7282 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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. 

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 April 10, 2012. 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: 

1. Federal eRulemaking Portal: 

www.regulations.gov. Follow the 

instructions for submitting comments. 

2. Email: DistributionTransformers2010-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 email 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). 

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=EERE2010-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. Email: 

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. Email: 

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 

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 LiquidImmersed Distribution Transformers 

c. BIL Ratings in Liquid-Immersed 

Distribution Transformers 

3. Technology Options 

a. Core Deactivation 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7283 

1For editorial reasons, upon codification in the 

U.S. Code, Parts B and C were redesignated as Parts 

A and A–1, respectively. 

2A 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. 

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. 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 

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 

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, DryType 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), Public Law 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.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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7284 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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). 

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 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 Proposed TSL 

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 

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

Medium-voltage, dry-type ..................................................................................... 9 3 2 1 

10 3 .................... 2 

11 3 .................... 1 

12 3 .................... 2 

13A 3 .................... 1 

13B 3 .................... 2 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7285 

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 

Equipment class 3 Equipment class 4 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7286 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

4For 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. 

5A 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 inplace 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. 

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. 

A. Benefits and Costs to Consumers 4

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 life-cycle 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 

11 ...................... 1,043 10.7 

12 ...................... 6,934 9.0 

13A ................... 25 16.5 

TABLE I.8—IMPACTS OF PROPOSED

STANDARDS ON CUSTOMERS OF DISTRIBUTION TRANSFORMERS—Continued 

Design Line 

Average 

LCC savings (2010$) 

Median payback period 

(years) 

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 liquidimmersed 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 drytype 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 lowvoltage 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, 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) 5 of 

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 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. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7287 

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. 

TABLE I.9—SUMMARY OF NATIONAL ECONOMIC BENEFITS AND COSTS OF PROPOSED DISTRIBUTION TRANSFORMER

ENERGY CONSERVATION STANDARDS

Category Present value 

billion 2010$ 

Discount rate 

(percent) 

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 

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, 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 

Monetized (million 2010$/year) 

Primary estimate * 

Low net 

benefits estimate * 

High net benefits estimate * 

Benefits: 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7288 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

9For editorial reasons, upon codification in the 

U.S. Code, Parts B and C were redesignated as Parts 

A and A–1, respectively 

10EPACT 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). 

TABLE I.10—ANNUALIZED BENEFITS AND COSTS OF PROPOSED STANDARDS FOR DISTRIBUTION TRANSFORMERS— 

Continued 

Discount rate 

Monetized (million 2010$/year) 

Primary estimate * 

Low net 

benefits estimate * 

High net benefits estimate * 

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. 

CO2 Reduction at $22.3/t** ............................................... 3% ........................................... 244 ................ 244 ................ 244. 

CO2 Reduction at $36.5/t** ............................................... 2.5% ........................................ 389 ................ 389 ................ 389. 

CO2 Reduction 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 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. 

A. Authority 

Title III, Part B of the Energy Policy 

and Conservation Act of 1975 (EPCA or 

the Act), Public Law 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), Public Law 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), Public Law 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7289 

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 

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 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 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 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 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 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7290 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

11EPACT 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). 

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 transformers (LVDTs).11

(EPACT 2005, Section 135(c); 42 U.S.C. 

6295(y)) The standard levels for lowvoltage 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 loadlosses, 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 liquidimmersed distribution transformers and 

medium-voltage dry-type distribution 

transformers, which are shown in Table 

II.2 and Table II.3, 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. 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7291 

12Copies of all the draft analyses published 

before the ANOPR are available on DOE’s Web site: 

http://www.eere.energy.gov/buildings/appliance_

standards/commercial/distribution_transformers_

draft_analysis.html. 

13Copies of the four draft NOPR analyses 

published in August 2005 are available on DOE’s 

Web site: http://www.eere.energy.gov/buildings/

appliance_standards/commercial/distribution_

transformers_draft_analysis_nopr.html. 

14The spreadsheets developed for this 

rulemaking proceeding are available at: http://www.

eere.energy.gov/buildings/appliance_standards/

commercial/distribution_transformers_draft_

analysis_nopr.html. 

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 

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 Web 

site 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 abovereferenced DOE Web site. 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 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 analyses it had 

performed for the proposed rule, 

including several spreadsheets that 

remain available on DOE’s Web site.14

Some commenters asserted that DOE’s 

proposed standards might adversely 

affect replacement of distribution 

transformers in certain spaceconstrained (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 three-phase 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 

medium-voltage dry-type distribution 

transformers. 72 FR 58190 (October 12, 


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7292 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

2007) (the 2007 Final Rule) (codified at 

10 CFR 431.196(b)–(c)). 

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. 

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 Web site. 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 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 mediumvoltage 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 EnergyEfficient 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 

• Pacific Gas and Electric Company 

• Progress Energy 

• Prolec GE 

• U.S. Department of Energy 

The ERAC subcommittee for mediumvoltage 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. 

