Energy Conservation Program: Energy Conservation Standards for Distribution Transformers, 29834-30043 [2024-07480]

Agencies

• DEPARTMENT OF ENERGY

[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 [www.gpo.gov]
[FR Doc No: 2024-07480]



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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

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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 www.regulations.gov. All documents in the docket are listed 
in the www.regulations.gov index. However, not all documents listed in 
the index may be publicly available, such as information that is exempt 
from public disclosure.
    The docket web page can be found at www.regulations.gov/docket/EERE-2019-BT-STD-0018. The docket web page contains instructions on how 
to access all documents, including public comments, in the docket.
    For further information on how to review the docket, contact the 
Appliance and Equipment Standards Program staff at (202) 287-1445 or by 
email: [email protected].

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: 
[email protected].
    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: 
[email protected].

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

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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 consumer 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 
consumer refers to electric utilities; for low- 
and medium-voltage dry-type distribution transformers, the term 
consumer 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 (CO2), 12.29 
thousand tons of sulfur dioxide (SO2), 89.85 thousand tons 
of nitrogen oxides (NOX), 416.15 thousand tons of methane 
(CH4), 0.40 thousand tons of nitrous oxide (N2O), 
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 CO2 are presented in short tons.
    \8\ DOE calculated emissions reductions relative to the no-new-
standards case, which reflects key assumptions in the Annual Energy 
Outlook 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 CO2 (SC-CO2), the social cost of methane 
(SC-CH4), and the social cost of nitrous oxide (SC-
N2O).\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. www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.

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    DOE estimated the monetary health benefits of SO2 and 
NOX 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 (PM2.5) concentrations from two 
precursors (SO2 and NOX), and from changes in 
ambient ozone from one precursor (NOX), but will continue to 
assess the ability to monetize other effects such as health benefits 
from reductions in direct PM2.5 emissions.
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    \11\ U.S. EPA. Estimating the Benefit per Ton of Reducing 
Directly Emitted PM2.5, PM2.5 Precursors and 
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
    \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 SO2 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 
NOX and SO2 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 NOX and SO2 
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.
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    \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.
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    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 CO2, 7.49 thousand tons 
of SO2, 55.92 thousand tons of NOX, 259.96 
thousand tons of CH4, 0.24 thousand tons of N2O, 
and 0.05 tons of Hg.\17\
---------------------------------------------------------------------------

    \16\ A metric ton is equivalent to 1.1 short tons. Results for 
emissions other than CO2 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-CO2CO2, 
the SC-CH4, and the SC-N2O. 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. 
www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------

    DOE estimated the monetary health benefits of SO2 and 
NOX emissions reductions, using benefit per ton estimates 
from the Environmental Protection Agency,\19\ as discussed in section 
IV.L of this document. DOE did not monetize the reduction in mercury 
emissions because the quantity is very

[[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 PM2.5 concentrations from 
two precursors (SO2 and NOX), and from changes in 
ambient ozone from one precursor (for NOX), but will 
continue to assess the ability to monetize other effects such as health 
benefits from reductions in direct PM2.5 emissions.
---------------------------------------------------------------------------

    \19\ U.S. EPA. Estimating the Benefit per Ton of Reducing 
Directly Emitted PM2.5, PM2.5 Precursors and 
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
    \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.
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    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 SO2 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 NOX and 
SO2 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 NOX and 
SO2 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 CO2, 0.63 thousand tons 
of SO2, 4.69 thousand tons of NOX, 21.86 thousand 
tons of CH4, 0.02 thousand tons of N2O, and 0.00 
tons of Hg.\25\
---------------------------------------------------------------------------

    \24\ A metric ton is equivalent to 1.1 short tons. Results for 
emissions other than CO2 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-CO2, the SC-
CH4, and the SC-N2O. 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. 
www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
---------------------------------------------------------------------------

    DOE estimated the monetary health benefits of SO2 and 
NOX 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 PM2.5 concentrations from two precursors 
(SO2 and NOX), and from changes in ambient ozone 
from one precursor (for NOX), but will continue to assess 
the ability to monetize other

[[Page 29849]]

effects such as health benefits from reductions in direct 
PM2.5 emissions.
---------------------------------------------------------------------------

    \27\ U.S. EPA. Estimating the Benefit per Ton of Reducing 
Directly Emitted PM2.5, PM2.5 Precursors and 
Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
    \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.
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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.\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 
NOX and SO2 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 NOX 
and SO2 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 NOX and SO2 emissions. In 
this case, the net benefit amounts to $29.9 million per year.
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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 SO2 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 CO2 
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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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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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.
BILLING CODE 6450-01-P

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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 
www.regulations.gov). The references are arranged as follows: 
(commenter name, comment docket ID number, page of that document).
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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\
---------------------------------------------------------------------------

    \35\ See Department of Energy. DOE Actions to Unlock 
Transformers and Grid Component Production. Available at 
www.energy.gov/policy/articles/doe-actions-unlock-transformer-and-grid-component-production (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 
[email protected].
    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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: www.regulations.gov/docket/EERE-2019-BT-STD-0018. 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. 
documents.hammondpowersolutions.com/documents/Literature/Specialty/HPS-Autotransformers-Brochure.pdf?_gl=1*db1907*_ga*NTA0ODk1MjQzLjE2NzExMzEzMTM.*_ga_RTZEGSXND8*MTY4MzIxNTc5My42Ni4xLjE2ODMyMTcyNjcuNTguMC4w.
---------------------------------------------------------------------------

    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: standards.ieee.org/ieee/449/675/.
---------------------------------------------------------------------------

    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 www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf.
    \46\ U.S. Department of Energy (2015), ``United States 
Electricity Industry Primer.'' Available at www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf.
---------------------------------------------------------------------------

    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 
standards.ieee.org/standard/C57_12_91-2020.html (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 www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875.
    \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: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
---------------------------------------------------------------------------

    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 https://standards.ieee.org/ieee/C57.12.34/6863/ (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 that the efficiency of these transformers will 
increase once the distribution grid is increased to the higher voltage 
rating and the entire winding is used. Further, stakeholder comments 
suggested that the difference in losses associated with multi-voltage 
distribution transformers is relatively small. DOE also noted that the 
same technologies that increase the efficiency of single-voltage 
distribution transformers can be used to increase the efficiency of 
multi-voltage distribution transformers, meaning that the efficiency of 
either product could be increased via the same methods to meet amended 
standards. Id. Therefore, DOE did not propose a separate equipment 
class for multi-voltage-capable distribution transformers with a 
voltage ratio other than 2:1 but requested comment and data on the 
number of shipments for and degree of additional losses experienced by 
these products.
    Howard commented that dual voltage transformers can increase load 
losses by 5-24 percent, requiring transformers to be overdesigned and 
possibly limiting manufacturers' ability to offer certain designs. 
Howard additionally commented that dual voltage ratios other than 2:1 
represent less than 10 percent of shipments for all equipment classes. 
(Howard, No. 116 at pp. 11-12)
    NEMA commented that it is difficult to say exactly how load loss 
changes with multi-voltage transformers and estimated that fewer than 2 
percent of shipments are multi-voltage transformers with ratios other 
than 2:1. (NEMA, No. 141 at p. 10)
    Eaton commented that load loss data for transformers with a voltage 
ratio other than 2:1 may not show a meaningful trend because load 
losses are adjusted based on the no-load losses to meet standards. 
Instead, Eaton provided cost versus efficiency data for 500 kVA 
transformers which indicated that transformers with a voltage rating 
other than 2:1 are capable of achieving effectively the same 
efficiencies as transformers with a single voltage rating. The data 
provided also indicated that the proposed efficiency levels could be 
met at a similar incremental cost for either a multi-voltage or single-
voltage transformer. However, Eaton went on to state that this may vary 
across voltage and kVA ratings and that there is insufficient data to 
draw broad conclusions. (Eaton, No. 137 at pp. 14-15) Eaton 
additionally commented that they construct a considerable number of 
dual-voltage units, and provided data stating that 13.9 percent of 
their single-phase units and 4 percent of their three-phase units have 
non-2:1 voltage ratios. (Eaton, No. 137 at p. 15)
    Carte commented that the cost to meet proposed efficiency levels 
with a GOES transformer increases substantially for dual- and multi-
voltage transformers. (Carte, No. 140 at p. 9)
    As described in section IV.A.2.d of this document, DOE may 
establish a separate equipment class for a product 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. DOE acknowledges that 
multi-voltage capable distribution transformers may provide a unique 
utility in allowing the grid to be upgraded to higher voltages without 
requiring that a transformer be replaced. As grid modernization 
continues to occur and as consumer loading increases, this utility may 
provide a unique benefit to utilities by enabling them to utilize 
transformers to the full extent of their lifetime and avoid early 
replacements.
    However, DOE has not determined that this feature results in multi-
voltage capable transformers being significantly disadvantage in 
meeting amended standards. DOE evaluated available loss data obtained 
from publicly available utility bid data for liquid-immersed 
distribution transformers and found distribution transformers with 
multi-voltage ratings, both in integer and non-integer ratios, 
occupying the same design space as general use transformers across all 
kVA sizes. (See chapter 5 of

[[Page 29884]]

the TSD for additional detail). As pointed out by Howard, multi-voltage 
capable transformers may need to be overdesigned to meet standards at 
both the higher and lower voltage rating. While this might lead to a 
higher base cost for these transformers, available data does not 
indicate that the incremental cost to meet amended efficiency standards 
for these units would be higher. This is illustrated by the data 
provided by Eaton, which shows that multi-voltage capable distribution 
transformers are often more expensive at baseline but follow similar 
cost-efficiency curves. Eaton's data also indicated that multi-voltage 
capable distribution transformers, including those with non-integer 
ratios, can be designed to meet the same efficiencies as distribution 
transformers with single-voltage ratings up until the edge of max-tech.
    Therefore, for the reasons discussed, DOE is not creating a 
separate equipment class in this final rule for multi-voltage capable 
distribution transformers with non-integer ratios.
e. Data Center Distribution Transformers
    As noted in the January 2023 NOPR, DOE considered a separate 
equipment class for data center distribution transformers in the April 
2013 Standard Final Rule, defined as the following:
    ``i. Data center transformer means a three-phase low-voltage dry-
type distribution transformer that--
    (i) is designed for use in a data center distribution system and 
has a nameplate identifying the transformer as being for this use only;
    (ii) has a maximum peak energizing current (or inrush current) less 
than or equal to four times its rated full load current multiplied by 
the square root of 2, as measured under the following conditions--
    1. during energizing of the transformer without external devices 
attached to the transformer that can reduce inrush current;
    2. the transformer shall be energized at zero +/-3 degrees voltage 
crossing of a phase. Five consecutive energizing tests shall be 
performed with peak inrush current magnitudes of all phases recorded in 
every test. The maximum peak inrush current recorded in any test shall 
be used;
    3. the previously energized and then de-energized transformer shall 
be energized from a source having available short circuit current not 
less than 20 times the rated full load current of the winding connected 
to the source; and
    4. the source voltage shall not be less than 5 percent of the rated 
voltage of the winding energized; and
    (iii) is manufactured with at least two of the following other 
attributes:
    1. Listed as a Nationally Recognized Testing Laboratory (NRTL), 
under the Occupational Safety and Health Administration, U.S. 
Department of Labor, for a K-factor rating greater than K-4, as defined 
in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition, 
Dry-Type General Purpose and Power Transformers;
    2. temperature rise less than 130 [deg]C with class 220 \(25)\ 
insulation or temperature rise less than 110 [deg]C with class 200 
\(26)\ insulation;
    3. a secondary winding arrangement that is not delta or wye (star);
    4. copper primary and secondary windings;
    5. an electrostatic shield; or
    6. multiple outputs at the same voltage a minimum of 15[deg] apart, 
which when summed together equal the transformer's input kVA 
capacity.'' \55\
---------------------------------------------------------------------------

    \55\ 78 FR 23336, 23358.
---------------------------------------------------------------------------

    In the April 2013 Standards Final Rule, DOE did not adopt this 
definition of ``data center distribution transformers'' or establish a 
separate class for such equipment for the following reasons: (1) the 
considered definition listed several factors unrelated to efficiency; 
(2) the potential risk of circumvention of standards and that a 
transformer may be built to satisfy the data center definition without 
significant added expense; (3) operators of data centers are generally 
interested in equipment with high efficiencies because they often face 
large electricity costs, and therefore may be purchasing at or above 
the standard established and unaffected by the rule; and (4) data 
center operator can take steps to limit inrush current external to the 
data center transformer. 78 FR 23336, 23358.
    In the August 2021 Preliminary Analysis TSD, DOE stated that data 
center distribution transformers could represent a potential equipment 
class-setting factor and requested additional data about the data 
center distribution transformer market, performance characteristics, 
and any physical features that could distinguish data center 
distribution transformers from general purpose distribution 
transformers. (August 2021 Preliminary Analysis TSD at pp. 2-22) 
However, DOE did not receive any comments as to physical features that 
could distinguish a data center distribution transformer from a general 
purpose distribution transformer.
    In the January 2023 NOPR, DOE did not propose a definition for data 
center distribution transformers and did not evaluate them as a 
separate equipment class. However, DOE noted that it may consider a 
separate equipment class if provided sufficient data to demonstrate 
that data center transformers warrant a different efficiency level and 
can appropriately be defined. 88 FR 1722, 1751. Accordingly, DOE 
requested comment on its proposal not to establish a separate equipment 
class for data center distribution transformers and on any identifying 
features related to efficiency which would prevent a data center 
transformer from being used in general purpose applications. Id.
    ABB SP commented that it supports a separate equipment class for 
data center transformers with standards maintained at the current 
levels. (ABB SP, No. 110 at pp. 1-2)
    DOE noted that distribution transformers used in data centers may 
sometimes, but not necessarily, be subject to different operating 
conditions and requirements which carry greater concern surrounding 
inrush current. 88 FR 1722, 1751. DOE requested comment on the 
interaction of inrush current and data center distribution transformer 
design. Id.
    Regarding the specific challenges related to inrush current for 
data center distribution transformers, Schneider and NEMA commented 
that because of the frequent energizing of data center transformers, 
designers typically seek to limit inrush to prevent nuisance trips of 
the system. However, both Schneider and NEMA further stated that the 
concerns for data center transformers inrush current are similar to the 
concerns for all LVDTs, and while inrush is often related to 
installation and restoration after power loss, increased adoption of 
alternate power systems will mean more general purpose LVDTs will have 
concerns when power is transferred from one source to another. 
(Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 12)
    Regarding inrush current more broadly, Schneider and NEMA commented 
that the maximum inrush must be less than the over current trip value. 
(Schneider, No. 101 at pp. 6-8; NEMA, No. 141 at pp. 12-13) Schneider 
and NEMA further stated that inrush current can be limited using lower 
quality steel, modifying coil windings, and modifying core 
configurations. Id. Schneider and NEMA commented that nuisance tripping 
can be addressed by adding circuit resistance during energization of 
transformers, using electronic circuit breakers with adjustable trip 
settings, designing

[[Page 29885]]

electrical system with the maximum allowed overcurrent protective 
device; however, all these approaches would add cost. Id.
    Schneider commented that while DOE assumes equipment will be 
redesigned or modified to handle inrush, the market has not yet started 
this analysis. (Schneider, No. 101 at pp. 12-13) Schneider stated that 
the 2016 standards increased the size of the primary over current 
protection device near the limits set by the National Electric Code. 
Schneider commented that customers today can use electronic trip 
breakers or secondary breakers to address inrush concerns, but those 
solutions may not be suitable for the amended efficiency levels. Id.
    ABB SP commented that data center transformers must be designed to 
account for inrush both during startup and during operation when part 
of the electrical system fails, and power is diverted to a redundant 
component. (ABB SP, No. 110 at p. 2) ABB SP stated that, while upstream 
infrastructure could be upsized to accommodate inrush current, this 
would decrease overall data center efficiency and consume more energy. 
Id.
    APPA commented that higher inrush currents may require a change of 
protective equipment, such as relays, at a higher cost. (APPA, No. 103 
at p. 13) APPA further stated that there is insufficient data on how to 
size protective devices for higher inrush, which will lead to 
transformer failure or excessive device tripping. Id. APPA stated that, 
in either scenario, excess fuse tripping will lead to millions of 
dollars of additional costs. Id. As such, APPA commented that DOE 
should publish protection standards and short circuit information prior 
to any changes and give a 4-year lead tie for industry to gain 
experience with amorphous transformers. Id.
    Eaton commented that general use LVDT transformers can be designed 
to generate inrush currents up to 25x rated current, but data center 
transformers cannot exceed 8x rated current to avoid potential power 
outages. (Eaton, No. 137 at p. 34) Eaton further commented that 
traditional inrush current limiting schemes, such as impedance 
insertion, are not viable for data center transformers because they 
starve the critical load of rated operating voltage. Id. Eaton stated 
that mitigating inrush current by controlling transformer energization 
is also not feasible for data center transformers because the required 
equipment would delay energization. Id.
    Prolec GE commented that the inrush current limit is 25x rated 
current for both data center transformers and general-use transformers 
as defined in IEEE standard C37.48.1. (Prolec GE, No. 120 at p. 7) 
Prolec GE commented that peak inrush current is determined by the air 
core inductance \56\ and not the core steel. Id. Prolec GE also stated 
that technologies to mitigate inrush current have high complexity, low 
reliability, and high costs. Id. Prolec GE also stated that the 
relationship between operational flux density and remanence \57\ 
matters more with regard to inrush current than the absolute magnitude 
of remanence. Id.
---------------------------------------------------------------------------

    \56\ The air core inductance of transformer represents the 
properties of the winding if there were no core to induce (i.e., 
using an ``air core''). Peak inrush can be approximated based on the 
air core inductance because when a transformer is pushed into 
saturation conditions, which is when maximum inrush would occur, the 
instantaneous induction of the core is very low, allowing it to be 
modelled as an air core.
    \57\ Operational flux density represents the max flux density at 
which a transformer is designed to operate, whereas remanence 
represents the magnitude of flux density that remains in a core 
after being de-energized. Both the remanence and the operational 
flux density must be considered when designing a transformer such 
that the core will not be pushed above its saturation flux density 
during normal operation, which can lead to very high inrush current 
and potentially damage the transformer or downstream equipment.
---------------------------------------------------------------------------

    Stakeholder comments suggest that inrush current concerns may be of 
particular importance for data center distribution transformers, due to 
the sensitive nature of the equipment placed downstream of the 
transformer. Stakeholder comment also suggest that increased efficiency 
standards can increase the likelihood of inrush conditions exceeding 
the limitations of standard protective equipment, depending on how the 
flux density and construction of the core are modified to increase 
transformer efficiency.
    However, increased inrush current is not guaranteed to occur 
because of increasing transformer efficiency and is partially within 
the control of the transformer designer. For example, designing a 
transformer with a lower flux density decreases the likelihood and 
magnitude of inrush current occurrences. Stakeholder feedback indicates 
that technologies exist to limit and protect against inrush current in 
situations when the transformer design cannot be modified to do so. 
Therefore, DOE does not consider inrush current to be an inhibiting 
factor which would prevent transformer manufacturers from meeting 
amended efficiency standards.
    In the January 2023 NOPR, DOE also requested comment on the 
specific challenges that might arise with designing data center 
distribution transformers with cores made of amorphous cores. 88 FR 
1722, 1751.
    Metglas commented that it is not aware of any technical issues to 
prevent the use of amorphous transformer cores in data center 
applications. (Metglas, No. 125 at p. 5) Metglas commented that inrush 
current varies based on impedance for amorphous transformers and is not 
20 percent different than for a GOES unit at the same impedance. 
(Metglas, No. 125 at p. 5)
    Howard commented that it is unaware of any challenges with data 
center transformers and is not aware of amorphous core transformers 
being built for the data center market. (Howard, No. 116 at p. 13)
    Schneider, Eaton, and NEMA stated that the inherent air gaps, high 
saturation flux density, and lower remnant flux density of stacked core 
construction cores helps limit inrush currents, but would no longer be 
viable under the proposed standards since amorphous can only be used in 
wound cores. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11; Eaton, 
No. 137 at p. 37) Eaton commented that using amorphous in data center 
transformers in PDUs will require significant research and development 
because each of these units has specific requirements and cannot be 
standardized. (Eaton, No. 137 at p. 3)
    Eaton commented that, due to the increased remnant flux and reduced 
saturation flux density, a data center transformer designed with an 
amorphous core would need to operate at about 9 to 12.6 kG to keep 
inrush current within the 4-8X limit. (Eaton, No. 137 at p. 35) Eaton 
stated that inrush current may be reduced for wound core amorphous 
transformers by increasing the winding turns to increase air core 
inductance, but this also increases load losses, impedance, winding 
temperature rise, and cost. Id. ABB SP further commented that the lower 
flux density of amorphous cores would require manufacturers of data 
center transformers to choose between higher inrush currents during 
emergency power transfers, longer transfer times, or significantly 
larger core and coil size. (ABB SP, No. 110 at p. 2)
    DOE received several comments stating that higher efficiency units, 
and specifically amorphous core transformers, are less efficient at 
higher loading than conventional GOES transformers. For dry-type units, 
Eaton commented that PDU transformers designed to meet DOE standards at 
35 percent loading are less efficient during typical operation at 60-
80-percent load and this problem will be exacerbated by amorphous. 
(Eaton, No. 137 at p. 37) NEMA and Schneider commented that

[[Page 29886]]

amorphous cores have not been used in data center applications and 
would not maximize savings because average loading is typically 65-80 
percent. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11)
    Powersmiths commented that the proposed efficiency standards at 35 
percent loading will significantly increase losses in high load 
applications, such as data centers. (Powersmiths, No. 112 at p. 5) 
Accordingly, Powersmiths recommended that DOE consider a provision to 
accommodate high transformer load applications, such as exemptions for 
specific use cases or different requirements at a higher load point. 
Id.
    Regarding stakeholder comment that data center distribution 
transformers transformer loading may be higher than general purpose 
transformers, DOE agrees that operating conditions with higher loading 
applications benefit less from reduced no-load losses. However, DOE 
disagrees that amorphous cores inherently are less efficient at higher 
loading. As discussed in section IV.C.1, amorphous transformers are not 
inherently designed with higher load losses. The reduced no-load losses 
for amorphous transformers provide additional design flexibility in 
meeting efficiency standards, often resulting in higher load losses to 
reduce costs in a minimally compliant amorphous transformer. However, 
amorphous transformers can be designed to target lower load losses, 
just as GOES transformers can. Further, DOE's modeling includes a 
variety of designs at higher efficiency levels, some with higher load 
losses and some with lower load losses. Hence, manufacturers have the 
capability to redesign transformers to meet higher efficiency standards 
either by reducing the no-load losses, reducing the load losses, or 
reducing some combination of the two.
    DOE received additional comments that amorphous-core transformers 
in data center applications would be larger, which could create 
additional challenges.
    For liquid-immersed units, Eaton stated that most of its data 
center transformers are in the size range of 2,500 to 3,500 kVA, which 
is outside the current range of transformer sizes that Eaton designs 
with amorphous cores. (Eaton, No. 137 at p. 21) Eaton also commented 
that the larger size of wound core amorphous transformers will increase 
the size of PDUs and go against Data Centers Industry efficiency goals 
for high power density per unit area. (Eaton, No. 137 at pp. 37-38) 
Eaton further stated that wound core designs may have difficulty 
meeting specific PDU requirements due to reduced design flexibility and 
greater likelihood of DC and/or subharmonic voltages issues resulting 
from the lack of air gaps. (Eaton, No. 137 at p. 38)
    ABB SP commented that the increased volume of data center 
transformers designed with amorphous cores would increase load losses, 
strain the elevated floor systems common for PDU's, and remove the 
ability to replace transformers at the end of life due to other 
necessary changes to accommodate the increased volume. (ABB SP, No. 110 
at p. 2)
    As indicated by stakeholders, amorphous metal is not commonly 
utilized in the U.S. data center distribution transformer market today, 
resulting in limited data from manufacturers available to assess the 
performance of amorphous units in data center applications. Stakeholder 
comments identified challenges with using amorphous core transformers 
related to transformer inrush and transformer size. Stakeholder comment 
suggests that those challenges could be overcome, such as reducing an 
amorphous cores flux density or modifying protective equipment. 
However, these changes may have additional costs. Further, many of 
those challenges identified for data center transformers were noted as 
existing for all LVDTs, not something necessarily unique to data center 
transformers.
    In DOE's review of the international market DOE observed several 
manufacturers marketing dry-type transformers with an amorphous metal 
core.58 59 60 61 DOE also observed marketing of amorphous 
core transformers being used in data centers.62 63 The 
existence of amorphous metal cores in dry-type distribution 
transformers, and particularly in LVDT distribution transformers, 
demonstrates the technological feasibility of converting to amorphous. 
While stakeholders indicated that data center distribution transformer 
may be subject to additional design constraints, commenters did not 
provide data to demonstrate how these design constraints may be 
impacted when using amorphous metal or specifics as to what these 
additional costs would be and when they come into effect (e.g. only 
beyond certain kVA sizes, only in certain applications, etc.). As such, 
DOE has concluded that there is insufficient data to warrant a separate 
equipment class for data center transformers.
---------------------------------------------------------------------------

    \58\ Toyo Electric, Dry-Type Amorphous Core Transformer. 
Available at: www.toyo-elec.co.jp/products/download/catalog/transform/Amorphous_EN.pdf (last accessed Nov. 7, 2023).
    \59\ Jiangsu Ryan Electric Company, SCBH15, SGBH15, SCBH16, 
SGBH16 amorphous alloy dry-type transformer. Available at 
en.redq.cc/SCBH15-SGBH15-SCBH16-SGBH16-amorphous-alloy-dry-type-
transformer-pd49182496.html (last accessed Nov. 7, 2023).
    \60\ Yuebian Electric, Amorphous Alloy Dry Type Transformer. 
Available at www.zjyb-electric.com/products/amorphous-alloy-dry-type-transformer.html (last accessed Nov. 7, 2023).
    \61\ China Electric Equipment Group, Amorphous Alloy Dry Type 
Transformer Three Phase Power Transformer Factory. Available at 
ceegtransformer.com/products/amorphous-alloy-dry-type-transformer-three-phase-power-transformer-factory (last accessed Nov. 7, 2023).
    \62\ CEEG, 42 Units of CEEG Amorphous Alloy Transformers For 
Data Center were Successfully Energized. Available at 
www.cnceeg.com/news/42-units-of-ceeg-amorphous-alloy-transformers-48777661.html (last accessed Nov. 7, 2023).
    \63\ Qingdao Yunlu Advanced Materials Technology Co. Ltd. 
Introduction to Amorphous Alloy Core. Available at www.yunluamt.com/product-44-1.html (last accessed Nov. 7, 2023).
---------------------------------------------------------------------------

    Stakeholders also commented as to what physical features of data 
center transformers could be identified to define data center 
transformers as an equipment class separate from other general purpose 
distribution transformers.
    ABB SP commented that data center transformers are primarily 
distinguished from general purpose LVDT transformers by their 
application, with most data center transformers used in PDU's. Id. ABB 
SP stated that transformers used in PDUs must be designed to 
accommodate specific system requirements, including power quality 
requirements, exposure to harmonic sources, continuous loading at 50-90 
percent, and the ability to supply a diverse variety of power sources 
without going into saturation or changing tap connections. Id. ABB SP 
also commented that since 2013, data center transformers have become 
larger, begun using elevated secondary voltage ratings, are designed 
with greater protections for arc flash and fault current, and are 
designed at higher ambient temperature. Id.
    Eaton recommended that DOE specifically exempt low-voltage 
transformers used in PDUs for data centers. (Eaton, No. 137 at p. 2) 
Eaton commented that data center transformers are not sold as 
standalone equipment but rather as part of power distribution units 
(PDUs). (Eaton, No. 137 at p. 34) Eaton further commented that data 
center transformers have specific design requirements which distinguish 
them from general-purpose units, including (1) an inrush current rating 
of 8x or lower, (2) a higher k-factor to accommodate non-linear loads, 
(3) a requirement for two electrostatic

[[Page 29887]]

shields connected to the ground,\64\ (4) increased insulation inside 
the winding and increased clearances from the winding to ground to 
improve reliability, (5) and an occasional requirement for a lower 
temperature rise, which is becoming increasingly common in data center 
design. (Eaton, No. 137 at pp. 34-36) Eaton also commented that wide 
range of impedance requirements can make it difficult to design PDU 
transformers which both comply with DOE standards and meet k-factor 
specifications. (Eaton, No. 137 at p. 36) Eaton additionally commented 
that data center transformers must be operated using low flux and 
current densities to meet standards, which is an inefficient use of 
resources. (Eaton, No. 137 at p. 36)
---------------------------------------------------------------------------

    \64\ Eaton commented that this is a unique requirement for all 
PDU transformers (Eaton No. 137 at p. 36)
---------------------------------------------------------------------------

    Schneider commented that a separate equipment class is not required 
for data center transformers as it opens the door to many other 
industry segments requesting exclusions. (Schneider, No. 92 at pp. 4-5) 
Schneider commented that there are attributes for data center 
transformers that may make it more difficult to comply with energy 
conservation standards; however, these difficulties may be reduced with 
higher efficiency levels. Id. Schneider gave the example of K-ratings 
not being necessary for higher efficiency transformers because the 
thermal characteristics are no longer the limiting factor of kVA. Id. 
Schneider further commented that many of the concerns seen by the data 
center market would exist for all applications. Id. Schneider commented 
that the only way to prevent data center transformers from being used 
in general purpose applications would be to limit the secondary voltage 
to certain values. Id. Schneider also stated that requiring a secondary 
winding arrangement that is not delta or wye, as proposed in the April 
2013 Standards Final Rule, relates to efficiency in that the efficiency 
of a transformer with a zig-zag secondary is less impacted under 
harmonic loading. Id.
    Howard commented that no guidelines are needed to prevent data 
center transformers from being used in general purpose applications. 
(Howard, No. 116 at p. 13) Metglas commented that there does not seem 
to be a technical distinction between a data center transformer and a 
standard transformer. (Metglas, No. 125 at p. 5)
    DOE recognizes that distribution transformers used in data center 
applications may be subject to unique requirements separate from those 
used in general-purpose applications, such as specific size constraints 
or a need for a higher k-factor. However, when establishing separate 
equipment classes for product groups, DOE is required to focus on 
capacity and performance related features that impact consumer utility. 
As indicated by stakeholders, the primary distinguisher between data 
center distribution transformers and general-purpose distribution 
transformers is their installation location, not the capacity or 
features of the transformer itself.
    Further, in its review of manufacturer literature, DOE observed 
multiple manufacturers advertising general use transformers 
specifically designed with higher k-factor ratings, low inrush current, 
and/or electrostatic shields, all of which are design features 
suggested by commenters as being characteristic of data center 
transformers. As stated by Schneider, a number of applications, such as 
LVDT transformers used in hospital units, may require similar design 
requirements to those specified for data center transformers.
    While some commenters provided specific features attributable to 
data center transformers, DOE notes that the majority of these features 
are not unique to data center distribution transformers. For example, 
several stakeholders indicated that data center distribution 
transformers must be designed with a higher k-factor to accommodate 
harmonic loading. In support of this claim, Eaton provided data 
comparing size and efficiency of DOE's modeling to k-factor rated 
transformers. However, Eaton's data did not demonstrate how an 
amorphous data center transformer would perform in this comparison. As 
stated by Schneider, the increased efficiency and reduced losses of an 
amorphous transformer would reduce the excess heat dissipation in a 
transformer, potentially reducing the need for higher k-factors.
    In this final rule, DOE is not establishing a separate equipment 
class for data center distribution transformers. Based on the feedback 
received, DOE maintains that there are not sufficient physical features 
to differentiate data center distribution transformers from general-
purpose distribution transformers. DOE does not have sufficient data to 
indicate that the characteristics that often distinguish a distribution 
transformer used in data center applications from one used in general 
purpose applications, such as a higher k-factor, would inhibit these 
units from being designed to meet an amended efficiency standard. 
Therefore, for the reasons discussed, DOE is not establishing a 
separate equipment class for data center transformers in this final 
rule.
    While stakeholders did identify legitimate challenges associated 
with data center transformers, most stakeholders noted that they could 
be overcome. However, there is uncertainty as to the downstream impacts 
on protective equipment and transformer sizes, along with uncertainty 
of the costs associated with overcoming those challenges. For example, 
in circumstances when inrush current may become a concern for data 
center applications, additional measures may be taken to mitigate 
inrush conditions, both regarding the design of the transformer and the 
external technologies that could be applied. However, the degree of 
difficulty associated with each of these challenges is largely 
dependent on the compliance period with which stakeholders must meet 
amended efficiency standards and the degree of efficiency improvement 
of any proposed standards. DOE notes that the compliance period in this 
final rule is longer than the proposed in the NOPR and efficiency 
levels for LVDT units is lower than was proposed in the NOPR, 
indicating that manufacturers will have both more time and more design 
flexibility to overcome the challenges identified in response to the 
NOPR. DOE further notes that its adopted energy efficiency standards 
are achievable using many designs with continued usage of stacked core 
GOES designs, wherein manufacturers have considerable experience in 
designing data center transformers.
f. BIL Rating
    Distribution transformers are built to carry different basic 
impulse insulation level (BIL) ratings. BIL ratings offer increased 
resistance to large voltage transients, for example, from lightning 
strikes. Due to the additional winding clearances required to achieve a 
higher BIL rating, high BIL distribution transformers tend to be less 
efficient, leading to higher costs and potentially more difficulty in 
achieving higher efficiencies. DOE currently separates medium-voltage 
dry-type distribution transformers into equipment classes based on BIL 
ratings, with classes for transforms with BIL ratings ranging from 20-
45 kV, 46-95 kV, and above 96 kV. 10 CFR 431.196(c).
    In the January 2023 NOPR, DOE discussed stakeholder comments which 
indicated that transformers with high BIL designs (>=150 BIL or >=200 
BIL) may experience higher losses that could inhibit them from meeting 
amended efficiency standards. 88 FR 1722, 1752.

[[Page 29888]]

However, because no stakeholders provided data to indicate the degree 
to which transformers with high BIL ratings may be disadvantaged and 
because separating liquid-immersed transformers by BIL rating would add 
additional complications for potentially minor differences in losses, 
DOE did not propose separate equipment class based on BIL rating for 
liquid-immersed units.
    In response to the January 2023 NOPR, DOE received several 
additional comments pertaining to BIL ratings for liquid-immersed 
distribution transformers.
    Eaton commented that smaller kVA units with higher-voltage primary 
ratings, and corresponding higher BIL ratings, are more expensive to 
build; however, Eaton went on to state that these units are generally 
outside of the scope of what is commonly manufactured by Eaton. (Eaton, 
No. 137 at p. 21) Eaton added that the max-tech efficiency of a 500 kVA 
unit was similar for either a lower or higher BIL rating. (Eaton, No. 
137 at p. 21)
    Prolec GE commented that higher BIL designs have increased core and 
coil dimensions to account for the additional insulation needed, 
increasing the transformer losses. (Prolec GE, No. 120 at p. 8) Howard 
commented that each BIL increase results in a 0.02-0.07 percentage 
point drop in efficiency. (Howard, No. 116 at p. 13)
    Carte commented that the increase in cost to meet the same 
efficiency for 200 kV BIL designs is the following: (1) a 20 percent 
increase relative to DOE's modeled 500 kVA, single-phase, 150 kV BIL 
design; (2) a 5 percent increase relative to DOE's modeled 150 kVA, 
three-phase, 95 kV BIL design; and (3) 16 percent increase relative to 
DOE's modeled 1,500 kVA, three-phase, 125 kV BIL design. (Carte, No. 
140 at pp. 8-9)
    To assess whether liquid-immersed units with high BIL ratings 
warranted being regulated under a separate equipment class, DOE 
evaluated publicly available utility bid data to investigate the 
performance of otherwise equivalent transformers with different BIL 
ratings. Based on this review, DOE observed designs with high BIL 
ratings (>=150 BIL) meeting higher efficiencies at a variety of kVA 
sizes. As stated by several stakeholders, units with higher BIL ratings 
may have a higher cost associated with them due to the added insulation 
and increased overall size of the unit. While the baseline cost for a 
high BIL unit may be greater than that for a lower BIL rating, DOE data 
indicates that the incremental cost to meet the amended efficiency 
standards would be similar for a transformer with a high BIL rating as 
opposed to one with a lower BIL rating. As such, DOE does not expect 
the consumers to lose access to the utility associated with high BIL 
designs absent designation in a new separate class.
    Further, DOE notes that the cost increases and efficiency decreases 
referenced by stakeholders most likely assume that higher efficiencies 
are being achieved using a GOES core. DOE notes that its analysis shows 
that max-tech efficiency designs are able to reduce losses by 
considerably more than both the proposed standards for liquid-immersed 
distribution transformers and the adopted standards. While it may be 
considerably more expensive to have higher BIL designs with a GOES core 
at high-efficiency levels, manufacturers also have the option of using 
an amorphous core, which has a relatively flat cost-efficiency curve 
across significantly higher-efficiency levels.
    Therefore, for the reasons discussed, DOE is not creating a 
separate equipment class based on BIL rating for liquid-immersed units 
in this final rule.
g. Other
    DOE received additional comments discussing other potential 
equipment classes but generally did not receive any data regarding what 
technical features associated with these products warrant a separate 
equipment class.
    NEMA commented that DOE should consider not including shovel 
transformers, above ground mining transformers, crane duty 
transformers, and marine application transformers. (NEMA, No. 141 at p. 
13)
    DOE notes that NEMA did not include any data or comment regarding 
the specific technical challenges this equipment would have in meeting 
efficiency standards or even suggest that these challenges exist. NEMA 
also did not provide comment regarding the physical features that would 
allow this equipment to be defined as compared to other general purpose 
distribution transformers. Therefore, DOE has not considered separate 
equipment classes for this equipment.
    DOE received comment regarding triplex core transformers, which 
include three, single-phase core-coil assemblies grouped together to 
form a three-phase transformer. WEC commented that it commonly uses a 
triplex core design to prevent ferro resonance, which requires more 
pounds of core steel per kVA and could mean amended efficiency 
standards result in higher incremental costs. (WEC, No. 118 at p. 2) 
WEC commented that further increases in efficiency requirements could 
lead to the elimination of triplex core transformers, which would 
present additional operational and safety challenges to WEC employees 
and significantly extend outages to customers. Id. Howard supported 
creating a different equipment class for 3-phase pole mounted 
transformers because of their unique triplex design. (Howard, No. 116 
at pp. 25-26) Howard additionally supported dividing pole and pad 
mounted transformers into separate equipment classes as utilities can 
more easily accommodate larger pad-mounted transformers. Id.
    While triplex core transformers have more core steel per kVA than a 
traditional three-phase transformer, DOE did not receive any data as to 
the degree of difference. DOE notes that lower-loss core steel 
technology options would be expected to improve the performance of both 
traditional three-phase transformers and triplex core transformers. 
DOE's max-tech efficiency levels are typically met with amorphous 
cores, which would have lower no-load losses for both traditional 
three-phase transformer cores and triplex core transformers. Further, 
as WEC noted, triplex core transformers can be used in the exact same 
applications as three-phase pad-mounted transformers. For these 
reasons, DOE has not considered a separate equipment class for triplex 
core transformers. To the extent pole and pad-mounted transformers may 
have different installation challenges, those costs are accounted for 
in the installation costs, discussed in section IV.F.4 of this 
document.
    Standards Michigan recommended DOE remove obstacles to 
manufacturers who choose to produce inexpensive, mobile transformers 
designed for the purpose of preventing civil unrest during major 
regional contingencies. Standards Michigan went on to state that these 
MRC transformers could be placed in a new product class. (Standards 
Michigan, No. 109 at pp. 1-2)
    Utilities tend to keep distribution transformer reserves available 
for emergency situations, such as during a natural disaster or other 
storm. DOE notes that it develops separate equipment classes based on 
specific class-setting factors as set forth by EPCA, as described in 
section IV.A.2. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(1)). Standards 
Michigan did not identify any specific features associated with 
contingency transformers. Therefore, DOE has not established a separate 
equipment class for these contingency transformers.

[[Page 29889]]

3. Technology Options
    In the preliminary market analysis and technology assessment, DOE 
identified several technology options initially determined to improve 
the efficiency of distribution transformers, as measured by the DOE 
test procedure.
    Increases in distribution transformer efficiency are based on a 
reduction of distribution transformer losses. There are two primary 
varieties of loss in distribution transformers: no-load losses and load 
losses. No-load losses are roughly constant with PUL and exist whenever 
the distribution transformer is energized (i.e., connected to 
electrical power). Load losses, by contrast, are zero at zero percent 
PUL but grow quadratically with PUL.
    No-load losses occur primarily in the transformer core, and for 
that reason the terms ``no-load loss'' and ``core loss'' are sometimes 
interchanged. Analogously, ``winding loss'' or ``coil loss'' is 
sometimes used in place of ``load loss'' because load loss arises 
chiefly in the windings. For consistency and clarity, DOE will use 
``no-load loss'' and ``load loss'' generally and reserve ``core loss'' 
and ``coil loss'' for when those quantities expressly are meant.
    Distribution transformer design is typically an optimization 
process. For a given core and conductor material, the mass and 
dimensions of the transformer core, winding material, insulation, 
radiators, transformer tank, etc., can be varied to minimize costs 
while meeting a variety of design criteria. Within a manufacturer's 
optimization process, transformers can be designed to be minimally 
efficient or, if customers place a dollar value on electrical loss, can 
be designed to minimize the transformers total owning costs. Typically, 
small improvements in efficiency can be met with modest increase in 
material quantities; however, at some point, achieving any further 
increases in efficiency can substantially increases costs (i.e., 
hitting the ``efficiency wall'' where costs rise dramatically for small 
increases in efficiency).
    Once manufacturers have reached the ``efficiency wall'' for a given 
core and conductor material, the only realistic option for meeting 
higher efficiency values is to transition to core materials with lower 
no-load losses and/or transition from aluminum to copper winding 
material. The relative costs and availability of these lower-loss core 
materials has varied over time and is discussed in detail in section 
IV.A.4 of this document.
    With respect to analyzed inputs, in the engineering analysis, DOE 
considered various combinations of the following technology options to 
improve efficiency: (1) Higher grade electrical core steels, (2) 
different conductor types and materials, and (3) adjustments to core 
and coil configuration.
4. Transformer Core Material Technology and Market Assessment
    Distribution transformer cores are constructed from a specialty 
kind of steel known as electrical steel. Electrical steel is an iron 
alloy which incorporates small percentages of silicon to enhance its 
magnetic properties, including increasing its magnetic permeability and 
reducing the iron losses associated with magnetizing that steel. 
Electrical steel is produced in thin laminations and either wound or 
stacked into a distribution transformer core shape.
    Electrical steel used in distribution transformer applications can 
broadly be categorized as either amorphous alloy or GOES. There are 
different subcategories of material performance within both amorphous 
alloy and grain-oriented electrical steel. In the January 2023 NOPR, 
DOE carried over the same naming convention developed in the August 
2021 Preliminary Analysis TSD to identify the various permutations of 
electrical steel. 88 FR 1722, 1754.
    DOE notes that producing distribution transformer cores with 
amorphous alloy requires different core production machinery than 
producing distribution transformer cores with GOES. As such, some 
amount of investment in machinery is required to transition between 
producing cores with amorphous alloy and GOES. Today, there are many 
equipment classes and kVA sizes where amorphous core transformers 
compete with GOES transformers on first cost. However, the vast 
majority of current core production equipment is set-up to produce GOES 
cores, and therefore the vast majority of transformer shipments use 
GOES cores even for products where using an amorphous core would lead 
to a lower first-cost to the consumer.
    In meeting efficiency standards with GOES, DOE notes that using 
lower-loss GOES steel allows manufacturers to achieve modest 
improvements in efficiency with essentially identical designs (e.g., 
essentially no increase in product weight, just a direct swap of 
higher-loss core steel with lower-loss core steel). However, there is a 
limited capacity of lower-loss GOES grades and only a single domestic 
manufacturer of GOES steel, which limits the availability of GOES 
products to distribution transformer manufacturers.
    In achieving higher efficiencies without changing GOES steel 
performance, Eaton commented that manufacturers increase the core cross 
sectional area and decrease the flux density. (Eaton, No. 137 at pp. 
21-22) The larger transformer cores require thicker conductors in order 
to maintain current density but using thicker conductors increases 
stray and eddy losses, which requires even larger conductor size to 
combat the additional stray and eddy losses. (Eaton, No. 137 at pp. 21-
22) Eaton stated that at some point, the only option is to transition 
to copper windings, at which point the cost of the transformer 
skyrockets and significant cost increases are needed for even modest 
efficiency gains. (Eaton, No. 137 at pp. 21-22)
    In other words, achieving higher efficiencies without reducing the 
losses of the core steel material is technically possible but gets 
increasingly difficult (in terms of significant increases in product 
weights and selling prices) as manufacturers attempt to reduce losses 
further.
    If lower-loss GOES were widely available, distribution transformer 
manufacturers could achieve modest improvements in efficiency with 
essentially identical designs (e.g., essentially no increase in product 
weight, just a direct swap of higher-loss core steel with lower-loss 
core steel). However, as with higher-loss GOES, beyond a certain point 
reducing losses further is technically possible but results in 
substantial increases in product weight and selling price.
    In the current market, distribution transformer manufacturers limit 
themselves to the single domestic GOES manufacturer's product offerings 
and pricing, as any imported GOES steel is subject to a tariff that 
makes such steel uncompetitive. Therefore, increasing the domestic 
availability of lower-loss GOES steel depends on the investments in 
product quality made by the single domestic GOES manufacturer.
    Amorphous cores reduce transformer no-load losses by approximately 
50 to 70 percent relative to GOES (see Chapter 5 of the TSD for 
relative performance of amorphous- and GOES-based designs). This 
substantial reduction in no-load losses means that much higher 
efficiency standards can be achieved with amorphous cores (DOE's max-
tech efficiency assumes use of an amorphous core) and there is more 
flexibility in designing transformers to meet efficiency standards (in 
terms of the weight and dimensions of the cores, amount of winding 
material, etc.).
    However, the different production equipment associated with 
producing

[[Page 29890]]

amorphous cores means that distribution transformer manufacturers must 
decide how to meet potential amended efficiency standards. If using 
amorphous cores, manufacturers would need to make substantial 
investments in amorphous core production equipment. In exchange, they 
would likely be able to sell many transformer ratings at a lower first 
cost and win business in doing so. Alternatively, manufacturers could 
continue to use existing GOES production equipment, however, they would 
likely be selling a transformer at a higher first cost.
    For modest reductions in transformer losses (generally through EL2 
for liquid-immersed distribution transformers and EL 3 for dry-type 
distribution transformers), the difference in first cost is not 
substantial enough to warrant the considerable investment in amorphous 
core production that is needed to meet efficiency standards. However, 
between EL2 and EL4 for liquid-immersed distribution transformers and 
EL3 and EL5 for dry-type distribution transformers, the size and weight 
increase associated with GOES cores become substantial and it generally 
becomes economically infeasible to continue producing GOES transformers 
unless consumers ignore product cost (e.g., if shortages have forced 
consumers to purchase any transformer they can access, regardless of 
product costs).
    DOE notes that in this final rule, it evaluated an additional TSL 
for liquid-immersed distribution transformers (TSL 3) that is a 
combination of proposed ELs, wherein some equipment classes are set at 
EL2 and other equipment classes are set at EL4. DOE notes that the ELs 
used in the final rule correspond to an identical reduction in losses 
as the ELs used in the January 2023 NOPR. However, the grouping of 
these ELs by equipment class has been modified in response to 
stakeholder feedback. In consideration of this feedback, for this final 
rule DOE regrouped the ELs that comprise TSL 3 such that EC1A and EC2A 
were evaluated at EL4, which is expected to predominantly be met via 
use of amorphous cores, while EC1B and EC2B were evaluated at EL2, 
which can be met via use of either GOES or amorphous cores. The new TSL 
3 is intended to reflect stakeholder concerns that standards requiring 
substantial amorphous core production are not economically justified. 
As explained further below, TSL 3, which DOE is adopting in this final 
rule, is economically justified, technologically, feasible and 
maximizes energy savings without requiring an entire market transition 
to amorphous cores.
    Under the adopted standard, the kVA ranges that will be required to 
meet EL4 represent only a portion of the overall distribution 
transformer market, and the volumes of amorphous steel required to 
supply this segment of the market is similar to the existing domestic 
amorphous ribbon production. As such, the adopted standard ensures that 
even absent significant growth in amorphous ribbon production, capacity 
in that market will be sufficient to meet demand in the transformer 
market. Further, the kVA ranges that have to meet EL2 approximately 
correspond with the existing domestic GOES production that serves the 
distribution transformer market. Accordingly, DOE has determined that 
this TSL ensures that manufacturers will not have to scrap existing 
production equipment. Rather, manufacturers of distribution 
transformers, amorphous ribbon, and GOES steel can all focus on and 
invest in increased production.
    The various markets, technologies, and naming conventions for 
amorphous and GOES are discussed in the following sections, along with 
a discussion as to the expected variables manufacturers would consider 
in deciding how to meet amended efficiency standards.
a. Amorphous Alloy Market and Technology
    Amorphous alloy \65\ is a variety of core material that is produced 
by rapidly cooling molten alloy such that crystals do not form. The 
resulting product is thinner than GOES and has lower core losses, but 
it reaches magnetic saturation at a lower flux density.
---------------------------------------------------------------------------

    \65\ Throughout this rulemaking, amorphous alloy is referred to 
by stakeholders using various terms including ``amorphous'', 
``amorphous alloy'', ``amorphous material'', and ``amorphous 
steel''. Each of these terms generally refers to amorphous ribbon 
which is then formed into an ``amorphous core'' that is used in the 
transformer.
---------------------------------------------------------------------------

    DOE has identified three subcategories of amorphous alloy as 
possible technology options. These technology options and their DOE 
naming shorthand are shown in Table IV.4.
[GRAPHIC] [TIFF OMITTED] TR22AP24.531

    In the January 2023 NOPR, DOE discussed that it did not include any 
designs which utilized high-permeability amorphous because, although 
there are some design flexibility advantages to using high-permeability 
amorphous, it is only available from a single supplier. 87 FR 1722, 
1754. DOE further noted that, in interviews, manufacturers had 
expressed a hesitance to rely on a single supplier of amorphous for any 
higher volume unit. Id. However, DOE also stated that hibam material 
can generally be used in place of standard am designs, though some 
specific applications may require redesigning. This assumption was 
supported by stakeholder comments in response to the August 2021 
Preliminary Analysis TSD, as discussed in the January 2023 NOPR. 87 FR 
1722, 1754-1755. Therefore, it is appropriate to include only standard 
am designs in the engineering analysis to avoid setting efficiency 
standards based on a steel variety, hibam, that is only available from 
a single supplier. Under this approach, manufacturers have the option 
to achieve efficiency levels that require am steel using either the 
standard am material or the hibam material depending on their sourcing 
practices and preferences. Id.
    In the January 2023 NOPR, DOE also discussed the existence of a 
hibam material that uses domain refinement (``hibam-dr'') to further 
reduce core losses. 87 FR 1722, 1755. DOE stated that it had learned 
through interviews

[[Page 29891]]

that the hibam-dr product is not yet widely commercially available. As 
such, DOE did not include the hibam-dr product in its analysis because 
DOE could not verify that the core loss reduction of this product is 
maintained throughout the core production process and because it is 
only produced by one supplier. Id.
    DOE notes that, since the publication of the January 2023 NOPR, it 
has identified additional amorphous suppliers who may offer high 
permeability grades, or potentially even high permeability domain 
refined grades.66 67 However, total capacity for these 
steels remains uncertain, potentially limiting their availability for 
use in the domestic distribution transformer market. Further, it is 
uncertain what the performance of amorphous ribbon would be from 
manufacturers with the technological know-how to produce amorphous 
68 69 but who do not currently produce wide-cast amorphous 
ribbon and may enter the market if demand for amorphous were to 
increase. Therefore, to allow greater design flexibility for 
manufacturers attempting to meet any amended standards, DOE has 
continued to exclude designs in the engineering analysis that use 
higher grades of amorphous.
---------------------------------------------------------------------------

    \66\ Qingdao Yunlu Advanced Materials Technology, Amorphous 
Ribbon Alloy. Available at www.yunluamt.com/product-50-1.html (last 
accessed Nov. 8, 2023).
    \67\ Qingdao Yunlu Advanced Materials Technology, Amorphous 
alloy strip, precursor thereof, preparation method of amorphous 
alloy strip, amorphous alloy iron core and transformer. China Patent 
No. CN116162870A. May 26, 2023.
    \68\ See Guidebook for POSCO's Amorphous Metal. Available at 
Docket No. EERE-2010-BT-STD-0048-0235.
    \69\ Vacuumschmelze GmbH and Co KG, Amorphous metal foil and 
method for producing an amorphous metal foil using a rapid 
solidification technology, U.S. Patent No. 11,623,271. Jun. 29, 
2023.
---------------------------------------------------------------------------

Amorphous Technological Feasibility
    In response to the January 2023 NOPR, DOE received additional 
comments regarding the performance of amorphous cores.
    Powersmiths stated a concern that amorphous core transformers may 
exhibit certain performance defects when compared to GOES, including 
shards breaking off from the core, which may lead to premature failures 
and higher audible noise, making it more difficult or impossible to 
achieve NEMA ST-20 audible noise levels. (Powersmiths, No. 112 at pp. 
2-3) Powersmiths additionally commented that there are many technical 
challenges with using amorphous cores, including non-homogenous flux 
distributions for wound cores, incompatibility with the cruciform 
structures required for larger kVA transformers, and greater difficulty 
in meeting standards for lower temperature units. Accordingly, 
Powersmiths commented that a wholesale conversion to amorphous material 
does not make sense given the limitations of the technology. 
(Powersmiths, No. 112 at p. 6)
    Schneider commented that more research is needed into the inrush 
current, sound levels, and reduced impedance of amorphous. (Schneider, 
No. 101 at p. 2) Carte commented that amorphous transformers are louder 
than GOES transformers and questioned what the impacts of amorphous 
transformers would be on noise-sensitive areas. (Carte, No. 140 at p. 
5) HVOLT commented that amorphous transformers create more audible 
noise. (HVOLT, No. 134 at p. 5) APPA commented that amorphous 
transformers produce more noise than GOES transformers, which would 
cause utilities to install transformers further away and increase 
secondary cable losses. APPA also stated that there are potential 
health impacts from higher levels of background noise. (APPA, No. 103 
at p. 14) Idaho Power recommended DOE include weight, noise, and cost 
in its engineering analysis, stating that the proposed standards will 
likely result in the use of heavier, noisier, and costlier amorphous 
core transformers. (Idaho Power, No. 139 at p. 3)
    AISI and Pugh Consulting both commented that amorphous is brittle 
and untested. (AISI, No. 115 at p. 2; Pugh Consulting, No. 117 at p. 5) 
Pugh Consulting additionally questioned whether amorphous transformers 
could be ``drop-in replacements'' for current transformers. (Pugh 
Consulting, No. 117 at p. 5)
    Exelon commented that domestic manufacturers have limited 
experience making amorphous core distribution transformers, a 
deficiency in domestic manufacturing experience that could have 
significant cost, supply chain, and reliability implications. Exelon 
added that most uses of amorphous core transformers have been limited 
to kVA ratings below Exelon's needs and its current research suggests 
the use of amorphous transformers at higher ratings is essentially 
experimental. (Exelon, No. 95 at p. 3)
    Metglas commented that amorphous core transformers accounted for 
approximately 10 percent of new installs in 1992 but became less common 
largely due to fewer utilities using a total owning cost (TOC) model. 
(Metglas, No. 125 at p. 2) Metglas further stated that amorphous 
transformers have served the electrical grid since 1982, with an 
estimated 22 million units in operation globally and approximately 1 
million additional units brought online each year. Id.
    Efficiency advocates commented that amorphous transformers are a 
proven technology, with an estimated 3 million transformers globally 
and over 90% of liquid immersed transformers in Canada utilizing 
amorphous cores. (Efficiency Advocates, No. 121 at pp. 1-2) NYSERDA 
similarly commented that transformers with amorphous cores are field 
proven and cost effective. (NYSERDA, No. 102 at pp. 2-3)
    EMS Consulting commented that GE produced over 600,000 amorphous 
transformers between 1986 and 2001 with very satisfactory field 
experiences, indicating that amorphous transformers are a reliable 
product. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting added that 
deregulation of electrical industries in the 1990s reduced demand for 
amorphous products in the U.S., but the products became more popular in 
developing countries like India and China due to its lower operating 
costs. Id. EMS Consulting stated that very few U.S. utilities purchase 
based on TOC but globally over 22M units have been installed and over 
1M amorphous transformers are installed globally per year. Id.
    EMS Consulting added that, although amorphous transformers 
exhibited certain performance challenges when they were first 
commercialized in the 1980s, such as increased transformer size and a 
tendency to be more brittle, improvements in amorphous properties and 
manufacturing methods have made them comparable in reliability to GOES 
transformers. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting 
further stated that the high-permeability amorphous products have a 
higher stacking factor and flux density, which will produce an even 
smaller and lighter transformer than that assumed by the NOPR. (EMS 
Consulting, No. 136 at p. 4)
    DOE notes that amorphous core transformers are not a new 
technology. As stated by Metglas and EMS Consulting, installations of 
amorphous transformers have occurred for decades, beginning in the 
1980s. While DOE agrees that amorphous core transformers are less 
common in the domestic market today than GOES core transformers, DOE 
disagrees with implication that this is the result of any performance 
defects precluding amorphous material from being used in place of GOES 
in distribution transformer cores. As pointed out by EMS consulting, 
early-stage amorphous core transformers

[[Page 29892]]

faced certain technical challenges, such as increased noise levels and 
metal shards flaking from the core. However, the development of better 
manufacturing processes for both amorphous ribbon and amorphous cores 
has mitigated the impact of these issues.
    In DOE's review of the market, it observed multiple major 
manufacturers of distribution transformers advertising amorphous 
transformers as reliable, low-loss alternatives to GOES 
transformers.70 71 72 73 Manufacturers design these 
transformers to comply with the same industry standards that apply to 
GOES units, which include provisions for general mechanical 
requirements and audible noise limits.\74\ During confidential 
manufacturer interviews, DOE also heard from stakeholders that 
amorphous transformers have become more comparable to GOES, with some 
manufacturers often providing specifications to customers for both GOES 
and amorphous core designs.
---------------------------------------------------------------------------

    \70\ Howard, Howard Amorphous Core Transformers. Available at 
howardtransformer.com/Literature/Amorphous%20Core%20Trans.pdf (last 
accessed Oct. 30, 2023).
    \71\ Hitachi, Hitachi Amorphous Transformers. Available at 
www.hitachi-ies.co.jp/english/catalog_library/pdf/transformers.pdf 
(last accessed Oct. 30, 2023).
    \72\ Eaton, Three-phase pad-mounted compartmental type 
transformer. Available at www.eaton.com/content/dam/eaton/products/medium-voltage-power-distribution-control-systems/cooper-power-series-transformers/three-phase-pad-mounted-compartmental-type-transformer-ca202003en.pdf (last accessed Nov. 15, 2023).
    \73\ Wilson Power Solutions, Amorphous Metal Transformers--Myth 
Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Nov. 30, 
2023).
    \74\ IEEE SA. (2021). IEEE C57.12.00-2021--IEEE Standard for 
General Requirements for Liquid-Immersed Distribution, Power, and 
Regulating Transformers. Available at standards.ieee.org/ieee/C57.12.00/6962/ (last accessed Nov. 8, 2021).
---------------------------------------------------------------------------

    DOE also notes that adoption of amorphous metal transformers has 
significantly increased on a global scale in the past decade. In 
Canada, for example, over 90 percent of sales for liquid-immersed 
distribution transformer are estimated to utilize amorphous cores.\75\ 
China and India have similarly exhibited large upticks in amorphous 
transformer sales.\74\ The fact that significant numbers of amorphous 
distribution transformers have been installed to the electrical grid 
without any significant reports of failure or apparent design defects, 
including approximately 600,000 units sold within the U.S.,\76\ 
demonstrates that amorphous transformers can be readily substituted for 
GOES transformers. Further, some utilities have stated that certain 
liquid-immersed manufacturers do not even state in bid sheets whether 
their transformers have an amorphous core or GOES core, indicating that 
the performance of each transformer is viewed as similar enough to be 
irrelevant to the manufacturer.\77\ For these reasons, DOE has 
maintained in this final rule that amorphous core transformers can be 
reasonably interchanged with GOES transformers without impacting 
performance.
---------------------------------------------------------------------------

    \75\ Bonneville Power Administration, Amorphous Core Liquid 
Immersed Distribution Transformers. 2020. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/liquid-immersed-amorphous-core-distribution-transformers-2020-03-31-final.pdf (last 
accessed Oct. 30, 2023).
    \76\ Metglas, Amorphous Metal Distribution Transformers. 2016. 
Available at metglas.com/wp-content/uploads/2021/06/Metglas-Power-Brochure-Updated.pdf (last accessed Oct. 30, 2023).
    \77\ Bonneville Power Administration, Low-Voltage Liquid 
Immersed Amorphous Core Distribution Transformers. 2022. Available 
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-0216.pdf 
(last accessed Nov. 8, 2023).
---------------------------------------------------------------------------

    Entergy expressed concern that ferroresonance might be a more 
prominent issue for amorphous core transformers, especially for lightly 
loaded transformers or those with protective switching, potentially 
damaging downstream equipment. (Entergy, No. 114 at p. 3) Entergy 
stated that an EPRI report indicated that increased noise is a common 
complaint for amorphous core transformers and that some users indicated 
that: (1) amorphous cores are more brittle and subject to breaking 
under strong forces; (2) operating practices may have to change to 
handle ferroresonance; and (3) lower harmonics passing through the 
transformer could interact with EV charging stations. Entergy commented 
that these technical challenges warrant additional research and 
development prior to the widespread deployment of amorphous technology. 
Id.
    Manufacturer literature and public reports \78\ widely indicate 
that technological improvements to the design of amorphous core 
transformers have largely resolved previous performance issues, such as 
brittleness of the core. As a result, amorphous core transformers have 
been deployed worldwide without any significant detriment to 
performance, as discussed further in Chapter 3 of the TSD, indicating 
that amorphous transformers can be substituted for GOES transformers in 
a wide array of applications, including those with sensitive downstream 
equipment. Regarding ferroresonance concerns specifically, DOE notes 
that increased instances of ferro resonant conditions have not been 
linked to use of amorphous metal cores. One study conducted by the 
Bonneville Power Administration indicated that amorphous core 
transformers do not significantly increase the probability or severity 
of ferroresonance incidents.\79\ Stakeholder have also previously 
indicated that they have not experienced any increases in 
ferroresonance for amorphous core transformers.\80\
---------------------------------------------------------------------------

    \78\ Bonneville Power Administration, Low-Voltage Liquid 
Immersed Amorphous Core Distribution Transformers. 2022. Available 
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf 
(last accessed Oct. 30, 2023).
    \79\ Bonneville Power Administration, Low-Voltage Liquid 
Immersed Amorphous Core Distribution Transformers. 2022. Available 
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf 
(last accessed Oct. 30, 2023).
    \80\ See Docket No. EERE-2019-BT-STD-0018, Eaton, No. 0055 at p. 
10.
---------------------------------------------------------------------------

    MTC commented that amorphous core transformers have approximately 
20-25 percent more mass, including all non-core components, due to a 
lower saturation flux density and stacking factor. (MTC, No. 119 at pp. 
11-12) Carte also asserted that amorphous cores require approximately 
20 percent more material and the environmental and carbon footprint of 
producing that material might counter the energy savings. (Carte, No. 
140 at p. 1) WEG commented that producing amorphous core transformers 
would increase the weight of units by 25 percent. (WEG, No. 92 at p. 3)
    HVOLT commented that many transformers require stacked core 
constructions, which is only viable with GOES materials and three-phase 
construction with wound cores generally increases the transformer size 
which may not be feasible for applications such as power center 
transformers. (HVOLT, No. 134 at p. 7) Portland General Electric 
commented that the larger profile of the amorphous core and windings 
would require a larger tank, more winding copper/aluminum wire, more 
oil, and more labor to produce, resulting in higher upfront procurement 
costs approximately 15-20 percent greater than GOES. (Portland General 
Electric, No. 130 at p. 3) As an example, Portland General Electric 
stated that a 25kVA pole-mounted amorphous transformer is roughly the 
size of 50kVA GOES core transformer. (Portland General Electric, No. 
130 at p. 3)
    Historically, amorphous transformers have been larger than GOES

[[Page 29893]]

transformers. GOES transformers have higher saturation flux density and 
a higher stacking factor than amorphous transformers, which allows GOES 
transformers to have a lower volume. However, quality improvements in 
amorphous ribbon have improved stacking factors. Further, the size of a 
GOES transformer is largely dependent on the loss performance of GOES 
being used. See Chapter 5 of the TSD for specific details. To reduce 
losses in a GOES transformer, manufacturers frequently design larger 
GOES cores with a reduced saturation flux density, meaning that the 
size of GOES transformers have increased in an effort to increase the 
efficiency of GOES transformers.
    Eaton submitted data demonstrating that for certain transformer 
designs, an amorphous transformer weights less at baseline. (Eaton, No. 
137 at p. 32) Further, Eaton stated that its data showed that in 
meeting the proposed efficiency standards, the incremental weight of a 
more efficient amorphous transformer is only 5.4 percent greater than 
the base amorphous design and ~1 percent relative to the base GOES 
design. Id. Eaton stated that its data also showed that achieving 
proposed efficiency levels with a GOES transformer results in a 50 
percent weight increase. Id.
    One study published by the Bonneville Power Administration in 2022 
reported the incremental weight increase for baseline GOES transformers 
and baseline amorphous transformers using data submitted by a 
distribution transformer manufacturer. Their data indicated that the 
baseline amorphous transformer was, in many cases, smaller than an 
equivalent GOES transformer for a number of kVA sizes.\81\
---------------------------------------------------------------------------

    \81\ Bonneville Power Administration, Low-Voltage Liquid 
Immersed Amorphous Core Distribution Transformers. 2022. Available 
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf 
(last accessed Oct. 30, 2023).
---------------------------------------------------------------------------

    The actual cost and size difference between a GOES core transformer 
and an amorphous core transformer depends on the actual design of the 
transformer, the loss performance of the core materials used, the 
winding material used, and whether manufacturers are trying to meet 
strict dimensional constraints or simply designing the lowest cost 
transformer. DOE does not apply blanket cost increases to any 
transformer that has an amorphous core. Rather, DOE evaluates the 
change in material costs that would be incurred by both amorphous core 
and GOES core transformers meeting a range of efficiency levels. In its 
analysis, DOE does reflect the fact that more efficient transformers 
typically require more material. This additional material has a cost, 
which is accounted for in DOE's modeling, is discussed in section IV.C 
of this document. DOE also considers potential impact on installation 
costs (see section IV.F.2 of this document).
    Idaho Falls Power and Fall River stated that amorphous core 
transformers may have negative environmental impacts when considering 
the energy gains versus the increased energy usage for manufacturing. 
(Idaho Falls Power, No. 77 at p. 1; Fall River, No. 83 at p. 1) NAHB 
commented that 40 percent of electrical steel manufacturing costs are 
attributed to energy consumption and stated that DOE should consider 
the impact of high heat in both GOES and amorphous manufacturing. 
(NAHB, No. 106 at p. 12)
    Regarding the energy usage associated with the manufacturing of 
amorphous cores, DOE notes that relative to GOES, amorphous ribbon 
production generally has lower temperatures used throughout its 
production process and a lower transformer core annealing temperature, 
which would indicate less energy use in manufacturing. Manufacturer 
literature has reported on the life-cycle assessment of amorphous and 
GOES cores, which would include the manufacturing, utilization, and 
end-of-life of the product, and concluded that the environmental impact 
of high-efficiency amorphous transformers is substantially lower than 
GOES transformers.\82\
---------------------------------------------------------------------------

    \82\ ABB, Distribution goes green. Available at 
library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).
---------------------------------------------------------------------------

    Pugh Consulting questioned whether amorphous metal could be 
recycled at the end of a transformer's lifetime and suggested DOE 
consider the costs associated with disposing of and/or recycling all 
current transformers by 2027. (Pugh Consulting, No. 117 at p. 5) DOE 
notes that amorphous cores can be recycled at end of life.\83\ Further, 
transformers manufactured before the compliance date for this final 
rule would be subject to the relevant standards corresponding to their 
date of manufacture, not the efficiency standards amended in this rule 
(i.e., all transformers do not need to be disposed of by 2027, as Pugh 
Consulting suggested). As such, any transformers currently installed, 
as well as those manufactured before the compliance date for this final 
rule, would not be required to be disposed of or replaced.
---------------------------------------------------------------------------

    \83\ Metglas, Inc. Recycling of Amorphous Transformer Cores, 
2010. Available at metglas.com/recycling-amorphous-transformer-cores/ (last accessed Nov. 9, 2023).
---------------------------------------------------------------------------

    REC commented that amorphous transformers are known to suffer 
higher failure rates due to increased susceptibility to mechanical 
stresses, lower short-circuit tolerance, and greater brittleness of the 
core. (REC, No. 126 at pp. 2-3) APPA commented that amorphous cores are 
less able to withstand short-circuit faults than GOES transformers and 
have a lower overload capacity due to lower saturation flux-density. 
(APPA, No. 103 at p. 12)
    APPA and Carte commented that amorphous transformers are subject to 
metal flakes in the oil which can lead to partial discharging and 
premature failure. (APPA, No. 103 at pp. 10-11; Carte, No. 140 at pp. 
7-8) APPA added that these discharges could require the use of oil 
monitoring devices for amorphous transformers at an additional cost. 
(APPA, No. 103 at pp. 10-11) Carte stated that discharging is more 
likely to occur if amorphous cores are used for higher voltages, which 
to Carte's understanding they have not been thus far. Carte added that 
it wasn't sure how amorphous cores were grounded and noted that current 
core grounding techniques may not be sufficient at higher voltages, 
additionally risking premature failure. (Carte, No. 140 at pp. 7-8) 
Regarding increased susceptibility to mechanical stresses, as 
previously noted, while brittleness of amorphous cores has historically 
been reported as a performance complication, performance improvements 
to amorphous ribbon as well as technological developments in the design 
and bracing of amorphous transformer cores have helped resolve this 
issue. Additionally, in DOE's review of the market, it observed 
manufacturer literature advertising construction techniques which 
reinforce amorphous metal cores and add resilience to mechanical 
stresses. For example, it has become standard to encase amorphous metal 
cores in an epoxy resin which stabilizes the core and reduces the 
likelihood of metal shards forming. Technologies also exist which can 
be used in tandem with the transformer core to capture shards, ensuring 
that they do not contaminate the insulation fluid or cause short 
circuits in the transformer windings. These developments, paired with 
performance improvements made to the amorphous metal ribbon itself, 
have significantly reduced the risk of metal flakes from an amorphous 
core impacting overall transformer performance.

