51230 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

1All 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). 

2For editorial reasons, upon codification in the 

U.S. Code, Part B was redesignated Part A. 

3For editorial reasons, upon codification in the 

U.S. Code, Part C was redesignated Part A–1. 

DEPARTMENT OF ENERGY 

10 CFR Part 431 

[EERE–2017–BT–TP–0055] 

RIN 1904–AE19 

Energy Conservation Program: Test 

Procedure for Distribution 

Transformers 

AGENCY: Office of Energy Efficiency and 

Renewable Energy, Department of 

Energy. 

ACTION: Final rule. 

SUMMARY: The U.S. Department of 

Energy (‘‘DOE’’) is amending the test 

procedure for distribution transformers 

to revise and add definitions of certain 

terms, update provisions based on the 

latest versions of relevant industry 

testing standards, and to specify the 

basis for voluntary representations at 

additional per-unit loads and additional 

reference temperatures. The updates in 

this final rule will not significantly 

change the test procedure. 

DATES: The effective date of this rule is 

October 14, 2021. The final rule changes 

will be mandatory for product testing 

starting March 14, 2022. 

ADDRESSES: The docket, which includes 

Federal Register notices, comments, 

and other supporting documents/ 

materials, is available for review at 

www.regulations.gov. All documents in 

the docket are listed in the 

www.regulations.gov index. However, 

some documents listed in the index, 

such as those containing information 

that is exempt from public disclosure, 

may not be publicly available. 

A link to the docket web page can be 

found at www.regulations.gov/docket/ 

EERE-2017-BT-TP-0055. 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–2J, 1000 

Independence Avenue SW, Washington, 

DC 20585–0121. Telephone: (202) 586– 

9870. Email: 

ApplianceStandardsQuestions@

ee.doe.gov. 

Mr. Matthew Ring, U.S. Department of 

Energy, Office of the General Counsel, 

GC–33, 1000 Independence Avenue SW, 

Washington, DC 20585–0121. 

Telephone: (202) 586–2555. Email: 

matthew.ring@hq.doe.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Authority and Background 

A. Authority 

B. Background 

II. Synopsis of the Final Rule 

III. Discussion 

A. Scope of Applicability 

B. Updates to Industry Testing Standards 

1. Recission of NEMA TP 2 

2. Updates to IEEE Standards 

C. Definitions 

1. Rectifier Transformers and Drive 

Transformers 

2. New Definitions 

3. Updated Definitions 

D. Per-Unit Load Testing Requirements 

1. Multiple-PUL Weighted-Average 

Efficiency Metric 

2. Single-PUL Efficiency Metric 

3. Voluntary Representations of Efficiency 

at Additional PULs 

E. Multiple Voltage Capability 

F. Other Test Procedure Topics 

1. Per-Unit Load Specification 

2. Reference Temperature Specification 

3. Measurement Location 

4. Specification for Stabilization of Current 

and Voltage 

5. Ambient Temperature Tolerances 

6. Harmonic Current 

7. Other Editorial Revisions 

G. Effective and Compliance Dates 

H. Test Procedure Costs 

IV. Procedural Issues and Regulatory Review 

A. Review Under Executive Order 12866 

B. Review Under the Regulatory Flexibility 

Act 

C. Review Under the Paperwork Reduction 

Act of 1995 

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 Treasury and General 

Government Appropriations Act, 2001 

K. Review Under Executive Order 13211 

L. Review Under Section 32 of the Federal 

Energy Administration Act of 1974 

M. Congressional Notification 

V. Approval of the Office of the Secretary 

I. Authority and Background 

DOE is authorized to establish and 

amend energy conservation standards 

and test procedures for certain 

industrial equipment, including 

distribution transformers. The current 

DOE test procedure for distribution 

transformers appear at title 10 of the 

Code of Federal Regulations (‘‘CFR’’) 

431.193 and appendix A to subpart K of 

10 CFR part 431 (‘‘appendix A’’) 

respectively. The current energy 

conservation standards for distribution 

transformers appear at 10 CFR 431.196. 

The following sections discuss DOE’s 

authority to establish test procedures for 

distribution transformers and relevant 

background information regarding 

DOE’s consideration of test procedures 

for this equipment. 

A. Authority 

The Energy Policy and Conservation 

Act, as amended (‘‘EPCA’’),1 authorizes 

DOE to regulate the energy efficiency of 

a number of consumer products and 

certain industrial equipment. (42 U.S.C. 

6291–6317, as codified) Title III, Part B 2

of EPCA established the Energy 

Conservation Program for Consumer 

Products Other Than Automobiles (42 

U.S.C. 6291–6309, as codified), which 

sets forth a variety of provisions 

designed to improve energy efficiency of 

specified consumer products. Title III, 

Part C 3 of EPCA, added by the National 

Energy Conservation Policy Act, Public 

Law 95–619, Title IV, section 441(a), 

established the Energy Conservation 

Program for Certain Industrial 

Equipment (42 U.S.C. 6311–6317, as 

codified), which sets forth a variety of 

provisions designed to improve energy 

efficiency of certain industrial 

equipment. This equipment includes 

distribution transformers, the subject of 

this final rule. (42 U.S.C. 6317(a)) 

The energy conservation program 

under EPCA consists essentially of four 

parts: (1) Testing, (2) labeling, (3) 

Federal energy conservation standards, 

and (4) certification and enforcement 

procedures. Relevant provisions of 

EPCA for distribution transformers 

specifically include definitions (42 

U.S.C. 6291; 42 U.S.C. 6311), test 

procedures (42 U.S.C. 6293; 42 U.S.C. 

6317), labeling provisions (42 U.S.C. 

6294; 42 U.S.C. 6315), energy 

conservation standards (42 U.S.C. 6295; 

42 U.S.C. 6317), and the authority to 

require information and reports from 

manufacturers (42 U.S.C. 6296; 42 

U.S.C. 6316). 

The Federal testing requirements 

consist of test procedures that 

manufacturers of covered products and 

covered equipment must use as the 

basis for: (1) Certifying to DOE that their 

products or equipment comply with the 

applicable energy conservation 

standards adopted pursuant to EPCA (42 

U.S.C. 6295(s); 42 U.S.C. 6316(a)), and 

(2) making representations about the 

efficiency of those covered products or 


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4 DOE generally refers to distribution transformers 

as covered equipment. However, to the extent that 

DOE is discussing provisions of Part B of EPCA that 

are applicable to distribution transformers, 

‘‘covered product’’ is used. 

5 DOE published a technical correction to the 

April 2006 Final Rule to correct typographical 

errors. 71 FR 60662 (Oct. 16, 2006). 

covered equipment (42 U.S.C. 6293(c); 

42 U.S.C. 6314(d)). Similarly, DOE must 

use these test procedures to determine 

whether the products or equipment 

comply with relevant standards 

promulgated under EPCA. (42 U.S.C. 

6295(s); 42 U.S.C. 6316(a)) 

Federal energy efficiency 

requirements for covered products and 

covered equipment established under 

EPCA generally supersede State laws 

and regulations concerning energy 

conservation testing, labeling, and 

standards. (42 U.S.C. 6297; 42 U.S.C. 

6316(a) and (b)) DOE may, however, 

grant waivers of Federal preemption for 

particular State laws or regulations, in 

accordance with the procedures and 

other provisions of EPCA. (42 U.S.C. 

6297(d); 42 U.S.C. 6316(b)(2)(D)) 

EPCA set forth the criteria and 

procedures DOE must follow when 

prescribing or amending test procedures 

for covered products 4 and covered 

equipment, respectively. EPCA requires 

that any test procedures prescribed or 

amended under these sections be 

reasonably designed to produce test 

results which measure energy 

efficiency, energy use or estimated 

annual operating cost of a covered 

product during a representative average 

use cycle or period of use and not be 

unduly burdensome to conduct. (42 

U.S.C. 6293(b)(3); see also 42 U.S.C. 

6314(a)(2)) 

EPCA also requires that, at least once 

every 7 years, DOE evaluate test 

procedures for each type of covered 

product and covered equipment, 

including distribution transformers, to 

determine whether amended test 

procedures would more accurately or 

fully comply with the requirements for 

the test procedures to not be unduly 

burdensome to conduct and be 

reasonably designed to produce test 

results that reflect energy efficiency, 

energy use, and estimated operating 

costs during a representative average 

use cycle. (42 U.S.C. 6293(b)(1)(A); see 

also 42 U.S.C. 6314(a)(1)) 

If the Secretary determines, on her 

own behalf or in response to a petition 

by any interested person, that a test 

procedure should be prescribed or 

amended, the Secretary shall promptly 

publish in the Federal Register 

proposed test procedures and afford 

interested persons an opportunity to 

present oral and written data, views, 

and arguments with respect to such 

procedures. The comment period on a 

proposed rule to amend a test procedure 

shall be at least 60 days and may not 

exceed 270 days. In prescribing or 

amending a test procedure, the 

Secretary shall take into account such 

information as the Secretary determines 

relevant to such procedure, including 

technological developments relating to 

energy use or energy efficiency of the 

type (or class) of covered products or 

covered equipment involved. (42 U.S.C. 

6293(b)(2)) If DOE determines that test 

procedure revisions are not appropriate, 

DOE must publish its determination not 

to amend the test procedures. DOE is 

publishing this final rule in satisfaction 

of the 7-year review requirement 

specified in EPCA. (42 U.S.C. 

6293(b)(1)(A); see also 42 U.S.C. 

6314(b)(1)) 

DOE is issuing this final rule to 

amend the test procedure for 

distribution transformers in accordance 

with its statutory obligations. 

B. Background 

With respect to distribution 

transformers, EPCA states that the test 

procedures for distribution transformers 

shall be based on the ‘‘Standard Test 

Method for Measuring the Energy 

Consumption of Distribution 

Transformers’’ prescribed by the 

National Electrical Manufacturers 

Association (NEMA TP 2–1998). (42 

U.S.C. 6293(b)(10)(A)) Further, DOE 

may review and revise the DOE test 

procedure. (42 U.S.C. 6293(b)(10)(B)) 

Consistent with the requirements in 

EPCA, DOE published a final rule on 

April 27, 2006, that established the test 

procedure for distribution transformers 

based on the test methods in NEMA TP 

2–1998 and the test methods contained 

in the Institute of Electrical and 

Electronics Engineers (‘‘IEEE’’) 

Standards C57.12.90–1999 and 

C57.12.91–2001. 71 FR 24972, 24974. 

See 71 FR 24972 (April 27, 2006) 

(‘‘April 2006 Final Rule’’).5

In a final rule published on April 18, 

2013, amending the energy conservation 

energy conservation standards (‘‘ECS’’) 

for distribution transformers (‘‘April 

2013 ECS Final Rule’’), DOE determined 

that the test procedure did not require 

amendment at that time, concluding 

that the test procedure as established in 

the April 2006 Final Rule was 

reasonably designed to produce test 

results that reflect energy efficiency and 

energy use, as required by 42 U.S.C. 

6314(a)(2). 78 FR 23336, 23347–23348. 

The current test procedures for 

distribution transformers may be found 

in 10 CFR 431.193 and 10 CFR part 431, 

subpart K, appendix A. 

On September 22, 2017, DOE 

published a request for information 

(‘‘RFI’’) to collect data and information 

to inform its consideration of whether to 

amend DOE’s test procedure for 

distribution transformers (‘‘September 

2017 RFI’’). 82 FR 44347. After 

consideration of comments received in 

response to the September 2017 RFI, 

DOE published a notice of proposed 

rulemaking (‘‘NOPR’’) on May 10, 2019 

(‘‘May 2019 NOPR’’), presenting DOE’s 

proposals to amend the distribution 

transformer test procedure. 84 FR 

20704. 

DOE received comments in response 

to the May 2019 NOPR from the 

interested parties listed in Table I.1. 

TABLE I.1—WRITTEN COMMENTS RECEIVED IN RESPONSE TO MAY 2019 NOPR 

Organization(s) * Reference in 

this document Organization type 

Appliance Standards Awareness Project, American Council for an Energy-Efficient 

Economy, Natural Resources Defense Council.

Efficiency Advocates Efficiency Organizations. 

Cargill ........................................................................................................................... Cargill ...................... Insulating Liquid Manufacturer. 

Copper Development Association ............................................................................... CDA ........................ Trade Association. 

Howard Industries Inc .................................................................................................. Howard .................... Manufacturer. 

HVOLT Inc ................................................................................................................... HVOLT .................... Industry Consultant. 

National Electrical Manufacturers Association ............................................................ NEMA ...................... Trade Association. 

Pacific Gas & Electric Company ................................................................................. PG&E ...................... Electrical Utility. 

* This list includes only those commenters that provided comments relevant to the May 2019 NOPR. 


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6The parenthetical reference provides a reference 

for information located in the docket of DOE’s 

rulemaking to develop test procedures for 

distribution transformers. (Docket No. EERE–2017– 

BT–STD–0055, which is maintained at 

www.regulations.gov). The references are arranged 

as follows: (commenter name, comment docket ID 

number, page of that document). 

A parenthetical reference at the end of 

a comment quotation or paraphrase 

provides the location of the item in the 

public record.6

II. Synopsis of the Final Rule 

In this final rule, DOE amends 10 CFR 

431.192, 431.193, 431.196, and 

appendix A as follows: 

(1) Explicitly specify that the test 

procedure is applicable only to 

distribution transformers that are 

subject to energy conservation 

standards, 

(2) Include new definitions for ‘‘perunit load,’’ ‘‘terminal’’ and ‘‘auxiliary 

device,’’ and updated definitions for 

‘‘low-voltage dry-type distribution 

transformer’’ and ‘‘reference 

temperature,’’ 

(3) Reflect certain revisions from the 

latest version of the IEEE testing 

standards on which the DOE test 

procedure is based, 

(4) Incorporate other clarifying 

revisions based on review of the DOE 

test procedure, 

(5) Specify use of existing test 

procedure provisions for voluntary 

(optional) representations at additional 

per-unit loads (‘‘PULs’’) and reference 

temperatures, and 

(6) Centralize the PUL and reference 

temperature specifications for 

certification to energy conservation 

standards and for voluntary 

representations. 

The adopted amendments are 

summarized in Table II.1 compared to 

the test procedure provision prior to the 

amendment, as well as the reason for 

the adopted change. Table II.2 compares 

the changes adopted in this final rule to 

the proposal of the May 2019 NOPR. 

TABLE II.1—SUMMARY OF CHANGES IN THE AMENDED TEST PROCEDURE

DOE test procedure 

prior to amendment 

Amended test procedure 

(adopted by this final rule) Attribution 

Current test procedure does not specify scope States explicitly that the scope of the test procedure is limited to the scope of equipment 

subject to the energy conservation standards.

Clarification added by DOE. 

PUL is referred to as ‘‘percent load,’’ ‘‘percent 

of nameplate-rated load,’’ ‘‘percent of the 

rated load,’’ or ‘‘per unit load level’’.

Consolidates all terms to only ‘‘per-unit load’’ Improves consistency and readability of test 

procedure. 

Does not define ‘‘Per-unit load,’’ ‘‘Terminal’’ and 

‘‘Auxiliary device,’’ which are used in the current test procedure (TP).

Adds new definitions for ‘‘Per-unit load,’’ 

‘‘Terminal,’’ and ‘‘Auxiliary device’’.

Reflects industry testing standard definition 

(terminal) and clarification added by DOE 

(PUL and auxiliary device). 

Includes definition of ‘‘Low-Voltage Dry-Type 

Distribution Transformer’’.

Updates definition of ‘‘Low-Voltage Dry-Type 

Distribution Transformer’’.

Aligns with industry definition. 

Test procedure provisions are based on four 

IEEE testing standards, which contain general requirements and methods for performing tests: 

C57.12.00–2000. 

C57.12.01–1998. 

C57.12.90–1999. 

C57.12.91–2001. 

Updates provisions based on the latest 

version of the four IEEE testing standards: 

C57.12.00–2015. ......................................

C57.12.01–2020. ......................................

C57.12.90–2015. ......................................

C57.12.91–2020. ......................................

Reflects industry testing standard updates. 

Requires reporting performance at the rated 

frequency; however, the rated frequency is 

not explicitly defined.

States explicitly that all testing under the DOE 

test procedure is to occur only at 60 Hz.

Update to reflect industry testing standards. 

Requires determining winding resistance but 

does not specify whether the polarity of the 

core magnetization should be kept constant 

as measurements are made.

Specifies that the polarity of the core magnetization be kept constant during all resistance readings.Update to reflect industry testing standards. 

Requires the measurement of load and no-load 

loss, without explicitly specifying the connection locations for measurements.

Specifies explicitly that load and no-load loss 

measurements are required to be taken 

only at the transformer terminals.

Update to reflect industry testing standards. 

Testing with a sinusoidal waveform explicitly 

specified only for transformers designed for 

harmonic currents.

Specifies that all transformers must be tested 

using a sinusoidal waveform (not just those 

designed for harmonic current).

Update to reflect industry practice. 

Energy conservation standards require that efficiency be determined at a single PUL of 50 

percent for both liquid-immersed and medium-voltage dry type (MVDT) distribution 

transformers, and at 35 percent for low-voltage dry-type (LVDT) distribution transformers.

Permits voluntary representations of efficiency, load loss and no-load loss at additional PULs and/or reference temperature, 

using the DOE test procedure. (Does not 

require certification to DOE of any voluntary 

representations.) 

Response to industry comment. 

Specifies PUL and reference temperature specifications for certification to energy conservation standards in multiple locations throughout appendix A.Centralizes the PUL and reference temperature specifications, both for the certification 

to energy conservation standards and for 

use with a voluntary representation.

Improves readability of test procedure. 


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TABLE II.2—SUMMARY OF CHANGES—FINAL RULE RELATIVE TO MAY 2019 NOPR 

DOE test procedure 

prior to amendment NOPR proposal Final rule 

Current test procedure does not specify scope States explicitly that the scope of the test procedure is limited to the scope of equipment 

subject to the energy conservation standards.

Adopts modification as proposed. 

PUL is referred to as ‘‘percent load,’’ ‘‘percent 

of nameplate-rated load,’’ ‘‘percent of the 

rated load,’’ or ‘‘per unit load level’’.

Consolidates all terms to only ‘‘per-unit load.’’ Adopts modification as proposed. 

Does not define ‘‘Per-unit load,’’ ‘‘Terminal’’ and 

‘‘Auxiliary device,’’ which are used in the current TP.

Adds new definitions for ‘‘Per-unit load,’’ 

‘‘Terminal,’’ and ‘‘Auxiliary device.’’.

Adopts modification as proposed. 

Aligns definition of ‘‘Low-Voltage Dry-Type Distribution Transformer’’ with industry definition.Proposes updated definition of ‘‘Low-Voltage 

Dry-Type Distribution Transformer.’’.

Slight change from NOPR to align with industry definition. 

Test procedure provisions are based on four 

IEEE testing standards, which contain general requirements and methods for performing tests: 

C57.12.00–2000. 

C57.12.01–1998. 

C57.12.90–1999. 

C57.12.91–2001. 

Updates provisions based on the latest 

version of the four IEEE testing standards: 

C57.12.00–2015. 

C57.12.01–2015. 

C57.12.90–2015. 

C57.12.91–2011. 

Adopts modifications as proposed. Note that 

after NOPR publication, IEEE updated 

C57.12.91–2011 and C57.12.01–2015 to 

C57.12.91–2020 and C57.12.01–2020. The 

relevant provisions of C57.12.91–2020 and 

C57.12.01–2020 and the other two testing 

standards are unchanged. 

Automatic Recording of Data Not Required ....... Requires automatic recording of data, as required in IEEE C57.12.90–2015 and IEEE 

C57.12.91–2011, using a digital data acquisition system. (Appendix A, section 

4.4.2(b)).

NOPR proposal not adopted in this final rule. 

Requires reporting performance at the rated 

frequency; however, the rated frequency is 

not explicitly defined.

States explicitly that all testing under the DOE 

test procedure is to occur only at 60 Hz for 

resistance measurement and no-load loss 

test.

Adopted no-load loss test as proposed. 

NOPR proposal not adopted for resistance 

measurements. 