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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7293 

15The 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). 

16The Northwest Power and Conservation 

Council (NPCC) and Northwest Energy Efficiency 

Alliance (NEEA) submitted joint comments and are 

hereinafter referred to as NPCC/NEEA. 

17This 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. 

than EL 1 for DLs 2 and 5. Therefore, the 

subcommittee did not arrive at 

consensus regarding proposed standard 

levels for medium-voltage liquidimmersed 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 Web 

site 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 lowvoltage distribution transformers. The 

ERAC subcommittee also held webinars 

on November 21, 2011, and 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 lowvoltage 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 EnergyEfficient 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 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 corematerial prices. 

At the conclusion of the final meeting, 

subcommittee members presented their 

energy efficiency level 

recommendations. For low-voltage drytype 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 drytype distribution transformers. 

Transcripts of the subcommittee 

meetings and all data and materials 

presented at the subcommittee meetings 

are available at the DOE Web site 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 Rule 15

indicates that DOE will issue a final test 

procedure, if one is needed, prior to 

issuing a proposed rule for energy 

conservation 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 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 


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7294 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

18Passive cooling is cooling that does not require 

fans, pumps, or other energy-consuming means of 

increasing thermal convection. 

19This 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. 

mode of operation for 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 forcedcooled 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) 

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 mediumvoltage 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 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 reconnectable 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) 

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 lowvoltage 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 multiplevoltage 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 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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7295 

20 IEEE C57.12.00. 

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 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 ‘‘low-voltage [transformers] be 

shipped with the connections done for 

the highest voltage’’ and requested that 

‘‘all compliance testing be done in the 

configuration requirement of ST–20.’’ 

(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) low-voltage 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 singlephase, pole-type transformers are used 

in the series connection, and the work 

to 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/ 

multiple-voltage 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 configuration that exhibits the 

highest losses, which is usually with the 

secondary windings in parallel. 

Whereas the IEEE Standard 20 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 low-voltage, dry-type 

distribution transformers comply at 35 

percent loading. 

Warner Power (WP) commented that 

a single 35 percent test load for lowvoltage 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 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 

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) 


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21The NIA spreadsheet model is described in 

section IV.G of this notice. 

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. 

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 liquidimmersed and medium-voltage, drytype 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. 

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) 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. 

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 shortterm 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. 


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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. 

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, 

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 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 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 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 


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22BT stands for DOE’s Building Technologies 

Program. 

23The 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. 

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 Web site: http:// 

www1.eere.energy.gov/buildings/ 

appliance_standards/commercial/ 

distribution_transformers.html. 

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 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 medium-voltage 

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; 

(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 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 


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suggested by NEMA and FPT, is 

warranted and able to be implemented 

with sufficient specificity. 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 

single-phase 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 (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 lifecycle 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 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 drytype) 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 U.S.C. 

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. 

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 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 


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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 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) 

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 

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) 

CDA observed that the current 

efficiency levels for LVDT distribution 

transformers are at NEMA TP–1 levels 

and that the 2010 MVDT and liquidimmersed 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 liquidimmersed] 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 liquidimmersed and MVDT distribution 

transformers and amend the efficiency 

standards for LVDT distribution 

transformers if justified. (ASAP/ACEEE/ 


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24See chapter 5 of the TSD for further discussion 

of equipment classes. 

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) 

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. 

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; 

(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. 

2. Equipment Classes 

DOE divides covered equipment into 

classes by: (a) the type of energy used; 

(b) the capacity; or (c) any performancerelated 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 (lowvoltage, 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 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 ..................... Liquid-Immersed .................... Medium .................................. Single ............................. ........................... 10–833 kVA 

2 ..................... Liquid-Immersed .................... Medium .................................. Three ............................. ........................... 15–2500 kVA 

3 ..................... Dry-Type ................................ Low ........................................ Single ............................. ........................... 15–333 kVA 

4 ..................... Dry-Type ................................ Low ........................................ Three ............................. ........................... 15–1000 kVA 


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TABLE IV.1—DISTRIBUTION TRANSFORMER EQUIPMENT CLASSES—Continued 

EC # Insulation Voltage Phase BIL Rating kVA Range 

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 mediumvoltage 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 ‘‘mediumvoltage 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 than that of traditional 

mineral oil. 71 FR 44369 (August 4, 

2006). Known as ‘‘less-flammable, 

liquid-immersed’’ (LFLI) transformers, 

these units are marketed to some 

applications where a fire would be 

especially costly and traditionally 

served by the dry-type 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 liquidimmersed 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 liquidimmersed 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). 

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 dry-type equipment, and 

came to the same conclusion as in the 

last rulemaking. While LFLI 

transformers can be used in some 

applications that historically use drytype 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 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 LiquidImmersed Distribution Transformers 

During negotiations, several parties 

raised the question of whether polemounted, 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 liquidimmersed 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, drytype 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. 