[[Page 29894]]

    Regarding decreased short circuit capacity for amorphous 
transformers, industry standards set forth the provisions for short-
circuit withstand capacity for all transformers, regardless of the 
transformer core material used.84 85 As previously noted, 
amorphous core transformers are currently being designed and deployed 
in the field to meet these standards, indicating that they can be 
designed to withstand the same short circuit capacities as GOES 
transformers. Similar to the developments which have resolved 
brittleness issues experienced by early-stage amorphous transformers, 
technological improvements in the core and coil design for amorphous 
transformers have the capacity to withstand short circuit events over 
the years. For example, utilizing foil windings on the secondary coil, 
rather than rectangular wire or strip, reduces axial forces on the core 
and winding, reducing mechanical stresses and increasing short circuit 
capacity. Insulating materials can also be applied around the core to 
absorb mechanical stresses during operation, reducing the strain 
experienced by the core itself.\86\ As a result, amorphous transformer 
cores can be reliably built without increased risk of short circuit or 
premature failure when compared to an equivalent GOES transformer.
---------------------------------------------------------------------------

    \84\ International Electrotechnical Commission, IEC 60076-
5:2006: Power transformers--Part 5: Ability to withstand short 
circuit. 2006. Available at webstore.iec.ch/publication/603.
    \85\ IEEE SA. (2021). IEEE C57.164-2021--IEEE Guide for 
Establishing Short-Circuit Withstand Capabilities of Liquid-Filled 
Power Transformers, Regulators, and Reactors. 2021. Available at 
standards.ieee.org/ieee/C57.164/6804/ (last accessed Nov. 8, 2023).
    \86\ Wilson Power Solutions, Amorphous Metal Transformers--Myth 
Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Oct. 30, 
2023).
---------------------------------------------------------------------------

    APPA stated that DOE should investigate whether the use of 
amorphous cores would change the gases produced by transformers with 
the new fluids and steels, the potential impact of using amorphous 
transformers in areas with extremely hot or cold climates, and the 
impact of amorphous transformers having a lower overload capacity. 
(APPA, No. 103 at pp. 16-17)
    DOE notes that amorphous core transformers use the same insulation 
fluids as GOES transformers and APPA did not elaborate as to how the 
use of an amorphous metal, rather than GOES, in the transformer core 
would cause the transformer to produce additional or different gases 
during operation, nor did they elaborate or provide data as to how a 
change in core material would impact gases produced in a transformer. 
As such, DOE does not have reason to believe that amorphous core 
transformers would perform any differently than GOES transformers with 
regard to gases produced during operation.
    Regarding deployment of amorphous transformers in hot or cold 
climates, as previously noted, amorphous core transformers have been in 
deployment for several decades and have been deployed worldwide, 
including areas with extremely hot or cold climates. Further, amorphous 
core transformers do not inherently have lower overload capacity as 
detailed in section IV.C.1.d of this document as this is a function of 
temperature rise and transformer load losses.
    APPA further commented that some research indicates that the 
performance of amorphous transformers degrades over time, with losses 
likely to become higher than GOES transformers. APPA stated that 
accounting for those losses would undermine any economic justification 
for the proposed standards. (APPA, No. 103 at pp. 10-11) DOE notes that 
both the study cited by APPA and the original 1996 study \87\ are 
referring to degradation in the process of forming an amorphous core 
from amorphous ribbon (i.e. the material destruction factor or build 
factor), not degradation of the material over time. This kind of 
degradation is accounted for in the losses for a transformer and is 
therefore considered in DOE's analysis of both GOES and amorphous core 
transformers.
---------------------------------------------------------------------------

    \87\ Y. Okazaki, Loss deterioration in amorphous cores for 
distribution transformer, Journal of Magnetism and Magnetic 
Materials 160 (1996) 217-222.
---------------------------------------------------------------------------

    Exelon stated its concern about the ability of amorphous core 
transformers to maintain their efficiency levels over an extended 
lifetime, calling into question the life-cycle environmental benefit of 
these new transformers. Exelon commented that studies to address these 
extended performance concerns are planned but have not yet been 
executed. (Exelon, No. 95 at p. 3) REC commented that, due to the 
metallurgical nature of amorphous material, there is a continuous 
erosion of loss-savings as core material ages and degrades. (REC, No. 
126 at p. 3)
    PSE commented that amorphous core transformers have lower overload 
capacity and experience greater mechanical stress during faults due to 
their rectangular core shape, as opposed round GOES cores. (PSE, No. 98 
at p. 13) The SBA expressed concern that amorphous cores may degrade 
faster and be less capable of sustaining overload conditions than 
current GOES cores. (SBA, No. 100 at p. 6) REC commented that amorphous 
transformers have limited load and overload capacity compared to GOES, 
which will require additional or higher-capacity units to serve the 
same number of consumers. (REC, No. 126 at p. 2-3) Portland General 
Electric commented its current design practices allow for peak loads up 
to 150 percent of the transformer nameplate rating but would need to be 
revised to accommodate accelerated degradation during overloading for 
amorphous transformers. (Portland General Electric, No. 130 at p. 3) 
Cliffs commented that amorphous transformers cannot be loaded as 
efficiently as GOES cores, which increases likelihood of transformer 
failure. (Cliffs, No. 105 at p. 11)
    Transformer overloading conditions can result in increased 
mechanical stress and excess heat generation. Therefore, a 
transformer's capacity to withstand overloading conditions is dependent 
on its ability to endure mechanical stress and effectively dissipate 
heat. As previously noted, construction techniques exist to reinforce 
amorphous metal transformers against mechanical stress, reducing the 
risk of damage caused by overloading conditions. With regard to an 
amorphous transformer's ability to shed heat, excess heat is primarily 
generated through transformer losses. At higher loads, the load losses 
primarily dictate heat generation due to the quadratic relationship 
between load losses and transformer loading. Since minimally compliant 
amorphous transformers are often designed with higher load losses than 
GOES units, this may lead to the belief that amorphous transformers are 
less equipped to handle overloading conditions. However, as further 
discussed in section IV.C.1.d of this document, amorphous transformers 
do not inherently have higher load losses. Just as GOES transformers 
can be designed to meet efficiency standards by either reducing no-load 
or load losses, amorphous transformers can similarly be designed with 
lower load losses. DOE's modeling includes amorphous core transformers 
with a range of load losses, thereby maintaining the availability of 
designs with higher overload capacity. As such, transformer customers 
will continue to have the option of purchasing transformers with higher 
or lower overload withstand capacity based on the needs of their 
application. In absence of overload capacity, customers would likely be

[[Page 29895]]

forced to purchase higher kVA ratings than necessary and in doing so 
risk wasting money, energy, and electrical steel availability.
    Although multiple stakeholders expressed concern that the 
efficiency of amorphous transformers may degrade over time, no 
stakeholders provided data to demonstrate any such loss of efficiency 
over time; rather, they only cited studies on the reduction in losses 
in converting amorphous ribbon into amorphous cores. DOE notes that 
degradation of transformer performance is often associated with a 
degradation of transformer insulation, typically due to operation at 
elevated operating temperatures. As discussed in section IV.C.1.d of 
this document, amorphous transformers are capable of achieving low load 
losses, meaning temperature rise would not increase as fast, even at 
higher-loading conditions. DOE does not have reason to believe that the 
rated efficiency of an amorphous transformer would degrade over time 
when compared to an equivalent GOES transformer. Further, manufacturer 
literature has reported on accelerated aging tests of amorphous 
transformers and concluded that they saw no degradation of losses in an 
amorphous core during the transformer life.\88\ Therefore, given the 
lack of data supplied, and given the technological developments which 
have enabled amorphous transformers to withstand overload conditions 
and short circuit conditions, DOE did not consider there to be 
sufficient evidence to model amorphous transformers degrading in 
performance over time when compared to an equivalent GOES transformer.
---------------------------------------------------------------------------

    \88\ ABB, Distribution goes green. Available at 
library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).
---------------------------------------------------------------------------

Amorphous Market
    In the January 2023 NOPR, DOE discussed how amorphous ribbon 
capacity has increased since the April 2013 Standards Final Rule. 88 FR 
1722, 1755. DOE stated that it had identified numerous companies 
capable of producing amorphous material (of standard am quality or 
better) and that global amorphous ribbon capacity is much greater than 
current demand. Id. DOE stated that it had learned through manufacturer 
interviews that amorphous production capacity increased in response to 
the April 2013 Standards Final Rule, but demand for amorphous did not 
necessarily correspondingly increase, resulting in excess capacity. DOE 
discussed how amorphous producers' response to the April 2013 Standards 
Final Rule demonstrated that, if there was expected to be an increase 
in market demand for amorphous, capacity would increase to meet that 
demand. Id. Further, DOE also learned through confidential manufacturer 
interviews conducted in support of the August 2021 Preliminary Analysis 
and the January 2023 NOPR that recent price increases for GOES have led 
amorphous to be far more cost competitive. However, despite this 
increased competitiveness, the industry has not seen an increase in 
amorphous transformer purchasing, likely due to existing distribution 
transformer core production equipment being set-up to produce GOES 
cores and a transition to amorphous cores requiring capital investment. 
Id. Based on these developments, in the January 2023 NOPR, DOE 
constrained the selection of amorphous alloys under the no-new-
standards scenario to better match the current market share of 
distribution transformers; however, DOE did not apply any constraints 
to standard am steel purchasing in its evaluation of higher efficiency 
levels. 88 FR 1722, 1756.
    In the January 2023 NOPR, DOE acknowledged that the availability of 
both GOES and amorphous alloy is a concern for distribution 
transformers, but expected that suppliers would be able to meet the 
market demand for amorphous for all TSLs analyzed given the NOPR's 3-
year compliance period. 88 FR 1722, 1817. DOE noted that manufacturers 
should be able to significantly increase supply of amorphous if they 
know there will be an increase in demand as a result of the proposed 
energy conservation standards. Id. DOE requested comment on this 
assumption and how supply and demand would change in response to the 
proposed amended energy conservation standards. Id.
    In response, HVOLT, Southwest Electric, Cliffs and NRECA expressed 
concern that there is not sufficient amorphous ribbon capacity 
currently and capacity will not be able to grow quickly enough to meet 
the amorphous demand increases expected from the proposed standards. 
(HVOLT, No. 134 at pp. 5-6; Southwest Electric, No. 87 at p. 3; Cliffs, 
No. 105 at pp. 10-11; NRECA, No. 98 at p. 3) Cliffs stated that even if 
all global capacity were used, it would not be enough to support the US 
market. (Cliffs, No. 105 at pp. 10-11) Cliffs added that DOE 
incorrectly assumes amorphous production can increase to meet demand 
without sufficient verification of if that is true. (Cliffs, No. 105 at 
pp. 10-11)
    Hammond commented that only one amorphous producer serves the U.S. 
market and it cannot scale up in time to meet forecasted demand. 
(Hammond, No. 142 at p. 2) Hammond added that it is not aware of any 
efforts outside the U.S. to expand amorphous production to the levels 
needed to serve the U.S. market. (Hammond, No. 142 at p. 2) DOE notes 
there is one domestic producer of amorphous steel and one domestic 
producer of GOES.
    Howard commented that the proposed standards will increase GOES 
demand by 60 percent, or increase amorphous by 600 million pounds, and 
if all amorphous is domestic, increase domestic amorphous ribbon 
capacity by 500 percent. (Howard, No. 116 at p. 2) Howard further 
stated that silicon steel plants typically require 3-4 years and $1-2B 
to design and build, whereas amorphous would require an additional 15-
20 production lines and $1B investment, which isn't achievable in the 
proposed timeline. (Howard, No. 116 at p. 2) Cliffs commented that 
amorphous transformers currently make up a small fraction of domestic 
transformers production and cannot be scaled in the near-term to meet 
the domestic market. (Cliffs, No. 105 at p. 6)
    Prolec GE commented that current and projected capacities of both 
amorphous metal ribbon and cores will likely remain below the levels 
required for future demand. (Prolec GE, No. 120 at p. 14) VA, MD, and 
DE House Representatives commented that the proposed standards will 
require a rapid expansion of amorphous ribbon capacity which could 
exacerbate near-term supply chain shortages. (VA, MD, and DE Members of 
Congress, No. 148 at pp. 1-2)
    Several stakeholders expressed concern that there was only a single 
domestic supplier of amorphous material. Powersmiths commented that the 
single supplier of amorphous will not be able to expand capacity to 
meet the needs of the entire distribution transformer market and that 
it is not acceptable to rely on a single supplier regardless. 
(Powersmiths, No. 112 at p. 6) TMMA commented that the U.S. 
manufacturer of amorphous would not be able to serve the entire US 
transformer market, even with stated capacity expansions, leaving the 
U.S. reliant on foreign produced amorphous. (TMMA, No. 138 at pp. 3-4) 
Powersmiths commented that amorphous is not available in the narrower 
strips required for LVDTs and the 2027 compliance date does not provide 
sufficient time to put a supply chain in place. (Powersmiths, No. 112 
at p. 6) Powersmiths further commented

[[Page 29896]]

that hibam is the most viable for LVDT markets and expressed concern 
that this steel is offered from a single source. (Powersmiths, No. 112 
at p. 6)
    NAHB expressed concern that the proposed rule would worsen supply 
and competition concerns. NAHB recommended that, given the limited 
number of manufacturers for certain products, DOE should work with 
other Federal agencies to fully review and address the likelihood that 
this rule will exacerbate anticompetitive supply constraints. (NAHB, 
No. 106 at pp. 2, 6)
    Idaho Falls Power and Fall River stated that relying upon a single 
domestic supplier of amorphous will create both a de facto monopoly and 
a bottleneck in an already constrained supply chain. (Idaho Falls 
Power, No. 77 at p. 1; Fall River, No. 83 at p. 2)
    Alliant Energy commented that requiring all distribution 
transformers to be made from a material with a single domestic suppler 
representing less than 5 percent of the market will negatively impact 
transformer production capacity and availability. (Alliant Energy, No. 
128 at pp. 2-3) Alliant Energy added that the significant transit times 
required to source amorphous from foreign nations would exacerbate 
existing supply chain challenges. (Alliant Energy, No. 128 at pp. 2-3)
    In this final rule, DOE notes that it has modified its assumptions 
to reflect stakeholder feedback suggesting that even if amorphous is 
the lowest first-cost option, manufacturers may elect to build GOES 
transformers in order to maintain a more robust supply chain and reduce 
the impact on existing short to medium-term supply challenges. 
Specifically, DOE assumed that for liquid-immersed distribution 
transformers, amorphous adoption will be constrained at all efficiency 
levels through EL 2, as discussed in section IV.F.3 of this document.
    Many stakeholders also commented expressing concern that the use of 
amorphous metal would increase U.S. reliance on foreign suppliers.
    Schneider asserted that given that only one company in Japan and 
one company in the United States can produce amorphous materials, there 
is risk of an oligopoly. (Schneider, No. 92 at pp. 9-10) Schneider 
further stated that there are only two manufacturers that can produce 
amorphous to meet DOE requirements and the barriers to entry are 
extremely high. (Schneider, No. 92 at pp. 9-10) Prolec GE commented 
that manufacturers will be forced to rely on foreign steel suppliers, 
mainly from China, because the domestic supply of amorphous cannot meet 
the demand of the U.S. distribution transformer market. (Prolec GE, No. 
120 at p. 3) Eaton commented that it would like to have at least three 
suppliers of amorphous, preferably located in different geographical 
regions of North America. (Eaton, No. 137 at p. 27)
    The Chamber of Commerce commented that requiring transformers to 
use amorphous cores conflicts with public policy goals by increasing 
the domestic electricity sector's reliance on inputs from China. 
(Chamber of Commerce, No. 88 at p. 3) AISI commented that U.S. steel 
production has a lower carbon intensity that steel made in China. 
(AISI, No. 115 at p. 2)
    EEI commented that the proposed standards will increase the need to 
rely on foreign sourced products, which will create national security 
concerns, eliminate American jobs, and increase transit times. (EEI, 
No. 135 at pp. 29-30) NRECA commented that the proposed standards will 
increase reliance on foreign nations for amorphous materials in 
distribution transformers and GOES for power transformers. (NRECA, No. 
98 at pp. 3-4) NRECA stated that higher labor costs for amorphous core 
and a limited domestic capacity for amorphous materials will increase 
outsourcing of distribution transformer manufacturing, creating a 
national security risk. (NRECA, No. 98 at pp. 3-4) NRECA added that 
many utilities are Rural Utilities Service (RUS) borrowers, which 
prohibits them from purchasing products with foreign-sourced steel. 
(NRECA, No. 98 at p. 7) Michigan Members of Congress stated that 
offshoring manufacturing of distribution transformers raises national 
security concerns. (Michigan Members of Congress, No. 152 at p. 1) Pugh 
Consulting advised against relying upon a single steel variety and 
stated that transformer shortages are dangerous given the number of 
storms, hurricanes, and violent attacks by extremists against 
distribution transformers. (Pugh Consulting, No. 117 at p. 4) TMMA 
commented that the proposed standards increase our reliance on 
international and unfriendly suppliers which is a threat to national 
security. (TMMA, No. 138 at pp. 2, 4) Howard commented that 
transformers are vital to national security and given existing 
shortages, it is vital to maintain both GOES and amorphous as viable 
options. (Howard, No. 116 at p. 4) AISI commented that if distribution 
transformers transition to amorphous, that could eliminate domestic 
GOES, which would be harmful to national security. (AISI, No. 115 at p. 
2)
    Carte commented that the proposed standards present national 
security concerns because the timeline is not sufficient for amorphous 
ribbon capacity to ramp up, which will require additional imports of 
amorphous. Carte also noted that the domestic supplier's parent company 
is headquartered in Japan. (Carte, No. 140 at p. 4)
    HVOLT expressed concern that the proposed standards requiring 
manufacturers to rely on a single amorphous supplier based in Japan, 
whereas they can currently source core steel from multiple GOES 
suppliers. (HVOLT, No. 134 at pp. 5-6)
    Webb expressed concern that shifting towards amorphous cores will 
place utilities at greater risk and increase U.S. reliance on foreign 
suppliers. Webb compared this to the recent U.S. semiconductor scarcity 
and questioned whether the government would similarly address 
transformer shortages via Federal funding, as was done for 
semiconductors with the CHIPS and Science Act. (Webb, No. 133 at p. 2)
    MTC commented that patent disputes have led Hitachi to consolidate 
all amorphous production in Japan, making the only global suppliers of 
amorphous Hitachi and Chinese suppliers. (MTC, No. 119 at p. 20) DOE 
notes that MTC's comment does not accurately reflect the current state 
of the market. DOE is aware of amorphous production in the United 
States today. See Appendix 3A of the TSD for a detailed discussion of 
the amorphous and GOES markets.
    MTC further commented that there is insufficient global production 
capacity of amorphous to support the U.S. distribution transformer 
market, even if domestic production capacity were tripled. (MTC, No. 
119 at p. 9) MTC additionally commented that lack of domestic steel 
supply is an issue of national security which should be referred to the 
Department of Commerce for remedies. (MTC, No. 119 at p. 20)
    Exelon commented that the proposed standards could exacerbate 
supply chain constraints and drive more foreign transformer sourcing, 
creating new grid reliability challenges and increasing consumer costs. 
(Exelon, No. 95 at p. 4)
    Cliffs commented that relying upon amorphous material represents a 
national security threat because it is not readily available in the 
U.S., cannot be manufactured using GOES production equipment, and 
cannot supply the U.S. grid. (Cliffs, No. 105 at pp. 4-5)
    Schneider commented that the production of ferroboron \89\ is 
limited to

[[Page 29897]]

locations outside the U.S., which leads to long-term availability 
concerns and, because of this, prior evaluations did not consider max-
tech. (Schneider, No. 92 at pp. 10-12) Cliffs added that the feedstock 
to produce amorphous is foreign-sourced, all other major amorphous 
producers are foreign, and amorphous is more labor intensive, making 
the U.S. more dependent on foreign supply chains. (Cliffs, No. 105 at 
p. 7) BCBC and BCGC expressed concern that DOE's proposal could be 
detrimental to the resiliency of the United States electric grid 
because amorphous is produced from imported, unproven, and foreign-
sourced materials that could compromise both energy and national 
security in the United States. BCBC and BCGC recommended that DOE adopt 
policies that increase domestic production of key materials and 
components to strengthen national security and self-reliance. (BCBC, 
No. 131 at p. 1; BCGC, No. 132 at p. 1) AISI commented that amorphous 
cores requires foreign-sourced materials whereas GOES is able to be 
produced with all stages using domestic manufacturing. (AISI, No. 115 
at p. 2) \90\
---------------------------------------------------------------------------

    \89\ Ferroboron is an input in amorphous production. It is 
produced by a well-known reaction of iron with boron (as boric 
acid). Both of these minerals are produced in the U.S., although 
actual ferroboron production typically occurs outside the U.S.
    \90\ U.S. Department of Commerce, The Effect of Imports of 
Transformers and Transformer Components on the National Security. 
(2020). Available at www.bis.doc.gov/index.php/documents/section-232-investigations/2790-redacted-goes-report-20210723-ab-redacted/file.
---------------------------------------------------------------------------

    DOE notes that the current status quo for the distribution 
transformer market involves a single domestic GOES manufacturer and 
multiple global GOES suppliers, with any imported GOES subject to 
tariffs. As a result, transformer manufacturers who produce transformer 
cores domestically are largely reliant on the single domestic GOES 
supplier, given that using GOES from any other supplier requires paying 
a tariff. For amorphous, there is similarly a single domestic amorphous 
manufacturer and multiple global suppliers. Meeting higher-efficiency 
standards with amorphous would result in domestic transformer 
manufacturers who produce transformer cores domestically being largely 
reliant on the single domestic amorphous supplier, given that using 
amorphous from any other supplier requires paying a tariff. This is 
similar to the current market structure for GOES. Therefore, DOE 
disagrees that a distribution transformer supply chain with substantial 
amorphous cores is inherently more of a national security risk than the 
existing GOES-based supply chain. The current distribution transformer 
supply chain, as well as how the market is expected to respond to 
amended standards, is further discussed in section IV.A.5 of this 
document.
    DOE considers the effect of DT standards on the domestic supply 
chain in setting standards. However, DOE notes that a distribution 
transformer market served by 100 percent domestically produced 
electrical steel does not exist today. One transformer manufacturer 
noted that having only a single-domestic supplier of GOES represents a 
considerable supply risk. They further stated that developing the 
workforce skills and manufacturing capabilities to leverage both GOES 
and amorphous will reduce their electrical steel supply risk, provided 
development of that capability does not disrupt existing product 
output.\91\ Several stakeholders expressed concern that too rapid of a 
transition to amorphous cores could worsen near-term supply chains and 
recommended DOE wait for capacity to increase prior to implementing any 
amended efficiency standards.
---------------------------------------------------------------------------

    \91\ Markham, I., ERMCO CEO: For an Effective Outcome, Focus on 
Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at: 
https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.
---------------------------------------------------------------------------

    ABB stated that DOE should ensure that there is a sufficient and 
competitive supply of GOES and amorphous before requiring significantly 
higher energy conservation standards. (ABB, No. 107 at pp. 2-3) ABB 
went on to state that the transformer industry is already experiencing 
an insufficient domestic supply of GOES and expressed concern that the 
same challenges would be faced with amorphous cores. (ABB, No. 107 at 
pp. 2-3) NWPPA commented that manufacturers struggle to source the high 
performing GOES required to meet current standards and the proposed 
standards would require an even scarcer variety of steel for very small 
gains in efficiency. (NWPPA, No. 104 at p. 1) NRECA commented that 
DOE's proposal will not expand the market for distribution transformers 
because most current production using GOES will not be able to meet the 
proposed standards. (NRECA, No. 98 at p. 2)
    WEG commented that amorphous cores will be the most cost effective 
way to meet standards, but the supply chain for amorphous material is 
not prepared to sustain the market or support the electrical grid. 
(WEG, No. 92 at pp. 2-3) WEG stated that U.S. manufacturers would need 
200,000 tons of amorphous to meet the proposed standards, which would 
be 100 percent of global amorphous ribbon capacity just to support the 
U.S. (WEG, No. 92 at pp. 2-3) WEG additionally commented that using 
amorphous cores will require years of technical development and 
industry won't be able to use GOES in the meantime. (WEG, No. 92 at pp. 
2-3)
    Cliffs commented that requiring amorphous cores would make the 
transformer supply chain less secure and require considerable 
investment from transformer manufacturers at a time of existing supply 
chain and labor challenges. (Cliffs, No. 105 at p. 6) Cliffs commented 
that only a single domestic manufacturer has the technical know-how to 
produce amorphous ribbon and even if that manufacturer licensed the 
technology, if efficiency standards require amorphous cores, the 
manufacturer will effectively have a monopoly that will lead to 
increased prices. (Cliffs, No. 105 at pp. 15-16)
    UAW commented that the proposed standards may upend the 
distribution transformer market by relying upon steel which is in short 
supply and more expensive than the GOES currently used. (UAW, No. 90 at 
p. 3)
    Webb recommended that DOE confirm whether amorphous ribbon capacity 
can be made available to meet both current GOES demand and increased 
future demand due to distributed energy resource deployment. (Webb, No. 
133 at p. 2)
    Metglas commented that continued expansion of amorphous production 
by other producers demonstrates that there are no IP-related 
impediments to expanding use of amorphous transformers. (Metglas, No. 
125 at pp. 3-4) Metglas commented that grades of GOES exist that can 
meet the proposed DOE standards and suggested that GOES will continue 
to serve a significant portion of U.S. demand for distribution 
transformers, even in the presence of amended standards. (Metglas, No. 
125 at pp. 3-4) Metglas went on to state that the proposed standards 
will encourage competition for transformer core steel and help solidify 
a majority domestic supply of transformer core steel. (Metglas, No. 125 
at pp. 3-4)
    The current domestic demand for electrical steel used in 
distribution transformers is estimated to be approximately 225,000 
metric tons, which is approximately equal to the global capacity for 
amorphous material. The response to the April 2013 Standards Final Rule 
demonstrated that amorphous material manufacturers are willing and 
capable of adding capacity in response to increased demand (See Chapter 
3A of the TSD). Metglas commented that between 2015 and 2018, 
production of amorphous alloy in China increased by 50,000 metric tons. 
(Metglas, No. 11 at pp. 3-4). Eaton commented that between 2013 and

[[Page 29898]]

2019, three additional companies entered the amorphous market with 
similar product widths to the U.S. domestic producer of amorphous 
(Eaton, No. 12 at p. 7)
    If amended standards created an assured demand for amorphous 
material, it can be reasonably expected that amorphous ribbon capacity 
would increase to meet the demands of the U.S. distribution transformer 
market. Given expected demand for amorphous ribbon, there are no 
technical constraints preventing amorphous ribbon capacity from 
increasing, eventually; however, there is uncertainty as to what time 
frame that capacity would be sufficient to meet the demand created by 
amended efficiency standards. Metglas commented that it currently has 
an installed capacity of 45,000 metric tons available domestically and 
stated that it can bring an additional 75,000 metric tons of production 
online in less than 37 months, bringing total domestic capacity to 
120,000 metric tons. Further, Metglas stated that it is willing to 
invest beyond current facility location constraints to meet customer 
demand. (Metglas, No. 125 at p. 8) In addition to statements from the 
current domestic amorphous supplier and demonstrations of capacity 
additions in other countries, recent patent filings from several major 
steel producers indicate that the production of amorphous alloy is an 
area of active technological innovation.92 93 94 95
---------------------------------------------------------------------------

    \92\ VAC, Amorphous Material--VITROVAC, (Last Accessed 12/21/
2023), Available online at: https://vacuumschmelze.com/products/soft-magnetic-materials-and-stamped-parts/amorphous-material-vitrovac.
    \93\ Hartman, T., Amorphous Metal Foil and Method for Producing 
an Amorphous Metal Foil Using a Rapid Solidification Technology, 
U.S. 0201914, 2023.
    \94\ Guidebook for POSCO's amorphous metal, Docket No. EERE-
2010-BT-STD-0048-0235.
    \95\ Nippon Steel Corp, Fe-Based Amorphous Alloy Having 
Excellent Soft Magnetic Characteristics and Processability, Fe-Based 
Amorphous Alloy Thin Strip Having Excellent Soft Magnetic 
Characteristics and Processability, Wound Core, Stacked Core and 
Rotary Electric Machine, JP20231017731A, 2023.
---------------------------------------------------------------------------

    If all distribution transformers had to transition to amorphous 
cores immediately, stakeholders stated that the capacity and core-
construction infrastructure would not exist and there would be 
considerable price increases which would very likely worsen supply 
chains and have negative cost impacts for consumers, at least until 
supply could catch up with demand. However, comments from stakeholders 
indicate that longer transition times could allow distribution 
transformer manufacturers to more gradually transition to amorphous 
cores, mitigating supply chain concerns. DOE received several comments 
from stakeholders as to what they believe would be a reasonable 
timeframe and scope to allow for a gradual transition to higher-
efficiency without significantly impacting near term pricing. These 
comments are discussed in section IV.C.2.a of this document.
    As discussed, for efficiency levels up through EL2 for liquid-
immersed distribution transformers, both amorphous and GOES 
transformers are anticipated to be able to compete on first cost. While 
stakeholders expressed concern that amorphous would not be able to 
scale up sufficiently to serve the entire distribution transformer 
market, DOE estimates that approximately 48,000 metric tons of 
amorphous will be used to meet the amended standards for liquid-
immersed distribution transformers. While this is a considerable 
increase from the amount of amorphous used in distribution transformer 
cores today, it is approximately equal to the current stated amorphous 
capacity (of approximately 45,000 metric tons). Meaning, even if the 
amorphous core market were to be entirely served by domestic 
manufacturing, no additional amorphous manufacturers were to enter the 
market, and the current domestic manufacturer were to add no production 
capacity, amorphous capacity would still be approximately sufficient to 
serve the distribution transformer market.
b. Grain-Oriented Electrical Steel Market and Technology
    GOES is a variety of electrical steel that is processed with tight 
control over its crystal orientation such that its magnetic flux 
density is increased in the direction of the grain orientation. The 
single-directional flow is well suited for distribution transformer 
applications and GOES is the dominant technology in the manufacturing 
of distribution transformer cores. GOES is produced in a variety of 
thicknesses and with a variety of loss characteristics and magnetic 
saturation levels. In certain cases, steel manufacturers may further 
enhance the performance of electrical steel by introducing local strain 
on the surface of the steel through a process known as domain 
refinement, such that core losses are reduced. This can be done via 
several methods, some of which survive the distribution transformer 
core annealing process.
    In the January 2023 NOPR, DOE maintained the four subcategories of 
GOES that it had identified in the August 2021 Preliminary Analysis as 
possible technology options. 87 FR 1722. 1756. These technology options 
and their DOE abbreviations are shown in Table IV.5.
[GRAPHIC] [TIFF OMITTED] TR22AP24.532

    DOE noted in the January 2023 NOPR that for high-permeability 
steels, steel manufacturers have largely adopted a naming convention 
that includes the steel's thickness, a brand-specific designator, 
followed by the guaranteed core loss of that steel in W/kg at 1.7 Tesla 
(T) and 50 Hz. Id. Power in the U.S. is delivered at 60 Hz and the flux

[[Page 29899]]

density can vary based on distribution transformer design, therefore 
the core losses reported in the steel name are not identical to their 
performance in the distribution transformer. However, the naming 
convention is generally a good indicator of the relative performance of 
different steels.
    In the January 2023 NOPR, DOE discussed how different grades of 
GOES, and in particular hib and dr GOES, are typically marketed as 
suitable for use in either power or distribution transformers. Id. 
However, DOE also noted that power transformers tend to have priority 
over distribution transformers and generally receive the highest 
performing grades of GOES, as stated by stakeholders in public comment. 
(Schneider, No. 49 at p. 14; Cliffs, No. 57 at p. 1) The larger volume 
of the liquid-immersed distribution transformer market similarly tends 
to be served before the dry-type distribution transformer market. Id.
    In response to the August 2021 Preliminary Analysis TSD, DOE 
received comment from stakeholders that the GOES steel supply had 
become more constrained in recent years. Stakeholders commented that 
certain grades of steel are becoming more difficult to acquire and 
costs have increased for all grades of steel. 87 FR 1722, 1756. In the 
January 2023 NOPR, DOE noted that the combined effect of general 
commodity related supply chain issues and competition from the EV 
market likely contributed to these recent supply issues and cost 
increases. Id. In response to stakeholder feedback, DOE proposed 
screening out some of the highest performing grades of GOES, where 
steel manufacturers are not able to mass produce GOES of similar 
quality. Id. In this final rule, DOE continued to screen out these 
steel grades, as discussed in section IV.B of this document. Further, 
DOE also updated all material costs in this final rule to account for 
recent trends in market prices, as discussed in section IV.C.2 of this 
document.
    In response to the January 2023 NOPR, DOE received additional 
comments regarding the supply and availability of GOES.
    NEMA commented that GOES with better performance than M3 is 
typically not available from domestic suppliers. (NEMA, No. 141 at p. 
14) WEG commented that there are global shortages of high-grade GOES 
today. (WEG, No. 92 at p. 1) Prolec GE commented that GOES supplies 
have been constrained by worldwide increase in demand for GOES coupled 
with shifting production capacity to non-oriented electrical steel 
(NOES). (Prolec GE, No. 120 at p. 10) Howard commented that the GOES 
market has been severely impacted by NOES demand spikes. (Howard, No. 
116 at p. 23) Metglas commented that there is currently a shortage of 
GOES due to a combination of factors, including competition from NOES 
and thinner gauge requirements for EVs reducing steel mill output 
capacity. (Metglas, No. 125 at p. 5)
    MTC provided US import and consumption data for GOES and commented 
that U.S. consumption of GOES for distribution transformers is 
approximately 175K MT. (MTC, No. 119 at p. 2) MTC additionally 
commented that Cliffs is not currently able to meet demand requirements 
for GOES in the U.S. (MTC, No. 119 at p. 2) MTC added that lack of a 
secure domestic steel supply is an issue of national security which 
should be referred to the Department of Commerce for remedies. (MTC, 
No. 119 at p. 20) Efficiency Advocates commented that the current 
domestic GOES supply is insufficient to meet market demands and 
additional suppliers of GOES are unlikely to form due to long lead 
times and significant capital requirements. Efficiency Advocates 
further commented that higher grades of GOES are not available in large 
quantities domestically. (Efficiency Advocates, No. 121 at pp. 2-3)
    Pugh Consulting commented that the single supplier of GOES has not 
indicated that they will increase production to meet demand and it is 
unclear whether a new manufacturer could obtain a Title V Clean Air Act 
permit. (Pugh Consulting, No. 117 at p. 3) DOE notes that Title V of 
the Clean Air Act requires facilities that are major sources of air 
pollutants to obtain operating permits, which specify permissible 
limits of pollutant emissions. However, Title V permitting for steel 
manufacturers is beyond the scope of this rulemaking.
    Hammond commented that it expects the market to provide an adequate 
supply of both NOES and GOES for the foreseeable future. (Hammond, No. 
142 at p. 2) Schneider commented that the supply and demand of GOES is 
well balanced today, GOES capacity will gradually increase over time, 
and they do not expect manufacturers to shift production of GOES to 
NOES because steel manufacturers recognize the role of GOES. 
(Schneider, No. 101 at p. 9)
    Cliffs commented that it recently invested $40M to expand domestic 
electrical steel production (both GOES and NOES) and aims to invest 
more in the near future to keep up with demand. (Cliffs, No. 105 at p. 
15)
    NAHB commented that GOES is harder and more costly to produce than 
NOES because it requires additional processing steps. NAHB pointed out 
that a new domestic electrical steel facility, which opened in 2023, 
elected to produce NOES rather than GOES, which may indicate other 
domestic steel producers are unlikely to add GOES production lines. 
(NAHB, No. 106 at pp. 9-10)
    Stakeholder comments submitted in response to the January 2023 NOPR 
further confirm that the current GOES market is experiencing supply 
constraints, inhibiting the ability of manufacturers to obtain the full 
range of core steel grades. DOE notes that this appears to be 
especially true for the domestic steel market, which stakeholders have 
stated does not have a sufficient quantity of low-loss steels to serve 
the needs of U.S. distribution transformer market.\96\ Although the 
sole domestic producer of GOES is capable of producing a full range of 
M-grades and some hi-b steels, the supply of dr steels is more 
constrained and there is currently no domestic production of pdr GOES. 
Further, as previously noted, distribution transformer manufacturers 
compete for GOES with power transformer manufacturers, with many of the 
highest performing grades dedicated to power transformer production 
over distribution transformer production.
---------------------------------------------------------------------------

    \96\ See also Department of Commerce investigation into imports 
of laminations and wound cores for incorporation into transformers. 
Docket No. BIS-2020-0015. Available at www.regulations.gov/docket/BIS-2020-0015.
---------------------------------------------------------------------------

    This leaves a limited supply of the lowest-loss grades of GOES for 
distribution transformer manufacturers. Since 2018, all raw imported 
electrical steel has also been subject to a 25 percent ad valorem 
tariff.\97\ Therefore, manufacturers are forced to choose between 
sourcing from the single domestic provider of GOES or paying more for 
imported product. The result of these myriad factors is a strained GOES 
supply for distribution transformer production.
---------------------------------------------------------------------------

    \97\ See 83 FR 11625.
---------------------------------------------------------------------------

    DOE also received comments regarding how the proposed standards 
might impact the GOES market.
    Pugh Consulting suggested DOE should explore options to incentivize 
the domestic production of amorphous and GOES steel for distribution 
transformers, such as funding authorized by Congress, tax credits, and 
use of the Defense Production Act. (Pugh Consulting, No. 117 at p. 7) 
DOE notes that this final rule pertains only to energy conservation 
standards for

[[Page 29900]]

distribution transformers, and any efforts to amend other Federal 
regulatory programs and policies are beyond the scope of this 
rulemaking. However, separate agency actions may promote production of 
domestic amorphous and GOES including the Advanced Energy Project 
Credit (48C) Program in partnership with the Department of the Treasury 
and the Internal Revenue Service.\98\
---------------------------------------------------------------------------

    \98\ See https://www.energy.gov/infrastructure/qualifying-advanced-energy-project-credit-48c-program.
---------------------------------------------------------------------------

    CARES commented that there is insufficient supply of either GOES or 
amorphous to meet the demand required by the proposed standards. 
(CARES, No. 99 at p. 3)
    Cliffs commented that the proposed standards are contrary to 
established Federal policies that have designated GOES a critical 
product essential to U.S. national security interests. (Cliffs, No. 105 
at pp. 2, 5-6) Specifically, Cliffs commented that the proposed 
standards are counter to the 232 report which concluded that 
maintaining domestic GOES capacity is crucial to national security and 
that domestic steel producers must have viable markets beyond solely 
the defense industry. (Cliffs, No. 105 at pp. 4-5) Cliffs stated that 
the proposed standards would negate any benefits currently being 
realized by the 25 percent 232 tariffs, which undermines the entire 
purpose of the tariffs. (Cliffs, No. 105 at pp. 3-5)
    Cliffs further commented that the majority of domestic GOES is 
manufactured for use in distribution transformers and the NOPR makes 
production of both GOES and NOES economically untenable, risking 1500 
jobs and undermining the supply chain for transformers, electric 
motors, and other industries. (Cliffs, No. 105 at p. 6) Cliffs 
additionally noted that: (1) GOES is needed for bulk power 
infrastructure, (2) several Federal reports have recommended 
establishing a stockpile of domestic GOES, and (3) the Cybersecurity 
and Infrastructure Security Agency has stated that large-power 
transformers are overly reliant on foreign imports, all of which 
further demonstrate the importance of domestic GOES manufacturing for 
national security. (Cliffs, No. 105 at pp. 7-8) DOE notes that large-
power transformers are not subject to energy conservation standards.
    Several stakeholders suggested that producers of electrical steel 
would discontinue production of GOES without demand for distribution 
transformers, eliminating the domestic supply of electrical steel and 
causing layoffs of approximately 1500 employees. (UAW, No. 90 at p. 1; 
UAW Locals, No. 91 at p. 1; BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 
1) Stakeholders stated that this would eliminate the supply of 
electrical steel for other industries, such as EV motors, and make the 
U.S. entirely reliant on foreign entities to support the grid. Id. BCBC 
and BCGC added that the Butler Works electrical steel plant supports 
Butler County and any loss will have an exponential and devastating 
impact well beyond the plant itself. (BCBC, No. 131 at p. 1; BCGC, No. 
132 at p. 1) UAW Locals and BCBC and BCGC recommended that DOE either 
withdraw the NOPR or proceed with an efficiency standard that ensures 
continued use of GOES in distribution transformers. (UAW Locals, No. 91 
at p. 2; BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1)
    A number of stakeholders similarly submitted comments expressing 
concern that the proposed rulemaking would weaken domestic supply 
chains and jeopardize U.S. jobs by making the U.S. more reliant on 
foreign amorphous suppliers and suggested DOE should ensure GOES can 
continue to be used in distribution transformers. (Thomas, No. 155 at 
p. 1-2; Pennsylvania AFL-CIO, No. 156 at p. 1-2; BCCC, No. 158 at p. 1-
2; Renick Brothers Co., No. 160 at p. 1; Snyder Companies, No. 161 at 
p. 1; Nelson, No. 157 at p. 1)
    Other stakeholders similarly expressed concern that the proposed 
standards may lead the single domestic producer of GOES to either 
reduce or discontinue production, which could hurt transformer supply 
chains and make transformer manufacturers more reliant on foreign steel 
importers. (Michigan Members of Congress, No. 152 at p. 1; HVOLT, No. 
134 at p. 7; AISI, No. 115 at pp. 2-3; Alliant Energy, No. 128 at p. 3; 
Kansas Congress Member, No. 143 at p. 1; Entergy, No. 114 at p. 2)
    Eaton commented that DOE should consider the possibility of 
domestic GOES manufacturing disappearing in response to standards, 
leaving other critical resources like power transformers without a 
stable supply chain. (Eaton, No. 137 at p. 26) TMMA commented that the 
domestic GOES producer is not planning to invest in producing premium 
GOES grades and, therefore, U.S. transformer manufacturers will need to 
use foreign-produced GOES which isn't available in sufficient capacity 
to support the U.S. transformer market. (TMMA, No. 138 at pp. 3-4) MTC 
commented that the proposed standards will increase the cost of GOES 
production, potentially jeopardizing refurbishment, resilience, and 
upgrading of the grid. (MTC, No. 119 at p. 19) NEMA commented that the 
administration has sought to increase domestic manufacturing and this 
rule creates a dangerous imbalance of core steel supply. (NEMA, No. 141 
at p. 2) NAHB commented that declining imports of both finished 
transformers and GOES in recent years, paired with a lack of domestic 
competition for GOES production, have exacerbated the transformer 
crisis and expressed concern that the NOPR will worsen these issues. 
(NAHB, No. 106 at pp. 6-8)
    In the January 2023 NOPR, DOE discussed how GOES production can be 
shifted to NOES production at only a modest cost. 88 FR 1722, 1767. 
Stakeholders have commented that this transition is already occurring 
and has partially contributed to the GOES shortages experienced by the 
transformer industry. Id. The shift towards NOES production is largely 
driven by electrification trends and increased production of EV motors, 
creating an assured demand for NOES well into the future. As such, 
manufacturers of GOES in the current market may have the option of 
converting GOES production lines to NOES capacity in the event that 
demand for GOES decreases.
    While Cliffs indicated in its comment that GOES production is used 
to support NOES production, DOE notes that in 2023 an additional 
domestic NOES production facility opened without GOES production.\99\ 
This indicates that a NOES production facility is a reasonable 
investment on its own.
---------------------------------------------------------------------------

    \99\ U.S. Steel, Big River Steel Overview. Available at 
www.ussteel.com/bigriversteeloverview (last accessed Nov. 8, 2023).
---------------------------------------------------------------------------

    DOE also notes that other markets for GOES exist. For example, the 
power transformer market also acts as an end-use for domestically 
produced GOES. Although this market is smaller than the distribution 
transformer market by volume, with total demand for medium and large 
power transformers estimated to be over 2,700 units per year, 
individual units can weigh several hundred tons, contributing a 
significant source of demand for GOES. 86 FR 64606, 64662. Increased 
electrification likely means that the demand for large-power 
transformers, and therefore demand for GOES in large-power 
transformers, will continue to increase. Given the assured demand for 
GOES from the power transformer industry and the available option to 
convert capacity to NOES, along with the fact that a second domestic 
NOES production facility recently began

[[Page 29901]]

production, it is unlikely that domestic electrical steel production 
would entirely disappear because of amended efficiency standards.
    However, lead times for distribution transformers have 
significantly increased in recent years and could be exacerbated by a 
wholesale transition to amorphous cores at this time. Further, the vast 
majority of domestic GOES production is used in distribution 
transformers, and while alternative uses for that capital equipment may 
exist, preemptive conversion of that capital in anticipation of 
disappearing demand could exacerbate near-term transformer shortages. 
In an effort to minimize this risk, DOE has evaluated an additional TSL 
in which certain segments of the distribution transformer market remain 
at efficiency levels that can be met cost-competitively via GOES, as 
discussed in section V.A. DOE has also, in response to stakeholder 
feedback, modified its consumer purchasing behavior model to reflect 
the emphasis that both manufacturers and utilities are placing on lead 
time, wherein consumers continue to purchase a GOES transformer even if 
an amorphous transformer is lower cost up to a certain efficiency 
level, as discussed in section IV.F.3 of this document.
    Finally, the standards finalized in this final rule include several 
equipment classes, representing considerable volume of core material, 
where GOES is expected to remain cost-competitive. DOE estimates the 
volume of core steel used in the equipment classes where GOES is 
expected to remain cost-competitive to be over ~146,000 metric tons for 
liquid-immersed distribution transformers, only a 21 percent reduction 
from the ~185,000 metric tons for liquid-immersed distribution 
transformers assumed in the no-new standards case. DOE also understands 
that manufacturers prefer to continue using existing GOES core 
production equipment, rather than replace GOES core production 
equipment with amorphous core production equipment., Accordingly, DOE 
expects that, for those classes where GOES remains cost-competitive, 
manufacturers will continue purchasing GOES steel, and will do so in 
quantities approximately equal to the existing domestic GOES market. 
Therefore, DOE does not expect a significant decrease in domestic GOES 
sales as a result of this rule.
    DOE notes that core production equipment is somewhat flexible to 
manufacturer a variety of core sizes. As such, if an existing piece of 
GOES core production equipment manufactures cores for 75 kVA, 100 kVA 
and 167 kVA, as an example, manufacturers can meet efficiency standards 
by shifting that equipment to increase 75 kVA and 100 kVA GOES cores 
and adding a new amorphous core production machinery to manufacture 167 
kVA transformers. The resulting set-up results in an increase in total 
transformer core production capacity as the amorphous line is invested 
in as an additive equipment line, as opposed to replacing existing GOES 
production equipment.
c. Transformer Core Production Dynamics
    In the January 2023 NOPR, DOE discussed how transformer 
manufacturers have the option of either making or purchasing 
transformer cores, with some manufacturers choosing to do a mix of the 
two. 88 FR 1722, 1757. DOE further stated that transformer 
manufacturers also have the choice of producing cores domestically or 
producing them in a foreign country and importing them into the U.S. 
This creates three unique pathways for producing distribution 
transformers: (1) producing both the distribution transformer core and 
finished transformer domestically; (2) producing the distribution 
transformer core and finished transformer in a foreign country and 
importing into the United States; (3) purchasing distribution 
transformer cores and producing only the finished transformer 
domestically. Id.
    DOE discussed how each of these unique sourcing pathways has their 
own advantages and disadvantages. Manufacturers who produce cores 
domestically may have the most control over their lead times and supply 
chains but may be more limited in selection of steel grades as a result 
of tariffs on foreign-produced GOES and only having access to one 
domestic manufacturer. Producing cores in a foreign country and 
importing into the U.S., on the other hand, allows for the same in-
house production with access to the entire global market for GOES 
without the tariff on electrical steel, but provides less supply chain 
control and may lead to longer lead times. Finally, purchasing finished 
cores directly allows manufacturers to avoid investing in the labor and 
capital equipment required for core production, but provides the least 
control over delivery lead times and often will result in a higher cost 
per pound of steel when compared to manufacturers producing their own 
cores. Id.
    In the January 2023 NOPR, DOE assumed that, in the presence of 
amended standards, manufacturers would maintain the same core 
production practices that they currently employ. 88 FR 1722, 1757-1758. 
For manufacturers that produce their own cores, this would mean 
investing in their in-house production processes and purchasing 
additional capital equipment, as required, in order to produce cores 
from higher grades of steel. For manufacturers that purchase finished 
cores, this would mean switching from purchasing cores of one steel 
grade to purchasing cores of a higher steel grade. Further, DOE stated 
that it did not view any one of these core and transformer production 
processes as becoming more advantaged or disadvantaged through amended 
standards and requested comment on whether the proposed standards would 
alter any of the current production pathways. Id.
    A Kansas Congress Member recommended that DOE consider the 
immediate economic impacts that new standards may have on domestic 
steel and transformer manufacturers, energy providers, and developers. 
(Kansas Congress Member, No. 143 at p. 1)
    Schneider commented that the 2016 standards caused many companies 
to shift from slitting steels to outsourcing core production. Schneider 
stated the proposed standards could potentially impact U.S. labor by 
further pushing core assembly to foreign suppliers. (Schneider, No. 92 
at p. 10)
    NEMA commented that GOES cores are both manufactured in-house and 
purchased from third party sources, but stated that distribution 
transformer manufacturers do not have the ability to produce amorphous 
cores internally. (NEMA, No. 141 at pp. 2-3) NEMA stated that the 
proposed standards would force manufacturers to either purchase 
transformer cores, weakening the supply chain, or make substantial 
investments in new capital. Id. NEMA added that there is only a single 
domestic company manufacturing amorphous cores and due to large capital 
costs, new capacity is unlikely to increase in the foreseeable future 
without Federal funding to expand domestic amorphous core 
manufacturing. (NEMA, No. 141 at pp. 2-3) NEMA further stated that the 
capital expenses needed for amorphous cores are likely to increase 
outsourcing of core manufacturing, potentially shifting jobs overseas 
and giving a monopolistic hold to the sole domestic manufacturer of 
amorphous cores. (NEMA, No. 141 at pp. 16-17) DOE notes that multiple 
domestic manufacturers have in-house amorphous core production 
capacity, although typically in substantially lesser volume than GOES 
core production. Substantial capital investments would

[[Page 29902]]

be needed to add amorphous core production capacity. DOE has accounted 
for these capital investments in its MIA as discussed in section IV.J.
    Howard commented that any regulation favoring GOES or amorphous 
will result in single source availability of core steel and encourage 
core offshoring, as tariffs have already done. (Howard, No. 116 at p. 
18)
    MTC expressed concern that the more labor intensive production 
process for amorphous metal cores will push core production outside the 
U.S. (MTC, No. 119 at p. 19)
    The SBA commented that DOE must consider statutory factors 
including ``the impact of any lessening of competition.'' The SBA went 
on to state that there is only one domestic manufacturer of transformer 
cores which is already unable to keep up with demand. (SBA, No. 100 at 
p. 5) DOE notes that there are multiple domestic producers of 
distribution transformers, many of whom also produce cores domestically 
as detailed in Chapter 3 of the TSD.
    Alliant Energy commented that it prefers to procure transformers 
domestically to protect grid security, expressing concern that there is 
currently only one U.S. producer of amorphous core steel with limited 
capacity. (Alliant Energy, No. 128 at pp. 2-3) DOE notes that most 
distribution transformers are produced domestically; however, depending 
on distribution transformer core production dynamics, the core steel in 
those products may or may not be produced domestically. As discussed in 
section IV.A.4.a of this document, both the amorphous and GOES market 
have one domestic producer and multiple global producers with capacity 
largely reflecting current demand.
    Metglas stated that it does not control amorphous core costs, but 
an increased number of amorphous core makers should promote competition 
and drive down costs. (Metglas, No. 125 at p. 6)
    DOE notes that while some stakeholders speculated efficiency 
standards where amorphous cores were most cost competitive would change 
core production dynamics, manufacturer's early responses in 
anticipation of a final rule suggest that a similar core production 
dynamic will exist (see chapter 3 of the TSD for additional details). 
DOE notes that distribution transformer manufacturers have already 
invested in additive facilities to produce amorphous cores domestically 
(and are already producing them).\100\ DOE also notes that core 
manufactures have stated that they are planning on adding new 
facilities to produce amorphous cores in Canada and sell them to 
transformer manufacturers.\101\
---------------------------------------------------------------------------

    \100\ Howard, T. Howard Industries cuts ribbon on Quitman plant, 
The Meridian Star, 2023. Available at www.meridianstar.com/news/howard-industries-cuts-ribbon-on-quitman-plant/article_022f5248-7a7e-11ee-91f9-873895c690d6.html.
    \101\ Worthington Steel, Investor Day. Transcript. Available at 
s201.q4cdn.com/849745219/files/doc_events/2023/Oct/17/worthington-steel-investor-day-transcript-final-10-11-23.pdf.
---------------------------------------------------------------------------

    DOE additionally notes that the adopted standards will maintain 
cost-competitive market segments for both GOES and amorphous. 
Therefore, manufacturers producing their own cores today can continue 
to utilize existing core production equipment.
    Further, distribution transformer manufacturers are already 
investing in manufacturing expansions to support increased capacity 
demands on the electrical grid. In the past several years, 
manufacturers across the distribution transformer market have announced 
expansions of current capacity and intentions expand (some of these 
announced capacity expansions are discussed in chapter 3 of the TSD). 
As such, even without amended standards, manufacturers currently 
producing their own cores would need to invest in additional core 
production equipment to support these capacity additions or make 
alternative core procurement decisions. Therefore, manufacturers will 
have the option to add amorphous production capacity as part of these 
planned expansions in an additive fashion to meet increased demand, 
rather than adding amorphous production capacity to replace existing 
GOES capacity. This will further reduce the capital expenditures that 
manufacturers would be required to incur to meet amended standards, 
mitigating the risk that outsourcing of cores will increase.
    Therefore, for the reasons discussed, DOE continued to assume in 
this final rule that all three core and transformer production pathways 
will remain viable options in the presence of amended standards, with 
manufacturers expected to maintain their current production practices.
5. Distribution Transformer Supply Chain
    The distribution transformer market is divided into three 
segments--liquid-immersed, low-voltage dry-type, and medium-voltage 
dry-type--each of which has unique market dynamics and production 
practices. In recent years, the distribution transformer market has 
experienced significant supply chain challenges across all three 
segments of the market that have largely been attributed to demand for 
distribution transformers, along with other electric grid related 
equipment, increasing substantially. As result, lead times for 
transformers have increased and utility companies' transformer 
inventories have been reduced.
    DOE notes that current shortages in the distribution transformer 
market are unrelated to efficiency standards. Current distribution 
transformer shortages are instead related to a significant increase in 
demand for many electric grid related products, which includes not only 
distribution transformers but many other products associated with 
expansion of the electrical grid not subject to any efficiency 
standards. Distribution transformer manufacturers have reported record 
production, in terms of number of shipments, but still noted that 
demand has grown even faster.\102\
---------------------------------------------------------------------------

    \102\ TB&P, Electric Coops CEO wrestles with ever-evolving 
factors to maintain reliability, affordability, Jan. 15, 2023. 
Available online at: https://talkbusiness.net/2023/01/electric-coops-ceo-wrestles-with-ever-evolving-factors-to-maintain-reliability-affordability/.
---------------------------------------------------------------------------

    PSE commented that lead times for distribution voltage regulators 
are even longer than for distribution transformers and this is unlikely 
to improve if electrical steelmakers are forced to shift to amorphous. 
(PSE, No. 98 at p. 11) DOE notes that voltage regulators are not 
subject to energy conservation standards but serve as an example of how 
product shortages are associated with many electric grid related 
products.
    While numerous expansions of distribution transformer production 
plants have been announced, as discussed in Chapter 3 of the TSD, it 
takes time for those capacity expansions to come online. DOE notes that 
its proposed standards have considered the interaction between capacity 
expansions and conversion investment costs to meet the amended 
efficiency standards. Specifically, DOE adopted standards wherein 
manufacturers can choose to comply using either GOES or amorphous for 
the vast majority of shipments and significantly limited the shipments 
that can realistically only be met with amorphous cores. Stakeholders 
have noted that the ability to leverage both GOES and amorphous will 
reduce their electrical steel supply risk, provided development of that 
capability does not disrupt existing product output.\103\
---------------------------------------------------------------------------

    \103\ Markham, I., ERMCO CEO: For an Effective Outcome, Focus on 
Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at: 
https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.

---------------------------------------------------------------------------

[[Page 29903]]

    In response to the January 2023 NOPR, DOE received comments on the 
current state of the distribution transformer market.
    A variety of utility companies, trade associations, and other 
stakeholders commented that increased demand has led to nationwide 
distribution transformer shortages, with utility reserve stocks 
significantly reduced and lead times on the scale of 2 to 4 years. 
(APPA, No. 103 at p. 4; TMMA, No. 138 at p. 2; Indiana Electric Co-Ops, 
No. 81 at p. 1; Fall River, No. 83 at p. 2; Central Lincoln, No. 85 at 
p. 1; NRECA, No. 98 at p. 2; EEI, No. 135 at pp. 6-7, 9-10; Pugh 
Consulting, No. 117 at p. 3; NWPPA, No. 104 at p. 1-2; Entergy, No. 114 
at p. 2; REC, No. 126 at p. 1-2; Xcel Energy, No. 127 at p. 1; Alliant 
Energy, No. 128 at p. 2; NMHC & NAA, No. 97 at p. 3; Portland General 
Electric, No. 130 at pp. 2-3; Webb, No. 133 at p. 1) Accordingly, many 
stakeholders advised against amending efficiency standards due to 
concerns that standards would further exacerbate supply chain 
challenges, increase the cost of transformers, delay transformer 
deliveries, and introduce additional strain on the electrical grid. 
(BIAW, No. 94 at p. 1; TMMA, No. 138 at p. 2; Entergy, No. 114 at p. 2; 
Alliant Energy, No. 128 at p. 1; Idaho Falls Power, No. 77 at pp. 1-2; 
Fall River, No. 83 at p. 1; Joint Associates, No. 68 at p. 2; Central 
Lincoln, No. 85 at p. 1; Chamber of Commerce, No. 88 at p. 3; NRECA, 
No. 98 at pp. 2-3; SBA, No. 100 at p. 5; Pugh Consulting, No. 117 at 
pp. 2-3; HVOLT, No. 134 at p. 6; Exelon, No. 95 at pp. 1-2; REC, No. 
126 at pp. 1-3; Idaho Power, No. 139 at pp. 3, 6; Portland General 
Electric, No. 130 at pp. 1, 4-5; Indiana Electric Co-Ops, No. 81 at p. 
1; NEPPA, No. 129 at p. 3; WEC, No. 118 at p. 3; TVPPA, No. 144 at p. 
2; AISI, No. 115 at pp. 2-3; TVPPA, No. 144 at p. 1-2; NAHB, No. 106 at 
p. 4; CARES, No. 99 at p. 5; APPA, No. 103 at p. 2; Webb, No. 133 at p. 
2; Allen-Batchelor Construction, No. 79 at p. 1; EEI, No. 135 at p. 1) 
NRECA urged DOE to not amend standards and instead focus on other means 
to incentivize amorphous cores without jeopardizing electric 
reliability. (NRECA, No. 98 at p. 8)
    Many elected officials submitted comments describing how their 
local jurisdictions have been impacted by the national shortage of 
distribution transformers, expressing concern that the proposed 
standards could worsen the impacts of this shortage. (New York Members 
of Congress, No. 153 at p. 1; Kansas Congress Member, No. 143 at p. 1; 
Alabama Senator, No. 113 at p. 1; VA, MD, and DE Members of Congress, 
No. 148 at p. 1; Texas Congress Member, No. 149 at p. 1; Florida 
Members of Congress, No. 150 at pp. 1-2; South Dakota Congress Member, 
No. 145 at p. 1)
    EEI attached a joint response to DOE's RFI on the Defense 
Production Act (87 FR 61306) reiterating a request that DOE dedicate 
funding to provide financial support to transformer manufacturers and 
producers of electrical steel. In that request, EEI stated that the 
primary challenges for transformer manufacturers include attracting and 
retaining a strong workforce and uncertainty of whether demand will 
continue to grow. (EEI, No. 135 at pp. 32-43)
    DOE notes that this final rule pertains only to energy conservation 
standards for distribution transformers, and any efforts to amend other 
Federal regulatory programs and policies are beyond the scope of this 
rulemaking.
    Several stakeholders specifically recommended that DOE abandon the 
proposed standard and instead issue a temporary waiver of the existing 
standards to allow more ubiquitous steel components to be used in the 
manufacturing process to increase transformer supplies. (NEPPA, No. 129 
at p. 3; NWPPA, No. 104 at p. 2; TVPPA, No. 144 at p. 2; CARES, No. 99 
at pp. 2-3)
    As discussed, DOE has made modifications to its distribution 
transformer purchasing model to reflect the current challenges 
associated with the distribution transformer supply chain as discussed 
in section IV.F.3 of this document.
    Pugh Consulting commented that the proposed rule will reduce 
competition for electric utilities, distribution transformer 
manufacturers, and home building construction companies. (Pugh 
Consulting, No. 117 at p. 4) DOE notes that its adopted standard allows 
for a diversity of core materials to be used and allows for 
manufacturers to largely maintain existing production equipment. 
Therefore, DOE does not anticipate reduced competition in the 
distribution transformer market. This conclusion is consistent with the 
assessment of the Attorney General as detailed in the letter published 
at the end of this final rule.
    Separately, DOE also received feedback that distribution 
transformer shortages are delaying building projects, negatively 
impacting the housing market and impeding the availability of 
affordable housing in the U.S. (NAHB, No. 106 at p. 2; APPA, No. 103 at 
p. 5; Fall River, No. 83 at p. 1; Cleveland, No. 80 at p. 1; Ivey 
Residential, No. 82 at p. 1; BIAW, No. 94 at p. 1; Pugh Consulting, No. 
117 at p. 4; NMHC & NAA, No. 97 at p. 1, Williams Development Partners, 
No. 84 at p. 1, Kansas Congress Member, No. 143 at p. 1; Allen-
Batchelor Construction, No. 79 at p. 1; Alliant Energy, No. 128 at pp. 
4-6) Several stakeholders also noted that the shortage of transformers 
is limiting the ability of utilities to interconnect new customers 
across the country, thereby impeding economic development in other 
sectors. (Alliant Energy, No. 128 at p. 2; EEI, No. 135 at pp. 10-11)
    Several stakeholders specifically commented that the shortage of 
distribution transformers is delaying the construction of new housing 
developments which increases costs for homebuyers and, in some cases, 
may cause them to lose their rate lock on mortgage interest rates. 
(BIAW, No. 94 at p. 1; NAHB, No. 106 at pp. 4-5; NMHC & NAA, No. 97 at 
pp. 1-4; LBA, No. 108 at pp. 1-3)
    Stakeholder comments demonstrate how distribution transformers play 
an integral role in the electrical grid, and how the impact that a 
shortage of transformers can have across industry and especially in 
certain infrastructure-oriented segments such as the housing market. 
DOE notes that the transformer industry is actively responding to 
current shortages of distribution transformers, with multiple major 
suppliers having announced capacity expansions in recent months and 
years (as discussed in chapter 3 of the TSD). While additional capacity 
takes time to build and the effects will not be immediately felt by the 
broader distribution transformer market, once online, these capacity 
expansions should help alleviate some of the current supply challenges.
    DOE notes that, historically, amended efficiency standards have not 
significantly increased transformer lead times, and current transformer 
shortages began occurring long after the most recent energy 
conservation standards went into effect. This is demonstrated by the 
producer price index time series data for the electric power and 
specialty transformer industry, which shows relatively steady pricing 
from 2010 to 2020 followed by significant price increases starting in 
2021.\104\ However, DOE acknowledges that if investments in conversion 
costs compete with needed investments in capacity expansions, lead 
times for distribution

[[Page 29904]]

transformers could increase. At the same time, investment in new 
amorphous production equipment could allow for higher efficiency 
standards for specific equipment classes, while shifting existing 
production equipment to increase production of other equipment classes, 
thereby increasing total capacity to produce distribution transformers. 
DOE has considered the impact that amended standards could have on 
distribution transformers costs in section IV.C.2 of this document.
---------------------------------------------------------------------------

    \104\ U.S. Bureau of Labor Statistics, Producer Price Index by 
Industry: PPI industry data for Electric power and specialty 
transformer mfg, not seasonally adjusted., Available online at: 
https://www.bls.gov/ppi/databases/ (retrieved on 03/17/2024).
---------------------------------------------------------------------------

    Several stakeholders specifically expressed concern that shortages 
of distribution transformers will reduce grid reliability, potentially 
impeding the ability of utilities to restore power following natural 
disasters and in emergency situations. (EEI, No. 135 at pp. 16-17, 28-
29; Michigan Members of Congress, No. 152 at p. 1; Alliant Energy, No. 
128 at p. 2; Portland General Electric, No. 130 at pp. 4-5, Pugh 
Consulting, No. 117 at p. 6; Florida Members of Congress, No. 150 at 
pp. 1-2; Entergy, No. 114 at p. 3; APPA, No. 103 at p. 12; Exelon, No. 
95 at p. 3)
    Other stakeholders commented that transformer shortages are 
negatively impacting grid resilience and modernization, and recommended 
that DOE prioritize restoring a steady supply of distribution 
transformers, which would facilitate electrification efforts. (Chamber 
of Commerce, No. 88 at p. 3; CARES, No. 99 at p. 2; EEI, No. 135 at pp. 
4-5; Pugh Consulting, No. 117 at p. 7; Exelon, No. 95 at p. 4; Xcel 
Energy, No. 127 at p. 1; Alliant Energy, No. 128 at p. 3; Alliant 
Energy, No. 128 at p. 4; NMHC & NAA, No. 97 at p. 3; Ivey Residential, 
No. 82 at p. 1; NWPPA, No. 104 at pp. 1-2; New York House 
Representatives, No. 153 at p. 1; Michigan Members of Congress, No. 152 
at p. 1; Florida Members of Congress, No. 150 at p. 1)
    Portland General Electric commented that it has made changes to 
reduce the impact of shortages on its customers, such as delaying non-
critical, non-customer jobs and exploring new sources, including 
offshore manufacturers, for refurbished transformers. (Portland General 
Electric, No. 130 at p. 3) Similarly, WEC commented that it has taken 
drastic steps to address the transformer shortages, and any additional 
supply chain issues will further limit the company's ability to support 
Federal and State grid resiliency initiatives, such as storm hardening 
and increasing capacity to support electric-vehicle-charging and solar 
installations. (WEC, No. 118 at p. 2)
    EVgo commented that the distribution transformer supply chain 
shortages are impacting deployment of EV charging infrastructure and 
encouraged DOE to prioritize adequate supply of transformers so that 
regulations do not hamper EV charger deployment goals. (EVgo, No. 111 
at pp. 1-2)
    APPA commented that this rulemaking will increase lead times by 6-
20 months and worsen supply chain constraints, which would negatively 
impact larger electrification efforts. (APPA, No. 103 at pp. 1-2, 6-7) 
NEMA commented that the proposed standards will increase production 
time and will negatively impact electrification and grid resiliency 
efforts while weakening domestic manufacturing capacity. (NEMA, No. 141 
at pp. 1, 5) NEPPA commented that the proposed standards are infeasible 
and may inhibit electric grid reliability, electrification, and 
modernization goals. (NEPPA, No. 129 at p. 1)
    NYSERDA commented that it anticipates a surge of distribution 
transformer installations as utilities make up for recent pandemic-
related supply chain delays. NYSERDA further stated that any delay of 
standards could result in a significant number of less efficient 
transformers remaining in service well beyond 2050. (NYSERDA, No. 102 
at p. 2)
    DOE recognizes that a stable transformer supply chain will be 
essential to grid modernization. However, DOE disagrees with the notion 
that amended standards stand in opposition of those goals. As pointed 
out by the CEC, increasing transformer efficiency saves energy that 
would otherwise need to pass through the electrical grid, thereby 
reducing strain on the electrical grid. Further, as stated by NYSERDA, 
delaying efficiency standards for distribution transformers in a time 
when additional capacity is expected to come online in the near-to 
medium-term would result in the loss of significant energy savings 
which could otherwise be realized. As discussed above, providing 
certainty as to future transformer efficiency standards could 
incentivize manufacturers to invest in more efficient core production 
technology in an additive fashion that diversifies core materials and 
increases overall production in the near term. DOE also notes that the 
adopted standard levels provide the maximum improvement in energy 
efficiency while still being technologically feasible and economically 
justified. As discussed further, DOE has included in its consideration 
of whether efficiency standards are justified the potential effect that 
a given standard would have on existing distribution transformer 
shortages, on the domestic electrical steel supply, and on projected 
changes to the transformer market to support electrification.
    DOE also received feedback on how the proposed rule might impact 
costs to consumers because of the effect that standards would have on 
the transformer supply chain.
    Several stakeholders commented that the added costs of using 
amorphous core transformers, both in the original purchase price and 
increased installation/maintenance costs, will be borne by the end 
consumer. (NEPPA, No. 129 at p. 3; REC, No. 126 at p. 2; TMMA, No. 138 
at p. 3; Fall River, No. 83 at p. 2; Idaho Falls Power, No. 77 at p. 1) 
NEPPA commented that during the 2016 rulemaking process, utilities and 
manufacturers predicted that forcing increased efficiency levels would 
cause increases to both per-unit cost and lead times. (REC, No. 126 at 
p. 2) NEPPA commented that prices are currently up to four times the 
predicted price and lead times are upwards of 188 weeks compared to 90-
percent shorter lead times just a few years ago, with many suppliers 
not even providing a guaranteed price or lead time to small-volume 
purchasers. (NEPPA, No. 129 at p. 2)
    Portland General Electric further stated that prices are spiking as 
utilities seek more transformers and that utilities are in a precarious 
position as they commit to buying and storing more transformers than 
may actually be needed. (Portland General Electric, No. 130 at p. 3) 
Webb advised against amending efficiency standards given the current 
volatility of the transformer market, with high material costs, 
restricted production capacity and labor resources, and increasing raw 
material costs all contributing to high prices and lead times for 
distribution transformers. (Webb, No. 133 at pp. 1-2) WEG commented 
that the initial costs of this rule outweigh the benefits, especially 
when considering current supply chains. (WEG, No. 92 at p. 1)
    DOE notes that the price increases and extended lead times 
currently exhibited in the distribution transformer market do not 
appear to be the direct result of standards amended in the 2013 
Standards Final Rule, as suggested by NEPPA. Rather, the price of 
distribution transformers stayed relative constant for several years 
following the implementation of standards in 2016.\105\

[[Page 29905]]

It was not until late 2020 or early 2021, when significant disruptions 
to the market and industry-wide supply chain challenges began to occur, 
that distribution transformer prices began to significantly increase. 
These price increases were directly correlated to price increases for 
grain oriented electrical steel, which nearly doubled in price from 
2021 to 2023.\106\ These price trends demonstrate how recent price 
hikes for distribution transformers have been more the result of 
increase demand, as opposed to amended efficiency standards. DOE has 
considered the potential impact that amended efficiency standards could 
have on transformer prices in section IV.C.2 of this document.
---------------------------------------------------------------------------

    \105\ U.S. Bureau of Labor Statistics, PPI Commodity data for 
Machinery and equipment-Power and distribution transformers, except 
parts, not seasonally adjusted. Available at data.bls.gov/pdq/SurveyOutputServlet (last accessed Nov. 3, 2023).
    \106\ Metal Miner, Global M3 Price Index. November 2023. 
Available at agmetalminer.com/metal-prices/grain-oriented-electrical-steel/ (last accessed Nov. 3, 2023).
---------------------------------------------------------------------------

    DOE also received comments relating to the specific challenges that 
the transformer supply chain might face in transitioning to amorphous 
cores.
    Portland General Electric commented that a shift to amorphous core 
transformers would lead to even more widespread unavailability of 
distribution transformers as transformer manufacturers retool and 
redesign production, which would require new submittal and approval 
drawings to be provided to utilities. (Portland General Electric, No. 
130 at p. 3) Entergy commented that the proposed standard creates an 
additional supply constraint for distribution transformers, creates 
technical issues that need to be vetted, increases costs, and hampers 
resiliency efforts in an area of the country that is critical to energy 
security. (Entergy, No. 114 at p. 4)
    APPA commented that transformer manufacturers are not expanding due 
to concern that the NOPR would make investments obsolete, concerns over 
electrical steel availability, and labor shortages, which would be 
exacerbated by the additional labor needed to produce amorphous 
transformers. (APPA, No. 103 at p. 6) Webb recommended DOE confirm that 
manufacturers can gear up their factories in a timely manner to 
effectively produce the equipment required for the proposed standards. 
(Webb, No. 133 at pp. 1-2)
    ERMCO and Exelon stated that the proposed rule would divert 
resources from resolving the current transformer supply crisis. (ERMCO, 
No. 86 at p. 1; Exelon, No. 95 at p. 2) ERMCO added that this redirect 
of resources will take focus off meeting current demand, which will 
inevitably open the door for overseas manufacturers to supply the US 
electrical grid. (ERMCO, No. 86 at p. 1) WEG commented that if 
implemented, the proposed standards will significantly reduce the 
supply of distribution transformers to the U.S. (WEG, No. 92 at p. 4) 
Southwest Electric commented that enforcing the proposed standards 
before sufficient capacity for both amorphous core material and copper 
is established could restrict availability of new transformers and 
further increase lead times. (Southwest Electric, No. 87 at p. 3)
    Prolec GE commented that longer cycle times for amorphous could 
reduce production capacity up to 20 percent. (Prolec GE, No. 120 at p. 
3) Similarly, Prolec GE commented that thinner laminations for lower-
loss GOES grades affect total mill production capacity and make it 
difficult to justify shifting production to lower-loss steels. (Prolec 
GE, No. 120 at p. 10)
    Eaton commented that prolonged labor and supply chain challenges 
have driven lead times up to 18 months for LVDT units and ranging from 
2 to 4 years for liquid immersed units. Eaton added that a forced 
transition to amorphous will require multiple development projects and 
significant capital investment, exacerbating existing labor and 
material supply issues. (Eaton, No. 137 at pp. 2-3) Howard commented 
that the NOPR has created uncertainty causing electrical steel 
manufacturers not to build new silicon steel plants at a time when they 
are desperately needed. Howard stated that even absent amended 
standards, additional electrical steel capacity is needed to serve the 
EV market and increasing efficiency standards magnify these 
requirements. (Howard, No. 116 at p. 2) Howard went on to state that 
virtually all components of transformers are experiencing a shortage 
right now driven by the limited number of suppliers and global labor 
and material shortages. Howard encouraged DOE to delay the 
implementation of any standards until the existing transformer shortage 
is resolved and lead times are back to normal. (Howard, No. 116 at pp. 
4-5) Hammond commented that it has expanded capacity by 20 percent in 
2020, with another 20 percent planned in 2023, but has still been 
struggling to meet demand. Hammond added that all of the expanded 
capacity is for GOES core construction, not amorphous. (Hammond, No. 
142 at p. 2) ABB stated that the transformer industry will be unable to 
provide an adequate supply of transformers to fuel grid modernization 
without a robust supply of transformer core steel. (ABB, No. 107 at p. 
3)
    SolaHD commented that distribution transformers are already very 
efficient, and due to the intricate designs, increasing efficiency by 
even a fraction of a percent could add weeks or months to lead times. 
(SolaHD, No. 93 at p. 2) SolaHD expressed concern that the proposed 
standards will worsen existing lead times, which are currently over 16 
months times for medium- and high-voltage distribution transformers and 
6-8 weeks for the LVDT units that SolaHD produces. SolaHD added that 
this might delay national efficiency improvements and electrification 
initiatives. (SolaHD, No. 93 at pp. 1-2)
    SolaHD, ABB, NEMA, and APPA commented that the administration 
clearly recognized the severity of the current supply chain crisis for 
transformers given the use of the Defense Production Act to prioritize 
domestic transformer production. (SolaHD, No. 93 at p. 2; ABB, No. 107 
at p. 3; NEMA, No. 141 at pp. 1-2; APPA, No. 103 at p. 5) Environmental 
and Climate Advocates commented that funds from the Bipartisan 
Infrastructure Bill and the Inflation Reduction Act can be used by 
utilities and buildings owners to cover the costs of new transformers. 
(Environmental and Climate Advocates, No. 122 at p. 2)
    As previously stated, DOE notes the distribution transformer market 
is in a unique position in which capacity needs to be added to meet 
demand, regardless of the implementation of standards. This provides 
the opportunity for industry to bring capital equipment online through 
additions to existing capacity. In light of these comments, DOE has 
evaluated an additional TSL in which certain equipment classes remain 
at efficiency levels that can cost-competitively be met via GOES. DOE 
notes the adopted efficiency levels allows GOES to remain cost-
competitive for a substantial volume of distribution transformer 
shipments, meaning that manufacturers can retain their existing capital 
equipment, thereby not worsening near-term supply chain issues.
    DOE also notes that the standards adopted in this final rule will 
allow distribution transformers to cost-competitively utilize existing 
GOES capacity across many kVA ratings. As discussed, core production 
equipment generally carries flexibility to manufacture a range of core 
sizes. As such, if an existing piece of GOES core production equipment 
manufactures cores for 75 kVA, 100 kVA and 167 kVA, as an example, 
manufacturers can meet efficiency standards by shifting that equipment 
to increase 75 kVA and 100 kVA GOES cores and adding a new

[[Page 29906]]

amorphous core production machinery to manufacture 167 kVA 
transformers. The resulting arrangement results in an increase in total 
transformer core production capacity as the amorphous line is invested 
in as an additive equipment line, as opposed to replacing existing GOES 
production equipment.
    Further, DOE notes that the compliance period for amended standards 
has been extended beyond what was proposed in the January 2023 NOPR. 
DOE believes the additional time provided to redesign transformers and 
build capacity will further mitigate the risk of disrupting production 
necessary to meet current demand.

B. Screening Analysis

    DOE uses the following four screening criteria to determine which 
technology options are suitable for further consideration in an energy 
conservation standards rulemaking:
    (1) Technological feasibility. Technologies that are not 
incorporated in commercial products or in commercially viable, existing 
prototypes will not be considered further.
    (2) Practicability to manufacture, install, and service. If it is 
determined that mass production of a technology in commercial products 
and reliable installation and servicing of the technology could not be 
achieved on the scale necessary to serve the relevant market at the 
time of the projected compliance date of the standard, then that 
technology will not be considered further.
    (3) Impacts on product utility. If a technology is determined to 
have a significant adverse impact on the utility of the product to 
subgroups of consumers, or result in the unavailability of any covered 
product type with performance characteristics (including reliability), 
features, sizes, capacities, and volumes that are substantially the 
same as products generally available in the United States at the time, 
it will not be considered further.
    (4) Safety of technologies. If it is determined that a technology 
would have significant adverse impacts on health or safety, it will not 
be considered further.
    (5) Unique-pathway proprietary technologies. If a technology has 
proprietary protection and represents a unique pathway to achieving a 
given efficiency level, it will not be considered further, due to the 
potential for monopolistic concerns.

