be corrosion resistant.''
b. Large Single-Phase Transformers
DOE received several comments from stakeholders (discussed in
sections IV.C.1.d and IV.E.2 of this document) noting that in the
immediate future, the ability to operate transformers efficiently at
higher loading may represent a distinct consumer utility. (APPA, No.
103 at p. 17; NEPPA, No. 129 at p. 2; Cliffs, No. 105 at pp. 16-17;
Carte, No. 140 at p. 6) Specifically, an increased ability to overload
small single-phase transformers, which are often placed most directly
near consumer loads, provides safety and reliability amidst uncertainty
over near-future demand patterns as electrification proceeds. DOE notes
that the ability to overload a distribution transformer is related to a
transformer's temperature rise and insulation.
The likelihood of a distribution transformer being overloaded is a
function of, among other factors, the size of the transformer and the
number of consumers being served by a given distribution transformer.
While smaller kVA transformers tend to serve a smaller number of
households, the loading on those smaller transformers could vary with
considerably more irregularity because the actions of a small number of
individuals can drastically impact loading. Larger kVA transformers
tend to serve a larger number of households, with overall loading on
the transformer distributed across a larger number of individuals.
Therefore, while loading still varies, it varies more predictably as no
single individual can impact the loading on a single transformer as
significantly. As a result, larger kVA transformers are less likely to
be subject to overloading conditions than their smaller kVA
counterparts.
Instantaneous temperature rise on a transformer tends to be
governed by load losses and it is typical for design options that
reduce load losses to increase no-load losses. While no-load losses
typically make up a relatively small portion of losses at full load,
no-load losses can contribute a significant portion of total losses at
50-percent PUL, at which manufacturers must currently demonstrate
compliance with energy conservation standards at 10 CFR 431.196(b). The
design choices needed to reduce temperature rise may lead manufacturers
to increase no-load losses, as not doing so may increase the cost of
the distribution transformer and diminish sales in a market sensitive
to selling price. Further, because operating temperature is impacted by
the ability of the transformer to dissipate heat, a transformer's
tolerance of overloading is directly linked to its ability to shed
heat. Heat transfer is directly dependent on the ratio of distribution
transformer surface area to volume. In other words, the more surface
area that a transformer has per unit of volume, the more effectively it
will be able to shed heat. As transformer capacity increases, however,
the weight and volume of the transformer tend to increase more rapidly
than the surface area, meaning that heat transfer become less
effective. As a result, smaller kVA transformers tend to be more
physically suitable for sustaining overload conditions than larger kVA
transformers, which typically need additional radiators to effectively
remove heat.
Similarly to submersible transformers, at the max-tech efficiency
levels for single phase transformers, both the no-load and load losses
are low enough that distribution transformers generally do not meet
their rated temperature rise. However, at intermediate efficiency
levels, trading load losses for no-load losses may allow smaller
distribution transformers serving fewer consumers to have increased
overload capability, particularly if paired with less-flammable
insulating liquid. This combination 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 at the rated temperature rise. Id.
One utility investigated the likelihood of distribution
transformers being overloaded based on potential electric vehicle (EV)
charging penetration rates for single-phase transformers ranging from
15 to 100 kVA. This study found that smaller transformers have a high
likelihood of being overloaded and, as the size of those transformers
increases, the percentage of overloaded transformers at a given kVA
goes to zero beyond 100 kVA.\53\ While in the longer term, the study
recommends upsizing transformers such that loading on transformers
remains low, in the immediate future, consumers will value increased
overload capacity as a consumer feature for small, single-phase
transformers.
---------------------------------------------------------------------------

\53\ Dalah, S., Aswani, D., Geraghty, M., Dunckley, J., Impact
of Increasing Replacement Transformer Size on the Probability of
Transformer Overloads with Increasing EV Adoption, 36th
International Electric Vehicle Symposium and Exhibition, June, 2023.
Available online at: <a href="https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf">https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf</a>.
---------------------------------------------------------------------------

