1

[6450-01-P]

DEPARTMENT OF ENERGY

10 CFR Part 431

[Docket Number EERE–2010–BT–STD–0048]

RIN: 1904-AC04

Energy Conservation Program: Energy Conservation Standards for Distribution 

Transformers

AGENCY: Office of Energy Efficiency and Renewable Energy, Department of Energy.

ACTION: Notice of proposed rulemaking and public meeting.

SUMMARY: The Energy Policy and Conservation Act of 1975 (EPCA), as amended, 

prescribes energy conservation standards for various consumer products and certain 

commercial and industrial equipment, including low-voltage dry-type distribution 

transformers, and directs the U.S. Department of Energy (DOE) to prescribe standards for 

various other products and equipment, including other types of distribution transformers. 

EPCA also requires DOE to determine whether more-stringent, amended standards would 

be technologically feasible and economically justified, and would save a significant 

amount of energy. In this notice, DOE proposes amended energy conservation standards 

for distribution transformers. The notice also announces a public meeting to receive 

comment on these proposed standards and associated analyses and results.
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DATES: DOE will hold a public meeting on February 23, 2012, from 9 a.m. to 1 p.m., in 

Washington, DC. The meeting will also be broadcast as a webinar. See section VII Public 

Participation for webinar registration information, participant instructions, and 

information about the capabilities available to webinar participants.

DOE will accept comments, data, and information regarding this notice of 

proposed rulemaking (NOPR) before and after the public meeting, but no later than 

[INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER PUBLICATION]. See section VII Public Participation for details.

ADDRESSES: The public meeting will be held at the U.S. Department of Energy, 

Forrestal Building, Room 8E-089, 1000 Independence Avenue, SW., Washington, DC 

20585. To attend, please notify Ms. Brenda Edwards at (202) 586–2945. Please note that 

foreign nationals visiting DOE Headquarters are subject to advance security screening 

procedures. Any foreign national wishing to participate in the meeting should advise 

DOE as soon as possible by contacting Ms. Edwards to initiate the necessary procedures. 

In addition, persons can attend the public meeting via webinar. For more information, 

refer to the Public Participation section near the end of this notice. 

Any comments submitted must identify the NOPR for Energy Conservation 

Standards for Distribution Transformers, and provide docket number EERE-2010–BT–

STD–0048 and/or regulation identifier number (RIN) number 1904-AC04. Comments 

may be submitted using any of the following methods:
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1. Federal eRulemaking Portal: www.regulations.gov. Follow the instructions for 

submitting comments. 

2. E-mail: DistributionTransformers-2010-STD-0048@ee.doe.gov. Include the 

docket number and/or RIN in the subject line of the message.

3. Mail: Ms. Brenda Edwards, U.S. Department of Energy, Building Technologies 

Program, Mailstop EE-2J, 1000 Independence Avenue, SW., Washington, DC, 

20585-0121. If possible, please submit all items on a CD. It is not necessary to 

include printed copies.

4. Hand Delivery/Courier: Ms. Brenda Edwards, U.S. Department of Energy, 

Building Technologies Program, 950 L’Enfant Plaza, SW., Suite 600, 

Washington, DC, 20024. Telephone: (202) 586-2945. If possible, please submit 

all items on a CD, in which case it is not necessary to include printed copies.

Written comments regarding the burden-hour estimates or other aspects of the 

collection-of-information requirements contained in this proposed rule may be submitted 

to Office of Energy Efficiency and Renewable Energy through the methods listed above 

and by e-mail to Chad_S_Whiteman@omb.eop.gov.

For detailed instructions on submitting comments and additional information on 

the rulemaking process, see section VII of this document (Public Participation).
4

Docket: The docket is available for review at www.regulations.gov, including 

Federal Register notices, framework documents, public meeting attendee lists and 

transcripts, comments, and other supporting documents/materials. A link to the docket 

web page can be found at: 

http://www.regulations.gov/#!docketDetail;rpp=10;po=0;D=EERE-2010-BT-STD-0048. 

FOR FURTHER INFORMATION CONTACT: 

James Raba, U.S. Department of Energy, Office of Energy Efficiency and 

Renewable Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue, 

SW., Washington, DC, 20585-0121. Telephone: (202) 586-8654. E-mail: 

Jim.Raba@ee.doe.gov.

Ami Grace-Tardy, U.S. Department of Energy, Office of the General Counsel, 

GC-71, 1000 Independence Avenue, SW., Washington, DC, 20585-0121. Telephone: 

(202) 586-5709. E-mail: Ami.Grace-Tardy@hq.doe.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Summary of the Proposed Rule

A. Benefits and Costs to Consumers

B. Impact on Manufacturers

C. National Benefits

II. Introduction

A. Authority

B. Background

1. Current Standards

2. History of Standards Rulemaking for Distribution Transformers

III. General Discussion
5

A. Test Procedures

1. General

2. Multiple kVA Ratings

3. Dual/Multiple-Voltage Basic Impulse Level

4. Dual/Multiple-Voltage Primary Windings

5. Dual/Multiple-Voltage Secondary Windings

6. Loading

B. Technological Feasibility

1. General

2. Maximum Technologically Feasible Levels

C. Energy Savings

1. Determination of Savings

2. Significance of Savings

D. Economic Justification

1. Specific Criteria

a. Economic Impact on Manufacturers and Consumers

b. Life-Cycle Costs

c. Energy Savings

d. Lessening of Utility or Performance of Products

e. Impact of Any Lessening of Competition

f. Need for National Energy Conservation

g. Other Factors

2. Rebuttable Presumption

IV. Methodology and Discussion of Related Comments

A. Market and Technology Assessment

1. Scope of Coverage

a. Definitions

b. Underground Mining Transformer Coverage

c. Low-Voltage Dry-Type Distribution Transformers

d. Negotiating Committee Discussion of Scope

2. Equipment Classes

a. Less-Flammable Liquid-Immersed Transformers

b. Pole- and Pad-mounted Liquid-Immersed Distribution Transformers

c. BIL Ratings in Liquid-Immersed Distribution Transformers

3. Technology Options

a. Core Deactivation

b. Symmetric Core

c. Intellectual Property

B. Screening Analysis

1. Nanotechnology Composites

C. Engineering Analysis

1. Engineering Analysis Methodology

2. Representative Units

3. Design Option Combinations

4. A and B Loss Value Inputs

5. Materials Prices
6

6. Markups

a. Factory Overhead

b. Labor Costs

c. Shipping Costs

7. Baseline Efficiency and Efficiency Levels

8. Scaling Methodology

9. Material Availability

10. Primary Voltage Sensitivities

11. Impedance

12. Size and Weight

D. Markups Analysis

E. Energy Use Analysis

F. Life-Cycle Cost and Payback Period Analysis

1. Modeling Transformer Purchase Decision

2. Inputs Affecting Installed Cost

a. Equipment Costs

b. Installation Costs

3. Inputs Affecting Operating Costs

a. Transformer Loading

b. Load Growth Trends

c. Electricity Costs

d. Electricity Price Trends

e. Standards Compliance Date

f. Discount Rates

g. Lifetime

h. Base Case Efficiency

G. National Impact Analysis—National Energy Savings and Net Present Value 

Analysis

1. Shipments

2. Efficiency Trends

3. Equipment Price Forecast

4. Discount Rate

5. Energy Used in Manufacturing Transformers

H. Customer Subgroup Analysis

I. Manufacturer Impact Analysis

1. Overview

2. Government Regulatory Impact Model

3. GRIM Key Inputs

a. Manufacturer Production Costs

b. Base-Case Shipments Forecast

c. Product and Capital Conversion Costs

d. Standards Case Shipments

e. Markup Scenarios

4. Discussion of Comments

a. Material Availability

b. Symmetric Core Technology
7

c. Patents Related to Amorphous Steel Production

5. Manufacturer Interviews

a. Conversion Costs and Stranded Assets

b. Shortage of Materials

c. Compliance

d. Effective Date

e. Emergency Situations

J. Employment Impact Analysis

K. Utility Impact Analysis

L. Emissions Analysis

M. Monetizing Carbon Dioxide and Other Emissions Impacts

1. Social Cost of Carbon

a. Monetizing Carbon Dioxide Emissions

b. Social Cost of Carbon Values Used in Past Regulatory Analyses

c. Current Approach and Key Assumptions

2. Valuation of Other Emissions Reductions

N. Discussion of Other Comments

1. Trial Standard Levels

2. Proposed Standards

3. Alternative Methods

4. Labeling

5. Imported Units

V. Analytical Results and Conclusions

A. Trial Standard Levels

B. Economic Justification and Energy Savings

1. Economic Impacts on Customers

a. Life-Cycle Cost and Payback Period

b. Customer Subgroup Analysis

c. Rebuttable-Presumption Payback

2. Economic Impact on Manufacturers

a. Industry Cash-Flow Analysis Results

b. Impacts on Employment

c. Impacts on Manufacturing Capacity

d. Impacts on Subgroups of Manufacturers

e. Cumulative Regulatory Burden

3. National Impact Analysis

a. Significance of Energy Savings

b. Net Present Value of Customer Costs and Benefits

c. Indirect Impacts on Employment

4. Impact on Utility or Performance of Equipment

5. Impact of Any Lessening of Competition

6. Need of the Nation to Conserve Energy

7. Summary of National Economic Impacts

8. Other Factors

C. Proposed Standards
8

1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-Immersed 

Distribution Transformers

2. Benefits and Burdens of Trial Standard Levels Considered for Low-Voltage, 

Dry-Type Distribution Transformers

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-Voltage, 

Dry-Type Distribution Transformers

4. Summary of Benefits and Costs (Annualized) of the Proposed Standards

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866 and 13563

B. Review Under the Regulatory Flexibility Act

1. Description and Estimated Number of Small Entities Regulated

a. Methodology for Estimating the Number of Small Entities

b. Manufacturer Participation

c. Distribution Transformer Industry Structure and Nature of Competition

d. Comparison between Large and Small Entities

2. Description and Estimate of Compliance Requirements

a. Summary of Compliance Impacts

3. Duplication, Overlap, and Conflict with Other Rules and Regulations

4. Significant Alternatives to the Proposed Rule

5. Significant Issues Raised by Public Comments

6. Steps DOE Has Taken to Minimize the Economic Impact on Small 

Manufacturers

C. Review Under the Paperwork Reduction Act

D. Review Under the National Environmental Policy Act of 1969

E. Review Under Executive Order 13132

F. Review Under Executive Order 12988

G. Review Under the Unfunded Mandates Reform Act of 1995

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

I. Review Under Executive Order 12630

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

K. Review Under Executive Order 13211

L. Review Under the Information Quality Bulletin for Peer Review

VII. Public Participation

A. Attendance at the Public Meeting

B. Procedure for Submitting Prepared General Statements For Distribution

C. Conduct of the Public Meeting

D. Submission of Comments

E. Issues on Which DOE Seeks Comment

VIII. Approval of the Office of the Secretary

I. Summary of the Proposed Rule 

Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the 

Act), Pub. L. 94-163 (42 U.S.C. 6291-6309, as codified), established the Energy 
9

Conservation Program for “Consumer Products Other Than Automobiles.” Part C of Title 

III of EPCA (42 U.S.C. 6311–6317) established a similar program for “Certain Industrial 

Equipment,” including distribution transformers.

1

Pursuant to EPCA, any new or 

amended energy conservation standard that the Department of Energy (DOE) prescribes 

for certain equipment, such as distribution transformers, shall be designed to achieve the 

maximum improvement in energy efficiency that is technologically feasible and 

economically justified. (42 U.S.C. 6295(o)(2)(A) and 6316(a)). Furthermore, the new or 

amended standard must result in a significant conservation of energy. (42 U.S.C. 

6295(o)(3)(B) and 6316(a)). In accordance with these and other statutory provisions 

discussed in this notice, DOE proposes amended energy conservation standards for 

distribution transformers. The proposed standards are summarized in the following 

tables: Table I.1, through Table I.3 that describe the covered equipment classes and 

proposed trial standard levels (TSLs), Table I.4 that shows the mapping of TSL to energy 

efficiency levels (ELs)2, and Table I.5 through Table I.8 which show the proposed 

standard in terms of minimum electrical efficiency. These proposed standards, if adopted, 

would apply to all covered distribution transformers listed in the tables and manufactured 

in, or imported into, the United States on or after January 1, 2016. As discussed in section 

IV.C.8 of this notice, any distribution transformer with a kVA rating falling between the 

kVA ratings shown in the tables shall meet a minimum energy efficiency level calculated 

 

1

For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and 

A-1, respectively.

2 A detailed description of the mapping of trial standard level to energy efficiency levels can be found in 

the Technical Support Document, chapter 10 section 10.2.2.3 pg 10-10.

Deleted: , which

Deleted: given in terms of minimum electrical 

efficiency, are shown in

Deleted: ,

Deleted: .

Comment [A1]: Change and footnote 2 

recommended by OIRA. 
10

by a linear interpolation of the minimum efficiency requirements of the kVA ratings 

immediately above and below that rating. 3

Table I.1. Proposed Energy Conservation Standards for Liquid-Immersed 

Distribution Transformers (Compliance Starting January 1, 2016)

Equipment 

Class Design Line Type Phase Count BIL ProposedTSL

1 1, 2 and 3 Liquid-immersed 1 Any 1

2 4 and 5 Liquid-immersed 3 Any 1

Note: BIL means “basic impulse insulation level.”

Table I.2. Proposed Energy Conservation Standards for Low-Voltage, Dry-Type 

Distribution Transformers (Compliance Starting January 1, 2016)

Equipment 

Class Design Line Type Phase Count BIL Proposed TSL

3 6 Low-voltage, dry-type 1 ≤ 10 kV 1

4 7 and 8 Low-voltage, dry-type 3 ≤ 10 kV 1

Note: BIL means “basic impulse insulation level.”

Table I.3. Proposed Energy Conservation Standards for Medium-Voltage, Dry-Type 

Distribution Transformers (Compliance Starting January 1, 2016)

Equipment 

Class

Design Line Type Phase 

Count BIL Proposed TSL

5 9 and 10 Medium-voltage, dry-type 1 25-45 kV 2

6 9 and 10 Medium-voltage, dry-type 3 25-45 kV 2

7 11 and 12 Medium-voltage, dry-type 1 46-95 kV 2

8 11 and 12 Medium-voltage, dry-type 3 46-95 kV 2

9 13A and 13B Medium-voltage, dry-type 1 ≥96 kV 2

10 13A and 13B Medium-voltage, dry-type 3 ≥96 kV 2

Note: BIL means “basic impulse insulation level,” and measures how resistant a transformer’s insulation is 

to large voltage transients.

Table I.4. Trial Standard Level to Energy Efficiency Level Mapping for Proposed

Energy Conservation Standard.

Type Design 

Line

Phase 

Count

Proposed 

TSL

Energy 

Efficiency 

Level

 

3

kVA is an abbreviation for kilovolt-ampere, which is a capacity metric used by industry to classify 

transformers. A transformer’s kVA rating represents its output power when it is fully loaded (i.e., 100 

percent).

Comment [A2]: Change recommended by OIRA. 

Comment [A3]: Change recommended by OIRA.

Comment [A4]: Change recommended by OIRA.

Comment [A5]: Changes recommended by 

OIRA.
11

Liquidimmersed

1 1

1

1

2 1 Base

3 1 1

4 3 1

5 3 1

Low-voltage, 

dry-type

6 1

1

Base

7 3 2

8 3 2

Mediumvoltage, drytype

9 3

2

1

10 3 2

11 3 1

12 3 2

13A 3 1

13B 3 2

Table I.5 Proposed Electrical Efficiencies for all Liquid-Immersed Distribution 

Transformer Equipment Classes (Compliance Starting January 1, 2016)

Standards by kVA and Equipment Class

Equipment Class 1 Equipment Class 2

kVA % kVA %

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1000 99.43

1500 99.48

Table I.6 Proposed Electrical Efficiencies for all Low-Voltage Dry-Type 

Distribution Transformer Equipment Classes (Compliance Starting January 1, 

2016)

Standards by kVA and Equipment Class
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Equipment Class 3 Equipment Class4

kVA % kVA %

15 97.73 15 97.44

25 98.00 30 97.95

37.5 98.20 45 98.20

50 98.31 75 98.47

75 98.50 112.5 98.66

100 98.60 150 98.78

167 98.75 225 98.92

250 98.87 300 99.02

333 98.94 500 99.17

750 99.27

1000 99.34

Table I.7 Proposed Electrical Efficiencies for all Medium-Voltage Dry-Type 

Distribution Transformer Equipment Classes (Compliance Starting January 1, 

2016)

Standards by kVA and Equipment Class

Equipment 

Class 5

Equipment 

Class 6

Equipment 

Class 7

Equipment 

Class 8

Equipment 

Class 9

Equipment 

Class 10

kVA % kVA % kVA % kVA % kVA % kVA %

15 98.10 15 97.50 15 97.86 15 97.18

25 98.33 30 97.90 25 98.12 30 97.63

37.5 98.49 45 98.10 37.5 98.30 45 97.86

50 98.60 75 98.33 50 98.42 75 98.13

75 98.73 112.5 98.52 75 98.57 112.5 98.36 75 98.53

100 98.82 150 98.65 100 98.67 150 98.51 100 98.63

167 98.96 225 98.82 167 98.83 225 98.69 167 98.80 225 98.57

250 99.07 300 98.93 250 98.95 300 98.81 250 98.91 300 98.69

333 99.14 500 99.09 333 99.03 500 98.99 333 98.99 500 98.89

500 99.22 750 99.21 500 99.12 750 99.12 500 99.09 750 99.02

667 99.27 1000 99.28 667 99.18 1000 99.20 667 99.15 1000 99.11

833 99.31 1500 99.37 833 99.23 1500 99.30 833 99.20 1500 99.21

2000 99.43 2000 99.36 2000 99.28

2500 99.47 2500 99.41 2500 99.33
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A. Benefits and Costs to Consumers4

Table I.8 presents DOE’s evaluation of the economic impacts of the proposed 

standards on customers of distribution transformers, as measured by the average lifecycle cost (LCC) savings and the median payback period (PBP). DOE measures the 

impacts of standards relative to a base case that reflects likely trends in the distribution 

transformer market in the absence of amended standards. The base case predominantly 

consists of products at the baseline efficiency levels evaluated for each representative 

unit, which correspond to the existing energy conservation standard level of efficiency 

for distribution transformers established either in DOE’s 2007 rulemaking or by EPACT 

2005. The average LCC savings are positive for all but two of the design lines, for which 

customers are not impacted by the proposed standards. (Throughout this document, 

“distribution transformers” are also referred to as simply “transformers.”)

Table I.8 Impacts of Proposed Standards on Customers of Distribution 

Transformers

Design Line Average LCC Savings (2010$) Median Payback 

Period (years)

Liquid-Immersed

1 36 20.2

2 N/A* N/A*

3 2,413 6.3

4 862 5.0

5 7,787 4.0

Low-Voltage, Dry-Type

6 N/A* N/A*

7 1,714 4.5

8 2,476 8.4

Medium-Voltage, Dry-Type

9 849 2.6

10 4,791 8.8

 

4

For the purposes of this document, the "consumers" of distribution transformers are referred to as

"customers." Customers refer to electric utilities in the case of liquid-immersed transformers, and to utilities 

and building owners in the case of dry-type transformers.

Comment [A6]: Change recommended by OIRA.
14

11 1,043 10.7

12 6,934 9.0

13A 25 16.5

13B 4,709 12.5

*No consumers are impacted by the proposed standard because no change from the minimum efficiency

standard is proposed for design lines 2 and 6.

B. Impact on Manufacturers

The industry net present value (INPV) is the sum of the discounted cash flows to 

the industry from the base year through the end of the analysis period (2011 through 

2045). Using a real discount rate of 7.4 percent for liquid-immersed distribution 

transformers, 9 percent for medium-voltage dry-type distribution transformers, and 11.1 

percent for low-voltage dry- type distribution transformers, DOE estimates that the 

industry net present value (INPV) for manufacturers of liquid-immersed, medium-voltage 

dry-type and low-voltage dry-type distribution transformers is $625 million, $91 million , 

and $220 million, respectively, in 2011$. Under the proposed standards, DOE expects 

that liquid-immersed manufacturers may lose up to 6.3 percent of their INPV, which is 

approximately $39.6 million; medium-voltage manufacturers may lose up to 7.1 percent 

of their INPV, which is approximately $6.5 million; and low-voltage dry-type 

manufacturers may lose up to 7.7 percent of their INPV, which is approximately $16.8

million. Additionally, based on DOE’s interviews with the manufacturers of distribution 

transformers, DOE does not expect any plant closings or significant loss of employment.

C. National Benefits

DOE’s analyses indicate that the proposed standards would save a significant 

amount of energy ―an estimated 1.58 quads over 30 years (2016–2045). In addition, 

Deleted: 6

Deleted: 41.5

Deleted: 8

Deleted: 17.2
15

DOE expects the energy savings from the proposed standards to be equivalent to the 

energy output from 2.40 gigawatts (GW) of generating capacity by 2045.

The cumulative national net present value (NPV) of total consumer costs and 

savings of the proposed standards for distribution transformers sold in 2016-2045, in 

2010$, ranges from $2.9 billion (at a 7-percent discount rate) to $12.2 billion (at a 3-

percent discount rate) over 30 years (2016–2045). This NPV expresses the estimated total 

value of future operating cost savings minus the estimated increased equipment costs for 

distribution transformers purchased in 2016–2045, discounted to 2010.

In addition, the proposed standards would have significant environmental 

benefits. The energy savings are expected to result in cumulative greenhouse gas 

emission reductions of 122.1 million metric tons (Mt)5of carbon dioxide (CO2) from

2016–2045. During this period, the proposed standards are expected to result in emissions 

reductions of 99.7 thousand tons of nitrogen oxides (NOX) and 0.819 tons of mercury 

(Hg).6

The value of the CO2 reductions is calculated using a range of values per metric 

ton of CO2 (otherwise known as the Social Cost of Carbon, or SCC) developed by a 

recent interagency process. The derivation of the SCC values is discussed in section 

 

5 A metric ton is equivalent to 1.1 short tons. A short ton is equal to 2,000 pounds. Results for NOX and Hg 

are presented in short tons (referred to here as simply “tons.”)

6 DOE calculates emissions reductions relative to the most recent version of the Annual Energy Outlook 

(AEO) Reference case forecast. This forecast accounts for emissions reductions from in-place regulations, 

including the Clean Air Interstate Rule (CAIR, 70 FR 25162 (May 12, 2005)), but not the Clean Air 

Mercury Rule (CAMR, 70 FR 28606 (May 18, 2005)). Subsequent regulations, including the Cross-State

Air Pollution rule issued on July 6, 2011, do not appear in the AEO forecast at this time.

Deleted: eliminate

Deleted: need for approximately

Comment [A7]: Change recommended by OIRA.

Deleted: 91

Deleted: 1
16

IV.M. DOE estimates the net present monetary value of the CO2 emissions reduction is 

between $0.71 and $12.5 billion, expressed in 2010$ and discounted to 2010. DOE also 

estimates the net present monetary value of the NOX emissions reduction, expressed in 

2010 $ and discounted to 2010, is between $0.069 billion at a 7-percent discount rate and

$0.210 billion at a 3-percent discount rate.7

Table I.9 summarizes the national economic costs and benefits expected to result 

from today’s proposed standards for distribution transformers.

Table I.9 Summary of National Economic Benefits and Costs of Proposed 

Distribution Transformer Energy Conservation Standards

Category Present Value

Billion 2010$ Discount Rate

Benefits

Operating Cost Savings

5.58 7%

17.44 3%

CO2 Reduction Monetized Value (at $4.9/t)* 0.71 5%

CO2 Reduction Monetized Value (at $22.3/t)* 4.13 3%

CO2 Reduction Monetized Value (at $36.5/t)* 7.20 2.5%

CO2 Reduction Monetized Value (at $67.6/t)* 12.54 3%

NOX Reduction Monetized Value (at $2,537/ton)*

0.069 7%

0.210 3%

Total Benefits**

9.78 7%

21.7 3%

Costs

Incremental Installed Costs

2.67 7%

5.21 3%

Net Benefits

Including CO2 and NOX 7.10 7%

 

7

 DOE is aware of multiple agency efforts to determine the appropriate range of values used in evaluating 

the potential economic benefits of reduced Hg emissions. DOE has decided to await further guidance 

regarding consistent valuation and reporting of Hg emissions before it once again monetizes Hg in its 

rulemakings.

Deleted: 12.2 and 125 million

Deleted: between $37.3 and $383 million

Comment [A8]: Change recommended by OIRA.

Deleted: 07

Comment [A9]: Change recommended by OIRA. 

Deleted: 21

Comment [A10]: Change recommended by 

OIRA.
17

16.5 3%

* The CO2 values represent global monetized values of the SCC in 2010 under several scenarios. The 

values of $4.9, $22.1, and $36.3 per metric ton (t) are the averages of SCC distributions calculated using 

5%, 3%, and 2.5% discount rates, respectively. The value of $67.1/t represents the 95th percentile of the 

SCC distribution calculated using a 3% discount rate. A metric ton is equivalent to 1.1 short tons. A short 

ton is equal to 2,000 pounds. Results for NOX are presented in short tons (referred to here as simply 

“tons.”)

** Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% 

discount rate, and the average of the low and high NOX values used in DOE’s analysis.

The benefits and costs of today’s proposed standards, for equipment sold in 2016-

2045, can also be expressed in terms of annualized values. The annualized monetary 

values are the sum of: (1) the annualized national economic value of the benefits from 

consumer operation of equipment that meets the proposed standards (consisting primarily 

of operating cost savings from using less energy minus increases in equipment purchase 

and installation costs, which is another way of representing consumer NPV), and (2) the 

annualized monetary value of the benefits of emission reductions, including CO2

emission reductions.8

Although combining the values of operating savings and CO2 emission reductions 

provides a useful perspective, two issues should be considered. First, the national 

operating savings are domestic U.S. consumer monetary savings that occur as a result of 

market transactions while the value of CO2 reductions is based on a global value. Second, 

 

8 DOE used a two-step calculation process to convert the time-series of costs and benefits into annualized 

values. First, DOE calculated a present value in 2011, the year used for discounting the NPV of total 

consumer costs and savings, for the time-series of costs and benefits using discount rates of 3 and 7 percent 

for all costs and benefits except for the value of CO2 reductions. For the latter, DOE used a range of 

discount rates, as shown in Table I.9. From the present value, DOE then calculated the fixed annual 

payment over a 30-year period, starting in 2011 that yields the same present value. The fixed annual 

payment is the annualized value. Although DOE calculated annualized values, this does not imply that the 

time-series of cost and benefits from which the annualized values were determined would be a steady 

stream of payments.
18

the assessments of operating cost savings and CO2 savings are performed with different 

methods that use different time frames for analysis. The national operating cost savings is 

measured for the lifetime of distribution transformers shipped in 2016-2045. The SCC 

values, on the other hand, reflect the present value of some future climate-related impacts 

resulting from the emission of one metric ton of carbon dioxide in each year. These 

impacts continue well beyond 2100.

Estimates of annualized benefits and costs of today’s proposed standards are 

shown in Table I.10. (All monetary values below are expressed in 2010$.) The results 

under the primary estimate are as follows. Using a 7-percent discount rate for benefits 

and costs other than CO2 reduction, for which DOE used a 3-percent discount rate along 

with the SCC series corresponding to a value of $22.3/metric ton in 2010, the cost of the 

standards proposed in today’s proposed standards is $302 million per year in increased 

equipment costs. The benefits are $631 million per year in reduced equipment operating 

costs, $244 million in CO2 reductions, and $7.78 million in reduced NOX emissions. In 

this case, the net benefit amounts to $581 million per year. Using a 3-percent discount 

rate for all benefits and costs and the SCC series corresponding to a value of $22.3/metric 

ton in 2010, the cost of the standards proposed in today’s rule is $308 million per year in 

increased equipment costs. The benefits are $1,026 million per year in reduced operating 

costs, $244 million in CO2 reductions, and $12.4 million in reduced NOX emissions. In 

this case, the net benefit amounts to $975 million per year.

Table I.10 Annualized Benefits and Costs of Proposed Standards for Distribution 

Transformers

Discount Rate Primary Low Net High Net 
19

Estimate* Benefits 

Estimate*

Benefits 

Estimate*

Monetized (million 2010$/year)

Benefits

Operating Cost Savings

7% 631 594 659

3% 1,026 950 1,075

CO2 Reduction at $4.9/t** 5% 58.6 58.6 58.6

CO2Reduction at $22.3/t** 3% 244 244 244

CO2Reduction at $36.5/t** 2.5% 389 389 389

CO2Reduction at $67.6/t** 3% 742 742 742

NOX Reduction at 

$2,537/ton**

7% 7.78 7.78 7.78

3% 12.4 12.4 12.4

Total†

7% plus CO2 range 697 to 1380 660 to 1343 726 to 1409

7% 883 846 911

3% plus CO2 range 1097 to 1780 1021 to 1704 1146 to 1829

3% 1,283 1,207 1,331

Costs

Incremental Product Costs

7% 302 338 285

3% 308 351 289

Total Net Benefits

Total†

7% plus CO2 range 400 to 1083 327 to 1010 445 to 1128

7% 581 507 626

3% plus CO2 range 789 to 1472 670 to 1353 857 to 1540

3% 975 855 1,043

* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from 

the AEO 2011 reference case, Low Economic Growth case, and High Economic Growth case, respectively. 

In addition, incremental product costs reflect no change in the Primary estimate, rising product prices in the 

Low Net Benefits estimate, and declining product prices in the High Net Benefits estimate. 

** The CO2 values represent global values (in 2010$) of the social cost of CO2 emissions in 2010 under 

several scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions 

calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6 per metric ton 

represents the 95th percentile of the SCC distribution calculated using a 3% discount rate. The value for 

NOX (in 2010$) is the average of the low and high values used in DOE’s analysis.

† Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount 

rate, which is $22.3/metric ton in 2010 (in 2010$). In the rows labeled as “7% plus CO2 range” and “3% 

plus CO2 range,” the operating cost and NOX benefits are calculated using the labeled discount rate, and 

those values are added to the full range of CO2 values.

DOE has tentatively concluded that the proposed standards represent the 

maximum improvement in energy efficiency that is technologically feasible and 
20

economically justified, and would result in the significant conservation of energy. DOE 

further notes that equipment achieving these proposed standard levels are already 

commercially available for at least some, if not most, equipment classes covered by 

today’s proposal. Based on the analyses described above, DOE has tentatively concluded 

that the benefits of the proposed standards to the Nation (energy savings, positive NPV of 

consumer benefits, consumer LCC savings, and emission reductions) would outweigh the 

burdens (loss of INPV for manufacturers and LCC increases for some consumers). 

DOE also considered more stringent energy efficiency levels as trial standard 

levels, and is still considering them in this rulemaking. However, DOE has tentatively 

concluded that, in some cases, the potential burdens of the more stringent energy 

efficiency levels would outweigh the projected benefits. Based on consideration of the 

public comments DOE receives in response to this notice and related information 

collected and analyzed during the course of this rulemaking effort, DOE may adopt 

energy efficiency levels presented in this notice that are either higher or lower than the 

proposed standards, or some combination of energy efficiency level(s) that incorporate 

the proposed standards in part. 

II. Introduction 

The following section briefly discusses the statutory authority underlying today’s 

proposal, as well as some of the relevant historical background related to the 

establishment of energy conservation standards for distribution transformers.
21

A. Authority

Title III, Part B of the Energy Policy and Conservation Act of 1975 (EPCA or the 

Act), Pub. L. 94-163 (42 U.S.C. 6291-6309, as codified), established the Energy 

Conservation Program for “Consumer Products Other Than Automobiles.” Part C of Title 

III of EPCA (42 U.S.C. 6311–6317) established a similar program for ‘‘Certain Industrial 

Equipment,’’ including distribution transformers.9 The Energy Policy Act of 1992 

(EPACT 1992), Pub. L. 102-486, amended EPCA and directed the Department to 

prescribe energy conservation standards for distribution transformers. (42 U.S.C. 

6317(a)) The Energy Policy Act of 2005 (EPACT 2005), Pub. L. 109-25, amended 

EPCA to establish energy conservation standards for low-voltage, dry-type distribution 

transformers.10 (42 U.S.C. 6295(y)) Under 42 U.S.C. 6313(a)(6)(C)(i), DOE must review 

energy conservation standards for commercial and industrial equipment and amend the 

standards as needed no later than six years from the issuance of a final rule establishing 

or amending a standard for a covered product. A final rule establishing any amended 

standards based on such notice of proposed rulemaking (NOPR) must be completed 

within two years of publication of the NOPR. (42 U.S.C. 6313(a)(6)(C)(iii)(I)).

DOE publishes today’s proposed rule pursuant to Part C of Title III, which 

establishes an energy conservation program for covered equipment that consists 

essentially of four parts: (1) testing; (2) labeling; (3) the establishment of Federal energy 

 

9

For editorial reasons, upon codification in the U.S. Code, Parts B and C were redesignated as Parts A and 

A-1, respectively

10 EPACT 2005 established that the efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2007 shall be the Class I Efficiency Levels for distribution 

transformers specified in Table 4-2 of the “Guide for Determining Energy Efficiency for Distribution 

Transformers” published by the National Electrical Manufacturers Association (NEMA TP 1-2002).
22

conservation standards; and (4) compliance certification and enforcement procedures. For 

those distribution transformers for which DOE determines that energy conservation 

standards are warranted, the DOE test procedures must be the "Standard Test Method for 

Measuring the Energy Consumption of Distribution Transformers" prescribed by the 

National Electrical Manufacturers Association (NEMA TP 2-1998), subject to review and 

revision by the Secretary in accordance with certain criteria and conditions. (42 U.S.C. 

6293(b)(10), 6314(a)(2)-(3) and 6317(a)(1)) Manufacturers of covered equipment must 

use the prescribed DOE test procedure as the basis for certifying to DOE that their 

equipment complies with the applicable energy conservation standards adopted under 

EPCA and when making representations to the public regarding the energy use or 

efficiency of those types of equipment. (42 U.S.C. 6314(d)) The DOE test procedures for 

distribution transformers currently appear at title 10 of the Code of Federal Regulations 

(CFR) part 431, subpart K, appendix A. 

DOE must follow specific statutory criteria for prescribing amended standards for 

covered equipment. As indicated above, any amended standard for covered equipment 

must be designed to achieve the maximum improvement in energy efficiency that is 

technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A) and 

6316(a)) Furthermore, DOE may not adopt any amended standard that would not result in 

the significant conservation of energy. (42 U.S.C. 6295(o)(3) and 6316(a)) Moreover, 

DOE may not prescribe a standard: (1) for certain equipment, including distribution 

transformers, if no test procedure has been established for the equipment, or (2) if DOE 

determines by rule that the proposed standard is not technologically feasible or 
23

economically justified. (42 U.S.C. 6295(o)(3)(A)-(B) and 6316(a)) In deciding whether a 

proposed amended standard is economically justified, DOE must determine whether the 

benefits of the standard exceed its burdens. (42 U.S.C. 6295(o)(2)(B)(i) and 6316(a)) 

DOE must make this determination after receiving comments on the proposed standard, 

and by considering, to the greatest extent practicable, the following seven factors:

1. The economic impact of the standard on manufacturers and consumers of the 

equipment subject to the standard;

2. The savings in operating costs throughout the estimated average life of the 

covered equipment in the type (or class) compared to any increase in the price, 

initial charges, or maintenance expenses for the covered products that are likely to 

result from the imposition of the standard; 

3. The total projected amount of energy, or as applicable, water, savings likely to 

result directly from the imposition of the standard;

4. Any lessening of the utility or the performance of the covered equipment likely 

to result from the imposition of the standard;

5. The impact of any lessening of competition, as determined in writing by the 

Attorney General, that is likely to result from the imposition of the standard;

6. The need for national energy and water conservation; and

7. Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 

6295(o)(2)(B)(i) and 6316(a))

EPCA, as codified, also contains what is known as an “anti-backsliding” 

provision, which prevents the Secretary from prescribing any amended standard that 
24

either increases the maximum allowable energy use or decreases the minimum required 

energy efficiency of a covered product. (42 U.S.C. 6295(o)(1) and 6316(a)) Also, the 

Secretary may not prescribe an amended or new standard if interested persons have 

established by a preponderance of the evidence that the standard is likely to result in the 

unavailability in the United States of any covered product type (or class) of performance 

characteristics (including reliability), features, sizes, capacities, and volumes that are 

substantially the same as those generally available in the United States. (42 U.S.C. 

6295(o)(4) and 6316(a))

Further, EPCA, as codified, establishes a rebuttable presumption that a an energy 

conservation standard is economically justified if the Secretary finds that the additional 

cost to the consumer of purchasing equipment complying with the energy conservation 

standard will be less than three times the value of the energy savings a consumer will 

receive in the first year of using the equipment. (See 42 U.S.C. 6295(o)(2)(B)(iii) and 

6316(a))

Additionally, 42 U.S.C. 6295(q)(1), as applied to covered equipment via 42 

U.S.C. 6316(a), specifies requirements when promulgating a standard for a type or class 

of covered equipment that has two or more subcategories. DOE must specify a different 

standard level than that which applies generally to such type or class of equipment for 

any group of covered equipment that has the same function or intended use if DOE 

determines that equipment within such group (A) consumes a different kind of energy 

from that consumed by other covered equipment within such type (or class); or (B) has a 
25

capacity or other performance-related feature which other equipment within such type (or 

class) does not have and such feature justifies a higher or lower standard. (42 U.S.C. 

6294(q)(1) and 6316(a)) In determining whether a performance-related feature justifies a 

different standard for a group of equipment, DOE must consider such factors as the utility 

to the consumer of the feature and other factors DOE deems appropriate. Id. Any rule 

prescribing such a standard must include an explanation of the basis on which such 

higher or lower level was established. (42 U.S.C. 6295(q)(2) and 6316(a))

Federal energy conservation requirements generally supersede State laws or 

regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 

6297(a)–(c) and 6316(a)) DOE may, however, grant waivers of Federal preemption for 

particular State laws or regulations, in accordance with the procedures and other 

provisions set forth under 42 U.S.C. 6297(d)).

DOE has also reviewed this regulation pursuant to Executive Order (EO) 13563, 

issued on January 18, 2011 (76 FR 3281, Jan. 21, 2011). EO 13563 is supplemental to 

and explicitly reaffirms the principles, structures, and definitions governing regulatory 

review established in EO 12866. To the extent permitted by law, agencies are required by 

EO 13563 to: (1) propose or adopt a regulation only upon a reasoned determination that 

its benefits justify its costs (recognizing that some benefits and costs are difficult to 

quantify); (2) tailor regulations to impose the least burden on society, consistent with 

obtaining regulatory objectives, taking into account, among other things, and to the extent 

practicable, the costs of cumulative regulations; (3) select, in choosing among alternative 
26

regulatory approaches, those approaches that maximize net benefits (including potential 

economic, environmental, public health and safety, and other advantages; distributive 

impacts; and equity); (4) to the extent feasible, specify performance objectives, rather 

than specifying the behavior or manner of compliance that regulated entities must adopt; 

and (5) identify and assess available alternatives to direct regulation, including providing 

economic incentives to encourage the desired behavior, such as user fees or marketable 

permits, or providing information upon which choices can be made by the public. 

DOE emphasizes as well that EO 13563 requires agencies to use the best 

available techniques to quantify anticipated present and future benefits and costs as 

accurately as possible. In its guidance, the Office of Information and Regulatory Affairs 

has emphasized that such techniques may include identifying changing future compliance 

costs that might result from technological innovation or anticipated behavioral changes. 

For the reasons stated in the preamble, DOE believes that today’s notice of proposed 

rulemaking (NOPR) is consistent with these principles, including the requirement that, to 

the extent permitted by law, benefits justify costs and that net benefits are maximized.

B. Background

1. Current Standards

On August 8, 2005, the Energy Policy Act of 2005 (EPACT 2005) amended 

EPCA to establish energy conservation standards for low-voltage, dry-type distribution 
27

transformers (LVDTs).11 (EPACT 2005, Section 135(c); 42 U.S.C. 6295(y)) The standard 

levels for low-voltage dry-type distribution transformers appear in Table II.1. 

Table II.1: Federal Energy Efficiency Standards for Low-Voltage, Dry-Type 

Distribution Transformers

Single-Phase Three-Phase

kVA Efficiency (%) kVA Efficiency (%)

15 97.7 15 97.0

25 98.0 30 97.5

37.5 98.2 45 97.7

50 98.3 75 98.0

75 98.5 112.5 98.2

100 98.6 150 98.3

167 98.7 225 98.5

250 98.8 300 98.6

333 98.9 500 98.7

750 98.8

1000 98.9

Note: Efficiencies are determined at the following reference conditions: (1) for no-load losses, at the 

temperature of 20 °C, and (2) for load-losses, at the temperature of 75 °C and 35 percent of nameplate load.

DOE incorporated these standards into its regulations, along with the standards 

for several other types of products and equipment, in a final rule published on October 

18, 2005. 70 FR 60407, 60416 – 60417. These standards appear at 10 CFR 431.196(a).

On October 12, 2007, DOE published a final rule that established energy 

conservation standard for liquid-immersed distribution transformers and medium-voltage 

dry-type distribution transformers, which are shown in Table II.2 and Table II.3, 

 

11 EPACT 2005 established that the efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2007 shall be the Class I Efficiency Levels for distribution 

transformers specified in Table 4-2 of the “Guide for Determining Energy Efficiency for Distribution 

Transformers” published by the National Electrical Manufacturers Association (NEMA TP 1-2002).
28

respectively. 72 FR 58190, 58239-40. These standards are codified at 10 CFR 431.196(b) 

and (c).

Table II.2 Energy Conservation Standards for Liquid-Immersed Distribution 

Transformers

Single-Phase Three-Phase

kVA Efficiency (%) kVA Efficiency (%)

10 98.62 15 98.36

15 98.76 30 98.62

25 98.91 45 98.76

37.5 99.01 75 98.91

50 99.08 112.5 99.01

75 99.17 150 99.08

100 99.23 225 99.17

167 99.25 300 99.23

250 99.32 500 99.25

333 99.36 750 99.32

500 99.42 1000 99.36

667 99.46 1500 99.42

833 99.49 2000 99.46

2500 99.49

Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE 

Test-Procedure. 10 CFR part 431, subpart K, appendix A.

Table II.3 Energy Conservation Standards for Medium-Voltage, Dry-Type 

Distribution Transformers

Single-Phase Three-Phase

BIL 20–45 kV 46–95 kV ≥96 kV BIL 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

(%)

Efficiency 

(%)

Efficiency 

(%) kVA Efficiency (%)

Efficiency 

(%)

Efficiency 

(%)

15 98.10 97.86 15 97.50 97.18

25 98.33 98.12 30 97.90 97.63

37.5 98.49 98.30 45 98.10 97.86

50 98.60 98.42 75 98.33 98.12

75 98.73 98.57 98.53 112.5 98.49 98.30

100 98.82 98.67 98.63 150 98.60 98.42

167 98.96 98.83 98.80 225 98.73 98.57 98.53

250 99.07 98.95 98.91 300 98.82 98.67 98.63

333 99.14 99.03 98.99 500 98.96 98.83 98.80

500 99.22 99.12 99.09 750 99.07 98.95 98.91

667 99.27 99.18 99.15 1000 99.14 99.03 98.99

833 99.31 99.23 99.20 1500 99.22 99.12 99.09

2000 99.27 99.18 99.15
29

2500 99.31 99.23 99.20

Note: BIL means “basic impulse insulation level.”

Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE 

Test-Procedure. 10 CFR part 431, subpart K, appendix A.

2. History of Standards Rulemaking for Distribution Transformers

In a notice published on October 22, 1997 (62 FR 54809), DOE stated that it had 

determined that energy conservation standards were warranted for electric distribution 

transformers, relying in part on two reports by DOE’s Oak Ridge National Laboratory 

(ORNL). These reports —Determination Analysis of Energy Conservation Standards for 

Distribution Transformers, ORNL-6847 (1996) and Supplement to the “Determination 

Analysis,” ORNL-6847 (1997)—are available on the DOE website at: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/

distribution_transformers.html. In 2000, DOE issued its Framework Document for 

Distribution Transformer Energy Conservation Standards Rulemaking, describing its 

proposed approach for developing standards for distribution transformers, and held a 

public meeting to discuss the Framework Document. The document is available on the 

above-referenced DOE website. Stakeholders also submitted written comments on the 

document, addressing a range of issues.

Subsequently, DOE issued draft reports as to certain of the key analyses 

contemplated by the Framework Document.12 It received comments from stakeholders on 

these draft reports and, on July 29, 2004, published an advance notice of proposed 

 

12 Copies of all the draft analyses published before the ANOPR are available on DOE’s website: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_an

alysis.html.
30

rulemaking (ANOPR) for distribution transformer standards. 69 FR 45376. DOE then 

held a webcast on material it had published relating to the ANOPR, followed by a public 

meeting on the ANOPR on September 28, 2004. In August 2005, DOE issued a draft of 

certain of the analyses on which it planned to base the standards for liquid-immersed and 

medium-voltage, dry-type distribution transformers, along with documents that supported 

the draft analyses.13 DOE did this to enable stakeholders to review the analyses and 

make recommendations as to standard levels.

On April 27, 2006, DOE published its Final Rule on Test Procedures for 

Distribution Transformers. The rule: (1) established the procedure for sampling and 

testing distribution transformers so that manufacturers can make representations as to 

their efficiency, as well as establish that they comply with Federal standards; and (2)

contained enforcement provisions, outlining the procedure the Department would follow 

should it initiate an enforcement action against a manufacturer. 71 FR 24972 (codified at 

10 CFR 431.198).

On August 4, 2006, DOE published a NOPR in which it proposed energy 

conservation standards for distribution transformers (the 2006 NOPR). 71 FR 44355. 

Concurrently, DOE also issued a technical support document (TSD) that incorporated the 

 

13 Copies of the four draft NOPR analyses published in August 2005 are available on DOE’s website: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_an

alysis_nopr.html.
31

analyses it had performed for the proposed rule, including several spreadsheets that 

remain available on DOE’s website.14

Some commenters asserted that DOE’s proposed standards might adversely affect 

replacement of distribution transformers in certain space-constrained (e.g., vault) 

installations. In response, DOE issued a notice of data availability and request for 

comments on this and another issue. 72 FR 6186 (Feb. 9, 2007) (the NODA). In the 

NODA, DOE sought comment on whether it should include in the LCC analysis potential 

costs related to size constraints of distribution transformers installed in vaults. DOE also 

outlined different approaches as to how it might account for additional installation costs 

for these space-constrained applications and requested comments on linking energy 

efficiency levels for three-phase liquid-immersed units with those of single-phase units. 

Finally, DOE addressed how it was inclined to consider a final standard that is based on 

energy efficiency levels derived from trial standard level (TSL) 2 and TSL 3 for threephase units and TSLs 2, 3 and 4 for single-phase units. 72 FR 6189.. Based on comments 

on the 2006 NOPR, and the NODA, DOE created new TSLs to address the treatment of 

three-phase units and single-phase units. In October 2007, DOE published a final rule

that created the current energy conservation standards for liquid-immersed and mediumvoltage dry-type distribution transformers. 72 FR 58190 (October 12, 2007) (the 2007 

Final Rule) (codified at 10 CFR 431.196(b)-(c)).

 

14 The spreadsheets developed for this rulemaking proceeding are available at: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_an

alysis_nopr.html.
32

The above paragraphs summarize development of the 2007 Final Rule. The 

preamble to the rule included additional, detailed background information on the history 

of that rulemaking. 72 FR 58194-96.

After the publication of the 2007 Final Rule, certain parties filed petitions for 

review in the United States Courts of Appeals for the Second and Ninth Circuits, 

challenging the rule. Several additional parties were permitted to intervene in support of 

these petitions. (All of these parties are referred to below collectively as “petitioners.”) 

The petitioners alleged that, in developing its energy conservation standards for 

distribution transformers, DOE did not comply with certain applicable provisions of 

EPCA and of the National Environmental Policy Act (NEPA), as amended (42 U.S.C. 

4321 et seq.) DOE and the petitioners subsequently entered into a settlement agreement 

to resolve the petitions. The settlement agreement outlined an expedited timeline for the 

Department to determine whether to amend the energy conservation standards for liquidimmersed and medium-voltage dry-type distribution transformers. Under the original 

settlement agreement, DOE was required to publish by October 1, 2011, either a 

determination that the standards for these distribution transformers do not need to be 

amended or a NOPR that includes any new proposed standards and that meets all 

applicable requirements of EPCA and NEPA. Under an amended settlement agreement, 

the October 1, 2011, deadline for a DOE determination or proposed rule was extended to 

February 1, 2012. If DOE finds that amended standards are warranted, DOE must publish 

a final rule containing such amended standards by October 1, 2012.
33

On March 2, 2011, DOE published in the Federal Register a notice of public 

meeting and availability of its preliminary TSD for the Distribution Transformer Energy 

Conservation Standards Rulemaking, wherein DOE discussed and received comments on 

issues such as equipment classes of distribution transformers that DOE would analyze in 

consideration of amending the energy conservation standards for distribution 

transformers, the analytical framework, models and tools it is using to evaluate potential 

standards, the results of its preliminary analysis, and potential standard levels. 76 FR 

11396. The notice is available on the above-referenced DOE website. To expedite the 

rulemaking process, DOE began at the preliminary analysis stage because it believes that 

many of the same methodologies and data sources that were used during the 2007

rulemaking rule remain valid. On April 5, 2011, DOE held a public meeting to discuss 

the preliminary TSD. Representatives of manufacturers, trade associations, electric 

utilities, energy conservation organizations, Federal regulators, and other interested 

parties attended this meeting. In addition, other interested parties submitted written 

comments about the TSD addressing a range of issues. These comments are discussed in 

the following sections of the NOPR. 

On July 29, 2011, DOE published in the Federal Register a notice of intent to 

establish a subcommittee under the Energy Efficiency and Renewable Energy Advisory 

Committee (ERAC), in accordance with the Federal Advisory Committee Act and the 

Negotiated Rulemaking Act, to negotiate proposed Federal standards for the energy 

efficiency of medium-voltage dry-type and liquid immersed distribution transformers. 76 

FR 45471. Stakeholders strongly supported a consensual rulemaking effort. DOE 
34

believed that, in this case, a negotiated rulemaking would result in a better informed 

NOPR and would minimize any potential negative impact of the NOPR. On August 12, 

2011, DOE published in the Federal Register a similar notice of intent to negotiate 

proposed Federal standards for the energy efficiency of low-voltage dry-type distribution 

transformers. 76 FR 50148. The purpose of the subcommittee was to discuss and, if 

possible, reach consensus on a proposed rule for the energy efficiency of distribution 

transformers. 

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type 

distribution transformers consisted of representatives of parties having a defined stake in 

the outcome of the proposed standards, listed below.

ABB Inc.

AK Steel Corporation

American Council for an Energy-Efficient Economy

American Public Power Association

Appliance Standards Awareness Project

ATI-Allegheny Ludlum

Baltimore Gas and Electric 

Cooper Power Systems

Earthjustice

Edison Electric Institute

Fayetteville Public Works Commission

Federal Pacific Company

Howard Industries Inc.

LakeView Metals

Efficiency and Renewables Advisory Committee member

Metglas, Inc.

National Electrical Manufacturers Association

National Resources Defense Council

National Rural Electric Cooperative Association

Northwest Power and Conservation Council
35

Pacific Gas and Electric Company

Progress Energy

Prolec GE

U.S. Department of Energy

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type 

distribution transformers held meetings on September 15 through 16, 2011, October 12 

through 13, 2011, November 8 through 9, 2011, and November 30 through December 1, 

2011; the ERAC subcommittee also held public webinars on November 17 and December 

14. During the course of the September 15, 2011, meeting, the subcommittee agreed to its 

rules of procedure., ratified its schedule of the remaining meetings, and defined the 

procedural meaning of consensus. The subcommittee defined consensus as unanimous 

agreement from all present subcommittee members. Subcommittee members were 

allowed to abstain from voting for an efficiency level; their votes counted neither toward 

nor against the consensus.

DOE presented its draft engineering, life-cycle cost and national impacts analysis 

and results. During the meetings of October 12 through 13, 2011, DOE presented its 

revised analysis and heard from subcommittee members on a number of topics. During 

the meetings on November 8 through 9, 2011, DOE presented its revised analysis, 

including life-cycle cost sensitivities based on exclusion ZDMH and amorphous steel as 

core materials. During the meetings on November 30 through December 1, 2011, DOE 

presented its revised analysis based on 2011 core-material prices. 
36

At the conclusion of the final meeting, subcommittee members presented their 

efficiency level recommendations. For medium-voltage liquid-immersed distribution 

transformers, the advocates, represented by the Appliance Standards Awareness Project 

(ASAP), recommended efficiency level (also referred to as “EL”) 3 for all design lines

(also referred to as “DLs”). The National Electrical Manufacturers Association (NEMA)

and AK Steel recommended EL 1 for all DLs except for DL 2, for which no change from 

the current standard was recommended. Edison Electric Institute (EEI) and ATI 

Allegheny Ludlum recommended EL1 for DLs 1, 3, and 4 and no change from the 

current standard or a proposed standard of less than EL 1 for DLs 2 and 5. Therefore, the

subcommittee did not arrive at consensus regarding proposed standard levels for 

medium-voltage liquid-immersed distribution transformers. 

For medium-voltage dry-type distribution transformers, the subcommittee arrived 

at consensus and recommended a proposed standard of EL2 for DLs 11 and 12, from 

which the proposed standards for DLs 9, 10, 13A, 13B would be scaled. Transcripts of 

the subcommittee meetings and all data and materials presented at the subcommittee 

meetings are available at the DOE website at: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/

distribution_transformers.html. 

The ERAC subcommittee held meetings on September 28, 2011, October 13-14, 

2011, November 9, 2011, and December 1-2, 2011, for low-voltage distribution 

transformers. The ERAC subcommittee also held webinars on November 21, 2011, and 
37

December 20, 2011. During the course of the September 28, 2011, meeting, the 

subcommittee agreed to its rules of procedure, finalized the schedule of the remaining 

meetings, and defined the procedural meaning of consensus. The subcommittee defined 

consensus as unanimous agreement from all present subcommittee members. 

Subcommittee members were allowed to abstain from voting for an efficiency level; their 

votes counted neither toward nor against the consensus.

The ERAC subcommittee for low-voltage distribution transformers consisted of 

representatives of parties having a defined stake in the outcome of the proposed 

standards.

AK Steel Corporation

American Council for an Energy-Efficient Economy

Appliance Standards Awareness Project

ATI-Allegheny Ludlum

EarthJustice

Eaton Corporation

Federal Pacific Company

Lakeview Metals

Efficiency and Renewables Advisory Committee member

Metglas, Inc.

National Electrical Manufacturers Association

Natural Resources Defense Council

ONYX Power

Pacific Gas and Electric Company

Schneider Electric

U.S. Department of Energy

DOE presented its draft engineering, life-cycle cost and national impacts analysis 

and results. During the meetings of October 14, 2011, DOE presented its revised analysis 
38

and heard from subcommittee members on various topics. During the meetings of 

November 9, 2011, DOE presented its revised analysis. During the meetings of 

December 1, 2011, DOE presented its revised analysis based on 2011 core-material 

prices. 

At the conclusion of the final meeting, subcommittee members presented their 

energy efficiency level recommendations. For low-voltage dry-type distribution 

transformers, the advocates, represented by ASAP, recommended EL4 for all DLs,

NEMA recommended EL 2 for DLs 7 and 8, and no change from the current standard for 

DL 6. EEI, AK Steel and ATI Allegheny Ludlum recommended EL 1 for DLs 7 and 8,

and no change from the current standard for DL 6. The subcommittee did not arrive at 

consensus regarding a proposed standard for low-voltage dry-type distribution 

transformers. Transcripts of the subcommittee meetings and all data and materials 

presented at the subcommittee meetings are available at the DOE website at: 

http://www.eere.energy.gov/buildings/appliance_standards/commercial/

distribution_transformers.html. 

III. General Discussion 

A. Test Procedures 

Section 7(c) of the Process Rule15 indicates that DOE will issue a final test 

procedure, if one is needed, prior to issuing a proposed rule for energy conservation 

 

15 The Process Rule provides guidance on how DOE conducts its energy conservation standards 

rulemakings, including the analytical steps and sequencing of rulemaking stages (such as test procedures 

and energy conservation standards). (10 CFR Part 430, Subpart C, Appendix A).
39

standards. DOE published its test procedure for distribution transformers in the Federal 

Register as a final rule on April 27, 2006. 71 FR 24972.

1. General

Currently, DOE requires distribution transformers to comply with standards with 

their windings in the configuration that produces the greatest losses. (10 CFR 431, 

Subpart K, Appendix A) During the April 5, 2011, public meeting, DOE addressed issues 

and solicited comments about amending the energy conservation standards for 

distribution transformers, the analytical framework and results of its preliminary analysis, 

and potential energy efficiency standards. At the outset, DOE proposed to amend the test 

procedure under appendix A to subpart K of 10 CFR Part 431, Uniform Test Method for 

Measuring the Energy Consumption of Distribution Transformers. DOE proposed to 

allow compliance testing in any secondary configuration and at the lowest basic impulse 

level (BIL) rating and to require compliance at the lowest BIL at which dual or multiple 

voltage distribution transformers are rated to operate.

The Northwest Power and Conservation Council (NPCC) and Northwest Energy 

Efficiency Alliance (NEEA)16 jointly submitted comments that the test procedure should 

adhere to specifications that do not make it difficult for the most challenging designs to 

comply with the standard, or else these transformer designs may be eliminated from the 

 

16 The Northwest Power and Conservation Council (NPCC) and Northwest Energy Efficiency Alliance 

(NEEA) submitted joint comments and are hereinafter referred to as NPCC/NEEA.
40

marketplace. (NPCC/NEEA, No. 11 at p. 2)17 NPCC and NEEA further noted that they 

would support a change to allow manufacturers to test at a single voltage for models with 

a range of voltage taps that is ± 5 percent, using the middle voltage of that range. 

(NPCC/NEEA, No. 11 at p. 3) Finally, NPCC and NEEA requested that DOE explicitly 

explain the benefit of any changes to the test procedure, since certain changes could make 

future and past ratings more difficult to consistently compare. (NPCC/NEEA, No. 11 at 

p. 3)

NEMA commented that distribution transformers are rated to operate at multiple 

kilovolt ampere (kVA) ratings corresponding to passive cooling, active cooling, or a 

combination of both. NEMA stated that the regulation should clarify that transformers 

with multiple kVA ratings should comply at the base rating (passive cooling). (NEMA, 

No. 13 at pp. 2-3)

Although DOE does not intend to eliminate features offering unique utility from 

the marketplace, it wishes to gather more information on the specific efficiency 

differences between winding configurations as well as the relative frequencies of their 

uses. With this in mind and considering the comments, DOE proposes to continue 

requiring compliance testing in the primary and secondary winding configuration with 

the highest losses, as is currently required under appendix A to subpart K of 10 CFR Part 

431. DOE agrees that passive cooling is the most common mode of operation for 

 

17 This short-hand citation format is used throughout this document. For example: "(NPCC/NEEA, No. 11 

at p. 2)" refers to a (1) a joint statement that was submitted by NPCC and NEEA and is recorded at 

http://www.regulations.gov/#!home in the docket under "Energy Conservation Standards for Distribution 

Transformers," Docket Number EERE-2010-BT-STD-0048, as comment number 11; and (2) a passage that 

appears on page 2 of that statement.
41

distribution transformers employed in power distribution and clarifies that manufacturers 

are only required to demonstrate compliance at kVA ratings that correspond to passive 

cooling. 18

DOE requests comment and corroborating data on how often distribution 

transformers are operated with their primary and secondary windings in different 

configurations, and on the magnitude of the additional losses in less efficient 

configurations.

2. Multiple kVA Ratings

Currently, DOE is nonspecific on which kVA rating should be used to assess 

compliance in the case of distribution transformers with more than one kVA.

ABB’s recommendations on transformers with multiple kVA ratings depended on 

how the transformer was cooled. For naturally-cooled transformers, ABB recommended 

that they should be required to meet the efficiency standard for every kVA rating. 

However, ABB suggested that forced-cooled transformers should only have to meet the 

efficiency standard at the naturally-cooled kVA rating. This is because the forced-cooled 

rating, which is meant only for temporary overload conditions, is dependent on the 

operation of auxiliary cooling fans that have a lower operating life than the transformer. 

(ABB, No. 14 at pp. 3-5)

 

18 Passive cooling is cooling that does not require fans, pumps, or other energy-consuming means of 

increasing thermal convection.

Comment [A11]: Change recommended by 

OIRA.
42

DOE has received nearly unanimous feedback that transformers in distribution 

applications are seldom designed to rely on active cooling even occasionally and that the 

majority of designs lack active cooling altogether. DOE wishes to clarify that 

manufacturers are only required to demonstrate compliance at kVA ratings that 

correspond to passive cooling.

3. Dual/Multiple-Voltage Basic Impulse Level

Currently, DOE requires distribution transformers to comply with standards using 

the BIL rating of the winding configuration that produces the greatest losses. (10 CFR 

431, Subpart K, Appendix A)

Several stakeholders commented that distribution transformers with multiple BIL 

ratings should comply with the efficiency based on the highest BIL rating, as the 

transformer core is based on the highest BIL rating. (Hammond (HPS), No. 3 at p. 1; 

NEMA, No. 13 at p.2; and FPT, No. 27 at p. 13) NEMA noted that for dual/multiple 

distribution transformers with varying BIL levels, DOE should align its requirements 

with those of the Institute of Electrical and Electronics Engineers (IEEE) standards 

(C57.12.00 for liquid-filled, NEMA ST20-1992:3.3 for low-voltage) and require testing 

in the “as shipped” condition, which would base the efficiency on the highest BIL rating, 

matching IEEE and industry practice. (NEMA, No. 13 at p. 2) Federal Pacific 

Transformers (FPT) stated that medium-voltage distribution transformers with multiple 

configurations should be held to the efficiency standard of the configuration with the 

highest BIL rating because the distribution transformer is required to be much larger for 
43

the higher BIL rating and, therefore, cannot reasonably meet the energy efficiency level 

of the lower BIL rating. (FPT, No. 27 at p. 13) FPT also expressed their support for 

testing on the highest BIL efficiency rating for re-connectable distribution transformers. 

(FPT, Pub. Mtg. Tr., No. 34 at p. 40)19

ABB commented that DOE should not change the test requirement to allow 

compliance at the lowest BIL rating. According to ABB, there is no way to ascertain 

which operating condition a distribution transformer will use over its lifetime. ABB 

stated that DOE should require that the efficiency be met on any operational 

configuration for which the distribution transformer is designed for continuous operation. 

(ABB, No. 14 at p. 2) 

DOE needs to gather more information in order to be certain that allowing 

compliance at any BIL rating would not result in lowered energy savings relative to what 

is predicted by DOE’s analysis. DOE proposes to maintain the current requirement to 

comply in the configuration that gives rise to the greatest losses.

4. Dual/Multiple-Voltage Primary Windings

Currently, DOE requires manufacturers to comply with energy conservation 

standards with distribution transformer primary windings (“primaries") in the 

configuration that produces the highest losses. (10 CFR 431, Subpart K, Appendix A)

 

19 This short-hand citation format for the public meeting transcript is used throughout this document. For 

example: "(FPT, Pub. Mtg. Tr., No. 34 at p. 40)" refers to a comment on the page number of the transcript 

of the "Public Meeting on Energy Conservation Standard Preliminary Analysis for Distribution 

Transformers," held in Washington, DC, April 5, 2011.
44

Where DOE invited additional comments about the test procedures, Howard 

Industries added that, under the presumption that DOE would allow compliance testing in 

any of the secondary configurations (“secondaries”), DOE should insert the word 

“primary” into the testing requirements [at section 5.0, Determining the Efficiency Value 

of the Transformer, under appendix A to subpart K of 10 CFR Part 431], and require the 

manufacturer to “determine the basic model’s efficiency at the ‘primary’ voltage at which 

the highest losses occur or at each ‘primary’ voltage at which the distribution transformer

is rated to operate.” Howard Industries noted that, for multiple-voltage distribution 

transformers, this insertion would clarify that distribution transformer efficiency is 

determined by the primary voltage and that the low-voltage or secondary winding 

configuration that is used would be at the manufacturer's discretion. (HI, No. 23 at p. 2)

HVOLT commented that distribution transformers with dual or multiple-voltage 

primary windings should be allowed to comply while the primaries are connected in 

series. HVOLT explained that utilities purchase these transformers to upgrade a 

distribution circuit to higher voltages within a few years of purchase and that these 

transformers will spend more than 90 percent of their lives with the primary windings 

connected in series. (HVOLT, No. 33 at p. 2)

DOE understands that, in contrast to the secondary windings, reconfigurable 

primaries typically exhibit a larger variation in efficiency between series and primary 

connections. As the above commenters have pointed out, however, such transformers are 
45

often purchased with the intent of upgrading the local power grid to a higher operating 

voltage with lowered overall system losses. In that sense, transformers with 

reconfigurable primaries can be seen as a stepping stone toward greater overall energy 

savings, even if those savings do not occur within the transformer itself.