10 CFR 431.4; 10 CFR part 430, subpart C, appendix A, 6(c)(3) and 7(b).

    In sum, if DOE determines that a technology, or a combination of 
technologies, fails to meet one or more of the listed five criteria, it 
will be excluded from further consideration in the engineering 
analysis. The reasons for eliminating any technology are discussed in 
the following sections.
    The subsequent sections include comments from interested parties 
pertinent to the screening criteria, DOE's evaluation of each 
technology option against the screening analysis criteria, and whether 
DOE determined that a technology option should be excluded (``screened 
out'') based on the screening criteria.
1. Screened-Out Technologies
    In the January 2023 NOPR, DOE screened-out the technology options 
listed in Table IV.6 and detailed the basis for screening in chapter 4 
of the NOPR TSD.\107\ DOE did not receive any comments on the screened-
out technology options. As such, DOE has retained those technology 
options as screened-out.
---------------------------------------------------------------------------

    \107\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
    [GRAPHIC] [TIFF OMITTED] TR22AP24.533
    
2. Remaining Technologies
    Through a review of each technology, DOE concludes that the 
remaining combinations of core steels, winding configurations and core 
configurations as combinations of ``design options'' for improving 
distribution transformer efficiency met all five screening criteria to 
be examined further as design options in DOE's final rule analysis.
    DOE determined that these technology options are technologically 
feasible because they are being used or

[[Page 29907]]

have previously been used in commercially available products or working 
prototypes. DOE also finds that all of the remaining technology options 
meet the other screening criteria (i.e., practicable to manufacture, 
install, and service; do not result in adverse impacts on consumer 
utility, product availability, health, or safety; and do not utilize 
unique-pathway proprietary technologies). For additional details, see 
chapter 4 of the final rule TSD.
    DOE received comments from certain stakeholders suggesting that 
amorphous cores should be screened out as a technology option.
    Regarding use of amorphous cores in high-kVA distribution 
transformers, Eaton commented that it is not aware of any amorphous 
core transformers that are commercially available beyond 1,500 kVA and 
therefore DOE should screen-out amorphous cores for distribution 
transformers beyond 1,500 kVA. (Eaton, No. 137 at p. 19) Eaton stated 
that manufacturers would need to resolve technical challenges before 
manufacturing amorphous cores over 1,500 kVA and therefore DOE should 
not evaluate efficiency standards for transformers above 1,500 kVA that 
cannot be met with GOES. (Eaton, No. 137 at p. 26) TMMA commented that 
amorphous is unproven for transformers larger than 2,500 kVA and 
therefore it is not clear that the proposed standards are technically 
feasible. (TMMA, No. 138 at p. 3) Prolec GE commented that amorphous is 
not proven all the way up to 5,000 kVA. (Prolec GE, No. 120 at p. 3) 
LBA commented that amorphous transformers have more limited capacity, 
which will require manufacturers to increase the number of 
transformers. (LBA, No. 108 at p. 3)
    Carte commented that amorphous cores are highly susceptible to any 
outside pressure on the cores and as such cannot be used to secure the 
coils inside a transformer on larger kVA. (Carte, No. 140 at p. 2) 
Carte stated that certain manufacturers had not built amorphous core 
transformers beyond certain sizes due to these clamping limitations and 
encouraged DOE to investigate if large amorphous cores could be built. 
(Carte, No. 140 at p. 2) Carte added that developing new technology to 
be able to brace large amorphous cores could take years and cost 
hundreds of thousands of dollars. (Carte, No. 140 at p. 2)
    DOE notes that amorphous transformers do exist over 1,500 kVA. 
Numerous foreign manufacturers advertise both liquid-immersed and MVDT 
distribution transformers above 1,500 kVA. One manufacturer in Korea 
markets 15,000 kVA amorphous oil-immersed transformers, with deliveries 
as early as 2007, and markets amorphous MVDT units up to 5,000 
kVA.\108\ One manufacturer in India markets amorphous liquid-immersed 
distribution transformers up to 5,000 kVA.\109\ Dating back to the 
early 2010's, ABB offered an amorphous MVDT unit up to 4,000 kVA.\110\ 
Further, in public utility bid data, DOE has observed numerous 
manufacturer bids for 2,500 kVA amorphous core distribution 
transformers (see chapter 4 of the TSD). While Carte is correct that 
amorphous cores do not have the same inherent mechanical strength as 
GOES, manufacturers have developed core clamps and bracing to provide 
the necessary mechanical strength. In some cases, this may even include 
using a strip of GOES steel on the exterior of an amorphous core to 
provide additional mechanical strength.\111\
---------------------------------------------------------------------------

    \108\ Cheryong Electric, Power Products. Available at 
en.cheryongelec.com/eng/library/catalog.php.
    \109\ Kotsons, Power & Distribution Transformers. Available at 
www.kotsons.com/assets/images/Broucher.pdf.
    \110\ ABB, Responding to a changing world: ABB launches new dry-
type transformer products, 2012. Available at library.e.abb.com/public/74cdbc97d4588a1cc1257ab8003a00b5/22-27%20sr105a_72dpi.pdf.
    \111\ Advanced Amorphous Technology, About Amorphous 
Distribution Transformer. Available at advancedamorphous.com/about-amorphous-distribution-transformer/ (last accessed Oct. 17, 2023).
---------------------------------------------------------------------------

    Regarding use of amorphous cores in LVDT distribution transformers, 
Hammond commented that the performance of amorphous cores degrades 
above 160C and LVDTs frequently are rated with an insulation system 
capable of 220C, so there is insufficient technical data to understand 
how amorphous cores will perform long term in LVDT applications. 
(Hammond, No. 142 at pp. 2-3)
    SolaHD expressed concern that amorphous cores are largely untested 
for LVDT distribution transformers, stating that amorphous cores are 
less flexible and more expensive than GOES. (SolaHD, No. 93 at p. 2) 
Schneider commented that amorphous will increase the sound emitted from 
distribution transformers, which likely won't be an issue for products 
installed outdoors or in large electrical rooms but may be an issue for 
LVDTs, which are typically in smaller rooms. (Schneider, No. 101 at p. 
14) Eaton commented that there is a lack of technical data to validate 
the performance of amorphous cores for LVDT transformers. Eaton further 
stated that developing manufacturing processes for amorphous LVDT 
transformers will require significant investment, years of research and 
development, and impact required accuracy to meet customer 
specifications. (Eaton, No. 137 at p. 41)
    DOE notes that Hammond did not provide any data or modeling as to 
the change in transformer core performance above 160C. However, 
distribution transformer temperature rise is governed by transformer 
losses. A more efficient transformer may not ever meet the insulation 
temperature limits. In the case of amorphous dry-type transformers, 
Schneider commented regarding K-factor rated transformers that computer 
modeling suggests that the reduced losses of amorphous LVDT units would 
place the thermal characteristics well below the insulation material. 
(Schneider, No. 101 at pp. 5-6) Further, in the amorphous LVDT and MVDT 
products marketed in international markets, it is common for 
transformers to be marketed with Class H or Class F insulation, 
corresponding to 150C and 115C temperature rise, or 220C and 185C 
performance.112 113 A comparison of the performance of these 
LVDT units to DOE modeled units is given in chapter 5 of the TSD and 
indicates that it is technically feasible to build LVDTs with amorphous 
cores that satisfy common customer specifications.
---------------------------------------------------------------------------

    \112\ Toyo Electric, ``Dry-type Amorphous core transformer.'' 
Available at www.toyo-elec.co.jp/en/products/dry-type-amorphous-core-transformer/ (last accessed Oct. 2023).
    \113\ Chu Lei Electric Co., ``Amorphous Transformers.'' 
Available online at: www.powertransformer.com.tw/en/amorphous-
transformers.html (last accessed Oct. 2023).
---------------------------------------------------------------------------

    APPA stated that rewinding transformers, rather than purchasing a 
new transformer, can result in a lower cost and shorter lead time for 
utilities. (APPA, No. 103 at pp. 11-12) APPA commented that utilities 
today are rewinding up to 15 percent of their transformers due to the 
significant lead times. (APPA, No. 103 at pp. 11-12). APPA commented 
that the ability to rewind GOES transformers is a consumer utility that 
would be lost if DOE standards require amorphous cores. (APPA, No. 103 
at pp. 11-12)
    APPA stated that GOES transformer rewinding equipment is 
incompatible with amorphous cores and notes that amorphous rewinding 
equipment is far more complex and expensive. (APPA, No. 103 at pp. 11-
12) DOE notes that amorphous core transformers can also be rewound, as 
acknowledged by APPA, and therefore DOE disagrees that the ability to 
rewind a transformer is lost if an amorphous core is used.
    DOE notes that the transformer rebuilding/rewinding market has 
historically been relatively small. Rewinding a distribution 
transformer

[[Page 29908]]

requires additional labor (because labor is required both to 
deconstruct the transformer and rebuild it) that has made replacing a 
distribution transformer the preferred option when a transformer fails. 
While recently there has been an uptick in transformer rewinding, that 
is primarily a function of long lead times for new transformers.
    Regardless of the core steel used to meet efficiency standards, 
rewinding of GOES transformers will continue to be an option for 
utilities for as long as existing GOES transformers remain in the 
field. Given that rewinding of transformers does not typically occur 
until late in a distribution transformer's lifetime, any existing 
utility investment in rewinding equipment will likely be used on the 
existing stock of transformers for many decades. Any investment in 
amorphous core rewinding equipment would likely be in an additive 
function and not impact near or medium-term ability to rewind 
transformers.
    DOE notes that amorphous core transformers have been used as a 
technology option for high-efficiency transformers for many decades. 
While there are conversion costs, required to transition from producing 
GOES cores to amorphous cores, those costs are considered in the 
manufacturer impact analysis. Additionally, while amorphous cores are 
different than GOES cores and require a degree of technological 
understanding to properly use amorphous core transformers, the vast 
majority of liquid-immersed transformer manufacturers have some 
experience building amorphous core transformers, and numerous foreign 
manufacturers produce amorphous core transformers spanning a range of 
product classes. Further, manufacturers have the option to purchase 
finished amorphous cores from third-party electrical processing 
companies, which provides another avenue to producing amorphous core 
transformers. Based on the foregoing discussion, DOE has retained 
amorphous cores as a technology option for achieving higher efficiency 
standards in distribution transformers.

C. Engineering Analysis

    The purpose of the engineering analysis is to establish the 
relationship between the efficiency and cost of distribution 
transformers. There are two elements to consider in the engineering 
analysis; the selection of efficiency levels to analyze (i.e., the 
``efficiency analysis'') and the determination of product cost at each 
efficiency level (i.e., the ``cost analysis''). In determining the 
performance of higher-efficiency equipment, DOE considers technologies 
and design option combinations not eliminated by the screening 
analysis. For each equipment class, DOE estimates the baseline cost, as 
well as the incremental cost for the product/equipment at efficiency 
levels above the baseline. The output of the engineering analysis is a 
set of cost-efficiency ``curves'' that are used in downstream analyses 
(i.e., the LCC and PBP analyses and the NIA).
1. Efficiency Analysis
    DOE typically uses one of two approaches to develop energy 
efficiency levels for the engineering analysis: (1) relying on observed 
efficiency levels in the market (i.e., the efficiency-level approach), 
or (2) determining the incremental efficiency improvements associated 
with incorporating specific design options to a baseline model (i.e., 
the design-option approach). Using the efficiency-level approach, the 
efficiency levels established for the analysis are determined based on 
the market distribution of existing products (in other words, based on 
the range of efficiencies and efficiency level ``clusters'' that 
already exist on the market). Using the design option approach, the 
efficiency levels established for the analysis are determined through 
detailed engineering calculations and/or computer simulations of the 
efficiency improvements from implementing specific design options that 
have been identified in the technology assessment. DOE may also rely on 
a combination of these two approaches. For example, the efficiency-
level approach (based on actual products on the market) may be extended 
using the design option approach to interpolate to define ``gap fill'' 
levels (to bridge large gaps between other identified efficiency 
levels) and/or to extrapolate to the ``max-tech'' level (particularly 
in cases where the ``max-tech'' level exceeds the maximum efficiency 
level currently available on the market).
    For this final rule analysis, DOE used an incremental efficiency 
(design-option) approach. This approach allows DOE to investigate the 
wide range of design option combinations, including varying the 
quantity of materials, the core steel material, primary winding 
material, secondary winding material, and core manufacturing technique.
    For each representative unit analyzed, DOE generated hundreds of 
unique distribution transformer designs by contracting with Optimized 
Program Services, Inc. (OPS), a software company specializing in 
distribution transformer design. The OPS software uses two primary 
inputs: (1) a design option combination, which includes core steel 
grade, primary and secondary conductor material, and core 
configuration, and (2) a loss valuation.
    DOE examined number design option combinations for each 
representative unit. The OPS software generated 518 designs for each 
design option combination based on unique loss valuation combinations. 
Taking the loss value combinations, known in industry as A and B values 
and representing the commercial consumer's present value of future no-
load and load losses in a distribution transformer respectively, the 
OPS software sought to generate the minimum TOC. TOC can be calculated 
using the equation below.

TOC = Transformer Purchase Price + A * [No Load Losses] + B * [Load 
Losses]
a. Representative Units
    Distribution transformers are divided into different equipment 
classes, categorized by the physical characteristics that affect 
equipment efficiency. DOE's current equipment classes are detailed in 
section IV.A.2.
    Because it is impractical to conduct detailed engineering analysis 
at every kVA rating, DOE conducts detailed modeling on ``representative 
units'' (RUs). These RUs are selected both to represent the more common 
designs found in the market and to include a variety of design 
specifications to enable generalization of results.
    DOE detailed the specific RUs used in the NOPR analysis and those 
units' characteristics in chapter 5 of the NOPR TSD.\114\ Each RU 
represents an individual transformer model referred to by a specific RU 
number (e.g., RU1, RU2, etc.). DOE requested comment on its 
representative units as well as any data for potential equipment that 
may have a different cost-efficiency curve than those that can be 
represented by the representative units. 88 FR 1722, 1759-1760.
---------------------------------------------------------------------------

    \114\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
---------------------------------------------------------------------------

    Regarding the characteristics of the representative units, Carte 
commented that RU3 uses a 150 kV BIL when, based on its primary voltage 
of 14.4 kV, it should use a 95 kV BIL or 125 kV BIL. (Carte No. 140 at 
p. 9)
    DOE notes that representative units are selected to represent both 
common designs found on the market and to include a variety of design 
specifications to enable generalization of results. In the case of RU3, 
DOE selected a more conservative BIL rating to assist in generalization 
of result. The

[[Page 29909]]

resulting design would be slightly more costly than a 95 kV BIL or 125 
kV BIL and therefore represents a more conservative design than the 
most common design.
    Regarding any units that have different cost-efficiency curves, 
Carte commented that high-impedance transformers still within the 
normal impedance range can be more challenging to meet efficiency 
standards. (Carte, No. 140 at p. 10) Carte commented that certain high-
BIL transformers can have higher costs in order to meet the current 
efficiency levels as compared to the modeled BIL values. (Carte, No. 
140 at pp. 9-10) Carte also identified multi-voltage transformers, and 
main and teaser transformers as other designs that have a very high-
cost to meet NOPR levels using GOES. (Carte, No. 140 at pp. 9-10) Carte 
commented that meeting NOPR levels with GOES for main and teaser 
transformers increases costs by over 100 percent. (Carte, No. 140 at p. 
9) DOE notes that the data cited by Carte refer to meeting EL 4 without 
using amorphous and does not discuss the cost increase if those same 
transformers were designed using amorphous cores.
    DOE agrees that certain distribution transformers with uncommon 
features may have a more difficult time meeting any given efficiency 
level. However, typically those uncommon features result in higher 
costs both at baseline and under amended efficiency standards. 
Therefore, the incremental costs of building that same transformer are 
similar.
    In the January 2023 NOPR, DOE also noted that while some 
applications may generally have a harder time meeting a given 
efficiency standard, most applications would generally be able to use 
amorphous cores to achieve higher efficiency levels. This includes 
designs at efficiency levels beyond the max-tech efficiency included in 
DOE's analysis. 88 FR 1722, 1759.
    Eaton provided data demonstrating relatively consistent incremental 
costs for a variety of multi-voltage distribution transformers. (Eaton, 
No. 137 at p. 16) Eaton's data showed the cost-efficiency curve for a 
500-kVA distribution transformer with an amorphous core and a variety 
of different primary voltage configurations. Id. Eaton's data showed 
that, depending on the voltage configuration, the baseline cost of a 
given transformer could vary. Id. However, the incremental cost 
associated with meeting any given efficiency level is similar for all 
transformers up until that specific design reaches its ``efficiency 
wall'' wherein the costs begin to increase rapidly.
    As discussed in the January 2023 NOPR, Eaton's data shows that all 
designs for this unit can meet max-tech efficiency levels using an 
amorphous core; however, certain designs may have a harder time meeting 
the max-tech level as evidence by the higher costs. Further, Eaton's 
data shows that all of these designs have a similar incremental cost to 
increase efficiency from a baseline design through the NOPR levels, 
indicating that DOE's analysis is likely sufficient to encompass all of 
these designs.
    While Carte commented that the incremental costs associated with 
meeting higher efficiency values is significant for distribution 
transformers with a variety of characteristics, DOE notes that Carte 
generally was referring to meeting higher standards without transiting 
to amorphous cores. DOE data similarly shows that meeting NOPR 
efficiency levels without using amorphous cores results in a 
significant cost increase. However, if using an amorphous core, higher 
efficiency levels can be met without extreme cost increases.
    Several stakeholders commented regarding potential challenges 
associated with transformers' ability to handle harmonics and the 
potential challenges units would have in meeting efficiency standards.
    Carte commented that solar inverters can create harmonics and 
speculated that the modifications needed to accommodate these harmonics 
may increase losses or not be achievable with amorphous cores. (Carte, 
No. 140 at p. 3) Carte commented that IEEE is evaluating the impact of 
solar generation on power quality and transformer design. Id. Nichols 
commented that the smart grid will have increased harmonics and 
additional control switches will be needed to monitor harmonics in 
addition to the amount of power. (Nichols, No. 73 at p. 1) Eaton 
commented that EV charging is likely to increase the amount of 
harmonics currents on transformers. (Eaton, No. 137 at p. 38)
    Harmonics lead to excess losses in both the transformer core and 
transformer coil. Distribution transformer efficiency is measured using 
a sinusoidal wave function (i.e., a current without harmonics) and 
therefore the impact of harmonic currents is not captured in the DOE's 
test procedure. The primary concern with harmonic currents is that they 
lead to excess heat generation. This excess heat can lead a transformer 
to overheat, even if it is not loaded at its maximum capacity. In 
dealing with harmonic currents, consumers can purchase harmonic 
mitigating transformers, K-factor rated transformers, or intentionally 
oversize transformers such that they never operate near their thermal 
loads. Regarding harmonic mitigating transformers, DOE notes harmonic 
mitigating transformers involve phase-shifted windings, which would be 
an option both at baseline and higher-efficiency levels, including with 
amorphous cores.
    Powersmiths commented that DOE did not consider K-factor rated 
transformers in its representative units, which have larger footprints 
and windings in order to deal with the thermal impacts of harmonic 
currents, and stated that K-factor rated transformers have a lower 
achievable efficiency. (Powersmiths, No. 112 at p. 2) Eaton expressed 
concern that the OPS software may not accurately model the additional 
requirements for data center transformers, such as higher k-factors, 
lower flux density, and adjusted temperature rise. To demonstrate this, 
Eaton provided data comparing the specifications of an OPS design 
without a K-factor rating to the specifications of manufactured data 
center transformers with various K-factor ratings. (Eaton, No. 137 at 
p. 37)
    Regarding modeling a K-factor rated transformer as a representative 
unit, DOE notes that a transformer that has a K-factor rating is 
designed to accommodate the additional thermal stress of equipment 
harmonics. Rather than trying to cancel out harmonic currents, as 
harmonic mitigating transformers do, K-factor rated transformers are 
typically oversized and derated to accommodate the additional heat from 
harmonics. As such, they have larger transformer cores and, therefore, 
higher no-load losses. However, DOE notes that more efficient 
transformers may not ever meet the insulation temperature limits. In 
the case of amorphous dry-type transformers, Schneider commented 
regarding K-factor rated transformers that computer modeling suggests 
that the reduced losses of amorphous LVDT units would result in thermal 
characteristics that are well below the insulation material. 
(Schneider, No. 101 at pp. 5-6) Further, amorphous cores have lower no-
load losses per pound of core material. Hence, transformer with 
additional core material, such as K-factor rated transformers, would 
experience a greater improvement in efficiency relative to a baseline 
transformer. For these reasons, DOE has not included a specific 
representative unit for K-factor rated transformers and

[[Page 29910]]

assumes the current representative units are sufficiently 
representative.
b. Data Validation
    There can be differences between distribution transformer modeling 
and real-world data. In order to ensure DOE's modeled data reflects 
reality, DOE has relied on a variety of manufacturer literature, 
manufacturer public utility bid data, and feedback from stakeholders. 
DOE presented plots demonstrating how real-world data compares with 
modeled data in chapter 5 of the NOPR TSD.\115\
---------------------------------------------------------------------------

    \115\ Available at Docket No. EERE-2019-BT-STD-0018-0060.
---------------------------------------------------------------------------

    Regarding data validation for LVDTs, Powersmiths commented that DOE 
should ensure models meeting the proposed LVDT efficiency standards 
have actually been built because gaps exist between transformer 
modeling and real-world performance. (Powersmiths, No. 112 at p. 2) 
Powersmiths stated that the OPS modeling software does not accurately 
model stray and eddy losses, which for certain high-kVA designs can 
increase significantly and requires comparison of modeling to real 
designs in order to create a feedback loop to ensure the modeled 
designs can actually be built. (Powersmith, No. 112 at pp. 3-4) 
Powersmiths particularly expressed concern that DOE NOPR levels for 
LVDTs are largely based on amorphous core transformers which include 
deviations between the real-world data and the modeled data. 
(Powersmiths, No. 112 at p. 2) Powersmiths recommended that DOE work 
with industry to build, test, and verify modelled designs. 
(Powersmiths, No. 112 at p. 6) Eaton commented that using modeling to 
reflect what is achievable is a valid approach; however, software 
modeling does not necessarily include the manufacturer-to-manufacturer 
variability that exists in the real world. (Eaton, No. 137 at p. 41) 
Hammond commented that their modeling confirms that amorphous cores 
would be used to meet the NOPR efficiency levels for LVDTs. (Hammond, 
No. 142 at p. 2)
    For dry-type transformers, DOE notes that chapter 5 of the NOPR TSD 
presents plots comparing the range of no-load and load loss 
combinations modeled for each representative unit to real world no-load 
and load loss data certified in NRCAN's database. These plots show the 
modeled design space for GOES transformers very closely aligns with the 
real-world design space shown in NRCAN's database. DOE notes that 
Powersmiths did not identify any unique features associated with 
amorphous core LVDTs that would result in the modeling for GOES to be 
accurate while the modeling for amorphous transformers to not be 
accurate. DOE has included additional data points taken from 
manufacturer literature in chapter 5 of the final rule TSD to 
demonstrate the real-world designs of amorphous LVDT transformers. DOE 
notes that this real-world data shows that the modeled amorphous design 
space very closely aligns with the real-world loss performance of 
amorphous core LVDTs.
    For liquid-immersed transformers, DOE has similarly presented a 
comparison of the no-load and load loss combinations modeled in each 
representative unit as compared to real world manufacturer data. These 
plots show the modeled design space for both amorphous and GOES 
transformers very closely aligns with the real-world design space shown 
in manufacturer bid sheets.
    Regarding the accuracy of DOE equipment costs, HVOLT commented that 
DOE's optimization model understates selling prices by as much as 40-50 
percent and suspected that this because some of DOE's designs were 
developed as part of the previous rulemaking. (HVOLT, No. 134 at p. 6)
    DOE notes that the difference between current prices and modeled 
prices is related to the fact that DOE modeling uses a 5-year average 
pricing while current prices for a baseline transformer are higher than 
the 5-year average. DOE's modeled prices have historically been in-line 
with real-world data, indicating that the physical construction of the 
transformers is accurate.
    Current distribution transformer pricing is near its all-time high 
due to shortages. However, because most of the market relies on GOES, 
the price of GOES steel has increased more than the price of amorphous 
alloy. If DOE relied on current spot prices, as HVOLT suggests, the 
cost of the baseline transformer would increase considerably and be 
more in-line with the 40-50 percent increase cited by HVOLT. However, 
higher efficiency levels, particularly those with amorphous cores, 
would become far more cost competitive because amorphous alloy has not 
had the same demand pressure as GOES steel in recent years. DOE has 
updated prices for the final rule, as described in section IV.C.2 of 
this document, to reflect updated 5-year average prices.
    Eaton submitted independently developed cost-efficiency and max-
tech performance curves. Eaton provided a cost-efficiency curve for 
both amorphous and GOES transformers of similar kVA sizes as DOE's RU5 
unit. (Eaton, No. at p. 19) DOE has provided a comparison between 
Eaton's data and DOE's modeled data in chapter 5 of the TSD. In 
general, the two are very closely aligned.
    Eaton stated that its modeling showed some discrepancies between 
some of the max-tech efficiencies modeled by DOE and its max-tech 
efficiencies resulting from scaling representative units to high-kVA 
units. Eaton recommended DOE work with manufacturers to compare its 
modeling to real world max-tech values, particularly for omitted kVA 
ratings in the analysis. (Eaton, No. 137 at p. 20) DOE appreciates 
Eaton's work to validate its modeling and has relied on Eaton's 
modeling, in addition to other data sources, to modify DOE's scaling 
methodology for high-kVA units, as detailed in section IV.C.1.e of this 
document.
c. Baseline Energy Use
    For each product/equipment class, DOE generally selects a baseline 
model as a reference point for each class, and measures anticipated 
changes resulting from potential energy conservation standards against 
the baseline model. The baseline model in each product/equipment class 
represents the characteristics of a product/equipment typical of that 
class (e.g., capacity, physical size). Generally, a baseline model is 
one that just meets current energy conservation standards, or, if no 
standards are in place, the baseline is typically the most common or 
least efficient unit on the market.
    DOE's analysis for distribution transformers generally relies on a 
baseline approach. However, instead of selecting a single unit for each 
efficiency level, DOE selects a set of units to reflect that different 
distribution transformer purchasers may not choose distribution 
transformers with identical characteristics because of difference in 
applications and manufacturer practices. The mechanics of the customer 
choice model at baseline and higher efficiency level are discussed in 
section IV.F.3 of this document.
d. Higher Efficiency Levels
    Regarding evaluating higher efficiency standards, numerous 
stakeholders commented that transformers are already efficient and 
stated that because efficiency is only increased by less than one 
percentage point, amended standards aren't worth the burdens that they 
would impose on manufacturers and the supply chains. (NMHC & NAA, No. 
97 at p. 4; TVPPA, No. 144 at p. 1; APPA, No. 103 at p. 7; Pugh 
Consulting, No. 117 at p. 2; Alabama Senator, No.

[[Page 29911]]

113 at p. 2; Webb, No. 133 at p. 2; CARES, No. 99 at pp. 2-3; AISI, No. 
115 at p. 1; Strauch, No. 74 at p. 1; VA, MD, and DE Members of 
Congress, No. 148 at p. 2; New York Members of Congress, No. 153 at p. 
2; EEI, No. 135 at pp. 44-47)
    REC commented that, while amorphous cores provide a significant 
percentage reduction in losses, the increase in rated efficiency is 
small. (REC, No. 126 at p. 3)
    CEC commented that distribution transformers are ubiquitous, and 
even small improvements to standards can have significant benefits to 
energy generators and distributors, manufacturers, consumers, and the 
environment. (CEC, No. 124 at p. 1)
    Stakeholders are correct in their assessment that currently 
available distribution transformers are typically over 98 percent 
efficient. However, nearly all electricity passes through at least one 
distribution transformer and distribution transformers experience those 
losses 24 hours a day, 365 days per year, across a usable life that 
spans decades. Therefore, the losses from any single transformer, even 
if small in a particular instance, can be substantial in the aggregate 
and make up a considerable portion of a given transformer's total 
ownership costs.
    Further, the efficiency levels proposed in the January 2023 NOPR 
represent a 2.5 to 50 percent reduction in transformer losses. DOE 
conducts its analysis to determine if the benefits of these operating 
cost and energy savings are economically justified. Hence, even though 
the change in efficiency appears to be a small number, the benefits of 
the evaluated efficiency standards may be substantial compared to 
existing performance, as reflected in DOE's analysis.
    In evaluating higher efficiency levels, DOE relies on a similar 
approach to its baseline engineering analysis. DOE's modeled designs 
span the entire design space. In evaluating a higher efficiency level 
up until the max-tech that DOE considers, DOE evaluates the modeled 
units that would exceed the higher efficiency level. Then, rather than 
selecting a single unit, DOE applies a customer choice model to 
evaluate the distribution transformer that would be purchased if 
standards were amended.
    DOE notes that for a given design option combination, the least 
efficient units typically tend to be the lowest cost unit.
    Eaton commented that when meeting higher efficiency levels with 
GOES, manufacturers increase the core cross sectional area and decrease 
the flux density. (Eaton, No. 137 at pp. 21-22) The larger transformer 
cores require thicker conductors in order to maintain current density 
but using thicker conductors increases stray and eddy losses, which 
requires even larger conductor size to combat the additional stray and 
eddy losses. (Eaton, No. 137 at pp. 21-22) Eaton stated that at some 
point, the only option is to transition to copper windings, at which 
point the cost of the transformer skyrockets and significant cost 
increases are needed for even modest efficiency gains. (Eaton, No. 137 
at pp. 21-22)
    HVOLT commented that DOE proposed levels result in several products 
that will hit an efficiency wall where significant cost increases would 
result in very little efficiency improvement. (HVOLT, No. 134 at p. 2) 
HVOLT did not specify which products or clarify if that comment was 
across all core materials or only GOES.
    Prolec GE commented that in their modeling, they found it was 
technically feasible to meet proposed standards with GOES cores and 
copper windings, but they would be at a cost disadvantage relative to 
amorphous cores that could use aluminum windings to meet efficiency 
standards. (Prolec GE, No. 120 at p. 8)
    Powersmiths commented that the proposed standards for LVDTs are at 
max-tech, which does not leave sufficient margin for manufacturing and 
material batch variability. (Powersmiths, No. 112 at p. 2)
    WEG commented that it is possible to reduce transformer losses to 
get halfway to the NOPR standards using a GOES core and copper 
windings, but the cost of the transformer would increase by 60 percent. 
(WEG, No. 92 at p. 1) NEMA commented that meeting the proposed LVDT 
efficiency standards with GOES would result in large weight increases 
and be impractical. (NEMA, No. 141 at p. 6)
    Stakeholder comment is consistent with DOE modeling that it is 
technically feasible to meet many higher efficiency levels with GOES. 
However, beyond some efficiency levels it is no longer the lowest cost 
option. In evaluating higher efficiency levels, beyond a certain 
reduction in losses, transitioning from a GOES steel core to an 
amorphous core becomes by far the most cost effective approach for 
meeting higher-efficiency standards due to the significant reduction in 
no-load losses associated with an amorphous core.
    As noted, the DOE test procedure specifies measuring efficiency at 
50 percent PUL for liquid-immersed and MVDT distribution transformers 
and 35 percent PUL for LVDT distribution transformers. Distribution 
transformer performance at any given PUL can be approximated as no-load 
losses plus load losses multiplied by the square of the PUL. In meeting 
higher efficiency standards, manufacturers can employ design options 
that reduce no-load losses, reduce load losses, or a combination of the 
two. DOE models different design options that reduce both no-load 
losses and load losses and generally relies on manufacturer selling 
prices to determine what consumers are likely to purchase.
    REC stated that if DOE measured energy efficiency at 100 percent 
PUL, the losses of an amorphous transformer could be higher than the 
losses of a GOES transformer. (REC, No. 126 at pp. 2-3) Idaho Power 
commented that it prefers technologies that reduce load losses rather 
than those that improve no-load losses. (Idaho Power, No. 139 at p. 2) 
Cliffs stated that when load levels are at 50 percent or higher, GOES 
transformers outperform amorphous transformers and provided plots to 
demonstrate this. (Cliffs, No. 105 at pp. 16-17) HVOLT recommended that 
DOE not implement any standards that exclude GOES given that amorphous 
cores hit peak efficiency at 20 percent loading and are less efficient 
than GOES above 50 percent loading. (HVOLT, No. 134 at p. 5) Cliffs 
further commented that AM transformers will not be able to sustain grid 
loading requirements, jeopardizing Department of Defense applications 
which rely upon resilient grid systems to supply backup power 
generation for mission requirements. (Cliffs, No. 105 at pp. 8-9)
    NEPPA commented that amorphous cores may have slightly lower no-
load losses than GOES cores, but they typically have higher load 
losses. NEPPA added that as loading levels increase due to 
electrification, amorphous core use does not guarantee overall lower 
losses when transformer loading increases over time. (NEPPA, No. 129 at 
p. 2) Idaho Power further recommended DOE evaluate transformer 
efficiency designs at higher load-losses (above 50 percent) instead of 
targeting increased efficiencies in no-load losses, given expected 
increases in loading with electrification. (Idaho Power, No. 139 at pp. 
2-3) CARES and AISI commented that amorphous transformers are less 
efficient at higher loads and therefore the benefits of the NOPR are 
limited. (CARES, No. 99 at p. 4; AISI, No. 115 at p. 3) MTC commented 
that both low-loss GOES and amorphous core transformers provide similar 
energy savings at higher load factors. MTC provided data for both GOES 
and amorphous designs compliant with the European ECO-1

[[Page 29912]]

and ECO-2 efficiency standards to demonstrate this point. (MTC, No. 119 
at pp. 13-15) MTC added that higher losses above 50 percent loading is 
not ubiquitous for amorphous transformers and is driven by DOE's 
testing requirement at 50 percent load. (MTC, No. 119 at p. 15)
    DOE notes that its analysis considers technologies that reduce both 
no-load losses and load losses. As discussed, both amorphous core 
transformers and GOES core transformers have no-load and load losses 
wherein the no-load losses are approximately constant and the load 
losses vary with loading. DOE evaluates efficiency at 50 percent 
loading for liquid-immersed and MVDT distribution transformers and 35 
percent for LVDT distribution transformers. DOE models any potential 
energy savings by evaluating the actual loading on transformers and 
accounts for both no-load and load losses as discussed in section IV.E 
of this document.
    Cliffs and Carte stated that increasing demand on the electric grid 
will result in distribution transformers frequently operating beyond 50 
percent load, which means that GOES transformers will have higher 
efficiency in the field. (Cliffs, No. 105 at pp. 16-17; Carte, No. 140 
at p. 6) WEG commented that amorphous cores have their peak efficiency 
at lower loads and as loading increases as a result of electrification, 
a GOES design will be better optimized for higher loading. (WEG, No. 92 
at p. 3) WEC and Xcel Energy commented that new load growth, such as 
the load growth associated with adding electric vehicles, will lead to 
load losses becoming more important and no-load losses becoming less 
important. (WEC, No. 118 at p. 1; Xcel Energy, No. 127 at p. 1) Webb 
commented that DOE should confirm amorphous transformers are efficient 
across a broad range of equipment loadings. (Webb, No. 133 at p. 2) 
NEMA commented that certain LVDTs could operate less efficiently if 
average load exceeds 35 percent. (NEMA, No. 141 at p. 6) Hammond 
commented that future electrification may result in many LVDT loaded 
above 35 percent and that puts greater emphasis on load losses, which 
favors GOES over amorphous. (Hammond, No. 142 at p. 2) Efficiency 
Advocates commented and provided data to show that, even under heavy 
load growth which would results in near 100 percent average load by 
2058, DOE's proposed standards would still provide energy savings. 
(Efficiency Advocates, No. 121 at pp. 5-6)
    Regarding the plots cited by Cliffs to support the claim that GOES 
transformers outperform amorphous transformers beyond 50 percent 
loading, DOE notes that Cliffs is making a comparison between a GOES 
and amorphous transformers that are equally efficient at 50 percent 
load. In evaluating higher efficiency standards, DOE makes a comparison 
between the baseline transformer (one purchased under current 
standards) and the transformer that would be purchased under amended 
efficiency standards. The plots cited by Cliffs show that both the GOES 
and amorphous designs at the proposed standards would outperform a 
baseline GOES design up to and beyond 100 percent loading. However, DOE 
notes that the GOES designs are expected to a require a significantly 
higher increase in both cost and weight, making them less favorable 
when compared to a current baseline design.\116\
---------------------------------------------------------------------------

    \116\ See attachment 2 of comment submitted by HVOLT for 
underlying data (HVOLT, No. 134).
---------------------------------------------------------------------------

    Eaton commented that the efficiency of an amorphous transformer can 
be improved at little cost by using larger conductors up until the size 
limits for aluminum conductors, at which point it becomes very 
expensive to reduce losses further. (Eaton, No. 137 at p. 22) Eaton 
commented that it is a misconception that amorphous units are less 
efficient than GOES transformers above 50 percent PUL. (Eaton, No. 137 
at p. 32) Eaton provided similar plots to Cliffs and noted that 
amorphous transformers that were designed to meet the current DOE 2016 
efficiency levels required very little investment in the transformer 
windings due to their very low no-load losses. Id. As such, the 
amorphous core transformer is the lowest weight product but also has an 
efficiency curve that decreases considerably as loading increases. Id.
    Eaton further commented that amorphous transformers designed to 
meet the proposed levels in the January 2023 NOPR include a modest 
investment in the transformer winding such that the efficiency of an 
amorphous design is greater than the baseline GOES design across all 
loading points. (Eaton, No. 137 at p. 32) Eaton stated that the 
incremental weight of the more efficient transformer is only 5.4 
percent relative to the base amorphous design and ~1 percent relative 
to the base GOES design. Id. Eaton noted that while a GOES design can 
still meet the January 2023 NOPR levels and that GOES transformer would 
have a higher efficiency beyond 50 percent load than the amorphous 
transformer, considerably more material is needed, leading to a 50 
percent weight increase. Id.
    Eaton provided an additional design point to represent an amorphous 
design with additional investment windings, which reduces the load 
losses such that the amorphous design is more efficient across all 
loading points than even the GOES design that meets the January 2023 
NOPR levels. Id. Eaton noted that this amorphous transformer can be 
built with an ``extremely modest weight increase of 14.5 percent'' 
relative to the baseline amorphous transformer. Id.
    The data provided by Eaton further confirms that amorphous 
transformers can be designed to maintain high efficiency across the 
entire range of transformer loading. While a baseline GOES transformer 
may exhibit higher efficiency than a baseline amorphous transformer at 
higher loading, both DOE's modeling and stakeholder comment indicate 
that either an amorphous or a GOES transformer designed to meet amended 
efficiency standards would outperform a baseline transformer at all 
loading points. As such, DOE maintains that amorphous transformers 
stand to provide significant energy savings, even if average 
transformer loading were to increase.
    Southwest Electric commented that they used current design data to 
model a baseline transformer and transformers that met the NOPR 
efficiency levels for 3-phase pad-mount transformers ranging from 112.5 
kVA to 3750 kVA. (Southwest Electric, No. 87 at p. 2) Southwest 
Electric stated that in their case, all of the baseline transformer 
designs would use amorphous cores. (Southwest Electric, No. 87 at p. 2) 
Southwest Electric stated that based on their data, simply switching to 
an amorphous core would not be sufficient to meet the NOPR efficiency 
standards and additional investment would be needed in the conductor in 
order to meet the NOPR proposed levels. (Southwest Electric, No. 87 at 
p. 2)
    DOE notes that manufacturer data from both Southwest Electric and 
Eaton suggest that for at least some 3-phase, liquid-immersed units, 
their design software suggest that the lowest cost design to meet 
baseline efficiency standards is using an amorphous core transformer. 
Despite this lower first cost, stakeholders have regularly stated that 
amorphous cores make up a very small percentage of the current 
distribution transformer market. DOE models amorphous core transformers 
across a range of efficiencies. Due to the substantial reduction in no-
load losses associated with amorphous cores, a baseline transformer 
with an amorphous core can meet DOE 2016 efficiency standards with very 
little investment into the transformer windings. In

[[Page 29913]]

evaluating higher efficiency models with amorphous cores, DOE designs 
include additional investment in the transformer windings which reduce 
load losses. DOE incorporates both the additional costs in the 
transformer core and the investment in the transformer windings in its 
analysis.
    Schneider commented that lower losses correspond to lower 
impedance, which will increase the let-through current during short 
circuits. Schneider stated that this will increase the required ratings 
for connected equipment and impact system arc flash studies and 
protection for workers. Schneider further commented that impedance 
limits the impact of harmonics, which protects sensitive electronic 
loads. Schneider added that lower impedance will reduce voltage drop 
internal to LVDT devices. (Schneider, No. 101 at p. 14) APPA commented 
that while within the ``normal'' impedance ranges, amorphous 
transformers tend to have lower impedance which increases likelihood of 
an extremely high fault current. (APPA, No. 103 at p. 13) NEMA 
commented that higher efficiency standards met with GOES results in low 
impedance levels and anything below 4 percent or preferably 5 percent 
makes it difficult to design power systems and choose circuit breakers 
or fuses to handle fault currents. (NEMA, No. 141 at p. 6)
    Metglas commented that impedance is fixed at 5.75 percent for units 
above 500 kVA and easily varied for smaller units. (Metglas, No. 125 at 
p. 5)
    In the January 2023 NOPR, DOE discussed that the design options 
considered in the engineering analysis, including those that utilize 
amorphous metal, span a range of impedance values within the ``normal 
impedance'' range, as currently defined. 88 FR 1722, 1743. The design 
options considered in this final rule continue to span a range of 
impedance values at higher efficiency levels, both for designs that 
utilize GOES and those that utilize amorphous metal. Further, DOE notes 
that, while lower-loss transformer designs often have lower impedances, 
higher efficiency does not necessarily correlate to lower impedance.
    Based on a review of manufacturer literature, DOE found that 
manufacturers often provide a range of impedance values for a given 
design, with customers able to request a specific impedance range to 
fit their application. DOE also observed transformers of varying levels 
of efficiency that provide the same impedance 
offerings.117 118 119 This indicates that options exist to 
increase transformer impedance, even for higher efficiency 
transformers. Therefore, in this final rule, DOE did not further 
separate transformers based on impedance, aside from ensuring that a 
range of normal impedance values are available at higher efficiency 
levels.
---------------------------------------------------------------------------

    \117\ Powersmiths, E-Saver Opal Series, Available at: https://www.powersmiths.com/products/transformers/e-saver-opal-series/ 
(accessed on 3/17/2024).
    \118\ Eaton, General Purpose Ventilated Transformers, Available 
at: https://www.eaton.com/us/en-us/catalog/low-voltage-power-distribution-controls-systems/ventilated-general-purpose-transformers.html (accessed on 3/17/2024).
    \119\ Hammond Power Solutions, HPS Sentinel Energy Efficient 
Distribution Transformers, Available at: https://americas.hammondpowersolutions.com/products/low-voltage-distribution/general-purpose-transformers (accessed on 3/17/2024).
---------------------------------------------------------------------------

e. kVA Scaling
    In the January 2023 NOPR, DOE proposed to expand the scope of the 
distribution transformer definition to include units up to 5,000 kVA. 
88 FR 1722, 1746 To assess the impact and potential energy savings 
associated with the expanded scope, DOE modeled three new 
representative units by using the scaling rules for transformer 
dimensions, weight, no-load losses, and load losses. 88 FR 1722, 1759-
1760. DOE noted that it only includes distribution transformers in its 
downstream analysis if they would meet or exceed current energy 
conservation standards. Because transformers greater than 2,500 kVA 
have not historically been subject to energy conservation standards, 
DOE relied on the consumer choice model to determine the efficiency of 
a typical baseline unit that would be selected in the present market 
based on lowest first-cost. DOE did not consider any units which did 
not meet or exceed the efficiency of this assumed baseline unit. Id. 
DOE requested comment on its approach to modeling these high-kVA 
transformers.
    DOE received numerous comments about scaling of design data for 
units beyond 2,500 kVA.
    Several stakeholders noted that the percentage that stray and eddy 
losses contribute to load losses increases substantially at high-
current values, which typically correspond to high-kVA ratings. 
Therefore, the 0.75 loss scaling cited by DOE does not hold when 
scaling to larger kVA ratings. (Eaton, No. 137 at p. 23; Prolec GE, No. 
120 at pp. 7-9; HVOLT, No. 134 at pp. 6-7; Howard, No. 116 at p. 14; 
NEMA, No. 141 at p. 5; NEMA, No. 141 at p. 14; Powersmiths, No. 112 at 
p. 3)
    Prolec GE commented that several of the high-kVA rated designs 
would be forced to use amorphous under the proposed standards because 
manufacturers would not be able to meet the proposed efficiency levels 
even with GOES and copper windings. (Prolec GE, No. 120 at p. 3) NEMA 
commented that for high-current transformers, it would be impractical 
to meet the NOPR efficiency levels with GOES as the flux density would 
be forced to such low values to make up for the increased buss and load 
losses. (NEMA, No. 141 at pp. 5-6)
    Howard commented that designing transformers to meet the NOPR 
efficiency levels is technically feasible for transformers 2,500 kVA 
and less. However, the proposed standards beyond 2,500 kVA are not 
feasible and therefore DOE should not include them in any amended 
efficiency standards. (Howard, No. 116 at p. 5) Howard and HVOLT stated 
that they have not been able to develop any valid designs, even with 
amorphous cores, that meet the proposed standards at 3,750 kVA or 5,000 
kVA. (Howard, No. 116 at p. 14; HVOLT, No. 134 at p. 7)
    Eaton speculated that OPS modeling uses a constant stray loss 
percentage, which could significantly underestimate the percentage of 
load losses made up by stray losses for large kVA values. (Eaton, No. 
137 at pp. 23-25) DOE notes that stray losses vary based on the design 
specifications of each specific unit modelled using the OPS design 
software and are not applied as a constant percentage of load losses.
    Eaton noted that improper scaling of stray losses in DOE's analysis 
may result in an overestimation of the efficiencies that can be 
achieved and an underestimation of the transformer costs. (Eaton, No. 
137 at p. 25) NEMA commented that for large kVA, high-current designs, 
stray and eddy losses can make up nearly 80 percent of the total load 
losses. (NEMA, No. 141 at pp. 13-14) HVOLT stated that stray and eddy 
losses can increase the load losses of a transformer over 3,000 kVA by 
as much as 50 percent. (HVOLT, No. 134 at p. 6)
    Eaton commented and provided data to show that as conductor sizes 
increase to meet higher efficiency standards, stray losses increase as 
a percentage of total load losses. (Eaton, No. 137 at p. 23) Eaton's 
data shows that a baseline transformer has stray and eddy losses which 
make up about 15 percent of total load losses, whereas at max-tech, 
stray and eddy losses make-up 30 percent of load losses. (Eaton, No. 
137 at p. 23)
    Howard stated that the scaling DOE used to estimate the performance 
of

[[Page 29914]]

3,750 kVA units is not accurate due to the unique challenges associated 
with the high-current densities in these units. (Howard, No. 116 at p. 
15) HVOLT commented that the 0.75 scaling relationship is only accurate 
over a narrow band of parameters and noted that scaling to high kVA 
ratings could result in underestimating winding losses by more than 50 
percent. (HVOLT, No. 134 at p. 6) Howard recommended DOE refer to Annex 
G of IEEE C57.110-2018 to review industry data on stray and eddy losses 
and their relationship with kVA. (Howard, No. 116 at p. 16)
    Eaton referenced DOE's compliance certification management system 
(CCMS) database and noted that the maximum reported percentage 
efficiencies do not increase beyond 1,000 kVA. Eaton stated this was 
evidence that the 0.75 scaling relationship does not hold for higher 
kVA values. (Eaton, No. 137 at pp. 27-28) Eaton noted that in 
evaluating the max-tech in their design software, some of the proposed 
standards for high-kVA transformers were near the technological limit, 
indicating a potential flaw in the 0.75 scaling relationship. (Eaton, 
No. 137 at p. 22)
    Regarding scaling generally, NEMA commented that the 0.75 scaling 
relationship is only applicable across narrow kVA ranges. (NEMA, No. 
141 at p. 4) NEMA commented that one of their members looked at their 
design data for MVDT transformers to investigate how accurate scaling 
transformer costs, no-load losses, and load losses from a 1,500 kVA and 
300 kVA transformer were. (NEMA, No. 141 at p. 4) NEMA's member found 
that the actual scaling factor can vary widely and at times can be much 
more or much less than the DOE scaling factors. (NEMA, No. 141 at p. 4) 
NEMA stated that this variability was a result of constraints on wire 
sizes, impedance ranges, and construction requirements which can result 
in considerably different scaling relationships. (NEMA, No. 141 at p. 
5) NEMA identified the small wire sizes associated with small kVA 
transformers as a very expensive component that skews the cost curve 
for small kVA units. (NEMA, No. 141 at p. 5) NEMA commented that the 
NOPR scaling factors only results in costs and losses that are within 5 
percent across a small range of kVA values and not across the entire 
range of kVA values. (NEMA, No. 141 at p. 4)
    Eaton provided data demonstrating how the max-tech in their design 
software varies based on secondary winding voltage and kVA. (Eaton, No. 
137 at p. 18) Eaton's data shows that max-tech efficiency percentages 
tend to increase as the kVA increase up until a certain point. (Eaton, 
No. 137 at p. 18) Beyond that point, the current, and specifically the 
additional stray and eddy losses associated with the higher currents, 
can make a considerable difference as to the max-tech at a given kVA. 
(Eaton, No. 137 at p. 18) Eaton's data shows that for a 480Y/277 
secondary voltage, the maximum efficiency occurs around 1,500 kVA. 
(Eaton, No. 137 at p. 18)
    Based on the comments received, DOE re-evaluated the accuracy of 
the OPS modeling of stray and eddy losses for the 1,500 kVA units and 
how that modeling varies for high-current transformers. For DOE's 
modeled RU5, corresponding to a 1,500 kVA distribution transformer with 
480Y/277 secondary, OPS modeling indicates that stray and eddy losses 
as a percentage of total load losses typically vary with design and 
with efficiency. While the exact percentage varies depending on the 
unique design specifications (e.g., efficiency, whether copper or 
aluminum windings are used, core steel, etc.) the stray and eddy losses 
for most designs make up between 10-20 percent of total load losses. 
These values align well with the percentage of stray losses submitted 
in Eaton's comment for a similar unit and many of the stray and eddy 
values listed in Annex G of IEEE C57.110-2018. Therefore, DOE has 
concluded that the OPS modeling accurately accounts for stray and eddy 
losses.
    Regarding the scaling of these OPS modeled representative units to 
other kVA ratings that are not individually modeled, DOE notes that 
scaling of units using power laws requires a variety of assumptions to 
remain valid. In chapter 5 of the TSD, DOE notes that these scaling 
relationships are valid if the core configuration, core material, core 
flux density, current density, physical proportions, eddy loss 
proportion, and insulation space factor are all held constant. DOE 
notes that in practical applications, it is rare that all of these are 
constant; however, scaling relationships can be used to establish 
reasonable estimates of performance.
    Real world data can vary depending on what variables are changing 
between transformer designs. The data submitted by NEMA suggests that 
material cost scaling can be as low as 0.14 or as high as 1.13, no-load 
loss scaling can be as low as 0.33 or as high as 0.88, and load loss 
scaling can be as low as 0.51 or as high as 1.02. IEEE C57.110-2018 
shows real world load loss scaling data with transformer kVA for solid 
cast transformers from 630 kVA to 20 MVA. These data show load loss 
scaling of 0.76. Data submitted by Eaton show that DOE's max-tech 
efficiency for 3-phase liquid-immersed distribution transformers are 
within a few tenths of a percentage point for the vast majority of kVA 
ratings, but the accuracy can vary depending on the current in the 
transformer.
    All of the data identified by manufacturers indicate that for the 
vast majority of the kVA ranges, the scaling laws used in the NOPR are 
sufficient to provide reasonable estimates of performance, dimensions, 
costs, and losses. Stakeholder data also indicate that when the stray 
and eddy losses increase substantially, those scaling relationships may 
be less accurate.
    However, stakeholders are correct in pointing out that for very 
high currents, stray and eddy losses may increase substantially such 
that it becomes much more difficult to meet efficiency standards. As 
noted in section IV.A.2.c of this document, industry standards 
recommend high-kVA transformers have higher-secondary voltages. As 
such, currents do not tend to reach problematic values. Beyond 1,500 
kVA, there tend to be considerably more 480Y/277 secondary voltages and 
208Y/120 voltages become relatively rare. However, if a manufacturer 
were to build a transformer with a very high-secondary current, the 
stray and eddy losses would make up a much greater percentage of the 
transformer load losses and, as such, the losses would scale at a 
higher factor. This was pointed out by numerous manufacturers who 
stated that DOE's proposed standards at 3,750 kVA may become 
technologically impossible.
    To account for the change in scaling relationships that occur for 
high kVA transformers with high currents, DOE has established and 
evaluated a separate equipment class for large three-phase transformers 
with kVA ratings greater than or equal to 500 kVA, as discussed in 
section IV.A.2.c of this document. DOE has also revised its high-kVA 
scaled representative units to account for the increase in load losses 
that occurs as a result of growing stray and eddy losses. These scaling 
factors are discussed in chapter 5 of the TSD.
2. Cost Analysis
    The cost analysis portion of the engineering analysis is conducted 
using one or a combination of cost approaches. The selection of cost 
approach depends on a suite of factors, including the availability and 
reliability of public information, characteristics of the regulated 
product, and the availability and timeliness of

[[Page 29915]]

purchasing the equipment on the market. The cost approaches are 
summarized as follows:
     Physical teardowns: Under this approach, DOE physically 
dismantles a commercially available product, component-by-component, to 
develop a detailed bill of materials for the product.
     Catalog teardowns: In lieu of physically deconstructing a 
product, DOE identifies each component using parts diagrams (available 
from manufacturer websites or appliance repair websites, for example) 
to develop the bill of materials for the product.
     Price surveys: If neither a physical nor catalog teardown 
is feasible (e.g., for tightly integrated products such as fluorescent 
lamps, which are infeasible to disassemble and for which parts diagrams 
are unavailable), cost-prohibitive, or otherwise impractical (e.g. 
large commercial boilers), DOE conducts price surveys using publicly 
available pricing data published on major online retailer websites and/
or by soliciting prices from distributors and other commercial 
channels.
    In the present case, DOE conducted the analysis by applying 
material prices to the distribution transformer designs modeled by OPS. 
The resulting bill of materials provides the basis for the manufacturer 
production cost (MPC) estimates for products at various efficiency 
levels spanning the full range of efficiencies from the baseline to 
max-tech. Markups are applied these MPCs to generate manufacturer 
selling prices (MSP). The primary material costs in distribution 
transformers come from electrical steel used for the core and the 
aluminum or copper conductor used for the primary and secondary 
winding. In the January 2023 NOPR, DOE noted that while prices have 
been up in recent years, it is difficult to say for certain how prices 
will vary in the medium to long term and, therefore, DOE relies on a 5-
year average in its base scenario and evaluates how the results would 
change with different pricing scenarios. 88 FR 1722, 1765.
    Regarding the cost analysis generally, WEC commented that based on 
information received from manufacturers, the costs used to support the 
NOPR are out of date and do not reflect current costs. (WEC, No. 118 at 
p. 1) APPA commented that DOE did not consider the recent rapid 
increases in transformer costs; APPA provided data indicating that the 
cost of transformers has increased substantially since 2018. (APPA, No. 
103 at p. 7-8)
    DOE data confirm that prices for distribution transformers have 
been up significantly from their historical averages. However, it is 
difficult to say for certain how those prices will vary in the medium 
to long term. The distribution transformer producer price index was 
approximately constant between 2010 and 2020, a time period that 
included implementation of two sets of energy efficiency standards 
(initial standards went into effect in 2010 and amended standards went 
into effect in 2016). Beginning in 2021, the producer price index of 
distribution transformers began to increase substantially through mid-
2022. Since mid-2022, prices have remained approximately constant.
    As discussed in section IV.A.5 of this document, the current 
distribution transformer shortage is largely driven by a supply-demand 
imbalance that exists across both distribution transformers and many 
electric and grid-related products. Considerable manufacturer 
investments in capacity increases have been publicly announced, 
including new locations which serve to expand accessible local labor 
markets. However, it is difficult to predict with certainty how the 
price of distribution transformers will vary when supply rises 
sufficiently to expected demand. DOE continues to rely on a 5-year 
average in its analysis.\120\ The five-year period preceding this 
rulemaking includes price increases in addition to those accounted for 
in the NOPR. Accordingly, material and transformer prices are generally 
higher in this final rule than in the NOPR. Additional comments on 
specific material prices are discussed in the sections that follow.
---------------------------------------------------------------------------

    \120\ Engineering results with current pricing are included in 
Appendix 5B of the TSD.
---------------------------------------------------------------------------

a. Electrical Steel Prices
    Electrical steel is one of the main material costs in distribution 
transformers and as such makes up a significant percentage of 
manufacturer production costs. Using lower-loss core materials is one 
of the primary tools for improving the energy efficiency of 
distribution transformers. As such, the relative costs associated with 
transitioning from the current baseline core materials to lower-loss 
core materials has a considerable impact on the cost effectiveness of 
amended efficiency standards.
    In the January 2023 NOPR, DOE relied on 5-year average pricing for 
the various grades of electrical steel evaluated. 88 FR 1722, 1765-
1767. In response to stakeholder comments submitted on the August 2021 
Preliminary Analysis TSD that amended standards may introduce higher 
volatility that may make 5-year average prices inaccurate, DOE stated 
that historically, when amended standards have been adopted, core 
material manufacturers have increased capacity of the electrical steel 
grades needed to meet amended efficiency standards. Id.
    DOE stated that substantial volatility has characterized the U.S. 
steel market, including the existing transformer core steel market, 
over the last several decades. From 2000 to 2007, U.S. steel markets, 
and more specifically the U.S. electrical steel market, began to 
experience pressure from several directions. Demand in China and India 
for high-efficiency, grain-oriented core steel contributed to increased 
prices and reduced global availability. Cost-cutting measures and 
technical innovation at their respective facilities, combined with the 
lower value of the U.S. dollar, enabled domestic core steel suppliers 
to become globally competitive exporters.
    In late 2007, the U.S. steel market began to decline with the onset 
of the global economic crisis. U.S. steel manufacturing declined to 
nearly 50 percent of production capacity utilization in 2009 from 
almost 90 percent in 2008. Only in China and India did the production 
and use of electrical grade steel increase for 2009.\121\ In 2010, the 
price of steel began to recover. However, the recovery was driven more 
by increasing costs of material inputs, such as iron ore and coking 
coal, than broad demand recovery.
---------------------------------------------------------------------------

    \121\ International Trade Administration. Global Steel Report. 
Available at legacy.trade.gov/steel/pdfs/global-monitor-report-2018.pdf (last accessed Sept. 1, 2022).
---------------------------------------------------------------------------

    In 2011, core steel prices again fell considerably. At this time, 
China began to transition from a net electrical steel importer to a net 
electrical steel exporter.\122\ Between 2005 and 2011, China imported 
an estimated 253,000 to 353,000 tonnes of electrical steel. During this 
time, China added significant domestic electrical steel production 
capacity, such that from 2016 to 2019 only about 22,000 tonnes were 
imported to China annually. China also exported nearly 200,000 tonnes 
of electric steel annually by the late 2010s.
---------------------------------------------------------------------------

    \122\ Capital Trade Incorporated, Effective Trade Relief on 
Transformer Cores and Laminations, 2020. Submitted as part of AK 
Steel comment at Docket No. BIS-2020-0015-0075 at p. 168.
---------------------------------------------------------------------------

    Many of the exporters formerly serving China sought new markets 
around 2011, namely the United States. The rise in U.S. imports at this 
time hurt domestic U.S. steel manufacturers, such that in 2013, 
domestic U.S. steel stakeholders filed anti-dumping and countervailing 
duty petitions with the U.S. International Trade

[[Page 29916]]

Commission.\123\ The resulting investigation found, however, that 
``industry in the United States is neither materially injured nor 
threatened with material injury by reason of imports of grain-oriented 
electrical steel . . . to be sold in the United States at less than 
fair value.'' \124\
---------------------------------------------------------------------------

    \123\ U.S. International Trade Commission, Grain-Oriented 
Electrical Steel from Germany, Japan, and Poland, Investigation Nos. 
731-TA-1233, 1234, and 1236. September 2014.
    \124\ Id.
---------------------------------------------------------------------------

    In the amorphous ribbon market, the necessary manufacturing 
technology has existed for many decades and has been used in 
distribution transformers since the late 1980s.\125\ In many countries, 
amorphous ribbon is widely used in the cores of distribution 
transformers.\126\ Significant amorphous ribbon use tends to occur in 
regions with relatively high valuations on losses (e.g., certain 
provinces of Canada, certain U.S. municipalities).
---------------------------------------------------------------------------

    \125\ DeCristofaro, N., Amorphous Metals in Electric-Power 
Distribution Applications, Material Research Society, MRS Bulletin, 
Volume 23, Number 5, 1998.
    \126\ BPA's Emerging Technologies Initiative, Phase 1 report: 
High Efficiency Distribution Transformer Technology Assessment, 
April 2020. Available at www.bpa.gov/EE/NewsEvents/presentations/Documents/Transformer%20webinar%204-7-20%20Final.pdf.
---------------------------------------------------------------------------

    Beginning in 2018, the U.S. government instituted a series of 
import duties on aluminum and steel articles, among other items. Steel 
and aluminum articles were generally subject to respective import 
duties of 25 and 10 percent ad valorem.127 83 FR 11619; 83 
FR 11625. Since March 2018, several presidential proclamations have 
created or modified steel and aluminum tariffs, including changes to 
the products covered, countries subject to the tariffs, exclusions, 
etc.\128\
---------------------------------------------------------------------------

    \127\ Ad valorem tariffs are assessed in proportion to an item's 
monetary value.
    \128\ Congressional Research Service, Section 232 
Investigations: Overview and Issues for Congress, May 18, 2021, 
Available at fas.org/sgp/crs/misc/R45249.pdf.
---------------------------------------------------------------------------

    Another recent trend in distribution transformer manufacturing is 
an increase in the rate of import or purchase of finished core 
products. The impact of electrical steel tariffs on manufacturers' 
costs varies widely depending on if manufacturers are purchasing raw 
electrical steel and paying a 25-percent tariff on imported steel, or 
if they are importing finished transformer cores which, along with 
distribution transformer core laminations and finished transformer 
imports, are not subject to the tariffs. Some stakeholders have argued 
that this trend toward importing distribution transformer cores, 
primarily from Mexico and Canada, is a method of circumventing tariffs, 
as electrical steel sold in the global market has been less expensive 
than domestic electrical steel on account of being allegedly unfairly 
traded.129 130 Conversely, other stakeholders have commented 
that this trend predated the electrical steel tariffs and that 
importation of transformer components is often necessary to remain 
competitive in the U.S. market, given the limited number of domestic 
manufacturers that produce transformer laminations and 
cores.131 132
---------------------------------------------------------------------------

    \129\ (AK Steel, Docket No. BIS-2020-0015-0075 at pp. 43-58).
    \130\ (American Iron and Steel Institute, Docket No. BIS-2020-
0015-0033 at pp. 2-5).
    \131\ (Central Maloney Inc., Docket No. BIS-2020-0015-0015 at p. 
1).
    \132\ (NEMA, Docket No. BIS-2020-0015-0034 at pp. 3-4).
---------------------------------------------------------------------------

    On May 19, 2020, the U.S. Department of Commerce (DOC) opened an 
investigation into the potential circumvention of tariffs via imports 
of finished distribution transformer cores and laminations. 85 FR 
29926. On November 18, 2021, DOC published a summary of the results of 
their investigation in a notice to the Federal Register. The report 
stated that importation of both GOES laminations and finished wound and 
stacked cores has significantly increased in recent years, with 
importation of laminations increasing from $15 million in 2015 to $33 
million in 2019, and importation of finished cores increasing from $22 
million in 2015 to $167 million in 2019. DOC attributed these 
increases, at least in part, to the increased electrical steel costs 
resulting from the imposed tariffs on electrical steel. In response to 
its investigation, DOC stated it is exploring several options to shift 
the market toward domestic production and consumption of GOES, 
including extending tariffs to include laminations and finished cores. 
No trade action has been taken at the time of publication of this final 
rule. 86 FR 64606.
    More recently, DOE learned from stakeholders during manufacturer 
interviews and from public comments that pricing of electrical steel 
has risen such that in the current market, the price of foreign 
electrical steel, without any tariffs applied, is similar to the price 
of domestic steel. (Powersmiths, No. 46 at p. 6; Carte, No. 54 at p. 3) 
These recent price increases, particularly in foreign-produced 
electrical steel, were cited as being a result of both general supply 
chain complications and increased demand for non-oriented electrical 
steel from electric motor applications. (NEMA, No. 50 at p. 9; 
Powersmiths, No. 46 at p. 5; Zarnowski, Public Meeting Transcript, No. 
40 at p. 36; Looby, Public Meeting Transcript, No. 40 at p. 37)
    For the January 2023 NOPR, DOE stated that rather than constructing 
sensitivity analysis scenarios to reflect every potential combination 
of factors that may affect steel pricing, DOE relies on a 5-year 
average pricing for its core steel. DOE requested comment on the 
market, prices, and barriers to added capacity for both amorphous and 
GOES. 88 FR 1722, 1767.
    Regarding the impact of other products on GOES and amorphous 
supply, Howard agreed that the price of GOES has increased 
significantly based on NOES becoming a more valuable investment and 
utilizing similar production equipment to GOES, thereby occupying some 
of the production capacity that otherwise would produce GOES, leading 
to material shortages of GOES. (Howard, No. 116 at p. 5) ABB commented 
that shortages of domestic GOES and likely amorphous would require 
transformer manufacturers to import electrical steel and bear the cost 
of tariffs, adding to the cost of transformers. (ABB, No. 107 at p. 3)
    Howard commented that competition for amorphous ribbon is limited 
to low-volume and niche products, including brazing foil and high-
frequency transformers. (Howard, No. 116 at p. 18) Metglas added that 
amorphous is almost exclusively used in distribution transformers, 
without other significant sources of competition. (Metglas, No. 125 at 
pp. 5-6) Efficiency and Climate Advocates commented that the proposed 
rule will improve the transformer supply chain because amorphous does 
not have as much price competition from EVs as GOES. (Efficiency and 
Climate Advocates, No. 154 at p. 1)
    NAHB commented that amorphous metals are used in aerospace, medical 
devices, electric motor parts, and robotics. (NAHB, No. 106 at pp. 10-
11) NAHB stated that demand for both amorphous metals and GOES will 
continue to increase due to grid modernization. Id. NAHB stated that, 
although amorphous metals are not suited to EV motors, they are well 
suited for other applications in EV manufacturing and will experience 
increased demand within that segment of the automotive market. (NAHB, 
No. 106 at pp. 10-11)
    Stakeholder comments confirm that competition from other products 
is greater for GOES than it is for amorphous. These statements 
generally confirm DOE's January 2023 NOPR observations as to how the 
price of

[[Page 29917]]

GOES has risen more in the previous 5-years than the price of amorphous 
alloy.
    Southwest Electric commented that the five-year average price of 
GOES is much lower than the current price of GOES and therefore DOE 
should update its cost models to reflect the more likely costs from 
2023-2027, rather than incorporating the discounted prices that existed 
between 2017 and 2021. (Southwest Electric, No. 87 at p. 3) NEMA 
commented that the pricing of GOES is impacted by global demand and 
stated that some foreign manufacturers of GOES have committed part of 
their production capacity to serving their domestic markets. As such, 
this foreign GOES capacity is no longer available to serve the U.S. 
transformer market. (NEMA, No. 141 at p. 14) NAHB stated that energy 
rationing policies in China increased electrical steel prices in 2021-
22 and, although prices have begun to stabilize, they are expected to 
increase again as demand for GOES and NOES rises. (NAHB, No. 106 at p. 
11) Webb questioned whether the tariffs were exacerbating industry 
challenges. (Webb, No. 133 at p. 2) Carte commented that the market 
should decide what steel to use, stating that the recent increase in 
GOES prices paired with increased competition from NOES might naturally 
shift the market toward increased usage of amorphous material. (Carte, 
No. 140 at pp. 4-5)
    DOE reiterates that there are a number of factors that can impact 
core material pricing, including competition from other markets, 
disruptions to supply chains, trade actions from both the U.S. and 
foreign countries, and increased demand. DOE has updated its base 
material prices in this final rule based on 5-year averages to capture 
more recent pricing trends as well as broader market developments. In 
general, the five-year average prices in this final rule are greater 
than the prices in the January 2023 NOPR, consistent with the 
observations from stakeholders.
    DOE received numerous comments suggesting that the future price of 
materials could be dependent on DOE's policy choice as to whether to 
amend efficiency standards.
    Howard commented that revised standards would further increase the 
demand for GOES and that its preliminary data shows transformer prices 
could be 50-125-percent greater than today's prices. (Howard, No. 116 
at p. 5) Prolec GE stated that electrical steel price volatility is 
expected to continue or become worse unless current supply and demand 
issues are resolved. (Prolec GE, No. 120 at pp. 10-11) Prolec GE added 
that increased demand coupled with limited supply for lower-loss 
steels, both amorphous and GOES, will lead to price hikes. (Prolec GE, 
No. 120 at pp. 10-11) Regarding the price of amorphous ribbon, Eaton 
commented that DOE should consider the possibility that amorphous 
prices will increase to curtail demand, causing distribution 
transformer prices to increase 50-100 percent whether GOES or amorphous 
is used. (Eaton, No. 137 at p. 26)
    Metglas commented that the price of amorphous ribbon has been 
stable relative to GOES over the last decade and additional amorphous 
ribbon capacity would drive down the fixed costs of amorphous ribbon 
and cores, which would improve the value of amorphous relative to GOES. 
(Metglas, No. 125 at pp. 5-6)
    DOE notes that both GOES and amorphous core production tend to 
carry volume-based efficiencies. In Canadian markets, stakeholders have 
noted that while amorphous core transformers previously had a 10% cost-
delta relative to GOES transformers, that cost-delta has fallen such 
that costs today are ``more or less even'' with GOES transformers.\133\ 
DOE further notes that the adopted standards include equipment classes 
with substantial volume where both GOES and amorphous are expected to 
be cost-competitive. DOE also notes that the compliance period for 
amended standards has been extended, from the 3-year compliance period 
proposed in the January 2023 NOPR to a 5-year compliance period adopted 
in this final rule. As discussed further below, DOE has considered 
comments at to what length of compliance period is necessary to ensure 
a competitive market.
---------------------------------------------------------------------------

    \133\ Bonneville Power Administration, Low-Voltage Liquid 
Immersed Amorphous Core Distribution Transformers. 2022. Available 
at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf 
(last accessed Oct. 30, 2023).
---------------------------------------------------------------------------

    Howard commented that, while current cost structures indicate 
amorphous is the cost effective option for meeting the proposed 
efficiency standards, shortages of amorphous would increase amorphous 
costs and decrease GOES costs, meaning GOES could remain a cost 
effective option. (Howard, No. 116 at p. 3) Howard commented that both 
amorphous and GOES prices are expected to increase due to tariffs and 
increased demand due to the larger cores needed to meet the proposed 
efficiency standards. (Howard, No. 116 at p. 17) TMMA commented that 
the challenges associated with transitioning to amorphous cores will 
cause a further increase in the cost of producing and delivering a 
transformer, which will ultimately be borne by consumers. (TMMA, No. 
138 at p. 3) WEG commented that the constrained supply of amorphous 
metal will significantly increase the cost of distribution 
transformers, amassing to $20M when applied across all of WEG's 
products. (WEG, No. 92 at p. 2) APPA commented that its current quotes 
from one vendor indicate that there would be a significant increase in 
costs if purchasing amorphous core transformers. (APPA, No. 103 at 
pp.7-8)
    Prolec GE commented that DOE's analysis underestimates incremental 
costs because it is unrealistic that the market will fully transition 
to amorphous cores. (Prolec GE, No. 120 at p. 3) Prolec GE commented 
that, because the supply of amorphous ribbon is insufficient to serve 
the present market, manufacturers would be required to produce GOES 
transformers with a 40-70-percent increase in incremental cost. (Prolec 
GE, No. 120 at p. 2) TMMA added that an insufficient supply of 
amorphous will force manufacturers to use GOES to meet standards, 
leading to heavier transformers and higher costs that will be passed on 
to consumers. (TMMA, No. 138 at pp. 3-4) Southwest Electric stated that 
amorphous prices should be updated as well to reflect the expected cost 
increases that would occur if DOE's NOPR efficiencies go into effect in 
2027. (Southwest Electric, No. 87 at p. 3) Powersmiths commented that 
DOE's costing estimate for amorphous transformers is flawed because a 
5-year average includes low demand of the Covid pandemic period and 
does not properly reflect current market prices, which are nearly 
double and not expected to decline. (Powersmiths, No. 112 at p. 3) 
Prolec GE commented that heavy investments in increasing amorphous 
production capacity would be required to meet demand, implying that an 
ROI cost would be added for new production. (Prolec GE, No. 120 at p. 
10) Alliant Energy commented in support of numerous manufacturers who 
expressed concern that conversion to amorphous cores by 2027 would 
increase prices and worsen existing supply chain concerns. (Alliant 
Energy, No. 128 at p. 2)
    As noted, the current market for distribution transformers is 
experiencing an imbalance in supply and demand that has led to price 
increases for distribution transformers in recent years. This has also 
led to an increase in the price of GOES material needed to build 
distribution transformers. Compounding these price

[[Page 29918]]

increases is the fact that there is only a single domestic supplier of 
GOES and, with tariffs on imported electrical steel, domestic 
transformer manufacturers are generally limited to purchasing M3 \134\ 
steel from the single domestic GOES supplier. Manufacturers do have the 
option of purchasing electrical steel from global suppliers, but that 
would mean paying a 25-percent tariff and result in even higher 
electrical steel prices. These factors have left manufacturers with a 
limited supply of core material available for distribution transformer 
production.
---------------------------------------------------------------------------

    \134\ M3 steel is the short-hand naming convention for 
conventional (i.e., not high-permeability) GOES that is 0.23 mm 
thick. It makes up the majority of domestically produced GOES used 
in distribution transformers in the U.S.
---------------------------------------------------------------------------

    In theory, manufacturers--under current standards--have the option 
of building amorphous transformers if the price of GOES transformers 
becomes prohibitively expensive. However, amorphous transformers 
require different capital equipment, meaning that manufacturers cannot 
easily switch between amorphous and GOES without new capital 
investments. As a result, the demand for GOES steel has increased by 
more than the demand for amorphous ribbon.
    Data submitted in Eaton's comment indicates that for a 1,500 kVA, 
3-phase liquid immersed transformer, an amorphous transformer is less 
expensive at baseline than a GOES transformer. Further, the proposed 
efficiency levels can be met with virtually zero incremental costs 
relative to a GOES transformer meeting efficiency standards today. If 
DOE applied current spot prices, as stakeholders have suggested, the 
baseline GOES transformer would get considerably more expensive while 
amorphous costs would remain relatively steady.
    Regarding stakeholder concerns that incremental costs will be 
greater than DOE's analysis predicts due to a limited supply of 
amorphous metal, DOE notes that it has constrained the consumer choice 
model in this final rule to reflect the actions manufacturers will take 
given their existing production equipment and concerns over core steel 
supply. Specifically, consumers are assumed to meet standards with GOES 
up to EL 2. (See section IV.F.3.a of this document). Further, the 
adopted standards are expected to be met via a combination of GOES and 
amorphous core steel, such that a limited supply of amorphous ribbon 
will not be a constraining factor in meeting amended standards. As 
such, DOE does not anticipate the supply of amorphous metal to become 
significantly constrained as a result of standards such that the 
incremental costs modeled in DOE's analysis to meet amended efficiency 
standards would greatly increase. Eaton expressed concern that relying 
on a single supplier of amorphous could create a virtual monopoly that 
would prevent competition from keeping prices in check. Accordingly, 
Eaton recommended DOE consider providing pricing and availability 
assurances until the market can create additional competition. (Eaton, 
No. 137 at p. 27) NEMA commented that it anticipates production of 
amorphous cores to be the bottleneck in meeting the NOPR efficiency 
standards. (NEMA, No. 141 at p. 14) NEMA stated that because it knew of 
just one domestic manufacturer of amorphous cores, there would likely 
be a dramatic increase in material price if the entire market is 
reliant on a single supplier. (NEMA, No. 141 at p. 14) NEMA commented 
that the NOPR would establish a monopoly on amorphous ribbon, which 
will increase costs and lead times. (NEMA, No. 141 at p. 3) NRECA 
commented that the proposed standards could eliminate production of 
GOES while likely creating a monopoly supplier for amorphous. (NRECA, 
No. 98 at p. 3)
    Regarding the notion that amended efficiency standards would 
significantly increase amorphous material prices by providing a 
monopoly to the single domestic supplier, DOE notes that the current 
distribution transformer market operates with a single domestic 
supplier of GOES and multiple foreign suppliers. As discussed in 
section IV.A.4.a of this document, in the presence of amended 
standards, the distribution transformer market is expected to be 
subject to the same dynamics present in the current market, even at 
efficiency levels expected to be met with amorphous.
    DOE does not assume having a single domestic supplier of GOES leads 
to monopolistic pricing. DOE notes that domestic GOES experiences 
competition from foreign-produced GOES. While direct imports of raw 
GOES are subject to tariff, transformer cores and laminations are not 
subject to tariffs. As previously discussed, transformer manufacturers 
rely on a combination of domestic steel--to produce their own cores--
and imported cores (that use foreign-produced steel).
    Similarly, DOE does not assume that because there is currently only 
a single domestic supplier of amorphous today, that there will be 
monopolistic pricing of amorphous in the presence of amended efficiency 
standards. Similar to GOES transformers, amorphous ribbon experiences 
competition from foreign-produced amorphous for which direct imports 
are subject to tariffs but transformer cores are not. In both cases, 
there are foreign competitors and opportunity for other suppliers to 
enter the market.
    However, there is uncertainty in the short-term price of electrical 
steel, with a variety of factors impacting core steel pricing. Short-
term prices could be driven by policy decisions and decisions of select 
market actors, including decisions made by distribution transformer 
manufacturers, amorphous ribbon manufacturers, and GOES steel 
manufacturers. The current market has limited supply of both amorphous 
and GOES steel with better loss performance than M3. Long-term pricing 
is driven by supply and demand, as well as the prices of the underlying 
commodities. DOE's updated 5-year pricing is intended to estimate a 
competitive market for core materials. While many factors are 
influencing competition in the distribution transformer market, the 
variety of supply pathways to produce transformers (e.g., domestically 
producing transformer core, importing transformer cores and 
domestically producing transformers, or importing finished 
transformers) support the continued existence of a competitive market 
for core materials in the long-term.
    Further, DOE notes while the majority of the distribution 
transformer shipments can meet adopted efficiency standards using 
either GOES or amorphous, for certain equipment classes DOE is adopting 
standards at EL4, which is likely to be met via amorphous cores. The 
expected increase in amorphous core production equipment to meet the 
adopted standards for equipment classes set at EL4 is likely to send a 
demand signal to amorphous alloy producers, thereby increasing 
amorphous supply. Further, because amorphous core production equipment 
can manufacture a range of transformer sizes, it is likely that 
additional competition will occur between GOES and amorphous core 
equipment classes set at EL2 for liquid-immersed distribution 
transformers.
    Efficiency standards have a multi-year compliance period and 
stakeholders are able to plan and invest such that a competitive market 
exists. Indeed, DOE notes that the compliance period for amended 
standards has been extended, from the 3-year compliance period proposed 
in the January 2023 NOPR to a 5-year compliance period adopted in this 
final rule. As previously discussed, DOE has considered comments at to

[[Page 29919]]

what sort of compliance period is necessary to ensure a market for GOES 
and amorphous steel sufficiently robust and competitive to provide 
adequate supply to the distribution transformer market to allow 
manufacturers to meet demand at the efficiency standards adopted.
    EEI commented that the proposed standards are in violation of EPCA 
because there is not a sufficient supply of amorphous metal capacity to 
replace GOES, making it likely that the available supply of compliant 
distribution transformers will be reduced. EEI stated that the 
conversion to amorphous will result in significant downtime for 
distribution transformer production lines, limiting production capacity 
in the near to medium term. (EEI, No. 135 at pp. 12-17) EEI added that 
the proposed standards will require significant changes across the 
entire value chain for distribution transformers, which raises concerns 
regarding the practicability of manufacturing and reliably installing 
and servicing amorphous core distribution transformers by the proposed 
effective date. (EEI, No. 135 at pp. 17-19) Portland General Electric 
commented that requiring amorphous metal transformers at a time when 
supplies are already severely constrained risks electric grid 
reliability, raising concerns regarding EPCA's requirement that DOE 
consider the availability of covered products and the practicability of 
manufacturing, installing, and servicing them. (Portland General 
Electric, No. 130 at p. 3)
    DOE notes that the adopted standards allow for both GOES and 
amorphous transformers on the market. DOE estimates that the majority 
of distribution transformers (the entirety of equipment class 1B and 
2B) will use GOES to meet the adopted standard (corresponding to over 
140,000 metric tons of GOES steel in just the liquid-immersed 
distribution transformer market), while the remainder of the liquid-
immersed distribution transformer market will use amorphous cores. 
Therefore, DOE has concluded that the adopted standards would not 
result in the unavailability of distribution transformers or negatively 
impact the distribution transformer supply chain.
    Idaho Falls Power and Fall River both commented that a 3-year 
compliance period is too aggressive and recommended that DOE consider a 
longer compliance period, which allows efficiency goals to be completed 
through innovation and utilization of incentives. (Idaho Falls Power, 
No. 77 at p. 2; Fall River, No. 83 at p. 2). Pugh Consulting commented 
that DOE did not consider the length of time and costs required to meet 
the proposed standards by the 2027 compliance deadline. (Pugh 
Consulting, No. 117 at p. 3) Portland General Electric questioned 
whether the proposed standards can be met in a 3-year compliance 
period, given the array of changes likely to result from the proposed 
rule. (Portland General Electric, No. 130 at p. 4) LBA commented that 
the proposed timeline is insufficient for the industry to make the 
required changes, including redesigning factories, establishing a 
dependable supply chain, hiring a workforce, and redesigning 
infrastructure to accommodate a new variety of distribution 
transformer. (LBA, No. 108 at p. 3)
    ERMCO commented that the timeline to meet the proposed standards 
will take longer than 3 years when considering the development of new 
supply chains, certification of new apparatus designs, and engagement 
of new manufacturing processes. (ERMCO, No. 86 at p. 1) Southwest 
Electric stated that converting to amorphous for entities that either 
supply or refine their own GOES appears to require more than the 3 
years currently being allowed. (Southwest Electric, No. 87 at p. 3) 
Howard commented that transformer manufacturers will not be able to 
begin shipping amorphous transformers within 3 years because both 
amorphous and GOES manufacturers would need to construct new facilities 
and transformer manufacturers would need to invest in new equipment. 
(Howard, No. 116 at pp. 1-2, 16)
    Powersmiths stated that January 2027 is too short a timeframe for 
the proposed standards due to how the technology change will disrupt 
existing manufacturing processes and supply chains. (Powersmiths, No. 
112 at p. 2) Schneider commented that the market is not prepared for 
the proposed efficiency levels and more time is needed to explore the 
risks of product substitution, impact on other power distribution 
equipment, supply chain and capital investment, non-ideal capital 
solutions, and electric room/building impacts. (Schneider, No. 101 at 
pp. 2, 16)
    DOE notes that the adopted standards include substantially lower 
conversion costs, as discussed in section IV.J of this document, and a 
longer compliance period, ensuring the energy savings associated with 
the amended standards can be achieved without negatively impacting the 
availability of distribution transformers.
    While there was general agreement from stakeholders that a 3-year 
compliance period was insufficient for the majority of liquid-immersed 
and LVDT transformers to transition to amorphous cores, as was proposed 
in the NOPR, there were a variety of opinions as to what efficiency 
levels and timelines were achievable and would not exacerbate shortages 
or lead to significant increases in material costs.
    Several stakeholders specifically recommended DOE delay any 
potential amendment of transformer standards until transformer prices 
and lead times return to historical averages.
    ABB recommended that DOE create an interagency working group to 
focus on the increased production of GOES, amorphous metal, and other 
constrained materials. (ABB, No. 107 at pp. 3-4)
    Eaton recommended DOE delay consideration of the NOPR until supply 
and demand for distribution transformers more closely aligns with 
historical levels. (Eaton, No. 137 at pp. 1-2) Southwest Electric 
recommended that the proposed standards be delayed until appropriate 
measures are taken to stabilize supply chains, including increasing the 
U.S. supplies of amorphous and copper, improving infrastructure for 
supporting heavier overhead transformers, and decreasing average lead 
times for liquid-filled transformers under 40 weeks. (Southwest 
Electric, No. 87 at p. 4) Howard commented that the timeline for 
proposed standards is too aggressive, reducing grid security by 
removing GOES, and making current supply chain issues more challenging. 
Accordingly, Howard encouraged DOE to delay implementation of standards 
based on the supply crisis and overly aggressive timeline. (Howard, No. 
116 at p. 5)
    DOE notes that an indefinite delay in efficiency standards violates 
DOE's statutory obligation to adopt the maximum increase in efficiency 
that is technologically feasible and economically justified (See 42 
U.S.C. 6295(m)). The adopted standards are both technologically 
feasible and economically justified and do not pose substantial risk to 
the distribution transformer supply chain as discussed in section V.C 
of this document. The existing distribution transformer shortages are 
primarily associated with increased demand for grid products and 
shortages are unrelated to transformer efficiency. The adopted 
standards complement the efforts to resolve these shortages by allowing 
for significant flexibility in meeting efficiency standards such that 
energy savings can be achieved while also investing in additive 
transformer capacity that can diversify the core steel market and 
increase total transformer capacity.

