Energy Conservation Program: Energy Conservation Standards for Distribution Transformers

Federal RegisterApr 22, 2024

Ask Donna

What actually matters in this document.

Text

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.

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:

ApplianceStandardsQuestions@ee.doe.gov.

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:

ApplianceStandardsQuestions@ee.doe.gov.

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:

matthew.schneider@hq.doe.gov.

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

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),

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 the EPCA, 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 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))

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.

For editorial reasons, upon codification in the U.S. Code, Part B was redesignated Part A.

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.

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

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.

BILLING CODE 6450-01-P

ER22AP24.501

ER22AP24.502

ER22AP24.503

ER22AP24.504

BILLING CODE 6450-01-C

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).

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.

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).

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

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.

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.

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”).

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.

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)

of carbon dioxide (CO

), 12.29 thousand tons of sulfur dioxide (SO

), 89.85 thousand tons of nitrogen oxides (NO

), 416.15 thousand tons of methane (CH

), 0.40 thousand tons of nitrous oxide (N

O), and 0.08 tons of mercury (Hg).

A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO

are presented in short tons.

DOE calculated emissions reductions relative to the no-new-standards case, which reflects key assumptions in the

Annual Energy Outlook 2023

(

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 greenhouse gases (GHG) using four different estimates of the social cost of CO

(SC-CO

), the social cost of methane (SC-CH

), and the social cost of nitrous oxide (SC-N

O).

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).

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.

Estimated climate-related benefits are provided in compliance with Executive Order 12866.

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.

DOE estimated the monetary health benefits of SO

and NO

emissions reductions, using benefit-per-ton estimates from the Environmental Protection Agency,

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.

DOE is currently only monetizing health benefits from changes in ambient fine particulate matter (PM

2.5

) concentrations from two precursors (SO

and NO

), and from changes in ambient ozone from one precursor (NO

), but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM

2.5

emissions.

U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM

2.5

, PM

2.5

Precursors and Ozone Precursors from 21 Sectors. Available at

www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.

DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.

Table I.5 summarizes the monetized benefits and costs expected to result from the 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.

BILLING CODE 6450-01-P

ER22AP24.505

ER22AP24.506

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.

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 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.

Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.

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.6 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.

Using a 7-percent discount rate for consumer benefits and costs and NOx and SO

reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $151.1 million per year in increased equipment installed costs, while the estimated annual benefits are $210.2 million from reduced equipment operating costs, $106.1 million in GHG reductions, and $117.0 million from reduced NO

and SO

emissions. In this case, the net benefit amounts to $282.3 million per year.

Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $152.6 million per year in increased equipment costs, while the estimated annual benefits are $348.3 million in reduced operating costs, $106.1 million from GHG reductions, and $213.2 million from reduced NO

and SO

emissions. In this case, the net benefit amounts to $515.1 million per year.

BILLING CODE 6450-01-P

ER22AP24.507

ER22AP24.508

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.

This represents a savings of 35 percent relative to the energy use of these products in the no-new-standards case.

The quantity refers to FFC energy savings. FFC energy savings includes the energy consumed in extracting, processing, and transporting primary fuels (

i.e.,

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

of CO

, 7.49 thousand tons of SO

, 55.92 thousand tons of NO

, 259.96 thousand tons of CH

, 0.24 thousand tons of N

O, and 0.05 tons of Hg.

A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO

are presented in short tons.

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-CH

, and the SC-N

O. Together these represent the SC-GHG.

DOE

used interim SC-GHG values (in terms of benefit per ton of GHG avoided) developed by an IWG.

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.

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 SO

and NO

emissions reductions, using benefit per ton estimates from the Environmental Protection Agency,

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 $0.76 billion using a 7-percent discount rate, and $2.42 billion using a 3-percent discount rate.

DOE is currently only monetizing health benefits from changes in ambient PM

2.5

concentrations from two precursors (SO

and NO

), and from changes in ambient ozone from one precursor (for NO

), but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM

2.5

emissions.

U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM

2.5

, PM

2.5

Precursors and Ozone Precursors from 21 Sectors. Available at

www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.

DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.

Table I.7 summarizes the monetized benefits and costs expected to result from the amended standards for low-voltage dry-type distribution transformers. There are other important unquantified effects, including certain unquantified climate benefits, unquantified public health benefits from the reduction of toxic air pollutants and other emissions, unquantified energy security benefits, and distributional effects, among others.

