Antonio Bouza To: Antonio Bouza/EE/DOE@DOE

cc:

08/04/2006 07:10 AM Subject: Distribution Transformers Energy Conservation Standards (NOPR)

0 Federal Record Not a Federal Record

User Filed as: Not Categorized in ERMS

To all Distribution Transformer stakeholders:

The Department of Energy is writing to inform you that the Notice of Proposed Rulemaking (NOPR) for the distribution transformer

energy conservation standards rulemaking was published today in the Federal Register. Please find the file attached below.

The Department will be updating its website and posting the NOPR, the Technical Support Document (TSD) and associated analytical

spreadsheets on its website early next week:

h ttp: //www. eere.energy. gov/buildings/appliance_standards/commercial/d istri b utio ntra nsformers. htm l

In this NOPR, the Department proposes a national efficiency standard for liquid-immersed distribution transformers and medium-voltage

dry-type distribution transformers. As you will recall, the mandatory standard for low-voltage distribution transformers was set by

Congress in the Energy Policy Act of 2005.

Stakeholders are invited to comment on the Department's proposal, and to attend a public meeting at the Department of Energy in

Washington DC from 9:00am to 4:00pm on September 27th, 2006. At the public meeting, all statements will be recorded and

transcribed, and will become part of the official record of the standards rulemaking.

The deadline for submitting written comments on the NOPR is October 18, 2006.

You may submit comments, identified by docket number EE-RM/STD-00-550 and/or Regulatory Information Number (RIN) 1904-ABO8,

by any of the following methods:

Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.

E-mail: TransformerNOPRComment@ee.doe.gov. Include docket number EE-RM/STD-00-550 and/or RIN 1904-ABO8 in the subject

line of the message.

• Mail: Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, NOPR for Distribution

Transformers Energy Conservation Standards, docket number EE-RM/STD-00-550 and/or RIN 1904-ABO8, 1000 Independence

Avenue, SW, Washington, DC, 20585-0121. Please submit one signed original paper copy.

• Hand Delivery/Courier: Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Room 1J-018,

1000 Independence Avenue, SW, Washington, DC, 20585. Telephone: (202) 586-2945. Please submit one signed original

paper copy.

All comments (electronic and paper) should clearly identify the Docket number: EE-RM/STD-00-550 and/or RIN 1904-ABO8.

We appreciate your thorough review of the materials and look forward to your participation at the public meeting and your comments

on the proposed rule.

Sincerely,

Antonio Bouza

Building Technologies Program

U.S. Department of Energy

1000 Independence Avenue, SW

Washington DC 20585-0121

phone: 202.586.4563

antonio.bouza@ee.doe.gov

DT NOPR 71 FR 44356.pdf

 EE-RM/STD-00-550 COMMENT 91.1

Antonio Bouza 

08/04/2006 07: 10 AM 

To: Antonio Bouza/EE/DOE@DOE 

cc: 

Subject: Distribution Transformers Energy Conservation Standards (NOPR) 

C Federal Record • Not a Federal Record 

#91.1 

User Filed as: Not Categorized in ERMS 

To all Distribution Transformer stakeholders: 

The Department of Energy is writing to inform you that the Notice of Proposed Rulemaking (NOPR) for the distribution transformer 

energy conservation standards rulemaking was published today in the Federal Register. Please find the file attached below. 

The Department will be updating its website and posting the NOPR, the Technical Support Document (TSD) and associated analytical 

spreadsheets on its website early next week: 

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

In this NOPR, the Department proposes a national efficiency standard for liquid-immersed distribution transformers and medium-voltage 

dry-type distribution transformers. As you will recall, the mandatory standard for low-voltage distribution transformers was set by 

Congress in the Energy Policy Act of 2005. 

Stakeholders are invited to comment on the Department's proposal, and to attend a public meeting at the Department of Energy in 

Washington DC from 9:00am to 4:00pm on September 27th, 2006. At the public meeting, all statements will be recorded and 

transcribed, and will become part of the official record of the standards rulemaking. 

The deadline for submitting written comments on the NOPR is October 18, 2006. 

You may submit comments, identified by docket number EE-RM/STD-00-550 and/or Regulatory Information Number (RIN) 1904-AB08, 

by any of the following methods: 

Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments. 

E-mail: TransformerNOPRComment@ee.doe.gov. Include docket number EE-RM/STD-00-550 and/or RIN 1904-AB08 in the subject 

line of the message. 

Mail: Ms. Brenda Edwards-Jones, U.s. Department of Energy, Building Technologies Program, Mailstop EE-2J, NOPR for Distribution 

Transformers Energy Conservation Standards, docket number EE-RM/STD-00-550 and/or RIN 1904-AB08, 1000 Independence 

Avenue, SW, Washington, DC, 20585-0121. Please submit one signed original paper copy. 

Hand Delivery/Courier: Ms. Brenda Edwards-Jones, U.s. Department of Energy, Building Technologies Program, Room lJ-018, 

1000 Independence Avenue, SW, Washington, DC, 20585. Telephone: (202) 586-2945. Please submit one signed original 

paper copy. 

All comments (electronic and paper) should clearly identify the Docket number: EE-RM/STD-00-550 and/or RIN 1904-AB08. 

We appreciate your thorough review of the materials and look forward to your participation at the public meeting and your comments 

on the proposed rule. 

Sincerely, 

Antonio Bouza 

Building Technologies Program 

U.s. Department of Energy 

1000 Independence Avenue, SW 

Washington DC 20585-0121 

phone: 202.586.4563 

antonio.bouza@ee.doe.gov 

DT NOPR 71 FR 44356.pdf 
Friday,

August 4, 2®®6

Department of

Energy

Office of Energy Efficiency and

Renewable Energy

10 CFR Part 431

Energy Conservation Program for

Commercial Equipment: Distribution

Transformers Energy Conservation

Standards; Proposed Rule

 EE-RM/STD-00-550 COMMENT 91.1

Friday, 

August 4, 2006 

Part IT 

Department of 

Energy 

Office of Energy Efficiency and 

Renewable Energy 

10 CFR Part 431 

Energy Conservation Program for 

Commercial Equipment: Distribution 

Transformers Energy Conservation 

Standards; Proposed Rule 
44356 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

DEPARTMENT OF ENERGY this fact as soon as possible by

Office of Energy Efficiency and

Renewable Energy

10 CFR Part 431

[Docket Number: EE-RM/STD-00-550]

RIN 1904-ABO8

Energy Conservation Program for

Commercial Equipment: Distribution

Transformers Energy Conservation

Standards

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 (EPCA or the Act)

authorizes the Department of Energy

(DOE or the Department) to establish

energy conservation standards for

various consumer products and

commercial and industrial equipment,

including those distribution

transformers for which DOE determines

that energy conservation standards

would be technologically feasible and

economically justified, and would result

in significant energy savings. In this

notice, the Department is proposing

energy conservation standards for

distribution transformers and is

announcing a public meeting.

DATES: The Department will hold a

public meeting on Wednesday,

September 27, 2006, from 9 a.m. to 4

p.m., in Washington, DC. The

Department must receive requests to

speak at the public meeting before 4

p.m., Wednesday, September 13, 2006.

The Department must receive a signed

original and an electronic copy of

statements to be given at the public

meeting before 4 p.m., Wednesday,

September 13, 2006.

The Department will accept

comments, data, and information

regarding the notice of proposed

rulemaking (NOPR) before and after the

public meeting, but no later than

October 18, 2006. See section VII,

"Public Participation," of this NOPR for

details.

ADDRESSES : The public meeting will be

held at the U.S. Department of Energy,

Forrestal Building, Room 1E245, 1000

Independence Avenue, SW.,

Washington, DC. (Please note that

foreign nationals visiting DOE

Headquarters are subject to advance

security screening procedures, requiring

a 30-day advance notice. If you are a

foreign national and wish to participate

in the workshop, please inform DOE of

contacting Ms. Brenda Edwards-Jones at

(202) 586-2945 so that the necessary

procedures can be completed.)

You may submit comments, identified

by docket number EE-RM/STD-00-550

and/or Regulatory Information Number

(RIN) 1904-ABO8, by any of the

following methods:

e Federal eRulemaking Portal: http://

www.regulations.gov. Follow the

instructions for submitting comments.

® E-mail: TransformerNOPR

Comment@ee.doe.gov. Include docket

number EE-RM/STD-00-550 and/or

RIN 1904-AB08 in the subject line of

the message.

® Mail: Ms. Brenda Edwards-Jones,

U.S. Department of Energy, Building

Technologies Program, Mailstop EE-2J,

NOPR for Distribution Transformers

Energy Conservation Standards, docket

number EE-RM/STD-00-550 and/or

RIN 1904-ABO8, 1000 Independence

Avenue, SW., Washington, DC 20585-

0121. Please submit one signed original

paper copy.

e Hand Delivery/Courier: Ms. Brenda

Edwards-Jones, U.S. Department of

Energy, Building Technologies Program,

Room 1J-018, 1000 Independence

Avenue, SW., Washington, DC 20585.

Telephone: (202) 586-2945. Please

submit one signed original paper copy.

Instructions: All submissions received

must include the agency name and

docket number or RIN for this

rulemaking. For detailed instructions on

submitting comments and additional

information on the rulemaking process,

see section VII of this document (Public

Participation).

Docket: For access to the docket to

read background documents or

comments received, visit the U.S.

Department of Energy, Forrestal

Building, Room 1J-018 (Resource Room

of the Building Technologies Program),

1000 Independence Avenue, SW.,

Washington, DC, (202) 586-2945,

between 9 a.m. and 4 p.m., Monday

through Friday, except Federal holidays.

Please call Ms. Brenda Edwards-Jones at

the above telephone number for

additional information regarding

visiting the Resource Room. Please note:

The Department's Freedom of

Information Reading Room (formerly

Room 1E-190 at the Forrestal Building)

is no longer housing rulemaking

materials.

FOR FURTHER INFORMATION CONTACT:

Antonio Bouza, Project Manager, Energy

Conservation Standards for Distribution

Transformers, Docket No. EE-RM/STD00-550, U.S. Department of Energy,

Energy Efficiency and Renewable

Energy, Building Technologies Program,

EE-2J, 1000 Independence Avenue,

SW., Washington, DC 20585-0121, (202)

586-4563, e-mail:

Antonio.Bouza@ee.doe.gov.

Thomas B. DePriest, Esq., U.S.

Department of Energy, Office of General

Counsel, GC-72,1000 Independence

Avenue, SW., Washington, DC 20585,

(202) 586-9507, e-mail:

Thomas.Depriest@hq. doe.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents

1. Summary of the Proposed Rule

II. Introduction

A. Consumer Overview

B. Authority

C. Background

1. Current Standards

2. History of Standards Rulemaking for

Distribution Transformers

3. Process Improvement

III. General Discussion

A. Test Procedures

B. Technological Feasibility

1. General

2. Maximum Technologically Feasible

Levels

C. Energy Savings

D. Economic justification

1. Economic Impact on Manufacturers and

Commercial Consumers

2. Life-Cycle Costs

3. Energy Savings

4. Lessening of Utility or Performance of

Equipment

5. Impact of Any Lessening of Competition

6. Need of the Nation To Conserve Energy

7. Other Factors

IV. Methodology and Discussion of

Comments

A. Market and Technology Assessment

1. Product Classes

2. Definition of a Distribution Transformer

B. Engineering Analysis

1. Engineering Analysis Methodology

2. Engineering Analysis Inputs

3. Engineering Analysis Outputs

C. Life-Cycle Cost and Payback Period

Analysis

1. Inputs Affecting Installed Cost

a. Equipment Price

b. Installation Costs

c. Baseline and Standard Design Selection

2. Inputs Affecting Operating Costs

a. Transformer Loading

b. Load Growth

c. Power Factor

d. Electricity Costs

e. Electricity Price Trends

3. Inputs Affecting Present Value of

Annual Operating Cost Savings

a. Standards Implementation Date

b. Discount Rate

4. Candidate Standard Levels

5. Trial Standard Levels

6. Miscellaneous Life-Cycle Cost Issues

a. Tax Impacts

b. Cost Recovery Under Deregulation, Rate

Caps

c. Other Issues

D. National Impact Analysis-National

Energy Savings and Net Present Value

Analysis

 EE-RM/STD-00-550 COMMENT 91.1

44356 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006 I Proposed Rules 

DEPARTMENT OF ENERGY 

Office of Energy Efficiency and 

Renewable Energy 

10 CFR Part 431 

[Docket Number: EE-RM/STD-00-650] 

RIN 1904-AB08 

Energy Conservation Program for 

Commercial Equipment: Distribution 

Transformers Energy Conservation 

Standards 

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 (EPCA or the Act) 

authorizes the Department of Energy 

(DOE or the Department) to establish 

energy conservation standards for 

various consumer products and 

commercial and industrial equipment, 

including those distribution 

transformers for which DOE determines 

that energy conservation standards 

would be technologically feasible and 

economically justified, and would result 

in significant energy savings. In this 

notice, the Department is proposing 

energy conservation standards for 

distribution transformers and is 

announcing a public meeting. 

DATES: The Department will hold a 

public meeting on Wednesday, 

September 27, 2006, from 9 a.m. to 4 

p.m., in Washington, DC. The 

Department must receive requests to 

speak at the public meeting before 4 

p.m., Wednesday, September 13, 2006. 

The Department must receive a signed 

original and an electronic copy of 

statements to be given at the public 

meeting before 4 p.m., Wednesday, 

September 13,2006. 

The Department will accept 

comments, data, and information 

regarding the notice of proposed 

rulemaking (NOPR) before and after the 

public meeting, but no later than 

October 18, 2006. See section VII, 

"Public Participation," of this NOPR for 

details. 

ADDRESSES: The public meeting will be 

held at the U.S. Department of Energy, 

Forrestal Building, Room lE245, 1000 

Independence Avenue, SW., 

Washington, DC. (Please note that 

foreign nationals visiting DOE 

Headquarters are subject to advance 

security screening procedures, requiring 

a 30-day advance notice. If you are a 

foreign national and wish to participate 

in the workshop, please inform DOE of 

this fact as soon as possible by 

contacting Ms. Brenda Edwards-Jones at 

(202) 586-2945 so that the necessary 

procedures can be completed.) 

You may submit comments, identified 

by docket number EE-RM/STD-00-550 

and/or Regulatory Information Number 

(RIN) 1904-AB08, by any of the 

following methods: 

.. Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the 

instructions for submitting comments. .. E-mail: TransformerNOPR 

Comment@ee.doe.gov. Include docket 

number EE-RM/STD-00-550 and/or 

RIN 1904-AB08 in the subject line of 

the message. 

" Mail: Ms. Brenda Edwards-Jones, 

U.S. Department of Energy, Building 

Technologies Program, Mailstop EE-2J, 

NOPR for Distribution Transformers 

Energy Conservation Standards, docket 

number EE-RMISTD-00-550 and/or 

RIN 1904-AB08, 1000 Independence 

Avenue, SW., Washington, DC 20585-

0121. Please submit one signed original 

paper copy. 

.. Hand Delivery/Courier: Ms. Brenda 

Edwards-Jones, U.S. Department of 

Energy, Building Technologies Program, 

Room IJ-018, 1000 Independence 

Avenue, SW., Washington, DC 20585. 

Telephone: (202) 586-2945. Please 

submit one signed original paper copy. 

Instructions: All submissions received 

must include the agency name and 

docket number or RIN for this 

rulemaking. For detailed instructions on 

submitting comments and additional 

information on the rulemaking process, 

see section VII of this document (Public 

Partici pation). 

Docket: For access to the docket to 

read background documents or 

comments received, visit the U.S. 

Department of Energy, Forrestal 

Building, Room IJ-018 (Resource Room 

of the Building Technologies Program), 

1000 Independence Avenue, SW., 

Washington, DC, (202) 586-2945, 

between 9 a.m. and 4 p.m., Monday 

through Friday, except Federal holidays. 

Please call Ms. Brenda Edwards-Jones at 

the above telephone number for 

additional information regarding 

visiting the Resource Room. Please note: 

The Department's Freedom of 

Information Reading Room (formerly 

Room lE-190 at the Forrestal Building) 

is no longer housing rulemaking 

materials. 

FOR FURTHER INFORMATION CONTACT: 

Antonio Bouza, Project Manager, Energy 

Conservation Standards for Distribution 

Transformers, Docket No. EE-RM/STD00-550, U.S. Department of Energy, 

Energy Efficiency and Renewable 

Energy, Building Technologies Program, 

EE-2J, 1000 Independence Avenue, 

SW., Washington, DC 20585-0121, (202) 

586-4563, e-mail: 

Antonio.Bouza@ee.doe.gov. 

Thomas B. DePriest, Esq., U.S. 

Department of Energy, Office of General 

Counsel, GC-72, 1000 Independence 

Avenue, SW., Washington, DC 20585, 

(202) 586-9507, e-mail: 

Thomas.Depriest@hq.doe.gov. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

I. Summary of the Proposed Rule 

II. Introduction . 

A. Consumer Overview 

B. Authority 

C. Background 

1. Current Standards 

2. History of Standards Rulemaking for 

Distribution Transformers 

3. Process Improvement 

III. General Discussion 

A. Test Procedures 

B. Technological Feasibility 

1. General 

2. Maximum Technologically Feasible 

Levels 

C. Energy Savings 

D. Economic Justification 

1. Economic Impact on Manufacturers and 

Commercial Consumers 

2. Life-Cycle Costs 

3. Energy Savings 

4. Lessening of Utility or Performance of 

Equipment 

5. Impact of Any Lessening of Competition 

6. Need of the Nation To Conserve Energy 

7. Other Factors 

IV. Methodology and Discussion of 

Comments 

A. Market and Technology Assessment 

1. Product Classes 

2. Definition of a Distribution Transformer 

B. Engineering Analysis 

1. Engineering Analysis Methodology 

2. Engineering Analysis Inputs 

3. Engineering Analysis Outputs 

C. Life-Cycle Cost and Payback Period 

Analysis 

1. Inputs Affecting Installed Cost 

a. Equipment Price 

b. Installation Costs 

c. Baseline and Standard Design Selection 

2. Inputs Affecting Operating Costs 

a. Transformer Loading 

b. Load Growth 

c. Power Factor 

d. Electricity Costs 

e. Electricity Price Trends 

3. Inputs Affecting Present Value of 

Annual Operating Cost Savings 

a. Standards Implementation Date 

b. Discount Rate 

4. Candidate Standard Levels 

5. Trial Standard Levels 

6. Miscellaneous Life-Cycle Cost Issues 

a. Tax Impacts 

b. Cost Recovery Under Deregulation, Rate 

Caps 

c. Other Issues 

D. National Impact Analysis-National 

Energy Savings and Net Present Value 

Analysis 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44357

E. Commercial Consumer Subgroup

Analysis

F. Manufacturer Impact Analysis

1. General Description

2. Industry Profile

3. Industry Cash-Flow Analysis

4. Subgroup Impact Analysis

5. Government Regulatory Impact Model

Analysis

G. Employment Impact Analysis

H. Utility Impact Analysis

1. Environmental Analysis

V. Analytical Results

A. Economic Justification and Energy

Savings

1. Economic Impacts on Commercial

Consumers

a. Life-Cycle Cost and Payback Period

b. Rebuttable-Presumption Payback

c. Commercial Consumer Subgroup

Analysis

2. Economic Impacts on Manufacturers

a. Industry Cash-Flow Analysis Results

b. Impacts on Employment

c. Impacts on Manufacturing Capacity

d. Impacts on Manufacturers that are Small

Businesses

3. National Impact Analysis

a. Amount and Significance of Energy

Savings

b. Energy Savings and Net Present Value

c. 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. Other Factors

B. Stakeholder Comments on the Selection

of a Final Standard

C. Proposed Standard

1. Results for Liquid-Immersed

Distribution Transformers

a. Liquid-Immersed Trial Standard Level 6

b. Liquid-Immersed Trial Standard Level 5

c. Liquid-Immersed Trial Standard Level 4

d. Liquid-Immersed Trial Standard Level 3

e. Liquid-Immersed Trial Standard Level 2

2. Results for Medium-Voltage, Dry-Type

Distribution Transformers

a. Medium-Voltage, Dry-Type Trial

Standard Level 6

b. Medium-Voltage, Dry-Type Trial

Standard Level 5

c. Medium-Voltage, Dry-Type Trial

Standard Level 4

d. Medium-Voltage, Dry-Type Trial

Standard Level 3

e. Medium-Voltage, Dry-Type Trial

Standard Level 2

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Order 12866

B. Review Under the Regulatory Flexibility

Act/Initial Regulatory Flexibility

Analysis

1. Reasons for the Proposed Rule

2. Objectives of, and Legal Basis for, the

Proposed Rule

3. Description and Estimated Number of

Small Entities Regulated

4. Description and Estimate of Compliance

Requirements

5. Duplication, Overlap, and Conflict With

Other Rules and Regulations

6. Significant Alternatives to the Rule

C. Review Under the Paperwork Reduction

Act

D. Review Under the National

Environmental Policy Act

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 of 1999

I. Review Under Executive Order 12630

J. Review Under the Treasury and General

Government Appropriations Act of 2001

K. Review Under Executive Order 13211

L. Review Under Section 32 of the Federal

Energy Administration Act of 1974

M. Review Under the Information Quality

Bulletin for Peer Review

VII. Public Participation

A. Attendance at Public Meeting

B. Procedure for Submitting Requests To

Speak

C. Conduct of 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

Pursuant to the Energy Policy and

Conservation Act, as amended, the

Department is proposing energy

conservation standards for liquidimmersed and medium-voltage, drytype distribution transformers. The

Department believes these standards

will achieve the maximum

improvement in energy efficiency that is

technologically feasible and

economically justified, and will result

in significant energy savings. In the

advance notice of proposed rulemaking

(ANOPR) for distribution transformers,

the Department had also conducted

analysis on low-voltage, dry-type

distribution transformers. 69 FR 45376

(July 29, 2004). However, the Energy

Policy Act of 2005 (EPACT 2005)

established energy conservation

standards for low-voltage, dry-type

distribution transformers. (42 U.S.C.

6295(y)) Because of these amendments,

DOE removed low-voltage, dry-type

distribution transformers-product class

3 (low-voltage, dry-type, single-phase)

and product class 4 (low-voltage, drytype, three-phase)-from this

rulemaking. Table I.1 shows the

proposed standard levels for the product

classes that are still within the scope of

this rulemaking.

TABLE I.1.-PROPOSED STANDARD LEVELS FOR DISTRIBUTION TRANSFORMERS

Superclasses-product classes (PC)

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

Single-phase (PC 1)

Three-phase (PC 2)

Medium-voltage , dry-type ......................................................................................................................................

Single-phase, 25-45 kV BIL (PC 5)

Three-phase, 25-45 kV BIL (PC 6)

Single-phase, 46-95 kV BIL (PC 7)

Three-phase, 46-95 kV BIL (PC 8)

Single-phase, ?96 kV BIL (PC 9)

Three-phase, ?96 kV BIL (PC 10)

Note: PC stands for product class; kV is kilovolt; BIL is basic impulse insulation level.

Tables 11.1 and 11.2 show the specific

efficiency levels for the various kilovolt

ampere (kVA) sizes, within each

product class, that reflect the

Department's proposed standards.

The Department's analyses indicate

that the proposed standards, trial

standard level 2 (TSL2) for liquidimmersed transformers and TSL2 for

medium-voltage, dry-type transformers,

would save a significant amount of

energy-an estimated 2.4 quads

(quadrillion (1015) British thermal units

(BTU)) of cumulative energy over 29

years (2010-2038). This amount is

roughly equal to the total energy

consumption of the Commonwealth of

Virginia in 2001. The economic impacts

on commercial consumers (i.e., the

Proposed standard levels

Trial Standard Level 2.

Trial Standard Level 2.

average life-cycle cost (LCC) savings) are

positive.

The national net present value (NPV)

of TSL2 is $2.52 billion using a sevenpercent discount rate and $9.43 billion

using a three-percent discount rate,

cumulative from 2010 to 2073 in 2004$.

This is the estimated total value of

future savings minus the estimated

increased equipment costs, discounted

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44357 

E. Commercial Consumer Subgroup 

Analvsis 

F. Manufacturer Impact Analysis 

1. General Description 

2. Industry Profile 

3. Industry Cash-Flow Analysis 

4. Subgroup Impact Analysis 

5. Government Regulatory Impact Model 

Analysis 

G. Employment Impact Analysis 

H. Utility Impact Analysis 

I. Environmental Analysis 

V. Analytical Results 

A. Economic Justification and Energy 

Savings 

1. Economic Impacts on Commercial 

Consumers 

a. Life-Cycle Cost and Payback Period 

b. Rebuttable-Presumption Payback 

c. Commercial Consumer Subgroup 

Analysis 

2. Economic Impacts on Manufacturers 

a. Industry Cash-Flow Analysis Results 

b. Impacts on Employment 

c. Impacts on Manufacturing Capacity 

d. Impacts on Manufacturers that are Small 

Businesses 

3. National Impact Analysis 

a. Amount and Significance of Energy 

Savings 

b. Energy Savings and Net Present Value 

c. 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. Other Factors 

B. Stakeholder Comments on the Selection 

of a Final Standard 

C. Proposed Standard 

1. Results for Liquid-Immersed 

Distribution Transformers 

a. Liquid-Immersed Trial Standard Level 6 

b. Liquid-Immersed Trial Standard Level 5 

c. Liquid-Immersed Trial Standard Level 4 

d. Liquid-Immersed Trial Standard Level 3 

e. Liquid-Immersed Trial Standard Level 2 

2. Results for Medium-Voltage, Dry-Type 

Distribution Transformers 

a. Medium-Voltage, Dry-Type Trial 

Standard Level 6 

b. Medium-Voltage. Dry-Type Trial 

Standard Level 5 

c. Medium-Voltage. Dry-Type Trial 

Standard Level 4 

d. Medium-Voltage. Dry-Type Trial 

Standard Level 3 

e. Medium-Voltage. Dry-Type Trial 

Standard Level 2 

VI. Procedural Issues and Regulatory Review 

A. Review Under Executive Order 12866 

B. Review Under the Regulatory Flexibility 

Act/Initial Regulatory Flexibility 

Analysis 

1. Reasons for the Proposed Rule 

2. Objectives of, and Legal Basis for, the 

Proposed Rule 

3, Description and Estimated Number of 

Small Entities Regulated 

4. Description and Estimate of Compliance 

Requirements 

5. Duplication, Overlap. and Conflict With 

Other Rules and Regulations 

6. Significant Alternatives to the Rule 

C. Review Under the Paperwork Reduction 

Act 

D. Review Under the National 

Environmental Policy Act 

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 of 1999 

I. Review Under Executive Order 12630 

J. Review Under the Treasury and General 

Government Appropriations Act of 2001 

K. Review Under Executive Order 13211 

1. Review Under Section 32 of the Federal 

Energy Administration Act of 1974 

M. Review Under the Information Quality 

Bulletin for Peer Review 

VII. Public Participation 

A. Attendance at Public Meeting 

B. Procedure for Submitting Requests To 

Speak 

C. Conduct of 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 

Pursuant to the Energy Policy and 

Conservation Act. as amended, the 

Department is proposing energy 

conservation standards for liquidimmersed and medium-voltage. drytype distribution transformers. The 

Department believes these standards 

will achieve the maximum 

improvement in energy efficiency that is 

technologically feasible and 

economically justified, and will result 

in significant energy savings. In the 

advance notice of proposed rulemaking 

(ANOPR) for distribution transformers, 

the Department had also conducted 

analysis on low-voltage, dry-type 

distribution transformers. 59 FR 45375 

(July 29. 2004). However. the Energy 

Policy Act of 2005 (EPACT 2005) 

established energy conservation 

standards for low-voltage, dry-type 

distribution transformers. (42 U.S.c. 

5295(y)) Because of these amendments. 

DOE removed low-voltage. dry-type 

distribution transformers-product class 

3 (low-voltage, dry-type, single-phase) 

and product class 4 (low-voltage. drytype. three-phase)-from this 

rulemaking. Table 1.1 shows the 

proposed standard levels for the product 

classes that are still within the scope of 

this rulemaking. 

TABLE 1.1.-PROPOSED STANDARD LEVELS FOR DISTRIBUTION TRANSFORMERS 

Superclasses-product classes (PC) Proposed standard levels 

Liquid-immersed .................................................................................................................................................... Trial Standard Level 2. 

Single-phase (PC 1) 

Three-phase (PC 2) 

Medium-voltage, dry-type .................................................... .................................................................................. Trial Standard Level 2. 

Single-phase. 25-45 kV BIL (PC 5) 

Three-phase. 25-45 kV BIL (PC 6) 

Single-phase, 46-95 kV BIL (PC 7) 

Three-phase, 46-95 kV BIL (PC 8) 

Single-phase. ~96 kV BIL (PC 9) 

Three-phase, ~96 kV BIL (PC 10) 

Note: PC stands for product class; kV is kilovolt; BIL is basic impulse insulation level. 

Tables ILl and II.2 show the specific 

efficiency levels for the various kilovolt 

ampere (kVA) sizes, within each 

product class, that reflect the 

Department's proposed standards. 

The Department's analyses indicate 

that the proposed standards, trial 

standard level 2 (TSL2) for liquidimmersed transformers and TSL2 for 

medium-voltage, dry-type transformers, 

would save a significant amount of 

energy-an estimated 2.4 quads 

(quadrillion (10 15) British thermal units 

(BTU)) of cumulative energy over 29 

years (2010-2038). This amount is 

roughly equal to the total energy 

consumption of the Commonwealth of 

Virginia in 2001. The economic impacts 

on commercial consumers (i.e., the 

average life-cycle cost (LCC) savings) are 

positive. 

The national net present value (NPV) 

of TSL2 is $2.52 billion using a sevenpercent discount rate and $9.43 billion 

using a three-percent discount rate, 

cumulative from 2010 to 2073 in 2004$. 

This is the estimated total value of 

future savings minus the estimated 

increased equipment costs, discounted 
44358 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

to the year 2004. Using a real corporate

discount rate of 8.9 percent, the

Department estimates the liquidimmersed and medium-voltage, drytype distribution transformer industry's

NPV to be $558 million in 2004$. The

impact of the proposed standard on

liquid-immersed transformer

manufacturers' industry net present

value (INPV) is expected to be between

a 2.4 percent loss and a 2.0 percent

increase (- $12.9 million to $10.7

million). The medium-voltage, dry-type

transformer industry is estimated to lose

between 10.1 percent and 13.4 percent

of its NPV (-$3.3 million to -$4.3

million) as a result of the proposed

standard. Based on the Department's

interviews with the major

manufacturers of distribution

transformers, DOE expects minimal

plant closings or loss of employment as

a result of the proposed standards.

The proposed standards will lead to

reductions in greenhouse gases,

resulting in cumulative (undiscounted)

emission reductions of 167.1 million

tons (Mt) of carbon dioxide (CO2).

Additionally, the standards would

generate 46.4 thousand tons (kt) of

nitrogen oxides (NOX) emissions

reductions or a similar amount of NOx

emissions allowance credits in areas

where such emissions are subject to

emissions caps. The Department expects

the energy savings from the proposed

standards to eliminate the need for

approximately 11 new 400-megawatt

(MW) power plants by 2038.

Therefore, the Department concludes

that the benefits (energy savings,

commercial consumer LCC savings,

national NPV increases, and emissions

reductions) to the Nation of the

proposed standards outweigh their costs

(loss of manufacturer NPV and

commercial consumer LCC increases for

some users of distribution transformers).

The Department concludes that the

proposed standards of TSL2 for liquidimmersed and TSL2 for mediumvoltage, dry-type transformers are

technologically feasible and

economically justified. At present, both

liquid-immersed and medium-voltage,

dry-type transformers are commercially

available at the TSL2 standard level.

H. Introduction

A. Consumer Overview

The Department is proposing to set

energy-efficiency standard levels for

distribution transformers as shown in

Tables 11.1 and 11.2. The proposed

standard would apply to liquidimmersed and medium-voltage, drytype distribution transformers

manufactured for sale in the United

States, or imported to the United States,

on or after January 1, 2010. In preparing

these tables, the Department identified

some areas where the analytical

methods used to develop the efficiency

values resulted in discontinuities in the

table of efficiencies. Generally, larger

transformers will have greater efficiency

than smaller transformers, all other

factors being equal. Not all efficiency

ratings that result from the Department's

analysis fit this pattern. The Department

invites comment on all the efficiency

ratings.

TABLE 11.1.-PROPOSED STANDARD LEVEL, TSL2, FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS

Single-phase Three-phase

kVA Efficiency kVA Efficiency

10 .................................................................................. 98.40 15 ................................................................................. 98.36

15 .................................................................................. 98.56 30 ................................................................................. 98.62

25 .................................................................................. 98.73 45 ................................................................................. 98.76

37.5 ............................................................................... 98.85 75 ................................................................................. 98.91

50 .................................................................................. 98.90 112.5 ............................................................................ 99.01

75 .................................................................................. 99.04 150 ............................................................................... 99.08

100 ................................................................................ 99.10 225 ............................................................................... 99.17

167 ................................................................................ 99.21 300 ............................................................................... 99.23

250 ................................................................................ 99.26 500 ............................................................................... 99.32

333 ................................................................................ 99.31 750 ............................................................................... 99.24

500 ................................................................................ 99.38 1000 ............................................................................. 99.29

667 ................................................................................ 99.42 1500 ............................................................................. 99.36

833 ................................................................................ 99.45 2000 ............................................................................. 99.40

2500 ............................................................................. 99.44

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; 71 FR 24972.

TABLE 11.2.-PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS

Single-phase Three-phase

BIL 20-45 kV 46-95 kV >_96 kV 20-45 kV 46-95 kV >_96 kV

kVA efficiency efficiency efficiency efficiency efficiency efficiency kVA

(%) (%) (%) (%) (%) (%)

15 .......................... 98.10 97.86 ........................ 15 .......................... 97.50 97.19 ........................

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

 EE-RM/STD-00-550 COMMENT 91.1

44358 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

to the year 2004. Using a real corporate 

discount rate of 8.9 percent, the 

Department estimates the liquidimmersed and medium-voltage, drytype distribution transformer industry's 

NPV to be $558 million in 2004$. The 

impact of the proposed standard on 

liquid-immersed transformer 

manufacturers' industry net present 

value (INPV) is expected to be between 

a 2.4 percent loss and a 2.0 percent 

increase (-$12.9 million to $10.7 

million). The medium-voltage, dry-type 

transformer industry is estimated to lose 

between 10.1 percent and 13.4 percent 

of its NPV (- $3.3 million to - $4.3 

million) as a result of the proposed 

standard. Based on the Department's 

interviews with the major 

manufacturers of distribution 

transformers, DOE expects minimal 

plant closings or loss of employment as 

a result of the proposed standards. 

The proposed standards will lead to 

reductions in greenhouse gases, 

resulting in cumulative (undiscounted) 

emission reductions of 167.1 million 

tons (Mt) of carbon dioxide (C02), 

Additionally, the standards would 

generate 46.4 thousand tons (kt) of 

nitrogen oxides (NOx) emissions 

reductions or a similar amount of NOx 

emissions allowance credits in areas 

where such emissions are subject to 

emissions caps. The Department expects 

the energy savings from the proposed 

standards to eliminate the need for 

approximately 11 new 400-megawatt 

(MW) power plants by 2038. 