[[Page 29920]]

    Several stakeholders suggested that implementing efficiency 
standards that increased amorphous production could reduce the shortage 
concerns by shifting the distribution transformer market to amorphous 
material and freeing up GOES supply to be used in other applications or 
converted to NOES for EV applications.
    Environmental and Climate Advocates commented that current 
transformer steel manufacturers are becoming increasingly focused on 
the EV market, creating greater reliance on electrical steel imports. 
Environmental and Climate Advocates stated that transitioning to 
amorphous could alleviate current GOES capacity constraints and will 
lead to a more robust long-term supply of distribution transformers 
since amorphous is not used in EV motors. Environmental and Climate 
Advocates also added that increasing capacity to amorphous production 
is relatively fast and inexpensive compared to adding GOES capacity. 
(Environmental and Climate Advocates, No. 122 at pp. 1-2)
    Similarly, Efficiency Advocates and CEC commented that the proposed 
standards will help create a more secure long-term distribution 
transformer supply because amorphous does not experience competitive 
pressure from the electric vehicle market as GOES does. (Efficiency 
Advocates, No. 121 at p. 2; CEC, No. 124 at p. 2) Efficiency Advocates 
further commented that it is reasonable to expect that amorphous 
production would rapidly expand in response to standards given that 
adding amorphous ribbon capacity is less capital-intensive than adding 
GOES capacity. Efficiency Advocates added that there is a bias against 
amorphous due to transformer production being geared toward GOES, 
causing GOES transformers to be selected even in some instances when 
amorphous transformers are cheaper. Efficiency Advocates stated that 
the proposed standards would address this bias by spurring 
manufacturers to invest in producing amorphous transformers. 
(Efficiency Advocates, No. 121 at pp. 3-4)
    DOE notes that the adopted standards include certain equipment 
classes that are expected to be met by transitioning to amorphous 
cores. Thereby, the adopted standards are likely to increase the number 
of domestic core steel suppliers serving the U.S. market from a single 
GOES producer to a mix of GOES and amorphous.
    Several stakeholders suggested that DOE should establish revised 
efficiency standards where GOES steel will likely remain cost 
competitive and expand the compliance time to allow for more investment 
in GOES steel.
    A group of U.S. Senators commented requesting that DOE finalize the 
proposed standards and extend the compliance date. The U.S. Senators 
stated that the proposed standards would provide Americans with 
significant savings on energy bills, but a longer compliance period is 
required to address current shortages and strengthen domestic supply 
chains. (U.S. Senators, No. 147 at pp. 1-2)
    ERMCO suggested that DOE should either maintain current efficiency 
standards or propose standards at EL 2 or less, which would allow the 
U.S. supply chain to leverage both GOES and amorphous core steel 
supplies. ERMCO commented that this would allow sufficient time to 
validate the availability of raw materials, clarify load efficiency 
tradeoffs, and properly consider the total manufacturing investment. 
(ERMCO, No. 86 at pp. 1-2)
    Sychak commented that Cliffs can supply lower-loss GOES grades but 
needs sufficient time to implement changes to its product mix. (Sychak, 
No. 89 at pp. 1-2) Sychak recommended DOE revise efficiency standards 
to allow for lower-loss GOES grades to remain cost competitive and 
revise the compliance date to 2030. (Sychak, No. 89 at pp. 1-2) Cliffs 
encouraged DOE to withdraw the proposed rule and meet with stakeholders 
to investigate alternative approaches, such as the possibility of 
producing higher-efficiency grades of GOES, given sufficient lead time 
to develop and manufacture these grades. (Cliffs, No. 105 at pp. 17-18)
    Carte commented that GOES manufacturers are working to improve 
quality and the timeline of the proposed standards is very aggressive, 
not giving industry time to develop better GOES products. (Carte, No. 
140 at pp. 3-4) Carte commented that future alloys will be able to 
maintain the durability of GOES and reduce eddy currents, but the 
proposed efficiency levels will inhibit this technology. (Carte, No. 
140 at p. 4)
    Carte recommended DOE delay standards until many of the concerns 
with amorphous are further investigated and work with industry to 
discuss what energy efficiency levels make sense. (Carte, No. 140 at p. 
11)
    MTC recommended DOE follow the lead of the European ECO-2 
standards, which represent efficiency improvements over DOE's 2016 
standards while allowing the use of GOES to ensure energy savings are 
cost effective. (MTC, No. 119 at pp. 16-17) MTC further recommended DOE 
delay amending efficiency standards for single phase transformers until 
experience with new core designs has been developed for three phase 
transformers similar to ECO-2. (MTC, No. 119 at p. 18)
    DOE notes that the adopted standards include certain equipment 
classes that are at EL 2, as suggested by ERMCO, and are expected to be 
met with GOES cores. Further, the compliance period for amended 
standards has been extended, from the 3-year compliance period proposed 
in the January 2023 NOPR to a 5-year compliance period adopted in this 
final rule. The expanded compliance time also offers substantial 
opportunity for GOES manufacturers to increase production of lower-loss 
GOES products, as Sychak and Cliffs suggested.
    Several other manufacturers recommended DOE move a portion of the 
market to amorphous and/or have expanded compliance dates in order to 
provide certainty that amorphous capacity will be sufficient and 
capital investment can be made without worsening near term transformer 
shortages.
    CPI recommended that the final rule provide enough time for 
domestic transformer manufacturers to adjust to the proposed amorphous 
requirement without exacerbating current supply chain issues. (CPI, No. 
78 at p. 1) CPI urged DOE to ensure that adequate sources of amorphous 
ribbon exist before the proposed rule becomes effective, suggesting 
that this could be achieved through a phased approach to the proposed 
rule. (CPI, No. 78 at p. 1)
    Powersmiths and Eaton both commented that a tiered approach could 
be taken to implement efficiency standards with a more gradual impact 
to industry. (Powersmiths, No. 112 at p. 7; Eaton, No. 137 at p. 3)
    Hammond commented that LVDT standards should not be amended because 
LVDTs already meet the most stringent efficiency requirements in the 
United States and Canada. However, Hammond stated that if DOE is going 
to amend efficiency standards, it recommends no higher than EL 3 for 
LVDTs. (Hammond, No. 142 at p. 3) Hammond also commented that the MVDT 
proposed standards are achievable and reasonable, especially given the 
proposed liquid-immersed levels. (Hammond, No. 142 at p. 3) DOE notes 
that Hammond's recommended efficiency levels correspond to efficiencies 
that could likely be cost effectively met using GOES.
    Schneider stated that time would be needed to transition to 
amorphous in order to validate models, finalize

[[Page 29921]]

footprint impacts, finalize capital requirements, and research impacts 
on sustainability, but supply chain constraints are inhibiting this 
research from being conducted via engineering samples. (Schneider, No. 
92 at pp. 10-12) Schneider recommended that DOE establish the NOPR 
levels immediately as a voluntary ENERGY STAR level and delay the 
mandatory compliance date until January 1, 2030, to gradually convert 
the market toward new efficiency. Schneider stated this would provide 
manufacturers more time to evaluate technical impacts and establish 
supply chain partners. (Schneider, No. 92 at pp. 2, 16)
    DOE notes that while a 3-year compliance period was proposed in the 
NOPR, stakeholder comment suggest that between 6 and 7 years would be 
needed to fully retool their production process to meet the proposed 
standards. WEG commented that between 5-7 years would be needed to 
retool their facility. (WEG, No. 92 at pp. 3-4) Schneider recommended 
mandatory compliance be delayed until 2030. (Schneider, No. 92 at pp. 
2, 16) Sychak recommended DOE revise efficiency standards to allow for 
lower-loss GOES grades to remain cost competitive and revise the 
compliance date to 2030. (Sychak, No. 89 at pp. 1-2).
    The timelines cited by stakeholders were generally based on the 
need to add substantially more amorphous core production capacity, as 
the January 2023 NOPR proposed EL4 for all liquid-immersed and EL5 for 
all low-voltage dry-type transformers. The standards adopted here, 
however, are expected to require less amorphous core production 
capacity. Accordingly, DOE anticipates that these lower efficiency 
standards could be achieved in fewer than the 7 years suggested by 
commenters. However, based on existing transformer shortages, DOE 
believes a 3-year compliance period may risk electrical steel prices 
increasing due to increased demand, which could result in exacerbating 
shortages in the near term. EPCA does not prescribe a specific time 
period for compliance with new or amended standards for distribution 
transformers.\135\ Therefore, DOE has concluded that it is appropriate 
to extend the compliance period to 5 year to ensure sufficient time to 
allow investments in amorphous core production equipment, amorphous 
ribbon, and so that lower-loss GOES can be made without substantially 
increasing electrical steel prices. DOE further notes that a five-year 
compliance period is not uncommon for COMMERCIAL AND INDUSTRIAL 
equipment regulated under EPCA. See generally, 42 U.S.C. 6313.
---------------------------------------------------------------------------

    \135\ EPCA prohibits the application of new standards to a 
product with respect to which other new standards have been required 
during the prior 6-year period. 42 U.S.C. 6295(m)(4)(B). As noted 
earlier, however, the standards for distribution transformers were 
last amended in April 2013.
---------------------------------------------------------------------------

    As discussed, the adopted efficiency standards include different 
efficiency levels for different equipment classes as well as an 
expanded timeline, thereby providing certainty that amorphous capacity 
will be sufficient and capital investment can be made without worsening 
near term transformer shortages. DOE notes that existing capacity 
expansion announcements suggest that the near-term reaction to the 
January 2023 NOPR was to invest in amorphous in an additive capacity, 
given that additional distribution transformer production was needed 
anyway, as discussed in Chapter 3 of the TSD.
    In evaluating whether higher efficiency standards would be met with 
GOES, DOE considers that, at baseline, most transformers are built with 
M3, as that is the predominant product sold by the single domestic GOES 
manufacturer. Lower-loss GOES exists and is included in DOE modeling; 
however, it generally has a price premium relative to M3 in the present 
market. As such, a transformer using lower-loss steel may be able to 
meet higher efficiency levels than a baseline M3 transformer using the 
same amount of steel (because the amount of losses per pound of steel 
are lower). However, because the lower-loss steel is sold at a price 
premium in the present market, the overall cost of that transformer may 
increase.
    Howard commented that the primary barrier to using lower-loss GOES 
steels is supply related and manufacturers would use lower-loss GOES if 
tariffs were removed and domestic core manufacturers could import 
lower-loss GOES steel or domestic GOES manufacturers were incentivized 
to make lower-loss material. (Howard, No. 116 at p. 17) Howard 
commented that it produces its own cores domestically due to 
insufficient availability of lower-loss GOES material. (Howard, No. 116 
at p. 17)
    In the presence of amended standards, Cliffs, Sychak, and Howard 
suggested that existing producers of GOES may increase production of 
lower-loss GOES to meet the demand of the market or new producers of 
GOES may enter the market. If the increase in production capacity of 
this lower-loss GOES results in a reduction in the price premium, 
higher efficiency standards could be met without a transformer cost or 
size increase. For example, if the single domestic producer 
transitioned M3 grades to a lower-loss steel and did not increase the 
price per pound of GOES, higher efficiency standards (up to a point) 
could be met by building the exact same size transformers with the 
exact same costs and no required capital investment from distribution 
transformer manufacturers.
    Schneider commented that as other countries require high grade dr 
core steel, lower quality hib and M-grade steels may become extremely 
cheap. (Schneider, No. 101 at p. 10)
    Steel production tends to have volume-based efficiencies, wherein 
an initial transition to higher performing grades requires some degree 
of investment. However, once that investment is made and production is 
standardized on lower-loss steels, the incremental cost may decrease. 
DOE notes this sort of transitioning of core steel production was 
observed in response to the April 2013 Standards Final Rule. Prior to 
the compliance date of amended standards in 2016, baseline distribution 
transformers used a significant amount of M4, M5, or M6 core steel. 78 
FR 23336. However, following the implementation of amended standards in 
2016, the domestic GOES producer standardized on primarily M3 steel 
while many foreign producers standardized on hib and dr steels. These 
volume-based efficiencies resulted in a lower incremental cost between 
lower-loss GOES steel and M4, M5 or M6 grades. Not extremely cheap 
grades of these steels, as Schneider suggested.
    For the current rulemaking, DOE's modeling indicates there is 
greater flexibility in transformer design, in terms of transformer size 
and core and coil design, when meeting amended standards with lower-
loss GOES as compared to M3. Despite higher per pound prices, as 
higher-efficiency standards are evaluated, designing transformers with 
lower-loss core steel begins to achieve price parity with those 
designed with M3 steel, as the M3 designs typically operate at a 
reduced flux-density and add additional core material and/or use more 
(or more expensive) winding materials in order to meet higher 
efficiency standards, as demonstrated in Chapter 5 of the TSD. Whereas 
designs using lower-loss core steels can use a lesser amount of 
material to achieve the same efficiencies.
    As stated by Howard, increased usage of lower-loss grades of GOES 
has traditionally been limited due to supply constraints on these 
steels which, in turn, contribute to a price premium on their market 
sale. (Howard, No. 116 at

[[Page 29922]]

p. 17) In the past, the sole domestic producer of GOES has stated that 
it has the technical experience and ability to invest in additional 
grades of GOES as required by the market.\136\
---------------------------------------------------------------------------

    \136\ (AK Steel, Docket No. BIS-2020-0015-0112 at pp. 7, 21).
---------------------------------------------------------------------------

    Cliffs commented that they could produce higher-efficiency grades 
of GOES, given sufficient lead time to develop and manufacture these 
grades. (Cliffs, No. 105 at pp. 17-18) DOE notes that the adopted 
standards for liquid-immersed distribution transformers both extended 
the compliance period and adopted EL2 for equipment classes 
representing a substantial volume of shipments. Given Cliffs stated 
ability to manufacture lower-loss grades, expected demand for these 
grades into the future, the widespread existence of these grades in the 
global market, and the expanded compliance period by which these grades 
will be needed, it is expected that an increase in domestically 
produced lower-loss GOES grades will occur. As such, in the presence of 
amended standards, it is likely that the supply of higher grades of 
GOES would increase and, as a result of increased supply, the price 
premium that currently exists between M3 grades and higher grades of 
GOES would decrease.
    Based on stakeholder feedback and historical GOES trends in the 
presence of amended efficiency standards, DOE has revised its pricing 
model for GOES in this final rule. In the no-new-standards case, DOE 
has continued to rely upon 5-year average pricing to develop base 
electrical steel prices. However, in the standards case, DOE revised 
its pricing for GOES for the liquid-immersed representative units to 
reflect an increased supply of low-loss GOES, as suggested by 
stakeholders. DOE notes that it is difficult to predict the exact 
investment and pricing strategy the domestic GOES manufacturer would 
employ. However, DOE assumed it would follow similar pricing dynamics 
to many of the foreign GOES suppliers that currently produce those 
steel grades. While the domestic GOES manufacturer could choose to 
follow different pricing dynamics, DOE notes that this would create 
considerable risk of losing market share to foreign GOES producers or 
the amorphous core market.
    DOE modeled the price of 23hib090 at amended efficiency levels to 
match the price of baseline M3 grades. DOE notes these two products are 
sold for approximately the same price today (and, as discussed, foreign 
produced hib was less expensive than domestic GOES prior to tariffs), 
indicating that once manufacturers have invested in significant volumes 
of hib grades, they sell them at approximately equivalent prices to M3. 
For domain-refined grades, DOE reduced the price to a $0.10 cost-per-
pound premium between 23hib090 grades and domain-refined grades. This 
premium aligns relatively well with the cost at which domain-refined 
grades become cost competitive with M3 grades at baseline, which 
stakeholders have noted is typical in the global market when sufficient 
supply is available.\137\ This $0.10 cost-per-pound premium 
additionally accounts for the incremental production costs associated 
with the domain-refinement process.\138\
---------------------------------------------------------------------------

    \137\ Central Moloney, a domestic manufacturer of distribution 
transformers, has commented that they purchase cores made of pdr 
steel for 90 percent of their designs. Indicating that if not 
subject to supply constraints, pdr can compete with M3 on first 
cost. See Docket No. EERE-2020-0015-0015.
    \138\ DOE notes that while pdr grades are modeled for liquid-
immersed distribution transformers, there may be instances where dr 
grades can be used in certain wound core transformer designs without 
annealing, specifically if using a unicore production machinery. It 
is uncertain whether investments would be into pdr steel or dr steel 
as pdr steel typically requires greater investment (and therefore 
have a greater premium than dr steel) but would achieve greater loss 
reduction on account of annealing benefits.
---------------------------------------------------------------------------

    DOE notes that the domain-refinement process can be either an 
integrated process, such that domain-refined GOES is the direct output 
of production, or an independent additional processing step, wherein 
hib steel is separately treated to add domain-refinement. While the 
latter of these options requires additional floor space and capital 
investment, neither option has high input costs. As such, the material 
inputs required to produce domain-refined grades are not likely to lead 
to a significantly higher selling price once manufacturers have 
invested in the necessary production equipment. Rather, in the presence 
of sufficient supply, only a modest price premium is likely to exist 
between domain-refined and hib grades to account for the additional 
processing step required to add domain refinement to high permeability 
steel grades. Additionally, since domain refinement can occur as an 
independent processing step, it does not necessarily have to occur at 
the steel production site. While domain-refinement is typically 
conducted at the steel manufacturer sites, some manufacturers of 
domain-refinement equipment market the products for transformer core 
manufacturers to conduct their own laser scribing, which may be an 
option for large volume core manufacturers to minimize the cost-premium 
associated with domain-refined products, particularly if hib grades are 
available in sufficient volume domestically.\139\
---------------------------------------------------------------------------

    \139\ Castellini, Laser Scribing Machine, (Last Accessed 1/23/
2024), Available online at: https://www.castellini.it/products/solution/coil-processing/laser-scribing/.
---------------------------------------------------------------------------

    These pricing updates reflect the fact that, in the no-new-
standards case, steel manufacturers are likely to maintain the status 
quo. However, they also reflect stakeholder feedback that lower loss 
GOES pricing is largely demand dependent and would likely be reduced if 
GOES manufacturers invest in lower loss grades of GOES in the presence 
of amended standards, or if tariffs were lifted. Further, given the 
volume-based benefits of standardized production at a given steel 
grade, the price of these lower loss GOES materials may decrease as a 
result of increased production. Therefore, DOE evaluated any potential 
amended standards for liquid-immersed distribution transformers based 
on the reduced price of GOES that would be expected when compared to 
the no-new-standards case. Additional details on DOE's modelling of 
electrical steel pricing are provided in chapter 5 of the final rule 
TSD.
    Additionally, as previously noted, DOE's modeling, as well as 
stakeholder comment, indicates that amorphous core transformer designs 
are already cost competitive with GOES core transformers for many 
transformer designs and would become even more favorable in the 
presence of amended standards, given the inherent improvement in no-
load losses associated with amorphous cores as discussed in Eaton's 
comment. (Eaton, No. 137 at pp. 21-22). Therefore, at standard levels 
in which both GOES and amorphous metal can compete on a first cost 
basis, provided manufacturers make investment into amorphous core 
production equipment, it will be even more imperative for GOES 
producers to provide a supply of lower loss grades of GOES at a 
competitive price.
    As discussed in section IV.F.3 of this document, DOE has also 
revised its assumptions to reflect transformer manufacturers' desire to 
not disrupt their existing GOES-core production capacity. Therefore, 
consumer amorphous core selection is limited through EL 2. The 
assumption limiting amorphous core selection is more likely to be valid 
the more cost- and performance-competitive GOES is. If there is a 
substantial increase in GOES core transformer cost, either resulting 
from a lack of investment in higher performing GOES steel or a 
substantial price premium for these lower loss GOES materials, 
customers would be

[[Page 29923]]

more likely to select amorphous transformer at EL 1 and EL 2.
    For medium-voltage and low-voltage dry-type equipment classes, DOE 
did not similarly estimate a decrease in the price of higher grades of 
GOES as a result of amended efficiency standards because the dry-type 
market is served by a different supply chain than the liquid-immersed 
market. As discussed in section IV.A.4.b of this document, although 
both the liquid-immersed and dry-type markets may, in theory, be 
supplied by the same grades of core steel, the liquid-immersed market 
tends to be served first in practice due to its higher volume of 
shipments. As a result, since the dry-type market represents a smaller 
proportion of total distribution transformer shipments and, in turn, a 
smaller required core steel capacity, any changes to amended efficiency 
standards the dry-type market are less likely to significantly impact 
the electrical steel market or incentivize manufacturers to invest in 
higher grades of GOES. Further, even if standards were amended for the 
liquid-immersed market and the supply of higher grades of GOES were to 
increase as a result, the dry-type market would not necessarily 
experience the price-reduction benefits of these investments. Since 
core steel supply chains are established to serve the liquid-immersed 
market first, any investments in GOES capacity would likely be 
primarily directed towards the liquid-immersed market. As such, dry-
type transformer manufacturers may be required to either continue to 
use M3 grades of GOES and meet amended efficiency standards via other 
design improvements or continue to pay a premium on higher grades of 
GOES in order to secure a supply chain over the liquid-immersed market. 
Therefore, for the reasons discussed, DOE only revised its GOES pricing 
model for the liquid-immersed representative units in this final rule 
and has continued to use 5-year averages (updated to reflect recent 
price changes between the January 2023 NOPR and final rule) to model 
electrical steel prices at all evaluated standard levels for the dry-
type representative units.
    Additionally, as discussed in sections IV.A.2.b and IV.A.2.c of 
this document, DOE has established separate equipment classes for 
liquid-immersed distribution transformers based on kVA rating. For 
certain equipment kVA ranges, levels were set at the NOPR efficiency 
levels, thereby assuring manufacturers that some portion of the market 
will likely be cost-effectively met by amorphous, and assuring 
amorphous ribbon manufacturers that capacity can be increased to meet 
expected increases in demand. However, for other kVA ranges, DOE walked 
back the efficiency levels such that GOES remains a very cost-
competitive option, even if standards may be more cost-effectively met 
with amorphous. As such, manufacturers will continue to have the design 
flexibility to decide which core material to utilize. Lastly, 
distribution transformer capital equipment is capable of producing a 
wide array of kVA ranges. Hence, existing GOES equipment can focus on 
levels that are more cost-effectively met with GOES while additive 
amorphous equipment can focus on levels that are more cost-effectively 
met with amorphous. Additionally, DOE has expanded the compliance 
period, such that transformers do not have to meet any higher 
efficiency levels for 5 years, ensuring additional time for these 
investments.
    Taken together with an expanded compliance period, the standards 
adopted here will give GOES manufacturers, amorphous manufacturers, and 
distribution transformer manufacturers sufficient time and market 
certainty to make investments in both GOES and amorphous such that, 
prices will remain in line with DOE's modeling across a range of all 
reasonable manufacturer choices and efficiency standards will not make 
existing distribution transformer shortages worse. Further, DOE 
believes at least some additional portion of the market is likely to be 
met via amorphous ribbon, meaning the U.S. distribution transformer 
core market will likely be served in considerable volume by at least 
two domestic manufacturers, one for amorphous and one for GOES--as 
compared to today, wherein nearly all of the domestic market is served 
by a single domestic GOES manufacturer. A more diversified domestic 
supply ensures that uncertainty in policy decisions, such as 
implementation of tariffs, have less of an impact on domestic producers 
of distribution transformers.
    In the economic analysis for distribution transformers, DOE models 
consumer purchases for baseline distribution transformers based on the 
current market trends, whereby a utility customer purchases the lowest 
cost distribution transformer that uses existing widely produced core 
steels, as discussed in section IV.F.3.a of this document. At EL1 and 
EL2 for liquid-immersed distribution transformers, DOE's analysis 
continues to model that distribution transformer manufacturers will 
choose to maintain their existing GOES equipment in order to avoid the 
investments needed to upgrade their production facilities to 
accommodate more-efficient types of steel used to make more-efficient 
distribution transformers. Therefore, DOE models consumers as 
purchasing GOES-core distribution transformers, even if amorphous-core 
transformers would be lower first-cost. Starting at EL3, DOE assumes 
liquid-immersed distribution transformer customers purchase the lowest 
cost distribution transformer that meets the evaluated efficiency level 
and therefore generally assumes most of that market transitions to 
amorphous cores. DOE assumes manufacturers begin shift to amorphous at 
EL 3 by making investments to upgrade their distribution transformer 
production facilities to accommodate amorphous steel, even though they 
would not at lower levels. Even though EL 3 can be met with more 
efficient GOES, manufacturers may choose to use amorphous steel to make 
distribution transformers cores because it is more economical. DOE 
considers various Trial Standard Levels as discussed in section V.A of 
this document; TSL 4 and above include all equipment classes at EL 4 
and above, while TSL 3, the amended standard level, includes only 
equipment class1A and 2A at EL 4 (with the remaining classes at EL 2), 
resulting in only 48,000 metric tons of amorphous usage. That level of 
amorphous steel usage is not expected to impact the current domestic 
steel market given the existing domestic capacity and announced 
amorphous capacity expansions.
    As discussed, amended standards could increase or decrease the 
demand for certain grades of GOES and amorphous steels that are used in 
cores to make more-efficient distribution transformers. To the extent 
that these shifts in market shares across raw material sources are 
large, such as in the case of TSL 4, it is possible that shifts in 
demand could change the underlying steel prices if supply cannot 
accommodate the demand increases. The pricing dynamics of the electric 
steel market are complicated given the global market dynamics, tariff 
structures and the modernization of the U.S. electric grid to help 
support resilience. DOE's adopted standard level accounts for these 
dynamics by setting efficiency levels which, based on the assumptions 
and data discussed above, are expected to maintain the demand for 
domestic GOES while beginning to grow the demand for amorphous steel in 
a managed transition that allows time for businesses and the workforce 
to gain experience, familiarity, and confidence

[[Page 29924]]

in amorphous core distribution transformers.
    Beyond any endogenous effect on steel demand--and price--resulting 
from the standards adopted in this rule, demand for electrical steel 
could be further heightened by efforts across the country to electrify 
building end-uses and transportation, including government initiatives, 
through legislation and rulemakings, outside the scope of this 
document. As one example, the proposed rulemaking by EPA on emissions 
standards for light duty vehicles projects that electricity demand will 
increase by 4.2% in 2055 as a result of that rule.\140\ In this 
rulemaking, for the reasons explained above, DOE models an increase in 
distribution transformer shipments annually, which results in a 0.7-
percent increase annually or approximately 75,000 units. These 
estimates are derived from AEO2023's growth rate to account for the 
increase in electricity demand resulting from various electrification 
policies and standards across the United States. DOE's use of AEO 2023 
projections to drive its future shipments (and stock) growth result in 
a 190-percent increase in total installed stock (in terms of capacity) 
by 2050 as compared to a 2021 baseline. A report \141\ by the National 
Renewable Energy Laboratory estimates future growth in stock between 
160 and 260 percent by 2050 for distribution transformers, including 
step-up transformers which are not in the scope of DOE's rulemaking, 
but it shows consistent projections regarding future growth. DOE also 
ran higher and lower growth sensitivities, which were developed from 
the high and low scenarios in AEO 2023.\142\ Lastly, DOE presents in 
appendix 10C of the TSD a sensitivity scenario examining the impacts of 
utilities installing larger distribution transformers (increased per 
unit average capacity) in response to growing decarbonization/
electrification initiatives. These are all further detailed in section 
VI.E.3.a of this document. If these electrification increases are not 
adequately captured by AEO 2023 energy usage projections and 
sensitivities, DOE may be underestimating the demand for electricity-
and therefore distribution transformers-in the analysis.
---------------------------------------------------------------------------

    \140\ 88 FR 29184. Multi-Pollutant Emissions Standards for Model 
Years 2027 and Later Light-Duty and Medium-Duty Vehicles. May 5, 
2023.
    \141\ K. McKenna et al: Major Drivers of Long-Term Distribution 
Transformer Demand, Feb 2024, NREL/TP-6A40-87653.
    \142\ See appendix 10B of the TSD. National Impacts Analysis 
Using Alternative Economic Growth Scenarios.
---------------------------------------------------------------------------

    An additional pricing consideration within the market for 
distribution transformers is the role of competition and market 
structure. As elsewhere discussed in this document, GOES and amorphous 
demand in the United States are each supplied by one (separate) 
domestic producer. Existing foreign supply sources for amorphous alloy 
is limited to one producer in Japan, as well as several producers in 
China. As mentioned earlier, DOE does not expect the adopted standard 
level to alter the demand for GOES, in addition to the estimated 
efficiency benefits that amorphous steel transformers provide, DOE 
further believes that shifting some demand to amorphous steel might on 
the margin alleviate existing supply chain issues with GOES core 
transformers that was the source of extensive stakeholder feedback in 
response to the NOPR. While the increase in demand for amorphous alloy 
caused by today's standard might encourage additional entrants into the 
supply chain, it is worth considering the resulting market structure 
for amorphous alloy suppliers should all new demand be serviced only by 
existing producers.
    At TSL 4, the demand for amorphous cores is projected to be 
approximately equal to today's global capacity of amorphous alloy. In 
the short term, an inability for suppliers to scale production and 
manufacturers to retool production lines towards amorphous core 
distribution transformers could lead to short-term market disruptions. 
If amorphous demand is serviced by the domestic manufacturer of 
amorphous alloy and tariffs remain in place, this introduces a 
possibility for a shift towards monopoly markups absent price 
competition. If foreign supply or additional domestic entrants for 
amorphous alloy are available, these monopoly markup issues can be 
somewhat mitigated. For example, in an alternative energy industry 
context it has been empirically shown that duopoly markups are lower 
than economic theory might otherwise predict, due to issues associated 
with protecting against additional market entrants and imperfect 
information.\143\
---------------------------------------------------------------------------

    \143\ Wolfram, Catherine. Measuring Duopoly Power in the British 
Electricity Spot Market. American Economic Review. 89 (4) 805-826. 
1999.
---------------------------------------------------------------------------

    DOE acknowledges the above issues with respect to this rulemaking's 
potential impact on prices, and further acknowledges the complexity of 
accurately modeling price responses to regulations. To address the 
aforementioned concerns with endogenous price changes as a consequence 
of the rulemaking, as well as increased demand resulting from exogenous 
policy changes, in lieu of a market structure analysis, DOE has adopted 
standards that DOE expects to require an increase in amorphous demand 
that can be met with much higher probability in the revised 5-year 
compliance window. DOE has determined that such standards achieve the 
greatest energy savings that are economically justified. That is so 
even though DOE estimates consumer benefits would be maximized under 
the TSL4 standard that requires additional amorphous steel. However, 
based on these market-structure concerns, DOE has determined such 
standards are economically justified at this time.
    General considerations for price responses and market structure are 
areas DOE plans to explore in a forthcoming rulemaking action related 
to the agency's updates to its overall analytic framework.
    For TSL 3, DOE assumes that for the 1A and 2A equipment classes 
where DOE has proposed efficiency level 4, all future demand for 
distribution transformers will likely be met be met by amorphous cores. 
However, at TSL 3 for all other liquid-immersed equipment classes where 
DOE has proposed efficiency level 2, DOE assumes minimal amorphous core 
production even where amorphous is the lower first-cost product. In the 
long-run, it is possible that amorphous alloy supply will adequately 
increase to meet the new demand and will increase adoption of amorphous 
even for segments of the market that subject to standards that could be 
met with GOES cores. In that scenario, consumer and energy savings may 
be even greater than those modeled in this analysis. However, for 
distribution transformers, given the acute shortages this market has 
experienced in the past several years and the resulting higher prices, 
DOE has accounted for stakeholder feedback that total conversion from 
GOES to amorphous is not feasible in the short-term. Therefore, DOE has 
adopted a TSL that reflects the extensive feedback and data supplied to 
the rulemaking record that is economically justified and 
technologically feasible.
b. Other Material Prices
    Regarding other materials used in a distribution transformer, DOE 
similarly relies on 5-year average costs for materials and includes 
labor costs derived largely from public indices, markup costs, and 
transportation costs.

[[Page 29925]]

DOE detailed all of these costs in chapter 5 of the NOPR TSD.
    Regarding these costs, Idaho Power commented that the metal price 
indices used by DOE are appropriate, but recommended DOE consider labor 
and transportation costs. (Idaho Power, No. 139 at p. 4) Pugh 
Consulting commented that DOE did not properly account for the impact 
of labor shortages. (Pugh Consulting, No. 117 at p. 3)
    Regarding labor requirements, Georg commented that automation can 
reduce the labor-intensive work associated with transformer production 
and stated that Georg offers solutions to automate wound core 
production for both GOES and amorphous cores and stacked GOES cores. 
(Georg, No. 76 at p. 1)
    DOE notes that Idaho Power did not suggest an alternative method 
for considering labor or transportation costs. As noted in the January 
2023 NOPR, DOE applies a labor cost per hour that is generally derived 
from the U.S. Bureau of Labor Statistics rates for North American 
Industry Classification System (NAICS) Code 335311--``Power, 
Distribution, and Specialty Transformer Manufacturing'' production 
employees hourly rates and applies markups for indirect production, 
overhead, fringe, assembly labor up-time, and a non-production markup 
to get a fully burdened cost of labor. 88 FR 1722, 1768. DOE has 
updated these labor rates, which reflect the recent increase in labor 
costs as discussed in chapter 5 of the TSD.
    Regarding other materials costs, DOE notes that the majority of 
materials in a distribution transformer, aside from the transformer 
core, are commodities used across many products.
    Southwest Electric stated that it predicts a 47.5-percent average 
increase in copper weight to meet the proposed standards and expressed 
concern that this increased demand will both increase the cost of 
copper and lead to potential shortages. (Southwest Electric, No. 87 at 
p. 3) Southwest Electric commented that the 5-year average price of 
copper is much lower than the current price of copper and therefore DOE 
should update its cost models to reflect the more likely costs from 
2023-2027, rather than incorporating the discounted prices that existed 
between 2017-2021. (Southwest Electric, No. 87 at p. 3) Southwest 
Electric further recommended that DOE correct its cost model before 
finalizing a standard to reflect the direct cost increases associated 
with rising metal prices and the indirect cost increases associated 
with transporting, supporting, and repairing heavier overhead 
transformers. Id.
    Powersmiths commented that copper will be required to meet many 
efficiency standards, which is more expensive, volatile, and subject to 
substantial competing demand to meet efficiency standards. Accordingly, 
Powersmiths encouraged DOE to set efficiency levels that can be met 
with aluminum windings. (Powersmiths, No. 112 at p. 3)
    WEG commented that the supply of copper is limited and higher 
standards will drive more need for copper material vs aluminum. (WEG, 
No. 92 at p. 2) Eaton recommended that DOE consider the risk of reduced 
copper availability over the next two decades. (Eaton, No. 137 at p. 
29) HVOLT commented that many designs will need to convert to copper 
windings in a time when copper is in tight supply. (HVOLT, No. 134 at 
p. 8) Carte commented that 20-percent additional conductor material 
would also have environmental and supply chain impacts. (Carte, No. 140 
at p. 2)
    Howard commented that copper usage will likely increase, making it 
more difficult for manufacturers to obtain. Howard added that, while 
other materials like oil, transformer tank steel, and insulating paper 
likely will not face significant shortages in the presence of amended 
standards, the quantity of these materials used will increase, thereby 
increasing the transformer MSP. (Howard, No. 116 at p. 24)
    DOE notes that copper is used in a variety of industries and with a 
variety of electrical products. Hence, the distribution transformer 
market does not singularly dictate the supply and demand dynamics that 
impact the price of copper. DOE has used common indexes to determine 
the 5-year average price of copper. Further, DOE notes that the adopted 
efficiency levels for liquid-immersed distribution transformers can be 
met with GOES cores and aluminum windings for the equipment classes set 
at EL2 and with amorphous cores and aluminum windings for the equipment 
classes set at EL4. Low-voltage dry-type and medium-voltage dry-type 
transformer efficiency levels can also be met with GOES cores and 
aluminum windings.
    Southwest Electric commented that, although a more efficient 
transformer allows manufacturers to reduce the amount of radiators 
required, the reduction is not enough to offset the material and labor 
increases needed to reach those efficiencies. (Southwest Electric, No. 
87 at p.2)
    Regarding transportation and labor costs, Schneider commented that 
DOE should consider the climate costs associated with increased 
transportation costs if the size of LVDTs increases. (Schneider, No. 
101 at p. 11) Multiple commenters stated that larger transformers, and 
specifically amorphous core transformers, will require more truckloads 
to deliver the same number of transformers and additional weight will 
increase fuel costs, which DOE should account for in additional 
transportation costs. (ERMCO, No. 86 at p. 1; Powersmiths, No. 112 at 
p. 3; Idaho Power, No. 139 at p. 6; Eaton, No. 137 at p. 41)
    Regarding transportation costs, DOE noted in the January 2023 NOPR 
that it uses a price per pound estimate for the shipping cost of 
distribution transformers. 88 FR 1722, 1768-1769. This methodology 
means that transformers with increased weight will have increased 
shipping costs reflected in DOE's analysis. DOE understands that the 
cost to ship each unit will vary depending on weight, volume, 
footprint, order size, destination, distance, and other, general 
shipping costs (fuel prices, drive wages, demand, etc.). DOE has 
previously sought comment as to whether this cost-per-pound accurately 
models the complexity of distribution transformer shipping costs. Id.
    In response, Eaton commented that shipping costs vary, but DOE's 
shipping cost estimates are reasonable. (Eaton, No. 55 at p. 16) DOE 
did not receive comments suggesting that its cost-per-pound to ship 
transformers is inaccurate, or any suggestions as to how to model the 
complexity of distribution transformer shipping costs more accurately. 
Therefore, DOE retained its cost-per-pound shipping methodology 
described in chapter 5 of the TSD.
    The resulting bill of materials provides the basis for the 
manufacturer production cost (MPC) estimates.
    To account for manufacturers' non-production costs and profit 
margin, DOE applies a multiplier (the manufacturer markup) to the MPC. 
The resulting manufacturer selling price (MSP) is the price at which 
the manufacturer distributes a unit into commerce.
    DOE's average gross margin was developed by examining the annual 
Securities and Exchange Commission (SEC) 10-K reports filed by publicly 
traded manufacturers primarily engaged in distribution transformer 
manufacturing and with a combined product range that includes 
distribution transformers. For distribution transformers, DOE applied a 
gross margin percentage of 20 percent for all distribution 
transformers.\144\
---------------------------------------------------------------------------

    \144\ The gross margin percentage of 20 percent is based on a 
manufacturer markup of 1.25.
---------------------------------------------------------------------------

    In the January 2023 NOPR, DOE acknowledges that while some 
manufacturer may have higher gross

[[Page 29926]]

margins, the gross margin is unchanged from the April 2013 Standards 
Final Rule and was presented to manufacturers in confidential 
interviews as part of both the preliminary analysis and the NOPR 
analysis and there was general agreement that a 20-percent gross margin 
was appropriate for the industry. 88 FR 1722, 1769. DOE has retained 
the 20-percent gross margin as part of this analysis.
3. Cost-Efficiency Results
    The results of the engineering analysis are reported as cost-
efficiency data (or ``curves'') in the form of energy efficiency (in 
percentage) versus MSP (in dollars), which form the basis for 
subsequent analyses in the final rule. DOE developed 19 curves 
representing the 16 representative units. DOE implemented design 
options by analyzing a variety of core steel material, winding 
material, and core construction methods for each representative unit 
and applying manufacturer selling prices to the output of the model for 
each design option combination. See chapter 5 of the TSD for additional 
details on the engineering analysis.
    DOE then relies on these cost-efficiency curves and models consumer 
choices in the presence of various amended efficiency levels to 
calculate the downstream impacts of each theoretical efficiency 
standard. In general, DOE's analysis assumes most distribution 
transformer customers purchase based on lowest first cost and there is 
limited market above minimum efficiency standards (see section IV.F.3 
of this document).

D. Markups Analysis

    The markups analysis develops appropriate markups (e.g., retailer 
markups, distributor markups, and contractor markups) in the 
distribution chain and sales taxes to convert the MSP estimates derived 
in the engineering analysis to consumer prices, which are then used in 
the LCC and PBP analysis. At each step in the distribution channel, 
companies mark up the price of the product to cover costs. DOE's markup 
analysis assumes that the MSPs estimated in the engineering analysis 
(see section IV.C of this document) are occurring in a competitive 
distribution transformer market as discussed in section V.B.2.d of this 
document.
    As part of the analysis, DOE identifies key market participants and 
distribution channels. For distribution transformers, the main parties 
in the distribution chain differ depending on purchaser and on the 
variety of distribution transformer being purchased.
    For the January 2023 NOPR, DOE assumed that liquid-immersed 
distribution transformers are almost exclusively purchased and 
installed by electrical distribution companies; as such, the 
distribution chain assumed by DOE reflects the different parties 
involved. 88 FR 1722, 1769. DOE also assumed that dry-type distribution 
transformers are used to step down voltages from primary service into 
the building to voltages used by different circuits within a building, 
such as plug loads, lighting, and specialty equipment; as such, DOE 
modeled that dry-type distribution transformers are purchased by non-
residential customers (i.e., COMMERCIAL AND INDUSTRIAL customers). Id.
    DOE considered the following distribution channels in Table IV.7.
    [GRAPHIC] [TIFF OMITTED] TR22AP24.534
    
    DOE did not receive any comments on the distribution channels 
applied in the NOPR and maintains the same approach in this final rule.
    Chapter 6 of the final rule TSD provides details on DOE's 
development of markups for distribution transformers.

E. Energy Use Analysis

    The energy use analysis produces energy use estimates and end-use 
load shapes for distribution transformers. The energy use analysis 
estimates the range of energy use of distribution transformers in the 
field (i.e., as they are used by consumers), enabling evaluation of 
energy savings from the operation of distribution transformer equipment 
at various efficiency levels, while the end-use load characterization 
allows evaluation of the impact on monthly and peak demand for 
electricity. The energy use analysis provides the basis for other 
analyses DOE performed, particularly assessments of the energy savings 
and the savings in operating costs that could result from adoption of 
amended or new standards.
    As presented in section IV.A.3, transformer losses can be 
categorized as ``no-load'' or ``load.'' No-load losses are roughly 
constant with the load on the transformer and exist whenever the 
distribution transformer is energized (i.e., connected to electrical 
power). Load losses, by contrast, are zero when the transformer is 
unloaded, but grow quadratically with load on the transformer.
    Because the application of distribution transformers varies 
significantly by category of distribution transformer (liquid-immersed 
or dry-type) and ownership (electric utilities own approximately 95 
percent of liquid-immersed distribution transformers; commercial/
industrial entities use mainly dry type), DOE performed two separate 
end-use load analyses to evaluate distribution transformer efficiency. 
The analysis for liquid-immersed distribution transformers

[[Page 29927]]

assumes that these are owned by utilities and uses hourly load and 
price data to estimate the energy, peak demand, and cost impacts of 
improved efficiency. For dry-type distribution transformers, the 
analysis assumes that these are owned by commercial and industrial 
entities, so the energy and cost savings estimates are based on monthly 
building-level demand and energy consumption data and marginal 
electricity prices. In both cases, the energy and cost savings are 
estimated for individual distribution transformers and aggregated to 
the national level using weights derived from transformer shipments 
data.
1. Trial Standard Levels
    As discussed in detail in section V.A of this final rule, DOE 
typically evaluates potential new or amended standards for products and 
equipment by grouping individual efficiency levels for each class into 
TSLs. Use of TSLs allows DOE to identify and consider manufacturer cost 
interactions between the equipment classes, to the extent that there 
are such interactions, and price elasticity of consumer purchasing 
decisions that may change when different standard levels are set. For 
this analysis, as in the NOPR, DOE applied a Purchase Decision model 
(See section IV.F.3 of this document) to simulate the process that 
consumers use to purchase their equipment in the field within the LCC 
and PBP analysis (See section IV.F of this document). To conduct these 
analysis DOE must know the composition of potential amended standards 
(TSL) as an input as they represent the purchasing environment to 
consumers under amended standards. The results that follow are 
presented by TSL to capture the consumer, national, and manufacturer 
impacts under the amended standards scenarios considered by DOE.
2. Hourly Load Model
    For utilities, the cost of serving the next increment of load 
varies as a function of the current load on the system. To 
appropriately estimate the cost impacts of improved distribution 
transformer efficiency in the LCC analysis, it is therefore important 
to capture the correlation between electric system loads and operating 
costs and between individual distribution transformer loads and system 
loads. For this reason, DOE estimated hourly loads on individual 
liquid-immersed distribution transformers using a statistical model 
that simulates two relationships: (1) the relationship between system 
load and system marginal price; and (2) the relationship between the 
distribution transformer load and system load. Both are estimated at a 
regional level. Distribution transformer loading is an important factor 
in determining which varieties of distribution transformer designs will 
deliver a specified efficiency, and for calculating distribution 
transformer losses, and the time-dependent values of those losses. To 
inform the hourly load model, DOE examined data made available through 
the IEEE Distribution Transformer Subcommittee Task Force (IEEE TF).
    DOE received the following comment regarding the loading of liquid-
immersed distribution transformers: Carte questioned if DOE's analysis 
considered the wide range of loads that transformers serve in the field 
and whether DOE considered periods of high loading and low loading as 
part of its simulation. (Carte, No. 140 at p. 7) Central Hudson Gas and 
Electric (CHG&E) commented that it attempts to size its transformers at 
80-percent of their nameplate capacity on new installations, and that 
some of its transformers are loaded at almost 200-percent of their 
nameplate rating. (CHG&E, Public Meeting Transcript, No. 75 at pp. 92-
93) Metglas commented that an IEEE TF on Loading revealed that there is 
less than a 20-percent load on most transformers--well below the 50-
percent loading test condition. Metglas added that it has heard from 
multiple utilities and OEMs that oversizing transformers is common and 
that, due to this fact, the actual loading is likely to remain around 
20 percent. (Metglas, No. 125 at pp. 4, 7) Idaho Power commented that 
it supports DOE's application of an hourly load model for liquid-
immersed distribution transformers. (Idaho Power, No. 139 at p. 4)
    In response to CHG&E, DOE assumes CHG&E is referring to its 
customers' maximum peak demand, and maximum peak demand is not the 
average load on the distribution transformer. DOE loading analysis 
accounts for occurrences where the distribution transformers are loaded 
at a high percentage of their nameplate. While the overloading that 
CHG&E describes is discussed in IEEE C57.91-2011 as acceptable 
practice, DOE understands that overloading is the exception and not the 
rule as, depending on seasonality, the additional heat accumulated in 
the distribution transformer on high-temperature peak days can be 
detrimental to distribution transformer insulation lifetimes, 
potentially resulting in premature replacement. This strategy may be 
beneficial to CHG&E given its operational cost structures, but runs 
counter to DOE's understanding that utilities strive to reduce the cost 
of operation.
    In response to CHG&E, Carte, Idaho Power, and Metglas, DOE's hourly 
load simulation, as discussed in the January 2023 NOPR, was designed 
specifically to account for the wide range of loads seen in the field, 
and for non-linear impacts on load losses when the transformer is under 
high loads. 88 FR 1722, 1770-1772. To do so, DOE used a two-step 
approach. Transformer load data were used to develop a set of joint 
probability distribution functions (JPDF), which capture the 
relationship between individual transformer loads and the total system 
load.\145\ The transformer loads were calculated as the sum load of all 
connected meters on a given transformer for each available hour of the 
year. Because the system load is the sum of the individual transformer 
loads, the value of the system load in a given hour conditions the 
probability of the transformer load taking on a particular value. To 
represent the full range of system load conditions in the United 
States, DOE used FERC Form 714 \146\ data to compile separate system 
load PDFs for each census division. These system PDFs are combined with 
a selected transformer JPDF to generate a simulated load appropriate to 
that system. As the simulated transformer loads are scaled to a maximum 
of one to calculate the losses, the load is multiplied by a scaling 
factor selected from the distribution of Initial Peak Loads (IPLs), and 
by the capacity of the representative unit being modeled. In the August 
2021 Preliminary Analysis, DOE defined the IPL as a triangular 
distribution between 50 and 130 percent of a transformer's capacity, 
with a mean of 85 percent. This produces an hourly distribution of PUL 
values from which hourly load losses are determined. These 
distributions of loads capture the variability of distribution 
transformers load diversity, from very low to very high loads, that are 
seen in the field. The comments received did not provide data or 
evidence beyond anecdotal statements for DOE to change the modeling 
assumptions in the NOPR; as such, this distribution was maintained from 
the NOPR in this final rule.
---------------------------------------------------------------------------

    \145\ See Distribution Transformer Load Simulation Inputs, 
Technical Support Document, chapter 7.
    \146\ Available at www.ferc.gov/industries-data/electric/general-information/electric-industry-forms/form-no-714-annual-electric/data.
---------------------------------------------------------------------------

    APPA commented that amorphous transformers are larger and more 
expensive, but the expense does not rise

[[Page 29928]]

linearly with the capacity of the transformer. APPA commented that 
higher capacity transformers are cheaper per kW than smaller ones, so 
to save money, it is only logical that where shared secondary cable 
already exists, one should replace two or more (smaller capacity) 
transformers with a single (larger capacity) transformer and combine 
the shared portion of the secondary network. APPA commented that this 
has been shown to increase losses in the shared secondary cable to 
between 0.6 and 2.2 percent of total power delivered, far outstripping 
the increased efficiency of the amorphous transformer. APPA added that 
although DOE could consider working with utilities on secondary issues 
for more efficiency, the NOPR's analysis does not adequately account 
for this issue, which would undercut the efficiency conclusions in the 
proposed rule. (APPA, No. 103 at p. 15)
    Regarding the APPA comment, when DOE conducts its analysis, it 
compares the costs and benefits of a revised standard against the no-
new standards case. APPA's scenario asserts that at the time of 
transformer replacement, ``it is only logical that . . . banks of 
distribution transformers should be replaced with a single,'' DOE 
assumes a larger-capacity distribution transformer to optimize the cost 
per unit capacity of service being delivered. The lack of information 
provided by APPA makes it impossible for DOE to respond technically to 
this assertion; DOE notes that any single-unit replacement of multiple-
unit installations would need to be sized in terms of capacity to meet 
the aggregate maximum demand of all connected customers (plus any 
safety margins) on said circuit. APPA's comment asserts that additional 
losses on the secondary is a function of equipment aggregation--a 
decision made at the individual utility's operational level, and, as 
described by APPA, is an example of a utility favoring operational 
efficiency over energy efficiency, which would happen in the absence of 
a revised standard by DOE and, as such, is not considered in this final 
rule.
a. Low-Voltage and Medium-Voltage Dry-Type Distribution Transformers 
Data Sources
    Idaho Power commented it believes the base data used in the April 
2013 Standards Final Rule was scaled from 1992 and 1995 data, and there 
have been many energy efficiency standards that have been incorporated 
over the last 30 years. Idaho Power recommended that DOE consider 
updating the standard to reflect current loading data and include 
advanced data collection methods that provide more granular data. Idaho 
Power added that many power companies have automated meter read data 
that could be leveraged for better analysis. (Idaho Power, No. 139 at 
p. 5)
    DOE agrees with Idaho Power's comments that since the CBECS last 
included monthly demand and energy use profiles for respondents in 1992 
and 1995 editions that many energy efficiency standards have been 
promulgated. For its dry-type analysis, DOE used the hourly load data 
for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE 
TF (from 2020 and 2021) to scale these monthly values in its loading 
analysis for low-, and medium-voltage dry-type distribution 
transformers (see chapter 7 of this final rule TSD). DOE is aware that 
many utilities meter their customers using real-time meters; however, 
DOE does not have the authority to demand such data from said 
utilities. Instead, DOE must rely on such industry initiatives such as 
the IEEE TF or individual companies to voluntarily come forward with 
data.
3. Future Load Growth
a. Liquid-Immersed Distribution Transformers
    Several commenters stated their concerns over the possibility that 
future loads would rise on distribution transformers as a result of 
increased electrification. While no single commenter provided data or 
projections (simulated or otherwise) to support this concern, some 
commenters did hypothesize that liquid-immersed distribution 
transformer loads may grow in the future. (Mulkey Engineering, No. 96 
at p. 1; Cliffs, No. 105 at pp. 12-13; HVOLT, No. 134 at pp. 3-4; WEG, 
No. 92 at p. 3; Idaho Power, No. 139 at p. 2)
    Metglas commented that electrification impacts on distribution 
transformers would be uncertain. Metglas commented that electrification 
is likely to increase in response to global decarbonization goals. 
However, Metglas added that efficiency improvements in HVAC units, 
electric lighting, and other areas have kept the demand for electricity 
consumption essentially flat since 2010. The proposed DOE efficiency 
regulations will also help to decrease loading on the grid. (Metglas, 
No. 125 at p. 4)
    CEC commented that electrification is increasing energy demands, 
with demand expected to increase by nearly 29 percent by 2035. CEC 
noted that increasing transformer efficiency would help reduce demand 
on the grid, but recommended DOE closely examine technical, cost, and 
reliability issues because of the unique risk that transformers pose to 
broader electrification trends. (CEC, No. 124 at pp. 1-2)
    HVOLT and WEG commented that based on information supplied by EIA, 
total (net) generation had grown at a rate of 3.3 percent between 2021 
and 2023. (HVOLT, No. 134 at pp. 3-4; WEG, No. 92 at p. 3) Further, 
APPA questioned DOE's use of EIA's AEO projection of future delivered 
electricity, stating that other trends suggest potentially much higher 
rates of electric end-use consumption, and citing President Biden's 
Executive Order No. 14037, which calls for 50 percent of all new 
passenger cars and light trucks sold in 2030 to be zero-emission 
vehicles. APPA commented that there are a wide variety of projections 
of electric vehicle sales by 2030, and EV sales already reached nearly 
6 percent of all new car purchases in 2022, and that share is only 
expected to increase. Additionally, APPA commented that Federal and 
State governments are mandating that homes and buildings be electrified 
to cut emissions. (APPA, No. 103 at p. 5) NYSERDA commented that EIA 
forecasts of electricity demand do not reflect the significant demand 
increases anticipated in New York and other parts of the country due to 
aggressive decarbonization policies and accelerating rates of EV 
adoption. As such, NYSERDA anticipates DOE has underestimated the 
potential energy-saving impact of these standards, underscoring the 
need to complete this rulemaking as quickly as possible. (NYSERDA, No. 
102 at pp. 1-2) Carte commented that EIA's loading appears to be based 
on history and not forward looking, which could explain why such a low 
increase in loading is predicted. Carte commented that electrification 
does not appear to be considered when talking about 0.9 percent 
increases per year. (Carte, No. 140 at p. 6)
    Further, APPA commented that with electric vehicles, solar 
photovoltaic, building decarbonization, and other energy transition 
technologies, the average household will move from an average load of 2 
kW to an average of 6 kW and a peak of 5 kW to a peak of 10 to 25 kW 
(with range based on EV sizing). APPA commented that currently, 25 kVA 
transformers serve two to six residences, and transformers are going to 
see at least twice the load, with fewer low/no load hours. APPA 
commented that an economic justification analysis for the proposed 
distribution transformer efficiency

[[Page 29929]]

standards would need to address the change in the way transformers will 
operate during and after the transition and analyze how NOES 
transformer efficiency will be impacted by these changes, and whether 
those changes impact the NOPR's cost/benefit analysis. (APPA, No. 103 
at p. 17)
    Regarding HVOLT and WEG's comment about net generation growth, DOE 
notes that net generation cannot be used as a proxy for distribution 
transformer loads.\147\ Net generation is a ``top-down'' indicator of 
how much generation is required to meet ``bottom-up'' demands of 
electrical consumption (purchases) and must account for generating 
capacity to meet total peak generation, reserve margins, the capacity 
factors of each variety of generating unit, and transmission losses, 
plus unavailable capacity (outages).148 149 150 DOE finds 
that EIA's changes in projected purchased electricity to the final 
consumer represents a more appropriate proxy for distribution 
transformer load growth due to the distribution system's physical 
proximity to the final electrical consumer. For this final rule, DOE 
has continued to use AEO's projection of Energy Use: Delivered: 
Purchased Electricity, noting that the rate has changed from that in 
the NOPR to 0.7 percent per year in this final rule.\151\
---------------------------------------------------------------------------

    \147\ Net generation: the amount of gross generation less the 
electrical energy consumed at the generating station(s) for station 
service or auxiliaries. See www.eia.gov/tools/glossary/
index.php?id=Net%20generation#:~:text=Net%20generation%3A%20The%20amo
unt%20of,is%20deducted%20from%20gross%20generation.
    \148\ Rserve margin: The amount of unused available capability 
of an electric power system (at peak load for a utility system) as a 
percentage of total capability. See www.eia.gov/tools/glossary/index.php?id=R.
    \149\ Capacity factor: The ratio of the electrical energy 
produced by a generating unit for the period of time considered to 
the electrical energy that could have been produced at continuous 
full power operation during the same period. See www.eia.gov/tools/glossary/index.php?id=C.
    \150\ Capacity factors vary by generating unit, ranging from 92 
percent for nuclear generation (almost always on and available) to 
24 percent for solar PV (the sun isn't always shining where the 
collector are located). See www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a, and www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_b.
    \151\ See www.eia.gov/outlooks/aeo/data/browser/#/?id=2-
AEO2023®ion=1-
0&cases=ref2023&start=2021&end=2050&f=A&linechart=~~~~ref2023-
d020623a.103-2-AEO2023.1-0&map=ref2023-d020623a.3-2-AEO2023.1-
0&ctype=linechart&sourcekey=0.
---------------------------------------------------------------------------

    APPA's comments to DOE did not suggest any specific alternative 
trends that would suggest potentially much higher rates of electric 
end-use consumption in place of AEO. As discussed later in this 
section, DOE applies the rate of load growth over its entire analysis 
period resulting in a significant growth of 22 percent, which results 
in positive consumer benefits for all liquid-immersed equipment at 
today's amended standard levels (see broadly: section V) Additionally, 
as specified in 10 CFR part 431, subpart K, appendix A certification of 
medium-voltage liquid-immersed distribution transformers must occur at 
50 percent PUL--a rate that ensures efficient load-loss performance 
over a wide range of loads, both low and high. If loads were to grow at 
a rate greater than that estimated by AEO, the standard adopted by DOE 
would result in greater energy savings, and consumer and National 
benefits.
    Further APPA, NYSERDA, and Carte commented that future loads would 
be driven by increased EV adoption, claiming that EV adoption is not 
included in AEO's total purchase electricity projection. DOE's 
examination of AEO2023, Table 2, Energy Consumption by Sector and 
Source, shows purchased electricity to transportation (including light 
duty vehicles) to increase at a rate of 9.7 percent per year.
    Idaho Power commented that it expects residential loads to increase 
10 to 25 percent; however, no time period for this increase was 
provided. (Idaho Power, No. 139 at p. 2) Xcel Energy commented that 
with increased electrification, it expects an increase in load factor 
and a higher rate of changeouts (to larger-capacity units). (Xcel 
Energy, Public Meeting Transcript, No. 57 at p. 133) WEC commented that 
it projected that loading would increase by 5 to 15 percent on its 
single-phase distribution transformers; again, no period over which 
this would occur was provided. (WEC, No. 118 at p. 1) Carte commented 
that increased adoption of EVs and other electrification technologies 
will greatly increase transformer loads. (Carte, No. 140 at pp. 5-6) 
Further, Carte and CARES expressed a belief that loads will grow by 50 
percent, a number that they attribute to EEI without citation. (Carte, 
No. 140 at p 6; CARES, No. 99 at p. 4)
    Specifically, in response to the assertions from Carte and CARES 
that loads will grow by 50 percent over the next 5 to 10 years, DOE has 
identified a presentation that is believed to be the source document of 
these values; \152\ the presentation forecasts that the range of 
electric loads increase will ``vary wildly, anywhere from 5 and 50 
percent, depending on multiple factors,'' indicating that 50 percent is 
a maximum bound of EEI's load growth estimate--not the likely outcome 
indicated by Carte and CARES.
---------------------------------------------------------------------------

    \152\ See: https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0162.
---------------------------------------------------------------------------

    As stated in the January 2023 NOPR, and evidenced by the comments 
received, many factors potentially impact future distribution 
transformer load growth, and these factors may be in opposition. At 
this time, many utilities, States, and municipalities are pursuing EV 
charging programs, and it is unclear the extent to which increases in 
electricity demand for EV charging or other State-level decarbonization 
efforts, will impact current distribution transformer sizing practices 
(for example, whether distribution utilities plan to upgrade their 
systems to increase the capacity of connected distribution 
transformers, thus maintaining current loads as a function of 
distribution transformer capacity; or if distribution utilities do not 
plan to upgrade their systems and will allow the loads on existing 
distribution transformers to rise). DOE recognizes that this is further 
complicated by the current supply shortage of distribution equipment. 
Some stakeholders speculate that these initiatives will increase the 
intensive per-unit load over time as a function of per unit of 
installed capacity. However, these stakeholders did not provide any 
quantitative evidence that this is indeed happening on their 
distribution systems, or in regions that are moving forward with 
decarbonization efforts. Further, the hypothesis that intensive load 
growth will be a factor in the future is not supported by available 
future trends in AEO2023, as indicated by the purchased electricity 
trend representing the delivered electricity to the customer. Others 
asserted that higher loads in response to decarbonization initiatives 
would be met with the extensive growth of the distribution system 
(i.e., increasing the total capacity of the distribution system through 
larger distribution transformers, or greater shipments, or some 
combination of both). Again, data were not provided to support this 
position, but some utilities stated they were maintaining service by 
(a) increasing the distribution capacity of given circuits (i.e., 
installing larger transformers); or (b) reducing the number of 
customers on a given circuit (i.e., installing more transformers).\153\ 
(APPA, No. 103 at p. 17; Highline Electric, No. 71 at pp. 1-2; Idaho 
Power, No. 139 at p. 5) For this final rule, DOE finds that neither 
position provides enough evidence to change its assumptions from the 
January 2023

[[Page 29930]]

NOPR and August 2021 Preliminary Analysis TSD. For this final rule, DOE 
updated its load growth assumption for liquid-immersed distribution 
transformers based on the change in average growth of AEO2023: 
Purchased Electricity: Delivered Electricity, which shows a year-on-
year growth rate of 0.7 percent. While this value may seem low, when 
compounded over the analysis period it results in a significant growth 
of 22 percent, which is higher than the rates indicated by Idaho Power 
and WEC, albeit over a presumed longer timeframe.
---------------------------------------------------------------------------

    \153\ Discussed in section IV.G.2 of this document in detail.
---------------------------------------------------------------------------

    Additionally, DOE has examined a scenario in the NIA to measure the 
potential impacts of increased capacity by shifting smaller units to 
larger units. There is little information from which to model this 
shift--specifically over how long a period this shift to larger 
capacities would occur. Based on report studying the impact of EVs on 
transformer overloading,\154\ and the impacts of reduced transformer 
lifetimes from increased transformer loads \155\ DOE estimated the 
extensive growth of the distribution system that would be needed. These 
studies indicate that it is distribution transformer up to 100 kVA that 
are at risk of overloading (EC 1B), and associated lifetime reductions, 
and most likely to be replaced with larger capacity equipment. These 
studies indicate that the risk of overload diminishes with increased 
capacity, with 100 kVA being the upper limit. DOE's approach shifts the 
capacities transformer shipments over to larger capacity equipment. DOE 
includes this scenario for illustrative purposes. This shift and 
results can be found in appendix 10C of the TSD. These results indicate 
that for EC 1B in the event of such a capacity shift, the national 
full-fuel cycle energy savings will increase by 21 percent, with the 
net present value of consumer savings also increasing by 19 and 20 
percent, at 3 and 7 percent discount rates, respectively.
---------------------------------------------------------------------------

    \154\ 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: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
    \155\ Jodie Lupton, Right-Sizing Residential Transformers for 
EVs, T&D World,January 2024, Available online: https://prismic-io.s3.amazonaws.com/wwwpowerengcom/9dd90ffc-4df8-442c-92c2-eb175f687ea0_Right-sizing+residential+transformers+for+EVs.pdf.

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[[Page 29931]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.535


[[Page 29932]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.536

[GRAPHIC] [TIFF OMITTED] TR22AP24.537

    Chapter 7 of the final rule TSD provides details on DOE's energy 
use analysis for distribution transformers.

F. Life-Cycle Cost and Payback Period Analysis

    DOE conducted LCC and PBP analyses to evaluate the economic impacts 
on individual consumers (in this case distribution utilities for 
liquid-immersed, and COMMERCIAL AND INDUSTRIAL entities for low-, and 
medium-voltage dry-type) of potential energy conservation standards for

[[Page 29933]]

distribution transformers. The effect of amended energy conservation 
standards on individual consumers usually involves a reduction in 
operating cost and an increase in purchase cost. DOE used the following 
two metrics to measure consumer impacts:
    [ssquf] The LCC is the total consumer expense of an appliance or 
product over the life of that product, consisting of total installed 
cost (manufacturer selling price, distribution chain markups, sales 
tax, and installation costs) plus operating costs (expenses for energy 
use, maintenance, and repair). To compute the operating costs, DOE 
discounts future operating costs to the time of purchase and sums them 
over the lifetime of the product.
    [ssquf] The PBP is the estimated amount of time (in years) it takes 
consumers to recover the increased purchase cost (including 
installation) of a more-efficient product through lower operating 
costs. DOE calculates the PBP by dividing the change in purchase cost 
at higher efficiency levels by the change in annual operating cost for 
the year that amended or new standards are assumed to take effect.
    For any given efficiency level, DOE measures the change in LCC 
relative to the LCC in the no-new-standards case, which reflects the 
estimated efficiency distribution of distribution transformers in the 
absence of new or amended energy conservation standards. In contrast, 
the PBP for a given efficiency level is measured relative to the 
baseline product.
    For each considered efficiency level in each product class, DOE 
calculated the LCC and PBP for a nationally representative set of 
electric distribution utilities and commercial and industrial 
customers. As stated previously, DOE developed these customer samples 
from various sources, including utility data from the Federal Energy 
Regulatory Commission (FERC), EIA; and commercial and industrial data 
from the Commercial Building Energy Consumption Survey (CBECS) and 
Manufacturing Energy Consumption Survey (MECS). For each sample, DOE 
determined the energy consumption in terms of no-load and load losses 
for distribution transformers and the appropriate electricity price. By 
developing a representative sample of consumer entities, the analysis 
captured the variability in energy consumption and energy prices 
associated with the use of distribution transformers.
    Inputs to the LCC calculation include the installed cost to the 
consumer, operating expenses, the lifetime of the product, and a 
discount rate. Inputs to the calculation of total installed cost 
include the cost of the equipment--which includes MSPs, retailer and 
distributor markups, and sales taxes--and installation costs. Inputs to 
the calculation of operating expenses include annual energy 
consumption, electricity prices and price projections, repair and 
maintenance costs, equipment lifetimes, and discount rates. Inputs to 
the PBP calculation include the installed cost to the consumer and 
first year operating expenses. DOE created distributions of values for 
equipment lifetime, discount rates, and sales taxes, with probabilities 
attached to each value, to account for their uncertainty and 
variability.
    The computer model DOE uses to calculate the LCC and PBP relies on 
a Monte Carlo simulation to incorporate uncertainty and variability 
into the analysis. The Monte Carlo simulations randomly sample input 
values from the probability distributions and distribution transformer 
samples. For this rulemaking, the Monte Carlo approach is implemented 
as a computer simulation. The model calculated the LCC and PBP for 
products at each efficiency level for 10,000 individual distribution 
transformer installations per simulation run. The analytical results 
include a distribution of 10,000 data points showing the range of LCC 
savings for a given efficiency level relative to the no-new-standards 
case efficiency distribution. In performing an iteration of the Monte 
Carlo simulation for a given consumer, product efficiency is as a 
function of the consumer choice model described in section IV.F.2 of 
this document. If the chosen equipment's efficiency is greater than or 
equal to the efficiency of the standard level under consideration, the 
LCC and PBP calculation reveals that a consumer is not impacted by the 
standard level. By accounting for consumers who are already projected 
to purchase more-efficient products in a given case, DOE avoids 
overstating the potential benefits from increasing product efficiency.
    DOE calculated the LCC and PBP for all consumers of distribution 
transformers as if each were to purchase new equipment in the expected 
year of required compliance with amended standards. Amended standards 
would apply to distribution transformers manufactured five years after 
the date on which any new or amended standard is published in the 
Federal Register. Therefore, DOE used 2029 as the first year of 
compliance with any amended standards for distribution transformers.
    Table IV.11 summarizes the approach and data DOE used to derive 
inputs to the LCC and PBP calculations. The subsections that follow 
provide further discussion. Details of the model, and of all the inputs 
to the LCC and PBP analyses, are contained in chapter 8 of the TSD and 
its appendices.

[[Page 29934]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.538

1. Equipment Cost
    To calculate consumer product costs, DOE multiplied the MPCs 
developed in the engineering analysis by the markups described 
previously (along with sales taxes). DOE used different markups for 
baseline products and higher-efficiency products because DOE applies an 
incremental markup to the increase in MSP associated with higher-
efficiency products.
    DOE examined historical producer price index (PPI) data for 
electric power and specialty transformer manufacturing available 
between 1967 and 2022 from the BLS.\156\ Even though this PPI series 
may also contain prices of electrical equipment other that distribution 
transformers, this is the most disaggregated price series that is 
representative of distribution transformers. DOE assumes that this PPI 
is a close proxy to historical price trends for distribution 
transformers, including liquid-immersed, and medium-, and low-voltage 
dry-type transformers. The PPI data reflect nominal prices adjusted for 
product quality changes. The inflation-adjusted (deflated) price index 
for electric power and specialty transformer manufacturing was 
calculated by dividing the PPI series by the Gross Domestic Product 
Chained Price Index.
---------------------------------------------------------------------------

    \156\ Product series ID: PCU3353113353111. Available at 
www.bls.gov/ppi/.
---------------------------------------------------------------------------

    DOE has observed a spike in the trend of annual real prices between 
2021 and 2022. However, when the PPI is examined at a month-by-month 
level, the deflated PPI from 2022 through 2023 appears to be leveling 
off. Specifically, the deflated monthly PPI data in Table IV.12 shows a 
near constant value since June 2022. DOE further examined the trends on 
key inputs into distribution transformers: steel, aluminum, and 
copper--these inputs show a similar trend over this same 
period.157 158 159 DOE notes that the engineering analysis 
estimated MSPs in 2023; additionally, and that it has captured the 
impact of this spike, if it were realized, as a constant increase in 
real prices in the low economic price scenario results shown in section 
V.C of this document.
---------------------------------------------------------------------------

    \157\ Steel: WPU101
    \158\ Aluminum: ID: WPU10250105
    \159\ Copper: WPU10260314

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[[Page 29935]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.539

    DOE received no comments on its future price trend methodology in 
the NOPR. For this final rule, DOE maintained the same approach for 
determining future equipment prices as in the NOPR and assumed that 
equipment prices would be constant over time in terms of real dollars 
(i.e., constant 2023 prices).
2. Efficiency Levels
    As in the January 2023 NOPR, for this final rule, DOE analyzed 
various efficiency levels expressed as a function of loss reduction 
over the equipment baseline \160\ as well as an overall efficiency 
rating. For units greater than 2,500 kVA, there is not a current 
baseline efficiency level that must be met. Therefore, DOE established 
EL 1 for these units as if they were aligning with the current energy 
conservation standards efficiency vs kVA relationship, scaled to the 
larger kVA sizes. To calculate this, DOE scaled the maximum losses of 
the minimally compliant design from the next highest kVA representative 
unit to the 3,750 kVA size using the equipment class specific scaling 
relationships in TSD appendix 5C. For example, for three-phase liquid-
immersed distribution transformers, the highest kVA representative unit 
is RU5, corresponding to a 1,500 kVA transformer. A minimally compliant 
1,500 kVA design is 99.48-percent efficient and has 3,920 W of total 
losses at 50-percent load, with representative no-load and load losses 
of 1,618 W and 2,290 W respectively based on RU5. Using the updated 
scaling factors of 0.73 and 1.04 for no-load and load losses 
respectively, as described in appendix 5C, the total losses of a 3,750 
kVA unit would be 9,096 W, corresponding to 99.52-percent efficient at 
50-percent load.
---------------------------------------------------------------------------

    \160\ Calculated as the current percentage loss (i.e., 100 
percent minus the current standard) multiplied by the percent 
reduction in loss plus the current standard
---------------------------------------------------------------------------

    EL 2 through EL 5 align with the same percentage reduction in loss 
as their respective equipment class, but rather than being relative to 
a baseline level, efficiency levels were established relative to EL 1 
levels.
    The rate of reduction is shown in Table IV.13, and the 
corresponding efficiency ratings in Table IV.14.