3. Technology Options 

The technology assessment provides 

information about existing technology 

options to construct more energyefficient 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) Highergrade electrical core steels, (2) different 


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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. 

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) .................... Lower ..................................... Higher .................................... Higher. 

Decreasing volts per turn ................................................. Lower ..................................... 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 ....................................................... Higher .................................... Lower ..................................... Lower. 

Increasing volts per turn ................................................... Higher .................................... 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. 

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 

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 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) 


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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 liquidimmersed 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 

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 than 

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) 

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 mediumvoltage 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) 

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. 

One manufacturer of symmetric core 

transformers cited several advantages to 

the symmetric core design. These 

include reduced weight, volume, noload 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 delta-wye 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 


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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. 

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 

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 

[Percentage changes] 

Core losses 

(W) 

Core weight 

(lbs) Labor hours 

Minimum ...................................................................................................................................... ¥0.0 ¥12.0 +10.0 

Mean ............................................................................................................................................ ¥15.5 ¥17.5 +55.0 

Maximum ..................................................................................................................................... ¥25.0 ¥25.0 +100.0 

DOE applied the adjustments to each 

of the traditional three-phase 

transformer designs to develop a costefficiency 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 

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 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 CSL3,25 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7306 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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) 

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 liquidimmersed 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 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. 

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 

manufacturers make symmetric cores, so 

patents should not be a limiting factor. 

(WP, No. 30 at pp. 3–4) 

EEI noted that, if certain higherefficiency 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. 

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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7307 

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 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) 

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) 

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. 

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 


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7308 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 equipment classes, DOE further 

classified distribution transformers by 

their kilovolt-ampere (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 drytype), 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 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. 

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, single-phase, rectangular tank .......... 10–167 50 kVA, 65 °C, single-phase, 60Hz, 14400V primary, 

240/120V secondary, rectangular tank. 

2 ....... Liquid-immersed, single-phase, round tank .................. 10–167 25 kVA, 65 °C, single-phase, 60Hz, 14400V primary, 

120/240V secondary, round tank. 

3 ....... Liquid-immersed, single-phase ...................................... 250–833 500 kVA, 65 °C, single-phase, 60Hz, 14400V primary, 

277V secondary. 

2 ........ 4 ....... Liquid-immersed, three-phase ....................................... 15–500 150 kVA, 65 °C, three-phase, 60Hz, 12470Y/7200V primary, 208Y/120V secondary. 

5 ....... Liquid-immersed, three-phase ....................................... 750–2500 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. 


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TABLE IV.5—ENGINEERING DESIGN LINES AND REPRESENTATIVE UNITS FOR ANALYSIS—Continued 

EC * DL Type of distribution transformer kVA 

Range 

Representative unit for this 

engineering design line 

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 ...... 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 dry-type 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 liquidimmersed 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 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 liquidimmersed 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 one-third the losses of threephase MVDT units and commented that 

DOE should directly analyze singlephase 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, 

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 liquidimmersed 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 medium-voltage drytype 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, 

single-phase, 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 

liquid-immersed design lines, such as 

19920 V (150 kV BIL), as well as for 

dual primary voltage ratings, such as 

7200 × 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 lowvoltage ratings, such as 208Y/120, 

should be examined because these 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7310 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 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 liquidimmersed 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 lowvoltage 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 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 

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, 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. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7311 

26A 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. 

TABLE IV.6—ENGINEERING DESIGN LINES (DLS) AND REPRESENTATIVE UNITS FOR ANALYSIS—Continued 

EC * DL Type of distribution transformer kVA Range Representative unit for this 

engineering design line 

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. 

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 factor 26

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 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 low-voltage dry-type 

design lines, where high sales volume 

could better justify the additional 

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 

dry-type 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. 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7312 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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. 

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 fullymitered designs. However, during the 

negotiations process, interested parties 

clarified that step-lap 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. 

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 

medium-voltage, 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. 

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 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. 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 fiveyear 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. 


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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, 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 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 

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 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. 

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 nonproduction 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. Non-production cost includes the 

cost of selling, general and 

administrative items (market research, 

advertising, sales representatives, and 


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7314 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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) 

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) 

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 a vertical manufacturing process 

in which the manufacturer produces all 

components in-house. (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 buttlapped 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 lowvoltage market. 

In response, DOE opted to increase 

mitering costs for both low- and 

medium-voltage dry-type designs. In the 

medium-voltage case, DOE incorporated 

a processing cost of 10 cents per core 

pound for step-lap mitering. In the lowvoltage 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 step-lap 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, drytype 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 liquidimmersed 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 drytype 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) 

During negotiations, Federal Pacific 

commented that it believed DOE was 

underestimating labor hours for core 

assembly for all low- and mediumvoltage dry-type design lines. 