Therefore, the Department concludes 

that the benefits (energy savings, 

commercial consumer LCC savings, 

national NPV increases, and emissions 

reductions) to the Nation of the 

proposed standards outweigh their costs 

(loss of manufacturer NPV and 

commercial consumer LCC increases for 

some users of distribution transformers). 

The Department concludes that the 

proposed standards of TSL2 for liquidimmersed and TSL2 for mediumvoltage, dry-type transformers are 

technologically feasible and 

economically justified. At present, both 

liquid-immersed and medium-voltage, 

dry-type transformers are commercially 

available at the TSL2 standard level. 

n. Introduction 

A. Consumer Overview 

The Department is proposing to set 

energy-efficiency standard levels for 

distribution transformers as shown in 

Tables ILl and II.2. The proposed 

standard would apply to liquidimmersed and medium-voltage, drytype distribution transformers 

manufactured for sale in the United 

States, or imported to the United States, 

on or after January 1, 2010. In preparing 

these tables, the Department identified 

some areas where the analytical 

methods used to develop the efficiency 

values resulted in discontinuities in the 

table of efficiencies. Generally, larger 

transformers will have greater efficiency 

than smaller transformers, all other 

factors being equal. Not all efficiency 

ratings that result from the Department's 

analysis fit this pattern. The Department 

invites comment on all the efficiency 

ratings. 

TABLE 11.1.-PROPOSED STANDARD LEVEL, TSL2, FOR liQUID-IMMERSED DISTRIBUTION TRANSFORMERS 

Single-phase 

kVA 

10 ................................................................................. . 

15 ................................................................................ .. 

25 ................................................................................. . 37.5 ............................................................................. .. 

50 ................................................................................ .. 

75 ................................................................................. . 

100 .............................................................................. .. 

167 ............................................................................... . 

250 .............................................................................. .. 

333 ............................................................................... . 

500 .............................................................................. .. 

667 .............................................................................. .. 

833 ............................................................................... . 

Efficiency 

("!o) 

98.40 

98.56 

98.73 

98.85 

98.90 

99.04 

99.10 

99.21 

99.26 

99.31 

99.38 

99.42 

99.45 

Three-phase 

kVA 

15 ................................................................................ . 

30 ................................................................................ . 

45 ................................................................................ . 

75 ................................................................................ . 

112.5 ........................................................................... . 

150 .............................................................................. . 

225 ............................................................................. .. 

300 .............................................................................. . 

500 .............................................................................. . 

750 .............................................................................. . 

1000 ............................................................................ . 

1500 ............................................................................ . 

2000 ............................................................................ . 2500 ........................................................................... .. 

Efficiency 

("!o) 

98.36 

98.62 

98.76 

98.91 

99.01 

99.08 

99.17 

99.23 

99.32 

99.24 

99.29 

99.36 

99.40 

99.44 

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; 71 FR 24972. 

TABLE 11.2.-PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS 

Single-phase 

BIL 

kVA 

20-45 kV 

efficiency 

(%) 

15 .......................... 98.10 

25.......................... 98.33 

37.5....................... 98.49 

50.......................... 98.60 

75.......................... 98.73 

100 ........................ 98.82 

167 ........................ 98.96 

250........................ 99.07 

333........................ 99.14 

500........................ 99.22 

667........................ 99.27 

833........................ 99.31 

46-95 kV 

efficiency 

("!o) 

97.86 

98.12 

98.30 

98.42 

98.57 

98.67 

98.83 

98.95 

99.03 

99.12 

99.18 

99.23 

~96 kV 

efficiency 

(%) 

........................ 

........................ 

........................ 

........................ 

98.53 

98.63 

98.80 

98.91 

98.99 

99.09 

99.15 

99.20 

20-45 kV 

efficiency 

("!o) 

15 . ......................... 

30 . ......................... 

45 . ......................... 

75 .......................... 

112.5 ..................... 

150 ........................ 

225 ........................ 

300 ........................ 

500 ........................ 

750 ........................ 

1000 ...................... 

1500 ...................... 

Three-phase 

46-95 kV 

efficiency 

(%) 

97.50 

97.90 

98.10 

98.33 

98.49 

98.60 

98.73 

98.82 

98.96 

99.07 

99.14 

99.22 

~96 kV 

efficiency 

(%) 

97.19 

97.63 

97.86 

98.12 

98.30 

98.42 

98.57 

98.67 

98.83 

98.95 

99.03 

99.12 

kVA 

........................ 

........................ 

........................ 

. ....................... 

........................ 

........................ 

98.53 

98.63 

98.80 

98.91 

98.99 

99.09 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44359

TABLE 11.2.-PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERSContinued

Single-phase Three-phase

20-45 kV 46-95 kV ?96 kV 20-45 kV 46-95 kV ?96 kV

BIL

kVA efficiency efficiency efficiency efficiency efficiency efficiency kVA

(%) . (%) (%) (%) (%) (%)

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; 71 FR 24972.

B. Authority

Title III of EPCA sets forth a variety

of provisions designed to improve

energy efficiency. Part B of Title III (42

U.S.C. 6291-6309) provides for the

Energy Conservation Program for

Consumer Products other than

Automobiles. Part C of Title III (42

U.S.C. 6311-6317) establishes a similar

program for "Certain Industrial

Equipment," and includes distribution

transformers, the subject of this

rulemaking. The Department publishes

today's NOPR pursuant to Part C of Title

III, which provides for test procedures,

labeling, and energy conservation

standards for distribution transformers

and certain other products, and

authorizes DOE to require information

and reports from manufacturers. The

distribution transformer test procedure

appears in Title 10 Code of Federal

Regulations (CFR) Part 431, Subpart K,

Appendix A; 71 FR 24972.

EPCA contains criteria for prescribing

new or amended energy conservation

standards. The Department must

prescribe standards only for those

distribution transformers for which

DOE: (1) Has determined that standards

would be technologically feasible and

economically justified and would result

in significant energy savings, and (2) has

prescribed test procedures. (42 U.S.C.

6317(a)) Moreover, as indicated above,

the Department analyzed whether

today's proposed standards for

distribution transformers will achieve

the maximum improvement in energy

efficiency that is technologically

feasible and economically justified. (See

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

6317(a) and (c)) In addition, DOE will

decide whether today's proposed

standard is economically justified, after

receiving comments on the proposed

standard, by determining whether the

benefits of the standard exceed its costs.

The Department will make this

determination by considering, to the

greatest extent practicable, the following

seven factors which are set forth in 42

U.S.C. 6295(o)(2)(B)(i):

(1) The economic impact of the standard Third, in setting standards for a type

on manufacturers and consumers of the or class of equipment that has two or

products subject to the standard; more subcategories, DOE will specify a

(2) The savings in operating costs different standard level than that which throughout the estimated average life of

products in the type (or class) compared to applies generally to such type or class

any increase in the price, initial charges, or of equipment for any group of products

maintenance expenses for the covered "which have the same function or

products that are likely to result from the intended use, if * * * products within

imposition of the standard; such group-(A) consume a different

(3) The total projected amount of energy kind of energy from that consumed by

savings likely to result directly from the other covered products within such type

imposition of the standard;

(4) Any lessening of the utility or the (or class); or (B) have a capacity or other

performance of the products likely to result performance-related feature which other

from the imposition of the standard; products within such type (or class) do

(5) The impact of any lessening of not have and such feature justifies a

competition, as determined in writing by the higher or lower standard" than applies

Attorney General, that is likely to result from or will apply to the other products. (See

the imposition of the standard; 42 U.S.C. 6295(q)(1)) In determining (6) The need for national energy

conservation; and whether a Performance related feature

(7) Other factors the Secretary considers justifies such a different standard for a

relevant. group of products, the Department

In developing energy conservation considers such factors as the utility to

standards for distribution transformers, the consumer of such a feature and

DOE is also applying certain other other factors DOE deems appropriate.

provisions of 42 U.S.C. 6295. First, the Any rule prescribing such a standard

Department will not prescribe a will include an explanation of the basis

standard for the product if interested on which DOE established such higher

persons have established by a or lower level. (See 42 U.S.C. 6295(q)(2))

preponderance of the evidence that the Federal energy efficiency

standard is likely to result in the requirements for equipment covered by

unavailability in the United States of 42 U.S.C. 6317 generally supersede

any type (or class) of this product with State laws or regulations concerning

performance characteristics, features, energy conservation testing, labeling,

sizes, capacities, and volume that are and standards. (42 U.S.C. 6297(a)-(c)

substantially the same as those generally and 42 U.S.C. 6316(a)) The Department

available in the United States. (See 42 can, however, grant waivers of

U.S.C. 6295(o)(4)) preemption for particular State laws or

Second, DOE is applying 42 U.S.C. regulations, in accordance with the

6295(o)(2)(B)(iii), which establishes a procedures and other provisions of

rebuttable presumption that a standard section 327(d) of the Act. (42 U.S.C.

is economically justified if the Secretary 6297(d) and 42 U.S.C. 6316(a))

finds that "the additional cost to the

consumer of purchasing a product C. Background

complying with an energy conservation 1. Current Standards

standard level will be less than three

times the value of the energy * * *

savings during the first year that the

consumer will receive as a result of the

standard, as calculated under the

applicable test procedure * * *" The

rebuttable-presumption test is an

alternative path to establishing

economic justification.

Presently, there are no national energy

conservation standards for the liquidimmersed and medium-voltage, drytype distribution transformers covered

by this rulemaking. However, on August

8, 2005, EPACT 2005 established energy

conservation standards for low-voltage,

dry-type distribution transformers that

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 44359 

TABLE 11.2.-PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERSContinued 

Single-phase Three-phase 

BIL 20-45 kV 46-95 kV ~96 kV 20-45 kV 46-95 kV ~96 kV 

kVA efficiency efficiency efficiency efficiency efficiency efficiency kVA 

(%) (%) (%) (%) (%) (%) 

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; 71 FR 24972. 

B. Authority 

Title III of EPCA sets forth a variety 

of provisions designed to improve 

energy efficiency. Part B of Title III (42 

U.S.C. 6291-6309) provides for the 

Energy Conservation Program for 

Consumer Products other than 

Automobiles. Part C of Title III (42 

U.S.C. 6311-6317) establishes a similar 

program for "Certain Industrial 

Equipment," and includes distribution 

transformers. the subject of this 

rulemaking. The Department publishes 

today's NOPR pursuant to Part C of Title 

III, which provides for test procedures. 

labeling, and energy conservation 

standards for distribution transformers 

and certain other products. and 

authorizes DOE to require information 

and reports from manufacturers. The 

distribution transformer test procedure 

appears in Title 10 Code of Federal 

Regulations (CFR) Part 431, Subpart K. 

Appendix A; 71 FR 24972. 

EPCA contains criteria for prescribing 

new or amended energy conservation 

standards. The Department must 

prescribe standards only for those 

distribution transformers for which 

DOE: (1) Has determined that standards 

would be technologically feasible and 

economically justified and would result 

in significant energy savings. and (2) has 

prescribed test procedures. (42 U.S.c. 

6317(a)) Moreover. as indicated above, 

the Department analyzed whether 

today's proposed standards for 

distribution transformers will achieve 

the maximum improvement in energy 

efficiency that is technologically 

feasible and economically justified. (See 

42 U.S.c. 6295(0)(2)(Aj, 6316(a). and 

6317(a) and (cll In addition. DOE will 

decide whether today's proposed 

standard is economically justified. after 

receiving comments on the proposed 

standard. by determining whether the 

benefits of the standard exceed its costs. 

The Department will make this 

determination by considering. to the 

greatest extent practicable, the following 

seven factors which are set forth in 42 

U.S.c. 6295(0)(2)(B)(i): 

(1) The economic impact of the standard 

on manufacturers and consumers of the 

products subject to the standard; 

(2) The savings in operating costs 

throughout the estimated average life of 

products 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 

savings likely to result directly from the 

imposition of the standard; 

(4) Any lessening of the utility or the 

performance of the products 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 

conservation; and 

(7) Other factors the Secretary considers 

relevant. 

In developing energy conservation 

standards for distribution transformers. 

DOE is also applying certain other 

provisions of 42 U.S.C. 6295. First. the 

Department will not prescribe a 

standard for the product 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 type (or class) of this product with 

performance characteristics. features, 

sizes, capacities. and volume that are 

substantially the same as those generally 

available in the United States. (See 42 

U.S.c. 6295(0)(4)) 

Second, DOE is applying 42 U.S.C. 

6295(0)(2)(B)(iii). which establishes a 

rebuttable presumption that a standard 

is economically justified if the Secretary 

finds that "the additional cost to the 

consumer of purchasing a product 

complying with an energy conservation 

standard level will be less than three 

times the value of the energy * * * 

savings during the first year that the 

consumer will receive as a result of the 

standard. as calculated under the 

applicable test procedure * * *" The 

rebuttable-presumption test is an 

alternative path to establishing 

economic justification. 

Third. in setting standards for a type 

or class of equipment that has two or 

more subcategories. DOE will specify a 

different standard level than that which 

applies generally to such type or class 

of equipment for any group of products 

"which have the same function or 

intended use. if * * * products within 

such group-rAJ consume a different 

kind of energy from that consumed by 

other covered products within such type 

(or class); or (B) have a capacity or other 

performance-related feature which other 

products within such type (or class) do 

not have and such feature justifies a 

higher or lower standard" than applies 

or will apply to the other products. (See 

42 U.S.C. 6295(q)(1)) In determining 

whether a performance-related feature 

justifies such a different standard for a 

group of products. the Department 

considers such factors as the utility to 

the consumer of such a feature and 

other factors DOE deems appropriate. 

Any rule prescribing such a standard 

will include an explanation of the basis 

on which DOE established such higher 

or lower level. (See 42 U.S.c. 6295(q)(2)) 

Federal energy efficiency 

requirements for equipment covered by 

42 U.S.C. 6317 generally supersede 

State laws or regulations concerning 

energy conservation testing. labeling. 

and standards. (42 U.S.C. 6297(a)-(c) 

and 42 U.S.c. 6316(a)) The Department 

can. however. grant waivers of 

preemption for particular State laws or 

regulations. in accordance with the 

procedures and other provisions of 

section 327(d) of the Act. (42 U.S.c. 

6297(d) and 42 U.S.C. 6316(a)) 

C. Background 

1. Current Standards 

Presently. there are no national energy 

conservation standards for the liquidimmersed and medium-voltage, drytype distribution transformers covered 

by this rulemaking. However. on August 

8,2005, EPACT 2005 established energy 

conservation standards for low-voltage. 

dry-type distribution transformers that 
44360 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

will take effect on January 1, 2007. (42

U.S.C. 6295(y))

2. History of Standards Rulemaking for

Distribution Transformers

On October 22, 1997, the Secretary of

Energy published a notice stating that

the Department "has determined, based

on the best information currently

available, that energy conservation

standards for electric distribution

transformers are technologically

feasible, economically justified and

would result in significant energy

savings." 62 FR 54809.

The Secretary's determination was

based, in part, on analyses conducted by

the Department's Oak Ridge National

Laboratory (ORNL). In July 1996, ORNL

published a report entitled

Determination Analysis of Energy

Conservation Standards for Distribution

Transformers, ORNL-6847, which

assessed options for setting energy

conservation standards. That report was

based on information from annual sales

data, average load data, and surveys of

existing and potential transformer

efficiencies obtained from several

organizations.

In September 1997, ORNL published

a second report entitled Supplement to

the "Determination Analysis" (ORNL6847) and NEMA Efficiency Standard

for Distribution Transformers, ORNL6925. This report assessed the suggested

efficiency levels contained in the thennewly published National Electrical

Manufacturers Association (NEMA)

Standards Publication No. TP 1-1996,

Guide for Determining Energy Efficiency

for Distribution Transformers, along

with the efficiency levels previously

considered by the Department in the

determination study.' In its

supplemental assessment, ORNL-6925,

the ORNL research team used a more

accurate analytical model and better

transformer market and loading data

developed following the publication of

ORNL-6847. Downloadable versions of

both ORNL reports are available on the

DOE Web site at: http://

www. eere. en ergy.gov/buildings/

a p pl ian ce_stan d and s/commercial /

distribution transformers.htm]

As a result of its positive

determination, the Department

developed the Framework Document for

Distribution Transformer Energy

Conservation Standards Rulemaking in

2000, describing the procedural and

analytic approaches the Department

anticipated using to evaluate the

I Note: NEMA later updated TP I in 2002 (NEMA

TP 1-2002), in which it increased some of the

efficiency levels. The latest version of TP 1 is

available at the NEMA Web site: http://

www.nema.org/Stds/tpi.cfm#downlood.

establishment of energy conservation

standards for distribution transformers.2

This document is also available on the

aforementioned DOE Web site. On

November 1, 2000, the Department held

a public meeting on the Framework

Document to discuss the proposed

analytical framework. Manufacturers,

trade associations, electric utilities,

environmental advocates, regulators,

and other interested parties attended the

Framework Document meeting. The

major issues discussed were: Definition

of covered transformer products,

definition of product classes, possible

proprietary (patent) issues regarding

amorphous material, ties between

efficiency improvements and

installation costs, baseline and possible

higher efficiency levels, base case trends

(i.e., trends absent regulation),

transformer costs versus transformer

prices, appropriate LCC subgroups, LCC

methods (e.g., total owning cost (TOG)),

loading levels, utility impact analysis

vis-a-vis deregulation, scope of

environmental assessment, and

harmonization of standards with other

countries.

Stakeholder comments submitted

during the Framework Document

comment period elaborated on the

issues raised at the meeting and also

addressed the following issues: Options

for the screening analysis, approaches

for the engineering analysis, discount

rates, electricity prices, the number and

basis for the efficiency levels to be

analyzed, the national energy savings

(NES) and NPV analyses, the analysis of

the effects of a potential standard on

employment, the manufacturer impact

analysis (MIA), and the timing of the

analyses.

As part of the information gathering

and sharing process, the Department

met with manufacturers of liquidimmersed and dry-type distribution

transformers during the first quarter of

2002. The Department met with

companies that produced all types of

distribution transformers, ranging from

small to large manufacturers, and

including both NEMA and non-NEMA

members. The Department had three

objectives for these meetings: (1) Solicit

feedback on the methodology and

findings presented in the draft

engineering analysis update report that

the Department posted on its Web site

December 17, 2001, (2) obtain

information and comments on

2 The Department published a notice of

availability of the Framework Document in the

Federal Register. 65 FR 59761 (October 6, 2000).

The Framework Document itself is available on the

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

buildings/appliance-standards/commercial/pd fs/

trans framework.pdf.

production costs and manufacturing

processes presented in the draft

engineering analysis update report, and

(3) provide to manufacturers an

opportunity, early in the rulemaking

process, to express specific concerns to

the Department.

Seeking early and frequent

consultation with stakeholders, the

Department posted draft reports on its

website as it prepared for the

publication of the ANOPR. The reports

included draft screening analysis

findings, and draft engineering analysis

and LCC analysis reports on 50 kVA

single-phase, liquid-immersed, padmounted transformers and 300 kVA

three-phase, medium-voltage, dry-type

transformers. The Department also held

a live, online Web cast on October 17,

2002, giving an overview of the LCC

analysis and a tutorial on the use of the

LCC spreadsheet. The Department

received comments from stakeholders

on all the draft publications, which

helped improve the quality of the

analysis included in the ANOPR

published on July 29, 2004. 69 FR

45376.

In the ANOPR, the Department

invited stakeholders to comment on the

following key issues: Definition and

coverage, product classes, engineering

analysis inputs, design option

combinations, the 0.75 scaling rule,

modeling of transformer load profiles,

distribution chain markups, discount

rate selection and use, baseline

determination through purchase

evaluation formulae, electricity prices,

load growth over time, life-cycle cost

subgroups, and utility deregulation

impacts.

In preparation for the September 28,

2004, ANOPR public meeting, the

Department held a Web cast on August

10, 2004, to acquaint stakeholders with

the analytical tools (spreadsheets) and

other material published the previous

month. During the ANOPR comment

period, which ended on November 9,

2004, stakeholders submitted comments

on the 13 issues listed above, as well as

on other issues. These comments are

discussed in section IV of this NOPR.

On August 5, 2005, the Department

posted on its Web site several draft

NOPR analyses for early public review,

including draft technical support

document (TSD) chapters on the

engineering analysis, the energy use and

end-use load characterization, the

markups for equipment price

determination, the LCC and payback

period analyses, the shipments analysis,

the national impact analysis, and the

MIA. The Department also posted draft

NOPR spreadsheets for the engineering

 EE-RM/STD-00-550 COMMENT 91.1

44360 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

will take effect on January 1, 2007. (42 

U.S.c. 6295(y)) 

2. History of Standards Rulemaking for 

Distribution Transformers 

On October 22, 1997, the Secretary of 

Energy published a notice stating that 

the Department "has determined, based 

on the best information currently 

available, that energy conservation 

standards for electric distribution 

transformers are technologically 

feasible, economically justified and 

would result in significant energy 

savings." 62 FR 54809. 

The Secretary's determination was 

based, in part, on analyses conducted by 

the Department's Oak Ridge National 

Laboratory (ORNL). In July 1996, ORNL 

published a report entitled 

Determination Analysis of Energy 

Conservation Standards for Distribution 

Transformers, ORNL-6847, which 

assessed options for setting energy 

conservation standards. That report was 

based on information from annual sales 

data, average load data, and surveys of 

existing and potential transformer 

efficiencies obtained from several 

organizations. 

In September 1997, ORNL published 

a second report entitled Supplement to 

the "Determination Analysis" (ORNL6847) and NEMA Efficiency Standard 

for Distribution Transformers, ORNL6925. This report assessed the suggested 

efficiency levels contained in the thennewly published National Electrical 

Manufacturers Association (NEMA) 

Standards Publication No. TP 1-1996, 

Guide for Determining Energy Efficiency 

for Distribution Transformers, along 

with the efficiency levels previously 

considered by the Department in the 

determination study.1 In its 

supplemental assessment, ORNL-6925, 

the ORNL research team used a more 

accurate analytical model and better 

transformer market and loading data 

developed following the publication of 

ORNL-6847. Downloadable versions of 

both ORNL reports are available on the 

DOE Web site at: http:// 

www.eere.energy.gov/buildings/ 

appliance_standards/commercial/ 

distribution_transformers.html 

As a result of its positive 

determination, the Department 

developed the Framework Document for 

Distribution Transformer Energy 

Conservation Standards Rulemaking in 

2000, describing the procedural and 

analytic approaches the Department 

anticipated using to evaluate the 

1 Note: NEMA later updated TP 1 in 2002 (NEMA 

TP 1-2002), in which it increased some of the 

efficiency levels. The latest version of TP 1 is 

available at the NEMA Web site: http:// 

www.nema.org!stdsltpl.cfm#download. 

establishment of energy conservation 

standards for distribution transformers. 2 

This document is also available on the 

aforementioned DOE Web site. On 

November 1, 2000, the Department held 

a public meeting on the Framework 

Document to discuss the proposed 

analytical framework. Manufacturers, 

trade associations, electric utilities, 

environmental advocates, regulators, 

and other interested parties attended the 

Framework Document meeting. The 

major issues discussed were: Definition 

of covered transformer products, 

definition of product classes, possible 

proprietary (patent) issues regarding 

amorphous material, ties between 

efficiency improvements and 

installation costs, baseline and possible 

higher efficiency levels, base case trends 

(Le., trends absent regulation), 

transformer costs versus transformer 

prices, appropriate Lee subgroups, Lee 

methods (e.g., total owning cost (TOe)), 

loading levels, utility impact analysis 

vis-a-vis deregulation, scope of 

environmental assessment, and 

harmonization of standards with other 

countries. 

Stakeholder comments submitted 

during the Framework Document 

comment period elaborated on the 

issues raised at the meeting and also 

addressed the following issues: Options 

for the screening analysis, approaches 

for the engineering analysis, discount 

rates, electricity prices, the number and 

basis for the efficiency levels to be 

analyzed, the national energy savings 

(NES) and NPV analyses, the analysis of 

the effects of a potential standard on 

employment, the manufacturer impact 

analysis (MIA), and the timing of the 

analyses. 

As part of the information gathering 

and sharing process, the Department 

met with manufacturers of liquidimmersed and dry-type distribution 

transformers during the first quarter of 

2002. The Department met with 

companies that produced all types of 

distribution transformers, ranging from 

small to large manufacturers, and 

including both NEMA and non-NEMA 

members. The Department had three 

objectives for these meetings: (1) Solicit 

feedback on the methodology and 

findings presented in the draft 

engineering analysis update report that 

the Department posted on its Web site 

December 17,2001, (2) obtain 

information and comments on 

2 The Department published a notice of 

availability of the Framework Document in the 

Federal Register. 65 FR 59761 (October 6. 2000). 

The Framework Document itself is available on the 

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

buildingslappliance_standardslcommerciollpdfsl 

transJramework.pdf. 

production costs and manufacturing 

processes presented in the draft 

engineering analysis update report, and 

(3) provide to manufacturers an 

opportunity, early in the rulemaking 

process, to express specific concerns to 

the Department. 

Seeking early and frequent 

consultation with stakeholders, the 

Department posted draft reports on its 

website as it prepared for the 

publication of the ANOPR. The reports 

included draft screening analysis 

findings, and draft engineering analysis 

and Lee analysis reports on 50 kVA 

single-phase, liquid-immersed, padmounted transformers and 300 kVA 

three-phase, medium-voltage, dry-type 

transformers. The Department also held 

a live, online Web cast on October 17, 

2002, giving an overview of the Lee 

analysis and a tutorial on the use of the 

Lee spreadsheet. The Department 

received comments from stakeholders 

on all the draft publications, which 

helped improve the quality of the 

analysis included in the ANOPR 

published on July 29, 2004. 69 FR 

45376. 

In the ANOPR, the Department 

invited stakeholders to comment on the 

following key issues: Definition and 

coverage, product classes, engineering 

analysis inputs, design option 

combinations, the 0.75 scaling rule, 

modeling of transformer load profiles, 

distribution chain markups, discount 

rate selection and use, baseline 

determination through purchase 

evaluation formulae, electricity prices, 

load growth over time, life-cycle cost 

subgroups, and utility deregulation 

impacts. 

In preparation for the September 28, 

2004, ANOPR public meeting, the 

Department held a Web cast on August 

10, 2004, to acquaint stakeholders with 

the analytical tools (spreadsheets) and 

other material published the previous 

month. During the ANOPR comment 

period, which ended on November 9, 

2004, stakeholders submitted comments 

on the 13 issues listed above, as well as 

on other issues. These comments are 

discussed in section IV of this NOPR. 

On August 5, 2005, the Department 

posted on its Web site several draft 

NOPR analyses for early public review, 

including draft technical support 

document (TSD) chapters on the 

engineering analysis, the energy use and 

end-use load characterization, the 

markups for equipment price 

determination, the Lee and payback 

period analyses, the shipments analysis, 

the national impact analysis, and the 

MIA. The Department also posted draft 

NOPR spreadsheets for the engineering 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44361

analysis, LCC analysis, national impact

analysis, and MIA on its Web site.

On August 8, 2005, President Bush

signed into law EPACT 2005, Public

Law 109-58. Section 135(c)(4) of this

Act establishes minimum efficiency

levels for low-voltage, dry-type

transformers manufactured, or imported

into the U.S., on or after January 1,

2007. (42 U.S.C. 6295(y)) The levels are

those appearing in Table 4-2 of NEMA

TP 1-2002, Guide for Determining

Energy Efficiency for Distribution

Transformers. The Department

incorporated this standard along with

efficiency standards for several other

products and equipment in a Federal

Register Notice. 70 FR 60407 (October

18, 2005). Because EPACT 2005

established standards for low-voltage,

dry-type distribution transformers, the

Department is no longer considering

standards for the single- and threephase, low-voltage dry-type distribution

transformers in this rulemaking.

In conjunction with this NOPR, the

Department also published on its

website the complete TSD and several

spreadsheets. The TSD contains

technical documentation of each

analysis conducted under this

rulemaking, providing specific

information on the methodology and

results. The spreadsheets, discussed in

the relevant TSD chapters, represent the

analytical tools and results that support

today's proposed rule. The engineering

analysis spreadsheets represent the

Department's design database, providing

the cost-efficiency relationships for the

10 specific distribution transformer

units analyzed-five liquid-immersed

and five medium-voltage, dry-type

units. The LCC spreadsheet calculates

the LCC and payback periods at six

standard levels for these representative

units. The national impact analysis

spreadsheet tool calculates impacts of

efficiency standards on distribution

transformer shipments, as well as the

NES and NPV of the standard levels

considered. The MIA spreadsheet

evaluates the financial impact of

standards on distribution transformer

manufacturers. All of these spreadsheet

tools are posted on the Department's

Web site, along with the complete

NOPR TSD, at http://

www. eere. en ergy.gov/buildings/

appliance-standards/commercial/

distribution_transform ers_draft

_analysis_nopr.html.

3. Process Improvement

The "Process Rule," Procedures,

Interpretations and Policies for

Consideration of New or Revised Energy

Conservation Standards for Consumer

Products, Title 10 CFR Part 430, Subpart

C, Appendix A, applies to the

development of energy-efficiency

standards for consumer products. While

distribution transformers are considered

a commercial product, the Department

decided to apply some of the provisions

of the "Process Rule" to this

rulemaking.

In today's notice, the Department

describes the framework and

methodologies for developing the

proposed standards. The framework and

methodologies reflect improvements

made, and steps taken, in accordance

with the Process Rule, including DOE's

use of economic models and analytical

tools. Since the rulemaking process is

dynamic, if timely new data, models, or

tools that enhance the development of

standards become available, the

Department will incorporate them into

the rulemaking.

III. General Discussion

A. Test Procedures

Section 7(b) of the Process Rule

requires that the Department propose

necessary modifications to the test

procedure for a product before issuing a

NOPR concerning efficiency standards

for that product. Section 7(c) of the

Process Rule states that DOE will issue

a final, modified test procedure prior to

issuing a proposed rule for energy

conservation standards. The test

procedure for distribution transformers

was published as a final rule on April

27, 2006. 71 FR 24972.

B. Technological Feasibility

1. General

The Department considers design

options technologically feasible if they

are in use by the respective industry or

if research has progressed to the

development of a working prototype.

The Process Rule sets forth a definition

of technological feasibility as follows:

"Technologies incorporated in

commercially available products or in

working prototypes will be considered

technologically feasible." 10 CFR Part

430, Subpart C, Appendix A, section

4(a)(4)(i).

In each standards rulemaking, the

Department conducts a screening

analysis, which is based on information

gathered regarding existing technology

options and prototype designs. In

consultation with manufacturers, design

engineers, and other stakeholders, the

Department develops a list of design

options for consideration in the

rulemaking. Once the Department has

determined that a particular design

option is technologically feasible, it

then further evaluates each design

option in light of the other three criteria

in the Process Rule. 10 CFR Part 430,

Subpart C, Appendix A, section 4(a)(3)

and (4). The three additional criteria are:

(a) Practicability to manufacture, install,

or service, (b) adverse impacts on

product utility or availability, or (c)

health or safety concerns that cannot be

resolved. 10 CFR Part 430, Subpart C,

Appendix A, section 4(a). All design

options that pass these screening criteria

are candidates for further assessment.

As discussed in the ANOPR for this

rulemaking, the Department is not

considering the following design

options because they do not meet one or

more of the screening criteria: Silver as

a conductor material, high-temperature

superconductors, amorphous core

material in stacked core configuration,

carbon composite materials for heat

removal, high-temperature insulating

material, and solid-state (power

electronics) technology. 69 FR 45387.

For the NOPR, there were no changes to

the list of technology options screened

out of the ANOPR analysis. Discussion

of the application of the screening

analysis criteria to the design options

appears in Chapter 4 of the TSD.

The Department believes that all of

the efficiency levels evaluated in today's

notice are technologically feasible. The

technologies incorporated in the

transformer design database have all

been used (or are being used) in

commercially available products or

working prototypes. The designs all

incorporate core steel and conductor

types that are commercially available in

today's transformer materials supply

market. Any one manufacturer may not

be using all the materials considered by

the Department for a given model

analyzed, but these materials could be

purchased from multiple suppliers

today if design changes warranted it.

In addition, to prepare transformer

designs for evaluation, DOE used

transformer design software that is also

used by manufacturers in the U.S. and

abroad. The Department evaluated the

transformer design software by

comparing the software's designs

against six transformers it purchased,

tested, and disassembled. For these

units, the software accurately predicted

the performance and manufacturer

selling prices when using the same

material cost, labor cost, and

manufacturer markup assumptions that

were used in the engineering analysis

for the NOPR (see TSD Chapter 5,

section 5.7).

For liquid-immersed distribution

transformers, the designs prepared by

the software were all wound-core

designs. The least efficient design used

M6 core steel and the most efficient

used amorphous material. All designs

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register IVoI. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 44361 

analysis, LCC analysis, national impact 

analysis, and MIA on its Web site. 

On August 8,2005, President Bush 

signed into law EPACT 2005, Public 

Law 109-58. Section 135(c)(4) ofthis 

Act establishes minimum efficiency 

levels for low-voltage, dry-type 

transformers manufactured, or imported 

into the U.S., on or after January 1, 

2007. (42 U.S.C. 6295(y)) The levels are 

those appearing in Table 4-2 of NEMA 

TP 1-2002, Guide for Determining 

Energy Efficiency for Distribution 

Transformers. The Department 

incorporated this standard along with 

efficiency standards for several other 

products and equipment in a Federal 

Register Notice. 70 FR 60407 (October 

18,2005). Because EPACT 2005 

established standards for low-voltage, 

dry-type distribution transformers, the 

Department is no longer considering 

standards for the single- and threephase, low-voltage dry-type distribution 

transformers in this rulemaking. 

In conjunction with this NOPR, the 

Department also published on its 

website the complete TSD and several 

spreadsheets. The TSD contains 

technical documentation of each 

analysis conducted under this 

rulemaking, providing specific 

information on the methodology and 

results. The spreadsheets, discussed in 

the relevant TSD chapters, represent the 

analytical tools and results that support 

today's proposed rule. The engineering 

analysis spreadsheets represent the 

Department's design database, providing 

the cost-efficiency relationships for the 

10 specific distribution transformer 

units analyzed-five liquid-immersed 

and five medium-voltage, dry-type 

units. The LCC spreadsheet calculates 

the LCC and payback periods at six 

standard levels for these representative 

units. The national impact analysis 

spreadsheet tool calculates impacts of 

efficiency standards on distribution 

transformer shipments, as well as the 

NES and NPV of the standard levels 

considered. The MIA spreadsheet 

evaluates the financial impact of 

standards on distribution transformer 

manufacturers. All of these spreadsheet 

tools are posted on the Department's 

Web site, along with the complete 

NOPR TSD, at http:// 

www.eere.energy.gov/buildings/ 

appliance_standards/ commercial/ 

distribution_transformers_draft 

_analysis_nopr.html. 