[[Page 29936]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.540


[[Page 29937]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.541

    DOE did not receive any comments regarding either the loss rates or 
the efficiency levels applied in the NOPR and continued their use for 
this final rule.
3. Modeling Distribution Transformer Purchase Decision
    In the January 2023 NOPR TSD, DOE presented its modelling 
assumptions on how distribution transformers were purchased. DOE used 
an approach that focuses on the selection criteria that customers are 
known to use when purchasing distribution transformers. Those criteria 
include first costs as well as the total ownership cost (TOC) method, 
which combines first costs with the cost of losses. Purchasers of 
distribution transformers, especially in the utility sector, have 
historically used the TOC method to determine which distribution 
transformers to purchase. However, comments received from stakeholders 
responding to the 2012 ECS NOPR (77 FR 7323) and the June 2019 Early 
Assessment RFI (84 FR 28254) indicated that the widespread practice of 
concluding the final purchase of a distribution transformer based on 
TOC is rare. Instead, customers have been purchasing the lowest first 
cost transformer design regardless of its loss performance. Respondents 
noted that some purchasers of distribution transformers do so on the 
basis of first cost in order to, among other things, maximize their 
inventories of transformers per dollar invested. This behavior allows 
transformer purchasers to have the maximum inventory of units available 
to quickly respond to demand for new transformers, as well as have 
replacements readily available in the event of transformer failure. DOE 
continues to explore consumer choice and market reaction to the new 
efficiency standards levels and the impact it would have on purchasers' 
inventory of transformers. This may be further explored in a future 
RFI. As discussed in section IV.F.3.b of this document the practice of 
purchasing based on first cost is unlikely to change over time.
    The utility industry developed TOC evaluation as a tool to reflect 
the unique financial environment faced by each distribution transformer 
purchaser. To express variation in such factors as the cost of electric 
energy, and capacity and financing costs, the utility industry 
developed a range of evaluation factors: A and B values, to use in 
their calculations.\161\ A and B are the

[[Page 29938]]

equivalent first costs of the no-load and load losses (in $/watt), 
respectively.
---------------------------------------------------------------------------

    \161\ In modeling the purchase decision for distribution 
transformers DOE developed a probabilistic model of A and B values 
based on utility requests for quotations when purchasing 
distribution transformers. In the context of the LCC the A and B 
model estimates the likely values that a utility might use when 
making a purchase decision.
---------------------------------------------------------------------------

    In response to the NOPR analysis, DOE received the following 
comments regarding the modeling of distribution transformer purchases.
a. Equipment Selection
    DOE did not receive comments regarding how engineering designs were 
selected by the consumer choice model in the LCC and maintained the 
material constraints in be no-new-standards case from the January 2023 
NOPR in this final rule. For the January 2023 NOPR, DOE's research 
indicated that distribution transformers can be fabricated with 
amorphous core steels that are cost competitive with conventional 
steels, as shown in the engineering analysis (see section IV.C), but 
they cannot currently be fabricated in the quantities needed to meet 
the large order requirements of electric utilities, and, as such, are 
limited to niche products. DOE experience shows that this lack of 
market response to the availability of new materials, amorphous, to be 
unique to the purchase of distribution transformers. The current market 
environment for distribution transformers is shaped primarily by the 
availability of products with short lead times to consumers given 
current demand dynamics. This in turn is driven by the availability of 
existing production capacity. Currently, distribution transformer 
capacity is primarily set up to produce equipment with GOES cores (97 
percent of units). Because GOES production equipment cannot be readily 
modified to manufacture amorphous distribution transformers, DOE 
understands that this production capacity will continue to produce GOES 
distribution transformers unless it is entirely replaced with amorphous 
specific production equipment. As a result, the availability of GOES 
core transformers will be maintained, even as amorphous production 
capacity is added under amended standards.
    This circumstance is unique to transformers where the production 
lines for GOES and amorphous core equipment are not interchangeable, 
meaning that to meet amended standards requiring amorphous core steel 
manufacturers cannot retool existing production lines, but must add new 
production capacity. DOE expects that, in the long term, manufacturers 
may begin to replace GOES production equipment with amorphous 
production equipment where amorphous is more cost competitive in the 
presence of amended standards. However, as discussed in section IV.A.5 
of this document, the distribution transformer market is currently 
experiencing significant supply constraints, creating extended lead 
times and supply shortages for distribution transformers. Therefore, to 
address these supply shortages, manufacturers may choose to maintain 
their GOES production to maximize their production output in the 
presence of amended standards, even if amorphous production is a more 
cost competitive production route. To reflect this, DOE has revised its 
customer choice model in the no-new-standards and standards cases in 
this final rule to limit the variety of core steel materials by TSL to 
the ratios shown in Table IV.15. DOE updated the consumer choice model 
from the January 2023 NOPR, which did not constrain the selection of 
designs based on core material variety in the standards case, based on 
feedback received expressing that manufacturers may maintain GOES 
production, even in instances when amorphous transformers may be the 
lowest cost option (See sections IV.A.4.c and IV.A.5 of this document). 
These material limits account for impacts in the amended standards case 
where GOES steel may continue to be used to meet the trial standard 
levels (see section V.A of this document). These material limits 
represent a conservative view of the future where AM does not displace 
any GOES production, or the demand for GOES distribution transformers 
is not diminished in favor of AM core distribution transformers. While 
it is likely that over time there would be some displacement, it is too 
speculative for DOE to establish amended standards on such a modeling 
assumption. For informational purposes DOE has included LCC 
sensitivities where the amorphous core distribution transformers 
increase in availability to 10 percent, and 25 percent. These 
sensitivity analyses, which demonstrate a higher percentage of 
distribution transformer manufacturers utilizing amorphous steel cores 
to meet TSL 3 standards, result in increasing LCC savings for EC 1B by 
62 and 193 percent, respectively. Further for EC 2B the LCC savings 
increased by 578 and 589 percent for increases in AM availability of 10 
and 25 percent, respectively. The impacts of these sensitivities can be 
reviewed in appendix 8E of the final rule TSD.

[[Page 29939]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.542

b. Total Owning Cost and Evaluators
    In the January 2023 NOPR Analysis TSD, DOE used TOC evaluation 
rates as follows: 10 percent of liquid-immersed transformer purchases 
were concluded using TOC, and 0 percent of low-voltage dry-type and 
medium-voltage dry-type transformer purchases were concluded using TOC. 
DOE received comments from several stakeholders regarding the rates at 
which TOC are practiced.
    NEMA and Prolec GE commented that the current percentage of 
transformers that are being purchased using TOC is estimated to be 
below 10 percent for both single-phase and three-phase transformers. 
(Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p. 15) However, Howard 
commented that in 2022, its TOC adoption rate was in the 40-percent 
range for both single- and three-phase liquid-immersed distribution 
transformers. (Howard, No. 116 at p. 19) NRECA commented that many 
electric cooperatives are RUS borrowers and thus use RUS Bulletin 
1724D-107, ``Guide for Economic Evaluation of Distribution 
Transformers,'' to calculate the cost of owning a transformer over its 
useful life using the TOC method.\162\ NRECA added that given today's 
supply chain challenges, its members' primary concern is the 
availability of transformers, not the cost, and therefore DOE's 
estimation of the utilities using TOC is not representative of real-
world experience. (NRECA, No. 98 at p. 7)
---------------------------------------------------------------------------

    \162\ See: https://www.rd.usda.gov/sites/default/files/UEP_Bulletin_1724D-107.pdf.
---------------------------------------------------------------------------

    Prolec GE, NEMA, NRECA, and Colorado Springs Utilities commented 
that the low usage of TOC was the implementation of DOE's current 
minimum efficiency levels (adopted in the April 2013 Standards Final 
Rule (78 FR 23335) with compliance required in 2016) due to the TOC 
formula becoming less relevant when defining the most cost-competitive 
transformer design option resulting in most customers are purchasing 
transformers based on lowest first-cost that meets the current DOE 
efficiency levels. (Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p. 
15; Colorado Springs Utilities, Public Meeting Transcript, No. 75 at p. 
114; NRECA, No. 98 at p. 7)
    WEC commented that the best interests of its customers would be 
served by allowing utilities to use their A and B factors to calculate 
efficiency requirements, as cost evaluation is unique to each utility. 
(WEC, No. 118 at p. 1) Rochester PU commented that it uses loss-
evaluated transformers for 30-plus years and if amorphous transformers 
are the best choice based on its loss evaluation (which considers 
energy cost), then those are the transformers Rochester PU would 
purchase. (Rochester PU, Public Meeting Transcript, No. 75 at pp. 61-
62)
    Given the comments received, DOE has maintained the same modeling 
assumption in this final rule as it used in the January 2023 NOPR, 
where an estimated 10 percent of purchases are concluded using TOC. DOE 
notes however that this final rule is not prescriptive, and that 
distribution transformers can be designed to meet any combination of A 
and B values if the overall design meets the amended minimum efficiency 
standards.
    Howard provided the fraction of sales that are concluded based on 
TOC. (Howard, No. 116 at p. 20) DOE applied the shipment weights per 
EMM region from Howard's data in DOE's customer choice model with an 
additional

[[Page 29940]]

percentage assigned to random EMM regions as was done in the NOPR, and 
the entry for California split evenly between Northern and Southern 
California. DOE found that for consumers who evaluate based on TOC in 
DOE's modeling, they are limited to the EMM regions based on the 
weights shown in Table IV.16.
[GRAPHIC] [TIFF OMITTED] TR22AP24.543

Band of Equivalents
    In the August 2021 Preliminary Analysis TSD, DOE proposed the 
following definition for Band of Equivalents (BOE): as a method to 
establish equivalency between a set of transformer designs within a 
range of similar TOC. BOE is defined as those transformer designs 
within a range of similar TOCs. The range of TOC varies from utility to 
utility and is expressed in percentage terms. In practice, the 
purchaser would consider the TOC of the transformer designs within the 
BOE and would select the lowest first-cost design from this set.
    NEMA commented that BOE is generally not used for low- or medium-
voltage dry-type transformer purchases. (NEMA, No. 141 at p. 15) Based 
on this comment from NEMA, DOE maintained its approach from the NOPR 
where TOC and BOE are not applied to low- and medium-voltage 
distribution transformers.
    Mulkey Engineering commented on the risks associated with following 
TOC ``to the penny,'' suggesting that a combination of TOC and BOE be 
used when evaluating transformer purchases. In addition to other 
experience-driven suggestions, Mulkey Engineering asserted a BOE rate 
within TOC of 10 percent. (Mulkey Engineering, No. 96 at pp. 1-2) NEMA 
commented that most utilities who use TOC methods also apply a band of 
equivalency ranging from 3-10 percent of the TOC, where the lowest 
first cost transformer in the band is purchased. (NEMA, No. 141 at p. 
15) Finally, Prolec GE commented that BOE is used in less than half of 
the cases where a TOC formula is specified. (Prolec GE, No. 120 at p. 
12)
    Based on the comments received, DOE will maintain the definition as 
per the NOPR. Additionally, for this final rule, DOE included a BOE 
rate of 5 percent for those consumers who use TOC in the consumer 
choice model.
c. Non-Evaluators and First Cost Purchases
    DOE defined those consumers who do not purchase based on TOC as 
those who purchase based on lowest first costs. DOE did not receive any 
comments regarding lowest first cost purchases and maintained the 
approach from the NOPR in this final rule.
4. Installation Cost
    Installation cost includes labor, overhead, and any miscellaneous 
materials and parts needed to install the product. DOE used data from 
RSMeans to estimate the baseline installation cost for distribution 
transformers.\163\ In the January 2023 NOPR TSD, DOE asserted that 
there would be no difference in installation costs between baseline and 
more efficient equipment. DOE also asserted that 5 percent of 
replacement installations would face increased costs over baseline 
equipment due to the need for site modifications. Stakeholders 
responded to DOE's assertions regarding installation costs as they 
related to the increases in efficiency proposed in the NOPR.
---------------------------------------------------------------------------

    \163\ Gordian, RSMeans Online, www.rsmeans.com/products/online 
(last accessed Sept. 2023).
---------------------------------------------------------------------------

a. Overall Size Increase
    Stakeholders had concerns over the increased size and weight of 
equipment due to amended efficiency standards, specifically that 
increased transformer size and weight would result in increased 
technical issues and increased costs when replacement transformers are 
installed in sensitive locations. (Cliffs, No. 105 at pp. 11-12; NEMA, 
No. 141 at p. 6; Highline Electric, No. 71 at pp. 1-2; Indiana Electric 
Co-Ops, No. 81 at p. 1; Southwest Electric, No. 87 at p. 3; Howard, No. 
116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 4; Pugh Consulting, 
No. 117 at p. 5; NRECA, No. 98 at p. 6; Entergy, No. 114 at p. 4; SBA, 
No. 100 at p. 6; WEC, No. 118 at p. 2; Portland General Electric, No. 
130 at p. 4; Southwest Electric, No. 87 at pp. 2-3; Xcel Energy, No. 
127 at p. 1; Idaho Power, No. 139 at pp. 5-6; APPA, No. 103 at p. 9; 
Schneider, No.

[[Page 29941]]

101 at p. 2; Powersmiths, No. 112 at pp. 4-5)
    The Efficiency Advocates commented that any size-related impacts 
resulting from DOE's proposal are not expected to significantly impact 
transformer installations. The Efficiency Advocates commented that as 
of 2015, more than 4 million AM transformers had been sold globally, 
with about 600,000 installed in the United States, over 1 million in 
China, and 1.3 million in India--this number of installed global AM 
units has increased several-fold since 2015. The Efficiency Advocates 
estimated that over 90 percent of liquid-immersed transformers sold in 
Canada use AM. The Efficiency Advocates commented it understands that 
``well-designed AM transformers'' are not meaningfully larger than 
current GOES transformers and noted that DOE's NOPR analysis considered 
the potential impact of increased transformer size on pole and vault 
installations. (Efficiency Advocates, No. 121 at pp. 6-7)
    In response to these comments, the amended standard in this final 
rule shows the following increases in transformer size and weight shown 
in Table IV.17 through Table IV.19. The impact on liquid immersed 
transformer weight om amended standards is expected to be less than 10 
percent for small (<=100 kVA) single-phase (overhead and surface 
mounts). For large (>100 kVA) single-phase the weight is expected to 
increase from 16 to 21 percent. For small three-phase (<500 kVA) the 
expected increase in weight and footprint (ft\2\) are 4 and 1 percent, 
respectively. For large (>=500 kVA) three-phase the expected increase 
in weight and footprint (ft\2\) are expected to be 2 and 1 percent, 
respectively; with the exception of three-phase liquid-immersed 
distribution transformers greater than 2500 kVA where ethe increases in 
the weight and footprint (ft\2\) are expected to be 25 and 8 percent, 
respectively.
[GRAPHIC] [TIFF OMITTED] TR22AP24.544


[[Page 29942]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.545

[GRAPHIC] [TIFF OMITTED] TR22AP24.546

    DOE appreciates these general comments and refers to its responses 
below on specific installation cost concerns.
b. Liquid-immersed
    NEMA, commented that the proposed amended standard would result in 
medium-voltage liquid- and dry-type unit weight increasing by 50 
percent and generally result in 15-percent taller, wider, and deeper 
units compared to those designed to meet the current standards; and 
that tank diameters and/or tank heights increases of 15 percent or more 
will create new logistical challenges. (NEMA, No. 141 at p. 6). WEB and 
LBA also expressed concerns regarding the potential increased weights 
of transformers more generally. (WEG, No. 92 at p. 2; LBA, No. 108 at 
p. 3)
    EEI and NEMA commented that the transportation, delivery, and 
handling of the new (heavier) equipment will also be impacted. EEI and 
NEMA commented that the increased size means fewer units per truck, 
with larger and heavier equipment requiring more trucks to move units 
to their installation locations. EEI and NEMA commented that for pole 
mounted transformers, new poles to support the weight will have to be 
sourced; for pad-mounted transformers, thicker and larger concrete pads 
will have to be poured. EEI and NEMA added that larger and heavier also 
means bigger boom cranes necessary to lift such equipment will need to 
be procured. (EEI, No. 135 at pp. 20-21; NEMA, No. 141 at p. 3)

[[Page 29943]]

    Idaho Falls Power and Fall River commented that amorphous core 
transformers are larger in size and heavier per kW rating than their 
counterparts, sometimes by more than 40 percent, leading to issues 
related to space and weight, such as placement in existing vaults where 
clearances must be maintained for safety reasons, or placement on poles 
designed to hold a specific weight. (Idaho Falls Power, No. 77 at p. 1; 
Fall River, No. 83 at p. 2)
    WEG commented that another major consideration, especially for 
urban areas, will be physical space requirements, as distribution 
transformers in major cities are often located in some variety of 
physical structure with specific limitations as to what size 
transformer can be installed. WEG commented that increased overall 
transformer size could drive a significant civil engineering issue in 
urban areas to accommodate transformers that meet these amended 
standards. (WEG, No. 92 at p. 2)
    As shown in in Table IV.17 through Table IV.19, DOE expects the 
maximum weight increase from amended standards to be no greater 25 
percent for three-phase liquid-immersed transformer over 2500 kVA, 
representing less than 0.5 percent of unit shipped. This is much less 
than 50 percent increase indicated by NEMA. DOE notes that for the vast 
majority of unit shipped (small single-phase up to and including 100 
kVA), representing 91 percent of single-phase shipments, the impact on 
weight is an increase of between 1 and 2 percent.
c. Overhead (Pole) Mounted Transformers
    Highline Electric provided information describing its fleet of 
distribution transformers and limitations, including approximately 250 
banks of three 75 kVA pole-mount transformers and 500 banks of three 50 
kVA pole-mount transformers. Highline Electric commented that it 
currently does not deploy larger than 75 kVA pole-mount transformers 
due to pole load limitations and the proposed amended standards would 
result in new, standards compliant, 50 kVA transformers with a weight 
like existing baseline 75 kVA transformers, and compliant 75 kVA 
transformers with a weight more than a baseline100 kVA pole-mount unit. 
Highline Electric added that it discontinued use of 100 kVA pole-mount 
units decades ago after outage records indicated such installations 
were prone to unacceptable rates of pole failure. (Highline Electric, 
No. 71 at pp. 1-2)
    Further, Highline Electric commented that if transformer weights 
are increased by 20-40 percent, compliant 75 kVA transformers could not 
be installed on Highline Electric's standard class of poles. Highline 
Electric commented it would instead have to: (1) Utilize pole-mount 
transformers that predate the proposed amended standards, which would 
require a two-man crew with a material handler truck plus a few hours 
of labor and can be done proactively or reactively during outage 
conditions; (2) Convert to pad-mount transformers, which would require 
a 3-plus man crew, a digger derrick truck, and enough hours of labor 
that such an operation could only be completed proactively as it would 
require unacceptably long outage restoration times; or, (3) Replace the 
existing pole to a much heavier-class of pole, which would require a 3-
plus man crew, a digger derrick truck, and enough hours of labor that 
such an operation could only be completed proactively as it would 
require unacceptably long outage restoration times--this option assumes 
that the heavier-class of pole is available at the time of need. 
(Highline Electric, No. 71 at p. 2)
    Idaho Power commented that it considers the 25-percent estimate for 
pole replacements to be too low, as it is likely that every transformer 
larger than 100 kVA on its distribution system would require an upsized 
pole. Idaho Power commented this may also be the case for 50 kVA and 75 
kVA transformers. Idaho Power recommended that DOE consider increasing 
the 25-percent replacement number used in 2013 to better reflect the 
impact of the additional weight from amorphous core transformers on 
pole replacements. (Idaho Power, No. 139 at pp. 5-6) Additionally, 
Idaho Power stated it had designs for a few pole-mounted transformers 
with amorphous cores, noting that for 50 kVA and smaller transformers, 
the additional weight is not enough to increase the installation cost, 
but for transformers 100 kVA and larger, the weights increased between 
40 and 60 percent and will likely require higher class poles resulting 
in increased installation costs. (Idaho Power, No. 139 at p. 5)
    Alliant Energy commented that DOE's proposal presents 
implementation and installation challenges given the greater size and 
weight of amorphous core distribution transformers, which may require 
additional pole replacement, larger trucks for transport, and the use 
of cranes for installation. (Alliant Energy, No. 128 at p. 3)
    Howard and Chamber of Commerce commented that the proposed amended 
standards may require the upgrading and/or full replacement of the 
brackets as IEEE standards stipulate that the top support lug must be 
at least five times the transformer weight. Howard and Chamber of 
Commerce commented that for most manufacturers, the current transformer 
weight limit for support lug A is about 1000 lbs., B is about 3000 
lbs., and Big B is 4000 lbs. Further, Howard and Chamber of Commerce 
commented that the new designs under this NOPR would also increase tank 
diameters, moving the center of gravity further away from the pole 
interface and increasing the moment force on the pole bracket. (Howard, 
No. 116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 1) Highline 
Electric commented that pole replacements are not directly attributable 
to the larger kVA capacity, but rather are attributable to the weight 
of these larger kVA units. Highline Electric commented that poles are 
not rated to hold certain amounts of kVA capacity in the air; they are 
rated to hold certain pounds in weight and certain pounds in wind-
loading (cross-sectional area of a transformer bank). (Highline 
Electric, No. 71 at p. 1)
    Southwest Electric commented that the proposed amended standard for 
single-phase designs, which typically include simpler cooling 
capability (fins versus cooling plates), will result in percent 
increases in tank and conductor weights exceeding that of 3-phase, 
raising the significant problem that most single-phase transformers are 
mounted overhead via utility poles, scaffolding, or some other 
platform. Southwest Electric commented that the increased weight of 
NOPR-compliant transformers could lead to further potential outages, 
pushing these annual costs even higher. (Southwest Electric, No. 87 at 
p. 3)
    EEI, Entergy, and Pugh Consulting commented that the electric 
utility industry is experiencing constraints with wood pole supplies, 
especially poles with higher strength capacities, and an increase in 
demand for stronger poles could cause additional challenges. (Entergy, 
No. 114 at p. 4; Pugh Consulting, No. 117 at p. 5; EEI, No. 135 at pp. 
21-24)
    DOE's analysis at the amended standard levels indicate the 
following weight increases for overhead mounted distribution 
transformers. DOE's engineering and LCC analysis of overheard 
transformers are conducted for the representative units discussed in 
section IV.C.1, representative unit 2 (25 kVA) and representative unit 
3 (500 kVA). DOE has scaled the weights determined in the engineering, 
and selected in the LCC model to the other common capacities shown in 
Table IV.17. These show that the increased

[[Page 29944]]

weight under amended standards is projected to be modest, under 10 
percent for transformers up to and including 100 kVA in capacity--which 
is approximately 95 percent of all single-phase shipments (in terms 
units) and 99 percent of overhead shipments (in terms of units). 
Further, the projected weights, except for 833 kVA, which are less than 
0.05 percent of annual overhead units shipped, are not expected to 
change the application of the support lugs mentioned by NEMA from 
current practices.\164\ The modest weight increases are below the 
supplied thresholds for premature pole change outs supplied by Highline 
Electric and Idaho Power and consequently are not expected results in 
undue burden of requiring new, higher-grade poles.
---------------------------------------------------------------------------

    \164\ Overhead transformers at 833 kVA represent less than 0.01 
precent of units shipped. See section G for detailed shipments 
projections.
---------------------------------------------------------------------------

    DOE cannot directly comment on the availability of wooden poles at 
higher strength classes. The comments from EEI, Entergy, and Pugh 
Consulting did not state which classes of poles they considered 
commonly used, or which classes of poles are considered higher 
strength. DOE reiterates that the increase in transformer weight 
determined in its analysis is expected to be sufficiently modest 
(estimated to be less than 20 percent), that it will not likely disrupt 
the current wooden pole supply chains, and not in the 40 to 60-percent 
range suggested by stakeholders. There is insufficient information to 
justify increased installation costs given the modest projected 
increase in equipment weight resulting from amended standards, however, 
DOE recognizes the uncertainty surrounding installation costs because 
it is a complex issue. DOE's technical analysis in appendix 8F of this 
final rule TSD shows there to be minimal load bearing impact on the 
structures used to mount overhead distribution transformers resulting 
from amended standards. However, each utility's distribution system is 
unique with different equipment build-outs of different vintages. Given 
the heterogeneous nature of distribution systems it is not possible for 
DOE to account for every potential hypothetical installation 
circumstance. To account for the uncertainty faced by distribution 
utilities raised in the comments above, DOE has increased the fraction 
of installations that will face additional costs from 5 percent in the 
January 2023 NOPR to 50 percent when the weight increase over current 
baseline equipment is greater than 10 percent.
    NRECA commented that DOE analysis assumes like-for-like pole 
replacements, which is misguided. NRECA commented it expects that more 
transformer replacements will be necessary to allow for greater-
capacity transformers due to electrification, thus requiring larger 
poles. (NRECA, No. 98 at p. 6)
    In response to NRECA, for the purpose of estimating the cost and 
benefits to consumers from a modeling perspective DOE needs to bound 
the issue of what is considered a replacement versus new installation. 
While NRECA comments that it expects future replacements to be of 
greater capacity than what is currently installed, NRECA did not 
provide any information on what it considers the current typical 
capacity, and what they'd be replaced with in the future. DOE can agree 
with NRECA that, in practice, replacing a 25 kVA overhead with a new 50 
kVA to maintain current levels of service can reasonably be considered 
a replacement. However, DOE maintains that, for example, installing a 
167 kVA in the place of a 25 kVA to meet new service would be a new 
installation, as it would require additional planning, secondary 
conductors, and likely a new structure (pole).
Replacement Costs
    Idaho Power typically charges between $3,500-5,000 for a pole 
replacement. (Idaho Power, No. 139 at p. 6) SBA provided cost estimates 
for wooden poles range anywhere from $500 to $1,400 per pole depending 
on labor and material shipping costs for small utilities. (SBA, No. 100 
at p. 6) WEC commented that it does not install transformers over 4,500 
lbs. on a single pole. To change to a two-pole structure will cost from 
$10,000 to $15,000 per transformer, assuming there is room for a two-
pole structure which is not viable in all locations. WEC further 
commented it would cost anywhere from $2,000 to $10,000 to change out 
the pole for a single transformer depending on its location and what 
other equipment is installed on the pole, which could lead to increased 
costs beyond these estimates. (WEC, No. 118 at p. 2)
    Based on the comments from Idaho Power, SBA and WEC DOE examined 
the values it used in the NOPR for the cost of pole replacement. DOE 
derived its values based on the RSMeans 2023, and found that the 
average price of a new single-pole installation ranged in cost, 
equipment and labor, (excluding profit, and excavation) ranged from 
$504 to $3,125 for 30 and 70 foot treated poles, respectively. The data 
from RSMeans indicates a strong relationship between pole length and 
cost, and did not include the additional cost for excavation that would 
be incurred by a utility. While the stakeholders did not provide the 
pole length or grades associated with the supplied costs, which DOE 
would expect such costs to vary on a utility-by-utility bases. Based on 
the information provided by stakeholders and RSMeans DOE has updated 
its pole replacement cost distribution for this final rule, which is a 
triangular distribution, for single-pole structures: low: $2,025; mode: 
$4,012; high: $5,999. And for multi-pole structures: low: $5,877; mode: 
$11,388; high: $16,899.
d. Surface (Pad) Mounted Transformers
    WEC and Xcel Energy commented that pad-mounded 167 kVA single-phase 
transformers will roughly increase in size (1-4 inches) under the 
proposed amended standards, and that this increase of the dimensional 
footprint will be incompatible with pad and fiberglass box-pad 
foundations that the current transformers are using and have used for 
many decades. WEC and Xcel Energy stated that this will make it more 
difficult to use existing underground infrastructure (trench and 
connections) for transformer changeouts and may result in extra digging 
to install a compatible fiberglass box and pad. (Xcel Energy, No. 127 
at p. 1; WEC, No. 118 at pp. 2-3)
    Southwest Electric commented that the proposed amended standard for 
3-phase designs will result in a significant weight increase, exceeding 
the weights the pads were designed to support--especially in areas 
where seismic zoning requires additional anchoring. (Southwest 
Electric, No. 87 at pp. 2-3)
    Howard commented that it and other manufacturers have difficulty 
meeting some utilities' pad dimensions at the current efficiency 
levels. Howard commented it had taken exception to required footprint 
dimensions in the past for 100 kVA and above dual voltage and 167 kVA 
and above straight voltage transformers for many utilities. Regarding 
three-phase pads, Howard commented that utilities may have two or three 
different pad sizes, and a bigger footprint for transformers will 
require utilities to utilize large pad sizes. (Howard, No. 116 at p. 
21)
    In response to these comments, DOE's analysis shows an increase in 
weight and footprint area of 7 and 3 percent, respectively, for single-
phase surface-mounted liquid-immersed distribution transformers up to 
and including 100 kVA, and an increase in weight and

[[Page 29945]]

footprint area of 18 and 19 percent, respectively, for single-phase 
liquid-immersed surface mounted distribution transformers greater 
than100 kVA designed to meet the current standard, see Table IV.17. 
Additionally, DOE's analysis shows that that the impacts to weight and 
footprint area of three-phase surface mounted distribution transformers 
to be 4 and 1 percent, respectively, for capacities up to 500 kVA, 
while for capacities equal to or greater than 500 kVA the increase in 
weight and footprint area is 2 and 1 percent (5 and 1 percent for 500 
kVA) over current standards, see Table IV.19. Commenters did not 
provide enough information to directly model the costs of increasing 
pad, or fiberglass box size; however, for some of the capacity ranges 
the increase in weight, particularly for single-phase surface-mounted 
distribution transformers over 100 kVA, may be enough to trigger the 
need to use additional materials or different crews to complete 
installations. While the specifics are not available to DOE, to capture 
these additional costs DOE increased the fraction of installation from 
5 percent in the NOPR (88 FR 1777) to 50 percent in this final rule.
e. Logistics and Hoisting
    Chamber of Commerce, EEI, Portland General Electric, WEC, and 
Southwest Electric commented that heavier transformers may trigger 
transportation and hoisting considerations and challenges, likely 
requiring flatbed trucks, additional permitting, and cranes to install. 
These commenters stated that weight and access restrictions for roads 
and certain areas, especially in rural places, may create further 
challenges for replacements of transformers. (Portland General 
Electric, No. 130 at p. 4; Southwest Electric, No. 87 at pp. 2-3; 
Chamber of Commerce, No. 88 at pp. 4-5; EEI, No. 135 at pp. 24-28; WEC, 
No. 118 at pp. 2-3) SPA commented that small utilities were concerned 
whether their current equipment (namely trucks and lifts) will be able 
to handle increased sizes and weights. (SBA, No. 100 at p. 6) Chamber 
of Commerce commented that larger transformers will consume more 
storage space on an individual basis than current GOES models, thereby 
reducing the number of units that can be held in reserve to support 
system restoration efforts. (Chamber of Commerce, No. 88 at pp. 4-5)
    As discussed in sections IV.F.4.c and IV.F.4.d of this document, 
DOE's analysis shows that the projected increase in size and weight of 
transformers under amended standards to be modest, which DOE believes 
will not be disruptive to current logistics and hoisting procedures.
f. Installation of Ancillary Equipment: Gas Monitors and Fuses
    APPA insinuated that DOE did not account for the costs associated 
with more than 10 million gas monitors, which would equate to $25 
billion in additional costs, and that these additional costs alone 
would exceed the $13 billion of economic benefits cited in the NOPR. 
APPA further stated that DOE's analysis did not consider the additional 
cost of labor to remove and install the gas monitor and the cost of a 
replacement transformer. (APPA, No. 103 at p. 11)
    DOE disagrees with the assertions from APPA that there would be an 
additional cost of $25 billion to consumers of distribution 
transformers for the removal and installation of gas monitor or other 
ancillary equipment not related to the transformer's efficiency. A gas 
monitor is a device installed by the customer that monitors the 
conditions of the transformer's internal insulating fluid to help 
predict future equipment faults. Due to the additional cost, they are 
typically installed by utilities on larger capacity (kVA) transformers 
for operational reliability, with their installation occurring 
regardless of the efficiency of the transformer. Further, DOE has never 
prescribed the use of gas monitors for distribution transformers; gas 
monitors are installed at the discretion of each individual utility, 
and outside the scope of DOE's authority. DOE has not included the use 
of gas monitoring equipment in this final rule.
    APPA commented that amorphous core transformers experience higher 
inrush currents, creating the need for external protective devices 
(e.g., fuses) to be reviewed and changed. APPA commented that the 
amount of core steel significantly increases, creating a much heavier 
device that could force the utility to rerate framing hardware while 
increasing pole size and class and potentially increasing costs in a 
way that DOE has not addressed. (APPA, No. 103 at p. 15)
    DOE's installation costs analysis includes increasing installation 
costs as a function of transformer weight. As generally indicated by 
stakeholders through their comments, there are many factors and costs 
that are unique to each utility's operating procedures; as such, these 
factors are beyond the practicality of DOE to model in detail. As 
discussed in section IV.F.4.c of this document, DOE increased the 
fraction of installations which would incur additional cost under 
amended standards from 5 to 50 percent to account for the circumstances 
described by APPA. This fraction is constant at all considered 
efficiency levels above the baseline.
g. Low-Voltage Dry-Type
    Increased floor space to store the LVDT units--product is 
commercially available off the shelf (COTS) device (Schneider, No. 101 
at p. 15) Powersmiths commented that an amended standard for LVDT, 
which requires amorphous cores would, for retrofits, to be successful 
the replacement transformers. In addition to customization to meet 
footprint needs, they will require design changes to match terminal 
layout, impedance. temperature rise and k-rating. These accommodations, 
while possible today with GOES core transformers, will further increase 
the level of difficulty of retrofitting with amorphous-based 
transformers. Many older transformers are closer to people than newer 
buildings so any increase the audible noise is a big issue--noise is 
one of the biggest complaints from users, itself driving retrofit 
projects.'' (Powersmiths, No. 112 at p. 4-5)
    To alleviate concerns from Schneider and Powersmiths regarding 
potential installation issues arising from moving to amended standard 
that are achievable only using amorphous core materials, the amended 
standards in this final rule are set at level that is achievable with 
GOES core materials, TSL 3.
5. Annual Energy Consumption
    For each sampled customer, DOE determined the energy consumption 
for a distribution transformer at different efficiency levels using the 
approach described previously in section IV.E of this document.
6. Energy Prices
    DOE derived average and marginal electricity prices for 
distribution transformers using two different methodologies to reflect 
the differences in how the electricity is paid for by consumers of 
distribution transformers. For liquid-immersed distribution 
transformers, which are largely owned and operated by electric 
distribution companies who purchase electricity from a variety of 
markets, DOE developed an hourly electricity cost model. For low- and 
medium-voltage dry-type, which are primarily owned and operated by 
commercial and industrial entities, DOE developed a monthly electricity 
cost model.
    Fall River commented that the amended standards would in turn drive 
up costs, which would ultimately be

[[Page 29946]]

borne by rate payers where energy burdens are already growing at a 
severe rate. (Fall River, No. 83 at p. 2) DOE notes that any amended 
standard is determined based on the specific criteria discussed in 
section III.F.1 of this document, and in the context of Fall River's 
comment criteria III.F.1.b of this document. The results in section 
V.B.1.a of this document show that most consumers are projected to show 
a net benefit from amended standards.
    DOE did not receive any further comments regarding its electricity 
costs analysis and maintained the approach used in the NOPR for this 
final rule.
7. Maintenance and Repair Costs
    Repair costs are associated with repairing or replacing product 
components that have failed in an appliance; maintenance costs are 
associated with maintaining the operation of the product. Typically, 
small incremental increases in product efficiency produce no, or only 
minor, changes in repair and maintenance costs compared to baseline 
efficiency products. In the NOPR analysis, DOE asserted that 
maintenance and repair costs do not increase with transformer 
efficiency.
    Cliffs commented that the costs of the rule would not outweigh the 
benefits if the substantial increase in price and maintenance 
requirements for amorphous metal cores were properly accounted for. 
(Cliffs, No. 105 at p. 16) However, Cliffs did not specify how 
amorphous metal cores increase the maintenance costs of a transformer 
nor did it provide any data to showcase these higher costs. DOE 
understands that most distribution transformers incur few maintenance 
or repairs throughout their product lifetime and typically none to the 
transformer core. As discussed in sections IV.A.4.a and IV.G.3 of this 
document, both amorphous and GOES cores can be rewound and rebuilt. DOE 
does not have any data to support that amorphous core transformers 
would be subject to substantially higher maintenance costs than GOES 
core transformers.
    DOE did not receive any comments on this assertion and continued 
its assumptions that maintenance and repair costs do not increase with 
transformer efficiency for this final rule analysis.
8. Transformer Service Lifetime
    For distribution transformers, DOE used a distribution of 
lifetimes, with an estimated average of 32 years and a maximum of 60 
years.\165\ 78 FR 23336, 23377. DOE received the following comments on 
transformer service lifetime. Prolec GE and NEMA commented that the 
current estimated transformer lifetime of 32 years is adequate, as 
distribution transformers are extremely durable. However, Prolec GE and 
NEMA noted, certain factors might accelerate transformer replacement 
rates, such as increased trends in transformer loading practices due to 
electrification and decarbonization initiatives. (Prolec GE, No. 120 at 
p. 13; NEMA, No. 141 at p. 16) APPA commented that GOES service 
transformers are typically run to failure (no operations and 
maintenance costs) and last 40 to 70 years and that amorphous 
distribution transformers are likely to have a lifetime of 20 to 40 
years. (APPA, No. 103 at p. 11)
---------------------------------------------------------------------------

    \165\ Barnes, P. R., Van Dyke, J. W., McConnell, B. W. & Das, S. 
Determination Analysis of Energy Conservation Standards for 
Distribution Transformers. (Oak Ridge National Laboratory, 1996).
---------------------------------------------------------------------------

    In response to Prolec GE, NEMA, and APPA, DOE characterizes 
transformer lifetimes as distribution of the possibility of equipment 
failure in each year up to the estimated maximum lifetime--in this case 
60 years--to account for circumstances where the transformer either 
fails prematurely (degradation from heat or otherwise) or is 
prematurely removed from service. APPA's range of service lifetimes for 
GOES and amorphous distribution transformers overlaps considerably with 
DOE's estimates. Additionally, DOE finds the APPA discussion from 
Australia regarding high amorphous failure rates to be excessively 
speculative, based on anecdotal discussion with unknown persons 
regarding an unknown sample size of distribution transformers of 
unknown vintage in a jurisdiction that operates on a fundamentally 
different frequency (50 hertz versus 60 hertz), and presented without 
citation, data, or analysis. For this final rule DOE is maintaining the 
distribution of service lifetimes from the NOPR; the distribution is 
shown in Table IV.20.

[[Page 29947]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.547

9. Discount Rates
    The discount rate is the rate at which future expenditures are 
discounted to estimate their present value. DOE employs a two-step 
approach in calculating discount rates for analyzing customer economic 
impacts (e.g., LCC). The first step is to assume that the actual cost 
of capital approximates the appropriate customer discount rate. The 
second step is to use the capital asset pricing model (CAPM) to 
calculate the equity capital component of the customer discount rate. 
For this final rule, DOE estimated a statistical distribution of 
commercial customer discount rates that varied by distribution 
transformer category, by calculating the cost of capital for the 
different varieties of distribution transformer owners.
    DOE's method views the purchase of a higher-efficiency appliance as 
an investment that yields a stream of energy cost savings. DOE derived 
the discount rates for the LCC analysis by estimating the cost of 
capital for companies or public entities that purchase distribution 
transformers. For private firms, the weighted average cost of capital 
(WACC) is commonly used to estimate the present value of cash flows to 
be derived from a typical company project or investment. Most companies 
use both debt and equity capital to fund investments, so their cost of 
capital is the weighted average of the cost to the firm of equity and 
debt financing, as estimated from financial data for publicly traded 
firms in the sectors that purchase distribution transformers.\166\ As 
discount rates can differ across industries, DOE estimates separate 
discount rate distributions for a number of aggregate sectors with 
which elements of the LCC building sample can be associated.
---------------------------------------------------------------------------

    \166\ Previously, Damodaran Online provided firm-level data, but 
now only industry-level data is available, as compiled from 
individual firm data, for the period of 1998-2018. The data sets 
note the number of firms included in the industry average for each 
year.
---------------------------------------------------------------------------

    DOE did not receive any comments in the NOPR to its approach to 
determining discount rates and maintained the same approach in this 
final rule. The discount rates applied to consumers of liquid-immersed 
distribution transformers are shown in Table IV.21, and those applied 
to low- and medium-voltage dry-type distribution transformers are shown 
in Table IV.22.

[[Page 29948]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.548

[GRAPHIC] [TIFF OMITTED] TR22AP24.549

    See chapter 8 of the NOPR TSD for further details on the 
development of consumer discount rates.
10. Energy Efficiency Distribution in the No-New-Standards Case
    To accurately estimate the share of consumers that would be 
affected by a potential energy conservation standard at a particular 
efficiency level, DOE's LCC analysis considered the projected 
distribution (market shares) of product efficiencies under the no-new-
standards case (i.e., the case without amended or new energy 
conservation standards) in the compliance year. This approach reflects 
the fact that some consumers may purchase products with efficiencies 
greater than the baseline levels in the absence of new or amended 
standards. To determine an appropriate basecase against which to 
compare various potential standard levels, DOE used the purchase-
decision model described in section IV.F.3 of this document, where 
distribution transformers are purchased based on either lowest first 
cost or lowest TOC (with BOE). In the no-new-standards case, 
distribution transformers are chosen from among the entire range of 
available distribution transformer designs for each representative unit 
simulated in the engineering analysis based on this purchase-decision 
model with the core material constraints discussed in section IV.F.3.a 
of this document. This selection is constrained only by purchase price 
in most cases (90 percent, and 100 percent for liquid-immersed and all 
dry-type transformers, respectively) and reflects the MSPs of the 
available designs determined in the engineering analysis in section 
IV.C of this document.
    DOE did not receive any comments regarding its methodology of 
determining its energy efficiency distribution in the no-new-standards

[[Page 29949]]

case and maintained the methodology from the NOPR in this final rule.
11. Payback Period Analysis
    The PBP is the amount of time (expressed in years) it takes the 
consumer to recover the additional installed cost of more-efficient 
products, compared to baseline products, through energy cost savings. 
PBPs that exceed the life of the product mean that the increased total 
installed cost is not recovered in reduced operating expenses.
    The inputs to the PBP calculation for each efficiency level are the 
change in total installed cost of the product and the change in the 
first-year annual operating expenditures relative to the baseline. DOE 
refers to this as a ``simple PBP'' because it does not consider changes 
over time in operating cost savings. The PBP calculation uses the same 
inputs as the LCC analysis when deriving first-year operating costs.
    As noted previously, EPCA establishes a rebuttable presumption that 
a standard is economically justified if the Secretary finds that the 
additional cost to the consumer of purchasing a product complying with 
an energy conservation standard level will be less than three times the 
value of the first year's energy savings resulting from the standard, 
as calculated under the applicable test procedure. (42 U.S.C. 
6295(o)(2)(B)(iii)) For each considered efficiency level, DOE 
determined the value of the first year's energy savings by calculating 
the energy savings in accordance with the applicable DOE test 
procedure, and multiplying those savings by the average energy price 
projection for the year in which compliance with the amended standards 
would be required.
    Carte commented that a study found that the increase to 2016 
transformer efficiencies will take approximately 80 years to payback 
(no citation provided) and questions what the PBP would be for the 
proposed standard level. (Carte, No. 140 at pp. 6-7) In response to 
Carte, DOE acknowledges that some consumers may be negatively affected 
by amended standards due to the details of how they operate their 
equipment. For example, consumers with low electricity costs may take 
longer to realize the benefits from more efficient equipment than might 
be seen from consumers with higher electricity costs. DOE's LCC 
analysis uses a Monte Carlo simulation to incorporate uncertainty and 
variability into the analysis precisely to capture and quantify the 
differences in costs and benefits to consumers Nationally. Carte's 
comment did not provide details for DOE to alter its LCC and PBP 
analysis. The PBPs of this final rule is shown in section V.C.1 through 
V.C.3 of this document.

G. Shipments Analysis

    DOE uses projections of annual product shipments to calculate the 
national impacts of potential amended or new energy conservation 
standards on energy use, NPV, and future manufacturer cash flows.\167\ 
The shipments model takes an accounting approach, tracking market 
shares of each product class and the vintage of units in the stock. 
Stock accounting uses product shipments as inputs to estimate the age 
distribution of in-service product stocks for all years. The age 
distribution of in-service product stocks is a key input to 
calculations of both the NES and NPV, because operating costs for any 
year depend on the age distribution of the stock.
---------------------------------------------------------------------------

    \167\ DOE uses data on manufacturer shipments as a proxy for 
national sales, as aggregate data on sales are lacking. In general, 
one would expect a close correspondence between shipments and sales.
---------------------------------------------------------------------------

    As in the NOPR, for this final rule DOE projected distribution 
transformer shipments for the no-new standards case by assuming that 
long-term growth in distribution transformer shipments will be driven 
by long-term growth in electricity consumption. For this final rule, 
DOE did not receive any comments regarding initial shipments estimates 
presented in the NOPR--which were based on data from the previous final 
rule, data submitted to DOE from interested parties and confidential 
manufacturer interviews. These initial shipments are shown for the 
assumed compliance year (2029), by distribution transformer category, 
in Table IV.23 through Table IV.25. DOE developed the shipments 
projection for liquid-immersed distribution transformers by assuming 
that annual shipments growth is equal to growth in electricity 
consumption (sales) for all sectors, as given by the AEO2023 forecast 
through 2050. DOE's model assumed that growth in annual shipments of 
dry-type distribution transformers would be equal to the growth in 
electricity consumption for COMMERCIAL AND INDUSTRIAL sectors, 
respectively. The model starts with an estimate of the overall growth 
in distribution transformer capacity, and then estimates shipments for 
particular representative units and capacities, using estimates of the 
recent market shares for different design and size categories.
    Idaho Power commented that it supported DOE's approach and believed 
it was still valid. (Idaho Power, No. 139 at p. 6)

[[Page 29950]]

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[GRAPHIC] [TIFF OMITTED] TR22AP24.551


[[Page 29951]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.552

1. Equipment Switching
    In the January 2023 NOPR, DOE stated MVDTs can be used as 
replacements for liquid-immersed distribution transformers, but DOE has 
historically considered it as an edge case due to the differences in 
purchase price as well as consumer sensitivity to first costs. At the 
time it proposed amended standards, DOE did not have sufficient data to 
model the substitution of liquid-immersed distribution transformers 
with MVDTs. DOE requested comment on the topic of using MVDT as a 
substitute for liquid-immersed distribution transformers. 88 FR 1754, 
1782. NEMA responded that this is not typical, and these two categories 
of distribution transformers coexist in the market. (NEMA, No. 141 at 
p. 16) Additionally, Prolec GE commented that switching tended to be 
with three-phase substation transformers for indoor applications. 
(Prolec GE, No. 120 at p. 13)
    In response to comments from NEMA and Prolec GE, DOE did not 
include the possible replacement of liquid-immersed distribution 
transformers with MVDT or vice versa in its analysis of this final 
rule.
2. Trends in Distribution Transformer Capacity (kVA)
    In response to the August 2021 Preliminary Analysis, NEMA commented 
that as consumer demand increases due to migration to all-electric 
homes and buildings, it stands to reason that kVA sizes will increase 
over time as infrastructure upgrades capacity to serve these consumer 
demands. Likewise, NEMA commented that investments in renewable energy 
generation would cause changes to transformer shipments, unit sizes, 
and selections, and that DOE should examine non-static capacity 
scenarios, where kVA of units by category increases over time as NEMA 
members express growth in average kVA of ordered units over time in 
recent years, presumably due to increased electrification of consumer 
and industrial applications. 88 FR 1722, 1782. In response to the NOPR, 
NEMA further commented that roughly 15 percent of the low-voltage 
commercial market is increasing their distribution capacity sizes, 
going from 500 kVA to 1,000 or 1,500 kVA. (NEMA, No. 141 at p. 16) 
Additionally, DOE has found evidence that a similar shift in 
transformer capacity occurs with liquid-immersed distribution 
transformer to meet increasing loads.\168\ DOE's approach to shifting 
capacities is discussed in section E.3.a, Idaho Power commented it 
believes the base data used in the April 2013 Standards Final Rule was 
scaled from 1992 and 1995 data, and there have been many energy 
efficiency standards that have been incorporated over the last 30 
years. Idaho Power recommended that DOE consider updating the standard 
to reflect current loading data and include advanced data collection 
methods that provide more granular data. Idaho Power added that many 
power companies have automated meter read data that could be leveraged 
for better analysis. (Idaho Power, No. 139 at p. 5)
---------------------------------------------------------------------------

    \168\ Dahal, S, Aswami D, Geraghty M, Dunckley, J. Impact of 
Increasing Replacement Transformer Sizing on the Probability of 
Transformer Overloads with Increasing EV Adoptions. 36th 
International Electric Vehicle Symposium and Exhibition Sacramento. 
California, USA, June 2023.
---------------------------------------------------------------------------

    DOE agrees with Idaho Power's comments that since the CBECS last 
included monthly demand and energy use profiles for respondents in 1992 
and 1995 editions that many energy efficiency standards have been 
promulgated. For its dry-type analysis, DOE used the hourly load data 
for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE 
TF (from 2020 and 2021) to scale

[[Page 29952]]

these monthly values in its loading analysis for low-, and medium-
voltage dry-type distribution transformers (see chapter 7 of this final 
rule TSD). DOE is aware that many utilities meter their customers using 
real-time meters; however, DOE does not have the authority to demand 
such data from said utilities. Instead, DOE must rely on such industry 
initiatives such as the IEEE TF or individual companies to voluntarily 
come forward with data.
3. Rewound and Rebuilt Equipment
    APPA estimated that more than 15 percent of transformers used 
Nationally are rebuilt/rewound units. These units would have been 
rebuilt/rewound by the owning utility or as a service performed by 
rewinding business. (APPA, No. 103 at p 11; NEMA, No. 141 at p. 15) 
Howard and APPA commented that rewinding was a common occurrence 
(especially for units greater than 300 kVA) and that the service life 
could be extended up to 60 years. (APPA, No. 103 at p. 11; Howard, No. 
116 at p. 21) However, NEMA responded that rebuilding, as they 
understood, did not typically occur with liquid-filled distribution 
transformers and was undertaken typically as a consequence of equipment 
failure unrelated to end of life. NEMA further commented that to its 
knowledge, no one was rebuilding low-voltage distribution transformers. 
(NEMA, No. 141 at p. 15)
    APPA continued that because most of a transformer's parts can be 
reused when rewinding (or when other repairs are made), it is possible 
that a new core could be installed in the old transformer, that costs 
could be lower, and that lead times could be currently shorter than 
purchasing new equipment. However, APPA stated that the rewinding 
equipment used for GOES core transformers is incompatible with 
amorphous core transformers, and for amorphous transformers the 
rewinding process is more complex (time-consuming) and therefore more 
expensive, resulting in a loss of benefit from rewinding to individual 
utilities and cutting the total available capacity of transformers. 
(APPA, No. 103 at pp. 11-12) Also, Idaho Power commented that it has 
refurbished some transformers and returned them to service. Idaho Power 
stated that this decision is based on reduced lead time and 
availability rather than cost, which is somewhat close between new and 
refurbished transformers. Idaho Power stated that its refurbished units 
are put back into inventory and used according to their nameplate data. 
(Idaho Power, No. 139 at p. 7)
    Despite the contradictory statements from NEMA and APPA, DOE is 
aware that transformer rewinding/repair is a service available to 
utilities, either as an ``in-house'' service or at an external repair 
shop that provides an additional avenue for utilities to maintain 
transformer stocks (as indicated by Idaho Power). DOE has viewed the 
rewind/repair services as additive and not in direct competition with 
new distribution transformer manufacturers. While APPA asserts that 
amorphous core rewinding may be more complex and diminishes the value 
of rewinding these transformers, DOE understands that rewinding this 
equipment is still possible and that a shift to amorphous core 
transformers does not negate the value of these services. Additionally, 
this final rule can be met with GOES core materials for approximately 
90 percent of projected annual units shipments.
    Regarding APPA's comment about reusing transformer parts to 
potential reduce lead times, DOE notes that the transformer rebuilding/
rewinding market has historically been relatively small. Rebuilding a 
distribution transformer requires additional labor (because labor is 
required both to deconstruct the transformer and rebuild it) that has 
made purchasing a new distribution transformer the preferred option 
when replacing a failed transformer. While recently there has been an 
uptick in transformer rebuilds, that is primarily a function of long 
lead times for new transformers and likely temporary as the transformer 
market recalibrates. Further, in response to Howard, as rewound 
equipment falls outside the scope of DOE authority, they are not 
considered in this final rule.

H. National Impact Analysis

    The NIA assesses the national energy savings (NES) and the NPV from 
a national perspective of total consumer costs and savings that would 
be expected to result from new or amended standards at specific 
efficiency levels.\169\ (``Consumer'' in this context refers to 
consumers of the product being regulated.) DOE calculates the NES and 
NPV for the potential standard levels considered based on projections 
of annual product shipments, along with the annual energy consumption 
and total installed cost data from the energy use and LCC analyses. For 
the present analysis, DOE projected the energy savings, operating cost 
savings, product costs, and NPV of consumer benefits over the lifetime 
of distribution transformers sold from 2029 through 2058.
---------------------------------------------------------------------------

    \169\ The NIA accounts for impacts in the 50 states and U.S. 
territories.
---------------------------------------------------------------------------

    DOE evaluates the impacts of new or amended standards by comparing 
a case without such standards with standards-case projections. The no-
new-standards case characterizes energy use and consumer costs for each 
product class in the absence of new or amended energy conservation 
standards. For this projection, DOE considers historical trends in 
efficiency and various forces that are likely to affect the mix of 
efficiencies over time. DOE compares the no-new-standards case with 
projections characterizing the market for each product class if DOE 
adopted new or amended standards at specific energy efficiency levels 
(i.e., the TSLs or standards cases) for that class. For the standards 
cases, DOE considers how a given standard would likely affect the 
market shares of products with efficiencies greater than the standard.
    DOE uses a spreadsheet model to calculate the energy savings and 
the national consumer costs and savings from each TSL. Interested 
parties can review DOE's analyses by changing various input quantities 
within the spreadsheet. The NIA spreadsheet model uses typical values 
(as opposed to probability distributions) as inputs.
    Table IV.26 summarizes the inputs and methods DOE used for the NIA 
analysis for the final rule. Discussion of these inputs and methods 
follows the table. See chapter 10 of the final rule TSD for further 
details.

[[Page 29953]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.553

1. Equipment Efficiency Trends
    A key component of the NIA is the trend in energy efficiency 
projected for the no-new-standards case and each of the amended 
standards cases. Section IV.F.3 of this document describes how DOE 
developed an energy efficiency distribution for the no-new-standards 
case for each of the considered equipment classes for the year of 
anticipated compliance with an amended or new standard. As discussed in 
section IV.F.3 of this document, DOE has found that the vast majority 
of distribution transformers are purchased based on first cost. For 
both the no-new-standards case and amended standards case, DOE used the 
results of the consumer choice mode in the LCC, described in section 
IV.F.3 of this document, to establish the shipment-weighted efficiency 
for the year potential standards are assumed to become effective 
(2029). For this final rule, despite the availability of a wide range 
of efficiencies, DOE modelled that these efficiencies would remain 
static over time because the purchase decision is largely based on 
first costs (see section IV.F.3 of this document) and DOE's application 
of constant future equipment costs (see section IV.F.1 of this 
document).
2. National Energy Savings
    The national energy savings analysis involves a comparison of 
national energy consumption of the considered products between each TSL 
and the case with no new or amended energy conservation standards. DOE 
calculated the national energy consumption by multiplying the number of 
units (stock) of each product (by vintage or age) by the unit energy 
consumption (also by vintage). DOE calculated annual NES based on the 
difference in national energy consumption for the no-new-standards case 
and for each higher-efficiency standard case. DOE estimated energy 
consumption and savings based on site energy and converted the 
electricity consumption and savings to primary energy (i.e., the energy 
consumed by power plants to generate site electricity) using annual 
conversion factors derived from AEO2023. For natural gas, primary 
energy is the same as site energy. Cumulative energy savings are the 
sum of the NES for each year over the timeframe of the analysis.
    Use of higher-efficiency equipment is occasionally associated with 
a direct rebound effect, which refers to an increase in utilization of 
the equipment due to the increase in efficiency and its lower operating 
cost. A distribution transformer's utilization is entirely dependent on 
the aggregation of the connected loads on the circuit the distribution 
transformer serves. Greater utilization would result in greater PUL on 
the distribution transformer. Any increase in distribution transformer 
PUL is coincidental and not related to rebound effect. NEMA and Howard 
agreed that a rebound effect is not needed for distribution 
transformers analysis. (NEMA, No. 141 at p. 16; Howard, No. 116 at p. 
22) Howard additionally speculated that a possible caveat to this is 
that utility companies could conceivably be inclined to increase the 
load on more efficient transformers. (Howard, No. 116 at p. 22)
    For this final rule, DOE has maintained the approach used in the 
NOPR and has not applied an additional rebound effect in the form of 
additional load. DOE accounts for incidental load growth on the 
distribution transformer resulting from additional connections not 
related to the rebound effect due to increased equipment efficiency in 
the LCC analysis in the form of future load growth. See section 0 for 
more details on DOE approach to load growth.
    In 2011, in response to the recommendations of a committee on 
``Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy 
Efficiency Standards'' appointed by the National Academy of Sciences, 
DOE announced its intention to use FFC

[[Page 29954]]

measures of energy use and greenhouse gas and other emissions in the 
national impact analyses and emissions analyses included in future 
energy conservation standards rulemakings. 76 FR 51281 (Aug. 18, 2011). 
After evaluating the approaches discussed in the August 18, 2011 
notice, DOE published a statement of amended policy in which DOE 
explained its determination that EIA's National Energy Modeling System 
(NEMS) is the most appropriate tool for its FFC analysis and its 
intention to use NEMS for that purpose. 77 FR 49701 (Aug. 17, 2012). 
NEMS is a public domain, multi-sector, partial equilibrium model of the 
U.S. energy sector \170\ that EIA uses to prepare its Annual Energy 
Outlook. The FFC factors incorporate losses in production and delivery 
in the case of natural gas (including fugitive emissions) and 
additional energy used to produce and deliver the various fuels used by 
power plants. The approach used for deriving FFC measures of energy use 
and emissions is described in appendix 10B of the final rule TSD.
---------------------------------------------------------------------------

    \170\ For more information on NEMS, refer to The National Energy 
Modeling System: An Overview DOE/EIA-0581(2023), May 2023 (Available 
at: https://www.eia.gov/outlooks/aeo/nems/overview/pdf/0581(2023).pdf) (Last accessed Oct. 23, 2023).
---------------------------------------------------------------------------

3. Net Present Value Analysis
    The inputs for determining the NPV of the total costs and benefits 
experienced by consumers are (1) total annual installed cost, (2) total 
annual operating costs (energy costs and repair and maintenance costs), 
and (3) a discount factor to calculate the present value of costs and 
savings. DOE calculates net savings each year as the difference between 
the no-new-standards case and each standards case in terms of total 
savings in operating costs versus total increases in installed costs. 
DOE calculates operating cost savings over the lifetime of each product 
shipped during the projection period.
    As discussed in section IV.F.1 of this document, DOE developed 
distribution transformers price trends based on historical PPI data. 
DOE applied the same trends to project prices for each product class at 
each considered efficiency level, which was a constant price trend 
through the end of the analysis period in 2058. DOE's projection of 
product prices is described in appendix 10C of the NOPR TSD.
    To evaluate the effect of uncertainty regarding the price trend 
estimates, DOE investigated the impact of different product price 
projections on the consumer NPV for the considered TSLs for 
distribution transformers. In addition to the default price trend, DOE 
considered two product price sensitivity cases: (1) a high price 
decline case based on the years between 2003 and 2019 and (2) a low 
price decline case based on the years between 1967 and 2002. The 
derivation of these price trends and the results of these sensitivity 
cases are described in appendix 10C of the NOPR TSD.
    The operating cost savings are energy cost savings, which are 
calculated using the estimated energy savings in each year and the 
projected price of the appropriate form of energy. To estimate energy 
prices in future years, DOE multiplied the average regional energy 
prices by the projection of annual national-average electricity price 
changes in the Reference case from AEO2023, which has an end year of 
2050. To estimate price trends after 2050, DOE maintained the price 
constant at 2050 levels. As part of the NIA, DOE also analyzed 
scenarios that used inputs from variants of the AEO2023 Reference case 
that have lower and higher economic growth. Those cases have lower and 
higher energy price trends compared to the Reference case. NIA results 
based on these cases are presented in appendix 10C of the final rule 
TSD.
    In calculating the NPV, DOE multiplies the net savings in future 
years by a discount factor to determine their present value. For this 
final rule, DOE estimated the NPV of consumer benefits using both a 3-
percent and a 7-percent real discount rate. DOE uses these discount 
rates in accordance with guidance provided by the Office of Management 
and Budget (OMB) to Federal agencies on the development of regulatory 
analysis.\171\ The discount rates for the determination of NPV are in 
contrast to the discount rates used in the LCC analysis, which are 
designed to reflect a consumer's perspective. The 7-percent real value 
is an estimate of the average before-tax rate of return to private 
capital in the U.S. economy. The 3-percent real value represents the 
``social rate of time preference,'' which is the rate at which society 
discounts future consumption flows to their present value.
---------------------------------------------------------------------------

    \171\ U.S. Office of Management and Budget. Circular A-4: 
Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 2, 2024). 
DOE used the prior version of Circular A-4 (September 17, 2003) in 
accordance with the effective date of the November 9, 2023 version.
---------------------------------------------------------------------------

I. Consumer Subgroup Analysis

    In analyzing the potential impact of new or amended energy 
conservation standards on consumers, DOE evaluates the impact on 
identifiable subgroups of consumers that may be disproportionately 
affected by a new or amended national standard. The purpose of a 
subgroup analysis is to determine the extent of any such 
disproportional impacts. DOE evaluates impacts on particular subgroups 
of consumers by analyzing the LCC impacts and PBP for those particular 
consumers from alternative standard levels. For this NOPR, DOE analyzed 
the impacts of the considered standard levels on two subgroups: (1) 
utilities serving low population densities and (2) utility purchasers 
of vault (underground) and subsurface installations. DOE used the LCC 
and PBP model to estimate the impacts of the considered efficiency 
levels on these subgroups. Chapter 11 in the NOPR TSD describes the 
consumer subgroup analysis.
1. Utilities Serving Low Customer Populations
    In rural areas, mostly served by electric cooperatives (COOPs), the 
number of customers per distribution transformer is lower than in 
metropolitan areas and may result in lower PULs.
    Idaho Power commented that low-population areas should include 
adjustments in the PUL and it supported the DOE adjustments to the PUL. 
Idaho Power commented that its transformers in rural areas do not 
experience the same levels of loading as in densely populated areas. 
(Idaho Power, No. 139 at p. 5) NEMA commented that for liquid-filled 
transformers, its members estimated PUL would typically be 10 percent 
of RMS-equivalent nameplate rating. (NEMA, No. 141 at p. 16) Further, 
PSE indicated that an increase in equipment costs of 50 percent would 
not be ideal for COOPs, as these additional costs would ultimately fall 
on their member-owners. (PSE, No. 98 at pp. 9-10)
    For this final rule, as in the January 2023 NOPR (88 FR 1722, 1785) 
and April 2013 Standards Final Rule, DOE reduced the PUL by adjusting 
the distribution of IPLs, as discussed in section IV.E.2.a of this 
document, resulting in the PULs shown below in Table IV.27. Further, 
DOE altered the customer sample to limit the distribution of discount 
rates (see section IV.F.9 of this document) to those observed by State 
and local governments discussed in IV.F.9 of this document.
    In the NOPR, DOE stated that while COOPs deploy a range of 
distribution transformers to serve their customers, in low population 
densities the most common unit is a 25 kVA pole overhead

[[Page 29955]]

liquid-immersed distribution transformer, which is represented in this 
analysis as representative unit 2B of equipment class 1B (small single-
phase liquid-immersed). NRECA suggested that 15 kVA transformers are 
used more commonly in areas with densities of six customers per mile. 
(NRECA, No. 98 at p. 7)
    DOE recognizes the suggestion by NRECA that the most common 
capacity used by their members to serve areas with very low customer 
densities would be 15 kVA. However, DOE's engineering analysis is 
limited to 25 kVA in this final rule, which is embodied in the results 
for equipment class 1B, single-phase distribution transformers up to 
and including 100 kVA.
    The results of the subgroups analysis are presented in section 
IV.I.1 for equipment class 1B. As equipment class 1B encompasses 
designs that are both pole-mounted (representative unit 2B) and pad-
mounted (representative unit 1B) these results represent the capacity 
scaled, shipment weighted average consumer benefits. NRECA stated that 
the 15 kVA pole mounted unit is the most used in low costumer density 
installations--this equipment is represented by representative unit 2B 
(a 25 kVA pole mount). It can be inferred through examining the LCC 
results by representative unit that shows that consumer benefits for 
pole mounted transformers are higher than those of pad mounted 
transformers, and that the consumer benefits for the 15 kVA pole 
mounted units would likely be greater than those shown for the entirety 
of equipment class 1B.\172\
---------------------------------------------------------------------------

    \172\ See appendix 8E of the TSD for LCC results by 
representative unit.
[GRAPHIC] [TIFF OMITTED] TR22AP24.554

2. Utility Purchasers of Vault (Underground) and Subsurface 
Installations
    In some urban areas, utilities provide service to customers by 
deploying parts of their transformer fleet in subsurface vaults, or 
other prefabricated underground concrete structures, referred to as 
vaults. At issue in the potential amended standards case is that the 
volume (ft\3\) of the more efficient replacement transformers may be 
too large to fit into the existing vault, which would have to be 
replaced to fit the new equipment. This analysis is applied to the 
representative units 15 and 16, specifically defined in the engineering 
analysis for vault and submersible liquid-immersed distribution 
transformers (see section IV.C.1 of this document).
    DOE received numerous comments on the topic of installing 
transformers in vaults: Subsurface and Confined Space Installations. 
APPA commented that its members do not have an inventory of existing 
vaults or their locations and dimensions; and that most vaults were 
built to ``fit'' the equipment that is housed within the vault, and 
currently many do not have ``safe working space'' for workers, given 
rules changes since they were built. APPA commented that such vaults 
are currently grandfathered into many of the work rules, but having to 
expand them to take a new transformer that is larger will mean also 
retrofitting them to safe working space rules. APPA added that under 
these circumstances, if the transformer is only 10 or 15 percent larger 
than the vault, expansion will likely be much larger. (APPA, No. 103 at 
p. 10)
    APPA commented that the $23,550 cost assigned in the NOPR to 
replace an existing vault by DOE is low for transformers installed in 
building interior vaults. By way of example, APPA commented that simple 
single-story buildings with parking lot-located vaults may cost at 
least $200,000; and there may be as much as a $4,000,000 to $50,000,000 
discrepancy in vault replacement cost for a multi-story building that 
would need to be braced and supported to have the foundation removed to 
expand the vault. (APPA, No. 103 at p. 9) Carte also speculated that in 
extreme cases, such as rooftop vaults, a weight increase could be 
achieved by reinforcing the structure. (Carte, No. 140 at p. 7) APPA 
and the Chamber of Commerce commented that DOE did not account for the 
potential of significant increased infrastructure replacement and 
business disruption costs that would be incurred if replacement 
transformers could not fit into existing locations. (Chamber of 
Commerce, No. 88 at p. 4; APPA, No. 103 at p. 9) Pugh Consulting 
commented that for submersible transformers, installing a new 
transformer that is larger than the existing vault size would lead to 
significant costs for utilities and municipal governments, including 
costs associated with potential soil testing to determine if soil can 
be removed and costs associated with shutting down streets, highways, 
and sidewalks while a vault is expanded. (Pugh Consulting, No. 117 at 
p. 6)
    DOE recognizes the potential for the cost to install transformers 
underground, or in building vaults to carry tremendous financial risk 
to utilities. While the examples provided by APPA, Carte, Chamber of 
Commerce, and Pugh Consulting are extreme cases where a utility's 
decision to alter or upgrade the existing installation location could 
lead to service disruptions, and maybe even health and safety 
liabilities. It is reasonable that utilities exercising good governance 
and financial responsibility to their ratepayers would approach such 
extreme projects only after exhausting all other avenues of maintaining 
service. As such DOE views these examples as edge cases. Further, 
stakeholders did not provide any technical information, such as 
specific transformer designs, weights, volumes; whether these cost 
estimates are for vaults that contain single or banks of multiple 
transformers from which DOE can improve its technical analysis. As such 
DOE is limited to revising its existing model. To address the cost 
concerns that stakeholders raised regarding the cost being too low in 
the NOPR, DOE reexamined the costs presented in RSMeans and found they 
lacked details such as excavation, disposal or fill--further they 
didn't account the additional costs associated with working in space 
confined spaces. To better capture these costs, for this final rule DOE 
has revised its transformer

[[Page 29956]]

vault installation cost function to the following:

Transformer Vault Installation Cost = 220.37 x DTVolume\1.1436\
[GRAPHIC] [TIFF OMITTED] TR22AP24.555

    The Efficiency Advocates commented that the creation of equipment 
classes for submersible distribution transformers (equipment class 12) 
will largely mitigate any size concerns regarding underground vaulted 
network transformer installations because the vast majority of these 
are submersible designs and thus would not have to meet the higher 
efficiency levels proposed for other liquid-immersed transformer 
equipment classes. (Efficiency Advocates, No. 75 at p. 35)
    DOE separated the vault and submersible equipment into their own 
equipment class (equipment class 12) which are designed to operate 
under higher heat loads which are experienced by equipment installed in 
enclosed spaces than general purpose distribution transformers. DOE is 
not amending standards for this equipment at this time precisely for 
the multitude of installation challenges described by commenters.