Requires determining winding resistance but 

does not specify whether the polarity of the 

core magnetization should be kept constant 

as measurements are made.

Specifies that the polarity of the core magnetization be kept constant during all resistance readings.Adopts modification as proposed. 

Requires the measurement of load and no-load 

loss, without explicitly specifying the connection locations for measurements.

Specifies explicitly that load and no-load loss 

measurements are required to be taken 

only at the transformer terminals.

Adopts modification as proposed. 

Testing with a sinusoidal waveform explicitly 

specified only for transformers designed for 

harmonic currents.

Specifies that all transformers must be tested 

using a sinusoidal waveform (not just those 

designed for harmonic current).

Adopts modification as proposed. 

Energy conservation standards require that efficiency be determined at a single PUL of 50 

percent for both liquid-immersed and MVDT 

distribution transformers, and at 35 percent 

for LVDT distribution transformers.

Permits voluntary representations of efficiency, load loss and no-load loss at additional PULs and/or reference temperature, 

using the DOE test procedure. (Does not 

require certification to DOE of any voluntary 

representations.) 

Adopts modification as proposed. 

Specifies PUL and reference temperature specifications for certification to energy conservation standards in multiple locations throughout appendix A.Centralizes the PUL and reference temperature specifications, both for the certification 

to energy conservation standards and for 

use with a voluntary representation.

No change from NOPR. 

DOE has determined that the 

amendments described in section III and 

adopted in this document will 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. Additionally, DOE has 

determined that the amendments will 

not increase the cost of testing. 

Discussion of DOE’s actions are 

addressed in detail in section III of this 

document. 

The effective date for the amended 

test procedure adopted in this final rule 

is 30 days after publication of this 

document in the Federal Register. 

Representations of energy use or energy 

efficiency must be based on testing in 

accordance with the amended test 

procedure beginning 180 days after the 

publication of this final rule. 

III. Discussion 

A. Scope of Applicability 

The applicability of the test procedure 

is provided in 10 CFR 431.193, which 

states that ‘‘the test procedures for 

measuring the energy efficiency of 

distribution transformers for purposes of 

EPCA are specified in appendix A to 

this subpart.’’ DOE has established 

energy conservation standards for lowvoltage dry-type (‘‘LVDT’’) distribution 

transformers, liquid-immersed 

distribution transformers, and mediumvoltage dry type (‘‘MVDT’’) distribution 

transformers at 10 CFR 431.196. In the 

May 2019 NOPR, DOE proposed to state 

explicitly that the scope of the test 

procedure is limited to the scope of the 

distribution transformers that are 

subject to energy conservation 

standards. 84 FR 20704, 20706. DOE did 

not receive any comments regarding this 

proposal. DOE is modifying text in 10 

CFR 431.193 regarding the scope of the 

test procedure as proposed. 


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51234 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

7Standard Test Method for Measuring the Energy 

Consumption of Distribution Transformers, 

available at: nema.org/Standards/Pages/StandardTest-Method-for-Measuring-the-EnergyConsumption-of-Distribution-Transformers.aspx. 

8Prior to the April 2006 Final Rule, NEMA 

provided the Department with its revised test 

procedure document (i.e., update to NEMA TP 2– 

1998), TP 2–2005. The Department treated this 

submission as a comment on DOE’s rulemaking to 

establish a distribution transformer test procedure. 

71 FR 24972, 24973. As such, the DOE test 

procedure incorporated a number of the changes 

that this revision made to the rule language and 

addressed the differences between the DOE test 

procedure and NEMA TP 2–2005. Id. 

B. Updates to Industry Testing 

Standards 

The current DOE test procedure for 

distribution transformers is based on 

provisions from the following industry 

testing standards (See 71 FR 24972, 

24982 (April 27, 2006)): 

• NEMA TP 2–1998, ‘‘Standard Test 

Method for Measuring the Energy 

Consumption of Distribution 

Transformers’’ (NEMA TP 2–1998) 

• IEEE C57.12.90–1999, ‘‘IEEE Standard 

Test Code for Liquid-Immersed 

Distribution, Power and Regulating 

Transformers and IEEE Guide for 

Short Circuit Testing of Distribution 

and Power Transformers’’ 

• IEEE C57.12.91–2001, ‘‘IEEE Standard 

Test Code for Dry-Type Distribution 

and Power Transformers’’ 

• IEEE C57.12.00–2000, ‘‘IEEE Standard 

General Requirements for LiquidImmersed Distribution, Power and 

Regulating Transformers’’ 

• IEEE C57.12.01–1998, ‘‘IEEE Standard 

General Requirements for Dry-Type 

Distribution and Power Transformers 

Including those with Solid Cast and/ 

or Resin Encapsulated Windings’’ 

In addition, the DOE test procedure is 

also based on provisions in NEMA TP 

2–2005,7 which in turn reference the 

aforementioned IEEE testing standards.8

DOE determined that basing the 

procedure on multiple industry testing 

standards, as opposed to adopting an 

industry test procedure (or procedures) 

without modification, was necessary to 

provide the detail and accuracy required 

for the Federal test procedure, with the 

additional benefit of providing 

manufacturers the Federal test 

procedure in a single reference. 71 FR 

24972, 24982 (April 27, 2006). 

DOE previously sought comment on 

the benefits and burdens of adopting 

industry testing standards without 

modification. 82 FR 44347, 44351 (Sep. 

22, 2017). NEMA commented generally 

that there is benefit but that DOE should 

limit the reference to the measurement 

of losses and retain DOE’s existing 

calculation for efficiency. (NEMA, 

Docket No. EERE–2017–BT–TP–0055– 

0014 p. 9) DOE stated in the May 2019 

NOPR that the current test procedure is 

already based on industry testing 

standards and that if DOE were to adopt 

an industry testing standard without 

modification, the resulting changes 

could require manufacturers to retest 

and recertify, because such an 

incorporation by reference would 

require updating a majority of the 

current test procedure. 84 FR 20704, 

20710. For these reasons, DOE did not 

propose to incorporate industry testing 

standard into its test procedure for 

distribution transformers. Id. 

NEMA further commented that while 

the existing test procedure is adequate, 

for high volume units the test 

procedures found in IEEE C57.12.90– 

2015 and IEEE C.57.12.91–2011 are less 

burdensome and recommended that 

DOE allow them as equivalent 

alternatives for the purposes of testing 

and certification. (NEMA, No. 30 at p. 

5) As discussed, DOE’s test procedure is 

partially based on the IEEE testing 

standards, and there are similarities 

between the DOE test procedure and the 

IEEE testing standards. There are also 

minor differences between the DOE test 

procedure and the IEEE testing 

standards, such as DOE’s requirement to 

test multiple-voltage-capable 

distribution transformers in the highest 

losses configuration (appendix A, 

sections 4.5.1(b) and 5.0), as discussed 

in section III.E. Testing according to the 

IEEE test procedures without 

modification could result in distribution 

transformers being tested at different 

conditions depending on the method 

used. Therefore, DOE is not permitting 

use of IEEE testing standards as 

equivalent alternatives. DOE may 

consider referencing sections of the 

IEEE test procedures as equivalent in 

the future if there is sufficient data and 

information that doing so would result 

in equivalent measured efficiency 

values with the DOE test procedure. 

1. Recission of NEMA TP 2 

As discussed, EPCA requires that DOE 

base the test procedure on NEMA TP 2– 

1998. (42 U.S.C. 6293(b)(10)(A)) Also as 

discussed, the DOE test procedure is 

based on (but does not incorporate by 

reference directly) NEMA TP 2–1998, 

NEMA TP 2–2005, as well as four IEEE 

standards that are referenced in NEMA 

TP 2–2005, i.e., IEEE.C57.12.00, IEEE 

C57.12.01, IEEE C57.12.90 and IEEE 

C57.12.91. See 71 FR 24972, 24982 

(April 27, 2006). As discussed in the 

following section, updates have been 

made to the IEEE testing standards. 

Since publication of the April 2006 

Final Rule, NEMA TP 2–2005 has been 

rescinded and superseded in industry 

by the IEEE standards. DOE has 

evaluated the provisions in the Federal 

test procedure that are based on NEMA 

TP 2 and, as discussed in the May 2019 

NOPR, has determined that these 

provisions remain appropriate for 

testing distribution transformers. DOE 

did not receive any comments on these 

provisions in the May 2019 NOPR and 

therefore maintained them in this final 

rule. 

2. Updates to IEEE Standards 

a. Background 

As discussed in section III.B, the DOE 

test procedure mirrors four widely used 

IEEE testing standards. Since the April 

2006 Final Rule, all of the four IEEE 

standards have been updated. 

In the May 2019 NOPR, DOE 

proposed updating certain Federal test 

procedure provisions to reflect the 

following updated versions of the 

relevant IEEE testing standards: IEEE 

C57.12.90–2015, IEEE C57.12.91–2011, 

IEEE C57.12.00–2015, and IEEE 

C57.12.01–2015. Since publication of 

the May 2019 NOPR, IEEE issued a 

further update to standard IEEE 

C57.12.91 (IEEE C57.12.91–2020) and 

IEEE C57.12.01–2015 (IEEE C57.12.01– 

2020). Table III.1 provides a list of old 

and new versions of each of these IEEE 

testing standards. 


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TABLE III.1—IEEE INDUSTRY TESTING STANDARDS VERSIONS AND SUMMARY

IEEE standard 

Version on which 

DOE test 

procedure prior 

to amendment 

is based 

(year) 

Most recent 

IEEE revision 

version 

(year) 

Content 

C57.12.00 ......... 2000 2015 General electrical and mechanical requirements for liquid-immersed distribution transformers. 

C57.12.01 ......... 1998 2020 General electrical and mechanical requirements for dry-type distribution transformers. 

C57.12.90 ......... 1999 2015 Methods for performing tests specified in C57.12.00 and others for liquid-immersed distribution transformers. 

C57.12.91 ......... 2001 2020 Methods for performing tests specified in C57.12.01 and others for dry-type distribution 

transformers. 

b. General Updates 

For the May 2019 NOPR, DOE 

reviewed the then most current editions 

of the relevant IEEE testing standards to 

determine whether any of the updates 

from the previously considered versions 

warranted proposed amendments to the 

DOE test procedure. The four IEEE 

testing standards are not relevant to the 

DOE test procedure in their entirety, as 

they include specifications and test 

methods beyond those required to 

measure efficiency, such as test methods 

for polarity, phase-relation, dielectric, 

and audible sound-level. DOE 

performed the review as follows: 

(1) DOE identified the sections of the 

IEEE testing standards that form the 

basis of the DOE test procedure, 

(2) DOE compared those sections 

between the old and the then current 

versions of the IEEE testing standards, 

and 

(3) DOE initially determined which of 

the changes were editorial versus which 

represented potential substantive 

improvements to the test method. 

In IEEE C57.12.90–2015 and IEEE 

C57.12.91–2011, sections 5, 8, and 9 

provide the resistance measurements, 

the no-load loss test, and the load loss 

test, respectively, which provide the 

basis for the DOE test procedure. In 

general, DOE did not identify major 

changes in sections 5, 8, and 9 between 

1999 and 2015 editions of IEEE 

C57.12.90–2015, or between the 2001 

and 2011 editions of IEEE C57.12.91– 

2011. Since the May 2019 NOPR, DOE 

has reviewed the updated IEEE 

C57.12.91–2020 test procedure and 

concluded that there were no 

substantive differences between the 

relevant provisions in the 2011 and 

2020 versions. 

The IEEE C57.12.00 and IEEE 

C57.12.01 testing standards include 

general electrical and mechanical 

requirements for the test methods for 

liquid-immersed and dry-type 

distribution transformers, in IEEE 

C57.12.90 and IEEE C57.12.91, 

respectively. In IEEE C57.12.00 and 

IEEE C57.12.01, section 9 and section 5, 

respectively, provide accuracy 

requirements for conducting the 

resistance measurements, the no-load 

loss test, and the load loss test. The 

primary change DOE identified in the 

accuracy requirements between the 

2000 and 1998 standards and the 2015 

standards was a slight relaxation of the 

temperature system accuracy 

requirement, from ±1 °C in the older 

versions to ±1.5 °C for liquid-immersed 

distribution transformers and ±2 °C for 

medium-voltage dry-type distribution 

transformers and low-voltage dry-type 

distribution transformers. Since the May 

2019 NOPR, DOE has reviewed the 

updated IEEE C57.12.91–2020 test 

procedure and concluded that there 

were no substantive differences between 

the relevant provisions in the 2015 and 

2020 versions. 

In the May 2019 NOPR, DOE 

proposed a series of updates based on 

the then most recent updates to the 

relevant IEEE testing standards. 84 FR 

20704, 20711. DOE stated the proposed 

updates reflect current industry 

practice, and as such, would not change 

current measured values. Id. DOE 

further stated that providing additional 

specificity consistent with the updates 

would improve the repeatability of the 

test procedure. Id. DOE requested 

comment on the proposed changes to 

reflect the updates to the relevant IEEE 

testing standards. Id. 

DOE received comments from 

Howard, NEMA, CDA, and HVOLT 

agreeing that the proposed updates are 

already industry practice and would not 

change any values or increase testing 

costs for manufacturers. (Howard, No. 

32 at p.1; NEMA, No. 20 at p. 3; CDA, 

No. 29 at p. 2; HVOLT, No. 27 at p. 91) 

Based on its review of the updates to 

the relevant IEEE testing standards and 

following consideration of the 

comments, DOE is adopting the 

proposed updates and clarifications, 

with two exceptions, discussed below. 

c. Automatic Recording of Data 

In the May 2019 NOPR, DOE 

proposed to require automatic recording 

of data using a digital data acquisition 

system at appendix A, section 4.4.2(b), 

in an attempt to align with industry 

standards. 84 FR 20704, 20711. NEMA 

commented that the proposed 

requirement to automatically record 

data using a digital data acquisition 

system is listed in IEEE C57.12.90–2015 

and C57.12.91–2020 for making 

resistance measurements by the 

voltmeter-ammeter method, and not for 

the no-load loss measurements as was 

proposed in the May 2019 NOPR. 

(NEMA, No. 30 at p. 3) NEMA 

commented that requiring automatic 

recording of data using a digital data 

acquisition system for the no-load losses 

could require some labs to upgrade test 

equipment, as not all power analyzers 

have this capability. Id. 

DOE acknowledges that IEEE 

C57.12.90–2015 and C57.12.91–2020 

both cite using digital data acquisition 

systems for making resistance 

measurements by the voltmeterammeter method and not for no-load 

losses, as was proposed. In an effort to 

remain aligned with the industry testing 

standard IEEE C57.12.90–2015 and 

C57.12.91–2020 no-load loss test, DOE 

has not adopted the proposal to require 

automatic recording of data using a 

digital data acquisition system. DOE is 

maintaining the current specification in 

section 4.4.2(b) of appendix A that 

requires recording data ‘‘as close to 

simultaneously as possible.’’ 

d. Test Frequency 

In the May 2019 TP NOPR, DOE 

proposed to require testing under the 

DOE test procedure to occur only at 60 

Hz in appendix A, sections 3.1(c) and 

4.1, in order to align with the industry 

testing standard and provide clarity on 

the frequency of the test current. 84 FR 

20704, 20711. 

NEMA commented that there was an 

error in the proposed language of 


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9A rectifier is an electrical device for converting 

alternating current to direct current. 

section 3.1(c) of Appendix A, stating 

that the proposed regulatory text should 

read ‘‘Measure resistance with the 

transformer energized by a DC supply’’ 

rather than with a 60 Hz supply as was 

proposed in the May 2019 NOPR. 

(NEMA, No. 30 at p. 5) DOE concurs 

with NEMA that the 60 Hz supply 

frequency is not applicable to the 

resistance measurement section of the 

test procedure, only to the loss 

measurement sections. The proposed 

addition of section 3.1(c) of appendix A, 

was an error. Resistance measurements 

are already stated as being a ‘‘direct 

current resistance’’ measurement in 

appendix A, section 3.1(b). Therefore, 

DOE is not adopting section 3.1(c) of 

appendix A as was proposed in the May 

2019 NOPR. 

The proposed language clarifying the 

‘‘Test Frequency’’ provision in appendix 

A, section 4.1, is aligned with the 

industry standard to test at the ‘‘rated 

frequency,’’ which by the definition of 

distribution transformer at 10 CFR 

431.192 is 60Hz. Therefore, this 

proposed addition remains appropriate. 

DOE did not receive any comment in 

opposition to its proposal to clarify that 

appendix A, section 4.1, is to be 

conducted with a 60 Hz frequency 

current. Therefore, DOE is adopting the 

change as proposed to section 4.1. 

e. Summary of Updates Adopted in This 

Final Rule 

Table III.2 summarizes proposed 

updates to the relevant IEEE testing 

standards that are adopted in this final 

rule. As summarized previously, DOE 

received comments from industry trade 

organizations and individual 

manufacturers indicating that the 

proposed updates are already industry 

practice and would not change any 

values or increase testing costs for 

manufacturers. (Howard, No. 32 at p. 1; 

NEMA, No. 30 at p. 3; CDA, No. 29 at 

p. 2; HVOLT, No. 27 at p. 91) As such, 

DOE has determined that the following 

amendments reflect current industry 

practice and provide additional 

specificity that will improve the 

repeatability of the test procedure. 

TABLE III.2—IEEE-BASED UPDATES ADOPTED IN THIS FINAL RULE

Topic Updates based on IEEE standards 

Consolidating the Terms ‘‘Oil,’’ ‘‘Transformer Liquid,’’ and ‘‘Insulating 

Liquid’’.

Replace the term ‘‘oil’’ and ‘‘transformer liquid’’ with ‘‘insulating liquid’’ 

in Appendix A to reflect that the term is inclusive of all insulating liquids, including those identified in IEEE C57.12.90–2015. 

Stability Requirement for Resistance Measurement ................................ Specify, consistent with IEEE C57.12.90–2015, that resistance measurements are considered stable if the top insulating liquid temperature does not vary more than 2 °C in a one-hour period. (Appendix 

A, section 3.2.1.2(b)) 

Temperature Test System Accuracy ........................................................ Relax the temperature test system accuracy requirements to be within 

±1.5 °C for liquid-immersed distribution transformers, and ±2.0 °C for 

MVDT and LVDT distribution transformers, as specified in IEEE 

C57.12.00–2015 and IEEE C57.12.01–2020, respectively. (Appendix 

A, section 2.0) 

Limits for Voltmeter-Ammeter Method ..................................................... Permit use of the voltmeter-ammeter method when the rated current of 

the winding is less than or equal to 1 A. Neither IEEE C57.12.90– 

2015 nor IEEE C57.12.91–2020 restrict usage of this method to certain current ranges. (Appendix A, section 3.3.2(a)) 

Number of Readings Required for Resistance Measurement ................. Include the requirement that a minimum of four readings for current 

and voltage must be used for each resistance measurement, as 

specified in IEEE C57.12.90–2015. (Appendix A, section 3.3.2(b)) 

Connection Locations for Resistance Measurements .............................. Add resistance measurement specifications for single-phase windings, 

wye windings and delta windings, as provided in section 5.4.1 and 

5.4.2 of IEEE C57.12.90–2015, and sections 5.6.1 through 5.6.3 of 

IEEE C57.12.91–2020. (Appendix A, section 3.4.1(g)–(i)) 

Test Frequency ......................................................................................... Require that all testing under the DOE test procedure is to occur only 

at 60 Hz. (Appendix A, section 4.1) 

Polarity of Core Magnetization ................................................................. Require that the polarity of the core magnetization be kept constant 

during all resistance readings. (Appendix A, section 3.4.1(f)) 

C. Definitions 

Definitions pertaining to distribution 

transformers are provided at 10 CFR 

431.192. The following sections discuss 

new and amended definitions 

established in this final rule. 

1. Rectifier Transformers and Drive 

Transformers 

DOE defines rectifier transformer as a 

transformer that operates at the 

fundamental frequency of an 

alternating-current system and that is 

designed to have one or more output 

windings connected to a rectifier.9 10 

CFR 431.192. 

DOE defines 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. The parenthetical 

inclusion of the term ‘‘isolation’’ 

indicates that the defined term includes 

only isolation transformers and not 

other transformers that may be 

described as ‘‘drive transformers’’ in the 

industry but which do not satisfy all 

three criteria specified in the definition 

of drive (isolation) transformer. 