3. Process Improvement 

The "Process Rule," Procedures, 

Interpretations and Policies for 

Consideration of New or Revised Energy 

Conservation Standards for Consumer 

Products, Title 10 CFR Part 430, Subpart 

C, Appendix A, applies to the 

development of energy-efficiency 

standards for consumer products. While 

distribution transformers are considered 

a commercial product, the Department 

decided to apply some of the provisions 

ofthe "Process Rule" to this 

rulemaking. 

In today's notice, the Department 

describes the framework and 

methodologies for developing the 

proposed standards. The framework and 

methodologies reflect improvements 

made, and steps taken, in accordance 

with the Process Rule, including DOE's 

use of economic models and analytical 

tools. Since the rulemaking process is 

dynamic, if timely new data, models, or 

tools that enhance the development of 

standards become available, the 

Department will incorporate them into 

the rule making. 

III. General Discussion 

A. Test Procedures 

Section 7(b) ofthe Process Rule 

requires that the Department propose 

necessary modifications to the test 

procedure for a product before issuing a 

NOPR concerning efficiency standards 

for that product. Section 7(c) of the 

Process Rule states that DOE will issue 

a final, modified test procedure prior to 

issuing a proposed rule for energy 

conservation standards. The test 

procedure for distribution transformers 

was published as a final rule on April 

27,2006. 71 FR 24972. 

B. Technological Feasibility 

1. General 

The Department considers design 

options technologically feasible if they 

are in use by the respective industry or 

if research has progressed to the 

development of a working prototype. 

The Process Rule sets forth a definition 

of technological feasibility as follows: 

"Technologies incorporated in 

commercially available products or in 

working prototypes will be considered 

technologically feasible." 10 CFR Part 

430, Subpart C, Appendix A, section 

4(a)(4)(i). 

In each standards rulemaking, the 

Department conducts a screening 

analysis, which is based on information 

gathered regarding existing technology 

options and prototype designs. In 

consultation with manufacturers, design 

engineers, and other stakeholders, the 

Department develops a list of design 

options for consideration in the 

rulemaking. Once the Department has 

determined that a particular design 

option is technologically feasible, it 

then further evaluates each design 

option in light of the other three criteria 

in the Process Rule. 10 CFR Part 430, 

Subpart C, Appendix A, section 4(a)(3) 

and (4). The three additional criteria are: 

(a) Practicability to manufacture, install, 

or service, (b) adverse impacts on 

product utility or availability, or (c) 

health or safety concerns that cannot be 

resolved. 10 CFR Part 430, Subpart C, 

Appendix A, section 4(a). All design 

options that pass these screening criteria 

are candidates for further assessment. 

As discussed in the ANOPR for this 

rulemaking, the Department is not 

considering the following design 

options because they do not meet one or 

more of the screening criteria: Silver as 

a conductor material, high-temperature 

superconductors, amorphous core 

material in stacked core configuration, 

carbon composite materials for heat 

removal, high-temperature insulating 

material, and solid-state (power 

electronics) technology. 69 FR 45387. 

For the NOPR, there were no changes to 

the list of technology options screened 

out of the ANOPR analysis. Discussion 

of the application of the screening 

analysis criteria to the design options 

appears in Chapter 4 of the TSD. 

The Department believes that all of 

the efficiency levels evaluated in today's 

notice are technologically feasible. The 

technologies incorporated in the 

transformer design database have all 

been used (or are being used) in 

commercially available products or 

working prototypes. The designs all 

incorporate core steel and conductor 

types that are commercially available in 

today's transformer materials supply 

market. Anyone manufacturer may not 

be using all the materials considered by 

the Department for a given model 

analyzed, but these materials could be 

purchased from multiple suppliers 

today if design changes warranted it. 

In addition, to prepare transformer 

designs for evaluation, DOE used 

transformer design software that is also 

used by manufacturers in the U.S. and 

abroad. The Department evaluated the 

transformer design software by 

comparing the software's designs 

against six transformers it purchased, 

tested, and disassembled. For these 

units, the software accurately predicted 

the performance and manufacturer 

selling prices when using the same 

material cost, labor cost, and 

manufacturer markup assumptions that 

were used in the engineering analysis 

for the NOPR (see TSD Chapter 5, 

section 5.7). 

For liquid-immersed distribution 

transformers, the designs prepared by 

the software were all wound-core 

designs. The least efficient design used 

M6 core steel and the most efficient 

used amorphous material. All designs 
44362 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

contained in the Department's design

database could be built today. For

medium-voltage, dry-type transformers,

DOE used commercially available core

steels, ranging from M6 through

domain-refined 9-mil (0.009 inch) high

permeability, grain-oriented steel (H-O

DR). Core-construction techniques

included butt-lap, mitered, and

cruciform construction. The conductors

and insulation types used were all

conventional, and are commercially

available in distribution transformers

today. Thus, the Department believes

that all the efficiency levels discussed in

today's proposed rule are

technologically feasible.

2. Maximum Technologically Feasible

Levels

In developing today's proposed

standards, the Department followed the

provisions of 42 U.S.C. 6295(p)(2),

which states that, when the Department

proposes to adopt, or to decline to

adopt, an amended or new standard for

each type (or class) of covered product,

"the Secretary shall determine the

maximum improvement in energy

efficiency or maximum reduction in

energy use that is technologically

feasible." The Department determined

the maximum technologically feasible

("max-tech") efficiency level in the

engineering analysis (see TSD Chapter

5) using the most efficient materials not

screened out and applying design

parameters that drove the transformer

design software to create designs at the

highest efficiencies achievable. The

Department then used these highestefficiency designs to establish the maxtech level for the LCC analysis (see TSD

Chapter 8). In the national impact

analysis (see TSD Chapter 10), the

Department then scaled these max-tech

efficiencies to the other kVA ratings

within a given design line, establishing

max-tech efficiencies at all the

distribution transformer kVA ratings.

Tables 111.1 and 111.2 provide the

complete list of max-tech efficiency

levels considered for all kVA ratings

within each product class.

TABLE 111.1.-MAX-TECH LEVELS FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS

Single-phase Three-phase

kVA Efficiency kVA Efficiency

(/°)

10 .................................................................................. 99.32 15 ................................................................................. 99.31

15 .................................................................................. 99.39 30 ................................................................................. 99.42

25 .................................................................................. 99.46 45 ................................................................................. 99.47

37.5 ............................................................................... 99.51 75 ................................................................................. 99.54

50 .................................................................................. 99.59 112.5 :........................................................................... 99.58

75 .................................................................................. 99.59 150 ............................................................................... 99.61

100 ................................................................................ 99.62 225 ............................................................................... 99.65

167 ..... ...................................................................... 99.66 300 ............................................................................... 99.67

250 ................................................................................ 99.70 500 ............................................................................... 99.71

333 ............ ............................................................. 99.72 750 ............................................................................... 99.66

500 ................................................................................ 99.75 1000 ............................................................................. 99.68

667 ................................................................................ 99.77 1500 ............................................................................. 99.71

833 ................................................................................ 99.78 2000 ............................................................................. 99.73

2500 ............................................................................. 99.74

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; 71 FR 24972.

TABLE 111.2.-MAX.-TECH LEVELS FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS

Single-phase Three-phase

BIL

kVA

20-45 kV

efficiency

(%)

46-95 kV

efficiency

(%)

>96 kV

(%)

kVA 20-45 kV

efficiency

(%)

46-95 kV

efficiency

(%)

?96 kV

efficiency

(%)

15 .......................... 99.05 98.54 ... ..... 15.......................... 15 98.75 98.08

25 .......................... 99 .17 98.71 ........ 30 .......................... 98.95 98.38

37.5 ....................... 99.25 98.84 ......... 45 .......................... 99 .05 98.54

50 .......................... 99.30 98.92

.

......... 75 .......................... 99.17 98.71

75 .......................... 99.37 99.02 9.22 112 .5..................... 99.25 98.84 ........................

100 ........................ 99.41 99.09 9.28 150 ........................ 99.30 98.92 ........................

167 ........................ 99 .48 99.20 99.36 225 ........................ 99.37 99.02 99.22

250 ........................ 99.42 99.42 99.42 300 ........................ 99.41 99.09 99.28

333 ........................ 99.46 99.46 99.46 500 ........................ 99.48 99.20 99.36

500 ........................ 99.51 99.51 99.52 750........................ 99.42 99.42 99.42

667 ........................ 99.54 99.54 99.55 1000 ...................... 99.46 99.46 99.46

833 ........................ 99.57 99 . 57 99 .57 1500 ...................... 99.51 99.51 99.52

2000 ............. ......... 99.54 99.54 99.55

2500 ...................... 99.57 99.57 99.57

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; 71 FR 24972.

 EE-RM/STD-00-550 COMMENT 91.1

44362 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

contained in the Department's design 

database could be built today. For 

medium-voltage, dry-type transformers, 

DOE used commercially available core 

steels, ranging from M6 through 

domain-refined 9-mil (0.009 inch) high 

permeability, grain-oriented steel (H-O 

DR). Core-construction techniques 

included butt-lap, mitered, and 

cruciform construction. The conductors 

and insulation types used were all 

conventional, and are commercially 

available in distribution transformers 

today. Thus, the Department believes 

that all the efficiency levels discussed in 

today's proposed rule are 

technologically feasible. 

2. Maximum Technologically Feasible 

Levels 

In developing today's proposed 

standards, the Department followed the 

provisions of 42 U.S.c. 6295(p)(2), 

which states that, when the Department 

proposes to adopt, or to decline to 

adopt, an amended or new standard for 

each type (or class) of covered product, 

"the Secretary shall determine the 

maximum improvement in energy 

efficiency or maximum reduction in 

energy use that is technologically 

feasible." The Department determined 

the maximum technologically feasible 

("max-tech") efficiency level in the 

engineering analysis (see TSD Chapter 

5) using the most efficient materials not 

screened out and applying design 

parameters that drove the transformer 

design software to create designs at the 

highest efficiencies achievable. The 

Department then used these highestefficiency designs to establish the maxtech level for the LCC analysis (see TSD 

Chapter 8). In the national impact 

analysis (see TSD Chapter 10), the 

Department then scaled these max-tech 

efficiencies to the other kVA ratings 

within a given design line, establishing 

max-tech efficiencies at all the 

distribution transformer kVA ratings. 

Tables III.l and III.2 provide the 

complete list of max-tech efficiency 

levels considered for all kVA ratings 

within each product class. 

TABLE 1I1.1.-MAX-TECH LEVELS FOR liQUID-IMMERSED DISTRIBUTION TRANSFORMERS 

Single-phase 

kVA 

10 ................................................................................. . 

15 ................................................................................. . 

25 ................................................................................. . 

37.5 .............................................................................. . 

50 ................................................................................. . 

75 ................................................................................. . 

100 ............................................................................... . 

167 ............................................................................... . 

250 ............................................................................... . 

333 ............................................................................... . 

500 ............................................................................... . 

667 ............................................................................... . 

833 ............................................................................... . 

Efficiency 

(%) 

99.32 

99.39 

99.46 

99.51 

99.59 

99.59 

99.62 

99.66 

99.70 

99.72 

99.75 

99.77 

99.78 

Three-phase 

kVA 

15 ................................................................................ . 

30 ................................................................................ . 

45 ................................................................................ . 

75 ................................................................................ . 

112.5 : .......................................................................... . 

150 .............................................................................. . 

225 .............................................................................. . 

300 .............................................................................. . 

500 .............................................................................. . 

750 .............................................................................. . 

1000 ............................................................................ . 

1500 ............................................................................ . 

2000 ............................................................................ . 

2500 ............................................................................ . 

Efficiency 

(%) 

99.31 

99.42 

99.47 

99.54 

99.58 

99.61 

99.65 

99.67 

99.71 

99.66 

99.68 

99.71 

99.73 

99.74 

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; 71 FR 24972. 

TABLE 1I1.2.-MAX.-TECH LEVELS FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS 

Single-phase 

BIL 

kVA 

20-45 kV 

efficiency 

(%) 

15.......................... 99.05 

25 .......................... 99.17 

37.5....................... 99.25 

50.......................... 99.30 

75.......................... 99.37 

100 ........................ 99.41 

167 ........................ 99.48 

250 ........................ 99.42 

333 ........................ 99.46 

500........................ 99.51 

667........................ 99.54 

833........................ 99.57 

46-95 kV 

efficiency 

(%) 

98.54 

98.71 

98.84 

98.92 

99.02 

99.09 

99.20 

99.42 

99.46 

99.51 

99.54 

99.57 

;::96 kV 

(%) 

........................ 

........................ 

........................ 

........................ 

99.22 

99.28 

99.36 

99.42 

99.46 

99.52 

99.55 

99.57 

kVA 

15 . ......................... 

30 . ......................... 

45 . ......................... 

75 . ......................... 

112.5 ..................... 

150 ........................ 

225 ........................ 

300 ........................ 

500 ........................ 

750 ........................ 

1000 ...................... 

1500 ...................... 

2000 ...................... 

2500 ...................... 

Three-phase 

20-45 kV 

efficiency 

(%) 

98.75 

98.95 

99.05 

99.17 

99.25 

99.30 

99.37 

99.41 

99.48 

99.42 

99.46 

99.51 

99.54 

99.57 

46-95 kV 

efficiency 

(%) 

98.08 

98.38 

98.54 

98.71 

98.84 

98.92 

99.02 

99.09 

99.20 

99.42 

99.46 

99.51 

99.54 

99.57 

;::96 kV 

efficiency 

(%) 

. ....................... 

. ....................... 

. ....................... 

. ....................... 

.. ...................... 

. ....................... 

99.22 

99.28 

99.36 

99.42 

99.46 

99.52 

99.55 

99.57 

Note: BIL means basic impulse insulation level. 

Note: All efficien.cy values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, 

Subpart K, AppendiX A; 71 FR 24972. 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44363

C. Energy Savings

One of the criteria that govern the

Department's adoption of standards for

distribution transformers is that the

standard must result in "significant"

energy savings. (42 U.S.C. 6317(a))

While the term "significant" is not

defined by EPCA, a U.S. Court of

Appeals, in Natural Resources Defense

Council v. Herrington, 768 F.2d 1355,

1373 (D.C. Cir. 1985), indicated that

Congress intended "significant" energy

savings in a similar context in Section

325 of the Act to be savings that were

not "genuinely trivial." The energy

savings for all of the trial standard levels

considered in this rulemaking are

nontrivial, and therefore the Department

considers them "significant" as required

by 42 U.S.C. 6317.

D. Economic Justification

As noted earlier, EPCA provides

seven factors to be evaluated in

determining whether an energy

conservation standard for distribution

transformers is economically justified.

The following discusses how the

Department has addressed each of those

seven factors thus far in this

rulemaking. (42 U.S.C. 6295(o)(2)(B)(i))

1. Economic Impact on Manufacturers

and Commercial Consumers

The Process Rule established

procedures, interpretations, and policies

to guide the Department in the

consideration of new or revised

appliance efficiency standards. The

provisions of the rule have direct

bearing on the implementation of the

MIA. First, the Department used an

annual-cash-flow approach in

determining the quantitative impacts of

a new or amended standard on

manufacturers. This included both a

short-term assessment based on the cost

and capital requirements during the

period between the announcement of a

regulation and the time when the

regulation comes into effect, and a longterm assessment. Impacts analyzed

include industry NPV, cash flows by

year, changes in revenue and income,

and other measures of impact, as

appropriate. Second, the Department

analyzed and reported the impacts on

different types of manufacturers, with

particular attention to impacts on small

manufacturers. Third, the Department

considered the impact of standards on

domestic manufacturer employment,

manufacturing capacity, plant closures,

and loss of capital investment. Finally,

the Department took into account

cumulative impacts of different DOE

regulations on manufacturers.

For commercial consumers, measures

of economic impact are the changes in

installed (first) cost and annual

operating costs. To assess the impact on

first cost, the Department considered the

percent increase in the consumer

equipment cost before installation. To

assess the impact on life-cycle costs,

which include both consumer

equipment costs and annual operating

costs, the Department conducted an LCC

analysis of the equipment at each

candidate standard level (CSL) (see

below).

2. Life-Cycle Costs

The LCC is the sum of the purchase

price, including the installation, and the

operating expense-including operating

energy consumption, maintenance, and

repair expenditures-discounted over

the lifetime of the equipment. To

determine the purchase price including

installation, DOE estimated the markups

that are added to the manufacturer

selling price by distributors and

contractors, and estimated installation

costs from an analysis of transformer

installation cost estimates for a wide

range of weights and sizes. The

Department assumed that maintenance

and repair costs are not dependent on

transformer efficiency. In estimating

operating energy costs, DOE used the

full range of commercial consumer

marginal energy prices, which are the

energy prices that correspond to

incremental changes in energy use.

For each distribution transformer

representative unit, the Department

calculated both LCC and LCC savings

from a base-case scenario for six

candidate standard efficiency levels.

The six candidate standard levels were

chosen to correspond to the following:

® NEMA TP 1-2002;

® 1/3 of efficiency difference between

TP 1 and minimum LCC;

® 2/3 of efficiency difference between

TP 1 and minimum LCC;

® Minimum LCC;

• Maximum energy savings with no

change in LCC; and

® Maximum technologically feasible.

In order to calculate the appropriate

efficiency levels for kVA ratings that

were not analyzed (i.e., all the kVA

ratings other than the ten representative

units), the Department applied a scaling

rule to extrapolate the findings on the

ten representative units to these other

ratings. For information on the scaling

rule, see section IV.B.1 and TSD Chapter

5, section 5.2.2.

The Department presents the

calculated LCC savings as a distribution,

with a mean value and range. The

Department used a distribution of

consumer real discount rates for the

calculations, with mean values ranging

from 3.3 to 7.5 percent, specific to the

cost of capital faced by purchasers of the

representative units. Chapter 8 of the

TSD contains the details of the LCC

calculations. The LCC is one of the

factors DOE considers in determining

the economic justification for a new or

amended standard. (See 42 U.S.C.

6295(o)(2)(B)(i)(II))

3. Energy Savings

While significant conservation of

energy is a separate statutory

requirement for imposing an energy

conservation standard, in determining

the economic justification of a standard,

the Department considers the total

projected energy savings that are

expected to result directly from the

standard. (See 42 U.S.C.

6295(o)(2)(B)(i)(III)) The Department

used the NES spreadsheet results in its

consideration of total projected savings.

The savings figures are discussed in

section V.A.3 of this notice.

4. Lessening of Utility or Performance of

Equipment

In establishing classes of products,

and in evaluating design options and

the impact of potential standard levels,

the Department avoided having new

standards for distribution transformers

that lessen the utility or performance of

the equipment under consideration in

this rulemaking. None of the proposed

trial standard levels reduces the utility

or performance of distribution

transformers. (See 42 U.S.C.

6295(o)(2)(B)(i)(IV)) The Department's

engineering options do not change the

utility and performance of distribution

transformers. The impact of any

increase in transformer weight

associated with efficiency

improvements is captured by the

economic analysis. Specifically,

installation costs for pole-mounted

transformers include estimates of

stronger pole and pole change-out costs

that may be incurred with heavier, more

efficient transformers.

5. Impact of Any Lessening of

Competition

The Department considers any

lessening of competition that is likely to

result from standards. Accordingly, DOE

has written to the Attorney General to

request that the Attorney General

transmit to the Secretary, not later than

60 days after the publication of this

proposed rule, a written determination

of the impact, if any, of any lessening

of competition likely to result from the

proposed standard, together with an

analysis of the nature and extent of such

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44363 

C. Energy Savings 

One of the criteria that govern the 

Department's adoption of standards for 

distribution transformers is that the 

standard must result in "significant" 

energy savings. (42 U.S.c. 6317(a)) 

While the term "significant" is not 

defined by EPCA, a u.s. Court of 

Appeals, in Natural Resources Defense 

Council v. Herrington, 768 F.2d 1355, 

1373 (D.C. Cir. 1985), indicated that 

Congress intended "significant" energy 

savings in a similar context in Section 

325 of the Act to be savings that were 

not "genuinely trivial." The energy 

savings for all of the trial standard levels 

considered in this rulemaking are 

nontrivial, and therefore the Department 

considers them "significant" as required 

by 42 U.S.c. 6317. 

D. Economic Justification 

As noted earlier, EPCA provides 

seven factors to be evaluated in 

determining whether an energy 

conservation standard for distribution 

transformers is economically justified. 

The following discusses how the 

Department has addressed each of those 

seven factors thus far in this 

rulemaking. (42 U.S.C. 6295(0)(2)(B)(i)) 

1. Economic Impact on Manufacturers 

and Commercial Consumers 

The Process Rule established 

procedures, interpretations, and policies 

to guide the Department in the 

consideration of new or revised 

appliance efficiency standards. The 

provisions of the rule have direct 

bearing on the implementation of the 

MIA. First, the Department used an 

annual-cash-flow approach in 

determining the quantitative impacts of 

a new or amended standard on 

manufacturers. This included both a 

short-term assessment based on the cost 

and capital requirements during the 

period between the announcement of a 

regulation and the time when the 

regulation comes into effect, and a longterm assessment. Impacts analyzed 

include industry NPV, cash flows by 

year, changes in revenue and income, 

and other measures of impact, as 

appropriate. Second, the Department 

analyzed and reported the impacts on 

different types of manufacturers, with 

particular attention to impacts on small 

manufacturers. Third, the Department 

considered the impact of standards on 

domestic manufacturer employment, 

manufacturing capacity, plant closures, 

and loss of capital investment. Finally, 

the Department took into account 

cumulative impacts of different DOE 

regulations on manufacturers. 

For commercial consumers, measures 

of economic impact are the changes in 

installed (first) cost and annual 

operating costs. To assess the impact on 

first cost, the Department considered the 

percent increase in the consumer 

equipment cost before installation. To 

assess the impact on life-cycle costs, 

which include both consumer 

equipment costs and annual operating 

costs, the Department conducted an LCC 

analysis ofthe equipment at each 

candidate standard level (CSL) (see 

below). 

2. Life-Cycle Costs 

The LCC is the sum of the purchase 

price, including the installation, and the 

operating expense-including operating 

energy consumption, maintenance, and 

repair expenditures-discounted over 

the lifetime of the equipment. To 

determine the purchase price including 

installation, DOE estimated the markups 

that are added to the manufacturer 

selling price by distributors and 

contractors, and estimated installation 

costs from an analysis of transformer 

installation cost estimates for a wide 

range of weights and sizes. The 

Department assumed that maintenance 

and repair costs are not dependent on 

transformer efficiency. In estimating 

operating energy costs, DOE used the 

full range of commercial consumer 

marginal energy prices, which are the 

energy prices that correspond to 

incremental changes in energy use. For each distribution transformer 

representative unit, the Department 

calculated both LCC and LCC savings 

from a base-case scenario for six 

candidate standard efficiency levels. 

The six candidate standard levels were 

chosen to correspond to the following: CD NEMA TP 1-2002; CD V3 of efficiency difference between 

TP 1 and minimum LCC; .. 2fa of efficiency difference between 

TP 1 and minimum LCC; .. Minimum LCC; 

.. Maximum energy savings with no 

change in LCC; and .. Maximum technologically feasible. 

In order to calculate the appropriate 

efficiency levels for kVA ratings that 

were not analyzed (j.e., all the kVA 

ratings other than the ten representative 

units), the Department applied a scaling 

rule to extrapolate the findings on the 

ten representative units to these other 

ratings. For information on the scaling 

rule, see section IV.B.l and TSD Chapter 

5, section 5.2.2. 

The Department presents the 

calculated LCC savings as a distribution, 

with a mean value and range. The 

Department used a distribution of 

consumer real discount rates for the 

calculations, with mean values ranging 

from 3.3 to 7.5 percent, specific to the 

cost of capital faced by purchasers of the 

representative units. Chapter 8 of the 

TSD contains the details of the LCC 

calculations. The LCC is one of the 

factors DOE considers in determining 

the economic justification for a new or 

amended standard. (See 42 U.S.C. 

6295(0 )(2)(B)(i)(II)) 

3. Energy Savings 

While significant conservation of 

energy is a separate statutory 

requirement for imposing an energy 

conservation standard, in determining 

the economic justification of a standard, 

the Department considers the total 

projected energy savings that are 

expected to result directly from the 

standard. (See 42 U.S.C. 

6295(0)(2)(B)(i)(III)) The Department 

used the NES spreadsheet results in its 

consideration of total projected savings. 

The savings figures are discussed in 

section V.A.3 of this notice. 

4. Lessening of Utility or Performance of 

Equipment 

In establishing classes of products, 

and in evaluating design options and 

the impact of potential standard levels, 

the Department avoided having new 

standards for distribution transformers 

that lessen the utility or performance of 

the equipment under consideration in 

this rulemaking. None of the proposed 

trial standard levels reduces the utility 

or performance of distribution 

transformers. (See 42 U.S.c. 

6295(0)(2)(B)(i)(IV)) The Department's 

engineering options do not change the 

utility and performance of distribution 

transformers. The impact of any 

increase in transformer weight 

associated with efficiency 

improvements is captured by the 

economic analysis. Specifically, 

installation costs for pole-mounted 

transformers include estimates of 

stronger pole and pole change-out costs 

that may be incurred with heavier, more 

efficient transformers. 

5. Impact of Any Lessening of 

Competition 

The Department considers any 

lessening of competition that is likely to 

result from standards. Accordingly, DOE 

has written to the Attorney General to 

request that the Attorney General 

transmit to the Secretary, not later than 

60 days after the publication of this 

proposed rule, a written determination 

of the impact, if any, of any lessening 

of competition likely to result from the 

proposed standard, together with an 

analysis of the nature and extent of such 
44364 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

impact. (See 42 U.S.C.

6295(o)(2)(B)(i)(V) and (B)(ii))

6. Need of the Nation To Conserve

Energy

The non-monetary benefits of the

proposed standard are likely to be

reflected in improvements to the

security and reduced reliability costs of

the Nation's energy system-namely,

reductions in the overall demand for

energy will result in reduced costs for

maintaining reliability of the Nation's

electricity system. The Department

conducts a utility impact analysis to

show the reduction in installed

generation capacity requirements.

Reduced power demand (including peak

power demand) generally reduces the

costs of maintaining the security and

reliability of the energy system.

The Department has determined that

today's proposed standard should result

in reductions in greenhouse gas

emissions. The Department quantified a

range of primary energy conversion

factors and estimated the emissions

reductions associated with the

generation displaced by energyefficiency standards. The environmental

effects from each trial standard level for

this equipment are reported in the TSD

environmental assessment. (See 42

U.S.C. 6295(o)(2)(B)(i)(VI))

7. Other Factors

The Secretary of Energy, in

determining whether a standard is

economically justified, considers any

other factors that the Secretary deems to

be relevant. (See 42 U.S.C.

6295(o)(2)(B)(i)(VII)) For today's

proposed standard, the Secretary took

into consideration a factor relating to

several comments received at the

ANOPR public meeting, during the

comment period following the meeting,

and in the MIA interviews. Stakeholders

expressed concern about the increasing

cost of raw materials for building

transformers, the volatility of material

prices, and the cumulative effect of

material price increases on the

transformer industry (see section IV.B.2,

Engineering Analysis Inputs). The

Department conducted supplementary

engineering and LCC analyses using

first-quarter 2005 material prices and

considered the impacts on LCC savings

and payback periods when evaluating

the appropriate standard levels for

liquid-immersed and medium-voltage,

dry-type distribution transformers. The

results of the engineering and LCC

analyses for the first-quarter 2005

material pricing analysis are in TSD

Appendix 5C.

IV. Methodology and Discussion of

Comments

the Department divides covered

products into classes by: (a) The type of

energy used, or (b) capacity, or other

performance-related features, such as

those that affect both consumer utility

and efficiency. Different energyefficiency standards may apply to

different product classes. As discussed

in the ANOPR, the Department received

some guidance from stakeholders on

establishing appropriate product classes

for the population of distribution

transformers. 69 FR 45385. Originally,

the Department created 10 product

classes, dividing up the population of

distribution transformers by:

® Type of transformer insulationliquid-immersed or dry-type;

® Number of phases-single or three;

e Voltage class-low or medium (for

dry-type units only); and

® Basic impulse insulation level (for

medium-voltage, dry-type units only).

EPACT 2005 includes provisions

establishing energy conservation

standards for two of the Department's

product classes (PC3, low-voltage,

single-phase, dry-type and PC4, lowvoltage, three-phase, dry-type). (42

U.S.C. 6295(y)) With standards thereby

established for low-voltage, dry-type

distribution transformers, the

A. Market and Technology Assessment Department is no longer considering

1. Product Classes these two product classes for standards.

Table IV.1 presents the eight product

In general, when evaluating and classes that remain within the scope of

establishing energy-efficiency standards, this rulemaking.

TABLE IV.1.-DISTRIBUTION TRANSFORMER PRODUCT CLASSES FOR THE NOPR

PC No.* Insulation Voltage Phase BIL rating kVA range

PC1 .............................. Liquid-Immersed .......... ..................................... Single . ......................... ..................................... 10-833 kVA.

PC2 .............................. Liquid-immersed .......... ..................................... Three ........................... ..................................... 15-2500 kVA.

PC5 .............................. Dry-Type ..................... Medium ....................... Single .......................... 20-45 kV BIL .............. 15-833 kVA.

PC6 .............................. Dry-Type ..................... Medium ....................... Three ........................... 20-45 kV BIL .............. 15-2500 kVA.

PC7 .............................. Dry-Type ..................... Medium ....................... Single .......................... 46-95 kV BIL .............. 15-833 kVA.

PC8 .............................. Dry-Type ..................... Medium .......... ............. Three ........................... 46-95 kV BIL .............. 15-2500 kVA.

PC9 .............................. Dry-Type ..................... Medium .............. ......... Single . ......................... ?96 kV BIL .................. 75-833 kVA.

PC10 ............................ Dry-Type .... ................. Medium ..... .................. Three ........................... >_96 kV BIL .................. 225-2500 kVA.

*Note : Although the PC3 and PC4 product classes are no longer included in this rulemaking, for consistency with prior material published

under this rulemaking, the Department has not renumbered the liquid-immersed and medium-voltage, dry-type product classes that remain.

DOE received no comments that

requested modifications to the

Department's product classes as

proposed in the ANOPR. However,

Howard Industries commented that it

supported the independent

categorization of liquid-immersed and

dry-type transformers. It pointed out

that the applications and type of

customers for these two types of

transformers can vary widely. (Howard,

No. 70 at p. 2) The Department agrees

with this comment and continues to

treat liquid-immersed and dry-type

transformers separately in its analysis.

Concerning the use of three basic

impulse insulation level (BIL) groupings

for medium-voltage, dry-type

transformers, Federal Pacific

Transformer (FPT) noted that BIL levels

do affect cost and efficiency, and agreed

that DOE should conduct its analysis by

BIL grouping. It commented that the

efficiency levels should be modeled

according to the BIL levels as much as

possible. (FPT, No. 64 at p. 3) NEMA

commented that it was willing to change

the BIL groupings in TP 1-2002 from

two to three, so TP 1 would have the

same BIL groupings for medium-voltage,

dry-type transformers as the

Department's proposal. (NEMA, No. 60

at p. 2) The Alliance to Save Energy

(ASE) commented that the Department's

refinement of BIL classifications over

TP 1 is justified and should result in

more appropriate efficiency levels.

(ASE, No. 52 at p. 2 and No. 75 at p.

2) Finally, the Oregon Department of

Energy (ODOE) commented that it

supports the refinements that created

three BIL groupings for these

transformers. (ODOE, No. 66 at p. 2) The

Department did not receive any

comments critical of the three BIL

 EE-RM/STD-00-550 COMMENT 91.1

44364 Federal Register! Vol. 71, No. 150/ Friday, August 4, 2006/ Proposed Rules 

impact. (See 42 U.S.C. 

6295(0)(2)(B)(i)(V) and (B)(ii)) 

6. Need of the Nation To Conserve 

Energy 

The non-monetary benefits of the 

proposed standard are likely to be 

reflected in improvements to the 

security and reduced reliability costs of 

the Nation's energy system-namely, 

reductions in the overall demand for 

energy will result in reduced costs for 

maintaining reliability of the Nation's 

electricity system. The Department 

conducts a utility impact analysis to 

show the reduction in installed 

generation capacity requirements. 

Reduced power demand (including peak 

power demand) generally reduces the 

costs of maintaining the security and 

reliability of the energy system. 

The Department has determined that 

today's proposed standard should result 

in reductions in greenhouse gas 

emissions. The Department quantified a 

range of primary energy conversion 

factors and estimated the emissions 

reductions associated with the 

generation displaced by energyefficiency standards. The environmental 

effects from each trial standard level for 

this equipment are reported in the TSD 

environmental assessment. (See 42 

U.S.C. 6295(o)(2)(B)(i)(VI)) 

7. Other Factors 

The Secretary of Energy, in 

determining whether a standard is 

economically justified, considers any 

other factors that the Secretary deems to 

be relevant. (See 42 U.S.c. 

6295(0)(2)(B)(i)(VII)) For today's 

proposed standard, the Secretary took 

into consideration a factor relating to 

several comments received at the 

ANOPR public meeting, during the 

comment period following the meeting, 

and in the MIA interviews. Stakeholders 

expressed concern about the increasing 

cost of raw materials for building 

transformers, the volatility of material 

prices, and the cumulative effect of 

material price increases on the 

transformer industry (see section IV.B.2, 

Engineering Analysis Inputs). The 

Department conducted supplementary 

engineering and LCC analyses using 

first-quarter 2005 material prices and 

considered the impacts on LCC savings 

and payback periods when evaluating 

the appropriate standard levels for 

liquid-immersed and medium-voltage, 

dry-type distribution transformers. The 

results of the engineering and LCC 

analyses for the first-quarter 2005 

material pricing analysis are in TSD 

Appendix 5C. 

IV. Methodology and Discussion of 

Comments 

A. Market and Technology Assessment 

1. Product Classes 

In general, when evaluating and 

establishing energy-efficiency standards, 

the Department divides covered 

products into classes by: (a) The type of 

energy used, or (b) capacity, or other 

performance-related features, such as 

those that affect both consumer utility 

and efficiency. Different energyefficiency standards may apply to 

different product classes. As discussed 

in the ANOPR, the Department received 

some guidance from stakeholders on 

establishing appropriate product classes 

for the population of distribution 

transformers. 69 FR 45385. Originally, 

the Department created 10 product 

classes, dividing up the population of 

distribution transformers by: 

.. Type of transformer insulationliquid-immersed or dry-type; 

" Number of phases-single or three; 

.. Voltage class-low or medium (for 

dry-type units only); and 

.. Basic impulse insulation level (for 

medium-voltage, dry-type units only). 

EP ACT 2005 includes provisions 

establishing energy conservation 

standards for two of the Department's 

product classes (PC3, low-voltage, 

single-phase, dry-type and PC4, lowvoltage, three-phase, dry-type). (42 

U.S.C. 6295(y)) With standards thereby 

established for low-voltage, dry-type 

distribution transformers, the 

Department is no longer considering 

these two product classes for standards. 

Table IV.1 presents the eight product 

classes that remain within the scope of 

this rulemaking. 

TABLE IV.1.-DISTRIBUTION TRANSFORMER PRODUCT CLASSES FOR THE NOPR 

PC No.* Insulation Voltage Phase BIL rating kVA range 

PC1 ............................. . Liquid-Immersed ......... . Single ......................... . 10-833 kVA. 