Based on this data, for this final rule DOE has evaluated two
equipment classes for single-phase liquid-immersed distribution
transformers. Equipment Class 1A corresponds to single-phase

[[Page 29881]]

liquid-immersed distribution transformers greater than 100 kVA.
Equipment Class 1B corresponds to single-phase liquid-immersed
distribution transformers ranging from 10-100 kVA. Equipment Class 1A
includes units that are unlikely to be overloaded, while Equipment
Class 1B includes units that are at higher likelihood of being
overloaded and, therefore, consumers are more likely to exchange no-
load losses for load losses, thereby making it more difficult to meet
amended efficiency standards.
DOE notes that in the cited study exploring the likelihood of
overloading in the presence of high-EV penetration (corresponding to a
50% penetration rate by 2035), the overloading likelihood ranges from
100 percent for 15 kVA transformers to 2.5 percent for 100 kVA
transformers. However, when those 100 kVA transformers are upsized, the
overload likelihood in the high-EV penetration scenario falls to 0.1
percent, indicating that 100 kVA approximately corresponds to the upper
limit of single-phase transformers that are likely to experience
overloading and therefore likely to be designed to trade load losses
for no-load losses to reduce the loss-of-life impacts associated with
overloading. DOE considered other potential capacities for separating
equipment, as lower-EV penetration scenarios show that 75 kVA and 100
kVA transformers are unlikely to be overloaded. However, given the
regional variance of EV penetration, DOE has determined that even in
the most aggressive EV-penetration scenarios, the likelihood of
overloading falls to virtually zero above 100 kVA. Therefore, in light
of the above, DOE has determined that 10-100 kVA and above 100 kVA are
reasonable capacity designation for determining product classes.
As noted, higher efficiency levels can result in low no-load and
load losses; however, intermediate efficiency levels require trading
off between the two. Further, the utility associated with increased
overloading is likely limited to the near-term electrification build-
out, wherein a significant number of new loads, notably electric
vehicles, are being added to the grid. Longer-term, utilities are
expected to replace this overloading ability with larger kVA
transformers, as recommended by the aforementioned study.
While DOE did not propose separate equipment classes based upon kVA
capacity for liquid-immersed transformers in the January 2023 NOPR, DOE
requested comment on any other categories of equipment that may warrant
a separate equipment class. 88 FR 1722, 1752. DOE also evaluated a
separate equipment class in the January 2023 NOPR for submersible
distribution transformer based, in part, on the high overload
capabilities and reduced heat transformer needed for many submersible
distribution transformers which require manufacturers to increase no-
load losses in order to decrease load losses. 88 FR 1722, 1748.
Stakeholder feedback in response to the NOPR regarding the likely
increase in loading--as summarized at the beginning of this section--
and the conclusions from the additional studies described previously in
this section regarding the likelihood of overloading a transformers in
the near-term justify evaluating single-phase liquid-immersed
distribution-transformers as two equipment classes based on kVA size,
based on a similar principle that increased ability to overload a
transformer requires trading no-load losses for load losses at
intermediate efficiency levels.
c. Large Three-Phase Transformers With High-Currents
Distribution transformers with high currents often have increased
stray losses, which can impact the efficiency of distribution
transformers. Because of this limitation, NRCAN regulations exclude
transformers with a nominal low-voltage line current of 4000 A or more.
DOE has historically not evaluated high-current transformers as a
separate equipment class.
In the January 2023 NOPR, DOE noted that while stray losses may be
slightly higher for high-current transformers, manufacturers have the
option to use copper secondaries or a copper buss bar to decrease load
losses. 87 FR 1722, 1750. Further, DOE noted that technologies that
increase the efficiency of lower-current transformers tend to also
increase the efficiency of high-current transformers. Id. Therefore,
DOE did not propose a separate equipment class for high-current
transformers. However, DOE stated that it may consider a separate
equipment class for high-current transformers if sufficient data were
provided, and DOE requested manufacturers provide data on the different
cost-efficiency curve associated with high-current transformers along
with the number of shipments of these units. Id. at 87 FR 1751.
Eaton provided data showing the max-tech of their designs with both
amorphous and grain-oriented electrical steel (GOES) cores with 208Y/
120 secondaries and 480Y/277 secondaries. (Eaton, No. 137 at p. 17)
Eaton's data showed that the max-tech is similar at low kVA values,
regardless of secondary current. (Eaton, No. 137 at p. 17) Eaton
additionally provided cost efficiency curves for 500 kVA units which
showed similar incremental costs at the proposed standard levels for
designs with either a 208Y/120 or a 480Y/277 secondary. Id. However, as
the transformer capacity increases and the secondary current increases,
the maximum transformer efficiency that can be achieved begins to drop
considerably. Id.
Most distribution transformers are sold at one of a handful of
standard secondary voltages. For three-phase transformers, this is
typically either 480Y/277 or 208Y/120. Eaton stated that 97 percent of
their three-phase shipments use either a 208Y/120 or 480Y/277
secondary. (Eaton, No. 137 at p. 20)
Eaton recommended DOE set an efficiency standard with at least a
20-percent margin in base losses relative to the actual max-tech for
208Y/120 secondary transformers. Id. Eaton suggested that DOE could
propose separate standards for transformers with 480Y/277V or 208Y/120V
secondaries based on having a line voltage above or below 250 V
respectively. (Eaton, No. 137 at p. 29)
DOE notes that across all transformers, variability in voltage can
impact the price and maximum achievable efficiency of a transformer. As
shown in Eaton's max-tech plots, there is a slight difference in the
maximum efficiency that can be achieved across all kVA ranges as the
stray and eddy currents and conductor thickness will vary slightly
between designs. Similarly, the choice in primary voltage may slightly
impact the maximum achievable efficiency of a given transformer design.
However, in general, these differences are not sufficient to warrant
separate equipment classes. As discussed in Eaton's comment, for most
kVA values there is sufficient ``margin'' that both a 208Y/120 and a
480Y/277 transformer have similar cost-efficiency relationships. Having
a different equipment class for all possible kVA and voltage
combinations is infeasible and was not suggested by any stakeholders.
Eaton additionally commented that its modeling of max-tech shows
that previous DOE efficiency standards may have resulted in the
unavailability of many 2,000 kVA and 2,500 kVA distribution
transformers with 208Y/120 secondaries, which should not have been
allowed under 42 U.S.C. 6295(o)(4), as this represents a performance
characteristic. (Eaton, No. 137 at p. 18)