Both rectifier transformers and drive 

transformers are among the exclusions 

to the term ‘‘distribution transformer’’ at 

10 CFR 431.192 and 42 U.S.C. 

6293(35)(B)(ii). Because both rectifier 

transformers and drive transformers are 

not classified as distribution 

transformers, they are not subject to the 

energy conservation standards at 10 CFR 

431.196. 


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10 IEEE C57.12.80–2010 is currently listed as 

‘‘inactive-reserved’’ which means that this standard 

is ‘‘. . . removed from active status through an 

administrative process for standards that have not 

undergone a revision process within 10 years.’’ (See 

Continued 

Although rectifier transformers and 

drive transformers are defined 

differently, they typically share features. 

As discussed in the May 2019 NOPR, 

both are isolation transformers (i.e., not 

autotransformers); both are typically 

exposed to (and must tolerate) 

significant harmonic content created 

from the drive or power supply; and 

both are likely to include design 

features enabling them to bear 

mechanical stress resulting from rapid 

current changes that may arise from 

operation of motors and other industrial 

equipment. 84 FR 207054, 20708. 

In response to the September 2017 

RFI, Babanna Suresh (‘‘Suresh’’) 

commented that it could be argued that 

most distribution-type transformers 

meet the present definition of the terms 

‘‘rectifier transformer’’ or ‘‘drive 

transformer’’ and suggested that those 

terms be removed from the list of 

exclusions to the term ‘‘distribution 

transformer.’’ (Suresh, Docket No. 

EERE–2017–BT–TP–0055, No. 9 at p. 1) 

Suresh further suggested that the 

definition of ‘‘rectifier transformer’’ be 

limited to transformers that supply 

loads that are composed of at least 75 

percent power electronics. Id. 

In the May 2019 NOPR, DOE stated 

that the definition of ‘‘rectifier 

transformer’’ is not intended to cover a 

large number of transformers intended 

for general power service; and that 

linking the definition to a percentage of 

supply load from power electronics 

would be insufficient to designate a 

distribution transformer because it may 

not be possible for a manufacturer to 

know in advance what fraction of a 

distribution transformer’s load will 

include power electronics. 84 FR 

207054, 20708. Based on further review 

of industry testing standards and 

available manufacturer literature, DOE 

further stated that it was unable to 

identify physical attributes that could be 

used to reliably identify rectifier 

transformers. Id. 

DOE requested comment on whether 

the current definitions of rectifier 

transformer and drive transformer are 

sufficiently specific; the level of 

technical similarity between the two 

types of transformers; and whether any 

physical or electrical properties could 

be used to reliably identify rectifier 

transformers. 

DOE received written comments from 

CDA and HVOLT stating that defining 

rectifier transformers as having multiple 

output windings could be a reasonable 

addition. (CDA, No. 29 at p.1; HVOLT 

No. 27 at p. 89) DOE notes that the 

current definition already specifies that 

rectifier transformers can have ‘‘one or 

more’’ output windings. 10 CFR 

431.192. 

CDA and HVOLT also stated that 

small drive transformers could meet 

energy conservations standards, but that 

larger drive transformers are more 

complicated and would have a more 

difficult time meeting standards. (CDA, 

No. 29 at p.1–2; HVOLT No. 27 at p. 89) 

While smaller drive transformers may 

be able to meet energy conservation 

standards, the statutory definition for 

distribution transformer excludes any 

transformer that is designed to be used 

in a special purpose applications and is 

unlikely to be used in general purpose 

applications, and specifies drive 

transformers as such an example. 42 

U.S.C. 6291(35)(b)(ii). 

NEMA commented that the current 

definition for both rectifier transformer 

and drive transformer are sufficient. 

(NEMA, No. 30 at p.2). 

Having considered these comments 

from interested parties, DOE remains 

unaware of any industry definition or 

physical features that would better 

define either rectifier transformers or 

drive transformers. 

Therefore, DOE makes no changes to 

the definitions of ‘‘rectifier transformer’’ 

and ‘‘drive transformer’’ in this final 

rule. Both varieties of equipment remain 

excluded from energy conservation 

standards and are therefore excluded 

from the scope of the test procedure (in 

accordance with the amendment 

discussed in section III.A of this final 

rule specifying that the scope of the test 

procedure is limited to the scope of the 

distribution transformers that are 

subject to energy conservation 

standards). However, as stated in the 

April 2006 Final Rule, DOE narrowly 

construes the exclusions from the 

definition of ‘‘distribution transformer.’’ 

DOE will also take appropriate steps, 

including enforcement action if 

necessary, if any manufacturer or other 

party erroneously invokes one of the 

exclusions as a basis for marketing a 

transformer that is a ‘‘distribution 

transformer,’’ but does not meet DOE 

standards. Moreover, to the extent 

transformers that do fall within the 

exclusions begin to be marketed for 

standard distribution applications, or 

find widespread use in such 

applications, DOE will examine whether 

re-defining the relevant exclusions is 

warranted. See 71 FR 24979. 

2. New Definitions 

In the May 2019 NOPR, DOE 

proposed and sought comment on 

definitions for the terms ‘‘per-unit 

load,’’ ‘‘terminal,’’ and ‘‘auxiliary 

device.’’ 84 FR 20704, 20708–20709. 

These terms are referenced in the DOE 

test procedure but are not currently 

defined in the regulatory text. The 

following sections discuss comments 

received regarding each of these terms 

and the definitions established in this 

final rule. 

a. Per-Unit Load 

Distribution transformers are regularly 

operated at capacities other than the 

capacity listed on a distribution 

transformer’s nameplate (i.e., the rated 

load). In general, distribution 

transformers are loaded substantially 

below their rated load. DOE’s current 

test procedure and energy conservation 

standards for distribution transformers 

use various terms to refer to operating 

or testing a distribution transformer at a 

capacity other than the rated load, 

including ‘‘percent load,’’ ‘‘percent of 

nameplate-rated load,’’ ‘‘percent of the 

rated load,’’ or ‘‘per unit load level.’’ 10 

CFR 431.192, 10 CFR 431.196, and 

appendix A. DOE proposed to 

consolidate the usage of these various 

terms into a single term, ‘‘per-unit load’’ 

(‘‘PUL’’) in all instances identified. 84 

FR 20704, 20709. DOE also proposed to 

define ‘‘per-unit load’’ to mean the 

fraction of rated load. Id. 

Howard, CDA, and HVOLT supported 

the proposed term per-unit load. 

(Howard, No. 32 at p.1; CDA, No. 29 at 

p.2; HVOLT, No. 27 at p. 89) DOE did 

not receive any comments against its 

proposed definition for per-unit load or 

its proposal to consolidate all references 

to partial loading into a single per-unit 

load term. In order to improve the 

readability of the test procedure, DOE is 

adopting the proposed definition for 

per-unit load at 10 CFR 431.192. DOE is 

also consolidating all references to 

partial load operation in 10 CFR 

431.192, 10 CFR 431.196, and appendix 

A to the defined ‘‘per-unit load’’ term. 

b. Terminal 

In the May 2019 NOPR, DOE 

proposed to clarify that load and noload loss measurements should be taken 

only at the distribution transformer 

terminals, as discussed in section III.F.3. 

As such, DOE proposed to define 

‘‘terminal’’ to mean ‘‘a conducting 

element of a distribution transformer 

providing electrical connection to an 

external conductor that is not part of the 

transformer.’’ 84 FR 20704, 20709. This 

definition is based on, but not identical 

to, the definition for ‘‘terminal’’ in IEEE 

C57.12.80–2010,10 ‘‘IEEE Standard 


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www.standard.iee.org). Given that the standard has 

not been superseded and is not listed as inactivewithdrawn, DOE is continuing to consider it the 

current industry standard on standard terminology 

for power and distribution transformers. 

Terminology for Power and Distribution 

Transformers.’’ IEEE C57.12.80–2010 

defines terminal as ‘‘(A) A conducting 

element of an equipment or a circuit 

intended for connection to an external 

conductor. (B) A device attached to a 

conductor to facilitate connection with 

another conductor.’’ 

Howard commented in agreement 

with the proposed definition. (Howard, 

No. 32 at p.1) NEMA, CDA and HVOLT 

preferred DOE to adopt the IEEE 

C57.12.80–2010 definition of ‘‘terminal’’ 

directly. (NEMA, No. 30 at p. 2; CDA, 

No. 29 at p. 2; HVOLT, No. 27 at p. 90). 

DOE has reviewed the IEEE definition 

and while part ‘‘(A)’’ is similar to the 

definition proposed in the May 2019 

NOPR, part ‘‘(B)’’ does not clarify that 

the terminal needs to be external. While 

adoption of industry-developed 

language would promote further 

consistency between the DOE test 

procedure and the industry testing 

standards, DOE is concerned that the 

IEEE definition could be understood to 

exclude busbar losses in testing of 

distribution transformers because part 

(B) of the IEEE definition does not 

specify that a terminal is for connection 

to an external conductor. A 

manufacturer could interpret terminal to 

be any conducting element within the 

distribution transformer, including a 

conducting element between the busbar 

and the windings. As a result, DOE is 

adopting the definition of ‘‘terminal’’ 

proposed in the May 2019 NOPR at 10 

CFR 431.192 as ‘‘a conducting element 

of a distribution transformer providing 

electrical connection to an external 

conductor that is not part of the 

transformer.’’ 

c. Auxiliary Device 

Section 4.5.3.1.2 of appendix A 

specifies that during testing, ‘‘measured 

losses attributable to auxiliary devices 

(e.g., circuit breakers, fuses, switches) 

installed in the transformer, if any, that 

are not part of the winding and core 

assembly, may be excluded from load 

losses measured during testing.’’ DOE 

has received inquiries from 

manufacturers regarding whether 

certain other internal components of 

distribution transformers are required 

by the DOE test procedure to be 

included in the loss calculation, or 

whether they are considered an 

auxiliary device. In the May 2019 

NOPR, DOE proposed to address the 

prior industry questions and establish a 

definition of the term ‘‘auxiliary device’’ 

based on a specific list of all 

components and/or component 

functions that would be considered 

auxiliary devices and, therefore, be 

optionally excluded from measurement 

of load loss during testing. 84 FR 20704, 

20709. 

The auxiliary device examples listed 

at section 4.5.3.1.2 of appendix A 

(circuit breakers, fuses, and switches) all 

provide protective function, but do not 

directly aid the transformer’s core 

function of supplying electrical power. 

Additionally, the term ‘‘device’’ 

indicates a localized nature, rather than 

a diffuse system or property of the 

transformer. 

DOE proposed to define ‘‘auxiliary 

device’’ to mean ‘‘a localized 

component of a distribution transformer 

that is a circuit breaker, switch, fuse, or 

surge/lightning arrester.’’ DOE requested 

comment on the proposed definition, if 

any components needed to be added or 

removed from the listed auxiliary 

devices, and whether it is appropriate to 

include functional component 

designations as part of a definition. Id. 

CDA and HVOLT stated that the 

proposed definition was adequate. 

(CDA, No. 29 at p.2; HVOLT, No. 27 at 

p. 90) Howard commented that the four 

components listed are sufficient and a 

functional designation is not needed. 

(Howard, No. 32 at p.1) NEMA 

commented that the current definitions 

are adequate and that it is not necessary 

to define auxiliary device. (NEMA, No. 

39 at p.2) NEMA did not specify what, 

if any, aspects of the proposed 

definition would be inadequate. 

Moreover, prior inquiries from industry 

indicate that the definition of ‘‘auxiliary 

device’’ would benefit from further 

detail. DOE did not receive any 

comment suggesting that the proposed 

definition is inadequate. DOE is 

adopting the definition of auxiliary 

device in this final rule as proposed. 

3. Updated Definitions 

a. Low-Voltage Dry-Type Distribution 

Transformer 

EPCA defines a ‘‘low-voltage dry-type 

distribution transformer’’ as ‘‘a 

distribution transformer that—(1) Has 

an input voltage of 600 volts or less; (2) 

is air-cooled; and (3) does not use oil as 

a coolant.’’ 42 U.S.C. 6291(38). 

In the May 2019 NOPR, DOE 

proposed to update the definition for 

‘‘low-voltage dry-type distribution 

transformer’’ by replacing the term ‘‘oil’’ 

with ‘‘insulating liquid’’ within the 

definition, in conjunction with DOE’s 

proposal to consolidate multiple terms 

to ‘‘insulating liquid,’’ as described in 

section III.B.2. 84 FR 20704, 20709. DOE 

proposed this update to reflect that the 

term is inclusive of all insulating 

liquids, including those identified in 

IEEE C57.12.90–2015. Id. 

Howard, CDA, and HVOLT generally 

supported using the broader term 

‘‘insulating liquid’’ rather than ‘‘oil.’’ 

(Howard, No. 32 at p. 1; CDA, No. 29 

at p. 2; HVOLT, No. 27 at p.91) NEMA 

recommended harmonizing the 

definition with the definition provided 

in IEEE C57.12.80–2010. (NEMA, No. 30 

at p. 3) IEEE defines a ‘‘low-voltage drytype distribution transformer’’ to mean 

‘‘a distribution transformer that—(1) Has 

an input voltage of 600 volts or less; (2) 

Has the core and coil assembly 

immersed in a gaseous or drycompound insulating medium.’’ 

Of the three components of EPCA’s 

definition of ‘‘low-voltage dry-type 

distribution transformer’’, the first 

component (‘‘Has an input voltage of 

600 volts or less’’) was not proposed for 

revision by either the May 2019 NOPR 

or by commenters. 42 U.S.C. 6291(38). 

This first component of the definition is 

left unchanged by this final rule. 

Whereas the first component of the 

definition addresses the ‘‘low-voltage’’ 

portion of term ‘‘low-voltage dry-type 

distribution transformer’’, the second 

and third components (‘‘is air-cooled’’; 

‘‘does not use oil as a coolant’’) combine 

to describe the manner in which LVDTs 

dissipate heat and collectively address 

the ‘‘dry-type’’ portion of the term. The 

comment from NEMA (suggesting that 

DOE amend the definition to reference 

the core and coil assembly being 

‘‘immersed in a gaseous or drycompound insulating medium’’) 

indicates that industry generally 

considers the descriptors ‘‘air cooled; 

does not use oil as a coolant’’ to be 

synonymous with ‘‘immersed in a 

gaseous or dry-compound insulating 

medium.’’ The revision suggested by 

NEMA would also be consistent with 

DOE’s terminology for addressing ‘‘dry 

type’’ in the definition of ‘‘mediumvoltage dry-type distribution 

transformer’’, which DOE defines as a 

distribution transformer in which the 

core and coil assembly is immersed in 

a gaseous or dry-compound insulating 

medium, and which has a rated primary 

voltage between 601 V and 34.5 kV. 10 

CFR 431.192. 

After further consideration of the May 

2019 NOPR proposal, and consideration 

of comments from interested parties in 

response to that proposal, this final rule 

revises the definition of ‘‘low-voltage 

dry-type distribution transformer’’ to 

mean ‘‘a distribution transformer that 

has an input voltage of 600 volts or less 

and has the core and coil assembly 

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Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 51239 

11 In the May 2019 NOPR, DOE used the term 

‘‘test PUL’’ to refer to ‘‘standard PUL’’ as used in 

this final rule. The term ‘‘standard PUL’’ better 

reflects that this is referring to the PUL at which 

the energy efficiency must be determined for the 

purpose of complying with the energy conservation 

standards at 10 CFR 431.196. As described 

previously in this document, testing can be 

performed at any PUL, with the results corrected to 

the standard PUL. 

compound insulating medium.’’ This 

revised wording harmonizes with the 

industry definition and implements 

consistent terminology across both 

varieties of dry-type distribution 

transformers (i.e., low-voltage and 

medium-voltage). 

b. Reference Temperature 

The reference temperature is the 

temperature at which the transformer 

losses must be determined, and to 

which such losses must be corrected if 

testing is performed at a different 

temperature. As currently defined at 10 

CFR 431.192, ‘‘reference temperature’’ 

means 20 °C for no-load loss, 55 °C for 

load loss of liquid-immersed 

distribution transformers at 50 percent 

load, and 75 °C for load loss of both 

low-voltage and medium-voltage drytype distribution transformers, at 35 

percent load and 50 percent load, 

respectively. 

In the May 2019 NOPR, DOE 

proposed to update the definition for 

‘‘reference temperature’’ by removing 

references to the numerical temperature 

values required for certification with 

energy conservation standards. 84 FR 

20704, 20709. DOE proposed to retain 

the conceptual definition of reference 

temperature and to include in appendix 

A the numerical temperature values for 

certification with energy conservation 

standards. The updated definition 

would allow use of the term reference 

temperature outside the context of 

conditions required for certification 

with energy conservation standards (i.e., 

voluntary representations at additional 

temperature values, as described in 

section III.D.2.b). DOE proposed 

‘‘reference temperature’’ to mean the 

temperature at which the transformer 

losses are determined, and to which 

such losses must be corrected if testing 

is performed at a different temperature. 

Howard and NEMA both supported 

the updated definition. (Howard, No. 32 

at p. 1; NEMA, No. 30 at p. 3). 

CDA and HVOLT commented that the 

reference temperature for ambient has 

been used throughout the industry as 20 

ßC and that letting that number float to 

other reference temperatures would be 

confusing to industry. (CDA, No. 29 at 

p. 2; HVOLT, No. 27 at p. 91). 

The reference temperature in the test 

procedure does not necessarily refer to 

the ambient temperature, because 

testing can be performed at a different 

temperature, with the results corrected 

to reflect testing at the defined reference 

temperature. DOE did not propose 

changes to any of these values for the 

purpose of certification with energy 

conservation standards. 

The updated definition does not 

specify particular temperature values in 

order to accommodate the use of the 

term in a context other than only the 

conditions required for certification and 

compliance, i.e., voluntary 

representations of efficiency at 

temperatures or PULs different from 

those specified in appendix A. For 

example, a manufacturer voluntarily 

representing efficiency at 100 percent 

PUL would correct to a reference 

temperature that is reflective of the 

distribution transformer temperature 

rise at 100 percent PUL. 

DOE is adopting the updated 

definition of ‘‘reference temperature’’ in 

10 CFR 431.192 as proposed. 

D. Per-Unit Load Testing Requirements 

The efficiency of distribution 

transformers varies depending on the 

PUL at which the distribution 

transformer is operated. DOE’s energy 

conservation standards for distribution 

transformers at 10 CFR 431.196 

prescribe the PUL at which the 

efficiency of the distribution 

transformer must be determined and 

certified to DOE (i.e., the ‘‘standard 

PUL’’). The standard PUL is intended to 

represent the typical PUL experienced 

by in-service distribution transformers 

over their lifetime. For liquid-immersed 

distribution transformers and mediumvoltage dry-type distribution 

transformers, the equipment efficiency 

is certified at a standard PUL of 50 

percent. For low-voltage dry-type 

distribution transformers, the efficiency 

is certified at a standard PUL of 35 

percent. These values were adopted in 

the April 2006 Final Rule from NEMA 

TP 2–1998. 71 FR 24972. 

As described previously, appendix A 

does not require testing of the 

distribution transformer at the standard 

PUL; rather, the standard PUL is 

required only for certification of 

efficiency. Testing can be performed at 

any PUL, with the results 

mathematically adjusted to reflect the 

applicable standard PUL. Section 5.1 of 

appendix A provides equations to 

calculate the efficiency of a distribution 

transformer at any PUL based on the 

testing of the distribution transformer at 

a single PUL. Current industry practice 

is to test at 100 percent PUL and 

mathematically determine the efficiency 

at the applicable standard PUL. (NEMA, 

No. 30 at p. 4). 

The efficiency of distribution 

transformers over the duration of its 

lifetime and across all installations 

cannot be fully represented by a single 

PUL. A given transformer may be highly 

loaded or lightly loaded depending on 

its application or variation in electrical 

demand throughout the day. DOE has 

previously acknowledged that 

distribution transformers may 

experience a range of loading levels 

when installed in the field. 78 FR 

23336, 23350 (April 18, 2013). 