In response to interested party 

feedback, DOE applied an incremental 

increase in core assembly time to 

amorphous designs in the liquidimmersed 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 liquidimmersed designs using amorphous 

cores. This is because DOE already 

accounts for bracing costs for all of its 

liquid-immersed 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 mediumand low-voltage 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 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 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 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 


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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 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 nonproduction 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, 

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 per-phase 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 levels for LVDT 

distribution transformers. Last, DOE 

considered additional ELs to 

characterize the maximumtechnologically 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 efficiency 

standards, and so any discussion of 

future standards necessarily begins with 

what is in effect at the time. 

Berman Economics noted that highcost 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 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 


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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 lowerend 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 

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 

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. 

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 

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 liquidimmersed 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 distribution transformers. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7318 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 drytype 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) 

Manufacturers often accuse DOE or 

over-representing manufacturer selling 

prices, while parties interested in 

increasing energy efficiency accuse it of 

under-representing 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. 

10. Primary Voltage Sensitivities 

DOE understands that primary voltage 

and the accompanying BIL may 

increasingly affect efficiency of liquidimmersed 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 threephase. 

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) 

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. 

Several interested parties expressed 

concerns about the size and weight of 

the designs used in DOE’s analysis. 

Power Partners commented that singlephase liquid-immersed 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 singlephase) 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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7319 

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, PG&E commented that the 

large transformers in its service area are 

typically pad-mounted 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 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 mediumvoltage, 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 medium-voltage, 

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. 

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 

liquid-immersed 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 liquidimmersed transformers. 

EEI stated that a distribution channel 

from manufacturers to distributors to 

multi-site 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. 

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 moreefficient products (incremental 

markups). Incremental markups are 

coefficients that relate the change in the 

installation cost due to the increase 

equipment weight of some higherefficiency models. 

FPT agreed with the distributor 

markups that DOE developed for liquidimmersed 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 liquid-immersed 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 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 endVerDate Mar<15>2010 21:38 Feb 09, 2012 Jkt 226001 PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 E:\FR\FM\10FEP2.SGM 10FEP2

srobinson on DSK4SPTVN1PROD with PROPOSALS2
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28See http://www1.eere.energy.gov/buildings/ 

appliance_standards/commercial/ac_hp.html. 

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 transformer 

(liquid-immersed or dry-type) and 

ownership (electric utilities own 

approximately 95 percent of liquidimmersed 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. 

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 liquid-filled 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 priceload 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 

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 liquidimmersed 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. 

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 

transformer designs will deliver a 

specified efficiency, and for calculating 

transformer losses. In the preliminary 


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analysis, DOE assumed non-residential 

load factors of 35 percent, 40 percent, 

and 25 percent for medium-voltage 

single-phase, medium-voltage threephase, 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 liquid-filled 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 

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. 

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) 

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. 

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 basecase efficiency levels. The base-case 

estimate reflects the market in the 

absence of amended energy 

conservation standards, including the 


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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 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 liquid-immersed transformers that are sold directly to utilities. 

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 medium-voltage.

Adjusted the percent of evaluators to: 10% for 

liquid-immersed transformers, and 2% for 

low-voltage dry-type and 2% for mediumvoltage 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 liquid-immersed 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 liquid-immersed 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). 

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 pole-mounted, liquid-immersed transformers to 5.1% for dry-type 

transformer owners.

The mean real discount rates were adjusted 

to 3.7% for owners of liquid-immersed 

transformers and 4.6% for dry-type transformers. 

Lifetime ........................................................ Distribution of lifetimes, with mean lifetime for 

both liquid and dry-type transformers assumed to be 32 years.

No change. 


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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 purchasedecision 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 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 liquidimmersed transformers are purchased 

using TOC evaluation. DOE assumed 

that 25 percent of low-voltage dry-type 

transformers are purchased using TOC 

evaluation. For medium-voltage drytype 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 drytype, about 10 percent for mediumvoltage 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 medium-voltage 

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 liquidimmersed, 2 percent for low-voltage, 

and 2 percent for medium-voltage drytype 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 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 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 inflationadjusted 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, or whether 

the recent trend represents the 

beginning of a long-term rising trend 


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7324 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

29As 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. 

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 liquidimmersed 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 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 

liquid-immersed 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 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 higherefficiency 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 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 ‘‘over-sizing’’ of the pole 

relative to the load by a factor of two to 

four. Because of this ‘‘over-sizing’’ 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 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 


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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 padmounted 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. 

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 vaultinstalled 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 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 dry-type 

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 hourlybased 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. 

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. 

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 drytype 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 standards by 

October 1, 2012. The statutorilyrequired compliance date of January 1, 

2016, provides manufacturers with over 

three years to prepare for manufacturing 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7326 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

30Barnes. Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers. ORNL–6847. 1996. 

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. 

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. 

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 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 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. 


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TABLE IV.2—INPUTS FOR THE SHIPMENTS ANALYSIS—Continued 

Input Preliminary analysis description Changes for proposed rule 

Shipments forecast ............................................. 2016–2045: Based on AEO 2010 .................... Updated to AEO 2011. 