[[Page 29882]]

DOE notes that 42 U.S.C. 6295(o)(4) specifies that DOE may not set
any amended standard that is likely to result in the unavailability of
any performance characteristics that are substantially the same as
those generally available in the United States at the time of the
Secretary's finding. DOE notes that voltage generally increases as
transformer capacity increases. As such, the high-current units cited
by Eaton generally were not available due to the challenges of
designing a transformer with a wire of sufficient thickness to handle
the very high-currents. DOE does not expect that the adopted standards
will result in the unavailability of any high-current units that are
currently being produced in any significant volume. Further, there is
no distinct purpose where such a large kVA transformer with such a
high-current would be the only option to provide a low secondary
voltage because consumers can and do achieve identical utility more
economically and efficiently with one or multiple smaller kVA
transformer placed closer to the electricity's end-use.
Transmission losses are also related to transformer current, and as
such, if a customer needs a very large amount of transformative
capacity, it is typically more efficient and cost effective to step-
down power to 480V/277 and then use smaller transformers to further
step down the voltage to 208Y/120, closer to the actual point of use.
For these reasons, industry standards recommend high-kVA transformers
have higher-secondary voltages. As such, currents do not tend to reach
problematic values.
However, transformers within common industry values may still have
a high enough current such that the stray and eddy losses would make up
a much greater percentage of the transformer load losses and require
manufacturers to overdesign transformers to meet a given efficiency
level. Additionally, as kVA increases, this effect may become
progressively more pronounced.
Prolec GE commented that load losses tend to be ten percent higher
for high-current transformers due to increased losses in the leads and
electrical connections on the secondary side of the transformer.
(Prolec GE, No. 120 at pp. 6-7) Carte commented that using a 120V
secondary instead of a 277V secondary for a 500 kVA, single-phase
transformer would increase the cost to meet current efficiency
standards by 52 percent. (Carte, No. 140 at p. 9) Carte commented that
for 1,500 kVA three-phase transformer, using 208Y/120 secondary instead
of a 480Y/277 secondary results in a 66 percent increase in first cost.
Carte added that a 1,500 kVA three-phase unit with 208Y/120 design
could at best achieve a 5 percent reduction in losses and would
increase the cost by 95 percent relative to current efficiency
standards, unless they transitioned to an amorphous core. (Carte, No.
140 at p. 9)
Several stakeholders gave specific low-voltage line-currents at
which stray and eddy losses grow disproportionately. Howard commented
that for three-phase transformers, it currently is difficult to meet
efficiency standards for currents greater than 3000 A. Howard commented
that typical load losses grow disproportionately at high current,
wherein the load loss to no-load loss ratio is typically between 3-5
for low-current transformers but increases to 7-8 for high-current
transformers, requiring higher grades of core steel to offset the
increased load losses. Howard added that under the NOPR proposed
levels, currents greater than 2000 A would be difficult. (Howard, No.
116 at p. 12) Prolec GE commented that above 3000 A, the manufacturer
needs to overdesign the transformer or it becomes infeasible to meet