15-2500 kV A. 

15-833 kVA. 

15-2500 kVA. 

15-833 kVA. 

15-2500 kV A. 

75-833 kVA. 

225-2500 kV A. 

PC2 ............................. . Liquid-Immersed ......... . Three .......................... . 

PC5 ............................. . Dry-Type .................... . Medium 

Medium 

Medium 

Medium 

Medium 

Medium 

Single ......................... . 20-45 kV BIL ............. . 

PC6 ............................. . Dry-Type .................... . Three .......................... . 20-45 kV BIL ............. . 

PC7 ............................. . Dry-Type .................... . Single ......................... . 46-95 kV BIL ............. . 

PCB ............................. . Dry-Type .................... . Three .......................... . 46-95 kV BIL ............. . 

PC9 ............................. . Dry-Type .................... . Single ......................... . ;::96 kV BIL ................. . 

PC10 ........................... . Dry-Type .................... . Three .......................... . ;::96 kV BIL ................. . 

*Note: Although the PC3 and PC4 product classes are no longer included in this rulemaking, for consistency with prior material published 

under this rulemaking, the Department has not renumbered the liquid-immersed and medium-voltage, dry-type product classes that remain. 

DOE received no comments that 

requested modifications to the 

Department's product classes as 

proposed in the ANOPR. However, 

Howard Industries commented that it 

supported the independent 

categorization of liquid-immersed and 

dry-type transformers. It pointed out 

that the applications and type of 

customers for these two types of 

transformers can vary widely. (Howard, 

No. 70 at p. 2) The Department agrees 

with this comment and continues to 

treat liquid-immersed and dry-type 

transformers separately in its analysis. 

Concerning the use of three basic 

impulse insulation level (BIL) groupings 

for medium-voltage, dry-type 

transformers, Federal Pacific 

Transformer (FPT) noted that BIL levels 

do affect cost and efficiency, and agreed 

that DOE should conduct its analysis by 

BIL grouping. It commented that the 

efficiency levels should be modeled 

according to the BIL levels as much as 

possible. (FPT, No. 64 at p. 3) NEMA 

commented that it was willing to change 

the BIL groupings in TP 1-2002 from 

two to three, so TP 1 would have the 

same BIL groupings for medium-voltage, 

dry-type transformers as the 

Department's proposal. (NEMA, No. 60 

at p. 2) The Alliance to Save Energy 

(ASE) commented that the Department's 

refinement of BIL classifications over 

TP 1 is justified and should result in 

more appropriate efficiency levels. 

(ASE, No. 52 at p. 2 and No. 75 at p. 

2) Finally, the Oregon Department of 

Energy (ODOE) commented that it 

supports the refinements that created 

three BIL groupings for these 

transformers. (ODOE, No. 66 at p. 2) The 

Department did not receive any 

comments critical of the three BIL 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44365

groupings for medium-voltage, dry-type

transformers, and therefore continues to

use these same BIL groupings in today's

proposed rule.

Howard Industries and ASE

commented on whether DOE should

regulate the efficiency of liquidimmersed transformers. Howard

commented that, for liquid-immersed

transformers-especially for the utility,

municipal, and co-operative segmentsenergy-efficiency standards should be

voluntary because these transformer

customers are already considering lifecycle costs in their purchasing

decisions. (Howard, No. 70 at p. 4)

Howard commented that it feels a

voluntary program would be better for

the whole utility market than a

mandatory standard. Howard believes a

mandatory program would contribute to

standardization of liquid-immersed

transformer designs, and encourage

manufacturers to move to countries with

lower labor costs. Howard suggested

that the ballast and electric motor

industries are two examples of products

where mandatory standards were

implemented and domestic

manufacturing declined. (Howard, No.

70 at p. 2) ASE agreed with the

Department's decision that liquidimmersed transformers fall within the

scope of the standard. (ASE, No. 75 at

p. 2) Under 42 U.S.C. 6317, the

Department is charged in this

rulemaking with determining whether

standards for distribution transformers

are technologically feasible and

economically justified and would result

in significant energy savings. Based on

the Department's analysis and

information available to date, standards

for liquid-immersed transformers appear

to be technologically feasible and

economically justified, and would result

in significant energy savings. The

Department considered a voluntary

program, NEMA TP-1 in its

Determination Analysis, but concluded

that the "efficiency levels would

capture the most cost effective energy

savings but may not capture substantial

energy savings that appear to be

economically justified and

technologically feasible." 62 FR 54816.

In addition, the Department considered

the impact of voluntary programs in its

regulatory impact analysis (see the

report in the TSD "Regulatory Impact

Analysis for Electrical Distribution

Transformers"), and found that a

voluntary program would not result in

standards that achieve the maximum

efficiency level that is technologically

feasible and economically justified.

Thus, in accordance with 42 U.S.C.

6317, the Department intends to

continue to consider liquid-immersed

distribution transformers for energy

efficiency standards. To gain a better

understanding of the concern raised by

Howard Industries about minimum

efficiency standards leading to design

standardization, the Department

requests that other stakeholders

comment on this issue.

2. Definition of a Distribution

Transformer

The Department received several

comments from stakeholders on the

definition of a distribution transformer.

The Department has established the

definition (and scope of this

rulemaking) in its final rule on the test

procedure for distribution transformers.

10 CFR Part 431, Subpart K; 71 FR

24972.

SPCA directed DOE to develop

standards for those "distribution

transformers" for which energy

conservation standards would be

technologically feasible and

economically justified, and would result

in significant energy savings, but did

not specify a definition for a

distribution transformer. (42 U.S.C.

6317(a)) Thus, the Department began

developing a definition in the

determination analysis, and refined that

definition through the test procedure

rulemaking and this rulemaking. This

process was obviated to a substantial

extent by the enactment of EPACT 2005,

which amended EPCA to, among other

things, include a definition of a

distribution transformer. (42 U.S.C.

6291(35)) The existing statutory

definition establishes the scope of

coverage for this rulemaking.

Before the passage of EPACT 2005,

stakeholders had submitted comments

on the definition of a distribution

transformer presented in the ANOPR.

These comments are summarized here

with discussion on whether or not the

new EPCA definition of a distribution

transformer, promulgated in EPACT

2005, addresses the issues raised by the

stakeholders. For more detail on the

definition of a distribution transformer,

please see the test procedure final rule

notice. 71 FR 24972.

PEMCO and Southern Company

commented on exclusions for

dimensionally or physically constrained

transformers. PEMCO noted that an

exclusion for replacement or retrofit

transformers is needed because they

must have exactly the same physical

dimensions as the ones they are

replacing. (PEMCO, No. 57 at p. 1)

Southern Company agreed, noting that

in retrofit installations, size and weight

are a factor. Southern commented that,

as transformer efficiency increases, the

units become larger and obstructions

and required minimum clearances are

more difficult to achieve. Southern

noted that this is true for both liquidimmersed, pad-mounted units and drytype transformers installed in buildings.

It concluded that the increased size is

likely to cause both delivery and

installation problems in many locations.

(Southern, No. 71 at p. 2) At the ANOPR

public meeting, Ameren commented

that the Department should consider the

impact of different size/configurations

resulting from increased efficiency on

the speed and ease of emergency

replacement transformers. (Public

Meeting Transcript, No. 56.12 at pp.

255-256) The Department accounted for

generally applicable dimensional and

physical constraints on transformer

installation through the inclusion of

size- and weight-dependent installation

costs in its LCC model. These costs

include potential pole change-out costs

for large overhead transformers, and the

size- and weight-dependent labor and

equipment costs associated with

installing larger transformers. The costs

estimated by the Department do not

include the costs of rehabilitating

confined spaces that may have to be

modified for the installation of larger

transformers. This issue is similar to the

situation that arises when utilities and

contractors need to increase transformer

size due to load growth. One method of

modeling such costs would be to

include a space-occupancy cost to the

cost of transformer operation. The

Department invites comment on

whether space-occupancy costs should

be included in transformer cost

estimates and which methods are

appropriate for estimating such costs.

Howard and FPT expressed concern

about distribution transformers

designed for use in specific

environments. Howard recommended

that underground and subway-style

transformers be excluded from the

standards. Howard noted that these

transformers are often being retrofitted

into existing concrete vaults and, in

most cases, the whole concrete structure

would need to be replaced if DOE

mandated a more efficient unit.

(Howard, No. 70 at p. 3) FPT

recommended that the Department

consider exempting mining transformers

designed for installation inside

equipment with severe space

limitations, due to their radically

different loss characteristics. FPT noted

that efficiency standards could cause

problems in applications where these

transformers would not fit. (Public

Meeting Transcript, No. 56.12 at pp. 54-

56; FPT, No. 64 at p. 2) ODOE

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. lSD/Friday, August 4, 2006/Proposed Rules 44365 

groupings for medium-voltage, dry-type 

transformers, and therefore continues to 

use these same BIL groupings in today's 

proposed rule. 

Howard Industries and ASE 

commented on whether DOE should 

regulate the efficiency of liquidimmersed transformers. Howard 

commented that, for liquid-immersed 

transformers-especially for the utility, 

municipal, and co-operative segmentsenergy-efficiency standards should be 

voluntary because these transformer 

customers are already considering lifecycle costs in their purchasing 

decisions. (Howard, No. 70 at p. 4) 

Howard commented that it feels a 

voluntary program would be better for 

the whole utility market than a 

mandatory standard. Howard believes a 

mandatory program would contribute to 

standardization of liquid-immersed 

transformer designs, and encourage 

manufacturers to move to countries with 

lower labor costs. Howard suggested 

that the ballast and electric motor 

industries are two examples of products 

where mandatory standards were 

implemented and domestic 

manufacturing declined. (Howard, No. 

70 at p. 2) ASE agreed with the 

Department's decision that liquidimmersed transformers fall within the 

scope of the standard. (ASE, No. 75 at 

p. 2) Under 42 U.S.C. 6317. the 

Department is charged in this 

rulemaking with determining whether 

standards for distribution transformers 

are technologically feasible and 

economically justified and would result 

in significant energy savings. Based on 

the Department's analysis and 

information available to date, standards 

for liquid-immersed transformers appear 

to be technologically feasible and 

economically justified, and would result 

in significant energy savings. The 

Department considered a voluntary 

program. NEMA TP-l in its 

Determination Analysis, but concluded 

that the "efficiency levels would 

capture the most cost effective energy 

savings but may not capture substantial 

energy savings that appear to be 

economically justified and 

technologically feasible." 62 FR 54816. 

In addition, the Department considered 

the impact of voluntary programs in its 

regulatory impact analysis (see the 

report in the TSD "Regulatory Impact 

Analysis for Electrical Distribution 

Transformers")' and found that a 

voluntary program would not result in 

standards that achieve the maximum 

efficiency level that is technologically 

feasible and economically justified. 

Thus, in accordance with 42 U.S.c. 

6317. the Department intends to 

continue to consider liquid-immersed 

distribution transformers for energy 

efficiency standards. To gain a better 

understanding of the concern raised by 

Howard Industries about minimum 

efficiency standards leading to design 

standardization, the Department 

requests that other stakeholders 

comment on this issue. 

2. Definition of a Distribution 

Transformer 

The Department received several 

comments from stakeholders on the 

definition of a distribution transformer. 

The Department has established the 

definition (and scope of this 

rulemaking) in its final rule on the test 

procedure for distribution transformers. 

10 CFR Part 431, Subpart K; 71 FR 

24972. 

EPCA directed DOE to develop 

standards for those "distribution 

transformers" for which energy 

conservation standards would be 

technologically feasible and 

economically justified, and would result 

in significant energy savings, but did 

not specify a definition for a 

distribution transformer. (42 U.S.C. 

6317(a)) Thus, the Department began 

developing a definition in the 

determination analysis, and refined that 

definition through the test procedure 

rulemaking and this rulemaking. This 

process was obviated to a substantial 

extent by the enactment of EP ACT 2005. 

which amended EPCA to, among other 

things, include a definition of a 

distribution transformer. (42 U.S.c. 

6291(35)) The existing statutory 

definition establishes the scope of 

coverage for this rulemaking. 

Before the passage of EPACT 2005, 

stakeholders had submitted comments 

on the definition of a distribution 

transformer presented in the ANOPR. 

These comments are summarized here 

with discussion on whether or not the 

new EPCA definition of a distribution 

transformer, promulgated in EPACT 

2005, addresses the issues raised by the 

stakeholders. For more detail on the 

definition of a distribution transformer, 

please see the test procedure final rule 

notice. 71 FR 24972. 

PEMCO and Southern Company 

commented on exclusions for 

dimensionally or physically constrained 

transformers. PEMCO noted that an 

exclusion for replacement or retrofit 

transformers is needed because they 

must have exactly the same physical 

dimensions as the ones they are 

replacing. (PEMCO, No. 57 at p. 1) 

Southern Company agreed, noting that 

in retrofit installations, size and weight 

are a factor. Southern commented that, 

as transformer efficiency increases, the 

units become larger and obstructions 

and required minimum clearances are 

more difficult to achieve. Southern 

noted that this is true for both liquidimmersed, pad-mounted units and drytype transformers installed in buildings. 

It concluded that the increased size is 

likely to cause both delivery and 

installation problems in many locations. 

(Southern, No. 71 at p. 2) At the ANOPR 

public meeting, Ameren commented 

that the Department should consider the 

impact of different size/configurations 

resulting from increased efficiency on 

the speed and ease of emergency 

replacement transformers. (Public 

Meeting Transcript, No. 56.12 at pp. 

255-256) The Department accounted for 

generally applicable dimensional and 

physical constraints on transformer 

installation through the inclusion of 

size- and weight-dependent installation 

costs in its LCC model. These costs 

include potential pole change-out costs 

for large overhead transformers, and the 

size- and weight-dependent labor and 

equipment costs associated with 

installing larger transformers. The costs 

estimated by the Department do not 

include the costs of rehabilitating 

confined spaces that may have to be 

modified for the installation of larger 

transformers. This issue is similar to the 

situation that arises when utilities and 

contractors need to increase transformer 

size due to load growth. One method of 

modeling such costs would be to 

include a space-occupancy cost to the 

cost of transformer operation. The 

Department invites comment on 

whether space-occupancy costs should 

be included in transformer cost 

estimates and which methods are 

appropriate for estimating such costs. 

Howard and FPT expressed concern 

about distribution transformers 

designed for use in specific 

environments. Howard recommended 

that underground and subway-style 

transformers be excluded from the 

standards. Howard noted that these 

transformers are often being retrofitted 

into existing concrete vaults and, in 

most cases, the whole concrete structure 

would need to be replaced if DOE 

mandated a more efficient unit. 

(Howard, No. 70 at p. 3) FPT 

recommended that the Department 

consider exempting mining transformers 

designed for installation inside 

equipment with severe space 

limitations, due to their radically 

different loss characteristics. FPT noted 

that efficiency standards could cause 

problems in applications where these 

transformers would not fit. (Public 

Meeting Transcript. No. 56.12 at pp. 54-

56; FPT, No. 64 at p. 2) ODOE 
44366 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

commented that it had no objection to

the Department excluding specialty

transformers for the mining industry,

provided that the exclusion can be

written so as not to inadvertently create

a loophole for other end uses. (ODOE,

No. 66 at p. 2) As amended, EPCA does

not exclude these types of

dimensionally constrained transformers

from its definition of distribution

transformer. Furthermore, although 42

U.S.C. 6291(35)(B)(iii) authorizes DOE

to exclude additional types of

distribution transformers, DOE does not

have a sufficient basis for excluding

dimensionally constrained transformers

under this provision. While these

transformers apparently are designed for

special applications, in line with 42

U.S.C. 6291(35)(B)(iii)(I), DOE lacks

specific information on the other two

criteria, namely, whether these

transformers would be likely to be used

in general purpose applications, and

whether significant energy savings

would result from applying standards to

them. Stakeholders have submitted

neither data on the energy savings

potential of standards for these

transformers, nor information as to the

likelihood they could be used in general

purpose applications. Therefore, the

Department is not proposing to exclude

any of the transformers discussed in this

paragraph under section 321(35)(B)(iii)

of EPCA. (42 U.S.C. 6291(35)(B)(iii))

On the issue of harmonic mitigating

and harmonic tolerating transformers,

most of the comments proposed

eliminating the exemption for these

types of distribution transformers. At

the ANOPR public meeting, both the

American Council for an Energy

Efficient Economy (ACEEE) and NEMA

commented that they supported the

elimination of the exemption for

harmonic mitigating and harmonic

tolerating (or K-rated) transformers.

(Public Meeting Transcript, No. 56.12 at

p. 27 and p. 35) In written comments,

ACEEE, Harmonics Limited, NEMA, and

ODOE all recommended eliminating the

exemption for harmonic mitigating and

harmonic tolerating (or K-rated)

transformers. (ACEEE, No. 50 at p. 2 and

No. 76 at p. 4; Harmonics Limited, No.

59 at p. 1; NEMA, No. 48 at p. 3 and

No. 60 at p. 2; ODOE, No. 66 at p. 2)

PEMCO commented that it agrees with

including K-factor transformers as

covered equipment to stop the current

practice of using that exemption to

avoid efficiency requirements. (PEMCO,

No. 57 at p. 2)

EMS International Consulting

(EMSIC) provided a different viewpoint

on harmonic tolerating transformers (or

K-factor designs); it commented that it

believes K-factor and harmonic

mitigating transformers (up to a certain

level of K-factor) should be subject to

standards. (EMSIC, No. 73 at p. 3) FPT

went further, proposing a more detailed

treatment of K-factor designs. FPT

recognizes that some parties are

specifying K-factor transformers as a

means of getting around State standards

requiring TP 1, and that this would

probably happen more if DOE exempts

K-factor transformers broadly.

Therefore, FPT recommended that: (1)

Transformers rated up to 300 kVA and

having a K-factor of K-13 or less be

required to comply with the efficiency

standards, and (2) transformers above

300 kVA and having a K-factor of K-4

or less be required to comply with the

efficiency standards. (FPT, No. 64 at

2

P The definition of a distribution

transformer in EPACT 2005 does not

contain an explicit exemption for

harmonic mitigating or harmonic

tolerating (K-rated) transformers.

Furthermore, DOE does not have a

sufficient basis for excluding them

under 42 U.S.C. 6291(35)(B)(iii). While

these transformers apparently are

designed for special applications, in line

with 42 U.S.C. 6291(35)(B)(iii)(I), DOE

lacks specific information on the other

two criteria, namely, whether these

transformers would be likely to be used

in general purpose applications, and

whether significant energy savings

would result from applying standards to

them. Therefore, the Department is not

proposing to exclude any of the

transformers discussed in this paragraph

under section 321(35)(B)(iii) of EPCA.

42 U.S.C. 6291(35)(B)(iii).

On the issue of non-ventilated

transformers, the Department received a

comment from NEMA indicating that it

agrees with the Department's exclusion

of non-ventilated transformers because

of the inherent core losses in such

designs. (NEMA, No. 60 at p. 1) This

exclusion is now required by EPCA,

because EPACT 2005 included an

exemption for sealed and non-ventilated

transformers.

On the issue of refurbished

transformers, the Department received

comments representing different

viewpoints. Georgia Power commented

that DOE's documentation is not clear

on the reuse of transformers that have

been removed from service for

refurbishment. It indicated that it saves

approximately 11.5 percent of its total

transformer budget by refurbishing and

reusing transformers. Georgia Power

concluded that, if the Department

requires these units to be regulated, it

will have a significant financial impact

on utilities. (Georgia Power, No. 78 at p.

3)

Manufacturers, on the other hand,

appear to be concerned that the

increased cost of new, standardscompliant transformers would cause

some customers to either purchase

rebuilt transformers or refurbish existing

ones they own. ERMCO is concerned

that if these products are not subject to

standards, it may be possible for an end

user to avoid the standard by always

rewinding failed units. ERMCO stated

that there are several independent and

utility-owned repair shops that

refurbish: Some make minor repairs,

others rewind coils. (ERMCO, No. 58 at

p. 2) Howard commented that when the

final rule is established, it is absolutely

essential that it apply to new

transformers, used transformers, and

repaired transformers. (Howard, No. 70

at p. 3) HVOLT recommended that the

Department require any rebuilt

transformer that has a winding replaced

to meet the new standard, stating that

this is necessary to remove a major

loophole and would ultimately result in

improved energy efficiency for the

country. (HVOLT, No. 65 at p. 3 and

Public Meeting Transcript, No. 56.12 at

p. 59) EMSIC commented that it

believes that all refurbished ("repaired")

units should be subject to the new

standards to close a potential loophole.

(EMSIC, No. 73 at p. 3) ODOE agreed

that re-wound transformers should be

required to meet the new standards.

ODOE also commented that some

organizations in the Pacific Northwest

have been involved in promotion of

high-quality rewinding practices.

Through these programs, it has become

evident that high-quality work in this

area can produce a product that meets

the same performance specifications as

a new product, while poor-quality work

can seriously degrade performance.

(ODOE, No. 66 at p. 2)

EPACT 2005's definition of a

distribution transformer does not

mention refurbished or repaired

transformers, and therefore no guidance

on treatment of these transformers is

provided by the statute. Furthermore,

the Department's regulatory authority

with respect to refurbished equipment is

not clearly delineated. EPCA, as

amended by EPACT 2005, seems to

require that only newly manufactured

distribution transformers meet Federal

efficiency requirements. (42 U.S.C.

6302, 6316(a) and 6317(a)(1)) Thus, DOE

believes it lacks authority to require

used and repaired transformers to

comply with energy conservation

standards. The same may be true for

rebuilt transformers, although DOE's

authority is an issue. Generally, EPCA

provides that products, when

 EE-RM/STD-00-550 COMMENT 91.1

44366 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

commented that it had no objection to 

the Department excluding specialty 

transformers for the mining industry, 

provided that the exclusion can be 

written so as not to inadvertently create 

a loophole for other end uses. (ODOE, 

No. 66 at p. 2) As amended, EPCA does 

not exclude these types of 

dimensionally constrained transformers 

from its definition of distribution 

transformer. Furthermore, although 42 

U.S.c. 6291 (35)(B)(iii) authorizes DOE 

to exclude additional types of 

distribution transformers, DOE does not 

have a sufficient basis for excluding 

dimensionally constrained transformers 

under this proviSion. While these 

transformers apparently are designed for 

special applications, in line with 42 

U.S.C. 6291 (35)(B)(iii)(I), DOE lacks 

specific information on the other two 

criteria, namely, whether these 

transformers would be likely to be used 

in general purpose applications, and 

whether significant energy savings 

would result from applying standards to 

them. Stakeholders have submitted 

neither data on the energy savings 

potential of standards for these 

transformers, nor information as to the 

likelihood they could be used in general 

purpose applications. Therefore, the 

Department is not proposing to exclude 

any of the transformers discussed in this 

paragraph under section 321 (35)(B)(iii) 

of EPCA. (42 U.S.C. 6291(35)(B)(iii)) 

On the issue of harmonic mitigating 

and harmonic tolerating transformers, 

most of the comments proposed 

eliminating the exemption for these 

types of distribution transformers. At 

the ANOPR public meeting, both the 

American Council for an Energy 

Efficient Economy (ACEEE) and NEMA 

commented that they supported the 

elimination of the exemption for 

harmonic mitigating and harmonic 

tolerating (or K-rated) transformers. 

(Public Meeting Transcript, No. 56.12 at 

p. 27 and p. 35) In written comments, 

ACEEE, Harmonics Limited, NEMA, and 

ODOE all recommended eliminating the 

exemption for harmonic mitigating and 

harmonic tolerating (or K-rated) 

transformers. (ACEEE, No. 50 at p. 2 and 

No. 76 at p. 4; Harmonics Limited, No. 

59 at p. 1; NEMA, No. 48 at p. 3 and 

No. 60 at p. 2; ODOE, No. 66 at p. 2) 

PEMCO commented that it agrees with 

including K-factor transformers as 

covered equipment to stop the current 

practice of using that exemption to 

avoid efficiency requirements. (PEMCO, 

No. 57 at p. 2) 

EMS International Consulting 

(EMSIC) provided a different viewpoint 

on harmonic tolerating transformers (or 

K-factor designs); it commented that it 

believes K-factor and harmonic 

mitigating transformers (up to a certain 

level of K-factor) should be subject to 

standards. (EMSIC, No. 73 at p. 3) FPT 

went further, proposing a more detailed 

treatment of K-factor designs. FPT 

recognizes that some parties are 

specifying K-factor transformers as a 

means of getting around State standards 

requiring TP 1, and that this would 

probably happen more if DOE exempts 

K-factor transformers broadly. 

Therefore, FPT recommended that: (1) 

Transformers rated up to 300 kVA and 

having a K-factor of K-13 or less be 

required to comply with the efficiency 

standards, and (2) transformers above 

300 kVA and having a K-factor ofK-4 

or less be required to comply with the 

efficiency standards. (FPT, No. 64 at 

p.2) 

The definition of a distribution 

transformer in EP ACT 2005 does not 

contain an explicit exemption for 

harmonic mitigating or harmonic 

tolerating (K-rated) transformers. 

Furthermore, DOE does not have a 

sufficient basis for excluding them 

under 42 U.S.C. 6291 (35)(B)(iii). While 

these transformers apparently are 

designed for special applications, in line 

with 42 U.S.C. 6291(35)(B)(iii)(I), DOE 

lacks specific information on the other 

two criteria, namely, whether these 

transformers would be likely to be used 

in general purpose applications, and 

whether significant energy savings 

would result from applying standards to 

them. Therefore, the Department is not 

proposing to exclude any of the 

transformers discussed in this paragraph 

under section 321(35)(B)(iii) of EPCA. 

42 U.S.C. 6291(35)(B)(iii). 

On the issue of non-ventilated 

transformers, the Department received a 

comment from NEMA indicating that it 

agrees with the Department's exclusion 

of non-ventilated transformers because 

of the inherent core losses in such 

designs. (NEMA, No. 60 at p. 1) This 

exclusion is now required by EPCA, 

because EPACT 2005 included an 

exemption for sealed and non-ventilated 

transformers. 

On the issue of refurbished 

transformers, the Department received 

comments representing different 

viewpoints. Georgia Power commented 

that DOE's documentation is not clear 

on the reuse of transformers that have 

been removed from service for 

refurbishment. It indicated that it saves 

approximately 11.5 percent of its total 

transformer budget by refurbishing and 

reusing transformers. Georgia Power 

concluded that, if the Department 

requires these units to be regulated, it 

will have a significant financial impact 

on utilities. (Georgia Power, No. 78 at p. 

3) 

Manufacturers, on the other hand, 

appear to be concerned that the 

increased cost of new, standardscompliant transformers would cause 

some customers to either purchase 

rebuilt transformers or refurbish existing 

ones they own. ERMCO is concerned 

that if these products are not subject to 

standards, it may be possible for an end 

user to avoid the standard by always 

rewinding failed units. ERMCO stated 

that there are several independent and 

utility-owned repair shops that 

refurbish: Some make minor repairs, 

others rewind coils. (ERMCO, No. 58 at 

p. 2) Howard commented that when the 

final rule is established, it is absolutely 

essential that it apply to new 

transformers, used transformers, and 

repaired transformers. (Howard, No. 70 

at p. 3) HVOLT recommended that the 

Department require any rebuilt 

transformer that has a winding replaced 

to meet the new standard, stating that 

this is necessary to remove a major 

loophole and would ultimately result in 

improved energy efficiency for the 

country. (HVOLT, No. 65 at p. 3 and 

Public Meeting Transcript, No. 56.12 at 

p. 59) EMSIC commented that it 

believes that all refurbished ("repaired") 

units should be subject to the new 

standards to close a potential loophole. 

(EMSIC, No. 73 at p. 3) ODOE agreed 

that re-wound transformers should be 

required to meet the new standards. 

ODOE also commented that some 

organizations in the Pacific Northwest 

have been involved in promotion of 

high-quality rewinding practices. 

Through these programs, it has become 

evident that high-quality work in this 

area can produce a product that meets 

the same performance specifications as 

a new product, while poor-quality work 

can seriously degrade performance. 

(ODOE, No. 66 at p. 2) 

EPACT 2005's definition of a 

distribution transformer does not 

mention refurbished or repaired 

transformers, and therefore no guidance 

on treatment of these transformers is 

provided by the statute. Furthermore, 

the Department's regulatory authority 

with respect to refurbished equipment is 

not clearly delineated. EPCA, as 

amended by EPACT 2005, seems to 

require that only newly manufactured 

distribution transformers meet Federal 

efficiency requirements. (42 U.S.c. 

6302, 6316(a) and 6317(a)(1)) Thus, DOE 

believes it lacks authority to require 

used and repaired transformers to 

comply with energy conservation 

standards. The same may be true for 

rebuilt transformers, although DOE's 

authority is an issue. Generally, EPCA 

provides that products, when 
Federal. Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44367

"manufactured," are subject to

efficiency standards. (42 U.S.C. 6302

and 6316) It is arguable, but by no

means clear, that rebuilt transformers

(i.e., those with one or more coils rewound) could be considered to be

"manufactured" again when they are

rebuilt, and therefore be classified as

new distribution transformers subject to

standards. If, however, rebuilt products

cannot be classified as newly

manufactured, DOE would be subject to

the same lack of authority to regulate

them as applies to other used and

repaired products. In addition, the

Department does not have authority to

regulate the efficiency of distribution

transformers re-wound by their owners

(i.e., ownership of the transformer is not

transferred or sold to another party),

despite the suggestion of some

commenters that DOE do so. EPCA

provides authority to regulate only

products that are sold, imported, or

otherwise placed in commerce. (42

U.S.C. 6291, 6311, and 6317(f)(1))

Throughout the history of its

appliance and commercial equipment

energy conservation standards program,

DOE has not sought to regulate used

units that have been reconditioned or

rebuilt, or that have undergone major

repairs. For transformers, regulating this

part of the market, including the

enforcement of efficiency requirements,

would be a complex and burdensome

task. By and large, the Department

believes EPCA indicates a Congressional

intent that DOE focus on the market for

new products, and believes this is

where the most energy savings can be

achieved. For distribution transformers

in particular, the Department

understands that, at present, rebuilt

transformers are only a small part of the

market.

For all of these reasons, the

Department is proposing not to include

energy conservation standards for used,

repaired, and rebuilt distribution

transformers in this rulemaking.

Nevertheless, the Department recognizes

the concerns raised by commenters

about possible substitution of rebuilt

transformers for new transformers. If

conditions change-for example, if

rebuilt transformers become a larger

segment of the transformer marketDOE will reconsider its decision not to

subject them to energy conservation

requirements. The Department invites

comment on this decision.

On the issue of excluding special

impedance transformers, the

Department received one comment from

Howard. In response to the ANOPR

table of normal impedance ranges,

Howard provided a slightly revised

table of "normal" impedance ranges that

it believes are more in line with the

American National Standards Institute

(ANSI) standards with which most

utility systems comply. (Howard, No. 70

at p. 3) Howard's table contains slightly

narrower bands of "normal" impedance

ranges, which would result in fewer

transformers being subject to standards

and more transformers being classified

as exempt. The Department is

concerned that some transformers

designed for electricity distribution

could be manufactured with

impedances outside normal ranges so

that they would not be subject to

otherwise applicable efficiency

standards. Such transformers could

have a competitive advantage over

standards-compliant distribution

transformers. If this occurred, it would

subvert the standards. The Department

also notes that, in NEMA's revised test

procedure document, NEMA TP 2-2005,

the tables of normal impedance ranges

for both liquid-immersed and dry-type

transformers are exactly the same as

those published by the Department.

Thus, in the test procedure final rule

notice, the Department retained its

tables of "normal" impedance ranges.

71 FR 24972.

B. Engineering Analysis

The purpose of the engineering

analysis was to evaluate a range of

transformer efficiency levels and

associated manufacturing selling prices.

The engineering analysis considered

technologies and design option

combinations that were not screened out

by the four criteria in the screening

analysis. In the LCC analysis, the

Department used the manufacturer

selling price-efficiency relationships

developed in the engineering analysis

when it considered the consumer costs

of moving to higher efficiency levels.

For the distribution transformers

engineering analysis, the Department

learned that manufacturers in both the

liquid-immersed and medium-voltage,

dry-type sectors commonly use software

to design a distribution transformer to

fill a customer's order. This softwaredesign approach follows from the actual

dynamics in the transformer market,

where customers often specify certain

performance characteristics and

requirements. Manufacturers then

compete for the contract based on the

customized designs they generate using

their software, which takes into account

the customer's requirements and current

material costs.

Consistent with this approach, the

Department used transformer design

software to create a database of

distribution transformer designs

spanning a range of efficiencies, while

tracking all the modifications to the

core, coil, labor, and other cost

components. The software creates

transformer designs and cost and

performance characteristics associated

with those designs that, when compiled,

characterize the relationship between

cost and efficiency. The Department

selected software developed by an

independent company, Optimized

Program Service (OPS), not associated

with any single manufacturer or

manufacturer's association. The

engineering analysis design runs span a

broad range of efficiencies from lowest

first cost to maximum technologically

feasible. The data used in the

engineering analysis is discussed in

Chapter 5 of the TSD.

1. Engineering Analysis Methodology

There exist certain fundamental

relationships between the kVA ratings

of transformers and their physical size

and performance. Termed the "0.75

scaling rule," these size-versusperformance relationships arise from

equations describing how a

transformer's cost and efficiency change

with kVA rating. The Department used

the 0.75 scaling rule to reduce the

number of units that needed to be

analyzed for establishing minimum

efficiency standards for distribution

transformers as a whole. The findings

on those units analyzed were later

scaled to other kVA ratings using the

0.75 scaling rule. To maintain the

accuracy of the 0.75 scaling rule, DOE

established engineering "design lines."

Each design line consists of distribution

transformers that have a full range of

kVA ratings and that have similar

construction and engineering principles.

Some design lines consist of an entire

product class, but none spans more than

a product class. The Department then

selected one representative unit from

each of these design lines for analysis.

The 0.75 scaling rule was a critical

underlying factor in the engineering

analysis, since it enabled DOE to reduce

the number of units analyzed to 10.

Discussion on use of the 0.75 scaling

rule can be found in TSD Chapter 5,

section 5.2.2. Technical detail on the

derivation of the 0.75 scaling rule can be

found in TSD Appendix 5B.

In the ANOPR, the Department

solicited comments on the use of the

0.75 scaling rule. 69 FR 45416. ASE and

ODOE wrote that they support the use

of the 0.75 scaling rule, and believe it

is the correct and necessary approach to

simplify the analysis. (ASE, No. 52 at p.