Dry-type/liquid-immersed market shares ............ Based 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, liquid-immersed ............................... For 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. 

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 weightedaverage 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-to-source conversion ........... A 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 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 


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7328 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 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 mediumvoltage 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 drytype transformers. DOE requests data 

that would allow it to estimate such 

switching for the final rule. 

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 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 liquid-immersed 

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 

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. 

4. Discount Rate 

In calculating the NPV, DOE 

multiplies the net savings in future 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7329 

31OMB Circular A–4 (Sept. 17, 2003), section E, 

‘‘Identifying and Measuring Benefits and Costs. 

Available at: www.whitehouse.gov/omb/ 

memoranda/m03-21.html. 

32See 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). 

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 higher-grade 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 

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 fullfuel-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 vaultinstalled 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 padmounted transformer for the national 

sample is approximately 35 percent. For 

rural electric 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 

space-constrained 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 vaultinstalled 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 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 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. 


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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 crosssection of manufacturers. During these 

interviews, DOE discussed engineering, 

manufacturing, procurement, and 

financial topics to validate assumptions 

used in the GRIM and to identify key 

issues or concerns. 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 dry-type, and lowvoltage 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 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 sub-group 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 mediumvoltage 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 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 nonproduction 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 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 


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33 I.e., 2012. 

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 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 

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 mediumvoltage 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 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 

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 mediumvoltage 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 rule 33 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 analysis includes an 

elasticity factor based on the potential 


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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; 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 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 liquidimmersed 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 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 foreignowned 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 grainoriented 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) 

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. 


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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. 

Based on its engineering analysis, 

DOE recognizes that some high 

efficiency steels are substantially more 

cost-effective at higher TSLs than lowergrade 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. 

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 M2, nor does DOE believe 

domestic suppliers could costeffectively 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 highgrade 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. 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7334 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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-how 

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, 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 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 liquid-immersed transformer sales, 75 

percent of medium-voltage dry-type 

transformer sales, 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 lowvoltage 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. 

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 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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7335 

34See Bureau of Economic Analysis, Regional 

Multipliers: A User Handbook for the Regional 

Input-Output Modeling System (RIMS II). 

Washington, DC. U.S. Department of Commerce, 

1992. 

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. 

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 out-of-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 outof-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 

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 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 

labor-intensive than other sectors. 

Energy conservation standards have the 

effect of reducing consumer utility bills. 

Because reduced consumer 

expenditures for energy likely lead to 

increased expenditures in other sectors 

of the economy, the general effect of 

efficiency standards is to shift economic 

activity from a less labor-intensive 

sector (i.e., the utility sector) to more 

labor-intensive sectors (e.g., the retail 

and service sectors). Thus, based 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 special-purpose version of 

the ‘‘U.S. Benchmark National InputOutput’’ (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 


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7336 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 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 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 (DC). 

SO2 emissions from 28 eastern States 

and DC 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 DC. 

Although CAIR was remanded to EPA 

by the U.S. Court of Appeals for the 

District of Columbia Circuit (DC 

Circuit), see North Carolina v. EPA, 550 

F.3d 1176 (DC Cir. 2008), it remained in 

effect temporarily, consistent with the 

DC Circuit’s earlier opinion in North 

Carolina v. EPA, 531 F.3d 896 (DC 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 DC Circuit stayed the new 

rules while a panel of judges reviews 

them, and told EPA to continue 

enforcing CAIR (see EME Homer City 

Generation v. EPA, No. 11–1302, Order 

at *2 (DC 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 NEMS–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. 

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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7337 

35National Research Council. ‘‘Hidden Costs of 

Energy: Unpriced Consequences of Energy 

Production and Use.’’ National Academies Press: 

Washington, DC 2009. 

36 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. 

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, 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 National Research 

Council35 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 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,36 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 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 


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37The models are described in appendix 15–A of 

the NOPR TSD. 

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 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 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.37 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 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 higherthan-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 

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 


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38Table 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. 

39For 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, DC 

40OMB, Circular A–4: Regulatory Analysis (Sept. 

17, 2003). 

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 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$).38

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 

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$).39 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. 40

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. 

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 threephase 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 threephase transformers received a lessstringent 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 singlephase 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 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 


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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 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 liquidimmersed 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. 

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 drytype 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 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, padmounted liquid-immersed 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. 

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 


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(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, 

the result could be less production, lesscompetitive 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 

liquid-immersed 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 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 lowvoltage dry-type distribution 

transformers, and provided 

recommendations to optimize future 

rulemakings certifying the energy 

efficiency of low-voltage 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) 

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 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). 

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 cost-competitive 

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 


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technologically feasible level (max 

tech). 