efficiency levels. (Prolec GE, No. 120 at pp. 6-7) NEMA commented that
for, liquid-filled transformers, it is difficult to meet current energy
conservation standards above 4000 A today and recommended DOE not
increase efficiency standards for any transformers with a low voltage
line current over 3000 A. (NEMA, No. 141 at p. 11)
The current limits mentioned by stakeholders typically correspond
to a specific common kVA value and common secondary voltage. For
example, a low-voltage line current of 2,000 A or greater corresponds
to 3-phase transformers with either a 208Y/120 secondary voltage and a
capacity of 750 kVA or transformers with a 480Y/277 secondary voltage
and a capacity of 2,000 kVA. A low-voltage line current of 3,000 A or
greater corresponds to transformers with a 208Y/120 secondary voltage
and capacity greater than 1000 kVA or transformers with a 480Y/277
secondary voltage and a capacity of 2,500 kVA. A low-voltage line
current of 4,000 A or greater corresponds to transformers with a 208Y/
120 secondary voltage and capacity of 1,500 kVA or transformers with a
480Y/277 secondary voltage and a capacity of 3,750 kVA.
IEEE C57.12.36-2017 recommends a minimum low-voltage of 277V
beginning at 1,500 kVA and a minimum of 1386V beginning at 5,000 kVA.
Similarly, IEEE C57.12.34-2022 recommends a maximum kVA of 1,000 kVA
for a 208Y/120 or 240V secondary. As such, the only IEEE standard
recommended products with a 208Y/120 or 480Y/277 secondary above 2,000
A include 750 kVA and 1,000 kVA transformers with 208Y/120 secondaries
and 2,000 kVA; 2,500 kVA; and 3,750 kVA with 480Y/277 secondaries. The
only recommended products above 3,000 A include a 2,500 kVA and 3,750
kVA with a 480Y/277 secondary. The only recommended products above
4,000 A include a 3,750 kVA with 480Y/277 secondary. DOE notes that
3,750 kVA transformers are not currently subject to energy conservation
standards but were proposed to be covered in the January 2023 NOPR.
Regarding transformers with low-voltage line currents exceeding
2,000 A that stakeholders identified as having a harder time meeting
standard, Eaton's data suggests that the DOE modeled max-tech closely
aligns with manufacturer data for the 2,000 kVA and 2,500 kVA
transformers with 480Y/277 secondaries.
Howard commented that 4.8 percent of their three-phase transformer
shipments exceed 2000 A. (Howard, No. 116 at p. 12) Howard did not give
specifics as to which of those also exceed 3,000 A or 4,000 A; however,
based on industry standards, DOE expects most of those units to be
2,000 kVA and 2,500 kVA transformers with 480Y/277 secondaries.
Eaton provided data showing that as transformer capacity increases,
the percentage of units with the higher secondary, and therefore lower
current, increases such that at 1500 kVA, only 7.9 percent of units
have 208Y/120 secondaries, and at 2,000 kVA and above, 0 percent of
shipments have 208Y/120 secondaries. (Eaton, No. 137 at p. 20)
The data supplied by Eaton indicates that, for lower kVA
capacities, transformer max-tech efficiency increases with kVA as
predicted in DOE's modeling. However, above a certain point, the
transformer begins to reach the limits of its design capabilities and
max-tech efficiency begins to decline, rather than increase. Eaton's
data suggest that this design limit can vary by steel variety, but for
grain oriented electrical steel begins at 500 kVA for a 208Y/120
secondary voltage, corresponding to a line current of 1,389 A. (Eaton,
No. 137 at p. 18)
Further, the normal impedance range for transformers as specified
in IEEE Standard C57.12.34 changes from 1.2%-6.0% below 500 kVA to
1.5%-7.0% at 500 kVA.\54\ Although impedance does