3 and No. 75 at p. 3; ODOE, No. 66 at

p. 4) HVOLT commented at the ANOPR

public meeting that the 0.75 scaling rule

was used to develop the NEMA TP 1

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. l50/Friday, August 4, 2006/Proposed Rules 44367 

"manufactured," are subject to 

efficiency standards. (42 U.S.c. 6302 

and 6316) It is arguable, but by no 

means clear, that rebuilt transformers 

(Le., those with one or more coils rewound) could be considered to be 

"manufactured" again when they are 

rebuilt, and therefore be classified as 

new distribution transformers subject to 

standards. If, however, rebuilt products 

cannot be classified as newly 

manufactured, DOE would be subject to 

the same lack of authority to regulate 

them as applies to other used and 

repaired products. In addition, the 

Department does not have authority to 

regulate the efficiency of distribution 

transformers re-wound by their owners 

(Le .. ownership of the transformer is not 

transferred or sold to another party). 

despite the suggestion of some 

commenters that DOE do so. EPCA 

provides authority to regulate only 

products that are sold. imported, or 

otherwise placed in commerce. (42 

U.S.C. 6291, 6311, and 6317(f)(1)) 

Throughout the history of its 

appliance and commercial equipment 

energy conservation standards program, 

DOE has not sought to regulate used 

units that have been reconditioned or 

rebuilt, or that have undergone major 

repairs. For transformers, regulating this 

part ofthe market, including the 

enforcement of efficiency requirements, 

would be a complex and burdensome 

task. By and large, the Department 

believes EPCA indicates a Congressional 

intent that DOE focus on the market for 

new products. and believes this is 

where the most energy savings can be 

achieved. For distribution transformers 

in particular. the Department 

understands that, at present, rebuilt 

transformers are only a small part of the 

market. 

For all ofthese reasons, the 

Department is proposing not to include 

energy conservation standards for used, 

repaired, and rebuilt distribution 

transformers in this rulemaking. 

Nevertheless, the Department recognizes 

the concerns raised by commenters 

about possible substitution of rebuilt 

transformers for new transformers. If 

conditions change-for example, if 

rebuilt transformers become a larger 

segment of the transformer marketDOE will reconsider its decision not to 

subject them to energy conservation 

requirements. The Department invites 

comment on this decision. 

On the issue of excluding special 

impedance transformers, the 

Department received one comment from 

Howard. In response to the ANOPR 

table of normal impedance ranges. 

Howard provided a slightly revised 

table of "normal" impedance ranges that 

it believes are more in line with the 

American National Standards Institute 

(ANSI) standards with which most 

utility systems comply. (Howard. No. 70 

at p. 3) Howard's table contains slightly 

narrower bands of "normal" impedance 

ranges, which would result in fewer 

transformers being subject to standards 

and more transformers being classified 

as exempt. The Department is 

concerned that some transformers 

designed for electricity distribution 

could be manufactured with 

impedances outside normal ranges so 

that they would not be subject to 

otherwise applicable efficiency 

standards. Such transformers could 

have a competitive advantage over 

standards-compliant distribution 

transformers. If this occurred, it would 

subvert the standards. The Department 

also notes that. in NEMA's revised test 

procedure document, NEMA TP 2-2005, 

the tables of normal impedance ranges 

for both liquid-immersed and dry-type 

transformers are exactly the same as 

those published by the Department. 

Thus, in the test procedure final rule 

notice. the Department retained its 

tables of "normal" impedance ranges. 

71 FR 24972. 

B. Engineering Analysis 

The purpose of the engineering 

analysis was to evaluate a range of 

transformer efficiency levels and 

associated manufacturing selling prices. 

The engineering analysis considered 

technologies and design option 

combinations that were not screened out 

by the four criteria in the screening 

analysis. In the LCC analysis, the 

Department used the manufacturer 

selling price-efficiency relationships 

developed in the engineering analysis 

when it considered the consumer costs 

of moving to higher efficiency levels. 

For the distribution transformers 

engineering analysis, the Department 

learned that manufacturers in both the 

liquid-immersed and medium-voltage, 

dry-type sectors commonly use software 

to design a distribution transformer to 

fill a customer's order. This softwaredesign approach follows from the actual 

dynamics in the transformer market, 

where customers often specify certain 

performance characteristics and 

requirements. Manufacturers then 

compete for the contract based on the 

customized designs they generate using 

their software, which takes into account 

the customer's requirements and current 

material costs. 

Consistent with this approach. the 

Department used transformer design 

software to create a database of 

distribution transformer designs 

spanning a range of efficiencies, while 

tracking all the modifications to the 

core, coil, labor. and other cost 

components. The software creates 

transformer designs and cost and 

performance characteristics associated 

with those designs that. when compiled. 

characterize the relationship between 

cost and efficiency. The Department 

selected software developed by an 

independent company, Optimized 

Program Service (OPS), not associated 

with any single manufacturer or 

manufacturer's association. The 

engineering analysis design runs span a 

broad range of efficiencies from lowest 

first cost to maximum technologically 

feasible. The data used in the 

engineering analysis is discussed in 

Chapter 5 of the TSD. 

1. Engineering Analysis Methodology 

There exist certain fundamental 

relationships between the kVA ratings 

of transformers and their physical size 

and performance. Termed the "0.75 

scaling rule," these size-versusperformance relationships arise from 

equations describing how a 

transformer'S cost and efficiency change 

with kVA rating. The Department used 

the 0.75 scaling rule to reduce the 

number of units that needed to be 

analyzed for establishing minimum 

efficiency standards for distribution 

transformers as a whole. The findings 

on those units analyzed were later 

scaled to other kVA ratings using the 

0.75 scaling rule. To maintain the 

accuracy ofthe 0.75 scaling rule, DOE 

established engineering "design lines." 

Each design line consists of distribution 

transformers that have a full range of 

kVA ratings and that have similar 

construction and engineering principles. 

Some design lines consist of an entire 

product class, but none spans more than 

a product class. The Department then 

selected one representative unit from 

each of these design lines for analysis. 

The 0.75 scaling rule was a critical 

underlying factor in the engineering 

analysis, since it enabled DOE to reduce 

the number of units analyzed to 10. 

Discussion on use ofthe 0.75 scaling 

rule can be found in TSD Chapter 5, 

section 5.2.2. Technical detail on the 

derivation of the 0.75 scaling rule can be 

found in TSD Appendix 5B. 

In the ANOPR, the Department 

solicited comments on the use of the 

0.75 scaling rule. 69 FR 45416. ASE and 

ODOE wrote that they support the use 

of the 0.75 scaling rule, and believe it 

is the correct and necessary approach to 

simplify the analysis. (ASE. No. 52 at p. 

3 and No. 75 at p. 3; ODOE, No. 66 at 

p. 4) HVOLTcommented at the ANOPR 

public meeting that the 0.75 scaling rule 

was used to develop the NEMA TP 1 
44368 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

tables, and there have been no major

complaints about it. (Public Meeting

Transcript, No. 56.12 at p. 92) PEMCO

commented that it routinely uses the

0.75 scaling rule in its business

operations, and that the rule works for

scaling component costs for consistent

construction practice and within

reasonable size differences. PEMCO

cautioned, however, that the higher the

voltage class of the windings and the

closer to the lower end of a kVA product

range, the greater the error from the 0.75

scaling rule. (PEMCO, No. 57 at p. 1)

The Department appreciates this

comment from PEMCO, as it had created

the engineering design lines to

minimize error, particularly with

respect to the medium-voltage, dry-type

BIL groupings. In addition to the three

BIL groupings, the Department also

subdivided some of the product classes

into two or more engineering design

lines, so the kVA rating of the

representative unit would not be scaled

more than an order of magnitude up or

down in any one design line. It took

both of these steps to minimize any

error from scaling, and to provide a

more robust analytic foundation for the

proposed standards. Based on these

comments and the cautionary note from

PEMCO, the Department will continue

to apply the 0.75 scaling rule to

extrapolate findings to those kVA

ratings not specifically analyzed within

each of the design lines.

Another critical issue on which

stakeholders commented pertained to

the use of OPS software in the

development of the Department's

database of transformer designs. HVOLT

commented that the Department's

percentage cost increases for the 25 kVA

pole-type transformer were not large

enough. It believes that the percentage

cost difference between the standard

levels considered should be greater.

(HVOLT, No. 65 at p. 2) The Department

appreciates this comment, and looked

carefully at all the OPS software inputs

and results, and discussed these with

individual manufacturers during site

visits in 2005. The Department

recognizes that the manufacturer selling

prices in the ANOPR base case for the

25 kVA unit were too high, and that the

percentage increase from a larger base

price would be smaller for the same

absolute dollar cost increase. Following

revisions to the engineering analysis for

the 25 kVA liquid-immersed, pole-type

transformer, the baseline unit

manufacturer selling price decreased

from around $800 to approximately

$500 and, as a result, the percentage

change in manufacturer selling prices

between efficiency values has increased.

FPT expressed concern that the

manufacturer selling prices for dry-type

transformers may rise more rapidly than

is represented in the engineering

analysis. FPT is concerned that this may

skew the decision-making process

regarding what efficiency levels are

cost-justified. (FPT, No. 64 at p. 2)

Similarly, Howard commented that it

believes the inputs and outputs of the

OPS program are inaccurate, since it

found the outputs of the software to be

different from its own calculations.

Howard expressed concern at the

number of compromises,

generalizations, and assumptions that

could dilute the effectiveness of the

results. (Howard, No. 70 at p. 3) NEMA

commented that, because LCC results

seem to justify standards higher than TP

1, the OPS design software may not be

accurately modeling real-world units.

(NEMA, No. 48 at p. 2) NEMA also

commented that it had tested an actual

unit that had a similar technical

specification to an OPS design, and

found different results than were

reported by the Department. NEMA

noted that the designs in the

Department's database were not built

and tested, and therefore are not

representative of real transformers.

(Public Meeting Transcript, No. 56.12 at

p. 35) In a written submission, NEMA

provided further detail on this

comparison, and again questioned the

real-world predictive capabilities of the

software used. (NEMA, No. 60 at p. 3)

In response to these comments, the

Department reviewed and refined the

inputs to the OPS software in

consultation with transformer

manufacturers, OPS, and the

Department's technical experts. It is

important to recognize that there are

many inputs to both the engineering and

the LCC analytical models. For both

analytical models, the Department

updated its data and cost estimates for

the NOPR analysis. These refinements

changed the resulting designs and

associated manufacturer selling priceefficiency relationships discussed in

section IV.B of today's notice and

Chapter 5 of the TSD.

The Department appreciates and

thanks NEMA and its members for

taking the time to locate and test a

transformer that was similar to the one

published. The Department found two

critical problems with the comparison

made. First, the design NEMA reviewed

was not one DOE used in the ANOPR

engineering analysis, but rather a draft

design produced for comment two years

before the ANOPR, in August 2002.

Based on stakeholder feedback on that

draft design, DOE modified the inputs to

the OPS software when generating the

ANOPR engineering database; thus, that

design was not included. Second, the

two designs NEMA compared, while

having the same kVA rating, were not

similar transformers. The OPS design

and the unit NEMA tested had different

BIL ratings and would be grouped in

different product classes; therefore,

different testing results would be

expected.

Concerning the comments on the

accuracy of the OPS software, the

Department recognizes that differences

between the Department's engineering

analysis results and those of

manufacturers can be caused by a

number of factors, including different

material prices, labor estimates,

modeling parameters (e.g., impedance

range, inductance), markups, and the

consideration of different non-active

transformer components (e.g., gauges,

tanks). The Department discussed its

inputs both in the ANOPR and during

the manufacturer site visits, and revised

them as necessary to be the best

approximation of real-world practices.

In the process of verifying the OPS

software, DOE found that, under similar

input conditions and modeling

parameters, the cost and performance

estimates in the Department's database

are consistent with real-world

transformer designs. This was verified

both by comparing designs during

manufacturer interviews in May 2005

and through a tear-down analysis of six

transformers. The Department

purchased six 75 kVA three-phase, lowvoltage, dry-type transformers, and had

the units tested, disassembled, and

analyzed. It then used the OPS software

to model the physical designs and

generate an electrical analysis report.

The OPS software accurately predicted

the actual performance of the six

transformers. In addition, using the

2000-2004 average material prices, the

Department calculated the manufacturer

selling prices for each of these six units

using the same method as it used for the

engineering analysis. The Department

found that the cost-efficiency

relationship (slope) for these six units

tracked the cost-efficiency relationship

developed for the NOPR analysis. A

description of this tear-down analysis

and its results can be found in TSD

Chapter 5, section 5.7.

In addition to consulting with

manufacturers and conducting a teardown analysis, the Department arranged

for a third-party transformer design

engineer to prepare transformer designs

based on the same inputs as those used

by OPS. The transformer design

engineer looked at three of the

representative units published in this

NOPR, and prepared designs at a low-

 EE-RM/STD-00-550 COMMENT 91.1

44368 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

tables, and there have been no major 

complaints about it. (Public Meeting 

Transcript, No. 56.12 at p. 92) PEMCO 

commented that it routinely uses the 

0.75 scaling rule in its business 

operations, and that the rule works for 

scaling component costs for consistent 

construction practice and within 

reasonable size differences. PEMCO 

cautioned, however, that the higher the 

voltage class of the windings and the 

closer to the lower end of a kVA product 

range, the greater the error from the 0.75 

scaling rule. (PEMCO, No. 57 at p. 1) 

The Department appreciates this 

comment from PEMCO, as it had created 

the engineering design lines to 

minimize error, particularly with 

respect to the medium-voltage, dry-type 

BIL groupings. In addition to the three 

BIL groupings, the Department also 

subdivided some of the product classes 

into two or more engineering design 

lines, so the kVA rating of the 

representative unit would not be scaled 

more than an order of magnitude up or 

down in anyone design line. It took 

both of these steps to minimize any 

error from scaling, and to provide a 

more robust analytic foundation for the 

proposed standards. Based on these 

comments and the cautionary note from 

PEMCO, the Department will continue 

to apply the 0.75 scaling rule to 

extrapolate findings to those kVA 

ratings not specifically analyzed within 

each of the design lines. 

Another critical issue on which 

stakeholders commented pertained to 

the use of OPS software in the 

development of the Department's 

database of transformer designs. HVOL T 

commented that the Department's 

percentage cost increases for the 25 kVA 

pole-type transformer were not large 

enough. It believes that the percentage 

cost difference between the standard 

levels considered should be greater. 

(HVOLT, No. 65 at p. 2) The Department 

appreciates this comment, and looked 

carefully at all the OPS software inputs 

and results, and discussed these with 

individual manufacturers during site 

visits in 2005. The Department 

recognizes that the manufacturer selling 

prices in the ANOPR base case for the 

25 kVA unit were too high, and that the 

percentage increase from a larger base 

price would be smaller for the same 

absolute dollar cost increase. Following 

revisions to the engineering analysis for 

the 25 kVA liquid-immersed, pole-type 

transformer, the baseline unit 

manufacturer selling price decreased 

from around $800 to approximately 

$500 and, as a result, the percentage 

change in manufacturer selling prices 

between efficiency values has increased. 

FPT expressed concern that the 

manufacturer selling prices for dry-type 

transformers may rise more rapidly than 

is represented in the engineering 

analysis. FPT is concerned that this may 

skew the decision-making process 

regarding what efficiency levels are 

cost-justified. (FPT, No. 64 at p. 2) 

Similarly, Howard commented that it 

believes the inputs and outputs of the 

OPS program are inaccurate, since it 

found the outputs of the software to be 

different from its own calculations. 

Howard expressed concern at the 

number of compromises, 

generalizations, and assumptions that 

could dilute the effectiveness of the 

results. (Howard, No. 70 at p. 3) NEMA 

commented that, because LCC results 

seem to justify standards higher than TP 

1, the OPS design software may not be 

accurately modeling real-world units. 

(NEMA, No. 48 at p. 2) NEMA also 

commented that it had tested an actual 

unit that had a similar technical 

specification to an OPS design, and 

found different results than were 

reported by the Department. NEMA 

noted that the designs in the 

Department's database were not built 

and tested, and therefore are not 

representative of real transformers. 

(Public Meeting Transcript, No. 56.12 at 

p. 35) In a written submission, NEMA 

provided further detail on this 

comparison, and again questioned the 

real-world predictive capabilities of the 

software used. (NEMA, No. 60 at p. 3) 

In response to these comments, the 

Department reviewed and refined the 

inputs to the OPS software in 

consultation with transformer 

manufacturers, OPS, and the 

Department's technical experts. It is 

important to recognize that there are 

many inputs to both the engineering and 

the LCC analytical models. For both 

analytical models, the Department 

updated its data and cost estimates for 

the NOPR analysis. These refinements 

changed the resulting designs and 

associated manufacturer selling priceefficiency relationships discussed in 

section IV.B oftoday's notice and 

Chapter 5 ofthe TSD. 

The Department appreciates and 

thanks NEMA and its members for 

taking the time to locate and test a 

transformer that was similar to the one 

published. The Department found two 

critical problems with the comparison 

made. First, the design NEMA reviewed 

was not one DOE used in the ANOPR 

engineering analysis, but rather a draft 

design produced for comment two years 

before the ANOPR, in August 2002. 

Based on stakeholder feedback on that 

draft design, DOE modified the inputs to 

the OPS software when generating the 

ANOPR engineering database; thus, that 

design was not included. Second, the 

two designs NEMA compared, while 

having the same kV A rating, were not 

similar transformers. The OPS design 

and the unit NEMA tested had different 

BIL ratings and would be grouped in 

different product classes; therefore, 

different testing results would be 

expected. 

Concerning the comments on the 

accuracy of the OPS software, the 

Department recognizes that differences 

between the Department's engineering 

analysis results and those of 

manufacturers can be caused by a 

number of factors, including different 

material prices, labor estimates, 

modeling parameters (e.g., impedance 

range, inductance), markUps, and the 

consideration of different non-active 

transformer components (e.g., gauges, 

tanks). The Department discussed its 

inputs both in the ANOPR and during 

the manufacturer site visits, and revised 

them as necessary to be the best 

approximation of real-world practices. 

In the process of verifying the OPS 

software, DOE found that, under similar 

input conditions and modeling 

parameters, the cost and performance 

estimates in the Department's database 

are consistent with real-world 

transformer designs. This was verified 

both by comparing designs during 

manufacturer interviews in May 2005 

and through a tear-down analysis of six 

transformers. The Department 

purchased six 75 kVA three-phase, lowvoltage, dry-type transformers, and had 

the units tested, disassembled, and 

analyzed. It then used the OPS software 

to model the physical designs and 

generate an electrical analysis report. 

The OPS software accurately predicted 

the actual performance of the six 

transformers. In addition, using the 

2000-2004 average material prices, the 

Department calculated the manufacturer 

selling prices for each of these six units 

using the same method as it used for the 

engineering analysis. The Department 

found that the cost-efficiency 

relationship (slope) for these six units 

tracked the cost-efficiency relationship 

developed for the NOPR analysis. A 

description of this tear-down analysis 

and its results can be found in TSD 

Chapter 5, section 5.7. 

In addition to consulting with 

manufacturers and conducting a teardown analysis, the Department arranged 

for a third-party transformer design 

engineer to prepare transformer designs 

based on the same inputs as those used 

by OPS. The transformer design 

engineer looked at three of the 

representative units published in this 

NOPR, and prepared designs at a low-
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44369

first-cost, TP 1, and high-efficiency

point. The Department then compared

these designs to the OPS output for

those same kVA ratings on an efficiency

and manufacturer's selling price basis. It

found that the transformer engineer's

designs tracked the cost and efficiency

improvements of the OPS designs. This

work is discussed in Chapter 5 of the

TSD.

The Department is confident of the

accuracy of the OPS software, given the

above-mentioned: (1) Comparison of

engineering results with manufacturers

during interviews; (2) tear-down

analysis; (3) comparison of OPS designs

with those of a third-party design

engineer; and (4) discussions with

manufacturers who use the OPS

software and consulting services.

The Department received a few

comments from stakeholders concerning

the design lines and the representative

units selected from those design lines.

ACEEE commented that additional

design lines may be necessary to better

represent all transformers and better

identify the lowest life-cycle cost points.

ACEEE recommended looking at singlephase, liquid-immersed distribution

transformers between 50 kVA and 500

kVA and three-phase units below 150

kVA. (ACEEE, No. 76 at p. 1 and Public

Meeting Transcript, No. 56.12 at p. 27)

In response to this comment, the

Department reviewed its design lines

and selection of representative units for

the NOPR. Concerning an additional

representative unit between 50 kVA and

500 kVA, the Department does not

believe one is required. The 50 kVA

(and 25 kVA pole-mounted) unit scales

up to a maximum of 167 kVAincluding the 75 kVA, 100 kVA, and 167

kVA rated units. The 500 kVA unit

scales down to only two ratings, 250

kVA and 333 kVA. Use of the 0.75

scaling rule within these ranges is

reasonable and accurate. Concerning an

additional representative unit in the

three-phase, liquid-immersed product

class below 150 kVA, the Department

also does not believe such an addition

is necessary or would substantially

improve the analysis. The 150 kVA unit

is scaled down to 15 kVA, which is the

maximum range over which the

Department applies the 0.75 scaling rule

in its analysis (one order of magnitude).

The Department believes the 0.75

scaling rule is reasonable and accurate

at this range. Additionally, creating an

additional design line and analyzing a

representative unit at kVA ratings below

150 kVA for three-phase, liquidimmersed transformers would not

significantly improve the analysis. The

shipments of three-phase, liquidimmersed transformers below 150 kVA

represent just 1.6 percent of all threephase, liquid-immersed units shipped,

and a fraction of a percent of the liquidimmersed product classes. Therefore,

the Department did not add any new

representative units to the NOPR

engineering analysis.

The Department received one

comment concerning the treatment of

medium-voltage, less-flammable, liquidimmersed transformers in the

engineering analysis. Cooper Industries

recommended that the Department

consider combining these units as

design option combinations in product

classes 5 through 10 (the mediumvoltage, dry-type product classes).

Cooper Industries noted that lessflammable, liquid-immersed

transformers are used in the same

applications as dry-type transformers

and are recognized for this application

in the National Electrical Code. (Cooper,

No. 62 at p. 2) As discussed in the

ANOPR, the Department considers

liquid-immersed and dry-type

transformers as separate product classes.

69 FR 45385. It based this decision on

input from several manufacturers during

site visits in 2002, a review of industry

standards-including those published

by the Institute of Electrical and

Electronics Engineers, Inc. (IEEE), the

NEMA TP 1-2002 voluntary standard,

and four comments received from

stakeholders on the distribution

transformer Framework Document.

(Howard, No. 4 at p. 2; NEMA, No. 7 at

p. 5; TXU Electric and Gas, No. 12 at p.

5; ACEEE, No. 14 at p. 2) All of these

stakeholders advised the Department to

treat liquid-immersed and dry-type

distribution transformers separately

when establishing standards.

Countering the separate treatment of

liquid-immersed and dry-type

transformers, Cooper asked that lessflammable, liquid-immersed units (a

special type of liquid-immersed

transformer) be evaluated for standards

along with medium-voltage, dry-type

units, because they can be used in the

same applications. The Department

appreciates this comment. However,

energy efficiency standards are

prescribed on the basis of differences in

features that affect energy use. (42

U.S.C. 6295(q)) An example of these

different features is the cooling

mechanism for a transformer coil,

whether it is air-cooled or liquid-cooled.

Standards are therefore not classified or

organized on the basis of whether they

can service the same application. That

said, customer applications are taken

into consideration for the Department's

economic analysis when a standard is

developed and proposed (see the LCC

analysis, TSD Chapter 8). Thus, due to

the fact that the efficiency standard is

applied on the basis of product class,

not application, the Department did not

incorporate less-flammable, liquidimmersed units into the mediumvoltage dry-type analysis. The

Department invites comment on this

issue and on the recommendation from

Cooper.

2. Engineering Analysis Inputs

One of the critical issues identified by

many stakeholders commenting on the

ANOPR analysis was whether DOE used

prices that were representative of

current material prices. Georgia Power

commented that future transformer

pricing may be affected by the

decreasing number of suppliers of

transformer materials-such as mineral

oil and core steel-and that those still

in business are already operating at full

capacity. At present there are only two

domestic suppliers of core steel: AK

Steel and Allegheny Ludlum Steel

Corporation (see TSD Appendix 3A).

Georgia Power noted that higherefficiency transformers will require

more of these materials, which may

result in material shortages. It is

concerned that this situation could have

a major impact on future transformer

pricing and availability. (Georgia Power,

No. 78 at pp. 1-2) HVOLT submitted a

similar comment, and mentioned

specifically that material prices have

risen dramatically in step with higher

energy prices. HVOLT noted that

virtually all material suppliers now

impose surcharges on top of their base

material prices to yield the net selling

price. HVOLT recommended the

Department conduct a more detailed

analysis of material prices. (HVOLT, No.

65 at pp. 2-3)

HVOLT and Edison Electric Institute

(EEI) commented that material prices at

the time of the ANOPR public meeting

(September 2004) had increased relative

to the material prices the Department

used for its ANOPR analysis (2001

prices). (Public Meeting Transcript, No.

56.12 at p. 77; EEI, No. 63 at p. 3) The

Southern Company commented that

there have been substantial price

increases in many of the materials used

to build transformers, including copper

and steel, and suggested that these

increases make high-efficiency

transformers less cost-effective.

Southern recommended that recent raw

material price increases and reasonable

projections of future prices be included

in the updated cost study produced for

the NOPR. (Southern, No. 71 at p. 3)

The National Rural Electric Cooperative

Association (NRECA) commented that it

supports and concurs with EEI's

comments on the dramatic increase in

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44369 

first-cost, TP 1, and high-efficiency 

point. The Department then compared 

these designs to the OPS output for 

those same kVA ratings on an efficiency 

and manufacturer's selling price basis. It 

found that the transformer engineer's 

designs tracked the cost and efficiency 

improvements of the OPS designs. This 

work is discussed in Chapter 5 of the 

TSD. 

The Department is confident of the 

accuracy of the OPS software, given the 

above-mentioned: (1) Comparison of 

engineering results with manufacturers 

during interviews; (2) tear-down 

analysis; (3) comparison of OPS designs 

with those of a third-party design 

engineer; and (4) discussions with 

manufacturers who use the OPS 

software and consulting services. 

The Department received a few 

comments from stakeholders concerning 

the design lines and the representative 

units selected from those design lines. 

ACEEE commented that additional 

design lines may be necessary to better 

represent all transformers and better 

identify the lowest life-cycle cost points. 

ACEEE recommended looking at singlephase, liquid-immersed distribution 

transformers between 50 kVA and 500 

kVA and three-phase units below 150 

kV A. (ACEEE, No. 76 at p. 1 and Public 

Meeting Transcript, No. 56.12 at p. 27) 

In response to this comment, the 

Department reviewed its design lines 

and selection of representative units for 

the NOPR. Concerning an additional 

representative unit between 50 kVA and 

500 kVA, the Department does not 

believe one is required. The 50 kVA 

(and 25 kV A pole-mounted) unit scales 

up to a maximum of 167 kVAincluding the 75 kVA, 100 kVA, and 167 

kV A rated units. The 500 kVA unit 

scales down to only two ratings, 250 

kVA and 333 kVA. Use of the 0.75 

scaling rule within these ranges is 

reasonable and accurate. Concerning an 

additional representative unit in the 

three-phase, liquid-immersed product 

class below 150 kVA, the Department 

also does not believe such an addition 

is necessary or would substantially 

improve the analysis. The 150 kVA unit 

is scaled down to 15 kVA, which is the 

maximum range over which the 

Department applies the 0.75 scaling rule 

in its analysis (one order of magnitude). 

The Department believes the 0.75 

scaling rule is reasonable and accurate 

at this range. Additionally. creating an 

additional design line and analyzing a 

representative unit at kVA ratings below 

150 kVA for three-phase. liquidimmersed transformers would not 

significantly improve the analysis. The 

shipments of three-phase. liquidimmersed transformers below 150 kVA 

represent just 1.6 percent of all threephase. liquid-immersed units shipped. 

and a fraction of a percent of the liquidimmersed product classes. Therefore. 

the Department did not add any new 

representative units to the NOPR 

engineering analysis. 

The Department received one 

comment concerning the treatment of 

medium-voltage. less-flammable. liquidimmersed transformers in the 

engineering analysis. Cooper Industries 

recommended that the Department 

consider combining these units as 

design option combinations in product 

classes 5 through 10 (the mediumvoltage, dry-type product classes). 

Cooper Industries noted that lessflammable. liquid-immersed 

transformers are used in the same 

applications as dry-type transformers 

and are recognized for this application 

in the National Electrical Code. (Cooper. 

No. 62 at p. 2) As discussed in the 

ANOPR. the Department considers 

liquid-immersed and dry-type 

transformers as separate product classes. 

69 FR 45385. It based this decision on 

input from several manufacturers during 

site visits in 2002. a review of industry 

standards-including those published 

by the Institute of Electrical and 

Electronics Engineers. Inc. (IEEE). the 

NEMA TP 1-2002 voluntary standard. 

and four comments received from 

stakeholders on the distribution 

transformer Framework Document. 

(Howard. No.4 at p. 2; NEMA. No.7 at 

p. 5; TXU Electric and Gas. No. 12 at p. 

5; ACEEE. No. 14 at p. 2) All ofthese 

stakeholders advised the Department to 

treat liquid-immersed and dry-type 

distribution transformers separately 

when establishing standards. 

Countering the separate treatment of 

liquid-immersed and dry-type 

transformers. Cooper asked that lessflammable. liquid-immersed units (a 

special type of liquid-immersed 

transformer) be evaluated for standards 

along with medium-voltage. dry-type 

units. because they can be used in the 

same applications. The Department 

appreciates this comment. However. 

energy efficiency standards are 

prescribed on the basis of differences in 

features that affect energy use. (42 

U.S.C. 6295(q)) An example of these 

different features is the cooling 

mechanism for a transformer coil. 

whether it is air-cooled or liquid-cooled. 

Standards are therefore not classified or 

organized on the basis of whether they 

can service the same application. That 

said. customer applications are taken 

into consideration for the Department's 

economic analysis when a standard is 

developed and proposed (see the LCC 

analysis. TSD Chapter 8). Thus. due to 

the fact that the efficiency standard is 

applied on the basis of product class. 

not application. the Department did not 

incorporate less-flammable. liquidimmersed units into the mediumvoltage dry-type analysis. The 

Department invites comment on this 

issue and on the recommendation from 

Cooper. 

2. Engineering Analysis Inputs 

One of the critical issues identified by 

many stakeholders commenting on the 

ANOPR analysis was whether DOE used 

prices that were representative of 

current material prices. Georgia Power 

commented that future transformer 

pricing may be affected by the 

decreasing number of suppliers of 

transformer materials-such as mineral 

oil and core steel-and that those still 

in business are already operating at full 

capacity. At present there are only two 

domestic suppliers of core steel: AK 

Steel and Allegheny Ludlum Steel 

Corporation (see TSD Appendix 3A). 

Georgia Power noted that higherefficiency transformers will require 

more of these materials. which may 

result in material shortages. It is 

concerned that this situation could have 

a major impact on future transformer 

pricing and availability. (Georgia Power. 

No. 78 at pp. 1-2) HVOLT submitted a 

similar comment. and mentioned 

specifically that material prices have 

risen dramatically in step with higher 

energy prices. HVOL T noted that 

virtually all material suppliers now 

impose surcharges on top of their base 

material prices to yield the net selling 

price. HVOL T recommended the 

Department conduct a more detailed 

analysis of material prices. (HVOL T. No. 

65 at pp. 2-3) 

HVOL T and Edison Electric Institute 

(EEl) commented that material prices at 

the time of the ANOPR public meeting 

(September 2004) had increased relative 

to the material prices the Department 

used for its ANOPR analysis (2001 

prices). (Public Meeting Transcript. No. 

56.12 at p. 77; EEl. No. 63 at p. 3) The 

Southern Company commented that 

there have been substantial price 

increases in many of the materials used 

to build transformers. including copper 

and steel. and suggested that these 

increases make high-efficiency 

transformers less cost-effective. 

Southern recommended that recent raw 

material price increases and reasonable 

projections of future prices be included 

in the updated cost study produced for 

the NOPR. (Southern. No. 71 at p. 3) 

The National Rural Electric Cooperative 

Association (NRECA) commented that it 

supports and concurs with EEl's 

comments on the dramatic increase in 
44370 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

the prices of steel and copper in the last

two years. (NRECA, No. 74 at p. 2) In

line with these statements, ERMCO

commented that the 2004 material

prices presented at the ANOPR public

meeting looked reasonable, although

prices for mineral oil and wire (both

aluminum and copper) had increased

substantially in the last month. ERMCO

recognized that material prices are

volatile, and again emphasized the cost

increase for mineral oil. (ERMCO, No.

58 at p. 2)

In response to these comments and

concerns about the increases in material

prices (many of which were also

provided to the Department verbally

during the 2005 manufacturer site

visits), the Department conducted two

material pricing scenarios for the NOPR,

covering core steel, conductors,

insulation, and other key material

inputs (see TSD Chapter 5, section 5.4).

One, the reference case scenario, uses a

five-year average of prices for these

materials for the years 2000 through

2004. This scenario averages some of the

material price volatility in the market,

including low and high material price

points that occurred during that time

period. The second scenario is a

"current" material price analysis, using

material prices from the first quarter of

2005. This scenario provides a snapshot

in time of material prices that were of

concern to the stakeholders who

submitted comments to the Department.

When establishing a standard that will

apply to all distribution transformers

manufactured after a date several years

in the future (here, January 1, 2010), the

Department believes a material price

that incorporates average pricing over a

time period is a better basis for

establishing the standard than using the

material prices that manufacturers

typically pay in any one year. Thus,

DOE used the reference case (five-year

average of material prices) as the basis

for the standards proposed today. The

engineering analysis results based on

the material price reference case can be

found in TSD Chapter 5. The

Department also calculated engineering

analysis and LCC analysis results based

on the current (first quarter 2005)

material price scenario; these are

provided in TSD Appendix 5C.

In addition, the Department worked to

gain a better understanding of the

electrical core steel market, which is the

main cost driver behind the

construction of distribution

transformers. It conducted interviews

with both domestic core steel providers,

two national steel wholesalers, and two

manufacturers of equipment that

processes core steel. The Department

also reviewed publicly available

information on the steel market in

general, including trends, pressures, and

constraints, such as input substitution

opportunities and the supply-demand

effects of Chinese economic growth. The

findings of the Department's study of

the electrical core steel market can be

found in TSD Appendix 3A. The

Department used the information from

this research to improve its

understanding of the core steel market

and to verify the comments received

from stakeholders concerning the recent

trend toward increases in material

prices, specifically electrical core steel.

During the ANOPR public meeting,

ERMCO recommended that the

Department consider the impacts of

tariffs on the availability (and cost) of

speciality steels. (Public Meeting

Transcript, No. 56.12 at pp. 243-244)

The Department did consider the import

duty on raw (un-worked) Japanese core

steel, specifically mechanically scribed,

deep-domain refined, core steel

(ZDMH). For discussion on the

treatment of ZDMH core steel in this

analysis, see TSD Chapter 5.

The Department also received a

comment on the labor inputs used in the

engineering analysis. FPT commented

that the labor calculations in the

ANOPR analysis for cutting and

stacking core steel were incorrect. It

stated that the labor rates should not be

based on hours/inch, because of the

different thicknesses of core steel.

Stacking thinner laminations of steels

takes longer because more pieces of

material must be handled for each inch

of core stack. (FPT, No. 64 at pp. 1-2)

The Department agrees with this

comment and modified the methods

used in the engineering analysis for

calculating the labor costs. The revised

method and stacking rates DOE used for

the various grades of steel are described

in TSD Chapter 5.