DOE conducted several sensitivity analyses to examine the effects of a 

reconfigurable primary winding on efficiency and found that the difference between the 

efficiency of the secondary and the efficiency of the primary was more significant than in 

the case of configurable secondary windings. 

DOE wishes to obtain more information on both the difference in losses between 

different winding configurations as well as the different configurations’ relative 

frequency of operation in practice. DOE requests comment on this proposal to continue to 

mandate compliance in the highest-loss configuration and data illustrating the efficiency 

differences between primary winding configurations.

5. Dual/Multiple-Voltage Secondary Windings

Currently, DOE requires transformers to comply with their secondary windings in 

the configuration that produces the greatest losses. (10 CFR 431, Subpart K, Appendix A)

Interested parties commented that DOE should not change the current test 

requirement to permit compliance testing in any secondary configuration at the lowest 

BIL rating for transformers with dual/multiple-voltage secondary windings, and that 
46

these transformers should comply with an energy efficiency level using the combination 

of connections that produces the highest losses. (HPS, No. 3 at p.1; NPCC/NEEA, No. 11 

at p. 3; and ABB, No. 14 at p. 2) ABB also noted that there is no way to determine the 

connection on which a unit will be operated over its lifetime.

Schneider Electric (SE) commented that NEMA ST20-1992: 3.3 [Dry-Type 

Transformers for General Applications, NEMA ST 20-1992(R1997)] requires that “lowvoltage [transformers] be shipped with the connections done for the highest voltage” and 

requested that “all compliance testing be done in the configuration requirement of ST20." (SE, No. 18 at p. 5) Similarly, NEMA commented that "DOE should align its 

requirements with those of IEEE standards (C57.12.00 for liquid-filled, NEMA ST 20-

1992: 3.3 for low-voltage), requiring testing in the 'as shipped' condition." (NEMA, No. 

13 at p. 2) Further, NEMA noted that industry practice is to ship these units in the series 

connection. Similarly, FPT asserted that, “for units with multiple (series-parallel) lowvoltage ratings, the efficiency standard should be based on the highest voltage (series) 

connection, which matches the IEEE standard and industry practice.” (FPT, No. 27 at p. 

11) 

Several interested parties expressed support for DOE’s proposal to allow 

compliance testing in any secondary configuration at the lowest voltage rating. (Power 

Partners, Inc. (PP), Pub. Mtg. Tr., No. 34 at p. 40; HVOLT, No. 33 at p. 2; HI, No. 23 at 

p.2; and PP, No. 19 at p. 2) HVOLT noted that about 99 percent of dual/multiple-voltage 

single-phase, pole-type transformers are used in the series connection, and the work to 
47

otherwise reconnect to the secondary is burdensome. (HVOLT, No. 33 at p.2) Similarly, 

HI pointed out that very few transformers are ever reconnected for parallel operation and 

that testing requirements in a parallel configuration can be burdensome. (HI, No. 23 at p. 

2)

Furthermore, HVOLT commented that a distribution transformer that is designed 

for a dual voltage rating does not have an even multiple quantity of series connections 

compared to parallel connection designs. This means that there are already unused 

windings that will be in the parallel connection. Because the testing procedure requires 

that they be tested on the lowest BIL connections, these types of distribution transformers 

effectively have a higher efficiency requirement. HVOLT believes dual voltage 

distribution transformers are being unduly burdened by the test procedure. (HVOLT, Pub. 

Mtg. Tr., No. 34 at pp. 38-39)

HI recommended that DOE adjust the efficiency value by 0.1 for dual/multiplevoltage liquid-immersed distribution transformers with windings having a ratio other than 

2:1, due to the complexity of the winding for these distribution transformers. HI noted 

that a similar approach was taken by the Canadian Standards Associations Standards. (HI, 

No. 23 at p. 2)

DOE understands that some distribution transformers may be shipped with 

reconfigurable secondary windings, and that certain configurations may have different 

efficiencies. Currently, DOE requires distribution transformers to be tested in the 
48

configuration that exhibits the highest losses, which is usually with the secondary 

windings in parallel. Whereas the IEEE Standard20 requires a distribution transformer to 

be shipped with the windings in series, a manufacturer testing for compliance could need 

to test the distribution transformer for energy efficiency, disassemble the unit, 

reconfigure the windings, and reassemble the unit for shipping at added time and 

expense. Nonetheless, DOE would need to obtain more specific information on the 

potential net energy losses associated with permitting distribution transformers to be 

tested in any secondary winding configuration and proposes to maintain the current 

requirement of compliance in the configuration that produces the greatest losses.

DOE requests comment on secondary winding configurations, and on the 

magnitude of the additional losses associated with the less efficient configurations as well 

as the relative frequencies of operation in each winding configuration.

6. Loading

Currently, DOE requires that both liquid-immersed and medium-voltage, dry-type 

distribution transformers comply with standards at 50 percent loading and that lowvoltage, dry-type distribution transformers comply at 35 percent loading.

Warner Power (WP) commented that a single 35 percent test load for low-voltage 

dry-type distribution transformers (LVDTs) does not adequately reflect known service 

conditions at widely varying, and often low, average loads. It cited several studies 

indicating a lower average load factor and a shrinking load factor and recommended 

 

20 IEEE C57.12.00

Comment [A12]: Change recommended by 

OIRA.
49

LVDTs be certified at 15 percent and 35 percent loading. (WP, No. 30 at pp. 1-2) In 

addition, Warner Power suggested that a weighted curve between 10 percent and 80 

percent load factors would be better than a single 35 percent load factor. It recommended 

using published data to more accurately reflect real load conditions, accounting for daily, 

weekly, and seasonal variations. For LVDT transformers, it pointed out that the load 

profile should characterize the typical use in different types of buildings. (WP, No. 30 at 

p.5) NPCC and NEEA opined that, with better loading data for distribution transformers, 

they would support testing at multiple loading points, such as 15, 35, 50 and 70 percent, 

with a weighted-average calculation that is unique to each class. They noted, however, 

that such data is likely not available. (NPCC/NEEA, No. 11 at pp. 2-3)

HVOLT commented that the test procedure-required load values for all three 

categories of distribution transformers appeared reasonable for the foreseeable future. 

Otherwise, with electric vehicles and plug-in hybrids entering the market, HVOLT 

opined that root-mean-square loading will increase in the long-term but may take decades 

to have an effect. (HVOLT, No. 33 at p. 1) NPCC and NEEA announced that they are 

collecting additional field data to inform the appropriateness of the test procedure loading 

points. (NPCC/NEEA, No. 11 at p. 2)

NEMA, ABB, and Schneider Electric (SE) all commented that DOE should not 

modify its test procedures by considering weighted-average loadings for core 

deactivation efficiency standards. (NEMA, No. 13 at p. 2; ABB, No. 14 at pp. 2-3; and 

SE, Pub. Mtg. Tr., No. 34 at p. 57) ABB further clarified that this approach would be 
50

inaccurate because the true load varies by every distinct installation. Instead, it asserted 

that the current load factors are more appropriate because they reflect the aggregate 

impact on the national grid. (ABB, No. 14 at pp. 2-3)

NPCC and NEEA recommended that DOE attempt to gather data on actual core 

deactivation designs and control algorithms before it changes the test procedure. 

Additionally, NPCC and NEEA suggested that DOE gather data on the performance of 

distribution transformers under various load conditions. If this data is unavailable or 

inconclusive, they suggested that DOE not change the test procedure at this time but 

rather ensure that core deactivation technology is examined in the next rulemaking for 

distribution transformers. (NPCC/NEEA, No. 11 at p. 3)

Warner Power (WP) indicated its intent to submit data concerning modified test 

procedures which would better capture core deactivation technologies. (WP, Pub. Mtg. 

Tr., No. 34 at p. 42)

DOE is proposing to maintain the use of a single, discrete loading point for 

distribution transformers because the use of weighted-average loadings would represent a 

fairly significant change in the test procedure, possibly causing some units that meet 

energy conservation standards to no longer do so. In the future, DOE may consider 

modifying this approach. DOE welcomes relevant data in conjunction with comments on 

typical distribution transformer loading profiles.
51

B. Technological Feasibility 

1. General 

There are distribution transformers available at all of the energy efficiency levels 

considered in today’s notice of proposed rulemaking. Therefore, DOE believes all of the 

energy efficiency levels adopted by today’s notice of proposed rulemaking are 

technologically feasible.

2. Maximum Technologically Feasible Levels

When DOE proposes to adopt, or decline to adopt, an amended or new standard 

for a type of covered product, section 325(o)(2) of EPCA, 42 U.S.C. 6295(o)(2), requires 

that DOE determine the maximum improvement in energy efficiency or maximum 

reduction in energy use that is technologically feasible. While developing the energy 

conservation standards for liquid-immersed and medium-voltage, dry-type distribution 

transformers that were codified under 10 CFR 431.196, DOE determined the maximum 

technologically feasible ("max-tech") energy efficiency level through its engineering 

analysis using the most efficient materials, such as core steels and winding materials, and 

applied design parameters that drove distribution transformer software to create designs 

at the highest efficiencies achievable at the time. 71 FR 44362 (August 4, 2006) and 72 

FR 58196 (October 12, 2007). DOE used these designs to establish max-tech levels for its 

LCC analysis and scaled them to other kVA ratings within a given design line, thereby 

establishing max-tech efficiencies for all the distribution transformer kVA ratings.
52

C. Energy Savings 

1. Determination of Savings

Section 325(o)(2)(A) of EPCA, 42 U.S.C. 6295(o)(2)(A), requires that any new or 

amended standard must be chosen so as to achieve the maximum improvement in energy 

efficiency that is technologically feasible and economically justified. In determining 

whether economic justification exists, key factors include the total projected amount of 

energy savings likely to result directly from the standard and the savings in operating 

costs throughout the estimated average life of the covered equipment. To understand the 

national economic impact of potential efficiency regulations for distribution transformers, 

DOE conducted a national impact analysis (NIA) using a spreadsheet model to estimate 

future national energy savings (NES) from amended energy conservation standards.21 For 

each TSL, DOE forecasted energy savings beginning in 2016, the year that manufacturers 

would be required to comply with amended standards, and ending in 2045. DOE 

quantified the energy savings for each TSL as the difference in energy consumption 

between the “standards case” and the “base case.” The base case represents the forecast 

of energy consumption in the absence of amended mandatory efficiency standards, and 

takes into consideration market demand for more-efficient equipment.

The NIA spreadsheet model calculates the electricity savings in “site energy” 

expressed in kilowatt-hours (kWh). Site energy is the energy directly consumed by 

distribution transformer products at the locations where they are used. DOE reports 

national energy savings on an annual basis in terms of the aggregated source (primary) 

 

21 The NIA spreadsheet model is described in section IV.G of this notice.
53

energy savings, which is the savings in the energy that is used to generate and transmit 

the site energy. (See TSD chapter 10.) To convert site energy to source energy, DOE 

derived annual conversion factors from the model used to prepare the Energy Information 

Administration’s (EIA) Annual Energy Outlook 2011 (AEO2011).

2. Significance of Savings

As noted above, 42 U.S.C. 6295(o)(3)(B) prevents DOE from adopting a standard 

for covered equipment if such a standard would not result in “significant” energy savings. 

While EPCA does not define the term “significant,” the U.S. Court of Appeals for the 

District of Columbia, in Natural Resources Defense Council v. Herrington, 768 F.2d 

1355, 1373 (D.C. Cir. 1985), indicated that Congress intended “significant” energy 

savings in this context to be savings that were not “genuinely trivial.” The energy savings 

for all of the TSLs considered in this rulemaking are non-trivial and, therefore, DOE 

considers them “significant” within the meaning of EPCA section 325(o).

D. Economic Justification

1. Specific Criteria

As noted previously, EPCA requires DOE to evaluate seven factors to determine 

whether a potential energy conservation standard is economically justified. (42 U.S.C. 

6295(o)(2)(B)(i)) The following sections describe how DOE has addressed each of the 

seven factors in this rulemaking.

Deleted: 2010 (AEO2010
54

a. Economic Impact on Manufacturers and Consumers

In determining the impacts of an amended standard on manufacturers, DOE first 

determines the quantitative impacts using an annual cash-flow approach. This includes 

both a short-term assessment, based on the cost and capital requirements during the 

period between the issuance of a regulation and when entities must comply with the 

regulation, and a long-term assessment over a 30-year analysis period. The industry-wide 

impacts analyzed include INPV (which values the industry on the basis of expected 

future cash flows), cash flows by year, changes in revenue and income, and other 

measures of impact, as appropriate. Second, DOE analyzes and reports the impacts on 

different types of manufacturers, paying particular attention to impacts on small 

manufacturers. Third, DOE considers the impact of standards on domestic manufacturer 

employment and manufacturing capacity, as well as the potential for standards to result in 

plant closures and loss of capital investment. Finally, DOE takes into account cumulative 

impacts of different DOE regulations and other regulatory requirements on 

manufacturers.

For individual consumers, measures of economic impact include the changes in 

LCC and the PBP associated with new or amended standards. The LCC, which is 

separately specified in EPCA as one of the seven factors to be considered in determining 

the economic justification for a new or amended standard (42 U.S.C. 

6295(o)(2)(B)(i)(II)), is discussed in the following section. For consumers in the 

aggregate, DOE also calculates the national net present value of the economic impacts on 

consumers over the forecast period used in a particular rulemaking.
55

Federal Pacific suggested that DOE establish reference efficiencies by rating, as 

defined by NEMA Premium, for those users who want efficiencies higher than current 

minimum efficiencies. However, they did not want these reference efficiencies to become 

the new minimum efficiency mandates. (FPT, No. 27 at p. 2)

The National Rural Electric Cooperative Association (NRECA) recommended 

that DOE not raise the efficiency standards for the liquid-filled distribution transformers, 

since many rural utilities with low distribution transformer loads cannot economically 

justify the current energy efficiency level. (NRECA, No. 31 and 36 at p. 1)

DOE appreciates the comments and considers impacts to consumers, 

manufacturers, and utilities in TSD chapters 8, 12, and 14, respectively. DOE welcomes 

comment on these analyses and on any subset of consumers, manufacturers, or utilities 

that could be disproportionately affected.

b. Life-Cycle Costs

The LCC is the sum of the purchase price of a type of equipment (including its 

installation) and the operating expense (including energy and maintenance and repair 

expenditures) discounted over the lifetime of the product. The LCC savings for the 

considered energy efficiency levels are calculated relative to a base case that reflects 

likely trends in the absence of amended standards. The LCC analysis requires a variety of 

inputs, such as equipment prices, equipment energy consumption, energy prices, 
56

maintenance and repair costs, equipment lifetime, and consumer discount rates. DOE 

assumed in its analysis that consumers will purchase the considered equipment in 2016. 

To account for uncertainty and variability in specific inputs, such as product 

lifetime and discount rate, DOE uses a distribution of values with probabilities attached 

to each value. A distinct advantage of this approach is that DOE can identify the 

percentage of consumers estimated to receive LCC savings or experience an LCC 

increase, in addition to the average LCC savings associated with a particular standard 

level. In addition to identifying ranges of impacts, DOE evaluates the LCC impacts of 

potential standards on identifiable subgroups of consumers that may be 

disproportionately affected by a national standard.

c. Energy Savings

While significant conservation of energy is a separate statutory requirement for 

imposing an energy conservation standard, EPCA requires DOE, in determining the 

economic justification of a standard, to consider the total projected energy savings that 

are expected to result directly from the standard. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE 

uses the NIA spreadsheet results in its consideration of total projected energy savings. 

d. Lessening of Utility or Performance of Products

In establishing classes of products, and in evaluating design options and the 

impact of potential standard levels, DOE sought to develop standards for distribution 

transformers that would not lessen the utility or performance of these products. (42 
57

U.S.C. 6295(o)(2)(B)(i)(IV)) None of the TSLs presented in today’s NOPR would 

substantially reduce the utility or performance of the equipment under consideration in 

the rulemaking.

DOE requests comment on the possibility of reduced equipment performance or 

utility resulting from today’s proposed standards, particularly the risk of reducing the 

ability to perform periodic maintenance and the risk of increasing vibration and acoustic 

noise.

e. Impact of Any Lessening of Competition

EPCA directs DOE to consider any lessening of competition that is likely to result 

from standards. It also directs the Attorney General of the United States (Attorney 

General) to determine the impact, if any, of any lessening of competition likely to result 

from a proposed standard and to transmit such determination to the Secretary within 60 

days of the publication of a proposed rule, together with an analysis of the nature and 

extent of the impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)) DOE will transmit a 

copy of today’s proposed rule to the Attorney General with a request that the Department 

of Justice (DOJ) provide its determination on this issue. DOE will address the Attorney 

General’s determination in the final rule.

f. Need for National Energy Conservation

Certain benefits of the proposed standards are likely to be reflected in 

improvements to the security and reliability of the Nation’s energy system. Reductions in 

Comment [A13]: Change recommended by 

OIRA.
58

the demand for electricity may also result in reduced costs for maintaining the reliability 

of the Nation’s electricity system. DOE conducts a utility impact analysis to estimate how 

standards may affect the Nation’s needed power generation capacity. (See 42 U.S.C. 

6295(o)(2)(B)(i)(VI))

Energy savings from the proposed standards are also likely to result in 

environmental benefits in the form of reduced emissions of air pollutants and greenhouse 

gases associated with energy production. DOE reports the environmental effects from the 

proposed standards, and from each TSL it considered, in the environmental assessment

contained in chapter 15 in the NOPR TSD. DOE also reports estimates of the economic 

value of emissions reductions resulting from the considered TSLs.

g. Other Factors

EPCA allows the Secretary of Energy, in determining whether a standard is 

economically justified, to consider any other factors that the Secretary considers relevant. 

(42 U.S.C. 6295(o)(2)(B)(i)(VII)) In developing the proposals of this notice, DOE has 

also considered the matter of electrical steel availability. This factor is discussed further 

in section V.B.8.

2. Rebuttable Presumption

As set forth in 42 U.S.C. 6295(o)(2)(B)(iii), EPCA creates a rebuttable 

presumption that an energy conservation standard is economically justified if the 

additional cost to the consumer of a product that meets the standard is less than three 
59

times the value of the first-year of energy savings resulting from the standard, as 

calculated under the applicable DOE test procedure. DOE’s LCC and payback period 

(PBP) analyses generate values used to calculate the PBP for consumers of potential 

amended energy conservation standards. These analyses include, but are not limited to, 

the three-year PBP contemplated under the rebuttable presumption test. However, DOE 

routinely conducts an economic analysis that considers the full range of impacts to the 

consumer, manufacturer, Nation, and environment, as required under 42 U.S.C. 

6295(o)(2)(B)(i). The results of this analysis serve as the basis for DOE to definitively 

evaluate the economic justification for a potential standard level (thereby supporting or 

rebutting the results of any preliminary determination of economic justification). The 

rebuttable presumption payback calculation is discussed in section V.B.1.c of this NOPR 

and chapter 8 of the NOPR TSD.

IV. Methodology and Discussion of Related Comments

DOE used two spreadsheet tools to estimate the impact of today’s proposed 

standards. The first spreadsheet calculates LCCs and PBPs of potential new energy 

conservation standards. The second provides shipments forecasts and calculates national 

energy savings and net present value impacts of potential new energy conservation 

standards. DOE also assessed manufacturer impacts, largely through use of the 

Government Regulatory Impact Model (GRIM). The two spreadsheets are available 

online at the rulemaking website: 

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_tra

nsformers.html.
60

Additionally, DOE estimated the impacts of energy conservation standards for 

distribution transformers on utilities and the environment. DOE used a version of EIA’s 

National Energy Modeling System (NEMS) for the utility and environmental analyses. 

The NEMS model simulates the energy sector of the U.S. economy. EIA uses NEMS to 

prepare its Annual Energy Outlook (AEO), a widely known energy forecast for the United 

States. The version of NEMS used for appliance standards analysis is called NEMS-BT22

and is based on the AEO version with minor modifications.23 The NEMS-BT offers a 

sophisticated picture of the effect of standards because it accounts for the interactions 

between the various energy supply and demand sectors and the economy as a whole.

A. Market and Technology Assessment

For the market and technology assessment, DOE develops information that 

provides an overall picture of the market for the products concerned, including the 

purpose of the products, the industry structure, and market characteristics. This activity 

includes both quantitative and qualitative assessments, based primarily on publicly 

available information. The subjects addressed in the market and technology assessment 

for this rulemaking include scope of coverage, definitions, equipment classes, types of 

products sold and offered for sale, and technology options that could improve the energy 

 

22BT stands for DOE’s Building Technologies Program.

23 The EIA allows the use of the name “NEMS” to describe only an AEO version of the model without any 

modification to code or data. Because the present analysis entails some minor code modifications and runs 

the model under various policy scenarios that deviate from AEO assumptions, the name “NEMS-BT” refers 

to the model as used here. For more information on NEMS, refer to The National Energy Modeling 

System: An Overview, DOE/EIA–0581 (98) (Feb.1998), available at: 

http://tonto.eia.doe.gov/FTPROOT/forecasting/058198.pdf.
61

efficiency of the products under examination. Chapter 3 of the TSD contains additional 

discussion of the market and technology assessment.

1. Scope of Coverage

This section addresses the scope of coverage for today’s proposal, stating which 

products would be subject to amended standards. The numerous comments DOE received 

on the scope of today’s proposal are also summarized and addressed in this section.

a. Definitions

Today’s proposed standards rulemaking concerns distribution transformers, which 

include three categories: liquid-immersed, low-voltage dry-type (LVDT) and mediumvoltage dry-type (MVDT). The definition of a distribution transformer was presented in 

EPACT 2005 and then further refined by DOE when it was codified into 10 CFR 431.192 

by the April 27, 2006 final rule for distribution transformer test procedures (71 FR 

24995) as follows:

Distribution transformer means a transformer that -

(1) Has an input voltage of 34.5 kV or less;

(2) Has an output voltage of 600 V or less;

(3) Is rated for operation at a frequency of 60 Hz; and

(4) Has a capacity of 10 kVA to 2500 kVA for liquid-immersed units and 15 kVA 

to 2500 kVA for dry-type units; but

(5) The term “distribution transformer” does not include a transformer that is an–

(i) Autotransformer;
62

(ii) Drive (isolation) transformer;

(iii) Grounding transformer;

(iv) Machine-tool (control) transformer;

(v) Non-ventilated transformer;

(vi) Rectifier transformer;

(vii) Regulating transformer;

(viii) Sealed transformer;

(ix) Special-impedance transformer;

(x) Testing transformer;

(xi) Transformer with tap range of 20 percent or more;

(xii) Uninterruptible power supply transformer; or

(xiii) Welding transformer.

Additional detail on the definitions of each of these excluded transformers can 

found in TSD chapter 3.

DOE received multiple comments seeking clarification on various terms used in 

the definition of a distribution transformer. NEMA requested that DOE amend the 

definitions of two transformer types explicitly excluded from the distribution transformer 

definition, namely “rectifier transformer” and “testing transformer.” NEMA suggested 

that both definitions should require the nameplates of such transformers to identify the 

transformers as being for such uses only. (NEMA, No. 13 at p. 10) Furthermore, NEMA 

recommended that transformers used inside underground tunneling equipment should be 
63

added to the definition for underground mining distribution transformers because this 

equipment is specialized and requires a compact transformer. (NEMA, No. 13 at p. 10) 

FPT agreed with NEMA and recommended that DOE amend the definition of 

“underground mining transformer” with the following sentence: “The term ‘mining’ may 

also be understood to mean underground tunneling or digging.” FPT added that the term 

“mining” should be clarified to encompass any underground operation involving the 

removal of material underground, such as digging or tunneling, which have the same 

restrictions with the size of distribution transformers, but might not be considered to be 

mining applications. (FPT, No. 27 at pp. 10-11) Finally, PP commented that DOE should 

clarify the definitions of input and output voltage to reflect the three-phase system 

voltages and not the line to ground voltage, which is typically the input voltage for 

single-phase transformers. (PP, No. 1 at p. 1)

DOE agrees that these additions to the definitions of “rectifier transformer” and 

“testing transformer” are helpful in aiding the consumer to distinguish rectifier and 

testing transformers and therefore proposes to amend its definitions correspondingly. 

Additionally, DOE believes that transformers used for the removal of material 

underground are subject to similar space constraints as traditional mining transformers 

and therefore their ability to meet higher efficiency standards are similarly restricted. 

However, DOE wishes to learn more about the nature of those applications in order to 

define the units precisely. Consequently, DOE proposes to maintain the current definition 

of “mining transformer” unless it is able to determine that the expansion, as suggested by 

NEMA and FPT, is warranted and able to be implemented with sufficient specificity. 
64

DOE requests comment on that proposal and any information useful in understanding 

how transformers used in certain underground applications differ and could be defined 

precisely. Finally, DOE also wishes to remove any ambiguity in the terms “input voltage” 

and “output voltage” and requests comment on where that ambiguity lies. 

Multiple interested parties submitted comments regarding the kVA ratings that are 

currently included in the scope of coverage. PP commented that DOE should consider 

removing single-phase liquid-immersed distribution transformers rated above 250 kVA 

with a low-voltage rating of 600V from the scope of the regulation. They contended that 

these transformers constitute a very low volume of shipments (481 units in 2009) and 

MVA capacity shipped (201 MVA in 2009) and therefore the overall national energy 

savings would not be significant. (PP, No. 19 at pp. 1-3; Pub. Mtg. Tr., No. 34 at p. 34) 

PP added that the impact of increased weight and dimensions is greater in these sizes 

where maximum tank size and weight constraints are critical. Moreover, PP proposed that 

DOE should consider 500 kVA the upper limit of kVA ratings covered and shift the 

lower limit from 10 to 5 kVA. (PP, Pub. Mtg. Tr., No. 34 at pp. 46, 73-74; PP, No. 19 at 

pp. 1-2) Similarly, NPCC and NEEA urged DOE to decide whether to include singlephase liquid-immersed distribution transformers down to 5 kVA in the scope of coverage. 

(NPCC/NEEA, No. 11 at p. 9) 

BBF and Associates suggested that DOE investigate increasing the scope of the 

rulemaking to include transformers from 2500 kVA to 20 MVA. (BBF, Pub. Mtg. Tr., 

No. 34 at p. 279) CDA recommended that DOE include transformers up to 30,000 kVA 
65

(30 MVA) in its scope, including sub-station transformers. It noted that these units are 

within the distribution system, and are substantial in unit shipment volumes. (CDA, No. 

17 at pp. 1-2, 4)

DOE understands that larger (250-833 kVA) single-phase, liquid-immersed units 

are currently covered and is not proposing to exclude them from consideration for this 

rulemaking. Because these ratings were covered by the previous rulemaking for 

distribution transformers, DOE is statutorily prohibited from backsliding and excluding 

such products from regulation at this time. (See 42 U.S.C. 6295(o)(1)6316(a)) However, 

DOE notes that it is accounting for the added life-cycle costs of larger and heavier 

transformers and discusses its methodology for this in chapter 6 of the TSD. 

Additionally, DOE determined during the previous standards rulemaking that 5 kVA 

transformers were below the kVA limit “commonly understood to be distribution 

transformers.” 69 FR 45381. DOE proposes to maintain that stance for this rulemaking as 

these units are generally too small to be employed in power distribution and collectively 

consume extremely little power. Similarly, units larger than 2.5 MVA (DOE’s current 

upper limit) are usually considered substation transformers, which DOE is not proposing 

to cover. DOE invites comment on its proposal to maintain the current scope of coverage.

Interested parties also solicited clarification from DOE on transformers that are 

used in a variety of applications. FPT requested that DOE clarify whether existing 

efficiency standards apply to transformers used in aircraft, trains/locomotives, offshore 

drilling platforms, mobile substations, ships, and other similar applications. (FPT, No. 27 
66

at p.2) Furthermore, FPT recommended that DOE investigate whether transformers being 

used in wind farms or solar energy applications should be exempted since these designs 

should be optimized at higher loading levels than the test procedure loading points of 35 

percent (low-voltage dry-type) and 50 percent (liquid-immersed and medium-voltage 

dry-type). (FPT, No. 27 at p. 2) Lastly, CDA commented that DOE should expand the 

scope of the rulemaking to include step-up transformers of kVA sizes that are currently 

included in the scope, such as transformers used in wind farms. (CDA, No. 17 at pp. 2-3)

EPACT 2005 defined the term “distribution transformer,” 42 USC 

6291(35)(B)(ii), to mean a transformer that (i) has an input voltage of 34.5 kilovolts or 

less; (ii) has an output voltage of 600 volts or less; and (iii) is rated for operation at a 

frequency of 60 Hertz. The definition goes on to generally exclude certain specializedapplication distribution transformers. At this time, DOE is not proposing to cover 

distribution transformers used in mobile applications because they do not represent 

traditional power distribution. For example, aircraft and marine transformers frequently 

operate at 400 Hz, and mobile substation transformers often fall outside the currently 

defined voltage and kVA ranges. Furthermore, transformers used in mobile applications 

could be unduly impacted by any increases in size and weight required to reach higher 

efficiencies. DOE requests comment on the topic of transformers used in mobile 

applications and any data helpful in considering whether standards are warranted. DOE 

also requests comment on the likelihood of this exclusion serving as a loophole in the 

face of increasing standards.
67

DOE does not propose to exclude transformers used in renewable energy 

applications simply because of the potential difference in loading that they may 

experience. DOE currently understands that the users who buy transformers for those 

applications tend to value losses highly and that such transformers would have little 

trouble meeting standards. Furthermore, DOE notes that its choices for the test procedure 

loading points do not imply that it intends to exclusively cover transformers with 

precisely those loading values. Rather, DOE accounts for consumers purchasing 

transformers optimized for loading values other than the test procedure value in its LCC 

analysis.

DOE proposes to continue to not set standards for step-up transformers, because 

they are not ordinarily considered to be performing a power distribution function. 

However, DOE is aware that step-up transformers may be able to be used in place of 

step-down transformers and may represent a potential loophole as standards increase. 

DOE requests comment on its proposal to continue not to set standards for step-up 

transformers.

Finally, DOE received an inquiry with regards to how it plans to deal with core 

deactivation technology. Specifically, Schneider Electric wanted to know if DOE would 

change the definition of transformers to include banks of transformers. (SE, Pub. Mtg. 

Tr., No. 34 at p. 57) Core-deactivation technology employs a system of smaller 

transformers to replace a single, larger transformer. For example, using this technology, 

three transformers sized at 25 kVA and operated in parallel could replace a single 75 
68

kVA transformer. The smaller transformers that compose the system can then be 

activated and deactivated using core deactivation technology based on the loading 

demand. At present, DOE is not proposing to set efficiency standards for banks of 

transformers, but notes that each constituent transformer would be subject to an 

efficiency standard if, on its own, it meets the definition of a distribution transformer.

b. Underground Mining Transformer Coverage

In the October 12, 2007, final rule on energy conservation standards for 

distributions transformers, DOE codified into 10 CFR 431.192 the definition of an 

“underground mining distribution transformer” as follows:

Underground mining distribution transformer means a medium-voltage dry-type 

distribution transformer that is built only for installation in an underground mine or inside 

equipment for use in an underground mine, and that has a nameplate which identifies the 

transformer as being for this use only. 72 FR 58239.

In that same final rule, DOE also clarified that although it believed these 

transformers were within its scope of coverage, it was not establishing any energy 

conservation standards for underground mining transformers. At the time, DOE 

recognized that these transformers were subject to unique and extreme dimensional 

constraints which impact their efficiency and performance capabilities. Therefore, DOE 

established a separate equipment class for mining transformers and stated that it may 

consider energy conservation standards for such transformers at a later date. Although 
69

DOE did not establish energy conservation standards for such transformers, it also did not 

add underground mining transformers to the list of excluded transformers in the 

definition of a distribution transformer. DOE retained that it had the authority to cover 

such equipment if, during a later analysis, it found technologically feasible and 

economically justified energy conservation standard levels. 72 FR 58197.

In response to the March 2, 2011 preliminary analysis, NEMA recommended that 

underground mining distribution transformers, including transformers used inside 

underground tunneling equipment, should be included on the exemption list to clarify that 

the standards shall not apply to them. (NEMA, No. 13 at p. 10) NPCC and NEEA 

commented that DOE should remove any confusion about the coverage of underground 

mining transformers either by setting standards for these units or adding them to the list 

of excluded transformers. (NPCC/NEEA, No. 11 at p 9)

FPT urged DOE to exclude mining transformers from minimum efficiency levels 

because it would result in undue economic hardship for the mining industry and 

unrealistic design constraints on mining equipment that use such transformers. FPT 

pointed out that mining transformers make up a small portion of the market and that the 

total amount of energy they consume is very small compared to the national energy 

consumption rate. FPT also noted that a mining transformer is more specialized in its 

design and application than many of the transformers excluded from the definition of 

distribution transformers under 10 CFR 431.192. (FPT, No. 27 at pp. 8-10)
70

In view of the above, DOE understands that underground mining transformers are 

subject to a number of constraints that are not usually concerns for transformers used in 

general power distribution. Because space is critical in mines, an underground mining 

transformer may be at a considerable disadvantage in meeting an efficiency standard. 

Underground mining transformers are further disadvantaged by the fact that they must 

supply power at several output voltages simultaneously. For this rulemaking, DOE again 

proposes not to set standards for underground mining transformers, but recognizes the 

possibility of a loophole. Therefore, DOE continues to leave underground mining 

transformers off of the list of exempt distribution transformers and reserve a separate 

equipment class for mining transformers. DOE may set standards in the future if it 

believes that underground mining transformers are being purchased as a way to 

circumvent energy conservation standards.

c. Low-Voltage Dry-Type Distribution Transformers

10 CFR 431.192 defines the term “low-voltage dry-type distribution transformer” 

to be 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.

Because EPACT 2005 prescribed standards for LVDTs, which DOE incorporated 

into its regulations at 70 FR 60407 (October 18, 2005) (codified at 10 CFR 431.196(a)), 

LVDTs were not included in the 2007 standards rulemaking. As a result, the settlement 
71

agreement following the publication of the 2007 final rule does not impact LVDT 

standards. 

Two interested parties, EEI and SE, requested clarification on whether LVDT 

distribution transformers would be included in this rulemaking. (EEI, Public Mtg. Tr., 

No. 34 at p. 56, 27; SE, No. 7 at p. 1) In particular, SE questioned whether Congress 

would be involved in amending standards for LVDTs. (SE, No. 7 at p. 1) Further, SE 

expressed concern that there does not appear to be a timeline for the LVDT distribution 

transformer rulemaking and that one is needed in order to plan potential capital 

expenditures for any new efficiency levels. (SE, Pub. Mtg. Tr., No. 34 at p. 19)

SE requested that DOE analyze LVDTs in a separate rulemaking from liquidimmersed distribution transformers and MVDTs. It noted that the law defines them 

separately and that LVDT distribution transformers are used in applications that are 

different from those of MVDT distribution transformers. SE further noted that LVDT 

distribution transformers may warrant an expanded scope of coverage and encouraged 

DOE to reassess the range of kVAs covered, product definitions, exemptions, and loading 

points. (SE, No. 18 at p. 1) FPT suggested that DOE evaluate LVDT distribution 

transformers at a later date because this product category is not part of the court order. 

(FPT, No. 27 at p. 1) Rather, FPT believed that DOE should establish non-mandatory 

efficiencies for LVDT distribution transformers so that consumers who wish to purchase 

higher efficiency units can have a point of reference. (FPT, No. 27 at pp. 1-2)
72

CDA observed that the current efficiency levels for LVDT distribution 

transformers are at NEMA TP-1 levels and that the 2010 MVDT and liquid-immersed 

distribution transformer efficiency levels were set at approximately TSL 4. 72 FR 58239-

40 (CDA, No. 17 at p. 3). CDA believed that it is appropriate for DOE to evaluate and 

adjust the minimum efficiency standards for LVDT distribution transformers, wherever 

cost-effective, to levels that are comparable to the 2010 levels for other [MVDT and 

liquid-immersed] distribution transformers. (CDA, No. 17 at p. 3) Earthjustice 

commented that DOE must revisit standards for LVDT distribution transformers as part 

of EPCA’s requirement that standards be reevaluated not later than six years after 

issuance. Earthjustice noted that, on October 18, 2005, DOE codified the efficiency 

standards for LVDT distribution transformers that were set forth in EPACT 2005 (70 FR 

60407) and that DOE must now publish, by October 18, 2011, either a new proposed 

standard or a determination that amended standards are not warranted. (Earthjustice, No. 

20 at pp. 1-2) In joint comments, the Appliance Standards Awareness Project (ASAP), 

American Council for an Energy Efficient Economy (ACEEE), and Natural Resources 

Defense Council (NRDC) agreed with Earthjustice that DOE is obligated under EPCA to 

review the efficiency standards for liquid-immersed and MVDT distribution transformers 

and amend the efficiency standards for LVDT distribution transformers if justified.

(ASAP/ACEEE/NRDC, No. 28 at p. 5) HVOLT also believed that DOE should consider 

LVDT distribution transformers at this time. (HVOLT, No. 33 at p. 2) EEI believed that 

LVDT distribution transformers could be included in the rulemaking, since they are 

covered products under the statute and are now under a DOE regulatory purview. (EEI, 

Pub. Mtg. Tr., No. 34 at pp. 21, 27)
73

Without regard to whether DOE may have a statutory obligation to review 

standards for LVDTs, DOE has analyzed all three transformer types and is proposing 

standards for each in this rulemaking.

Schneider Electric suggested expanding coverage to include sealed units within 

the range of Design Lines 6 and 7: single-phase 15 and 25 kVA and three-phase 15 kVA 

distribution transformers. Further, it suggested that an additional three-phase 15 kVA 

design line, which would include SCOTT-T and OPEN DELTA designs, be created to 

meet the definition of sealed transformers. (SE, No. 7 at p. 2) DOE is not making this 

change because the EPACT 2005 definition of a distribution transformer and the 

definition currently codified at 10 CFR 431.192 both explicitly prohibit the inclusion of 

such transformers.

d. Negotiating Committee Discussion of Scope

Negotiation participants noted that both network/vault transformers and “data 

center” transformers may experience disproportionate difficulty in achieving higher 

efficiencies due to certain features that may affect consumer utility. (ABB, Pub. Mtg. Tr., 

No. 89 at p. 245) The definitions below had been proposed at various points by 

committee members and DOE seeks comment on both whether it would be appropriate to 

establish separate equipment classes for any of the following types and, if so, on how 

such classes might be defined such that it was not financially advantageous for 

consumers to purchase transformers in either class for general use.
74

i. A “network transformer” is one–

(i) designed for use in a vault,

(ii) designed for occasional submerged operation in water, 

(iii)designed to feed a system of variable capacity system of 

interconnected secondaries, and

(iv)built per the requirements of IEEE C57.12.40-(year)

ii. A “vault-type” transformer is one–

(i) designed for use in a vault,

(ii) designed for occasional submerged operation in water, and

(iii) built per the requirements of IEEE C57.12.23-(year) or IEEE 

C57.12.24-(year), respectively.

iii. Data center transformer means a three-phase low-voltage dry-type 

distribution transformer that—

(i) is designed for use in a data center distribution system and has a 

nameplate identifying the transformer as being for this use only;

(ii) has a maximum peak energization current (or in-rush current) less 

than or equal to four times its rated full load current multiplied by 

the square root of 2, as measured under the following conditions—

(iii)during energization of the transformer without external devices 

attached to the transformer that can reduce inrush current;
75

(iv)the transformer shall be energized at zero +/- 3 degrees voltage 

crossing of A phase. Five consecutive energization tests shall be 

performed with peak inrush current magnitudes of all phases 

recorded in every test. The maximum peak inrush current recorded 

in any test shall be used;

(v) the previously energized and then de-energized transformer shall 

be energized from a source having available short circuit current 

not less than 20 times the rated full load current of the winding 

connected to the source; and

(vi)the source voltage shall not be less than 5 percent of the rated 

voltage of the winding energized; and 

(vii) is manufactured with at least two of the following other attributes:

1. listed by NRTL for a K-factor rating, as defined in UL standard 

1561: 2011 Fourth Edition, greater than K-4;

2. temperature rise less than 130°C with class 220 insulation or 

temperature rise less than 110°C with class 200 insulation;

3. a secondary winding arrangement that is not delta or wye 

(star);

4. copper primary and secondary windings;

5. an electrostatic shield; or 

6. multiple outputs at the same voltage a minimum of 15° apart, 

which when summed together equal the transformer’s input 

kVA capacity.
76

2. Equipment Classes

DOE divides covered equipment into classes by: (a) the type of energy used; (b) 

the capacity; or (c) any performance-related features that affect consumer utility or 

efficiency. (42 U.S.C. 6295(q)) Different energy conservation standards may apply to 

different equipment classes (ECs). For the preliminary analysis and for today’s NOPR, 

DOE analyzed the same ten ECs as were used in the previous distribution transformers 

energy conservation standards rulemaking

24. These ten equipment classes divided up the 

population of distribution transformers by:

(a) Type of transformer insulation - liquid-immersed or dry-type, 

(b) Number of phases - single or three,

(c) Voltage class - low or medium (for dry-type units only), and

(d) Basic impulse insulation level (for medium-voltage, dry-type units only).

On August 8, 2005, the President signed into law EPACT 2005, which contained 

a provision establishing energy conservation standards for two of DOE’s equipment 

classes – EC3 (low-voltage, single-phase, dry-type) and EC4 (low-voltage, three-phase, 

dry-type). With standards thereby established for low-voltage, dry-type distribution 

transformers, DOE no longer considered these two equipment classes for standards 

during the previous rulemaking. Since the current rulemaking is considering new 

standards for distribution transformers, DOE has preliminarily decided to also revisit 

low-voltage, dry-type distribution transformers to determine if higher efficiency 

 

24 See chapter 5 of the TSD for further discussion of equipment classes
77

standards are justified. Table IV.1 presents the ten equipment classes within the scope of 

this rulemaking analysis and provides the kVA range associated with each.

Table IV.1 Distribution Transformer Equipment Classes

EC # Insulation Voltage Phase BIL Rating kVA Range

1

LiquidImmersed Medium Single - 10-833 kVA

2

LiquidImmersed Medium Three - 15-2500 kVA

3 Dry-Type Low Single - 15-333 kVA

4 Dry-Type Low Three - 15-1000 kVA

5 Dry-Type Medium Single 20-45kV BIL 15-833 kVA

6 Dry-Type Medium Three 20-45kV BIL 15-2500 kVA

7 Dry-Type Medium Single 46-95kV BIL 15-833 kVA

8 Dry-Type Medium Three 46-95kV BIL 15-2500 kVA

9 Dry-Type Medium Single ≥ 96kV BIL 75-833 kVA

10 Dry-Type Medium Three ≥ 96kV BIL 225-2500 kVA

ABB commented that the currently defined equipment classes do not cover the 

product scope as defined in 10 CFR Part 431.192, which defines medium-voltage as 

between 601 V and 34.5 kV. Therefore, it recommended changing the equipment classes 

analyzed, or at least revising the definition in the CFR. (ABB, No. 14 at p. 9)

DOE is uncertain of how its current equipment classes are inconsistent with its 

published definition of “medium-voltage dry-type” and requests further comment on the 

issue.

a. Less-Flammable Liquid-Immersed Transformers

In the August 2006 standards NOPR, DOE solicited comments about how it 

should treat distribution transformers filled with an insulating fluid of higher flash point 
78

than that of traditional mineral oil. 71 FR 44369 (August 4, 2006). Known as “lessflammable, liquid-immersed” (LFLI) transformers, these units are marketed to some 

applications where a fire would be especially costly and traditionally served by the drytype market, such as indoor applications.

During preliminary interviews with manufacturers, DOE was informed that LFLI 

transformers might offer the same utility as dry-type transformers since they were 

unlikely to catch fire. Manufacturers also stated that LFLI transformers could have a 

minor efficiency disadvantage relative to traditional liquid-immersed transformers 

because their more viscous insulating fluid requires more internal ducting to properly 

circulate.

In the October 2007 final rule, DOE determined that LFLI transformers should be 

considered in the same equipment class as traditional liquid-immersed transformers. DOE 

concluded that the design of a transformer (i.e., dry-type or liquid-immersed) was a 

performance-related feature that affects the energy efficiency of the equipment and, 

therefore, dry-type and liquid-immersed should be analyzed separately. Furthermore, 

DOE found that LFLI transformers could meet the same efficiency levels as traditional 

liquid-immersed units. As a result, DOE did not separately analyze LFLI transformers, 

but relied on the analysis for the mineral oil liquid-immersed transformers. 72 FR 58202 

(October 12, 2007).
79

For the preliminary analysis, DOE revisited the issue in light of additional 

research on LFLI transformers and conversations with manufacturers and industry 

experts. DOE first considered whether LFLI transformers offered the same utility as drytype equipment, and came to the same conclusion as in the last rulemaking. While LFLI 

transformers can be used in some applications that historically use dry-type units, there 

are applications that cannot tolerate a leak or fire. In these applications, customers assign 

higher utility to a dry-type transformer. Since LFLI transformers can achieve higher 

efficiencies than comparable dry-type units, combining LFLIs and dry-types into one 

equipment class may result in standard levels that dry-type units are unable to meet. 

Therefore, DOE decided not to analyze LFLI transformers in the same equipment classes 

as dry-type distribution transformers.

Similarly, DOE revisited the issue of whether or not LFLI transformers should be 

analyzed separately from traditional liquid-immersed units. DOE concluded, once again, 

that LFLI transformers could achieve any efficiency level that mineral oil units could 

achieve. Although their insulating fluids are slightly more viscous, this disadvantage has 

little efficiency impact, and diminishes as efficiency increases and heat dissipation 

requirements decline. Furthermore, at least one manufacturer suggested that LFLI 

transformers might be capable of higher efficiencies than mineral oil units because their 

higher temperature tolerance may allow the unit to be downsized and run hotter than 

mineral oil units. Additionally, HVOLT agreed with DOE that high temperature liquidfilled transformer insulation systems have a similar space factor to mineral oil systems 

and should thus have similar losses. (HVOLT, No. 33 at p. 2) For these reasons, DOE 
80

believes that LFLI transformers would not be disproportionately affected by standards set 

in the liquid-immersed equipment classes. Therefore, DOE did not consider LFLI in a 

separate equipment class for the NOPR analysis.

b. Pole- and Pad-mounted Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether pole-mounted, 

pad-mounted, and possibly other types of liquid-immersed transformers should be 

considered in separate equipment classes. (ABB, Pub. Mtg. Tr., No. 89 at p. 230) DOE 

acknowledges that as standards rise, transformer types which previously had similar 

incremental costs may start to diverge and requests comment on whether and why 

separate equipment classes are warranted for pole-mounted, pad-mounted, and other 

types of liquid-immersed distribution transformers.

c. BIL Ratings in Liquid-Immersed Distribution Transformers

During negotiations, several parties raised the question of whether liquidimmersed distribution transformers should have standards set according to BIL rating, as 

do medium-voltage, dry-type distribution transformers. (ABB, Pub. Mtg. Tr., No. 89 at p. 

218) DOE acknowledges that as standards rise, BIL ratings which previously had similar 

incremental costs may start to diverge and requests comment on whether and why 

separate equipment classes are warranted for liquid-immersed transformers of different 

BIL ratings. DOE requests particular comment on how many BIL bins are appropriate to 

cover the range and where the specific boundaries of those bins should lie.
81

3. Technology Options

The technology assessment provides information about existing technology 

options to construct more energy-efficient distribution transformers. There are two main 

types of losses in transformers: no-load (core) losses and load (winding) losses. Measures 

taken to reduce one type of loss typically increase the other type of losses. Some 

examples of technology options to improve efficiency include: (1) higher-grade electrical 

core steels, (2) different conductor types and materials, and (3) adjustments to core and 

coil configurations.

In consultation with interested parties, DOE identified several technology options 

and designs for consideration. These technology options are presented in Table IV.2. 

Further detail on these technology options can be found in chapter 3 of the preliminary 

TSD.
82

Table IV.2 Options and Impacts of Increasing Transformer Efficiency

No-load 

losses

Load

losses

Cost 

impact

To decrease no-load losses

Use lower-loss core materials Lower No 

change* Higher

Decrease flux density by:

Increasing core cross-sectional area (CSA)

Decreasing volts per turn

Lower

Lower

Higher

Higher

Higher

Higher

Decrease flux path length by decreasing conductor 

CSA Lower Higher Lower

Use 120 ̊ symmetry in three-phase cores** Lower No change TBD

To decrease load losses

Use lower-loss conductor material No change Lower Higher

Decrease current density by increasing conductor 

CSA Higher Lower Higher

Decrease current path length by:

Decreasing core CSA

Increasing volts per turn

Higher

Higher

Lower

Lower

Lower

Lower

* Amorphous core materials would result in higher load losses because flux density drops, requiring a 

larger core volume.

** Sometimes referred to as a “hexa-transformer” design.

HYDRO-Quebec (IREQ) notified DOE that a new iron-based amorphous alloy 

ribbon for distribution transformers was developed that has enhanced magnetic properties 

while remaining ductile after annealing. Further, IREQ noted that a distribution 

transformer assembly using this technology has been developed. (IREQ, No. 10 at pp. 1-

2)

DOE was not able to analyze the described material in the NOPR phase of the 

rulemaking, but intends to explore it further in the final rule. Two of the challenges 

facing amorphous steel include availability of the raw material and core manufacturing 

capacity. DOE seeks comment and analysis about amorphous steels that offer greater raw 

material availability and greater capacity to manufacture amorphous core steel.
83

a. Core Deactivation

As noted previously, core deactivation technology employs the concept that a 

system of smaller transformers can replace a single, larger transformer. For example, 

three 25 kVA transformers operating in parallel could replace a single 75 kVA 

transformer. 

DOE understands that winding losses are proportionally smaller at lower load 

factors, but for any given current, a smaller transformer will experience greater winding 

losses than a larger transformer. As a result, those losses may be more than offset by the 

smaller transformer’s reduced core losses. As loading increases, winding losses become 

proportionally larger and eventually outweigh the power saved by using the smaller core. 

At that point, the control unit (which consumes little power itself) switches on an 

additional transformer, which reduces winding losses at the cost of additional core losses. 

The control unit knows how efficient each combination of transformers is for any given 

loading, and is constantly monitoring the unit’s power output so that it will use the 

optimal number of cores. In theory, there is no limit to the number of transformers that 

may operate in parallel in this sort of system, but cost considerations would imply an 

optimal number.

DOE spoke with a company that is developing a core deactivation technology. 

Noting that many dry-type transformers are operated at very low loadings a large 

percentage of the time (e.g., a building at night), the company seeks to reduce core losses 

by replacing a single, traditional transformer with two or more smaller units that could be 
84

activated and deactivated in response to load demands. In response to load demand 

changes, a special unit controls the transformers and activates and/or deactivates them in 

real-time.

Although core deactivation technology has some potential to save energy over a 

real-world loading cycle, those savings might not be represented in the current DOE test 

procedure. Presently, the test procedure specifies a single loading point of 50 percent for 

liquid-immersed and MVDT transformers, and 35 percent for LVDT. The real gain in 

efficiency for core deactivation technology comes at loading points below the root mean 

square (RMS) loading specified in the test procedure, where some transformers in the 

system could be deactivated. At loadings where all transformers are activated, which may 

be the case at the test procedure loading, the combined core and coil losses of the system 

of transformers could exceed those of a single, larger transformer. This would result in a 

lower efficiency for the system of transformers compared to the single, larger 

transformer.

In response to the preliminary analysis, NEMA commented that core deactivation 

technology is unrelated to the design of a transformer, but rather is related to the system 

of which it is a part. Therefore, NEMA commented, it is outside the scope of this 

rulemaking, because all transformers must comply with DOE regulations. (NEMA, No. 

13 at p. 3) ABB agreed that core deactivation technology is not related to the design of a 

transformer, but rather related to the design of the system in which the transformer is 

deployed. ABB noted that core deactivation technology input voltage source is 
85

disconnected from the transformer terminals, similar to a switchgear component and, as 

such, is not an integral element of the distribution transformer any more than a disconnect 

switch or circuit breaker. ABB commented that DOE does not consider other systems for 

energy efficiency, but if it is to look at core deactivation technology, perhaps it should 

also consider technologies that maintain the load power factor closer to unity. (ABB, No. 

14 at pp. 3, 6) 

Howard Industries (HI) commented that core deactivation technology does not 

currently exist for liquid-immersed transformers, and has not been evaluated for 

feasibility. In its opinion, core deactivation technology could cause several issues, such as 

flicker problems and in-rush current/surge protection. Additionally, HI believed that there 

are patent issues for this technology. For these reasons, HI recommended that DOE not 

consider core deactivation technology for liquid-immersed transformers. (HI, No. 23 at 

pp. 4, 11) Edison Electric Institute (EEI) agreed that core deactivation should not be 

considered for liquid-immersed transformers, which face significant load diversity 

because multiple buildings and/or homes can be served by a single transformer. EEI 

commented that, due to this load diversity, it is highly unlikely that core deactivation 

would provide energy savings for liquid-immersed transformers. (EEI, No. 29 at pp. 4-5)

HVOLT commented that core deactivation is not feasible. Based on HVOLT 

calculations, core deactivation only achieves fewer losses than a single, full-sized unit 

when loaded below 15 percent. Core deactivation also requires considerations for 

impedance, regulation, switching devices, and transformer reliability, making the 
86

technology unattractive for efficiency regulations. (HVOLT, No. 33 at pp. 2-3) 

Furthermore, HVOLT performed loading analyses of core deactivation technology and 

found that the only loading point where it beats traditional transformers was at zero 

percent. (HVOLT, Pub. Mtg. Tr., No. 34 at p. 60) However, Warner Power indicated that 

HVOLT’s analysis was based on assumed numbers rather than actual designs and stated 

that core deactivation technology is more efficient that HVOLT’s analysis indicated. 

(WP, Pub. Mtg. Tr., No. 34 at p. 62) Warner Power also commented that the 0.75 scaling 

factor did not accurately capture the efficiency of the smaller component transformers in 

a core deactivation system and asserted that it would prefer to see a linear scaling factor 

(WP, No. 30 at pp. 6-7, 11). Furthermore, Warner Power pointed out that core 

deactivation technology is better suited for many small loads than for large, discrete 

loads. The multiple, smaller loads create a smooth load profile throughout the day 

without sudden large demands. (WP, No. 30 at p. 7) Warner Power also commented that, 

for core deactivation technology, it is important to note that the secondary and tertiary 

component transformers do not typically power on at 33 percent and 66 percent load. 

Rather, the switching point is where the system operates with the lowest total losses and 

is specific to the transformer design. (WP, No. 30 at p. 7) Finally, Warner Power stated 

that core deactivation technology allows a transformer to achieve higher efficiency at low 

loading values. WP hypothesized that average power consumption will go down in 

buildings and transformer core losses will start to become more significant, thus making 

core deactivation technology more desirable. (WP, Pub. Mtg. Tr., No. 34 at p. 42)
87

NRECA and the NRECA Transmission & Distribution Engineering Committee 

(T&DEC) commented that core deactivation technology would be extremely difficult to 

successfully implement from an economical viewpoint. (NRECA/T&DEC, No. 31 and 36 

at p. 2) Southern Company (SC) agreed and noted that core deactivation technology does 

not seem practical or cost-effective because it would use more materials than a single 

transformer, which would increase the weight and cost of the unit. SC further noted that 

the increased weight could be problematic for pole-mounted transformers. (SC, No. 22 at 

p. 3)

FPT commented that DOE should not consider core deactivation in the efficiency 

standard rulemaking at this time because it is only advantageous in certain situations with 

low loading requirements, and thus only represents a small portion of the market. (FPT, 

No. 27 at p. 3) Rather, FPT suggested that DOE encourage users to de-energize the 

LVDT from the primary switch/breaker. FPT also noted that the technology would face 

challenges with medium-voltage transformers, such as pre-strikes, re-strikes, 

ferroresonance, and reducing the life of the primary circuit sectionalizing device. (FPT, 

No. 27 at p. 3)

Berman Economics was interested to know if DOE would also be looking at the 

potential differences in stress and wear on the transformer as one is activating and 

deactivating the core deactivation transformer. (BE, Pub. Mtg. Tr, No. 34 at p. 62)
88

DOE appreciates all of the comments from interested parties regarding core 

deactivation technology. DOE understands that core deactivation technology is most 

easily implemented in LVDT distribution transformer designs. Implementing core 

deactivation technology in medium-voltage distribution transformers is possible, but 

poses difficulties for switching the primary and secondary connections. For the NOPR, 

DOE has not fully quantified these difficulties because it did not directly analyze core 

deactivation technology, although DOE believes it may be possible to evaluate the 

technology using its existing transformer designs. DOE also acknowledges that operating 

a core deactivation bank of transformers instead of a single unit may save energy and 

lower LCC for certain consumers. At present, however, DOE is adopting the position that 

each of the constituent transformers must comply with the energy conservation standards 

under the scope of the rulemaking.

b. Symmetric Core

DOE understands that several companies worldwide are commercially producing 

three-phase transformers with symmetric cores – those in which each leg of the 

transformer is identically connected to the other two. The symmetric core uses a 

continuously wound core with 120-degree radial symmetry, resulting in a triangularly 

shaped core when viewed from above. In a traditional core, the center leg is magnetically 

distinguishable from the other two because it has a shorter average flux path to each. In a 

symmetric core, however, no leg is magnetically distinguishable from the other two.
89

One manufacturer of symmetric core transformers cited several advantages to the 

symmetric core design. These include reduced weight, volume, no-load losses, noise, 

vibration, stray magnetic fields, inrush current, and power in the third harmonic. Thus far, 

DOE has seen limited cost and efficiency data for only a few symmetric core units from 

testing done by manufacturers. DOE has not seen any designs for symmetric core units 

modeled in a software program.

DOE understands that, because of zero-sequence fluxes associated with wye-wye 

connected transformers, symmetric core designs are best suited to delta-delta or deltawye connections. While traditional cores can circumvent the problem of zero-sequence 

fluxes by introducing a fourth or fifth unwound leg, core symmetry makes extra legs 

inherently impractical. Another way to mitigate zero-sequence fluxes comes in the form 

of a tertiary winding, which is delta-connected and has no external connections. This

winding is dormant when the transformer’s load is balanced across its phases. Although 

symmetric core designs may, in theory, be made tolerant of zero-sequence fluxes by 

employing this method, this would come at extra cost and complexity. 

Using this tertiary winding, DOE believes that symmetric core designs can service 

nearly all distribution transformer applications in the United States. Most dry-type 

transformers have a delta connection and would not require a tertiary winding. Similarly, 

most liquid-immersed transformers serving the industrial sector have a delta connection. 

These market segments could use the symmetric core design without any modification for 

a tertiary winding. However, in the United States most utility-operated distribution 
90

transformers are wye-wye connected. These transformers would require the tertiary 

winding in a symmetric core design.

DOE understands that symmetric core designs are more challenging to 

manufacture and require specialized equipment that is currently uncommon in the 

industry. However, DOE did not find a reasonable basis to screen this technology option 

out of the analysis, and is aware of at least one manufacturer producing dry-type 

symmetric core designs commercially in the United States.

For the preliminary analysis, DOE lacked the data necessary to perform a 

thorough engineering analysis of symmetric core designs. To generate a cost-efficiency 

relationship for symmetric core design transformers, DOE made several assumptions. 

DOE adjusted its traditional core design models to simulate the cost and efficiency of a 

comparable symmetric core design. To do this, DOE reduced core losses and core weight 

while increasing labor costs to approximate the symmetric core designs. These 

adjustments were based on data received from manufacturers, published literature, and 

through conversations with manufacturers. Table IV.3 indicates the range of potential 

adjustments for each variable that DOE considered and the mean value used in the 

analysis.

Table IV.3 Symmetric Core Design Adjustments

Range Core Losses 

(W) Core Weight (lbs) Labor Hours

[Percentage Changes]

Minimum -0.0 -12.0 +10.0

Mean -15.5 -17.5 +55.0

Maximum -25.0 -25.0 +100.0
91

DOE applied the adjustments to each of the traditional three-phase transformer 

designs to develop a cost-efficiency relationship for symmetric core technology. DOE did 

not model a tertiary winding for the wye-wye connected liquid-immersed design lines 

(DLs). Based on its research, DOE believes that the losses associated with the tertiary 

winding may offset the benefits of the symmetric core design and that the tertiary 

winding will add cost to the design. Therefore, DOE modeled symmetric core designs for 

the three-phase, liquid-immersed design lines without a tertiary winding to examine the 

impact of symmetric core technology on the subgroup of applications that do not require 

the tertiary winding.

NPCC and NEEA jointly commented that DOE should revise its assumptions 

about costs and limitations of symmetric core designs in accordance with information 

provided by manufacturers of these technologies. (NPCC/NEEA, No. 11 at p. 2) 

Furthermore, NPCC and NEEA noted that DOE should revise its analysis for symmetric 

core designs to account for labor costs that mirror those of conventional core designs. 

NPCC and NEEA recommended that DOE request additional data from manufacturers 

that are producing this technology. (NPCC/NEEA, No. 11 at pp. 4, 6)

Hex Tec (HEX) commented that DOE should consider a symmetric core design 

using amorphous core steel in its evaluation. (HEX, No. 35 at p. 1) It noted that there are 

several variations of the symmetric core design being made around the world and that 

licenses are available. Furthermore, it commented that amorphous metal suppliers are 
92

emerging in India and China, concluding that there are no barriers to adopting symmetric 

core technology with an amorphous core. (HEX, No. 35 at p. 1) Hex Tec pointed out that 

amorphous units up to 3 MVA in size have been produced using Evans distributed gap 

core construction, but are labor intensive and difficult to produce, and concluded that 

amorphous designs are easier to make using a symmetric core. (HEX, No. 35 at p. 1) 

Finally, Hex Tec submitted a letter written by the Vice President of Research & 

Development at Metglas that indicates that symmetric core units using amorphous steel 

of 15 to 100 kVA demonstrated core losses of 0.13 Watts/lb at an induction of 1.2 T. The 

letter also noted that audible sound levels were low. (HEX, No. 35 at p. 14) 

Hammond (HPS) commented that its analytical and prototype work indicated that 

symmetric core designs do not experience a core loss advantage but do have higher 

manufacturing costs. (HPS, No. 3 at p. 2) However, Hex Tec commented that it builds 

symmetric cores with labor costs and material savings that are comparable to those 

incurred by conventional construction. (HEX, Pub. Mtg. Tr., No. 34 at p. 25) Hex Tec 

noted that the equipment to produce symmetric wound cores is significantly less 

expensive than flat stack steel equipment and that the labor production times are lower. 

(HEX, Pub. Mtg. Tr., No. 34 at p. 52) Hex Tec added that labor requirements, both TAC 

time and process times, are lower for symmetric core designs than for conventional 

designs. (HEX, No. 35 at p. 2)

Hex Tec submitted data showing that the weight of three-phase, 75 kVA LVDT 

symmetric core designs ranged from 390 to 600 pounds between 98.6 and 99.2 percent 
93

efficiency. These weights are lower than the weights of comparably efficient designs 

using conventional cores. (HEX, No. 35 at p. 7) Hex Tec also submitted data comparing 

the efficiency, dimensions, core and coil material content, and cost of several 

conventional designs for three-phase, 75 kVA LVDT units to those of otherwise identical 

symmetric core designs. (HEX, No. 35 at p. 8) Hex Tec noted it took the same amount of 

labor time as a major conventional-design manufacturer to produce a three-phase 75 kVA 

LVDT rated at CSL325, and that it was able to do so with lower material costs. (HEX, 

Pub. Mtg. Tr., No. 34 at p. 110) Hex Tec also submitted data showing comparisons 

between the weight, losses, and costs of conventional core designs and symmetric core 

designs at 1000 kVA and 2000 kVA for MVDTs. (HEX, No. 35 at pp. 9-10)

Warner Power pointed out that recent improvements in the manufacturing process 

for symmetric core designs, leveraged by increasing volumes, will bring labor costs down 

to approximately 10 percent below labor costs for conventional cores. (WP, No. 30 at p. 

3) Warner Power commented that symmetric cores use a wound core with no scrap and 

approximately 15 percent lower weight than that of conventional cores. (WP, No. 30 at p. 

3) Warner felt that DOE’s symmetric core analysis contained some significant errors that

would generate the wrong output, and that the manufacturing cost estimates for 

symmetric cores were overstated. (WP, No. 30 at p. 9; WP Pub. Mtg. Tr., No. 34 at p. 