BILLING CODE 6450-01-P

ER22AP24.509

ER22AP24.510

BILLING CODE 6450-01-C

e.g.,

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.

Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.

As discussed in section IV.L.1 of this document, DOE agrees with the IWG that using consumption-based discount rates

e.g.,

i.e.,

7 percent) is reasonable because of the different nature of the types of benefits being measured.

Table I.8 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.

Using a 7-percent discount rate for consumer benefits and costs and NOx and SO

reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for low-voltage dry-type is $66.6 million per year in increased equipment installed costs, while the estimated annual benefits are $286.8 million from reduced equipment operating costs, $70.4 million in GHG reductions, and $80.3 million from reduced NO

and SO

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 NO

and SO

emissions. In this case, the net benefit amounts to $593.0 million per year.

BILLING CODE 6450-01-P

ER22AP24.511

ER22AP24.512

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.

This represents a savings of 9 percent relative to the energy use of these products in the no-new-standards case.

The quantity refers to FFC energy savings. FFC energy savings includes the energy consumed in extracting, processing, and transporting primary fuels (

i.e.,

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

of CO

, 0.63 thousand tons of SO

, 4.69 thousand tons of NO

, 21.86 thousand tons of CH

, 0.02 thousand tons of N

O, and 0.00 tons of Hg.

A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO

are presented in short tons.

DOE calculated emissions reductions relative to the no-new-standards case, which reflects key assumptions in the

AEO2023. AEO2023

reflects, to the extent possible, laws and regulations adopted through mid-November 2022, including the Inflation Reduction Act.

See

section IV.K of this document for further discussion of

AEO2023

assumptions that affect air pollutant emissions.

DOE estimates the value of climate benefits from a reduction in GHG using four different estimates of the SC-CO

, the SC-CH

, and the SC-N

O. Together these represent the SC-GHG. DOE used interim SC-GHG values (in terms of benefit per ton of GHG avoided) developed by an IWG.

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.

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 SO

and NO

emissions reductions, using benefit per ton estimates from the Environmental Protection Agency,

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.

DOE is currently only monetizing health benefits from changes in ambient PM

2.5

concentrations from two precursors (SO

and NO

), and from changes in ambient ozone from one precursor (for NO

), but will continue to assess the ability to monetize other

effects such as health benefits from reductions in direct PM

2.5

emissions.

U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM

2.5

, PM

2.5

Precursors and Ozone Precursors from 21 Sectors. Available at

www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.

DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.

Table I.9 summarizes the monetized benefits and costs expected to result from the amended standards for medium-voltage dry-type distribution transformers. There are other important unquantified effects, including certain unquantified climate benefits, unquantified public health benefits from the reduction of toxic air pollutants and other emissions, unquantified energy security benefits, and distributional effects, among others.

BILLING CODE 6450-01-P

ER22AP24.513

ER22AP24.514

BILLING CODE 6450-01-C

e.g.,

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.

Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.

As discussed in section IV.L.1 of this document, DOE agrees with the IWG that using consumption-based discount rates

e.g.,

i.e.,

7 percent) is reasonable because of the different nature of the types of benefits being measured.

Table I.10 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.

Using a 7-percent discount rate for consumer benefits and costs and NO

and SO

reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for medium-voltage dry-type is $12.5 million per year in increased equipment installed costs, while the estimated annual benefits are $15.9 million from reduced equipment operating costs, $5.9 million in GHG reductions, and $6.7 million from reduced NO

and SO

emissions. In this case, the net benefit amounts to $16.0 million per year.

Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for medium-voltage dry-type distribution transformers is $12.7 million per year in increased equipment costs, while the estimated annual benefits are $25.1 million in reduced operating costs, $5.9 million from GHG reductions, and $11.7 million from reduced NO

and SO

emissions. In this case, the net benefit amounts to $29.9 million per year.

BILLING CODE 6450-01-P

ER22AP24.515

ER22AP24.516

BILLING CODE 6450-01-C

DOE's analysis of the national impacts of the adopted standards is described in sections IV.H, IV.K, and IV.L of this document.

D. Conclusion

DOE concludes that the standards adopted in this final rule represent the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in the significant conservation of energy. Specifically, with regards to technological feasibility, products are already commercially available which either achieve these standard levels or utilize the technologies required to achieve these standard levels for all product classes covered by this proposal. As for economic justification, DOE's analysis shows that the benefits of the standards exceed, to a great extent, the burdens of the standards.