3. Engineering Analysis Outputs

DOE received two comments on the

energy losses associated with auxiliary

devices. During the ANOPR workshop,

Ameren commented that the

Department should include the impact

of losses from accessories in its

calculation and determination of

national energy savings. (Public Meeting

Transcript, No. 56.12 at p. 254) ERMCO

also commented on this subject,

requesting that an allowance be made

for protective devices for transformers

(e.g., circuit breakers), which are

sometimes specified by utility

companies. In its comment, ERMCO

suggested two possible approaches: (1)

Have a separate table of efficiency

ratings for transformers with protective

devices, or (2) do not include any losses

due to protective devices in the

measurement of efficiency of the

transformer. (ERMCO, No. 58 at p. 1)

The Department notes that the

measurement and representation of the

efficiency of regulated transformers is

prescribed in the test procedures for

distribution transformers. 10 CFR Part

431, Subpart K, Appendix A; 71 FR

24972. As published, the test procedure

directs manufacturers to provide an

efficiency representation for a regulated

unit that does not include losses from

protective devices. The efficiency

standard proposed today only governs

the performance of the basic

transformer; it would not apply to the

protective devices and would not seek

to regulate the efficiency of these

devices. The test procedure directs

manufacturers to either calculate and

deduct losses from these protective

devices, or to by-pass the protective

devices in the load-loss test set-up

configuration.

HVOLT, NEMA, and ODOE

commented on manufacturer selling

prices. HVOLT commented during the

ANOPR workshop that the actual selling

prices of liquid-immersed units are

lower than was reported in DOE's

analysis. (Public Meeting Transcript,

No. 56.12 at p. 78) HVOLT also later

stated that the price for a low-first-cost

25 kVA single-phase, pole-mount

transformer was on the order of $400,

while the Department's analysis

reported $800. (Public Meeting

Transcript, No. 56.12 at p. 96) NEMA

recommended that the Department

contact individual manufacturers and

discuss the pricing of their lowest-firstcost transformers to calibrate the

engineering analysis. (NEMA, No. 48 at

p. 2 and Public Meeting Transcript, No.

56.12 at p. 35) ODOE echoed the

comment from NEMA, recommending

that the Department check the pricing of

transformers sold by manufacturers.

(ODOE, No. 66 at p. 3) Following

NEMA's and ODOE's recommendations,

the Department spoke to individual

manufacturers (both NEMA members

and non-NEMA members) about

material pricing, manufacturers' selling

prices, OPS software inputs, and other

equipment costs (e.g., tanks, bushings,

busbar). The adjustments DOE made

following these conversations resulted

in a reduction in manufacturer selling

prices for some design lines. For

example, the low-first-cost design for

the 25kVA single-phase, pole-mount

transformer went from approximately

$800 per unit to around $500 per unit

using the five-year, average-materialprice scenario.

DOE received two comments about

the feasibility of manufacturing the most

 EE-RM/STD-00-550 COMMENT 91.1

44370 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

the prices of steel and copper in the last 

two years. (NRECA, No. 74 at p. 2) In 

line with these statements. ERMCO 

commented that the 2004 material 

prices presented at the ANOPR public 

meeting looked reasonable. although 

prices for mineral oil and wire (both 

aluminum and copper) had increased 

substantially in the last month. ERMCO 

recognized that material prices are 

volatile. and again emphasized the cost 

increase for mineral oil. (ERMCO, No. 

58 at p. 2) 

In response to these comments and 

concerns about the increases in material 

prices (many of which were also 

provided to the Department verbally 

during the 2005 manufacturer site 

visits). the Department conducted two 

material pricing scenarios for the NOPR. 

covering core steel. conductors. 

insulation, and other key material 

inputs (see TSD Chapter 5. section 5.4). 

One. the reference case scenario, uses a 

five-year average of prices for these 

materials for the years 2000 through 

2004. This scenario averages some of the 

material price volatility in the market. 

including low and high material price 

points that occurred during that time 

period. The second scenario is a 

"current" material price analysis. using 

material prices from the first quarter of 

2005. This scenario provides a snapshot 

in time of material prices that were of 

concern to the stakeholders who 

submitted comments to the Department. 

When establishing a standard that will 

apply to all distribution transformers 

manufactured after a date several years 

in the future (here. January 1. 2010), the 

Department believes a material price 

that incorporates average pricing over a 

time period is a better basis for 

establishing the standard than using the 

material prices that manufacturers 

typically pay in anyone year. Thus. 

DOE used the reference case (five-year 

average of material prices) as the basis 

for the standards proposed today. The 

engineering analysis results based on 

the material price reference case can be 

found in TSD Chapter 5. The 

Department also calculated engineering 

analysis and LCC analysis results based on the current (first quarter 2005) 

material price scenario; these are 

provided in TSD Appendix 5C. 

In addition, the Department worked to 

gain a better understanding of the 

electrical core steel market. which is the 

main cost driver behind the 

construction of distribution 

transformers. It conducted interviews 

with both domestic core steel providers. 

two national steel wholesalers. and two 

manufacturers of equipment that 

processes core steel. The Department 

also reviewed publicly available 

information on the steel market in 

general. including trends. pressures, and 

constraints. such as input substitution 

opportunities and the supply-demand 

effects of Chinese economic growth. The 

findings of the Department's study of 

the electrical core steel market can be 

found in TSD AppendiX 3A. The 

Department used the information from 

this research to improve its 

understanding of the core steel market 

and to verify the comments received 

from stakeholders concerning the recent 

trend toward increases in material 

prices. specifically electrical core steel. 

During the ANOPR public meeting. 

ERMCO recommended that the 

Department consider the impacts of 

tariffs on the availability (and cost) of 

speciality steels. (Public Meeting 

Transcript. No. 56.12 at pp. 243-244) 

The Department did consider the import 

duty on raw (un-worked) Japanese core 

steel. specifically mechanically scribed. 

deep-domain refined. core steel 

(ZDMH). For discussion on the 

treatment of ZDMH core steel in this 

analysis. see TSD Chapter 5. 

The Department also received a 

comment on the labor inputs used in the 

engineering analysis. FPT commented 

that the labor calculations in the 

ANOPR analysis for cutting and 

stacking core steel were incorrect. It 

stated that the labor rates should not be 

based on hours/inch. because of the 

different thicknesses of core steel. 

Stacking thinner laminations of steels 

takes longer because more pieces of 

material must be handled for each inch 

of core stack. (FPT, No. 64 at pp. 1-2) 

The Department agrees with this 

comment and modified the methods 

used in the engineering analysis for 

calculating the labor costs. The revised 

method and stacking rates DOE used for 

the various grades of steel are described 

in TSD Chapter 5. 

3. Engineering Analysis Outputs 

DOE received two comments on the 

energy losses associated with auxiliary 

devices. During the ANOPR workshop. 

Ameren commented that the 

Department should include the impact 

of losses from accessories in its 

calculation and determination of 

national energy savings. (Public Meeting 

Transcript. No. 56.12 at p. 254) ERMCO 

also commented on this subject, 

requesting that an allowance be made 

for protective devices for transformers 

(e.g .. circuit breakers), which are 

sometimes specified by utility 

companies. In its comment. ERMCO 

suggested two possible approaches: (1) 

Have a separate table of efficiency 

ratings for transformers with protective 

devices, or (2) do not include any losses 

due to protective devices in the 

measurement of efficiency of the 

transformer. (ERMCO, No. 58 at p. 1) 

The Department notes that the 

measurement and representation of the 

efficiency of regulated transformers is 

prescribed in the test procedures for 

distribution transformers. 10 CFR Part 

431, Subpart K. Appendix A; 71 FR 

24972. As published. the test procedure 

directs manufacturers to provide an 

efficiency representation for a regulated 

unit that does not include losses from 

protective devices. The efficiency 

standard proposed today only governs 

the performance of the basic 

transformer; it would not apply to the 

protective devices and would not seek 

to regulate the efficiency of these 

devices. The test procedure directs 

manufacturers to either calculate and 

deduct losses from these protective 

devices. or to by-pass the protective 

devices in the load-loss test set-up 

configuration. 

HVOLT, NEMA. and ODOE 

commented on manufacturer selling 

prices. HVOL T commented during the 

ANOPR workshop that the actual selling 

prices of liquid-immersed units are 

lower than was reported in DOE's 

analysis. (Public Meeting Transcript. 

No. 56.12 at p. 78) HVOLT also later 

stated that the price for a low-first-cost 

25 kVA single-phase. pole-mount 

transformer was on the order of $400. 

while the Department's analysis 

reported $800. (Public Meeting 

Transcript, No. 56.12 at p. 96) NEMA 

recommended that the Department 

contact individual manufacturers and 

discuss the pricing of their lowest-firstcost transformers to calibrate the 

engineering analysis. (NEMA. No. 48 at 

p. 2 and Public Meeting Transcript. No. 

56.12 at p. 35) ODOE echoed the 

comment from NEMA. recommending 

that the Department check the pricing of 

transformers sold by manufacturers. 

(ODOE, No. 66 at p. 3) Following 

NEMA's and ODOE's recommendations, 

the Department spoke to individual 

manufacturers (both NEMA members 

and non-NEMA members) about 

material pricing, manufacturers' selling 

prices, OPS software inputs, and other 

equipment costs (e.g., tanks. bushings. 

busbar). The adjustments DOE made 

following these conversations resulted 

in a reduction in manufacturer selling 

prices for some design lines. For 

example. the low-first-cost design for 

the 25kV A single-phase, pole-mount 

transformer went from approximately 

$800 per unit to around $500 per unit 

using the five-year, average-materialprice scenario. 

DOE received two comments about 

the feasibility of manufacturing the most 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44371

efficient designs produced in the

engineering analysis. Cooper conducted

a design analysis of the 50 kVA padmount, the 150 kVA three-phase, and

the 1500 kVA three-phase, liquidimmersed units. It found that it was not

possible to meet the ANOPR candidate

standard level 5 (CSL5) efficiency level.

Furthermore, it found that, as the design

reaches ANOPR CSL3, the cost to

produce the transformer generally

increases exponentially. Because of this,

Cooper believes that the OPS software

does not account for realistic material

performance characteristics or realize

the cost or productivity impact of these

design changes with regard to the

manufacturing of a product. (Cooper,

No. 62 at p. 1) NRECA also questioned

the validity of the highest efficiency

levels (ANOPR CSL4 and CSL5). It

recommended that the Department

verify whether transformers with these

efficiencies actually exist or are merely

theoretical designs on paper. (NRECA,

No. 74 at p. 2)

As discussed in section IV.B.1, the

Department took several steps to verify

the OPS software and the predictive

capability of the software to design

transformers. The Department is

confident in the accuracy of the OPS

software, given the: (1) Comparison of

engineering results with manufacturers

during interviews; (2) tear-down

analysis; (3) comparison of OPS designs

with those of a third-party design

engineer; and (4) discussions with

manufacturers who use the OPS

software and consulting services. In

response to Cooper's and NRECA's

comments on the maximum

technologically feasible designs, the

Department notes that the design option

combinations that achieved the highest

efficiencies in a given representative

unit used non-traditional materials,

such as amorphous material and laserscribed, high-permeability, grainoriented electrical steel. The core

destruction factors, packing factors, and

other real-world adjustments for

production floor manufacturing are

inputs that OPS has refined over

decades in consultation with its clients,

some of which have manufactured

amorphous material and laser-scribed

steel. If the core material, winding, and

construction are all built to the design

report specification, these are feasible

designs. Details of the engineering

analysis can be found in TSD Chapter 5

and Appendices 5A, 5B, and 5C.

C. Life-Cycle Cost and Payback Period

Analysis

This section describes the LCC and

payback period (PBP) analysis and the

spreadsheet model DOE used for

analyzing the economic impacts on

customers. Details of the spreadsheet

model, and of all the inputs to the LCC

and PBP analysis, are in TSD Chapter 8.

The Department conducted the LCC and

PBP analysis using a spreadsheet model

developed in Microsoft (MS) Excel for

Windows 95 or above. When combined

with Crystal Ball (a commercially

available software program), the LCC

and PBP model generates a Monte Carlo

simulation to perform the analysis by

incorporating uncertainty and

variability considerations. While the

Department included an annual

maintenance cost as part of the LCC and

PBP calculation, it assumed that

maintenance and repair costs are

independent of transformer efficiency.

The LCC is the total customer cost

over the life of the equipment, including

purchase expense and operating costs

(including energy expenditures and

maintenance). To compute the LCC, the

Department summed the installed price

of a transformer and the discounted

annual future operating costs over the

lifetime of the equipment. The PBP is

the change in purchase expense due to

an increased efficiency standard divided

by the change in first-year operating cost

that results from the standard. The

Department expresses PBP in years. The

data inputs to the PBP calculation are

the purchase expense (otherwise known

as the total installed consumer cost or

first cost) and the annual operating costs

for each selected design. The inputs to

the transformer purchase expense were

the equipment price and the installation

cost, with appropriate markups. The

inputs to the operating costs were the

annual energy consumption and the

electricity price. The PBP calculation

uses the same inputs as the LCC

analysis but, since it is a simple

payback, the operating cost is for the

year the standard takes effect, assumed

to be 2010.

For each efficiency level analyzed, the

LCC analysis required input data for the

total installed cost of the equipment, the

operating cost, and the discount rate.

Table IV.2 summarizes the inputs and

key assumptions used to calculate the

customer economic impacts of various

energy efficiency levels. Equipment

price, installation cost, and baseline and

standard design selection 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 effective

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.2 shows

how the Department modified these

inputs and key assumptions for the

NOPR, relative to the ANOPR.

TABLE IV.2.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC AND PBP ANALYSES

Inputs

Equipment price .. .............

Installation cost ................

Baseline and standard

design selection.

ANOPR description

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 sales tax. Shipping costs were included for

both types of transformers.

Includes a weight-specific component, derived from RS Means Electrical

Cost Data 2002 and a markup to cover installation labor, and equipment

wear and tear.

The selection of baseline and standard -compliant transformers depended

on customer behavior . For liquid-immersed transformers , the fraction of

purchases evaluated was 50%, while for dry-type transformers, the fraction of evaluated purchases was 10%. The average A value for evaluators was $5/watt, while the B value depended on expected transformer

load.

Changes for NOPR

Reduced distributor markup for drytype added small distributor markup

for liquid-immersed.

Added a pole replacement component

to design line 2.

Increased liquid-immersed transformer evaluation percentage to

75%. Divided dry-types into (1)

small-capacity medium-voltage and

(2) large-capacity medium-voltage,

with evaluation percentages of 50%

and 80%, respectively.

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 44371 

efficient designs produced in the 

engineering analysis. Cooper conducted 

a design analysis of the 50 kVA padmount, the 150 kVA three-phase. and 

the 1500 kVA three-phase, liquidimmersed units. It found that it was not 

possible to meet the ANOPR candidate 

standard level 5 (CSL5) efficiency level. 

Furthermore, it found that. as the design 

reaches ANOPR CSL3, the cost to 

produce the transformer generally 

increases exponentially. Because ofthis, 

Cooper believes that the OPS software 

does not account for realistic material 

performance characteristics or realize 

the cost or productivity impact of these 

design changes with regard to the 

manufacturing of a product. (Cooper, 

No. 62 at p. 1) NRECA also questioned 

the validity of the highest efficiency 

levels (ANOPR CSL4 and CSL5). It 

recommended that the Department 

verify whether transformers with these 

efficiencies actually exist or are merely 

theoretical designs on paper. (NRECA, 

No. 74 at p. 2) 

As discussed in section IV.B.l, the 

Department took several steps to verify 

the OPS software and the predictive 

capability of the software to design 

transformers. The Department is 

confident in the accuracy of the OPS 

software, given the: (1) Comparison of 

engineering results with manufacturers 

during interviews; (2) tear-down 

analysis; (3) comparison of OPS designs 

with those of a third-party design 

engineer; and (4) discussions with 

manufacturers who use the OPS 

software and consulting services. In 

response to Cooper's and NRECA's 

comments on the maximum 

technologically feasible designs, the 

Department notes that the design option 

combinations that achieved the highest 

efficiencies in a given representative 

unit used non-traditional materials, 

such as amorphous material and laserscribed, high-permeability, grainoriented electrical steel. The core 

destruction factors, packing factors. and 

other real-world adjustments for 

production floor manufacturing are 

inputs that OPS has refined over 

decades in consultation with its clients, 

some of which have manufactured 

amorphous material and laser-scribed 

steel. If the core material, winding, and 

construction are all built to the design 

report specification, these are feasible 

designs. Details of the engineering 

analysis can be found in TSD Chapter 5 

and Appendices 5A, 5B, and 5C. 

C. Life-Cycle Cost and Payback Period 

Analysis 

This section describes the LCC and 

payback period (PBP) analysis and the 

spreadsheet model DOE used for 

analyzing the economic impacts on 

customers. Details of the spreadsheet 

model, and of all the inputs to the LCC 

and PBP analysis, are in TSD Chapter 8. 

The Department conducted the LCC and 

PBP analysis using a spreadsheet model 

developed in Microsoft (MS) Excel for 

Windows 95 or above. When combined 

with Crystal Ball (a commercially 

available software program), the LCC 

and PBP model generates a Monte Carlo 

simulation to perform the analysis by 

incorporating uncertainty and 

variability considerations. While the 

Department included an annual 

maintenance cost as part of the LCC and 

PBP calculation, it assumed that 

maintenance and repair costs are 

independent of transformer efficiency. 

The LCC is the total customer cost 

over the life of the equipment, including 

purchase expense and operating costs 

(including energy expenditures and 

maintenance). To compute the LCC, the 

Department summed the installed price 

of a transformer and the discounted 

annual future operating costs over the 

lifetime of the equipment. The PBP is 

the change in purchase expense due to 

an increased efficiency standard divided 

by the change in first-year operating cost 

that results from the standard. The 

Department expresses PBP in years. The 

data inputs to the PBP calculation are 

the purchase expense (otherwise known 

as the total installed consumer cost or 

first cost) and the annual operating costs 

for each selected design. The inputs to 

the transformer purchase expense were 

the equipment price and the installation 

cost, with appropriate markups. The 

inputs to the operating costs were the 

annual energy consumption and the 

electricity price. The PBP calculation 

uses the same inputs as the LCC 

analysis but, since it is a simple 

payback, the operating cost is for the 

year the standard takes effect, assumed 

to be 2010. 

For each efficiency level analyzed, the 

LCC analysis required input data for the 

total installed cost of the equipment, the 

operating cost, and the discount rate. 

Table IV.2 summarizes the inputs and 

key assumptions used to calculate the 

customer economic impacts of various 

energy efficiency levels. Equipment 

price, installation cost, and baseline and 

standard design selection affect the 

installed cost ofthe 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 effective 

date of the standard, the discount rate, 

and the lifetime of equipment affect the 

calculation ofthe present value of 

annual operating cost savings from a 

proposed standard. Table IV.2 shows 

how the Department modified these 

inputs and key assumptions for the 

NOPR, relative to the ANOPR. 

TABLE IV.2.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE Lee AND PBP ANALYSES 

Inputs 

Equipment price .............. . 

Installation cost .............. .. 

Baseline and standard 

design selection. 

ANOPR description 

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 sales tax. Shipping costs were included for 

both types of transformers. 

Includes a weight-specific component, derived from RS Means Electrical 

Cost Data 2002 and a markup to cover installation labor, and equipment 

wear and tear. 

The selection of baseline and standard-compliant transformers depended 

on customer behavior. For liquid-immersed transformers, the fraction of 

purchases evaluated was 50%, while for dry-type transformers, the fraction of evaluated purchases was 10%. The average A value for evaluators was $5/watt, while the B value depended on expected transformer 

load. 

Changes for NOPR 

Reduced distributor markup for drytype added small distributor markup 

for liquid-immersed. 

Added a pole replacement component 

to design line 2. 

Increased liquid-immersed transformer evaluation percentage to 

75%. Divided dry-types into (1) 

small-capacity medium-voltage and 

(2) large-capacity medium-VOltage, 

with evaluation percentages of 50% 

and 80%, respectively. 
44372 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE IV.2.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC AND PBP ANALYSES-Continued

Inputs ANOPR description

Affecting Operating Costs

Transformer loading ........

Load growth .....................

Power factor ....................

Annual energy use and

demand.

Electricity costs ................

Electricity price trend .......

Maintenance cost ............

Loading depended on customer and transformer characteristics. The average initial liquid-immersed transformer loading was 30% for 25 dry-type

kVA and 59% for 1500 kVA transformers. The average initial dry-type

transformer loading was 32% for 25 kVA and 37% for 2000 kVA transformers. The shipment-weighted lifetime average loading was 33.6% for

low-voltage, dry and 36.5% for medium-voltage, dry. With load growth,

average installed liquid-immersed transformer loading was 35% for 25

kVA and 70% for 1500 kVA transformers with a shipment-weighted lifetime average loading of 52.9%.

1 % per year for liquid-immersed and 0% per year for dry-type transformers

Assumed to be unity ........................................................................................

Derived from a statistical hourly use and demand load simulation for liquidimmersed transformers, and estimated from the 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.

Derived from tariff-based and hourly based electricity prices. Capacity costs

provided extra value for reducing losses at peak. Average marginal tariffbased retail electricity price: 6.4¢/kWh.for no-load losses and 7.40/kWh

for load losses. Average marginal wholesale utility hourly based costs:

3.8¢/kWh for no-load losses and 4.50/kWh for load losses.

Obtained from Annual Energy Outlook 2003 (AEO2003) ...............................

Annual maintenance cost did not vary cost as a function of efficiency ..........

Affecting Present Value of Annual Operating Cost Savings

Effective date ...................

Discount rates ..................

Lifetime ............................

Assumed to be 2007 ........................................................................................

Mean real discount rates ranged from 4.2% for owners of pole-mounted, liquid-immersed transformers to 6.6% for dry-type transformer owners.

Distribution of lifetimes, with mean lifetime for both liquid and dry-type transformers assumed to be 32 years.

Candidate Standard Levels

Candidate standard levels Five efficiency levels for each design line with the minimum equal to TP 1

and the maximum from the most efficient designs from the engineering

analysis.

Changes for NOPR

Increased average peak loading for

medium-voltage, dry-type transformers from 75% to 85%.

No change.

No change.

No change.

Updated tariff-based electricity prices

with 2004 tariff data. Adjusted hourly based electricity prices for inflation.

Updated to AE02005.t

No change.

Assumed to be 2010.

No change.

No change.

Six efficiency levels with the minimum

equal to TP 1 and the maximum

from the most efficient designs from

the engineering analysis. Intermediate efficiency levels for each

design line selected using a redefined set of LCC criteria (see section III.D.1.b).

*The concept of using A and B loss evaluation combinations is discussed in TSD chapter 3, Total Owning Cost Evaluation. Within the context

of the LCC analysis, the A factor measures the value to a transformer purchaser, in $/watt, of reducing no-load losses while the B factor measures the value, in $/watt, of reducing load losses. The purchase decision model developed by the Department mimics the likely choices that consumers make given the A and B values they assign to the transformer losses.

t The Department is aware of AEO2006, and the electricity price forecast does not differ significantly from AE02005.

The following sections contain brief

discussions of the methods underlying

each of these inputs and key

assumptions in the LCC analysis. Where

appropriate, the Department also

summarizes stakeholder comments on

these inputs and key assumptions and

explains how it took these comments

into consideration.

1. Inputs Affecting Installed Cost

a. Equipment Price

The equipment price of a transformer

reflects the application of supply-chain

markups, and the addition of sales tax

and shipping costs, to the

manufacturer's selling price. The

markup is the percentage increase in

price as the transformer passes through

the distribution channel. Commercial

and industrial customers most often

purchase dry-type transformers from

electrical contractors who purchase the

transformers through distributors,

whereas many liquid-immersed

transformers are purchased by utilities

directly from manufacturers and

installed directly by utility staff.

Therefore, DOE's markups for liquidimmersed transformers are smaller than

those for dry-type transformers. In

addition to the supply-chain markups,

DOE's equipment prices include

shipping costs and sales tax for both

types of transformers. The Department

did not have sufficient data to diversify

the distribution channels and markups

beyond these two general categories.

Details of the installed cost inputs can

be found in TSD Chapter 7.

In the ANOPR analysis, the

Department assumed that all liquidimmersed transformers were purchased

directly from manufacturers by utilities.

NEMA commented that distribution

channels are more complex than DOE

assumed in the ANOPR analysis. It

noted that some liquid-immersed units

may go through distributors and some

dry-type units may be sold directly from

the manufacturer. NEMA also indicated

that small transformers are more likely

to go through distributors and large

transformers are more likely to be sold

 EE-RM/STD-00-550 COMMENT 91.1

44372 Federal Register / Vol. 71, No. 150/ Friday, August 4, 2006/ Proposed Rules 

TABLE IV.2.-SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC AND PBP ANALYSES-Continued 

Inputs 

Transformer loading ....... . 

Load growth ................... .. 

Power factor .................. .. 

Annual energy use and 

demand. 

Electricity costs ............... . 

Electricity price trend ..... .. 

Maintenance cost .......... .. 

ANOPR description 

Affecting Operating Costs 

Loading depended on customer and transformer characteristics. The average initial liquid-immersed transformer loading was 30% for 25 dry-type 

kVA and 59% for 1500 kV A transformers. The average initial dry-type 

transformer loading was 32% for 25 kVA and 37% for 2000 kVA transformers. The shipment-weighted lifetime average loading was 33.6% for 

low-voltage, dry and 36.5% for medium-voltage, dry. With load growth, 

average installed liquid-immersed transformer loading was 35% for 25 

kVA and 70% for 1500 kVA transformers with a shipment-weighted lifetime average loading of 52.9%. 

1 % per year for liquid-immersed and 0% per year for dry-type transformers 

Assumed to be unity ....................................................................................... . 

Derived from a statistical hourly use and demand load simulation for Iiquidimmersed transformers, and estimated from the 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. 

Derived from tariff-based and hourly based electricity prices. Capacity costs 

provided extra value for reducing losses at peak. Average marginal tariffbased retail electricity price: 6.4¢/kWh.for no-load losses and 7.4¢/kWh 

for load losses. Average marginal wholesale utility hourly based costs: 

3.8¢/kWh for no-load losses and 4.5¢IkWh for load losses. 

Obtained from Annual Energy Outlook 2003 (AE02003) ............................. .. 

Annual maintenance cost did not vary cost as a function of efficiency ......... . 

Affecting Present Value of Annual Operating Cost Savings 

Changes for NOPR 

Increased average peak loading for 

medium-voltage, dry-type transformers from 75% to 85%. 

No change. 

No change. 

No change. 

Updated tariff-based electricity prices 

with 2004 tariff data. Adjusted hourly based electricity prices for inflation. 

Updated to AE02005.t 

No change. 

Effective date ................... Assumed to be 2007 ........................................................................................ Assumed to be 2010. 

Discount rates .................. Mean real discount rates ranged from 4.2% for owners of pole-mounted, liq- No change. 

uid-immersed transformers to 6.6% for dry-type transformer owners. 

lifetime ............................ Distribution of lifetimes, with mean lifetime for both liquid and dry-type trans- No change. 

formers assumed to be 32 years. 

Candidate Standard Levels 

Candidate standard levels Five efficiency levels for each design line with the minimum equal to TP 1 

and the maximum from the most efficient designs from the engineering 

analysis. 

Six efficiency levels with the minimum 

equal to TP 1 and the maximum 

from the most efficient designs from 

the engineering analysis. Intermediate efficiency levels for each 

design line selected using a redefined set of LCC criteria (see section III.D.1.b). 

'The concept of using A and B loss evaluation combinations is discussed in TSD chapter 3, Total Owning Cost Evaluation. Within the context 

of the LCC analysis, the A factor measures the value to a transformer purchaser, in $/watt, of reducing no-load losses while the B factor meas- ures the value, in $/watt, of reducing load losses. The purchase decision model developed by the Department mimics the likely choices that con- sumers make given the A and B values they assign to the transformer losses. 

t The Department is aware of AE02006, and the electricity price forecast does not differ significantly from AE02005. 

The following sections contain brief 

discussions of the methods underlying 

each of these inputs and key 

assumptions in the LCC analysis. Where 

appropriate, the Department also 

summarizes stakeholder comments on 

these inputs and key assumptions and 

explains how it took these comments 

into consideration. 

1. Inputs Affecting Installed Cost 

a. Equipment Price 

The equipment price of a transformer 

reflects the application of supply-chain 

markups, and the addition of sales tax 

and shipping costs, to the 

manufacturer's selling price. The 

markup is the percentage increase in 

price as the transformer passes through 

the distribution channel. Commercial 

and industrial customers most often 

purchase dry-type transformers from 

electrical contractors who purchase the 

transformers through distributors, 

whereas many liquid-immersed 

transformers are purchased by utilities 

directly from manufacturers and 

installed directly by utility staff. 

Therefore, DOE's markups for liquidimmersed transformers are smaller than 

those for dry-type transformers. In 

addition to the supply-chain markups, 

DOE's equipment prices include 

shipping costs and sales tax for both 

types of transformers. The Department 

did not have sufficient data to diversify 

the distribution channels and markups 

beyond these two general categories. 

Details of the installed cost inputs can 

be found in TSD Chapter 7. 

In the ANOPR analysis, the 

Department assumed that all liquidimmersed transformers were purchased 

directly from manufacturers by utilities. 

NEMA commented that distribution 

channels are more complex than DOE 

assumed in the ANOPR analysis. It 

noted that some liquid-immersed units 

may go through distributors and some 

dry-type units may be sold directly from 

the manufacturer. NEMA also indicated 

that small transformers are more likely 

to go through distributors and large 

transformers are more likely to be sold 
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules 44373

directly. (NEMA, No. 48 at p. 2) NRECA

commented that most, if not all,

cooperative utilities purchase liquidimmersed transformers through

distributors. (Public Meeting Transcript,

No. 56.12 at p. 120) In response to

NEMA's comment, the Department

discussed distribution channels and

markup practices with utility technical

staff to obtain additional input for the

NOPR analysis. Based on this input, the

Department adjusted the distributor

markup to 7 percent for liquidimmersed transformers and 15 percent

for dry-type transformers. These

distributor markup values compare with

0 percent and 35 percent, respectively,

for the liquid-immersed and dry-type

distributor markups for the more

simplified distribution channels that the

Department assumed for the ANOPR

analysis.

b. Installation Costs

Higher-efficiency distribution

transformers tend to be larger and

heavier than less efficient designs. The

Department therefore included the

increased cost of installing larger,

heavier transformers as a component of

the first cost of efficient transformers. In

the ANOPR, the Department presented

the installation cost model and solicited

comment from stakeholders. For details

of the installation cost calculations, see

TSD section 7.3.1.

EEI provided substantial comments

regarding the installation cost

implications of more-efficient

transformers that are physically larger

and heavier than less-efficient

transformers. It asserted that transformer

size and weight may require physical

modification to pole structure or

mounting pads, and that, in severe

replacement applications, increased

transformer size may require building

and structural modifications. (EEI, No.

63 at pp. 4-5) NRECA expressed similar

concerns that the size and weight of

more energy-efficient transformers may

dramatically affect installation cost.

(NRECA, No. 74 at p. 2) Tampa Electric

Company (TEC) commented that

transformer efficiency standards must

take into account physical dimension

constraints to ensure compatibility with

older units that will need to be replaced.

(TEC, No. 77 at p. 1) Georgia Power

Company commented that, as a result of

the expected increase in physical size

and weight of higher efficiency

transformers, installation costs will be

increased in several ways. First, it

estimates that pole replacements will be

required for 80 percent of the

transformer replacement installations

that have joint use applications (e.g.,

telephone line, cable television) on the

pole. Second , in addition to the pole

replacements at existing locations,

Georgia Power projects that numerous

larger diameter and taller poles will be

required at new transformer

installations. Third, it asserts that an

increase in the size and weight of polemounted and pad-mounted transformers

will significantly increase utility costs,

and that this impact will be

proportional to the percent increase in

transformer size and weight resulting

from the higher efficiency requirements.

(Georgia Power , No. 78 at pp. 2-3)

Ameren also commented that it believes

the Department should consider the

economic impact of transformer weight

increases, such as the necessity for

using stronger poles, resulting from

efficiency improvements. (Public

Meeting Transcript, No. 56.12 at pp.

253-254)

Howard commented that higher

efficiency transformers will be larger,

resulting in increased shipping costs as

well as handling problems for the

installers. (Howard, No . 70 at p. 3)

Comments from EEI included

information from utility members of

EEI, the American Public Power

Association (APPA), and NRECA, who

reported that in many cases increased

transformer size and weight can affect

the cost of new pole-mounted

transformer installations ; costs vary

from utility to utility and depend on the

size and weight increase . (EEI, No. 63 at

pp. 20-62) Southern Company asserted

that increases in installation costs from

the weight increases of more-efficient

transformers are not adequately covered

in the ANOPR analysis. (Southern, No.

71 at p. 2) National Grid (NGrid)

commented that high-efficiency

transformers present utilities with

logistical and financial challenges, but

they have found that the benefits

outweigh the costs when analyzed using

a life-cycle cost analysis method

employed in the industry . (NGrid, No.

80 at p. 1)

While the Department's ANOPR

included weight- and size-dependent

installation costs associated with the

increased shipping , handling, labor, and

equipment costs of installing larger and

heavier transformers, the ANOPR did

not include the costs of stronger poles

or pole replacement. In response to

stakeholder comments on polereplacementcosts, for the NOPR

analysis the Department added a polereplacement-cost function to the

installation cost equation for design line

2, which covers pole-mounted

transformers. This analysis assumed

that a pole change-out cost of $2,000

occurs for up to 25 percent of polemounted transformers when the weight

of the transformer exceeds 1,000

pounds. Because not all transformer

installations require a change-out of

existing equipment even in the most

extreme case, the Department assumed

a maximum change-out fraction. The

Department selected 25 percent as the

maximum change-out fraction estimate

based on stakeholder input. (EEI No. 63

at p. 25)

c. Baseline and Standard Design

Selection

A major factor in estimating the

economic impact of aproposed standard

is the selection of transformer designs in

the base case and standards case

scenarios. A key issue in the selection

process is the degree to which

transformer purchasers take into

consideration the cost of transformer

losses (A and B factors) when choosing

a transformer-both before and after the

implementation of a standard. The

purchase-decision model in the LCC

spreadsheet selects which of the

hundreds of designs in the engineering

database are likely to be selected by

transformer purchasers. The LCC

transformer selection process is

discussed in detail in TSD Chapter 8,

section 8.2.

The Department received three types

of comments on the design selection

and purchase behavior modeled in the

LCC spreadsheets: (1) Applicability of

values used, (2) actual values that

stakeholders have observed in the

market, and (3) percent of customers

who use the evaluation formulae.

Concerning the applicability of values

used, NRECA questioned whether the B

factors relative to the A factors used in

the LCC spreadsheet accurately

represent the A and B factors for rural

cooperatives. (NRECA, No. 74 at pp. 2-

3) Ameren asserted that the A and B

values used by the Department for the

ANOPR analysis were not representative

of Midwestern electric utilities. (Public

Meeting Transcript, No. 56.12 at p. 113)

NEMA said that both manufacturers and

utilities indicated at the public meeting

that the A and B values assumed by the

Department to characterize the base case

were higher than those in current use,

leading to a DOE base case that may

reflect higher transformer efficiencies

than marketplace reality. (NEMA, No.