111) 

 

25 “Candidate Standard Levels” (CSLs) are analogous to the Efficiency Levels (ELs) DOE utilizes together 

in the NOPR to create Trial Standard Levels (TSLs). This particular commenter refers to CSL3 from the 

2007 rulemaking, not the present one.
94

Power Partners commented that DOE should not set a standard based on 

symmetric core designs because they are not common in the industry and could place an 

unreasonable burden on smaller manufacturers who would be unable to invest in the 

equipment necessary for the technology. (PP, No. 19 at p. 2) NEMA agreed, commenting 

that symmetric core is in its infancy and has low penetration in the industry and should 

not be introduced into the regulation until it has been proven in the marketplace. (NEMA, 

No. 13 at p. 3) FPT commented that symmetric core technology should not be used as the 

basis for increasing efficiency levels and noted that, while the technology may be 

advantageous in some areas, it may present problems with larger transformers. (FPT, No. 

27 at pp. 3-4, 13) Warner Power disagreed and stated that symmetric core designs and 

core deactivation technology should be included in the scope of DOE’s analysis, 

recommending several symmetric core and core deactivation design option combinations. 

(WP, No. 30 at p. 9)

NEEA reiterated that symmetric core manufacturers have stated that there should 

not be any patent concerns for the technology, since it is not yet patented. (NEEA, No. 11 

at p. 4; NEEA, Pub. Mtg. Tr., No. 34 at p. 261) Howard Industries disagreed and 

commented that DOE should not consider symmetric core technology because it is 

patented by Hexaformer AB of Sweden, which would result in increased licensing costs. 

(HI, No. 23 at pp. 3-4, 6-7, 11) Furthermore, HI noted that no manufacturers in North 

America currently produce the design for liquid-immersed units. (HI, No. 23 at pp. 3-4, 

6-7, 11) HI also pointed out that Hexaformer AB does not produce units higher than 200 

kVA and 24 kV, whereas most utilities require larger kVA sizes and 35 kV. (HI, No. 23 
95

at pp. 3-4, 6-7, 11) Finally, Howard commented that all efficiency improvements for 

symmetric core liquid-immersed designs are theoretical at this point. (HI, No. 23 at pp. 3-

4, 6-7, 11)

Southern Company commented that symmetric core technology is not feasible for 

utility applications because they require wye-wye connections, while symmetric cores 

have a delta connection. SC noted that, while a tertiary winding may enable the 

symmetric core design to be connected in the system, SC has had trouble in the past with 

tertiary windings and has discontinued purchasing transformers that use them. (SC, No. 

22 at p. 2) Howard Industries and HVOLT also noted that most utility transformers are 

wye-wye connected and would need a delta tertiary winding to use symmetric core 

technology, which would drive down efficiency while increasing costs. (HI, No. 23 at pp. 

3-4, 6-7, 11; HVOLT, Pub. Mtg. Tr., No. 34 at p. 50; HVOLT, Pub. Mtg. Tr., No. 34 at p. 

50)

DOE attempts to consider all designs that are technologically feasible and 

practicable to manufacture and believes that symmetric core designs can meet these 

criteria. However, DOE has not been able to obtain or produce sufficient data to modify 

its analysis of symmetric cores since the preliminary analysis. Therefore, although not 

screened out, DOE has not considered symmetric core designs for its NOPR analyses. 

DOE welcomes comment and submission of engineering data that would be useful in 

analyzing symmetric core designs in the final rule.
96

c. Intellectual Property

In setting standards, DOE seeks to analyze the efficiency potentials of 

commercially available technologies and working prototypes as well as the availability of 

those technologies to the market at-large. If certain market participants own intellectual 

property that enable them to reach efficiencies that other participants practically cannot, 

amended standards may reduce the competitiveness of the market.

In the case of distribution transformers, stakeholders have raised potential 

intellectual property concerns surrounding both symmetric core technology and 

amorphous metals in particular. DOE currently understands that symmetric core 

technology itself is not proprietary, but that one of the more commonly employed 

methods of production is the property of the Swedish company Hexaformer AB. 

However, Hexaformer AB’s method is not the only one capable of producing symmetric 

cores. Moreover, Hexaformer AB and other companies owning intellectual property 

related to the manufacture of symmetric core designs have demonstrated an eagerness to 

license such technology to others that are using it to build symmetric core transformers 

commercially today.

Warner Power commented that the well-known symmetric core design 

(Hexaformers) is subject to worldwide patents for the core winding and assembly 

process, but multiple licenses have been authorized and the IP owner has indicated it will 

entertain additional licenses. The basic design concept is not patented, and several other 
97

manufacturers make symmetric cores, so patents should not be a limiting factor. (WP, 

No. 30 at pp. 3-4)

EEI noted that, if certain higher-efficiency designs are covered by patents, then 

the number of manufacturers may decrease, which would increase transformer prices. It 

recommended that DOE discuss any relevant patents and indicate whether they will be in 

place after 2016. (EEI, No. 29 at p. 10)

DOE understands that symmetric core technology may ultimately offer a lowercost path to higher efficiency, at least in certain applications, and that few symmetric 

cores are produced in the United States. However, DOE notes again that it has been 

unable to secure data that are sufficiently robust for use as the basis for an energy 

conservation standard, but encourages interested parties to submit data that would assist 

in DOE’s analysis of symmetric core technology.

B. Screening Analysis

DOE uses the following four screening criteria to determine which design options 

are suitable for further consideration in a standards rulemaking: 

1. Technological feasibility. Technologies incorporated in commercial products or 

in working prototypes will be considered to be technologically feasible.
98

2. Practicability to manufacture, install, and service. If mass production of a 

technology in commercial products and reliable installation and servicing of the 

technology could be achieved on the scale necessary to serve the relevant market 

at the time of the effective date of the standards, then that technology will be 

considered practicable to manufacture, install, and service.

3. Impacts on product utility to consumers. If a technology is determined to have 

significant adverse impact on the utility of the product to significant subgroups of 

consumers, or result in the unavailability of any covered product type with 

performance characteristics (including reliability), features, sizes, capacities, and 

volumes that are substantially the same as products generally available in the 

United States at the time, it will not be considered further.

4. Safety of technologies. If it is determined that a technology will have 

significant adverse impacts on health or safety, it will not be considered further. 

(10 CFR part 430, subpart C, appendix A)

In the preliminary analysis, DOE identified the technologies for improving 

distribution transformer efficiency that were under consideration. DOE developed this 

initial list of design options from the technologies identified in the technology 

assessment. Then DOE reviewed the list to determine if the design options are practicable 

to manufacture, install, and service; would adversely affect equipment utility or 

equipment availability; or would have adverse impacts on health and safety. In the 
99

engineering analysis, DOE only considered those design options that satisfied the four 

screening criteria. The design options that DOE did not consider because they were 

screened out are summarized in Table IV.4.

Table IV.4 Design Options Screened Out of the Analysis

Design Option Excluded Eliminating Screening Criteria

Silver as a Conductor Material Practicability to manufacture, install, and service

High-Temperature Superconductors Technological feasibility;

Practicability to manufacture, install, and service

Amorphous Core Material in Stacked 

Core Configuration

Technological feasibility;

Practicability to manufacture, install, and service

Carbon Composite Materials for Heat 

Removal Technological feasibility

High-Temperature Insulating Material Technological feasibility

Solid-State (Power Electronics) 

Technology

Technological feasibility;

Practicability to manufacture, install, and service

Nanotechnology Composites Technological feasibility

Chapter 4 of the TSD discusses each of these screened-out design options in more 

detail. The chapter also includes a list of emerging technologies that could impact future 

distribution transformer manufacturing costs.

Multiple interested parties commented that they agreed with the technology 

options screened out of the analysis by DOE. (EEI, No. 29 at p. 5; HI, No. 23 at p. 5; 

NPCC/NEEA, No. 11 at p. 3) Metglas concurred that using amorphous metals in a stack 

core configuration is technically infeasible. (Metglas, Pub. Mtg. Tr., No. 34 at p. 66) 

Howard Industries also recommended that DOE screen out symmetric core designs and 

core deactivation technology from their analysis based on proprietary concerns. (HI, No.

23 at p. 5)
100

DOE appreciates the feedback and remains interested in advances that would 

allow a currently screened technology to be considered as a design option. As for 

symmetric core designs, DOE has not screened this technology out because it is aware 

that manufacturers around the world are building and selling such transformers. 

However, without additional information regarding the technology, DOE has been unable 

to fully evaluate this as a design option. 

1. Nanotechnology Composites

DOE understands that the nanotechnology field is actively researching ways to 

produce bulk material with desirable features on a molecular scale. Some of these 

materials may have high resistivity, high permeability, or other properties that make them 

attractive for use in electrical transformers. DOE knows of no current commercial efforts 

to employ these materials in distribution transformers and no prototype designs using this 

technology, but welcomes comment on such technology and its implications for the 

future of the industry.

NEMA and ABB Transformers both commented that, because nanotechnology 

composite technology is not commercially available in the U.S., manufacturers cannot 

discuss it publicly. (NEMA, No. 13 at p. 4; ABB, No. 14 at p. 7) Howard Industries, Inc. 

was unaware of any nanotechnology composite technology for distribution transformers. 

(HI, No. 23 at p. 4)
101

DOE appreciates confirmatory feedback, and does not propose to consider 

nanotechnology composites in the current rulemaking.

C. Engineering Analysis

The engineering analysis develops cost-efficiency relationships for the equipment 

that are the subject of a rulemaking by estimating manufacturer costs of achieving 

increased efficiency levels. DOE uses manufacturing costs to determine retail prices for 

use in the LCC analysis and MIA. In general, the engineering analysis estimates the 

efficiency improvement potential of individual design options or combinations of design 

options that pass the four criteria in the screening analysis. The engineering analysis also

determines the maximum technologically feasible energy efficiency level.

DOE must consider those distribution transformers that are designed to achieve 

the maximum improvement in energy efficiency that the Secretary of Energy determines 

to be technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) 

Therefore, an important role of the engineering analysis is to identify the maximum 

technologically feasible efficiency level. The maximum technologically feasible level is 

one that can be reached by adding efficiency improvements and/or design options, both 

commercially feasible and in prototypes, to the baseline units. DOE believes that the 

design options comprising the maximum technologically feasible level must have been 

physically demonstrated in a prototype form to be considered technologically feasible. 
102

In general, DOE can use three methodologies to generate the manufacturing costs 

needed for the engineering analysis. These methods are: 

1) the design-option approach – reporting the incremental costs of adding design 

options to a baseline model;

2) the efficiency-level approach – reporting relative costs of achieving 

improvements in energy efficiency; and

3) the reverse engineering or cost assessment approach – involving a "bottom 

up" manufacturing cost assessment based on a detailed bill of materials 

derived from transformer teardowns.

DOE’s analysis for the distribution transformers rulemaking is based on the 

design-option approach, in which design software is used to assess the cost-efficiency 

relationship between various design option combinations. This is the same approach that 

was taken in the previous rulemaking for distribution transformers.

1. Engineering Analysis Methodology

When developing its engineering analysis for distribution transformers, DOE 

divided the covered equipment into equipment classes. As discussed, distribution 

transformers are classified by insulation type (liquid-immersed or dry-type), number of 

phases (single or three), primary voltage (low-voltage or medium-voltage for dry-types) 

and basic impulse insulation level (BIL) rating (for dry-types). Using these transformer 

design characteristics, DOE developed ten equipment classes. Within each of these 
103

equipment classes, DOE further classified distribution transformers by their kilovoltampere (kVA) rating. These kVA ratings are essentially size categories, indicating the 

power handling capacity of the transformers. For DOE’s rulemaking there are over 100 

kVA ratings across all ten equipment classes.

DOE recognized that it would be impractical to conduct a detailed engineering 

analysis on all kVA ratings, so it sought to develop an approach that simplified the 

analysis while retaining reasonable levels of accuracy. DOE consulted with industry 

representatives and transformer design engineers to develop an understanding of the 

construction principles for distribution transformers. It found that many of the units share 

similar designs and construction methods. Thus, DOE simplified the analysis by creating 

engineering design lines (DLs), which group kVA ratings based on similar principles of 

design and construction. The DLs subdivide the equipment classes, to improve the 

accuracy of the engineering analysis. These DLs differentiate the transformers by 

insulation type (liquid-immersed or dry-type), number of phases (single or three), and 

primary insulation levels for medium-voltage, dry-type (three different BIL levels). 

After developing its DLs, DOE then selected one representative unit from each 

DL for study in the engineering analysis, greatly reducing the number of units for direct 

analysis. For each representative unit, DOE generated hundreds of unique designs by 

contracting with Optimized Program Services, Inc. (OPS), a software company 

specializing in transformer design since 1969. The OPS software used three primary 

inputs that it received from DOE, 1) a design option combination, which included core 
104

steel grade, primary and secondary conductor material, and core configuration; 2) a loss 

valuation combination; and 3) material prices. For each representative unit, DOE 

examined anywhere from 8 to 16 design option combinations and for each design option 

combination, the OPS software generated 518 designs based off of unique loss valuation 

combinations. These loss valuation combinations are known in industry as A and B 

evaluation combinations and represent a customer’s present value of future losses in a 

transformer core and winding, respectively. For each design option combination and A 

and B combination, the OPS software generated an optimized transformer design based 

on the material prices that were also part of the inputs. Consequently, DOE obtained 

thousands of transformer designs for each representative unit. The performance of these 

designs ranged in efficiency from a baseline level, equivalent to the current distribution 

transformer energy conservation standards, to a theoretical max-tech efficiency level.

After generating each design, DOE used the outputs of the OPS software to help 

create a manufacturer selling price (MSP). The material cost outputs of the OPS software, 

along with labor estimates were marked up for scrap factors, factory overhead, shipping, 

and non-production costs to generate an MSP for each design. Thus, DOE obtained a cost 

versus efficiency relationship for each representative unit. Finally, after DOE had 

generated the MSPs versus efficiency relationship for each representative unit, it 

extrapolated the results the other, unanalyzed, kVA ratings within that same engineering 

design line.
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2. Representative Units

For the preliminary analysis, DOE analyzed 13 DLs that cover the range of 

equipment classes within the distribution transformer market. Within each DL, DOE 

selected a representative unit to analyze in the engineering analysis. A representative unit 

is meant to be an idealized distribution transformer typical of those used in high volume 

applications. Table IV.5 outlines the design lines and representative units selected for 

each equipment class.

Table IV.5 Engineering Design Lines and Representative Units for Analysis

EC* DL Type of Distribution 

Transformer

kVA 

Range

Representative Unit for this

Engineering Design Line

1

1

Liquid-immersed, singlephase, rectangular tank 10–167

50 kVA, 65 C, single-phase, 60Hz, 14400V 

primary, 240/120V secondary, rectangular 

tank

2

Liquid-immersed, singlephase, round tank 10–167 25 kVA, 65 C, single-phase, 60Hz, 14400V 

primary, 120/240V secondary, round tank

3

Liquid-immersed, singlephase 250–833 500 kVA, 65 C, single-phase, 60Hz, 14400V 

primary, 277V secondary

2

4

Liquid-immersed, threephase 15–500

150 kVA, 65 C, three-phase, 60Hz, 

12470Y/7200V primary, 208Y/120V 

secondary

5

Liquid-immersed, threephase750–

2500

1500 kVA, 65 C, three-phase, 60Hz, 

24940GrdY/14400V primary, 480Y/277V 

secondary

3 6

Dry-type, low-voltage, 

single-phase 15–333 25 kVA, 150 C, single-phase, 60Hz, 480V 

primary, 120/240V secondary, 10kV BIL

4

7

Dry-type, low-voltage, 

three-phase 15–150 75 kVA, 150 C, three-phase, 60Hz, 480V 

primary, 208Y/120V secondary, 10kV BIL

8

Dry-type, low-voltage, 

three-phase

225–

1000

300 kVA, 150 C, three-phase, 60Hz, 480V 

Delta primary, 208Y/120V secondary, 10kV 

BIL

6

9

Dry-type, medium-voltage, 

three-phase, 20-45kV BIL 15–500

300 kVA, 150 C, three-phase, 60Hz, 4160V 

Delta primary, 480Y/277V secondary, 45kV 

BIL

10 Dry-type, medium-voltage, 

three-phase, 20-45kV BIL

750–

2500

1500 kVA, 150 C, three-phase, 60Hz, 4160V 

primary, 480Y/277V secondary, 45kV BIL

8

11 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL 15–500 300 kVA, 150 C, three-phase, 60Hz, 12470V 

primary, 480Y/277V secondary, 95kV BIL

12 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL

750–

2500 1500 kVA, 150 C, three-phase, 60Hz, 
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12470V primary, 480Y/277V secondary, 

95kV BIL

10 13 Dry-type, medium-voltage, 

three-phase, 96-150kV BIL

225–

2500

2000 kVA, 150 C, three-phase, 60Hz, 

12470V primary, 480Y/277V secondary, 

125kV BIL

* EC = Equipment Class.

ABB commented that the definition of design lines for equipment class 4 leaves 

an uncovered kVA range from 150 kVA to 225 kVA, and recommended that DOE extend 

the scope of DL 8 to be 150 - 1000 kVA. (ABB, No. 14 at p. 12) In view of the ABB 

comment, DOE would like to clarify that DL 7 covers kVA ratings up through 150 kVA, 

and that DL 8 covers kVA ratings beginning with 225 kVA. DOE does not specify any 

ratings in between 150 and 225 kVA because it is not aware of any standard ratings 

between these two ratings. Furthermore, 10 CFR 431.196(a) states that low-voltage drytype distribution transformers with kVA ratings not appearing in the table [of designated 

kVA ratings and efficiencies] shall have their minimum efficiency level determined by 

linear interpolation of the kVA and efficiency values immediately above and below that 

kVA rating. Therefore, DOE has not altered the design lines for low-voltage dry-type 

transformers.

Additionally, ABB had several recommendations for DOE regarding 

representative units. First, ABB commented that DOE correctly noted in the 2007 

rulemaking that BIL does not impact efficiency for liquid-immersed transformers as 

significantly as it impacts MVDT units. However, since DOE does not separate out the 

liquid-immersed efficiency levels by BIL and performs its analysis on the 15 kV voltage 

class, it understates the energy savings for units with a higher BIL and makes it more 
107

difficult for these units to meet the efficiency standard. ABB recommended that DOE 

analyze representative units for liquid-immersed design lines in the 200 kV BIL class, 

such as a 34500 V (200 BIL) unit. (ABB, No. 14 at pp. 7-8) For the liquid-immersed 

design lines, ABB recommended that DOE consider a 150 kVA (200 BIL) single-phase 

representative unit and a 30 kVA (200 BIL) three-phase representative unit to better 

represent the range of BILs covered and to provide for more accurate scaling. (ABB, No. 

14 at p. 11) To improve the scaling within the LVDT equipment classes, ABB also 

recommended that DOE consider a 100 kVA (10 BIL) single-phase representative unit 

and a 25 kVA (10 BIL) three-phase unit. (ABB, No.14 at p. 12) For DL13, ABB 

recommended that DOE consider a representative unit in the 200 kV BIL class, such as 

34500 V (200 BIL). For EC 10, ABB recommended that DOE consider a representative 

unit at 200 kV BIL in order to analyze a unit at the upper limit of the BIL rating for the 

equipment class. (ABB, No. 14 at p. 10)

ABB also disagreed with the assumption that single-phase MVDT units have onethird the losses of three-phase MVDT units and commented that DOE should directly 

analyze single-phase MVDT units. It further noted that this assumption was not made for 

liquid-immersed or LVDT units. (ABB, No. 14 at pp. 5, 10) ABB suggested that DOE 

analyze several single-phase MVDT representative units including the following: 50 kVA 

(45 BIL), 300 kVA (45 BIL), 50 kVA (95 BIL), and 300 kVA (95 BIL). ABB also 

recommended that DOE analyze 150 kVA (200 BIL) and 500 kVA (200 BIL) units if 

DOE does not change the definition of EC 9, or 50 kVA (200 BIL) and 300 kVA (200 

BIL) if it does change the definition of EC 9 to align with 10 CFR Part 431.192. (ABB, 
108

No. 14 at p. 10) To provide for better scaling, ABB recommended that DOE consider the 

following representative units for three-phase MVDT: 30 kVA (45 BIL), and 30 kVA (95 

BIL). ABB also recommended that DOE analyze 500 kVA (200 BIL) units if it does not 

change the definition of EC10, or 30 kVA (200 BIL) and 300 kVA (200 BIL) units if it 

does change the definition of EC9 to align with 10 CFR 431.192. (ABB, No. 14 at p. 10)

NEMA commented that it found the representative unit for DL 5, DL 13, and the 

units for the single-phase liquid-immersed design lines all to be satisfactory. (NEMA, 

No. 13 at p. 4) However, NEMA stated that DOE should consider at least one 

representative unit for each of the three equipment classes for single-phase mediumvoltage dry-type transformers. (NEMA, No. 13 at p. 5) NEMA also suggested an 

additional representative unit for each of the three LVDT design lines. (NEMA, No. 13 at 

p. 5) For DL1, NEMA commented that DOE should examine an additional representative 

unit of 167 kVA, 65 degrees Celsius, single-phase, 60 Hz, 14400V primary, 240/120 

secondary, rectangular tank. (NEMA, No. 13 at p. 4) For DL2, NEMA felt that DOE 

should examine an additional representative unit of 100 kVA, 65 degrees Celsius, singlephase, 60 Hz, 14400V primary, 120/240 secondary, round tank. (NEMA, No. 13 at p. 5)

Howard Industries also recommended several representative units for DOE to 

consider. Howard noted that it is not optimum to require the same efficiency for the entire 

range of BIL ratings for liquid-immersed distribution transformers. It suggested that DOE 

examine representative units with higher BIL ratings for the single-phase liquidimmersed design lines, such as 19920 V (150 kV BIL), as well as for dual primary 
109

voltage ratings, such as 7200 X 19920 V primary voltages. (HI, No. 23 at p. 5) Also, 

Howard Industries recommended that DOE consider a representative unit for DL5 with a 

150 kV BIL and a dual voltage primary, such as 12470GRDY/7200 x 

24500GRDY/19920. (HI, No. 23 p. 5) Further, it commented that large three-phase 

liquid-immersed transformers with low-voltage ratings, such as 208Y/120, should be 

examined because these designs are difficult to manufacture even under the present 

efficiency standards. (HI, No. 23 at p. 5) Finally, Howard Industries noted that DOE may 

need to consider additional representative units in order to perform accurate scaling for 

pole type transformers. It recommended that DOE consider kVA ranges of 10-50 kVA, 

75-167 kVA, and 250-833 kVA for accurate scaling of pole-mount units. (HI, No. 23 at 

p. 8)

Power Partners noted that it could not determine the BIL rating for design line 1. 

(PP, Pub. Mtg. Tr., No. 34 at p. 71) Howard Industries and Power Partners both 

supported using 125 BIL 14400 volt designs for design lines 1-3. (PP, Pub. Mtg. Tr., No. 

34 at p. 72; HI, Pub. Mtg. Tr., No. 34 at p. 72) NRECA and T&DEC commented that the 

14.4 kV primary voltage selected for DOE’s analysis of design lines 1 through 3 is 

appropriate in that it represents a large portion of the market. However, they commented 

that DOE should explain how other voltages above and below this level would be 

impacted. (NRECA/T&DEC, No. 31 and 36 at p. 3) In DL 3, PP suggested analyzing the 

smallest and largest transformers in addition to the midpoint. (PP, Pub. Mtg. Tr., No. 34 

at p. 136) Power Partners would support the use of 14400 volt 125 BIL coil voltage as the 

means of analysis for all liquid-filled design lines. (PP, Pub. Mtg. Tr., No. 34 at p. 83) PP 
110

would also support 14400 volts in the design lines for single-phase liquid-immersed 

transformers. (PP, Pub. Mtg. Tr., No. 34 at p. 71) It commented that DOE should increase 

the voltage of its liquid-immersed representative units to 34500GY/19920 (150 BIL) or, 

at a minimum, consider 14400/24940Y (125 BIL). Power Partners noted that it is more 

difficult to meet the efficiency standards at these higher voltages, and suggested detailed 

specifications for revision to the representative units for DL2 and DL3. (PP, No. 19 at pp. 

2-3)

In regards to the representative unit for DL13, FPT commented that dry-type 

transformers with primaries rated for 125 kV BIL are more commonly rated at 24900V 

and 150 kV BIL units typically have 34500 volt primaries. (FPT, No. 27 at p. 14) Hex 

Tec stated that, for DL 13, “MVDT three-phase units, 2000 kVA 12470, 480/277 with a 

95 kV BIL is the workhorse of that market.” (HEX, Pub. Mtg. Tr., No. 34 at p. 81) For 

96-150 kV BIL, FPT believed that 24900 or 24940 volts would be more appropriate for 

the primary voltage of the representative unit in DL13. (FPT, Pub. Mtg. Tr., No. 34 at p. 

81) Hammond commented that the representative unit for DL13 should have a primary of 

24940 V Delta for the 125 kV BIL. (HPS, No. 3 at p. 3)

Schneider Electric (SE) suggested adding another design line for low-voltage 

three-phase units at 15 kVA. SE felt that this would be beneficial to the national impact 

analysis because that design line is readily available in the marketplace. (SE, Pub. Mtg. 

Tr., No. 34 at p. 83) SE also commented that DOE should analyze two representative 

units for each of the three existing LVDT design lines. It recommended that DOE split 
111

the analyzed kVA ranges into two ranges and analyze a representative unit in each. (SE, 

No. 18 at p. 7)

Central Moloney commented that the 25 kVA pole unit is shown as 240/120 but 

that the standard is 120/240. (CM, Pub. Mtg. Tr., No. 34 at p. 72)

Overall, NPCC and NEEA commented that the representative units selected 

should accurately represent products that are being sold in the marketplace, and 

recommended that DOE adjust its analysis based on feedback from manufacturers. 

(NPCC/NEEA, No. 11 at p. 5)

In view of the above comments, DOE slightly modified its representative units for 

the NOPR analysis. For the NOPR, DOE analyzed the same 13 representative units as in 

the preliminary analysis, but also added a design line, and therefore representative unit, 

by splitting the former design line 13 into two new design lines, 13A and 13B. This new 

representative unit is shown in Table IV.6. The representative units selected by DOE 

were chosen because they comprise high volume segments of the market for their 

respective design lines and also provide, in DOE’s view, a reasonable basis for scaling to 

the unanalyzed kVA ratings. DOE chooses certain designs to analyze as representative of 

a particular design line or design lines because it is impractical to analyze all possible 

designs in the scope of coverage for this rulemaking. DOE will consider extending its 

direct analysis further to substantiate the efficiency standard proposed for the final rule 

and will publish sensitivity results to help assess the accuracy of its analysis in the areas 
112

not directly analyzed. DOE also notes that as a part of the negotiations process, DOE has 

worked directly with multiple interested parties to develop a new scaling methodology 

for the NOPR that addresses some of the aforementioned interested party concerns 

regarding scaling.

Table IV.6 Engineering Design Lines (DLs) and Representative Units for Analysis

EC* DL Type of Distribution 

Transformer

kVA 

Range

Representative Unit for this

Engineering Design Line

1

1

Liquid-immersed, single-phase, 

rectangular tank 10–167 50 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

240/120V secondary, rectangular tank, 95kV BIL

2

Liquid-immersed, single-phase, 

round tank 10–167 25 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

120/240V secondary, round tank, 125 kV BIL

3 Liquid-immersed, single-phase 250–833 500 kVA, 65 C, single-phase, 60Hz, 14400V primary, 

277V secondary, 150kV BIL

2

4 Liquid-immersed, three-phase 15–500 150 kVA, 65 C, three-phase, 60Hz, 12470Y/7200V 

primary, 208Y/120V secondary, 95kV BIL

5 Liquid-immersed, three-phase 750–2500

1500 kVA, 65 C, three-phase, 60Hz, 

24940GrdY/14400V primary, 480Y/277V secondary, 

125 kV BIL

3 6

Dry-type, low-voltage, singlephase 15–333 25 kVA, 150 C, single-phase, 60Hz, 480V primary, 

120/240V secondary, 10kV BIL

4

7

Dry-type, low-voltage, threephase 15–150 75 kVA, 150 C, three-phase, 60Hz, 480V primary, 

208Y/120V secondary, 10kV BIL

8

Dry-type, low-voltage, threephase 225–1000 300 kVA, 150 C, three-phase, 60Hz, 480V Delta 

primary, 208Y/120V secondary, 10kV BIL

6

9

Dry-type, medium-voltage, 

three-phase, 20-45kV BIL 15–500 300 kVA, 150 C, three-phase, 60Hz, 4160V Delta 

primary, 480Y/277V secondary, 45kV BIL

10 Dry-type, medium-voltage, 

three-phase, 20-45kV BIL 750–2500 1500 kVA, 150 C, three-phase, 60Hz, 4160V primary, 

480Y/277V secondary, 45kV BIL

8

11 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL 15–500 300 kVA, 150 C, three-phase, 60Hz, 12470V primary, 

480Y/277V secondary, 95kV BIL

12 Dry-type, medium-voltage, 

three-phase, 46-95kV BIL 750–2500 1500 kVA, 150 C, three-phase, 60Hz, 12470V 

primary, 480Y/277V secondary, 95kV BIL

10

13A Dry-type, medium-voltage, 

three-phase, 96-150kV BIL 75–833 300 kVA, 150 C, three-phase, 60Hz, 24940V primary, 

480Y/277V secondary, 125kV BIL

13B Dry-type, medium-voltage, 

three-phase, 96-150kV BIL 225–2500 2000 kVA, 150 C, three-phase, 60Hz, 24940V 

primary, 480Y/277V secondary, 125kV BIL

* EC means equipment class (see Chapter 3 of the TSD). DOE did not select any representative units from 

the single-phase, medium-voltage equipment classes (EC5, EC7 and EC9), but calculated the analytical 

results for EC5, EC7, and EC9 based on the results for their three-phase counterparts.
113

3. Design Option Combinations

There are many different combinations of design options that could be considered 

for each representative unit DOE analyzes. While DOE cannot consider all the possible 

combinations of design options, DOE attempts to select design option combinations that 

are common in the industry while also spanning the range of possible efficiencies for a 

given DL. For each design option combination chosen, DOE evaluates 518 designs based 

on different A and B factor26 combinations. For the engineering analysis, DOE reused 

many of the design option combinations that were analyzed in the previous rulemaking 

for distribution transformers.

For the preliminary analysis, DOE considered a design option combination that 

uses an amorphous steel core for each of the dry-type design lines, whereas DOE’s 

previous rulemaking did not consider amorphous steel designs for the dry-type design 

lines. Instead, DOE had considered H-0 domain refined (H-0 DR) steel as the maximumtechnologically feasible design. However, DOE is aware that amorphous steel designs are 

now used in dry-type distribution transformers. Therefore, DOE considered amorphous 

steel designs for each of the dry-type transformer design lines in the preliminary analysis.

During preliminary interviews with manufacturers, DOE received comment that it 

should consider additional design option combinations using aluminum for the primary 

conductor rather than copper. While manufacturers commented that copper is still used 

for the primary conductor in many distribution transformers, they noted that aluminum 

 

26 A and B factors correspond to loss valuation and are used by DOE to generate distribution transformers 

with a broad range of performance and design characteristics.
114

has become relatively more common. This is due to the relative prices of copper and 

aluminum. In recent years, copper has become even more expensive compared to 

aluminum.

DOE also noted that certain design lines were lacking a design to bridge the 

efficiency values between the lowest efficiency amorphous designs and the next highest 

efficiency designs. In an effort to close that gap for the preliminary analysis, DOE 

evaluated ZDMH and M2 core steel as the highest efficiency designs below amorphous 

for the liquid-immersed design lines. Similarly, DOE evaluated H-0 DR and M3 core 

steel as the highest efficiency designs below amorphous for dry-type design lines.

The joint comments submitted by NPCC and NEEA as well as those submitted by 

ASAP, ACEEE, and NRDC indicated that DOE should include these supplementary 

designs in the reference case analysis for the NOPR. (NPCC/NEEA, No. 11 at pp. 5-6; 

ASAP/ACEEE/ NRDC, No. 28 at p. 3) NPCC and NEEA added that DOE should 

consider all potential design options in its analyses to ensure that all the cost-effective 

means of reaching higher efficiencies have been considered. (NPCC/NEEA, No. 11 at p. 

4) For example, several stakeholders recommended that DOE examine wound core 

designs for its analysis of dry-type distribution transformers. (NPCC/NEEA, No. 11 at 

pp. 2, 4-5; EMS, Pub. Mtg. Tr., No. 34 at p. 86; PG&E, Pub. Mtg. Tr., No. 34 at p. 87; 

ASAP, Pub. Mtg. Tr., No. 34 at p. 88) Joint comments from ASAP, ACEEE, and NRDC 

and PG&E and SCE noted that DOE should consider wound core designs for its lowvoltage dry-type design lines, where high sales volume could better justify the additional 
115

equipment and tooling costs of switching to wound core production. 

(ASAP/ACEEE/NRDC, No. 28 at p. 3; PG&E/SCE, No. 32 at p. 1; PG&E, Pub. Mtg. 

Tr., No. 34 at p. 261) Lastly, HVOLT noted that wound cores in kVA sizes beyond 300 

kVA will tend to buzz, but Hex Tec clarified that the wound cores used in symmetric 

core designs above 300 kVA do not induce any additional audible sound. (HVOLT, Pub. 

Mtg. Tr., No. 34 at p. 51; Hex Tec, Pub. Mtg. Tr., No. 34 at p. 51)

DOE clarifies that although it was not done so in the preliminary analysis, DOE 

has incorporated its supplementary designs into the reference case for the NOPR analysis. 

Additionally, DOE aims to consider the most popular design option combinations, and 

the design option combinations that yield the greatest improvements in efficiency. While 

DOE is unable to consider all potential design option combinations, it does consider 

multiple designs for each representative unit and has considered additional design options 

in its NOPR analysis based on stakeholder comments.

As for wound core designs, DOE did consider analyzing them for all of its drytype representative units that are 300 kVA or less in the NOPR. However, based on 

limited availability in the United States, DOE did not believe that it was feasible to 

include these designs in their final engineering results. For similar availability reasons, 

DOE chose to exclude its wound core ZDMH and M3 designs from its low-voltage drytype analysis. Based on how uncommon these designs are in the current market, DOE 

believes that it would be unrealistic to include them in engineering curves without major 

adjustments. 
116

DOE did not consider wound core designs for DLs 10, 12, and 13B because they 

are 1500 kVA and larger. DOE understands that conventional wound core designs in 

these large kVA ratings will emit an audible “buzzing” noise, and will experience an 

efficiency penalty that grows with kVA rating such that stacked core is more attractive. 

DOE notes, however, that it does consider a wound core amorphous design in each of the 

dry-type design lines.

DOE also received interested party feedback indicating that DOE should consider 

step-lap miter designs for its dry-type design lines. (NPCC/NEEA, No. 11 at p. 4; 

Metglas, Pub. Mtg. Tr., No. 34 at p. 91) In the preliminary analysis, DOE had only 

analyzed fully-mitered designs for the dry-type design lines, but stakeholders noted that 

step-lap miter designs could potentially yield greater efficiencies than the fully-mitered 

designs. However, during the negotiations process, interested parties clarified that steplap mitering may not be cost-effective in the smaller dry-type designs because the smaller 

average steel piece size gives rise to a larger destruction factor, and larger losses, than 

would be predicted by modeling. (ONYX, Pub. Mtg. Tr., No. 30 at p. 43) Stakeholders 

agreed that it would not be appropriate to consider step-lap mitering for design line 6, a 

25 kVA unit, to reflect its scarcity or absence from the market. Therefore, in the NOPR 

DOE analyzed step-lap miter designs for each of the dry-type design lines except design 

line 6.
117

In the preliminary analysis, DOE considered several premium grade core steels. It 

examined H0-DR, ZDMH, and SA1 amorphous core steels in its designs, as well as the

standard M-grade steels. DOE requested comment on whether there were other premium 

grade core steels that should be considered in the analysis. ABB commented that ZDMH, 

H0-DR, and SA1 amorphous steels cover all the high performance core steel grades that 

are currently commercially available. (ABB, No. 14 at p. 13) Therefore, DOE continued 

to analyze them for the NOPR and did not consider any additional premium core steels. 

DOE did opt to add two design option combinations that incorporate M-grade 

steels that have become popular choices at the current standard levels. For all mediumvoltage, dry-type design lines (9-13B), DOE added a design option combination of an M4 

step-lap mitered core with aluminum primary and secondary windings. For design line 8, 

DOE added a design option combination of an M6 fully mitered core with aluminum 

primary and secondary windings. DOE understands both combinations to be prevalent 

baseline options in the present transformer market.

For the NOPR analysis, DOE also made the decision to remove certain high flux 

density designs from DL7 in order to be consistent with designs submitted by 

manufacturers.27 There is a variety of reasons that manufacturers would choose to limit 

flux density (e.g., vibration, noise). Further detail on this change can be found in chapter 

5 of the TSD.

 

27 During the negotiations process, DOE’s subcontractor, Navigant Consulting, Inc. (Navigant), participated 

in a bidirectional exchange of engineering data in an effort to validate the OPS designs generated for the 

engineering analysis.
118

4. A and B Loss Value Inputs

As discussed, one of the primary inputs to the OPS software is an A and B 

combination for customer loss evaluation. In the preliminary analysis, DOE generated 

each transformer design in the engineering analysis based upon an optimized lowest total 

owning cost evaluation for a given combination of A and B values. Again, the A and B 

values represent the present value of future core and coil losses, respectively and DOE 

generated designs for over 500 different A and B value combinations for each of the 

design option combinations considered in the analysis.

In response to the preliminary analysis, Berman Economics commented that 

designing a transformer to total owning cost based on A and B factors will result in a 

higher first cost transformer than a design that aims to minimize first cost for a given 

efficiency level. (BE, No. 16 at p. 6) Additionally, Berman Economics noted that many 

utilities and customers do not specify an A and B value when ordering transformers, and 

will just ask for the lowest first cost design. (BE, Pub. Mtg. Tr., No. 34 at p. 123)

DOE notes that the designs created in the engineering analysis span a range of 

costs and efficiencies for each design option combination considered in the analysis. This 

range of costs and efficiencies is determined by the range of A and B factors used to 

generate the designs. Although DOE does not generate a design for every possible A and 

B combination, because there are infinite variations, DOE believes that its 500-plus 

combinations have created a sufficiently broad design space. By using so many A and B 

factors, DOE is confident that it produces the lowest first cost design for a given 
119

efficiency level and also the lowest total owning cost design. Furthermore, although all 

distribution transformer customers do not purchase based on total owning cost, the A and 

B combination is still a useful tool that allows DOE to generate a large number of designs 

across a broad range of efficiencies and costs for a particular design line. Finally, OPS 

noted at the public meeting that its design software requires A and B values as inputs. 

(OPS, Pub. Mtg. Tr., No. 34 at p. 123) For all of these reasons, DOE continued to use A 

and B factors in the NOPR to generate the range of designs for the engineering analysis.

5. Materials Prices

In distribution transformers, the primary materials costs come from electrical steel 

used for the core and the aluminum or copper conductor used for the primary and 

secondary winding. As these are commodities whose prices frequently fluctuate 

throughout a year and over time, DOE attempted to account for these fluctuations by 

examining prices over multiple years. For the preliminary analysis, DOE conducted the 

engineering analysis analyzing materials price information over a five-year time period 

from 2006-2010, all in constant 2010$. Whereas DOE used a five-year average price in 

the previous rulemaking for distribution transformers, for the preliminary analysis in this 

rulemaking, DOE selected one year from its five-year time frame as its reference case, 

namely 2010. Additionally, DOE considered high and low materials price sensitivities 

from that same five-year time frame, 2008 and 2006 respectively.

DOE decided to use current (2010) materials prices in its analysis for the 

preliminary analysis because of feedback from manufacturers during interviews. 
120

Manufacturers noted the difficulty in choosing a price that accurately projects future 

materials prices due to the recent variability in these prices. Manufacturers also 

commented that the previous five years had seen steep increases in materials prices 

through 2008, after which prices declined as a result of the global economic recession. 

Further detail on these factors can be found in appendix 3A. Due to the variability in 

materials prices over this five-year timeframe, manufacturers did not believe a five-year 

average price would be the best indicator, and recommended using the current materials 

prices.

To estimate its materials prices, DOE spoke with manufacturers, suppliers, and 

industry experts to determine the prices paid for each raw material used in a distribution 

transformer in each of the five years between 2006 and 2010. While prices fluctuate 

during the year and can vary from manufacturer to manufacturer depending on a number 

of variables, such as the purchase quantity, DOE attempted to develop an average 

materials price for the year based on the price a medium to large manufacturer would 

pay.

In general, stakeholders agreed with DOE’s approach for analyzing materials 

prices in the preliminary analysis. Power Partners and EEI agreed with DOE’s approach 

of using 2010 materials prices in the reference case and examining alternate years’ 

materials prices as sensitivities. (PP, Pub. Mtg. Tr., No. 34 at p. 100; EEI, Pub. Mtg. Tr., 

No. 34 at p. 100) Howard Industries noted that 2010 prices are reasonable for the 

reference case as long as DOE uses the 2010 prices with any additional design runs. (HI, 
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No. 23 at p. 6) Similarly, ABB agreed with DOE's approach to use a single reference 

year, such as 2010, for the materials prices, and noted that materials prices are reaching 

an all-time high in 2011. (ABB, No. 14 at p. 14) Finally, Power Partners commented that 

DOE did a reasonable job grouping the various wire sizes into ranges. (PP, Pub. Mtg. Tr., 

No. 34 at p. 118)

Conversely, Southern Company and FPT commented that DOE’s approach for 

generating reference case materials prices could be improved. Southern Company noted 

that 2010 materials prices may be lower than future materials prices once the economy 

improves and there is a limited availability of supplies coupled with increased demand. 

(SC, No. 22 at p. 4) FPT also commented that DOE should consider whether there will be 

an adequate supply of higher grade core steels at the price points identified in the 

analysis, noting that smaller manufacturers are likely not able to purchase materials at the 

same price points as larger manufacturers and may have to pay more, especially if there is 

an increase in demand resulting from amended standards. (FPT, No. 27 at p. 2)

With the onset of the negotiations, DOE was presented with an opportunity to 

implement a 2011 materials price case based on data it had gathered before and during 

the negotiation proceedings. Relative to the 2010 case, the 2011 prices were lower for all 

steels, particularly M2 and lower grade steels.

For the NOPR, DOE continued to use the 2010 materials prices as a reference 

case scenario, but added a second, 2011 price case. DOE presents both cases as recent 
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examples of how the steel market fluctuates and uses both to derive economic results. It 

also considered high and low price scenarios based on the 2008 and 2006 materials 

prices, respectively, but adjusted the prices in each of these years to consider greater 

diversity in materials prices. For the high price scenario, DOE increased the 2008 prices 

by 25 percent, and for the low price scenario, DOE decreased the 2006 prices by 25 

percent as additional sensitivity analyses. DOE believes that these price sensitivities 

accurately account for any pricing discrepancies experienced by smaller or larger 

manufacturers, and adequately consider potential price fluctuations.

NPCC and NEEA jointly commented that DOE should forecast future materials 

prices based on spot commodities future prices. (NPCC/NEEA, No. 11 at pp. 6-7) 

Similarly, FPT commented that 2010 materials prices may not be a good indication of 

future steel prices, which will likely increase. (FPT, No. 27 at p. 12) On the other hand, 

Berman Economics commented that the pricing of core steels over the past few years has 

declined, even though standard levels have shifted the market to higher core steel grades. 

As a result, Berman Economics stated that core steel production could be expected to 

expand in light of new energy conservation standards without any significant impacts on 

the materials prices. (BE, No. 16 at p. 10)

For the engineering analysis, DOE did not attempt to forecast future materials 

prices. DOE continued to use the 2010 materials price in the reference case scenario, 

added a 2011 reference scenario, and also considered high and low sensitivities to 

account for any potential fluctuations in materials prices. The LCC and NIA consider a 
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scenario, however, in which transformer prices increase in the future based on increasing 

materials prices, among other variables. Further detail on this scenario can be found in 

chapter 8 of the TSD.

Several stakeholders commented that the average materials prices DOE calculated 

for the 2006–2010 timeframe, particularly for year 2010, were not accurate. NEMA 

recommended that DOE gather additional information from manufacturers on this topic. 

(NEMA, No. 13 at p. 6) FPT commented that DOE's price of $2.38 per pound for 

amorphous steel appeared to be low, and questioned whether the price had been verified 

with suppliers of amorphous material. Joint comments submitted by ASAP, ACEEE, and 

NRDC stated that DOE's materials prices were too high compared to market prices in 

2010. (ASAP/ACEEE/NRDC, No. 28 at p. 2) HVOLT commented that DOE’s prices for 

copper and aluminum were understated, noting that current copper prices are around 

$6.50. (HVOLT, No. 33 at p. 1; HVOLT, Pub. Mtg. Tr., No. 34 at p. 117) Power Partners 

commented that the prices for aluminum wire were too high and that prices for copper 

wire were too low, suggesting that DOE derive its conductor prices by adding a 

processing cost to the COMEX or London Metal Exchange (LME) indices. (PP, Pub. 

Mtg. Tr., No. 34 at pp. 100, 118; PP, No. 19 at p. 3) To this point, Hex Tec added that the 

fabrication cost varies by wire size. (HEX, Pub. Mtg. Tr., No. 34 at p. 118)

For the NOPR, DOE reviewed its materials prices during interviews with 

manufacturers and industry experts and revised its materials prices for copper and 

aluminum conductors. As suggested by Power Partners, DOE derived these prices by 
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adding a processing cost increment to the underlying index price. DOE determined the 

current 2011 index price from the LME and COMEX. These indices only had current 

2011 values available, so DOE used the producer price index for copper and aluminum to 

convert the 2011 index price into prices for the time period of 2006–2010. DOE then 

applied a unique processing cost adder to the index price for each of its conductor 

groupings. To derive the adder price, DOE compared the difference in the LME index 

price to the 2011 price paid by manufacturers, and applied this difference to the index 

price in each year. DOE inquired with many manufacturers, both large and small, to 

derive these prices. Further detail can be found in chapter 5 of the TSD.

DOE reviewed core steel prices with manufacturers and industry experts and 

found them to be accurate within the range of prices paid by manufacturers in 2010.

However, based on feedback in negotiations, DOE adjusted steel prices for M4 grade 

steels and lower grade steels. 

As for FPT’s concern regarding prefabricated amorphous cores, estimated at 

$2.38 per pound in 2010, DOE notes that this price was derived from speaking with 

several North American suppliers of prefabricated amorphous cores, and aligns with 

marked-up price estimates for raw amorphous ribbon. Therefore, so DOE continued to 

use this price estimate in the NOPR for the 2010 price scenario.
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6. Markups

DOE derived the manufacturer’s selling price for each design in the engineering 

analysis by considering the full range of production costs and non-production costs. The 

full production cost is a combination of direct labor, direct materials, and overhead. The 

overhead contributing to full production cost includes indirect labor, indirect material, 

maintenance, depreciation, taxes, and insurance related to company assets. Nonproduction cost includes the cost of selling, general and administrative items (market 

research, advertising, sales representatives, and logistics), research and development 

(R&D), interest payments, warranty and risk provisions, shipping, and profit factor. 

Because profit factor is included in the non-production cost, the sum of production and 

non-production costs is an estimate of the manufacturer’s selling price. DOE utilized 

various markups to arrive at the total cost for each component of the distribution 

transformer. These markups are outlined in greater detail in chapter 5 of the TSD.

NPCC and NEEA jointly commented that DOE should vet the non-production 

markup with manufacturers to ensure that it is accurate. (NPCC/NEEA, No. 11 at p. 6) 

Berman Economics added that manufacturers do not price their units in the same way that 

DOE did in its analysis; rather, they look at their costs and the market and generate a 

competitive price accordingly. Therefore, Berman Economics suggested that DOE only 

look at the material and labor costs and refrain from including the other markups. (BE, 

Pub. Mtg. Tr., No. 34 at p. 96)
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DOE interviewed manufacturers of distribution transformers and related products 

to learn about markups, among other topics, and observed a number of very different 

practices. In absence of a consensus, DOE attempted to adapt manufacturer feedback to 

inform its current modeling methodology while acknowledging that it may not reflect the 

exact methodology of many manufacturers. DOE feels that it is necessary to model 

markups, however, since there are costs other than material and labor that affect final 

manufacturer selling price. The following sections describe various facets of DOE’s 

markups for distribution transformers.

a. Factory Overhead

DOE uses a factory overhead markup to account for all indirect costs associated 

with production, indirect materials and energy use (e.g., annealing furnaces), taxes, and 

insurance. In the preliminary analysis, DOE derived the cost for factory overhead by 

applying a 12.5 percent markup to direct material production costs.

Several stakeholders commented that factory overhead is more commonly 

estimated as a markup on labor costs, not material costs. (NPCC/NEEA, No. 11 at pp. 2, 

6; ASAP/ACEEE/NRDC, No. 28 at p. 2; PP, Pub. Mtg. Tr., No. 34 at p. 102; HEX, Pub. 

Mtg. Tr., No. 34 at p. 103) ABB commented that factory overhead should not be tied to 

direct material costs, but rather to the design option being produced and the volume being 

produced, using a fixed quantity for factory overhead based on the design option. (ABB, 

No. 14 at pp. 14-15)
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DOE appreciates the comments and considered other approaches for calculating 

factory overhead for the NOPR. However, DOE was unable to determine an alternate 

methodology that could accurately estimate factory overhead costs. In the absence of 

further information for how to calculate factory overhead based on labor costs or design 

options, DOE continued to use its approach based on the material production costs. DOE 

notes that factory overhead costs are not applied to the material production cost 

component, but are simply estimated based on the production costs.

In the preliminary analysis, DOE applied the same factory overhead markup to its 

prefabricated amorphous cores as it did to its other design options where the 

manufacturer was assumed to produce the core. Since the factory overhead markup 

accounts for indirect production costs that are not easily tied to a particular design, it was 

applied consistently across all design types. DOE did not find that there was sufficient 

substantiation to conclude that manufacturers would apply a reduced overhead markup 

for a design with a prefabricated core.

Hammond Power Systems and Howard Industries agreed with DOE’s decision to 

apply the same factory overhead to prefabricated amorphous cores. (HPS, No. 3 at p. 4; 

HI, No. 23 at p. 6) On the other hand, NPCC and NEEA jointly commented that factory 

overhead should not be applied to prefabricated cores because the markup would already 

be included in the selling price of the prefabricated core. (NPCC/NEEA, No. 11 at p. 7) 

ABB, however, noted that even though manufacturers may outsource various components 

of the transformer manufacturing, such as enclosures, cores, or coils, DOE should assume 
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a vertical manufacturing process in which the manufacturer produces all components inhouse. (ABB, No. 14 at pp. 14-15) NEMA commented that DOE should gather additional 

data from individual manufacturers on the topic of factory overhead. (NEMA, No. 13 at 

p. 6)

For the NOPR analysis, DOE continued to apply the same factory overhead 

markup to prefabricated amorphous cores as to other cores built in-house. This approach 

is consistent with the suggestion of the manufacturers, and DOE notes that factory 

overhead for a given design applies to many items aside from the core production. 

Furthermore, since DOE already accounts for decreased labor hours in its designs using 

prefabricated amorphous cores, but also considers an increased core price based on a 

prefabricated core rather than the raw amorphous material, it already accounts for the 

tradeoffs associated with developing the core in-house versus outsourced.

During negotiations, DOE learned from both manufacturers of transformers and 

manufacturers of transformer cores that mitering and, to a greater extent, step-lap 

mitering, result in a per-pound cost of finished cores higher than butt-lapped units built to 

the same specifications. (ONYX, Pub. Mtg. Tr., No. 30 at p. 43) This helps to account for 

the fact that butt-lapping is common at baseline efficiencies in today’s low-voltage 

market.

In response, DOE opted to increase mitering costs for both low- and mediumvoltage dry-type designs. In the medium-voltage case, DOE incorporated a processing 
129

cost of 10 cents per core pound for step-lap mitering. In the low-voltage case, DOE 

incorporated a processing cost of 10 cents per core pound for ordinary mitering and 20 

cents per core pound for step-lap mitering. DOE used different per pound adders for steplap mitering for medium-voltage and low-voltage units because the base case design 

option for each is different. For low-voltage units, DOE modeled butt-lapped designs at 

the baseline efficiency level whereas ordinary mitering was modeled at the baseline for 

medium-voltage. Therefore, using a step-lap mitered core represents a more significant 

change in technology for low-voltage dry-type transformers and thus the higher markup.

b. Labor Costs

In the preliminary analysis, DOE accounted for additional labor and material costs 

for large (≥1500 kVA), dry-type designs using amorphous metal. The additional labor

costs accounted for special handling considerations, since the amorphous material is very 

thin and can be difficult to work with in such a large core. They also accounted for extra 

bracing that is necessary for large, wound core, dry-type designs in order to prevent short 

circuit problems.

NPCC, NEEA, and NEMA commented that DOE should consult individual 

manufacturers to gather information about the additional costs DOE associates with large 

amorphous designs. (NPCC/NEEA, No. 11 at p. 6; NEMA, No. 13 at p. 6) NPCC and 

NEEA added that DOE should consider a range of assumed incremental costs starting at 

zero when analyzing amorphous core designs. (NPCC/NEEA, No. 11 at p. 7)
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Several manufacturers also commented on the issue of additional costs for large 

amorphous designs. Howard Industries commented that these designs face similar cost 

increases as those that DOE identified for large dry-type designs using an amorphous 

core. It noted that typically these liquid-immersed designs require an additional 10 hours 

of handling, added cost for the epoxy and catalyst used in sealing the amorphous cores, 

and additional bracing depending on the weight of the core/coil assembly. Howard 

Industries estimated this cost as an extra $100 to $200 for additional materials and 

hardware. (HI, No. 23 at p. 6)

ABB commented that if DOE accounts for additional labor and material costs for 

large amorphous designs, then it should apply the same logic to all design options, and 

also noted that large liquid-immersed amorphous designs would have the same costs as 

the dry-type designs. ABB noted that large wound cores would have more labor and 

hardware compared to small wound cores, and that stacked cores will have more labor 

than wound cores. Finally, ABB noted that stacked M2 would require more labor than 

stacked M6 steel. (ABB, No. 14 at p. 15) Power Partners commented that DOE needed to 

add in additional assembly time for liquid-immersed transformers using amorphous 

cores. (PP, Pub. Mtg. Tr., No. 34 at p. 102) Finally, Hex Tec noted that certain core 

construction methods (e.g., symmetric core designs) make the handling of amorphous 

material much easier, which can eliminate the need for extra handling. (HEX, Pub. Mtg. 

Tr., No. 34 at p. 103)
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During negotiations, Federal Pacific commented that it believed DOE was 

underestimating labor hours for core assembly for all low- and medium-voltage dry-type 

design lines.

In response to interested party feedback, DOE applied an incremental increase in 

core assembly time to amorphous designs in the liquid-immersed design line 5 (1500 

kVA). This additional core assembly time of 10 hours is consistent with DOE’s treatment 

of amorphous designs in large, dry-type design lines. However, DOE did not account for 

additional hardware costs for bracing in the liquid-immersed designs using amorphous 

cores. This is because DOE already accounts for bracing costs for all of its liquidimmersed designs, which use wound cores, in its analysis. DOE determined that it 

adequately accounted for these bracing costs in the smaller kVA sizes using amorphous 

designs, and thus only made the change to the large (≥1500 kVA) design lines. DOE did 

not model varying incremental cost increases starting with zero for large amorphous 

designs, as NEEA and NPCC suggested, noting that the impact of these incremental costs 

are oftentimes very minor for large, expensive transformer designs. In response to 

Federal Pacific’s comment and data from other manufacturers of medium- and lowvoltage transformers, DOE explored its estimates of labor hours and increased those 

relating to core assembly for design lines 6-13B. Details on the specific values of the 

adjustments can be found in chapter 5 of the TSD.

Finally, in response to ABB’s comment that DOE should apply different labor 

and material costs to each design option in the analysis, DOE notes that it already does 
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account for costs differently based on the design options used. Labor requirements are, 

for example, determined in part based on the grade of core steel, the core weight, and the 

number of turns in the winding. Similarly, material costs are determined specific to each 

material input based on each design’s specifications.

c. Shipping Costs

During its interviews with manufacturers in the preliminary analysis, DOE was 

informed that manufacturers often pay shipping (freight) costs to the customer. 

Manufacturers indicated that they absorb the cost of shipping the units to the customer 

and that they include these costs in their total cost structure when calculating profit 

markups. As such, manufacturers apply a profit markup to their shipping costs just like 

any other cost of their production process. Manufacturers indicated that these costs 

typically amount to anywhere from four to eight percent of revenue.

In the previous rulemaking for distribution transformers, DOE accounted for 

shipping costs exclusively in the LCC analysis. These costs were paid by the customer, 

and thus did not include a markup from the manufacturer based on its profit factor. In the 

preliminary analysis, DOE included shipping costs in the manufacturer’s cost structure, 

which is then marked up by a profit factor. These shipping costs account for delivering 

the units to the customer, who may then bear additional shipping costs to deliver the units 

to the final end-use location. As such, DOE accounts for the first leg of shipping costs in 

the engineering analysis and then any subsequent shipping costs in the LCC analysis. The 

shipping cost was estimated to be $0.22 per pound of the transformer’s total weight and 
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typically amounts to four to eight percent of the total MSP. DOE derived the $0.22 per 

pound by relying on the shipping costs developed in its previous rulemaking on 

distribution transformers, when DOE collected a sample of shipping quotations for 

transporting transformers. In that rulemaking, DOE estimated shipping costs as $0.20 per 

pound based on an average shipping distance of 1,000 miles. For the preliminary 

analysis, DOE updated the cost to $0.22 per pound based on the price index for freight 

shipping between 2007 and 2010. Additional detail on these shipping costs can be found 

in chapter 5 and chapter 8 of the TSD.

DOE received several comments about the methodology for deriving shipping 

costs. NEMA commented that DOE should gather additional information from 

manufacturers. (NEMA, No. 13 at p. 6) Federal Pacific commented that weight increases 

as transformers become more efficient, and noted that shipping costs would thus increase 

if standards were amended. (FPT, No. 27 at pp. 4-5) Several stakeholders commented 

that DOE should consider the cost of fuel in its shipping cost calculation, particularly 

since it has increased in recent years. (NRECA/T&DEC, No. 31 and 36 at p. 3; EEI, Pub. 

Mtg. Tr., No. 34 at p. 95; EEI, No. 29 at p. 5) NPCC and NEEA jointly commented that 

shipping costs will increase with time as diesel fuel prices rise. (NPCC/NEEA, No. 11 at 

p. 7)

For the NOPR, DOE revised its shipping cost estimate to account for the rising 

cost of diesel fuel. DOE adjusted its previous shipping cost of $0.20 (in 2006 dollars) 

from the previous rulemaking to a 2011 cost based on the producer price index for No. 2 
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diesel fuel. This yielded a shipping cost of $0.28 per pound. DOE also retained its 

shipping cost calculation based on the weight of the transformer to differentiate the 

shipping costs between lighter and heavier, typically more efficient, designs.

In the preliminary analysis, DOE applied a non-production markup to all cost 

components, including shipping costs, to derive the MSP. DOE based this cost treatment 

on the assumption that manufacturers would mark up the shipping costs when calculating 

their final selling price. The resulting shipping costs were, as stated, approximately four 

to eight percent of total MSP.

During the public meeting, ASAP asked if DOE had found market data that 

indicated that shipping costs should be included in the sale price. (ASAP, Pub. Mtg. Tr., 

No. 34 at p. 102) HPS commented that DOE's assumption that shipping costs are 

typically four to eight percent of MSP is accurate, but noted that it does not typically 

mark up shipping costs. (HPS, No. 3 at p. 5) ABB commented that shipping costs are 

recognized as an expense to manufacturers, but that they do not impact the profit markup 

of the manufacturer because transformers must be priced based on the market. Rather, 

shipping costs reduce the profit of the sale. Additionally, ABB noted that shipping costs 

are typically only two to four percent of total transformer costs. (ABB, No. 14 at p. 15) 

Similarly, Federal Pacific commented that manufacturers bear the cost of shipping, but 

they do not mark up the shipping cost in their profit markup or other markups. (FPT, No. 

27 at p. 17) Conversely, Howard Industries agreed with DOE’s approach in which 
135

markups were applied to the cost of shipping. Howard Industries added that it agreed that 

shipping costs are typically four to eight percent of revenues. (HI, No. 23 at p. 6)

Based on the comments received and DOE’s additional research into the 

treatment of shipping costs through manufacturer interviews, DOE has preliminarily 

decided to retain the shipping costs in its calculation of MSP, but not to apply any 

markups to the shipping cost component. Therefore, shipping costs were added separately 

into the MSP calculation, but not included in the cost basis for the non-production 

markup. The resulting shipping costs were still in line with the estimate of four to eight 

percent of MSP for all the dry-type design lines. For the liquid-immersed design lines, the 

shipping costs ranged from six to twelve percent of MSP and averaged about nine percent 

of MSP.

7. Baseline Efficiency and Efficiency Levels

DOE analyzed designs over a range of efficiency values for each representative 

unit. Within the efficiency range, DOE developed designs that approximate a continuous 

function of efficiency. However, DOE only analyzes incremental impacts of increased 

efficiency by comparing discrete efficiency benchmarks to a baseline efficiency level. 

The baseline efficiency level evaluated for each representative unit is the existing energy 

conservation standard level of efficiency for distribution transformers established either 

in DOE’s previous rulemaking or by EPACT 2005. The incrementally higher efficiency 

benchmarks are referred to as “efficiency levels” (ELs) and, along with MSP values, 
136

characterize the cost-efficiency relationship above the baseline. These ELs are ultimately 

used by DOE if it decides to amend the existing energy conservation standards.

For the NOPR, DOE considered several criteria when setting ELs. First, DOE 

harmonized the efficiency values across single-phase transformers and the per-phase 

kVA equivalent three-phase transformers. For example, a 50 kVA single-phase 

transformer would have the same efficiency requirement as a 150 kVA three-phase 

transformer. This approach is consistent with DOE’s methodology from the previous 

rulemaking and from the preliminary analysis of this rulemaking. Therefore, DOE 

selected equivalent ELs for several of the representative units that have equivalent perphase kVA ratings.

Second, DOE selected equally spaced ELs by dividing the entire efficiency range 

into five to seven evenly spaced increments. The number of increments depended on the 

size of the efficiency range. This allowed DOE to examine impacts based on an 

appropriate resolution of efficiency for each representative unit.

Finally, DOE adjusted the position of some of the equally spaced ELs and 

examined additional ELs. These minor adjustments to the equally spaced ELs allowed 

DOE to consider important efficiency values based on the results of the software designs. 

For example, DOE adjusted some ELs slightly up or down in efficiency to consider the 

maximum efficiency potential of non-amorphous design options. Other ELs were added 

to consider important benchmark efficiencies, such as the NEMA Premium efficiency 
137

levels for LVDT distribution transformers. Last, DOE considered additional ELs to 

characterize the maximum-technologically feasible design for representative units where 

the harmonized per-phase efficiency value would have been unachievable for one of the 

representative units. 

EEI requested that DOE provide summary tables of the ELs and the proposed 

TSLs to highlight any differences between the two. (EEI, Pub. Mtg. Tr., No. 34 at p. 125) 

Furthermore, EEI pointed out that CSL 0 is TSL 3 or 4 from the last rulemaking and is 

more efficient than a 2005 or 2007 unit. (EEI, Pub. Mtg. Tr., No. 34 at p. 113)

NEMA recommended that the TSLs from the previous rulemaking be visually 

overlaid with the ELs from this rulemaking to allow easier comparisons between the 

recent standards and the current rulemaking. (NEMA, No. 13 at pp. 6-7)

Schneider Electric commented that it would like to see the label “CSL 0” 

removed from the analysis and instead replaced with exactly what those levels were and 

where it was mandated, i.e., in EISA 2007. (SE, Pub. Mtg. Tr., No. 34 at p. 119)

DOE has found that multiple sets of efficiency levels and candidate standard 

levels have confused stakeholders in the past, and prefers to limit this document’s 

discussion to those ELs at hand. EEI is correct to point out that the previous rule’s 

standard is the current rule’s baseline. DOE is statutorily prohibited from decreasing 
138

efficiency standards, and so any discussion of future standards necessarily begins with 

what is in effect at the time.

Berman Economics noted that high-cost designs that are above the minimum first 

cost amount for a given EL should not be considered in DOE’s analysis because they do 

not represent the cost required to comply with the standard. It felt that, by including these 

designs, DOE artificially increases the cost estimate from the Monte Carlo analysis. (BE, 

No. 16 at pp. 6-7)

Although DOE’s current test procedure specifies a load value at which to test 

transformers, DOE recognizes that different consumers see real-world loadings that may 

be higher or lower. In those cases, consumers may choose a transformer offering a lower 

LCC even when faced with a higher first cost. If DOE’s cost/efficiency design cloud 

were redrawn to reflect loadings other than those specified in the test procedure, different 

designs would migrate to the optimum frontier of the cloud. Additionally, although 

DOE’s engineering analysis reflects a range of transformers costs for a given EL, the 

LCC analysis only selects transformer designs near the lowest cost point.