TABLE V.1—EFFICIENCY VALUES OF THE TRIAL STANDARD LEVELS FOR LIQUID-IMMERSED TRANSFORMERS BY DESIGN

LINE

[In percent] 

Design line Baseline 

TSL 

1 2 3 4 5 6 7 

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 DRY-TYPE TRANSFORMERS BY

DESIGN LINE

[In percent] 

Design line Baseline 

TSL 

1 2 3 4 5 6 

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 

TABLE V.3—EFFICIENCY VALUES OF THE TRIAL STANDARD LEVELS FOR MEDIUM-VOLTAGE DRY-TYPE TRANSFORMERS BY

DESIGN LINE

[In percent] 

Design line Baseline 

TSL 

1 2 3 4 5 

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 higherefficiency 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. 

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 


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TABLE V.4—SUMMARY LIFE-CYCLE COST AND PAYBACK PERIOD RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT— 

Continued 

Trial standard level 

1 2 3 4 5 6 7 

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 

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 ($) .............. 2,413 2,413 3,831 5,591 5,245 6,531 4,135 

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 3,356 3,356 3,362 1,274 

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 


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TABLE V.8—SUMMARY LIFE-CYCLE COST AND PAYBACK PERIOD RESULTS FOR DESIGN LINE 5 REPRESENTATIVE UNIT— 

Continued 

Trial standard level 

1 2 3 4 5 6 7 

Transformers with No Change in 

LCC (%) .................................. 0 .4 0 .4 0 .1 0 .0 0 .0 0 .0 0 .0 

Mean LCC Savings ($) .............. 7,787 7,787 10,288 12,513 11,395 12,746 3,626 

Median PBP (Years) .................. 4 .0 4 .0 4 .2 6 .3 5 .7 8 .3 16 .9 

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 ($) ........................................ 1,714 1,714 1,793 2,270 2,270 270 

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 ($) ........................................ 2,476 2,476 2,625 4,145 ¥2,812 ¥2,812 

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 

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 1,659 1,659 237 

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 


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TABLE V.13—SUMMARY LIFE-CYCLE COST AND PAYBACK PERIOD RESULTS FOR DESIGN LINE 10 REPRESENTATIVE

UNIT—Continued 

Trial standard level 

1 2 3 4 5 

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 ($) .................................................................. 4,509 4,791 4,791 4,791 ¥12,756 

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 ($) .................................................................. 1,043 1,043 2,000 2,000 ¥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 ($) .................................................................. 4,518 6,934 8,860 8,860 ¥12,420 

Median PBP (Years) ...................................................................... 6 .3 9 .0 13 .0 13 .0 25 .9 

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 ¥11,077 

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 ($) .................................................................. 2,733 4,709 384 384 ¥5,407 

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 


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7346 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

presents the detailed results of that 

analysis. 

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 ............................................................... 1,062 1,062 3,203 4,689 3,854 4,270 ¥5,996 

All Customers 

4 ............................................................... 862 862 862 3,356 3,356 3,362 1,274 

5 ............................................................... 7,787 7,787 10,288 12,513 11,395 12,746 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 rebuttablepresumption 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 

rebuttable-presumption payback value, 

and not a distribution of PBPs, for each 

TSL. 

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 DRY-TYPE 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 ..................................................................................... 1,500 1.9 5 .7 5.7 5.7 21.8 

11 ..................................................................................... 300 9.5 9 .5 13.0 13.0 18.8 

12 ..................................................................................... 1,500 5.5 7 .44 12.0 12.0 20.3 

13A ................................................................................... 300 11.9 11 .9 22.2 22.2 28.9 

13B ................................................................................... 2,000 5.2 11 .1 19.1 19.1 19.4 


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DOE believes that the rebuttablepresumption 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 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 drytype, 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 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 Conversion Costs ............ 2011$ M ................ 26.3 64.9 67.6 98.5 100.4 105.6 128.2 

Product Conversion Costs ........... 2011$ M ................ 27.6 46.8 57.5 93.7 93.7 93.7 93.7 

Total Conversion 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 Conversion Costs ............ 2011$ M ................ 26.3 64.9 67.6 98.5 100.4 105.6 128.2 

Product Conversion Costs ........... 2011$ M ................ 27.6 46.8 57.5 93.7 93.7 93.7 93.7 

Total Conversion 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 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 


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7348 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 mark up 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 upperbound 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). 

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 highprofitability 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. 

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. 

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. 

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. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7349 

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 

* 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. 

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 highvolume 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. 

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, 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7350 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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-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 

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 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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7351 

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 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 HiB steel, a major concern of some 

manufacturers because it is used and 

generally priced for power transformer 

markets, relatively large expenditures 

would be required in R&D and 

engineering as most manufacturers 

would have to move production to steel, 

with which they have little experience. 

DOE estimates 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 

altogether or source their cores rather 

than make the investments in plant and 

equipment and R&D required to meet 

these levels. 

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 laborintensive and would require greater 

labor expenditures than traditional 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. 

Low-Voltage Dry-Type. Based on 

interviews with manufacturers, DOE 

estimates that there are approximately 

2,200 employees associated with DOEcovered 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 cleansheet 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 DOEcovered 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 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7352 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 affected 

disproportionately. As discussed in 

section V.B.2.a, using average cost 

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 mediumvoltage, 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. 