60 at p. 2) ODOE also commented that

the method the Department used to

characterize the base case may result in

higher average efficiencies than are

actually found in the current market.

ODOE believes that the value of losses

is seldom a significant factor in

purchase decisions for transformers.

(ODOE, No. 66 at p. 5)

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006 I Proposed Rules 44373 

directly. (NEMA, No. 48 at p. 2) NRECA 

commented that most, if not all, 

cooperative utilities purchase liquidimmersed transformers through 

distributors. (Public Meeting Transcript, 

No. 56.12 at p. 120) In response to 

NEMA's comment, the Department 

discussed distribution channels and 

markup practices with utility technical 

staff to obtain additional input for the 

NOPR analysis. Based on this input, the 

Department adjusted the distributor 

markup to 7 percent for liquidimmersed transformers and 15 percent 

for dry-type transformers. These 

distributor markup values compare with 

o percent and 35 percent, respectively, 

for the liquid-immersed and dry-type 

distributor markups for the more 

simplified distribution channels that the 

Department assumed for the ANOPR 

analysis. 

b. Installation Costs 

Higher-efficiency distribution 

transformers tend to be larger and 

heavier than less efficient designs. The 

Department therefore included the 

increased cost of installing larger, 

heavier transformers as a component of 

the first cost of efficient transformers. In 

the ANOPR, the Department presented 

the installation cost model and solicited 

comment from stakeholders. For details 

of the installation cost calculations, see 

TSD section 7.3.1. 

EEl provided substantial comments 

regarding the installation cost 

implications of more-efficient 

transformers that are physically larger 

and heavier than less-efficient 

transformers. It asserted that transformer 

size and weight may req)lire physical 

modification to pole structure or 

mounting pads, and that, in severe 

replacement applications, increased 

transformer size may require building 

and structural modifications. (EEl, No. 

63 at pp. 4-5) NRECA expressed similar 

concerns that the size and weight of 

more energy-efficient transformers may 

dramatically affect installation cost. 

(NRECA, No. 74 at p. 2) Tampa Electric 

Company (TEC) commented that 

transformer efficiency standards must 

take into account physical dimension 

constraints to ensure compatibility with 

older units that will need to be replaced. 

(TEC, No. 77 at p. 1) Georgia Power 

Company commented that, as a result of 

the expected increase in physical size 

and weight of higher efficiency 

transformers, installation costs will be 

increased in several ways. First, it 

estimates that pole replacements will be 

required for 80 percent of the 

transformer replacement installations 

that have joint use applications (e.g., 

telephone line, cable television) on the 

pole. Second, in addition to the pole 

replacements at existing locations, 

Georgia Power projects that numerous 

larger diameter and taller poles will be 

required at new transformer 

installations. Third, it asserts that an 

increase in the size and weight of polemounted and pad-mounted transformers 

will significantly increase utility costs, 

and that this impact will be 

proportional to the percent increase in 

transformer size and weight resulting 

from the higher efficiency requirements. 

(Georgia Power, No. 78 at pp. 2-3) 

Ameren also commented that it believes 

the Department should consider the 

economic impact of transformer weight 

increases, such as the necessity for 

using stronger poles, resulting from 

efficiency improvements. (Public 

Meeting Transcript, No. 56.12 at pp. 

253-254) 

Howard commented that higher 

efficiency transformers will be larger, 

resulting in increased shipping costs as 

well as handling problems for the 

installers. (Howard, No. 70 at p. 3) 

Comments from EEl included 

information from utility members of 

EEl, the American Public Power 

Association (APP A), and NRECA, who 

reported that in many cases increased 

transformer size and weight can affect 

the cost of new pole-mounted 

transformer installations; costs vary 

from utility to utility and depend on the 

size and weight increase. (EEl, No. 63 at 

pp. 20-62) Southern Company asserted 

that increases in installation costs from 

the weight increases of more-efficient 

transformers are not adequately covered 

in the ANOPR analysis. (Southern, No. 

71 at p. 2) National Grid (NGrid) 

commented that high-efficiency 

transformers present utilities with 

logistical and financial challenges, but 

they have found that the benefits 

outweigh the costs when analyzed using 

a life-cycle cost analysis method 

employed in the industry. (NGrid, No. 

80 at p. 1) 

While the Department's ANOPR 

included weight- and size-dependent 

installation costs associated with the 

increased shipping, handling, labor, and 

equipment costs of installing larger and 

heavier transformers, the ANOPR did 

not include the costs of stronger poles 

or pole replacement. In response to 

stakeholder comments on polereplacement costs, for the NOPR 

analysis the Department added a polereplacement-cost function to the 

installation cost equation for design line 

2, which covers pole-mounted 

transformers. This analysis assumed 

that a pole change-out cost of $2,000 

occurs for up to 25 percent of polemounted transformers when the weight 

of the transformer exceeds 1,000 

pounds. Because not all transformer 

installations require a change-out of 

existing equipment even in the most 

extreme case, the Department assumed 

a maximum change-out fraction. The 

Department selected 25 percent as the 

maximum change-out fraction estimate 

based on stakeholder input. (EEl No. 63 

at p. 25) 

c. Baseline and Standard Design 

Selection 

A major factor in estimating the 

economic impact of a proposed standard 

is the selection of transformer designs in 

the base case and standards case 

scenarios. A key issue in the selection 

process is the degree to which 

transformer purchasers take into 

consideration the cost of transformer 

losses (A and B factors) when choosing 

a transformer-both before and after the 

implementation of a standard. The 

purchase-decision model in the LCC 

spreadsheet selects which of the 

hundreds of designs in the engineering 

database are likely to be selected by 

transformer purchasers. The LCC 

transformer selection process is 

discussed in detail in TSD Chapter 8, 

section 8.2. 

The Department received three types 

of comments on the design selection 

and purchase behavior modeled in the 

LCC spreadsheets: (1) Applicability of 

values used, (2) actual values that 

stakeholders have observed in the 

market, and (3) percent of customers 

who use the evaluation formulae. 

Concerning the applicability of values 

used, NRECA questioned whether the B 

factors relative to the A factors used in 

the LCC spreadsheet accurately 

represent the A and B factors for rural 

cooperatives. (NRECA, No. 74 at pp. 2-

3) Ameren asserted that the A and B 

values used by the Department for the 

ANOPR analysis were not representative 

of Midwestern electric utilities. (Public 

Meeting Transcript, No. 56.12 at p. 113) 

NEMA said that both manufacturers and 

utilities indicated at the public meeting 

that the A and B values assumed by the 

Department to characterize the base case 

were higher than those in current use, 

leading to a DOE base case that may 

reflect higher transformer efficiencies 

than marketplace reality. (NEMA, No. 

60 at p. 2) ODOE also commented that 

the method the Department used to 

characterize the base case may result in 

higher average efficiencies than are 

actually found in the current market. 

ODOE believes that the value of losses 

is seldom a significant factor in 

purchase decisions for transformers. 

(ODOE, No. 66 at p. 5) 
44374 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

Regarding the actual values observed

in the market, HVOLT commented that,

for the 80 percent of electric utilities

that currently evaluate losses when

purchasing a liquid-immersed

transformer, the A factor is between

$2.00 and $2.50 and the B factor is

approximately $0.75. HVOLT noted that

these evaluation formulae are higher

than the A factor ($1.57) and B factor

($0.57) used to develop the TP 1

standard. (Public Meeting Transcript,

No. 56.12 at p. 107) AK Steel

Corporation observed that some

transformer customers evaluate with an

A value of between $1.50 and $2.00.

(Public Meeting Transcript, No. 56.12 at

p. 109)

Relating to the percent of customers

who use the evaluation formulae, BBF &

Associates (BBF&A) said its market

study in the early 1990s indicated that

90 percent or more of transformers were

evaluated using A and B factors in the

traditional approach. It pointed out that

a subsequent survey in 2001-2002

showed that less than 50 percent were

evaluated. (Public Meeting Transcript,

No. 56.12 at p. 110) In the context of a

discussion on liquid-immersed

transformers, HVOLT said that around

80 percent of the market evaluates

losses today. (Public Meeting

Transcript, No. 56.12 at p. 107) For drytype transformers, HVOLT suggested

that there is probably less purchase

evaluation than the Department

assumed in the analysis, but that an

estimate of 10 percent evaluators is

probably accurate. (Public Meeting

Transcript, No. 56.12 at p. 156) ACEEE

stated that the efficiency of liquidimmersed transformers is dropping as

utilities move away from evaluation of

purchase decisions, due to regulatory

uncertainty caused by restructuring of

the electric utility industry. (ACEEE,

No. 76 at pp. 1-2) Similarly, the Copper

Development Association (CDA)

observed that at the ANOPR public

meeting, stakeholders commented that

62 percent of the smaller-kVA

distribution transformers sold in 2002

were lowest-cost versions and several

utility personnel indicated that A and B

evaluation values were zero. CDA

commented that it believes these

statements illustrate that many

transformers currently being purchased

are lowest-first-cost, low-efficiency

units. (CDA, No. 69 at p. 4)

The Department responded to these

stakeholder comments regarding A and

B values and the percent evaluators by

using new data provided by

stakeholders, and newly collected data

from the Internet, to adjust the

distributions and parameters it used to

model purchase decisions (see TSD

Chapter 8, section 8.3.1). It used data

provided by NRECA and data collected

from the Internet to revise its estimate

of the mean A value to $3.85/watt

compared to the value of $5/watt used

in the ANOPR analysis. This addresses

the stakeholder concerns that the A

values used in the ANOPR analysis may

have been high. With regard to the

actual values, the Department

characterized transformer loss

evaluation with a distribution of A

values that includes the lower range of

values-$1.50/watt to $2.50/wattmentioned by AK Steel. However, the

data collected by the Department were

inconsistent with HVOLT's assertion

that 80 percent of electric utilities use

an A factor between $2.00 and $2.50.

With respect to the percentage of

evaluators, the Department obtained

new data from NEMA regarding the

percentage of transformers sold that are

consistent with the voluntary TP 1

standard. The Department therefore

adjusted the percentage of evaluators in

its customer choice model to be

consistent with the new data provided

by NEMA. The Department believes that

this method provides the most precise

and detailed estimate of the percentage

of evaluators that is consistent with

actual market data.

The Department received several

comments noting that shipments of TP

1-compliant transformers have recently

increased, and noting the potential

impact of States adopting TP 1 as their

transformer standard. NEMA stated that

its members' shipments of TP 1-

compliant transformers increased in

2002 and 2003 compared to 2001 for all

transformers considered in the scope of

this rulemaking. (NEMA, No. 48 at p. 3)

An EEI survey of nine of its members

showed that an average of

approximately 65 percent of liquidimmersed transformers purchased are

already compliant with NEMA TP 1.

(EEI, No. 63 at pp. 7-19) NGrid now

purchases energy-efficient, liquidimmersed transformers that meet or

exceed NEMA's TP 1 standard

throughout its service territory in

Massachusetts, Rhode Island, New

Hampshire, and New York. This is true

despite the fact that only Massachusetts

requires TP 1-compliant, liquidimmersed transformers. (NGrid, No. 80

at p. 1) Georgia Power expressed doubt

that the Department can accurately

account for the number of transformers

that are already purchased with NEMA

TP 1 efficiencies. (Georgia Power, No.

78 at pp. 1-2)

The Appliance Standards Awareness

Project (ASAP) and Northwest Power

and Conservation Council (NPCC)

commented that the base case should

reflect the impact of State-established

transformer standards. (Public Meeting

Transcript, No. 56.12 at p. 248, Public

Meeting Transcript, No. 56.12 at pp.

180-181) ODOE commented that the

Department needs to pay careful

attention to those States that have TP 1

as an existing standard because, by the

time the DOE standard is published,

States mandating TP 1 could represent

a quarter to a third of transformer

shipments. (Public Meeting Transcript,

No. 56.12 at p. 185) NEMA said that, of

those States that have adopted TP 1,

most have done it for low-voltage, drytype distribution transformers, so the

other product classes would not be

affected. (Public Meeting Transcript, No.

56.12 at p. 182)

In response to these comments, the

Department obtained from NEMA new,

detailed data regarding TP 1 compliance

of shipped transformers. The

Department adjusted the parameters of

the customer choice model such that the

base case TP 1 compliance in the LCC

is consistent with the most recent

NEMA data available to the Department.

Southern Company and ODOE

requested that the Department provide

the efficiency rating for the base case.

(Public Meeting Transcript, No. 56.12 at

p. 215 and p. 217) ACEEE agreed, noting

that this information would enable

further independent analysis of the cost

and savings data. (ACEEE, No. 50 at p.

2 and No. 76 at p. 3) The Department

complied with this request and reported

the base case efficiencies for the ANOPR

analysis in Supplemental Appendix 8E

of the ANOPR TSD. These values have

been updated for the NOPR analysis,

and can be found in Appendix 8E of the

TSD.

2. Inputs Affecting Operating Costs

a. Transformer Loading

Transformer loading is an important

factor in determining which types of

transformer designs will deliver a

specified efficiency, and for calculating

transformer losses. Transformer losses

have two components: No-load losses

and load losses. No-load losses are

independent of the load on the

transformer, while load losses depend

approximately on the square of the

transformer loading. Because load losses

increase exponentially with loading,

there is a particular concern that, during

times of peak system load, load losses

can impact system capacity costs and

reliability. Details of the transformer

loading models are presented in TSD

Chapter 6.

For the ANOPR analysis, the

Department estimated the loading

characteristics of transformers by

 EE-RM/STD-00-550 COMMENT 91.1

44374 Federal Register / Vol. 71, No. 150/ Friday, August 4, 2006/ Proposed Rules 

Regarding the actual values observed 

in the market, HVOL T commented that, 

for the 80 percent of electric utilities 

that currently evaluate losses when 

purchasing a liquid-immersed 

transformer, the A factor is between 

$2.00 and $2.50 and the B factor is 

approximately $0.75. HVOLT noted that 

these evaluation formulae are higher 

than the A factor ($1.57) and B factor 

($0.57) used to develop the TP 1 

standard. (Public Meeting Transcript, 

No. 56.12 at p. 107) AK Steel 

Corporation observed that some 

transformer customers evaluate with an 

A value of between $1.50 and $2.00. 

(Public Meeting Transcript, No. 56.12 at 

p. 109) 

Relating to the percent of customers 

who use the evaluation formulae, BBF & 

Associates (BBF&A) said its market 

study in the early 1990s indicated that 

90 percent or more of transformers were 

evaluated using A and B factors in the 

traditional approach. It pointed out that 

a subsequent survey in 2001-2002 

showed that less than 50 percent were 

evaluated. (Public Meeting Transcript. 

No. 56.12 at p. 110) In the context of a 

discussion on liquid-immersed 

transformers. HVOL T said that around 

80 percent of the market evaluates 

losses today. (Public Meeting 

Transcript. No. 56.12 at p. 107) For drytype transformers. HVOL T suggested 

that there is probably less purchase 

evaluation than the Department 

assumed in the analysis. but that an 

estimate of 10 percent evaluators is 

probably accurate. (Public Meeting 

Transcript. No. 56.12 at p. 156) ACEEE 

stated that the efficiency of liquidimmersed transformers is dropping as 

utilities move away from evaluation of 

purchase decisions. due to regulatory 

uncertainty caused by restructuring of 

the electric utility industry. (ACEEE, 

No. 76 at pp. 1-2) Similarly. the Copper 

Development Association (CDA) 

observed that at the ANOPR public 

meeting. stakeholders commented that 

62 percent of the smaller-kVA 

distribution transformers sold in 2002 

were lowest-cost versions and several 

utility personnel indicated that A and B 

evaluation values were zero. CDA 

commented that it believes these 

statements illustrate that many 

transformers currently being purchased 

are lowest-first-cost. low-efficiency 

units. (CDA, No. 69 at p. 4) 

The Department responded to these 

stakeholder comments regarding A and 

B values and the percent evaluators by 

using new data provided by 

stakeholders. and newly collected data 

from the Internet. to adjust the 

distributions and parameters it used to 

model purchase decisions (see TSD 

Chapter 8. section 8.3.1). It used data 

provided by NRECA and data collected 

from the Internet to revise its estimate 

of the mean A value to $3.85/watt 

compared to the value of $5/watt used 

in the ANOPR analysis. This addresses 

the stakeholder concerns that the A 

values used in the ANOPR analysis may 

have been high. With regard to the 

actual values. the Department 

characterized transformer loss 

evaluation with a distribution of A 

values that includes the lower range of 

values-$1.50/watt to $2.50/wattmentioned by AK Steel. However, the 

data collected by the Department were 

inconsistent with HVOL T's assertion 

that 80 percent of electric utilities use 

an A factor between $2.00 and $2.50. 

With respect to the percentage of 

evaluators, the Department obtained 

new data from NEMA regarding the 

percentage of transformers sold that are 

consistent with the voluntary TP 1 

standard. The Department therefore 

adjusted the percentage of evaluators in 

its customer choice model to be 

consistent with the new data provided 

by NEMA. The Department believes that 

this method provides the most precise 

and detailed estimate of the percentage 

of evaluators that is consistent with 

actual market data. 

The Department received several 

comments noting that shipments of TP 

1-compliant transformers have recently 

increased. and noting the potential 

impact of States adopting TP 1 as their 

transformer standard. NEMA stated that 

its members' shipments ofTP 1-

compliant transformers increased in 

2002 and 2003 compared to 2001 for all 

transformers considered in the scope of 

this rulemaking. (NEMA, No. 48 at p. 3) 

An EEl survey of nine of its members 

showed that an average of 

approximately 65 percent of liquidimmersed transformers purchased are 

already compliant with NEMA TP 1. 

(EEl. No. 63 at pp. 7-19) NGrid now 

purchases energy-efficient. liquidimmersed transformers that meet or 

exceed NEMA's TP 1 standard 

throughout its service territory in 

Massachusetts. Rhode Island. New 

Hampshire. and New York. This is true 

despite the fact that only Massachusetts 

requires TP l-compliant. liquidimmersed transformers. (NGrid, No. 80 

at p. 1) Georgia Power expressed doubt 

that the Department can accurately 

account for the number of transformers 

that are already purchased with NEMA 

TP 1 efficiencies. (Georgia Power. No. 

78 at pp. 1-2) 

The Appliance Standards Awareness 

Project (ASAP) and Northwest Power 

and Conservation Council (NPCC) 

commented that the base case should 

reflect the impact of State-established 

transformer standards. (Public Meeting 

Transcript. No. 56.12 at p. 248. Public 

Meeting Transcript. No. 56.12 at pp. 

180-181) ODOE commented that the 

Department needs to pay careful 

attention to those States that have TP 1 

as an existing standard because. by the 

time the DOE standard is published. 

States mandating TP 1 could represent 

a quarter to a third of transformer 

shipments. (Public Meeting Transcript. 

No. 56.12 at p. 185) NEMA said that. of 

those States that have adopted TP 1. 

most have done it for low-voltage. drytype distribution transformers. so the 

other product classes would not be 

affected. (Public Meeting Transcript. No. 

56.12 at p. 182) 

In response to these comments. the 

Department obtained from NEMA new. 

detailed data regarding TP 1 compliance 

of shipped transformers. The 

Department adjusted the parameters of 

the customer choice model such that the 

base case TP 1 compliance in the LCe 

is consistent with the most recent 

NEMA data available to the Department. 

Southern Company and ODOE 

requested that the Department provide 

the efficiency rating for the base case. 

(Public Meeting Transcript, No. 56.12 at 

p. 215 and p. 217) ACEEE agreed, noting 

that this information would enable 

further independent analysis of the cost 

and savings data. (ACEEE. No. 50 at p. 

2 and No. 76 at p. 3) The Department 

complied with this request and reported 

the base case efficiencies for the ANOPR 

analysis in Supplemental Appendix 8E 

of the ANOPR TSD. These values have 

been updated for the NOPR analysis, 

and can be found in Appendix 8E of the 

TSD. 

2. Inputs Affecting Operating Costs 

a. Transformer Loading 

Transformer loading is an important 

factor in determining which types of 

transformer designs will deliver a 

specified efficiency. and for calculating 

transformer losses. Transformer losses 

have two components: No-load losses 

and load losses. No-load losses are 

independent of the load on the 

transformer. while load losses depend 

approximately on the square of the 

transformer loading. Because load losses 

increase exponentially with loading, 

there is a particular concern that. during 

times of peak system load. load losses 

can impact system capacity costs and 

reliability. Details of the transformer 

loading models are presented in TSD 

Chapter 6. 

For the ANOPR analysis. the 

Department estimated the loading 

characteristics of transformers by 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44375

analyzing the statistics of available load

data, and by assuming a distribution of

initial annual peak loadings. ASE

commented that the Department's

analysis of load profiles is largely

consistent with data provided by other

stakeholders. It also recognized that the

Department used publicly available data

for utility loads, and commented that

the average loadings for liquidimmersed transformers were reasonable.

(ASE, No. 52 at p. 3 and No. 75 at p.

3) ODOE agreed with the transformer

loads estimated by the Department

based on ODOE's examination of

loading studies conducted in the Pacific

Northwest, which produced lower

loading levels than expected by many

analysts. (ODOE, No. 66 at p. 4)

HVOLT estimated that the average

loading for dry-type, medium-voltage

units is about 50 percent, with a

daytime average of 60 percent and a

nighttime average of 35 percent. (Public

Meeting Transcript, No. 56.12 at pp.

131-132) HVOLT estimated that loading

for liquid-immersed transformers is

about 50 percent, but noted that loads

in the residential sector can increase so

much that loading can exceed the

transformer nameplate rating. (Public

Meeting Transcript, No. 56.12 at p. 131

and p. 133) In a written comment,

HVOLT endorsed using loading

assumptions identical to those for

NEMA TP 1. HVOLT is not familiar

with any publicly released loading

studies that would alter the root mean

square (RMS)-equivalent load of 50

percent load for medium-voltage

transformers. (HVOLT, No. 65 at p. 3)

EEI estimated that, according to three

surveyed members, average loading

levels range from 30 percent to 58

percent. A survey of eight members

yielded a range of high-loading levels

from 45 to 100 percent, and a range of

low-loading levels from 35 to 75

percent. (EEI, No. 63 at pp. 7-19) TEC

said that it strives to load transformers

higher than the 50 percent level

assumed by DOE, and recommended

that the Department give consideration

to efficiency ratings at higher loading

levels. (TEC, No. 77 at p. 1)

The Department concluded that the

ANOPR statistical loading analysis was

largely consistent with stakeholder

comments, with slight adjustments

necessary for the loading levels of

medium-voltage, dry-type transformers

(see TSD Chapter 6, section 6.3.3.3). The

Department increased the loading on

medium-voltage, dry-type transformers

in response to the comments by HVOLT,

to be consistent with the relative

difference in loading levels used by

NEMA TP 1 between low-voltage and

medium-voltage dry-type transformers.

On the issue of peak load

coincidence, the Department received

two comments. ASE agreed with the

Department's peak load coincidence

analysis for the ANOPR. (ASE, No. 52 at

p. 3 and No. 75 at p. 3) The CDA

commented that peak coil losses may

have a high coincidence factor with

system peaks. (CDA, No. 51 at pp. 3-4)

The Department concluded that the

statistical model used for peak loading

in the ANOPR analysis was consistent

with stakeholder comments and did not

change peak loading statistics for the

NOPR analysis.

b. Load Growth

The LCC takes into account the

growth on those transformers. (Public

Meeting Transcript, No. 56.12 at p. 40)

HVOLT also stated that one-percent

load growth for liquid-immersed

transformers seems too high. (Public

Meeting Transcript, No. 56.12 at p. 138)

HVOLT also said that there is not much

load growth in residential applications,

since transformers are installed in a

community with a cluster of homes,

they come online quickly, and after that,

there are few factors producing load

p

projected operating costs for growth for liquid-immersed

distribution transformers many years transformers. While some stakeholders into the future. This projection requires disagreed with the Department's

an estimate of how, if at all, the estimate of load growth for liquidelectrical load on transformers will immersed transformers, data showing

change over time. For dry-type both growth in per-customer electrical transformers, the Department assumed loads over time and increasing

no load growth. For liquid-immersed transformer sizes purchased by utilities

transformers, the Department used as support the Department's approach (see the default scenario a one-percent-per- TSD Chapter 8).

year load growth. It applied the load Regarding another aspect of the issue growth factor to each transformer

beginning in 2010, the expected of load growth over time, EEI stated its

effective date of the standard. To concern that, because of load growth,

explore the LCC sensitivity to variations higher efficiency transformers

the Department optimized to the loading point in load growth ,

included in the model the ability to

examine scenarios with zero-percent,

one-percent, and two-percent load

growth. Load growth is discussed in

detail in TSD Chapter 8, section 8.3.6.

The Department received a range of

comments on its load growth

projections. CDA commented that

loading on all transformers increases

with time. It stated that, for liquidimmersed transformers, residential

consumption per household has

increased; for dry-types, commercial

and industrial loads grow over time

growth for the rest of the transformer's

life. (Public Meeting Transcript, No.

56.12 at p. 39)

The Department retained its estimate

of zero-percent load growth for dry-type

transformers and one- ercent load

prescribed by the test procedure may

have higher coil losses after being in

service for several years. That is, EEI is

concerned that the "balance point"

between higher coil losses and lower

core losses may not be reached until late

in the operating life of a transformer.

(EEI, No. 63 at pp. 3-4) Both the ANOPR

and NOPR load analyses were

responsive to this comment. The

Department's estimate of losses tracked

losses based on estimates of actual loads

rather than test procedure loads. Both

near-term and long-term losses were

through more energy-intensive use of included in LCC estimates, with a

floor space and plant expansion. (CDA, weighting determined by the customer

No. 51 at pp. 1-2) ODOE stated that discount rate (see TSD Chapter 8).

DOE should select a growth rate of zero, c. Power Factor

with sensitivity analysis at one-percent

growth. (ODOE, No. 66 at p. 6) NEMA The power factor is real power

agreed with the Department's load divided by apparent power. Real power

growth estimates of zero percent for dry- is the time average of the instantaneous

type and one percent for liquid- product of voltage and current.

immersed transformers. However, to the Apparent power is the product of the

extent that building owners may defer RMS voltage and the RMS current. For

transformer upgrades because of high the ANOPR, the Department used a

unit costs, it noted that there may be power factor of 1.0. A detailed

some load growth on older, less efficient discussion of the power factor can be

units. (NEMA, No. 48 at p. 2) found in TSD Chapter 8, section 8.3.12.

HVOLT commented that, in The Department received two

commercial and industrial complexes, comments on power factor. Southern

new transformers are added to handle Company commented that the power

additional loads when there is an factor should be less than 1.0. (Public

expansion, and there is not much Meeting Transcript, No. 56.12 at p. 164)

information to suggest a substantial load NEMA, on the other hand, stated that a

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44375 

analyzing the statistics of available load 

data, and by assuming a distribution of 

initial annual peak loadings. ASE 

commented that the Department's 

analysis of load profiles is largely 

consistent with data provided by other 

stakeholders. It also recognized that the 

Department used publicly available data 

for utility loads, and commented that 

the average loadings for liquidimmersed transformers were reasonable. 

(ASE, No. 52 at p. 3 and No. 75 at p. 

3) ODOE agreed with the transformer 

loads estimated by the Department 

based on ODOE's examination of 

loading studies conducted in the Pacific 

Northwest, which produced lower 

loading levels than expected by many 

analysts. (ODOE, No. 66 at p. 4) 

HVOL T estimated that the average 

loading for dry-type, medium-voltage 

units is about 50 percent, with a 

daytime average of 60 percent and a 

nighttime average of 35 percent. (Public 

Meeting Transcript, No. 56.12 at pp. 

131-132) HVOLT estimated that loading 

for liquid-immersed transformers is 

about 50 percent, but noted that loads 

in the residential sector can increase so 

much that loading can exceed the 

transformer nameplate rating. (Public 

Meeting Transcript, No. 56.12 at p. 131 

and p. 133) In a written comment, 

HVOL T endorsed using loading 

assumptions identical to those for 

NEMA TP 1. HVOL T is not familiar 

with any publicly released loading 

studies that would alter the root mean 

square (RMS)-equivalent load of 50 

percent load for medium-voltage 

transformers. (HVOLT, No. 65 at p. 3) 

EEl estimated that, according to three 

surveyed members, average loading 

levels range from 30 percent to 58 

percent. A survey of eight members 

yielded a range of high-loading levels 

from 45 to 100 percent, and a range of 

low-loading levels from 35 to 75 

percent. (EEl, No. 63 at pp. 7-19) TEC 

said that it strives to load transformers 

higher than the 50 percent level 

assumed by DOE, and recommended 

that the Department give consideration 

to efficiency ratings at higher loading 

levels. (TEC, No. 77 at p. 1) 

The Department concluded that the 

ANOPR statistical loading analysis was 

largely consistent with stakeholder 

comments, with slight adjustments 

necessary for the loading levels of 

medium-voltage, dry-type transformers 

(see TSD Chapter 6. section 6.3.3.3). The 

Department increased the loading on 

medium-voltage. dry-type transformers 

in response to the comments by HVOLT. 

to be consistent with the relative 

difference in loading levels used by 

NEMA TP 1 between low-voltage and 

medium-voltage dry-type transformers. 

On the issue of peak load 

coincidence. the Department received 

two comments. ASE agreed with the 

Department's peak load coincidence 

analysis for the ANOPR. (ASE, No. 52 at 

p. 3 and No. 75 at p. 3) The CDA 

commented that peak coil losses may 

have a high coincidence factor with 

system peaks. (CDA, No. 51 at pp', 3-4) 

The Department concluded that the 

statistical model used for peak loading 

in the ANOPR analysis was consistent 

with stakeholder comments and did not 

change peak loading statistics for the 

NOPR analysis. 

b. Load Growth 

The LCC takes into account the 

projected operating costs for 

distribution transformers many years 

into the future. This projection requires 

an estimate of how. if at all, the 

electrical load on transformers will 

change over time. For dry-type 

transformers. the Department assumed 

no load growth. For liquid-immersed 

transformers. the Department used as 

the default scenario a one-percent-peryear load growth. It applied the load 

growth factor to each transformer 

beginning in 2010. the expected 

effective date ofthe standard. To 

explore the LCC sensitivity to variations 

in load growth. the Department 

included in the model the ability to 

examine scenarios with zero-percent. 

one-percent. and two-percent load 

growth. Load growth is discussed in 

detail in TSD Chapter 8. section 8.3.6. 

The Department received a range of 

comments on its load growth 

projections. CDA commented that 

loading on all transformers increases 

with time. It stated that, for liquidimmersed transformers. residential 

consumption per household has 

increased; for dry-types. commercial 

and industrial loads grow over time 

through more energy-intensive use of 

floor space and plant expansion. (CDA. 

No. 51 at pp. 1-2) ODOE stated that 

DOE should select a growth rate ofzero. 

with sensitivity analysis at one-percent 

growth. (ODOE, No. 66 at p. 6) NEMA 

agreed with the Department's load 

growth estimates of zero percent for drytype and one percent for liquidimmersed transformers. However, to the 

extent that building owners may defer 

transformer upgrades because of high 

unit costs. it noted that there may be 

some load growth on older. less efficient 

units. (NEMA, No. 48 at p. 2) 

HVOL T commented that, in 

commercial and industrial complexes. 

new transformers are added to handle 

additional loads when there is an 

expansion. and there is not much 

information to suggest a substantial load 

growth on those transformers. (Public 

Meeting Transcript, No. 56.12 at p. 40) 

HVOL T also stated that one-percent 

load growth for liquid-immersed 

transformers seems too high. (Public 

Meeting Transcript. No. 56.12 at p. 138) 

HVOL T also said that there is not much 

load growth in residential applications. 

since transformers are installed in a 

community with a cluster of homes, 

they come online quickly. and after that. 

there are few factors producing load 

growth for the rest of the transformer's 

life. (Public Meeting Transcript, No. 

56.12 at p. 39) 

The Department retained its estimate 

of zero-percent load growth for dry-type 

transformers and one-percent load 

growth for liquid-immersed 

transformers. While some stakeholders 

disagreed with the Department's 

estimate of load growth for liquidimmersed transformers, data showing 

both growth in per-customer electrical 

loads over time and increasing 

transformer sizes purchased by utilities 

support the Department's approach (see 

TSD Chapter 8). 

Regarding another aspect of the issue 

of load growth over time, EEl stated its 

concern that. because of load growth, 

higher efficiency transformers 

optimized to the loading point 

prescribed by the test procedure may 

have higher coil losses after being in 

service for several years. That is. EEl is 

concerned that the "balance point" 

between higher coil losses and lower 

core losses may not be reached until late 

in the operating life of a transformer. 

(EEl. No. 63 at pp. 3-4) Both the ANOPR 

and NOPR load analyses were 

responsive to this comment. The 

Department's estimate of losses tracked 

losses based on estimates of actual loads 

rather than test procedure loads. Both 

near-term and long-term losses were 

included in LCC estimates. with a 

weighting determined by the customer 

discount rate (see TSD Chapter 8). 

c. Power Factor 

The power factor is real power 

divided by apparent power. Real power 

is the time average of the instantaneous 

product of voltage and current. 

Apparent power is the product of the 

RMS voltage and the RMS current. For 

the ANOPR, the Department used a 

power factor of 1.0. A detailed 

discussion of the power factor can be 

found in TSD Chapter 8. section 8.3.12. 

The Department received two 

comments on power factor. Southern 

Company commented that the power 

factor should be less than 1.0. (Public 

Meeting Transcript. No. 56.12 at p. 164) 

NEMA. on the other hand. stated that a 
44376 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

power factor assumption of 1.0 is

appropriate. (NEMA, No. 60 at p. 2)

While the Department agrees with

Southern Company that actual power

factors are less than 1.0, they are very

close to 1.0, and the Department agrees

with NEMA that use of a power factor

of 1.0 is appropriate for the analysis of

the efficiency standard. Using a power

factor less than 1.0 would slightly

increase the estimated losses for

transformers, but would complicate the

Department's analysis and affect all

components of the Department's

analysis where losses are estimated. The

Department determined that the

disadvantages of complicating the

analysis by using an estimated

distribution of slightly lower power

factors outweighed the slight increase in

analytical accuracy that could result.

d. Electricity Costs

The Department needed estimates of

electricity prices and costs to place a

value on transformer losses for the LCC

calculation. As noted earlier, the

Department created two sets of

electricity prices to estimate annual

energy expenses for its ANOPR: An

hourly based estimate of wholesale

electricity costs for the liquid-immersed

transformer market, and a tariff-based

estimate for the dry-type transformer

market (see TSD Chapter 8).