J. Manufacturer Impact Analysis

1. Overview
    DOE performed an MIA to estimate the financial impacts of amended 
energy conservation standards on manufacturers of distribution 
transformers and to estimate the potential impacts of such standards on 
employment and manufacturing capacity. The MIA has both quantitative 
and qualitative aspects and includes analyses of projected industry 
cash flows, the INPV, investments in research and development (R&D) and 
manufacturing capital, and domestic manufacturing employment. 
Additionally, the MIA seeks to determine how amended energy 
conservation standards might affect manufacturing employment, capacity, 
and competition, as well as how standards contribute to overall 
regulatory burden. Finally, the MIA serves to identify any 
disproportionate impacts on manufacturer subgroups, including small 
business manufacturers.
    The quantitative part of the MIA primarily relies on the Government 
Regulatory Impact Model (GRIM), an industry cash flow model with inputs 
specific to this rulemaking. The key GRIM inputs include data on the 
industry cost structure, unit production costs, equipment shipments, 
manufacturer markups, and investments in R&D and manufacturing capital 
required to produce compliant equipment. The key GRIM outputs are the 
INPV, which is the sum of industry annual cash flows over the analysis 
period, discounted using the industry-weighted average cost of capital, 
and the impact to domestic manufacturing employment. The model uses 
standard accounting principles to estimate the impacts of more-
stringent energy conservation standards on a given industry by 
comparing changes in INPV and domestic manufacturing employment between 
a no-new-standards case and the various standards cases (i.e., TSLs). 
To capture the uncertainty relating to manufacturer pricing strategies 
following amended standards, the GRIM estimates a range of possible 
impacts under different manufacturer markup scenarios.
    The qualitative part of the MIA addresses manufacturer 
characteristics and market trends. Specifically, the MIA considers such 
factors as a potential standard's impact on manufacturing capacity, 
competition within the industry, the cumulative impact of other DOE and 
non-DOE regulations, and impacts on manufacturer subgroups. The 
complete MIA is outlined in chapter 12 of the final rule TSD.
    DOE conducted the MIA for this rulemaking in three phases. In Phase 
1 of the MIA, DOE prepared a profile of the distribution transformer 
manufacturing industry based on the market and technology assessment, 
preliminary manufacturer interviews, and publicly available 
information. This included a top-down analysis of distribution 
transformer manufacturers that DOE used to derive preliminary financial 
inputs for the GRIM (e.g., revenues; materials, labor, overhead, and 
depreciation expenses; selling, general, and administrative expenses 
(SG&A); and R&D expenses). DOE also used public sources of information 
to further calibrate its initial characterization of the distribution 
transformer manufacturing industry, including company filings of form 
10-K from the SEC,\173\ corporate annual reports, the U.S. Census 
Bureau's ``Economic Census,'' \174\ and reports from D&B Hoovers.\175\
---------------------------------------------------------------------------

    \173\ See: www.sec.gov/edgar
    \174\ See: www.census.gov/programs-surveys/asm/data/tables.html
    \175\ See: app.avention.com
---------------------------------------------------------------------------

    In Phase 2 of the MIA, DOE prepared a framework industry cash flow 
analysis to quantify the potential impacts of amended energy 
conservation standards. The GRIM uses several factors to determine a 
series of annual cash flows starting with the announcement of the 
standard and extending over a 30-year period following the compliance 
date of the standard. These factors include annual expected revenues, 
costs of sales, SG&A and R&D expenses, taxes, and capital expenditures. 
In general, energy conservation standards can affect manufacturer cash 
flow in three distinct ways: (1) creating a need for increased 
investment, (2) raising production costs per unit, and (3) altering 
revenue due to higher per-unit prices and changes in sales volumes.
    In addition, during Phase 2, DOE developed interview guides to 
distribute to manufacturers of distribution transformers in order to 
develop other key GRIM inputs, including product and capital conversion 
costs, and to gather additional information on the anticipated effects 
of energy conservation standards on revenues, direct employment, 
capital assets, industry competitiveness, and subgroup impacts.
    In Phase 3 of the MIA, DOE conducted structured, detailed 
interviews with representative

[[Page 29957]]

manufacturers. During these interviews, DOE discussed engineering, 
manufacturing, procurement, and financial topics to validate 
assumptions used in the GRIM and to identify key issues or concerns. As 
part of Phase 3, DOE also evaluated subgroups of manufacturers that may 
be disproportionately impacted by amended standards or that may not be 
accurately represented by the average cost assumptions used to develop 
the industry cash flow analysis. Such manufacturer subgroups may 
include small business manufacturers, low-volume manufacturers (LVMs), 
niche players, and/or manufacturers exhibiting a cost structure that 
largely differs from the industry average. DOE identified one subgroup 
for a separate impact analysis: small business manufacturers. The small 
business subgroup is discussed in section VI.B, ``Review under the 
Regulatory Flexibility Act,'' and in chapter 12 of the final rule TSD.
2. Government Regulatory Impact Model and Key Inputs
    DOE uses the GRIM to quantify the changes in cash flow due to 
amended standards that result in a higher or lower industry value. The 
GRIM uses a standard, annual discounted cash flow analysis that 
incorporates manufacturer costs, manufacturer markups, shipments, and 
industry financial information as inputs. The GRIM models changes in 
costs, distribution of shipments, investments, and manufacturer margins 
that could result from amended energy conservation standards. The GRIM 
spreadsheet uses the inputs to arrive at a series of annual cash flows, 
beginning in 2024 (the base year of the analysis) and continuing to 
2058. DOE calculated INPVs by summing the stream of annual discounted 
cash flows during this period. For manufacturers of distribution 
transformers, DOE used a real discount rate of 7.4 percent for liquid-
immersed distribution transformers, 11.1 percent for LVDT distribution 
transformers, and 9.0 percent for MVDT distribution transformers, which 
was derived from the April 2013 Standards Final Rule and then modified 
according to feedback received during manufacturer interviews.\176\
---------------------------------------------------------------------------

    \176\ See Chapter 12 of the April 2013 Standards Final Rule TSD 
for discussion of where initial discount factors were derived, 
available online at www.regulations.gov/document/EERE-2010-BT-STD-0048-0760. For the April 2013 Standards Final Rule, DOE initially 
calculated a 9.1 percent discount rate, however during manufacturer 
interviews conducted for that rulemaking, manufacturers suggested 
using different discount rates specific for each equipment class 
group. During manufacturer interviews conducted for the January 2023 
NOPR, manufacturers continued to agree that using different discount 
rates for each equipment class group is appropriate.
---------------------------------------------------------------------------

    The GRIM calculates cash flows using standard accounting principles 
and compares changes in INPV between the no-new-standards case and each 
standards case. The difference in INPV between the no-new-standards 
case and a standards case represents the financial impact of amended 
energy conservation standards on manufacturers. As discussed 
previously, DOE developed critical GRIM inputs using a number of 
sources, including publicly available data, results of the engineering 
analysis, and information gathered from industry stakeholders during 
the course of manufacturer interviews. The GRIM results are presented 
in section V.B.2 of this document. Additional details about the GRIM, 
the discount rate, and other financial parameters can be found in 
chapter 12 of the final rule TSD.
a. Manufacturer Production Costs
    Manufacturing more efficient equipment is typically more expensive 
than manufacturing baseline equipment due to the use of more complex 
components, which are typically more costly than baseline components. 
The changes in the MPCs of covered equipment can affect the revenues, 
gross margins, and cash flow of the industry.
    During the engineering analysis, DOE used transformer design 
software to create a database of designs spanning a broad range of 
efficiencies for each of the representative units. This design software 
generated a bill of materials. DOE then applied markups to allow for 
scrap, handling, factory overhead, and other non-production costs, as 
well as profit, to estimate the MSP.
    These designs and their MSPs are subsequently inputted into the LCC 
customer choice model. For each efficiency level and within each 
representative unit, the LCC model uses a consumer choice model and 
criteria described in section IV.F.3 of this document to select a 
subset of all the potential designs options (and associated MSPs). This 
subset is meant to represent those designs that would actually be 
shipped in the market under the various analyzed TSLs. DOE inputted 
into the GRIM the weighted average cost of the designs selected by the 
LCC model and scaled those MSPs to other selected capacities in each 
design line's KVA range.
    For a complete description of the MSPs, see chapter 5 of the final 
rule TSD.
b. Shipments Projections
    The GRIM estimates manufacturer revenues based on total unit 
shipment projections and the distribution of those shipments by 
efficiency level. Changes in sales volumes and efficiency mix over time 
can significantly affect manufacturer finances. For this analysis, the 
GRIM uses the NIA's annual shipment projections derived from the 
shipments analysis from 2024 (the base year) to 2058 (the end year of 
the analysis period). See chapter 9 of the final rule TSD for 
additional details.
c. Product and Capital Conversion Costs
    Amended energy conservation standards could cause manufacturers to 
incur conversion costs to bring their production facilities and 
equipment designs into compliance. DOE evaluated the level of 
conversion-related expenditures that would be needed to comply with 
each considered efficiency level in each equipment class. For the MIA, 
DOE classified these conversion costs into two major groups: (1) 
product conversion costs; and (2) capital conversion costs. Product 
conversion costs are investments in research, development, testing, 
marketing, and other non-capitalized costs necessary to make equipment 
designs comply with amended energy conservation standards. Capital 
conversion costs are investments in property, plants, and equipment 
necessary to adapt or change existing production facilities such that 
new compliant equipment designs can be fabricated and assembled.
    For capital conversion costs, DOE prepared bottom-up estimates of 
the costs required to meet the analyzed amended energy conservation 
standards at each EL for each representative unit. Major drivers of 
capital conversion costs include changes in core steel variety (and 
thickness), core weight, and core stack height, all of which are 
interdependent and can vary by efficiency level. The MIA used the 
estimated quantity of the core steel (by steel variety) for each EL at 
each representative unit that was modeled as part of the engineering 
analysis and incorporated into the LCC analysis, to estimate the 
additional production equipment that the distribution transformer 
industry would need to purchase in order to meet each analyzed EL.
    Capital conversion costs are primarily driven at each EL by the 
potential need for the industry to expand production capacity for the 
potential increase in amorphous alloy used in distribution transformer 
cores. In the January 2023 NOPR, DOE estimated that an

[[Page 29958]]

amorphous production line capable of producing 1,200 tons annual of 
amorphous cores would cost approximately $1,000,000 in capital 
investments. This capital investment includes costs associated with 
purchasing annealing ovens, core cutting machines, lacing tables, as 
well as additional conveyors and cranes to move the potentially larger 
amorphous cores, new winding machines and assembly tools specific to 
amorphous core production. Lastly, this capital investment also 
accounts for the potential additional production floor space that could 
be needed to accommodate these additional or larger production 
equipment that would be required to manufacture amorphous cores. The 
quantity of amorphous cores are outputs of the engineering analysis and 
the LCC. At higher ELs, the percent of distribution transformers 
selected in the LCC consumer choice model that have amorphous cores 
increases. Additionally, at the highest ELs, the quantity of amorphous 
material per distribution transformer also increases. As the increasing 
stringency of the ELs drive the use of more amorphous cores in 
distribution transformers (and more amorphous material per distribution 
transformer), capital conversion costs increase.
    For product conversion costs, DOE understands the production of 
amorphous cores requires unique production expertise from a 
manufacturer's employees and engineering labor to create new equipment 
designs for distribution transformers using amorphous cores. For 
manufacturers without experience with amorphous core production, 
standards that would likely be met using amorphous cores would require 
the development or the procurement of the technical knowledge to 
produce cores as well as potentially re-training production employees. 
Because amorphous material is thinner and more brittle after annealing, 
materials management, safety measures, and design considerations that 
are not associated with non-amorphous materials would need to be 
implemented.
    In the January 2023 NOPR, DOE estimated product conversion costs 
would be equal to 100 percent of the normal annual industry R&D 
expenses for those ELs where a majority of the market would be expected 
to transition to amorphous material. These one-time product conversion 
costs would be in addition to the annual R&D expenses normally incurred 
by distribution transformer manufacturers. These one-time expenditures 
account for the design, engineering, prototyping, re-training of 
production employees, and other R&D efforts the industry would have to 
undertake to move to a predominately amorphous market. For ELs that 
would not require the use of amorphous cores, but would still require 
distribution transformer models to be redesigned to meet higher 
efficiency levels, the January 2023 NOPR estimated product conversion 
costs would be equal to 50 percent of the normal annual industry R&D 
expenses. These one-time product conversion costs would also be in 
addition to the annual R&D expenses normally incurred by distribution 
transformer manufacturers.
    Several interested parties commented on the conversion cost 
estimate used in the January 2023 NOPR. Several interested parties 
commented that manufacturers converting from GOES core production to 
amorphous core production will require large investments and the 
acquisition of several production equipment as well as re-training 
production employees. MTC commented that using amorphous cores requires 
different mandrels, winding, assembly processes, and equipment, 
including specialty annealing equipment and that the costs are 
significant and would be a major cost burden on distribution 
transformer manufacturers. (MTC, No. 119 at p. 19) Prolec GE commented 
that converting to amorphous cores would require investment in larger 
production lines in addition to other manufacturing equipment like 
cutting lines and annealing ovens. (Prolec GE, No. 120, at pp. 2-3) 
TMMA commented that in order to meet the standards proposed in the 
January 2023 NOPR, distribution transformer manufacturers will be 
required to make a significant investment for new manufacturing 
equipment, including cutting machines and annealing ovens. (TMMA, No. 
138 at pp. 2-3) NEMA commented that producing distribution transformers 
that use amorphous cores requires manufacturers to reconfigure their 
assembly processes, including time to retrain electricians to match 
transformer coils to calibrate with the properties of the new steel and 
the steel tanks which house both the coil and cores will need to be 
reconfigured to match these new dimensions. (NEMA, No. 141 at p. 3) 
Schneider commented that the January 2023 NOPR conversion cost 
estimates only considered core conversion costs when in actuality the 
standards proposed in the January 2023 NOPR would require new winding 
equipment to handle larger cores, expanded conveyors, cranes, and ovens 
to handle larger equipment, and potentially new facilities to handle 
the larger manufacturing footprints. (Schneider, No. 101 at p. 11) 
Howard commented that in addition to the capital equipment to produce 
amorphous cores, some facilities will need to be upgraded to 
accommodate the additional core-making equipment. (Howard, No. 116 at 
p. 2) Carte commented that amorphous core production is totally 
different than GOES core production and would require either a large 
expansion of their plant or purchasing cores from an external vendor. 
(Carte, No. 140 at p. 1) Eaton commented that distribution transformer 
manufacturers that currently manufacture GOES cores will be left with 
scrapping their equipment due to very little shared processes or 
equipment between GOES and amorphous steel. (Eaton, No. 137 at p. 26) 
Lastly, WEG commented that the standards proposed in the January 2023 
NOPR would require 50 percent of their operations to be retooled for 
amorphous core production and their employees would have to be 
completely retrained. (WEG, No. 92 at p. 3)
    DOE acknowledges that distribution transformer manufacturers would 
incur significant conversion costs to convert production facilities 
that are currently designed to produce GOES cores into production 
facilities that would produce amorphous steel cores in order to meet 
energy conservation standards. The January 2023 NOPR and this final 
rule analysis attempts to capture the full costs that distribution 
transformer manufacturers would incur to be able to produce compliant 
distribution transformers analyzed in this rulemaking. The cost 
estimates used in the January 2023 NOPR and this final rule analysis, 
include manufacturing equipment used in the cutting lines, annealing 
ovens, new winding equipment to handle larger cores, expanded conveyors 
and cranes, as well as costs to expand production floor space.
    Several interested parties commented that the conversion cost 
estimates used in the January 2023 NOPR were underestimated and should 
be increased. Cliffs commented that the substantial conversion costs 
estimated in the January 2023 NOPR are far below the reasonably 
foreseeable economic impact on manufacturers. (Cliffs, No. 105 at p. 
14) Additionally, Cliffs commented that the January 2023 NOPR 
conversion cost estimates were based on manufacturer interviews 
conducted in 2019 and did not account for the significant inflationary 
forces have substantially increased capital

[[Page 29959]]

equipment costs by at least 50 percent. (Id.) Cliffs continued by 
commenting that in order for manufacturers to comply with the standards 
proposed in the January 2023 NOPR, it would require new investments of 
between $30 and $50 million for each individual manufacturer to retool 
existing production factories, which they estimate would cost the 
entire industry between $500 million and $800 million to convert all 
distribution transformer production facilities into being capable of 
producing amorphous cores for the entire U.S. distribution transformer 
market. (Cliffs, No. 105 at p. 15) Hammond stated that they estimate 
having their production facility produce amorphous cores for all of 
their distribution transformers would take twice as long to produce and 
would require $40 million to $45 million in investment to ensure 
current and planned capacity could be shifted to the production of 
distribution transformers using amorphous cores. (Hammond, No. 142 at 
p. 2) Howard commented that if standards directly or indirectly force 
all distribution transformer designs only to use amorphous cores, the 
investment required from a monetary and time perspective would be even 
larger and longer that the conversion costs estimated in the January 
2023 NOPR. (Howard, No. 116 at p. 3) Howard commented that they 
estimate distribution transformer manufacturers would need to invest 
between $500 million and $1 billion to convert all distribution 
transformer manufacturing to accommodate producing amorphous cores for 
all distribution transformers sold in the U.S. (Howard, No. 116 at p. 
2) Prolec GE commented that it would need to invest approximately $50 
million to convert their liquid-immersed distribution transformer 
production, which currently used GOES cores to use amorphous cores. 
(Prolec GE, No. 120 at p. 1) WEG commented that they estimate that it 
would take 5-7 years to retool their distribution transformer 
production facilities to support the necessary production equipment and 
methods to produce amorphous core transformers at an estimated 
investment of between $25 million and $30 million. (WEG, No. 92 at pp. 
3-4) Additionally WEG commented that developing amorphous core designs 
would require building 20 prototypes and need three full time engineers 
to complete this transition to all amorphous core distribution 
transformers. WEG estimates this engineering effort would cost their 
company approximately $2 million. (WEG, No, 92 at pp. 1-2)
    As part of this final rule MIA, DOE reexamined the estimated 
conversion costs used in the January 2023 NOPR. For this final rule 
analysis, DOE continues to use the same methodology to estimate the 
conversion costs that industry would incur at each analyzed EL for each 
representative unit. However, DOE has increased the estimated capital 
conversion costs used in the January 2023 NOPR from $1,000,000 in 
capital investments to build a production line capable of producing 
distribution transformers that use 1,200 tons annually of amorphous 
core material to $2,000,000 in capital investments for the same 
quantity of amorphous core material. This increase in capital 
investments reflect both the inflationary market mentioned by Cliffs 
and the additional production equipment that would be in addition to 
the production equipment that is specific to amorphous core production, 
as well as the potential increase in production floor space that might 
be needed to accommodate additional or larger production equipment 
associated with amorphous core production.
    Additionally, DOE increased the estimated product conversion costs 
for distribution transformers using amorphous cores from 100 percent of 
the annual industry R&D expenses to be 150 percent of the annual 
industry R&D expenses; and for distribution transformers continuing to 
use GOES cores from 50 percent the annual industry R&D expenses to be 
75 percent of annual R&D expenses. The end result is that product 
conversion cost estimates used in this final rule analysis are 50 
percent more than the product conversion cost estimates used in the 
January 2023 NOPR, for the same level of amorphous core production 
requirements. These one-time product conversion costs would be in 
addition to the annual R&D expenses normally incurred by distribution 
transformer manufacturers. This increase in product conversion costs 
from the January 2023 NOPR to this final rule analysis reflect the 
additional redesigning, engineering, prototyping, re-training of 
production employees, and other R&D efforts the industry would have to 
undertake to move to producing distribution transformers using 
amorphous cores.
    The conversion costs by TSL and representative unit are displayed 
in Table IV.29. These conversion costs are incorporated into the cash 
flow analysis discussed in section V.B.2.a. The industry-wide 
conversion cost estimates to convert all distribution transformer 
manufacturing to accommodate producing amorphous cores for all 
distribution transformers sold in the U.S. (which would occur at TSL 5) 
would be approximately $825 million. This industry-wide conversion 
estimate aligns with the estimates that several interested parties 
suggested in response to the January 2023 NOPR.

[[Page 29960]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.556

    Capital and product conversion costs are key inputs into the GRIM 
and directly impact the change in INPV (which is outputted from the 
model) due to analyzed amended standards. The GRIM assumes all 
conversion-related investments occur between the year of publication of 
this final rule and the year by which manufacturers must comply with 
the amended standards. The conversion cost figures used in the GRIM can 
be found in section V.B.2.a of this document. For additional 
information on the estimated capital and product conversion costs, see 
chapter 12 of the final rule TSD.
d. Manufacturer Markup Scenarios
    MSPs include direct manufacturing production costs (i.e., labor, 
materials, and overhead estimated in DOE's MPCs) and all non-production 
costs (i.e., SG&A, R&D, and interest), along with profit. To calculate 
the MSPs in the GRIM, DOE applied non-production cost markups to the 
MPCs estimated in the engineering analysis for each equipment class and 
efficiency level. Modifying these manufacturer markups in the standards 
case yields different sets of impacts on manufacturers. For the MIA, 
DOE modeled two standards-case manufacturer markup scenarios to 
represent uncertainty regarding the potential impacts on prices and 
profitability for manufacturers following the implementation of amended 
energy conservation standards: (1) a preservation of gross margin 
scenario; and (2) a preservation of operating profit scenario. These 
scenarios lead to different manufacturer markup values that, when 
applied to the MPCs, result in varying revenue and cash flow impacts.
    Under the preservation of gross margin percentage markup scenario, 
DOE applied a single uniform ``gross margin percentage'' across all 
efficiency levels, which assumes that manufacturers would be able to 
maintain the same amount of profit as a percentage of revenues at all 
efficiency levels within an equipment class. This scenario assumes that 
manufacturers would be able to maintain the same amount of profit as a 
percentage of revenues at all TSLs, even as the MPCs increase in the 
standards case. Based on data from the April 2013 Standards Final Rule, 
publicly available financial information for manufacturers of 
distribution transformers, and comments made during manufacturer 
interviews, DOE estimated a gross margin percentage of 20 percent for 
all distribution transformers.\177\ This is the same value used in the 
January 2023 NOPR. Because this scenario assumes that manufacturers 
would be able to maintain the same gross margin percentage as MPCs 
increase in response to the analyzed energy conservation standards, it 
represents the upper bound to industry profitability

[[Page 29961]]

under amended energy conservation standards.
---------------------------------------------------------------------------

    \177\ The gross margin percentage of 20 percent is based on a 
manufacturer markup of 1.25.
---------------------------------------------------------------------------

    Under the preservation of operating profit scenario, DOE modeled a 
situation in which manufacturers are not able to increase per-unit 
operating profit in proportion to increases in MPCs. Under this 
scenario, as the MPCs increase, manufacturers reduce their manufacturer 
markups (on a percentage basis) to a level that maintains the no-new-
standards operating profit (in absolute dollars). The implicit 
assumption behind this scenario is that the industry can only maintain 
its operating profit in absolute dollars after compliance with amended 
standards. Therefore, operating margin in percentage terms is reduced 
between the no-new-standards case and the analyzed standards cases. DOE 
adjusted the manufacturer markups in the GRIM at each TSL to yield 
approximately the same earnings before interest and taxes in the 
standards case in the year after the compliance date of the amended 
standards as in the no-new-standards case. This scenario represents the 
lower bound to industry profitability under amended energy conservation 
standards.
    A comparison of industry financial impacts under the two 
manufacturer markup scenarios is presented in section V.B.2.a of this 
document.

K. Emissions Analysis

    The emissions analysis consists of two components. The first 
component estimates the effect of potential energy conservation 
standards on power sector and site (where applicable) combustion 
emissions of CO2, NOX, SO2, and Hg. 
The second component estimates the impacts of potential standards on 
emissions of two additional greenhouse gases, CH4 and 
N2O, as well as the reductions in emissions of other gases 
due to ``upstream'' activities in the fuel production chain. These 
upstream activities comprise extraction, processing, and transporting 
fuels to the site of combustion.
    The analysis of electric power sector emissions of CO2, 
NOX, SO2, and Hg uses emissions intended to 
represent the marginal impacts of the change in electricity consumption 
associated with amended or new standards. The methodology is based on 
results published for the AEO, including a set of side cases that 
implement a variety of efficiency-related policies. The methodology is 
described in appendix 13A in the final rule TSD. The analysis presented 
in this notice uses projections from AEO2023. Power sector emissions of 
CH4 and N2O from fuel combustion are estimated 
using Emission Factors for Greenhouse Gas Inventories published by the 
Environmental Protection Agency (EPA).\178\
---------------------------------------------------------------------------

    \178\ Available at www.epa.gov/sites/production/files/2021-04/documents/emission-factors_apr2021.pdf (last accessed July 12, 
2021).
---------------------------------------------------------------------------

    Site emissions of these gases were estimated using Emission Factors 
for Greenhouse Gas Inventories and, for NOX and 
SO2, emissions intensity factors from an EPA 
publication.\179\
---------------------------------------------------------------------------

    \179\ U.S. Environmental Protection Agency. External Combustion 
Sources. In Compilation of Air Pollutant Emission Factors. AP-42. 
Fifth Edition. Volume I: Stationary Point and Area Sources. Chapter 
1. Available at www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors#Proposed/ 
(last accessed July 12, 2021).
---------------------------------------------------------------------------

    FFC upstream emissions, which include emissions from fuel 
combustion during extraction, processing, and transportation of fuels, 
and ``fugitive'' emissions (direct leakage to the atmosphere) of 
CH4 and CO2, are estimated based on the 
methodology described in chapter 15 of the final rule TSD.
    The emissions intensity factors are expressed in terms of physical 
units per MWh or MMBtu of site energy savings. For power sector 
emissions, specific emissions intensity factors are calculated by 
sector and end use. Total emissions reductions are estimated using the 
energy savings calculated in the national impact analysis.
1. Air Quality Regulations Incorporated in DOE's Analysis
    DOE's no-new-standards case for the electric power sector reflects 
the AEO, which incorporates the projected impacts of existing air 
quality regulations on emissions. AEO2023 reflects, to the extent 
possible, laws and regulations adopted through mid-November 2022, 
including the emissions control programs discussed in the following 
paragraphs and the Inflation Reduction Act.\180\
---------------------------------------------------------------------------

    \180\ For further information, see the Assumptions to AEO2023 
report that sets forth the major assumptions used to generate the 
projections in the Annual Energy Outlook. Available at www.eia.gov/outlooks/aeo/assumptions/ (last accessed January 2, 2024).
---------------------------------------------------------------------------

    SO2 emissions from affected electric generating units 
(EGUs) are subject to nationwide and regional emissions cap-and-trade 
programs. Title IV of the Clean Air Act sets an annual emissions cap on 
SO2 for affected EGUs in the 48 contiguous States and the 
District of Columbia (``D.C.''). (42 U.S.C. 7651 et seq.) 
SO2 emissions from numerous States in the eastern half of 
the United States are also limited under the Cross-State Air Pollution 
Rule (``CSAPR''). 76 FR 48208 (Aug. 8, 2011). CSAPR requires these 
States to reduce certain emissions, including annual SO2 
emissions, and went into effect as of January 1, 2015.\181\ The AEO 
incorporates implementation of CSAPR, including the update to the CSAPR 
ozone season program emission budgets and target dates issued in 2016. 
81 FR 74504 (Oct. 26, 2016). Compliance with CSAPR is flexible among 
EGUs and is enforced through the use of tradable emissions allowances. 
Under existing EPA regulations, for states subject to SO2 
emissions limits under CSAPR, any excess SO2 emissions 
allowances resulting from the lower electricity demand caused by the 
adoption of an efficiency standard could be used to permit offsetting 
increases in SO2 emissions by another regulated EGU.
---------------------------------------------------------------------------

    \181\ CSAPR requires states to address annual emissions of 
SO2 and NOX, precursors to the formation of 
fine particulate matter (PM2.5) pollution, in order to 
address the interstate transport of pollution with respect to the 
1997 and 2006 PM2.5 National Ambient Air Quality 
Standards (NAAQS). CSAPR also requires certain states to address the 
ozone season (May-September) emissions of NOX, a 
precursor to the formation of ozone pollution, in order to address 
the interstate transport of ozone pollution with respect to the 1997 
ozone NAAQS. 76 FR 48208 (Aug. 8, 2011). EPA subsequently issued a 
supplemental rule that included an additional five states in the 
CSAPR ozone season program; 76 FR 80760 (Dec. 27, 2011) 
(Supplemental Rule), and EPA issued the CSAPR Update for the 2008 
ozone NAAQS. 81 FR 74504 (Oct. 26, 2016).
---------------------------------------------------------------------------

    However, beginning in 2016, SO2 emissions began to fall 
as a result of the Mercury and Air Toxics Standards (MATS) for power 
plants.\182\ 77 FR 9304 (Feb. 16, 2012). The final rule establishes 
power plant emission standards for mercury, acid gases, and non-mercury 
metallic toxic pollutants. Because of the emissions reductions under 
the MATS, it is unlikely that excess SO2 emissions 
allowances resulting from the lower electricity demand would be needed 
or used to permit offsetting increases in SO2 emissions by 
another regulated EGU. Therefore, energy conservation standards that 
decrease electricity generation will generally reduce SO2 
emissions. DOE estimated SO2 emissions reduction using 
emissions factors based on AEO2023.
---------------------------------------------------------------------------

    \182\ In order to continue operating, coal power plants must 
have either flue gas desulfurization or dry sorbent injection 
systems installed. Both technologies, which are used to reduce acid 
gas emissions, also reduce SO2 emissions.
---------------------------------------------------------------------------

    CSAPR also established limits on NOX emissions for 
numerous States in the eastern half of the United States. Energy 
conservation standards would have little effect on NOX 
emissions in those States covered by CSAPR emissions limits if excess 
NOX emissions allowances resulting from the lower 
electricity demand could be used to

[[Page 29962]]

permit offsetting increases in NOX emissions from other 
EGUs. In such case, NOX emissions would remain near the 
limit even if electricity generation goes down. Depending on the 
configuration of the power sector in the different regions and the need 
for allowances, however, NOX emissions might not remain at 
the limit in the case of lower electricity demand. That would mean that 
standards might reduce NOX emissions in covered States. 
Despite this possibility, DOE has chosen to be conservative in its 
analysis and has maintained the assumption that standards will not 
reduce NOX emissions in States covered by CSAPR. Standards 
would be expected to reduce NOX emissions in the States not 
covered by CSAPR. DOE used AEO2023 data to derive NOX 
emissions factors for the group of States not covered by CSAPR.
    The MATS limit mercury emissions from power plants, but they do not 
include emissions caps and, as such, DOE's energy conservation 
standards would be expected to slightly reduce Hg emissions. DOE 
estimated mercury emissions reduction using emissions factors based on 
AEO2023, which incorporates the MATS.
    EEI commented that electric companies are already reducing 
greenhouse gas emissions via clean energy initiatives such as utilizing 
more renewable energy technology. (EEI, No. 135 at pp. 7-8) Several 
other stakeholders similarly commented that utility companies are 
actively reducing greenhouse gas emissions and already utilize carbon-
free energy sources. (Idaho Falls Power, No. 77 at p. 2; Fall River, 
No. 83 at p. 2; WEC, No. 118 at p. 3)
    In response to EEI and other utility stakeholders, DOE notes that 
the emissions factors are determined by AEO, which accounts for 
declining future carbon emissions due increased renewable generation.

L. Monetizing Emissions Impacts

    As part of the development of this final rule, for the purpose of 
complying with the requirements of Executive Order 12866, DOE 
considered the estimated monetary benefits from the reduced emissions 
of CO2, CH4, N2O, NOX, and 
SO2 that are expected to result from each of the TSLs 
considered. In order to make this calculation analogous to the 
calculation of the NPV of consumer benefit, DOE considered the reduced 
emissions expected to result over the lifetime of products shipped in 
the projection period for each TSL. This section summarizes the basis 
for the values used for monetizing the emissions benefits and presents 
the values considered in this final rule.
    To monetize the benefits of reducing GHG emissions, this analysis 
uses the interim estimates presented in the Technical Support Document: 
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates 
Under Executive Order 13990 published in February 2021 by the IWG.
1. Monetization of Greenhouse Gas Emissions
    DOE estimates the monetized benefits of the reductions in emissions 
of CO2, CH4, and N2O by using a 
measure of the SC of each pollutant (e.g., SC-CO2). These 
estimates represent the monetary value of the net harm to society 
associated with a marginal increase in emissions of these pollutants in 
a given year, or the benefit of avoiding that increase. These estimates 
are intended to include (but are not limited to) climate-change-related 
changes in net agricultural productivity, human health, property 
damages from increased flood risk, disruption of energy systems, risk 
of conflict, environmental migration, and the value of ecosystem 
services.
    DOE exercises its own judgment in presenting monetized climate 
benefits as recommended by applicable Executive orders, and DOE would 
reach the same conclusion presented in this rulemaking in the absence 
of the social cost of greenhouse gases. That is, the social costs of 
greenhouse gases, whether measured using the February 2021 interim 
estimates presented by the IWG on the Social Cost of Greenhouse Gases 
or by another means, did not affect the rule ultimately adopted by DOE.
    DOE estimated the global social benefits of CO2, 
CH4, and N2O reductions using SC-GHG values that 
were based on the interim values presented in the Technical Support 
Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim 
Estimates under Executive Order 13990, published in February 2021 by 
the IWG (``February 2021 SC-GHG TSD''). The SC-GHG is the monetary 
value of the net harm to society associated with a marginal increase in 
emissions in a given year, or the benefit of avoiding that increase. In 
principle, the SC-GHG includes the value of all climate change impacts, 
including (but not limited to) changes in net agricultural 
productivity, human health effects, property damage from increased 
flood risk and natural disasters, disruption of energy systems, risk of 
conflict, environmental migration, and the value of ecosystem services. 
The SC-GHG, therefore, reflects the societal value of reducing 
emissions of the gas in question by 1 metric ton. The SC-GHG is the 
theoretically appropriate value to use in conducting benefit-cost 
analyses of policies that affect CO2, N2O, and 
CH4 emissions. As a member of the IWG involved in the 
development of the February 2021 SC-GHG TSD, DOE agrees that the 
interim SC-GHG estimates represent the most appropriate estimate of the 
SC-GHG until revised estimates have been developed reflecting the 
latest, peer-reviewed science. DOE continues to evaluate recent 
developments in the scientific literature, including the updated SC-GHG 
estimates published by the EPA in December 2023 within their rulemaking 
on oil and natural gas sector sources.\183\ For this rulemaking, DOE 
used these updated SC-GHG values to conduct a sensitivity analysis of 
the value of GHG emissions reductions associated with alternative 
standards for distribution transformers (see section IV.L.1.c of this 
document).
---------------------------------------------------------------------------

    \183\ U.S. EPA. (2023). Supplementary Material for the 
Regulatory Impact Analysis for the Final Rulemaking, ``Standards of 
Performance for New, Reconstructed, and Modified Sources and 
Emissions Guidelines for Existing Sources: Oil and Natural Gas 
Sector Climate Review'': EPA Report on the Social Cost of Greenhouse 
Gases: Estimates Incorporating Recent Scientific Advances. 
Washington, DC: U.S. EPA. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-oil-and-natural-gas.
---------------------------------------------------------------------------

    The SC-GHG estimates presented here were developed over many years, 
using peer-reviewed methodologies, a transparent process, the best 
science available at the time of that process, and input from the 
public. Specifically, in 2009, the IWG, which included DOE and other 
Executive branch agencies and offices, was established to ensure that 
agencies were using the best available science and to promote 
consistency in the SC-CO2 values used across agencies. The 
IWG published SC-CO2 estimates in 2010 that were developed 
from an ensemble of three widely cited integrated assessment models 
(IAMs) that estimate global climate damages using highly aggregated 
representations of climate processes and the global economy combined 
into a single modeling framework. The three IAMs were run using a 
common set of input assumptions in each model for future population, 
economic, and CO2 emissions growth, as well as equilibrium 
climate sensitivity--a measure of the globally averaged temperature 
response to increased atmospheric CO2 concentrations. These 
estimates were updated in 2013 based on new versions of each IAM. In 
August 2016 the IWG published estimates of the

[[Page 29963]]

SC-CH4 and SC-N2O using methodologies that are 
consistent with the methodology underlying the SC-CO2 
estimates. The modeling approach that extends the IWG SC-CO2 
methodology to non-CO2 GHGs has undergone multiple stages of 
peer review. The SC-CH4 and SC-N2O estimates were 
developed by Marten et al.\184\ and underwent a standard double-blind 
peer review process prior to journal publication. In 2015, as part of 
the response to public comments received to a 2013 solicitation for 
comments on the SC-CO2 estimates, the IWG announced a 
National Academies of Sciences, Engineering, and Medicine review of the 
SC-CO2 estimates to offer advice on how to approach future 
updates to ensure that the estimates continue to reflect the best 
available science and methodologies. In January 2017, the National 
Academies released their final report, ``Valuing Climate Damages: 
Updating Estimation of the Social Cost of Carbon Dioxide,'' and 
recommended specific criteria for future updates to the SC-
CO2 estimates, a modeling framework to satisfy the specified 
criteria, and both near-term updates and longer-term research needs 
pertaining to various components of the estimation process.\185\ 
Shortly thereafter, in March 2017, President Trump issued Executive 
Order 13783, which disbanded the IWG, withdrew the previous TSDs, and 
directed agencies to ensure SC-CO2 estimates used in 
regulatory analyses are consistent with the guidance contained in OMB's 
Circular A-4, ``including with respect to the consideration of domestic 
versus international impacts and the consideration of appropriate 
discount rates'' (E.O. 13783, Section 5(c)). Benefit-cost analyses 
following E.O. 13783 used SC-GHG estimates that attempted to focus on 
the U.S.-specific share of climate change damages as estimated by the 
models and were calculated using two discount rates recommended by 
Circular A-4, 3 percent and 7 percent. All other methodological 
decisions and model versions used in SC-GHG calculations remained the 
same as those used by the IWG in 2010 and 2013, respectively.
---------------------------------------------------------------------------

    \184\ Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. Newbold, 
and A. Wolverton. Incremental CH4 and N2O 
mitigation benefits consistent with the U.S. Government's SC-
CO2 estimates. Climate Policy. 2015. 15(2): pp. 272-298.
    \185\ National Academies of Sciences, Engineering, and Medicine. 
Valuing Climate Damages: Updating Estimation of the Social Cost of 
Carbon Dioxide. 2017. The National Academies Press: Washington, DC. 
nap.nationalacademies.org/catalog/24651/valuing-climate-damages-updating-estimation-of-the-social-cost-of.
---------------------------------------------------------------------------

    On January 20, 2021, President Biden issued Executive Order 13990, 
which re-established the IWG and directed it to ensure that the U.S. 
Government's estimates of the social cost of carbon and other 
greenhouse gases reflect the best available science and the 
recommendations in the National Academies 2017 report. The IWG was 
tasked with first reviewing the SC-GHG estimates currently used in 
Federal analyses and publishing interim estimates within 30 days of the 
E.O. that reflect the full impact of GHG emissions, including by taking 
global damages into account. The interim SC-GHG estimates published in 
February 2021 are used here to estimate the climate benefits for this 
rulemaking. The E.O. instructs the IWG to undertake a fuller update of 
the SC-GHG estimates that takes into consideration the advice in the 
National Academies 2017 report and other recent scientific literature. 
The February 2021 SC-GHG TSD provides a complete discussion of the 
IWG's initial review conducted under E.O. 13990. In particular, the IWG 
found that the SC-GHG estimates used under E.O. 13783 fail to reflect 
the full impact of GHG emissions in multiple ways.
    First, the IWG found that the SC-GHG estimates used under E.O. 
13783 fail to fully capture many climate impacts that affect the 
welfare of U.S. citizens and residents, and those impacts are better 
reflected by global measures of the SC-GHG. Examples of omitted effects 
from the E.O. 13783 estimates include direct effects on U.S. citizens, 
assets and investments located abroad, supply chains, U.S. military 
assets and interests abroad, tourism, and spillover pathways such as 
economic and political destabilization and global migration that can 
lead to adverse impacts on U.S. national security, public health, and 
humanitarian concerns. In addition, assessing the benefits of U.S. GHG 
mitigation activities requires consideration of how those actions may 
affect mitigation activities by other countries, as those international 
mitigation actions will provide a benefit to U.S. citizens and 
residents by mitigating climate impacts that affect U.S. citizens and 
residents. A wide range of scientific and economic experts have 
emphasized the issue of reciprocity as support for considering global 
damages of GHG emissions. If the United States does not consider 
impacts on other countries, it is difficult to convince other countries 
to consider the impacts of their emissions on the United States. The 
only way to achieve an efficient allocation of resources for emissions 
reduction on a global basis--and so benefit the U.S. and its citizens--
is for all countries to base their policies on global estimates of 
damages. As a member of the IWG involved in the development of the 
February 2021 SC-GHG TSD, DOE agrees with this assessment and, 
therefore, in this final rule DOE centers attention on a global measure 
of SC-GHG. This approach is the same as that taken in DOE regulatory 
analyses from 2012 through 2016. A robust estimate of climate damages 
that accrue only to U.S. citizens and residents does not currently 
exist in the literature. As explained in the February 2021 SC-GHG TSD, 
existing estimates are both incomplete and an underestimate of total 
damages that accrue to the citizens and residents of the U.S. because 
they do not fully capture the regional interactions and spillovers 
discussed above, nor do they include all of the important physical, 
ecological, and economic impacts of climate change recognized in the 
climate change literature. As noted in the February 2021 SC-GHG TSD, 
the IWG will continue to review developments in the literature, 
including more robust methodologies for estimating a U.S.-specific SC-
GHG value, and explore ways to better inform the public of the full 
range of carbon impacts. As a member of the IWG, DOE will continue to 
follow developments in the literature pertaining to this issue.
    Second, the IWG found that the use of the social rate of return on 
capital (estimated to be 7 percent under OMB's 2003 Circular A-4 
guidance) to discount the future benefits of reducing GHG emissions 
inappropriately underestimates the impacts of climate change for the 
purposes of estimating the SC-GHG. Consistent with the findings of the 
National Academies and the economic literature, the IWG continued to 
conclude that the consumption rate of interest is the theoretically 
appropriate discount rate in an intergenerational context,\186\ and it

[[Page 29964]]

recommended that discount rate uncertainty and relevant aspects of 
intergenerational ethical considerations be accounted for in selecting 
future discount rates.
---------------------------------------------------------------------------

    \186\ Interagency Working Group on Social Cost of Carbon. Social 
Cost of Carbon for Regulatory Impact Analysis under Executive Order 
12866. 2010. United States Government. www.epa.gov/sites/default/files/2016-12/documents/scc_tsd_2010.pdf (last accessed April 15, 
2022.); Interagency Working Group on Social Cost of Carbon. 
Technical Update of the Social Cost of Carbon for Regulatory Impact 
Analysis Under Executive Order 12866. 2013. www.federalregister.gov/documents/2013/11/26/2013-28242/technical-support-document-technical-update-of-the-social-cost-of-carbon-for-regulatory-impact 
(last accessed April 15, 2022.); Interagency Working Group on Social 
Cost of Greenhouse Gases, United States Government. Technical 
Support Document: Technical Update on the Social Cost of Carbon for 
Regulatory Impact Analysis--Under Executive Order 12866. August 
2016. www.epa.gov/sites/default/files/2016-12/documents/sc_co2_tsd_august_2016.pdf (last accessed January 18, 2022.); 
Interagency Working Group on Social Cost of Greenhouse Gases, United 
States Government. Addendum to Technical Support Document on Social 
Cost of Carbon for Regulatory Impact Analysis under Executive Order 
12866: Application of the Methodology to Estimate the Social Cost of 
Methane and the Social Cost of Nitrous Oxide. August 2016. 
www.epa.gov/sites/default/files/2016-12/documents/addendum_to_sc-ghg_tsd_august_2016.pdf (last accessed January 18, 2022.).
---------------------------------------------------------------------------

    Furthermore, the damage estimates developed for use in the SC-GHG 
are estimated in consumption-equivalent terms, and so an application of 
OMB Circular A-4's guidance for regulatory analysis would then use the 
consumption discount rate to calculate the SC-GHG. DOE agrees with this 
assessment and will continue to follow developments in the literature 
pertaining to this issue. DOE also notes that while OMB's 2003 Circular 
A-4 recommends using 3-percent and 7-percent discount rates as 
``default'' values, Circular A-4 also reminds agencies that ``different 
regulations may call for different emphases in the analysis, depending 
on the nature and complexity of the regulatory issues and the 
sensitivity of the benefit and cost estimates to the key assumptions.'' 
On discounting, Circular A-4 recognizes that ``special ethical 
considerations arise when comparing benefits and costs across 
generations,'' and Circular A-4 acknowledges that analyses may 
appropriately ``discount future costs and consumption benefits . . . at 
a lower rate than for intragenerational analysis.'' In the 2015 
Response to Comments on the Social Cost of Carbon for Regulatory Impact 
Analysis, OMB, DOE, and the other IWG members recognized that 
``Circular A-4 is a living document'' and ``the use of 7 percent is not 
considered appropriate for intergenerational discounting. There is wide 
support for this view in the academic literature, and it is recognized 
in Circular A-4 itself.'' Thus, DOE concludes that a 7-percent discount 
rate is not appropriate to apply to value the social cost of greenhouse 
gases in the analysis presented in this analysis.
    To calculate the present and annualized values of climate benefits, 
DOE uses the same discount rate as the rate used to discount the value 
of damages from future GHG emissions, for internal consistency. That 
approach to discounting follows the same approach that the February 
2021 SC-GHG TSD recommends ``to ensure internal consistency--i.e., 
future damages from climate change using the SC-GHG at 2.5 percent 
should be discounted to the base year of the analysis using the same 
2.5 percent rate.'' DOE has also consulted the National Academies' 2017 
recommendations on how SC-GHG estimates can ``be combined in RIAs with 
other cost and benefits estimates that may use different discount 
rates.'' The National Academies reviewed several options, including 
``presenting all discount rate combinations of other costs and benefits 
with [SC-GHG] estimates.''
    As a member of the IWG involved in the development of the February 
2021 SC-GHG TSD, DOE agrees with the above assessment and will continue 
to follow developments in the literature pertaining to this issue. 
While the IWG works to assess how best to incorporate the latest, peer-
reviewed science to develop an updated set of SC-GHG estimates, it set 
the interim estimates to be the most recent estimates developed by the 
IWG prior to the group being disbanded in 2017. The estimates rely on 
the same models and harmonized inputs and are calculated using a range 
of discount rates. As explained in the February 2021 SC-GHG TSD, the 
IWG has recommended that agencies revert to the same set of four values 
drawn from the SC-GHG distributions based on three discount rates as 
were used in regulatory analyses between 2010 and 2016 and were subject 
to public comment. For each discount rate, the IWG combined the 
distributions across models and socioeconomic emissions scenarios 
(applying equal weight to each) and then selected a set of four values 
recommended for use in benefit-cost analyses: an average value 
resulting from the model runs for each of three discount rates (2.5 
percent, 3 percent, and 5 percent), plus a fourth value, selected as 
the 95th percentile of estimates based on a 3-percent discount rate. 
The fourth value was included to provide information on potentially 
higher-than-expected economic impacts from climate change. As explained 
in the February 2021 SC-GHG TSD, and DOE agrees, this update reflects 
the immediate need to have an operational SC-GHG for use in regulatory 
benefit-cost analyses and other applications that was developed using a 
transparent process, peer-reviewed methodologies, and the science 
available at the time of that process. Those estimates were subject to 
public comment in the context of dozens of proposed rulemakings as well 
as in a dedicated public comment period in 2013.
    There are a number of limitations and uncertainties associated with 
the SC-GHG estimates. First, the current scientific and economic 
understanding of discounting approaches suggests discount rates 
appropriate for intergenerational analysis in the context of climate 
change are likely to be less than 3 percent, near 2 percent or 
lower.\187\ Second, the IAMs used to produce these interim estimates do 
not include all of the important physical, ecological, and economic 
impacts of climate change recognized in the climate change literature 
and the science underlying their ``damage functions''--i.e., the core 
parts of the IAMs that map global mean temperature changes and other 
physical impacts of climate change into economic (both market and 
nonmarket) damages--lags behind the most recent research. For example, 
limitations include the incomplete treatment of catastrophic and non-
catastrophic impacts in the integrated assessment models, their 
incomplete treatment of adaptation and technological change, the 
incomplete way in which inter-regional and intersectoral linkages are 
modeled, uncertainty in the extrapolation of damages to high 
temperatures, and inadequate representation of the relationship between 
the discount rate and uncertainty in economic growth over long time 
horizons. Likewise, the socioeconomic and emissions scenarios used as 
inputs to the models do not reflect new information from the last 
decade of scenario generation or the full range of projections. The 
modeling limitations do not all work in the same direction in terms of 
their influence on the SC-CO2 estimates. However, as 
discussed in the February 2021 SC-GHG TSD, the IWG has recommended 
that, taken together, the limitations suggest that the interim SC-GHG 
estimates used in this final rule likely underestimate the damages from 
GHG emissions. DOE concurs with this assessment.
---------------------------------------------------------------------------

    \187\ Interagency Working Group on Social Cost of Greenhouse 
Gases. 2021. Technical Support Document: Social Cost of Carbon, 
Methane, and Nitrous Oxide Interim Estimates under Executive Order 
13990. February. United States Government. Available at 
www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/.
---------------------------------------------------------------------------

    DOE's derivations of the SC-CO2, SC-N2O, and 
SC-CH4 values used for this NOPR are discussed in the 
following sections, and the results of DOE's analyses estimating the 
benefits of the reductions in emissions of these GHGs are presented in 
section V.B.6 of this document.
a. Social Cost of Carbon
    The SC-CO2 values used for this final rule were based on 
the values developed for the February 2021 SC-GHG TSD,

[[Page 29965]]

which are shown in Table IV.30 in 5-year increments from 2020 to 2050. 
The set of annual values that DOE used, which was adapted from 
estimates published by EPA,\188\ is presented in appendix 14A of the 
final rule TSD. These estimates are based on methods, assumptions, and 
parameters identical to the estimates published by the IWG (which were 
based on EPA modeling), and include values for 2051 to 2070. DOE 
expects additional climate benefits to accrue for products still 
operating after 2070, but a lack of available SC-CO2 
estimates for emissions years beyond 2070 prevents DOE from monetizing 
these potential benefits in this analysis.
---------------------------------------------------------------------------

    \188\ See EPA, ``Revised 2023 and Later Model Year Light-Duty 
Vehicle GHG Emissions Standards: Regulatory Impact Analysis,'' 
Washington, DC, December 2021. Available at nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1013ORN.pdf (last accessed Feb. 21, 2023).
[GRAPHIC] [TIFF OMITTED] TR22AP24.557

    DOE multiplied the CO2 emissions reduction estimated for 
each year by the SC-CO2 value for that year in each of the 
four cases. DOE adjusted the values to 2022$ using the implicit price 
deflator for gross domestic product (GDP) from the Bureau of Economic 
Analysis. To calculate a present value of the stream of monetary 
values, DOE discounted the values in each of the four cases using the 
specific discount rate that had been used to obtain the SC-
CO2 values in each case.
b. Social Cost of Methane and Nitrous Oxide
    The SC-CH4 and SC-N2O values used for this 
final rule were based on the values developed for the February 2021 SC-
GHG TSD. Table IV.31 shows the updated sets of SC-CH4 and 
SC-N2O estimates from the latest interagency update in 5-
year increments from 2020 to 2050. The full set of annual values used 
is presented in appendix 14A of the final rule TSD. To capture the 
uncertainties involved in regulatory impact analysis, DOE has 
determined it is appropriate to include all four sets of SC-
CH4 and SC-N2O values, as recommended by the IWG. 
DOE derived values after 2050 using the approach described above for 
the SC-CO2.
[GRAPHIC] [TIFF OMITTED] TR22AP24.558

    DOE multiplied the CH4 and N2O emissions 
reduction estimated for each year by the SC-CH4 and SC-
N2O estimates for that year in each of the cases. DOE 
adjusted the values to 2022$ using the implicit price deflator for GDP 
from the Bureau of Economic Analysis. To calculate a present value of 
the stream of monetary values, DOE discounted the values in each of the 
cases using the specific discount rate that had been used to obtain the 
SC-CH4 and SC-N2O estimates in each case.
c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
    In the regulatory impact analysis of EPA's December 2023 Final 
Rulemaking, ``Standards of Performance for New, Reconstructed, and 
Modified Sources and Emissions Guidelines for Existing Sources: Oil and 
Natural Gas

[[Page 29966]]

Sector Climate Review,'' EPA estimated climate benefits using a new set 
of Social Cost of Greenhouse Gas (SC-GHG) estimates. These estimates 
incorporate recent research addressing recommendations of the National 
Academies (2017), responses to public comments on an earlier 
sensitivity analysis using draft SC-GHG estimates, and comments from a 
2023 external peer review of the accompanying technical report.\189\
---------------------------------------------------------------------------

    \189\ For further information about the methodology used to 
develop these values, public comments, and information pertaining to 
the peer review, see https://www.epa.gov/environmental-economics/scghg.
---------------------------------------------------------------------------

    The full set of annual values is presented in appendix 14C of the 
direct final rule TSD. Although DOE continues to review EPA's 
estimates, for this rulemaking, DOE used these new SC-GHG values to 
conduct a sensitivity analysis of the value of GHG emissions reductions 
associated with alternative standards for distribution transformers. 
This sensitivity analysis provides an expanded range of potential 
climate benefits associated with amended standards. The final year of 
EPA's new estimates is 2080; therefore, DOE did not monetize the 
climate benefits of GHG emissions reductions occurring after 2080.
    The results of the sensitivity analysis are presented in appendix 
14C of the final rule TSD. The overall climate benefits are larger when 
using EPA's higher SC-GHG estimates, compared to the climate benefits 
using the more conservative IWG SC-GHG estimates. However, DOE's 
conclusion that the standards are economically justified remains the 
same regardless of which SC-GHG estimates are used.
2. Monetization of Other Emissions Impacts
    For the final rule, DOE estimated the monetized value of 
NOX and SO2 emissions reductions from electricity 
generation using benefit-per-ton estimates for that sector from the 
EPA's Benefits Mapping and Analysis Program. \190\ DOE used EPA's 
values for PM2.5-related benefits associated with 
NOX and SO2 and for ozone-related benefits 
associated with NOX for 2025 and 2030, 2035, and 2040, 
calculated with discount rates of 3 percent and 7 percent. DOE used 
linear interpolation to define values for the years not given in the 
2025 to 2040 period; for years beyond 2040, the values are held 
constant (rather than extrapolated) to be conservative. DOE combined 
the EPA regional benefit-per-ton estimates with regional information on 
electricity consumption and emissions from AEO2023 to define weighted-
average national values for NOX and SO2.
---------------------------------------------------------------------------

    \190\ U.S. Environmental Protection Agency. Estimating the 
Benefit per Ton of Reducing Directly-Emitted PM2.5, 
PM2.5 Precursors and Ozone Precursors from 21 Sectors. 
www.epa.gov/benmap/estimating-benefit-ton-reducing-directly-emitted-pm25-pm25-precursors-and-ozone-precursors.
---------------------------------------------------------------------------

    DOE received the following comments regarding its monetization of 
emissions impacts.
    The Chamber of Commerce urged DOE to reconsider the use of the SC-
GHG estimates in this rulemaking based on three core concerns. First, 
the Chamber of Commerce commented that before DOE considers applying 
the SC-GHG estimates to the proposed rule (and, likewise, to any final 
rule resulting from this rulemaking), the SC-GHG estimates should be 
subject to a proper administrative process, including a full and fair 
public comment process, as well as a robust independent peer review. 
Second, the Chamber of Commerce stated that there are statutory 
limitations on using the SC-GHG estimates, and it urged DOE to fully 
consider the applicable limits before applying the estimates. Third, 
the Chamber of Commerce urged DOE to carefully consider whether the 
``major questions'' doctrine precludes the application of the SC-GHG 
estimates in the proposed rule given the political and economic 
significance of the estimates. (Chamber of Commerce, No. 88 at p. 6)
    In response, DOE first notes that it would reach the same 
conclusion presented in this final rule in the absence of the social 
cost of greenhouse gases. As it relates to the Chamber of Commerce's 
first comment, DOE reiterates that the SC-GHG estimates were developed 
using a transparent process, peer-reviewed methodologies, the best 
science available at the time of that process, and input from the 
public.
    Regarding possible statutory limitations on using the SC-GHG 
estimates, DOE maintains that environmental and public health benefits 
associated with the more efficient use of energy, including those 
connected to global climate change, are important to take into account 
when considering the ``need for national energy . . . conservation,'' 
which is one of the factors that EPCA requires DOE to evaluate in 
determining whether a potential energy conservation standard is 
economically justified. (42 U.S.C. 6295(o)(2)(B)(i)(VI)); Zero Zone, 
Inc. v. United States DOE, 832 F.3d 654, 677 (7th Cir. 2016) (pointing 
to 42 U.S.C. 6295(o)(2)(B)(i)(VI) in concluding that ``[w]e have no 
doubt that Congress intended that DOE have the authority under the EPCA 
to consider the reduction in SCC.'') DOE has been analyzing the 
monetized emissions impacts from its rules, for over 10 years. In 
addition, Executive Order 13563, ``Improving Regulation and Regulatory 
Review,'' which was re-affirmed on January 20, 2021, states that each 
agency, among other things, must, to the extent permitted by law: 
``select, in choosing among alternative regulatory approaches, those 
approaches that maximize net benefits (including potential economic, 
environmental, public health and safety, and other advantages; 
distributive impacts; and equity).'' E.O. 13563, Section 1(b). 
Furthermore, as noted previously, E.O. 13990, ``Protecting Public 
Health and the Environment and Restoring Science to Tackle the Climate 
Crisis,'' re-established the IWG and directed it to ensure that the 
U.S. Government's estimates of the social cost of carbon and other 
greenhouse gases reflect the best available science and the 
recommendations of the National Academies. As a member of the IWG 
involved in the development of the February 2021 SC-GHG TSD, DOE agrees 
that the interim SC-GHG estimates represent the most appropriate 
estimate of the SC-GHG until revised estimates have been developed 
reflecting the latest, peer-reviewed science. For these reasons, DOE 
includes monetized emissions reductions in its evaluation of potential 
standard levels.
    Regarding whether the ``major questions'' doctrine precludes the 
application of the SC-GHG estimates in proposed or final rules, DOE 
notes that the ``major questions'' doctrine raised by the Chamber of 
Commerce applies only in ``extraordinary cases'' concerning Federal 
agencies claiming highly consequential regulatory authority beyond what 
Congress could reasonably be understood to have granted. West Virginia 
v. EPA, 142 S. Ct. 2587, 2609 (2022); N.C. Coastal Fisheries Reform 
Grp. v. Capt. Gaston LLC, 2023 U.S. App. LEXIS 20325, *6-8 (4th Cir., 
Aug. 7, 2023) (listing the hallmarks courts have recognized to invoke 
the major questions doctrine, such as a hesitancy ``to recognize new-
found powers in old statutes against a backdrop of an agency failing to 
invoke them previously,'' ``when the asserted power raises federalism 
concerns,'' or ``when the asserted authority falls outside the agency's 
traditional expertise, . . . or is found in an `ancillary provision.' 
''). DOE has clear authorization under EPCA to regulate the energy 
efficiency or energy use of a variety of COMMERCIAL AND INDUSTRIAL

[[Page 29967]]

equipment, including distribution transformers. Although DOE routinely 
conducts an analysis of the anticipated emissions impacts of potential 
energy conservation standards under consideration, see, e.g., Zero 
Zone, 832 F.3d at 677, DOE does not purport to regulate such emissions, 
and as stated elsewhere in this document, DOE's selection of standards 
would be the same without consideration of emissions. Where DOE applied 
the factors it was tasked to consider under EPCA and the rule is 
justified even absent use of the SC-GHG analysis, the major questions 
doctrine has no bearing.
    The Institute for Policy Integrity (IPI) commented that DOE 
appropriately applies the social cost estimates developed by the IWG to 
its analysis of climate benefits. IPI stated that these values are 
widely agreed to underestimate the full social costs of greenhouse gas 
emissions, but for now they remain appropriate to use as conservative 
estimates. (IPI, No. 123 at p. 1)
    DOE agrees that the interim SC-GHG values applied for this final 
rule are conservative estimates. In the February 2021 SC-GHG TSD, the 
IWG stated that the models used to produce the interim estimates do not 
include all of the important physical, ecological, and economic impacts 
of climate change recognized in the climate change literature. For 
these same impacts, the science underlying their ``damage functions'' 
lags behind the most recent research. In the judgment of the IWG, these 
and other limitations suggest that the range of four interim SC-GHG 
estimates presented in the TSD likely underestimate societal damages 
from GHG emissions. The IWG is in the process of assessing how best to 
incorporate the latest peer-reviewed science and the recommendations of 
the National Academies to develop an updated set of SC-GHG estimates, 
and DOE remains engaged in that process.
    IPI suggested that DOE should state that criticisms of the social 
cost of greenhouse gases are moot in this rulemaking because the 
proposed rule is justified without them. DOE agrees that the proposed 
rule is economically justified without including climate benefits 
associated with reduced GHG emissions. (IPI, No. 123 at p. 2)
    IPI commented that DOE should consider applying sensitivity 
analysis using EPA's draft climate-damage estimates released in 
November 2022, as EPA's work faithfully implements the road map laid 
out in 2017 by the National Academies of Sciences and applies recent 
advances in the science and economics on the costs of climate change. 
(IPI, No. 123 at p. 1)
    DOE typically does not conduct analyses using draft inputs that are 
still under review. DOE notes that because the EPA's draft estimates 
are considerably higher than the IWG's interim SC-GHG values applied 
for this final rule, an analysis that used the draft values would 
result in significantly greater climate-related benefits. However, such 
results would not affect DOE's decision in this proposed rule.

M. Utility Impact Analysis

    The utility impact analysis estimates the changes in installed 
electrical capacity and generation projected to result for each 
considered TSL. The analysis is based on published output from the NEMS 
associated with AEO2023. NEMS produces the AEO Reference case, as well 
as a number of side cases that estimate the economy-wide impacts of 
changes to energy supply and demand. For the current analysis, impacts 
are quantified by comparing the levels of electricity sector 
generation, installed capacity, fuel consumption and emissions in the 
AEO2023 Reference case and various side cases. Details of the 
methodology are provided in the appendices to chapters 13 and 15 of the 
final rule TSD.
    The output of this analysis is a set of time-dependent coefficients 
that capture the change in electricity generation, primary fuel 
consumption, installed capacity and power sector emissions due to a 
unit reduction in demand for a given end use. These coefficients are 
multiplied by the stream of electricity savings calculated in the NIA 
to provide estimates of selected utility impacts of potential new or 
amended energy conservation standards.

N. Employment Impact Analysis

    DOE considers employment impacts in the domestic economy as one 
factor in selecting a standard. Employment impacts from new or amended 
energy conservation standards include both direct and indirect impacts. 
Direct employment impacts are any changes in the number of employees of 
manufacturers of the products subject to standards, their suppliers, 
and related service firms. The MIA addresses those impacts. Indirect 
employment impacts are changes in national employment that occur due to 
the shift in expenditures and capital investment caused by the purchase 
and operation of more-efficient appliances. Indirect employment impacts 
from standards consist of the net jobs created or eliminated in the 
national economy, other than in the manufacturing sector being 
regulated, caused by (1) reduced spending by consumers on energy, (2) 
reduced spending on new energy supply by the utility industry, (3) 
increased consumer spending on the products to which the new standards 
apply and other goods and services, and (4) the effects of those three 
factors throughout the economy.
    One method for assessing the possible effects on the demand for 
labor of such shifts in economic activity is to compare sector 
employment statistics developed by the Labor Department's Bureau of 
Labor Statistics (BLS). BLS regularly publishes its estimates of the 
number of jobs per million dollars of economic activity in different 
sectors of the economy, as well as the jobs created elsewhere in the 
economy by this same economic activity. Data from BLS indicate that 
expenditures in the utility sector generally create fewer jobs (both 
directly and indirectly) than expenditures in other sectors of the 
economy.\191\ There are many reasons for these differences, including 
wage differences and the fact that the utility sector is more capital-
intensive and less labor-intensive than other sectors. Energy 
conservation standards have the effect of reducing consumer utility 
bills. Because reduced consumer expenditures for energy likely lead to 
increased expenditures in other sectors of the economy, the general 
effect of efficiency standards is to shift economic activity from a 
less labor-intensive sector (i.e., the utility sector) to more labor-
intensive sectors (e.g., the retail and service sectors). Thus, the BLS 
data suggest that net national employment may increase due to shifts in 
economic activity resulting from energy conservation standards.
---------------------------------------------------------------------------

    \191\ See U.S. Department of Commerce-Bureau of Economic 
Analysis. Regional Input-Output Modeling System (RIMS II) User's 
Guide. Available at: apps.bea.gov/resources/methodologies/RIMSII-user-guide (last accessed Sept. 12, 2022).
---------------------------------------------------------------------------

    DOE estimated indirect national employment impacts for the standard 
levels considered in this final rule using an input/output model of the 
U.S. economy called Impact of Sector Energy Technologies version 4 
(ImSET).\192\ ImSET is a special-purpose version of the U.S. Benchmark 
National Input-Output (I-O) model, which was designed to estimate the 
national employment and income effects of energy-saving technologies. 
The ImSET software includes a computer-based I-O model having 
structural coefficients that

[[Page 29968]]

characterize economic flows among 187 sectors most relevant to 
industrial, commercial, and residential building energy use.
---------------------------------------------------------------------------

    \192\ Livingston, O. V., S. R. Bender, M. J. Scott, and R. W. 
Schultz. ImSET 4.0: Impact of Sector Energy Technologies Model 
Description and User's Guide. 2015. Pacific Northwest National 
Laboratory: Richland, WA. PNNL-24563.
---------------------------------------------------------------------------

    DOE notes that ImSET is not a general equilibrium forecasting 
model, and that there are uncertainties involved in projecting 
employment impacts, especially changes in the later years of the 
analysis. Because ImSET does not incorporate price changes, the 
employment effects predicted by ImSET may overestimate actual job 
impacts over the long run for this rule. Therefore, DOE used ImSET only 
to generate results for near-term timeframes (2034), where these 
uncertainties are reduced. In the long-term DOE expects that the net 
effect from amended standards will be an increased shift towards 
consumer goods from the utility sector. For more details on the 
employment impact analysis, see chapter 16 of the final rule TSD.

V. Analytical Results and Conclusions

    The following section addresses the results from DOE's analyses 
with respect to the considered energy conservation standards for 
distribution transformers. It addresses the TSLs examined by DOE, the 
projected impacts of each of these levels if adopted as energy 
conservation standards for distribution transformers, and the standards 
levels that DOE is adopting in this final rule. Additional details 
regarding DOE's analyses are contained in the final rule TSD supporting 
this document.
[GRAPHIC] [TIFF OMITTED] TR22AP24.559

A. Trial Standard Levels

    In general, DOE typically evaluates potential new or amended 
standards for products and equipment by grouping individual efficiency 
levels for each class into TSLs. Use of TSLs allows DOE to identify and 
consider manufacturer cost interactions between the equipment classes, 
to the extent that there are such interactions, and price elasticity of 
consumer purchasing decisions that may change when different standard 
levels are set.
    In the analysis conducted for this final rule, DOE analyzed the 
benefits and burdens of five TSLs for distribution transformers. DOE 
developed TSLs that combine efficiency levels for each analyzed 
equipment class and kVA rating. For this analysis, DOE defined its 
efficiency levels as a percentage reduction in baseline losses (See 
section IV.F.2 of this document). To create TSLs, DOE maintained this 
approach and directly mapped ELs to TSLs, for low-voltage dry-type and 
medium-voltage dry-type distribution transformers. To create TSLs for 
liquid-immersed distribution transformers other than submersible 
distribution transformers, DOE directly mapped ELs to TSLs for TSL 1, 
2, 4, and 5. For TSL 3, DOE considered a TSL wherein class 1A and 2A 
were mapped to EL 4 and equipment class 1B and 2B were mapped to EL 2, 
which corresponds to a TSL where a diversity of domestically produced 
core materials are cost competitive without requiring substantial 
investments in new capacity for core materials.
    DOE notes that all TSLs align with the TSLs from the NOPR except 
for liquid-immersed TSL 3. In the NOPR, DOE mapped EL 3 to TSL 3.
    In this final rule, DOE modified TSL 3 for liquid-immersed 
distribution transformers such that for equipment classes 1A, 1B, 2A, 
and 2B TSL3 is a combination wherein equipment classes 1B and 2B are 
set at EL2, and 1A and 2A are set at EL4. This ensures that capacity 
for amorphous ribbon increases driven by equipment classes 1A and 2A; 
and leaves a considerable portion of the market at efficiency levels 
where GOES remains cost competitive, equipment classes 1B and 2B. 
Further, TSL 3 ensures that units that are more likely

[[Page 29969]]

to have high currents (equipment class 2B) and units that are more 
likely to be overloaded (equipment class 1B), have additional 
flexibility in meeting efficiency standards to accommodate this 
consumer utility, as discussed in sections IV.A.2.b and IV.A.2.c of 
this document. For all other equipment classes TSL 3 is identical to 
that which was presented in the January 2023 NOPR. DOE notes that the 
ELs used in the final rule correspond to an identical reduction in 
rated losses as the ELs used in the January 2023 NOPR. However, the 
grouping of these ELs by equipment class has been modified in response 
to stakeholder feedback. TSL3 is intended to reflect stakeholder 
concerns that substantial amorphous core production could lead to near 
term supply chain constraints given the investment required to 
transition the entire U.S. market to amorphous cores.
    DOE notes that both EL 3 and EL 4 for liquid-immersed distribution 
transformers generally are met with substantial amorphous core 
production and therefore would have similar consumer and manufacturer 
impacts along with similar concerns regarding supply chain and domestic 
core production. DOE considered, and adopts, TSL 3 in this final rule 
to maximize the energy savings and consumer benefits without requiring 
that the entire market transition to amorphous cores, which, as 
discussed, would not be economically justified.
    Liquid-immersed submersible distribution transformers remain at 
baseline for all TSLs except max-tech. For submersible distribution 
transformers, being able to fit in an existing vault is a performance 
related feature of significant consumer utility and these transformers 
often serve high density applications. DOE recognizes that beyond some 
size increase a vault replacement may be necessary, however, DOE lacks 
sufficient data as to where exactly that vault replacement is needed. 
In order to maintain the consumer utility associated with submersible 
transformers, DOE has taken the conservative approach of not 
considering TSLs for submersible transformers aside from max-tech. DOE 
presents the results for the TSLs in this document, while the results 
for all efficiency levels that DOE analyzed are in the final rule TSD.
    Table V.2 presents the TSLs and the corresponding efficiency levels 
that DOE has identified for potential amended energy conservation 
standards for distribution transformers. TSL 5 represents the maximum 
technologically feasible (``max-tech'') energy efficiency for all 
product classes. TSL 4 represents a loss reduction over baseline of 20 
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 40 and 30 percent 
reduction in baseline losses for single-, and three-phase low-voltage 
distribution transformers, respectively; and a 30 percent reduction in 
baseline losses for all medium-voltage dry-type distribution 
transformers. TSL 3 represents a loss reduction over baseline of 5 
percent for liquid-immersed transformers for single-phase transformers 
less than or equal to 100 kVA and three-phase transformers greater than 
or equal to 500 kVA and a loss reduction over baseline of 20 percent 
for all other liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 30 and 20 percent 
reduction in baseline losses for single-, and three-phase low-voltage 
distribution transformers, respectively; and a 20 percent reduction in 
baseline losses for all medium-voltage dry-type distribution 
transformers. TSL 2 represents a loss reduction over baseline of 5 
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 20 and 10 percent 
reduction in baseline losses for single-, and three-phase low-voltage 
distribution transformers, respectively; and a 10 percent reduction in 
baseline losses for all medium-voltage dry-type distribution 
transformers. TSL 1 represents a loss reduction over baseline of 2.5 
percent for liquid-immersed transformers, except submersible liquid-
immersed transformers which remain at baseline; a 10 and 5 percent 
reduction in baseline losses for single-, and three-phase low-voltage 
distribution transformers, respectively; and a 5 percent reduction in 
baseline losses for all medium-voltage dry-type distribution 
transformers.

[[Page 29970]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.560

[GRAPHIC] [TIFF OMITTED] TR22AP24.561

    DOE constructed the TSLs for this final rule to include ELs 
representative of ELs with similar characteristics (i.e., using similar 
technologies and/or efficiencies, and having roughly comparable 
equipment availability) and taking into consideration the domestic 
electrical steel and amorphous capacity and conversion cost impacts 
associated with various ELs. The use of representative ELs provided for 
greater distinction between the TSLs. While representative ELs were 
included in the TSLs, DOE considered all efficiency levels as part of 
its analysis.\193\
---------------------------------------------------------------------------

    \193\ Efficiency levels that were analyzed for this final rule 
are discussed in section IV.F.2 of this document. Results by 
efficiency level are presented in TSD chapters 8, 10, and 12.

---------------------------------------------------------------------------

[[Page 29971]]

B. Economic Justification and Energy Savings

1. Economic Impacts on Individual Consumers
    DOE analyzed the economic impacts on distribution transformer 
consumers by looking at the effects that potential amended standards at 
each TSL would have on the LCC and PBP. DOE also examined the impacts 
of potential standards on selected consumer subgroups. These analyses 
are discussed in the following sections.
a. Life-Cycle Cost and Payback Period
    In general, higher-efficiency products affect consumers in two 
ways: (1) purchase price increases and (2) annual operating costs 
decrease. Inputs used for calculating the LCC and PBP include total 
installed costs (i.e., product price plus installation costs), and 
operating costs (i.e., annual energy use, energy prices, energy price 
trends, repair costs, and maintenance costs). The LCC calculation also 
uses product lifetime and a discount rate. Chapter 8 of the final rule 
TSD provides detailed information on the LCC and PBP analyses.
    The following sections show the LCC and PBP results for the TSLs 
considered for each product class. In the first of each pair of tables, 
the simple payback is measured relative to the baseline product. In the 
second table, the impacts are measured relative to the efficiency 
distribution in the in the no-new-standards case in the compliance year 
(see section IV.F.10 of this document). Because some consumers purchase 
products with higher efficiency in the no-new-standards case, the 
average savings are less than the difference between the average LCC of 
the baseline product and the average LCC at each TSL. The savings refer 
only to consumers who are affected by a standard at a given TSL. Those 
who already purchase a product with efficiency at or above a given TSL 
are not affected. Consumers for whom the LCC increases at a given TSL 
experience a net cost.
Liquid-Immersed Distribution Transformer
[GRAPHIC] [TIFF OMITTED] TR22AP24.562

[GRAPHIC] [TIFF OMITTED] TR22AP24.563


[[Page 29972]]


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[[Page 29973]]


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[[Page 29974]]


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[GRAPHIC] [TIFF OMITTED] TR22AP24.572


[[Page 29975]]


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[GRAPHIC] [TIFF OMITTED] TR22AP24.575


[[Page 29976]]


Medium-Voltage Dry-Type Distribution Transformer
[GRAPHIC] [TIFF OMITTED] TR22AP24.576

[GRAPHIC] [TIFF OMITTED] TR22AP24.577

[GRAPHIC] [TIFF OMITTED] TR22AP24.578


[[Page 29977]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.579

[GRAPHIC] [TIFF OMITTED] TR22AP24.580

[GRAPHIC] [TIFF OMITTED] TR22AP24.581

b. Consumer Subgroup Analysis
    In the consumer subgroup analysis, DOE estimated the impact of the 
considered TSLs on utilities who deploy distribution transformers in 
vaults or other space constrained areas, and utilities who serve low 
population densities. For each of these subgroups, DOE compares the 
average LCC savings and PBP at each efficiency level for the consumer 
subgroups with similar metrics.
    For the utilities serving low-population densities subgroup DOE 
presents the impacts of small single-phase liquid-immersed (equipment 
class 1B) against the those determined for the National average. DOEs 
analysis show that the impacts for utilities serving low populations to 
be negligible in terms of impacts and increased total installed cost, 
see Table V.23 and Table V.24.
    In most cases, the average LCC savings and PBP for utilities 
serving low populations at the considered trial standard levels are not 
substantially different from the average for all consumers. Chapter 11 
of the final rule TSD presents the complete LCC and PBP results for the 
subgroups.
Utilities Serving Low Population Densities

[[Page 29978]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.582

[GRAPHIC] [TIFF OMITTED] TR22AP24.583

Utilities That Deploy Distribution Transformers in Vaults or Other 
Space Constrained Areas
    As noted in section IV.I of this document, for this final rule DOE 
considered submersible distribution transformers and their associated 
vault, or space constrained installation costs with individual 
representative units, 15 and 16. DOE has incorporated increased 
installation costs as a function of increased volume in these results. 
However, as discussed in sections IV.1.2 and V.A of this document, 
there is considerable uncertainty surrounding the volume increase at 
which vault replacement would become necessary, and were this to occur 
at a lower volume than assumed and/or were the volume to increase with 
EL at a higher rate than assumed, this would result in significantly 
worse average LCC savings. Due to this significant uncertainty, DOE is 
unable to pinpoint at which EL, if any, this would occur. The consumer 
results for these equipment are presented in Table V.25 and Table V.26.

[[Page 29979]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.584

[GRAPHIC] [TIFF OMITTED] TR22AP24.585

c. Rebuttable Presumption Payback
    As discussed in section IV.F.11, EPCA establishes a rebuttable 
presumption that an energy conservation standard is economically 
justified if the increased purchase cost for a product that meets the 
standard is less than three times the value of the first-year energy 
savings resulting from the standard. In calculating a rebuttable 
presumption PBP for each of the considered TSLs, DOE used discrete 
values and, as required by EPCA, based the energy use calculation on 
the DOE test procedures for distribution transformers. In contrast, the 
PBPs presented in section V.B.1.a of this document were calculated 
using distributions that reflect the range of energy use in the field.
    Table V.27 presents the rebuttable-presumption PBPs for the 
considered TSLs for distribution transformers. While DOE examined the 
rebuttable-presumption criterion, it considered whether the standard 
levels considered for this rule are economically justified through a 
more detailed analysis of the economic impacts of those levels, 
pursuant to 42 U.S.C. 6295(o)(2)(B)(i), that considers the full range 
of impacts to the consumer, manufacturer, Nation, and environment. The 
results of that analysis serve as the basis for DOE to definitively 
evaluate the economic justification for a potential standard level, 
thereby supporting or rebutting the results of any preliminary 
determination of economic justification.