8. Scaling Methodology

For the preliminary analysis, DOE performed a detailed analysis on each 

representative unit and then extrapolated the results of its analysis from the unit studied to 

the other kVA ratings within that same engineering design line. DOE performed this 

extrapolation to develop inputs to the national impacts analysis. The technique it used to 
139

extrapolate the findings of the representative unit to the other kVA ratings within a design 

line is referred to as “the 0.75 scaling rule.” This rule states that, for similarly designed 

transformers, costs of construction and losses scale with the ratio of their kVA ratings 

raised to the 0.75 power. The relationship is valid where the optimum efficiency loading 

points of the two transformers being scaled are the same. DOE used the same 

methodology to scale its findings during the previous rulemaking on distribution 

transformers.

In response to the preliminary analysis, DOE received multiple comments 

regarding the 0.75 scaling rule. HVOLT expressed its support for the use of the 0.75 

scaling rule. (HVOLT, Pub. Mtg. Tr., No. 34 at p. 139) Several other stakeholders stated 

that they believed the 0.75 scaling rule is accurate over small kVA ranges, but can break 

down near the limits of the scaling range. (HPS, No. 3 at p.4; NPCC/NEEA, No. 11 at pp. 

7-8; NEMA, No. 13 at pp. 4, 6; SE, No. 18 at p.7; HI, No. 23 at p. 7; FPT, Pub. Mtg. Tr., 

No. 34 at p. 137) NPCC, NEEA and NEMA recommended that DOE consider analyzing 

additional design lines and representative units to maintain the integrity of the scaling. 

(NPCC/NEEA, No. 11 at pp. 7-8; NEMA, No. 13 at pp. 4-6) FPT also suggested 

introducing additional designs to the analysis, noting that it has found it difficult to meet 

the efficiency levels on the lower-end kVAs for the dry-types. (FPT, Pub. Mtg. Tr., No. 

34 at p. 136) Schneider Electric recommended that DOE expand its kVA ranges within 

the design lines and overlay the design lines to allow for multiple evaluation points 

within the scaling rule. (SE, No. 18 at p. 7) Howard Industries believed that DOE should 
140

adjust the 0.75 scaling factor to account for more efficient and costlier materials needed 

to stay within the size and weight constraints of customers’ demands. (HI, No. 23 at p. 7)

EEI commented that the 0.75 scaling rule may not be accurate for scaling outside 

a single standard deviation of kVA size. EEI recommended that DOE work with 

manufacturers to create new formulas for scaling beyond a single standard deviation. 

(EEI, No. 29 at p. 6) Warner Power stated that the 0.75 scaling rule is less accurate for 

higher scaling ratios where transformer designs change significantly, but felt that the rule 

was accurate for scaling where the ratio of kVAs was between 0.8 and 1.2. (WP, No. 30 

at pp. 7, 11)

ABB noted that the 0.75 scaling rule is accurate within about a half order of 

magnitude when all other parameters are constant. ABB also stated that in their 

experience the 0.75 coefficient increases as the kVA decreases and approaches 1.0 as an 

upper limit. ABB added that the same is true as the BIL increases. (ABB, No. 14 at pp. 

10, 13) Hammond agreed that the 0.75 scaling rule can be problematic for smaller kVAs 

of higher voltage and BIL ratings. (HPS, No. 3 at p. 4) Metglas explained that the scaling 

rule assumes one has the same percentage insulation in the cross-section of the conductor 

in the transformers while, in reality, as the transformers get smaller, more insulation is 

needed to maintain the same BIL. FPT believed that the 0.75 scaling rule was less 

accurate for lower kVA ratings (below 500 kVA), in part because small kVA sizes 

require very small wires that are dramatically more expensive than larger wires in larger 
141

kVA sizes. FPT also claimed that current standards are more difficult to meet at the lower 

kVA sizes. (FPT, No. 27 at pp. 14-17)

PP expressed frustration that the design work involved extrapolating from a 500 

kVA model to a 833 kVA model and believed that the extrapolations did not hold true. 

(PP, Pub. Mtg. Tr., No. 34 at p. 135)

Because it is not practical to directly analyze every combination of design options 

and kVAs under the rulemaking’s scope of coverage, DOE selected a smaller number of 

units it believed to be representative of the larger scope. Many of the current design lines 

use representative units retained from the 2007 rulemaking with minor modifications. To 

generate efficiency values for kVA values not directly analyzed, DOE employed a 

scaling methodology based on physical principles (overviewed in Appendix 5B) and 

widely used by industry in various forms. DOE’s scaling methodology is an 

approximation and, as with any approximation, can suffer in accuracy as it is extended 

further from its reference value.

Several of the comments on this topic suggest that DOE could improve the 

accuracy of its scaling by limiting the range over which it is applied. To that end, DOE 

has added a design line (13A to address the case of high BIL, small kVA medium-voltage 

dry-type units while redesignating the former 13 “13B”.) DOE will seek to corroborate 

scaling results with direct analysis in other areas that fall outside of the scaling ranges put 

forth by commenters for the final rule.
142

Additionally, DOE modified the way it splices extrapolations from each 

representative unit to cover equipment classes at large. Previously, DOE extrapolated 

curves from individual data points and blended them near the boundaries to set standards. 

Currently, DOE fits a single curve through all available data points in a space and 

believes that the resulting curve will both be smoother and offer a more robust scaling 

behavior over the covered kVA range.

Finally, although the laws of physics applied to an ideal transformer yield a 

scaling exponent of 0.75, DOE recognizes that real-world engineering considerations 

may produce a behavior better modeled using a different exponent. A number of 

commenters suggested that the smaller transformers in particular had difficulty meeting 

standards, which seems to imply that the overall shape of the efficiency curve should 

come from a lower overall exponent. This would tend to project lower efficiencies at 

lower kVAs and higher efficiencies at higher kVAs. DOE seeks to further understand 

how kVA rating and other factors combine to affect transformer efficiency, and seeks 

comment to that end.

Negotiating parties agreed that deriving results for the “high” and “low” BIL 

MVDT equipment classes, namely, 5,6,9, and 10, was the most appropriate way to 

correctly establish relative standards such that the various efficiencies were logical with 

respect to each other. (ASAP, Pub. Mtg. Tr., No. ## (docket number unavailable) at p. 

175) Parties agreed that standards should be set by adding 10 percent in losses to 
143

equipment classes 7 and 8 to derive standards for equipment classes 9 and 10 and 

subtracting 10 percent in losses from classes 7 and 8 to derive standards for classes 5 and 

6. DOE’s own analysis suggests that this method of scaling is reasonable and proposes 

using it to derive standards as it does it today’s notice.

Furthermore, several parties noted that liquid-immersed transformers experienced 

smaller, but not insignificant, performance benefits or penalties as a function of BIL and 

noted that standards for liquid-immersed units could be tweaked in the same manner as 

those from MVDT units. Doing so would permit capture of increased energy savings at 

the more-efficient BILs while still permitting manufacture of the higher BIL transformers 

at reasonable expense.

DOE requests comment on scaling across both BIL and kVA ratings as it applies 

to both dry-type and liquid-immersed transformers and on specific ways for DOE to 

establish a sound methodology for deriving BIL adjustment factors in the liquidimmersed case. DOE also requests comment on how standards are best harmonized 

across phase counts for all types of transformers and how standards for single-phase 

transformers may be scaled to produce those of three-phase transformers and vice-versa.

9. Material Availability

DOE received several comments expressing concern over the availability of 

materials, including core steel and conductors, needed to build energy efficient 
144

distribution transformers. These issues pertain to a global scarcity of materials as well as 

issues of materials access for small manufacturers.

NPCC, NEEA, Schneider Electric, and the joint comments from ASAP, ACEEE 

and NRDC all indicated that DOE should revise its selling prices to make sure they are in 

line with market prices. They commented that DOE’s selling prices were too high 

compared to the prices supplied by manufacturers at the public meeting. (NPCC/NEEA, 

No. 11 at p. 2 and pp. 6-7; SE, No. 18 at p. 8; ASAP/ACEEE/NRDC, No. 28 at pp. 1-2) 

The ASAP, ACEEE and NRDC joint comments further specified that commenters at the 

meeting noted that the price of a small purchase quantity going through a distributor was 

still 40-60% lower than DOE’s price estimates. They added that, if DOE is unable to 

determine how to adjust its cost inputs, it should apply an adjustment factor to the final 

selling price to bring it in line with current market prices. If DOE cannot determine prices 

for LVDT, the joint commenters recommended that DOE apply the adjustment factor 

from the liquid-immersed analysis to the dry-type analysis. (ASAP/ACEEE/NRDC, No. 

28 at pp. 1-2)

Conversely, HVolt, Inc. commented that DOE’s finished transformer prices are 

too low and that several manufacturers have generated selling prices (using current 

materials prices and low markups) that are 2.5-4 times higher than DOE’s prices at CSL 

6. (HVOLT, No. 33 at p. 1)
145

Manufacturers often accuse DOE or over-representing manufacturer selling 

prices, while parties interested in increasing energy efficiency accuse it of underrepresenting these prices. DOE is interested in tailoring its analysis to align more closely 

with the market and believes the best way for parties to demonstrate falsely high or low 

prices is to submit actual purchase or bid records for designs close to DOE’s 

representative units. If needed, such records could be submitted under the terms of a nondisclosure agreement. Finally, DOE notes that it is the incremental, and not absolute, cost 

of added efficiency that dominates the cost-effectiveness calculations that it performs. 

Consequently, errors in the absolute prices will have a smaller effect on the rule outcome 

than errors in the cost of marginal efficiency. DOE requests further comment on 

manufacturer selling price and any accompanying data that can help substantiate such 

comment.

Southern Company commented that DOE should consider the limited supply of 

amorphous steel when evaluating amended standard levels. It added that there is not 

enough amorphous steel to meet the demand of the entire transformer industry, and noted 

that prices for amorphous steel could increase substantially if it was the sole core material 

used in distribution transformer designs. (SC, No. 22 at p. 1)

DOE is aware that many core steels, including amorphous steels, have constraints 

on their supply and presents an analysis of global steel supply in Appendix 3-A.
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10. Primary Voltage Sensitivities

DOE understands that primary voltage and the accompanying BIL may 

increasingly affect efficiency of liquid-immersed transformers as standards rise. DOE 

may conduct primary voltage sensitivity analysis in order to better quantify the effects of 

BIL and primary voltage on efficiency, and may use such information to consider 

establishing equipment classes by BIL rating for liquid-immersed distribution 

transformers.

11. Impedance

In the preliminary analysis, DOE only considered transformer designs with 

impedances within the normal impedance ranges specified in Table 1 and Table 2 of 10 

CFR Part 431.192. These impedances represent the typical range of impedance that is 

used for a given liquid-immersed or dry-type transformer based on its kVA rating and 

whether it is single-phase or three-phase.

Commonwealth Edison (ComEd) commented that its single-phase overhead 

transformer specification only allows impedances between 5.3 and 6.2 percent for 250, 

333, and 500 kVA transformers. Furthermore, ComEd commented that manufacturers are 

already having difficulty creating designs with the minimum impedance requirement of 

5.3 percent based on the current standard level. (ComEd, No. 24 at p. 3) Similarly, 

Central Moloney commented that it also has limitations on the impedance of the 

transformers, which get harder to meet at larger sizes. (Central Moloney, Pub. Mtg. Tr., 

No. 34 at p. 78)
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For the NOPR, DOE continued to consider designs within the normal impedance 

ranges used in the preliminary analysis. While certain applications may have 

specifications that are more stringent than these normal impedance ranges, DOE believes 

that the majority of applications are able to tolerate impedances within these ranges. 

Since DOE considers a wide array of designs within the normal impedance ranges, it 

adequately considers the cost considerations of higher and lower impedance tolerances.

DOE requests comment on impedance values and on any related parameters (e.g., 

inrush current, X/R ratio) that may be used in evaluation of distribution transformers. 

DOE requests particular comment on how any of those parameters may be affected by 

energy conservation standards of today’s proposed levels or higher.

12. Size and Weight

In the preliminary analysis, DOE did not constrain the weight of its designs. DOE 

accounted for the full weight of each design generated by the optimization software based 

on its materials and hardware. Similarly, DOE let several dimensional measurements of 

its designs vary based on the optimal core/coil dimensions plus space factors. However, 

DOE did hold certain tank and enclosure dimensions constant for its design lines. Most 

notably, DOE fixed the height dimension on all of its rectangular tank transformers. For 

each design that had variable dimensions, DOE accounted for the additional cost of 

installing the unit, where applicable.

Comment [A14]: Change recommended by 

OIRA.
148

Several interested parties expressed concerns about the size and weight of the 

designs used in DOE’s analysis. Power Partners commented that single-phase liquidimmersed units above 500 kVA are very difficult to design for the current standard level 

when accounting for the weight and size constraints that users specify. (PP, Pub. Mtg. 

Tr., No. 34 at p. 46) Power Partners and Howard Industries commented that this issue is 

particularly a concern for pole-mounted transformers, and noted that many customers put 

large (500 kVA single-phase) units on poles. (PP, Pub. Mtg. Tr., No. 34 at p. 75; HI, Pub. 

Mtg. Tr., No. 34 at p. 77) Pepco Holdings, Inc. (PHI) stated that the largest transformer 

that it will hang on a pole is 333 kVA, but noted that it, too, has concerns about weight 

and size. (PHI, Pub. Mtg. Tr., No. 34 at p. 77)

Many stakeholders noted that size and weight limitations exist for certain 

customer specifications. Power Partners, Central Moloney (CM), and PHI all commented 

that restrictions exist for size and weight, and stated that DOE should account for 

maximum weight and dimensional limits. (PP, Pub. Mtg. Tr., No. 34 at p. 73; CM, Pub. 

Mtg. Tr., No. 34 at p. 77; PHI, Pub. Mtg. Tr., No. 34 at p. 74) PHI noted that these 

restrictions are especially important for pole-mount, subway, subsurface, and network 

transformers. (PHI, No. 26 and 37 at p. 1) Power Partners commented that over 80 

percent of new transformers manufactured are for replacement, and noted that 

replacement pole-mount transformers need to fit into the existing pole space. As such, 

Power Partners suggested a maximum weight of 650 pounds for the representative unit in 

DL2 (25 kVA single-phase) and a maximum weight of 3,600 pounds for the 

representative unit in DL3 (500 kVA single-phase). (PP, No. 19 at p. 3) Conversely, 
149

PG&E commented that the large transformers in its service area are typically padmounted and noted that weight is not a big concern. (PG&E, Pub. Mtg. Tr., No. 34 at p. 

74)

For the NOPR engineering analysis, DOE did not restrict its designs based on a 

limit for size or weight beyond the fixed height measurements it was already considering 

for the rectangular tank sizes. DOE understands that larger transformers may require 

additional installation costs such as a new pole change-out or vault expansion. To the 

extent that it had data on these additional costs, DOE accounted for them in its LCC 

analysis, as described in section IV.F. However, DOE did not choose to limit its design 

specifications based on a specific size or weight constraint.

During negotiation meetings, several parties noted that transformers in 

underground vaults could face staggering cost increases if obligated to comply with 

unmodified standards. (ABB, Pub. Mtg. Tr., No. 89 at p. 245) The parties proposed to 

create a separate equipment class for such units and began discussing how such a class 

might be defined in terms of physical features and such that it would not represent a 

standards loophole. DOE requests comment on the possibility of establishing a separate 

equipment class for vault transformers and how such a class could be defined.

Nonetheless, DOE notes that the majority of its designs are within the weight 

constraints suggested by Power Partners. In design line 2, over 95 percent of DOE’s 

designs are below 650 pounds. In design line 3, over 62 percent of DOE’s designs are 
150

below 3,600 pounds, and when only the designs with the lowest first cost are considered, 

nearly 74 percent of the designs are less than 3,600 pounds. The majority of the designs 

that exceed 3,600 pounds are at the maximum efficiency levels using an amorphous core 

steel.

During negotiations, Federal Pacific and HVOLT commented that substationstyle designs common to the medium-voltage, dry-type market are larger than the designs 

that DOE had previously modeled and would exhibit bus and lead losses reflecting their 

longer buses and leads. (HVOLT, Pub. Mtg. Tr., No. 91 at p. 290)

DOE worked with manufacturers to explore the magnitude of the effect of longer 

buses and leads and found it to be small relative to the gap between efficiency levels. 

Nonetheless, DOE made small upward adjustments to bus and lead losses of all mediumvoltage, dry-type design lines. Details on the specific values of the adjustments made can 

be found in Chapter 5 of the TSD.

D. Markups Analysis

The markups analysis develops appropriate markups in the distribution chain to 

convert the estimates of manufacturer selling price derived in the engineering analysis to 

customer prices. In the preliminary analysis, DOE determined the distribution channels 

for distribution transformers, their shares of the market, and the markups associated with 

the main parties in the distribution chain, distributors, contractors and electric utilities.
151

Several stakeholders commented that DOE’s analysis failed to include the 

distribution channel that delivers liquid-immersed transformers directly from 

manufacturers to large utilities. (NEEA, No. 11 at p. 2, Joint Comments PG&E and SCE, 

No. 32 at p. 2, and EMS, Public Meeting Transcript, No. 34 at p. 145) EMS Consulting 

commented that when large utilities purchase directly from manufacturers, the 

commission of the manufacturer's representative is included in the price of the 

transformer and should not be added in separately. (EMS, Public Meeting Transcript, No. 

34 at p. 145) PG&E and SCE noted that because utilities often pay much less for 

transformers purchased in bulk, the selling prices DOE presented in the preliminary 

analysis are too high. (Joint Comments PG&E and SCE, No. 32 at p. 2) For the NOPR, 

DOE added a new distribution channel to represent the direct sale of transformers to 

independently owned utilities, which account for approximately 80 percent of liquidimmersed transformer shipments. This sales channel removes a distributor markup, which 

had included the commission of the manufacturer's representative in the preliminary 

analysis. The inclusion of this channel reduces the overall markup for liquid-immersed 

transformers.

EEI stated that a distribution channel from manufacturers to distributors to multisite commercial and/or industrial customers (i.e., large purchasers) may represent 10 

percent to 25 percent of dry-type transformer sales. (EEI, No. 29 at p. 6) DOE did not 

find data that would allow it to include the channel mentioned by EEI as a separate 

distribution channel.
152

In the preliminary analysis, DOE developed average distributor and contractor 

markups by examining the installation and contractor cost estimates provided by RS 

Means Electrical Cost Data 2011. DOE developed separate markups for baseline products 

(baseline markups) and for the incremental cost of more-efficient products (incremental 

markups). Incremental markups are coefficients that relate the change in the installation 

cost due to the increase equipment weight of some higher-efficiency models. 

FPT agreed with the distributor markups that DOE developed for liquid-immersed 

transformers. (FPT, No. 27 at p. 17) HPS agreed that a 15-percent markup is appropriate 

for distributor markup. (HPS, No. 3 at p. 6) ABB and NEMA, on the other hand, 

recommended that DOE consult with a sample of major distributors to obtain a better 

understanding of internal markups. (ABB, No. 14 at p. 18; NEMA, No. 13 at p. 8) DOE 

was not able to conduct a representative survey of transformer distributors within the 

context of the current rulemaking. Given the supportive comments from FPT and HPS, 

DOE retained the markup used in the preliminary analysis for the NOPR for liquidimmersed and low-voltage dry-type transformers. However, based on input received from 

manufacturers during the negotiated rulemaking process, DOE revised the distributor and 

contractor markups that affect the retail price for medium-voltage dry-type transformers 

to 1.26 and 1.16, respectively.

HVOLT suggested that DOE's estimated contractor labor and materials markup 

that affects the installation costs of 1.43 is too high. (HVOLT, Public Meeting Transcript, 

No. 34 at p. 149) DOE used RS Means Electrical Cost Data 2010 to estimate a contractor 
153

labor and materials markup of 1.43. This markup is justified as it includes: (1) direct 

labor required for installation, including unloading, uncrating, hauling within 200 feet of 

the loading dock, setting in place, connecting to the distribution network, and testing; and 

(2) equipment rentals necessary for completion of the installation such as a forklift, 

and/or hoist.

Chapter 6 of the NOPR TSD provides additional detail on the markups analysis.

E. Energy Use Analysis

The energy use and end-use load characterization analysis (chapter 6) produced 

energy use estimates and end-use load shapes for distribution transformers. The energy 

use estimates enabled evaluation of energy savings from the operation of distribution 

transformer equipment at various efficiency levels, while the end-use load 

characterization allowed evaluation of the impact on monthly and peak demand for 

electricity from the operation of transformers.

The energy used by distribution transformers is characterized by two types of 

losses. The first are no-load losses, which are also known as core losses. No-load losses 

are roughly constant and exist whenever the transformer is energized (i.e., connected to 

live power lines). The second are load losses, which are also known as resistance or I2R 

losses. Load losses vary with the square of the load being served by the transformer. 

Because the application of distribution transformers varies significantly by type of 
154

transformer (liquid-immersed or dry-type) and ownership (electric utilities own 

approximately 95 percent of liquid-immersed transformers, commercial/industrial entities 

use mainly dry-type), DOE performed two separate end-use load analyses to evaluate 

distribution transformer efficiency. The analysis for liquid-immersed transformers 

assumes that these are owned by utilities and uses hourly load and price data to estimate 

the energy, peak demand, and cost impacts of improved efficiency. For dry-type 

transformers, the analysis assumes that these are owned by commercial and industrial 

customers, so the energy and cost savings estimates are based on monthly building-level 

demand and energy consumption data and marginal electricity prices. In both cases, the 

energy and cost savings are estimated for individual transformers and aggregated to the 

national level using weights derived from either utility or commercial/industrial building 

data.

For utilities, the cost of serving the next increment of load varies as a function of 

the current load on the system. To correctly estimate the cost impacts of improved 

transformer efficiency, it is therefore important to capture the correlation between electric 

system loads and operating costs and between individual transformer loads and system 

loads. For this reason, DOE estimated hourly loads on individual liquid-immersed 

transformers using a statistical model that simulates two relationships: (1) the relationship 

between system load and system marginal price; and (2) the relationship between the 

transformer load and system load. Both are estimated at a regional level.
155

DOE received a number of comments on its preliminary analysis for liquidimmersed transformers. 

Regarding the price-load correlation incorporated into the end-use load 

characterization, EEI suggested that DOE obtain data for 2009/2010 to develop a more 

complete picture of the savings associated with reducing core and coil losses in liquidfilled transformers. (EEI, No. 29 at p. 6) Because changes to the functional form of the 

price-load correlation are small compared to the variability in the model, updating the 

data will not affect the resulting price-load correlation. Thus, DOE continued to use 2008 

Federal Energy Regulatory Commission (FERC) Form714 lambda data and market prices 

for the NOPR analysis.

EEI also suggested that DOE use tariffs to determine the prices paid for base load 

electricity generation, because reducing the constant core losses will not save electricity 

at marginal rates. (EEI, No. 29 at p. 8) NRECA stated that most NRECA members make 

wholesale purchases at tariff rates that reflect installed, existing resources, with only a 

small increment based on hourly, market-based purchases. (NRECA, No. 31 and 36 at p. 

4) They concluded that DOE’s approach overemphasized rates for purchases made on the 

hourly market.

The energy savings from more efficient distribution transformers are a small 

decrement to the total energy consumption. The hourly price reflects the cost of serving a 

small, marginal change in load, and is therefore the appropriate method to use to estimate 
156

the costs savings associated with energy savings. This is true for both coil losses and 

winding losses, and is independent of how the transformer owner pays for the bulk of 

their power purchases. DOE produced a detailed comparison of tariff-based marginal 

prices and hourly marginal prices for peaking end-uses as part of the Commercial Unitary 

Air Conditioner & Heat Pump rulemaking.

28 This analysis confirmed that, on an annual 

average basis, both methods lead to similar cost estimates.

Regarding hourly load data, NEMA recommended that DOE consult with utilities, 

building owners, and other end-users to obtain any available field data. (NEMA, No. 13 

at p. 8) DOE consulted with a variety of industry contacts but was unable to find any 

source of metered hourly load for transformers. Data submitted by subcommittee member 

K. Winder of Moon Lake Electric during the negotiations were used to validate the load 

models for single-phase liquid-immersed transformers. For the final rule, if stakeholders 

are able to provide, or assist in providing such data, DOE will use it to validate and 

modify the transformer load models as needed.

Dry-type transformers are primarily installed on buildings and owned by the 

building owner/operator. Commercial and industrial (C&I) utility customers are typically 

billed monthly, with the bill based on both electricity consumption and demand. Hence, 

the value of improved transformer efficiency depends on both the load impacts on the 

customer’s electricity consumption and demand and the customer’s marginal prices.

 

28 See http://www1.eere.energy.gov/buildings/appliance_standards/commercial/ac_hp.html
157

The customer sample of dry-type distribution transformer owners was taken from 

the EIA Commercial Buildings Energy Consumption Survey (CBECS) databases. Survey 

data for the years 1992 and 1995 were used, as these are the only years for which 

monthly customer electricity consumption (kWh) and peak demand (kW) are provided. 

To account for changes in the distribution of building floor space by building type and 

size, the weights defined in the 1992 and 1995 building samples were rescaled to reflect 

the distribution in the most recent 2003 CBECS survey. CBECS covers primarily 

commercial buildings, but a significant fraction of transformers are shipped to industrial 

building owners. To account for this in the sample, data from the 2006 Manufacturing 

Energy Consumption Survey (MECS) were used to estimate the amount of floor space of 

buildings that might use the type of transformer covered by the rulemaking. The weights 

assigned to the building sample were rescaled to reflect this additional floor space. Only 

the weights of large buildings were rescaled.

Regarding DOE’s energy use characterization, EEI stated that DOE should use 

EIA’s 2006 MECS to develop baseline electricity consumption and demand for industrial 

facilities. (EEI, No. 29 at p. 8) Using CBECS data as a proxy, they said, may lead to 

incorrect analysis on transformers for the industrial facilities being modeled. (EEI, No. 29 

at p. 8) The MECS survey data does not contain any building-level information on energy 

consumption, and contains no information whatsoever on electricity demand. Thus, DOE 

retained use of CBECS data for the NOPR analysis.

Transformer loading is an important factor in determining which types of 
158

transformer designs will deliver a specified efficiency, and for calculating transformer 

losses. In the preliminary analysis, DOE assumed non-residential load factors of 35 

percent, 40 percent, and 25 percent for medium-voltage single-phase, medium-voltage 

three-phase, and low-voltage transformers respectively. Several stakeholders commented 

on the load factors DOE used to characterize commercial and industrial loads. EEI 

suggested that DOE use Electric Power Research Institute (EPRI) and/or utility load 

factor studies to develop separate commercial and industrial load factors to use in its 

analysis. (EEI, No. 29 at p. 7) suggested that load factors for large commercial buildings 

have been trending upward because of the increased numbers of data centers. (HEX, 

Public Meeting Transcript, No. 34 at p. 192) EEI suggested that, based on EPRI data, 

DOE use higher load factors (50-55 percent for commercial buildings and 70-80 percent 

for industrial buildings). (EEI, Public Meeting Transcript, No. 34 at p. 168) ABB stated 

that DOE’s current assumptions about average load factors are sufficiently accurate. 

(ABB, No. 14 at p. 18) FPT stated commercial and industrial users tend to load their 

transformers to a lower percent of nameplate than utilities would load residential liquidfilled transformers because of the greater risk and impact of an outage of a transformer in 

a commercial or industrial installation. (FTP, No. 27 at p. 19)

Several subcommittee members commented that in rural areas the number of 

customers per transformer is likely to be significantly lower than in urban or suburban 

areas, which in turn results in lower RMS loads. (APPA and NRECA, Public Meeting 

Transcript, No. 91 at p. 201) To account for this effect, DOE performed an analysis to 

determine an average population density in the territory served by each of the utilities 
159

represented in the LCC simulation. For each utility, EIA Form 861 data were used to 

generate a list of counties served by the utility. Census data were used to determine the 

average housing unit density in each county. An average over counties was then used to 

assign the utility to a low density, average density or high density category, with the 

cutoff for low density set at 32 households per square mile. For those utilities serving 

primarily low density areas the median of the RMS load distribution is reduced from 35 

percent to 25 percent. 

For the NOPR, DOE modified its analysis of dry-type transformer loading to: (1) 

model commercial and industrial building installations separately; and (2) reflect how 

transformers are used in the field. Higher-capacity medium-voltage transformers are 

loaded at 40 percent and smaller capacity transformers medium-voltage are loaded at 35 

percent. Low-voltage transformers are loaded at 25 percent.

DOE received a number of comments that apply to both the hourly and monthly 

load models.

Regarding load (coil) losses, EEI suggested that DOE use diversity factors to 

account for the fact that significantly less than 100 percent of load losses are correlated

with peak demands for a building or distribution system. Using this method, they said, 

would prevent overestimating cost savings. (EEI, No. 29 at p. 8) DOE already employs 

diversity factors to account for the fact that load (coil) losses often do not correlate with 

system or building peak loads.
160

Several stakeholders questioned whether DOE’s analysis of responsibility factor 

accounts for the diversity of loads that transformers serve. NRECA, for instance, 

commented that diversity among a transformer's loads must be considered to set the 

responsibility factor for an individual transformer, if multiple customers are served 

through a transformer. (NRECA, No. 31 and 36 at p. 4) EEI also expressed concern that 

DOE’s analysis of responsibility factor excluded diversity of loads. (EEI, No. 29 at p. 7) 

CDA recommended that DOE’s analysis of responsibility factor consider the effect of 

load (winding) losses that likely occur simultaneously with system peaks. (CDA, No. 17 

at p. 3)

The statistical model that DOE uses to estimate the responsibility factor for each 

individual transformer accounts for the diversity of loads. The responsibility factor model 

is applied to the load (winding) losses. The model accounts for the effect of diversity of 

individual transformer loads with respect to the peak of the aggregate load of the system 

that contains the transformer. Winding losses are included in the analysis.

Several stakeholders commented on DOE’s use of a power factor of 1 in its end-use 

load characterization. PG&E and SCE stated that DOE should consider a power factor 

less than unity. (Joint Comments PG&E and SCE, No. 32 at p. 1) EEI suggested that 

DOE use a power factor other than 1 to account for decreased transformer efficiency 

from increased harmonic parasitic loads. (EEI, Public Meeting Transcript, No. 34 at p. 

156)
161

In DOE’s analysis, transformer loss estimates are calculated relative to the peak 

load on the transformer. The ratio of the peak load on a transformer to the transformer 

capacity is modeled by a distribution. There are two additional parameters that can affect 

the overall scale of transformer loading relative to its rated capacity. One is the power 

factor, and the other is a modeling parameter that adjusts the ratio of the RMS load 

relative to the square of the transformer peak load. Neither of these factors is known with 

great accuracy. The LCC spreadsheet allows the user to adjust the power factor. 

Adjusting the power factor from one to 0.95 may scale the energy losses up slightly, but 

as all transformer designs are affected equally, there should be no significant impact on 

the selection of designs that meet the candidate standard level. In the absence of 

additional field data on both RMS loads and power factors in different transformer 

installations, DOE does not believe that these small adjustments can significantly 

improve the accuracy of the LCC calculations.

NEEA commented on the calculation of load losses, recommending that DOE use 

hourly marginal line losses rather than annual average line losses to adjust distribution 

transformer loads to system generation loads. It stated that using hourly marginal line 

losses would more accurately reflect the value of load losses. (NEEA, No. 11 at p. 10) 

DOE found no data supporting the use of hourly marginal line losses rather than average 

annual line losses in calculating load losses. Thus, it continued to use average annual line 

losses for the NOPR analysis.
162

F. Life-Cycle Cost and Payback Period Analysis

DOE conducts LCC and PBP analyses to evaluate the economic impacts on 

individual customers of potential energy conservation standards for distribution 

transformers. The LCC is the total customer expense over the life of a product, consisting 

of purchase and installation costs plus operating costs (expenses for energy use, 

maintenance and repair). To compute the operating costs, DOE discounts future operating 

costs to the time of purchase and sums them over the lifetime of the product. The PBP is 

the estimated amount of time (in years) it takes customers to recover the increased 

purchase cost (including installation) of a more efficient product through lower operating 

costs. DOE calculates the PBP by dividing the change in purchase cost (normally higher) 

due to a more stringent standard by the change in average annual operating cost 

(normally lower) that results from the standard.

For any given efficiency level, DOE measures the PBP and the change in LCC 

relative to an estimate of the base-case efficiency levels. The base-case estimate reflects 

the market in the absence of amended energy conservation standards, including the 

market for products that exceed the current energy conservation standards.

Equipment price, installation cost, and baseline and standard affect the installed 

cost of the equipment. Transformer loading, load growth, power factor, annual energy use 

and demand, electricity costs, electricity price trends, and maintenance costs affect the 

operating cost. The compliance date of the standard, the discount rate, and the lifetime of 

equipment affect the calculation of the present value of annual operating cost savings 
163

from a proposed standard. Table IV.1 summarizes all the major inputs to the LCC and 

PBP analysis, and whether those inputs were revised for the proposed rule.

Commenting on the preliminary analysis, SC stated that because the assumptions 

DOE uses in its LCC and PBP analyses are not always correct and not specific to an 

individual utility or user, the conclusions are most likely inaccurate for some utilities. 

(SC, No. 22 at p. 4) DOE calculated the LCC and PBP for a representative sample (a 

distribution) of individual transformers. In this manner, DOE’s analysis explicitly 

recognized that there is both variability and uncertainty in its inputs. DOE used Monte 

Carlo simulations to model the distributions of inputs. The Monte Carlo process 

statistically captures input variability and distribution without testing all possible input 

combinations. Some atypical situations may not be captured in the analysis, but DOE 

believes the analysis captures an adequate range of situations in which transformers 

operate.

Table IV.1 Key Inputs for the LCC and PBP Analyses 

Inputs Preliminary Analysis 

Description

Changes for Proposed Rule

Affecting Installed Costs

Equipment price Derived by multiplying 

manufacturer selling price (from 

the engineering analysis) by 

distributor markup and 

contractor markup plus sales tax 

for dry-type transformers. For 

liquid-immersed transformers, 

DOE used manufacturer selling 

price plus small distributor 

markup plus sales tax. Shipping 

costs were included for both 

types of transformers.

Added a case for liquidimmersed transformers that are 

sold directly to utilities.
164

Installation cost Includes a weight-specific 

component, derived from RS 

Means Electrical Cost Data 

2010 and a markup to cover 

installation labor, pole 

replacement costs for design line 

2 and equipment wear and tear.

Updated the installation factors 

to use RS Means Electrical Cost 

Data 2011. Improved the 

modeling of pole replacements 

for design line 2. 

Baseline and 

standard design 

selection

The selection of baseline and 

standard-compliant transformers 

depended on customer behavior. 

For liquid-immersed 

transformers, the fraction of 

purchases evaluated was 75%, 

while for dry-type transformers, 

the fraction of evaluated 

purchases was 50% for small 

capacity medium-voltage and 

80% for large-capacity mediumvoltage.

Adjusted the percent of 

evaluators to: 10% for liquidimmersed transformers, and 2% 

for low-voltage dry-type and 2% 

for medium-voltage dry-type 

transformers.

Affecting Operating Costs

Transformer 

loading

Loading depended on customer 

and transformer characteristics. 

Adjusted loading as a function 

of transformer capacity and 

utility customer density.

Load growth 0.5% per year for liquidimmersed and 0% per year for 

dry-type transformers.

No change.

Power factor Assumed to be unity. No change.

Annual energy 

use and demand

Derived from a statistical hourly 

load simulation for liquidimmersed transformers, and 

estimated from the 1992 and 

1995 Commercial Building 

Energy Consumption Survey 

data for dry-type transformers 

using factors derived from 

hourly load data. Load losses 

varied as the square of the load 

and were equal to rated load 

losses at 100% loading.

No change.

Electricity costs Derived from tariff-based and 

hourly based electricity prices. 

Capacity costs provided extra 

value for reducing losses at 

peak. 

No change.

Electricity price 

trend

Obtained from Annual Energy 

Outlook 2010 (AEO2010).

Updated to Annual Energy 

Outlook 2011 (AEO 2011)
165

Maintenance 

cost

Annual maintenance cost did not 

vary as a function of efficiency.

No change.

Compliance date Assumed to be 2016. No change.

Discount rates Mean real discount rates ranged 

from 4.0% for owners of polemounted, liquid-immersed 

transformers to 5.1% for drytype transformer owners.

The mean real discount rates 

were adjusted to 3.7% for 

owners of liquid-immersed 

transformers and 4.6% for drytype transformers.

Lifetime Distribution of lifetimes, with 

mean lifetime for both liquid 

and dry-type transformers 

assumed to be 32 years.

No change.

The following sections contain brief discussions of comments on the inputs and key 

assumptions of DOE’s LCC analysis and explain how DOE took these comments into 

consideration.

1. Modeling Transformer Purchase Decision

The LCC spreadsheet uses a purchase-decision model that specifies which of the 

hundreds of designs in the engineering database are likely to be selected by transformer 

purchasers to meet a given efficiency level. The engineering analysis yielded a costefficiency relationship in the form of manufacturer selling prices, no-load losses, and load 

losses for a wide range of realistic transformer designs. This set of data provides the LCC 

model with a distribution of transformer design choices. 

DOE used an approach that focuses on the selection criteria customers are known to 

use when purchasing transformers. Those criteria include first costs, as well as what is 

known in the transformer industry as total owning cost (TOC). The TOC method 
166

combines first costs with the cost of losses. Purchasers of distribution transformers, 

especially in the utility sector, have long used the TOC method to determine which 

transformers to purchase. DOE refers to purchasers who use the TOC method as 

evaluators.

The utility industry developed TOC evaluation as an easy-to-use tool to reflect the 

unique financial environment faced by each transformer purchaser. To express variation 

in such factors as the cost of electric energy, and capacity and financing costs, the utility 

industry developed a range of evaluation factors, called A and B values, to use in their 

calculations. A and B are the equivalent first costs of the no-load and load losses (in 

$/watt), respectively. 

In the preliminary analysis, DOE assumed that 75 percent of liquid-immersed 

transformers are purchased using TOC evaluation. DOE assumed that 25 percent of lowvoltage dry-type transformers are purchased using TOC evaluation. For medium-voltage 

dry-type transformers, DOE assumed that 50 percent of smaller capacity units are 

purchased with TOC evaluation and that 85 percent of larger capacity units are purchased 

using TOC evaluation.

Several stakeholders commented on DOE’s estimate of the share of purchasers who 

make purchase decisions based on TOC. FPT said that DOE significantly overstated the 

percentage of evaluators for dry-type distribution transformers. They estimated there are 

0 percent to 1 percent evaluators for low-voltage dry-type, about 10 percent for medium-
167

voltage dry-type, and about 20 percent for high-capacity dry-type distribution 

transformers. (FPT, No. 27 at p. 4) ABB agreed that DOE overestimated the number of 

evaluators. They estimated that evaluators represent less than 1 percent for low-voltage 

dry-type and small medium-voltage dry-type, and less than 5 percent for large mediumvoltage dry-type. (ABB, No. 14 at p. 19) Other stakeholders agreed that DOE’s estimates 

of evaluators are too high. (EEI, No. 29 at p. 8; ASAP, Public Meeting Transcript, No. 34 

at p. 197) NEMA commented that the percent of evaluators seems high for some product 

lines, and recommended that DOE obtain information from individual manufacturers and 

end-users, or examine shipments data to determine evaluators. (NEMA, No. 13 at p. 8) 

ASAP et al. recommended that the DOE survey enough users and suppliers to develop a 

better estimate of the percentage of units purchased in 2010 that had significantly higher 

efficiency than the minimum standard. (Joint Comments ASAP, ACEEE and NRDC, No. 

28 at p. 4)

Conducting a representative survey of users or manufacturers is not possible within 

the scope of the present rulemaking. For the NOPR analysis, DOE revised the evaluation 

rates, based on the available data and stakeholder comments. DOE revised its evaluation 

rates as follows: 10 percent for liquid-immersed, 2 percent for low-voltage, and 2 percent 

for medium-voltage dry-type transformers. The transformer selection approach is 

discussed in detail in chapter 8 of the NOPR TSD.

FPT stated that only utilities really evaluate based on A and B factors, so another 

method needs to be used to analyze other types of customers. FPT recommended that 
168

DOE base its analysis of industrial and commercial customers on PBP criteria. (FPT, No. 

27 at p. 5) DOE effectively bases its analysis on PBP; the results are converted to 

equivalent A and B factors so that the same model structure can be used in all the 

spreadsheets.

HI stated that fewer customers will evaluate their purchases when DOE mandates 

higher efficiency levels, which would result in purchase of transformers with less than 

optimum efficiency for their application. (HI, No. 23 at p. 9) DOE acknowledges that 

evaluation rates may vary depending on the standard for a given design line. Because 

DOE has no basis for estimating this phenomenon, however, it used the same evaluation 

rates for each of the considered CSLs.

2. Inputs Affecting Installed Cost

a. Equipment Costs

In the LCC and PBP analysis, the equipment costs faced by distribution 

transformer purchasers are derived from the MSPs estimated in the engineering analysis 

and the overall markups estimated in the markups analysis.

Several stakeholders recommended that DOE lower its estimate of transformer 

selling prices. Based on its Internet review of selling prices, Metglas said the prices DOE

generated are too high. (MET, Public Meeting Transcript, No. 34 at p. 97) PG&E and 

SCE suggested that DOE calibrate its prices against market data and exclude the cost of 

any additional features from the price estimates. (Joint Comments PG&E and SCE, No. 

32 at p. 2) ASAP, ACEEE and NRDC agreed that DOE’s estimated selling prices are too 
169

high, and recommended that DOE adjust its estimates based on market research, and then 

apply an adjustment factor to bring final transformer selling prices in line with observed 

prices. (Joint Comments ASAP, ACEEE and NRDC, No. 28 at pp. 1-2)

For the NOPR analysis, DOE reviewed bid documents on the Internet after the 

current standards took effect in 2010 and found a wide range of prices. DOE also 

received confidential data from NEEA on utility transformer purchases that showed a 

wide range of prices. The data did not clearly indicate that DOE’s estimated customer 

prices are too high. DOE notes that the inclusion of a new distribution channel for liquid 

results in a lower average markup and thus lower average customer price for these 

products.

EEI stated that DOE should consider transformer pricing data from 2006 onward, 

because that period reflects the increasing global demand for distribution transformers as 

well as the increase in commodity costs for key transformer components. EEI asserted 

that transformer prices have not declined, but rather increased, compared to the rate of 

inflation. (EEI, No. 29 at pp. 2-4) 

To forecast a price trend for the NOPR, DOE derived an inflation-adjusted index 

of the PPI for electric power and specialty transformer manufacturing over 1967-2010. 

These data show a long-term decline from 1975 to 2003, and then a steep increase since 

then. DOE believes that there is considerable uncertainty as to whether the recent trend 

has peaked, and would be followed by a return to the previous long-term declining trend, 
170

or whether the recent trend represents the beginning of a long-term rising trend due to 

global demand for distribution transformers and rising commodity costs for key 

transformer components. Given the uncertainty, DOE has chosen to use constant prices 

(2010 levels) for both its LCC and PBP analysis and the NIA. For the NIA, DOE also 

analyzed the sensitivity of results to alternative transformer price forecasts. DOE 

developed one forecast in which prices decline after 2010, and one in which prices rise. 

Appendix 10-C of the NOPR TSD describes the historic data and the derivation of the 

default and alternative price forecasts. 

DOE requests comments on the most appropriate trend to use for real transformer 

prices, both in the short run (to 2016) and the long run (2016-2045). 

b. Installation Costs

Higher efficiency distribution transformers tend to be larger and heavier than less 

efficient designs. In the preliminary analysis, DOE included the increased cost of 

installing larger, heavier transformers as a component of the first cost of more efficient 

transformers. DOE presented the installation cost model and solicited comment from 

stakeholders. 

Commenting on the preliminary analysis, several stakeholders stated that DOE 

should revise its assumption that 25 percent of pole-mounted liquid-immersed 

transformers greater than 1,000 pounds will require an additional $2,000 cost for pole 

change-out. (Joint Comments PG&E and SCE, No. 32 at p. 2; Joint Comments ASAP, 

ACEEE and NRDC, No. 28 at p. 2-3; NEEA, No. 11 at p. 8) The above comments reflect 
171

a misunderstanding of DOE’s preliminary analysis. The 25 percent referred to in the 

comments was the maximum pole change-out fraction in the algorithm DOE used to 

estimate when change-outs would be required when the weight of the transformer 

exceeds 1,000 pounds. 

EEI noted that several of its members expressed concern that more efficient liquidimmersed transformers would have much higher weights, which would increase costs in 

terms of installation and pole structural integrity for retrofits of existing pole-mounted 

transformers. (EEI, No. 29 at p. 2) APPA commented that DOE must adequately account 

for the costs of pole replacements due to larger transformers. (APPA, No. 21 at p. 2) SC 

stated that pole change-outs may be necessary when transformers are replaced because 

larger diameter poles will be needed to support transformer weight increases, and that 

larger diameter poles may be required with new transformer installations. (SC, No. 22 at 

p. 3) ComEd commented that for pole-mounted transformers, an increase in transformer 

weight may generate an increase in the required pole class to sustain the load. (ComEd,

No. 24 at p. 1) PP agreed that additional transformer weight could make pole-mounting 

difficult. (PP, No. 19 at p. 1) NRECA and T&DEC stated that the added cost of replacing 

utility poles is especially burdensome for rural electric cooperatives. (Joint Comments 

NRECA and T&DEC, No. 31 and 36 at pp. 1-2)

Other stakeholders stated that standards that result in heavier transformers would 

not necessarily require pole change-outs. ASAP et al. stated that increased weight due to 

higher efficiency will not require pole change-outs. They noted that the primary 
172

determining factor in selecting pole size is the horizontal load, not the vertical load, 

which is affected by the transformer weight. (Joint Comments ASAP, ACEEE and 

NRDC, No. 28 at p. 2-3) PG&E and SCE stated that replacement of the pole (or pad) is 

more a function of transformer upsizing than of increased size due to efficiency 

improvement, adding that when replacing in-kind utility transformers, the rate of pole 

change-out due to increased size and weight of higher-efficiency improvements is very 

low. They also noted that for new construction, pole change-out is unnecessary because 

there is no existing pole to change out. (Joint Comments PG&E and SCE, No. 32 at p. 2)

In general, as transformers are redesigned to reach higher efficiency, the weight 

and size also increase. The degree of weight increase depends on how the design is 

modified to improve efficiency. For pole-mounted transformers, represented by design 

line (DL) 2, the increased weight may lead to situations where the pole needs to be 

replaced to support the additional weight of the transformer. This in turn leads to an 

increase in the installation cost. To account for this effect in the analysis, three steps are 

needed:

The first step is to determine whether the pole needs to be changed. This depends 

on the weight of the transformer in the base case compared to the weight of the 

transformer under a proposed efficiency level, and on assumptions about the load-bearing 

capacity of the pole. In the LCC calculation, it is assumed that a pole change-out will 

only be necessary if the weight increase is larger than 15 percent and greater than 150 lbs 

of the weight of the baseline unit. Utility poles are primarily made of wood. Both ANSI 
173

and NESC provide guidelines on how to estimate the strength of a pole based on the tree 

species, pole circumference and other factors. Natural variability in wood growth leads to 

a high degree of variability in strength values across a given pole class. Thus, NESC also 

provides guidelines on reliability, which result in an acceptable probability that a given 

pole will exceed the minimal required design strength. Because poles are sized to cope 

with large wind stresses and potential accumulation of snow and ice, this results in “oversizing” of the pole relative to the load by a factor of two to four. Because of this “oversizing” DOE limited the total fraction of pole replacements to 25 percent of the total 

population.

The second step is to determine the cost of a pole change-out. Specific examples 

of pole change-out costs were submitted by the sub-committee. These examples were 

consistent with data taken from the RSMeans Building Construction Cost database. 

Based on this information, a triangular distribution was used to estimate pole change-out 

costs, with a lower limit at $2,025 and an upper limit at $5,999. Utility poles have a finite 

life-time, so that pole change-out due to increased transformer weight should be counted 

as an early replacement of the pole; i.e. it is not correct to attribute the full cost of pole 

replacement to the transformer purchase. Equivalently, if a pole is changed out when a 

transformer is replaced, it will have a longer lifetime relative to the pole it replaces, 

which offsets some of the cost of the pole installation. To account for this affect, pole 

installation costs are multiplied by a factor n/pole-lifetime, which approximately 
174

represents the value of the additional years of life. The parameter n is chosen from a flat 

distribution between 1 and the pole lifetime, which is assumed to be 30 years.29

PHI noted that if a pole-mount transformer exceeds 900 pounds, they are required 

to have two crews for the replacement, a heavy-duty rigger and traffic control crew, 

adding to the expense of the installation. (PHI, No. 26 at p. 1) DOE’s analysis accounts 

for increase in installation labor costs as transformer weight increases and is described in 

detail in chapter 6 of the NOPR TSD.

Regarding pad-mounted transformers, ComEd commented that new standards 

could require that the pads for some pad-mounted transformers receive foundation 

upgrades to accommodate the increased size and weight, which might require that 

generators be deployed to maintain customer services during the upgrade. (ComEd, No. 

24 at p. 3) APPA also stated that DOE must adequately account for the costs of pad 

mount replacements due to larger transformers. (APPA, No. 21 at p. 2) HI noted that 

symmetric core technology could affect installation practices because the core design has 

a triangular footprint that requires a much deeper pad to accommodate the deeper tanks. 

(HI, No. 23 at p. 3) At present, DOE’s model does not include any additional costs that 

may be required for pad-mounted transformers at higher efficiency levels. DOE requests 

data on the weight and size thresholds that might be expected to trigger pad mount 

upgrades and on approximate costs of a typical upgrade.

 

29 As the LCC represents the costs associated with purchase of a single transformer, to account for multiple 

transformers mounted on a single pole, the pole cost should also be divided by a factor representing the 

average number of transformers per pole. No data is currently available on the fraction of poles that have 

more than one transformer, so this factor is not included.
175

DOE received comments on the affect that that symmetric core technology would 

have on installation costs. NRECA described theoretical evaluation that indicates weight 

and labor costs would increase for symmetric core technology. (NRECA, No. 31 and 36 

at p. 3) The engineering analysis estimated the weight of transformers that utilize 

symmetric core technology. As mentioned above, the LCC and PBP analysis accounts for 

increase in installation labor costs as transformer weight increases.

EEI noted that several of its members expressed concern that more efficient 

transformers will be larger in size (height, width, and depth), which will have an impact 

for all retrofit situations, especially in underground vaults, which in many urban areas 

cannot be physically expanded, or can only be expanded at a great cost in terms of 

materials, labor, and street closures. (EEI, No. 29 at p. 2) Because vault-installed 

transformers account for a small fraction of transformer installations, and mainly affect 

urban utilities that have underground distribution systems, DOE chose to analyze these 

transformers as part of the customer subgroup analysis. This analysis, and the approach 

DOE used to account for installing larger-volume transformers, is described in section 

IV.H.

3. Inputs Affecting Operating Costs

a. Transformer Loading

DOE’s assumptions about loading of different types of transformers are described 

in section IV.E. DOE generally estimated the loading on larger transformers is greater 
176

than the loading on smaller transformers. 

b. Load Growth Trends

The LCC takes into account the projected operating costs for distribution 

transformers many years into the future. This projection requires an estimate of how the 

electrical load on transformers will change over time. In the preliminary analysis, for drytype transformers, DOE assumed no load growth, while for liquid-immersed transformers 

DOE used as the default scenario a one-percent-per-year load growth. It applied the load 

growth factor to each transformer beginning in 2016. To explore the LCC sensitivity to 

variations in load growth, DOE included in the model the ability to examine scenarios 

with zero percent, one percent, and two percent load growth. 

DOE did not receive comments regarding its load growth assumptions, and it 

retained the assumptions described above for the NOPR analysis.

c. Electricity Costs

DOE needed estimates of electricity prices and costs to place a value on 

transformer losses for the LCC calculation. As discussed in section IV.E, DOE created 

two sets of electricity prices to estimate annual energy expenses for its analysis: an 

hourly-based estimate of wholesale electricity costs for the liquid-immersed transformer 

market, and a tariff-based estimate for the dry-type transformer market. IV.E also 

presents the comments received on this topic and DOE’s response. 
177

DOE received a few comments regarding electricity cost estimation. Electricity cost 

estimates are discussed in detail in chapter 7 of the NOPR TSD.

d. Electricity Price Trends

For the relative change in electricity prices in future years, DOE relied on price 

forecasts from the Energy Information Administration (EIA) Annual Energy Outlook

(AEO). For the preliminary analysis, DOE used price forecasts from AEO 2011. 

PG&E and SCE considered DOE's forecasted electricity prices in the preliminary 

analysis to be low. They recommended that DOE revisit their electric price forecast to 

ensure it accurately reflects historical trends and potential future global scenarios that 

may drive electricity prices higher than otherwise anticipated. (Joint Comments PG&E 

and SCE, No. 32 at p. 2) For the proposed rule, DOE updated the price forecast to AEO 

2011 and examined the sensitivity of analysis results to changes in electricity price 

trends. Appendix 8-D of the NOPR TSD provides a sensitivity analysis for equipment of 

each product group with the largest market shares, for liquid-immersed transformers 

design lines 1 and 5 are examined, for low-voltage dry-type transformers design line 7 is 

examined, and for medium-voltage dry-type transformers design line 12. These analysis 

shows that the effect of changes in electricity price trends, compared to changes in other 

analysis inputs, is relatively small. DOE evaluated a variety of potential sensitivities, and 

the robustness of analysis results with respect to the full range of sensitivities, in 

weighing the potential benefits and burdens of the proposed rule. 
178

e. Standards Compliance Date

DOE calculated customer impacts as if each new distribution transformer purchase 

occurs in the year manufacturers must comply with the standard. For the preliminary 

analysis, this was assumed to be January 1, 2016. 

Several stakeholders commented on the compliance date for new efficiency 

standards for distribution transformers. Howard Industries stated that the feasibility of 

the proposed date depends on the magnitude of changes in the new rulemaking and the 

supply chain limitations that will occur once the economy recovers. They estimated that 

they will need until the January 1, 2016, date to comply with new efficiency levels for 

liquid-immersed distribution transformers. (HI, No. 23 at p. 1) EEI agreed that the 

compliance date for any new standards should be no sooner than January 1, 2016. (EEI, 

No. 29 at p. 4) Schneider Electric commented that the previous standard for low-voltage 

dry-type transformers was implemented within 16 months because many manufacturers 

already were producing enough compliant transformers that it was a stock product. It 

noted that circumstances are not the same for the new standard levels, and a longer period 

should be allowed for compliance. (SE, No. 18 at p. 5) (NEEA agreed with the current 

compliance date, but said that if the final rule is not stringent, DOE should consider an 

earlier date and/or should examine the interaction between stringency of standards with 

the number of models already in production. (NEEA, No. 11 at p. 10)

As discussed in section II.A, if DOE finds that amended standards for distribution 

transformers are warranted, DOE must publish a final rule containing such amended 
179

standards by October 1, 2012. The statutorily-required compliance date of January 1, 

2016, provides manufacturers with over three years to prepare for manufacturing 

distribution transformers to the new standards. 

f. Discount Rates

The discount rate is the rate at which future expenditures are discounted to estimate 

their present value. DOE employs a two-step approach in calculating discount rates for 

analyzing customer economic impacts. The first step is to assume that the actual customer 

cost of capital approximates the appropriate customer discount rate. The second step is to 

use the use the capital asset pricing model (CAPM) to calculate the equity capital 

component of the customer discount rate. For the preliminary analysis, DOE estimated a 

statistical distribution of commercial customer discount rates that varied by transformer 

type by calculating the cost of capital for the different types of transformer owners.

Commenting on the preliminary analysis, EEI stated that small businesses and 

entities under financial duress likely would face significantly higher effective discount 

rates. (EEI, No. 29 at p. 8) The intent of the LCC analysis is to estimate the economic 

impacts of higher-efficiency transformers over a representative range of customer 

situations. While the discount rates used may not be applicable for all customers, DOE 

believes that they reflect the financial situation of the majority of transformer customers.

More detail regarding DOE’s estimates of commercial customer discount rates is 

provided in chapter 8 of the NOPR TSD. 
180

g. Lifetime

DOE defined distribution transformer life as the age at which the transformer retires 

from service. For the preliminary analysis, DOE assumed, based on a report by Oak 

Ridge National Laboratory,30 that the average life of distribution transformers is 32 years. 

This lifetime assumption includes a constant failure rate of 0.5 percent/year due to 

lightning and other random failures unrelated to transformer age and an additional 

corrosive failure rate of 0.5 percent/year starting at year 15. 

Commenting on this assumption, HVOLT and PHI suggested that DOE use a 

lifetime of 30 years. (HVOLT, Public Meeting Transcript, No. 34 at p. 126; PHI, Public 

Meeting Transcript, No. 34 at p. 210) DOE did not receive any additional data that 

provide a basis for changing its 32-year assumption on distributor lifetime, so it retained 

the approach used in the preliminary analysis for the NOPR analysis.

h. Base Case Efficiency

To determine an appropriate base case against which to compare various candidate 

standard levels, DOE used the purchase-decision model described in section IV.F.1. For 

the base case, initially transformer purchasers are allowed to choose among the entire 

range of transformers at each design line. 

 

30 Barnes. Determination Analysis of Energy Conservation Standards for Distribution Transformers. 

ORNL-6847. 1996.
181

During the negotiation process, ERAC subcommittee members noted that 

currently there are no transformers using ZDMH as a core material sold in the U.S. 

market. (ABB, Public Meeting Transcript, No. 91 at p. 276) Therefore, DOE screened out 

designs using this material in the base case selection. For higher efficiency levels, the 

LCC analysis samples from all design options identified in the engineering analysis. 

Subcommittee members provided data on market share as a function of efficiency. 

For some design lines, the lower boundary of the price-efficiency curve produced in the 

engineering analysis is quite flat, so that the choice algorithm in the LCC analysis 

showed units being selected in the base case with efficiencies substantially higher than 

the current DOE minimum standard. DOE modified its approach so that the fraction of 

units selected in the base case at different efficiency levels is consistent with the provided 

market share data.

G. National Impact Analysis—National Energy Savings and Net Present Value Analysis

DOE’s NIA assessed the national energy savings (NES) and the national NPV of 

total customer costs and savings that would be expected to result from amended standards 

at specific efficiency levels. (“Customer” refers to purchasers of the product being 

regulated.)

To make the analysis more accessible and transparent to all interested parties, 

DOE used an MS Excel spreadsheet model to calculate the energy savings and the 

national customer costs and savings from each TSL. DOE understands that MS Excel is 
182

the most widely used spreadsheet calculation tool in the United States and there is general 

familiarity with its basic features. Thus, DOE’s use of MS Excel as the basis for the 

spreadsheet models provides interested parties with access to the models within a familiar 

context. In addition, the TSD and other documentation that DOE provides during the 

rulemaking help explain the models and how to use them, and interested parties can 

review DOE’s analyses by changing various input quantities within the spreadsheet. 

DOE used the NIA spreadsheet to calculate the NES and NPV, based on the 

annual energy consumption and total installed cost data from the energy use 

characterization and the LCC analysis. DOE forecasted the energy savings, energy cost 

savings, product costs, and NPV of customer benefits for each product class for products 

sold from 2016 through 2045. The forecasts provided annual and cumulative values for 

all four output parameters. In addition, DOE analyzed scenarios that used inputs from the 

AEO 2011 Low Economic Growth and High Economic Growth cases. These cases have 

higher and lower energy price trends compared to the Reference case. NIA results based 

on these cases are presented in appendix 10-B of the NOPR TSD.

DOE evaluated the impacts of amended standards for distribution transformers by 

comparing base-case projections with standards-case projections. The base-case 

projections characterize energy use and customer costs for each product class in the 

absence of amended energy conservation standards. DOE compared these projections 

with projections characterizing the market for each product class if DOE were to adopt 

amended standards at specific energy efficiency levels (i.e., the standards cases) for that 
183

class.

The tables below summarize all the major NOPR inputs to the shipments analysis 

and the NIA, and whether those inputs were revised for the proposed rule. 

Table IV.2 Inputs for the Shipments Analysis

Input Preliminary Analysis Description Changes for Proposed Rule

Shipments data Third-party expert (HVOLT) for 2009. No change.

Shipments forecast 2016-2045: Based on AEO 2010. Updated to AEO 2011

Dry-type/liquidimmersed market sharesBased on EIA’s electricity sales data and 

AEO2010.

Updated to AEO 2011

Regular replacement 

market

Based on a survival function constructed 

from a Weibull distribution function 

normalized to produce a 32-year mean 

lifetime. Source: ORNL 6804/R1, The 

Feasibility of Replacing or Upgrading Utility 

Distribution Transformers During Routine 

Maintenance, page D-1.

No change.

Elasticities, liquidimmersedFor liquid-immersed transformers:

 • Low: 0.00

 • Medium: -0.04

 • High: -0.20

No change.

Elasticities, dry-type For dry-type transformers:

• Low: 0.00

• Medium: -0.02

• High: -0.20

No change.
184

Table IV.3 Inputs for the National Impact Analysis

Input Preliminary Analysis Description Changes for Proposed Rule

Shipments Annual shipments from shipments model. No change.

Compliance date of 

standard

January 1, 2016 No change.

Base case efficiencies Constant efficiency through 2044. Equal to 

weighted-average efficiency in 2016.

No change.

Standards case 

efficiencies

Constant efficiency at the specified standard level 

from 2016 to 2044.

No change.

Annual energy 

consumption per unit

Average rated transformer losses are obtained 

from the LCC analysis, and are then scaled for 

different size categories, weighted by size market 

share, and adjusted for transformer loading (also 

obtained from the LCC analysis).

No change.

Total installed cost per 

unit

Weighted-average values as a function of 

efficiency level (from LCC analysis).

No change.

Electricity expense per 

unit

Energy and capacity savings for the two types of 

transformer losses are each multiplied by the 

corresponding average marginal costs for capacity 

and energy, respectively, for the two types of 

losses (marginal costs are from the LCC analysis).

No change.

Escalation of 

electricity prices

AEO 2010 forecasts (to 2035) and extrapolation 

for 2044 and beyond.

Updated the escalation of 

electricity prices forecast 

using AEO 2011.

Electricity site-tosource conversionA time series conversion factor; includes electric 

generation, transmission, and distribution losses. 

Conversion varies yearly and is generated by 

DOE/EIA’s National Energy Modeling System 

(NEMS) program. 

Updated conversion factors 

from NEMS.

Discount rates 3% and 7% real. No change.

Present year Equipment and operating costs are discounted to 

the year of equipment price data, 2010. 

No change.

1. Shipments

DOE constructed a simplified forecast of transformer shipments for the base case 

by assuming that long-term growth in transformer shipments will be driven by long-term 

growth in electricity consumption. The detailed dynamics of transformer shipments is 
185

highly complex. This complexity can be seen in the fluctuations in the total quantity of 

transformers manufactured as expressed by the U.S. Department of Commerce, Bureau of 

Economic Analysis (BEA), transformer quantity index. DOE examined the possibility of 

modeling the fluctuations in transformers shipped using a bottom-up model where the 

shipments are triggered by retirements and new capacity additions, but found that there 

were not sufficient data to calibrate model parameters within an acceptable margin of 

error. Hence, DOE developed the transformer shipments forecast assuming that annual 

transformer shipments growth is equal to forecasted growth in electricity consumption as 

given by the AEO 2011 forecast up to the year 2035. For the years from 2036 to 2045, 

DOE extrapolated the AEO 2011 forecast with the growth rate of electricity consumption 

from 2025 to 2035. The model starts with an estimate of the overall growth in 

transformer capacity and then estimates shipments for particular design lines and 

transformer sizes using estimates of the recent market shares for different design and size 

categories. Chapter 9 provides a detailed description of how DOE conducted its 

shipments forecasts.

EEI suggested that the shipment projections are overly optimistic and should be 

closer to a flat line of growth. (EEI, No. 29 at p. 9) The historical shipments data based 

on the BEA’s quantity index data for power and distribution transformers show a 

relatively flat trend between the late 1970s and 2007. The data show a sharp increase in 

2008, a higher-than-average level in 2009, and a steep plunge in 2010. This recent trend 

apparently reflects purchasers stocking up on transformers in advance of the standards 

that took effect in 2010. Given this unusual market situation, DOE believes that holding 
186

future shipments at the 2010 level would be unrealistic. For the NOPR, DOE’s base case 

forecast shows shipments gradually returning to the level of 2008 by the end of the 

forecast period.