DOE previously acknowledged that 

the majority of stakeholders, including 

manufacturers and utilities, support 

retention of the current testing 

requirements; and DOE determined that 

its existing test procedure provides 

results that are representative of the 

performance of distribution 

transformers in normal use. Id. DOE 

further determined that potential 

improvements in testing precision that 

might result from testing at multiple 

PULs would be outweighed by the 

complexity and the burden of requiring 

testing at different loadings depending 

on each individual transformer’s 

characteristics. Id. 

In the May 2019 NOPR, DOE stated 

that it had considered (1) revising the 

single standard PUL 11 to a multiplePUL weighted-average efficiency metric, 

(2) revising the single standard PUL to 

an alternative single test PUL metric 

that better represents in-service PUL, or 

(3) maintaining the current single test 

PUL specifications. 84 FR 20704, 20714. 

DOE tentatively determined that the 

range of in-service PUL is diverse, and 

that the available information describing 

in-service PUL is inconclusive. Id. DOE 

was unable to show that any alternative 

standard PUL(s) would be more 

representative than the current standard 

PUL and therefore did not propose an 

amendment of the standard PULs. Id. 

DOE proposed, however, to allow for 

voluntary representations to be made at 

PULs other than the standard PUL. Id. 

The following sections summarize 

comments received on each of these 

considerations, as well as DOE’s 

responses and conclusions. 

1. Multiple-PUL Weighted-Average 

Efficiency Metric 

In the past, DOE has considered a 

multiple-PUL efficiency metric in 

contemplating whether a weightedaverage efficiency metric composed of 

efficiency at more than one PUL may 

better reflect how distribution 

transformers operate in service. 84 FR 

20704, 20713. In the May 2019 NOPR, 

DOE expressed concern that a multiVerDate Sep<11>2014 20:08 Sep 13, 2021 Jkt 253001 PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 E:\FR\FM\14SER2.SGM 14SER2

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51240 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

12Specified as a set of any number of pairs of PUL 

values and weighting coefficient at that PUL. 

13 DOE determined in the April 2013 ECS Final 

Rule as having an average lifespan of 32 years, and 

in many cases they may have an in-service lifetime 

that is significantly longer. 78 FR 23336, 23377. 

14See: Section 2.3 of Chapter 2. Analytical 

Framework, Comments from Interested Parties, and 

DOE Responses of the Prelim Technical Support 

Document (TSD) at Docket No. EERE–2019–BT– 

STD–0018–0022. 

15See: grouper.ieee.org/groups/transformers/ 

subcommittees/distr/EnergyEfficiency/F20- 

DistrTransfLoading-Mulkey.pdf. 

PUL metric could increase burden on 

manufacturers and create challenges in 

consumer education without being more 

representative of in-service PULs than 

the current metric. Id. 

The Efficiency Advocates suggested 

that DOE request transformer loading 

data from IEEE’s Transformer 

Committee to analyze the empirical data 

describing PUL variation. (Efficiency 

Advocates, No. 34 at p. 2) The 

Efficiency Advocates, asserted that the 

IEEE data shows a wide variation in 

PUL and that DOE should consider a 

weighted average PUL efficiency metric 

in the DOE test procedure. (Efficiency 

Advocates, No. 34 at p. 2). 

DOE has considered a metric based on 

a weighted average of a transformer’s 

efficiency at multiple different PULs. 

Different weighting schemes are 

possible. For example, the measured 

efficiencies could be weighted by the 

fraction of operating hours expected at 

each PUL over the lifecycle of a 

distribution transformer. 

Generally, distribution transformer 

losses are presented within the industry 

as consisting of no-load losses, which 

are approximately constant with PUL, 

and load losses, which scale nearly 

quadratically with PUL. Under that set 

of mathematical assumptions, any 

particular multi-PUL metric 12 could 

alternatively be represented by a singlePUL metric that would yield the same 

efficiency value. In other words, any 

multi-PUL metric would be replaceable 

by a certain single-PUL metric. Given 

this, DOE finds no advantage in 

adopting a multi-PUL metric for 

distribution transformers. A multi-PUL 

metric would represent a slightly more 

complex way of arriving at the same 

result that could be derived from a 

carefully chosen single-PUL metric. As 

a result, DOE is not adopting a multiPUL metric for distribution transformers 

in this final rule. 

2. Single-PUL Efficiency Metric 

As stated previously, DOE requires 

distribution transformers’ efficiency to 

be certified at a standard PUL of 50 

percent for liquid-immersed distribution 

transformers and medium-voltage drytype distribution transformers and 35 

percent for low-voltage dry-type 

distribution transformers. 10 CFR 

431.196. 

In the May 2019 NOPR, DOE stated 

that it had considered revising the 

single standard PUL to an alternative 

single test PUL that better represents inservice PUL. 84 FR 20704, 20714. DOE 

tentatively determined that the range of 

in-service PUL values is diverse, and 

that the available information describing 

in-service PUL is inconclusive. Id. DOE 

was unable to conclude that any 

alternative standard PUL(s) would be 

more representative than the current 

standard PUL and, therefore, did not 

propose to amendment the standard 

PULs. Id. 

In response to the May 2019 NOPR, 

DOE received comments arguing both 

for and against revising the single-PUL 

metric; these are discussed in detail in 

sections III.D.2.a and III.D.2.b. These 

comments comport with the idea that 

distribution transformers’ in-service 

PULs reflect diverse operating 

conditions. After considering the 

comments brought forward by 

stakeholders and discussed in sections 

III.D.2.a and III.D.2.b. DOE has 

concluded that revising the PUL is not 

justified at this time for two reasons. 

First, there is significant long-term 

uncertainty regarding what standard 

PUL would correspond to a 

representative average use cycle for a 

distribution transformer given their long 

lifetimes.13 The publicly available data 

effectively amounts to a single year from 

a few distribution transformer 

customers. Given the uncertainty 

associated with future distribution 

transformer loading, DOE is unable to 

conclude with certainty that a given 

alternative single-PUL efficiency metric 

is more representative than the current 

standard PUL. 

Second, given the uncertainty of 

future loading distributions, there may 

be greater risk in selecting too low a 

standard PUL than too high a standard 

PUL for two reasons. First, the quadratic 

nature of load loss means that absolute 

power consumption grows more quickly 

on the high side of the standard PUL 

than on the low side. Second, 

divergence of the costs associated with 

different categories of loss means that 

there is greater risk associated with 

selecting too low a standard PUL than 

too high. 

Accordingly, in this final rule, DOE is 

maintaining the current standard PUL 

specifications. DOE is centralizing the 

PUL specifications in appendix A, as 

discussed in section III.F.1. 

DOE considered several factors in 

determining not to revise the current 

standard PUL requirements in this final 

rule. In section III.D.2.a, DOE reviews 

publicly available in-service PUL data. 

In sections III.D.2.b and III.D.2.c, DOE 

considers uncertainty in estimates of 

future load growth, its effects on 

distribution transformers’ in-service 

PULs, and the respective risks 

associated with both under- and 

overestimating actual future in-service 

PULs.14

a. Publicly Available Transformer Load 

Data 

In response to the May 2019 NOPR, 

the Efficiency Advocates suggested that 

DOE use IEEE’s Advanced Meter 

Information (‘‘AMI’’) data to inform the 

PUL rulemaking. (Efficiency Advocates, 

No. 34 at p. 1) Citing IEEE’s Distribution 

Transformer Subcommittee Task Force’s 

(‘‘IEEE–TF’’) estimates of average inservice PUL for medium-voltage, liquidfilled transformers, the Efficiency 

Advocates suggest in-service PULs are 

significantly lower than the current 

standard PULs. (Efficiency Advocates, 

No. 34 at p. 2) The Efficiency Advocates 

recommend, if DOE does not base its 

analysis on AMI data, that DOE use PUL 

values of 35 percent for liquidimmersed transformers, 25 percent for 

low-voltage dry-type distribution 

transformers, and 38 percent for 

medium-voltage dry-type distribution 

transformers. (Efficiency Advocates, No. 

34, at pp. 2–3). 

Cargill commented that the IEEE–TF 

data suggests average annual loading is 

less than 30 percent of the ‘‘Peak 

Annual Load’’. (Cargill, No. 28 at p. 1) 

Cargill stated that even in the most 

conservative case of peak load equaling 

nameplate load, the resulting average 

PUL would be less than 30 percent. 

(Cargill No. 28 at p. 1) NEMA 

commented that it is not aware of any 

changes in the field that would justify 

modifying the current PUL levels. 

(NEMA, No. 30 at p. 4). 

DOE examined the data made 

available through IEEE–TF.15 All of the 

data available through the IEEE–TF is 

for liquid-immersed distribution 

transformers; DOE did not separately 

receive updated loading data for LVDTs 

or MVDTs. 

DOE has identified several limitations 

and questions regarding the data made 

available through the IEEE–TF. First and 

foremost, none of the datasets of AMI 

data referred to by the Efficiency 

Advocates are measured transformer 

loads, rather they are samples of 

customer load connected to specific 

transformers. Additionally, each dataset 


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Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 51241 

16 J. Triplett, S. Rinell and J. Foote, ‘‘Evaluating 

distribution system losses using data from deployed 

AMI and GIS systems,’’ 2010 IEEE Rural Electric 

Power Conference (REPC), 2010, pp. C1–8, doi: 

10.1109/REPCON.2010.5476204. 

17Zip codes were used to aggregate customer AMI 

data to anonymize the data. 

18See: Chapter 7. Energy Use Analysis of the 

Prelim TSD at Docket No. EERE–2019–BT–STD– 

0018–0022. 

presented during the IEEE–TF is a 

sample of customers’ AMI data (i.e., not 

a complete population of distribution 

transformer load data), and each carries 

questions regarding the sampling 

methodology, representativeness, and 

completeness. DOE does not know what 

criteria were used to select the sample 

from each existing population of utility 

customers. Further, each data set was 

also incomplete in terms of missing 

meter readings, non-sequential metering 

periods, or missing unmetered loads (for 

example, exterior building lighting, 

utility owned equipment, and street 

lighting are usually on separate 

unmetered tariffs 16). These unmetered 

loads, on separate unmetered tariffs, 

would not be accounted for in the AMI 

data, and would produce the effect of 

underestimating in-service PUL for a 

given transformer. 

DOE examined the largest individual 

sample of data, from Dominion Energy, 

Inc., which consisted of a year of hourly 

and sub-hourly readings for roughly 

60,000 AMI meters connected to 

distribution transformers aggregated 

into zip codes for parts of Virginia and 

North Carolina.17 After removing data 

from AMI meters that were incomplete, 

or that had the quality issues 

highlighted in the presentation to the 

IEEE–TF (loads with peak-loads that 

were several times higher than the 

connected transformers capacity), DOE 

found that the average root mean square 

(RMS) load, as a function of transformer 

nameplate capacity, over the year in 

question (2018) was substantially higher 

than the 10 percent mode value 

presented to the IEEE–TF. DOE found 

that average RMS in-service PUL for the 

transformers subject to the DOE test 

procedure and energy conservation 

standards was 27.8 percent.18

After reviewing the IEEE–TF AMI 

data, DOE agrees with the Efficiency 

Advocates and Cargill that the current 

data indicates that the average, current, 

in-service, liquid-immersed distribution 

transformer loading is lower than the 

standard PUL. However, the data also 

indicates that distribution transformers 

operate over a diverse range of operating 

conditions. The data shows that a single 

customer does not operate a distribution 

transformer at a single constant PUL. 

Further, a given distribution transformer 

model may be used at different PULs by 

different customers. The realities of the 

typical range of operations, and issues 

of data quality and sample completeness 

raise uncertainties regarding the 

representativeness of the average PUL 

values presented by the IEEE–TF. 

DOE also notes that while the IEEE– 

TF AMI data provides valuable insight 

into the in-service PUL of liquidimmersed distribution transformers, no 

equivalent, publicly available data has 

been presented for medium-voltage and 

low-voltage dry-type distribution 

transformers. 

Another complicating factor in the 

representativeness of the currently 

available data is that the IEEE–TF AMI 

data only covers a single year of 

distribution transformer lifespans. 

Distribution transformers have lifespans 

of several decades and as such, DOE 

needs to consider not only the diversity 

of operating conditions that distribution 

transformer currently experience but the 

entire range of operating conditions a 

distribution transformer would 

experience in its lifespan. Additionally, 

most of the available data are from 

similar geographies, on the Atlantic 

coast, which would experience similar 

climatic sensitivities, which is not 

representative of the Nation as a whole. 

Stakeholders identified several possible 

factors that could significantly impact 

distribution transformer loading in the 

short to medium term, as discussed in 

section III.D.2.b. 

b. Load Growth Uncertainties 

DOE received several comments from 

stakeholders in response to the May 

2019 NOPR on the topic of future load 

growth on distribution transformers. 

Cargill supported maintaining the 

current standard PUL, asserting that as 

future transformer loads increase, 

increased transformer efficiency could 

be realized due to conventional core 

steel having a peak efficiency between 

45 and 55 percent PUL. (Cargill, No. 28 

at p. 1) Cargill also suggested that 

utilities are increasingly considering 

overloading transformers during peak 

demand with the objective of replacing 

larger mineral-oil-filled transformers 

with smaller, cheaper transformers. 

Such an approach, Cargill asserts, could 

increase average loading to 50 percent 

and support retaining the current 

standard PULs. (Cargill, No. 28 at p. 2) 

The Efficiency Advocates commented 

that increased adoption of photovoltaic 

generation (‘‘PV’’) will depress peak 

demand, as it has done in California. 

The Efficiency Advocates also 

commented that increasing adoption of 

electric vehicles (‘‘EVs’’) is unlikely to 

contribute to peak demand and load 

growth because it is in utilities’ interest 

to encourage off-peak charging. 

(Efficiency Advocates, No. 34 at p. 3) 

Further, the Efficiency Advocates 

recommended against DOE’s continued 

use of a 1 percent average annual 

increase, claiming that based on past 

experience and future projections, load 

growth of this magnitude is unlikely. 

(Efficiency Advocates, No. 34 at pp. 4) 

Finally, the Efficiency Advocates 

asserted that increases in demand due to 

population growth will be met with the 

installation of new transformers, rather 

than increasing loads on existing 

transformers. (Efficiency Advocates, No. 

34 at p. 2–3). 

HVOLT and CDA commented that 

standard PUL changes are not needed 

right now, but that EV charging in the 

future may increase loading. (CDA, No. 

29 at p. 89; HVOLT, No. 27 at p. 94). 

Load growth has always been, and 

continues to be, difficult to predict. 

Stakeholders disagreed as to what future 

distribution transformer loading would 

be expected. While IEEE–TF data 

suggests that the current in-service PUL 

is lower than the standard PUL, the 

extent to which distribution transformer 

load will change over time is unclear. 

Distribution transformers were 

evaluated in the April 2013 ECS Final 

Rule as having an average lifespan of 32 

years, and in many cases they may have 

an in-service lifetime that is 

significantly longer. 78 FR 23336, 

23377. The long lifetime of distribution 

transformers means that many will 

operate through multiple economic, 

social, or climate-driven events that 

could affect the average in-service PUL 

on individual transformers. 

In response to Cargill, while many 

conventional core steel transformers 

have a peak efficiency between 45 and 

55 percent, this is not generally the case 

across the entire market and may in part 

be driven by the 50 percent standard 

PUL specified in the DOE test 

procedure. Given an alternative 

standard PUL, conventional core steel 

transformers could be designed with 

peak efficiencies at other values. 

Further, while some utilities may be 

considering overloading transformers as 

standard operating practice and could 

therefore replace larger distribution 

transformers with smaller distribution 

transformers, thereby increasing the inservice PUL of these distribution 

transformers, DOE does not have any 

data to substantiate Cargill’s claim that 

this practice is actually occurring or is 

expected to occur. 

In response to the Efficiency 

Advocates, DOE generally agrees that 

PV generation as a resource at the level 

of the transmission grid can both reduce 


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51242 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

19Palmintier, Bryan, Meghan Mooney, Kelsey 

Horowitz, et al. 2021. ‘‘Chapter 7: Distribution 

System Analysis.’’ In the Los Angeles 100% 

Renewable Energy Study, edited by Jaquelin 

Cochran and Paul Denholm. Golden, CO: National 

Renewable Energy Laboratory. NREL/TP–6A20– 

79444–7. www.nrel.gov/docs/fy21osti/79444-7.pdf. 

20 J. Coignard, P. MacDougall, F. Stadtmueller and 

E. Vrettos, ‘‘Will Electric Vehicles Drive 

Distribution Grid Upgrades?: The Case of 

California,’’ in IEEE Electrification Magazine, vol. 7, 

no. 2, pp. 46–56, June 2019, doi: 10.1109/ 

MELE.2019.2908794. 

21 Ibid. 

22Hale, Elaine, Anthony Fontanini, Eric Wilson, 

et al. 2021. ‘‘Chapter 3: Electricity Demand 

Projections.’’ In the Los Angeles 100% Renewable 

Energy Study, edited by Jaquelin Cochran and Paul 

Denholm. Golden, CO: National Renewable Energy 

Laboratory. NREL/TP–6A20–79444–3. 

www.nrel.gov/docs/fy21osti/79444-3.pdf. 

23Energy Information Administration, Electric 

Power Monthly, www.eia.gov/electricity/monthly/. 24Energy Information Administration, {Electric 

Power Monthly December 1997, DOE/EIA–0226(97/ 

12); Electric Power Monthly December 2011, DOE/ 

EIA–0226(2011/12); Electric Power Monthly 

December 2017; Electric Power Monthly December 

2020}, www.eia.gov/electricity/monthly/, See for 

each of the four listed time periods: Table 5.1. Sales 

of Electricity to Ultimate Customers: Total by EndUse Sector. 

the overall generation required to serve 

a population and have potential impacts 

of reducing peak-demand in areas where 

there is enough solar resource to do so. 

However, when considered at the level 

of the load(s) being served by individual 

distribution transformers, PV generation 

(or other demand-side generation) will 

generally reduce the load on the 

transformer only by the quantity of 

energy consumed on the secondaryservice side, (i.e., the customer 

connected side), of the transformer. 

Unless the PV generation is not gridtied, any surplus energy being 

transformed from secondary-service 

voltages to primary-service voltages and 

fed back into the grid for distribution 

would contribute to the average load of 

the transformer. Depending on the 

quantity of surplus energy being fed 

back into the grid, PV generation could 

have the effect of either decreasing or 

increasing the average PUL on an 

individual distribution transformer. 

Further, if surplus energy is fed back 

into the grid during peak times, it could 

have the impact of increasing both peak 

load and average load. A recent study by 

National Renewable Energy Laboratory 

(‘‘NREL’’) and Los Angeles Department 

of Water and Power (‘‘LADWP’’), Los 

Angeles 100% Renewable Energy Study 

(‘‘LA100’’), researching the needs to 

serve the greater city of Los Angeles 

with 100 percent renewable energy, 

estimated that 80 percent of existing 

distribution feeders would need to be 

upgraded due to occurrences of one or 

more overloading violations with the 

connected transformers.19 Integrating 

PV or other distributed-generation in a 

dispatchable manner is a technically 

complex task, and at the transmission 

level can reduce overall electricity 

demands; however there is also the 

potential that loads may rise on some 

distribution circuits (and connected 

distribution transformers) to meet these 

transmission reductions. 