[[Page 29883]]

not necessarily correlate to transformer efficiency, as discussed in
section IV.C.1.d, designing to a higher impedance range leaves
transformer with less design flexibility to meet amended efficiency
standards.
---------------------------------------------------------------------------

\54\ IEEE SA. (2022). IEEE C57.12.34-2023--IEEE Standard
Requirements for Pad Mounted, Compartmental-Type, Self-Cooled,
Three-Phase Distribution Transformers, 10 MVA and Smaller; High-
Voltage, 34.5 kV Nominal System Voltage and Below; Low-Voltage, 15
kV Nominal System Voltage and Below. Available at <a href="https://standards.ieee.org/ieee/C57.12.34/6863/">https://standards.ieee.org/ieee/C57.12.34/6863/</a> (last accessed Nov. 8,
2021).
---------------------------------------------------------------------------

Based on the increase in stray and eddy losses associated with
high-current and the change in impedance range, DOE has concluded that
transformers greater than 500 kVA warrant a separate equipment class.
Specifically, DOE has evaluated two equipment classes for three-phase
liquid-immersed distribution transformers based upon capacity.
Equipment Class 2A corresponds to three-phase liquid-immersed
distribution transformers ranging from 15 to less than 500 kVA.
Equipment Class 2B corresponds to three-phase liquid-immersed
distribution transformers greater than or equal to 500 kVA).
Regarding further separation of large three-phase kVA transformers
based on current, DOE acknowledges that high-current transformers may
experience greater challenges in meeting amended efficiency standards
and higher-current transformers tend to correspond to larger kVA sizes.
However, DOE analyzed the incremental costs associated with three-phase
1,500 kVA units at 208Y/120 secondaries as compared to 480Y/277
secondaries. These results are discussed in Chapter 5 of the TSD. DOE
has determined that both units are capable of meeting amended
efficiency standards and therefore concluded that a transformer with a
higher-current does not justify having a lower efficiency standard than
transformers with lower-currents. Therefore, DOE has not established a
separate equipment class for high-current transformers.
d. 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 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 pp. 2-21) In
response to the August 2021 Preliminary Analysis TSD, DOE received
comment reiterating that these transformers may experience additional
losses which could make it more difficult to comply with standards,
particularly when tested in the lower voltage configuration.
(Schneider, No. 49 at p. 9; ERMCO, No. 45 at p. 1; NEMA, No. 50 at p.
6; Eaton, No. 55 at p. 12)
In the January 2023 NOPR, DOE discussed how multi-voltage
distribution transformers, and specifically those with non-integer
ratings, 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 requiring a replacement
transformer. 88 FR 1722, 1750. DOE also acknowledged that these
distribution transformers often have additional, unused winding turns
when operated at their lower voltage, increasing the transformer
losses. Id.
However, DOE noted

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