Commenting on the preliminary analysis, NEMA noted that in some markets, 

liquid-immersed and medium-voltage dry-type transformers compete against one another, 

and for some applications, liquid-immersed units have additional costs for liquid 

containment or fire protection. NEMA encouraged DOE to consider whether higher 

prices for liquid-immersed units due to standards might cause users to shift to dry-type 

transformers. (NEMA, No. 13 at p. 7) ABB said that they have not observed a shift in 

market share between equipment classes as a result of current regulations, but they asked 

that any new regulation be analyzed as to its potential impact in shifting demand between 

equipment classes. (ABB, No. 14 at p. 19)

In principle, the appropriate way to address the probability that a customer 

switches to a different product class in response to an increase in the price of a specific 

product is to estimate the cross-price elasticity of demand between competing classes. To 

estimate this elasticity, DOE would need historical data on the shipments and price of the 

liquid-immersed and medium-voltage dry-type transformers. The shipments data at that 

level of disaggregation is available only for two years (2001 and 2009), which is not 

sufficient to support the estimation of cross-price elasticity of liquid-immersed 

distribution transformers. Thus, for the NOPR DOE did not estimate potential switching 

from liquid-immersed to dry-type transformers. DOE requests data that would allow it to 

estimate such switching for the final rule.
187

Some stakeholders expressed concern that higher prices due to new standards will 

increase refurbishing of transformers, which would reduce purchase and shipments of 

new transformers. (EEI, Public Meeting Transcript, No. 34 at p. 249; NEEA, No. 11 at p. 

9; HI, No. 23 at p. 13) NEMA commented that the analysis should consider the replace 

versus refurbish decision for each considered standard level. (NEMA, No. 13 at pp. 7, 9) 

ABB commented that it has not observed increased refurbishing with the current 

regulation since January 1, 2010, but it believes new regulations may well increase the 

use of rebuilt transformers. (ABB, No. 14 at p. 19) NRECA said that some of its 

members are already making greater efforts to maintain and refurbish older units rather 

than purchase costlier new, more efficient units. (NRECA, No. 31 and 36 at p. 4)

To capture the customer response to transformer price increase, DOE estimated 

the customer price elasticity of demand. Although the general trend of transformer 

purchases is determined by increases in generation, utilities conceivably exercise some 

discretion in how much transformer capacity to buy – the amount of “over-capacity” to 

purchase. The ratio of transformer capacity to load varies according to economic 

considerations, namely the price of transformers, and the income generated by each unit 

of capacity purchased (essentially the price of electricity). When transformer costs are

low, utilities may increase their investment in capacity in order to economically meet 

future increases in demand, and they will be more likely to do so when returns, indicated 

by electricity prices, are high. Any decrease in sales induced by an increase in the price of 

distribution transformers is due to a decrease in this ratio. In DOE’s estimation of the 
188

purchase price elasticity, it used a logit function to characterize the utilities' response to 

the price of a unit capacity of transformer. The functional form captures what can be 

called an average price elasticity of demand with a term to capture the estimation error, 

which accounts for all other effects. Technically, the price elasticity should therefore 

account for any decrease in the shipments due to a decision on the customer's part to 

refurbish transformers as opposed to purchasing a new unit. DOE’s approach is described 

in chapter 9 of the NOPR TSD.

During the negotiated rulemaking, DOE heard from many stakeholders that there 

is a growing potential for utilities to repair failed transformers and return them to service 

for less than the cost of a purchasing a new transformer. Some manufacturers commented 

that if the cost of a new transformer increased by 20 percent utilities may refurbish rather 

than purchase new equipment to replace failed equipment. (ABB, Public Meeting 

Transcript, No. 95 at p. 100) DOE received a market potential study from AK Steel 

stating that the replacement market could represent up to 80 percent of the liquidimmersed market over the next 15 years and that utilities purchasing replacement 

equipment would consider refurbishing failed units instead of purchasing new equipment. 

(AK, Public Meeting Transcript, No. 95 at p. 101) DOE received comment from 

committee members that a small number of municipal utilities were already purchasing 

refurbished equipment as part of their normal day-to-day operations. (APPA, Public 

Meeting Transcript, No. 95 at p. 169) On the other hand, PG&E stated that the risks 

involved with using refurbished equipment (e.g., shorter lifetimes, shorter warrantee, 

inconsistent equipment quality) give this option limited appeal to larger investor-owned 
189

utilities. (PG&E, Public Meeting Transcript, No. 95 at p. 172) DOE acknowledges that 

uncertainty exists regarding the issue of refurbishing vs. replacement. However, it did not 

receive data that provided a reasonable basis for changing the analysis used for the 

NOPR. DOE intends to further investigate this issue for the final rule. Toward that end, 

DOE request further information that would allow it to quantify the likely extent of 

refurbishment at different potential standard levels.

2. Efficiency Trends

DOE did not include any base case efficiency trends in its shipments and national 

energy savings models. AEO forecasts show no long term trend in transmission and 

distribution losses. DOE estimates that the probability of an increasing efficiency trend 

and the probability of a decreasing efficiency trend are approximately equal, and 

therefore used a zero trend in base case efficiency. DOE seeks further comment on its 

decision to use frozen efficiencies for the analysis period. Specifically, DOE would like 

comments on additional sources of data on trends in efficiency improvement.

3. Equipment Price Forecast

As noted in section IV.F.2, DOE assumed no change in transformer prices over 

the 2016-2045 period. In addition, DOE conducted sensitivity analysis using alternative 

price trends. Based on PPI data for electric power and specialty transformer 

manufacturing, DOE developed one forecast in which prices decline after 2010, and one 

in which prices rise. These price trends, and the NPV results from the associated 

sensitivity cases, are described in Appendix 10-C of the NOPR TSD.
190

4. Discount Rate

In calculating the NPV, DOE multiplies the net savings in future years by a 

discount factor to determine their present value. For today’s NOPR, DOE estimated the 

NPV of appliance consumer benefits using both a 3-percent and a 7-percent real discount 

rate. DOE uses these discount rates in accordance with guidance provided by the Office 

of Management and Budget (OMB) to Federal agencies on the development of regulatory 

analysis.31 The discount rates for the determination of NPV are in contrast to the discount 

rates used in the LCC analysis, which are designed to reflect a consumer’s perspective. 

The 7-percent real value is an estimate of the average before-tax rate of return to private 

capital in the U.S. economy. The 3-percent real value represents the “social rate of time 

preference,” which is the rate at which society discounts future consumption flows to 

their present value.

5. Energy Used in Manufacturing Transformers

FPT stated that DOE should account for the additional energy needed to produce 

more efficient transformers, such as energy use associated with working with highergrade core steels. (FPT, No. 27 at p. 4) HI and SC made similar comments. (HI, No. 23 at 

p. 7; SC, No. 22 at p. 3) In response, DOE notes that EPCA directs DOE to consider the 

total projected amount of energy, or as applicable, water, savings likely to result directly 

from the imposition of the standard when determining whether a standard is economically 

justified. (42 U.S.C. 6295(o)(2)(B)(i)(III)) DOE interprets this to include energy used in 

 

31 OMB Circular A-4 (Sept. 17, 2003), section E, “Identifying and Measuring Benefits and Costs. Available 

at: www.whitehouse.gov/omb/memoranda/m03-21.html.
191

the generation, transmission, and distribution of fuels used by appliances or equipment. 

In addition, DOE is evaluating the full-fuel-cycle measure, which includes the energy 

consumed in extracting, processing, and transporting primary fuels. DOE’s current 

accounting of primary energy savings and the full-fuel-cycle measure are directly linked 

to the energy used by appliances or equipment. DOE believes that energy used in 

manufacturing of appliances or equipment falls outside the boundaries of “directly” as 

intended by EPCA. Thus, DOE did not consider such energy use in the NIA.

H. Customer Subgroup Analysis

In analyzing the potential impacts of new or amended standards, DOE evaluates 

impacts on identifiable groups (i.e., subgroups) of customers that may be 

disproportionately affected by a national standard. For this rulemaking, DOE identified 

purchasers of vault-installed transformers (mainly utilities concentrated in urban areas) as 

subgroups that could be disproportionately affected, and examined the impact of 

proposed standards on these groups using the methodology of the LCC and PBP analysis. 

Kentucky Association of Electric Cooperatives, Inc. (KAEC) stated that rural 

electric cooperatives should be analyzed as a customer subgroup in the LCC subgroup 

analysis because they will face disproportionate costs for any amended efficiency 

standards. KAEC stated that rural electric cooperatives typically are loaded at only 25 

percent, not the 50 percent loading assumed in the test procedure. (KAEC, No. 4 at p. 2) 

DOE’s estimate of average root mean square (RMS) loading for a 50 kVA pad-mounted 

transformer for the national sample is approximately 35 percent. For rural electric 
192

cooperatives DOE used the estimate provided by KAEC to lower the average loading for 

rural customers, as described in section IV.E of this document.

Several interested parties commented that it is important for DOE to take into 

consideration the problem that may arise in installing larger transformers in spaceconstrained situations. HI commented that DOE needs to do more analysis on the size 

constraints for submersible and vault type transformers. (HI, No. 23 at p. 13) ComEd 

stated that for street and building vaults, larger transformers potentially could cause 

severe problems during replacement because of equipment openings, operating 

clearances, and the loading capacity of floors and elevators. It stated that: (1) existing 

building vaults typically have only a few inches of clearance; and (2) larger transformers 

may not be able to be maneuvered through building hallways or may exceed the weight 

limitations of building elevators and floors. It added that although a slightly larger 

transformer would not create a space issue for street/sidewalk vaults, a larger transformer 

may violate certain company operating clearances inside the vault, and possibly be 

deemed a safety issue. (ComEd, No. 24 at p. 2) PHI noted that the existing manholes 

provided for subsurface, subway, and network transformers would have to be enlarged to 

install a larger unit, which requires time and additional costs. (PHI, No. 26 and 37 at p. 1)

For the NOPR, DOE evaluated vault-installed transformers represented by design 

lines 4 and 5 as a customer subgroup. DOE examined the impacts of larger transformer 

volume with regard to costs for vault enlargement. DOE assumed that if the volume of a 

unit in a standard case is larger than the median volume of transformer designs for the 
193

particular design line, a vault modification would be warranted. To estimate the cost, 

DOE compared the difference in volume between the unit selected in the base case 

against the unit selected in the standard case, and applied fixed and variable costs. In the 

2007 final rule, DOE estimated the fixed cost as $1,740 per transformer and the variable 

cost as $26 per transformer cubic foot.32 For today’s notice, these costs were adjusted to 

2010$ using the chained price index for non-residential construction for power and 

communications to $1854 per transformer and $28 per transformer cubic foot. DOE 

considered instances where it may be extremely difficult to modify existing vaults by 

adding a very high vault replacement cost option to the LCC spreadsheet. Under this 

option, the fixed cost is $30,000 and the variable cost is $733 per transformer cubic foot. 

The customer subgroup analysis is discussed in detail in chapter 11 of the NOPR 

TSD.

I. Manufacturer Impact Analysis

1. Overview

DOE performed a manufacturer impact analysis (MIA) to estimate the financial 

impact of amended energy conservation standards on manufacturers of distribution 

transformers and to calculate the impact of such standards on employment and 

manufacturing capacity. The MIA has both quantitative and qualitative aspects. The 

quantitative part of the MIA primarily relies on the Government Regulatory Impact 

Model (GRIM), an industry cash-flow model with inputs specific to this rulemaking. The 

 

32 See section 7.3.5 of the 2007 final rule TSD, available at 

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/pdfs/transformer_fr_tsd/chapter7.

pdf).
194

key GRIM inputs are data on the industry cost structure, product costs, shipments, and 

assumptions about markups and conversion expenditures. The key output is the industry 

net present value (INPV). Different sets of shipment and markup assumptions (scenarios) 

will produce different results. The qualitative part of the MIA addresses factors such as 

product characteristics, impacts on particular sub-groups of firms, and important market 

and product trends. The complete MIA is outlined in Chapter 12 of the NOPR TSD.

DOE conducted the MIA for this rulemaking in three phases. In Phase 1 of the 

MIA, DOE prepared a profile of the distribution transformer industry, which includes a 

top-down cost analysis of manufacturers used to derive preliminary financial inputs for 

the GRIM (e.g., sales general and administration (SG&A) expenses; R&D expenses; and 

tax rates). DOE used public sources of information, including company Securities and 

Exchange Commission (SEC) 10–K filings, Moody’s company data reports, corporate 

annual reports, the U.S. Census Bureau’s Economic Census, and Hoover’s reports.

In Phase 2 of the MIA, DOE prepared an industry cash-flow analysis to quantify 

the impacts of a new energy conservation standard. In general, more stringent energy 

conservation standards can affect manufacturer cash flow in three distinct ways: (1) 

create a need for increased investment, (2) raise production costs per unit, and (3) alter 

revenue due to higher per-unit prices and possible changes in sales volumes.

 

In Phase 3 of the MIA, DOE conducted structured, detailed interviews with a 

representative cross-section of manufacturers. During these interviews, DOE discussed 
195

engineering, manufacturing, procurement, and financial topics to validate assumptions 

used in the GRIM and to identify key issues or concerns. See section IV.I.4 for a 

description of the key issues manufacturers raised during the interviews.

Additionally, in Phase 3, DOE evaluates sub-groups of manufacturers that may be 

disproportionately impacted by standards or that may not be accurately represented by the 

average cost assumptions use to develop the industry cash-flow analysis. For example, 

small manufacturers, niche players, or manufacturers with cost structures that largely 

differ from the industry average could be more negatively affected. 

For the MIA, DOE grouped the cash flow results for design lines made by the same 

sets of manufacturers serving the same markets in order to assess the impacts of amended 

energy conservation standards with more granularity. DOE separately analyzed the 

industries of three transformer ”superclasses”—liquid-immersed, medium-voltage drytype, and low-voltage dry-type—based on differences in the tooling and equipment, 

product designs, customer types, and characteristics of the markets in which they operate. 

The Department considered small manufacturers as a separate subgroup because they 

may be disproportionately affected by standards. DOE applied the small business size 

standards published by the Small Business Administration (SBA) to determine whether a 

company is considered a small business 65 FR 30836, 30848 (May 15, 2000), as 

amended at 65 FR 53533, 53544 (Sept. 5, 2000) and codified at 13 CFR Part 121. To be 

categorized as a small business under NAICS 335311(“Power, Distribution and Specialty 

Transformer Manufacturing”), a distribution transformer manufacturer and its affiliates 

Deleted: the 

Deleted: types—

Comment [A15]: Change recommended by 

OIRA.
196

may employ a maximum of 750 employees. The 750-employee threshold includes all 

employees in a business’s parent company and any other subsidiaries. Based upon this 

classification, DOE identified at least 31 small distribution transformer manufacturers 

that qualify as small businesses. The distribution transformer small manufacturer subgroup is discussed in Chapter 12 of the TSD and in section VI.B.1 of today’s notice.

2. Government Regulatory Impact Model 

DOE uses the GRIM to quantify the standards-induced changes in cash flow that 

result in a higher or lower industry value. The GRIM analysis uses a standard, annual 

cash-flow analysis that incorporates products costs, markups, shipments, and industry 

financial information as inputs, and models changes in costs, investments, and 

manufacturer margins that would result from new and amended energy conservation 

standards. The GRIM spreadsheet uses the inputs to arrive at a series of annual cash 

flows, beginning with the base year of the analysis, 2011, and continuing to 2045. DOE 

calculates INPVs by summing the stream of annual discounted cash flows during this 

period, using a discount rate of 7.4 percent for liquid immersed transformers, 9 percent 

for medium-voltage dry-type transformers, and 11.1 percent for low-voltage dry-type

transformers. The difference in INPV between the base case and a standards case 

represents the financial impact of the amended standard on manufacturers. DOE’s 

discount rate estimate was derived from industry financials and then modified according 

to feedback during manufacturer interviews.

DOE typically presents its estimates of industry impacts by groups of the major 

equipment types served by the same manufacturers. For the distribution transformer 
197

industry, DOE presents its estimates of industry impacts for each superclass. The GRIM 

results are shown in section V.B.2.a. Additional details about the GRIM can be found in 

Chapter 12 of the TSD.

3. GRIM Key Inputs

a. Manufacturer Production Costs

Manufacturing a higher-efficiency product is typically more expensive than 

manufacturing a baseline product. The changes in the MPCs of the analyzed products can 

affect the revenues, gross margins, and cash flow of the industry, making these product 

cost data key GRIM inputs for DOE’s analysis.

During the engineering analysis, DOE used transformer design software to create a 

database of designs spanning a broad range of efficiencies for each of the representative 

units. This design software generated a bill of materials. The software also provided 

information pertaining to the labor necessary to construct the transformer, including the 

number of turns in the windings and core dimensions, including stack height, which 

enabled DOE to estimate per unit labor costs. The Department then applied markups to 

allow for scrap, handling, factory overhead, and non-production costs to estimate the 

manufacturer selling price. 

These designs and their MSPs are subsequently inputted into the LCC customer 

choice model. For each CSL and within each design line, the LCC model uses a Monte 

Carlo analysis and criteria described in section F to select a subset of all the potential 

Deleted: transformer type.
198

designs options (and associated MSPs). This subset is meant to represent those designs 

that would actually be shipped in the market under various standard levels. DOE inputted 

into the GRIM the weighted average cost of the designs selected by the LCC model and 

scaled those MPCs to other selected capacities in each design line’s KVA range. 

b. Base-Case Shipments Forecast

The GRIM estimates manufacturer revenues based on total unit shipment forecasts 

and the distribution of these values by capacity and design line. Changes in sales volumes 

and product mix over time can significantly affect manufacturer finances. For this 

analysis, the GRIM uses the NIA’s annual shipment forecasts from 2011 to 2045, the end 

of the analysis period. See Chapter 9 of the TSD for additional details.

c. Product and Capital Conversion Costs

Amended energy conservation standards will cause manufacturers to incur 

conversion costs to bring their production facilities and product designs into compliance. 

For the MIA, DOE classified these conversion costs into two major groups: (1) product 

conversion costs and (2) capital conversion costs. Product conversion costs are 

investments in research, development, testing, marketing, and other non-capitalized costs 

necessary to make product designs comply with the new or amended energy conservation 

standard. Capital conversion costs are investments in property, plant, and equipment 

necessary to adapt or change existing production facilities such that new product designs 

can be fabricated and assembled.

Several manufacturers commented on the capital and product conversion costs that 
199

would be necessary to meet particular efficiency levels. Power Partners stated that any 

new standards would require additional retooling and investment (Power Partners, Public 

Meeting Transcript, No. 19 at p. 1). Howard Industries commented that DOE should 

consider the full impact of capital investments for higher efficiency designs, such as 

symmetric core designs, which would require large capital investments and patent fees, 

and amorphous core designs, which would require large capital investments for additional 

floor space, laminators, cutters, stackers, encapsulation equipment, and annealing ovens. 

(Howard Industries, Public Meeting Transcript, No. 23 at p. 10-11) Additionally, Federal 

Pacific indicated that manufacturers who do not currently have the experience and 

resources needed to manufacture amorphous cores themselves will have to spend a 

significant amount of money in certifying amorphous core transformers to the IEEE C57 

short circuit requirements if DOE efficiency levels necessitate the use of amorphous steel 

in core production. (Federal Pacific, Public Meeting Transcript, No. 27 at p. 3)

DOE recognizes manufacturers would incur conversion costs to modify their plants 

and equipment to produce higher efficiency distribution transformers. DOE explicitly 

considers these expenditures it in its GRIM analysis; the following describes the 

department’s methodology for estimating potential conversion costs for each TSL.

For capital conversion costs, DOE prepared bottom-up estimates of the costs 

required to meet standards at each TSL for each design line. To do this, DOE used 

equipment cost estimates provided by manufacturers and equipment suppliers, an 

understanding of typical manufacturing processes developed during interviews and in 
200

consultation with subject matter experts, and the properties associated with different core 

and winding materials. Major drivers of capital conversion costs include changes in core 

steel type (and thickness), core weight, core stack height, and core construction 

techniques, all of which are interdependent and can vary by efficiency level. DOE uses 

estimates of the core steel quantities needed by steel type for each TSL, and then most 

likely core construction techniques, to model the additional equipment the industry would 

need to meet the efficiencies embodied by each TSL. 

For the liquid-immersed sector, conversion costs are entirely driven at each TSL by 

the need of the industry to expand capacity for amorphous production. Based on 

interviews with manufacturers and equipment suppliers, DOE assumed an amorphous 

production line with 1,200 tons of annual capacity would cost $950,000. This figure

includes costs associated with an annealing oven, core cutting machine, lacing tables and 

other miscellaneous equipment. As the increasing stringency of the TSLs drive 

amorphous adoption, conversion costs increase. 

For the low-voltage and medium-voltage dry-type market, DOE took two 

approaches to estimate capital conversion costs. First, DOE used an industry feedback 

approach. The Department interviewed manufacturers and industry experts about the 

capital conversion costs for design lines at increasing efficiency levels, aggregated the 

conversion cost feedback, and market-shared weighted the feedback to determine likely 

industry capital conversion costs. For the second approach, DOE performed a bottoms-up 

analysis of conversion costs based on core steel selections forecasted by the LCC and 

Deleted: it aggregated estimates gathered during 

manufacturer interviews and discussions with 

Deleted: scaled those estimates to represent the 

Deleted: share of those not interviewed or those 

unable to estimate

Deleted: interviewed
201

production equipment costs (a more detailed description of the analysis can be found in 

chapter 12 of the TSD). The two approaches yielded results with similar orders of 

magnitude. For those levels that do not require amorphous wound cores, the capital costs 

are largely driven by the need to modify existing or purchase new core cutting machines 

and associated equipment and tooling. This need arises as increasingly stringent TSLs 

require thinner steels, heavier cores, and mitered core construction techniques, all of 

which slow throughput and reduce existing capacity. At those TSLs where amorphous 

cores become the dominant steel of choice, DOE used the same amorphous core 

production line output and cost assumptions as discussed above for the liquid immersed 

market.

As it relates to product conversion costs, DOE understands the production of 

amorphous cores requires unique expertise and equipment. For manufacturers without 

experience with amorphous steel, a standard necessitating the use of the material would 

require the development or the procurement of the technical expertise necessary to 

produce cores. Because amorphous steel is extremely thin and brittle after annealing, 

materials management, safety measures, and design considerations that are not associated 

with non-amorphous steels would need to be implemented. 

For the liquid immersed distribution transformers, because of the industry’s relative 

inexperience with amorphous technology, DOE estimated product conversion costs 

would equal two times annual industry R&D expenses for those TSLs where a majority 

of the market would be expected to transition to amorphous material. These one-time 

Deleted: manufacturers and modeled the 

incremental equipment needs that would be required 

by the industry based on the design options available 

to them and

Deleted: fact that capacity needs rise as steels get 

thinner and units get heavier.

Deleted: results

Deleted: mitering

Comment [A16]: Changes recommended by 

OIRA.
202

expenditures account for the design, engineering, prototyping, and other R&D efforts the 

industry would have to undertake to move to a predominately amorphous market. At TSL 

1, the only TSL which did not show a clear move to amorphous technology, DOE 

estimated product conversion costs of one times industry annual R&D.

In the low-voltage and medium-voltage dry-type market, DOE aggregated estimates 

of product conversion costs from manufacturers that were gathered during interviews and 

scaled those estimates to represent the market share of those not interviewed. Again, for 

those levels that indicated a clear shift to amorphous (or, in the case of LVDT, potentially 

wound cores), DOE assumed one-time product conversion costs equal to two times 

annual industry R&D expenses.

In conclusion, both capital and product conversion costs are key inputs to the 

GRIM and directly impact the change in INPV that results from new standards. DOE 

assumed that all conversion-related investments occur between the year of publication of 

the final rule33 and the year by which manufacturers must comply with the standard

(2016). DOE’s estimates of conversion costs can be found in section V.B.2.a of today’s 

notice and a detailed description of the estimation methodology can be found in TSD 

chapter 12. 

d. Standards Case Shipments

As discussed in section F, DOE modeled standard case shipments based on what 

units the LCC customer choice model selected at each efficiency level. DOE’s shipments 

 

33 I.e., 2012
203

analysis includes an elasticity factor based on the potential for transformer purchasers to 

elect to refurbish rather than replace failed transformers as the purchase price increases. 

The shipments analysis is discussed in more detail in chapter 9 of the TSD.

e. Markup Scenarios

As discussed above, manufacturer selling prices include direct manufacturing 

production costs (i.e., labor, material, and overhead estimated in DOE’s MPCs) and all 

non-production costs (i.e., SG&A, R&D, and interest), along with profit. To calculate the 

MSPs in the GRIM, DOE applied markups to the MPCs estimated in the engineering 

analysis and selected in the LCC for each design line and efficiency level. Modifying 

these markups in the standards case yields different sets of impacts on manufacturers. For 

the MIA, DOE modeled two standards-case markup scenarios to represent the uncertainty 

regarding the potential impacts on prices and profitability for manufacturers following 

the implementation of amended energy conservation standards: (1) a preservation of 

gross margin percentage markup scenario, and (2) a preservation of operating profit 

markup scenario. These scenarios lead to different markups values, which, when applied 

to the inputted MPCs, result in varying revenue and cash flow impacts. 

Under the preservation of gross margin percentage scenario, DOE applied a single 

uniform “gross margin percentage” markup across all efficiency levels. As production 

costs increase with efficiency, this scenario implies that the absolute dollar markup will 

increase as well. Based on publicly available financial information for manufacturers of 

distribution transformers and comments from manufacturer interviews, DOE assumed the 

non-production cost markup—which includes SG&A expenses; R&D expenses; interest; 
204

and profit—to be 1.25 for distribution transformers. Because this markup scenario 

assumes that manufacturers would be able to maintain their gross margin percentage

markups as production costs increase in response to an energy conservation standard, it 

represents a high bound to industry profitability under an energy conservation standard.

In the preservation of operating profit scenario, DOE adjusted the manufacturer 

markups in the GRIM at each TSL to yield approximately the same earnings before 

interest and taxes in the standards case in the year after the compliance date of the 

amended standards as in the base case. Under this scenario, as the cost of production and 

the cost of sales go up, DOE assumes manufacturers are generally required to reduce 

their markups to a level that maintains base case operating profit in absolute dollars. 

Therefore, operating margin in percentage terms is reduced between the base case and 

standards case. This markup scenario represents a low bound to industry profitability 

under an energy conservation standard.

4. Discussion of Comments

During the April 2011 public meeting, interested parties commented on the 

assumptions and results of the preliminary TSD. Oral and written comments discussed 

several topics, including conversion costs, material availability, amorphous steel, and 

symmetric core technology. DOE addresses these comments below.

a. Material Availability

Manufacturers noted that the availability of raw materials is particularly a concern 

at higher efficiency levels, where transformer designs would be based upon a very limited 
205

selection of steel types. Hammond stated that the supply of high grade steels, such as 

domain-refined steels, would not be sufficient to meet demand if the efficiency standard 

forces all designs to use that type of steel. Hammond also stated that shortages could 

occur if levels are pushed anywhere beyond the current level. (Hammond, Public Meeting 

Transcript, No. 3 at p. 4 and 6) According to EEI, scarcity of raw materials would be 

especially problematic if standards are raised beyond CSL 2 for most design lines. Also, 

EEI noted that if the efficiency levels selected are so high that they can only be met with 

one or two design options, manufacturers would be faced with limited choices in 

suppliers and higher costs, and customers would be faced with limited choices in designs 

and with higher prices. (EEI, Public Meeting Transcript, No. 29 at p. 1 and 4) 

Furthermore, as noted by KAEC, the transformer industry may not be able to respond to 

demand under emergency situations if increased efficiency levels reduce the number of 

options available for core steels and those steels are in limited supply or subject to long 

lead times. (KAEC, Public Meeting Transcript, No. 4 at p. 3) Southern Company also 

noted that an improved economy would increase demand for transformers and exacerbate 

the shortage of core steels necessary to build higher efficiency transformers. (Southern

Company, Public Meeting Transcript, No. 22 at p. 1) Many manufacturers expressed 

concerns about the limited availability of raw materials, especially higher efficiency 

electrical steels. Power Partners commented that: 1) there is a limited global supply of 

core steels in grades better than M3, 2) the domestic supply of M2 steel is not enough to 

support 100 percent of all liquid-immersed transformer production, and 3) grades of grain 

oriented electrical steel better than M2 (e.g., ZDMH) is in limited supply and only 

available from a foreign supplier. (Power Partners, Public Meeting Transcript, No. 19 at 
206

p. 4) Howard Industries also commented on the limited availability of ZDMH and M2 

steel, stating that ZDMH steel is only produced in Japan and that production of M2 steel 

by AK Steel and Allegheny Ludlum (the two primary suppliers of M2) is unlikely to 

increase. (Howard Industries, Public Meeting Transcript, No. 23 at p. 10-11) 

The use and availability of amorphous steel, in particular, is a major concern in

the distribution transformer industry. DOE understands that amorphous steel is currently 

produced by only two companies in the world (Metglas and AT&M), both of which are 

foreign-owned and one of which only supplies the Chinese market. Southern Company 

argued that a standard level that requires the use of amorphous steel could cause domestic 

suppliers of grain-oriented steel to go out of business or force them to lay off employees. 

(Southern Company, Public Meeting Transcript, No. 22 at p. 1) Also, Howard Industries 

commented that, because production in China is not exported, amorphous steel will likely 

need to be supplied by U.S. manufacturers. (Howard Industries, Public Meeting 

Transcript, No. 23 at p. 10-11) However, Metglas stated that AT&M (the Chinese 

amorphous supplier) has announced aggressive expansion in its plants and is expected to 

export at some point in the future. (Metglas, Public Meeting Transcript, No. 34 at p. 259) 

Nevertheless, due to the limited current supply of amorphous steel, Federal Pacific 

suggested that DOE should consider whether the increased demand for amorphous steel 

from any proposed standard levels could be met by the compliance date. (Federal Pacific, 

Public Meeting Transcript, No. 27 at p. 2-3)
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Manufacturers suggested several analyses which DOE should consider 

performing in order to determine core steel availability. ABB recommended that DOE 

should project the consumption of all grades of core steels for each efficiency level in the 

analysis so that the industry can assess the underlying impact on supply. (ABB, Public 

Meeting Transcript, No. 14 at p. 17) Schneider Electric recommended that DOE should 

work with the steel industry to gain insights into core steel availability. (Schneider, 

Public Meeting Transcript, No. 18 at p. 9) NEMA recommended that DOE should discuss 

core steel supply with large and small manufacturers, and that DOE should also forecast 

the supply and cost of steel at each CSL and TSL considered in the analysis. (NEMA, 

Public Meeting Transcript, No. 13 at p. 7-8) Also, Berman Economics commented that 

the shape of the material supply curve is more relevant than the current quantity of 

supply. Once demand increases, the market would respond by supplying more steel, 

according to Berman Economics. (Berman Economics, Public Meeting Transcript, No. 34 

at p. 260)

DOE agrees with comments that standards could shift the mix and quantities of 

core steels demanded by transformer manufacturers and could alter the market dynamics 

among core steel and transformer manufacturers. Therefore, DOE interviewed many 

players in the core steel supply chain. DOE investigated core steel availability with large 

and small distribution transformers manufacturers, core manufacturers, and steel 

suppliers. DOE discussed several topics during these interviews, including market 

capacity for each type of core steel, prospects for expansion, barriers to obtaining those 

steels, and impacts on competition. 
208

Based on its engineering analysis, DOE recognizes that some high efficiency 

steels are substantially more cost-effective at higher TSLs than lower-grade or traditional 

steels. Furthermore, the most stringent TSLs can only be met with certain core steels, 

typically amorphous, depending on the design line. Based on its interviews and market 

research, DOE understands these steels are currently produced in limited quantities by a 

small handful of suppliers, some of which do not produce steels domestically. 

To better understand the impact of standards on materials availability, DOE 

conducted an extensive analysis of the core steel market, as discussed in TSD appendix 

3A.

To evaluate the impacts of standards on the core steel market and transformer 

manufacturers, DOE first estimated the core steel consumption of transformer 

manufacturers in 2016 (the first year of required compliance with the proposed standard) 

in the base case and the standards cases. To do this, DOE had to evaluate the designs 

selected by the LCC customer choice model at each EL for each design line. This model 

estimated the distribution of designs that would be selected at any given standard level. 

Key parameters of this sample of selected designs, such as the distribution of core steel 

types and average core weights by steel type, were critical inputs into the steel demand 

analysis. DOE found the average core weight of the designs selected for each design 

line’s representative unit at each efficiency level.
209

Next, the Department used the .75 scaling rule to extrapolate these average core 

weights to those units forecast to be shipped within a design line but not at the KVA 

range of the representative unit that is directly analyzed in the engineering and LCC 

analyses. For example, DOE extrapolated the core weight of the 50 kVA representative 

unit for DL1 to a 100 kVA unit in DL1. This implicitly assumes that the distribution of 

core steel types used in transformers remains constant within the kVA range represented 

by each design line. Although the calculation of core weights for units at the extremes of 

a kVA range may benefit from an adjusted scaling rule or intermediate design lines, time 

constraints have limited the extent of the analysis. However, for the most part, the .75 

scaling rule is a suitable method for scaling across kVAs.

Using the shipments analysis, which projected kVA demand by design line and 

capacity, DOE calculated total core steel demand from transformers covered by this rule. 

While DOE recognizes the core steel market is global in scope, its projections include 

only core steel used in distribution transformers covered by this rulemaking for use in the 

U.S. [In response to Southern Company’s comment regarding additional demand that 

may come from an improved economy, DOE notes that the shipment analysis is based on 

the EIA forecast of economic growth throughout the analysis period, and thus accounts 

for higher-the-current rates of economic growth.] 

In reference to the comments summarized above, based on industry research and 

the core steel analysis, DOE agrees with Power Partners that domestic steel suppliers do 

not currently have the capacity to supply the entire distribution transformer market with 
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M2, nor does DOE believe domestic suppliers could cost-effectively produce enough M2 

to do so because the nature of silicon steel production limits M2 output to one pound for 

every four pounds of M3. Due to this manufacturing constraint, if M3 was not able to be 

used due to standards, steel manufacturers would be unlikely to produce M2 at levels 

potentially demanded by standards, which could create a tipping point at which the 

market must move to amorphous by default. 

With respect to amorphous demand and capacity, at this time, DOE understands 

there is only one credible supplier to the U.S. market of high-grade amorphous core steel. 

(Although there is one notable Chinese supplier with substantial capacity, DOE 

understands the company has no history of exporting the material and serves only 

China’s rapidly growing domestic market at this time. Despite Metglas’ comment above 

that this supplier is expected to export soon, several manufacturers expressed skepticism 

at that possibility in interviews and also noted the quality of the steel was poor. At this 

time, DOE has little reason to believe the company will commence exporting substantial 

amounts of high quality amorphous steel in the near future.) Based on publically 

available information, DOE estimates the domestic supplier of amorphous metal has a 

global capacity of approximately 100,000 metrics tons per year, 40 percent of which is 

U.S. based. DOE estimates less than 10,000 tons are currently used for covered US 

transformers. Notably, the company has substantially ramped up capacity in a relatively 

short time, growing from a 30,000-tons-per-year level in 2005 and lending credence to 

the notion that its supply can escalate quickly. The amorphous supplier is a subsidiary of 

a large conglomerate and has commented that it has the financial resources to expand. 
211

While DOE believes the company could substantially grow capacity beyond its 

current levels in time for a 2016 compliance date, there still exists a significant risk of 

supply constraints, given the magnitude of the surge in amorphous demand that could 

potentially be compelled by TSL 2 and above. It is worth noting that this is a global 

market (indeed, as discussed, DOE estimates less than 10 percent of all amorphous core 

from this supplier is used in U.S. transformers). Therefore, even if the company could 

increase capacity substantially, it is unlikely, according to most projections, that demand 

would remain flat in markets receiving the other 90 percent of this supplier’s business.

Beyond potential capacity constraints, DOE is also concerned about the 

competitive impact—among both steel manufacturers and distribution transformer 

manufacturers—of a standard that threatened to shift most of the market to amorphous 

steel. In highly competitive markets, standard economic theory dictates that higher prices 

would encourage additional suppliers and production to come online, bringing prices 

back to a long-run equilibrium. In the very long run, that may be true here. However, the 

highly sophisticated nature of amorphous ribbon production, which is based on extensive 

know-now gained over years of production and high fixed costs, creates barriers to entry 

that, while not legal (i.e., patents) in nature, suggest there is a significant risk that there 

will be no alternative sources of supply by the compliance date or even in the few years 

beyond it. Therefore, DOE is concerned about the lack of alternative amorphous suppliers 

and the virtual monopoly supplier that would likely exist in the short term at higher TSLs, 
212

particularly given the engineering constraints on the economic production of M2 and very 

limited supply of ZDMH.

b. Symmetric Core Technology

Several stakeholders commented on the costs that may be associated with the 

implementation of symmetric core technology. Howard Industries stated that symmetric 

core designs would require large capital investments and patent fees. (Howard Industries, 

Public Meeting Transcript, No. 23 at p. 10-11) Conversely, NEEA stated that capital 

investments for the technology are low according to symmetric core manufacturers 

(NEEA, Public Meeting Transcript, No. 11 at p. 4). Furthermore, HVOLT argued that, 

although there may be specific patents with different kinds of construction, patents 

fundamentally related to core configurations should have expired by now given that 

symmetric core technology was patented in the 1930s. (HVOLT, Public Meeting 

Transcript, No. 34 at p. 49) 

Symmetric core manufacturers commented on the benefits of symmetric core 

technology. Hex Tec noted that the equipment used to produce symmetric wound cores is 

significantly less expensive than flat stacked steel equipment for the same size and the 

labor production times are lower. (Hex Tec, Public Meeting Transcript, No. 34 at p. 52) 

Furthermore, according to Hex Tec, intellectual property should not be a concern because 

there are a number of symmetric core designs available and therefore plenty of variance 

in design. (Hex Tec, Public Meeting Transcript, No. 34 at p. 49) Hex Tec has also 

submitted a letter from the Vice President of Research & Development at Metglas which 

indicates that Hex Tec's core winding machine for amorphous symmetric core designs 
213

can be easily scaled for commercialization. (Hex Tec, Public Meeting Transcript, No. 35 

at p. 11-14)

DOE did not explicitly analyze symmetric core as a design option for 

consideration in the engineering. Therefore, symmetric core construction was not 

considered in the MIA.

c. Patents Related to Amorphous Steel Production

Some manufacturers were concerned about patents on amorphous steel production. 

ASAP has questioned whether or not there are any patent issues that exist for amorphous 

manufacturers entering the market. (ASAP, Public Meeting Transcript, No. 34 at p. 262) 

However, according to Metglas, the basic amorphous patent expired in 1999, so barriers 

to entry are based more on know-how than on patents. (Metglas, Public Meeting 

Transcript, No. 34 at p. 262)

Because there are no more patents that create a barrier to entry in the production 

of amorphous steel, DOE did not consider patents in its analysis of amorphous steel 

production capacity. However, DOE did consider the technical barriers that exist and 

accounted for the engineering and R&D investment necessary to begin production.

5. Manufacturer Interviews

DOE interviewed manufacturers representing approximately 65 percent of liquidimmersed transformer sales, 75 percent of medium-voltage dry-type transformer sales, 
214

and 30 percent of low-voltage dry-type transformer sales. These interviews were in 

addition to those DOE conducted as part of the engineering analysis. The information 

gathered during these interviews enabled DOE to tailor the GRIM to reflect the unique 

financial characteristics of the distribution transformer industry. All interviews provided 

information that DOE used to evaluate the impacts of potential new and amended energy 

conservation standards on manufacturer cash flows, manufacturing capacities, and 

employment levels.

During the manufacturer interviews, DOE asked manufacturers to describe their 

major concerns about this rulemaking. The following sections describe the most 

significant issues identified by manufacturers. DOE also includes additional concerns in 

chapter 12 of the NOPR TSD.

a. Conversion Costs and Stranded Assets

For manufacturers of distribution transformers, liquid-immersed, medium-voltage 

dry-type, and low-voltage dry-type, conversion costs and stranded assets are a major 

concern. All manufacturers stated that efficiency levels that require the use of amorphous 

steel would sharply increase conversion costs. Due to the thickness and brittleness of 

amorphous steel, unique production processes and new material handling processes must 

be applied. Manufacturers noted that they would need to make extensive capital 

investments in amorphous core production equipment, including core cutting machines, 

annealing ovens, and lacing tables. 
215

Dry-type manufacturers also stated that a standard that moves the industry to 

wound cores would also greatly increase conversions costs. Since the vast majority of 

LVDT and MVDT manufacturers produce stacked cores, a move to wound cores would 

lead to extensive stranded assets. In some cases, manufacturers may consider purchasing 

prefabricated cores rather than modifying their facilities to produce wound cores due to 

the extensive conversion costs. 

Additionally, dry-type manufactures stated that a revised standard that does not 

require amorphous steel or wound core designs could still lead to capital conversion 

costs. As the standard increases, manufacturers are likely to use higher grade steels for 

core production. Because high grade steels tend to be thinner, additional Georg machines, 

core assembly lines and workstations, custom miter cutters, and panel boards may be 

needed in order to maintain existing throughput levels. 

Some manufacturers mentioned that stranded assets may also be an issue when 

equipment needs to be retired and/or replaced if it cannot be repurposed for higher 

efficiency designs. DOE accounted for stranded assets in the GRIM.

b. Shortage of Materials

The availability of higher efficiency grain-oriented electrical steels is a key issue 

for all manufacturers of distribution transformers. Manufacturers stated that there is 

currently a limited supply of M4, M3, M2, ZDMH, H-0 DR, and SA1 amorphous steels 

on the market and manufacturers expressed concern that higher standards may increase 
216

both demand and prices. Of these steels, M4 and M3 steels are currently the most widely 

produced, with suppliers such as AK Steel, Allegheny Ludlum, ThyssenKrupp, Nippon, 

JFE, Wuhan, Novolipetsk, Posco, ArcelorMittal, Orb, Baosteel, Stalproduct, Angang, and 

Arcelor/Hunan. However, as the grade of grain-oriented electrical steel improves, its 

availability decreases. M2 is a higher grade than M3 but it is produced by fewer 

suppliers, such as AK Steel, Allegheny Ludlum, ThyssenKrupp, Nippon, and JFE. The 

availability of deep domain-refined steel such as ZDMH , H-0 DR, and SA1 amorphous 

is even more limited. H-0 DR is only produced by Nippon, JFE, AK Steel, Posco, and 

Baosteel, and ZDMH is only produced by Nippon. Amorphous steel is only produced by 

Hitachi (MetGlas) and AT&M, but AT&M only supplies the Chinese market. If 

efficiency levels are set so high that only amorphous can be used, then domestic 

manufacturers may be subject to monopolistic pricing from suppliers.

Manufacturers further stated that, in addition to being in limited supply, higher 

efficiency steels are also: 1) more expensive, 2) subject to tariffs when imported from a 

foreign supplier, 3) subject to long lead times for both domestic and international 

suppliers, and 4) difficult to obtain for manufacturers that do not have contracts in place 

with suppliers. Furthermore, due in part to the major capital investment required to build 

a steel plant, barriers to entry are high and capacity cannot be easily increased. 

Transformer manufacturers feel that all these factors contribute to the limited availability 

of higher efficiency steel. 
217

c. Compliance

Some manufacturers emphasized the importance of compliance and enforcement. 

According to manufacturers, insufficient enforcement could result in an unfair 

competitive advantage for some companies who opt not to comply. Manufacturers were 

particularly concerned about importers of foreign manufactured products. One specific 

issue is the scope of coverage for low-voltage dry-type transformers, which is currently 

the scope recommended by NEMA in the 2006 TP1 rulemaking. The market for products 

inside of scope and the market for products outside of scope are approximately equal in 

terms of revenue. As a result, if standards increase for products that are in-scope, 

manufacturers are concerned there would be an increase in demand for products that are 

out-of-scope and are not be subject to the same compliance burdens. Some of these outof-scope products are highly inefficient, so if they become more widely used, the energy 

savings resulting from more efficient in-scope transformers may be significantly offset by 

the additional energy needed to run less efficient out-of-scope transformers.

d. Effective Date

Manufacturers expressed concerns about the amount of time being provided for 

the implementation of a possible new standard. Manufacturers indicated that more time is 

needed to meet a new standard, especially if the standard requires a very high efficiency 

level. In order to avoid stranding too many assets and materials, sufficient time must be 

given to manufacturers for the purchase and use of new equipment, development of new 

designs if needed, and transitioning of customers to new product offerings. Also, some 
218

manufacturers stated that standards for low-voltage dry-type transformers, which were 

not included in the previous 2007 rulemaking, should be on an extended timeline.

e. Emergency Situations

Liquid-immersed transformer manufacturers stated that the ability to obtain 

waivers during emergency situations is an important issue for them. For example, when a 

natural disaster occurs, there may be a sharp increase in demand for transformers and 

manufacturers may not be able to meet DOE’s efficiency requirements under these 

circumstances due to limitations of high efficiency steel availability. In order to 

adequately supply areas facing such emergency situations, manufacturers requested the 

ability to obtain waivers so that they can produce transformers as quickly as possible. 

Because the TSLs proposed in today’s rulemaking can be met using traditional 

steels, DOE does not anticipate that steel availability during emergency situations will 

affect manufacturer compliance with the proposed TSLs.

J. Employment Impact Analysis

DOE considers employment impacts in the domestic economy as one factor in 

selecting a proposed standard. Employment impacts include direct and indirect impacts. 

Direct employment impacts are any changes in the number of employees of 

manufacturers of the products subject to standards, their suppliers, and related service 

firms. The MIA addresses those impacts. Indirect employment impacts are changes in 

national employment that occur due to the shift in expenditures and capital investment 
219

caused by the purchase and operation of more efficient appliances. Indirect employment 

impacts from standards consist of the jobs created or eliminated in the national economy, 

other than in the manufacturing sector being regulated, due to: (1) reduced spending by 

end users on energy; (2) reduced spending on new energy supply by the utility industry; 

(3) increased consumer spending on the purchase of new products; and (4) the effects of 

those three factors throughout the economy. 

One method for assessing the possible effects on the demand for labor of such 

shifts in economic activity is to compare sector employment statistics developed by the 

Labor Department’s Bureau of Labor Statistics (BLS). BLS regularly publishes its 

estimates of the number of jobs per million dollars of economic activity in different 

sectors of the economy, as well as the jobs created elsewhere in the economy by this 

same economic activity. Data from BLS indicate that expenditures in the utility sector 

generally create fewer jobs (both directly and indirectly) than expenditures in other 

sectors of the economy.34 There are many reasons for these differences, including wage 

differences and the fact that the utility sector is more capital-intensive and less laborintensive than other sectors. Energy conservation standards have the effect of reducing 

consumer utility bills. Because reduced consumer expenditures for energy likely lead to 

increased expenditures in other sectors of the economy, the general effect of efficiency 

standards is to shift economic activity from a less labor-intensive sector (i.e., the utility 

sector) to more labor-intensive sectors (e.g., the retail and service sectors). Thus, based 

 

34 See Bureau of Economic Analysis, Regional Multipliers: A User Handbook for the Regional InputOutput Modeling System (RIMS II). Washington, DC. U.S. Department of Commerce, 1992.
220

on the BLS data alone, DOE believes net national employment may increase because of 

shifts in economic activity resulting from amended standards for transformers.

For the standard levels considered in today’s direct final rule, DOE estimated 

indirect national employment impacts using an input/output model of the U.S. economy 

called Impact of Sector Energy Technologies version 3.1.1 (ImSET). ImSET is a specialpurpose version of the “U.S. Benchmark National Input-Output” (I–O) model, which was 

designed to estimate the national employment and income effects of energy-saving 

technologies. The ImSET software includes a computer-based I–O model having 

structural coefficients that characterize economic flows among the 187 sectors. ImSET’s 

national economic I–O structure is based on a 2002 U.S. benchmark table, specially 

aggregated to the 187 sectors most relevant to industrial, commercial, and residential 

building energy use. DOE notes that ImSET is not a general equilibrium forecasting 

model. Given the relatively small change to expenditures due to energy conservation 

standards and the resulting small changes to employment, however, DOE believes that 

the size of any forecast error caused by using ImSET will be small.

For more details on the employment impact analysis, see chapter 13 of the NOPR 

TSD. 

K. Utility Impact Analysis

The utility impact analysis estimates several important effects on the utility 

industry that would result from the adoption of new or amended standards. For this 

analysis, DOE used the NEMS-BT model to generate forecasts of electricity 
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consumption, electricity generation by plant type, and electric generating capacity by 

plant type, that would result from each TSL. DOE obtained the energy savings inputs 

associated with efficiency improvements to considered products from the NIA. DOE 

conducts the utility impact analysis as a scenario that departs from the latest AEO 2011

reference case. In other words, the estimated impacts of a proposed standard are the 

differences between values forecasted by NEMS–BT and the values in the AEO 2011

reference case. 

As part of the utility impact analysis, DOE used NEMS-BT to assess the impacts 

on electricity prices of the reduced need for new electric power plants and infrastructure 

projected to result from the considered standards. In NEMS-BT, changes in power 

generation infrastructure affect utility revenue requirements, which in turn affect 

electricity prices. DOE estimated the change in electricity prices projected to result over 

time from each TSL.

Chapter 14 of the NOPR TSD describes the utility impact analysis.

L. Emissions Analysis

In the emissions analysis, DOE estimated the reduction in power sector emissions 

of CO2, NOX, and Hg from amended energy conservation standards for distribution 

transformers. DOE used the NEMS–BT computer model, which is run similarly to the 

AEO NEMS, except that distribution transformer energy use is reduced by the amount of 

energy saved (by fuel type) due to each TSL. The inputs of national energy savings come 
222

from the NIA spreadsheet model, while the output is the forecasted physical emissions. 

The net benefit of each TSL is the difference between the forecasted emissions estimated 

by NEMS–BT at each TSL and the AEO Reference Case. NEMS–BT tracks CO2

emissions using a detailed module that provides results with broad coverage of all sectors 

and inclusion of interactive effects. For today’s rule, DOE used the version of NEMS-BT 

based on AEO2011, which incorporated projected effects of all emissions regulations 

promulgated as of January 31, 2011.

SO2 emissions from affected electric generating units (EGUs) are subject to 

nationwide and regional emissions cap and trading programs, and DOE has determined 

that these programs create uncertainty about the impact of energy conservation standards 

on SO2 emissions. Title IV of the Clean Air Act sets an annual emissions cap on SO2 for 

affected EGUs in the 48 contiguous States and the District of Columbia (D.C.). SO2

emissions from 28 eastern States and D.C. are also limited under the Clean Air Interstate 

Rule (CAIR, 70 Fed. Reg. 25162 (May 12, 2005)), which created an allowance-based 

trading program that would gradually replaced the Title IV program in those States and 

D.C. Although CAIR was remanded to EPA by the U.S. Court of Appeals for the District 

of Columbia Circuit (D.C. Circuit), see North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 

2008), it remained in effect temporarily, consistent with the D.C. Circuit’s earlier opinion 

in North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008). On July 6, 2011 EPA issued a 

replacement for CAIR, the Cross-State Air Pollution Rule. 76 FR 48208 (August 8, 

2011). (See http://www.epa.gov/crossstaterule/). On December 30, 2011, however, the 

D.C. Circuit stayed the new rules while a panel of judges reviews them, and told EPA to 

Deleted: 2010,

Deleted: the Transport Rule proposal, 

Deleted: . 75 FR 45210 (Aug. 2, 2010). On July 6, 

2011, EPA issued the final Transport Rule, titled

Deleted: http://www.epa.gov/crossstaterule/). 

Because
223

continue enforcing CAIR (see EME Homer City Generation v. EPA, No. 11-1302, Order 

at *2 (D.C. Cir. Dec. 30, 2011)). The AEO 2011 NEMS-BT used for today’s NOPR

assumes the implementation of CAIR.

The attainment of emissions caps typically is flexible among EGUs and is 

enforced through the use of emissions allowances and tradable permits. Under existing 

EPA regulations, any excess SO2 emissions allowances resulting from the lower 

electricity demand caused by the imposition of an efficiency standard could be used to 

permit offsetting increases in SO2 emissions by any regulated EGU. However, if the 

standard resulted in a permanent increase in the quantity of unused emissions allowances, 

there would be an overall reduction in SO2 emissions from the standards. While there 

remains some uncertainty about the ultimate effects of efficiency standards on SO2

emissions covered by the existing cap-and-trade system, the NEMS-BT modeling system 

that DOE uses to forecast emissions reductions currently indicates that no physical 

reductions in power sector emissions would occur for SO2. 

As discussed above, the AEO 2011 NEMS used for today’s NOPR assumes the 

implementation of CAIR, which established a cap on NOx emissions in 28 eastern States 

and the District of Columbia. With CAIR in effect, the energy conservation standards for 

distribution transformers are expected to have little or no physical effect on NOx

emissions in those States covered by CAIR, for the same reasons that they may have little 

effect on SO2 emissions. However, the standards would be expected to reduce NOx

emissions in the 22 States not affected by CAIR. For these 22 States, DOE used NEMSDeleted: 2010

Deleted: rule

Deleted: , DOE has not been able to take into 

account the effects of the Transport Rule for this 

analysis.35

Comment [A17]: Changes recommended by 

OIRA,
224

BT to estimate NOx emissions reductions from the standards considered in today’s 

NOPR.

On December 21, 2011, EPA announced national emissions standards for 

hazardous air pollutants (NESHAPs) for mercury and certain other pollutants emitted 

from coal and oil-fired EGUs. (See http://epa.gov/mats/pdfs/20111216MATSfinal.pdf.)

The NESHAPs do not include a trading program and, as such, DOE’s energy 

conservation standards would likely reduce Hg emissions. For the emissions analysis for 

this rulemaking, DOE estimated mercury emissions reductions using NEMS-BT based on 

AEO2011, which does not incorporate the NESHAPs. DOE expects that future versions 

of the NEMS-BT model will reflect the implementation of the NESHAPs.

FPT requested that the DOE perform an emissions analysis for the additional 

energy required to process higher-grade materials for more efficient core steels. (FPT, 

No. 27 at p. 4) HI maintained that higher-efficiency transformers will weigh more, which 

will result in higher air emissions from extra oven energy for annealing and extra energy 

use for processing raw materials. (HI, No. 23 at p. 12) As discussed in section IV.G.5, 

DOE did not include the energy used to manufacture transformers in its analysis because 

EPCA directs DOE to consider the total projected amount of energy savings likely to 

result directly from the imposition of the standard and DOE interprets this to only include 

energy used in the generation, transmission, and distribution of fuels used by appliances 

or equipment. DOE did not include the emissions associated with such energy use for the 

same reason.
225

M. Monetizing Carbon Dioxide and Other Emissions Impacts 

As part of the development of this proposed rule, DOE considered the estimated 

monetary benefits likely to result from the reduced emissions of CO2 and NOX that are 

expected to result from each of the considered TSLs. In order to make this calculation 

similar to the calculation of the NPV of customer benefit, DOE considered the reduced 

emissions expected to result over the lifetime of products shipped in the forecast period 

for each TSL. This section summarizes the basis for the monetary values used for each of 

these emissions and presents the values considered in this rulemaking.

For today’s NOPR, DOE is relying on a set of values for the social cost of carbon 

(SCC) that was developed by an interagency process. A summary of the basis for those 

values is provided below, and a more detailed description of the methodologies used is

provided as an appendix to chapter 16 of the NOPR TSD.

1. Social Cost of Carbon

Under section 1(b)(6) of Executive Order 12866, 58 FR 51735 (Oct. 4, 1993), 

agencies must, to the extent permitted by law, “assess both the costs and the benefits of 

the intended regulation and, recognizing that some costs and benefits are difficult to 

quantify, propose or adopt a regulation only upon a reasoned determination that the 

benefits of the intended regulation justify its costs.” The purpose of the SCC estimates 

presented here is to allow agencies to incorporate the monetized social benefits of 

reducing CO2 emissions into cost-benefit analyses of regulatory actions that have small, 
226

or “marginal,” impacts on cumulative global emissions. The estimates are presented with 

an acknowledgement of the many uncertainties involved and with a clear understanding 

that they should be updated over time to reflect increasing knowledge of the science and 

economics of climate impacts.

As part of the interagency process that developed the SCC estimates, technical 

experts from numerous agencies met on a regular basis to consider public comments, 

explore the technical literature in relevant fields, and discuss key model inputs and 

assumptions. The main objective of this process was to develop a range of SCC values 

using a defensible set of input assumptions grounded in the existing scientific and 

economic literatures. In this way, key uncertainties and model differences transparently 

and consistently inform the range of SCC estimates used in the rulemaking process.

a. Monetizing Carbon Dioxide Emissions

The SCC is an estimate of the monetized damages associated with an incremental 

increase in carbon emissions in a given year. It is intended to include (but is not limited 

to) changes in net agricultural productivity, human health, property damages from 

increased flood risk, and the value of ecosystem services. Estimates of the SCC are 

provided in dollars per metric ton of carbon dioxide.

When attempting to assess the incremental economic impacts of carbon dioxide 

emissions, the analyst faces a number of serious challenges. A recent report from the 
227

National Research Council36 points out that any assessment will suffer from uncertainty, 

speculation, and lack of information about (1) future emissions of greenhouse gases, (2) 

the effects of past and future emissions on the climate system, (3) the impact of changes 

in climate on the physical and biological environment, and (4) the translation of these 

environmental impacts into economic damages. As a result, any effort to quantify and 

monetize the harms associated with climate change will raise serious questions of 

science, economics, and ethics and should be viewed as provisional.

Despite the serious limits of both quantification and monetization, SCC estimates 

can be useful in estimating the social benefits of reducing carbon dioxide emissions. 

Consistent with the directive quoted above, the purpose of the SCC estimates presented 

here is to make it possible for agencies to incorporate the social benefits from reducing 

carbon dioxide emissions into cost-benefit analyses of regulatory actions that have small, 

or “marginal,” impacts on cumulative global emissions. Most Federal regulatory actions 

can be expected to have marginal impacts on global emissions.

For such policies, the agency can estimate the benefits from reduced (or costs 

from increased) emissions in any future year by multiplying the change in emissions in 

that year by the SCC value appropriate for that year. The net present value of the benefits 

can then be calculated by multiplying each of these future benefits by an appropriate 

discount factor and summing across all affected years. This approach assumes that the 

marginal damages from increased emissions are constant for small departures from the 

 

36 National Research Council. “Hidden Costs of Energy: Unpriced Consequences of Energy Production and 

Use.” National Academies Press: Washington, D.C. 2009.
228

baseline emissions path, an approximation that is reasonable for policies that have effects 

on emissions that are small relative to cumulative global carbon dioxide emissions. For 

policies that have a large (non-marginal) impact on global cumulative emissions, there is 

a separate question of whether the SCC is an appropriate tool for calculating the benefits 

of reduced emissions. This concern is not applicable to this notice, and DOE does not 

attempt to answer that question here.

At the time of the preparation of this notice, the most recent interagency estimates 

of the potential global benefits resulting from reduced CO2 emissions in 2010, expressed 

in 2010$, were $4.9, $22.3, $36.5, and $67.6 per metric ton avoided. For emissions 

reductions that occur in later years, these values grow in real terms over time. 

Additionally, the interagency group determined that a range of values from 7 percent to 

23 percent should be used to adjust the global SCC to calculate domestic effects,37

although preference is given to consideration of the global benefits of reducing CO2

emissions.

It is important to emphasize that the interagency process is committed to updating 

these estimates as the science and economic understanding of climate change and its 

impacts on society improves over time. Specifically, the interagency group has set a 

preliminary goal of revisiting the SCC values within 2 years or at such time as 

substantially updated models become available, and to continue to support research in 

this area. In the meantime, the interagency group will continue to explore the issues 

 

37 It is recognized that this calculation for domestic values is approximate, provisional, and highly 

speculative. There is no a priori reason why domestic benefits should be a constant fraction of net global 

damages over time.
229

raised by this analysis and consider public comments as part of the ongoing interagency 

process.

b. Social Cost of Carbon Values Used in Past Regulatory Analyses

To date, economic analyses for Federal regulations have used a wide range of 

values to estimate the benefits associated with reducing carbon dioxide emissions. In the 

model year 2011 CAFE final rule, the Department of Transportation (DOT) used both a 

“domestic” SCC value of $2 per metric ton of CO2 and a “global” SCC value of $33 per 

metric ton of CO2 for 2007 emission reductions (in 2007$), increasing both values at 2.4 

percent per year. It also included a sensitivity analysis at $80 per metric ton of CO2. See

Average Fuel Economy Standards Passenger Cars and Light Trucks Model Year 2011, 74 

FR 14196 (March 30, 2009) (Final Rule); Final Environmental Impact Statement 

Corporate Average Fuel Economy Standards, Passenger Cars and Light Trucks, Model 

Years 2011-2015 at 3-90 (Oct. 2008) (Available at: http://www.nhtsa.gov/fuel-economy). 

A domestic SCC value is meant to reflect the value of damages in the United States 

resulting from a unit change in carbon dioxide emissions, while a global SCC value is 

meant to reflect the value of damages worldwide.

A 2008 regulation proposed by DOT assumed a domestic SCC value of $7 per

metric ton of CO2 (in 2006$, with a range of $0 to $14 for sensitivity analysis) for 2011 

emission reductions, also increasing at 2.4 percent per year. See Average Fuel Economy 

Standards, Passenger Cars and Light Trucks, Model Years 2011-2015, 73 FR 24352 

(May 2, 2008) (Proposed Rule); Draft Environmental Impact Statement Corporate 
230

Average Fuel Economy Standards, Passenger Cars and Light Trucks, Model Years 2011-

2015 at 3-58 (June 2008) (Available at: http://www.nhtsa.gov/fuel-economy). A 

regulation for packaged terminal air conditioners and packaged terminal heat pumps 

finalized by DOE in October of 2008 used a domestic SCC range of $0 to $20 per metric 

ton CO2 for 2007 emission reductions (in 2007$). 73 FR 58772, 58814 (Oct. 7, 2008). In 

addition, EPA’s 2008 Advance Notice of Proposed Rulemaking on Regulating 

Greenhouse Gas Emissions Under the Clean Air Act identified what it described as “very 

preliminary” SCC estimates subject to revision. 73 FR 44354 (July 30, 2008). EPA’s 

global mean values were $68 and $40 per metric ton CO2 for discount rates of 

approximately 2 percent and 3 percent, respectively (in 2006$ for 2007 emissions).

In 2009, an interagency process was initiated to offer a preliminary assessment of 

how best to quantify the benefits from reducing carbon dioxide emissions. To ensure 

consistency in how benefits are evaluated across agencies, the Administration sought to 

develop a transparent and defensible method, specifically designed for the rulemaking 

process, to quantify avoided climate change damages from reduced CO2 emissions. The 

interagency group did not undertake any original analysis. Instead, it combined SCC 

estimates from the existing literature to use as interim values until a more comprehensive 

analysis could be conducted. The outcome of the preliminary assessment by the 

interagency group was a set of five interim values: global SCC estimates for 2007 (in 

2006$) of $55, $33, $19, $10, and $5 per ton of CO2. These interim values represent the 

first sustained interagency effort within the U.S. government to develop an SCC for use 

in regulatory analysis. The results of this preliminary effort were presented in several 
231

proposed and final rules and were offered for public comment in connection with 

proposed rules, including the joint EPA-DOT fuel economy and CO2 tailpipe emission 

proposed rules.

c. Current Approach and Key Assumptions 

Since the release of the interim values, the interagency group reconvened on a 

regular basis to generate improved SCC estimates, which were considered for this 

proposed rule. Specifically, the group considered public comments and further explored 

the technical literature in relevant fields. The interagency group relied on three integrated 

assessment models (IAMs) commonly used to estimate the SCC: the FUND, DICE, and 

PAGE models.38 These models are frequently cited in the peer-reviewed literature and 

were used in the last assessment of the Intergovernmental Panel on Climate Change. Each 

model was given equal weight in the SCC values that were developed.

Each model takes a slightly different approach to model how changes in 

emissions result in changes in economic damages. A key objective of the interagency 

process was to enable a consistent exploration of the three models while respecting the 

different approaches to quantifying damages taken by the key modelers in the field. An 

extensive review of the literature was conducted to select three sets of input parameters 

for these models: climate sensitivity, socio-economic and emissions trajectories, and 

discount rates. A probability distribution for climate sensitivity was specified as an input 

into all three models. In addition, the interagency group used a range of scenarios for the 

 

38 The models are described in appendix 15-A of the NOPR TSD.
232

socio-economic parameters and a range of values for the discount rate. All other model 

features were left unchanged, relying on the model developers’ best estimates and 

judgments.

The interagency group selected four SCC values for use in regulatory analyses. 