The Efficiency Advocates’ claim that 

EV impacts on peak electricity demand 

and transformer loads may be small, 

given the assertion that it is in the 

electric utility’s interest to promote offpeak charging, is incomplete. The 

Efficiency Advocates cited an article in 

support of their assertion that ‘‘at a 

macro scale, EVs appear to pose only a 

modest burden on the electric grid’’.20

However, this position oversimplifies 

the relationship between connected 

loads, the distribution grid, and 

transmission grid. The article cited by 

the Energy Advocates cautions that at a 

micro scale, EVs represent a significant 

addition to traditional household loads; 

and further states that the addition of a 

level 2 residential EV charging station 

contributes a load similar to an 

additional house on the grid.21

While there are likely benefits to 

promoting off-peak charging, or other 

types of structured charging schemes, 

EV charging is difficult to predict and 

model because EV adoption is still in 

the early stages. While some utility 

programs have been successful at 

shifting EV loads from peak to off-peak 

times using time-of-use rates or specific 

EV charging electricity tariffs, offsetting 

system peak capacity demands, the 

additional load required to charge an EV 

during non-peak times will still 

contribute to the overall average 

transformer PUL. Analysis conducted 

for the LA100 study indicates, under the 

‘‘moderate’’ projection, that electrical 

demand for transportation will be one of 

the largest contributors to distribution 

load growth over their analysis period 

(2020 through 2045).22 The LA100 study 

addresses the load impacts on utility 

distribution systems, which would be 

served by liquid-immersed mediumvoltage distribution transformers, it does 

not address the potential impacts to 

commercial and industrial customers 

who deploy dry-type distribution 

transformers. The impact of EV driven 

load growth on dry-type distribution 

transformers could also be significant, 

particularly if EVs are charged on 

circuits without upgrades to the serving 

low- or medium-voltage dry-type 

distribution transformers. 

In response to the September 2017 

RFI, the Efficiency Advocates 

challenged DOE’s assertion that the 

record supports a 50 percent PUL for 

liquid-immersed distribution 

transformers (on the basis that 

increasing future load growth at the rate 

of one percent per-year would result in 

in-service PULs that would eventually 

converge with the test standard PUL 

over time was calculated was 

incorrectly). In the September 2017 RFI 

DOE asserted that with a one-percent 

future growth rate over time, thencurrent observed RMS PUL values 

would approximately converge to the 

standard PUL values. 82 FR 44347, 

44349. In response to the load growth 

assertions from the Efficiency 

Advocates, DOE examined the trend in 

sales of electricity to customers made 

available by the Annual Energy Outlook 

(AEO) in its Electric Power Monthly 

periodical.23 DOE first examined the 

time period highlighted by the 

Efficiency Advocates and confirms that 

2018 was a year in which sales were 

much higher than in the preceding 

period from 2011 through 2017. DOE 

notes that while 2018 had the greatest 

year-on-year growth over this period, 

there were other years with positive 

growth, and the average year-on-year 

growth for the period between 2011 

through 2018 was 0.4 percent. DOE also 

finds that the time period highlighted by 

the Efficiency Advocates is not 

sufficient for this analysis given that the 

average in-service lifetime for 

distribution transformers is 32 years. As 

such, DOE takes a longer view of the 

trend of available data when 

considering the impacts of load growth. 

When examining the 10-year rolling 

average of year-on-year growth for the 

period 2010 through 2020, it can be 

observed that sales of electricity 

increased for every period, except for 

the periods ending in 2017 and 2020, 

with an average year-on-year increase of 

0.3 percent.24

As mentioned, the Efficiency 

Advocates assert that future growth in 

electricity sales will be driven by 

population growth, which tends to 

cause grid expansion and the 

installation of new transformers, rather 

than to increase loads on existing 

transformers. (Efficiency Advocates, No. 

34 at p. 2–3) DOE partially agrees with 

the Efficiency Advocates, that load 

growth from new construction would be 

met with new transformers. DOE must 

consider that the additional factors that 

drive load growth (e.g., weather events, 

expanding populations, increased 

electrification), impact all connected 

distribution transformers, not just those 

installed to provide service to new 

construction, and therefore must 

consider the effect of load growth’s 


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25See: Section 2.3 of Chapter 2. Analytical 

Framework, Comments from Interested Parties, and 

DOE Responses of the Prelim TSD at Docket No. 

EERE–2019–BT–STD–0018–0022. 

impact on a transformer’s typical use 

cycle. 

The Efficiency Advocates requested 

DOE respond to their comment on the 

September 2017 RFI, where the 

Efficiency Advocates challenged DOE’s 

assertion that, for liquid-immersed 

distribution transformers, future load 

growth (at the rate of one percent peryear), would result in in-service PULs 

that would eventually converge with the 

standard PUL over time, and stated that 

the in-service PUL was calculated 

incorrectly. (Efficiency Advocates, 0015 

at p. 1) In the September 2017 RFI, DOE 

asserted that, on average, the initial 

(first year) RMS PUL for liquidimmersed transformers ranged from 34 

and 40 percent for single- and threephase equipment, respectively, with a 

one percent annual increase over the life 

of the transformer to account for 

connected load growth. This resulted in 

a lifetime average PUL of 49 and 56 

percent for single- and three-phase 

liquid-immersed transformers, 

respectively. And that it was consistent 

with the current test procedure 

requirements of rating liquid-immersed 

transformers at 50 percent PUL. 86 FR 

44349. After further analysis of the data, 

DOE agrees with the Efficiency 

Advocates that the load growth impact 

on PUL in the September 2017 RFI was 

incorrectly calculated. DOE agrees the 

load growth rates needed to support the 

assertion that the in-service PUL would 

converge with the standards PUL over 

the transformers typical lifetime in the 

September 2017 RFI would need to be 

greater than the proposed one percent 

per-year. While the conclusions drawn 

in the September 2017 RFI cannot be 

supported, recent market and policy 

changes since the publication of the RFI 

indicate that the premise that there are 

uncertainties and concerns associated 

with future load growth, continue to be 

valid. 

c. Risks Associated With Current and 

Future Losses 

Given the diversity of conditions 

under which distribution transformers 

are currently operated and the 

uncertainty as to how future changes in 

connected loads will affect in-service 

PULs, DOE must consider how a single 

standard PUL would fare in both 

circumstances in which it overestimates 

and underestimates the in-service PUL. 

As discussed in section III.D.1, a 

distribution transformer’s efficiency is 

determined as a function of the total 

losses at the standard PUL. A 

distribution transformer’s total losses at 

the standard PUL are the sum of its noload losses and load losses at the 

standard PUL. No-load losses are 

approximately constant with the PUL 

and load losses increase quadratically 

with PUL. 

Every distribution transformer has a 

PUL for which efficiency peaks, where 

no-load and load losses happen to be 

equal. While there is no prescribed PUL 

at which this must occur, often, as a 

result of optimizations in the 

manufacturing process, transformers are 

most efficient at, or near, the DOE 

prescribed standard PUL. Distribution 

transformers that have a peak efficiency 

at PUL values greater than the average 

in-service PUL overemphasize load 

losses and distribution transformers that 

have a peak efficiency less than the 

average in-service PUL overemphasize 

no-load losses relative to transformer 

designs with equivalent total losses that 

peak at the in-service PUL. The 

asymmetry in rate of loss change—the 

losses rise faster at PULs greater than 

the standard PUL than they fall at PULs 

less than the standard PUL—contributes 

to the conclusion that the risk of 

selecting a suboptimal standard PUL is 

greater on the low side than on the high 

side. Efficiency falls in proportion to the 

degree to which in-service PUL diverges 

from standard PUL. Because a lower inservice PUL corresponds (on a singleunit basis) to a lower absolute quantity 

of energy, however, a given loss of 

efficiency equates to a greater absolute 

quantity of energy when the in-service 

PUL exceeds standard PUL.25

As stated in section III.D.2.a, the 

Efficiency Advocates recommend DOE 

select a lower standard PUL to better 

align with the AMI data. (Efficiency 

Advocates, No. 34, at pp. 2–3) DOE 

notes that the maximum technologically 

feasible design options analyzed in the 

April 2013 Final Rule consist of 

distribution transformers that have a 

peak efficiency well below the standard 

PUL (often times below 20 percent 

PUL). 78 FR 23337. This indicates that 

distribution transformers can be built 

that perform well at both the in-service 

PULs cited by the Efficiency Advocates 

and meet efficiency standards at the 

current standard PUL. Energy savings 

achieved through the energy 

conservation standard rulemaking at the 

current PUL have less of this 

asymmetric risk because they do not 

discount load losses to the same degree 

as a lower PUL. 

In addition to considering the energy 

savings potential of the standard PUL 

overestimating and underestimating inservice PUL, DOE also considered the 

financial value of losses to consumers 

associated with overestimating and 

underestimating in-service PULs. 

i. Peak Coincidence Risks 

The Efficiency Advocates suggested 

that it in the best interest of utilities to 

pursue programs to mitigate risks 

related to peak demands. (Efficiency 

Advocates, No. 34 at p. 3) Demand 

response programs can help flatten 

peaks at the grid, distribution, and 

individual consumer levels. A 

simplified example is a demand 

response program which promotes peakload shifting, wherein utility ratepayers 

defer or forego electrical consumption 

during times when the system is 

peaking. This may have a bottom-up 

effect of reducing peak power through 

individual distribution transformers by 

reducing peak generation. Owners of 

distribution transformers typically face 

different costs depending on overall 

demand, which influences the mix of 

generation and storage they may deploy 

to meet the demand. Large electrical 

consumers (who with electrical utilities 

generally form the total set of 

distribution transformer owners), too, 

face demand-based cost of electrical 

power. In general, marginal cost of 

electricity is greater during times of high 

demand. This carries implications for 

valuing the losses of distribution 

transformers. Specifically, load losses 

will tend to be costlier for the owner of 

the distribution transformers as 

proportionally more of them occur 

during periods of high demand and 

correspondingly higher energy cost. 

By their nature, distribution 

transformers tend to be ‘‘peakcoincident’’, i.e., the peak load on the 

distribution transformers tends to 

coincide with peak load on the larger 

electrical network. That distribution 

transformer loading peaks to when 

electrical power costs peak can result in 

certain distribution transformer 

customers bearing high operating cost 

for a small number of peak operating 

hours. Distribution transformers 

designed without account of this 

electrical cost dynamic, optimized for 

lower in-service PULs, will operate at 

comparatively low efficiency when the 

cost of operation is greatest. DOE 

recognizes that demand response 

programs can reduce the peak-load 

impacts. However, because distribution 

transformers reflect the load patterns of 

their connected loads, the risks of the 

high rate of load losses associated with 

peak coincidence cannot be fully 

controlled by utilities and are 

dependent on consumer patterns. 

Accordingly, DOE needs to maintain a 


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51244 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

26Energy Information Administration, Annual 

Energy Outlook, 2012, Table 54. Electric Power 

Projections by Electricity Market Module Region. 

27See Chapter 7 of the 2013 final rule TSD, 

available at https://www.regulations.gov/document/ 

EERE-2010-BT-STD-0048-0760. 

28 Ibid. 

PUL which adequately addresses both 

high and low in-service loads. 

ii. Serving Future No-Load and Load 

Losses 

In evaluating the financial risk to 

consumers of the standard PUL overand underestimating in-service PULs, 

and given the long lifespans of 

distribution transformers, DOE needs to 

consider how future no-load and load 

losses will be served. 

The way in which future electricity 

generation needs will be met has 

historically been considered in DOE’s 

ECS analyses. However, to the extent 

that the choice of metric affects the cost 

effectiveness and energy consumption 

(both in the aggregate quantity and the 

timing of that energy consumption) of 

consumers, some background on the 

power grid (the operating site of 

distribution transformers) is necessary 

to understand the broader impacts of 

any metric change. Insofar as purchasers 

of distribution transformers select on 

the basis of first cost, manufacturers 

may attempt to minimize first cost 

subject to compliance with energy 

conservation standards. The specific 

distribution transformer design that 

minimizes first cost may vary based on 

the metric it is being evaluated against. 

Thus, selection of standard PUL may 

indirectly influence purchase prices and 

energy consumption of distribution 

transformers. 

In the April 2013 ECS Final Rule, 

DOE assumed that future power needs 

for no-load losses would be met by the 

mix of different baseline generation 

types in the year of compliance, 2016. 

78 FR 23337. At that time, DOE based 

its analysis on the data available from 

AEO 2012, which indicated a mix of 

generation types which was 

predominantly served by coal at 26 

percent, natural gas combined cycle at 

19 percent, renewables and natural gas 

combustion turbines both at 15 percent, 

with the remainder generation being 

met by other generation types.26 DOE 

projected that future no-load losses 

generation would be met by new 

capacity from coal, as it serves 

predominantly base load, and natural 

gas and renewables serve a mix of 

base-, mid-merit and peaking loads.27

DOE assumed that load losses would be 

met with simple combustion turbines.28

This resulted in a cost, in terms of 

dollars per watt, ($/W) for no-load 

losses that was higher than the cost of 

load losses. A contributing factor to this 

difference is the relatively high 

overnight capital cost of large coal 

plants, in terms of dollars per megawatt 

unit capacity, ($/MW) when compared 

to other generating types for 

determining the capacity cost 

component of the cost of electricity. 

However, the current AEO 2021 projects 

a very different mix of generating fuel 

types, now and into the future, with 

retiring coal and, to a lesser degree, 

nuclear generation being displaced by 

natural gas, in the near-term, and then 

renewables in future years. These trends 

are shown in Table III.3. This shift in 

generating fuels suggests that the future 

cost associated with no-load losses and 

load losses will be closer in price than 

previously estimated as similar 

generating units are used to meet both 

no-load and load losses. 

TABLE III.3—PROJECTED FRACTION OF GENERATION BY FUEL TYPES FOR CERTAIN YEARS

[Percent of total generation] 

Year Coal 

(%) 

Natural gas 

(%) 

Nuclear 

(%) 

Renewable sources 

(%) 

Other sources 

(%) *

AEO 2012 ** 2021 † 2012 2021 2012 2021 2012 2021 2012 2021 

2010 .............................................................................. 46 .............. 23 .............. 20 .............. 10 .............. 1 ..............

2015 .............................................................................. 39 .............. 26 .............. 21 .............. 13 .............. 1 ..............

2020 .............................................................................. 40 20 24 40 22 20 13 20 1 0 

2025 .............................................................................. 41 17 24 35 21 18 14 29 1 0 

2030 .............................................................................. 40 16 25 34 21 15 13 34 1 0 

2035 .............................................................................. 40 15 26 33 19 14 14 37 1 0 

2040 .............................................................................. .............. 14 .............. 34 .............. 13 .............. 38 .............. 0 

2045 .............................................................................. .............. 12 .............. 35 .............. 13 .............. 39 .............. 0 

2050 .............................................................................. .............. 12 .............. 35 .............. 12 .............. 41 .............. 0 

* Includes the following generation fuel-type categories: Distributed Generation, Generation for Own Use, Petroleum, Pumped Storage/Other. 

** Source: U.S. Energy Information Administration, Annual Energy Outlook 2012, Electricity Electric Power Sector Generation (Case Reference case Region United 

States). 

† Source: U.S. Energy Information Administration, Annual Energy Outlook 2021, Electricity Electric Power Sector Generation (Case Reference case Region United 

States). 

As stated previously, in this final rule, 

DOE is maintaining the current standard 

PUL specifications. DOE is centralizing 

the PUL specifications in appendix A, 

as discussed in section III.F.1. 

Further, the test procedure and 

accompanying energy conservation 

standards do not preclude 

manufacturers from optimizing 

distribution transformer performance at 

a PUL other than the standard PUL so 

long as the unit complies with the 

applicable standard when tested at the 

standard PUL. While reducing the 

standard PUL could in certain cases 

have a positive impact on energy 

savings, especially for distribution 

transformers fabricated with low-loss 

core materials such as amorphous steel, 

the same energy savings outcome can 

often be achieved through amending the 

energy conservation standard for 

distribution transformers. In other 

words, the savings associated with a 

potential reduction of standard PUL is 

often a byproduct of greater consumer 

selection of amorphous-based 

transformers, which by chance tend to 

both be relatively better at smaller PUL 

values and also be more efficient in 

absolute terms. Many of the distribution 

transformer designs in the 

accompanying energy conservation 

standards preliminary engineering 

analysis with efficiencies above the 

current standard are optimized to 

operate at a PUL below 25 percent due 

to the use of amorphous steel cores, 

while certifying at the current standard 

PUL. It is in the accompanying energy 

conservation standards where details 

and data related to the efficiency 

standards of distribution transformers 

can be fully evaluated under the EPCA 

requirements that any new or amended 

energy conservation standard be 

designed to achieve the maximum 

improvement in energy or water 


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Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 51245 

29United States Environmental Protection 

Agency. ENERGY STAR® Guide to Buying More 

Energy Efficient Distribution Transformers. October 

2017. Accessed July 7, 2021. 

https://www.energystar.gov/sites/default/files/asset/ 

document/ 

Transformers%20Buyer%27s%20GuideFinal10-16- 

17.pdf. 

efficiency that is technologically 

feasible and economically justified. (42 

U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) 

DOE is also permitting voluntary 

representations of efficiency at 

additional PULs so that manufacturers 

can communicate to customers the 

efficiency of their distribution 

transformers at various service PULs, as 

discussed in section III.D.3. 

Additionally, voluntarily 

representations at additional PULs may 

be relied upon by voluntarily programs 

such as ENERGY STAR®, which 

publishes a buying guide 29 to assist 

distribution transformer purchasers that 

may save energy and cost in the context 

of the purchasers’ specific PUL 

distribution. 

Finally, DOE notes that the observable 

data and trends indicate that there are 

ongoing changes in policies, consumer 

demand, and data availability which are 

beginning to have an impact on the 

distribution transformer operations. 

These changes present uncertainties 

with regard to distribution transformer 

loading, and DOE will continue to 

evaluate changes in the market and in 

operation that may require 

consideration in future test procedure 

evaluations. 

3. Voluntary Representations of 

Efficiency at Additional PULs 

In the May 2019 NOPR, DOE 

proposed amendments to the test 

procedure to permit manufacturers to 

make voluntary representations of 

additional performance information of 

distribution transformers when operated 

under conditions other than those 

required for compliance with the energy 

conservation standards for distribution 

transformers at 10 CFR 431.196. 84 FR 

20704, 20714. DOE proposed the 

provisions regarding voluntary 

representations to help consumers make 

better purchasing decisions based on 

their specific installation conditions. 

Specifically, DOE proposed in a new 

section 7 of appendix A to specify that 

manufacturers are permitted to 

represent efficiency, no-load loss, or 

load loss at additional PULs and/or 

reference temperatures, as long as the 

equipment is also represented in 

accordance with DOE’s test procedure at 

the mandatory (standard) PUL and 

reference temperature. When making 

voluntary representations, best practice 

would be for the manufacturers also to 

provide the PUL and reference 

temperature corresponding to those 

voluntary representations. 

NEMA stated that the current test 

procedure is already applicable to 

alternative PULs. (NEMA, No. 30 at p. 

4) Howard, CDA, and HVOLT 

commented that voluntary 

representations would be useful in 

examining efficiencies at alternative 

PULs. (Howard, No. 32 at p. 1; CDA, No. 

29 at p. 3; CDA, No. 29 at p. 4; HVOLT, 

No. 27 at p. 92–94) 

As discussed, while the test 

procedure accommodates testing at any 

PUL, and correcting the results to reflect 

any other specified PUL, DOE’s energy 

conservation standards specify standard 

PULs that must be used to represent the 

energy efficiency of distribution 

transformers. 10 CFR 431.196. EPCA 

prohibits manufacturers from making 

representations respecting the energy 

consumption of covered equipment or 

cost of energy consumed by such 

equipment unless that equipment has 

been tested in accordance with the 

applicable DOE test procedure and such 

representations fairly disclose the 

results of that testing. (42 U.S.C. 

6314(d)) Accordingly, there is benefit in 

manufacturers being explicitly 

permitted to make representations 

respecting energy consumption at 

alternative PULs and reference 

temperatures that may better suit an 

individual consumer’s demands. 

For the reason expressed in the May 

2019 NOPR and above, DOE is 

establishing new section 7 of appendix 

A, which explicitly provides that any 

PUL and temperature values other than 

those required for determining 

compliance can be used for voluntary 

representations when testing is 

conducted in accordance with the 

applicable DOE test procedure. Table 

III.4 summarizes the applicable PUL and 

temperature values. 

TABLE III.4—SUMMARY OF VOLUNTARY REPRESENTATION

Mandatory certified values * Voluntary representations 

Metric PUL 

(percent) 

Reference 

temperature 

for loead loss 

(°C) 

Metric PUL 

(percent) 

Reference 

temperature 

(°C) 

Liquid Immersed .......... Efficiency ..................... 50 55 Efficiency, load loss, 

no-load loss.

Any ................. Any. 