[[Page 29980]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.586

2. Economic Impacts on Manufacturers
    DOE performed an MIA to estimate the impact of amended energy 
conservation standards on manufacturers of distribution transformers. 
The next section describes the expected impacts on manufacturers at 
each considered TSL. Chapter 12 of the final rule TSD explains the 
analysis in further detail.
a. Industry Cash Flow Analysis Results
    In this section, DOE provides GRIM results from the analysis, which 
examines changes in the industry that would result from amended 
standards. The following tables summarize the estimated financial 
impacts (represented by changes in INPV) of potential amended energy 
conservation standards on manufacturers of distribution transformers, 
as well as the conversion costs that DOE estimates manufacturers of 
distribution transformers would incur at each TSL. DOE analyzes the 
potential impacts on INPV separately for each category of distribution 
transformer manufacturer: liquid-immersed, LVDT, and MVDT.
    As discussed in section IV.J.2.d of this document, DOE modeled two 
scenarios to evaluate a range of cash flow impacts on the distribution 
transformer industry: (1) the preservation of gross margin scenario and 
(2) the preservation of operating profit scenario. In the preservation 
of gross margin scenario, distribution transformer manufacturers are 
able to maintain the same gross margin percentage, even as the MPCs of 
distribution transformers increase due to energy conservation 
standards. In this scenario, the same gross margin percentage of 20 
percent \194\ is applied across all ELs. In the preservation of 
operating profit scenario, manufacturers do not earn additional 
operating profit when compared to the no-standards case scenario. While 
manufacturers make the necessary upfront investments required to 
produce compliant equipment, per-unit operating profit does not change 
in absolute dollars. The preservation of operating profit scenario 
results in the lower (or more severe) bound to impacts of amended 
standards on industry.
---------------------------------------------------------------------------

    \194\ The gross margin percentage of 20 percent is based on a 
manufacturer markup of 1.25.
---------------------------------------------------------------------------

    Each of the modeled scenarios results in a unique set of cash flows 
and corresponding industry values at each TSL for each category of 
distribution transformer manufacturer. In the following discussion, the 
INPV results refer to the difference in industry value between the no-
new-standards case and each standards case resulting from the sum of 
discounted cash flows from 2024 through 2058. To provide perspective on 
the short-run cash flow impact, DOE includes in the discussion of 
results a comparison of free cash flow between the no-new-standards 
case and the standards case at each TSL in the year before amended 
standards are required.
    DOE presents the range in INPV for liquid-immersed distribution 
transformer manufacturers in Table V.28 and Table V.29; the range in 
INPV for LVDT distribution transformer manufacturers in Table V.31 and 
Table V.32; and the range in INPV for MVDT distribution transformer 
manufacturers in Table V.34 and Table V.35.
Liquid-Immersed Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.587


[[Page 29981]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.588

[GRAPHIC] [TIFF OMITTED] TR22AP24.589

    At TSL 5, DOE estimates the impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$686 million to -
$338 million, corresponding to a change in INPV of -38.3 percent to -
18.8 percent. At TSL 5, industry free cash flow is estimated to 
decrease by approximately 245 percent to -$175 million, compared to the 
no-new-standard case value of $121 million in 2028, the year before the 
compliance date.
    TSL 5 would set the energy conservation standard at EL 5, max-tech, 
for all liquid-immersed distribution transformers. DOE estimates that 
less than one percent of shipments would meet these energy conservation 
standards in the no-new-standards case in 2029. DOE estimates liquid-
immersed distribution transformer manufacturers would spend 
approximately $194 million in product conversion costs to redesign 
transformers and approximately $503 million in capital conversion costs 
as all liquid-immersed distribution transformer cores manufactured are 
expected to use amorphous steel.
    At TSL 5, the shipment weighted average MPC for liquid-immersed 
distribution transformers significantly increases by 27.0 percent 
relative to the no-new-standards case shipment weighted average MPC in 
2029. In the preservation of gross margin scenario, manufacturers can 
fully pass along this cost increase, which causes an increase in 
manufacturers' free cash flow. However, the $697 million in conversion 
costs estimated at TSL 5, ultimately results in a significantly 
negative change in INPV at TSL 5 under the preservation of gross margin 
scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 27.0 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $697 million in conversion costs 
incurred by manufacturers cause a significantly negative change in INPV 
at TSL 5 in the preservation of operating profit scenario. This 
represents the lower-bound, or most severe impact, on manufacturer 
profitability.
    At TSL 4, DOE estimates the impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$476 million to -
$388 million, corresponding to a change in INPV of -26.6 percent to -
21.6 percent. At TSL 4, industry free cash flow is estimated to 
decrease by approximately 204 percent to -$125 million, compared to the 
no-new-standard case value of $121 million in 2028, the year before the 
compliance date.
    TSL 4 would set the energy conservation standard at EL 4 for all 
liquid-immersed distribution transformer representative units, except 
for representative units 15 and 16, which are set at baseline. DOE 
estimates that less than one percent of shipments would meet or exceed 
these energy conservation standards in the no-new-standards case in 
2029. DOE estimates liquid-immersed distribution transformer 
manufacturers would spend approximately $193 million in product 
conversion costs to redesign transformers and approximately $395 
million in capital conversion costs as almost all liquid-immersed 
distribution transformer cores manufactured are expected to use 
amorphous steel.
    At TSL 4, the shipment weighted average MPC for liquid-immersed 
distribution transformers increases by 6.9 percent relative to the no-
new-standards case shipment weighted

[[Page 29982]]

average MPC in 2029. In the preservation of gross margin scenario, 
manufacturers can fully pass along this cost increase, which causes an 
increase in manufacturers' free cash flow. However, the $587 million in 
conversion costs estimated at TSL 4, ultimately results in a moderately 
negative change in INPV at TSL 4 under the preservation of gross margin 
scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 6.9 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $587 million in conversion costs 
incurred by manufacturers cause a moderately negative change in INPV at 
TSL 4 in the preservation of operating profit scenario. This represents 
the lower-bound, or most severe impact, on manufacturer profitability.
    At TSL 3, DOE estimates the impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$145 million to -
$111 million, corresponding to a change in INPV of -8.1 percent to -6.2 
percent. At TSL 3, industry free cash flow is estimated to decrease by 
approximately 60 percent to $48 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the 
compliance date.
    TSL 3 would set the energy conservation standard at EL 4 for the 
liquid-immersed distribution transformer representative units 1A, 2A, 
3, and 4A; at EL 2 for the liquid-immersed distribution transformer 
representative units 1B, 2B, 4B, 5, and 17; and at baseline for the 
liquid-immersed distribution transformer representative units 15 and 
16. DOE estimates that approximately 3.7 percent of shipments would 
meet or exceed these energy conservation standards in the no-new-
standards case in 2029. DOE estimates liquid-immersed distribution 
transformer manufacturers would spend approximately $118 million in 
product conversion costs to redesign transformers and approximately $69 
million in capital conversion costs as a portion of liquid-immersed 
distribution transformer cores manufactured are expected to use 
amorphous steel.
    At TSL 3, the shipment weighted average MPC for liquid-immersed 
distribution transformers increases by 2.6 percent relative to the no-
new-standards case shipment weighted average MPC in 2029. In the 
preservation of gross margin scenario, manufacturers can fully pass 
along this cost increase, which causes an increase in manufacturers' 
free cash flow. However, the $187 million in conversion costs estimated 
at TSL 3, ultimately results in a moderately negative change in INPV at 
TSL 3 under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 2.6 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $187 million in conversion costs 
incurred by manufacturers cause a moderately negative change in INPV at 
TSL 3 in the preservation of operating profit scenario. This represents 
the lower-bound, or most severe impact, on manufacturer profitability.
    At TSL 2, DOE estimates the impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$77 million to -
$58 million, corresponding to a change in INPV of -4.3 percent to -3.2 
percent. At TSL 2, industry free cash flow is estimated to decrease by 
approximately 32 percent to $82 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the 
compliance date.
    TSL 2 would set the energy conservation standard at EL 2 for all 
liquid-immersed distribution transformer representative units, except 
for representative units 15 and 16, which are set at baseline. DOE 
estimates that approximately 4.0 percent of shipments would meet or 
exceed these energy conservation standards in the no-new-standards case 
in 2029. DOE estimates liquid-immersed distribution transformer 
manufacturers would spend approximately $101 million in product 
conversion costs to redesign transformers and approximately $6 million 
in capital conversion costs as almost all liquid-immersed distribution 
transformer cores manufactured are expected to continue to use GOES 
steel.
    At TSL 2, the shipment weighted average MPC for liquid-immersed 
distribution transformers increases slightly by 1.5 percent relative to 
the no-new-standards case shipment weighted average MPC in 2029. In the 
preservation of gross margin scenario, manufacturers can fully pass 
along this cost increase, which causes a slight increase in 
manufacturers' free cash flow. However, the $107 million in conversion 
costs estimated at TSL 2, ultimately results in a slightly negative 
change in INPV at TSL 2 under the preservation of gross margin 
scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 1.5 percent increase in the shipment weighted average MPC results 
in a slight reduction in the margin after the compliance year. This 
slight reduction in the manufacturer margin and the $107 million in 
conversion costs incurred by manufacturers cause a slightly negative 
change in INPV at TSL 2 in the preservation of operating profit 
scenario. This represents the lower-bound, or most severe impact, on 
manufacturer profitability.
    At TSL 1, DOE estimates the impacts on INPV for liquid-immersed 
distribution transformer manufacturers to range from -$66 million to -
$62 million, corresponding to a change in INPV of -3.7 percent to -3.5 
percent. At TSL 1, industry free cash flow is estimated to decrease by 
approximately 30 percent to $84 million, compared to the no-new-
standard case value of $121 million in 2028, the year before the 
compliance date.
    TSL 1 would set the energy conservation standard at EL 1 for all 
liquid-immersed distribution transformer representative units, except 
for representative units 15 and 16, which are set at baseline. DOE 
estimates that approximately 13.3 percent of shipments would meet or 
exceed these energy conservation standards in the no-new-standards case 
in 2029. DOE estimates liquid-immersed distribution transformer 
manufacturers would spend approximately $100 million in product 
conversion costs to redesign transformers and approximately $2 million 
in capital conversion costs as almost all liquid-immersed distribution 
transformer cores manufactured are expected to continue to use GOES 
steel.
    At TSL 1, the shipment weighted average MPC for liquid-immersed 
distribution transformers increases slightly by 0.3 percent relative to 
the no-new-standards case shipment weighted average MPC in 2029. In the 
preservation of gross margin scenario, manufacturers can fully pass 
along this cost increase, which causes a slight increase in 
manufacturers' free cash flow. However, the $102 million in

[[Page 29983]]

conversion costs estimated at TSL 1, ultimately results in a slightly 
negative change in INPV at TSL 1 under the preservation of gross margin 
scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 0.3 percent increase in the shipment weighted average MPC results 
in a slight reduction in the margin after the compliance year. This 
slight reduction in the manufacturer margin and the $102 million in 
conversion costs incurred by manufacturers cause a slightly negative 
change in INPV at TSL 1 in the preservation of operating profit 
scenario. This represents the lower-bound, or most severe impact, on 
manufacturer profitability.
Low-Voltage Dry-Type Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.590

[GRAPHIC] [TIFF OMITTED] TR22AP24.591

[GRAPHIC] [TIFF OMITTED] TR22AP24.592

    At TSL 5, DOE estimates the impacts on INPV for LVDT distribution 
transformer manufacturers to range from -$68.4 million to -$54.0 
million, corresponding to a change in INPV of -32.3 percent to -25.5 
percent. At TSL 5, industry free cash flow is estimated to decrease by 
approximately 183.6 percent to -$17.5 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the 
compliance date.
    TSL 5 would set the energy conservation standard at EL 5, max-tech, 
for all LVDT distribution transformers. DOE estimates that no shipments 
would meet these energy conservation standards in the no-new-standards 
case in 2029. DOE estimates LVDT distribution transformer manufacturers 
would spend approximately $31.0 million in product conversion costs to 
redesign transformers and approximately $60.8 million in capital 
conversion costs as all LVDT distribution transformer cores 
manufactured are expected to use amorphous steel.
    At TSL 5, the shipment weighted average MPC for LVDT distribution 
transformers increases by 11.1 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However,

[[Page 29984]]

the $91.8 million in conversion costs estimated at TSL 5, ultimately 
results in a moderately negative change in INPV at TSL 5 under the 
preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 11.1 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $91.8 million in conversion costs 
incurred by manufacturers cause a significantly negative change in INPV 
at TSL 5 in the preservation of operating profit scenario. This 
represents the lower-bound, or most severe impact, on manufacturer 
profitability.
    At TSL 4, DOE estimates the impacts on INPV for LVDT distribution 
transformer manufacturers to range from -$62.9 million to -$52.2 
million, corresponding to a change in INPV of -29.7 percent to -24.7 
percent. At TSL 4, industry free cash flow is estimated to decrease by 
approximately 173.0 percent to -$15.2 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the 
compliance date.
    TSL 4 would set the energy conservation standard at EL 4 for all 
LVDT distribution transformers. DOE estimates that no shipments would 
meet these energy conservation standards in the no-new-standards case 
in 2029. DOE estimates LVDT distribution transformer manufacturers 
would spend approximately $30.3 million in product conversion costs to 
redesign transformers and approximately $56.4 million in capital 
conversion costs as almost all LVDT distribution transformer cores 
manufactured are expected to use amorphous steel.
    At TSL 4, the shipment weighted average MPC for LVDT distribution 
transformers increases by 8.2 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $86.7 million in conversion costs estimated at TSL 4, 
ultimately results in a moderately negative change in INPV at TSL 4 
under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 8.2 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $86.7 million in conversion costs 
incurred by manufacturers cause a moderately negative change in INPV at 
TSL 4 in the preservation of operating profit scenario. This represents 
the lower-bound, or most severe impact, on manufacturer profitability.
    At TSL 3, DOE estimates the impacts on INPV for LVDT distribution 
transformer manufacturers to range from -$27.1 million to -$18.9 
million, corresponding to a change in INPV of -12.8 percent to -8.9 
percent. At TSL 3, industry free cash flow is estimated to decrease by 
approximately 68.8 percent to $6.5 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the 
compliance date.
    TSL 3 would set the energy conservation standard at EL 3 for all 
LVDT distribution transformers. DOE estimates that less than one 
percent of shipments would meet these energy conservation standards in 
the no-new-standards case in 2029. DOE estimates LVDT distribution 
transformer manufacturers would spend approximately $19.9 million in 
product conversion costs to redesign transformers and approximately 
$16.3 million in capital conversion costs as a portion of LVDT 
distribution transformer cores manufactured are expected to use 
amorphous steel.
    At TSL 3, the shipment weighted average MPC for LVDT distribution 
transformers increases by 6.3 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $36.1 million in conversion costs estimated at TSL 3, 
ultimately results in a moderately negative change in INPV at TSL 3 
under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 6.3 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $36.1 million in conversion costs 
incurred by manufacturers cause a moderately negative change in INPV at 
TSL 3 in the preservation of operating profit scenario. This represents 
the lower-bound, or most severe impact, on manufacturer profitability.
    At TSL 2, DOE estimates the impacts on INPV for LVDT distribution 
transformer manufacturers to range from -$10.4 million to -$9.6 
million, corresponding to a change in INPV of -4.9 percent to -4.5 
percent. At TSL 2, industry free cash flow is estimated to decrease by 
approximately 30.1 percent to $14.6 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the 
compliance date.
    TSL 2 would set the energy conservation standard at EL 2 for all 
LVDT distribution transformers. DOE estimates that approximately 3.7 
percent of shipments would meet these energy conservation standards in 
the no-new-standards case in 2029. DOE estimates LVDT distribution 
transformer manufacturers would spend approximately $15.9 million in 
product conversion costs to redesign transformers and approximately 
$1.4 million in capital conversion costs as almost all LVDT 
distribution transformer cores manufactured are expected to continue to 
use GOES steel.
    At TSL 2, the shipment weighted average MPC for LVDT distribution 
transformers increases by 0.6 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $17.3 million in conversion costs estimated at TSL 2, 
ultimately results in a slightly negative change in INPV at TSL 2 under 
the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 0.6 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $17.3 million in conversion costs 
incurred by manufacturers cause a slightly negative change in INPV at 
TSL 2 in the preservation of operating profit scenario. This represents 
the lower-

[[Page 29985]]

bound, or most severe impact, on manufacturer profitability.
    At TSL 1, DOE estimates the impacts on INPV for LVDT distribution 
transformer manufacturers to range from -$8.9 million to -$8.5 million, 
corresponding to a change in INPV of -4.2 percent to -4.0 percent. At 
TSL 1, industry free cash flow is estimated to decrease by 
approximately 26.4 percent to $15.4 million, compared to the no-new-
standard case value of $20.9 million in 2028, the year before the 
compliance date.
    TSL 1 would set the energy conservation standard at EL 1 for all 
LVDT distribution transformers. DOE estimates that approximately 24.5 
percent of shipments would meet these energy conservation standards in 
the no-new-standards case in 2029. DOE estimates LVDT distribution 
transformer manufacturers would spend approximately $15.5 million in 
product conversion costs to redesign transformers.
    At TSL 1, the shipment weighted average MPC for LVDT distribution 
transformers deceases slightly by 0.3 percent relative to the no-new-
standards case shipment weighted average MPC in 2029. In both 
manufacturer markup scenarios, this slight decrease in manufacturer 
markup does not have a significant impact on manufacturers' free cash 
flow. However, in both manufacturer markup scenarios, the $15.5 million 
in conversion costs estimated at TSL 1, results in a slightly negative 
change in INPV at TSL 1.
Medium-Voltage Dry-Type Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.593

[GRAPHIC] [TIFF OMITTED] TR22AP24.594

[GRAPHIC] [TIFF OMITTED] TR22AP24.595

    At TSL 5, DOE estimates the impacts on INPV for MVDT distribution 
transformer manufacturers to range from -$33.2 million to -$16.3 
million, corresponding to a change in INPV of -34.9 percent to -17.1 
percent. At TSL 5, industry free cash flow is estimated to decrease by 
approximately 200.3 percent to -$7.7 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the 
compliance date.
    TSL 5 would set the energy conservation standard at EL 5, max-tech, 
for all MVDT distribution transformers. DOE estimates that no shipments 
would meet these energy conservation standards in the no-new-standards 
case in 2029. DOE estimates MVDT distribution transformer manufacturers 
would spend approximately $10.1 million in product conversion costs to 
redesign transformers and approximately $26.2 million in capital

[[Page 29986]]

conversion costs as all MVDT distribution transformer cores 
manufactured are expected to use amorphous steel.
    At TSL 5, the shipment weighted average MPC for LVDT distribution 
transformers significantly increases by 26.3 percent relative to the 
no-new-standards case shipment weighted average MPC in 2029. In the 
preservation of gross margin scenario, manufacturers can fully pass 
along this cost increase, which causes an increase in manufacturers' 
free cash flow. However, the $36.2 million in conversion costs 
estimated at TSL 5, ultimately results in a moderately negative change 
in INPV at TSL 5 under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 26.3 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $36.2 million in conversion costs 
incurred by manufacturers cause a significantly negative change in INPV 
at TSL 5 in the preservation of operating profit scenario. This 
represents the lower-bound, or most severe impact, on manufacturer 
profitability.
    At TSL 4, DOE estimates the impacts on INPV for MVDT distribution 
transformer manufacturers to range from -$29.5 million to -$18.6 
million, corresponding to a change in INPV of -31.0 percent to -19.5 
percent. At TSL 4, industry free cash flow is estimated to decrease by 
approximately 191.7 percent to -$7.0 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the 
compliance date.
    TSL 4 would set the energy conservation standard at EL 4 for all 
MVDT distribution transformers. DOE estimates that no shipments would 
meet these energy conservation standards in the no-new-standards case 
in 2029. DOE estimates LVDT distribution transformer manufacturers 
would spend approximately $10.1 million in product conversion costs to 
redesign transformers and approximately $24.7 million in capital 
conversion costs as all MVDT distribution transformer cores 
manufactured are expected to use amorphous steel.
    At TSL 4, the shipment weighted average MPC for MVDT distribution 
transformers increases by 17.0 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $34.8 million in conversion costs estimated at TSL 4, 
ultimately results in a moderately negative change in INPV at TSL 4 
under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 17.0 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $34.8 million in conversion costs 
incurred by manufacturers cause a significantly negative change in INPV 
at TSL 4 in the preservation of operating profit scenario. This 
represents the lower-bound, or most severe impact, on manufacturer 
profitability.
    At TSL 3, DOE estimates the impacts on INPV for MVDT distribution 
transformer manufacturers to range from -$26.4 million to -$19.1 
million, corresponding to a change in INPV of -27.8 percent to -20.1 
percent. At TSL 3, industry free cash flow is estimated to decrease by 
approximately 179.9 percent to -$6.1 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the 
compliance date.
    TSL 3 would set the energy conservation standard at EL 3 for all 
MVDT distribution transformers. DOE estimates that no shipments would 
meet these energy conservation standards in the no-new-standards case 
in 2029. DOE estimates MVDT distribution transformer manufacturers 
would spend approximately $9.8 million in product conversion costs to 
redesign transformers and approximately $22.9 million in capital 
conversion costs as the majority of MVDT distribution transformer cores 
manufactured are expected to use amorphous steel.
    At TSL 3, the shipment weighted average MPC for MVDT distribution 
transformers increases by 11.3 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $32.7 million in conversion costs estimated at TSL 3, 
ultimately results in a moderately negative change in INPV at TSL 3 
under the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would be earned in the no-
new-standards case, but manufacturers do not earn additional profit 
from their investments or potentially higher MPCs. In this scenario, 
the 11.3 percent increase in the shipment weighted average MPC results 
in a reduction in the margin after the compliance year. This reduction 
in the manufacturer margin and the $32.7 million in conversion costs 
incurred by manufacturers cause a moderately negative change in INPV at 
TSL 3 in the preservation of operating profit scenario. This represents 
the lower-bound, or most severe impact, on manufacturer profitability.
    At TSL 2, DOE estimates the impacts on INPV for MVDT distribution 
transformer manufacturers to range from -$4.4 million to -$2.3 million, 
corresponding to a change in INPV of -4.7 percent to -2.5 percent. At 
TSL 2, industry free cash flow is estimated to decrease by 
approximately 27.2 percent to $5.6 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the 
compliance date.
    TSL 2 would set the energy conservation standard at EL 2 for all 
MVDT distribution transformers. DOE estimates that approximately 3.8 
percent of shipments would meet these energy conservation standards in 
the no-new-standards case in 2029. DOE estimates MVDT distribution 
transformer manufacturers would spend approximately $5.2 million in 
product conversion costs to redesign transformers and approximately 
$0.5 million in capital conversion costs as almost all MVDT 
distribution transformer cores manufactured are expected to continue to 
use GOES steel.
    At TSL 2, the shipment weighted average MPC for MVDT distribution 
transformers increases by 3.2 percent relative to the no-new-standards 
case shipment weighted average MPC in 2029. In the preservation of 
gross margin scenario, manufacturers can fully pass along this cost 
increase, which causes an increase in manufacturers' free cash flow. 
However, the $5.7 million in conversion costs estimated at TSL 2, 
ultimately results in a slightly negative change in INPV at TSL 2 under 
the preservation of gross margin scenario.
    Under the preservation of operating profit scenario, manufacturers 
earn the same per-unit operating profit as would

[[Page 29987]]

be earned in the no-new-standards case, but manufacturers do not earn 
additional profit from their investments or potentially higher MPCs. In 
this scenario, the 3.2 percent increase in the shipment weighted 
average MPC results in a reduction in the margin after the compliance 
year. This reduction in the manufacturer margin and the $5.7 million in 
conversion costs incurred by manufacturers cause a slightly negative 
change in INPV at TSL 2 in the preservation of operating profit 
scenario. This represents the lower-bound, or most severe impact, on 
manufacturer profitability.
    At TSL 1, DOE estimates the impacts on INPV for MVDT distribution 
transformer manufacturers to range from -$3.5 million to -$2.7 million, 
corresponding to a change in INPV of -3.6 percent to -2.8 percent. At 
TSL 1, industry free cash flow is estimated to decrease by 
approximately 23.4 percent to $5.9 million, compared to the no-new-
standard case value of $7.7 million in 2028, the year before the 
compliance date.
    TSL 1 would set the energy conservation standard at EL 1 for all 
MVDT distribution transformers. DOE estimates that approximately 21.7 
percent of shipments would meet these energy conservation standards in 
the no-new-standards case in 2029. DOE estimates MVDT distribution 
transformer manufacturers would spend approximately $5.0 million in 
product conversion costs to redesign transformers.
    At TSL 1, the shipment weighted average MPC for MVDT distribution 
transformers deceases slightly by 1.2 percent relative to the no-new-
standards case shipment weighted average MPC in 2029. In both 
manufacturer markup scenarios, this slight decrease in manufacturer 
markup does not have a significant impact on manufacturers' free cash 
flow. However, in both manufacturer markup scenarios, the $5.0 million 
in conversion costs estimated at TSL 1, results in a slightly negative 
change in INPV at TSL 1.
b. Direct Impacts on Employment
    To quantitatively assess the potential impacts of amended energy 
conservation standards on direct employment in the distribution 
transformer industry, DOE used the GRIM to estimate the domestic labor 
expenditures and number of direct employees in the no-new-standards 
case and in each of the standards cases during the analysis period.
    Production employees are those who are directly involved in 
fabricating and assembling equipment within a manufacturer facility. 
Workers performing services that are closely associated with production 
operations, such as materials handling tasks using forklifts, are 
included as production labor, as well as line supervisors.
    DOE used the GRIM to calculate the number of production employees 
from labor expenditures. DOE used statistical data from the U.S. Census 
Bureau's 2021 Annual Survey of Manufacturers (ASM) and the results of 
the engineering analysis to calculate industry-wide labor expenditures. 
Labor expenditures related to equipment manufacturing depend on the 
labor intensity of the product, the sales volume, and an assumption 
that wages remain fixed in real terms over time. The total labor 
expenditures in the GRIM were then converted to domestic production 
employment levels by dividing production labor expenditures by the 
annual payment per production worker.
    Non-production employees account for those workers that are not 
directly engaged in the manufacturing of the covered equipment. This 
could include sales, human resources, engineering, and management. DOE 
estimated non-production employment levels by multiplying the number of 
distribution transformer workers by a scaling factor. The scaling 
factor is calculated by taking the ratio of the total number of 
employees, and the total production workers associated with the 
industry NAICS code 335311, which covers power, distribution, and 
specialty transformer manufacturing.
    Using data from manufacturer interviews and estimated market share 
data, DOE estimates that approximately 85 percent of all liquid-
immersed distribution transformer manufacturing; 15 percent of all LVDT 
distribution transformer manufacturing; and 75 percent of all MVDT 
distribution transformer manufacturing takes place domestically.
    Several interested parties commented on the direct employment 
analysis in the January 2023 NOPR. Some interested parties commented 
that the standards proposed in the January 2023 NOPR would result in a 
decrease in domestic employment. UAW commented that it expects mass 
layoffs as a result of the standards proposed in the January 2023 NOPR 
since 70 percent of the electrical steel that UAW members produce for 
Cleveland Cliffs is used in distribution transformer cores. (UAW, No. 
90 at P. 2) UAW also commented that currently 90 percent of 
distribution transformers are made with GOES. Without this demand for 
GOES, the continued production of all GOES in the United States could 
be placed in jeopardy. (Id.) UAW urged DOE to consider the potential 
loss of electrical steel jobs as a result of any adopted standards for 
distribution transformers. (Id.) Similarly, UAW Locals commented that 
the standards proposed in the January 2023 NOPR would make Cleveland 
Cliffs electrical steel plants uneconomic, which could jeopardize 
nearly 1,500 steel manufacturing jobs. (UAW Locals, No. 91 at p. 1)
    NAHB commented that DOE must consider the possibility that 
requiring a new manufacturing process to make distribution transformers 
more efficient may actually require fewer workers. (NAHB, No. 106 at 
pp. 11-12) Prolec GE commented that any standards that required a shift 
from GOES production to amorphous steel production would affect 
domestic employment as currently most of the core manufacturing using 
GOES is done in-house, and it would need to be shifted to outsourced 
finished amorphous metal cores where most of the production capacity is 
not domestic. (Prolec GE, No. 120 at p. 13) Lastly, Cliffs commented 
that DOE underestimated the required number amount of labor to convert 
to amorphous production in the January 2023 NOPR and the actual 
additional number of employees to meet the standards proposed in the 
January 2023 NOPR will lead to increased offshoring. (Cliffs, No. 105 
at pp. 14-15)
    Other interested parties comments that the standards proposed in 
the January 2023 NOPR would result in an increase in domestic 
employment. Eaton commented that it expects an increase in labor 
content to meet the standards proposed in the January 2023 NOPR. 
(Eaton, No. 137 at p. 29) Howard commented that they would need to add 
1,000-2,000 employees (which corresponds to a 25-50 percent increase in 
their current employment levels) to meet the standards proposed in the 
January 2023 NOPR. (Howard, No. 116 at p. 2) Howard stated they 
estimate the entire industry could need an additional 5,500 to 6,000 
employees to meet the standards proposed in the January 2023 NOPR. 
(Howard, No. 116 at p. 2) Additionally, Howard commented that in 
addition to distribution transformer manufacturers adding employees, 
electrical steel manufacturers would have to add employees as well, 
which will be difficult given the 3-year compliance period used in the 
January 2023 NOPR and the current labor market, which lacks available 
personnel. (Howard, No. 116 at pp. 2-3) Metglas commented that it 
estimated that amorphous production would require 600 to 900 new U.S. 
jobs to meet the standards proposed in the January

[[Page 29988]]

2023 NOPR. (Metglas, No. 125 at p. 7) Efficiency advocates commented 
that the expansion of amorphous production capacity would be expected 
to add hundreds of electrical steel manufacturing jobs. (Efficiency 
advocates, No. 121 at pp. 4-5) Efficiency advocates additionally stated 
that producers of GOES would be well positioned to transition 
production capacity to NOES to preserve manufacturing jobs. (Id.)
    DOE's direct employment analysis conducted in the January 2023 NOPR 
presented a range of impacts to employment. As some interested parties 
commented, manufacturing distribution transformers with amorphous cores 
will likely require additional employees. However, DOE also recognizes 
that currently many amorphous core manufacturing locations are outside 
the U.S., as some interested parties commented. DOE continues to 
present a range of domestic employment impacts in this final rule that 
show the likely range in domestic employment given that manufacturing 
more efficient distribution transformers will likely result in an 
increase in production employees; however, some manufacturers may shift 
current domestic production to non-domestic locations to fulfill this 
additional labor demand. The range of potential impacts displayed in 
Table V.37, Table V.38, and Table V.39 present the most likely range of 
potential impacts to domestic employment for the analyzed TSLs.
Liquid-Immersed Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.596

    Using the estimated labor content from the GRIM combined with data 
from the 2021 ASM, DOE estimates that there would be approximately 
6,561 domestic production workers, and 2,721 domestic non-production 
workers involved in liquid-immersed distribution transformer 
manufacturing in 2029 in the absence of amended energy conservation 
standards. Table V.37 shows the range of the impacts of energy 
conservation standards on U.S. production on liquid-immersed 
distribution transformers.
    Amorphous core production is more labor intensive and would require 
additional labor expenditures. The upper range of the ``Potential 
Change in Total Domestic Employment in 2029'' displayed in Table V.37, 
assumes that all domestic liquid-immersed distribution transformer 
manufacturing remains in the U.S. For this scenario, the additional 
labor expenditures associated with amorphous core production result in 
the number of total direct employees to increase due to energy 
conservation standards. At higher TSLs, the estimated number of 
amorphous cores used in liquid-immersed distribution transformers 
increases, which causes the number of direct employees to also 
increase. The lower range of the ``Potential Change in Total Domestic 
Employment in 2029'' displayed in Table V.37, assumes that as more 
amorphous cores are used to meet higher energy conservation standards, 
either the amorphous core production is outsourced to core only 
manufacturers (manufacturers that specialize in manufacturing cores 
used in distribution transformers, but do not actually manufacture 
entire distribution transformers) which may be located in foreign 
countries, or distribution transformer manufacturing is re-located to 
foreign countries. This lower range assumes that 30 percent of 
distribution transformers using amorphous cores are re-located to 
foreign countries due to energy conservation standards. DOE 
acknowledges that each distribution transformer manufacturer would 
individually make a business decision to either make the substantial 
investments to add or increase their own amorphous core production 
capabilities and continue to manufacturer their own cores in-house; 
outsource their amorphous core production to another distribution core 
manufacturer, which may or may not be located in the U.S.; or re-locate 
some or all of their distribution transformer manufacturing to a 
foreign country. DOE acknowledges there is a wide range of potential 
domestic employment impacts due to energy conservation standards, 
especially at the higher TSLs. The ranges in potential employment 
impacts displayed in Table V.37 at each TSL attempt to provide a 
reasonable upper and lower bound to how liquid-immersed distribution 
transformer manufacturers may respond to potential energy conservation 
standards.
Low-Voltage Dry-Type Distribution Transformers

[[Page 29989]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.597

    Using the estimated labor content from the GRIM combined with data 
from the 2021 ASM, DOE estimates that there would be approximately 185 
domestic production workers, and 77 domestic non-production workers 
involved in LVDT distribution transformer manufacturing in 2029 in the 
absence of amended energy conservation standards. Table V.38 shows the 
range of the impacts of energy conservation standards on U.S. 
production on LVDT distribution transformers.
    DOE used the same methodology to estimate the potential impacts to 
domestic employment for LVDT distribution transformer manufacturing 
that was used for liquid-immersed distribution transformer 
manufacturing. The upper range of the ``Potential Change in Total 
Domestic Employment in 2029'' displayed in Table V.38, assumes that all 
LVDT distribution transformer manufacturing remains in the U.S. The 
lower range of the ``Potential Change in Total Domestic Employment in 
2029'', assumes that 30 percent of distribution transformers using 
amorphous cores are re-located to foreign countries, either due to 
amorphous core production that is outsourced to core only manufacturers 
located in foreign countries or LVDT distribution transformer 
manufacturers re-locating their distribution transformer production to 
foreign countries.
Medium-Voltage Dry-Type Distribution Transformers
[GRAPHIC] [TIFF OMITTED] TR22AP24.598

    Using the estimated labor content from the GRIM combined with data 
from the 2021 ASM, DOE estimates that there would be approximately 300 
domestic production workers, and 125 domestic non-production workers 
involved in MVDT distribution transformer manufacturing in 2029 in the 
absence of amended energy conservation standards. Table V.39 shows the 
range of the impacts of energy conservation standards on U.S. 
production on MVDT distribution transformers.
    DOE used the same methodology to estimate the potential impacts to 
domestic employment for MVDT distribution transformer manufacturing 
that was used for liquid-immersed distribution transformer 
manufacturing. The upper range of the ``Potential Change in Total 
Domestic Employment in 2029'' displayed in Table V.39, assumes that all 
MVDT distribution transformer manufacturing remains in the U.S. The 
lower range of the ``Potential Change in Total Domestic Employment in 
2029'', assumes that 30 percent of distribution transformers using 
amorphous cores are re-located to foreign countries, either due to 
amorphous core production that is outsourced to core only manufacturers 
located in foreign countries or MVDT distribution transformer 
manufacturers re-locating their distribution transformer production to 
foreign countries.
c. Impacts on Manufacturing Capacity
    The prices of raw materials currently used in distribution 
transformers, such as GOES, copper, and aluminum, have all experienced 
a significant increase in price starting at the beginning of 2021. The 
availability of these commodities remains a significant concern with 
distribution transformer manufacturers. As previously stated in the 
January 2023

[[Page 29990]]

NOPR, GOES investment from steel producers is competing with NOES 
investment suited for electric vehicle production. This competing 
investment, combined with demand growth supporting other 
electrification trends has led to a substantial global increase in 
GOES. However, amorphous alloys have not seen the same significant 
increase in price as GOES.
    The availability of amorphous material is a concern for many 
distribution transformer manufacturers. Based on information received 
during manufacturer interviews, some distribution transformer 
manufacturers suggested that there would not be enough amorphous steel 
available to be used in all or even most distribution transformers 
currently sold in the U.S. Other distribution transformer manufacturers 
and steel suppliers interviewed stated that, while the current capacity 
of amorphous steel does not exist to supply the majority of the steel 
used in distribution transformer cores, steel manufacturers are capable 
of significantly increasing their amorphous steel production if there 
is sufficient market demand for amorphous steel.
    Cliffs commented that the January 2023 NOPR did not accurately 
account for the supply chain constraints associated with ramping up 
production of amorphous steel in addition to the tremendous increased 
demands linked to greater market penetration of electric vehicles and 
other decarbonization efforts that the steel industry is facing. 
(Cliffs., No, 105 at p. 15) Cliffs continued stating the increased 
costs associated with all distribution transformers using amorphous 
cores, which currently constitutes about three percent of the market 
for distribution transformers, will be massive and stretch the limits 
of existing supply chains beyond their breaking point. (Id.) Eaton 
commented that changing the current supply of GOES that used in almost 
all distribution transformer cores today to having almost all 
distribution transformers using amorphous cores would disrupt the 
supply of cores and/or core steel to a massive extent and would likely 
to be accompanied by some unexpected outcomes. (Eaton, No. 137 at p. 
26)
    While the availability of both GOES and amorphous steel is a 
concern for many distribution transformer manufacturers, steel 
suppliers should be able to meet the market demand for amorphous steel 
for all TSLs analyzed given the 5-year compliance period for 
distribution transformers. Steel manufacturers should be able to 
significantly increase their supply of amorphous steel if they know 
there will be an increase in the demand for this material due to energy 
conservation standards for distribution transformers. See section V.C 
for a more detailed discussion of the expected core materials needed to 
meet amended standards.
    Additionally, in response to the January 2023 NOPR, Howard 
commented that the standards proposed in the January 2023 NOPR would 
require them to redesign 8,000--10,000 distribution transformers, which 
ordinarily would be done over a 5-year period. (Howard, No. 116 at p. 
3) Howard also commented that they estimate that facility and equipment 
additions alone will take 5 years and Howard will need to begin 
production of new units prior to the actual compliance deadline to 
ensure all raw materials are used. (Id.) In the January 2023 NOPR, DOE 
used a 3-year compliance period. For this final rule, DOE is adopting a 
5-year compliance period. While DOE acknowledges that manufacturers 
will be required to make significant changes to their manufacturing 
facilities to be able to produce distribution transformers that use 
amorphous cores, this is not anticipated to cause manufacturing 
capacity constraints given the 5-year compliance period. Further, DOE 
notes that the adopted standards in this final rule require 
substantially less manufacturer investment than those proposed in the 
January 2023 NOPR.
d. Impacts on Subgroups of Manufacturers
    As discussed in section IV.J.1 of this document, using average cost 
assumptions to develop an industry cash flow estimate may not be 
adequate for assessing differential impacts among manufacturer 
subgroups. Small manufacturers, niche manufacturers, and manufacturers 
exhibiting a cost structure substantially different from the industry 
average could be affected disproportionately. DOE used the results of 
the industry characterization to group manufacturers exhibiting similar 
characteristics. Consequently, DOE considered four manufacturer 
subgroups in the MIA: liquid-immersed, LVDT, MVDT, and small 
manufacturers as a subgroup for a separate impact analysis. DOE 
discussed the potential impacts on liquid-immersed, LVDT, and MVDT 
distribution transformer manufacturers separately in sections V.B.2.a 
and V.B.2.b of this document.
    For the small business subgroup analysis, DOE applied the small 
business size standards published by the Small Business Administration 
(SBA) to determine whether a company is considered a small business. 
The size standards are codified at 13 CFR part 121. To be categorized 
as a small business under NAICS code 335311, ``power, distribution, and 
specialty transformer manufacturing,'' a distribution transformer 
manufacturer and its affiliates may employ a maximum of 800 employees. 
The 800-employee threshold includes all employees in a business's 
parent company and any other subsidiaries. For a discussion of the 
impacts on the small manufacturer subgroup, see the Regulatory 
Flexibility Analysis in section VI.B of this document.
e. Cumulative Regulatory Burden
    One aspect of assessing manufacturer burden involves looking at the 
cumulative impact of multiple DOE standards and the regulatory actions 
of other Federal agencies and States that affect the manufacturers of a 
covered product or equipment. While any one regulation may not impose a 
significant burden on manufacturers, the combined effects of several 
existing or impending regulations may have serious consequences for 
some manufacturers, groups of manufacturers, or an entire industry. 
Multiple regulations affecting the same manufacturer can strain profits 
and lead companies to abandon product lines or markets with lower 
expected future returns than competing products. For these reasons, DOE 
conducts an analysis of cumulative regulatory burden as part of its 
rulemakings pertaining to appliance efficiency.
    DOE evaluates product-specific regulations that will take effect 
approximately 3 years before or after the estimated 2029 compliance 
date of any amended energy conservation standards for distribution 
transformers. This information is presented in Table V.40.

[[Page 29991]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.599

3. National Impact Analysis
    This section presents DOE's estimates of the national energy 
savings and the NPV of consumer benefits that would result from each of 
the TSLs considered as potential amended standards.
a. National Energy Savings
    To estimate the energy savings attributable to potential amended 
standards for distribution transformers, DOE compared their energy 
consumption under the no-new-standards case to their anticipated energy 
consumption under each TSL. The savings are measured over the entire 
lifetime of products purchased in the 30-year period that begins in the 
year of anticipated compliance with amended standards 2029-2058. Table 
V.41 presents DOE's projections of the national energy savings for each 
TSL considered for distribution transformers, the results showing DOE's 
amended standards are in bold. The savings were calculated using the 
approach described in section IV.H of this document.

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[[Page 29993]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.601

    OMB Circular A-4 \195\ requires agencies to present analytical 
results, including separate schedules of the monetized benefits and 
costs that show the type and timing of benefits and costs. Circular A-4 
also directs agencies to consider the variability of key elements 
underlying the estimates of benefits and costs. For this rulemaking, 
DOE undertook a sensitivity analysis using 9 years, rather than 30 
years, of product shipments. The choice of a 9-year period is a proxy 
for the timeline in EPCA for the review of certain energy conservation 
standards and potential revision of and compliance with such revised 
standards.\196\ The review timeframe established in EPCA is generally 
not synchronized with the product lifetime, product manufacturing 
cycles, or other factors specific to distribution transformers. Thus, 
such results are presented for informational purposes only and are not 
indicative of any change in DOE's analytical methodology. The NES 
sensitivity analysis results based on a 9-year analytical period are 
presented in Table V.42. The impacts are counted over the lifetime of 
distribution transformers purchased during the period 2029-2058, the 
results showing DOE's amended standards are in bold.
---------------------------------------------------------------------------

    \195\ U.S. Office of Management and Budget. Circular A-4: 
Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 19, 2024). 
DOE used the prior version of Circular A-4 (September 17, 2003) in 
accordance with the effective date of the November 9, 2023 version.
    \196\ EPCA requires DOE to review its standards at least once 
every 6 years, and requires, for certain products, a 3-year period 
after any new standard is promulgated before compliance is required, 
except that in no case may any new standards be required within 6 
years of the compliance date of the previous standards. (42 U.S.C. 
6316(a); 42 U.S.C. 6295(m)) While adding a 6-year review to the 3-
year compliance period adds up to 9 years, DOE notes that it may 
undertake reviews at any time within the 6-year period and that the 
3-year compliance date may yield to the 6-year backstop. A 9-year 
analysis period may not be appropriate given the variability that 
occurs in the timing of standards reviews and the fact that for some 
products, the compliance period is 5 years rather than 3 years.

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[[Page 29995]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.603

b. Net Present Value of Consumer Costs and Benefits
    DOE estimated the cumulative NPV of the total costs and savings for 
consumers that would result from the TSLs considered for distribution 
transformers. In accordance with OMB's guidelines on regulatory 
analysis,\197\ DOE calculated NPV using both a 7-percent and a 3-
percent real discount rate. Table V.43 shows the consumer NPV results 
with impacts counted over the lifetime of products purchased during the 
period 2029-2058.
---------------------------------------------------------------------------

    \197\ U.S. Office of Management and Budget. Circular A-4: 
Regulatory Analysis. September 17, 2003. https://www.whitehouse.gov/wp-content/uploads/legacy_drupal_files/omb/circulars/A4/a-4.pdf#page=33.
[GRAPHIC] [TIFF OMITTED] TR22AP24.604


[[Page 29996]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.605

    The NPV results based on the aforementioned 9-year analytical 
period are presented in Table V.44. The impacts are counted over the 
lifetime of products purchased during the period 2029-2037. As 
mentioned previously, such results are presented for informational 
purposes only and are not indicative of any change in DOE's analytical 
methodology or decision criteria.

[[Page 29997]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.606

    The previous results reflect the use of a default trend to estimate 
the change in price for distribution transformers over the analysis 
period (see section IV.H.3 of this document). DOE also conducted a 
sensitivity analysis that considered

[[Page 29998]]

one scenario with a lower rate of price decline than the reference case 
and one scenario with a higher rate of price decline than the reference 
case. The results of these alternative cases are presented in appendix 
10C of the final rule TSD. In the high-price-decline case, the NPV of 
consumer benefits is higher than in the default case. In the low-price-
decline case, the NPV of consumer benefits is lower than in the default 
case.
c. Indirect Impacts on Employment
    DOE estimates that amended energy conservation standards for 
distribution transformers will reduce energy expenditures for consumers 
of those products, with the resulting net savings being redirected to 
other forms of economic activity. These expected shifts in spending and 
economic activity could affect the demand for labor. As described in 
section IV.N of this document, DOE used an input/output model of the 
U.S. economy to estimate indirect employment impacts of the TSLs that 
DOE considered. There are uncertainties involved in projecting 
employment impacts, especially changes in the later years of the 
analysis. Therefore, DOE generated results for near-term timeframes 
(2029-2034), where these uncertainties are reduced.
    The results suggest that the adopted standards are likely to have a 
negligible impact on the net demand for labor in the economy. The net 
change in jobs is so small that it would be imperceptible in national 
labor statistics and might be offset by other, unanticipated effects on 
employment. Chapter 16 of the final rule TSD presents detailed results 
regarding anticipated indirect employment impacts.
4. Impact on Utility or Performance of Products
    As discussed in section IV.C.1.b of this document, DOE has 
concluded that the standards adopted in this final rule will not lessen 
the utility or performance of the distribution transformers under 
consideration in this rulemaking. Manufacturers of these products 
currently offer units that meet or exceed the adopted standards.
5. Impact of Any Lessening of Competition
    DOE considered any lessening of competition that would be likely to 
result from new or amended standards. As discussed in section III.F.1.e 
of this document, EPCA directs the Attorney General of the United 
States (``Attorney General'') to determine the impact, if any, of any 
lessening of competition likely to result from a proposed standard and 
to transmit such determination in writing 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. To assist the Attorney General 
in making this determination, DOE provided the Department of Justice 
(DOJ) with copies of the NOPR and the TSD for review. 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. DOE is publishing the 
Attorney General's assessment at the end of this final rule.
6. Need of the Nation to Conserve Energy
    Enhanced energy efficiency, where economically justified, improves 
the Nation's energy security, strengthens the economy, and reduces the 
environmental impacts (costs) of energy production. Reduced electricity 
demand due to energy conservation standards is also likely to reduce 
the cost of maintaining the reliability of the electricity system, 
particularly during peak-load periods. Chapter 15 in the final rule TSD 
presents the estimated impacts on electricity generating capacity, 
relative to the no-new-standards case, for the TSLs that DOE considered 
in this rulemaking.
    Energy conservation resulting from potential energy conservation 
standards for distribution transformers is expected to yield 
environmental benefits in the form of reduced emissions of certain air 
pollutants and greenhouse gases. Table V.45 through Table V.48 provides 
DOE's estimate of cumulative emissions reductions expected to result 
from the TSLs considered in this rulemaking. The emissions were 
calculated using the multipliers discussed in section IV.K of this 
document. DOE reports annual emissions reductions for each TSL in 
chapter 13 of the final rule TSD.

[[Page 29999]]

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[GRAPHIC] [TIFF OMITTED] TR22AP24.608


[[Page 30000]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.609

[GRAPHIC] [TIFF OMITTED] TR22AP24.610

    As part of the analysis for this rule, DOE estimated monetary 
benefits likely to result from the reduced emissions of CO2 
that DOE estimated for each of the considered TSLs for distribution 
transformers. Section IV.L.1.a of this

[[Page 30001]]

document discusses the estimated SC-CO2 values that DOE 
used. Table V.49 presents the value of CO2 emissions 
reduction at each TSL for each of the SC-CO2 cases. The 
time-series of annual values is presented for the selected TSL in 
chapter 14 of the final rule TSD.
[GRAPHIC] [TIFF OMITTED] TR22AP24.611

    As discussed in section IV.L.2 of this document, DOE estimated the 
climate benefits likely to result from the reduced emissions of methane 
and N2O that DOE estimated for each of the considered TSLs 
for distribution transformers. Table V.50 presents the value of the 
CH4 emissions reduction at each TSL, and Table V.51 presents 
the value of the N2O emissions reduction at each TSL. The 
time-series of annual values is presented for the selected TSL in 
chapter 14 of the final rule TSD.

[[Page 30002]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.612

[GRAPHIC] [TIFF OMITTED] TR22AP24.613

    DOE is well aware that scientific and economic knowledge about the 
contribution of CO2 and other GHG emissions to changes in 
the future global climate and the potential resulting damages to the 
global and U.S. economy continues to evolve rapidly. DOE, together with 
other Federal agencies, will continue to review methodologies for 
estimating the monetary value of reductions in CO2 and other 
GHG emissions. This ongoing review will consider the comments on this 
subject that are part of the public record for this and other 
rulemakings, as well as other methodological assumptions and issues. 
DOE notes, however, that the adopted standards would be economically 
justified even without inclusion of monetized benefits of reduced GHG 
emissions.
    DOE also estimated the monetary value of the economic benefits 
associated with NOX and SO2 emissions reductions 
anticipated to result from the considered TSLs for distribution 
transformers. The dollar-per-ton values that DOE used are discussed in 
section IV.L of this document. Table V.52 presents the present value 
for NOX emissions reduction for each TSL calculated using 7-
percent and 3-percent discount rates, and Table V.53 presents similar 
results for SO2 emissions reductions. The results in these 
tables reflect application of EPA's low dollar-per-ton values, which 
DOE used to be conservative. The time-series of annual values is 
presented for the selected TSL in chapter 14 of the final rule TSD.

[[Page 30003]]

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[GRAPHIC] [TIFF OMITTED] TR22AP24.615


[[Page 30004]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.616

[GRAPHIC] [TIFF OMITTED] TR22AP24.617


[[Page 30005]]


    Not all the public health and environmental benefits from the 
reduction of greenhouse gases, NOX, and SO2 are 
captured in the values above, and additional unquantified benefits from 
the reductions of those pollutants as well as from the reduction of 
direct PM and other co-pollutants may be significant. DOE has not 
included monetary benefits of the reduction of Hg emissions because the 
amount of reduction is very small.
7. Other Factors
    The Secretary of Energy, in determining whether a standard is 
economically justified, may consider any other factors that the 
Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) In 
this final rule, DOE considered the near-term impact of amended 
standards on existing distribution transformer shortages, on the 
domestic electrical steel supply, and on projected changes to the 
transformer market to support electrification.
8. Summary of Economic Impacts
    Table V.54 presents the NPV values that result from adding the 
estimates of the economic benefits resulting from reduced GHG and 
NOX and SO2 emissions to the NPV of consumer 
benefits calculated for each TSL considered in this rulemaking. The 
consumer benefits are domestic U.S. monetary savings that occur as a 
result of purchasing the covered equipment and are measured for the 
lifetime of products shipped during the period 2029-2058. The climate 
benefits associated with reduced GHG emissions resulting from the 
adopted standards are global benefits and are also calculated based on 
the lifetime of distribution transformers shipped during the period 
2029-2058.
[GRAPHIC] [TIFF OMITTED] TR22AP24.618


[[Page 30006]]



C. Conclusion

    When considering new or amended energy conservation standards, the 
standards that DOE adopts for any type (or class) of covered equipment 
must be designed to achieve the maximum improvement in energy 
efficiency that the Secretary determines is technologically feasible 
and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 
6295(o)(2)(A)) In determining whether a standard is economically 
justified, the Secretary must determine whether the benefits of the 
standard exceed its burdens by, to the greatest extent practicable, 
considering the seven statutory factors discussed previously. (42 
U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)) The new or amended standard 
must also result in significant conservation of energy. (42 U.S.C. 
6316(a); 42 U.S.C. 6295(o)(3)(B))
    For this final rule, DOE considered the impacts of amended 
standards for distribution transformers at each TSL, beginning with the 
maximum technologically feasible level, to determine whether that level 
was economically justified. Where the max-tech level was not justified, 
DOE then considered the next most efficient level and undertook the 
same evaluation until it reached the highest efficiency level that is 
both technologically feasible and economically justified and saves a 
significant amount of energy.
    To aid the reader as DOE discusses the benefits and/or burdens of 
each TSL, tables in this section present a summary of the results of 
DOE's quantitative analysis for each TSL. In addition to the 
quantitative results presented in the tables, DOE also considers other 
burdens and benefits that affect economic justification. These include 
the impacts on identifiable subgroups of consumers who may be 
disproportionately affected by a national standard and impacts on 
employment.
    DOE also notes that the economics literature provides a wide-
ranging discussion of how consumers trade off upfront costs and energy 
savings in the absence of government intervention. Much of this 
literature attempts to explain why consumers appear to undervalue 
energy efficiency improvements. There is evidence that consumers 
undervalue future energy savings as a result of: (1) a lack of 
information; (2) a lack of sufficient salience of the long-term or 
aggregate benefits; (3) a lack of sufficient savings to warrant 
delaying or altering purchases; (4) excessive focus on the short term, 
in the form of inconsistent weighting of future energy cost savings 
relative to available returns on other investments; (5) computational 
or other difficulties associated with the evaluation of relevant 
tradeoffs; and (6) a divergence in incentives (for example, between 
renters and owners, or builders and purchasers). Having less than 
perfect foresight and a high degree of uncertainty about the future, 
consumers may trade off these varieties of investments at a higher-
than-expected rate between current consumption and uncertain future 
energy cost savings.
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed 
Distribution Transformer Standards
    Table V.55 and Table V.56 summarize the quantitative impacts 
estimated for each TSL for liquid-immersed distribution transformers. 
The national impacts are measured over the lifetime of distribution 
transformers purchased in the 30-year period that begins in the 
anticipated year of compliance with amended standards (2029-2058). The 
energy savings, emissions reductions, and value of emissions reductions 
refer to full-fuel-cycle results. DOE is presenting monetized benefits 
of GHG emissions reductions in accordance with the applicable Executive 
Orders, and DOE would reach the same conclusion presented in this 
notice in the absence of the social cost of greenhouse gases, including 
the Interim Estimates presented by the Interagency Working Group. The 
efficiency levels contained in each TSL are described in section V.A of 
this document.

[[Page 30007]]

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[[Page 30008]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.620

    DOE first considered TSL 5, which represents the max-tech 
efficiency levels across all product classes of liquid-immersed 
distribution transformers essentially requiring the shift to the most-
efficient electrical steel for core fabrication and larger and heavier 
distribution transformers as more material is needed to support the 
efficiency gains. TSL 5 would save an estimated 10.91 quads of energy, 
an amount DOE considers significant. Under TSL 5, the NPV of consumer 
benefit would be -$7.39 billion using a discount rate of 7 percent, and 
-$3.57 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 5 are 204.96 Mt of 
CO2, 49.0 thousand tons of SO2, 358.5 thousand 
tons of NOX, 0.3 tons of Hg, 1,660.6 thousand tons of 
CH4, and 1.6 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 5 is $7.37 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 5 is $4.42 billion using a 7-percent discount rate and $14.81 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 5 is $4.40 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 5 is $18.61 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
standard level is economically justified.
    At TSL 5, the average LCC impact ranges from -$2,977 for equipment 
class 2B to $770 for equipment class 12. The median PBP ranges from 
14.8 years for equipment class 12 to 42.1 years for equipment class 1A. 
The fraction of consumers experiencing a net LCC cost ranges from 28.7 
percent for equipment class 2A to 89.0 percent for equipment class 1A.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$686 million to a decrease of $338 million, which corresponds to 
decreases of 38.3 percent and 18.8 percent, respectively. This decrease 
is primarily driven by the investments needed to move the entire 
liquid-immersed distribution transformer market to the most-efficient 
designs, including converting their production facilities to produce 
and accommodate amorphous core technology. DOE estimates that industry 
must invest $697 million to comply with standards set at TSL 5.
    The Secretary concludes that at TSL 5 for liquid-immersed 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the economic burden on many consumers 
as indicated by lengthy PBPs, the percentage of customers who would 
experience LCC increases, negative consumer NPV at both 3- and 7-
percent discount rates,

[[Page 30009]]

and the capital and engineering costs that would result in a reduction 
in INPV for manufacturers. At TSL 5, the LCC savings are negative for 
most liquid-immersed distribution transformers, indicating there is a 
substantial risk that a disproportionate number of consumers will incur 
increased costs; these costs are also reflected in simple PBP estimates 
that approach average transformer lifetimes for some equipment. NPVs 
are calculated for equipment shipped over the period of 2029 through 
2058 (see section IV.H.3 of this document). Distribution transformers 
are durable equipment with a maximum lifetime estimated at 60 years 
(see section IV.F.8), accruing operating cost savings through 2117. 
When considered over this time period, the discounted value of the 
incremental equipment costs outweighs the discounted value of the 
operating costs savings. Incremental equipment costs are incurred in 
the first year of equipment life, while operating cost savings occur 
throughout the equipment lifetime, with later years heavily discounted. 
Further, there is risk of greater reduction in INPV at max-tech if 
manufacturers maintain their operating profit in the presence of 
amended efficiency standards on account of having higher costs but 
similar profits. The benefits of max-tech efficiency levels for liquid-
immersed distribution transformers do not outweigh the negative impacts 
to consumers and manufacturers. Consequently, the Secretary has 
concluded that TSL 5 is not economically justified.
    Next, DOE considered TSL 4, a level at which DOE estimates a likely 
shift in the electrical steel used for distribution transformer cores 
for liquid-immersed distribution transformers. TSL 4 would save an 
estimated 10.67 quads of energy, an amount DOE considers significant. 
Under TSL 4, the NPV of consumer benefit would be $2.82 billion using a 
discount rate of 7 percent, and $13.01 billion using a discount rate of 
3 percent.
    The cumulative emissions reductions at TSL 4 are 201.15 Mt of 
CO2, 48.0 thousand tons of SO2, 350.8 thousand 
tons of NOX, 0.3 tons of Hg, 1,624.0 thousand tons of 
CH4, and 1.5 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 4 is $7.23 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 4 is $4.33 billion using a 7-percent discount rate and $14.50 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 4 is $14.38 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 4 is $34.74 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
standard level is economically justified.
    At TSL 4, the average LCC impact ranges from $317 for equipment 
class 1B to $5,301 for equipment class 2B. The median PBP ranges from 
7.4 years for equipment class 1B to 10.7 years for equipment class 1A. 
The fraction of consumers experiencing a net LCC cost ranges from 
7.1percent for equipment classes 1B and 2A to 27.5 percent for 
equipment class 1A.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$476 million to a decrease of $388 million, which corresponds to 
decreases of 26.6 percent and 21.6 percent, respectively. These 
estimates are driven by DOE's estimate that liquid-immersed 
distribution transformer manufacturers will need to invest $587 million 
to comply with standards set at TSL 4 to produce or accommodate 
amorphous core technology.
    The energy savings under TSL 4 are primarily achievable by using 
amorphous cores and DOE believes manufacturers will likely choose this 
technology pathway in order to meet TSL 4 efficiency levels due to the 
relative cost of meeting these levels with amorphous and GOES cores. In 
the present market, distribution transformers are primarily designed 
using GOES cores and the production equipment used for GOES core 
distribution transformer manufacturing is not the same. While DOE 
understands that amorphous core distribution transformers are 
technically feasible for liquid-immersed, DOE also understands that 
current domestic supply would need to ramp up significantly for 
amorphous steel to support this market.
    The transition to amorphous cores is constrained in two important 
ways. First, amorphous cores require amorphous steel. Supply of 
amorphous steel for transformer cores is not inherently constrained. 
Supply, including domestic supply, could increase in the face of 
increased demand.
    For example, both global and domestic annual production capacity of 
amorphous ribbon is greater now than it was leading up to the April 
2013 Standards Final Rule, with global annual production capacity of 
amorphous ribbon (estimated to be approximately 150,000-250,000 metric 
tons) approximately equal to the U.S. annual demand for core steel in 
distribution transformer applications (estimated to be approximately 
225,000 metric tons). While additional amorphous ribbon capacity would 
be required to serve the entirety of the U.S. distribution transformer 
market, in addition to existing global applications, it is likely that 
supply would increase quickly in response to increased demand from 
standards. Following the April 2013 Standards Final Rule, amorphous 
ribbon capacity grew, although amorphous ribbon demand did not grow in-
kind. As such, excess amorphous ribbon capacity already exists that 
could be utilized to serve a larger portion of the distribution 
transformer market, if demand were to increase. Further, the response 
of amorphous ribbon manufacturers following the April 2013 Standards 
Final Rule, as well as public announcements of development in amorphous 
core production capacity since the January 2023 NOPR, demonstrate that 
amorphous ribbon and core capacity can be added quickly if suppliers 
anticipate demand. As such, the supply of amorphous metal would likely 
increase in response to amended standards that favored amorphous ribbon 
as the optimal design option. Stakeholders have expressed a willingness 
to increase supply to match any potential demand created by an amended 
efficiency standard. As noted, in the current market, sales of 
amorphous ribbon are limited by demand for amorphous cores rather than 
any constraints on production capacity. Therefore, in the presence of 
an amended standard, it is expected that amorphous ribbon capacity 
would quickly rise to meet demand before the effective date of any 
amended energy conservation standards.
    However, and secondly, demand for amorphous steel is constrained by 
distribution transformer manufacturers' willingness and ability to 
invest in in the capital equipment required to produce and process 
amorphous metal cores. The production pathway for both amorphous core 
and GOES core transformers is similar once this investment in the 
equipment has been made. However, the transition from production of 
GOES cores to production of amorphous cores would require significant 
investment by distribution

[[Page 30010]]

transformer manufacturers that produce their own cores. At TSL 4, most 
existing core production equipment, which is predominantly set up to 
produce GOES cores, would need to be replaced with amorphous core 
production equipment. Given existing supply challenges and long lead 
times for distribution transformers, it is unclear if most 
manufacturers would have the capacity to complete the necessary 
investments in amorphous core production equipment within the 5-year 
compliance period and maintain their existing GOES production lines to 
supply the current market demand without increasing near-term 
distribution transformer lead times. If manufacturers anticipate 
requiring more than 5 years to fully convert production or add 
production of amorphous cores, they may prioritize maintaining lead 
times by continuing to produce transformers with GOES cores. If GOES 
cores are used to meet TSL 4, the resulting designs are substantially 
larger and more expensive than amorphous core designs, with some size 
capacities in DOE's modelling unable to meet TSL 4 at all with GOES. 
Conversely, if manufacturers prioritize a transition to amorphous cores 
over maintaining lead times, they may prioritize investing in replacing 
existing production equipment, rather than in new additive capacity. 
This could inhibit manufacturers' abilities to invest in necessary 
capacity upgrades to help resolve the existing transformer shortages.
    In addition to the production equipment and investments needed to 
support a TSL 4 transition by distribution transformers, DOE 
understands that the current workforce supporting the distribution 
transformer manufacturer is also limited in their experience with 
amorphous core production. DOE understands from the many stakeholder 
comments that current workforce challenges within the distribution 
transformer industry may be exacerbated in the short-term if a full 
transition to TSL 4 is required. While DOE understands most 
manufacturers currently can produce liquid-immersed transformers at TSL 
4 efficiencies, DOE also understand that due to the lower volume of 
amorphous cores in the market today many production facilities 
outsource amorphous core production but produce GOES cores in-house. 
DOE believes that if TSL 4 efficiencies were required for liquid-
immersed distribution transformers the sourcing decisions on core 
fabrication would not largely change from what they are today as these 
are inherent business decisions that balance quality, control, and 
lead-times. Therefore, despite offering liquid-immersed transformers at 
TSL 4 efficiencies, manufacturers do not yet have a lot of experience 
fabricating amorphous cores and will take significant training and time 
in order to support a transition of this magnitude. Some manufacturers 
raised questions in comments about their ability to invest in both the 
capital as well as the workforce in the time provided to transition to 
TSL 4, while maintaining their supply needs for GOES transformers in 
the near-term.
    DOE notes that while the January 2023 NOPR proposed standards at 
TSL 4, distribution transformer shortages persisted throughout 2023. 
DOE further notes that hundreds of millions of dollars in investments 
have been announced by distribution transformer manufacturers to add 
capacity to resolve the existing transformer shortages and those 
investments are currently undergoing the design, permitting, 
engineering, and construction process needed to begin production with 
scheduled completions typically targeting 24 to 36 months. DOE updated 
its analysis of conversion costs in this final rule based on 
stakeholder feedback and are the costs are now greater than the costs 
analyzed in the January 2023 NOPR. Investing in conversion costs and 
workforce training, in addition to manufacturers investments to 
increase capacity, without offering flexibility for manufacturers to 
add amorphous capacity in an additive manner has led DOE to conclude 
that TSL 4 offers substantial risk that could extend current 
transformer shortages longer they otherwise would be.
    The Secretary concludes that at TSL 4 for liquid-immersed 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the significant impact to 
manufacturers (a loss in INPV of up to 26.6 percent, conversion costs 
of approximately $587 million, and a free cash flow of -$125 million in 
the year leading up to the compliance year) and the risks that 
manufacturers would not be able to scale up amorphous core production 
capacity within the compliance period without significantly increasing 
distribution transformer lead times or maintaining very large and 
costly GOES core transformers after the compliance period. In addition, 
DOE has concerns about distribution transformer manufacturer's ability 
to maintain their existing GOES lines in the near-term, while training 
their workforce to become comfortable with producing transformers cores 
with amorphous ribbon. Further, as discussed in section IV.C.2.a, an 
inability of suppliers of amorphous ribbon to scale production and 
manufacturers to retool production lines for amorphous cores within the 
compliance period could lead to market uncertainty and disruption 
during a critical time. Several stakeholders have noted that given 
existing supply challenges, a total conversion to amorphous is not 
feasible in the near term. While this final rule considers a longer 
compliance period, the impacts of shortages are substantial, which may 
have an impact on grid reliability. Therefore, the risks of scale-up 
and compliance taking slightly longer, due to any number of unforeseen 
challenges, could have substantial impacts. The benefits of TSL 4 for 
liquid-immersed distribution transformer do not outweigh the risks when 
considering the potential impacts to the broader distribution 
transformer supply chain. Consequently, the Secretary has concluded 
that TSL 4 is not economically justified.
    Next, DOE considered TSL 3. TSL 3 would save an estimated 2.73 
quads of energy, an amount DOE considers significant. Under TSL 3, the 
NPV of consumer benefit would be $0.56 billion using a discount rate of 
7 percent, and $3.41 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 3 are 51.40 Mt of 
CO2, 12.3 thousand tons of SO2, 89.9 thousand 
tons of NOX, 0.1 tons of Hg, 416.2 thousand tons of 
CH4, and 0.4 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 3 is $1.85 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 3 is $1.11 billion using a 7-percent discount rate and $3.71 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 3 is $3.52 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 3 is $9.97 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
standard level is economically justified.

[[Page 30011]]

    At TSL 3, the average LCC impact ranges from $48 for equipment 
class 1B to $851 for equipment class 2A. The median PBP ranges from 9.2 
years for equipment class 2A to 19.5 years for equipment class 1B. The 
fraction of consumers experiencing a net LCC cost ranges from 7.1 
percent for equipment class 2A to 39.6 percent for equipment class 2B.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$145 million to a decrease of $111 million, which corresponds to 
decreases of 8.1 percent and 6.2 percent, respectively. DOE estimates 
that industry must invest $187 million to comply with standards set at 
TSL 3.
    After considering the analysis and weighing the benefits and 
burdens, the Secretary has concluded that a standard set at TSL 3 for 
liquid-immersed distribution transformers would be economically 
justified. Notably, the benefits to consumers outweigh the cost to 
manufacturers. At TSL 3, the average LCC savings are positive across 
all equipment classes. An estimated 29 percent of liquid-immersed 
distribution transformer consumers experience a net cost. DOE notes 
that if the shipments equipment classes 1B and 2B transition to 
amorphous cores from DOE's assumed rate of 3 percent to 10, or 25 
percent, the maximum number of consumers experiencing a net cost 
decreases to 25 and 21 percent, respectively.\198\ The FFC national 
energy savings are significant and the NPV of consumer benefits is 
positive using both a 3-percent and 7-percent discount rate when 
considered for all liquid-immersed distribution transformers subject to 
amended standards. When examined as individual equipment classes the 
NPV at 7 percent is positive for most equipment classes; with the 
exception of equipment class 2B, where the NPV at a 7 percent discount 
rate is negative: -$0.05 billion (see Table V.43). When equipment class 
2B is considered with the addition of its associated health benefits of 
$0.22 billion at TSL 3 (see Table V.51 and Table V.52) the impacts 
become positive, with a net benefit of $0.17 billion. At TSL 3, the NPV 
of consumer benefits, even measured at the more conservative discount 
rate of 7 percent is larger than the maximum estimated manufacturers' 
loss in INPV. The standard levels at TSL 3 are economically justified 
even without weighing the estimated monetary value of emissions 
reductions. When those emissions reductions are included--representing 
$1.85 billion in climate benefits (associated with the average SC-GHG 
at a 3-percent discount rate), and $3.71 billion (using a 3-percent 
discount rate) or $1.11 billion (using a 7-percent discount rate) in 
health benefits--the rationale becomes stronger still.
---------------------------------------------------------------------------

    \198\ See: Appendix 8D of the final rule TSD for DOE's scenario 
examining the impacts resulting from increased amorphous adoption.
---------------------------------------------------------------------------

    Notably, the standards under TSL 3 would not pose the same near-
term risks to distribution transformer availability. As compared to TSL 
4, for which the energy savings are primarily achievable via amorphous 
cores, the energy savings under TSL 3 are achieved by using a mix of 
amorphous cores and GOES cores. Under TSL 3, DOE estimates that 
equipment class 1A and 2A will meet efficiency standards by 
transitioning to amorphous cores. If the unit sizes represented by 
these equipment classes shift entirely to amorphous, DOE estimates that 
approximately 48,000 metric tons of amorphous ribbon would be consumed, 
which is approximately equal to the current domestic amorphous ribbon 
production capacity (45,000 metric tons of domestic amorphous today). 
Under TSL 3, DOE estimates that the vast majority of liquid-immersed 
distribution transformers shipments (89 percent of units) could be met 
with GOES cores.
    As noted, the transition from GOES cores to amorphous cores 
requires significant investment on the part of distribution transformer 
manufacturers that produce their own cores. However, core production 
equipment is somewhat flexible in that a given piece of equipment can 
produce a range of core sizes corresponding to a range of transformer 
kVA sizes. Given existing supply challenges facing the distribution 
transformer market, DOE assumes that manufacturers would prioritize 
maintaining lead times by continuing to produce transformers with GOES 
cores for transformer sizes where costs are approximately equal, even 
if a transformer with an amorphous core may be slightly less expensive 
to produce. Under TSL 3, DOE evaluated a higher efficiency level for 
Equipment Class 1A and 2A and a lower efficiency level for Equipment 
Class 1B and 2B. As such, manufacturers would have significant 
flexibility to invest in new capacity to meet efficiency standards 
while allowing for the continued use of current production equipment to 
ensure a robust short- to medium-term supply of distribution 
transformers.
    TSL 3 results in positive LCCs for all equipment classes, whether 
expected to remain predominantly GOES-based (Equipment Class 1B and 2B) 
or predominantly amorphous-based (Equipment Class 1A and 2A).
    Because only a portion of the market is expected to transition to 
amorphous at TSL 3 and because existing GOES production equipment can 
produce a variety of kVA sizes, manufacturers may invest in amorphous 
production equipment as additive capacity to serve those portions of 
the market where amorphous is most competitive. As such, manufacturers 
would have the flexibility of using existing GOES production equipment 
to serve the rest of the market, while adding additional amorphous 
production equipment that may help resolve the existing transformer 
shortages. Public statements from major liquid-immersed distribution 
transformer core manufacturers suggest that some have already begun 
investing in additive amorphous capacity in response to the January 
2023 NOPR.199 200 201
---------------------------------------------------------------------------

    \199\ Yahoo Finance, Howard Industries cuts ribbon on Quitman 
plant, November 3, 2023, Available online at: https://finance.yahoo.com/news/howard-industries-cuts-ribbon-quitman-035900515.html.
    \200\ JFE Shoji Power, ``What Got Us Here Won't Get Us to Where 
We Want to Go'', You Will Be an Embarrassment to the Company, Nov. 
2023. https://www.amazon.in/What-Here-Wont-Where-Want/dp/B0CMD84HRW.
    \201\ Worthington Steel, Investor Day, Oct. 2023, Transcript. 
Available online at: worthington-steel-investor-day-transcript-
final-10-11-23.pdf (worthingtonenterprises.com.)
---------------------------------------------------------------------------

    Amorphous cores are expected to be the most cost-effective option 
for meeting efficiency levels for equipment class 1A and 2A. This 
suggests a future demand for amorphous ribbon and encourages both 
existing amorphous producers to increase supply and potential new 
producers to enter the market.
    DOE expects manufacturers would prioritize amorphous core capital 
investments at the kVA ranges (i.e., equipment class 1A and 2A), where 
amorphous cores are expected to be most cost competitive. However, if 
excess amorphous ribbon and amorphous core capacity exists, amorphous 
is also a cost-effective option for many of the other kVA ratings. 
While DOE has modeled equipment class 1B and 2B as meeting amended 
standards using exclusively GOES in its base analysis at TSL 3, DOE has 
included additional sensitivities in which amorphous core usage 
increases to a maximum of 25 percent at equipment class 1B and 2B. 
These scenarios further increase consumer benefits (see appendix 8G of 
the TSD).
    DOE expects manufacturers would maintain some amount of GOES core 
production equipment and some amount of amorphous core production

[[Page 30012]]

equipment, thereby ensuring the U.S. distribution transformer market 
continues to be served by at least two domestic electrical steel 
providers, one producing GOES and one producing amorphous. This may 
support balanced supply chain for distribution transformers through a 
more diversified core steel supply, which is presently served 
predominantly by GOES production for which there is only one domestic 
supplier.
    As stated, DOE conducts the walk-down analysis to determine the TSL 
that represents the maximum improvement in energy efficiency that is 
technologically feasible and economically justified as required under 
EPCA. The walk-down is not a comparative analysis, as a comparative 
analysis would result in the maximization of net benefits instead of 
energy savings that are technologically feasible and economically 
justified, which would be contrary to the statute. 86 FR 70892, 70908.
    Although DOE has not conducted a comparative analysis to select the 
new energy conservation standards, DOE notes that TSL 3 ensures 
capacity for amorphous ribbon increases, on account of anticipated 
future demand, while leaving a considerable portion of the market at 
efficiency levels wherein GOES would remain cost competitive. As a 
result, this ensures that near-term shortages can be resolved and that 
overall U.S. electrification trends and support for domestic electrical 
steel industries are not compromised. As noted by numerous 
stakeholders, distribution transformers are crucial to supporting U.S. 
infrastructure, grid resiliency, and electrification goals. TSL 3 
allows for efficiency standards to be met by additive capacity, which 
can help renormalize distribution transformer lead times. TSL 4 and TSL 
5 did not include the same possibility for stakeholders to invest in an 
additive capacity to meet efficiency standards, thereby creating risks 
to the short- and medium-term supply of distribution transformers.
    Although DOE considered amended standard levels for distribution 
transformers by grouping the efficiency levels for each equipment 
category into TSLs, DOE evaluates all analyzed efficiency levels in its 
analysis. The TSLs constructed by DOE to examine the impacts of amended 
energy efficiency standards for liquid-immersed distribution 
transformers align with the corresponding ELs defined in the 
engineering analysis, which the exception of TSL 3 which seeks to 
consider electrical steel capacity and demand growth limitations. For 
the ELs above baseline that compose TSL 3, DOE finds that LCC savings 
are positive for all equipment classes, with simple paybacks well below 
the average equipment lifetimes. DOE also finds that the estimated 
fraction of consumers who would be negatively impacted from a standard 
at TSL 3 to be 29.2 percent for all equipment classes. Importantly, DOE 
expects TSL 3 to be achievable with additive distribution transformer 
capacity in addition to capital conversion costs, thereby reducing both 
transformer and larger grid supply concerns.
    Therefore, based on the previous considerations, DOE adopts the 
energy conservation standards for liquid-immersed distribution 
transformers at TSL 3. The amended energy conservation standards for 
distribution transformers, which are expressed as percentage efficiency 
at 50 percent PUL, are shown in Table V.57.
[GRAPHIC] [TIFF OMITTED] TR22AP24.621

2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-Type 
Distribution Transformer Standards
    Table V.58 and Table V.59 summarize the quantitative impacts 
estimated for each TSL for low-voltage dry-type distribution 
transformers. The national impacts are measured over the lifetime of 
distribution transformers purchased in the 30-year period that begins 
in the anticipated year of compliance with amended standards (2029-
2058). The energy savings, emissions reductions, and value of emissions 
reductions refer to full-fuel-cycle results. DOE is presenting 
monetized benefits of GHG emissions reductions in accordance with the 
applicable Executive Orders, and DOE would reach the same conclusion 
presented in this notice in

[[Page 30013]]

the absence of the social cost of greenhouse gases, including the 
Interim Estimates presented by the Interagency Working Group. The 
efficiency levels contained in each TSL are described in section V.A of 
this document.
[GRAPHIC] [TIFF OMITTED] TR22AP24.622


[[Page 30014]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.623

    DOE first considered TSL 5, which represents the max-tech 
efficiency levels. TSL 5 would save an estimated 2.53 quads of energy, 
an amount DOE considers significant. Under TSL 5, the NPV of consumer 
benefit would be $3.00 billion using a discount rate of 7 percent, and 
$9.86 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 5 are 46.20 Mt of 
CO2, 11.1 thousand tons of SO2, 82.7 thousand 
tons of NOX, 0.1 tons of Hg, 384.4 thousand tons of 
CH4, and 0.4 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 5 is $1.81 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 5 is $1.12 billion using a 7-percent discount rate and $3.58 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 5 is $5.93 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 5 is $15.25 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
proposed standard level is economically justified.
    At TSL 5, the average LCC impact ranges from $517 for equipment 
class 3 to $1,044 for equipment class 4. The median PBP ranges from 4.8 
years for equipment class 4 to 8.9 years for equipment class 3. The 
fraction of consumers experiencing a net LCC cost ranges from 3 percent 
for equipment class 4 to 18 percent for equipment class 3.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$68.4 million to a decrease of $54.0 million, which corresponds to 
decreases of 32.3 percent and 25.5 percent, respectively. DOE estimates 
that industry must invest $91.8 million to comply with standards set at 
TSL 5.
    The energy savings under TSL 5 are primarily achievable by using 
amorphous cores. The transition from GOES cores to amorphous cores 
requires significant investment on the part of the distribution 
transformer manufacturer if they produce their own cores. At TSL 5, 
most existing core production equipment would need to be replaced with 
amorphous core production equipment. Most LVDT manufacturers have 
little or no experience producing transformer designs with amorphous 
cores and little experience as to potential modifications that may need 
to be made to new protective equipment. Further, LVDT manufacturers 
tend to have considerably lower transformer core volumes than liquid-
immersed manufacturers. As such, electrical steel manufacturers tend to 
prioritize service to liquid-immersed manufacturers over dry-type 
distribution transformer manufacturers. This creates a risk that, given 
the quantity of amorphous ribbon expected to be used within the liquid-
immersed distribution transformer market, there may be considerable 
competition for amorphous ribbon that may hamper LVDT manufacturers' 
ability to develop experience with amorphous cores in the near-term, 
which would lead to considerable

[[Page 30015]]

supply chain disruptions in the compliance year.
    DOE notes that while the January 2023 NOPR proposed standards at 
TSL 5, distribution transformer shortages have persisted throughout 
2023. DOE further notes that hundreds of millions of dollars in 
investments have been announced by distribution transformer 
manufacturers to add capacity to resolve the existing transformer 
shortages and those investments are currently undergoing the design, 
permitting, engineering, and construction process needed to begin 
production with scheduled completions typically targeting 24 to 36 
months. DOE updated its analysis of conversion costs in this final rule 
based on stakeholder feedback and are the costs are now greater than 
the costs analyzed in the January 2023 NOPR. Investing in conversion 
costs, in addition to manufacturers investments to increase capacity, 
without offering flexibility for manufacturers to add amorphous 
capacity in an additive manner has led DOE to conclude that TSL 5 
offers substantial risk that could extend current transformer shortages 
longer they otherwise would be.
    The Secretary concludes that at TSL 5 for low-voltage dry-type 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the risks that manufacturers would 
not be able to scale up amorphous core production within the compliance 
period without significantly increasing distribution transformer lead 
times. The benefits of TSL 5 for low-voltage dry-type distribution 
transformers do not outweigh the risks of significant impacts to the 
distribution transformer supply chain, particularly when considered in 
conjunction with the expected demand for core materials in the liquid-
immersed distribution transformer market. Consequently, the Secretary 
has concluded that TSL 5 is not economically justified.
    Next, DOE considered TSL 4. TSL 4 would save an estimated 2.38 
quads of energy, an amount DOE considers significant. Under TSL 4, the 
NPV of consumer benefit would be $3.20 billion using a discount rate of 
7 percent, and $10.14 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 4 are 43.56 Mt of 
CO2, 10.4 thousand tons of SO2, 77.9 thousand 
tons of NOX, 0.1 tons of Hg, 362.3 thousand tons of 
CH4, and 0.3 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 4 is $1.71 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 4 is $1.06 billion using a 7-percent discount rate and $3.38 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 4 is $5.97 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 4 is $15.23 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
proposed standard level is economically justified.
    At TSL 4, the average LCC impact ranges from $551 for equipment 
class 3 to $1,068 for equipment class 4. The median PBP ranges from 3.4 
years for equipment class 4 to 7.4 years for equipment class 3. The 
fraction of consumers experiencing a net LCC cost ranges from 2 percent 
for equipment class 4 to 14 percent for equipment class 3.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$62.9 million to a decrease of $52.2 million, which corresponds to 
decreases of 29.7 percent and 24.7 percent, respectively. DOE estimates 
that industry must invest $86.7 million to comply with standards set at 
TSL 4.
    The energy savings under TSL 4 are primarily achievable by using 
amorphous cores. As noted, LVDT manufacturers have little or no 
experience producing transformer designs with amorphous cores and 
little experience as to potential modifications that may need to be 
made to new protective equipment. DOE is concerned that given the large 
quantity of amorphous ribbon expected to be used within the liquid-
immersed distribution transformer market, there may be considerable 
competition for amorphous ribbon that may hamper LVDT manufacturers' 
ability to develop experience with amorphous cores in the near-term, 
which would lead to considerable supply chain disruptions in the 
compliance year.
    The Secretary concludes that at TSL 4 for low-voltage dry-type 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the risks that manufacturers would 
not be able to scale up amorphous core production within the compliance 
period without significantly increasing distribution transformer lead 
times. Further, as discussed in section IV.C.2.a of this document, an 
inability of suppliers of amorphous ribbon to scale production and 
manufacturers to retool production lines for amorphous cores within the 
compliance period could lead to market uncertainty and disruption 
during a critical time. Several stakeholders have noted that given 
existing supply challenges, a total conversion to amorphous is not 
feasible in the near term. While this final rule considers a longer 
compliance period, the impacts of shortages are substantial, which may 
have an impact on grid reliability. Therefore, the risks of scale-up 
and compliance taking slightly longer, due to any number of unforeseen 
challenges, could have substantial impacts. The benefits of TSL 4 for 
low-voltage dry-type distribution transformer do not outweigh the risks 
of significant impacts to the distribution transformer supply chain, 
particularly when considered in conjunction with the expected demand 
for core materials in the liquid-immersed distribution transformer 
market. Consequently, the Secretary has concluded that TSL 4 is not 
economically justified.
    Next, DOE considered TSL 3. TSL 3 would save an estimated 1.71 
quads of energy, an amount DOE considers significant. Under TSL 3, the 
NPV of consumer benefit would be $2.08 billion using a discount rate of 
7 percent, and $6.68 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 3 are 31.28 Mt of 
CO2, 7.5 thousand tons of SO2, 55.9 thousand tons 
of NOX, 0.1 tons of Hg, 260.0 thousand tons of 
CH4, and 0.2 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 3 is $1.23 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 3 is $0.76 billion using a 7-percent discount rate and $2.42 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 3 is $4.07 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 3 is $10.33 billion. The

[[Page 30016]]

estimated total NPV is provided for additional information, however DOE 
primarily relies upon the NPV of consumer benefits when determining 
whether a standard level is economically justified.
    At TSL 3, the average LCC impact ranges from $321 for equipment 
class 3 to $765 for equipment class 4. The median PBP ranges from 3.6 
years for equipment class 4 to 7.4 years for equipment class 3--well 
below the estimated average lifetime of 32 years. The fraction of 
consumers experiencing a net LCC cost ranges from 9 percent for 
equipment class 4 to 28 percent for equipment class 3.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$27.1 million to a decrease of $18.9 million, which corresponds to 
decreases of 12.8 percent and 8.9 percent, respectively. DOE estimates 
that industry must invest $36.1 million to comply with standards set at 
TSL 3.
    After considering the analysis and weighing the benefits and 
burdens, the Secretary has concluded that a standard set at TSL 3 for 
low-voltage dry-type distribution transformers would be economically 
justified. Notably, the benefits to consumers outweigh the cost to 
manufacturers. At this TSL, the average LCC savings are positive across 
all equipment classes. An estimated 11 percent of low-voltage dry-type 
distribution transformer consumers experience a net cost. The FFC 
national energy savings are significant and the NPV of consumer 
benefits is positive using both a 3-percent and 7-percent discount 
rate. At TSL 3, the NPV of consumer benefits, even measured at the more 
conservative discount rate of 7 percent, is larger than the maximum 
estimated manufacturers' loss in INPV. The standard levels at TSL 3 are 
economically justified even without weighing the estimated monetary 
value of emissions reductions. When those emissions reductions are 
included--representing $1.23 billion in climate benefits (associated 
with the average SC-GHG at a 3-percent discount rate), and $2.42 
billion (using a 3-percent discount rate) or $0.76 billion (using a 7-
percent discount rate) in health benefits--the rationale becomes 
stronger still.
    Notably, the energy savings under TSL 3 do not carry the same risks 
to distribution transformer supply chains as TSL 4 and TSL 5. The 
energy savings under TSL 3 are primarily achieved using lower-loss GOES 
cores with some shipments using amorphous cores where it is most cost-
competitive. DOE notes that at TSL 3, both amorphous and GOES cores are 
cost-competitive with regard to which core steel produces the lowest 
first-cost unit, allowing manufacturers flexibility in establishing 
supply chains and redesigning transformers to meet amended standards 
based on their specific needs.
    As stated, DOE conducts the walk-down analysis to determine the TSL 
that represents the maximum improvement in energy efficiency that is 
technologically feasible and economically justified as required under 
EPCA. The walk-down is not a comparative analysis, as a comparative 
analysis would result in the maximization of net benefits instead of 
energy savings that are technologically feasible and economically 
justified, which would be contrary to the statute. 86 FR 70892, 70908.
    Although DOE has not conducted a comparative analysis to select the 
new energy conservation standards, DOE notes that TSL 3 has 
considerably lower manufacturer impacts than TSL 4 and TSL 5. Further, 
TSL 3 allows both GOES and amorphous cores to compete, ensuring a 
diverse supply of materials can serve the LVDT market.
    Although DOE considered amended standard levels for distribution 
transformers by grouping the efficiency levels for each equipment 
category into TSLs, DOE evaluates all analyzed efficiency levels in its 
analysis. The TSLs constructed by DOE to examine the impacts of amended 
energy efficiency standards for low-voltage dry-type distribution 
transformers align with the corresponding ELs defined in the 
engineering analysis. For the ELs above baseline that compose TSL 3, 
DOE finds that LCC savings are positive for all equipment classes, with 
simple paybacks well below the average equipment lifetimes. DOE also 
finds that the estimated fraction of consumers who would be negatively 
impacted from a standard at TSL 3 to be 11 percent for all equipment 
classes. Importantly, DOE expects TSL 3 to be achievable with both 
amorphous and GOES core materials.
    Therefore, based on the previous considerations, DOE adopts the 
energy conservation standards for LVDT distribution transformers at TSL 
3. The amended energy conservation standards for distribution 
transformers, which are expressed as percentage efficiency at 35 
percent PUL, are shown in Table V.60.
[GRAPHIC] [TIFF OMITTED] TR22AP24.624


[[Page 30017]]


3. Benefits and Burdens of TSLs Considered for Medium-Voltage Dry-Type 
Distribution Transformer Standards
    Table V.61 and Table V.62 summarize the quantitative impacts 
estimated for each TSL for medium-voltage dry-type distribution 
transformers. The national impacts are measured over the lifetime of 
distribution transformers purchased in the 30-year period that begins 
in the anticipated year of compliance with amended standards (2029-
2058). The energy savings, emissions reductions, and value of emissions 
reductions refer to full-fuel-cycle results. DOE is presenting 
monetized benefits of GHG emissions reductions in accordance with the 
applicable Executive Orders, and DOE would reach the same conclusion 
presented in this notice in the absence of the social cost of 
greenhouse gases, including the Interim Estimates presented by the 
Interagency Working Group. The efficiency levels contained in each TSL 
are described in section V.A of this document.