Three values are based on the average SCC from three integrated assessment models, at 

discount rates of 2.5 percent, 3 percent, and 5 percent. The fourth value, which represents 

the 95th percentile SCC estimate across all three models at a 3-percent discount rate, is 

included to represent higher-than-expected impacts from temperature change further out 

in the tails of the SCC distribution. For emissions (or emission reductions) that occur in 

later years, these values grow in real terms over time, as depicted in Table IV.7.

Table IV.7 Social Cost of CO2, 2010–2050 (in 2007 dollars per metric ton)

Year

Discount Rate (%)

5 3 2.5 3

Average Average Average 95th Percentile

2010 4.7 21.4 35.1 64.9

2015 5.7 23.8 38.4 72.8

2020 6.8 26.3 41.7 80.7

2025 8.2 29.6 45.9 90.4

2030 9.7 32.8 50.0 100.0

2035 11.2 36.0 54.2 109.7

2040 12.7 39.2 58.4 119.3

2045 14.2 42.1 61.7 127.8

2050 15.7 44.9 65.0 136.2

It is important to recognize that a number of key uncertainties remain, and that 

current SCC estimates should be treated as provisional and revisable since they will 

evolve with improved scientific and economic understanding. The interagency group also 
233

recognizes that the existing models are imperfect and incomplete. The National Research 

Council report mentioned above points out that there is tension between the goal of 

producing quantified estimates of the economic damages from an incremental metric ton 

of carbon and the limits of existing efforts to model these effects. There are a number of 

concerns and problems that should be addressed by the research community, including

research programs housed in many of the agencies participating in the interagency 

process to estimate the SCC.

DOE recognizes the uncertainties embedded in the estimates of the SCC used for 

cost-benefit analyses. As such, DOE and others in the U.S. Government intend to 

periodically review and reconsider those estimates to reflect increasing knowledge of the 

science and economics of climate impacts, as well as improvements in modeling. In this 

context, statements recognizing the limitations of the analysis and calling for further 

research take on exceptional significance.

In summary, in considering the potential global benefits resulting from reduced 

CO2 emissions, DOE used the most recent values identified by the interagency process, 

adjusted to 2010$ using the GDP price deflator. For each of the four cases specified, the 

values used for emissions in 2010 were $4.9, $22.3, $36.5, and $67.6 per metric ton 

avoided (values expressed in 2010$).39 To monetize the CO2 emissions reductions 

expected to result from amended standards for distribution transformers, DOE used the 

values identified in Table A1 of the “Social Cost of Carbon for Regulatory Impact 

 

39 Table A1 presents SCC values through 2050. For DOE’s calculation, it derived values after 2050 using 

the 3-percent per year escalation rate used by the interagency group.
234

Analysis Under Executive Order 12866,” which is reprinted in appendix 16-A of the 

NOPR TSD, appropriately escalated to 2010$. To calculate a present value of the stream 

of monetary values, DOE discounted the values in each of the four cases using the 

specific discount rate that had been used to obtain the SCC values in each case.

2. Valuation of Other Emissions Reductions

DOE investigated the potential monetary benefit of reduced NOX emissions from 

the TSLs it considered. As noted above, new or amended energy conservation standards 

would reduce NOX emissions in those 22 States that are not affected by the CAIR. DOE 

estimated the monetized value of NOX emissions reductions resulting from each of the 

TSLs considered for today’s NOPR based on environmental damage estimates found in 

the relevant scientific literature. Available estimates suggest a very wide range of 

monetary values, ranging from $370 per ton to $3,800 per ton of NOX from stationary 

sources, measured in 2001$ (equivalent to a range of $450 to $4,623 per ton in 2010$).40

In accordance with OMB guidance, DOE conducted two calculations of the monetary 

benefits derived using each of the economic values used for NOX, one using a real 

discount rate of 3 percent and the other using a real discount rate of 7 percent. 41

DOE is aware of multiple agency efforts to determine the appropriate range of 

values used in evaluating the potential economic benefits of reduced Hg emissions. DOE 

 

40 For additional information, refer to U.S. Office of Management and Budget, Office of Information and 

Regulatory Affairs, 2006 Report to Congress on the Costs and Benefits of Federal Regulations and 

Unfunded Mandates on State, Local, and Tribal Entities, Washington, D.C.

41 OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
235

has decided to await further guidance regarding consistent valuation and reporting of Hg 

emissions before it once again monetizes Hg in its rulemakings.

N. Discussion of Other Comments 

Comments DOE received in response to the preliminary analysis on the 

soundness and validity of the methodologies and data DOE used are discussed in section 

IV. Other stakeholder comments in response to the preliminary analysis addressed the 

burdens and benefits associated with new energy conservation standards. DOE addresses 

these other stakeholder comments below.

1. Trial Standard Levels

Current standards maintain “harmonized” standards across phases, which means 

that a single-phase transformer must meet the same efficiency standard of its three-phase 

analog of three times the kVA. DOE is aware of the potential for misapplied standards to 

shift market demand to segments with relatively less stringent coverage and implanted 

phase harmonization to guard against incentivizing replacement of three-phase 

transformers with three smaller single-phase units.

HVOLT asserted that the previous 2007 rulemaking misstated the potential of 

three-phase distribution transformers early on in the rulemaking. Furthermore, HVOLT 

commented that, as a result, the final selected TSL for three-phase distribution 

transformers was low compared to the TSL selected for single-phase transformers. 

HVOLT believes that this has caused a misperception to the public that three-phase 
236

transformers received a less-stringent standard, when it is in fact of equal stringency to 

the standard for single-phase transformers. HVOLT requested that this point be clarified 

in the NOPR. (HVOLT, No. 33 at p. 2)

Relative to single-phase designs, DOE understands three-phase transformers to 

have an efficiency disadvantage related to harmonics and zero-sequence fluxes. That 

disadvantage happens to be of such a size that efficiency will be similar, all else constant, 

for transformers with the same power per phase. For example, a 75 kVA three-phase unit 

should have efficiency similar to that of a 25 kVA single-phase unit designed to similar 

specifications. During the 2007 rulemaking, DOE created additional TSLs to 

“harmonize” efficiency across phase counts in responses to stakeholder comment that 

standards should be set thus. 

For the NOPR, DOE relaxed the phase harmonization constraint on single-phase 

efficiency, particularly for LVDT and MVDT equipment classes. DOE believes that 

market shift will not occur unless standards are dramatically disproportionate.

DOE acknowledges that acceptance of this “constant efficiency per phase” 

principle is not universal and seeks comment on where and why this principle may or 

may not apply.

Hammond Power Solutions and Howard Industries expressed agreement with 

DOE’s method to develop TSLs. (HPS, No. 3 at p. 5; HI, No. 23 at p. 7) However, ASAP 
237

commented that it would like to see the TSL at the minimum LCC point as well as the 

maximum level that is cost-effective, which typically would fall above the LCC. (ASAP, 

Pub. Mtg. Tr., No. 34 at p. 127) Furthermore, ASAP encouraged DOE to consider a TSL 

that retained a variety of core materials as an option, and to include a wide range of TSLs 

for consideration. (ASAP, Pub. Mtg. Tr., No. 34 at p. 128) ABB commented that DOE 

should develop a structured methodology that evaluates and ranks each CSL and TSL 

based on technological feasibility, economic justification, and maximum improvement in 

energy efficiency. (ABB, No. 14 at pp. 16, 19-20) ABB added that DOE should 

recognize the risk of inadvertently shifting demand between kVA within the same 

equipment class, between single-phase and three-phase units within the same product 

group (e.g. MVDT or LVDT), between product groups (e.g., between liquid-immersed 

and MVDT), and between new product offerings and refurbished transformers. (ABB, 

No. 14 at pp. 16, 19-20) Edison Electrical Institute requested that DOE provide detailed 

tables explaining how the CSL numbers in the preliminary analysis relate to the TSL 

numbers in the NOPR. (EEI, No. 29 at p. 6)

DOE constructs TSLs from efficiency levels (ELs), the NOPR analog of the 

Preliminary Analysis’ CSLs, using several economic factors (e.g., maximum LCC) and 

technological factors (e.g., maximum LCC where a variety of core materials are 

available) factors. DOE did not choose a TSL corresponding to minimized LCC savings 

above the maximum, but does have a TSL corresponding to the CSL above maximum 

LCC savings that offers increased efficiency. DOE does not use CSLs from the 

Preliminary Analysis to construct TSLs, but does outline in section V.A the ELs 
238

packaged into each TSL. Finally, DOE is concerned about the possibility of inadvertently 

shifting demand between equipment.

2. Proposed Standards

NRECA and T&DEC cautioned that raising efficiency standards for mediumvoltage dry-type transformers would limit a customer’s purchase choices and increase 

costs both for utilities and their customers. They stated that higher efficiency standards 

would not be economically justified for rural electric cooperatives. (NRECA/ T&DEC, 

No. 31 and No. 36 at pp. 1–2) FPT stated its opposition to new efficiency standards that 

would limit the choices available to customers to achieve the optimum transformer design 

for each circumstance. (FPT, No. 27 at p. 1) PHI recommended that DOE not raise 

efficiency standards for liquid-immersed distribution transformers because they cannot 

withstand additional increases in weight or dimensions. (PHI, Nos. 26 and 37 at p. 1) FPT 

commented that, if the efficiency levels for medium-voltage dry-type transformers are 

increased, the PBP for the cost increase to meet the higher mandated efficiency should be 

no longer than 3 to 5 years. (FPT, No. 27 at p. 18)

DOE appreciates comment on appropriate standard levels and acknowledges that 

maintaining availability of equipment offering unique consumer utility is important. DOE 

believes, however, that it has made an effort to quantify the costs of more efficient 

equipment to a variety of consumers as well as the costs of additional size and weight.
239

The Kentucky Association of Electric Cooperatives, Inc. (KAEC) commented that 

the current minimum efficiency standards for liquid-immersed distribution transformers 

already represent the maximum energy efficiency that is economically justified, and any 

higher efficiency level will come at a high cost. (KAEC, No. 4 at pp. 1-2) Power Partners 

commented that increases to the current minimum efficiency standards are not justified 

based on the increased costs to manufacturers, customers, and ultimately, consumers. 

(PP, No. 19 at p. 1) FPT noted that it is not in favor of increasing efficiency standards for 

dry-type distribution transformers because higher efficiency levels will take away 

customer choices for the most optimum transformer design. (FPT, No. 27 at pp. 1, 18) 

Additionally, FPT commented that, because most MVDTs are custom built, they should 

not be subject to standards. (FPT, No. 27 at pp. 1, 18) Furthermore, HVOLT noted that 

any standard level should not require a specific design, including materials, 

configurations and manufacturing methods. HVOLT believes that the 2007 rule reached 

the limits for many of these considerations, and once the inputs are corrected, the analysis 

will indicate this result. (HVOLT, No. 33 at p. 3)

Berman Economics suggested that DOE set the efficiency standard at the highest 

level justified, which appeared to be CSL 4 in the preliminary analysis or CSL 2 at a 

minimum after adjusting for overpricing. BE suggested that change itself affects 

manufacturers more than the amount of change because any change in efficiency 

standards requires manufacturers to re-optimize designs to ensure compliance. (BE, No. 

16 at p. 2) Joint comments submitted by ASAP, ACEEE and NRDC noted that DOE’s 

analysis shows that amorphous steel is cost-effective and commented that DOE should 
240

propose standards that utilize amorphous steel technology for a portion of the market. 

They believed that DOE should identify the portion of the market that would be the least 

disrupted by standards set at an amorphous level, such as small, pad-mounted liquidimmersed transformers (DL1 and DL4). It is their understanding that most of the 

manufacturers operating in the DL1 and DL4 markets already have amorphous 

capabilities, and very few smaller manufacturers operate in this market segment. 

(ASAP/ACEEE/NRDC, No. 28 at pp. 4-5) Alternatively, Power Partners commented that 

DOE should not set a standard level that requires a core steel above the M3 grade. (PP, 

No. 19 at p. 4)

DOE conducted several analyses in order to meet its obligation to evaluate the 

economic justifiability of a proposed standard, notable among them the LCC and PBP 

Analysis and the NIA. Summaries of those analyses are present in this notice, with more 

detailed descriptions of the methodology in the TSD. In proposing or setting standards, 

DOE considers a variety of criteria, including the availability of materials needed to reach 

a given efficiency. In the case of core steel, DOE has conducted a supply analysis 

(presented in appendix 3A of the NOPR TSD) examining the ability of the market to 

supply steel at different efficiency levels and requests comment on the methodology and 

results of this analysis. The barriers to entry and the potential for limited supply of 

amorphous steel, and the potential for significant price in the near future, are important 

qualitative factors that DOE is considering. Comment [A18]: Change recommended by 

OIRA.
241

The Copper Development Association (CDA) and Pacific Gas & Electric (PG&E) 

commented that DOE should set standards levels at the highest efficiency that is 

technologically feasible and economically justified. (CDA, No. 17 at p. 1; PG&E, Pub. 

Mtg. Tr., No. 34 at pp. 24-25) The American Public Power Association (APPA) noted 

that the October 2007 final rule for distribution transformers achieved the highest 

efficiency levels that are economically justified and expressed concern that when 

efficiency levels gravitate to the highest levels achievable, the cost benefit analysis 

breaks down as peripheral costs rise. Pole replacements and pad mount replacements–due 

to larger distribution transformers–also add costs that might not be adequately captured in 

the DOE analysis. (APPA, No. 21 at p. 2)

HVOLT opined that this rulemaking is a reassessment of the previous distribution 

transformers rulemaking but with new economic parameters. It asserted that national 

standards should be doable with known technology, not require an invention, and not put 

a lot of manufacturers out of business. (HVOLT, Pub. Mtg. Tr., No. 34 at p. 116) 

NRECA and the Transmission & Distribution Engineering Committee (T&DEC) together 

recommended that DOE not raise the efficiency standards for liquid-filled distribution 

transformers, because the current levels already represent the economically justified 

maximum efficiency. Both added that many users in rural areas with low transformer 

loads cannot economically justify the current level. (NRECA/T&DEC, Nos. 31 and 36 at 

p. 1) Additionally, the added weight and increased dimensions of the higher efficiency 

distribution transformers would require pole replacement for many cooperatives and 

other utilities. NRECA/T&DEC opined that when higher efficiency levels are mandated, 
242

the result could be less production, less-competitive materials, questionable availability, 

and reduced competition. (NRECA/T&DEC, Nos. 31 and 36 at p. 3)

FPT noted that if DOE sets higher efficiency standards, it should coordinate with 

the EPA to reinstitute the Energy Star program for distribution transformers so that 

manufacturers can use the label to market their products. (FPT, No. 27 at p. 4) FPT also 

commented that higher efficiency levels based on a specified loading of 35 percent or 50 

percent could result in greater losses for applications that operate at higher load factors. 

FPT provided an example of a NEMA Premium transformer versus a TP1 transformer 

with an 80-degree temperature rise, indicating that the TP1 transformer with the lower 

temperature rise could have a greater efficiency at loadings above 50 percent. (FPT, No. 

27 at pp. 5-7)

The Kentucky Association of Electric Cooperatives (KAEC) believed that liquidimmersed single-phase standards are adequate and achieve maximum efficiency while 

being economically justifiable. It believed the biggest efficiency gains have already been 

made. In addition, KAEC expressed concern that, as a small manufacturer, it would need 

higher capital investment to meet any increase in efficiency standards, and that its energy 

savings would be less and payback periods longer because it and other rural electric 

cooperatives serve fewer customers. (KAEC, Pub. Mtg. Tr., No. 34 at pp. 22-23)

As stated previously, DOE seeks to set the highest energy conservation standards 

that are technologically feasible, economically justified, and that will result in significant 
243

energy savings and appreciates any analysis that would assist DOE in evaluating the 

appropriate standard using these parameters.

3. Alternative Methods

Mr. Kenneth Harden (HK), a design engineer, offered to DOE a copy of his 

thesis, which evaluated the impact of federal regulations and operational conditions on 

the efficiency of low-voltage dry-type distribution transformers, and provided 

recommendations to optimize future rulemakings certifying the energy efficiency of lowvoltage dry-type distribution transformers. It also recommended the specification of lowvoltage dry-type distribution transformers and the design of transformers for industrial 

power networks. (HK, No. 12 at p. 1)

DOE appreciates Mr. Harden’s submission and would welcome a meeting to 

discuss some of the thoughts he has put forth on the rulemaking process in general and on 

distribution transformers in particular.

4. Labeling

Both NEMA and FPT recommended that DOE establish a uniform approach for 

how to mark a distribution transformer nameplate to indicate compliance with the 

applicable energy conservation standard in 10 CFR 431.196. (FPT, No. 27 at p. 20; 

NEMA, No. 13 at p. 9) NEMA proposed the following: “DOE 10 CFR PART 431 

COMPLIANT.” (NEMA, No. 13 at p. 9) 
244

DOE appreciates the comments regarding labeling and will take it under 

consideration as it continues to explore appropriate requirements for certification, 

compliance, enforcement and how labeling may fit into those processes. Certification 

requirements for distribution transformers can be found in 10 CFR 429.47.

5. Imported Units

NEMA commented that, although covered non-compliant products that are 

imported for export must be marked as such, U.S. Customs and Border Protection will 

likely have difficulty determining which products are covered, and whether a covered 

product is compliant, other than those marked for export. (NEMA, No. 13 at p. 9)

DOE notes that it is the responsibility of the importer, and not United States 

Customs, to establish compliance just as any manufacturer would. DOE welcomes further 

comment and evidence that can suggest imported transformers are failing to meet 

standards.

V. Analytical Results and Conclusions

A. Trial Standard Levels 

DOE analyzed the benefits and burdens of the TSLs developed for today’s 

proposed rule. DOE examined seven TSLs for liquid-immersed distribution transformers, 

six TSLs for low-voltage, dry-type distribution transformers, and five TSLs for mediumvoltage dry-type distribution transformers. Table V.1 through Table V.3 present the TSLs 

analyzed and the corresponding efficiency level for the representative unit in each 
245

transformer design line. For other capacities in each design line, the corresponding 

efficiencies for each TSL are given in appendix 8-B in the NOPR TSD. The baseline in 

the tables is equal to the current energy conservation standard. 

For liquid-immersed distribution transformers, the efficiency levels in each TSL 

can be characterized as follows: TSL 1 represents an increase in efficiency where a 

diversity of electrical steels are cost-competitive and economically feasible for all design 

lines; TSL 2 represents EL1 for all design lines; TSL 3 represents the maximum 

efficiency level achievable with M3 core steel; TSL 4 represents the maximum NPV 

with 7 percent discounting; TSL 5 represents EL 3 for all design lines; TSL 6 represents 

the maximum source energy savings with positive NPV with 7 percent discounting; and 

TSL 7 represents the maximum technologically feasible level (max tech).

For low-voltage, dry-type distribution transformers, the efficiency levels in each 

TSL can be characterized as follows: TSL 1 represents the maximum efficiency level 

achievable with M6 core steel; TSL 2 represents NEMA premium levels; TSL 3 

represents the maximum EL achievable using butt-lap miter core manufacturing for 

single-phase distribution transformers, and full miter core manufacturing for three-phase 

distribution transformers; TSL 4 represents the maximum NPV with 7 percent 

discounting; TSL 5 represents the maximum source energy savings with positive NPV 

with 7 percent discounting; and TSL 6 represents the maximum technologically feasible 

level (max tech).
246

For medium-voltage, dry-type distribution transformers, the efficiency levels in 

each TSL can be characterized as follows: TSL 1 represents EL1 for all design lines; TSL 

2 represents an increase in efficiency where a diversity of electrical steels are costcompetitive and economically feasible for all design lines; TSL 3 represents the 

maximum NPV with 7 percent discounting; TSL 4 represents the maximum source 

energy savings with positive NPV with 7 percent discounting; and TSL 5 represents the 

maximum technologically feasible level (max tech).

Table V.1 Efficiency Values of the Trial Standard Levels for Liquid-Immersed 

Transformers by Design Line

Design 

Line Baseline

TSL

1 2 3 4 5 6 7

Percent

1 99.08 99.16 99.16 99.16 99.22 99.25 99.31 99.50

2 98.91 98.91 99.00 99.00 99.07 99.11 99.18 99.41

3 99.42 99.48 99.48 99.51 99.57 99.54 99.61 99.73

4 99.08 99.16 99.16 99.16 99.22 99.25 99.31 99.60

5 99.42 99.48 99.48 99.51 99.57 99.54 99.61 99.69

Table V.2. Efficiency Values of the Trial Standard Levels for Low-Voltage DryType Transformers by Design Line

Design 

Line Baseline

TSL

1 2 3 4 5 6

Percent

6 98.00 98.00 98.60 98.80 99.17 99.17 99.44

7 98.00 98.47 98.60 98.80 99.17 99.17 99.44

8 98.60 99.02 99.02 99.25 99.44 99.58 99.58
247

Table V.3. Efficiency Values of the Trial Standard Levels for Medium-Voltage DryType Transformers by Design Line

Design 

Line Baseline

TSL

1 2 3 4 5

Percent

9 98.82 98.93 98.93 99.04 99.04 99.55

10 99.22 99.29 99.37 99.37 99.37 99.63

11 98.67 98.81 98.81 99.13 99.13 99.50

12 99.12 99.21 99.30 99.46 99.46 99.63

13A 98.63 98.69 98.69 99.04 99.04 99.45

13B 99.15 99.19 99.28 99.45 99.45 99.52

B. Economic Justification and Energy Savings

1. Economic Impacts on Customers

a. Life-Cycle Cost and Payback Period

To evaluate the net economic impact of standards on transformer customers, DOE 

conducted LCC and PBP analyses for each TSL. In general, a higher-efficiency product 

would affect customers in two ways: (1) annual operating expense would decrease; and 

(2) purchase price would increase. Section III.F.2 of this notice discusses the inputs DOE 

used for calculating the LCC and PBP. The LCC and PBP results are calculated from 

transformer cost and efficiency data that are modeled in the engineering analysis (section 

IV.C). During the negotiated rulemaking, DOE presented separate transformer cost data 

based on 2010 and 2011 material prices to the committee members. DOE conducted its 

LCC and PBP analysis utilizing both the 2010 and 2011 material price cost data. The 

average results of these two analyses are presented here.
248

For each design line, the key outputs of the LCC analysis are a mean LCC savings 

and a median PBP relative to the base case, as well as the fraction of customers for which 

the LCC will decrease (net benefit), increase (net cost), or exhibit no change (no impact) 

relative to the base-case product forecast. No impacts occur when the product efficiencies 

of the base-case forecast already equal or exceed the efficiency at a given TSL. Table V.4

through Table V.17 show the key results for each transformer design line.

Table V.4 Summary Life-Cycle Cost and Payback Period Results for Design Line 1 

Representative Unit

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.16 99.16 99.16 99.22 99.25 99.31 99.50

Transformers with Net 

LCC Cost (%) 57.9 57.9 57.9 4.8 4.8 8.0 55.4

Transformers with Net 

LCC Benefit (%) 41.8 41.8 41.8 95.0 95.0 92.0 44.6

Transformers with No 

Change in LCC (%) 0.2 0.2 0.2 0.2 0.2 0.0 0.0

Mean LCC Savings ($) 36 36 36 641 641 532 50

Median PBP (Years) 20.2 20.2 20.2 7.9 7.9 10.0 19.2

Table V.5 Summary Life-Cycle Cost and Payback Period Results for Design Line 2 

Representative Unit

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.91 99.00 99.00 99.07 99.11 99.18 99.41

Transformers with Net 

LCC Cost (%) 0.0 14.2 14.2 9.8 11.2 15.8 80.2

Transformers with Net 

LCC Benefit (%) 0.0 85.8 85.8 90.2 88.8 84.3 19.8

Transformers with No 

Change in LCC (%) 100.0 0.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 0 309 309 338 300 250 -736

Median PBP (Years) 0.0 6.9 6.9 8.0 9.5 11.5 24.3
249

Table V.6 Summary Life-Cycle Cost and Payback Period Results for Design Line 3 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.48 99.48 99.51 99.57 99.54 99.61 99.73

Transformers with Net 

LCC Cost (%) 15.7 15.7 11.2 4.0 5.3 3.9 25.1

Transformers with Net 

LCC Benefit (%) 83.0 83.0 87.7 96.0 94.6 96.1 74.9

Transformers with No 

Change in LCC (%) 1.4 1.4 1.2 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2413 2413 3831 5591 5245 6531 4135

Median PBP (Years) 6.3 6.3 4.0 4.7 4.6 5.2 13.3

Table V.7 Summary Life-Cycle Cost and Payback Period Results for Design Line 4 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.16 99.16 99.16 99.22 99.25 99.31 99.60

Transformers with Net 

LCC Cost (%) 6.0 6.0 6.0 1.9 1.9 1.9 31.1

Transformers with Net 

LCC Benefit (%) 93.5 93.5 93.5 97.5 97.5 97.6 63.9

Transformers with No 

Change in LCC (%) 0.6 0.6 0.6 0.6 0.6 0.6 0.0

Mean LCC Savings ($) 862 862 862 3356 3356 3362 1274

Median PBP (Years) 5.0 5.0 5.0 4.1 4.1 4.1 14.6

Table V.8 Summary Life-Cycle Cost and Payback Period Results for Design Line 5 

Representative Unit 

Trial Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.48 99.48 99.51 99.57 99.54 99.61 99.69

Transformers with Net 

LCC Cost (%) 19.1 19.1 13.2 7.8 10.4 7.9 39.9

Transformers with Net 

LCC Benefit (%) 80.6 80.6 86.8 92.2 89.6 92.1 60.1

Transformers with No 

Change in LCC (%) 0.4 0.4 0.1 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 7787 7787 10288 12513 11395 12746 3626

Median PBP (Years) 4.0 4.0 4.2 6.3 5.7 8.3 16.9
250

Table V.9 Summary Life-Cycle Cost and Payback Period Results for Design Line 6 

Representative Unit

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 98.00 98.60 98.93 99.17 99.17 99.44

Transformers with Net Increase in LCC 

(%) 0.0 71.5 17.6 36.2 36.2 93.4

Transformers with Net LCC Savings (%) 0.0 28.5 82.4 63.8 63.8 6.6

Transformers with No Impact on LCC 

(%) 100.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 0 -125 335 187 187 -881

Median PBP (Years) 0.0 24.7 13.0 16.3 16.3 32.4

Table V.10 Summary Life-Cycle Cost and Payback Period Results for Design Line 

7 Representative Unit

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 98.47 98.60 98.80 99.17 99.17 99.44

Transformers with Net Increase in LCC 

(%) 1.8 1.8 2.0 3.7 3.7 46.4

Transformers with Net LCC Savings (%) 98.2 98.2 98.0 96.3 96.3 53.6

Transformers with No Impact on LCC 

(%) 0.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 1714 1714 1793 2270 2270 270

Median PBP (Years) 4.5 4.5 4.7 6.9 6.9 18.1

Table V.11 Summary Life-Cycle Cost and Payback Period Results for Design Line 

8 Representative Unit 

Trial Standard Level

1 2 3 4 5 6

Efficiency (%) 99.02 99.02 99.25 99.44 99.58 99.58

Transformers with Net Increase in LCC 

(%) 5.2 5.2 15.3 10.5 78.5 78.5

Transformers with Net LCC Savings (%) 94.8 94.8 84.7 89.5 21.5 21.5

Transformers with No Impact on LCC 

(%) 0.0 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2476 2476 2625 4145 -2812 -2812

Median PBP (Years) 8.4 8.4 12.3 11.0 24.5 24.5

Table V.12 Summary Life-Cycle Cost and Payback Period Results for Design Line 

9 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.93 98.93 99.04 99.04 99.55

Transformers with Net Increase in LCC 

(%) 3.4 3.4 5.7 5.7 53.4
251

Transformers with Net LCC Savings (%) 83.4 83.4 94.3 94.3 46.6

Transformers with No Impact on LCC (%) 13.3 13.3 0.0 0.0 0.0

Mean LCC Savings ($) 849 849 1659 1659 237

Median PBP (Years) 2.6 2.6 6.2 6.2 19.1

Table V.13 Summary Life-Cycle Cost and Payback Period Results for Design Line 

10 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.29 99.37 99.37 99.37 99.63

Transformers with Net Increase in LCC (%) 0.7 16.7 16.7 16.7 84.8

Transformers with Net LCC Savings (%) 98.8 83.3 83.3 83.3 15.2

Transformers with No Impact on LCC (%) 0.5 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 4509 4791 4791 4791 -12756

Median PBP (Years) 1.1 8.8 8.8 8.8 28.4

Table V.14 Summary Life-Cycle Cost and Payback Period Results for Design Line 

11 Representative Unit

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.81 98.81 99.13 99.13 99.50

Transformers with Net Increase in LCC 

(%) 20.6 20.6 25.7 25.7 76.1

Transformers with Net LCC Savings (%) 79.4 79.4 74.3 74.3 23.9

Transformers with No Impact on LCC 

(%) 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 1043 1043 2000 2000 -3160

Median PBP (Years) 10.7 10.7 14.1 14.1 24.5

Table V.15 Summary Life-Cycle Cost and Payback Period Results for Design Line 

12 Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.21 99.30 99.46 99.46 99.63

Transformers with Net Increase in LCC 

(%) 6.7 7.8 18.1 18.1 81.1

Transformers with Net LCC Savings (%) 93.3 92.2 81.9 81.9 18.9

Transformers with No Impact on LCC (%) 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 4518 6934 8860 8860 -12420

Median PBP (Years) 6.3 9.0 13.0 13.0 25.9
252

Table V.16 Summary Life-Cycle Cost and Payback Period Results for Design Line 

13A Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 98.69 98.69 99.04 99.04 99.45

Transformers with Net Increase in LCC 

(%) 52.2 52.2 64.4 64.4 97.1

Transformers with Net LCC Savings (%) 47.8 47.8 35.6 35.6 2.9

Transformers with No Impact on LCC (%) 0.0 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 25 25 -846 -846 -11077

Median PBP (Years) 16.5 16.5 21.7 21.7 37.1

Table V.17 Summary Life-Cycle Cost and Payback Period Results for Design Line 

13B Representative Unit 

Trial Standard Level

1 2 3 4 5

Efficiency (%) 99.19 99.28 99.45 99.45 99.52

Transformers with Net Increase in LCC 

(%) 28.5 26.3 52.7 52.7 67.2

Transformers with Net LCC Savings (%) 71.3 73.7 47.3 47.3 32.8

Transformers with No Impact on LCC (%) 0.2 0.0 0.0 0.0 0.0

Mean LCC Savings ($) 2733 4709 384 384 -5407

Median PBP (Years) 4.6 12.5 19.3 19.3 21.9

b. Customer Subgroup Analysis

DOE estimated customer subgroup impacts by determining the LCC impacts of 

the distribution transformer TSLs on purchasers of vault-installed transformers (primarily 

urban utilities). DOE included only the liquid-immersed design lines in this analysis, 

since those types account for more than ninety percent of the transformers purchased by 

electric utilities. Table V.18 shows the mean LCC savings at each TSL for this customer 

subgroup. 

Chapter 11 of the NOPR TSD explains DOE’s method for conducting the 

customer subgroup analysis and presents the detailed results of that analysis.
253

Table V.18 Comparison of Mean Life-Cycle Cost Savings for Liquid-Immersed 

Transformers Purchased by Consumer Subgroups (2010$)

Design 

Line Trial Standard Level

1 2 3 4 5 6 7

Medium Vault Replacement Subgroup

4 -422 -422 -422 106 106 113 -2,358

5 1062 1062 3203 4689 3854 4270 -5996

All Customers

4 862 862 862 3356 3356 3362 1274

5 7787 7787 10288 12513 11395 12746 3626

c. Rebuttable-Presumption Payback 

As discussed above, EPCA establishes a rebuttable presumption that an energy 

conservation standard is economically justified if the increased purchase cost for a 

product that meets the standard is less than three times the value of the first-year energy 

savings resulting from the standard. (42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) DOE 

calculated a rebuttable-presumption PBP for each TSL to determine whether DOE could 

presume that a standard at that level is economically justified. Table V.19 shows the 

rebuttable-presumption PBPs for the considered TSLs. Because only a single, average 

value is necessary for establishing the rebuttable-presumption PBP, DOE used discrete 

values rather than distributions for its input values. As required by EPCA, DOE based the 

calculations on the assumptions in the DOE test procedure for distribution transformers. 

(42 U.S.C. 6295(o)(2)(B)(iii), 6316(a)) As a result, DOE calculated a single rebuttablepresumption payback value, and not a distribution of PBPs, for each TSL.
254

Table V.19 Rebuttable-Presumption Payback Periods (years) for Liquid-Immersed 

Distribution Transformers

Design 

Line

Rated 

Capacity 

(kVA)

Trial Standard Level

1 2 3 4 5 6 7

1 50 17.1 17.1 17.1 8.3 8.3 10.2 16.3

2 25 0.0 9.5 9.5 9.9 11.0 12.5 21.3

3 500 5.8 5.8 4.5 4.9 4.9 5.2 11.9

4 150 4.7 4.7 4.7 3.9 3.9 4.0 13.5

5 1500 4.3 4.3 4.2 5.9 5.5 7.5 15.2

Table V.20 Rebuttable-Presumption Payback Periods (years) for Low-Voltage DryType Distribution Transformers

Design 

Line

Rated 

Capacity 

(kVA)

Trial Standard Level

1 2 3 4 5 6

6 25 0.0 15.9 13.0 15.0 15.0 26.5

7 75 4.2 4.2 4.4 6.4 6.4 14.9

8 300 6.8 6.8 10.4 9.7 20.2 20.2

Table V.21 Rebuttable-Presumption Payback Periods (years) for Medium-Voltage 

Dry-Type Distribution Transformers

Design 

Line

Rated 

Capacity 

(kVA)

Trial Standard Level

1 2 3 4 5

9 300 1.9 1.9 4.6 4.6 15.5

10 1500 1.9 5.7 5.7 5.7 21.8

11 300 9.5 9.5 13.0 13.0 18.8

12 1500 5.5 7.44 12.0 12.0 20.3

13A 300 11.9 11.9 22.2 22.2 28.9

13B 2000 5.2 11.1 19.1 19.1 19.4

DOE believes that the rebuttable-presumption PBP criterion (i.e., a limited PBP) 

is not sufficient for determining economic justification. Therefore, DOE has considered a 

full range of impacts, including those to customers, manufacturers, the Nation, and the 
255

environment. Section V.C provides a complete discussion of how DOE considered the 

range of impacts to select its proposed standards.

2. Economic Impact on Manufacturers

DOE performed a MIA to estimate the impact of amended energy conservation 

standards on manufacturers of distribution transformers. The section below describes the 

expected impacts on manufacturers at each TSL. Chapter 12 of the TSD explains the 

analysis in further detail.

a. Industry Cash-Flow Analysis Results

The tables below depict the financial impacts (represented by changes in INPV) 

of amended energy standards on manufacturers as well as the conversion costs that DOE 

estimates manufacturers would incur at each TSL. The effect of amended standards on 

INPV was analyzed separately for each type of distribution transformer manufacturer: 

liquid-immersed, medium-voltage dry-type, and low-voltage dry-type. To evaluate the 

range of cash flow impacts on the distribution transformer industry, DOE modeled two 

different scenarios using different assumptions for markups that correspond to the range 

of anticipated market responses to new and amended standards. A full description of 

these scenarios and their results can be found in chapter 12 of the NOPR TSD.

To assess the lower end of the range of potential impacts, DOE modeled the 

preservation of operating profit markup scenario, which assumes that manufacturers 

would be able to earn the same operating margin in absolute dollars in the standards case 
256

as in the base case. To assess the higher end of the range of potential impacts, DOE 

modeled a preservation of gross margin percentage markup scenario in which a uniform 

“gross margin percentage” markup is applied across all efficiency levels. In this scenario, 

DOE assumed that a manufacturer’s absolute dollar markup would increase as production 

costs increase in the standards case. 

The set of results below shows two tables of INPV impacts for each of the three 

types of distribution transformer manufacturers: the first table reflects the lower bound of 

impacts and the second represents the upper bound.

In the discussion that follows the tables, DOE also discusses the difference in cash 

flow between the base case and the standards case in the year before the compliance date 

for new and amended energy conservation standards. This figure represents how large the 

required conversion costs are relative to the cash flow generated by the industry in the 

absence of new and amended energy conservation standards. 

Table V.22 Manufacturer Impact Analysis for Liquid-Immersed Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6 7

INPV 2011$ 

M

625.1 585.5 532.1 523.8 461.0 451.2 427.5 297.9

Change in 

INPV

2011$ 

M

- (39.6) (92.9) (101.2) (164.0) (173.8)

(197.6

)

(327.2

)

% - (6.3) (14.9) (16.2) (26.2) (27.8) (31.6) (52.3)

Capital 

Conversio

n Costs

2011$ 

M

- 26.3 64.9 67.6 98.5 100.4 105.6 128.2

Product 

Conversio

n Costs

2011$ 

M

- 27.6 46.8 57.5 93.7 93.7 93.7 93.7 

Deleted: 583

Deleted: 529.9

Deleted: 521.5

Deleted: 460.1

Deleted: 4

Deleted: 425.2

Deleted: 296.0

Deleted: 41.5

Deleted: 95.1

Deleted: 103.6

Deleted: 165

Deleted: 6

Deleted: 199.9

Deleted: 329.1

Deleted: 6

Deleted: 15.2

Deleted: 6

Deleted: 4

Deleted: 32.0

Deleted: 6

Deleted: 28.8

Deleted: 67.7

Deleted: 70.7

Deleted: 99.8

Deleted: 101.7

Deleted: 108.7

Deleted: 130.7
257

Total 

Conversio

n Costs

2011$ 

M

- 53.9 111.7 125.1 192.1 194.1 199.3 221.8

*Note: Parentheses indicate negative values.

Table V.23 Manufacturer Impact Analysis for Liquid-Immersed Distribution 

Transformers - Preservation of Gross Margin Percentage Markup

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6 7

INPV 2011$ 

M

625.1 614.7 583.4 577.5 551.6 537.1 547.6 673.0

Change in 

INPV

2011$ 

M

- (10.4) (41.7) (47.6) (73.5) (88.0) (77.5) 48.0

% - (1.7) (6.7) (7.6) (11.8) (14.1) (12.4) 7.7

Capital 

Conversio

n Costs

2011$ 

M

- 26.3 64.9 67.6 98.5 100.4 105.6 128.2

Product 

Conversio

n Costs

2011$ 

M

- 27.6 46.8 57.5 93.7 93.7 93.7 93.7 

Total 

Conversio

n Costs

2011$ 

M

- 53.9 111.7 125.1 192.1 194.1 199.3 221.8

At TSL 1, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$39.6 million to -$10.4 million, corresponding 

to a change in INPV of -6.3 percent to -1.7 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 60.1 percent to $15.8 million, 

compared to the base-case value of $39.5 million in the year before the compliance date 

(2015).

While TSL 1 can be met with traditional steels, including M3, in all design lines, 

amorphous core transformers will be incrementally more competitive on a first cost basis, 

likely inducing some or many manufacturers to gradually build amorphous steel 

transformer production capacity. Because the production process for amorphous cores is 

Deleted: 56.4

Deleted: 114.5

Deleted: 128.2

Deleted: 193.4

Deleted: 195.4

Deleted: 202.4

Deleted: 224.3

Deleted: 612

Deleted: 581.2

Deleted: 575.1

Deleted: 550

Deleted: 534.3

Deleted: 545.2

Deleted: 671.1

Deleted: 12.3

Deleted: 43.9

Deleted: 49.9

Deleted: 74

Deleted: 90.8

Deleted: 79.8

Deleted: 46.1

Deleted: 2.0

Deleted: .0

Deleted: 8.0

Deleted: 9

Deleted: 5

Deleted: 8

Deleted: 4

Deleted: 28.8

Deleted: 67.7

Deleted: 70.7

Deleted: 99.8

Deleted: 101.7

Deleted: 108.7

Deleted: 130.7

Deleted: 56.4

Deleted: 114.5

Deleted: 128.2

Deleted: 193.4

Deleted: 195.4

Deleted: 202.4

Deleted: 224.3

Deleted: 41.5...9.6 million to -$12.3...0.4 million, 

...
258

entirely separate from that of silicon steel cores, large investments in new capital, 

including new core cutting equipment and annealing ovens will be required. 

Additionally, a great deal of testing, prototyping, design and manufacturing engineering 

resources will be required because most manufacturers have relatively little experience, if 

any, with amorphous steel transformers. These capital and production conversion 

expenses lead to a reduction in cash flow in the years preceding the standard. In the 

lower-bound scenario, DOE assumes manufacturers can only maintain annual operating 

profit in the standards case. Therefore, these conversion investments, and manufacturers’ 

higher working capital needs associated with more expensive transformers, drain cash 

flow and lead to a greater reduction in INPV, when compared to the upper-bound 

scenario. In the upper bound scenario, DOE assumes manufacturers will be able to fully 

markup and pass the higher product costs, leading to higher operating income. This 

higher operating income is essentially offset on a cash flow basis by the conversion costs 

and the increase in working capital requirements, leading to a negligible change in INPV 

at TSL1 in the upper-bound scenario.

At TSL 2, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$92.9 million to -$41.7 million, corresponding 

to a change in INPV of -14.9 percent to -6.7 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 122.7 percent to -$9 million, 

compared to the base-case value of $39.5 million in the year before the compliance date 

(2015).

Deleted: 95.1 million to -$43

Deleted: 15.2

Deleted: 125.9

Deleted: 10.2
259

TSL 2 requires the same efficiency levels as TSL 1, except for DL 2, which is 

increased from baseline to EL1. EL1, as opposed to the baseline efficiency, could induce 

manufacturers to build more amorphous capacity, when compared to TSL 1, because 

amorphous transformers become incremental more cost competitive. Because DL2 

represents the largest share of core steel usage of all design lines, this has a significant 

impact on investments. There are more severe impacts on industry in the lower-bound 

profitability scenario when these greater one-time cash outlays are coupled with slight 

margin pressure. In the high-profitability scenario, manufacturers are able to maintain 

gross margins, mitigating the adverse cash flow impacts of the increased investment in 

working capital (associated with more expensive transformers).

At TSL 3, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$101.2 million to -$47.6 million, 

corresponding to a change in INPV of -16.2 percent to -7.6 percent. At this proposed 

level, industry free cash flow is estimated to decrease by approximately 135.2 percent to -

$13.9 million, compared to the base-case value of $39.5 million in the year before the 

compliance date (2015).

TSL 3 results are similar to TSL 2 results because the efficiency levels are the 

same except for DL3 and DL5, which each increase to EL 2 under TSL 3. The increase 

in stringency makes more amorphous core transformers slightly more cost competitive in 

these DLs, likely increasing amorphous transformer capacity needs, all other things being 

equal, and driving more investment to meet the standards.

Deleted: 103

Deleted: to -$49.9 million

Deleted: 6

Deleted: 8

Deleted: 138.7

Deleted: 15.3
260

At TSL 4, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$164 million to -$73.5 million, corresponding 

to a change in INPV of -26.2 percent to -11.8 percent. At this proposed level, industry 

free cash flow is estimated to decrease by approximately 202 percent to -$40.3 million, 

compared to the base-case value of $39.5 million in the year before the compliance date 

(2015).

During interviews, manufacturers expressed differing views on whether the 

efficiency levels embodied in TSL 4 would shift the market away from silicon steels 

entirely. Because DL3 and DL5 must meet EL4 at this TSL, DOE expects the majority 

of the market would shift to amorphous core transformers at TSL 4 and above. Even 

assuming a sufficient supply of amorphous steel were available, TSL 4 and above would 

require a dramatic build up in amorphous core transformer production capacity. DOE 

believes this wholesale transition away from silicon steels could seriously disrupt the 

market, drive small businesses to either source their cores or exit the market, and lead 

even large businesses to consider moving production offshore or exiting the market 

altogether. The negative impacts are driven by the large conversion costs associated with 

new amorphous production lines and stranded assets of manufacturers’ existing silicon 

steel transformer production capacity. If the higher first costs at TSL 4 drive more 

utilities to refurbish rather than replace failed transformers, a scenario many 

manufacturers predicted at the efficiency levels and prices embodied in TSL 4, reduced 

transformer sales could cause further declines in INPV. 

Deleted: 165

Deleted: 74

Deleted: 4

Deleted: 9

Deleted: 203.5

Deleted: 9
261

At TSL 5, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$173.8 million to -$88 million, or a change in 

INPV of -27.8 percent to -14.1 percent. At this proposed level, industry free cash flow is 

estimated to decrease by approximately 230.8 percent to -$51.7 million, compared to the 

base-case value of $39.5 million in the year before the compliance date (2015).

TSL5 would likely shift the entire market to amorphous core transformers, 

leading to even greater investment needs than TSL4, driving the adverse impacts 

discussed above.

At TSL 6, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$197.6 million to -$77.5 million, 

corresponding to a change in INPV of -31.6 percent to -12.4 percent. At this proposed 

level, industry free cash flow is estimated to decrease by approximately 241.5 percent to -

$55.9 million, compared to the base-case value of $39.5 million in the year before the 

compliance date (2015).

The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that 

slightly more amorphous core production capacity will be needed because TSL 6-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to 

TSL 5.

Deleted: 6 million to -$90.

Deleted: 5

Deleted: 232.3

Deleted: 52.2

Deleted: 199.9

Deleted: 79.8

Deleted: 32

Deleted: 8

Deleted: 245.1

Deleted: 57.3
262

At TSL 7, DOE estimates impacts on INPV for liquid-immersed distribution 

transformer manufacturers to range from -$327.2 million to $48 million, corresponding to 

a change in INPV of -52.3 percent to 7.7 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 267.2 percent to -$66 million, 

compared to the base-case value of $39.5 million in the year before the compliance date 

(2015).

The impacts at TSL 7 are similar to those DOE expects at TSL 6, except that 

slightly more amorphous core production capacity will be needed because TSL 6-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 7 compared to 

TSL 6, incrementally reducing industry value.

Table V.24 Manufacturer Impact Analysis Low-voltage Dry-Type Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6

INPV 2011

$ M 219.5 202.7 199.9 192.8 173.4 164.2 136.4 

Change in 

INPV

2011

$ M - (16.8) (19.6) (26.7) (46.1) (55.3) (83.1)

% - (7.7) (8.9) (12.2) (21.0) (25.2) (37.9)

Capital 

Conversion 

Costs

2011

$ M - 5.1 7.4 11.4 23.8 23.8 23.8 

Product 

Conversion 

Costs

2011

$ M - 2.9 3.8 5.0 8.0 8.0 8.0 

Total 

Conversion 

Costs

2011

$ M - 8.0 11.1 16.4 31.8 31.8 31.8 

Deleted: 329.1

Deleted: 46.1

Deleted: 6

Deleted: 4

Deleted: 270.1

Deleted: 67.1

Deleted: 4

Deleted: 17.2

Deleted: 8

Deleted: 3

Deleted: 3.0

Deleted: 3
263

* Note: Parentheses indicate negative values.

Table V.25 Manufacturer Impact Analysis Low-voltage Dry-Type Distribution 

Transformers - Preservation of Gross Margin Percentage Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5 6

INPV 2011$ 

M

219.5 236.4 234.6 239.6 250.4 263.4 321.5 

Change in 

INPV

2011$ 

M

- 16.9 15.0 20.1 30.9 43.9 101.9 

% - 7.7 6.8 9.1 14.1 20.0 46.4 

Capital 

Conversion 

Costs

2011$ 

M

- 5.1 7.4 11.4 23.8 23.8 23.8 

Product 

Conversion 

Costs

2011$ 

M

- 2.9 3.8 5.0 8.0 8.0 8.0 

Total 

Conversion 

Costs

2011$ 

M

- 8.0 11.1 16.4 31.8 31.8 31.8 

*Note: Parentheses indicate negative values.

At TSL 1, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$16.8 million to $16.9 million, corresponding 

to a change in INPV of -7.7 percent to 7.7 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 26.1 percent to $10.2 million, 

compared to the base-case value of $13.8 million in the year before the compliance date 

(2015).

TSL 1 provides many design paths for manufacturers to comply. DOE’s 

engineering analysis indicates manufacturers can continue to use the low-capital butt-lap 

core designs, meaning investment in mitering or wound core capability is not necessary. 

Manufacturers can use higher-quality grain oriented steels in butt-lap designs to meet 

TSL1, source some or all cores, or invest in modified mitering capability. 

Deleted: 5

Deleted: 17.0

Deleted: 3

Deleted: 3.0

Deleted: 3

Deleted: 17.2

Deleted: 17

Deleted: 8

Deleted: 27

Deleted: 1
264

At TSL 2, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$19.6 million to $15 million, corresponding to 

a change in INPV of -8.9 percent to 6.8 percent. At this proposed level, industry free cash 

flow is estimated to decrease by approximately 37.4 percent to $8.6 million, compared to 

the base-case value of $13.8 million in the year before the compliance date (2015).

TSL2 differs from TSL1 in that DL6 and DL7 must meet EL3, up from baseline 

for DL 6 and EL2 for DL 7, which will likely require advanced core construction 

techniques, including mitering or wound core designs. Much of the incremental 

investment needed at TSL2 is due to the increase from EL2 to EL3 in DL7, which 

represents more than three-quarters of the market by core weight in this superclass. This 

increase in stringency for DL7 drives the need for investment in mitering capacity. All 

major manufacturers already have mitering capability but moving the high-volume DL7 

from butt-lap to mitered cores would slow throughput and require additional capacity. A 

range of options are still available at TSL2 as manufacturers could use higher grade 

steels, mitering, or wound cores. Additionally, at TSL2, manufacturers will still be able to 

use M6, which is common in the current market. Some manufacturers, however, usually 

small manufacturers, indicated during interviews they would begin to source a greater 

share of their cores rather than make investments in mitering machines or wound core 

production lines.

Deleted: EL2
265

At TSL 3, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$26.7 million to $20.1 million, corresponding 

to a change in INPV of -12.2 percent to 9.1 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 53.9 percent to $6.4 million, 

compared to the base-case value of $13.8 million in the year before the compliance date 

(2015).

TSL3 represents EL4 for DL6, DL7, and DL8. DOE’s engineering analysis shows 

that manufacturers will be able to meet EL4 using M4 or better steels. M4, however, is a 

thinner steel than is currently employed, which, in combination with larger cores, will 

dramatically slow production throughput, requiring the industry to expand capacity to 

maintain current shipments. This is the reason for the increase in conversion costs. In the 

lower-bound profitability scenario, when DOE assumes the industry cannot fully pass on 

incremental costs, these investments and the higher working capital needs drain cash flow 

and lead to the negative impacts shown in the preservation of operating profit scenario. 

In the high-profitability scenario, impacts are slightly positive because DOE assumes 

manufacturers are able to fully recoup their conversion expenditures through higher 

operating cash flow. 

At TSL 4, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$46.1 million to $30.9 million, corresponding 

to a change in INPV of -21 percent to 14.1 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 102.1 percent to -$0.3 million, 
266

compared to the base-case value of $13.8 million in the year before the compliance date 

(2015).

TSL 4 and higher would create significant challenges for the industry and likely 

disrupt the marketplace. DOE’s conversion costs at TSL 4 assume the industry will 

entirely convert to amorphous wound core technology to meet the efficiency standards. 

Few manufacturers of distribution transformers in this superclass have any experience 

with amorphous steel or wound core technology and would face a steep learning curve. 

This is reflected in the large conversion costs and adverse impacts on INPV in the 

Preservation of Operating Profit scenario. Most manufacturers DOE interviewed 

expected many low-volume manufacturers to exit the DOE-covered market altogether if 

amorphous steel was required to meet the standard. As such, DOE believes TSL 4 could 

lead to greater consolidation than the industry would experience at lower TSLs.

At TSL 5, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$55.3 million to $43.9 million, corresponding 

to a change in INPV of -25.2 percent to 20 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 122.6 percent to -$3.1 million, 

compared to the base-case value of $13.8 million in the year before the compliance date 

(2015).

The impacts at TSL 5 are similar to those DOE expects at TSL 4, except that 

slightly more amorphous core production capacity will be needed because TSL 5-
267

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 5 compared to 

TSL 4.

At TSL 6, DOE estimates impacts on INPV for low-voltage dry-type distribution 

transformer manufacturers to range from -$83.1 million to $101.9 million, corresponding 

to a change in INPV of -37.9 percent to 46.4 percent. At this proposed level, industry free 

cash flow is estimated to decrease by approximately 125.7 percent to -$3.5 million, 

compared to the base-case value of $13.8 million in the year before the compliance date 

(2015).

The impacts at TSL 6 are similar to those DOE expects at TSL 5, except that 

slightly more amorphous core production capacity will be needed because TSL 6-

compliant transformers will have somewhat heavier cores and thus require more 

amorphous steel. This leads to slightly greater capital expenditures at TSL 6 compared to 

TSL 5.

Table V.26 Manufacturer Impact Analysis Medium-voltage Dry-Type Distribution 

Transformers - Preservation of Operating Profit Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5

INPV 2011

$ M 91.0 87.1 84.5 79.7 77.1 71.0 

Change in 

INPV

2011

$ M - (3.8) (6.5) (11.3) (13.9) (20.0)

% - (4.2) (7.1) (12.4) (15.3) (21.9)

Capital 

Conversion 

Costs

2011

$ M - 2.6 4.0 7.5 10.9 11.1 
268

Product 

Conversion 

Costs

2011

$ M - 1.0 3.0 4.7 4.7 8.0 

Total 

Conversion 

Costs

2011

$ M - 3.6 7.0 12.2 15.6 19.1 

*Note: Parentheses indicate negative values.

Table V.27 Manufacturer Impact Analysis Medium-voltage Dry-Type Distribution 

Transformers - Preservation of Gross Margin Percentage Markup Scenario

Units Base 

Case

Trial Standard Level

1 2 3 4 5

INPV 2011$ 

M

91.0 89.1 90.0 95.1 92.5 114.1 

Change in 

INPV

2011$ 

M

- (1.9) (0.9) 4.1 1.5 23.1 

% - (2.0) (1.0) 4.5 1.7 25.4 

Capital 

Conversion 

Costs

2011$ 

M

- 2.6 4.0 7.5 10.9 11.1 

Product 

Conversion 

Costs

2011$ 

M

- 1.0 3.0 4.7 4.7 8.0 

Total 

Conversion 

Costs

2011$ 

M

- 3.6 7.0 12.2 15.6 19.1 

*Note: Parentheses indicate negative values.

At TSL 1, DOE estimates impacts on INPV for medium-voltage dry-type 

distribution transformer manufacturers to range from -$3.8 million to -$1.9 million, 

corresponding to a change in INPV of -4.2 percent to -2.0 percent. At this proposed level, 

industry free cash flow is estimated to decrease by approximately 28.1 percent to $4.1

million, compared to the base-case value of $5.7 million in the year before the 

compliance date (2015).

TSL 1 represents EL1 for all MVDT DLs. At TSL 1, manufacturers have a variety 

of steels available to them, including M4, the most common steel in the superclass, in 
269

DL12, the largest DL by core steel usage. Additionally, the vast majority of the market 

already uses step-lap mitering technology. Therefore, DOE anticipates only moderate 

conversion costs for the industry, mainly associated with slower throughput due to larger 

cores. Some manufacturers may need to slightly expand capacity to maintain throughput 

and/or modify equipment to manufacturer with greater precision and tighter tolerances. In 

general, however, conversion expenditures should be relatively minor compared INPV. 

For this reason, TSL 1 yields relatively minor adverse changes to INPV in the standards 

case.

At TSL 2, DOE estimates impacts on INPV for medium-voltage dry-type 

distribution transformer manufacturers to range from -$6.5 million to -$0.9 million, 

corresponding to a change in INPV of -7.1 percent to -1.0 percent. At this proposed level, 

industry free cash flow is estimated to decrease by approximately 52.1 percent to $2.7

million, compared to the base-case value of $5.7 million in the year before the 

compliance date (2015).

Compared to TSL 1, TSL 2 requires EL2, rather than EL1, in DLs 10, 12, and 

13B. Because M4 (as well as the commonly used H1) can still be employed to meet 

these levels, DOE expects similar results at TSL 2 as at TSL 1. Slightly greater 

conversion costs will be required as the compliant transformers will have heavier cores, 

all other things being equal, meaning additionally capacity may be necessary depending 

on each manufacturer’s current capacity utilization rate. As with TSL 1, TSL 2 will not 

Deleted: $
270

require significant changes to most manufacturers production processes because the 

thickness of the steels will not change significantly, if at all.

At TSL 3, DOE estimates impacts on INPV for medium-voltage dry-type 

distribution transformer manufacturers to range from -$11.3 million to $4.1 million, 

corresponding to a change in INPV of -12.4 percent to 4.5 percent. At this proposed 

level, industry free cash flow is estimated to decrease by approximately 90.1 to $0.6

million, compared to the base-case value of $5.7 million in the year before the 

compliance date (2015).

At TSL 4, DOE estimates impacts on INPV for medium-voltage dry-type 

distribution transformer manufacturers to range from -$13.9 million to $1.5 million, 

corresponding to a change in INPV of -15.3 percent to 1.7 percent. At this proposed 

level, industry free cash flow is estimated to decrease by approximately -117.2 percent to 

-$1.0 million, compared to the base-case value of $5.7 million in the year before the 

compliance date (2015).

TSL 3 and TSL 4 require EL2 for DL9 and DL10, but EL4 for DL11 through 

DL13B, which hold the majority of the volume. Several manufacturers were concerned 

TSL 3 would require some of the high volume design lines to use either H1,HO, or 

transition entirely to amorphous wound cores. Without a cost effective M-grade steel 

option, the industry could face severe disruption. Even assuming a sufficient supply of 

Hi-B steel, a major concern of some manufacturers because it is used and generally 
271

priced for power transformer market, relatively large expenditures would be require in 

R&D and engineering as most manufacturers would have to move production to steel 

with which they have little experience. DOE estimate total conversion costs would more 

than double at TSL 3, relative to TSL 2. If, based on the movement of steel prices, EL4 

can be met cost competitively only through the use of amorphous steel or an exotic 

design with little or no current place in scale manufacturing, manufacturers would face 

significant challenges that DOE believes would lead to consolidation and likely cause 

many low-volume manufacturers to exit the product line or source their cores. 

At TSL 5, DOE estimates impacts on INPV for medium-voltage dry-type 

distribution transformer manufacturers to range from -$20 million to $23.1 million, 

corresponding to a change in INPV of -21.9 percent to 25.4 percent. At this proposed 

level, industry free cash flow is estimated to decrease by approximately 152.8 percent to -

$3.0 million, compared to the base-case value of $5.7 million in the year before the 

compliance date (2015).

TSL 5 represents max-tech and yields results similar to but more severe than TSL 

4 results. The entire market must convert to amorphous wound cores at TSL 5. Because 

the industry has no experience with wound core technology, and little, if any, experience 

with amorphous steel, this transition would represent a tremendous challenge for 

industry. Interviews suggest most manufacturers would exit the market rather altogether 

or source their cores rather than make the investments in plant and equipment and R&D 

required to meet these levels. 
272

b. Impacts on Employment

Liquid Immersed. Based on interviews and industry research, DOE estimates 

that there are roughly 5,000 employees associated with DOE-covered liquid immersed 

distribution transformer production and some three-quarters of these workers are located 

domestically. DOE does not expect large changes in domestic employment to occur due 

to today’s proposed standard. Manufacturers generally agreed that amorphous production 

is more labor-intensive and would require greater labor expenditures than tradition steel 

core production. So long as domestic plants are not relocated outside the country, DOE 

expects moderate increases in domestic employment at TSL1 and TSL2. There could be a 

small drop in employment at small, domestic manufacturing firms if small manufacturers 

began sourcing cores. This employment would presumably transfer to the core makers, 

some of whom are domestic and some of whom are foreign. There is a risk that energy 

conservation standards that largely require the use of amorphous steel could cause even 

large manufacturers who are currently producing transformers in the U.S. to evaluate 

offshore options. Faced with the prospect of wholesale changes to their production 

process, large investments and stranded assets, some manufacturers expect to strongly 

consider shifting production offshore at TSL 3 due to the increased labor expenses 

associated with the production processes required to make amorphous steel cores. In 

summary, at TSLs 1 and 2, DOE does not expect significant impacts on employment, but 

at TSL 3 or greater, which would require more investment, the impact is very uncertain.
273

Low-Voltage Dry-Type. Based on interviews with manufacturers, DOE 

estimates that there are approximately 2,200 employees associated with DOE-covered 

LVDT production. Approximately 75 percent of these employees are located outside of 

the U.S. Typically, high volume units are made in Mexico, taking advantage of lower 

labor rates, while custom designs are made closer to the manufacturer’s customer base or 

R&D centers. DOE does not expect large changes in domestic employment to occur due 

to a standard. Most production already occurs outside the U.S., and, by and large, 

manufacturers agreed that most design changes necessary to meet higher energy 

conservation standards would increase labor expenditures, not decrease it. If, however, 

small manufacturers began sourcing cores instead of manufacturing them in-house, there 

could be a small drop in employment at these firms. This employment would presumably 

transfer to the core makers, some of whom are domestic and some of whom are foreign. 

In summary, DOE does not expect significant changes to domestic LVDT industry 

employment levels as a result of the proposed standards. Higher TSLs may lead to small 

declines in domestic employment as more firms will be challenged with what amounts to 

clean-sheet redesigns. Facing the prospect of greenfield investments, these manufacturers 

may elect to make those investments in lower-labor cost countries.

Medium-Voltage Dry-Type. Based on interviews with manufacturers, DOE 

estimates that there are approximately 1,850 employees associated with DOE-covered 

MVDT production. Approximately 75 percent of these employees are located 

domestically. With the exception of TSLs that require amorphous cores, manufacturers 

agreed that most design changes necessary to meet higher energy conservation standards 
274

would increase labor expenditures, not decrease them, but current production equipment 

would not be stranded, mitigating any incentive to move production offshore. 

Corroborating this, the largest manufacturer and domestic employer in this market has 

indicated that the standard, as proposed in this rule, will not cause their company to 

reconsider production location. As such, DOE does not expect significant changes to 

domestic MVDT industry employment levels as a result of the standard proposed in this 

rule. For TSLs that would require amorphous cores, DOE does anticipate significant 

changes to domestic MVDT industry employment levels.

c. Impacts on Manufacturing Capacity 

Based on manufacturer interviews, DOE believes that there is significant excess 

capacity in the distribution transformer market. Shipments in the industry are well down 

from their peak in 2007, according to manufacturers. Therefore, DOE does not believe 

there would be any production capacity constraints at TSLs that do not require dramatic 

transitions to amorphous cores. For those TSLs that require amorphous cores in 

significant volumes, DOE believes there is potential for capacity constraints in the near 

term due to limitations on core steel availability. However, for the levels proposed in this 

rule, DOE does not foresee any capacity constraints.

d. Impacts on Subgroups of Manufacturers

Small manufacturers, niche equipment manufacturers, and manufacturers 

exhibiting a cost structure substantially different from the industry average could be 

affe V.B.2.a, using average cost 
275

assumptions to develop an industry cash-flow estimate is inadequate to assess differential 

impacts among manufacturer subgroups. DOE considered four subgroups in the MIA: 

liquid-immersed, dry-type medium-voltage, dry-type low-voltage, and small 

manufacturers. For a discussion of the impacts on the first three groups, see section 

IV.I.1. For a discussion of the impacts on the small manufacturer subgroup, see the 

Regulatory Flexibility Analysis in section VI.B and chapter 12 of the NOPR TSD. 

e. Cumulative Regulatory Burden

While any one regulation may not impose a significant burden on manufacturers, 

the combined effects of recent or impending regulations may have serious consequences 

for some manufacturers, groups of manufacturers, or an entire industry. Assessing the 

impact of a single regulation may overlook this cumulative regulatory burden. In addition 

to energy conservation standards, other regulations can significantly affect 

manufacturers’ financial operations. Multiple regulations affecting the same 

manufacturer can strain profits and lead companies to abandon product lines or markets 

with lower expected future returns than competing products. For these reasons, DOE 

conducts an analysis of cumulative regulatory burden as part of its rulemakings 

pertaining to appliance efficiency. During previous stages of this rulemaking DOE 

identified a number of requirements in addition to amended energy conservation 

standards for distribution transformers. The following section briefly addresses comments 

DOE received with respect to cumulative regulatory burden and summarizes other key 

related concerns that manufacturers raised during interviews.
276

Many interested parties have expressed concerns about the recent implementation 

of previous standards for distribution transformers. For low-voltage dry-type distribution 

transformers, the Energy Policy Act of 2005 required compliance with NEMA TP-1 

standards by the beginning of 2007. For liquid-immersed and medium-voltage dry-type 

transformers, DOE’s 2007 energy conservation standards rulemaking required 

compliance by the beginning of 2010. Power Partners has stated that the last set of energy 

conservation standards for distribution transformers went into effect very recently and 

required large capital investments and retooling. Therefore, any new standards which 

would require additional retooling and investment would create a cumulative burden for 

manufacturers. (PP, No. 19 at p. 1) EEI also commented that DOE standards were 

increased less than 14 months ago, with effective dates of January 1, 2007 for lowvoltage dry-type distribution transformers and January 1, 2010 for medium-voltage drytype and liquid-immersed designs. (EEI, Pub. Mtg. Tr., No. 34 at p. 28)

Other factors that manufacturers stated may contribute to cumulative regulatory 

burden are foreign regulations and Underwriters Laboratories listing compliance 

requirements. Manufacturers that export their products to places such as Canada, China, 

Mexico, or the Middle East need to comply with foreign as well as domestic regulations. 