MVDT ........................... ..................................... 50 75 

LVDT ............................ ..................................... 35 75 

* Efficiency must be determined at a reference temperature of 20 °C for no-load loss for all distribution transformers. 

E. Multiple Voltage Capability 

Some distribution transformers have 

primary windings (‘‘primaries’’) and 

secondary windings (‘‘secondaries’’) 

that may each be reconfigured, for 

example either in series or in parallel, 

to accommodate multiple voltages. 

Some configurations may be more 

efficient than others. 

Section 4.5.1(b) of appendix A 

requires that for a transformer that has 

a configuration of windings that allows 

for more than one nominal rated 

voltage, the load losses must be 

determined either in the winding 

configuration in which the highest 

losses occur, or in each winding 

configuration in which the transformer 

can operate. Similarly, section 5.0 of 

appendix A states that for a transformer 

that has a configuration of windings that 

allows for more than one nominal rated 

voltage, its efficiency must be 

determined either at the voltage at 

which the highest losses occur, or at 

each voltage at which the transformer is 

rated to operate. Under either testing 

and rating option (i.e., testing only the 

highest loss configuration, or testing all 

configurations), the winding 

configuration that produces the highest 

losses is tested and consequently must 

comply with the applicable energy 

conservation standard. 


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51246 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

The relevant industry test standards, 

IEEE C57.12.00–2015 and IEEE 

C57.12.01–2020, direct distribution 

transformers to be shipped with the 

windings in series. Therefore, a 

manufacturer physically testing for DOE 

compliance may need to disassemble 

the unit, reconfigure the windings to 

test the configuration that produces the 

highest losses, test the unit, then 

reassemble the unit in its original 

configuration for shipping, which 

would add time and expense. 

In the May 2019 NOPR, DOE did not 

propose amending the requirement 

related to transformers being tested in 

the configuration that produces the 

highest losses. 84 FR 20704, 20718. DOE 

noted that it provides for certification 

using an alternative efficiency 

determination method (AEDM), which 

is a mathematical model based on the 

transformer design (10 CFR 429.47), and 

that the availability of an AEDM 

mitigates the potential cost associated 

with having to physically test a unit in 

a configuration other than in its ‘‘asshipped’’ configuration. Id. 

Howard, NEMA, CDA and HVOLT 

suggested that transformers be tested in 

the ‘‘as-shipped’’ configuration, which 

is typically with the windings in series. 

(Howard, No 32 at p. 1; CDA, No. 29 at 

p. 3; HVOLT, No. 27 at p. 92; NEMA, 

No. 30 at p. 6) NEMA commented that 

the requirement to test in the highest 

losses configuration is confusing to 

customers and adds undue burden on 

manufacturers, whereas industry testing 

standards have changed to test and ship 

in highest voltage configurations. 

(NEMA, No. 30 at p. 6) NEMA claims 

the burden associated with requiring 

testing of the configuration with the 

highest loss is especially unnecessary 

given that the overwhelming majority of 

transformers are used in the highest 

voltage configuration, with less than 5% 

of transformers in applications other 

than the ‘‘as-shipped’’ configuration. 

(NEMA, No. 30 at p. 6) NEMA asserted 

that while it can be hard to generalize 

the losses associated with less efficient 

winding configurations, given the 

variability in application, the losses are 

typically less than 1% of load losses, 

and that it has never seen the difference 

between configurations exceed 2% of 

load losses. (NEMA, No. 30 at p. 4; 

NEMA, No. 30 at p. 6) NEMA further 

asserted that given the minimal 

efficiency gains in testing in the highestloss and the relatively small percentage 

of transformers operated in a 

configuration other than ‘‘as-shipped’’, 

the burden on manufacturers is not 

justified. (NEMA, No. 30 at p. 6) 

As stated in the May 2019 NOPR, 

DOE recognizes that testing in the asshipped condition may be less 

burdensome for certain manufacturers, 

but DOE also stated that it does not have 

data to support NEMA’s claim that the 

‘‘as-shipped’’ configuration would lead 

to a maximum of 2 percent increase in 

load losses. 84 FR 20704, 20718. NEMA 

cited certain example distribution 

transformers where the load loss 

increase was 2 percent or less, however, 

the data is only for a few select 

distribution transformers and not 

representative of the industry as a 

whole. (NEMA, No. 30 at p. 7) In 

interviews, several manufacturers 

suggested that in certain extreme cases 

the difference in efficiency could be 

much higher than the 2 percent figure 

cited by NEMA. 

Further, even if DOE did have data 

affirming the 2 percent figure NEMA 

cited, it would be expected that such a 

change to the test procedure would 

require a corresponding change to the 

energy conservation standards to 

account for the change in measured load 

loss values. A change to the energy 

conservation standards would 

necessitate certain manufacturers of 

transformers with multiple windings to 

re-test and re-certify their performance 

to DOE. 

As explained in the May 2019 NOPR, 

as an alternative to physical testing, 

DOE provides for certification using an 

AEDM, which is a mathematical model 

based on the transformer design. 10 CFR 

429.47. The shipped configuration has 

no bearing on the AEDM calculation, 

and an AEDM can determine the 

highest-loss configuration instantly. 

DOE notes that most transformers are 

currently certified using the AEDM and 

the current burden is therefore less than 

the commenters asserted for the 

majority of manufacturers. In 

interviews, manufacturers suggested 

that this burden existed only when 

verifying an AEDM. Further, many 

distribution transformers are 

reconfigured using a switch, which 

minimizes effort required to change 

winding configurations. NEMA 

confirmed that there is no burden 

associated with rewiring when utilizing 

an AEDM and rather that the benefit to 

changing to ‘‘as-shipped’’ testing is that 

for higher-volume, single-phase pole 

mount units manufacturers could 

continually gauge the ‘‘as-shipped’’ 

performance against the AEDM. (NEMA, 

Docket No. EERE–2017–BT–TP–0055– 

0036 at p. 3) While there may be 

benefits in continually gauging the ‘‘asshipped’’ performance against the 

AEDM, DOE remains concerned about 

the magnitude of the increase in load 

losses for certain distribution 

transformers. 

As a result, DOE is not amending in 

this final rule the current requirements 

of section 4.5.1(b) of appendix A (for a 

transformer that has a configuration of 

windings that allows for more than one 

nominal rated voltage, the load losses 

must be determined either in the 

winding configuration in which the 

highest losses occur, or in each winding 

configuration in which the transformer 

can operate) and section 5.0 of appendix 

A (for a transformer that has a 

configuration of windings that allows 

for more than one nominal rated 

voltage, its efficiency must be 

determined either at the voltage at 

which the highest losses occur, or at 

each voltage at which the transformer is 

rated to operate). 

F. Other Test Procedure Topics 

In addition to the updates to the DOE 

test procedure discussed in the 

preceding sections, DOE also considered 

whether the existing test procedure 

would benefit from any further revisions 

and/or reorganizing. Additional issues 

are discussed in the following sections. 

1. Per-Unit Load Specification 

In the May 2019 NOPR, DOE 

proposed to centralize the PUL 

specifications, both for the certification 

to energy conservation standards and for 

use with a voluntary representation. 84 

FR 20704, 20718–20719. Currently, the 

PULs required for certification to energy 

conservation standards are specified for 

each class of distribution transformer at 

10 CFR 431.196 and referenced 

indirectly in multiple locations, 

including 10 CFR 431.192 (within the 

definition of reference temperature), 

section 3.5(a) of appendix A, and 

section 5.1 of appendix A. DOE 

proposed to consolidate the PUL 

specification into one location—a newly 

proposed section 2.1 of appendix A. 

Additionally, DOE proposed to provide 

in the proposed section 2.1 of appendix 

A that the PUL specification can be any 

value for purposes of voluntary 

representations. Id. DOE did not receive 

any comments on these proposed 

changes and is adopting them in this 

final rule. 

The consolidation enhances 

readability of the test procedure and 

more clearly communicates the PUL 

requirements with respect to 

certification to energy conservation 

standards and voluntary 

representations. The updates do not 

change the standard PUL requirements 

with respect to certification to energy 

conservation standards. Instead, the 

updates improve clarity with respect to 

selection of PUL for voluntary 


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representations versus certification to 

energy conservation standards. 

DOE also proposed editorial changes 

to section 5.1 of appendix A to support 

the consolidated approach to PUL 

specification. 84 FR 20704, 20719. 

Section 5.1 of appendix A provides 

equations used to calculate load-losses 

at any PUL. Section 5.1 of appendix A 

used language that limited its 

applicability to certification to energy 

conservation standards only. For 

example, it referenced the ‘‘specified 

energy efficiency load level’’ (i.e., the 

PUL required for certification to energy 

conservation standards) specifically. 

DOE proposed to generalize the 

language in this section to reference the 

PUL selected in the proposed section 

2.1. Id. 

DOE did not receive any comments 

regarding these proposed editorial 

changes and is adopting them in this 

final rule. 

2. Reference Temperature Specification 

Similar to PUL, DOE proposed to 

consolidate the reference temperature 

specifications for certification to energy 

conservation standards and for the 

proposed voluntary representations. 84 

FR 20704, 20719. The reference 

temperature specifications for 

certification to energy conservation 

standards are defined at 10 CFR 431.192 

(as the definition of ‘‘reference 

temperature’’), and are referenced in 

section 3.5(a) of appendix A and section 

4.4.3.3 of appendix A. DOE proposed to 

consolidate the reference temperature 

specifications into one location—a 

newly proposed section 2.2 of appendix 

A. 84 FR 20704, 20719. Additionally, 

DOE proposed to describe in the 

proposed section 2.2 of appendix A that 

the reference temperature specification 

can be any value for purposes of 

voluntary representations. Id. DOE did 

not receive any comments on the 

proposed changes and is adopting them 

in this final rule. 

Similar to PUL, this consolidation 

will enhance readability of the test 

procedure and more clearly 

communicate DOE’s reference 

temperature requirements with respect 

to certification to energy conservation 

standards or voluntary representations. 

The updates do not change existing 

reference temperature requirements 

with respect to certification to energy 

conservation standards. Instead, the 

updates improve clarity with respect to 

selection of reference temperature for 

voluntary representations versus 

certification to energy conservation 

standards. 

DOE also proposed editorial changes 

to sections 3.5 and 4.4.3.3 of appendix 

A to support the consolidated approach 

to reference temperature specification. 

Section 3.5 of appendix A provided 

reference temperatures for certification 

to energy conservation standards. DOE 

has consolidated reference temperature 

specifications into one location (section 

2.2); therefore, DOE has removed the 

same specification in section 3.5 so that 

the section is applicable to determine 

voluntary representations. 

Section 4.4.3.3 of appendix A 

provides the specifications and 

equations used for correcting no-load 

loss to the reference temperature. 

Specifically, the section provides an 

option for no correction if the no-load 

measurements were made between 10 

°C and 30 °C (representing a ±10 °C 

tolerance around the 20 °C reference 

temperature). This tolerance is 

applicable only for certification to 

energy conservation standards. For 

simplicity, DOE proposed no such 

tolerance for voluntary representations 

at additional reference temperatures, so 

that all measured values would be 

adjusted using the reference 

temperature correction formula. 84 FR 

20704, 20719. Finally, DOE proposed to 

remove any reference to a reference 

temperature of 20 °C so that the section 

would be applicable to determine 

voluntary representations. Id. 

DOE did not receive any comments on 

these proposed changes and is adopting 

them in this final rule. 

3. Measurement Location 

DOE proposed to specify that load 

and no-load loss measurements are 

required to be taken only at the 

transformer terminals. 84 FR 20704, 

20719. In the May 2019 NOPR, DOE 

proposed a definition for ‘‘terminal,’’ as 

described in section III.C.2.b of this final 

rule. DOE notes that section 5.4 of 

IEEE.C57.12.90–2015 and section 5.6 of 

IEEE C57.12.91–2020 specify terminalbased load-loss measurements. In 

addition, section 8.2.4 of 

IEEE.C57.12.90–2015 and section 8.2.5 

of IEEE C57.12.91–2020 provide the 

same for no-load loss measurement. 

These documents reflect current 

industry practices and manufacturers 

are already measuring losses at the 

transformer terminals. Therefore, DOE 

proposed to specify in section 4.3(c) of 

appendix A that both load loss and noload loss measurements must be made 

from terminal to terminal. 84 FR 20704, 

20719. 

DOE received no comments in 

response to this proposal and is 

adopting it in this final rule. 

4. Specification for Stabilization of 

Current and Voltage 

Section 3.3.2 and 3.3.1 of appendix A 

describe a voltmeter-ammeter method 

and resistance bridge methods, 

respectively, for measuring resistance. 

Both methods require measurements to 

be stable before determining the 

resistance of the transformer winding 

being measured. Specifically, the 

voltmeter-ammeter method in section 

3.3.2(b) of appendix A requires that 

current and voltage readings be stable 

before taking simultaneous readings of 

current and voltage to determine 

winding resistance. For the resistance 

bridge methods, section 3.3.1 of 

appendix A requires the bridge to be 

balanced (i.e., no voltage across it or 

current through it) before determining 

winding resistance. Both methods allow 

for a resistor to reduce the time constant 

of the circuit, but do not explicitly 

specify how to determine when 

measurements are stable. DOE notes that 

IEEE C57.12.90–2015, IEEE C57.12.91– 

2020, IEEE C57.12.00–2015, and IEEE 

C57.12.01–2020 do not specify how to 

determine that stabilization is reached. 

Section 3.4.2 of appendix A provides 

related instruction for improving 

measurement accuracy of resistance by 

reducing the transformer’s time 

constant. However, section 3.4.2 also 

does not explicitly provide for the 

period of time (such as a certain 

multiple of the time constant) necessary 

to achieve stability. In the May 2019 

NOPR, DOE requested comment on how 

industry currently determines that 

measurements have stabilized before 

determining winding resistance using 

both voltmeter-ammeter method and 

resistance bridge methods. 84 FR 20704, 

20719. 

NEMA commented that testing is 

typically done with a computer/ 

electronic automatic test system where 

the feature is provided. NEMA stated 

that its members have not used a 

resistance bridge method in 20 years. 

(NEMA, No. 30 at p. 4) HVOLT and 

CDA commented that both the 

resistance bridge and voltmeterammeter methods should be accurate as 

long as four-time constants have passed. 

(HVOLT, No. 27 at p. 93; CDA, No. 29 

at p. 3) 

Commenters have not suggested that 

there is an issue with the accuracy of 

measurements associated with 

achieving sufficient stability and did not 

suggest that DOE needed to explicitly 

provide for the period of time necessary 

to achieve stability. Therefore, DOE has 

not adopted any amendments related to 

the period of time to achieve stability. 


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30Under the changes adopted in this document, 

section 3.2.2(a) of appendix A is split into section 

3.2.2(a) and section 3.2.2(b). 

31Under the changes adopted in this document, 

this section is redesignated as section 3.2.2(c)(4) of 

appendix A. 

5. Ambient Temperature Tolerances 

In response to the September 2017 

RFI, NEMA recommended that DOE 

increase the ambient temperature 

tolerances for testing dry-type 

transformers, stating that testing may 

otherwise be burdensome in laboratories 

that are not climate controlled, and that 

a mathematical correction factor could 

be developed as an alternative to the 

temperature limits. (NEMA, Docket No. 

EERE–2017–BT–0055–0014 at p. 2) 

In the May 2019 NOPR, DOE 

explained that while widening the 

tolerances of temperatures (or other 

measured parameters) may reduce 

testing cost, it may impact the 

reproducibility and repeatability of the 

test result. 84 FR 20704, 20719–20720. 

Further, NEMA acknowledged that 

manufacturers are not having difficulty 

meeting the temperature requirement. 

(NEMA, Docket No. EERE–2017–BT– 

0055–0014 at p. 8) 

DOE does not have data regarding 

typical ranges of laboratory ambient 

temperature and, as a result, cannot be 

certain that reduction in temperature 

tolerance would not impact 

reproducibility, repeatability, and 

accuracy and cause future test results to 

become incomparable to past data. For 

these reasons, DOE did not propose 

amendments to the laboratory ambient 

temperature and transformer internal 

temperature requirements in the May 

2019 NOPR. 84 FR 20704, 20720. 

Comments received on this issue 

supported maintaining the current 

ambient temperature tolerances. 

(Howard, No. 31 at p. 1; NEMA, No. 30 

at p. 4; CDA, No. 29 at p. 3; HVOLT, No. 

27 at p. 93) For the reasons discussed 

in the May 2019 NOPR and in the 

preceding paragraph, DOE is 

maintaining the ambient temperature 

requirements in appendix A. 

6. Harmonic Current 

Harmonic current refers to electrical 

power at alternating current frequencies 

greater than the fundamental frequency. 

Distribution transformers in service are 

commonly subject to (and must tolerate) 

harmonic current of a degree that varies 

by application. Sections 4.4.1(a) and 

4.4.3.2(a) of appendix A direct use of a 

sinusoidal waveform for evaluating 

efficiency in distribution transformers. 

DOE recognizes that transformers in 

service are subject to a variety of 

harmonic conditions, and that the test 

procedure must provide a common basis 

for comparison. Currently, the test 

procedure states that transformers 

designed for harmonic currents must be 

tested with a sinusoidal waveform (i.e., 

free of harmonic current), but does not 

do so for all other varieties of 

transformers. However, the intent of the 

test procedure is for all transformers to 

be tested with a sinusoidal waveform, as 

is implicit in section 4.4.1(a) of 

appendix A. To clarify this test setup 

requirement, DOE proposed to modify 

section 4.1 of appendix A to read ‘‘. . . 

Test all distribution transformers using 

a sinusoidal waveform (k=1).’’ 84 FR 

20704, 20720 This is consistent with 

industry practice and manufacturers are 

already testing all distribution 

transformers using a sinusoidal 

waveform. Id. 

DOE received several comments in 

support of this clarification and none in 

opposition. (Howard, No. 32 at p. 2; 

NEMA, No. 30 at p. 4; CDA, No. 29 at 

p. 3; HVOLT, No. 27 at p. 93) For the 

reasons discussed in the May 2019 

NOPR and in the preceding paragraph, 

DOE is adopting the clarification 

regarding use of a sinusoidal waveform 

as proposed. 

7. Other Editorial Revisions 

In the May 2019 NOPR, DOE 

proposed the following editorial 

updates to improve the readability of 

the test procedure and provide 

additional detail: (i) Revising ‘‘shall’’ 

(and a single instance of ‘‘should’’ in the 

temperature condition requirements at 

section 3.2.2(b)(3)) to ‘‘must’’ 

throughout appendix A, (ii) clarifying 

the instructional language for recording 

the winding temperature for dry-type 

transformers (section 3.2.2 of appendix 

A), (iii) separating certain sentences into 

enumerated clauses (section 3.2.2(a) of 

appendix A),30 (iv) identifying the 

corresponding resistance measurement 

method sections (section 3.3 of 

appendix A), (v) replacing a reference to 

‘‘uniform test method’’ with ‘‘this 

appendix’’ (section 3.3 of appendix A), 

(vi) removing reference to guidelines 

under section 3.4.1, Required actions, of 

appendix A to clarify that section 

establishes requirements, (vii) 

specifying the maximum amount of time 

for the temperature of the transformer 

windings to stabilize (section 3.2.2(b)(4) 

of appendix A 31), (viii) removing 

references to the test procedure in 10 

CFR 431.196, and (ix) replacing any 

reference to accuracy requirements in 

‘‘section 2.0’’ and/or ‘‘Table 2.0’’ to 

‘‘section 2.3’’ and/or ‘‘Table 2.3,’’ 

accordingly. 84 FR 20704, 20720. 

Section 3.2.2 of appendix A requires 

that, for testing of both ventilated and 

sealed units, the ambient temperature of 

the test area may be used to estimate the 

winding temperature (rather than direct 

measurement of the winding 

temperature), provided a number of 

conditions are met, including the 

condition that neither voltage nor 

current has been applied to the unit 

under test for 24 hours (provided in 

section 3.2.2(b)(4) of appendix A). The 

same section also allows for the time 

period of the initial 24 hours to be 

increased to up to a maximum of an 

additional 24 hours, so as to allow the 

temperature of the transformer windings 

to stabilize at the level of the ambient 

temperature. Based on this requirement, 

the total amount of time allowed would 

be a maximum of 48 hours. As such, in 

the May 2019 NOPR, DOE proposed to 

specify explicitly that, for section 

3.2.2(b)(4) of appendix A, the total 

maximum amount of time allowed is 48 

hours. Id. 