[[Page 30018]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.625


[[Page 30019]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.626

    DOE first considered TSL 5. TSL 5 would save an estimated 0.65 
quads of energy, an amount DOE considers significant. Under TSL 5, the 
NPV of consumer benefit would be $-0.08 billion using a discount rate 
of 7 percent, and $0.72 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 5 are 11.72 Mt of 
CO2, 2.8 thousand tons of SO2, 21.2 thousand tons 
of NOX, 0.02 tons of Hg, 98.6 thousand tons of 
CH4, and 0.1 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 5 is $0.46 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 5 is $0.29 billion using a 7-percent discount rate and $0.92 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 5 is $0.67 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 5 is $2.10 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
standard level is economically justified.
    At TSL 5, the average LCC impact ranges from $-6,239 for equipment 
class 10 to $136 for equipment class 6. The median PBP ranges from 5.0 
years for equipment class 6 to 10.5 years for equipment class 10. The 
fraction of consumers experiencing a net LCC cost ranges from 47 
percent for equipment class 6 to 85 percent for equipment class 10.
    At TSL 5, the projected change in INPV ranges from a decrease of 
$33.2 million to a decrease of $16.3 million, which corresponds to 
decreases of 34.9 percent and 17.1 percent, respectively. DOE estimates 
that industry must invest $36.2 million to comply with standards set at 
TSL 5.
    The Secretary concludes that at TSL 5 for medium-voltage dry-type 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the economic burden on many consumers 
as indicated by the negative LCCs for many equipment classes, the 
percentage of customers who would experience LCC increases, and the 
capital and engineering costs that could result in a reduction in INPV 
for manufacturers. At TSL 5 DOE is estimating negative benefits for a 
disproportionate fraction of consumers--a shipment weighted average of 
68 percent. Further DOE estimates that there is a substantial risk to 
consumers, with a shipment weighted LCC savings for all MVDT equipment 
of -$3,178. Consequently, the Secretary has concluded that TSL 5 is not 
economically justified.
    Next, DOE considered TSL 4. TSL 4 would save an estimated 0.55 
quads of energy, an amount DOE considers significant. Under TSL 4, the 
NPV of

[[Page 30020]]

consumer benefit would be $0.18 billion using a discount rate of 7 
percent, and $1.14 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 4 are 9.85 Mt of 
CO2, 2.4 thousand tons of SO2, 17.8 thousand tons 
of NOX, 0.02 tons of Hg, 82.9 thousand tons of 
CH4, and 0.1 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 4 is $0.39 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 4 is $0.24 billion using a 7-percent discount rate and $0.77 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 4 is $0.81 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 4 is $2.30 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
proposed standard level is economically justified.
    At TSL 4, the average LCC impact ranges from $-2,569 for equipment 
class 10 to $2,882 for equipment class 8. The median PBP ranges from 
4.2 years for equipment class 8 to 9.2 years for equipment class 10. 
The fraction of consumers experiencing a net LCC cost ranges from 29 
percent for equipment class 8 to 67 percent for equipment class 10.
    At TSL 4, the projected change in INPV ranges from a decrease of 
$29.5 million to a decrease of $18.6 million, which corresponds to 
decreases of 31.0 percent and 19.5 percent, respectively. DOE estimates 
that industry must invest $34.8 million to comply with standards set at 
TSL 4.
    The Secretary concludes that at TSL 4 for medium-voltage dry-type 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the economic burden on many consumers 
as indicated by the negative LCCs for many equipment classes, the 
percentage of customers who would experience LCC increases, and the 
capital and engineering costs that could result in a reduction in INPV 
for manufacturers. At TSL 4 DOE is estimating negative benefits for a 
disproportionate fraction of consumers--a shipment weighted average of 
45 percent. Consequently, the Secretary has concluded that TSL 4 is not 
economically justified.
    Next, DOE considered TSL 3. TSL 3 would save an estimated 0.42 
quads of energy, an amount DOE considers significant. Under TSL 3, the 
NPV of consumer benefit would be $0.25 billion using a discount rate of 
7 percent, and $1.15 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 3 are 7.55 Mt of 
CO2, 1.8 thousand tons of SO2, 13.6 thousand tons 
of NOX, 0.01 tons of Hg, 63.5 thousand tons of 
CH4, and 0.1 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 3 is $0.30 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 3 is $0.19 billion using a 7-percent discount rate and $0.59 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 3 is $0.73 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 3 is $2.04 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
proposed standard level is economically justified. At TSL 3, the 
average LCC impact ranges from $-2,788 for equipment class 10 to $3,418 
for equipment class 8. The median PBP ranges from 3.5 years for 
equipment class 6 to 10.0 years for equipment class 10. The fraction of 
consumers experiencing a net LCC cost ranges from 29 percent for 
equipment class 8 to 63 percent for equipment class 10.
    At TSL 3, the projected change in INPV ranges from a decrease of 
$26.4 million to a decrease of $19.1 million, which corresponds to 
decreases of 27.8 percent and 20.1 percent, respectively. DOE estimates 
that industry must invest $32.7 million to comply with standards set at 
TSL 3.
    The Secretary concludes that at TSL 3 for medium-voltage dry-type 
distribution transformers, the benefits of energy savings, emission 
reductions, and the estimated monetary value of the emissions 
reductions would be outweighed by the economic burden on many consumers 
as indicated by the negative LCCs for many equipment classes, the 
percentage of customers who would experience LCC increases, and the 
capital and engineering costs that could result in a reduction in INPV 
for manufacturers. At TSL 3, DOE estimates negative benefits for a 
disproportionate fraction of consumers--a shipment weighted average of 
41 percent. Consequently, the Secretary has concluded that TSL 3 is not 
economically justified.
    Next, DOE considered TSL 2. TSL 2 would save an estimated 0.14 
quads of energy, an amount DOE considers significant. Under TSL 2, the 
NPV of consumer benefit would be $0.03 billion using a discount rate of 
7 percent, and $0.22 billion using a discount rate of 3 percent.
    The cumulative emissions reductions at TSL 2 are 2.59 Mt of 
CO2, 0.6 thousand tons of SO2, 4.7 thousand tons 
of NOX, 0.0 tons of Hg, 21.9 thousand tons of 
CH4, and 0.0 thousand tons of N2O. The estimated 
monetary value of the climate benefits from reduced GHG emissions 
(associated with the average SC-GHG at a 3-percent discount rate) at 
TSL 2 is $0.10 billion. The estimated monetary value of the health 
benefits from reduced SO2 and NOX emissions at 
TSL 2 is $0.06 billion using a 7-percent discount rate and $0.20 
billion using a 3-percent discount rate.
    Using a 7-percent discount rate for consumer benefits and costs, 
health benefits from reduced SO2 and NOX 
emissions, and the 3-percent discount rate case for climate benefits 
from reduced GHG emissions, the estimated total NPV at TSL 2 is $0.20 
billion. Using a 3-percent discount rate for all benefits and costs, 
the estimated total NPV at TSL 2 is $0.52 billion. The estimated total 
NPV is provided for additional information, however DOE primarily 
relies upon the NPV of consumer benefits when determining whether a 
proposed standard level is economically justified.
    At TSL 2, the average LCC impact ranges from $-1,438 for equipment 
class 10 to $3,794 for equipment class 8. The median PBP ranges from 
0.5 years for equipment class 8 to 10.1 years for equipment class 10. 
The fraction of consumers experiencing a net LCC cost ranges from 10 
percent for equipment class 6 to 77 percent for equipment class 10.
    At TSL 2, the projected change in INPV ranges from a decrease of 
$4.4 million to a decrease of $2.3 million, which corresponds to 
decreases of 4.7 percent and 2.5 percent, respectively. DOE estimates 
that industry must invest

[[Page 30021]]

$5.7 million to comply with standards set at TSL 2.
    After considering the analysis and weighing the benefits and 
burdens, the Secretary has concluded that at a standard set at TSL 2 
for medium-voltage distribution transformers would be economically 
justified. At this TSL, the average LCC savings are positive across all 
equipment classes except for equipment class 10, with a shipment 
weighed average LCC for all medium-voltage dry-type distribution 
transformers of $1,738. An estimated 10 percent of equipment class 6 to 
77 percent of equipment class 10 medium-voltage dry-type distribution 
transformer consumers experience a net cost, while the shipment 
weighted average of consumers who experience a net cost is 33 percent. 
The FFC national energy savings are significant and the NPV of consumer 
benefits is positive using both a 3-percent and 7-percent discount 
rate. Notably, the benefits to consumers outweigh the cost to 
manufacturers. At TSL 2, the NPV of consumer benefits, even measured at 
the more conservative discount rate of 7 percent is over 6 times higher 
than the maximum estimated manufacturers' loss in INPV. The standard 
levels at TSL 2 are economically justified even without weighing the 
estimated monetary value of emissions reductions. When those emissions 
reductions are included--representing $0.10 billion in climate benefits 
(associated with the average SC-GHG at a 3-percent discount rate), and 
$0.20 billion (using a 3-percent discount rate) or $0.06 billion (using 
a 7-percent discount rate) in health benefits--the rationale becomes 
stronger still.
    As stated, DOE conducts the walk-down analysis to determine the TSL 
that represents the maximum improvement in energy efficiency that is 
technologically feasible and economically justified as required under 
EPCA. The walk-down is not a comparative analysis, as a comparative 
analysis would result in the maximization of net benefits instead of 
energy savings that are technologically feasible and economically 
justified, which would be contrary to the statute. 86 FR 70892, 70908.
    Although DOE considered amended standard levels for distribution 
transformers by grouping the efficiency levels for each equipment 
category into TSLs, DOE evaluates all analyzed efficiency levels in its 
analysis. For medium-voltage dry-type distribution transformer the TSL 
2 maps directly to EL 2 for all equipment classes. EL 2 represents a 10 
percent reduction in losses over the current standard. While the 
consumer benefits for equipment class 10 are negative at EL 2 at -
$1,438, they are positive for all other equipment representing 67 
percent of all MVDT units shipped, additionally the consumer benefits 
at EL 2, excluding equipment class 10, increases from $1,738 to $2,217 
in LCC savings Further, the EL 2 represent an improvement in efficiency 
where the FFC national energy savings is maximized, with positive NPVs 
at both 3 and 7 percent, and the shipment weighted average consumer 
benefit at EL 2 is positive. The shipment weighted consumer benefits 
for TSL, and EL 2 are shown in Table V.63.
    As discussed previously, at the max-tech efficiency levels (TSL 5), 
TSL 4, and TSL 3 for all medium-voltage dry-type distribution 
transformers there is a substantial risk to consumers due to negative 
LCC savings for some equipment, with a shipment weighted average 
consumer benefit of -$3,178, $754, and $1,036, respectively, while at 
TSL 2 it is $1,738. Therefore, DOE has concluded that the efficiency 
levels above TSL 2 are not justified. Additionally, at the examined 
efficiency levels greater than TSL 2 DOE is estimating that a 
disproportionate fraction of consumers would be negatively impacted by 
these efficiency levels. DOE estimates that shipment weighted fraction 
of negatively impacted consumers for TSL 3, TSL 4, and TSL 5 (max-tech) 
to be 68, 45, and 41 percent, respectively.
    Therefore, based on the previous considerations, DOE adopts the 
energy conservation standards for distribution transformers at TSL 2. 
The amended energy conservation standards for MVDT distribution 
transformers, which are expressed as percentage efficiency at 50 
percent PUL, are shown in Table V.63.

[[Page 30022]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.627

4. Annualized Benefits and Costs of the Adopted Standards for Liquid-
Immersed Distribution Transformers
    The benefits and costs of the adopted standards can also be 
expressed in terms of annualized values. The annualized net benefit is 
(1) the annualized national economic value (expressed in 2022$) of the 
benefits from operating products that meet the adopted standards 
(consisting primarily of operating cost savings from using less 
energy), minus increases in product purchase costs, and (2) the 
annualized monetary value of the climate and health benefits.
    Table V.64 shows the annualized values for liquid-immersed 
distribution transformers under TSL 3, expressed in 2022$. The results 
under the primary estimate are as follows.
    Using a 7-percent discount rate for consumer benefits and costs and 
NOx and SO2 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 
NOX and SO2 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 NOX and SO2 
emissions. In this case, the net benefit amounts to $515.1 million per 
year.

[[Page 30023]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.628


[[Page 30024]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.629

5. Annualized Benefits and Costs of the Adopted Standards for Low-
Voltage Dry-Type Distribution Transformers
    The benefits and costs of the adopted standards can also be 
expressed in terms of annualized values. The annualized net benefit is 
(1) the annualized national economic value (expressed in 2022$) of the 
benefits from operating products that meet the adopted standards 
(consisting primarily of operating cost savings from using less 
energy), minus increases in product purchase costs, and (2) the 
annualized monetary value of the climate and health benefits.
    Table V.65 shows the annualized values for low-voltage dry-type 
under TSL 3, expressed in 2022$. The results under the primary estimate 
are as follows.
    Using a 7-percent discount rate for consumer benefits and costs and 
NOx and SO2 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 NOX and 
SO2 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 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 NOX and SO2 emissions. In this case, the 
net benefit amounts to $593.0 million per year.

[[Page 30025]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.630


[[Page 30026]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.631

6. Annualized Benefits and Costs of the Adopted Standards for Medium-
Voltage Dry-Type Distribution Transformers
    The benefits and costs of the adopted standards can also be 
expressed in terms of annualized values. The annualized net benefit is 
(1) the annualized national economic value (expressed in 2022$) of the 
benefits from operating products that meet the adopted standards 
(consisting primarily of operating cost savings from using less 
energy), minus increases in product purchase costs, and (2) the 
annualized monetary value of the climate and health benefits.
    Table V.66 shows the annualized values for medium-voltage dry-type 
under TSL 2, expressed in 2022$. The results under the primary estimate 
are as follows.
    Using a 7-percent discount rate for consumer benefits and costs and 
NOx and SO2 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 NOX and 
SO2 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 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 
NOX and SO2 emissions. In this case, the net 
benefit amounts to $29.9 million per year.

[[Page 30027]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.632


[[Page 30028]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.633

7. Benefits and Costs of the Proposed Standards for All Considered 
Distribution Transformers
    As described in sections V.C.1 through V.C.3, for this final rule 
DOE is adopting TSL 3 for liquid-immersed, TSL 3 for low-voltage dry-
type, and TSL 2 for medium-voltage dry-type distribution transformers. 
Table V.67 shows the combined cumulative benefits, and Table V.68 shows 
the combined annualized benefits for the proposed levels for all 
distribution transformers.

[[Page 30029]]

[GRAPHIC] [TIFF OMITTED] TR22AP24.634


[[Page 30030]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.635


[[Page 30031]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.636


[[Page 30032]]


[GRAPHIC] [TIFF OMITTED] TR22AP24.637

8. Severability
    Finally, DOE added a new paragraph (e) to 10 CFR 431.196 to provide 
that each energy conservation standard for each distribution 
transformer category (liquid immersed, LVDT, MDVT) is separate and 
severable from one another, and that if any energy conservation 
standard for any category is stayed or determined to be invalid by a 
court of competent jurisdiction, the remaining energy conservation 
standards for the other categories shall continue in effect. This 
severability clause is intended to clearly express the Department's 
intent that should an energy conservation standard for any category be 
stayed or invalidated, energy conservation standards for the other 
categories shall continue to remain in full force and legal effect.

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866, 13563, and 14094

    Executive Order (E.O.) 12866, ``Regulatory Planning and Review,'' 
as supplemented and reaffirmed by E.O. 13563, ``Improving Regulation 
and Regulatory Review,'' 76 FR 3821 (Jan. 21, 2011) and amended by E.O. 
14094, ``Modernizing Regulatory Review,'' 88 FR 21879 (April 11, 2023), 
requires agencies, to the extent permitted by law, to (1) propose or 
adopt a regulation only upon a reasoned determination that its benefits 
justify its costs (recognizing that some benefits and costs are 
difficult to quantify); (2) tailor regulations to impose the least 
burden on society, consistent with obtaining regulatory objectives, 
taking into account, among other things, and to the extent practicable, 
the costs of cumulative regulations; (3) select, in choosing among 
alternative regulatory approaches, those approaches that maximize net 
benefits (including potential economic, environmental, public health 
and safety, and other advantages; distributive impacts; and equity); 
(4) to the extent feasible, specify performance objectives, rather than 
specifying the behavior or manner of compliance that regulated entities 
must adopt; and (5) identify and assess available alternatives to 
direct regulation, including providing economic incentives to encourage 
the desired behavior, such as user fees or marketable permits, or 
providing information upon which choices can be made by the public. DOE 
emphasizes as well that E.O. 13563 requires agencies to

[[Page 30033]]

use the best available techniques to quantify anticipated present and 
future benefits and costs as accurately as possible. In its guidance, 
the Office of Information and Regulatory Affairs (OIRA) in the Office 
of Management and Budget (OMB) has emphasized that such techniques may 
include identifying changing future compliance costs that might result 
from technological innovation or anticipated behavioral changes. For 
the reasons stated in the preamble, this final regulatory action is 
consistent with these principles.
    Section 6(a) of E.O. 12866 also requires agencies to submit 
``significant regulatory actions'' to OIRA for review. OIRA has 
determined that this final regulatory action constitutes a 
``significant regulatory action'' within the scope of section 3(f)(1) 
of E.O. 12866. Accordingly, pursuant to section 6(a)(3)(C) of E.O. 
12866, DOE has provided to OIRA an assessment, including the underlying 
analysis, of benefits and costs anticipated from the final regulatory 
action, together with, to the extent feasible, a quantification of 
those costs; and an assessment, including the underlying analysis, of 
costs and benefits of potentially effective and reasonably feasible 
alternatives to the planned regulation, and an explanation why the 
planned regulatory action is preferable to the identified potential 
alternatives. These assessments are summarized in this preamble and 
further detail can be found in the technical support document for this 
rulemaking.

B. Review Under the Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires 
preparation of an initial regulatory flexibility analysis (IRFA) and a 
final regulatory flexibility analysis (FRFA) for any rule that by law 
must be proposed for public comment, unless the agency certifies that 
the rule, if promulgated, will not have a significant economic impact 
on a substantial number of small entities. As required by E.O. 13272, 
``Proper Consideration of Small Entities in Agency Rulemaking,'' 67 FR 
53461 (Aug. 16, 2002), DOE published procedures and policies on 
February 19, 2003, to ensure that the potential impacts of its rules on 
small entities are properly considered during the rulemaking process. 
68 FR 7990. DOE has made its procedures and policies available on the 
Office of the General Counsel's website (www.energy.gov/gc/office-general-counsel). DOE has prepared the following FRFA for the products 
that are the subject of this rulemaking.
    For manufacturers of distribution transformers, the SBA has set a 
size threshold, which defines those entities classified as ``small 
businesses'' for the purposes of the statute. DOE used the SBA's small 
business size standards to determine whether any small entities would 
be subject to the requirements of the rule. (See 13 CFR part 121.) The 
size standards are listed by NAICS code and industry description and 
are available at www.sba.gov/document/support-table-size-standards. 
Manufacturing of distribution transformers is classified under NAICS 
335311, ``Power, Distribution, and Specialty Transformer 
Manufacturing''. The SBA sets a threshold of 800 employees or fewer for 
an entity to be considered as a small business for this category.
1. Need for, and Objectives of, Rule
    EPCA authorizes DOE to regulate the energy efficiency of a number 
of consumer products and certain industrial equipment. 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, added by Public Law 95-619, Title IV, section 411(a), 
established the Energy Conservation Program for Certain Industrial 
Equipment. The Energy Policy Act of 1992, Public Law 102-486, amended 
EPCA and directed DOE to prescribe energy conservation standards for 
those distribution transformers for which DOE determines such standards 
would be technologically feasible, economically justified, and would 
result in significant energy savings. (42 U.S.C. 6317(a)) The Energy 
Policy Act of 2005, Public Law 109-58, amended EPCA to establish energy 
conservation standards for low-voltage dry-type distribution 
transformers. (42 U.S.C. 6295(y))
    EPCA further provides that, not later than 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))
    DOE must follow specific statutory criteria for prescribing new or 
amended standards for covered equipment, including distribution 
transformers. Any new or amended standard for a covered product must be 
designed to achieve the maximum improvement in energy efficiency that 
the Secretary of Energy determines is technologically feasible and 
economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) 
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))
2. Significant Issues Raised by Public Comments in Response to the IRFA
    APPA commented that some small manufacturers will not be able to 
retool in sufficient time and will further worsen supply chain 
concerns. (APPA, No. 103 at p. 6) Powersmiths commented that using 
amorphous steel for LVDT distribution transformers requires an overhaul 
of the manufacturing production process. (Powersmiths, No. 112 at p. 6) 
Powersmiths commented that small manufacturers may not be able to make 
this transition due to the complexity and novelty of amorphous steel, 
along with the need for qualified designers, significant retooling 
costs, new manufacturing processes, and other additional resources. 
(Id.) Additionally, Powersmiths commented that even if LVDT small 
manufacturers could make this transition to amorphous steel they will 
need more than the 3-year compliance period proposed in the January 
2023 NOPR. (Id.)
    DOE understands that distribution transformer manufacturers, 
including small businesses, will incur conversion costs, which include 
retooling production facilities, in order to comply with standards. DOE 
estimates the impacts to the distribution transformer industry at each 
TSL in section V.B.2.a of this document and specifically estimates the 
impact to small businesses as part of this FRFA. Additionally, in the 
January 2023 NOPR DOE proposed a 3-year compliance period for 
manufacturers to meet the proposed standards. DOE is adopting a 5-year 
compliance period for this final rule. This additional time should 
allow for manufacturers, including small manufacturers, to retool their 
production facilities and make the necessary equipment additions that 
manufacturers will have to make to manufacture compliant distribution 
transformers. DOE also notes that the expanded compliance date provides 
greater time for core steel manufacturers, both GOES and amorphous, to 
meet expected demand.
    NAHB commented that most home builders are considered a small 
business based on SBA's small business definition and expressed concern 
that DOE has not considered these home builders and other small 
businesses that rely on a consistent supply of distribution 
transformers that might be impacted by this rulemaking. (NAHB,

[[Page 30034]]

No. 106 at p. 5) As stated in section IV.A.5 of this document, DOE 
notes that the standards amended in this rule will allow distribution 
transformers to cost-competitively utilize existing GOES capacity 
across many kVA ratings. Additionally, DOE notes that the compliance 
period for amended standards has been extended, from the 3-year 
compliance period proposed in the January 2023 NOPR to a 5-year 
compliance period adopted in this final rule. The additional time 
provided to redesign distribution transformers and build capacity will 
further mitigate any risk of disrupting production to meet current 
demand. Additionally, as stated in section V.B.2.c of this document, 
DOE does not anticipate that there will be a significant disruption in 
the supply of distribution transformers due to the adopted standards to 
home builders or any other distribution transformer markets.
3. Description and Estimated Number of Small Entities Affected
    DOE conducted a more focused inquiry of the companies that could be 
small businesses that manufacture distribution transformers covered by 
this rulemaking. DOE used publicly available information to identify 
potential small businesses. DOE's research involved industry trade 
association membership directories (including NEMA),\202\ DOE's 
publicly available Compliance Certification Database \203\ (CCD), 
California Energy Commission's Modernized Appliance Efficiency Database 
System \204\ (MAEDBS) to create a list of companies that manufacture or 
sell distribution transformers covered by this rulemaking. DOE also 
asked stakeholders and industry representatives if they were aware of 
any other small businesses during manufacturer interviews. DOE 
contacted select companies on its list, as necessary, to determine 
whether they met the SBA's definition of a small business that 
manufacturers distribution transformers covered by this rulemaking. DOE 
screened out companies that did not offer products covered by this 
rulemaking, did not meet the definition of a ``small business,'' or are 
foreign owned and operated.
---------------------------------------------------------------------------

    \202\ See: www.nema.org/membership/manufacturers.
    \203\ See: www.regulations.doe.gov/certification-data.
    \204\ See: cacertappliances.energy.ca.gov.
---------------------------------------------------------------------------

    DOE's analysis identified 36 companies that sell or manufacture 
distribution transformers coved by this rulemaking in the U.S. market. 
At least two of these companies are not the original equipment 
manufacturers (OEM) and instead privately label distribution 
transformers that are manufactured by another distribution transformer 
manufacturer. Of the 34 companies that are OEMs, DOE identified nine 
companies that have fewer than 800 total employees and are not entirely 
foreign owned and operated. There are three small businesses that 
manufacture liquid-immersed distribution transformers; there are three 
small businesses that manufacture LVDT and MVDT distribution 
transformers; and there are three small businesses that only 
manufacture LVDT distribution transformers.\205\
---------------------------------------------------------------------------

    \205\ Therefore, there are a total of six small businesses that 
manufacture LVDT distribution transformers. Three that exclusively 
manufacture LVDT distribution transformers and three that 
manufacture both LVDT and MVDT distribution transformers.
---------------------------------------------------------------------------

Liquid-Immersed Distribution Transformer Small Businesses
    Liquid-immersed distribution transformers account for over 80 
percent of all distribution transformer shipments covered by this 
rulemaking. Seven major manufacturers supply more than 80 percent of 
the market for liquid-immersed distribution transformers covered by 
this rulemaking. None of these seven major manufacturers of liquid-
immersed distribution transformers are small businesses. Most liquid-
immersed distribution transformers are manufactured domestically. 
Electric utilities compose the customer base and typically buy on a 
first-cost basis. Many small manufacturers position themselves towards 
the higher end of the market or in particular product niches, such as 
network transformers or harmonic mitigating transformers, but, in 
general, competition is based on price after a given unit's specs are 
prescribed by a customer. None of the three small businesses have a 
market share larger than five percent of the liquid-immersed 
distribution transformer market.
Low-Voltage Dry-Type Distribution Transformer Small Businesses
    LVDT distribution transformers account for approximately 16 percent 
of all distribution shipments covered by this rulemaking. Eleven major 
manufacturers supply more than 80 percent of the market for LVDT 
distribution transformers covered by this rulemaking. Two of these 11 
major LVDT distribution transformer manufacturers are small businesses. 
The majority of LVDT distribution transformers are manufactured outside 
the U.S., mostly in Canada and Mexico. The customer base rarely 
purchases on efficiency and is very first-cost conscious, which, in 
turn, places a premium on economies of scale in manufacturing. However, 
there are universities and other buildings that purchase LVDT based on 
efficiency as more and more organizations are striving to get to 
reduced or net-zero emission targets.
    In the LVDT market, lower volume manufacturers typically do not 
compete directly with larger volume manufacturers, as these lower 
volume manufacturers are frequently not able to compete on a first cost 
basis. However, there are lower volume manufactures that do serve 
customers that purchase more efficient LVDT distribution transformers. 
Lastly, there are some smaller firms that focus on the engineering and 
design of LVDT distribution transformers and source the production of 
some parts of the distribution transformer, most frequently the cores, 
to another company that manufactures those components.
Medium-Voltage Dry-Type Distribution Transformer Small Businesses
    MVDT distribution transformers account for less than one percent of 
all distribution transformer shipments covered by this rulemaking. 
Eight major manufacturers supply more than 80 percent of the market for 
MVDT distribution transformers covered by this rulemaking. Two of the 
eight major MVDT distribution transformer manufacturers are small 
businesses. The rest of MVDT distribution transformer market is served 
by a mix of large and small manufactures. Most MVDT distribution 
transformers are manufactured domestically. Electric utilities and 
industrial users make up most of the customer base and typically buy on 
first-cost or features other than efficiency.
4. Description of Reporting, Recordkeeping, and Other Compliance 
Requirements
Liquid-Immersed Distribution Transformers
    DOE is adopting energy conservation standards at TSL 3 for liquid-
immersed distribution transformers. For liquid-immersed distribution 
transformers, TSL 3 is a combination of EL 2 and EL 4 for most liquid-
immersed distribution transformer equipment classes.
    Based on the LCC consumer choice model, DOE anticipates that most

[[Page 30035]]

liquid-immersed distribution transformer manufacturers would use 
primarily grain-oriented with amorphous cores at select kVA ranges in 
their distribution transformers to meet these adopted energy 
conservation standards. While DOE anticipates that several large 
liquid-immersed distribution transformer manufacturers would make 
significant capital investments to accommodate the production of 
amorphous cores, DOE does not anticipate that any small businesses will 
make these capital investments to be able to produce their own 
amorphous cores, based on the large capital investments needed to be 
able to make amorphous cores and the limited ability for small 
businesses to access large capital investments. Based on manufacturer 
interviews and market research, DOE was not able to identify any 
liquid-immersed small businesses that manufacture their own cores. 
Therefore, DOE anticipates that all liquid-immersed small manufacturers 
would continue to outsource their production of distribution 
transformer cores. However, instead of outsourcing exclusively GOES 
cores they will now outsource a combination of GOES cores and amorphous 
cores for most of the liquid-immersed distribution transformers that 
they manufacture in order to comply with the adopted energy 
conservation standard for liquid-immersed distribution transformers.
    DOE acknowledges that there is uncertainty if these small 
businesses will be able to find core manufacturers that will supply 
them with amorphous cores in order to comply with the adopted energy 
conservation standards for liquid-immersed distribution transformers. 
DOE anticipates that there will be an increase in the number of large 
liquid-immersed distribution transformer manufacturers that will 
outsource the production of their cores to core manufacturers capable 
of producing amorphous cores. This could increase the competition for 
small businesses to procure amorphous cores for their distribution 
transformers. Small businesses manufacturing liquid-immersed 
distribution transformers must be able to procure amorphous cores 
suitable for their distribution transformers at a cost that allows them 
to continue to be competitive in the market.
    Based on feedback received during manufacturer interviews, DOE does 
not anticipate that liquid-immersed small businesses that are currently 
not producing their own cores would have to make a significant capital 
investment in their production lines to be able to use amorphous cores, 
that are purchased from a core manufacturer, in the distribution 
transformers that they manufacture. There will be some additional 
product conversion costs, in the form of additional R&D and testing, 
that will need to be incurred by small businesses that manufacture 
liquid-immersed distribution transformers, even if they do not 
manufacture their own cores. The methodology used to calculate product 
conversion costs, described in section IV.J.2.c of this document, 
estimates that manufacturers would incur approximately one and a half 
additional years of R&D expenditure to redesign their distribution 
transformers to be capable of accommodating the use of an amorphous 
core. Based on the financial parameters used in the GRIM, DOE estimated 
that the normal annual R&D is approximately 3.0 percent of annual 
revenue. Therefore, liquid-immersed small businesses would incur an 
additional 4.5 percent of annual revenue to redesign their distribution 
transformers to be able to accommodate using amorphous cores that were 
purchased from core manufacturers.
Low-Voltage Dry-Type Distribution Transformers
    DOE is adopting amended energy conservation standards to be at TSL 
3 for LVDT distribution transformers. For LVDT distribution 
transformers, TSL 3 corresponds to EL 3 for all LVDT distribution 
transformer equipment classes.
    Based on the LCC consumer choice model, DOE anticipates that 
approximately 30 percent of LVDT distribution transformer manufacturers 
would use amorphous cores in their distribution transformers to meet 
these adopted energy conservation standards. Based on manufacturer 
interviews and market research, DOE was able to identify one LVDT small 
business that manufactures their own cores. The one LVDT small business 
that is currently manufacturing their own cores would have to make a 
business decision to either continue making GOES cores that they 
currently manufacture, make a large capital investment to be able to 
manufacture amorphous cores, or to outsource the production of 
amorphous cores. Outsourcing the production of their cores would be a 
significant change in their production process and could result in a 
reduction in this small business' market share in the LVDT distribution 
transformer market.
    The other LVDT small businesses that are currently outsourcing 
their cores will continue to outsource their cores. These LVDT small 
businesses will have to make a business decision either to continue 
outsourcing GOES cores that they currently use in their LVDT 
distribution transformers or to find a core manufacturer that is 
capable of producing amorphous cores and outsource the production of 
amorphous cores.
    DOE acknowledges that there is uncertainty if these small 
businesses will be able to find core manufacturers that will supply 
them with amorphous cores in order to comply with the adopted energy 
conservation standards for LVDT distribution transformers. DOE 
anticipates that there will be an increase in the number of large LVDT 
distribution transformer manufacturers that will outsource the 
production of their cores to core manufacturers capable of producing 
amorphous cores. This could increase the competition for small 
businesses to procure amorphous cores for their LVDT distribution 
transformers. However, small businesses manufacturing LVDT distribution 
transformers will still be able to meet the adopted energy conservation 
standards using GOES cores.
    Based on feedback received during manufacturer interviews, DOE does 
not anticipate that small businesses that are currently not producing 
their own cores would have to make a significant capital investment in 
their production lines to be able to meet the adopted energy 
conservation standards for LVDT distribution transformers. There will 
be some additional product conversion costs, in the form of additional 
R&D and testing, that will need to be incurred by small businesses that 
manufacture LVDT distribution transformers, even if they do not 
manufacture their own cores. The methodology used to calculate product 
conversion costs, described in section IV.J.2.c estimates that 
manufacturers would incur approximately one and a half additional years 
of R&D expenditure to redesign their distribution transformers to be 
capable of accommodating the use of an amorphous core and 75 percent of 
annual R&D expenditures to redesign their distribution transformers 
that continue to use GOES cores. Based on the financial parameters used 
in the GRIM, DOE estimated that the normal annual R&D is approximately 
3.0 percent of annual revenue. Therefore, LVDT small businesses would 
incur an additional 2.25 to 4.5 percent of annual revenue to redesign 
their distribution transformers, depending on if they choose to 
continue to use GOES cores or amorphous cores, to meet the adopted 
energy conservation standard for LVDT distribution transformers, which 
are set at TSL 3.

[[Page 30036]]

Medium-Voltage Dry-Type Distribution Transformers
    DOE is adopting energy conservation standards to be at TSL 2 for 
MVDT distribution transformers. This corresponds to EL 2 for all MVDT 
distribution transformer equipment classes. Based on the LCC consumer 
choice model, DOE only anticipates that approximately 12 percent of 
MVDT distribution transformer manufacturers would use amorphous cores 
in their MVDT distribution transformers to meet these adopted energy 
conservation standards. DOE does not anticipate that MVDT distribution 
transformer manufacturers would make significant investments to either 
be able to produce cores capable of meeting these adopted amended 
energy conservation standards or be able to integrate more efficient 
purchased cores from core manufacturers. There will be some additional 
product conversion costs, in the form of additional R&D and testing, 
that will need to be incurred by small businesses that manufacture MVDT 
distribution transformers, even if they do not manufacture their own 
cores. The methodology used to calculate product conversion costs, 
described in section IV.J.2.c of this document, estimates that 
manufacturers would incur approximately 75 percent of additional R&D 
expenditure to redesign their distribution transformers to higher 
efficiency levels, when continuing to use GOES cores. Based on the 
financial parameters used in the GRIM, DOE estimated that the normal 
annual R&D is approximately 3.0 percent of annual revenue. Therefore, 
MVDT small businesses would include an additional 2.25 percent of 
annual revenue to redesign, MVDT distribution transformers to higher 
efficiency levels that could be met without using amorphous cores.
5. Significant Alternatives Considered and Steps Taken To Minimize 
Significant Economic Impacts on Small Entities
    The discussion in the previous section analyzes impacts on small 
businesses that would result from DOE's proposed rule, represented by 
TSL 3 for liquid-immersed distribution transformer equipment classes; 
TSL 3 for LVDT equipment classes; and TSL 2 for MVDT equipment classes. 
In reviewing alternatives to the proposed rule, DOE examined energy 
conservation standards set at lower efficiency levels. While lower TSLs 
would reduce the impacts on small business manufacturers, it would come 
at the expense of a reduction in energy savings. For liquid-immersed 
equipment classes TSL 1 achieves 84 percent lower energy savings 
compared to the energy savings at TSL 3; and TSL 2 achieves 58 percent 
lower energy savings compared to the energy savings at TSL 3. For LVDT 
equipment classes TSL 1 achieves 77 percent lower energy savings 
compared to the energy savings at TSL 3; and TSL 2 achieves 65 percent 
lower energy savings compared to the energy savings at TSL 3. For MVDT 
equipment classes TSL 1 achieves 29 percent lower energy savings 
compared to the energy savings at TSL 2.
    Establishing standards at TSL 3 for liquid-immersed equipment 
classes and LVDT equipment classes and TSL 2 for MVDT equipment classes 
balances the benefits of the energy savings at the adopted TSLs with 
the potential burdens placed on distribution transformer manufacturers, 
including small business manufacturers. Accordingly, DOE is not 
adopting one of the other TSLs considered in the analysis, or the other 
policy alternatives examined as part of the regulatory impact analysis 
and included in chapter 17 of the final rule TSD.
    Additional compliance flexibilities may be available through other 
means. Manufacturers subject to DOE's energy efficiency standards may 
apply to DOE's Office of Hearings and Appeals for exception relief 
under certain circumstances. Manufacturers should refer to 10 CFR part 
430, subpart E, and 10 CFR part 1003 for additional details.

C. Review Under the Paperwork Reduction Act

    Manufacturers of distribution transformers must certify to DOE that 
their products comply with any applicable energy conservation 
standards. In certifying compliance, manufacturers must test their 
products according to the DOE test procedures for distribution 
transformers, including any amendments adopted for those test 
procedures. DOE has established regulations for the certification and 
recordkeeping requirements for all covered consumer products and 
commercial equipment, including distribution transformers. (See 
generally 10 CFR part 429). The collection-of-information requirement 
for the certification and recordkeeping is subject to review and 
approval by OMB under the Paperwork Reduction Act (PRA). This 
requirement has been approved by OMB under OMB Control Number 1910-
1400. Public reporting burden for the certification is estimated to 
average 35 hours per response, including the time for reviewing 
instructions, searching existing data sources, gathering and 
maintaining the data needed, and completing and reviewing the 
collection of information.
    Notwithstanding any other provision of the law, no person is 
required to respond to, nor shall any person be subject to a penalty 
for failure to comply with, a collection of information subject to the 
requirements of the PRA, unless that collection of information displays 
a currently valid OMB Control Number.

D. Review Under the National Environmental Policy Act of 1969

    Pursuant to the National Environmental Policy Act of 1969 (NEPA), 
DOE has analyzed this rule in accordance with NEPA and DOE's NEPA 
implementing regulations (10 CFR part 1021). DOE has determined that 
this rule qualifies for categorical exclusion under 10 CFR part 1021, 
subpart D, appendix B5.1 because it is a rulemaking that establishes 
energy conservation standards for consumer products or industrial 
equipment, none of the exceptions identified in B5.1(b) apply, no 
extraordinary circumstances exist that require further environmental 
analysis, and it meets the requirements for application of a 
categorical exclusion. See 10 CFR 1021.410. Therefore, DOE has 
determined that promulgation of this rule is not a major Federal action 
significantly affecting the quality of the human environment within the 
meaning of NEPA, and does not require an environmental assessment or an 
environmental impact statement.

E. Review Under Executive Order 13132

    E.O. 13132, ``Federalism,'' 64 FR 43255 (Aug. 10, 1999), imposes 
certain requirements on Federal agencies formulating and implementing 
policies or regulations that preempt State law or that have federalism 
implications. The Executive order requires agencies to examine the 
constitutional and statutory authority supporting any action that would 
limit the policymaking discretion of the States and to carefully assess 
the necessity for such actions. The Executive order also requires 
agencies to have an accountable process to ensure meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications. On March 14, 2000, DOE 
published a statement of policy describing the intergovernmental 
consultation process it will follow in the development of such 
regulations. 65 FR 13735. DOE has examined this rule and has determined 
that it would not have a substantial direct effect on the States, on 
the relationship between the national government and the States, or on 
the

[[Page 30037]]

distribution of power and responsibilities among the various levels of 
government. EPCA governs and prescribes Federal preemption of State 
regulations as to energy conservation for the equipment that is the 
subject of this final rule. States can petition DOE for exemption from 
such preemption to the extent, and based on criteria, set forth in 
EPCA. (42 U.S.C. 6316(a) and (b); 42 U.S.C. 6297) Therefore, no further 
action is required by Executive Order 13132.

F. Review Under Executive Order 12988

    With respect to the review of existing regulations and the 
promulgation of new regulations, section 3(a) of E.O. 12988, ``Civil 
Justice Reform,'' imposes on Federal agencies the general duty to 
adhere to the following requirements: (1) eliminate drafting errors and 
ambiguity, (2) write regulations to minimize litigation, (3) provide a 
clear legal standard for affected conduct rather than a general 
standard, and (4) promote simplification and burden reduction. 61 FR 
4729 (Feb. 7, 1996). Regarding the review required by section 3(a), 
section 3(b) of E.O. 12988 specifically requires that Executive 
agencies make every reasonable effort to ensure that the regulation (1) 
clearly specifies the preemptive effect, if any, (2) clearly specifies 
any effect on existing Federal law or regulation, (3) provides a clear 
legal standard for affected conduct while promoting simplification and 
burden reduction, (4) specifies the retroactive effect, if any, (5) 
adequately defines key terms, and (6) addresses other important issues 
affecting clarity and general draftsmanship under any guidelines issued 
by the Attorney General. Section 3(c) of E.O. 12988 requires Executive 
agencies to review regulations in light of applicable standards in 
section 3(a) and section 3(b) to determine whether they are met or it 
is unreasonable to meet one or more of them. DOE has completed the 
required review and determined that, to the extent permitted by law, 
this final rule meets the relevant standards of E.O. 12988.

G. Review Under the Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) 
requires each Federal agency to assess the effects of Federal 
regulatory actions on State, local, and Tribal governments and the 
private sector. Public Law 104-4, sec. 201 (codified at 2 U.S.C. 1531). 
For a regulatory action likely to result in a rule that may cause the 
expenditure by State, local, and Tribal governments, in the aggregate, 
or by the private sector of $100 million or more in any one year 
(adjusted annually for inflation), section 202 of UMRA requires a 
Federal agency to publish a written statement that estimates the 
resulting costs, benefits, and other effects on the national economy. 
(2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to 
develop an effective process to permit timely input by elected officers 
of State, local, and Tribal governments on a ``significant 
intergovernmental mandate,'' and requires an agency plan for giving 
notice and opportunity for timely input to potentially affected small 
governments before establishing any requirements that might 
significantly or uniquely affect them. On March 18, 1997, DOE published 
a statement of policy on its process for intergovernmental consultation 
under UMRA. 62 FR 12820. DOE's policy statement is also available at 
www.energy.gov/sites/prod/files/gcprod/documents/umra_97.pdf.
    DOE has concluded that this final rule may require expenditures of 
$100 million or more in any one year by the private sector. Such 
expenditures may include (1) investment in research and development and 
in capital expenditures by distribution transformer manufacturers in 
the years between the final rule and the compliance date for the new 
standards and (2) incremental additional expenditures by consumers to 
purchase higher-efficiency distribution transformers, starting at the 
compliance date for the applicable standard.
    Section 202 of UMRA authorizes a Federal agency to respond to the 
content requirements of UMRA in any other statement or analysis that 
accompanies the final rule. (2 U.S.C. 1532(c)) The content requirements 
of section 202(b) of UMRA relevant to a private sector mandate 
substantially overlap the economic analysis requirements that apply 
under section 325(o) of EPCA and Executive Order 12866. The 
SUPPLEMENTARY INFORMATION section of this document and the TSD for this 
final rule respond to those requirements.
    Under section 205 of UMRA, DOE is obligated to identify and 
consider a reasonable number of regulatory alternatives before 
promulgating a rule for which a written statement under section 202 is 
required. (2 U.S.C. 1535(a)) DOE is required to select from those 
alternatives the most cost effective and least burdensome alternative 
that achieves the objectives of the rule unless DOE publishes an 
explanation for doing otherwise, or the selection of such an 
alternative is inconsistent with law. As required by 42 U.S.C. 6316(a) 
and 42 U.S.C. 6295(m)(1), this final rule establishes amended energy 
conservation standards for distribution transformers that are designed 
to achieve the maximum improvement in energy efficiency that DOE has 
determined to be both technologically feasible and economically 
justified, as required by 42 U.S.C. 6316(a); 6295(o)(2)(A) and 
6295(o)(3)(B). A full discussion of the alternatives considered by DOE 
is presented in chapter 17 of the TSD for this final rule.

H. Review Under the Treasury and General Government Appropriations Act, 
1999

    Section 654 of the Treasury and General Government Appropriations 
Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family 
Policymaking Assessment for any proposed rule or policy that may affect 
family well-being. Although this final rule would not have any impact 
on the autonomy or integrity of the family as an institution as 
defined, this final rule could impact a family's well-being. When 
developing a Family Policymaking Assessment, agencies must assess 
whether: (1) the action strengthens or erodes the stability or safety 
of the family and, particularly, the marital commitment; (2) the action 
strengthens or erodes the authority and rights of parents in the 
education, nurture, and supervision of their children; (3) the action 
helps the family perform its functions, or substitutes governmental 
activity for the function; (4) the action increases or decreases 
disposable income or poverty of families and children; (5) the proposed 
benefits of the action justify the financial impact on the family; (6) 
the action may be carried out by State or local government or by the 
family; and whether (7) the action establishes an implicit or explicit 
policy concerning the relationship between the behavior and personal 
responsibility of youth, and the norms of society.
    DOE has considered how the benefits of this final rule compare to 
the possible financial impact on a family (the only factor listed that 
is relevant to this proposed rule). As part of its rulemaking process, 
DOE must determine whether the energy conservation standards enacted in 
this final rule are economically justified. As discussed in sections 
V.C.1 through V.C.3 of this document, DOE has determined that the 
standards enacted in this final rule are economically justified because 
the benefits to consumers would far outweigh the costs to 
manufacturers. Moreover, as discussed further in section V.B.1 of this 
document, DOE has determined that for utilities who serve

[[Page 30038]]

low population densities, average LCC savings and PBP at the considered 
efficiency levels are not substantially different, and are often 
improved (i.e., higher LCC savings and lower PBP), as compared to the 
average for all utilities. Further, the standards will also result in 
climate and health benefits for families.

I. Review Under Executive Order 12630

    Pursuant to E.O. 12630, ``Governmental Actions and Interference 
with Constitutionally Protected Property Rights,'' 53 FR 8859 (March 
18, 1988), DOE has determined that this rule would not result in any 
takings that might require compensation under the Fifth Amendment to 
the U.S. Constitution.

J. Review Under the Treasury and General Government Appropriations Act, 
2001

    Section 515 of the Treasury and General Government Appropriations 
Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to 
review most disseminations of information to the public under 
information quality guidelines established by each agency pursuant to 
general guidelines issued by OMB. OMB's guidelines were published at 67 
FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 
62446 (Oct. 7, 2002). Pursuant to OMB Memorandum M-19-15, Improving 
Implementation of the Information Quality Act (April 24, 2019), DOE 
published updated guidelines which are available at www.energy.gov/sites/prod/files/2019/12/f70/DOE%20Final%20Updated%20IQA%20Guidelines%20Dec%202019.pdf. DOE has 
reviewed this final rule under the OMB and DOE guidelines and has 
concluded that it is consistent with applicable policies in those 
guidelines.

K. Review Under Executive Order 13211

    E.O. 13211, ``Actions Concerning Regulations That Significantly 
Affect Energy Supply, Distribution, or Use,'' 66 FR 28355 (May 22, 
2001), requires Federal agencies to prepare and submit to OIRA at OMB, 
a Statement of Energy Effects for any significant energy action. A 
``significant energy action'' is defined as any action by an agency 
that promulgates or is expected to lead to promulgation of a final 
rule, and that (1) is a significant regulatory action under Executive 
Order 12866, or any successor order; and (2) is likely to have a 
significant adverse effect on the supply, distribution, or use of 
energy, or (3) is designated by the Administrator of OIRA as a 
significant energy action. For any significant energy action, the 
agency must give a detailed statement of any adverse effects on energy 
supply, distribution, or use should the proposal be implemented, and of 
reasonable alternatives to the action and their expected benefits on 
energy supply, distribution, and use.
    DOE has concluded that this regulatory action, which sets forth 
amended energy conservation standards for distribution transformers, is 
not a significant energy action because the standards are not likely to 
have a significant adverse effect on the supply, distribution, or use 
of energy, nor has it been designated as such by the Administrator at 
OIRA. Accordingly, DOE has not prepared a Statement of Energy Effects 
on this final rule.

L. Information Quality

    On December 16, 2004, OMB, in consultation with the Office of 
Science and Technology Policy (OSTP), issued its Final Information 
Quality Bulletin for Peer Review (``the Bulletin''). 70 FR 2664 (Jan. 
14, 2005). The Bulletin establishes that certain scientific information 
shall be peer reviewed by qualified specialists before it is 
disseminated by the Federal Government, including influential 
scientific information related to agency regulatory actions. The 
purpose of the Bulletin is to enhance the quality and credibility of 
the Government's scientific information. Under the Bulletin, the energy 
conservation standards rulemaking analyses are ``influential scientific 
information,'' which the Bulletin defines as ``scientific information 
the agency reasonably can determine will have, or does have, a clear 
and substantial impact on important public policies or private sector 
decisions.'' 70 FR 2664, 2667.
    In response to OMB's Bulletin, DOE conducted formal peer reviews of 
the energy conservation standards development process and the analyses 
that are typically used and prepared a report describing that peer 
review.\206\ Generation of this report involved a rigorous, formal, and 
documented evaluation using objective criteria and qualified and 
independent reviewers to make a judgment as to the technical/
scientific/business merit, the actual or anticipated results, and the 
productivity and management effectiveness of programs and/or projects. 
Because available data, models, and technological understanding have 
changed since 2007, DOE has engaged with the National Academy of 
Sciences to review DOE's analytical methodologies to ascertain whether 
modifications are needed to improve DOE's analyses. DOE is in the 
process of evaluating the resulting report.\207\
---------------------------------------------------------------------------

    \206\ The 2007 ``Energy Conservation Standards Rulemaking Peer 
Review Report'' is available at the following website: energy.gov/eere/buildings/downloads/energy-conservation-standards-rulemaking-peer-review-report-0 (last accessed Jan. 16, 2024).
    \207\ The report is available at www.nationalacademies.org/our-work/review-of-methods-for-setting-building-and-equipment-performance-standards.
---------------------------------------------------------------------------

M. Congressional Notification

    As required by 5 U.S.C. 801, DOE will report to Congress on the 
promulgation of this rule prior to its effective date. The report will 
state that the Office of Information and Regulatory Affairs has 
determined that the rule meets the criteria set forth in 5 U.S.C. 
804(2).).

VII. Approval of the Office of the Secretary

    The Secretary of Energy has approved publication of this final 
rule.

List of Subjects in 10 CFR Part 431

    Administrative practice and procedure, Confidential business 
information, Energy conservation test procedures, Reporting and 
recordkeeping requirements.

Signing Authority

    This document of the Department of Energy was signed on April 3, 
2024, by Jeffrey Marootian, Principal Deputy Assistant Secretary for 
Energy Efficiency and Renewable Energy, pursuant to delegated authority 
from the Secretary of Energy. That document with the original signature 
and date is maintained by DOE. For administrative purposes only, and in 
compliance with requirements of the Office of the Federal Register, the 
undersigned DOE Federal Register Liaison Officer has been authorized to 
sign and submit the document in electronic format for publication, as 
an official document of the Department of Energy. This administrative 
process in no way alters the legal effect of this document upon 
publication in the Federal Register.

    Signed in Washington, DC, on April 4, 2024.
Treena V. Garrett,
Federal Register Liaison Officer, U.S. Department of Energy.
    For the reasons set forth in the preamble, DOE amends part 431 of 
chapter II, of title 10 of the Code of Federal Regulations, as set 
forth below:

[[Page 30039]]

PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND 
INDUSTRIAL EQUIPMENT

0
1. The authority citation for part 431 continues to read as follows:

    Authority:  42 U.S.C. 6291-6317; 28 U.S.C. 2461 note.


0
2. Amend Sec.  431.192 by:
0
a. Revising the definitions for ``Distribution transformer'', ``Drive 
(isolation) transformer'', ``Nonventilated transformer'', ``Sealed 
transformer'', and ``Special-impedance transformer'';
0
b. Adding in alphabetical order a definition for ``Submersible 
distribution transformer''; and
0
c. Revising the definitions for ``Transformer with a tap range of 20 
percent or more'' and ``Uninterruptible power supply transformer''.
    The revisions and addition read as follows:


Sec.  431.192   Definitions.

* * * * *
    Distribution transformer means a transformer that--
    (1) Has an input line voltage of 34.5 kV or less;
    (2) Has an output line voltage of 600 V or less;
    (3) Is rated for operation at a frequency of 60 Hz; and
    (4) Has a capacity of 10 kVA to 5000 kVA for liquid-immersed units 
and 15 kVA to 5000 kVA for dry-type units; but
    (5) The term ``distribution transformer'' does not include a 
transformer that is an--
    (i) Autotransformer;
    (ii) Drive (isolation) transformer;
    (iii) Grounding transformer;
    (iv) Machine-tool (control) transformer;
    (v) Nonventilated transformer;
    (vi) Rectifier transformer;
    (vii) Regulating transformer;
    (viii) Sealed transformer;
    (ix) Special-impedance transformer;
    (x) Testing transformer;
    (xi) Transformer with tap range of 20 percent or more;
    (xii) Uninterruptible power supply transformer; or
    (xiii) Welding transformer.
    Drive (isolation) transformer means a transformer that:
    (1) Isolates an electric motor from the line;
    (2) Accommodates the added loads of drive-created harmonics;
    (3) Is designed to withstand the additional mechanical 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''.
* * * * *
    Nonventilated transformer means a dry-type transformer constructed 
so as to prevent external air circulation through the coils of the 
transformer while operating at zero gauge pressure.
* * * * *
    Sealed transformer means a dry-type transformer designed to remain 
hermetically sealed under specified conditions of temperature and 
pressure.
    Special-impedance transformer means a transformer built to operate 
at an impedance outside of the normal impedance range for that 
transformer's kVA rating. The normal impedance range for each kVA 
rating for liquid-immersed and dry-type transformers is shown in Tables 
1 and 2, respectively.

                 Table 1 to the Definition o ``Special-Impedance Transformer''--Normal Impedance Ranges for Liquid-Immersed Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                          Single-phase transformers                                                    Three-phase transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Impedance (%)                               kVA                              Impedance (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                   10 <= kVA < 50                               1.0-4.5                         15 <= kVA < 75                               1.0-4.5
                  50 <= kVA < 250                               1.5-4.5                      75 <= kVA < 112.5                               1.0-5.0
                 250 <= kVA < 500                               1.5-6.0                     112.5 <= kVA < 500                               1.2-6.0
                 500 <= kVA < 667                               1.5-7.0                       500 <= kVA < 750                               1.5-7.0
                667 <= kVA <= 833                               5.0-7.5                     750 <= kVA <= 5000                               5.0-7.5
--------------------------------------------------------------------------------------------------------------------------------------------------------


                    Table 2 to the Definition o ``Special-Impedance Transformer''--Normal Impedance Ranges for Dry-Type Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                          Single-phase transformers                                                    Three-phase transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Impedance (%)                               kVA                              Impedance (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                   10 <= kVA < 50                               1.0-4.5                         15 <= kVA < 75                               1.0-4.5
                  50 <= kVA < 250                               1.5-4.5                      75 <= kVA < 112.5                               1.0-5.0
                 250 <= kVA < 500                               1.5-6.0                     112.5 <= kVA < 500                               1.2-6.0
                 500 <= kVA < 667                               1.5-7.0                       500 <= kVA < 750                               1.5-7.0
                667 <= kVA <= 833                               5.0-7.5                     750 <= kVA <= 5000                               5.0-7.5
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Submersible distribution transformer means 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.
* * * * *
    Transformer with tap range of 20 percent or more means 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.
    Uninterruptible power supply transformer means a transformer that 
is used within an uninterruptible power system, which in turn supplies 
power to

[[Page 30040]]

loads that are sensitive to power failure, power sages, over voltage, 
switching transients, line notice, and other power quality factors. It 
does not include distribution transformers at the input, output, or by-
pass of an uninterruptible power system.
* * * * *

0
3. Amend Sec.  431.196 by:
0
a. Revising paragraph (a)(2) and adding paragraph (a)(3);
0
b. Revising paragraph (b)(2) and adding paragraphs (b)(3) and (4);
0
c. Revising paragraph (c)(2) and adding paragraph (c)(3); and
0
d. Adding paragraph (e).
    The revisions and additions read as follows:


Sec.  431.196   Energy conservation standards and their effective 
dates.

    (a) * * *
    (2) The efficiency of a low-voltage, dry-type distribution 
transformer manufactured on or after January 1, 2016, but before April 
23, 2029, shall be no less than that required for the applicable kVA 
rating in the following table. Low-voltage dry-type distribution 
transformers with kVA ratings not appearing in the table shall have 
their minimum efficiency level determined by linear interpolation of 
the kVA and efficiency values immediately above and below that kVA 
rating.

                                                               Table 2 to Paragraph (a)(1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                                                                           kVA
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               15                                 97.70                                     15                                 97.89
                               25                                 98.00                                     30                                 98.23
                             37.5                                 98.20                                     45                                 98.40
                               50                                 98.30                                     75                                 98.60
                               75                                 98.50                                  112.5                                 98.74
                              100                                 98.60                                    150                                 98.83
                              167                                 98.70                                    225                                 98.94
                              250                                 98.80                                    300                                 99.02
                              333                                 98.90                                    500                                 99.14
                                                                                                           750                                 99.23
                                                                                                          1000                                 99.28
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
  of Distribution Transformers under appendix A to this subpart K.

    (3) The efficiency of a low-voltage dry-type distribution 
transformer manufactured on or after April 23, 2029, shall be no less 
than that required for their kVA rating in the following table. Low-
voltage dry-type distribution transformers with kVA ratings not 
appearing in the table shall have their minimum efficiency level 
determined by linear interpolation of the kVA and efficiency values 
immediately above and below that kVA rating.

                                                               Table 3 to Paragraph (a)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Efficiency (%)                              kVA                             Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               15                                 98.39                                     15                                 98.31
                               25                                 98.60                                     30                                 98.58
                             37.5                                 98.74                                     45                                 98.72
                               50                                 98.81                                     75                                 98.88
                               75                                 98.95                                  112.5                                 98.99
                              100                                 99.02                                    150                                 99.06
                              167                                 99.09                                    225                                 99.15
                              250                                 99.16                                    300                                 99.22
                              333                                 99.23                                    500                                 99.31
                                                                                                           750                                 99.38
                                                                                                          1000                                 99.42
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
  of Distribution Transformers under appendix A to this subpart K.

    (b) * * *
    (2) The efficiency of a liquid-immersed distribution transformer, 
including submersible distribution transformers, manufactured on or 
after January 1, 2016, but before April 23, 2029, shall be no less than 
that required for their kVA rating in the following table. Liquid-
immersed distribution transformers, including submersible distribution 
transformers, with kVA ratings not appearing in the table shall have 
their minimum efficiency level determined by linear interpolation of 
the kVA and efficiency values immediately above and below that kVA 
rating.

[[Page 30041]]



                                                               Table 5 to Paragraph (b)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Efficiency (%)                              kVA                             Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               10                                 98.70                                     15                                 98.65
                               15                                 98.82                                     30                                 98.83
                               25                                 98.95                                     45                                 98.92
                             37.5                                 99.05                                     75                                 99.03
                               50                                 99.11                                  112.5                                 99.11
                               75                                 99.19                                    150                                 99.16
                              100                                 99.25                                    225                                 99.23
                              167                                 99.33                                    300                                 99.27
                              250                                 99.39                                    500                                 99.35
                              333                                 99.43                                    750                                 99.40
                              500                                 99.49                                   1000                                 99.43
                              667                                 99.52                                   1500                                 99.48
                              833                                 99.55                                   2000                                 99.51
                                                                                                          2500                                 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test--Procedure, appendix A to this subpart K.

    (3) The efficiency of a liquid-immersed distribution transformer, 
that is not a submersible distribution transformer, manufactured on or 
after April 23, 2029, shall be no less than that required for their kVA 
rating in the following table. Liquid-immersed distribution 
transformers with kVA ratings not appearing in the table shall have 
their minimum efficiency level determined by linear interpolation of 
the kVA and efficiency values immediately above and below that kVA 
rating.

                                                               Table 6 to Paragraph (b)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Efficiency (%)                              kVA                             Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               10                                 98.77                                     15                                 98.92
                               15                                 98.88                                     30                                 99.06
                               25                                 99.00                                     45                                 99.14
                             37.5                                 99.10                                     75                                 99.22
                               50                                 99.15                                  112.5                                 99.29
                               75                                 99.23                                    150                                 99.33
                              100                                 99.29                                    225                                 99.38
                              167                                 99.46                                    300                                 99.42
                              250                                 99.51                                    500                                 99.38
                              333                                 99.54                                    750                                 99.43
                              500                                 99.59                                   1000                                 99.46
                              667                                 99.62                                   1500                                 99.51
                              833                                 99.64                                   2000                                 99.53
                                                                                                          2500                                 99.55
                                                                                                          3750                                 99.54
                                                                                                          5000                                 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
  of Distribution Transformers under appendix A to this subpart K.

    (4) The efficiency of a submersible distribution transformer, 
manufactured on or after April 23, 2029, shall be no less than that 
required for their kVA rating in the following table. Submersible 
distribution transformers with kVA ratings not appearing in the table 
shall have their minimum efficiency level determined by linear 
interpolation of the kVA and efficiency values immediately above and 
below that kVA rating.

                                                               Table 7 to Paragraph (b)(4)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                 kVA                               Efficiency (%)                              kVA                             Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                               10                                 98.70                                     15                                 98.65
                               15                                 98.82                                     30                                 98.83
                               25                                 98.95                                     45                                 98.92
                             37.5                                 99.05                                     75                                 99.03

[[Page 30042]]

 
                               50                                 99.11                                  112.5                                 99.11
                               75                                 99.19                                    150                                 99.16
                              100                                 99.25                                    225                                 99.23
                              167                                 99.33                                    300                                 99.27
                              250                                 99.39                                    500                                 99.35
                              333                                 99.43                                    750                                 99.40
                              500                                 99.49                                   1000                                 99.43
                              667                                 99.52                                   1500                                 99.48
                              833                                 99.55                                   2000                                 99.51
                                                                                                          2500                                 99.53
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test--Procedure, appendix A to this subpart K.

    (c) * * *
    (2) The efficiency of a medium-voltage dry-type distribution 
transformer manufactured on or after January 1, 2016, but before April 
23, 2029, shall be no less than that required for their kVA and BIL 
rating in the following table. Medium-voltage dry-type distribution 
transformers with kVA ratings not appearing in the table shall have 
their minimum efficiency level determined by linear interpolation of 
the kVA and efficiency values immediately above and below that kVA 
rating.

                                                               Table 9 to Paragraph (c)(2)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Single-phase                                                                 Three-phase
                   ----------------------------------------------------------                   --------------------------------------------------------
                                             BIL \1\                                                                       BIL
        kVA        ----------------------------------------------------------        kVA        --------------------------------------------------------
                         20-45 kV           46-95 kV            >=96 kV                               20-45 kV           46-95 kV           >=96 kV
                   ----------------------------------------------------------                   --------------------------------------------------------
                      Efficiency (%)     Efficiency (%)     Efficiency (%)                         Efficiency (%)     Efficiency (%)     Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
              15               98.10              97.86   ..................                15              97.50              97.18   .................
              25               98.33              98.12   ..................                30              97.90              97.63   .................
            37.5               98.49              98.30   ..................                45              98.10              97.86   .................
              50               98.60              98.42   ..................                75              98.33              98.13   .................
              75               98.73              98.57              98.53               112.5              98.52              98.36   .................
             100               98.82              98.67              98.63                 150              98.65              98.51   .................
             167               98.96              98.83              98.80                 225              98.82              98.69              98.57
             250               99.07              98.95              98.91                 300              98.93              98.81              98.69
             333               99.14              99.03              98.99                 500              99.09              98.99              98.89
             500               99.22              99.12              99.09                 750              99.21              99.12              99.02
             667               99.27              99.18              99.15                1000              99.28              99.20              99.11
             833               99.31              99.23              99.20                1500              99.37              99.30              99.21
                    .................  .................  ..................              2000              99.43              99.36              99.28
                    .................  .................  ..................              2500              99.47              99.41              99.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
  of Distribution Transformers under appendix A to this subpart K.

    (3) The efficiency of a medium-voltage dry-type distribution 
transformer manufactured on or after April 23, 2029, shall be no less 
than that required for their kVA and BIL rating in the following table. 
Medium-voltage dry-type distribution transformers with kVA ratings not 
appearing in the table shall have their minimum efficiency level 
determined by linear interpolation of the kVA and efficiency values 
immediately above and below that kVA rating.

                                                              Table 10 to Paragraph (c)(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Single-phase                                                                 Three-phase
                   ----------------------------------------------------------                   --------------------------------------------------------
                                             BIL \1\                                                                       BIL
        kVA        ----------------------------------------------------------        kVA        --------------------------------------------------------
                         20-45 kV           46-95 kV            >=96 kV                               20-45 kV           46-95 kV           >=96 kV
                   ----------------------------------------------------------                   --------------------------------------------------------
                      Efficiency (%)     Efficiency (%)     Efficiency (%)                         Efficiency (%)     Efficiency (%)     Efficiency (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
              15               98.29              98.07   ..................                15              97.75              97.46   .................

[[Page 30043]]

 
              25               98.50              98.31   ..................                30              98.11              97.87   .................
            37.5               98.64              98.47   ..................                45              98.29              98.07   .................
              50               98.74              98.58   ..................                75              98.50              98.32   .................
              75               98.86              98.71              98.68               112.5              98.67              98.52   .................
             100               98.94              98.80              98.77                 150              98.79              98.66   .................
             167               99.06              98.95              98.92                 225              98.94              98.82              98.71
             250               99.16              99.06              99.02                 300              99.04              98.93              98.82
             333               99.23              99.13              99.09                 500              99.18              99.09              99.00
             500               99.30              99.21              99.18                 750              99.29              99.21              99.12
             667               99.34              99.26              99.24                1000              99.35              99.28              99.20
             833               99.38              99.31              99.28                1500              99.43              99.37              99.29
                    .................  .................  ..................              2000              99.49              99.42              99.35
                    .................  .................  ..................              2500              99.52              99.47              99.40
                    .................  .................  ..................              3750              99.50              99.44              99.40
                    .................  .................  ..................              5000              99.48              99.43              99.39
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ BIL means basic impulse insulation level/
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption
  of Distribution Transformers under appendix A to this subpart K.

* * * * *
    (e) Severability. The provisions of paragraphs (a) through (d) of 
this section are separate and severable from one another. Should a 
court of competent jurisdiction hold any provision(s) of this section 
to be stayed or invalid, such action shall not affect any other 
provision of this section.

    Note:  The following letter will not appear in the Code of 
Federal Regulations.

U.S. DEPARTMENT OF JUSTICE
Antitrust Division
RFK Main Justice Building
950 Pennsylvania Avenue NW
Washington, DC 20530-0001

March 20, 2023

Ami Grace-Tardy
Assistant General Counsel for Legislation, Regulation and Energy 
Efficiency
U.S. Department of Energy
Washington, DC 20585
[email protected]

Re: Energy Conservation Standards for Distribution Transformers, DOE 
Docket No. EERE-2019-BT-STD-0018

Dear Assistant General Counsel Grace-Tardy:

    I am responding to your January 19, 2023 letter seeking the 
views of the Attorney General about the potential impact on 
competition of proposed energy conservation standards for 
distribution transformers.
    Your request was submitted under Section 325(o)(2)(B)(i)(V) of 
the Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C. 
6295(o)(2)(B)(i)(V), which requires the Attorney General to make a 
determination of the impact of any lessening of competition that is 
likely to result from the imposition of proposed energy conservation 
standards. The Attorney General's responsibility for responding to 
requests from other departments about the effect of a program on 
competition has been delegated to the Assistant Attorney General for 
the Antitrust Division in 28 CFR 0.40(g). The Assistant Attorney 
General for the Antitrust Division has authorized me, as the Policy 
Director for the Antitrust Division, to provide the Antitrust 
Division's views regarding the potential impact on competition of 
proposed energy conservation standards on his behalf.
    In conducting its analysis, the Antitrust Division examines 
whether a proposed standard may lessen competition, for example, by 
substantially limiting consumer choice, by placing certain 
manufacturers at an unjustified competitive disadvantage, or by 
inducing avoidable inefficiencies in production or distribution of 
particular products. A lessening of competition could result in 
higher prices to manufacturers and consumers.
    We have reviewed the proposed standards contained in the Notice 
of proposed rulemaking and request for comment (88 FR 1722, January 
11, 2023) and the related Technical Support Document. We have also 
reviewed public comments and information presented at the Webinar of 
the Public Meetings held on September 29, 2021 and February 16, 
2023.
    Based on this review, our conclusion is that the proposed energy 
conservation standards for distribution transformers are unlikely to 
have a significant adverse impact on competition.

Sincerely,
David G.B. Lawrence,
Policy Director.

[FR Doc. 2024-07480 Filed 4-19-24; 8:45 am]
BILLING CODE 6450-01-P