The Canadian government regulates efficiency of dry-type transformers through its 

Canadian Standards Association (CSA) standard C802.2-00 (effective January 1, 2005). 

China regulates transformer efficiency through its China Compulsory Certification 

(CCC) program (effective May 1, 2002), which requires manufacturers of various 

products including transformers to obtain the CCC Mark before exporting to or selling in 
277

the Chinese market. In Mexico, liquid-immersed units are regulated through NOM-002-

SEDE-2010. 

DOE discusses these and other requirements, and includes the full details of the 

cumulative regulatory burden analysis, in Chapter 12 of the NOPR TSD.

3. National Impact Analysis

a. Significance of Energy Savings

To estimate the energy savings through 2045 attributable to potential standards 

for distribution transformers, DOE compared the energy consumption of those products 

under the base case to their energy consumption under each TSL. Table V.28 presents the 

forecasted NES for each considered TSL. The savings were calculated using the approach 

described in section IV.G.

Table V.28 Cumulative National Energy Savings for Distribution Transformer Trial 

Standard Levels in 2016–2045

Trial Standard Level

1 2 3 4 5 6 7

Liquid-Immersed

Cumulative Source Savings 

2045 (Quads) 0.36 0.74 0.82 1.44 1.42 1.70 2.70

Low-Voltage Dry-Type

Cumulative Source Savings 

2045 (Quads) 1.09 1.12 1.29 1.86 1.90 2.08

Medium-Voltage Dry-Type

Cumulative Source Savings 

2045 (Quads) 0.06 0.13 0.23 0.23 0.37
278

Chapter 10 of the NOPR TSD provides additional details on the NES values 

reported and also presents tables that show the magnitude of the energy savings 

discounted at rates of 3 percent and 7 percent. Discounted energy savings represent a 

policy perspective in which energy savings realized farther in the future are less 

significant than energy savings realized in the nearer term.

b. Net Present Value of Customer Costs and Benefits

DOE estimated the cumulative NPV to the Nation of the total costs and savings 

for customers that would result from the TSLs considered for distribution transformers. 

In accordance with the OMB’s guidelines on regulatory analysis,42 DOE calculated NPV 

using both a 7-percent and a 3-percent real discount rate. The 7-percent rate is an estimate 

of the average before-tax rate of return on private capital in the U.S. economy, and 

reflects the returns on real estate and small business capital as well as corporate capital. 

DOE used this discount rate to approximate the opportunity cost of capital in the private 

sector, because recent OMB analysis has found the average rate of return on capital to be 

near this rate. DOE used the 3-percent rate to capture the potential effects of standards on 

private consumption (e.g., through higher prices for products and reduced purchases of 

energy). This rate represents the rate at which society discounts future consumption flows 

to their present value. This rate can be approximated by the real rate of return on longterm government debt (i.e., yield on United States Treasury notes minus annual rate of 

change in the Consumer Price Index), which has averaged about 3 percent on a pre-tax 

basis for the past 30 years.

 

42 OMB Circular A-4, section E (Sept. 17, 2003). Available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4. (Last accessed March 18, 2011.)
279

Table V.29 shows the customer NPV results for each TSL DOE considered for 

distribution transformers, using both a 7-percent and a 3-percent discount rate. In each 

case, the impacts cover the lifetime of products purchased in 2016–2045. See chapter 10 

of the NOPR TSD for more detailed NPV results. 

Table V.29 Cumulative Net Present Value of Consumer Benefits for Distribution 

Transformers Trial Standard Levels for Units Sold in 2016–2045

Discount 

Rate (%)

Trial Standard Level

1 2 3 4 5 6 7

Liquid-Immersed

Net Present Value 

(billion 2010$)

3 3.66 7.39 8.24 14.21 13.48 13.17 -1.11

7 0.75 1.51 1.73 2.96 2.65 1.76 -8.25

Low-Voltage Dry-Type

Net Present Value 

(billion 2010$)

3 7.81 7.79 8.51 11.16 9.37 2.69

7 2.03 1.97 2.03 2.36 1.37 -2.41

Medium-Voltage Dry-Type

Net Present Value 

(billion 2010$)

3 0.42 0.67 0.90 0.90 -0.38

7 0.10 0.13 0.06 0.06 -0.84

The results shown here reflect the default product price trend, which uses constant 

prices. DOE conducted an NPV sensitivity analysis using alternative price trends. DOE 

developed one forecast in which prices decline after 2010, and one in which prices rise. 

The NPV results from the associated sensitivity cases are described in appendix 10-C of 

the NOPR TSD. 

c. Indirect Impacts on Employment 

As discussed above, DOE expects energy conservation standards for distribution 

transformers to reduce energy costs for equipment owners, and the resulting net savings 
280

to be redirected to other forms of economic activity. Those shifts in spending and 

economic activity could affect the demand for labor. As described in section IV.J, DOE 

used an input/output model of the U.S. economy to estimate indirect employment impacts 

of the TSLs that DOE considered in this rulemaking. DOE understands that there are 

uncertainties involved in projecting employment impacts, especially changes in the later 

years of the analysis. Therefore, DOE generated results for near-term timeframes (2015–

2020), where these uncertainties are reduced. 

The results suggest that today’s proposed standards are likely to have negligible 

impact on the net demand for labor in the economy. The net change in jobs is so small 

that it would be imperceptible in national labor statistics and might be offset by other, 

unanticipated effects on employment. Chapter 13 of the NOPR TSD presents more 

detailed results.

4. Impact on Utility or Performance of Equipment

DOE believes that the standards it is proposing today will not lessen the utility or 

performance of distribution transformers. 

5. Impact of Any Lessening of Competition 

DOE has also considered any lessening of competition that is likely to result from 

new and amended standards. The Attorney General determines the impact, if any, of any 

lessening of competition likely to result from a proposed standard, and transmits such 
281

determination to the Secretary, together with an analysis of the nature and extent of such 

impact. (42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))

To assist the Attorney General in making such a determination, DOE has 

provided DOJ with copies of this notice and the TSD for review. DOE will consider 

DOJ’s comments on the proposed rule in preparing the final rule, and DOE will publish 

and respond to DOJ’s comments in that document.

6. Need of the Nation to Conserve Energy 

Enhanced energy efficiency, where economically justified, improves the Nation’s 

energy security, strengthens the economy, and reduces the environmental impacts or 

costs of energy production. Reduced electricity demand due to energy conservation 

standards is also likely to reduce the cost of maintaining the reliability of the electricity 

system, particularly during peak-load periods. As a measure of the expected energy 

conservation out to 2045, Table V.30 presents the estimated energy savings in terms of 

equivalent generating capacity for the TSLs that DOE considered in this rulemaking.

Table V.30 Expected Energy Savings out to 2045 Represented as Equivalent

Generating Capacity Under Distribution Transformer Trial Standard Levels

Trial Standard Level

1 2 3 4 5 6 7

Liquid-Immersed (GW) 0.610 1.23 1.33 2.24 2.21 2.53 3.73

Low-Voltage Dry-Type (GW) 1.62 1.66 1.90 2.70 2.75 2.92 --

Medium-Voltage Dry-Type (GW) 0.091 0.174 0.332 0.332 0.510 -- --

Total 2.33 3.06 3.56 5.28 5.47 5.46 3.73

Deleted: this reduced demand

Deleted: reduction

Deleted: in 2045

Comment [A19]: Changes recommended by 

OIRA.

Deleted: Reduction in National Electric

Deleted: in 2045

Comment [A20]: Changes recommended by 

OIRA.
282

Energy savings from standards for distribution transformers could also produce 

environmental benefits in the form of reduced emissions of air pollutants and greenhouse 

gases associated with electricity production. Table V.31 provides DOE’s estimate of 

cumulative CO2, NOX, and Hg emissions reductions projected to result from the TSLs 

considered in this rulemaking. DOE reports annual CO2, NOX, and Hg emissions 

reductions for each TSL in chapter 15 of the NOPR TSD.

IV.M, DOE did not report SO2 emissions reductions from 

power plants because, due to SO2 emissions caps, there is uncertainty about the effect of 

energy conservation standards on the overall level of SO2 emissions in the United States. 

DOE also did not include NOX emissions reduction from power plants in States subject to 

CAIR because an energy conservation standard would not affect the overall level of NOX

emissions in those States due to the emissions caps mandated by CAIR.

Table V.31 Summary of Emissions Reduction Estimated for Distribution 

Transformer Trial Standard Levels (cumulative in 2016-2045)

Trial Standard Level

1 2 3 4 5 6 7

Liquid-Immersed

 CO2 (million metric tons) 31.2 62.7 67.7 113 112 128 186

 NOX (thousand tons) 25.5 51.2 55.3 92.7 91.5 104 152

 Hg (tons) 0.209 0.420 0.454 0.762 0.751 0.857 1.25

Low-Voltage Dry-Type

 CO2 (million metric tons) 82.1 83.9 96.0 137 139 148 --

 NOX (thousand tons) 67.0 68.6 78.4 112 114 121 --

 Hg (tons) 0.551 0.564 0.645 0.918 0.934 0.992 --
283

As part of the analysis for this proposed rule, DOE estimated monetary benefits 

likely to result from the reduced emissions of CO2 and NOX that DOE estimated for each 

of the TSLs considered. As discussed in section IV.M, DOE used values for the SCC 

developed by an interagency process. The four values for CO2 emissions reductions 

resulting from that process (expressed in 2010$) are $4.9/metric ton (the average value 

from a distribution that uses a 5-percent discount rate), $22.3/metric ton (the average 

value from a distribution that uses a 3-percent discount rate), $36.5/metric ton (the 

average value from a distribution that uses a 2.5-percent discount rate), and $67.6/metric 

ton (the 95th-percentile value from a distribution that uses a 3-percent discount rate). 

These values correspond to the value of emission reductions in 2010; the values for later 

years are higher due to increasing damages as the magnitude of climate change increases. 

Table V.32 presents the global value of CO2 emissions reductions at each TSL. 

For each of the four cases, DOE calculated a present value of the stream of annual values 

using the same discount rate as was used in the studies upon which the dollar-per-ton 

values are based. DOE calculated domestic values as a range from 7 percent to 23 percent 

of the global values, and these results are presented in chapter 16 of the NOPR TSD.

Medium-Voltage Dry-Type

 CO2 (million metric tons) 4.62 8.80 16.8 16.8 25.7 -- --

 NOX (thousand tons) 3.77 7.19 13.7 13.7 21.0 -- --

 Hg (tons) 0.031 0.059 0.113 0.113 0.173 -- --
284

Table V.32 Estimates of Global Present Value of CO2 Emissions Reduction Under 

Distribution Transformer Trial Standard Levels

TSL

5% discount 

rate, average*

3% discount 

rate, average*

2.5% discount 

rate, average*

3% discount 

rate, 95th

percentile*

Million 2010$

Liquid-Immersed

1 173 1003 1747 3051

2 350 2026 3528 6160

3 382 2219 3866 6746

4 655 3831 6681 11643

5 646 3779 6591 11486

6 752 4414 7705 13414

7 1140 6754 11811 20523

Low-Voltage Dry-Type

1 481 2820 4921 8570

2 492 2884 5032 8764

3 562 3297 5753 10020

4 800 4693 8190 14264

5 814 4776 8336 14517

6 866 5076 8858 15427

Medium-Voltage Dry-Type

1 27 159 277 483

2 52 302 528 919

3 98 576 1006 1751

4 98 576 1006 1751

5 151 884 1543 2688

DOE is well aware that scientific and economic knowledge about the contribution 

of CO2 and other GHG emissions to changes in the future global climate and the potential 

resulting damages to the world economy continues to evolve rapidly. Thus, any value 

placed on reducing CO2 emissions in this rulemaking is subject to change. DOE, together 

with other Federal agencies, will continue to review various methodologies for estimating 

the monetary value of reductions in CO2 and other GHG emissions. This ongoing review 
285

will consider the comments on this subject that are part of the public record for this and 

other rulemakings, as well as other methodological assumptions and issues. However, 

consistent with DOE’s legal obligations, and taking into account the uncertainty involved 

with this particular issue, DOE has included in this NOPR the most recent values and 

analyses resulting from the ongoing interagency review process.

DOE also estimated a range for the cumulative monetary value of the economic 

benefits associated with NOX emissions reductions anticipated to result from amended 

standards for refrigeration products. The low and high dollar-per-ton values that DOE 

used are discussed in section IV.M. Table V.33 presents the cumulative present values for 

each TSL calculated using 7-percent and 3-percent discount rates.

Table V.33 Estimates of Present Value of NOX Emissions Reduction Under 

Distribution Transformer Trial Standard Levels

TSL 3% discount rate 7% discount rate

Million 2010$

Liquid-Immersed

1 9 to 94 3 to 32

2 19 to 191 6 to 64

3 20 to 208 7 to 69

4 35 to 356 11 to 117

5 34 to 351 11 to 115

6 40 to 408 13 to 132

7 60 to 616 19 to 194

Low-Voltage Dry-Type

1 25 to 261 8 to 85

2 26 to 267 8 to 87

3 30 to 305 10 to 99

4 42 to 434 14 to 141

5 43 to 442 14 to 143
286

6 46 to 470 15 to 152

Medium-Voltage Dry-Type

1 1 to 15 0 to 5

2 3 to 28 1 to 9

3 5 to 53 2 to 17

4 5 to 53 2 to 17

5 8 to 82 3 to 27

7. Summary of National Economic Impacts

The NPV of the monetized benefits associated with emissions reductions can be 

viewed as a complement to the NPV of the customer savings calculated for each TSL 

considered in this rulemaking. Table V.34 through Table V.36 present the NPV values 

that result from adding the estimates of the potential economic benefits resulting from 

reduced CO2 and NOX emissions in each of four valuation scenarios to the NPV of 

customer savings calculated for each TSL considered in this rulemaking, at both a sevenpercent and three-percent discount rate. The CO2 values used in the columns of each table 

correspond to the four scenarios for the valuation of CO2 emission reductions presented 

in section IV.M.

Table V.34 Liquid-Immersed Distribution Transformers: Net Present Value of 

Customer Savings Combined with Net Present Value of Monetized Benefits from 

CO2 and NOX Emissions Reductions 

TSL

Consumer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 3.8 4.7 5.5 6.8

2 7.8 9.5 11.0 13.7

3 8.6 10.6 12.2 15.2

4 14.9 18.2 21.1 26.2
287

5 14.2 17.5 20.3 25.3

6 14.0 17.8 21.1 27.0

7 0.1 6.0 11.0 20.0

TSL

Consumer NPV at 7% Discount Rate added with:

SCC Value of 

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 0.9 1.8 2.5 3.8

2 1.9 3.6 5.1 7.7

3 2.1 4.0 5.6 8.5

4 3.6 6.9 9.7 14.7

5 3.3 6.5 9.3 14.3

6 2.5 6.2 9.5 15.3

7 -7.1 -1.4 3.7 12.5

* These label values represent the global SCC in 2010, in 2010$. The present values have been calculated 

with scenario-consistent discount rates. 

** Low Value corresponds to $450 per ton of NOX emissions. Medium Value corresponds to $2,537 per ton 

of NOX emissions. High Value corresponds to $4,623 per ton of NOX emissions.

Table V.35 Low-Voltage Dry-Type Distribution Transformers: Net Present Value of 

Customer Savings Combined with Net Present Value of Monetized Benefits from 

CO2 and NOX Emissions Reductions 

TSL

Consumer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 8.3 10.8 12.9 16.6

2 8.3 10.8 13.0 16.8

3 9.1 12.0 14.4 18.8

4 12.0 16.1 19.6 25.9

5 10.2 14.4 17.9 24.3

6 3.6 8.0 11.8 18.6

TSL

Consumer NPV at 7% Discount Rate added with:

SCC Value of

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 2.5 4.9 7.0 10.7

2 2.5 4.9 7.1 10.8

3 2.6 5.4 7.8 12.1

4 3.2 7.1 10.6 16.8

5 2.2 6.2 9.8 16.0
288

6 -1.5 2.7 6.5 13.2

Table V.36 Medium-Voltage Dry-Type Distribution Transformers: Net Present 

Value of Customer Savings Combined with Net Present Value of Monetized Benefits 

from CO2 and NOX Emissions Reductions

TSL

Consumer NPV at 3% Discount Rate added with:

SCC Value of 

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 0.5 0.6 0.7 0.9

2 0.7 1.0 1.2 1.6

3 1.0 1.5 1.9 2.7

4 1.0 1.5 1.9 2.7

5 -0.2 0.6 1.2 2.4

TSL

Consumer NPV at 7% Discount Rate added with:

SCC Value of 

$4.9/metric ton 

CO2

*

and Low 

Value for NOX

**

SCC Value of 

$22.3/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$36.5/metric ton 

CO2

*

and Medium 

Value for NOX

**

SCC Value of 

$67.6/metric ton 

CO2

*

and High 

Value for NOX

**

Billion 2010$

1 0.1 0.3 0.4 0.6

2 0.2 0.4 0.7 1.1

3 0.2 0.6 1.1 1.8

4 0.2 0.6 1.1 1.8

5 -0.7 0.1 0.7 1.9

Although adding the value of customer savings to the values of emission 

reductions provides a valuable perspective, two issues should be considered. First, the 

national operating cost savings are domestic U.S. customer monetary savings that occur 

as a result of market transactions, while the value of CO2 reductions is based on a global 

value. Second, the assessments of operating cost savings and the SCC are performed with 

different methods that use quite different time frames for analysis. The national operating 

cost savings is measured for the lifetime of products shipped in 2016–2045. The SCC 

values, on the other hand, reflect the present value of future climate-related impacts 
289

resulting from the emission of one metric ton of CO2 in each year. These impacts 

continue well beyond 2100.

8. Other Factors 

The Secretary of Energy, in determining whether a standard is economically 

justified, may consider any other factors that the Secretary deems to be relevant. (42 

U.S.C. 6295(o)(2)(B)(i)(VI)) 

Electrical steel is a critical consideration in the design and manufacture of 

distribution transformers, amounting for more than 60 percent of the distribution 

transformers mass in some designs. Rapid changes in the supply or pricing of certain 

grades can seriously hinder manufacturers’ abilities to meet the market demand and, as a 

result, this rulemaking has given an uncommon level of attention to effects of electrical 

steel supply and availability.

The most important point to note is that several energy efficiency levels in each 

design line are reachable only by using amorphous steel, which is available in the United 

States from a single supplier that does not have enough present capacity to supply the 

industry at all-amorphous standard levels. Several more energy efficiency levels are 

reachable with the top grades of conventional electrical steels (“grain-oriented”) but 

result in distribution transformers that are unlikely to be cost-competitive with the often 

more-efficient amorphous units. As stated above, switching to amorphous steel is not 

practicable as there are availability concerns with amorphous steel.
290

Distribution transformers are also highly customized products; manufacturers 

routinely build only one or a handful of units of a particular design and require flexibility 

with respect to construction materials in order to do this competitively. Setting a standard 

that either technologically or economically required amorphous material would both 

eliminate a large amount of design flexibility and expose the industry to enormous risk 

with respect to supply and pricing of core steel. For both reasons, DOE considered 

electrical steel availability to be a major factor in determining which TSLs were 

economically justified.

C. Proposed Standards

When considering proposed standards, the new or amended energy conservation 

standard that DOE adopts for any type (or class) of covered product shall be designed to 

achieve the maximum improvement in energy efficiency that the Secretary determines is 

technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) In 

determining whether a standard is economically justified, the Secretary must determine 

whether the benefits of the standard exceed its burdens to the greatest extent practicable, 

in light of the seven statutory factors discussed previously. (42 U.S.C. 6295(o)(2)(B)(i)) 

The new or amended standard must also “result in significant conservation of energy.” 

(42 U.S.C. 6295(o)(3)(B))

For today’s NOPR, DOE considered the impacts of standards at each TSL, 

beginning with the maximum technologically feasible level, to determine whether that 
291

level was economically justified. Where the max-tech level was not justified, DOE then 

considered the next most efficient level and undertook the same evaluation until it 

reached the highest efficiency level that is both technologically feasible and economically 

justified and saves a significant amount of energy.

To aid the reader in understanding the benefits and/or burdens of each TSL, tables 

in this section summarize the quantitative analytical results for each TSL, based on the 

assumptions and methodology discussed herein. The efficiency levels contained in each 

TSL are described in section V.A. In addition to the quantitative results presented in the 

tables, DOE also considers other burdens and benefits that affect economic justification. 

These include the impacts on identifiable subgroups of customers who may be 

disproportionately affected by a national standard, and impacts on employment. Section 

V.B.1 presents the estimated impacts of each TSL for these subgroups. DOE discusses 

the impacts on employment in transformer manufacturing in section V.B.2.b, and 

discusses the indirect employment impacts in section V.B.3.c.

1. Benefits and Burdens of Trial Standard Levels Considered for Liquid-Immersed 

Distribution Transformers 

Table V.37 and Table V.38 summarize the quantitative impacts estimated for each 

TSL for liquid-immersed distribution transformers.

Table V.37 Summary of Analytical Results for Liquid-Immersed Distribution 

Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

National Energy 0.36 0.74 0.82 1.44 1.42 1.70 2.70
292

Savings (quads)

NPV of Consumer Benefits (2010$ billion)

3% discount rate 3.66 7.39 8.24 14.21 13.48 13.17 -1.11

7% discount rate 0.75 1.51 1.73 2.96 2.65 1.76 -8.25

Cumulative Emissions Reduction

CO2 (million metric tons) 31.2 62.7 67.7 113 112 128 186

NOX (thousand tons) 25.5 51.2 55.3 92.7 91.5 104 152

Hg (tons) 0.209 0.420 0.454 0.762 0.751 0.857 1.25

Value of Emissions Reduction

CO2 (2010$ million)* 173 to 

3051

350 to 

6160

382 to 

6746

655 to 

11643

646 to 

11486

752 to 

13414

1140 to 

20523

NOX – 3% discount rate 

(2010$ million)

9 to 94 19 to 

191

20 to 

208

35 to 

356

34 to 

351

40 to 

408

60 to 

616

NOX – 7% discount rate 

(2010$ million)

3 to 32 6 to 64 7 to 69 11 to 

117

11 to 

115

13 to 

132

19 to 

194

* Range of the economic value of CO2 reductions is based on estimates of the global benefit of reduced CO2 

emissions.

Table V.38 Summary of Analytical Results for Liquid-Immersed Distribution 

Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

Manufacturer Impacts

Industry NPV (2011$ 

million)

586 to 

615

532 to 

583

524 to 

578

461 to 

552

451 to 

537

428 to 

548

298 to 

673

Industry NPV (% 

change)

(6.3) to 

(1.7)

(14.9) to 

(6.7)

(16.2) to 

(7.6)

(26.2) to 

(11.8)

(27.8) to 

(14.1)

(31.6) to 

(12.4)

(52.3) to 

7.7

Consumer Mean LCC Savings (2010$)

Design line 1 36 36 36 641 641 532 50

Design line 2 0 309 309 338 300 250 -736

Design line 3 2413 2413 3831 5591 5245 6531 4135

Design line 4 862 862 862 3356 3356 3362 1274

Design line 5 7787 7787 10288 12513 11395 12746 3626

Deleted: 584

Deleted: 613

Deleted: 530

Deleted: 581

Deleted: 522

Deleted: 575

Deleted: 460

Deleted: 551

Deleted: 534

Deleted: 425

Deleted: 545

Deleted: 296

Deleted: 671

Deleted: 6

Deleted: 2.0

Deleted: 15.2

Deleted: .0

Deleted: 6

Deleted: 8.0

Deleted: 4

Deleted: 9

Deleted: 5

Deleted: 32.0

Deleted: 8

Deleted: 6

Deleted: 4
293

Consumer Median PBP (years)

Design line 1 20.2 20.2 20.2 7.9 7.9 10.0 19.2

Design line 2 0.0 6.9 6.9 8.0 9.5 11.5 24.3

Design line 3 6.3 6.3 4.0 4.7 4.6 5.2 13.3

Design line 4 5.0 5.0 5.0 4.1 4.1 4.1 14.6

Design line 5 4.0 4.0 4.2 6.3 5.7 8.3 16.9

Distribution of Consumer LCC Impacts

Design line 1

Net Cost (%) 57.9 57.9 57.9 4.8 4.8 8.0 55.4

Net Benefit (%) 41.8 41.8 41.8 95.0 95.0 92.0 44.6

No Impact (%) 0.2 0.2 0.2 0.2 0.2 0.0 0.0

Design line 2

Net Cost (%) 0.0 14.2 14.2 9.8 11.2 15.8 80.2

Net Benefit (%) 0.0 85.8 85.8 90.2 88.8 84.3 19.8

No Impact (%) 100.0 0.0 0.0 0.0 0.0 0.0 0.0

Design line 3

Net Cost (%) 15.7 15.7 11.2 4.0 5.3 3.9 25.1

Net Benefit (%) 83.0 83.0 87.7 96.0 94.6 96.1 74.9

No Impact (%) 1.4 1.4 1.2 0.0 0.0 0.0 0.0

Design line 4

Net Cost (%) 6.0 6.0 6.0 1.9 1.9 1.9 31.1

Net Benefit (%) 93.5 93.5 93.5 97.5 97.5 97.6 63.9

No Impact (%) 0.6 0.6 0.6 0.6 0.6 0.6 0.0

Design line 5

Net Cost (%) 19.1 19.1 13.2 7.8 10.4 7.9 39.9

Net Benefit (%) 80.6 80.6 86.8 92.2 89.6 92.1 60.1

No Impact (%) 0.4 0.4 0.1 0.0 0.0 0.0 0.0

First, DOE considered TSL 7, the most efficient level (max tech), which would 

save an estimated total of 2.70 quads of energy through 2045, an amount DOE considers 

significant. TSL 7 has an estimated NPV of customer benefit of -$8.25 billion using a 7 

percent discount rate, and -$1.11 billion using a 3 percent discount rate. 
294

The cumulative emissions reductions at TSL 7 are 186 million metric tons of CO2, 

152 thousand tons of NOX, and 1.25 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 7 ranges from $1,140 million to $20,523 million.

At TSL 7, the average LCC impact ranges from -$736 for design line 2 to $4,135 

for design line 3. The median PBP ranges from 24.3 years for design line 2 to 13.3 years 

for design line 3. The share of customers experiencing a net LCC benefit ranges from 

19.8 percent for design line 2 to 74.9 percent for design line 3.

At TSL 7, the projected change in INPV ranges from a decrease of $327 million 

to an increase of $48 million. If the decrease of $327 million were to occur, TSL 7 could 

result in a net loss of 52.3 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 7, there is a risk of very large negative impacts on 

manufacturers due to the substantial capital and engineering costs they would incur and 

the market disruption associated with the likely transition to a market entirely served by 

amorphous steel. Additionally, if manufacturers’ concerns about their customers 

rebuilding rather than replacing transformers at the price points projected for TSL 7 are 

realized, new transformer sales would suffer and make it even more difficult to recoup 

investments in amorphous transformer production capacity. Additionally, if 

manufacturers’ concerns about their customers rebuilding rather than replacing 

transformers at the price points projected for TSL 7 are realized, new transformer sales 

would suffer and make it even more difficult to recoup investments in amorphous 

transformer production capacity. DOE also has concerns about the competitive impact of 

Comment [A21]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 3.73 gigawatts under TSL 

7.

Deleted: 329

Deleted: 46

Deleted: 329

Deleted: 6
295

TSL 7 on the electrical steel industry, as only one proven supplier of amorphous ribbon 

currently serves the U.S. market. 

The Secretary tentatively concludes that, at TSL 7 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive average customer LCC 

savings, emission reductions, and the estimated monetary value of the emissions 

reductions would be outweighed by the potential multi-billion dollar negative net 

economic cost, the economic burden on customers as indicated by large PBPs, significant 

increases in installed cost, and the large percentage of customers who would experience 

LCC increases, the capital and engineering costs that could result in a large reduction in 

INPV for manufacturers, and the risk that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards at TSL 7. Consequently, DOE 

has tentatively concluded that TSL 7 is not economically justified. 

Next, DOE considered TSL 6, which would save an estimated total of 1.70 quads 

of energy through 2045, an amount DOE considers significant. TSL 6 has an estimated 

NPV of customer benefit of $1.76 billion using a 7 percent discount rate, and $13.17 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 6 are 128 million metric tons of CO2, 

104 thousand tons of NOX, and 0.857 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 6 ranges from $752 million to $13,414 million.

Comment [A22]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 

Comment [A23]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.53 gigawatts under TSL 

6.
296

At TSL 6, the average LCC impact ranges from $250 for design line 2 to $12,746 

for design line 5. The median PBP ranges from 11.5 years for design line 2 to 4.1 years 

for design line 4. The share of customers experiencing a net LCC benefit ranges from 

84.3 percent for design line 2 to 97.6 percent for design line 4.

At TSL 6, the projected change in INPV ranges from a decrease of $198 million 

to a decrease of $78 million. If the decrease of $198 million were to occur, TSL 6 could 

result in a net loss of 31.6 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 6, DOE recognizes the risk of very large negative 

impacts on manufacturers due to the large capital and engineering costs and the market 

disruption associated with the likely transition to a market entirely served by amorphous 

steel. Additionally, if manufacturers’ concerns about their customers rebuilding rather 

than replacing their transformers at the price points projected for TSL 6 are realized, new 

transformer sales would suffer and make it even more difficult to recoup investments in 

amorphous transformer production capacity. 

The energy savings under TSL 6 are achievable only by using amorphous steel, 

which is currently available from a single supplier that has annual production capacity of 

approximately 100,000 tons, the vast majority of which serves global demand. Thus, 

current availability is far below the amount that would be required to meet the U.S. 

liquid-immersed transformer market demand of approximately 250,000 tons. Electrical 

steel is a critical consideration in the manufacture of distribution transformers, accounting 

Deleted: 200

Deleted: 80

Deleted: 200

Deleted: 32
297

for more than 60 percent of the transformer's mass in some designs. DOE is concerned 

that the current supplier, together with others that might enter the market, would not be 

able to increase production of amorphous steel rapidly enough to supply the amounts that 

would be needed by transformer manufacturers before 2015. Therefore, setting a standard 

that requires amorphous material would expose the industry to enormous risk with 

respect to core steel supply. DOE also has concerns about the competitive impact of TSL 

6 on the electrical steel industry. . TSL 6 could jeopardize the ability of silicon steels to 

compete with amorphous metal, which risks upsetting competitive balance among steel 

suppliers and between them and their customers.

The Secretary tentatively concludes that, at TSL 6 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, emission reductions, and the estimated 

monetary value of the CO2 emissions reductions would be outweighed by the capital and 

engineering costs that could result in a large reduction in INPV for manufacturers, and 

the risk that manufacturers may not be able to obtain the quantities of amorphous steel 

required to meet standards at TSL 6. Consequently, DOE has tentatively concluded that 

TSL 6 is not economically justified.

Next, DOE considered TSL 5, which would save an estimated total of 1.42 quads 

of energy through 2045, an amount DOE considers significant. TSL 5 has an estimated 

NPV of customer benefit of $2.65 billion using a 7 percent discount rate, and $13.48 

billion using a 3 percent discount rate. 

Comment [A24]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
298

The cumulative emissions reductions at TSL 5 are 112 million metric tons of CO2, 

104 thousand tons of NOX, and 0.751 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 5 ranges from $646 million to $11,486 million.

At TSL 5, the average LCC impact ranges from $300 for design line 2 to $11,395 

for design line 5. The median PBP ranges from 9.5 years for design line 2 to 4.1 years for 

design line 4. The share of customers experiencing a net LCC benefit ranges from 88.8 

percent for design line 2 to 97.5 percent for design line 4.

At TSL 5, the projected change in INPV ranges from a decrease of $174 million 

to a decrease of $88 million. If the decrease of $174 million were to occur, TSL 5 could 

result in a net loss of 27.8 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 5, DOE recognizes the risk of very large negative 

impacts on manufacturers due to the large capital and engineering costs they would incur 

and the market disruption associated with the likely transition to a market almost entirely 

served by amorphous steel. Additionally, if manufacturers’ concerns about their 

customers rebuilding rather than replacing transformers at the price points projected for 

TSL 5 are realized, new transformer sales would suffer and make it even more difficult to 

recoup investments in amorphous transformer production capacity. 

The energy savings under TSL 5 are achievable only by using amorphous steel, 

which is currently available from a single supplier that has annual production capacity of 

Comment [A25]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.21 gigawatts under TSL 

5.

Deleted: 91
299

100,000 tons, far below the amount that would be required to meet the U.S. liquidimmersed transformer market demand of approximately 250,000 tons. DOE is concerned 

that the current supplier, together with others that might enter the market, would not be 

able to increase production of amorphous steel rapidly enough to supply the amounts that 

would be needed by transformer manufacturers before 2015. Therefore, setting a standard 

that requires amorphous material would expose the industry to enormous risk with 

respect to core steel supply. As with higher TSLs, DOE also has concerns about the 

competitive impact of TSL 5 on the electrical steel manufacturing industry. TSL 5 could 

jeopardize the ability of silicon steels to compete with amorphous metal, which risks 

upsetting competitive balance among steel suppliers and between them and their 

customers. 

The Secretary tentatively concludes that, at TSL 5 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, emission reductions, and the estimated 

monetary value of the CO2 emissions reductions would be outweighed by the capital and 

engineering costs that could result in a large reduction in INPV for manufacturers, and 

the risk that manufacturers may not be able to obtain the quantities of amorphous steel 

required to meet standards at TSL 5. Consequently, DOE has concluded that TSL 5 is not 

economically justified. 

Next, DOE considered TSL 4, which would save an estimated total of 1.44 quads 

of energy through 2045, an amount DOE considers significant. TSL 4 has an estimated 

Comment [A26]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
300

NPV of customer benefit of $2.96 billion using a 7 percent discount rate, and $14.21 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 4 are 113 million metric tons of CO2, 

92.7 thousand tons of NOX, and 0.762 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 4 ranges from $655 million to $11,643 million.

At TSL 4, the average LCC impact ranges from $338 for design line 2 to $12,513 

for design line 5. The median PBP ranges from 8.0 years for design line 2 to 4.1 years for 

design line 4. The share of customers experiencing a net LCC benefit ranges from 90.2 

percent for design line 2 to 97.5 percent for design line 4.

At TSL 4, the projected change in INPV ranges from a decrease of $164 million 

to a decrease of $74 million. If the decrease of $164 million were to occur, TSL 4 could 

result in a net loss of 26.2 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 4, DOE recognizes the risk of large negative impacts 

on manufacturers due to the substantial capital and engineering costs they would incur. 

Additionally, if manufacturers’ concerns about their customers rebuilding rather than 

replacing transformers at the price points projected for TSL 4 are realized, new 

transformer sales would suffer and make it even more difficult to recoup investments in 

amorphous transformer production capacity. 

Comment [A27]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.24 gigawatts under TSL 

4.

Deleted: 165

Deleted: 75

Deleted: 165

Deleted: 4
301

DOE is also concerned that TSL 4, like the higher TSLs, will require amorphous 

steel to be competitive in many applications and at least a few design lines. As stated 

previously, the available supply of amorphous steel is well below the amount that would 

likely be required to meet the U.S. liquid-immersed transformer market demand. DOE is 

concerned that the current supplier, together with others that might enter the market, 

would not be able to increase production of amorphous steel rapidly enough to supply the 

amounts that would be needed by transformer manufacturers before 2015. Therefore, 

setting a standard that requires amorphous material would expose the industry to 

enormous risk with respect to core steel supply.

In addition, depending on how steel prices react to a standard, DOE believes TSL 

4 could threaten the viability of a place in the market for conventional steel. Therefore, as 

with higher TSLs, DOE has concerns about the competitive impact of TSL 4 on the 

electrical steel manufacturing industry. 

The Secretary tentatively concludes that, at TSL 4 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, emission reductions, and the estimated 

monetary value of the CO2 emissions reductions would be outweighed by the capital and 

engineering costs that could result in a large reduction in INPV for manufacturers, and 

the risk that manufacturers may not be able to obtain the quantities of amorphous steel 

required to meet standards at TSL 4. Consequently, DOE has tentatively concluded that 

TSL 4 is not economically justified.

Comment [A28]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
302

Next, DOE considered TSL 3, which would save an estimated total of 0.82 quads 

of energy through 2045, an amount DOE considers significant. TSL 3 has an estimated 

NPV of customer benefit of $1.73 billion using a 7 percent discount rate, and $8.24 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 3 are 67.7 million metric tons of 

CO2, 55.3 thousand tons of NOX, and 0.454 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 3 ranges from $382 million to $6,746 million.

At TSL 3, the average LCC impact ranges from $36 for design line 1 to $10,288 

for design line 5. The median PBP ranges from 20.2 years for design line 1 to 4.0 years 

for design line 3. The share of customers experiencing a net LCC benefit ranges from 

41.8 percent for design line 1 to 93.5 percent for design line 4.

At TSL 3, the projected change in INPV ranges from a decrease of $101 million 

to a decrease of $48 million. If the decrease of $101 million were to occur, TSL 3 could 

result in a net loss of 16.2 percent in INPV to manufacturers. At TSL 3, DOE recognizes 

the risk of large negative impacts on manufacturers due to the large capital and 

engineering costs they would incur.

Although the industry can manufacture liquid-immersed transformers at TSL 3 

from M3 or lower grade steels, the positive LCC and national impacts results described 

Comment [A29]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 1.33 gigawatts under TSL 

3.

Deleted: 104

Deleted: 50

Deleted: 104

Deleted: 6
303

above are based on lowest first-cost designs, which include amorphous steel for all the 

design lines analyzed. As is the case with higher TSLs, DOE is concerned that the current 

supplier, together with others that might enter the market, would not be able to increase 

production of amorphous steel rapidly enough to supply the amounts that would be 

needed by transformer manufacturers before 2015. If manufacturers were to meet 

standards at TSL 3 using M3 or lower grade steels, DOE’s analysis shows that the LCC 

impacts are negative.43

The Secretary tentatively concludes that, at TSL 3 for liquid-immersed

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, emission reductions, and the estimated 

monetary value of the CO2 emissions reductions would be outweighed by the capital and 

engineering costs that could result in a large reduction in INPV for manufacturers, and 

the risk that manufacturers may not be able to obtain the quantities of amorphous steel 

required to meet standards at TSL 3 in a cost-effective manner. Consequently, DOE has 

tentatively concluded that TSL 3 is not economically justified.

Next, DOE considered TSL 2, which would save an estimated total of 0.74 quads 

of energy through 2045, an amount DOE considers significant. TSL 2 has an estimated 

NPV of customer benefit of $1.51 billion using a 7 percent discount rate, and $7.39 

billion using a 3 percent discount rate. 

 

43 DOE conducted a sensitivity analysis where LCC results are presented for liquid-immersed transformers 

without amorphous steel; see in appendix 8-C in the NOPR TSD.

Comment [A30]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
304

The cumulative emissions reductions at TSL 2 are 62.7 million metric tons of 

CO2, 51.2 thousand tons of NOX, and 0.42 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 2 ranges from $350 million to $6,160 million.

At TSL 2, the average LCC impact ranges from $0 for design line 2 to $7,787 for 

design line 5. The median PBP ranges from 20.2 years for design line 1 to 4.0 years for 

design line 5. The share of customers experiencing a net LCC benefit ranges from 41.8 

percent for design line 1 to 93.5 percent for design line 4.

At TSL 2, the projected change in INPV ranges from a decrease of $93 million to 

a decrease of $42 million. If the decrease of $93 million were to occur, TSL 2 could 

result in a net loss of 14.9 percent in INPV to manufacturers of liquid-immersed 

distribution transformers. At TSL 2, DOE recognizes the risk of negative impacts on 

manufacturers due to the significant capital and engineering costs they would incur.

Although the industry can manufacture liquid-immersed transformers at TSL 2 

from M3 or lower grade steels, the positive LCC and national impacts results described 

above are based on lowest first-cost designs, which include amorphous steel for design 

line 2. This design line represents approximately 44 percent of all liquid-immersed 

transformer shipments by MVA. Amorphous steel is available from a single supplier 

whose annual production capacity is below the amount that would be required to meet the 

demand for design line 2 under TSL 2. DOE is concerned that the current supplier, 

together with others that might enter the market, would not be able to increase production 

Comment [A31]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 1.23 gigawatts under TSL 

2.

Deleted: 95

Deleted: 44

Deleted: 95

Deleted: 15.2
305

of amorphous steel rapidly enough to supply the amounts that would be needed by 

transformer manufacturers before 2015. If manufacturers were to meet standards at TSL 

2 using M3 or lower grade steels, DOE’s analysis shows that the LCC impacts would be 

negative.

The Secretary tentatively concludes that, at TSL 2 for liquid-immersed 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average customer LCC savings, emission reductions, and the estimated

monetary value of the CO2 emissions reductions would be outweighed by the capital and 

engineering costs that could result in a reduction in INPV for manufacturers, and the risk 

that manufacturers may not be able to obtain the quantities of amorphous steel required to 

meet standards at TSL 2 in a cost-effective manner. Consequently, DOE has tentatively 

concluded that TSL 2 is not economically justified.

Next, DOE considered TSL 1, which would save an estimated total of 0.36 quads 

of energy through 2045, an amount DOE considers significant. TSL 1 has an estimated 

NPV of customer benefit of $0.75 billion using a 7 percent discount rate, and $3.66 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 1 are 31.2 million metric tons of 

CO2, 25.5 thousand tons of NOX, and 0.209 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 1 ranges from $173 million to $3,051 million.

Comment [A32]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 

Comment [A33]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 0.61 gigawatts under TSL 

1.
306

At TSL 1, the average LCC impact ranges from $0 for design line 2 to $7,787 for 

design line 5. The median PBP ranges from 20.2 years for design line 1 to 4.0 years for 

design line 5. The share of customers experiencing a net LCC benefit ranges from 41.8 

percent for design line 1 to 93.5 percent for design line 4.

At TSL 1, the projected change in INPV ranges from a decrease of $40 million to 

a decrease of $10 million. If the decrease of $40 million were to occur, TSL 1 could 

result in a net loss of 6.3 percent in INPV to manufacturers of liquid-immersed 

distribution transformers.

The energy savings under TSL 1 are achievable without using amorphous steel. 

Therefore, the aforementioned risks that manufacturers may not be able to obtain the 

quantities of amorphous steel required to meet standards, or that manufacturers may be 

exposed to increased material prices due to the concentration of core material to a single 

supplier are not present under TSL 1.

After considering the analysis and weighing the benefits and the burdens, DOE 

has tentatively concluded that at TSL 1 for liquid-immersed distribution transformers, the 

benefits of energy savings, positive NPV of customer benefit, positive average customer 

LCC savings, emission reductions, and the estimated monetary value of the emissions 

reductions would outweigh the potential reduction in INPV for manufacturers. The 

Secretary of Energy has concluded that TSL 1 would save a significant amount of energy 

and is technologically feasible and economically justified. In addition, during the 

Deleted: 42

Deleted: 12

Deleted: 42

Deleted: 6

Comment [A34]: Change recommended by 

OIRA.

Comment [A35]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
307

negotiated rulemaking, NEMA and AK Steel recommended TSL 1. For the above 

considerations, DOE today proposes to adopt the energy conservation standards for 

liquid-immersed distribution transformers at TSL 1. Table V.39 presents the proposed 

energy conservation standards for liquid-immersed distribution transformers.

Table V.39 Proposed Energy Conservation Standards for Liquid-Immersed 

Distribution Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment Class 1 Equipment Class 2

kVA % kVA %

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1000 99.43

1500 99.48

2. Benefits and Burdens of Trial Standard Levels Considered for Low-Voltage, DryType Distribution Transformers

Table V.40 and Table V.41 summarize the quantitative impacts estimated for each 

TSL for low-voltage, dry-type distribution transformers.

Table V.40 Summary of Analytical Results for Low-Voltage, Dry-Type Distribution 

Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

National Energy 

Savings (quads) 1.09 1.12 1.29 1.86 1.90 2.08

NPV of Consumer Benefits (2010$ billion)

3% discount rate 7.81 7.79 8.51 11.16 9.37 2.69
308

7% discount rate 2.03 1.97 2.03 2.36 1.37 -2.41

Cumulative Emissions Reduction

CO2 (million metric 

tons) 82.1 83.9 96.0 137 139 148

NOX (thousand tons) 67.0 68.6 78.4 112 114 121

Hg (tons) 0.551 0.564 0.645 0.918 0.934 0.992

Value of Emissions Reduction

CO2 (2010$ million)* 481 to 

8570

492 to 

8764

562 to 

10020

800 to 

14264

814 to 

14517

866 to 

15427

NOX – 3% discount 

rate (2010$ million) 25 to 261 26 to 267 30 to 305 42 to 434 43 to 442 46 to 470

NOX – 7% discount 

rate (2010$ million) 8 to 85 8 to 87 10 to 99 14 to 141 14 to 143 15 to 152

* Range of the economic value of CO2 reductions is based on estimates of the global benefit of 

reduced CO2 emissions.

Table V.41 Summary of Analytical Results for Low-Voltage, Dry-Type Distribution 

Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

Manufacturer Impacts

Industry NPV (2011$ 

million)

203 to 

236

200 to 

235

193 to 

240

173 to 

250

164 to 

263

136 to 

322

Industry NPV (% change) (7.7) to 

7.7

(8.9) to 

6.8

(12.2) to 

9.1

(21.0) to 

14.1

(25.2) to 

20.0

(37.9) to 

46.4

Consumer Mean LCC Savings (2010$)

Design line 6 0 -125 335 187 187 -881

Design line 7 1714 1714 1793 2270 2270 270

Design line 8 2476 2476 2625 4145 -2812 -2812

Consumer Median PBP (years)

Design line 6 0.0 24.7 13.0 16.3 16.3 32.4

Design line 7 4.5 4.5 4.7 6.9 6.9 18.1

Design line 8 8.4 8.4 12.3 11.0 24.5 24.5

Distribution of Consumer LCC Impacts

Design line 6

Net Cost (%) 0.0 71.5 17.6 36.2 36.2 93.4

Net Benefit (%) 0.0 28.5 82.4 63.8 63.8 6.6

No Impact (%) 100.0 0.0 0.0 0.0 0.0 0.0

Design line 7

Deleted: 202

Deleted: 237

Deleted: 8
309

Net Cost (%) 1.8 1.8 2.0 3.7 3.7 46.4

Net Benefit (%) 98.2 98.2 98.0 96.3 96.3 53.6

No Impact (%) 0.0 0.0 0.0 0.0 0.0 0.0

Design line 8

Net Cost (%) 5.2 5.2 15.3 10.5 78.5 78.5

Net Benefit (%) 94.8 94.8 84.7 89.5 21.5 21.5

No Impact (%) 0.0 0.0 0.0 0.0 0.0 0.0

First, DOE considered TSL 6, the most efficient level (max tech), which would 

save an estimated total of 2.08 quads of energy through 2045, an amount DOE considers 

significant. TSL 6 has an estimated NPV of customer benefit of -$2.41 billion using a 7 

percent discount rate, and $2.69 billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 6 are 148 million metric tons of CO2, 

121 thousand tons of NOX, and 0.992 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 6 ranges from $866 million to $15,427 million.

At TSL 6, the average LCC impact ranges from -$2,812 for design line 8 to $270 

for design line 7. The median PBP ranges from 32.4 years for design line 6 to 18.1 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 6.6 

percent for design line 6 to 53.6 percent for design line 7.

At TSL 6, the projected change in INPV ranges from a decrease of $83 million to 

an increase of $102 million. If the decrease of $83 million occurs, TSL 6 could result in a 

net loss of 37.9 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 6, DOE recognizes the risk of very large negative impacts on the 

Comment [A36]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.92 gigawatts under TSL 

6.
310

industry. TSL 6 would require manufacturers to scrap nearly all production assets and 

create transformer designs with which most, if not all, have no experience. DOE is 

concerned, in particular, about large impacts on small businesses, which may not be able 

to procure sufficient volume of amorphous steel at competitive prices, if at all. 

The Secretary tentatively concludes that, at TSL 6 for low-voltage dry-type 

distribution transformers, the benefits of energy savings, emission reductions, and the 

estimated monetary value of the CO2 emissions reductions would be outweighed by the 

economic burden on customers (as indicated by negative average LCC savings, large 

PBPs, and the large percentage of customers who would experience LCC increases at 

design line 6 and design line 8), the potential for very large negative impacts on the 

manufacturers, and the potential burden on small manufacturers. Consequently, DOE has 

tentatively concluded that TSL 6 is not economically justified.

Next, DOE considered TSL 5, which would save an estimated total of 1.90 quads 

of energy through 2045, an amount DOE considers significant. TSL 5 has an estimated 

NPV of customer benefit of $1.37 billion using a 7 percent discount rate, and $9.37 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 5 are 139 million metric tons of CO2, 

114 thousand tons of NOX, and 0.934 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 5 ranges from $814 million to $14,517 million.

Comment [A37]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 

Comment [A38]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.75 gigawatts under TSL 

5.
311

At TSL 5, the average LCC impact ranges from -$2,812 for design line 8 to 

$2,270 for design line 7. The median PBP ranges from 24.5 years for design line 8 to 6.9 

years for design line 7. The share of customers experiencing a net LCC benefit ranges 

from 21.5 percent for design line 8 to 96.3 percent for design line 7.

At TSL 5, the projected change in INPV ranges from a decrease of $55 million to 

an increase of $44 million. If the decrease of $55 million occurs, TSL 5 could result in a 

net loss of 25.2 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 5, DOE recognizes the risk of very large negative impacts on the 

industry. TSL 5 would require manufacturers to scrap nearly all production assets and 

create transformer designs with which most, if not all, have no experience. DOE is 

concerned, in particular, about large impacts on small businesses, which may not be able 

to procure sufficient volume of amorphous steel at competitive prices, if at all.

The Secretary tentatively concludes that, at TSL 5 for low-voltage dry-type 

distribution transformers, the benefits of energy savings, emission reductions, and the 

estimated monetary value of the CO2 emissions reductions would be outweighed by the 

economic burden on customers at design line 8 (as indicated by negative average LCC 

savings, large PBPs, and the large percentage of customers who would experience LCC 

increases), the potential for very large negative impacts on the manufacturers, and the 

potential burden on small manufacturers. Consequently, DOE has tentatively concluded 

that TSL 5 is not economically justified.

Comment [A39]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
312

Next, DOE considered TSL 4, which would save an estimated total of 1.86 quads 

of energy through 2045, an amount DOE considers significant. TSL 4 has an estimated 

NPV of customer benefit of $2.36 billion using a 7 percent discount rate, and $11.16 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 4 are 137 million metric tons of CO2, 

112 thousand tons of NOX, and 0.918 tons of Hg. The estimated monetary value of the 

CO2 emissions reductions at TSL 4 ranges from $800 million to $14,264 million.

At TSL 4, the average LCC impact ranges from $187 for design line 6 to $4,145 

for design line 8. The median PBP ranges from 16.3 years for design line 6 to 6.9 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 

63.8 percent for design line 6 to 96.3 percent for design line 7.

At TSL 4, the projected change in INPV ranges from a decrease of $46 million to 

an increase of $31 million. If the decrease of $46 million occurs, TSL 4 could result in a 

net loss of 21 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 4, DOE recognizes the risk of very large negative impacts on the 

industry. As with the higher TSLs, TSL 4 would require manufacturers to scrap nearly all 

production assets and create transformer designs with which most, if not all, have no 

experience. DOE is concerned, in particular, about large impacts on small businesses, 

which may not be able to procure sufficient volume of amorphous steel at competitive 

prices, if at all.

Comment [A40]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 2.7 gigawatts under TSL 4.
313

The Secretary tentatively concludes that, at TSL 4 for low-voltage dry-type 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average LCC savings, emission reductions, and the estimated monetary 

value of the CO2 emissions reductions would be outweighed by the potential for very 

large negative impacts on the manufacturers, and the potential burden on small 

manufacturers. Consequently, DOE has tentatively concluded that TSL 4 is not 

economically justified.

Next, DOE considered TSL 3, which would save an estimated total of 1.29 quads 

of energy through 2045, an amount DOE considers significant. TSL 3 has an estimated 

NPV of customer benefit of $2.03 billion using a 7 percent discount rate, and $8.51 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 3 are 96.0 million metric tons of 

CO2, 78.4 thousand tons of NOX, and 0.645 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 3 ranges from $562 million to $10,020 million.

At TSL 3, the average LCC impact ranges from $335 for design line 6 to $2,625 

for design line 8. The median PBP ranges from 13.0 years for design line 6 to 4.7 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 

82.4 percent for design line 6 to 98.0 percent for design line 7.

Comment [A41]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 

Comment [A42]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 1.9 gigawatts under TSL 3.
314

At TSL 3, the projected change in INPV ranges from a decrease of $27 million to 

an increase of $20 million. If the decrease of $27 million occurs, TSL 3 could result in a 

net loss of 12.2 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 3, DOE recognizes the risk of negative impacts on the industry, 

particularly the small manufacturers. While TSL 3 could likely be met with M4 steel, 

DOE’s analysis shows that this design option is at the edge of its technical feasibility at 

the efficiency levels comprised by TSL 3. Although these levels could be met with M3 

or better steels, DOE is concerned that a significant number of small manufacturers 

would be unable to acquire these steels in sufficient supply and quality to compete. 

Additionally, TSL 3 requires significant investment in advanced core construction 

equipment such are step-lap mitering machines or wound core production lines, as butt 

lap designs, even with high-grade designs, are unlikely to comply. Given their more 

limited engineering resources and capital, small businesses may find it difficult to make 

these designs at competitive prices and may have to exit the market. At the same time, 

however, those small manufacturers may be able to source their cores—and many are 

doing so to a significant extent currently—which could mitigate impacts. 

The Secretary tentatively concludes that, at TSL 3 for low-voltage dry-type 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average LCC savings, emission reductions, and the estimated monetary 

value of the CO2 emissions reductions would be outweighed by the risk of negative 

impacts on the industry, particularly the small manufacturers. Consequently, DOE has 

tentatively concluded that TSL 3 is not economically justified.

Comment [A43]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
315

Next, DOE considered TSL 2, which would save an estimated total of 1.12 quads 

of energy through 2045, an amount DOE considers significant. TSL 2 has an estimated 

NPV of customer benefit of $1.97 billion using a 7 percent discount rate, and $7.79 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 2 are 83.9 million metric tons of 

CO2, 68.6 thousand tons of NOX, and 0.564 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 2 ranges from $492 million to $8,764 million.

At TSL 2, the average LCC impact ranges from -$125 for design line 6 to $2,476 

for design line 8. The median PBP ranges from 24.7 years for design line 6 to 4.5 years 

for design line 7. The share of customers experiencing a net LCC benefit ranges from 

28.5 percent for design line 6 to 98.2 percent for design line 7.

At TSL 2, the projected change in INPV ranges from a decrease of $20 million to 

an increase of $15 million. If the decrease of $20 million occurs, TSL 2 could result in a 

net loss of 8.9 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 2, DOE recognizes the risk of negative impacts on the industry, 

particularly small manufacturers. TSL 2 would likely require mitering or wound core 

technology, which many small businesses do not have in-house. Given their more 

limited engineering resources and capital, small businesses may find it difficult to make 

these designs at competitive prices and may have to exit the market. At the same time, 

Comment [A44]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 1.66 gigawatts under TSL 

2.
316

however, those small manufacturers may be able to source their cores—and many are 

doing so to a significant extent currently—which could mitigate impacts. 

The Secretary tentatively concludes that, at TSL 2 for low-voltage dry-type 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive average LCC savings, emission reductions, and the estimated monetary 

value of the CO2 emissions reductions would be outweighed by the risk of negative 

impacts on the industry, particularly regarding the uncertainty over how small businesses 

would be impacted. Consequently, DOE has tentatively concluded that TSL 2 is not 

economically justified.

Next, DOE considered TSL 1, which would save an estimated total of 1.09 quads 

of energy through 2045, an amount DOE considers significant. TSL 1 has an estimated 

NPV of customer benefit of $2.03 billion using a 7 percent discount rate, and $7.81 

billion using a 3 percent discount rate. 

The cumulative emissions reductions at TSL 1 are 82.1 million metric tons of 

CO2, 67.0 thousand tons of NOX, and 0.551 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 1 ranges from $481 million to $8,570 million.

At TSL 1, the average LCC impact ranges from $1,714 for design line 7 to $2,476 

for design line 8. The median PBP ranges from 8.4 years for design line 8 to 4.5 years for 

Comment [A45]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 

Comment [A46]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 1.62 gigawatts under TSL 

1.
317

design line 7. The share of customers experiencing a net LCC benefit ranges from 94.8 

percent for design line 8 to 98.2 percent for design line 7.

At TSL 1, the projected change in INPV ranges from a decrease of $17 million to 

an increase of $17 million. If the decrease of $17 million occurs, TSL 1 could result in a 

net loss of 7.7 percent in INPV to manufacturers of low-voltage dry-type distribution 

transformers. At TSL 1, DOE recognizes the risk of small negative impacts on the 

industry if manufacturers are not able to recoup their investment costs. At this level, 

small manufacturers can still use butt-lap construction and steels with which they 

generally have experience. 

After considering the analysis and weighing the benefits and the burdens, DOE 

has tentatively concluded that at TSL 1 for low-voltage, dry-type distribution 

transformers, the benefits of energy savings, NPV of customer benefit, positive customer 

LCC impacts, emissions reductions and the estimated monetary value of the emissions 

reductions would outweigh the risk of small negative impacts on the manufacturers. In 

particular, the Secretary has concluded that TSL 1 would save a significant amount of 

energy and is technologically feasible and economically justified. NEMA also 

recommended TSL 1 for low-voltage, dry-type distribution transformers during the 

negotiated rulemaking. For the reasons given above, DOE today proposes to adopt the 

energy conservation standards for low-voltage dry-type distribution transformers at TSL 

1. Table V.42 presents the proposed energy conservation standards for low-voltage, drytype distribution transformers.

Deleted: 8
318

Table V.42 Proposed Energy Conservation Standards for Low-Voltage, Dry-Type 

Distribution Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment Class 3 Equipment Class4

kVA % kVA %

15 97.73 15 97.44

25 98.00 30 97.95

37.5 98.20 45 98.20

50 98.31 75 98.47

75 98.50 112.5 98.66

100 98.60 150 98.78

167 98.75 225 98.92

250 98.87 300 99.02

333 98.94 500 99.17

750 99.27

1000 99.34

3. Benefits and Burdens of Trial Standard Levels Considered for Medium-Voltage, 

Dry-Type Distribution Transformers 

Table V.43 and Table V.44 summarize the quantitative impacts estimated for each 

TSL for medium-voltage, dry-type distribution transformers.

Table V.43 Summary of Analytical Results for Medium-Voltage, Dry-Type 

Distribution Transformers: National Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

National Energy Savings (quads) 0.06 0.13 0.23 0.23 0.37

NPV of Consumer Benefits (2010$ billion)

3% discount rate 0.42 0.67 0.90 0.90 -0.38

7% discount rate 0.10 0.13 0.06 0.06 -0.84

Cumulative Emissions Reduction

CO2 (million metric tons) 4.62 8.80 16.8 16.8 25.7

NOX (thousand tons) 3.77 7.19 13.7 13.7 21.0

Hg (tons) 0.031 0.059 0.113 0.113 0.173

Value of Emissions Reduction

CO2 (2010$ million)* 27 to 

483

52 to 

919

98 to 

1751

98 to 

1751

151 to 

2688

NOX – 3% discount rate (2010$ 1 to 15 3 to 28 5 to 53 5 to 53 8 to 82
319

million)

NOX – 7% discount rate (2010$ 

million)

0 to 5 1 to 9 2 to 17 2 to 17 3 to 27

* Range of the economic value of CO2 reductions is based on estimates of the global benefit 

of reduced CO2 emissions.

Table V.44 Summary of Analytical Results for Medium-Voltage, Dry-Type 

Distribution Transformers: Manufacturer and Consumer Impacts

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

Manufacturer Impacts

Industry NPV (2011$ 

million) 87 to 89 85 to 90 80 to 95 77 to 93 71 to 114

Industry NPV (% change) (4.2) to 

(2.0)

(7.1) to 

(1.0)

(12.4) to 

4.5

(15.3) to 

1.7

(21.9) to 

25.4

Consumer Mean LCC Savings (2010$)

Design line 9 849 1659 1659 1659 237

Design line 10 4509 4791 4791 4791 -12756

Design line 11 1043 202 2000 2000 -3160

Design line 12 4518 6332 8860 8860 -12420

Design line 13A 25 447 -846 -846 -11077

Design line 13B 2734 -961 384 384 -5403

Consumer Median PBP (years)

Design line 9 2.6 6.2 6.2 6.2 19.1

Design line 10 1.1 8.8 8.8 8.8 28.4

Design line 11 10.7 17.6 14.1 14.1 24.5

Design line 12 6.3 13.5 13.0 13.0 25.9

Design line 13A 16.5 16.6 21.7 21.7 37.1

Design line 13B 4.6 20.4 19.3 19.3 21.9

Distribution of Consumer LCC Impacts

Design line 9

Net Cost (%) 3.4 5.7 5.7 5.7 53.4

Net Benefit (%) 83.4 94.3 94.3 94.3 46.6

No Impact (%) 13.3 0.0 0.0 0.0 0.0

Design line 10

Net Cost (%) 0.7 16.7 16.7 16.7 84.8

Net Benefit (%) 98.8 83.3 83.3 83.3 15.2

No Impact (%) 0.5 0.0 0.0 0.0 0.0

Design line 11

Net Cost (%) 20.6 49.5 25.7 25.7 76.1
320

Net Benefit (%) 79.4 50.5 74.3 74.3 23.9

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 12

Net Cost (%) 6.7 23.5 18.1 18.1 81.1

Net Benefit (%) 93.3 76.5 81.9 81.9 18.9

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 13A

Net Cost (%) 52.2 42.3 64.4 64.4 97.1

Net Benefit (%) 47.8 57.7 35.6 35.6 2.9

No Impact (%) 0.0 0.0 0.0 0.0 0.0

Design line 13B

Net Cost (%) 28.5 59.6 52.7 52.7 67.2

Net Benefit (%) 71.3 40.4 47.3 47.3 32.8

No Impact (%) 0.2 0.0 0.0 0.0 0.0

First, DOE considered TSL 5, the most efficient level (max tech), which would 

save an estimated total of 0.37 quads of energy through 2045, an amount DOE considers 

significant. TSL 5 has an estimated NPV of customer benefit of -$0.84 billion using a 7 

percent discount rate, and -$0.38 billion using a 3 percent discount rate.

The cumulative emissions reductions at TSL 5 are 25.7 million metric tons of 

CO2, 21.0 thousand tons of NOX, and 0.173 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 5 ranges from $151 million to $2,688 million.

At TSL 5, the average LCC impact ranges from -$12,756 for design line 10 to -

$237 for design line 9. The median PBP ranges from 37.1 years for design line 13A to 

19.1 years for design line 9. The share of customers experiencing a net LCC benefit 

ranges from 2.9 percent for design line 13A to 46.6 percent for design line 9.

Comment [A47]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 0.51 gigawatts under TSL 

5.
321

At TSL 5, the projected change in INPV ranges from a decrease of $20 million to 

an increase of $23 million. If the decrease of $20 million occurs, TSL 5 could result in a 

net loss of 21.9 percent in INPV to manufacturers of medium-voltage dry-type 

distribution transformers. At TSL 5, DOE recognizes the risk of very large negative 

impacts on industry because they would likely forced to move to amorphous technology, 

with which there is no experience in this market.

The Secretary tentatively concludes that, at TSL 5 for medium-voltage dry-type 

distribution transformers, the benefits of energy savings, emission reductions, and the 

estimated monetary value of the emissions reductions would be outweighed by the 

negative NPV of customer benefit, the economic burden on customers (as indicated by 

negative average LCC savings, large PBPs, and the large percentage of customers who 

would experience LCC increases), and the risk of very large negative impacts on the 

manufacturers. Consequently, DOE has tentatively concluded that TSL 5 is not 

economically justified.

Next, DOE considered TSL 4, which would save an estimated total of 0.23 quads 

of energy through 2045, an amount DOE considers significant. TSL 4 has an estimated 

NPV of customer benefit of $0.06 billion using a 7 percent discount rate, and $0.90

billion using a 3 percent discount rate.

Comment [A48]: Change recommended by 

OIRA.

Deleted: generating capacity reductions, 
322

The cumulative emissions reductions at TSL 4 are 16.8 million metric tons of 

CO2, 13.7 thousand tons of NOX, and 0.113 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 4 ranges from $98 million to $1,751 million.