DOE also proposed conforming 

amendments to the energy conservation 

standard provisions. The provisions in 

10 CFR 431.196 establishes energy 

conservation standards for certain 

distribution transformers. Id. 

Immediately following each table of 

standards, a note specifies the 

applicable standard PUL and DOE test 

procedure. For example, in 10 CFR 

431.196(a) the note reads, ‘‘Note: All 

efficiency values are at 35 percent of 

nameplate-rated load, determined 

according to the DOE Test Method for 

Measuring the Energy Consumption of 

Distribution Transformers under 

appendix A to subpart K of 10 CFR part 

431.’’ Because 10 CFR 431.193 already 

requires that testing be in accordance 

with appendix A, DOE proposes to 

remove the references to the test 

procedure in 10 CFR 431.196. DOE 

proposes to maintain the portion of the 

note identifying the PUL corresponding 

to the efficiency values, for continuity 

and clarity. Id. 

As discussed in sections III.F.1 and 

III.F.2 of this final rule, DOE is 

clarifying the PUL and reference 

temperature specifications for 

certification to energy conservation 

standards, and providing PUL and 

reference temperature specifications for 

voluntary representations, with a new 

section 2.1 for PUL requirements and 

section 2.2 for reference temperature 

requirements in appendix A. 

Accordingly, DOE proposed that the 

accuracy requirements previously 

provided in section 2.0 be moved to 

section 2.3 in appendix A. In addition, 

DOE proposed to re-number Table 2.1, 

Test System Accuracy Requirements for 

Each Measured Quantity, to Table 2.3. 

Lastly, DOE proposed to update crossVerDate Sep<11>2014 20:08 Sep 13, 2021 Jkt 253001 PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 E:\FR\FM\14SER2.SGM 14SER2

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references in appendix A to the 

accuracy requirements in section 2.0 

and/or Table 2.1, to section 2.3 and/or 

Table 2.3. The cross-references occur in 

sections 3.1(b), 3.3.3, 3.4.2(a), 4.3(a), 6.0, 

and 6.2 of appendix A. 

DOE did not receive any comment in 

opposition to these edits and is adopting 

them in the test procedure. 

NEMA noted certain errors in the 

equation references in section 4 of 

appendix A. (NEMA, No. 30 at p. 5) 

Specifically, NEMA stated that the load 

loss power (Plc1) appears with subscripts 

‘‘LCL’’, ‘‘LCI’’, and ‘‘LC1’’ (capital letters 

used for clarity, but lower case used in 

the text). Id. DOE has reviewed the 

subscripts in section 4 of appendix A 

and corrected each instance to ‘‘LC1’’ 

(capitalized here for clarity) where 

necessary. 

NEMA also noted that there is 

potential confusion regarding which 

reference temperature should be used in 

section 4.5.3.3 of appendix A. NEMA 

suggested to clarify the text as follows: 

‘‘When the measurement of load loss is 

made at a temperature Tim that is 

different from the reference 

temperature, use the procedure 

summarized in the equations 4–6 to 4– 

10 to correct the measured load loss to 

the reference temperature (as defined in 

3.5 (a)).’’ (NEMA, No. 30 at p. 5–6) This 

final rule includes a new section, 

section 2.2 of appendix A, to specify 

reference temperature in a centralized 

location, as described in section III.F.2 

of this document. In view of the new 

requirement, NEMA’s suggested edits to 

specify reference temperature in section 

4.5.3.3 are redundant. 

PG&E commented in response to the 

May 2019 NOPR that in order to 

properly comment, it would like a 

before and after document of proposed 

changes to the CFR. (PG&E, No. 33 at p. 

1) The May 2019 NOPR includes a 

synopsis table of the proposed changes, 

including a side-by-side comparison of 

the current DOE TP language, the 

proposed test procedure language, and 

attribution of the changes. 84 FR 20704, 

20706. Further, DOE published all 

proposed regulatory text in the May 

2019 NOPR which could be juxtaposed 

with the current CFR in order to 

perform the comparison PG&E 

describes. 84 FR 20704, 20727–20730. 

G. Effective and Compliance Dates 

The effective date for the adopted test 

procedure amendment is 30 days after 

publication of this final rule in the 

Federal Register. EPCA prescribes that 

all representations of energy efficiency 

and energy use, including those made 

on marketing materials and product 

labels, must be made in accordance with 

an amended test procedure, beginning 

180 days after publication of the final 

rule in the Federal Register. (42 U.S.C. 

6293(c)(2); 42 U.S.C. 6314(d)(1)) EPCA 

provides an allowance for individual 

manufacturers to petition DOE for an 

extension of the 180-day period if the 

manufacturer may experience undue 

hardship in meeting the deadline. (42 

U.S.C. 6293(c)(3); 42 U.S.C. 6314(d)(2)) 

To receive such an extension, petitions 

must be filed with DOE no later than 60 

days before the end of the 180-day 

period and must detail how the 

manufacturer will experience undue 

hardship. (Id.) 

H. Test Procedure Costs 

In this final rule, DOE is amending 

the existing test procedure for 

distribution transformers by revising 

certain definitions, incorporating new 

definitions, incorporating revisions 

based on the latest versions of the IEEE 

industry testing standards, including 

provisions to allow manufacturers to 

use the DOE test procedure to make 

voluntary representations at additional 

PULs and/or reference temperatures, 

and reorganizing content among 

relevant sections of the CFR to improve 

readability. The adopted amendments 

primarily provide updates and 

supplemental details for how to conduct 

the test procedure and do not add 

complexity to test conditions/setup or 

add test steps. In accordance with 

EPCA, DOE has determined that these 

adopted amendments will not be 

unduly burdensome for manufacturers 

to conduct. Further, DOE has 

determined that the adopted test 

procedure amendments will not impact 

testing costs already experienced by 

manufacturers. DOE estimated, based on 

a test quote from a laboratory, that the 

cost for testing distribution transformers 

using the existing test procedure is 

approximately $400 per unit tested and 

that this figure will not change in 

response to the adopted test procedure 

amendments. In summary, the adopted 

test procedure amendments reflect and 

codify current industry practice. 

As previously described in the May 

2019 NOPR, the adopted amendments 

will not impact the scope of the test 

procedure. The adopted amendments 

will not require the testing of 

distribution transformers not already 

subject to the test procedure at 10 CFR 

431.193 (i.e., the adopted amendments 

will not require manufacturers to test 

autotransformers, drive (isolation) 

transformers, grounding transformers, 

machine-tool (control) transformers, 

nonventilated transformers, rectifier 

transformers, regulating transformers, 

sealed transformer; special-impedance 

transformer; testing transformer; 

transformer with tap range of 20 percent 

or more; uninterruptible power supply 

transformer; or welding transformer, 

which are presently not subject to 

testing). The adopted amendments will 

not alter the measured energy efficiency 

or energy use of the distribution 

transformers. Manufacturers will be able 

to rely on data generated under the 

current test procedure. Further, the 

adopted amendments will not require 

the purchase of additional equipment 

for testing. 

In the May 2019 NOPR, DOE 

described why the proposed test 

procedure amendments would not add 

costs to manufacturers. In response, 

manufacturers commented stating the 

proposed testing should not increase 

testing costs for any manufacturers. 

(Howard, No. 32 at p. 2; CDA, No. 29 

at p. 3–4; HVOLT, No. 27 at p. 91–93) 

NEMA commented that it does not 

anticipate any negative impact or 

increased costs associated with any of 

the proposed changes but stressed that 

DOE continue to allow manufacturers to 

certify distribution transformers using 

an AEDM as is allowed at 10 CFR 

429.70(d) in order to minimize testing 

costs. (NEMA, No. 30 at p. 4) DOE notes 

that it has not proposed or adopted any 

changes to 10 CFR 429.70(d), and 

manufacturers are permitted to use an 

AEDM for means of certifying 

distribution transformer efficiency to 

DOE. 

IV. Procedural Issues and Regulatory 

Review 

A. Review Under Executive Order 12866 

The Office of Management and Budget 

(‘‘OMB’’) has determined this test 

procedure rulemaking does not 

constitute a ‘‘significant regulatory 

action’’ under section 3(f) of Executive 

Order (‘‘E.O.’’) 12866, Regulatory 

Planning and Review, 58 FR 51735 (Oct. 

4, 1993). Accordingly, this action was 

not subject to review under the 

Executive order by the Office of 

Information and Regulatory Affairs 

(‘‘OIRA’’) in OMB. 

B. Review Under the Regulatory 

Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. 601 et seq.) requires preparation 

of a final regulatory flexibility analysis 

(‘‘FRFA’’) for any final rule where the 

agency was first required by law to 

publish a proposed rule for public 

comment, unless the agency certifies 

that the rule, if promulgated, will not 

have a significant economic impact on 

a substantial number of small entities. 

As required by Executive Order 13272, 


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51250 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

‘‘Proper Consideration of Small Entities 

in Agency Rulemaking,’’ 67 FR 53461 

(August 16, 2002), DOE published 

procedures and policies on February 19, 

2003 to ensure that the potential 

impacts of its rules on small entities are 

properly considered during the DOE 

rulemaking process. 68 FR 7990. DOE 

has made its procedures and policies 

available on the Office of the General 

Counsel’s website: https://energy.gov/ 

gc/office-general-counsel. 

As stated, the amendments adopted in 

this final rule revise certain definitions, 

incorporate new definitions, incorporate 

revisions based on the latest versions of 

the IEEE industry testing standards, 

include provisions to allow 

manufacturers to use the DOE test 

procedure to make voluntary 

representations at additional PULs and/ 

or reference temperatures, and 

reorganize content among relevant 

sections of the CFR to improve 

readability. DOE has determined that 

the adopted test procedure amendments 

would not impact testing costs already 

experienced by manufacturers. NEMA, 

CDA, and HVOLT commented that they 

do not anticipate any undue burden on 

small businesses or small 

manufacturers. (NEMA, No. 30 at p. 5; 

CDA, No. 29 at p. 4; HVOLT, No. 27 at 

p. 94) 

Therefore, DOE concludes that the 

cost effects accruing from the final rule 

would not have a ‘‘significant economic 

impact on a substantial number of small 

entities,’’ and that the preparation of a 

FRFA is not warranted. DOE has 

submitted a certification and supporting 

statement of factual basis to the Chief 

Counsel for Advocacy of the Small 

Business Administration for review 

under 5 U.S.C. 605(b). 

C. Review Under the Paperwork 

Reduction Act of 1995 

Manufacturers of distribution 

transformers must certify to DOE that 

their products comply with any 

applicable energy conservation 

standards. To certify compliance, 

manufacturers must first obtain test data 

for their products according to the DOE 

test procedure, including any 

amendments adopted for that test 

procedure. DOE has established 

regulations for the certification and 

recordkeeping requirements for all 

covered consumer products and 

commercial equipment, including 

distribution transformers. (See generally 

10 CFR part 429.) The collection-ofinformation requirement for the 

certification and recordkeeping is 

subject to review and approval by OMB 

under the Paperwork Reduction Act 

(PRA). This requirement has been 

approved by OMB under OMB control 

number 1910–1400. Public reporting 

burden for the certification is estimated 

to average 35 hours per response, 

including the time for reviewing 

instructions, searching existing data 

sources, gathering and maintaining the 

data needed, and completing and 

reviewing the collection of information. 

The amendments adopted in this final 

rule do not impact the certification and 

reporting requirements for distribution 

transformers. 

Notwithstanding any other provision 

of the law, no person is required to 

respond to, nor shall any person be 

subject to a penalty for failure to comply 

with, a collection of information subject 

to the requirements of the PRA, unless 

that collection of information displays a 

currently valid OMB Control Number. 

D. Review Under the National 

Environmental Policy Act of 1969 

Pursuant to the National 

Environmental Policy Act of 1969 

(‘‘NEPA’’), DOE has analyzed this action 

in accordance with NEPA and DOE’s 

NEPA implementing regulations (10 

CFR part 1021). DOE has determined 

that this rule qualifies for categorical 

exclusion under 10 CFR part 1021, 

subpart D, appendix A5, because it is an 

interpretive rulemaking that does not 

change the environmental effect of the 

rule and meets the requirements for 

application of a CX. See 10 CFR 

1021.410. Therefore, DOE has 

determined that promulgation of this 

rule is not a major Federal action 

significantly affecting the quality of the 

human environment within the meaning 

of NEPA and does not require an EA or 

EIS. 

E. Review Under Executive Order 13132 

Executive Order 13132, ‘‘Federalism,’’ 

64 FR 43255 (August 4, 1999), imposes 

certain requirements on agencies 

formulating and implementing policies 

or regulations that preempt State law or 

that have federalism implications. The 

Executive order requires agencies to 

examine the constitutional and statutory 

authority supporting any action that 

would limit the policymaking discretion 

of the States and to carefully assess the 

necessity for such actions. The 

Executive order also requires agencies to 

have an accountable process to ensure 

meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications. On March 14, 2000, DOE 

published a statement of policy 

describing the intergovernmental 

consultation process it will follow in the 

development of such regulations. 65 FR 

13735. DOE examined this final rule 

and determined that it will not have a 

substantial direct effect on the States, on 

the relationship between the National 

Government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government. EPCA governs and 

prescribes Federal preemption of State 

regulations as to energy conservation for 

the products that are the subject of this 

final rule. States can petition DOE for 

exemption from such preemption to the 

extent, and based on criteria, set forth in 

EPCA. (42 U.S.C. 6297(d)) No further 

action is required by Executive Order 

13132. 

F. Review Under Executive Order 12988 

Regarding the review of existing 

regulations and the promulgation of 

new regulations, section 3(a) of 

Executive Order 12988, ‘‘Civil Justice 

Reform,’’ 61 FR 4729 (Feb. 7, 1996), 

imposes on Federal agencies the general 

duty to adhere to the following 

requirements: (1) Eliminate drafting 

errors and ambiguity; (2) write 

regulations to minimize litigation; (3) 

provide a clear legal standard for 

affected conduct rather than a general 

standard; and (4) promote simplification 

and burden reduction. Section 3(b) of 

Executive Order 12988 specifically 

requires that executive agencies make 

every reasonable effort to ensure that the 

regulation (1) clearly specifies the 

preemptive effect, if any; (2) clearly 

specifies any effect on existing Federal 

law or regulation; (3) provides a clear 

legal standard for affected conduct 

while promoting simplification and 

burden reduction; (4) specifies the 

retroactive effect, if any; (5) adequately 

defines key terms; and (6) addresses 

other important issues affecting clarity 

and general draftsmanship under any 

guidelines issued by the Attorney 

General. Section 3(c) of Executive Order 

12988 requires executive agencies to 

review regulations in light of applicable 

standards in sections 3(a) and 3(b) to 

determine whether they are met, or it is 

unreasonable to meet one or more of 

them. DOE has completed the required 

review and determined that, to the 

extent permitted by law, this final rule 

meets the relevant standards of 

Executive Order 12988. 

G. Review Under the Unfunded 

Mandates Reform Act of 1995 

Title II of the Unfunded Mandates 

Reform Act of 1995 (‘‘UMRA’’) requires 

each Federal agency to assess the effects 

of Federal regulatory actions on State, 

local, and Tribal governments, and the 

private sector. Public Law 104–4, sec. 

201 (codified at 2 U.S.C. 1531). For a 

regulatory action resulting in a rule that 


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may cause the expenditure by State, 

local, and Tribal governments, in the 

aggregate, or by the private sector of 

$100 million or more in any one year 

(adjusted annually for inflation), section 

202 of UMRA requires a Federal agency 

to publish a written statement that 

estimates the resulting costs, benefits, 

and other effects on the national 

economy. (2 U.S.C. 1532(a), (b)) The 

UMRA also requires a Federal agency to 

develop an effective process to permit 

timely input by elected officers of State, 

local, and Tribal governments on a 

proposed ‘‘significant intergovernmental 

mandate,’’ and requires an agency plan 

for giving notice and opportunity for 

timely input to potentially affected 

small governments before establishing 

any requirements that might 

significantly or uniquely affect small 

governments. On March 18, 1997, DOE 

published a statement of policy on its 

process for intergovernmental 

consultation under UMRA. 62 FR 

12820; also available at https://

energy.gov/gc/office-general-counsel. 

DOE examined this final rule according 

to UMRA and its statement of policy 

and determined that the rule contains 

neither an intergovernmental mandate, 

nor a mandate that may result in the 

expenditure of $100 million or more in 

any year, so these requirements do not 

apply. 

H. Review Under the Treasury and 

General Government Appropriations 

Act, 1999 

Section 654 of the Treasury and 

General Government Appropriations 

Act, 1999 (Pub. L. 105–277) requires 

Federal agencies to issue a Family 

Policymaking Assessment for any rule 

that may affect family well-being. This 

final rule will not have any impact on 

the autonomy or integrity of the family 

as an institution. Accordingly, DOE has 

concluded that it is not necessary to 

prepare a Family Policymaking 

Assessment. 

I. Review Under Executive Order 12630 

DOE has determined, under Executive 

Order 12630, ‘‘Governmental Actions 

and Interference with Constitutionally 

Protected Property Rights’’ 53 FR 8859 

(March 18, 1988), that this regulation 

will not result in any takings that might 

require compensation under the Fifth 

Amendment to the U.S. Constitution. 

J. Review Under Treasury and General 

Government Appropriations Act, 2001 

Section 515 of the Treasury and 

General Government Appropriations 

Act, 2001 (44 U.S.C. 3516 note) provides 

for agencies to review most 

disseminations of information to the 

public under guidelines established by 

each agency pursuant to general 

guidelines issued by OMB. OMB’s 

guidelines were published at 67 FR 

8452 (Feb. 22, 2002), and DOE’s 

guidelines were published at 67 FR 

62446 (Oct. 7, 2002). Pursuant to OMB 

Memorandum M–19–15, Improving 

Implementation of the Information 

Quality Act (April 24, 2019), DOE 

published updated guidelines which are 

available at www.energy.gov/sites/prod/ 

files/2019/12/f70/DOE%20

Final%20Updated%20

IQA%20Guidelines%20

Dec%202019.pdf. DOE has reviewed 

this final rule under the OMB and DOE 

guidelines and has concluded that it is 

consistent with applicable policies in 

those guidelines. 

K. Review Under Executive Order 13211 

Executive Order 13211, ‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use,’’ 66 FR 28355 (May 

22, 2001), requires Federal agencies to 

prepare and submit to OMB, a 

Statement of Energy Effects for any 

significant energy action. A ‘‘significant 

energy action’’ is defined as any action 

by an agency that promulgated or is 

expected to lead to promulgation of a 

final rule, and that (1) is a significant 

regulatory action under Executive Order 

12866, or any successor order; and (2) 

is likely to have a significant adverse 

effect on the supply, distribution, or use 

of energy; or (3) is designated by the 

Administrator of OIRA as a significant 

energy action. For any significant energy 

action, the agency must give a detailed 

statement of any adverse effects on 

energy supply, distribution, or use if the 

regulation is implemented, and of 

reasonable alternatives to the action and 

their expected benefits on energy 

supply, distribution, and use. 

This regulatory action is not a 

significant regulatory action under 

Executive Order 12866. Moreover, it 

would not have a significant adverse 

effect on the supply, distribution, or use 

of energy, nor has it been designated as 

a significant energy action by the 

Administrator of OIRA. Therefore, it is 

not a significant energy action, and, 

accordingly, DOE has not prepared a 

Statement of Energy Effects. 

L. Review Under Section 32 of the 

Federal Energy Administration Act of 

1974 

Under section 301 of the Department 

of Energy Organization Act (Pub. L. 95– 

91; 42 U.S.C. 7101), DOE must comply 

with section 32 of the Federal Energy 

Administration Act of 1974, as amended 

by the Federal Energy Administration 

Authorization Act of 1977. (15 U.S.C. 