Many interested parties have 

expressed concerns about the recent 

implementation of previous standards 

for distribution transformers. For lowvoltage 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 low-voltage dry-type 

distribution transformers and January 1, 

2010 for medium-voltage dry-type 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 drytype 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 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7353 

41OMB Circular A–4, section E (Sept. 17, 2003). 

Available at: http://www.whitehouse.gov/omb/ 

circulars_a004_a-4. (Last accessed March 18, 2011.) 

TABLE V.28—CUMULATIVE NATIONAL ENERGY SAVINGS FOR DISTRIBUTION TRANSFORMER TRIAL STANDARD LEVELS IN

2016–2045—Continued 

Trial Standard Level 

1 2 3 4 5 6 7 

Medium-Voltage Dry-Type 

Cumulative Source Savings 2045 (Quads) ............................................. 0.06 0.13 0.23 0.23 0.37 

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,41 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 long-term 

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. 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7354 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

the resulting net savings 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 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 

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. 

As discussed in section 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 — 

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 — — 


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TABLE V.31—SUMMARY OF EMISSIONS REDUCTION ESTIMATED FOR DISTRIBUTION TRANSFORMER TRIAL STANDARD

LEVELS (CUMULATIVE IN 2016–2045)—Continued 

Trial standard level 

1 2 3 4 5 6 7 

Hg (tons) .............................................................................. 0 .031 0 .059 0 .113 0 .113 0 .173 — — 

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. 

TABLE V.32—ESTIMATES OF GLOBAL PRESENT VALUE OF CO2 EMISSIONS REDUCTION UNDER DISTRIBUTION

TRANSFORMER TRIAL STANDARD LEVELS

[Million 2010$] 

TSL 5% discount rate, 

average * 

3% discount rate, 

average * 

2.5% discount rate, 

average * 

3% discount rate, 

95th percentile * 

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 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 


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7356 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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

Million 2010$ 

TSL 3% discount 

rate 

7% discount 

rate 

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 

TABLE V.33—ESTIMATES OF PRESENT

VALUE OF NOX EMISSIONS REDUCTION UNDER DISTRIBUTION TRANSFORMER TRIAL STANDARD LEVELS— 

Continued 

Million 2010$ 

TSL 3% discount 

rate 

7% discount 

rate 

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 

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 seven-percent 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

[Billion 2010$] 

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** 

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 

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** 

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. 


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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

[Billion 2010$] 

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** 

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** 

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 

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

[Billion 2010$] 

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** 

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** 

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 climaterelated impacts 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)) 


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7358 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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 (‘‘grainoriented’’) but result in distribution 

transformers that are unlikely to be costcompetitive with the often moreefficient amorphous units. As stated 

above, switching to amorphous steel is 

not practicable as there are availability 

concerns with amorphous steel. 

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 level was 

economically justified. Where the maxtech 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 LiquidImmersed 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 

Savings 

(quads).

0.36 ................. 0.74 ................. 0.82 ................. 1.44 ................. 1.42 ................. 1.70 ................. 2.70 

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 6,160 .... 382 to 6,746 .... 655 to 11,643 .. 646 to 11,486 .. 752 to 13,414 .. 1140 to 20,523 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7359 

TABLE V.37—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS: NATIONAL

IMPACTS—Continued 

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7 

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 

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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7360 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

TABLE V.38—SUMMARY OF ANALYTICAL RESULTS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS: MANUFACTURER

AND CONSUMER IMPACTS—Continued 

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7 

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. 

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 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 multibillion 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. 

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 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 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7361 

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. 

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 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 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. 

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. liquidimmersed 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. 

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. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7362 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

42 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. 

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 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.42

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. 

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 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. 

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 negotiated rulemaking, 

NEMA and AK Steel recommended TSL 

1. For the above considerations, DOE 

today proposes to adopt the energy 

conservation standards for liquidVerDate Mar<15>2010 21:38 Feb 09, 2012 Jkt 226001 PO 00000 Frm 00082 Fmt 4701 Sfmt 4702 E:\FR\FM\10FEP2.SGM 10FEP2

srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7363 

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 Percent kVA Percent 

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 LowVoltage, Dry-Type 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 

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 


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TABLE V.41—SUMMARY OF ANALYTICAL RESULTS FOR LOW-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS: 

MANUFACTURER AND CONSUMER IMPACTS—Continued 

Category TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 

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 

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 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. 

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. 

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 


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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. 

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. 

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. 

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, 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 design line 7. The 


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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 buttlap 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 lowvoltage, dry-type distribution 

transformers. 

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 class 4 

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$ million) ..................................... 1 to 15 .......... 3 to 28 .......... 5 to 53 .......... 5 to 53 .......... 8 to 82 

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. 


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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 

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. 

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 

be 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 drytype 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 


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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. 

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 drytype 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 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 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 drytype 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. 