Table I.11 shows the annualized values for all distribution transformers under amended standards, expressed in 2022$. The results under the primary estimate are as follows.

Using a 7-percent discount rate for consumer benefits and costs and NOx and SO

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,

and DOE would adopt the same standards in the absence of such benefits.

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.

Procedures, Interpretations, and Policies for Consideration in New or Revised Energy Conservation Standards and Test Procedures for Consumer Products and Commercial/Industrial Equipment, 86 FR 70892, 70901 (Dec. 13, 2021).

As previously mentioned, the standards are projected to result in estimated national energy savings of 4.58 quads full fuel cycle (FFC), the equivalent of the primary annual energy use of 49.2 million homes. In addition, they are projected to reduce cumulative CO

emissions by 85.27 Mt. Based on these findings, 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. 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.

BILLING CODE 6450-01-P

ER22AP24.517

ER22AP24.518

ER22AP24.519

ER22AP24.520

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,

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))

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

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.

BILLING CODE 6450-01-P

ER22AP24.521

ER22AP24.522

ER22AP24.523

BILLING CODE 6450-01-C

2. History of Standards Rulemaking for Distribution Transformers

On June 18, 2019, DOE published notice that it was initiating an early assessment review to determine whether any new or amended standards would satisfy the relevant requirements of EPCA for a new or amended energy conservation standard for distribution transformers and a request for information (RFI). 84 FR 28239 (“June 2019 Early Assessment Review RFI”).

On August 27, 2021, DOE published a notification of a webinar and availability of a preliminary technical support document (TSD), which announced the availability of its analysis for distribution transformers. 86 FR 48058 (“August 2021 Preliminary Analysis TSD”). The purpose of the August 2021 Preliminary Analysis TSD was to make publicly available the initial technical and economic analyses conducted for distribution transformers, and present initial results of those analyses. DOE did not propose new or amended standards for distribution transformers at that time. The initial TSD and accompanying analytical spreadsheets for the August 2021 Preliminary Analysis TSD provided the analyses DOE used to examine the potential for amending energy conservation standards for distribution transformers and provided preliminary discussions in response to a number of issues raised in comments to the June 2019 Early Assessment Review RFI. It described the analytical methodology that DOE used and each analysis DOE performed.

On January 11, 2023, DOE published a NOPR and public meeting announcement, in which DOE proposed amended energy conservation standards for distribution transformers. 88 FR 1722 (“January 2023 NOPR”). DOE proposed amended standards for liquid-immersed, low-voltage dry-type, and MVDT distribution transformers. DOE additionally proposed to establish a separate equipment class for submersible distribution transformers, with standards maintained at the levels prescribed by the April 2013 Standards Final Rule.

Id.

On February 16, 2023, DOE presented the proposed standards and accompanying analysis in a public meeting.

On February 22, 2023, DOE published a notice extending the comment period for the January 2023 NOPR by an additional 14 days. 88 FR 10856.

DOE received 93 comments in response to the January 2023 NOPR from the interested parties listed in Table II.4.

BILLING CODE 6450-01-P

ER22AP24.524

ER22AP24.525

ER22AP24.526

ER22AP24.527

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.

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.

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).

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

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.

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

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

ApplianceStandardsQuestions@ee.doe.gov.

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.

In many cases, the max-tech efficiency level is not commercially available because it is not currently economically feasible.

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.

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).

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.

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

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.

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.

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.

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.

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).

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

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.

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.”

As noted in the marketing, autotransformers are only suitable in transformer applications where load isolation is not required.

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.

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

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.

ER22AP24.528

ER22AP24.529

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)(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.

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”).

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.

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

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.

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.”

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

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.

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.

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.

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.

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.

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.

The European Union (EU) Ecodesign requirements also specify maximum load losses and maximum no-load losses for three-phase liquid-

immersed distribution transformers up to 3,150 kVA.

See NRCAN dry-type transformer energy efficiency regulations at

www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875.

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.

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)

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.

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.

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

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

) 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).

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.

ER22AP24.530

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

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 °C; (2) has insulation rated for a temperature rise of 65 °C; (3) has sealed-tank construction; and (4) has the tank, cover, and all external appurtenances made of corrosion-resistant material.”

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 °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

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 transfo

This text is long and has been trimmed here. Open the source document for the complete record.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.