788; ‘‘FEAA’’) Section 32 essentially 

provides in relevant part that, where a 

proposed rule authorizes or requires use 

of commercial standards, the notice of 

proposed rulemaking must inform the 

public of the use and background of 

such standards. In addition, section 

32(c) requires DOE to consult with the 

Attorney General and the Chairman of 

the Federal Trade Commission (‘‘FTC’’) 

concerning the impact of the 

commercial or industry testing 

standards on competition. 

The modifications to the test 

procedure for distribution transformers 

adopted in this final rule do not 

incorporate testing methods contained 

in commercial standards. Therefore, the 

requirements of section 32(b) of the 

FEAA do not apply. 

M. Congressional Notification 

As required by 5 U.S.C. 801, DOE will 

report to Congress on the promulgation 

of this rule before its effective date. The 

report will state that it has been 

determined that the rule is not a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). 

V. Approval of the Office of the 

Secretary 

The Secretary of Energy has approved 

publication of this final rule. 

List of Subjects in 10 CFR Part 431 

Administrative practice and 

procedure, Confidential business 

information, Energy conservation test 

procedures, and Reporting and 

recordkeeping requirements. 

Signing Authority 

This document of the Department of 

Energy was signed on September 2, 

2021, by Kelly Speakes-Backman, 

Principal Deputy Assistant Secretary 

and Acting Assistant Secretary for 

Energy Efficiency and Renewable 

Energy, pursuant to delegated authority 

from the Secretary of Energy. That 

document with the original signature 

and date is maintained by DOE. For 

administrative purposes only, and in 

compliance with requirements of the 


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51252 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

Office of the Federal Register, the 

undersigned DOE Federal Register 

Liaison Officer has been authorized to 

sign and submit the document in 

electronic format for publication, as an 

official document of the Department of 

Energy. This administrative process in 

no way alters the legal effect of this 

document upon publication in the 

Federal Register. 

Signed in Washington, DC, on September 

2, 2021. 

Treena V. Garrett, 

Federal Register Liaison Officer, U.S. 

Department of Energy. 

For the reasons stated in the 

preamble, DOE amends part 431 of 

chapter II of title 10, Code of Federal 

Regulations as set forth below: 

PART 431—ENERGY EFFICIENCY 

PROGRAM FOR CERTAIN 

COMMERCIAL AND INDUSTRIAL 

EQUIPMENT 

■ 1. The authority citation for part 431 

continues to read as follows: 

Authority: 42 U.S.C. 6291–6317; 28 U.S.C. 

2461 note. 

■ 2. Section 431.192 is amended by: 

■ a. Adding in alphabetical order the 

definition for Auxiliary device; 

■ b. Revising the definition of Lowvoltage dry-type distribution 

transformer; 

■ c. Adding in alphabetical order the 

definition for Per-unit load; 

■ d. Revising the definition of Reference 

temperature; and 

■ e. Adding in alphabetical order the 

definition for Terminal. 

The additions and revisions read as 

follows: 

§ 431.192 Definitions. 

* * * * * 

Auxiliary device means a localized 

component of a distribution transformer 

that is a circuit breaker, switch, fuse, or 

surge/lightning arrester. 

* * * * * 

Low-voltage dry-type distribution 

transformer means a distribution 

transformer that has an input voltage of 

600 volts or less and has the core and 

coil assembly immersed in a gaseous or 

dry-compound insulating medium. 

* * * * * 

Per-unit load means the fraction of 

rated load. 

* * * * * 

Reference temperature means the 

temperature at which the transformer 

losses are determined, and to which 

such losses are corrected if testing is 

done at a different point. (Reference 

temperature values are specified in the 

test method in appendix A to this 

subpart.) 

* * * * * 

Terminal means a conducting element 

of a distribution transformer providing 

electrical connection to an external 

conductor that is not part of the 

transformer. 

* * * * * 

■ 3. Section 431.193 is revised to read 

as follows: 

§ 431.193 Test procedure for measuring 

energy consumption of distribution 

transformers. 

The test procedure for measuring the 

energy efficiency of distribution 

transformers for purposes of EPCA is 

specified in appendix A to this subpart. 

The test procedure specified in 

appendix A to this subpart applies only 

to distribution transformers subject to 

energy conservation standards at 

§ 431.196. 

■ 4. Section 431.196 is amended by 

revising the Notes in paragraphs (a)(1) 

and (2), (b)(1) and (2), and (c)(1) and (2) 

to read as follows: 

§ 431.196 Energy conservation standards 

and their effective dates. 

(a) * * * 

(1) * * * 

Note 1 to paragraph (a)(1): All efficiency 

values are at 35 percent per-unit load. 

(2) * * * 

Note 2 to paragraph (a)(2): All efficiency 

values are at 35 percent per-unit load. 

(b) * * * 

(1) * * * 

Note 3 to paragraph (b)(1): All efficiency 

values are at 50 percent per-unit load. 

(2) * * * 

Note 4 to paragraph (b)(2): All efficiency 

values are at 50 percent per-unit load. 

(c) * * * 

(1) * * * 

Note 5 to paragraph (c)(1): All efficiency 

values are at 50 percent per-unit load. 

(2) * * * 

Note 6 to paragraph (c)(2): All efficiency 

values are at 50 percent per-unit load. 

* * * * * 

■ 5. Appendix A to subpart K of part 

431 is amended by: 

■ a. In section 2.0: 

■ i. Revising the section heading; 

■ ii. Removing paragraphs (a) and (b); 

and 

■ iii. Adding sections 2.1, 2.2, and 2.3; 

■ b. Adding paragraph (c) to section 3.1; 

■ c. Revising section 3.2.1.1; 

■ d. Revising paragraph (b) in section 

3.2.1.2; 

■ e. Revising section 3.2.2; 

■ f. Revising section 3.3; 

■ g. Revising paragraph (a) introductory 

text and paragraph (b) in section 3.3.2; 

■ h. Revising section 3.3.3; 

■ i. Revising the introductory text and 

adding paragraphs (f), (g), (h), and (i) in 

section 3.4.1; 

■ j. Revising paragraph (a) in section 

3.4.2; 

■ k. Revising paragraph (a) in section 

3.5; 

■ l. Revising section 4.1; 

■ m. Revising paragraph (a) and adding 

paragraph (c) in section 4.3; 

■ n. Revising section 4.4.3.3; 

■ o. Revising paragraph (c) of section 

4.5.3.2; 

■ p. Revising section 5.1; 

■ q. Revising section 6.0; 

■ r. Revising section 6.1; 

■ s. Revising paragraph (a) in section 

6.2; and 

■ t. Adding section 7.0. 

The additions and revisions read as 

follows: 

Appendix A to Subpart K of Part 431— 

Uniform Test Method for Measuring the 

Energy Consumption of Distribution 

Transformers 

* * * * * 

2.0 Per-Unit Load, Reference Temperature, 

and Accuracy Requirements 

2.1 Per-Unit Load 

In conducting the test procedure in this 

appendix for the purpose of: 

(a) Certification to an energy conservation 

standard, the applicable per-unit load in 

Table 2.1 must be used; or 

(b) Making voluntary representations as 

provided in section 7.0 at an additional perunit load, select the per-unit load of interest. 

TABLE 2.1—PER-UNIT LOAD FOR CERTIFICATION TO ENERGY CONSERVATION STANDARDS

Distribution transformer category 

Per-unit 

load 

(percent) 

Liquid-immersed ......................... 50 

Medium-voltage dry-type ............ 50 

Low-voltage dry-type .................. 35 

2.2 Reference Temperature 

In conducting the test procedure in this 

appendix for the purpose of: 

(a) Certification to an energy conservation 

standard, the applicable reference 

temperature in Table 2.2 must be used; or 

(b) Making voluntary representations as 

provided in section 7.0 at an additional 

reference temperature, select the reference 

temperature of interest. 


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TABLE 2.2—REFERENCE TEMPERATURE FOR CERTIFICATION TO ENERGY CONSERVATION STANDARDS

Distribution transformer 

category Reference temperature 

Liquid-immersed ............. 20 °C for no-load loss. 

55 °C for load loss. 

Medium-voltage dry-type 20 °C for no-load loss. 

75 °C for load loss. 

Low-voltage dry-type ...... 20 °C for no-load loss. 

75 °C for load loss. 

2.3 Accuracy Requirements 

(a) Equipment and methods for loss 

measurement must be sufficiently accurate 

that measurement error will be limited to the 

values shown in Table 2.3. 

TABLE 2.3—TEST SYSTEM ACCURACY

REQUIREMENTS FOR EACH MEASURED QUANTITY

Measured 

quantity 

Test system 

accuracy 

Power Losses .... ±3.0%. 

Voltage .............. ±0.5%. 

Current ............... ±0.5%. 

Resistance ......... ±0.5%. 

Temperature ...... ±1.5 °C for liquid-immersed distribution transformers, and 

±2.0 °C for low-voltage dry-type 

and medium-voltage dry-type 

distribution transformers. 

(b) Only instrument transformers meeting 

the 0.3 metering accuracy class, or better, 

may be used under this test method. 

3.0 * * * 

3.1 General Considerations 

* * * * * 

(c) Measure the direct current resistance 

(Rdc) of transformer windings by one of the 

methods outlined in section 3.3. The 

methods of section 3.5 must be used to 

correct load losses to the applicable reference 

temperature from the temperature at which 

they are measured. Observe precautions 

while taking measurements, such as those in 

section 3.4, in order to maintain 

measurement uncertainty limits specified in 

Table 2.3 of this appendix. 

* * * * * 

3.2.1.1 Methods 

Record the winding temperature (Tdc) of 

liquid-immersed transformers as the average 

of either of the following: 

(a) The measurements from two 

temperature sensing devices (for example, 

thermocouples) applied to the outside of the 

transformer tank and thermally insulated 

from the surrounding environment, with one 

located at the level of the insulating liquid 

and the other located near the tank bottom 

or at the lower radiator header if applicable; 

or 

(b) The measurements from two 

temperature sensing devices immersed in the 

insulating liquid, with one located directly 

above the winding and other located directly 

below the winding. 

3.2.1.2 Conditions 

* * * * * 

(b) The temperature of the insulating liquid 

has stabilized, and the difference between the 

top and bottom temperature does not exceed 

5 °C. The temperature of the insulating liquid 

is considered stable if the top liquid 

temperature does not vary more than 2 °C in 

a 1-h period. 

3.2.2 Dry-Type Distribution Transformers 

Record the winding temperature (Tdc) of 

dry-type transformers as one of the following: 

(a) For ventilated dry-type units, use the 

average of readings of four or more 

thermometers, thermocouples, or other 

suitable temperature sensors inserted within 

the coils. Place the sensing points of the 

measuring devices as close as possible to the 

winding conductors; or 

(b) For sealed units, such as epoxy-coated 

or epoxy-encapsulated units, use the average 

of four or more temperature sensors located 

on the enclosure and/or cover, as close to 

different parts of the winding assemblies as 

possible; or 

(c) For ventilated units or sealed units, use 

the ambient temperature of the test area, only 

if the following conditions are met: 

(1) All internal temperatures measured by 

the internal temperature sensors must not 

differ from the test area ambient temperature 

by more than 2 °C. Enclosure surface 

temperatures for sealed units must not differ 

from the test area ambient temperature by 

more than 2 °C. 

(2) Test area ambient temperature must not 

have changed by more than 3 °C for 3 hours 

before the test. 

(3) Neither voltage nor current has been 

applied to the unit under test for 24 hours. 

In addition, increase this initial 24-hour 

period by any added amount of time 

necessary for the temperature of the 

transformer windings to stabilize at the level 

of the ambient temperature. However, this 

additional amount of time need not exceed 

24 hours (i.e., after 48 hours, the transformer 

windings can be assumed to have stabilized 

at the level of the ambient temperature. Any 

stabilization time beyond 48 hours is 

optional). 

3.3 Resistance Measurement Methods 

Make resistance measurements using either 

the resistance bridge method (section 3.3.1), 

the voltmeter-ammeter method (section 3.3.2) 

or resistance meters (section 3.3.3). In each 

instance when this appendix is used to test 

more than one unit of a basic model to 

determine the efficiency of that basic model, 

the resistance of the units being tested may 

be determined from making resistance 

measurements on only one of the units. 

* * * * * 

3.3.2 Voltmeter-Ammeter Method 

(a) Employ the voltmeter-ammeter method 

only if the test current is limited to 15 

percent of the winding current. Connect the 

transformer winding under test to the circuit 

shown in Figure 3.3 of this appendix. 

* * * * * 

(b) To perform the measurement, turn on 

the source to produce current no larger than 

15 percent of the rated current for the 

winding. Wait until the current and voltage 

readings have stabilized and then take a 

minimum of four readings of voltage and 

current. Voltage and current readings must be 

taken simultaneously for each of the 

readings. Calculate the average voltage and 

average current using the readings. 

Determine the winding resistance Rdc by 

using equation 3–4 as follows: 

Where: 

Vmdc is the average voltage measured by the 

voltmeter V; and 

Imdc is the average current measured by the 

ammeter (A). 

* * * * * 

3.3.3 Resistance Meters 

Resistance meters may be based on 

voltmeter-ammeter, or resistance bridge, or 

some other operating principle. Any meter 

used to measure a transformer’s winding 

resistance must have specifications for 

resistance range, current range, and ability to 

measure highly inductive resistors that cover 

the characteristics of the transformer being 

tested. Also, the meter’s specifications for 

accuracy must meet the applicable criteria of 

Table 2.3 in section 2.3 of this appendix. 

* * * * * 

3.4.1 Required Actions 

The following requirements must be 

observed when making resistance 

measurements: 

* * * * * 

(f) Keep the polarity of the core 

magnetization constant during all resistance 

measurements. 

(g) For single-phase windings, measure the 

resistance from terminal to terminal. The 

total winding resistance is the terminal-toterminal measurement. For series-parallel 

windings, the total winding resistance is the 

sum of the series terminal-to-terminal section 

measurements. 

(h) For wye windings, measure the 

resistance from terminal to terminal or from 

terminal to neutral. For the total winding 

resistance, the resistance of the lead from the 

neutral connection to the neutral bushing 

may be excluded. For terminal-to-terminal 

measurements, the total resistance reported is 

the sum of the three measurements divided 

by two. 

(i) For delta windings, measure resistance 

from terminal to terminal with the delta 

closed or from terminal to terminal with the 


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51254 Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 

delta open to obtain the individual phase 

readings. The total winding resistance is the 

sum of the three-phase readings if the delta 

is open. If the delta is closed, the total 

winding resistance is the sum of the three 

phase-to-phase readings times 1.5. 

3.4.2 Guideline for Time Constant 

(a) The following guideline is suggested for 

the tester as a means to facilitate the 

measurement of resistance in accordance 

with the accuracy requirements of section 

2.3: 

* * * * * 

3.5 Conversion of Resistance Measurements 

(a) Resistance measurements must be 

corrected from the temperature at which the 

winding resistance measurements were 

made, to the reference temperature. 

* * * * * 

4.0 * * * 

4.1 General Considerations 

The efficiency of a transformer is 

computed from the total transformer losses, 

which are determined from the measured 

value of the no-load loss and load loss power 

components. Each of these two power loss 

components is measured separately using test 

sets that are identical, except that shorting 

straps are added for the load-loss test. The 

measured quantities need correction for 

instrumentation losses and may need 

corrections for known phase angle errors in 

measuring equipment and for the waveform 

distortion in the test voltage. Any power loss 

not measured at the applicable reference 

temperature must be adjusted to that 

reference temperature. The measured load 

loss must also be adjusted to a specified 

output loading level if not measured at the 

specified output loading level. Test all 

distribution transformers using a sinusoidal 

waveform (k = 1). Measure losses with the 

transformer energized by a 60 Hz supply. 

* * * * * 

4.3 Test Sets 

(a) The same test set may be used for both 

the no-load loss and load loss measurements 

provided the range of the test set 

encompasses the test requirements of both 

tests. Calibrate the test set to national 

standards to meet the tolerances in Table 2.3 

in section 2.3 of this appendix. In addition, 

the wattmeter, current measuring system and 

voltage measuring system must be calibrated 

separately if the overall test set calibration is 

outside the tolerance as specified in section 

2.3 or the individual phase angle error 

exceeds the values specified in section 4.5.3. 

* * * * * 

(c) Both load loss and no-load loss 

measurements must be made from terminal 

to terminal. 

* * * * * 

4.4.3.3 Correction of No-Load Loss to 

Reference Temperature 

After correcting the measured no-load loss 

for waveform distortion, correct the loss to 

the reference temperature. For both 

certification to energy conservation standards 

and voluntary representations, if the 

correction to reference temperature is 

applied, then the core temperature of the 

transformer during no-load loss measurement 

(Tnm) must be determined within ±10 °C of 

the true average core temperature. For 

certification to energy conservation standards 

only, if the no-load loss measurements were 

made between 10 °C and 30 °C, this 

correction is not required. Correct the noload loss to the reference temperature by 

using equation 4–2 as follows: 

Where: 

Pnc is the no-load losses corrected for 

waveform distortion and then to the 

reference temperature; 

Pnc1 is the no-load losses, corrected for 

waveform distortion, at temperature Tnm; 

Tnm is the core temperature during the 

measurement of no-load losses; and 

Tnr is the reference temperature. 

* * * * * 

4.5.3.2 Correction for Phase Angle Errors 

* * * * * 

(c) If the correction for phase angle errors 

is to be applied, first examine the total 

system phase angle (bw¥bv + bc). Where the 

total system phase angle is equal to or less 

than ±12 milliradians (±41 minutes), use 

either equation 4–4 or 4–5 to correct the 

measured load loss power for phase angle 

errors, and where the total system phase 

angle exceeds ±12 milliradians (±41 minutes) 

use equation 4–5, as follows: 

* * * * * 5.0 * * * 

5.1 Output Loading Level Adjustment 

If the per-unit load selected in section 2.1 

is different from the per-unit load at which 

the load loss power measurements were 

made, then adjust the corrected load loss 

power, Plc2, by using equation 5–1 as follows: 

Where: 

Plc is the adjusted load loss power to the perunit load; 

Plc2 is as calculated in section 4.5.3.3; 

Por is the rated transformer apparent power 

(name plate); 

Pos is the adjusted rated transformer apparent 

power, where Pos = PorL; and 

L is the per-unit load, e.g., if the per-unit load 

is 50 percent then ‘‘L’’ is 0.5. 

* * * * * 

6.0 Test Equipment Calibration and 

Certification 

Maintain and calibrate test equipment and 

measuring instruments, maintain calibration 

records, and perform other test and 

measurement quality assurance procedures 

according to the following sections. The 

calibration of the test set must confirm the 

accuracy of the test set to that specified in 

section 2.3, Table 2.3 of this appendix. 

6.1 Test Equipment 

The party performing the tests must 

control, calibrate, and maintain measuring 

and test equipment, whether or not it owns 

the equipment, has the equipment on loan, 

or the equipment is provided by another 

party. Equipment must be used in a manner 

which assures that measurement uncertainty 

is known and is consistent with the required 

measurement capability. 

6.2 Calibration and Certification 

* * * * * 


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P1c1 = Vzmllm cos( ({J + f3w - f3v + f3c) 

(4-2) 

(4-4) 

(4-5) 

(5-1) 
Federal Register / Vol. 86, No. 175 / Tuesday, September 14, 2021 / Rules and Regulations 51255 

(a) Identify the measurements to be made, 

the accuracy required (section 2.3) and select 

the appropriate measurement and test 

equipment; 

* * * * * 

7.0 Test Procedure for Voluntary 

Representations 

Follow sections 1.0 through 6.0 of this 

appendix using the per-unit load and/or 

reference temperature of interest for 

voluntary representations of efficiency, and 

corresponding values of load loss and noload loss at additional per-unit load and/or 

reference temperature. Representations made 

at a per-unit load and/or reference 

temperature other than those required to 

comply with the energy conservation 

standards at § 431.196 must be in addition to, 

and not in place of, a representation at the 

required DOE settings for per-unit load and 

reference temperature. As a best practice, the 

additional settings of per-unit load and 

reference temperature should be provided 

with the voluntary representations. 

[FR Doc. 2021–19366 Filed 9–13–21; 8:45 am] 

BILLING CODE 6450–01–P 


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