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 mediumvoltage 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 

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 mediumvoltage, dry-type distribution 

transformers. 


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43 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. 

TABLE V.45—PROPOSED ENERGY CONSERVATION STANDARDS FOR MEDIUM-VOLTAGE, DRY-TYPE 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 reductions, 

including CO2 emission reductions.43

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 climaterelated 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 

$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 

Monetized (million 2010$/year) 

Primary 

estimate* 

Low net 

benefits 

estimate* 

High net 

benefits 

estimate* 

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 


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TABLE V.46—ANNUALIZED BENEFITS AND COSTS OF PROPOSED STANDARDS FOR DISTRIBUTION TRANSFORMERS SOLD IN

2016–2045—Continued 

Discount rate 

Monetized (million 2010$/year) 

Primary 

estimate* 

Low net 

benefits 

estimate* 

High net 

benefits 

estimate* 

CO2 Reduction at $22.3/t** ....................... 3% ..................................................................... 244 ............... 244 ............... 244 

CO2 Reduction at $36.5/t** ....................... 2.5% .................................................................. 389 ............... 389 ............... 389 

CO2 Reduction 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 NOX 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. 

(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 Manufacturers 

Association indicated that these 

guidelines or similar criteria are applied 

to approximately 75 percent of liquidimmersed transformer purchases, 50 

percent of small capacity mediumvoltage 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 


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Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7371 

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. 

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. 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 Web site (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. 

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-smallbusiness-size-standards. 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 previous rulemakings, 

UL qualification directories, individual 

company Web sites, 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, 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. 


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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 

low-voltage 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 lowvoltage dry-type market produce 

specialized 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 high-volume 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 

DOE-exempted markets. DOE did not 

attempt to contact companies operating 

entirely in this very fragmented market. 

Of those that do compete in the DOEcovered market, a few small businesses 

reported a focus on the high-end of the 

market, often selling NEMA Premium or 

better transformers as retrofit 

opportunities. Others focus on 

particular applications or other niches, 

like data centers, and become wellversed 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 

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. 

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 re-optimizing their 

production processes around new 

baseline products. DOE estimates TSL 1 


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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. 

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 lowvoltage 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. 

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 third-party 

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 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 

expand mitering capacity to meet TSL 2. 

Table VI.3 illustrates the relative 

impacts on small and large 

manufacturers. 


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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 lowvoltage dry-type, medium-voltage drytype, 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. 

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 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 justified for liquid 

immersed and low-voltage dry-type 

transformers and TSL2 is the highest 

level that can be justified for mediumvoltage, 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, drytype transformers, as would TSL 2 or 

higher for liquid immersed and lowvoltage 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 dry-type 

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. 

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 


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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-ofinformation requirement for the 

certification and recordkeeping is 

subject to review and approval by OMB 

under the Paperwork Reduction Act 

(PRA). This requirement has been 

approved by OMB under OMB control 

number 1910–1400. Public reporting 

burden for the certification is estimated 

to average 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. 

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 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. Public Law 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 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 


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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 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. 

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, 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 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 


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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 

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 

Web site at: http:// 

www1.eere.energy.gov/buildings/ 

appliance_standards/commercial/ 

distribution_transformers.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. 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. 

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 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 

Web site 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 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, 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
7378 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

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. 

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 well-marked 

copies: one copy of the document 

marked confidential including all the 

information believed to be confidential, 

and one copy of the document marked 

non-confidential 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. 

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. 

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, padmounted, or other types of liquidimmersed transformers. 

13. DOE requests comment on setting 

standards by BIL rating for liquidimmersed distribution transformers as it 

currently does for medium-voltage, drytype units. 

14. DOE requests comment on how 

best to scale across phase counts for 

each transformer type and how 

standards for either single- or threephase 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 highgrade 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 liquid-immersed 

transformers that estimates that 

approximately 80 percent of 

transformers are sold by manufacturers 

directly to utilities. 

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 


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refurbished, specifically re-wound, 

distribution transformer over the 

purchase of new distribution 

transformer. 

26. DOE seeks comment on the 

equipment lifetimes of refurbished, 

specifically re-wound 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 liquid-immersed 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. 

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. 

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 January 31, 

2012. 

Henry Kelly, 

Acting Assistant Secretary of Energy, Energy 

Efficiency and Renewable Energy. 

For the reasons set forth in the 

preamble, DOE proposes to amend 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. 

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 


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7380 Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 

Single-phase Three-phase 

kVA % kVA % 

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. 

(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 liquidimmersed 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 

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. Mediumvoltage 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. 


srobinson on DSK4SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 77, No. 28 / Friday, February 10, 2012 / Proposed Rules 7381 

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 

..................................... ...................... ...................... ...................... 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 mediumvoltage 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. Mediumvoltage 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] 

[FR Doc. 2012–2642 Filed 2–9–12; 8:45 am] 

BILLING CODE 6450–01–P 


srobinson on DSK4SPTVN1PROD with PROPOSALS2