At TSL 4, the average LCC impact ranges from -$846 for design line 13A to 

$8,860 for design line 12. The median PBP ranges from 21.7 years for design line 13A to 

6.2 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 35.6 percent for design line 13A to 94.3 percent for design line 9.

At TSL 4, the projected change in INPV ranges from a decrease of $14 million to 

an increase of $2 million. If the decrease of $14 million occurs, TSL 4 could result in a 

net loss of 15.3 percent in INPV to manufacturers of medium-voltage dry-type 

distribution transformers. At TSL 4, DOE recognizes the risk of very large negative 

impacts on most manufacturers in the industry who have little experience with the steels 

that would be required. Small businesses, in particular, with limited engineering 

resources, may not be able to convert their lines to employ thinner steels and may be 

disadvantaged with respect to access to key materials, including Hi-B steels.

The Secretary tentatively concludes that, at TSL 4 for medium-voltage dry-type 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive impacts on consumers (as indicated by positive average LCC savings, 

favorable PBPs, and the large percentage of customers who would experience LCC 

benefits), emission reductions, and the estimated monetary value of the emissions 

Comment [A49]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 0.332 gigawatts under TSL 

4.
323

reductions would be outweighed by the risk of very large negative impacts on the 

manufacturers, particularly small businesses. Consequently, DOE has tentatively 

concluded that TSL 4 is not economically justified.

Next, DOE considered TSL 3, which would save an estimated total of 0.23 quads 

of energy through 2045, an amount DOE considers significant. TSL 3 has an estimated 

NPV of customer benefit of $0.06 billion using a 7 percent discount rate, and $0.90

billion using a 3 percent discount rate.

The cumulative emissions reductions at TSL 3 are 16.8 million metric tons of 

CO2, 13.7 thousand tons of NOX, and 0.113 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 3 ranges from $98 million to $1,751 million.

At TSL 3, the average LCC impact ranges from -$846 for design line 13A to 

$8,860 for design line 12. The median PBP ranges from 21.7 years for design line 13A to 

6.2 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 35.6 percent for design line 13A to 94.3 percent for design line 9.

At TSL 3, the projected change in INPV ranges from a decrease of $11 million to 

an increase of $4 million. If the decrease of $11 million occurs, TSL 3 could result in a 

net loss of 12.4 percent in INPV to manufacturers of medium-voltage dry-type 

transformers. At TSL 3, DOE recognizes the risk of large negative impacts on most 

manufacturers in the industry who have little experience with the steels that would be 

Comment [A50]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 0.332 gigawatts under TSL 

3.
324

required. As with TSL 4, small businesses, in particular, with limited engineering 

resources, may not be able to convert their lines to employ thinner steels and may be 

disadvantaged with respect to access to key materials, including Hi-B steels.

The Secretary tentatively concludes that, at TSL 3 for medium-voltage dry-type 

distribution transformers, the benefits of energy savings, positive NPV of customer 

benefit, positive impacts on consumers (as indicated by positive average LCC savings, 

favorable PBPs, and the large percentage of customers who would experience LCC 

benefits), emission reductions, and the estimated monetary value of the emissions 

reductions would be outweighed by the risk of large negative impacts on the 

manufacturers, particularly small businesses. Consequently, DOE has tentatively 

concluded that TSL 3 is not economically justified.

Next, DOE considered TSL 2, which would save an estimated total of 0.13 quads 

of energy through 2045, an amount DOE considers significant. TSL 2 has an estimated 

NPV of customer benefit of $0.10 billion using a 7 percent discount rate, and $0.42

billion using a 3 percent discount rate.

The cumulative emissions reductions at TSL 2 are 8.80 million metric tons of 

CO2, 7.19 thousand tons of NOX, and 0.059 tons of Hg. The estimated monetary value of 

the CO2 emissions reductions at TSL 2 ranges from $52 million to $919 million. Comment [A51]: Change recommended by 

OIRA.

Deleted: Total generating capacity in 2045 is 

estimated to decrease by 0.174 gigawatts under TSL 

2.
325

At TSL 2, the average LCC impact ranges from -$961 for design line 13B to 

$6,332 for design line 12. The median PBP ranges from 20.4 years for design line 13B to 

6.2 years for design line 9. The share of customers experiencing a net LCC benefit ranges 

from 40.4 percent for design line 13B to 94.3 percent for design line 9.

At TSL 2, the projected change in INPV ranges from a decrease of $7 million to a 

decrease of $1 million. If the decrease of $7 million occurs, TSL 2 could result in a net 

loss of 7.1 percent in INPV to manufacturers of medium-voltage dry-type distribution 

transformers. At TSL 2, DOE recognizes the risk of small negative impacts if 

manufacturers are unable to recoup investments made to meet the standard.

After considering the analysis and weighing the benefits and the burdens, DOE 

has tentatively concluded that at TSL 2 for medium-voltage, dry-type distribution 

transformers, the benefits of energy savings, positive NPV of customer benefit, positive 

impacts on consumers (as indicated by positive average LCC savings for five of the six 

design lines, favorable PBPs, and the large percentage of customers who would 

experience LCC benefits), emission reductions, and the estimated monetary value of the 

emissions reductions would outweigh the risk of small negative impacts if manufacturers 

are unable to recoup investments made to meet the standard. In particular, the Secretary 

of Energy has concluded that TSL 2 would save a significant amount of energy and is 

technologically feasible and economically justified. In addition, DOE notes that TSL 2 

corresponds to the standards that were agreed to by the ERAC subcommittee, as 

described in section II.B.2. Based on the above considerations, DOE today proposes to 
326

adopt the energy conservation standards for medium-voltage, dry-type distribution 

transformers at TSL 2. Table V.45 presents the proposed energy conservation standards 

for medium-voltage, dry-type distribution transformers.

Table V.45 Proposed Energy Conservation Standards for Medium-Voltage, DryType Distribution Transformers

Electrical Efficiency by kVA and Equipment Class

Equipment 

Class 5

Equipment 

Class 6

Equipment 

Class 7

Equipment 

Class 8

Equipment 

Class 9

Equipment 

Class 10

kVA % kVA % kVA % kVA % kVA % kVA %

15 98.10 15 97.50 15 97.86 15 97.18

25 98.33 30 97.90 25 98.12 30 97.63

37.5 98.49 45 98.10 37.5 98.30 45 97.86

50 98.60 75 98.33 50 98.42 75 98.13

75 98.73 112.5 98.52 75 98.57 112.5 98.36 75 98.53

100 98.82 150 98.65 100 98.67 150 98.51 100 98.63

167 98.96 225 98.82 167 98.83 225 98.69 167 98.80 225 98.57

250 99.07 300 98.93 250 98.95 300 98.81 250 98.91 300 98.69

333 99.14 500 99.09 333 99.03 500 98.99 333 98.99 500 98.89

500 99.22 750 99.21 500 99.12 750 99.12 500 99.09 750 99.02

667 99.27 1000 99.28 667 99.18 1000 99.20 667 99.15 1000 99.11

833 99.31 1500 99.37 833 99.23 1500 99.30 833 99.20 1500 99.21

2000 99.43 2000 99.36 2000 99.28

2500 99.47 2500 99.41 2500 99.33

4. Summary of Benefits and Costs (Annualized) of the Proposed Standards

The benefits and costs of today’s proposed standards can also be expressed in 

terms of annualized values. The annualized monetary values are the sum of (1) the 

annualized national economic value of the benefits from operating products that meet the 

proposed standards (consisting primarily of operating cost savings from using less 

energy, minus increases in equipment purchase costs, which is another way of 

representing customer NPV), and (2) the monetary value of the benefits of emission 
327

reductions, including CO2 emission reductions.44 The value of the CO2 reductions is 

calculated using a range of values per metric ton of CO2 developed by a recent 

interagency process. 

Although combining the values of operating savings and CO2 reductions provides 

a useful perspective, two issues should be considered. First, the national operating 

savings are domestic U.S. customer monetary savings that occur as a result of market 

transactions while the value of CO2 reductions is based on a global value. Second, the 

assessments of operating cost savings and SCC are performed with different methods that 

use different time frames for analysis. The national operating cost savings is measured for 

the lifetime of products shipped in 2016–2045. The SCC values, on the other hand, 

reflect the present value of future climate-related impacts resulting from the emission of 

one metric ton of CO2 in each year. These impacts continue well beyond 2100.

Table V.46 shows the annualized values for the proposed standards for 

distribution transformers. The results for the primary estimate are as follows. Using a 7-

percent discount rate for benefits and costs other than CO2 reductions, for which DOE 

used a 3-percent discount rate along with the SCC series corresponding to a value of 

 

44 DOE used a two-step calculation process to convert the time-series of costs and benefits into annualized 

values. First, DOE calculated a present value in 2011, the year used for discounting the NPV of total 

consumer costs and savings, for the time-series of costs and benefits using discount rates of 3 and 7 percent

for all costs and benefits except for the value of CO2 reductions. For the latter, DOE used a range of 

discount rates, as shown in Table V.46. From the present value, DOE then calculated the fixed annual 

payment over a 30-year period, starting in 2011 that yields the same present value. The fixed annual 

payment is the annualized value. Although DOE calculated annualized values, this does not imply that the 

time-series of cost and benefits from which the annualized values were determined would be a steady 

stream of payments.
328

$22.3/metric ton in 2010, the cost of the standards proposed in today’s rule is $302 

million per year in increased product costs, while the annualized benefits are $631 

million in reduced product operating costs, $244 million in CO2 reductions, and $7.78

million in reduced NOX emissions. In this case, the net benefit amounts to $581 million 

per year. Using a 3-percent discount rate for all benefits and costs and the SCC series 

corresponding to a value of $22.3/metric ton in 2010, the cost of the standards proposed 

in today’s rule is $308 million per year in increased product costs, while the annualized 

benefits are $1,026 million in reduced operating costs, $244 million in CO2 reductions, 

and $12.4 million in reduced NOX emissions. In this case, the net benefit amounts to $975

million per year.

Table V.46 Annualized Benefits and Costs of Proposed Standards for Distribution 

Transformers Sold in 2016–2045

Discount Rate

Primary 

Estimate*

Low Net 

Benefits 

Estimate*

High Net 

Benefits 

Estimate*

Monetized (million 2010$/year)

Benefits

Operating Cost Savings

7% 631 594 659

3% 1,026 950 1,075

CO2 Reduction at $4.9/t** 5% 58.6 58.6 58.6

CO2Reduction at $22.3/t** 3% 244 244 244

CO2Reduction at $36.5/t** 2.5% 389 389 389

CO2Reduction at $67.6/t** 3% 742 742 742

NOX Reduction at 

$2,537/ton**

7% 7.78 7.78 7.78

3% 12.4 12.4 12.4

Total†

7% plus CO2 range 697 to 1380 660 to 1343 726 to 1409

7% 883 846 911

3% plus CO2 range 1097 to 1780 1021 to 1704 1146 to 1829

3% 1,283 1,207 1,331

Costs
329

Incremental Product Costs

7% 302 338 285

3% 308 351 289

Total Net Benefits

Total†

7% plus CO2 range 400 to 1083 327 to 1010 445 to 1128

7% 581 507 626

3% plus CO2 range 789 to 1472 670 to 1353 857 to 1540

3% 975 855 1,043

* The Primary, Low Net Benefits, and High Net Benefits Estimates utilize forecasts of energy prices from 

the AEO 2011 reference case, Low Economic Growth case, and High Economic Growth case, respectively. 

In addition, incremental product costs reflect no change in the Primary estimate, rising product prices in the 

Low Net Benefits estimate, and declining product prices in the High Net Benefits estimate. 

** The CO2 values represent global values (in 2010$) of the social cost of CO2 emissions in 2010 under 

several scenarios. The values of $4.9, $22.3, and $36.5 per metric ton are the averages of SCC distributions 

calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $67.6 per metric ton 

represents the 95th percentile of the SCC distribution calculated using a 3% discount rate. The value for 

NOX (in 2010$) is the average of the low and high values used in DOE’s analysis.

† Total Benefits for both the 3% and 7% cases are derived using the SCC value calculated at a 3% discount 

rate, which is $22.3/metric ton in 2010 (in 2010$). In the rows labeled as “7% plus CO2 range” and “3% 

plus CO2 range,” the operating cost and NOX benefits are calculated using the labeled discount rate, and 

those values are added to the full range of CO2 values.

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866 and 13563

Section 1(b)(1) of Executive Order 12866, “Regulatory Planning and Review,” 58 

FR 51735 (Oct 4, 1993), requires each agency to identify the problem that it intends to 

address, including, where applicable, the failures of private markets or public institutions 

that warrant new agency action, as well as to assess the significance of that problem. The 

problems that today’s proposed standards address are as follows: 

(1) There is a lack of consumer information and/or information processing capability 

about energy efficiency opportunities in the commercial equipment market.
330

(2) There is asymmetric information (one party to a transaction has more and better 

information than the other) and/or high transactions costs (costs of gathering 

information and effecting exchanges of goods and services).

(3) There are external benefits resulting from improved energy efficiency of 

distribution transformers that are not captured by the users of such equipment. 

These benefits include externalities related to environmental protection and 

energy security that are not reflected in energy prices, such as reduced emissions 

of greenhouse gases.

The specific market failure that the energy conservation standard addresses for 

distribution transformers is that a substantial portion of distribution transformer 

purchasers are not evaluating the cost of transformer losses when they make distribution 

transformer purchase decisions. Therefore, distribution transformers are being purchased 

that do not provide the minimum LCC service to equipment owners.

For distribution transformers, the Institute of Electronic and Electrical Engineers 

Inc. (IEEE) has documented voluntary guidelines for the economic evaluation of 

distribution transformer losses, IEEE PC57.12.33/D8. These guidelines document 

economic evaluation methods for distribution transformers that are common practice in 

the utility industry. But while economic evaluation of transformer losses is common, it is 

not a universal practice. DOE collected information during the course of the previous 

energy conservation standard rulemaking to estimate the extent to which distribution 

transformer purchases are evaluated. Data received from the National Electrical 
331

Manufacturers Association indicated that these guidelines or similar criteria are applied 

to approximately 75 percent of liquid-immersed transformer purchases, 50 percent of 

small capacity medium-voltage dry-type transformer purchases, and 80 percent of large 

capacity medium-voltage dry-type transformer purchases. Therefore, 25 percent, 50 

percent, and 20 percent of distribution transformer purchases do not have economic 

evaluation of transformer losses. These are the portions of the distribution transformer 

market in which there is market failure. Today’s proposed energy conservation standards

would eliminate from the market those distribution transformers designs that are 

purchased on a purely minimum first cost basis, but which would not likely be purchased 

by equipment buyers when the economic value of equipment losses are properly 

evaluated. 

In addition, DOE has determined that today’s regulatory action is an 

“economically significant regulatory action” under section 3(f)(1) of Executive Order 

12866. Accordingly, section 6(a)(3) of the Executive Order requires that DOE prepare a 

regulatory impact analysis (RIA) on today’s proposed rule and that the Office of 

Information and Regulatory Affairs (OIRA) in the Office of Management and Budget 

(OMB) review this rule. DOE presented to OIRA for review the draft rule and other 

documents prepared for this rulemaking, including the RIA, and has included these 

documents in the rulemaking record. The assessments prepared pursuant to Executive 

Order 12866 can be found in the technical support document for this rulemaking. 
332

DOE has also reviewed this regulation pursuant to Executive Order 13563. 76 FR 

3281 (Jan. 21, 2011). EO 13563 is supplemental to and explicitly reaffirms the principles, 

structures, and definitions governing regulatory review established in Executive Order 

12866. To the extent permitted by law, agencies are required by Executive Order 13563 

to: (1) propose or adopt a regulation only upon a reasoned determination that its benefits 

justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) 

tailor regulations to impose the least burden on society, consistent with obtaining 

regulatory objectives, taking into account, among other things, and to the extent 

practicable, the costs of cumulative regulations; (3) select, in choosing among alternative 

regulatory approaches, those approaches that maximize net benefits (including potential 

economic, environmental, public health and safety, and other advantages; distributive 

impacts; and equity); (4) to the extent feasible, specify performance objectives, rather 

than specifying the behavior or manner of compliance that regulated entities must adopt; 

and (5) identify and assess available alternatives to direct regulation, including providing 

economic incentives to encourage the desired behavior, such as user fees or marketable 

permits, or providing information upon which choices can be made by the public. 

DOE emphasizes as well that Executive Order 13563 requires agencies to use the 

best available techniques to quantify anticipated present and future benefits and costs as 

accurately as possible. In its guidance, the Office of Information and Regulatory Affairs 

has emphasized that such techniques may include identifying changing future compliance 

costs that might result from technological innovation or anticipated behavioral changes. 
333

For the reasons stated in the preamble, DOE believes that today’s NOPR is consistent 

with these principles. 

B. Review Under the Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires preparation of an 

initial regulatory flexibility analysis (IRFA) for any rule that by law must be proposed for 

public comment, unless the agency certifies that the rule, if promulgated, will not have a 

significant economic impact on a substantial number of small entities. As required by 

Executive Order 13272, “Proper Consideration of Small Entities in Agency Rulemaking,” 

67 FR 53461 (Aug. 16, 2002), DOE published procedures and policies on February 19, 

2003, to ensure that the potential impacts of its rules on small entities are properly 

considered during the rulemaking process. 68 FR 7990. DOE has made its procedures 

and policies available on the Office of the General Counsel’s website (www.gc.doe.gov ).

Based on the number of small distribution transformer manufacturers and the 

potential scope of the impact, DOE could not certify that the proposed standards would 

not have a significant impact on a significant number of small businesses in the 

distribution transformer industry. Therefore, DOE has prepared an IRFA for this 

rulemaking, a copy of which DOE will transmit to the Chief Counsel for Advocacy of the 

SBA for review under 5 U.S.C 605(b). As presented and discussed below, the IFRA 

describes potential impacts on small transformer manufacturers associated with capital 

and product conversion costs and discusses alternatives that could minimize these 

impacts. 
334

A statement of the objectives of, and reasons and legal basis for, the proposed rule 

are set forth elsewhere in the preamble and not repeated here.

1. Description and Estimated Number of Small Entities Regulated

a. Methodology for Estimating the Number of Small Entities

For manufacturers of distribution transformers, the Small Business 

Administration (SBA) has set a size threshold, which defines those entities classified as 

“small businesses” for the purposes of the statute. DOE used the SBA’s small business 

size standards to determine whether any small entities would be subject to the 

requirements of the rule. 65 FR 30836, 30850 (May 15, 2000), as amended at 65 FR 

53533, 53545 (Sept. 5, 2000) and codified at 13 CFR part 121.The size standards are 

listed by North American Industry Classification System (NAICS) code and industry 

description and are available at http://www.sba.gov/content/table-small-business-sizestandards. Distribution transformer manufacturing is classified under NAICS 335311, 

“Power, Distribution and Specialty Transformer Manufacturing.” The SBA sets a 

threshold of 750 employees or less for an entity to be considered as a small business for 

this category.

To estimate the number of companies that could be small business manufacturers 

of products covered by this rulemaking, DOE conducted a market survey using available 

public information to identify potential small manufacturers. DOE’s research involved 

industry trade association membership directories (including NEMA), information from 
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previous rulemakings, UL qualification directories, individual company websites, and 

market research tools (e.g., Hoover’s reports) to create a list of companies that potentially 

manufacture distribution transformers covered by this rulemaking. DOE also asked 

stakeholders and industry representatives if they were aware of any other small 

manufacturers during manufacturer interviews and at previous DOE public meetings. As 

necessary, DOE contacted companies on its list to determine whether they met the SBA’s 

definition of a small business manufacturer. DOE screened out companies that do not 

offer products covered by this rulemaking, do not meet the definition of a “small 

business,” or are foreign owned and operated. 

DOE initially identified at least 63 potential manufacturers of distribution 

transformers sold in the U.S. DOE reviewed publicly available information on these 

potential manufacturers and contacted many to determine whether they qualified as small 

businesses. . Based on these efforts, DOE estimates there are 10 liquid immersed small 

business manufacturers, 14 LVDT small business manufacturers, and 17 small business 

manufacturers of MVDT. . Some small businesses compete in more than one of these 

markets.

b. Manufacturer Participation

Of the LVDT manufacturers, DOE was able to reach and discuss potential 

standards with eight of the 14 small business manufacturers. . Of the MVDT 

manufacturers, DOE was able to reach and discuss potential standards with five of the 17 

small business manufacturers. Of the liquid-immersed small business manufacturers, 
336

DOE was able to reach and discuss potential standards with three of the 10 small business 

manufacturers. . DOE also obtained information about small business impacts while 

interviewing large manufacturers. 

c. Distribution Transformer Industry Structure and Nature of Competition

Liquid Immersed.

Six major manufacturers supply more than 80 percent of the market for liquidimmersed transformers. None of the major manufacturers of distribution transformers

covered in this rulemaking are considered to be small businesses. The vast majority of 

shipments are manufactured domestically. Electric utilities compose the customer base 

and typically buy on first-cost. Many small manufacturers position themselves towards 

the higher end of the market or in particular product niches, such as network transformers 

or harmonic mitigating transformers, but, in general, competition is based on price after a 

given unit’s specs are prescribed by a customer.

Low-Voltage Dry-Type. 

Four major manufacturers supply more than 80 percent of the market for lowvoltage dry-type transformers. None of the major LVDT manufacturers of distribution 

transformers covered in this rulemaking are small businesses. The customer base rarely 

purchases on efficiency and is very first-cost conscious, which, in turn, places a premium 

on economies of scale in manufacturing. DOE estimates approximately 80 percent of the 

market is served by imports, mostly from Canada and Mexico. Many of the small 

businesses that compete in the low-voltage dry-type market produce specialized 
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transformers that are exempted from standards. Roughly 50 percent of the market by 

revenue is exempted from DOE standards. This market is much more fragmented than the 

one serving DOE-covered LVDT transformers. 

In the DOE-covered LVDT market, low-volume manufacturers typically do not 

compete directly with large manufacturers using business models similar to those of their 

bigger rivals because scale disadvantages in purchasing and production are usually too 

great a barrier in this portion of the market.. The exceptions to this rule are those 

companies that also compete in the medium-voltage market and, to some extent, are able 

to leverage that experience and production economies. More typically, low-volume 

manufacturers have focused their operations on one or two parts of the value chain—

rather than all of it—and trained their sights on market segments outside of the highvolume baseline efficiency market.

In terms of operations, some small firms focus on the engineering and design of 

transformers and source the production of the cores or even the whole transformer, while 

other small firms focus on just production and rebrand for companies that offer broader 

solutions through their own sales and distribution networks. 

In terms of market focus, many small firms simply compete entirely in the DOEexempted markets. DOE did not attempt to contact companies operating entirely in this 

very fragmented market. Of those that do compete in the DOE-covered market, a few 

small businesses reported a focus on the high-end of the market, often selling NEMA 
338

Premium or better transformers as retrofit opportunities. Others focus on particular 

applications or other niches, like data centers, and become well-versed in the unique 

needs of a particular customer base. 

Medium-Voltage Dry-Type.

The medium-voltage dry-type transformer market is relatively consolidated with 

one large company holding a substantial share of the market. Electric utilities and 

industrial users make up most of the customer base and typically buy on first-cost or 

features other than efficiency. DOE estimates that at least 75 percent of production occurs 

domestically. Several manufacturers also compete in the power transformer market. . 

Like the LVDT industry, most small business manufacturers often produce transformers 

exempted from DOE standards. DOE estimates 10 percent of the market is exempt from 

standards.

d. Comparison between Large and Small Entities

Small distribution transformer manufacturers differ from large manufacturers in 

several ways that affect the extent to which they would be impacted by the proposed 

standards. Characteristics of small manufacturers include: lower production volumes, 

fewer engineering resources, less technical expertise, lack of purchasing power for high 

performance steels, and less access to capital.

Lower production volumes lie at the heart of most small business disadvantages, 

particularly for a small manufacturer that is vertically integrated. A lower-volume 
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manufacturer’s conversion costs would need to be spread over fewer units than a larger 

competitor. Thus, unless the small business can differentiate its product in some way that 

earns a price premium, the small business is a ‘price taker’ and experiences a reduction in 

profit per unit relative to the large manufacturer. Therefore, because much of the same 

equipment would need to be purchased by both large and small manufacturers in order to 

produce transformers (in-house) at higher TSLs, undifferentiated small manufacturers 

would face a greater variable cost penalty because they must depreciate the one-time 

conversion expenditures over fewer units.

Smaller companies are also more likely to have more limited engineering 

resources and they often operate with lower levels of design and manufacturing 

sophistication. Smaller companies typically also have less experience and expertise in 

working with more advanced technologies, such as amorphous core construction in the 

liquid immersed market or step-lap mitering in the dry-type markets. Standards that 

required these technologies could strain the engineering resources of these small 

manufacturers if they chose to maintain a vertically integrated business model.

Small distribution transformer manufacturers can also be at a disadvantage due to 

their lack of purchasing power for high performance materials. If more expensive steels 

are needed to meet standards and steel cost grows as a percentage of the overall product 

cost, small manufacturers who pay higher per pound prices would be disproportionately 

impacted. 
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Lastly, small manufacturers typically have less access to capital, which may be 

needed by some to cover the conversion costs associated with new technologies. 

2. Description and Estimate of Compliance Requirements 

Liquid Immersed. Based on interviews with manufacturers in the liquidimmersed market, DOE does not believe small manufacturers will face significant capital 

conversion costs at the levels proposed in today’s rulemaking. DOE expects small 

manufacturers of liquid-immersed distribution transformers to continue to produce silicon 

steel cores, rather than invest in amorphous technology. While silicon steel designs 

capable of achieving TSL 1 would get larger, and thus reduce throughput, most 

manufacturers said the industry in general has substantial excess capacity due to the 

recent economic downturn. Therefore, DOE believes TSL 1 would not require the typical 

small manufacturer to invest in additional capital equipment. However, small 

manufacturers may incur some engineering and product design costs associated with reoptimizing their production processes around new baseline products. DOE estimates TSL 

1 would require industry production development costs of only one-half of one year’s 

annual industry R&D expenses, as the levels do not require any changes in technology or 

steel types. Because these costs are relatively fixed per manufacturer, these one-time 

costs impact smaller manufacturers disproportionately compared to larger manufacturers. 

The table below illustrates this effect by comparing the conversion costs to a typical 

small company’s and a typical large manufacturer’s annual R&D expenses. 
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Table VI.1 Estimated Product Conversion Costs as a Percentage of Annual R&D 

Expense

Product Conversion 

Cost 

Product Conversion Cost as a 

Percentage of Annual R&D 

Expense

Typical Large Manufacturer $1.4 M 20%

Typical Small Manufacturer $1.4 M 222%

While the costs disproportionately impact small manufactures, the standard levels, 

as stated above, do not require small manufacturers to invest in entirely different 

production processes nor do they require steels or core construction techniques with 

which these manufacturers are not familiar. A range of design options would still be 

available. 

Low-Voltage Dry-Type. For the low-voltage dry-type market, at TSL 1, the level 

proposed in today’s notice, DOE estimates, capital conversion costs of $0.75 million and 

product conversion costs of $0.2 million for a typical small and large manufacturer, based 

on manufacturer interviews. Because of the largely fixed nature of these one-time 

conversion expenditures that distribution transformer manufacturers would incur as a 

result of standards, small manufacturers who choose to invest to maintain in-house 

production will likely be disproportionately impacted compared to large manufacturers. 

As Table VI.2 indicates, small manufacturers face a greater relative hurdle in complying 

with standards should they opt to continue to maintain core production in-house. 
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Table VI.2 Estimated Capital and Product Conversion Costs as a Percentage of 

Annual Capital Expenditures and R&D Expense

Capital Conversion 

Cost as a Percentage 

of Annual Capital 

Expenditures

Product Conversion 

Cost as a Percentage 

of Annual R&D 

Expense

Total Conversion Cost 

as a Percentage of 

Annual EBIT

Large Manufacturer 40% 11% 17%

Small Manufacturer 152% 49% 77%

As demonstrated in the table above, the investments required to meet TSL 1, 

disproportionately impact small businesses. However, DOE’s capital conversion costs 

estimates in the table above assume that small businesses are currently producing their 

cores in-house and will choose to do so in the future, rather than source them from thirdparty core manufactures who often have significant cost advantages through bulk steel 

purchasing power and greater production efficiencies due to higher volumes. As such, 

many small businesses DOE interviewed already source a large percentage of their cores 

and many indicated they expected such a strategy would be the low-cost option under 

higher standards. 

Compared to higher TSLs, TSL 1 provides many more design paths for small 

manufacturers to comply. DOE’s engineering analysis indicates manufacturers can 

continue to use the low-capital butt-lap core designs, meaning investment in mitering 

capability is not necessary to comply. Manufacturers can use higher-quality grain 

oriented steels in butt-lap designs to meet these proposed efficiency levels, source some 

or all cores, or invest in mitering capability. DOE notes that roughly half of the small 

business LVDT manufacturers DOE interviewed already have mitering capability. For all 
343

of the reasons discussed, DOE believes the capital expenditures it assumed for small 

businesses are likely conservative and that small businesses have a variety of technical 

and strategic paths to continue to compete in the market at TSL 1.

Medium-Voltage Dry-Type. . Based on its engineering analysis and interviews, 

DOE expects relatively minor capital expenditures for the industry to meet TSL 2. DOE 

understands that the market is already standardized on step-lap mitering, so 

manufacturers will not need to make major investments for more advanced core 

construction. Furthermore, TSL 2 does not require a change to much thinner steels such 

as M3 or HO. The industry can use M4 and H1, thicker steels with which it has much 

more experience and which are easier to employ in the stacked-core production process 

that dominates the medium-voltage market. However, some investment will be required 

to maintain capacity as some manufacturers will likely migrate to more M4 and H1 steel 

from the slightly thicker M5, which is also common.. Additionally, design options at TSL 

2 typically have larger cores, also slowing throughput. Therefore, some manufacturers 

may need to invest in additional production equipment. Alternatively, depending on each 

company’s availability capacity, manufacturers could employ addition production shifts, 

rather than invest in additional capacity.

For the medium-voltage dry-type market, at TSL 2, the level proposed in today’s 

notice, DOE estimates capital conversion costs of $1.0 million and product conversion 

costs of $0.2 million for a typical small and large manufacturer that would need to 
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expand mitering capacity to meet TSL 2. Table VI.3 illustrates the relative impacts on 

small and large manufacturers.

Table VI.3 Estimated Capital and Product Conversion Costs as a Percentage of 

Annual Capital Expenditures and R&D Expense

Capital Conversion 

Cost as a Percentage 

of Annual Capital 

Expenditures

Product Conversion 

Cost as a Percentage 

of Annual R&D 

Expense

Total Conversion Cost 

as a Percentage of 

Annual EBIT

Large Manufacturer 43% 7% 14%

Small Manufacturer 327% 65% 124%

a. Summary of Compliance Impacts

The compliance impacts on small businesses are discussed above for low-voltage 

dry-type, medium-voltage dry-type, and liquid-filled distribution transformer 

manufacturers. Although the conversion costs required can be considered substantial for 

all companies, the impacts could be relatively greater for a typical small manufacturer 

because of much lower production volumes and the relatively fixed nature of the R&D 

and capital investments required. 

DOE seeks comment on the potential impacts of amended standards on small 

distribution transformer manufacturers. 

3. Duplication, Overlap, and Conflict with Other Rules and Regulations

DOE is not aware of any rules or regulations that duplicate, overlap, or conflict 

with the rule being considered today.
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4. Significant Alternatives to the Proposed Rule 

The discussion above analyzes impacts on small businesses that would result from 

the other TSLs DOE considered. Though TSLs lower than the proposed TSLs are 

expected to reduce the impacts on small entities, DOE is required by EPCA to establish 

standards that achieve the maximum improvement in energy efficiency that are 

technically feasible and economically justified, and result in a significant conservation of 

energy. Therefore, DOE rejected the lower TSLs. 

In addition to the other TSLs being considered, the NOPR TSD includes a 

regulatory impact analysis in chapter 17. For distribution transformers, this report

discusses the following policy alternatives: (1) consumer rebates, (2) consumer tax 

credits, and (3) manufacturer tax credits. DOE does not intend to consider these 

alternatives further because they either are not feasible to implement or are not expected

to result in energy savings as large as those that would be achieved by the standard levels 

under consideration. 

DOE continues to seek input from businesses that would be affected by this 

rulemaking and will consider comments received in the development of any final rule.

5. Significant Issues Raised by Public Comments

DOE’s MIA suggests that, while TSL1, TSL1, and TSL 2 presents greater 

difficulties for small businesses than lower levels in the liquid-immersed, LVDT, and 

MVDT superclasses, respectively, the impacts at higher TSLs would be greater. DOE 
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expects that small businesses will generally be able to profitably compete at the TSL 

proposed in today’s rulemaking. DOE’s MIA is based on its interviews of both small and 

large manufacturers, and consideration of small business impacts explicitly enters into 

DOE’s choice of the TSLs proposed in this NOPR. 

DOE also notes that today’s proposed standards can be met with a variety of 

materials, including multiple core steels and both copper and aluminum windings. 

Because the proposed TSLs can be met with a variety of materials, DOE does not expect 

that material availability issues will be a problem for the industry that results from this 

rulemaking. 

ACEEE submitted a comment stating that small, medium-voltage dry-type 

manufacturers would not be forced out of business at higher standard levels because they 

could either install the necessary mitering equipment or purchase finished cores. 

(ACEEE, No. 127 at p. 9) DOE recognizes both of these possibilities. While DOE agrees 

that standard levels higher than TSL2 would not necessarily drivel small businesses from 

the market, there is much more uncertainty about whether traditional M-grade steels can 

be used at higher TSLs, which could disproportionately jeopardize many small 

manufacturers who have limited access to domain refined steels.

6. Steps DOE Has Taken to Minimize the Economic Impact on Small Manufacturers

In consideration of the benefits and burdens of standards, including the burdens 

posed to small manufacturers, DOE concluded TSL1 is the highest level that can be 
347

justified for liquid immersed and low-voltage dry-type transformers and TSL2 is the 

highest level that can be justified for medium-voltage, dry-type transformers. As 

explained in part 6 of the IRFA, “Significant Alternatives to the Rule,” DOE explicitly 

considered the impacts on small manufacturers of liquid immersed and dry-type 

transformers in selecting the TSLs proposed in today’s rulemaking, rather than selecting 

a higher trial standard level. It is DOE’s belief that levels at TSL3 or higher would place 

excessive burdens on small manufacturers of medium-voltage, dry-type transformers, as 

would TSL 2 or higher for liquid immersed and low-voltage dry-type transformers. Such 

burdens would include large product redesign costs and also operational problems 

associated with the extremely thin laminations of core steel that would be needed to meet 

these levels and advanced core construction equipment and tooling. For low-voltage drytype specifically, TSL2 essentially eliminates butt-lap core designs and will therefore put 

more burden on small manufacturers than would TSL1. However, the differential impact 

on small businesses (versus large businesses) is expected to be lower in moving to TSL1 

than in moving from TSL2 to TSL3 because of the likely need to employ step lap 

mitering or wound core designs. Similarly, for medium voltage dry-type, the steels and 

construction techniques likely to be used at TSL 2 are already commonplace in the 

market, whereas TSL 3 would likely trigger a more dramatic shift to thinner and more 

exotic steels, to which many small businesses have limited access. Lastly, DOE is 

confident that TSL1 for the liquid immersed market would not require small 

manufacturers to invest in amorphous technology, which could put them at a significant 

disadvantage. 
348

Section VI.B above discusses how small business impacts entered into DOE’s 

selection of today’s proposed standards for distribution transformers. DOE made its 

decision regarding standards by beginning with the highest level considered and 

successively eliminating TSLs until it found a TSL that is both technologically feasible 

and economically justified, taking into account other EPCA criteria. Because DOE 

believes that the TSLs proposed are economically justified (including consideration of 

small business impacts), the reduced impact on small businesses that would have been 

realized in moving down to lower efficiency levels was not considered in DOE’s decision 

(but the reduced impact on small businesses that is realized in moving down to TSL2 

from TSL3 (in the case of medium-voltage dry-type) and TSL2 to TSL1 (in the case of 

liquid immersed and low-voltage dry-type) was explicitly considered in the weighing of 

benefits and burdens).

C. Review Under the Paperwork Reduction Act

Manufacturers of distribution transformers must certify to DOE that their products 

comply with any applicable energy conservation standards. In certifying compliance, 

manufacturers must test their products according to the DOE test procedures for 

distribution transformers, including any amendments adopted for those test procedures. 

DOE has established regulations for the certification and recordkeeping requirements for 

all covered consumer products and commercial equipment, including distribution 

transformers. (76 FR 12422 (March 7, 2011). The collection-of-information requirement 

for the certification and recordkeeping is subject to review and approval by OMB under 

the Paperwork Reduction Act (PRA). This requirement has been approved by OMB 
349

under OMB control number 1910-1400. Public reporting burden for the certification is 

estimated to average 20 hours per response, including the time for reviewing instructions, 

searching existing data sources, gathering and maintaining the data needed, and 

completing and reviewing the collection of information. 

Notwithstanding any other provision of the law, no person is required to respond 

to, nor shall any person be subject to a penalty for failure to comply with, a collection of 

information subject to the requirements of the PRA, unless that collection of information 

displays a currently valid OMB Control Number.

D. Review Under the National Environmental Policy Act of 1969

Pursuant to the National Environmental Policy Act (NEPA) of 1969, as amended 

(42 U.S.C. 4321 et seq.), DOE has determined that the proposed rule fits within the 

category of actions included in Categorical Exclusion (CX) B5.1 and otherwise meets the 

requirements for application of a CX. (See 10 CFR 1021.410(b) and Appendix B to 

Subpart D) The proposed rule fits within this category of actions because it is a 

rulemaking that establishes energy conservation standards for consumer products or 

industrial equipment, and for which none of the exceptions identified in CX B5.1(b) 

apply. Therefore, DOE has made a CX determination for this rulemaking, and DOE does 

not need to prepare an Environmental Assessment or Environmental Impact Statement

for this proposed rule. DOE’s CX determination for this proposed rule is available at

http://cxnepa.energy.gov.
350

E. Review Under Executive Order 13132

Executive Order 13132, “Federalism,” 64 FR 43255 (Aug. 10, 1999) imposes 

certain requirements on Federal agencies formulating and implementing policies or 

regulations that preempt State law or that have Federalism implications. The Executive 

Order requires agencies to examine the constitutional and statutory authority supporting 

any action that would limit the policymaking discretion of the States and to carefully 

assess the necessity for such actions. The Executive Order also requires agencies to have 

an accountable process to ensure meaningful and timely input by State and local officials 

in the development of regulatory policies that have Federalism implications. On March 

14, 2000, DOE published a statement of policy describing the intergovernmental 

consultation process it will follow in the development of such regulations. 65 FR 13735. 

EPCA governs and prescribes Federal preemption of State regulations as to energy 

conservation for the products that are the subject of today’s proposed rule. States can 

petition DOE for exemption from such preemption to the extent, and based on criteria, set 

forth in EPCA. (42 U.S.C. 6297) No further action is required by Executive Order 13132.

F. Review Under Executive Order 12988

With respect to the review of existing regulations and the promulgation of new 

regulations, section 3(a) of Executive Order 12988, “Civil Justice Reform,” imposes on 

Federal agencies the general duty to adhere to the following requirements: (1) eliminate 

drafting errors and ambiguity; (2) write regulations to minimize litigation; and (3) 

provide a clear legal standard for affected conduct rather than a general standard and 

promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Section 3(b) of 
351

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 

section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to 

meet one or more of them. DOE has completed the required review and determined that, 

to the extent permitted by law, this proposed rule meets the relevant standards of 

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. Pub. L. 104-4, sec. 201 (codified at 2 U.S.C. 

1531). For a proposed regulatory action likely to result in a rule that may cause the 

expenditure by State, local, and Tribal governments, in the aggregate, or by the private 

sector of $100 million or more in any one year (adjusted annually for inflation), section 

202 of UMRA requires a Federal agency to publish a written statement that estimates the 

resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a),

(b)) The UMRA also requires a Federal agency to develop an effective process to permit 
352

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. DOE’s policy statement is

also available at www.gc.doe.gov.

Although today’s proposed rule does not contain a Federal intergovernmental 

mandate, it may require expenditures of $100 million or more on the private sector. 

Specifically, the proposed rule will likely result in a final rule that could require 

expenditures of $100 million or more. Such expenditures may include: (1) investment in 

R&D and in capital expenditures by distribution transformer manufacturers in the years 

between the final rule and the compliance date for the new standards, and (2) incremental 

additional expenditures by consumers to purchase higher-efficiency distribution 

transformers, starting at the compliance date for the applicable standard.

Section 202 of UMRA authorizes a Federal agency to respond to the content 

requirements of UMRA in any other statement or analysis that accompanies the proposed 

rule. (2 U.S.C. 1532(c)) The content requirements of section 202(b) of UMRA relevant to 

a private sector mandate substantially overlap the economic analysis requirements that 

apply under section 325(o) of EPCA and Executive Order 12866. The 

SUPPLEMENTARY INFORMATION section of this NOPR and the “Regulatory 
353

Impact Analysis” chapter of the TSD for this proposed rule respond to those 

requirements. 

Under section 205 of UMRA, the Department is obligated to identify and consider 

a reasonable number of regulatory alternatives before promulgating a rule for which a 

written statement under section 202 is required. 2 U.S.C. 1535(a). DOE is required to 

select from those alternatives the most cost-effective and least burdensome alternative 

that achieves the objectives of the proposed rule unless DOE publishes an explanation for 

doing otherwise, or the selection of such an alternative is inconsistent with law. As 

required by 42 U.S.C. 6295(d), (f), and (o), 6313(e), and 6316(a), today’s proposed rule 

would establish energy conservation standards for distribution transformers that are 

designed to achieve the maximum improvement in energy efficiency that DOE has 

determined to be both technologically feasible and economically justified. A full 

discussion of the alternatives considered by DOE is presented in the “Regulatory Impact 

Analysis” section of the TSD for today’s proposed rule.

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

Section 654 of the Treasury and General Government Appropriations Act, 1999 

(Pub. L. 105-277) requires Federal agencies to issue a Family Policymaking Assessment 

for any rule that may affect family well-being. This rule would not have any impact on 

the autonomy or integrity of the family as an institution. Accordingly, DOE has 

concluded that it is not necessary to prepare a Family Policymaking Assessment.
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I. Review Under Executive Order 12630

DOE has determined that under Executive Order 12630, “Governmental Actions 

and Interference with Constitutionally Protected Property Rights” 53 FR 8859 (March 18, 

1988), this regulation would not result in any takings that might require compensation 

under the Fifth Amendment to the U.S. Constitution.

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

Section 515 of the Treasury and General Government Appropriations Act, 2001 

(44 U.S.C. 3516, note) provides for Federal agencies to review most disseminations of 

information to the public under guidelines established by each agency pursuant to general 

guidelines issued by OMB. OMB’s guidelines were published at 67 FR 8452 (February

22, 2002), and DOE’s guidelines were published at 67 FR 62446 (October 7, 2002). DOE 

has reviewed today’s NOPR under the OMB and DOE guidelines and has concluded that 

it is consistent with applicable policies in those guidelines.

K. Review Under Executive Order 13211

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 OIRA at OMB, a Statement of Energy Effects 

for any proposed significant energy action. A “significant energy action” is defined as 

any action by an agency that promulgates or is expected to lead to promulgation of a final 

rule, and that: (1) is a significant regulatory action under Executive Order 12866, or any 

successor order; and (2) is likely to have a significant adverse effect on the supply, 
355

distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a 

significant energy action. For any proposed significant energy action, the agency must 

give a detailed statement of any adverse effects on energy supply, distribution, or use 

should the proposal be implemented, and of reasonable alternatives to the action and their 

expected benefits on energy supply, distribution, and use. 

DOE has tentatively concluded that today’s regulatory action, which sets forth 

proposed energy conservation standards for distribution transformers, is not a significant 

energy action because the proposed standards are not likely to have a significant adverse 

effect on the supply, distribution, or use of energy, nor has it been designated as such by 

the Administrator at OIRA. Accordingly, DOE has not prepared a Statement of Energy 

Effects on the proposed rule.

L. Review Under the Information Quality Bulletin for Peer Review 

On December 16, 2004, OMB, in consultation with the Office of Science and 

Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review 

(the Bulletin). 70 FR 2664 (January 14, 2005). The Bulletin establishes that certain 

scientific information shall be peer reviewed by qualified specialists before it is 

disseminated by the Federal Government, including influential scientific information 

related to agency regulatory actions. The purpose of the bulletin is to enhance the quality 

and credibility of the Government’s scientific information. Under the Bulletin, the energy 

conservation standards rulemaking analyses are “influential scientific information,” 

which the Bulletin defines as scientific information the agency reasonably can determine 
356

will have, or does have, a clear and substantial impact on important public policies or 

private sector decisions. 70 FR 2667.

In response to OMB’s Bulletin, DOE conducted formal in-progress peer reviews 

of the energy conservation standards development process and analyses and has prepared 

a Peer Review Report pertaining to the energy conservation standards rulemaking 

analyses. Generation of this report involved a rigorous, formal, and documented 

evaluation using objective criteria and qualified and independent reviewers to make a 

judgment as to the technical/scientific/business merit, the actual or anticipated results, 

and the productivity and management effectiveness of programs and/or projects. The 

“Energy Conservation Standards Rulemaking Peer Review Report” dated February 2007 

has been disseminated and is available at the following Web site: 

www1.eere.energy.gov/buildings/appliance_standards/peer_review.html.

VII. Public Participation

A. Attendance at the Public Meeting

The time, date, and location of the public meeting are listed in the DATES and 

ADDRESSES sections at the beginning of this notice. If you plan to attend the public 

meeting, please notify Ms. Brenda Edwards at (202) 586-2945 or 

Brenda.Edwards@ee.doe.gov. As explained in the ADDRESSES section, foreign 

nationals visiting DOE Headquarters are subject to advance security screening 

procedures. Please also note that anyone that wishes to bring a laptop computer into the 
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Forrestal Building will be required to obtain a property pass. Otherwise, visitors should 

avoid bringing laptops, or allow an extra 45 minutes.

In addition, you can attend the public meeting via webinar. Webinar registration 

information, participant instructions, and information about the capabilities available to 

webinar participants will be published on DOE’s website at:

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/distribution_tra

nsformers.html. Participants are responsible for ensuring their systems are compatible 

with the webinar software.

All documents in the docket are listed in the www.regulations.gov index. 

However, not all documents listed in the index may be publicly available, such as 

information that is exempt from public disclosure. The regulations.gov web page will 

contain simple instructions on how to access all documents, including public comments, 

in the docket. See section B for further information on how to submit comments through 

www.regulations.gov.

B. Procedure for Submitting Prepared General Statements For Distribution

Any person who has plans to present a prepared general statement may request 

that copies of his or her statement be made available at the public meeting. Such persons 

may submit requests, along with an advance electronic copy of their statement in PDF 

(preferred), Microsoft Word or Excel, WordPerfect, or text (ASCII) file format, to the 

appropriate address shown in the ADDRESSES section at the beginning of this notice. 
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The request and advance copy of statements must be received at least one week before 

the public meeting and may be emailed, hand-delivered, or sent by mail. DOE prefers to 

receive requests and advance copies via email. Please include a telephone number to 

enable DOE staff to make follow-up contact, if needed.

C. Conduct of the Public Meeting

DOE will designate a DOE official to preside at the public meeting and may also 

use a professional facilitator to aid discussion. The meeting will not be a judicial or 

evidentiary-type public hearing, but DOE will conduct it in accordance with section 336 

of EPCA (42 U.S.C. 6306). A court reporter will be present to record the proceedings and 

prepare a transcript. DOE reserves the right to schedule the order of presentations and to 

establish the procedures governing the conduct of the public meeting. After the public 

meeting, interested parties may submit further comments on the proceedings as well as on 

any aspect of the rulemaking until the end of the comment period.

The public meeting will be conducted in an informal, conference style. DOE will 

present summaries of comments received before the public meeting, allow time for 

prepared general statements by participants, and encourage all interested parties to share 

their views on issues affecting this rulemaking. Each participant will be allowed to make 

a general statement (within time limits determined by DOE), before the discussion of 

specific topics. DOE will allow, as time permits, other participants to comment briefly on 

any general statements. 
359

At the end of all prepared statements on a topic, DOE will permit participants to 

clarify their statements briefly and comment on statements made by others. Participants 

should be prepared to answer questions by DOE and by other participants concerning 

these issues. DOE representatives may also ask questions of participants concerning other 

matters relevant to this rulemaking. The official conducting the public meeting will 

accept additional comments or questions from those attending, as time permits. The 

presiding official will announce any further procedural rules or modification of the above 

procedures that may be needed for the proper conduct of the public meeting.

A transcript of the public meeting will be included in the docket, which can be 

viewed as described in the Docket section at the beginning of this notice. In addition, any 

person may buy a copy of the transcript from the transcribing reporter.

D. Submission of Comments

DOE will accept comments, data, and information regarding this proposed rule 

before or after the public meeting, but no later than the date provided in the DATES 

section at the beginning of this proposed rule. Interested parties may submit comments, 

data, and other information using any of the methods described in the ADDRESSES 

section at the beginning of this notice. 

Submitting comments via regulations.gov. The regulations.gov web page will 

require you to provide your name and contact information. Your contact information will 

be viewable to DOE Building Technologies staff only. Your contact information will not 
360

be publicly viewable except for your first and last names, organization name (if any), and 

submitter representative name (if any). If your comment is not processed properly 

because of technical difficulties, DOE will use this information to contact you. If DOE 

cannot read your comment due to technical difficulties and cannot contact you for 

clarification, DOE may not be able to consider your comment.

However, your contact information will be publicly viewable if you include it in 

the comment itself or in any documents attached to your comment. Any information that 

you do not want to be publicly viewable should not be included in your comment, nor in 

any document attached to your comment. Persons viewing comments will see only first 

and last names, organization names, correspondence containing comments, and any 

documents submitted with the comments. 

Do not submit to regulations.gov information for which disclosure is restricted by 

statute, such as trade secrets and commercial or financial information (hereinafter 

referred to as Confidential Business Information (CBI)). Comments submitted through 

regulations.gov cannot be claimed as CBI. Comments received through the website will 

waive any CBI claims for the information submitted. For information on submitting CBI, 

see the Confidential Business Information section below.

DOE processes submissions made through regulations.gov before posting. 

Normally, comments will be posted within a few days of being submitted. However, if 

large volumes of comments are being processed simultaneously, your comment may not 
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be viewable for up to several weeks. Please keep the comment tracking number that 

regulations.gov provides after you have successfully uploaded your comment. 

Submitting comments via email, hand delivery/courier, or mail. Comments and 

documents submitted via email, hand delivery, or mail also will be posted to 

regulations.gov. If you do not want your personal contact information to be publicly 

viewable, do not include it in your comment or any accompanying documents. Instead, 

provide your contact information in a cover letter. Include your first and last names, 

email address, telephone number, and optional mailing address. The cover letter will not 

be publicly viewable as long as it does not include any comments

Include contact information each time you submit comments, data, documents, 

and other information to DOE. If you submit via mail or hand delivery/courier, please 

provide all items on a CD, if feasible. It is not necessary to submit printed copies. No 

facsimiles (faxes) will be accepted.

 

Comments, data, and other information submitted to DOE electronically should 

be provided in PDF (preferred), Microsoft Word or Excel, WordPerfect, or text (ASCII) 

file format. Provide documents that are not secured, that are written in English, and that 

are free of any defects or viruses. Documents should not contain special characters or any 

form of encryption and, if possible, they should carry the electronic signature of the 

author. 
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Campaign form letters. Please submit campaign form letters by the originating 

organization in batches of between 50 to 500 form letters per PDF or as one form letter 

with a list of supporters’ names compiled into one or more PDFs. This reduces comment 

processing and posting time. 

Confidential Business Information. According to 10 CFR 1004.11, any person 

submitting information that he or she believes to be confidential and exempt by law from 

public disclosure should submit via email, postal mail, or hand delivery/courier two wellmarked copies: one copy of the document marked confidential including all the 

information believed to be confidential, and one copy of the document marked nonconfidential with the information believed to be confidential deleted. Submit these 

documents via email or on a CD, if feasible. DOE will make its own determination about 

the confidential status of the information and treat it according to its determination.

Factors of interest to DOE when evaluating requests to treat submitted 

information as confidential include: (1) a description of the items; (2) whether and why 

such items are customarily treated as confidential within the industry; (3) whether the 

information is generally known by or available from other sources; (4) whether the 

information has previously been made available to others without obligation concerning 

its confidentiality; (5) an explanation of the competitive injury to the submitting person 

which would result from public disclosure; (6) when such information might lose its 

confidential character due to the passage of time; and (7) why disclosure of the 

information would be contrary to the public interest.
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It is DOE’s policy that all comments may be included in the public docket, 

without change and as received, including any personal information provided in the 

comments (except information deemed to be exempt from public disclosure). 

E. Issues on Which DOE Seeks Comment

Although DOE welcomes comments on any aspect of this proposal, DOE is 

particularly interested in receiving comments and views of interested parties concerning 

the following issues: 

1. DOE requests comment on primary and secondary winding configurations, on 

how testing should be required, on efficiency differences related to different 

winding configurations, and on how frequently transformers are operated in 

various winding configurations.

2. DOE requests comment on its proposal to require transformers with multiple 

nameplate kVA ratings to comply only at those ratings corresponding to passive 

cooling.

3. DOE requests comment on its proposal to maintain the requirement that 

transformers comply with standards for the BIL rating of the configuration that 

produces the highest losses.

4. DOE requests comment on its proposal to maintain the current test loading value 

requirements for all types of distribution transformers.
364

5. DOE requests comment on its proposal to require rectifier and testing 

transformers to indicate on their nameplates that they are for such purposes 

exclusively.

6. DOE requests comment on its proposal to maintain the definition of mining 

transformer but also requests information useful in precisely expanding the 

definition to encompass any activity that entails the removal of material 

underground, such as digging or tunneling.

7. DOE requests comment on its proposal to maintain the current kVA scope of 

coverage.

8. DOE requests comment on its proposal to continue not to set standards for step-up 

transformers.

9. DOE requests comment on the negotiating committee’s proposal to establish a 

separate equipment class for network/vault transformers and on how such 

transformers might be defined.

10. DOE requests comment on the negotiating committee’s proposal to establish a 

separate equipment class for data center transformers and on how such 

transformers might be defined.

11. DOE seeks comment on the operating characteristics for data center transformers. 

Specifically DOE seeks comment on appropriate load factors, and peak 

responsibility factors of data center transformers.

12. DOE requests comment on whether separate equipment classes are warranted for 

pole-mounted, pad-mounted, or other types of liquid-immersed transformers.

Comment [A52]: Change recommended by 

OIRA.
365

13. DOE requests comment on setting standards by BIL rating for liquid-immersed 

distribution transformers as it currently does for medium-voltage, dry-type units.

14. DOE requests comment on how best to scale across phase counts for each 

transformer type and how standards for either single- or three-phase transformers 

may be derived from the other type.

15. DOE requests comment on its proposal to scale standards to unanalyzed kVA 

ratings by fitting a straight line in logarithmic space to selected efficiency levels 

(ELs) with the understanding that the resulting line may not have a slope equal to 

0.75.

16. DOE seeks comment on symmetric core designs.

17. DOE seeks comment on nanotechnology composites and their potential for use in 

distribution transformers.

18. DOE requests comment on its materials prices for both 2010 and 2011 cases.

19. DOE requests comment on the current and future availabilities of high-grade 

steels, particularly amorphous and mechanically-scribed steel in the United States.

20. DOE requests comment on particular applications in which transformer size and 

weight are likely to be a constraint and any data that may be used to characterize 

the problem.

21. DOE requests comment on its steel supply availability analysis, presented in 

appendix 3A of the TSD.

22. DOE seeks comment on its proposed additional distribution channel for liquidimmersed transformers that estimates that approximately 80 percent of 

transformers are sold by manufacturers directly to utilities. Comment [A53]: Change recommended by 

OIRA.
366

23. DOE seeks comment on any additional sources of distribution transformer load 

data that could be used to validate the Energy Use and End-Use Load 

Characterization analysis. DOE is specifically interested in additional load data 

for higher capacity three phase distribution transformers.

24. DOE seeks comment on its pole replacement methodology that is used estimate 

increased installation costs resulting from increased transformer weight due the 

proposed standard. The pole replacement methodology is presented in chapter 6, 

section 6.3.1 of the TSD.

25. DOE seeks comment on recent changes to utility distribution transformer 

purchase practices that would lead to the purchase of a refurbished, specifically 

re-wound, distribution transformer over the purchase of new distribution

transformer. 

26. DOE seeks comment on the equipment lifetimes of refurbished, specifically rewound distribution transformers and how it compares to that of a new distribution 

transformer.

27. DOE seeks comment on recent changes in distribution transformer sizing 

practices. In particular, DOE would like comments on any additional sources of

data regarding trends in market share across equipment classes for either liquidimmersed or dry-type transformers that should be considered in the analysis.

28. DOE requests comment on the possibility of reduced equipment utility or 

performance resulting from today’s proposed standards, particularly the risk of 

reducing the ability to perform periodic maintenance and the risk of increasing 

vibration and acoustic noise.

Comment [A54]: Change recommended by 

OIRA.
367

29. DOE requests comment and corroborating data on how often distribution 

transformers are operated with their primary and secondary windings in different 

configurations, and on the magnitude of the additional losses in less efficient 

configurations.

30. DOE requests comment on impedance values and on any related parameters (e.g., 

inrush current, X/R ratio) that may be used in evaluation of distribution 

transformers. DOE requests particular comment on how any of those parameters 

may be affected by energy conservation standards of today’s proposed levels or 

higher. Comment [A55]: Changes recommended by 

OIRA.
368

VIII. Approval of the Office of the Secretary

The Secretary of Energy has approved publication of today’s proposed rule.

List of Subjects in 10 CFR Part 431

Administrative practice and procedure, Confidential business information, Energy 

conservation, Household appliances, Imports, Intergovernmental relations, Reporting and 

recordkeeping requirements, and Small businesses. 

Issued in Washington, DC, on 

________________________________

Henry Kelly

Acting Assistant Secretary of Energy

Energy Efficiency and Renewable Energy
369

For the reasons set forth in the preamble, DOE proposes to amend subpart K of 

part 431 of chapter II, of title 10 of the Code of Federal Regulations, to read 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. 

2. Revise § 431.196 to read as follows:

§431.196 Energy conservation standards and their effective dates.

(a) Low-Voltage Dry-Type Distribution Transformers. 

(1) The efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2007, but before January 1, 2016, shall be no less 

than that required for their kVA rating in the table below. Low-voltage dry-type 

distribution transformers with kVA ratings not appearing in the table shall have their 

minimum efficiency level determined by linear interpolation of the kVA and efficiency 

values immediately above and below that kVA rating.
370

Single-Phase Three-Phase

kVA % kVA %

15 97.7 15 97.0

25 98.0 30 97.5

37.5 98.2 45 97.7

50 98.3 75 98.0

75 98.5 112.5 98.2

100 98.6 150 98.3

167 98.7 225 98.5

250 98.8 300 98.6

333 98.9 500 98.7

750 98.8

1000 98.9

Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(2) The efficiency of a low-voltage dry-type distribution transformer 

manufactured on or after January 1, 2016, shall be no less than that required for their 

kVA rating in the table below. Low-voltage dry-type distribution transformers with kVA 

ratings not appearing in the table shall have their minimum efficiency level determined 

by linear interpolation of the kVA and efficiency values immediately above and below 

that kVA rating.

Single-Phase Three-Phase

kVA % kVA %

15 97.73 15 97.44

25 98.00 30 97.95

37.5 98.20 45 98.20

50 98.31 75 98.47

75 98.50 112.5 98.66

100 98.60 150 98.78

167 98.75 225 98.92

250 98.87 300 99.02

333 98.94 500 99.17

750 99.27

1000 99.34

Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.
371

(b) Liquid-Immersed Distribution Transformers.

(1) The efficiency of a liquid-immersed distribution transformer manufactured on 

or after January 1, 2010, but before January 1, 2016, shall be no less than that required 

for their kVA rating in the table below. Liquid-immersed distribution transformers with 

kVA ratings not appearing in the table shall have their minimum efficiency level 

determined by linear interpolation of the kVA and efficiency values immediately above 

and below that kVA rating.

Single-Phase Three-Phase

kVA % kVA %

10 98.70 15 98.65

15 98.82 30 98.83

25 98.95 45 98.92

37.5 99.05 75 99.03

50 99.11 112.5 99.11

75 99.19 150 99.16

100 99.25 225 99.23

167 99.33 300 99.27

250 99.39 500 99.35

333 99.43 750 99.40

500 99.49 1000 99.43

1500 99.48

Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(2) The efficiency of a liquid-immersed distribution transformer manufactured on 

or after January 1, 2016, shall be no less than that required for their kVA rating in the 

table below. Liquid-immersed distribution transformers with kVA ratings not appearing 

in the table shall have their minimum efficiency level determined by linear interpolation 

of the kVA and efficiency values immediately above and below that kVA rating.

Single-Phase Three-Phase

kVA Efficiency (%) kVA Efficiency (%)

10 98.62 15 98.36

15 98.76 30 98.62

25 98.91 45 98.76
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37.5 99.01 75 98.91

50 99.08 112.5 99.01

75 99.17 150 99.08

100 99.23 225 99.17

167 99.25 300 99.23

250 99.32 500 99.25

333 99.36 750 99.32

500 99.42 1000 99.36

667 99.46 1500 99.42

833 99.49 2000 99.46

2500 99.49

Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(c) Medium-Voltage Dry-Type Distribution Transformers.

(1) The efficiency of a medium- voltage dry-type distribution transformer 

manufactured on or after January 1, 2010, but before January 1, 2016, shall be no less 

than that required for their kVA and BIL rating in the table below. Medium-voltage drytype distribution transformers with kVA ratings not appearing in the table shall have their 

minimum efficiency level determined by linear interpolation of the kVA and efficiency 

values immediately above and below that kVA rating.

Single-Phase Three-Phase

BIL* 20–45 kV 46–95 kV ≥96 kV BIL* 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

(%)

Efficiency 

(%)

Efficiency 

(%) kVA Efficiency (%)

Efficiency 

(%)

Efficiency 

(%)

15 98.10 97.86 - 15 97.50 97.18 -

25 98.33 98.12 - 30 97.90 97.63 -

37.5 98.49 98.30 - 45 98.10 97.86 -

50 98.60 98.42 - 75 98.33 98.13 -

75 98.73 98.57 98.53 112.5 98.52 98.36 -

100 98.82 98.67 98.63 150 98.65 98.51 -

167 98.96 98.83 98.80 225 98.82 98.69 98.57

250 99.07 98.95 98.91 300 98.93 98.81 98.69

333 99.14 99.03 98.99 500 99.09 98.99 98.89

500 99.22 99.12 99.09 750 99.21 99.12 99.02

667 99.27 99.18 99.15 1000 99.28 99.20 99.11

833 99.31 99.23 99.20 1500 99.37 99.30 99.21
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2000 99.43 99.36 99.28

2500 99.47 99.41 99.33

*BIL means basic impulse insulation level

Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(2) The efficiency of a medium- voltage dry-type distribution transformer 

manufactured on or after January 1, 2016, shall be no less than that required for their 

kVA and BIL rating in the table below. Medium-voltage dry-type distribution 

transformers with kVA ratings not appearing in the table shall have their minimum 

efficiency level determined by linear interpolation of the kVA and efficiency values 

immediately above and below that kVA rating.

Single-Phase Three-Phase

BIL* 20–45 kV 46–95 kV ≥96 kV BIL* 20–45 kV 46–95 kV ≥96 kV

kVA Efficiency 

(%)

Efficiency 

(%)

Efficiency 

(%) kVA Efficiency (%)

Efficiency 

(%)

Efficiency 

(%)

15 98.10 97.86 - 15 97.50 97.18 -

25 98.33 98.12 - 30 97.90 97.63 -

37.5 98.49 98.30 - 45 98.10 97.86 -

50 98.60 98.42 - 75 98.33 98.12 -

75 98.73 98.57 98.53 112.5 98.49 98.30 -

100 98.82 98.67 98.63 150 98.60 98.42 -

167 98.96 98.83 98.80 225 98.73 98.57 98.53

250 99.07 98.95 98.91 300 98.82 98.67 98.63

333 99.14 99.03 98.99 500 98.96 98.83 98.80

500 99.22 99.12 99.09 750 99.07 98.95 98.91

667 99.27 99.18 99.15 1000 99.14 99.03 98.99

833 99.31 99.23 99.20 1500 99.22 99.12 99.09

2000 99.27 99.18 99.15

2500 99.31 99.23 99.20

* BIL means basic impulse insulation level

Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE 

Test- Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(d) Underground Mining Distribution Transformers. [RESERVED]