Southern Company questioned

whether wholesale electricity prices are

the correct prices for liquid-immersed

transformers, and suggested that the

Department consider the availability of

very inexpensive electricity generating

capacity in some regions. (Public

Meeting Transcript, No. 56.12 at p. 125

and pp. 237-238) The Department's

analysis for both the ANOPR and the

NOPR estimated the marginal, or

incremental, wholesale cost of

electricity. The Department agrees with

Southern Company that inexpensive

electricity generating capacity exists in

many regions of the country. The

Department modeled a national

distribution of generation capacity costs

by estimating the marginal capacity cost

of new generation as a function of the

type of plant serving the capacity and

the utility cost of capital which the

Department obtained from a

representative national sample of

utilities (see TSD Chapter 8).

e. Electricity Price Trends

For the relative change in electricity

prices in future years, DOE relied on

price forecasts from the EIA's Annual

Energy Outlook (AEO). For its ANOPR,

the Department used price forecasts

from the AE02003, the most recent

price forecasts available at the time. The

application of electricity price trends in

the NOPR analysis is discussed in detail

in TSD Chapter 8, section 8.3.7.

ODOE and HVOLT commented that

the price forecasts used by the

Department were too low. (ODOE, No.

66 at p. 4; Public Meeting Transcript,

No. 56.12 at p. 38) Some stakeholders

stated that more volatility should be

added to the forecasts. The Natural

Resources Defense Council (NRDC)

commented that DOE should consider a

scenario where electricity prices

increase unexpectedly. (Public Meeting

Transcript, No. 56.12 at p. 45) The

NPCC stated that the Department

assumed a monotonic wholesale

electricity market and should model

forecasted prices with some volatility.

(Public Meeting Transcript, No. 56.12 at

p. 124) ODOE and ACEEE suggested that

the price trends should be updated with

the most recent AEO forecasts; ACEEE

added that DOE should include a high

electricity price scenario in the analysis.

(ODOE, No. 66 at p. 4; ACEEE, No. 76

at p. 3) Counter to the above

stakeholders, CDA and AK Steel thought

the Department's price forecasts were

reasonable. CDA commented that the

Department was correct to assume a

moderate rate of energy cost increases,

although it also believes a higher rate

could be justified given recent

experience. (CDA, No. 51 at p. 3) AK

Steel added that EIA's long-term

electricity price forecasts are good.

(Public Meeting Transcript, No. 56.12 at

p. 128)

For the NOPR, the Department

updated its price forecasts with trends

from the AE02005 as recommended by

stakeholders, and addressed other

stakeholder concerns through use of

sensitivity analysis. The Department

believes that price forecasts from the

AEO are the most reliable and credible

estimates of future electricity prices. As

compared to AEO2003, the price trends

from AE02005 actually show slightly

lower forecasted prices. During the

writing of this notice, the EIA published

AEO2006, but since the electricity price

forecast did not differ significantly from

AEO2005, the Department did not

update its analysis results using

AEO2006. The Department addresses

stakeholder concerns regarding the

possibility of higher electricity prices

through the sensitivity section of the

LCC analysis (see TSD Chapter 8). This

analysis estimates LCC results under

conditions where electricity prices are

15 percent higher than the Department's

medium scenario. However, as in the

ANOPR analysis, the Department

retained the medium AEO forecast as

the electricity price trend that is most

credible and authoritative with respect

to the analysis of the future economic

impacts of efficiency standards.

3. Inputs Affecting Present Value of

Annual Operating Cost Savings

a. Standards Implementation Date

The Department proposes that the

new energy-efficiency standard for

distribution transformers apply to all

units manufactured three years or more

after publication of the final rule. For

the NOPR analysis, the Department

assumed a 2007 final rule publication;

hence a 2010 implementation or

compliance date. The Department

calculated the LCC for customers as if

each new distribution transformer

purchase occurs in the year

manufacturers must comply with the

standard.

Several comments called for

acceleration of the rulemaking schedule.

ACEEE said the NOPR should be

published by July 2005 and the final

rule six months later. (ACEEE, No. 76 at

p. 4) The National Association of

Regulatory Utility Commissioners

(NARUC) urged DOE to establish a new

standard for distribution transformers as

soon as possible. (NARUC, No. 68 at pp.

2-5) NRDC asked DOE to make a

commitment to a schedule, with

appropriate milestones, that will allow

a final rule to be issued no later than

January 29, 2006. (NRDC, No. 61 at p.

3) ASE urged the Department to

maintain an 18-month schedule to

complete the rulemaking. (ASE, No. 52

at p. 1 and No. 75 at p. 1)

The Department understands that the

rulemaking schedule impacts the date

by which manufacturers of distribution

transformers must comply with any new

energy-efficiency standard. It is

committed to completing the

rulemaking in a timely fashion and

expects to publish a final rule by

September 2007.

b. Discount Rate

The discount rate is the rate at which

future expenditures are discounted to

estimate their present value. It is the

factor that determines the relative

weight of first costs and operating costs

in the LCC calculation. Consumers

experience discount rates in their dayto-day lives either as interest rates on

loans or as rates of return on

investments. Another characterization

of the discount rate is the "time value

of money." The value of a dollar today

is one plus the discount rate times the

value of a dollar a year from now. The

Department estimated consumer

discount rates by calculating the

consumer cost of capital (see TSD

Chapter 8).

 EE-RM/STD-00-550 COMMENT 91.1

44376 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

power factor assumption of 1.0 is 

appropriate. (NEMA, No. 60 at p. 2) 

While the Department agrees with 

Southern Company that actual power 

factors are less than 1.0, they are very 

close to 1.0, and the Department agrees 

with NEMA that use of a power factor 

of 1.0 is appropriate for the analysis of 

the efficiency standard. Using a power 

factor less than 1.0 would slightly 

increase the estimated losses for 

transformers, but would complicate the 

Department's analysis and affect all 

components of the Department's 

analysis where losses are estimated. The 

Department determined that the 

disadvantages of complicating the 

analysis by using an estimated 

distribution of slightly lower power 

factors outweighed the slight increase in 

analytical accuracy that could result. 

d. Electricity Costs 

The Department needed estimates of 

electricity prices and costs to place a 

value on transformer losses for the LCC 

calculation. As noted earlier, the 

Department created two sets of 

electricity prices to estimate annual 

energy expenses for its ANOPR: An 

hourly based estimate of wholesale 

electricity costs for the liquid-immersed 

transformer market, and a tariff-based 

estimate for the dry-type transformer 

market (see TSD Chapter 8). 

Southern Company questioned 

whether wholesale electricity prices are 

the correct prices for liquid-immersed 

transformers, and suggested that the 

Department consider the availability of 

very inexpensive electricity generating 

capacity in some regions. (Public 

Meeting Transcript, No. 56.12 at p. 125 

and pp. 237-238) The Department's 

analysis for both the ANOPR and the 

NOPR estimated the marginal, or 

incremental, wholesale cost of 

electricity. The Department agrees with 

Southern Company that inexpensive 

electricity generating capacity exists in 

many regions ofthe country. The 

Department modeled a national 

distribution of generation capacity costs 

by estimating the marginal capacity cost 

of new generation as a function of the 

type of plant serving the capacity and 

the utility cost of capital which the 

Department obtained from a 

representative national sample of 

utilities (see TSD Chapter 8). 

e. Electricity Price Trends 

For the relative change in electricity 

prices in future years, DOE relied on 

price forecasts from the EIA's Annual 

Energy Outlook (AEO). For its ANOPR, 

the Department used price forecasts 

from the AE02003, the most recent 

price forecasts available at the time. The 

application of electricity price trends in 

the NOPR analysis is discussed in detail 

in TSD Chapter 8, section 8.3.7. 

ODOE and HVOL T commented that 

the price forecasts used by the 

Department were too low. (ODOE, No. 

66 at p. 4; Public Meeting Transcript, 

No. 56.12 at p. 38) Some stakeholders 

stated that more volatility should be 

added to the forecasts. The Natural 

Resources Defense Council (NRDC) 

commented that DOE should consider a 

scenario where electricity prices 

increase unexpectedly. (Public Meeting 

Transcript, No. 56.12 at p. 45) The 

NPCC stated that the Department 

assumed a monotonic wholesale 

electricity market and should model 

forecasted prices with some volatility. 

(Public Meeting Transcript, No. 56.12 at 

p. 124) ODOE and ACEEE suggested that 

the price trends should be updated with 

the most recent AEO forecasts; ACEEE 

added that DOE should include a high 

electricity price scenario in the analysis. 

(ODOE, No. 66 at p. 4; ACEEE, No. 76 

at p. 3) Counter to the above 

stakeholders, CDA and AK Steel thought 

the Department's price forecasts were 

reasonable. CDA commented that the 

Department was correct to assume a 

moderate rate of energy cost increases, 

although it also believes a higher rate 

could be justified given recent 

experience. (CDA, No. 51 at p. 3) AK 

Steel added that EIA's long-term 

electricity price for~casts are good. 

(Public Meeting Transcript, No. 56.12 at 

p. 128) 

For the NOPR, the Department 

updated its price forecasts with trends 

from the AE02005 as recommended by 

stakeholders, and addressed other 

stakeholder concerns through use of 

sensitivity analysis. The Department 

believes that price forecasts from the 

AEO are the most reliable and credible 

estimates of future electricity prices. As 

compared to AE02003, the price trends 

from AE02005 actually show slightly 

lower forecasted prices. During the 

writing of this notice, the EIA published 

AE02006, but since the electricity price 

forecast did not differ significantly from 

AE02005, the Department did not 

update its analysis results using 

AE02006. The Department addresses 

stakeholder concerns regarding the 

possibility of higher electricity prices 

through the sensitivity section of the 

LCC analysis (see TSD Chapter 8). This 

analysis estimates LCC results under 

conditions where electricity prices are 

15 percent higher than the Department's 

medium scenario. However, as in the 

ANOPR analysis, the Department 

retained the medium AEO forecast as 

the electricity price trend that is most 

credible and authoritative with respect 

to the analysis of the future economic 

impacts of efficiency standards. 

3. Inputs Affecting Present Value of 

Annual Operating Cost Savings 

a. Standards Implementation Date 

The Department proposes that the 

new energy-efficiency standard for 

distribution transformers apply to all 

units manufactured three years or more 

after publication of the final rule. For 

the NOPR analysis, the Department 

assumed a 2007 final rule publication; 

hence a 2010 implementation or 

compliance date. The Department 

calculated the LCC for customers as if 

each new distribution transformer 

purchase occurs in the year 

manufacturers must comply with the 

standard. 

Several comments called for 

acceleration of the rulemaking schedule. 

ACEEE said the NOPR should be 

published by July 2005 and the final 

rule six months later. (ACEEE, No. 76 at 

p. 4) The National Association of 

Regulatory Utility Commissioners 

(NARUC) urged DOE to establish a new 

standard for distribution transformers as 

soon as possible. (NARUC, No. 68 at pp. 

2-5) NRDC asked DOE to make a 

commitment to a schedule, with 

appropriate milestones, that will allow 

a final rule to be issued no later than 

January 29, 2006. (NRDC, No. 61 at p. 

3) ASE urged the Department to 

maintain an 18-month schedule to 

complete the rulemaking. (ASE, No. 52 

at p. 1 and No. 75 at p. 1) 

The Department understands that the 

rulemaking schedule impacts the date 

by which manufacturers of distribution 

transformers must comply with any new 

energy-efficiency standard. It is 

committed to completing the 

rulemaking in a timely fashion and 

expects to publish a final rule by 

September 2007. 

b. Discount Rate 

The discount rate is the rate at which 

future expenditures are discounted to 

estimate their present value. It is the 

factor that determines the relative 

weight of first costs and operating costs 

in the LCC calculation. Consumers 

experience discount rates in their dayto-day lives either as interest rates on 

loans or as rates of return on 

investments. Another characterization 

of the discount rate is the "time value 

of money." The value of a dollar today 

is one plus the discount rate times the 

value of a dollar a year from now. The 

Department estimated consumer 

discount rates by calculating the 

consumer cost of capital (see TSD 

Chapter 8). 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44377

Discount rates depend on who is

borrowing and at what scale. Thus, the

discount rates in the LCC analysis are

different than those in the national

impact analysis. This section discusses

consumer discount rates that the

Department used in the LCC analysis.

With respect to consumer discount

rates in the ANOPR, stakeholders

expressed a diversity of views regarding

which discount rates are appropriate for

the LCC analysis. ASE and ODOE

commented that the Department should

use a three-percent real discount rate,

similar to the discount rate used by the

California Energy Commission (CEC) in

recent State-level energy efficiency

analyses. (ASE, No. 75 at p. 3; ODOE,

No. 66 at p. 5) NRDC said that the

Department's use of discount rates

exceeding 5.5 percent real conflicts with

the explicit instructions in NRDC v.

Herrington, because of the court's

instruction to consider payback times of

less than nine years as economically

justified. (NRDC, No. 61 at p. 6) ACEEE

commented that the Department's

choice of discount rates for utilities was

appropriate. (ACEEE, No. 76 at p. 3)

HVOLT recommended that the

Department set efficiency standards on

a three-to five-year consumer

investment return, to represent

commercial customer preferences.

(HVOLT, No. 65 at p. 3)

The Department examined each of

these comments to see if any would lead

to a more accurate description of

consumer economic impacts. In

examining the three-percent discount

rate recommended by ASE and ODOE,

the Department found that the CEC, in

its rulemaking, estimated the consumer

cost of capital using a method similar to

that of the Department. However, the

CEC analyzed a different class of

consumers and used less detailed data.

Therefore, the Department considers its

discount rates to be more accurate for

the distribution transformer energyefficiency analysis than the discount

rates estimated by the CEC for other

products. The Department retained the

consumer discount rates that it used in

the ANOPR analysis, as shown in Table

IV.3. The consumer discount rates

shown in the table are based on a

detailed analysis of risk-adjusted cost of

capital for consumers, as described in

TSD Chapter 8.

TABLE IV.3.-WEIGHTED-AVERAGE DISCOUNT RATES BY DESIGN LINE AND OWNERSHIP CATEGORY

Transformer ownership category

Property Industrial Commercial Investor- Publicly owned Government

owners companies companies owned utilities utilities offices

Mean real discount rate ...........................

Design line Weighted

average

discount rate

4.35% 7.55% 7.46% 4.16% 4.31% 3.33%

Estimated ownership (%)

(%)

1 ................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2

2 ................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2

3 ................................... 4.40 2.1 2.4 4.5 80.0 10.0 1.0

4 ................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2

5 ................................... 5.38 9.5 9.5 27.0 35.0 15.0 4.0

9 ................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9

10 ................................. 6.56 19.0 19.0 54.0 0.0 0.0 7.9

11 ................................. 6.56 19.0 19.0 54.0 0.0 0.0 7.9

12 ................................. 6.56 19.0 19.0 54.0 0.0 0.0 7.9

13 ................................. 6.56 19.0 19.0 54.0 0.0 0.0 7.9

4. Candidate Standard Levels

To conduct the LCC analysis, the

Department first selected CSLs. Based

on its examination of the CSLs, the

Department then selected trial standard

levels (TSLs). From those TSLs, it

developed today's proposed standards.

Cooper Power Industries commented

that DOE should use a consistent

method for all product classes to

determine CSLs. (Cooper, No. 62 at p. 3)

ASAP stated that DOE should examine

a CSL with the maximum efficiency that

maintains a positive economic impact

for each product class. (Public Meeting

Transcript, No. 56.12 at p. 218) ACEEE

recommended that the Department

examine TP 1 plus 0.2 percent, 0.3

percent, and 0.4 percent efficiency

improvements for all design lines. It

encouraged the Department to carefully

examine the cost and other economic

inputs, since the lowest life-cycle cost

point, when compared to TP 1, varies

significantly among design lines.

(ACEEE, No. 76 at p. 1) ACEEE said that

DOE should regroup the CSLs so that

CSL 1 is TP 1, CSL 3 is the minimum

life-cycle cost point, and CSLs 2 and 4

are slightly above and below the

minimum LCC. (ACEEE, No. 50 at p. 1

and No. 76 at p. 2) ACEEE suggested

that DOE realign the CSLs so that they

have approximately equivalent

economic performance. (Public Meeting

Transcript, No. 56.12 at p. 26) EEI and

NRECA recommended that DOE

investigate CSLs that have rated

efficiencies below TP 1, since many

transformers in the current market have

efficiencies below TP 1. (EEI, No. 63 at

p. 2; NRECA, No. 74 at p. 2 ) Howard

stated that it is appropriate to round

candidate standard efficiency levels to

one decimal place. (Howard, No. 70 at

p. 3)

For the NOPR analysis, the

Department complied with most of the

stakeholder recommendations regarding

standard levels. As requested by Cooper,

DOE developed a consistent method for

selecting standard levels for each design

line. In response to the request by

ASAP, the Department defined a

standard level that represented the

maximum energy savings with

approximately no change in LCC. In

response to ACEEE, the Department

defined CSL 4 as the efficiency level

with minimum LCC for each design

line, and realigned CSLs 4 and 5 to have

equivalent economic performance for

each design line. The Department did

not comply with EEI's and NRECA's

requests to examine standard levels

lower than TP 1 because-as described

in this NOPR-the Department has

found that efficiencies higher than or

equal to TP 1 are economically

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44377 

Discount rates depend on who is exceeding 5.5 percent real conflicts with rate recommended by ASE and ODOE, 

borrowing and at what scale. Thus, the the explicit instructions in NRDCv. the Department found that the CEC, in 

discount rates in the LCC analysis are Herrington. because of the court's its rulemaking. estimated the consumer 

different than those in the national instruction to consider payback times of cost of capital using a method similar to 

impact analysis. This section discusses less than nine years as economically that of the Department. However, the 

consumer discount rates that the justified. (NRDC, No. 61 at p. 6) ACEEE CEC analyzed a different class of 

Department used in the LCC analysis. commented that the Department's consumers and used less detailed data. 

With respect to consumer discount choice of discount rates for utilities was Therefore, the Department considers its 

rates in the ANOPR, stakeholders appropriate. (ACEEE, No. 76 at p. 3) discount rates to be more accurate for 

expressed a diversity of views regarding HVOLT recommended that the the distribution transformer energywhich discount rates are appropriate for Department set efficiency standards on efficiency analysis than the discount 

the LCC analysis. ASE and ODOE a three-to five-year consumer rates estimated by the CEC for other 

commented that the Department should investment return, to represent products. The Department retained the 

use a three-percent real discount rate, commercial customer preferences. consumer discount rates that it used in 

similar to the discount rate used by the (HVOLT, No. 65 at p. 3) the ANOPR analysis, as shown in Table 

California Energy Commission (CEC) in The Department examined each of IV.3. The consumer discount rates 

recent State-level energy efficiency these comments to see if any would lead shown in the table are based on a 

analyses. (ASE, No. 75 at p. 3; ODOE, to a more accurate description of detailed analysis of risk-adjusted cost of 

No. 66 at p. 5) NRDC said that the consumer economic impacts. In capital for consumers, as described in 

Department's use of discount rates examining the three-percent discount TSD Chapter 8. 

TABLE IV.3.-WEIGHTED-AVERAGE DISCOUNT RATES BY DESIGN LINE AND OWNERSHIP CATEGORY 

Mean real discount rate ........................... 

Design line Weighted 

average 

discount rate 

(%) 

1 ................................... 4.24 

2 ................................... 4.24 

3 ................................... 4.40 

4 ................................... 4.24 

5 ................................... 5.38 

9 ................................... 6.56 

10 ................................. 6.56 

11 ................................. 6.56 

12 ................................. 6.56 

13 ................................. 6.56 

4. Candidate Standard Levels 

To conduct the LCC analysis, the 

Department first selected CSLs. Based 

on its examination of the CSLs, the 

Department then selected trial standard 

levels (TSLs). From those TSLs. it 

developed today's proposed standards. 

Cooper Power Industries commented 

that DOE should use a consistent 

method for all product classes to 

determine CSLs. (Cooper, No. 62 at p. 3) 

ASAP stated that DOE should examine 

a CSL with the maximum efficiency that 

maintains a positive economic impact 

for each product class. (Public Meeting 

Transcript. No. 56.12 at p. 218) ACEEE 

recommended that the Department 

examine TP 1 plus 0.2 percent, 0.3 

percent, and 0.4 percent efficiency 

improvements for all design lines. It 

encouraged the Department to carefully 

examine the cost and other economic 

inputs, since the lowest life-cycle cost 

Transformer ownership category 

Property Industrial Commercial Investor- Publicly owned Government 

owners companies companies owned utilities utilities offices 

4.35% 7.55% 7.46% 4.16% 4.31% 3.33% 

Estimated ownership (%) 

0.4 

0.4 

2.1 

0.4 

9.5 

19.0 

19.0 

19.0 

19.0 

19.0 

0.5 

0.5 

2.4 

0.5 

9.5 

19.0 

19.0 

19.0 

19.0 

19.0 

0.9 

0.9 

4.5 

0.9 

27.0 

54.0 

54.0 

54.0 

54.0 

54.0 

point, when compared to TP 1, varies 

significantly among design lines. 

(ACEEE, No. 76 at p. 1) ACEEE said that 

DOE should regroup the CSLs so that 

CSL 1 is TP 1, CSL 3 is the minimum 

life-cycle cost point, and CSLs 2 and 4 

are slightly above and below the 

minimum LCC. (ACEEE, No. 50 at p. 1 

and No. 76 at p. 2) ACEEE suggested 

that DOE realign the CSLs so that they 

have approximately equivalent 

economic performance. (Public Meeting 

Transcript, No. 56.12 at p. 26) EEl and 

NRECA recommended that DOE 

investigate CSLs that have rated 

efficiencies below TP 1, since many 

transformers in the current market have 

efficiencies below TP 1. (EEL No. 63 at 

p. 2; NRECA, No. 74 at p. 2) Howard 

stated that it is appropriate to round 

candidate standard efficiency levels to 

one decimal place. (Howard, No. 70 at 

p.3) 

72.0 26.0 0.2 

72.0 26.0 0.2 

80.0 10.0 1.0 

72.0 26.0 0.2 

35.0 15.0 4.0 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

0.0 0.0 7.9 

For the NOPR analysis, the 

Department complied with most of the 

stakeholder recommendations regarding 

standard levels. As requested by Cooper, 

DOE developed a consistent method for 

selecting standard levels for each design 

line. In response to the request by 

ASAP, the Department defined a 

standard level that represented the 

maximum energy savings with 

approximately no change in LCC. In 

response to ACEEE, the Department 

defined CSL 4 as the efficiency level 

with minimum LCC for each design 

line, and realigned CSLs 4 and 5 to have 

equivalent economic performance for 

each design line. The Department did 

not comply with EEl's and NRECA's 

requests to examine standard levels 

lower than TP 1 because-as described 

in this NOPR-the Department has 

found that efficiencies higher than or 

equal to TP 1 are economically 
44378 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

justifiable, and thus the Department is

obligated to pick a standard level that

has efficiencies greater than or equal to

TP 1. If the Department had reason to

believe that any TP 1 levels were not

economically justifiable for a standard,

it would have examined efficiency

levels below TP 1.

Table IV.4 lists the CSLs evaluated for

each design line, expressed in terms of

efficiency, and in terms relative to

NEMA TP 1 efficiency levels.

TABLE IV.4.-CANDIDATE STANDARD LEVELS EVALUATED FOR EACH DESIGN LINE

CSL

1 2 3 4 5 6

TP 1 1/3 of dill. between TP Z/3 of dill. between TP Min LCC Max energy savings Max energy savings

Design line 1 and min LCC 1 and min LCC with no change in

LCC

TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y

% % % % % % % %

1 ........................ 0.0 98. 9 0.14 99.04 0.29 99. 19 0.43 99.33 0.59 99.49 0.69 99.59

2 ........................ 0.0 98.7 0.03 98.73 0.06 98.76 0.09 98.79 0.26 98.96 0.76 99.46

3 ........................ 0.0 99.3 0.08 99.38 0.16 99.46 0.24 99.54 0.44 99.74 0.45 99.75

4 ........................ 0.0 98.9 0.18 99.08 0.36 99.26 0.55 99.45 0.68 99.58 0.71 99.61

5 ........................ 0.0 99.3 0.06 99.36 0.12 99.42 0.17 99.47 0.41 99.71 0.41 99.71

9 ........................ 0.0 98.6 0.22 98.82 0.44 99.04 0.66 99.26 0.81 99.41 0.81 99.41

10 ...................... 0.0 99.1 0.12 99.22 0.23 99.33 0.35 99.45 0.41 99.51 0.41 99.51

11 ...................... 0.0 98.5 0.17 98.67 0.34 98.84 0.51 99.01 0.59 99.09 0.59 99.09

12 ...................... 0.0 99.0 0.12 99.12 0.23 99.23 0.35 99.35 0.40 99.40 0.40 99.40

13 ...................... 0.0 99. 0 0.15 99. 15 0.30 99.30 0.45 99.45 0.55 99.55 0.55 99.55

5. Trial Standard Levels

The TSLs are the efficiency levels

considered by the Department for the

proposed standard. They are based on

the CSLs selected for the LCC analysis.

However, because of special

considerations concerning manufacturer

impacts and design lines (DLs) within

the same product class, some efficiency

levels for DL1 and DL4 are drawn from

the same CSL. See TSD Chapter 10 for

a more detailed explanation . Table IV.5

shows the mapping from the design line

CSLs to the TSLs. In the LCC and LCC

subgroups chapters of the TSD

(Chapters 8 and 11), the Department

reports results in terms of CSLs. In

subsequent analyses (e.g., shipments in

Chapter 9, national impacts in Chapter

10, MIA in Chapter 12) and in this

NOPR, the Department reports all

results in terms of TSLs, mapping the

LCC results according to Table IV.5.

TABLE IV.5.-MAPPING OF THE CANDIDATE STANDARD LEVELS TO TRIAL STANDARD LEVELS

DL1 DL2 DL3 DL4 DL5 DL9 DL10 DL11 DL12 DL13

TSL1 ......... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1

TSL2 ......... CSL1 ....... CSL2....... CSL2....... CSL2....... CSL2 ....... CSL2....... CSL2....... CSL2....... CSL2 ....... CSL2

TSL3 ......... CSL1 ....... CSL3....... CSL3....... CSL3....... CSL3....... CSL3....... CSL3....... CSL3....... CSL3....... CSL3

TSL4 ......... CSL2 ....... CSL4....... CSL4....... CSL3....... CSL4....... CSL4....... CSL4....... CSL4....... CSL4....... CSL4

TSL5 ......... CSL3 ....... CSL5....... CSL5....... CSL5....... CSL5....... CSL5....... CSL5....... CSL5....... CSL5....... CSL5

TSL6 ......... CSL6....... CSL6....... CSL6....... CSL6....... CSL6....... CSL6....... CSL6....... CSL6....... CSL6...... CSL6

Georgia Power asked whether the

efficiency values shown in Table II.d of

the ANOPR apply only to the

representative transformer for each

design line, or if that efficiency is

applicable to all of the kVA sizes

represented by that design line. It noted

that the latter would be too restrictive.

(Georgia Power, No. 78 at pp. 3-4) The

ANOPR document did not provide

efficiency levels for all kVA ratings in

a product class or design line. For the

NOPR, the Department provides a

complete specification of the efficiency

levels for all kVA ratings. Tables 11.1

and 11.2 of this NOPR express the

efficiency ratings for all specific kVA

ratings covered by today's proposed

standard. This additional information

also responds to a comment by ACEEE.

ACEEE asked that the Department

The Department provides this

information in TSD Chapter 8.

6. Miscellaneous Life-Cycle Cost Issues

In response to the ANOPR analysis,

DOE examined several additional issues

relating to the LCC. These issues are

grouped for organizational clarity and

completeness, and are discussed below.

a. Tax Impacts

The Department did not include the

impact of income taxes in the LCC

analysis for the ANOPR. The

Department understands that there are

two ways in which taxes affect the net

impacts attributed to purchasing

equipment that is more energy-efficient

than baseline equipment: (1) Energyefficient equipment typically costs more

to purchase than baseline equipment,

to operate than baseline equipment,

which increases net income and may

increase company taxes.

In general, the Department believes

that the net impact of taxes on the LCC

analysis depends on firm profitability

and expense practices (i.e., how firms

expense the purchase cost of

equipment). In the ANOPR, the

Department sought input on whether

commercial income tax effects are

significant enough to warrant inclusion

in the LCC analysis. 69 FR 45396.

ACEEE commented that income tax

should not be included in the analysis,

because it would significantly

complicate the analysis, and it has

found that many businesses do not pay

income taxes due to the many credits

and deductions that are available in the

current tax code. (ACEEE, No. 76 at p.

4) ODOE stated that it believes the

number of corporations actually paying

income taxes has declined to the point

provide efficiency values for all the kVA which lowers net income and may

ratings in between the representative lower company taxes; and (2) moreunits analyzed. (ACEEE, No. 50 at p. 2) efficient equipment typically costs less

 EE-RM/STD-00-550 COMMENT 91.1

44378 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

justifiable, and thus the Department is 

obligated to pick a standard level that 

has efficiencies greater than or equal to 

TP 1. If the Department had reason to 

believe that any TP 1 levels were not 

economically justifiable for a standard, 

it would have examined efficiency 

levels below TP 1. 

Table IVA lists the CSLs evaluated for 

each design line, expressed in terms of 

efficiency, and in terms relative to 

NEMA TP 1 efficiency levels. 

TABLE IV.4.-CANDIDATE STANDARD LEVELS EVALUATED FOR EACH DESIGN liNE 

CSL 

1 2 3 4 5 6 

TP 1 '13 01 dill. between TP 2fa 01 diff. between TP Min LCC Max energy savings Max energy savings 

Design line 1 and min LCC 1 and min LCC with no change in 

TP 1+ Effic'y TP 1+ 

% % % 

1 ........................ 0.0 98.9 0.14 

2 ........................ 0.0 98.7 0.03 

3 ........................ 0.0 99.3 0.08 

4 ........................ 0.0 98.9 0.18 

5 ........................ 0.0 99.3 0.06 

9 ........................ 0.0 98.6 0.22 

10 ., .................... 0.0 99.1 0.12 

11 ...................... 0.0 98.5 0.17 

12 ...................... 0.0 99.0 0.12 

13 ...................... 0.0 99.0 0.15 

5. Trial Standard Levels 

. The TSLs are the efficiency levels 

considered by the Department for the 

proposed standard. They are based on 

the CSLs selected for the LCC analysis. 

However, because of special 

considerations concerning manufacturer 

LCC 

Effic'y TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y TP 1+ Effic'y 

% % % % 

99.04 0.29 99.19 0.43 

98.73 0.06 98.76 0.09 

99.38 0.16 99.46 0.24 

99.08 0.36 99.26 0.55 

99.36 0.12 99.42 0.17 

98.82 0.44 99.04 0.66 

. 99.22 0.23 99.33 0.35 

98.67 0.34 98.84 0.51 

99.12 0.23 99.23 0.35 

99.15 0.30 99.30 0.45 

impacts and design lines (DLs) within 

the same product class, some efficiency 

levels for DLl and DL4 are drawn from 

the same CSL. See TSD Chapter 10 for 

a more detailed explanation. Table IV.5 

shows the mapping from the design line 

CSLs to the TSLs. In the LCC and LCC 

subgroups chapters of the TSD 

% % % % % 

99.33 0.59 99.49 0.69 99.59 

98.79 0.26 98.96 0.76 99.46 

99.54 0.44 99.74 0.45 99.75 

99.45 0.68 99.58 0.71 99.61 

99.47 0.41 99.71 0.41 99.71 

99.26 0.81 99.41 0.81 99.41 

99.45 0.41 99.51 0.41 99.51 

99.01 0.59 99.09 0.59 99.09 

99.35 0.40 99.40 0.40 99.40 

99.45 0.55 99.55 0.55 99.55 

(Chapters 8 and 11), the Department 

reports results in terms of CSLs. In 

subsequent analyses (e.g., shipments in 

Chapter 9, national impacts in Chapter 

10, MIA in Chapter 12) and in this 

NOPR, the Department reports all 

results in terms of TSLs, mapping the 

LCC results according to Table IV.5. 

TABLE IV.5.-MAPPING OF THE CANDIDATE STANDARD LEVELS TO TRIAL STANDARD LEVELS 

DL1 DL2 DL3 DL4 DL5 DL9 DL10 DL11 DL12 DL13 

TSL1 CSL1 ....... CSL1 ....... CSL1 

TSL2 CSL1 ....... CSL2 ....... CSL2 

TSL3 CSL1 ....... CSL3 ....... CSL3 

TSL4 CSL2 ....... CSL4 ....... CSL4 

TSL5 CSL3 ....... CSL5 ....... CSL5 

TSL6 ......... CSL6 ....... CSL6 ....... CSL6 

Georgia Power asked whether the 

efficiency values shown in Table n.d of 

the ANOPR apply only to the 

representative transformer for each 

design line, or if that efficiency is 

applicable to all of the kVA sizes 

represented by that design line. It noted 

that the latter would be too restrictive. 

(Georgia Power, No. 78 at pp. 3-4) The 

ANOPR document did not provide 

efficiency levels for all kVA ratings in 

a product class or design line. For the 

NOPR, the Department provides a 

complete specification of the efficiency 

levels for all kVA ratings. Tables ILl 

and 11.2 of this NOPR express the 

efficiency ratings for all specific kVA 

ratings covered by today's proposed 

standard. This additional information 

also responds to a comment by ACEEE. 

ACEEE asked that the Department 

provide efficiency values for all the kVA 

ratings in between the representative 

units analyzed. (ACEEE, No. 50 at p. 2) 

....... CSL1 ....... CSL1 ....... CSL1 ....... CSL1 . ...... CSL1 . ...... CSL1 . ...... CSL1 

....... CSL2 ....... CSL2 . ...... CSL2 ....... CSL2 . ...... CSL2 . ...... CSL2 . ...... CSL2 

....... CSL3 ....... CSL3 ....... CSL3 ....... CSL3 . ...... CSL3 . ...... CSL3 . ...... CSL3 

....... CSL3 ....... CSL4 ....... CSL4 ....... CSL4 .. ..... CSL4 . ...... CSL4 .. ..... CSL4 

....... CSL5 ....... CSL5 ....... CSL5 ....... CSL5 .. ..... CSL5 .. ..... CSL5 . ...... CSL5 

....... CSL6 . ...... CSL6 ....... CSL6 ....... CSL6 .. ..... CSL6 .. ..... CSL6 . ...... CSL6 

The Department provides this 

information in TSD Chapter 8. 

6. Miscellaneous Life-Cycle Cost Issues 

In response to the ANOPR analysis, 

DOE examined several additional issues 

relating to the LCC. These issues are 

grouped for organizational clarity and 

completeness, and are discussed below. 

a. Tax Impacts 

The Department did not include the 

impact of income taxes in the LCC 

analysis for the ANOPR. The 

Department understands that there are 

two ways in which taxes affect the net 

impacts attributed to purchasing 

equipment that is more energy-efficient 

than baseline equipment: (1) Energyefficient equipment typically costs more 

to purchase than baseline equipment, 

which lowers net income and may 

lower company taxes; and (2) moreefficient equipment typically costs less 

to operate than baseline equipment, 

which increases net income and may 

increase company taxes. 

In general·, the Department believes 

that the net impact of taxes on the LCC 

analysis depends on firm profitability 

and expense practices (Le., how firms 

expense the purchase cost of 

equipment). In the ANOPR, the 

Department sought input on whether 

commercial income tax effects are 

significant enough to warrant inclusion 

in the LCC analysis. 69 FR 45396. 

ACEEE commented that income tax 

should not be included in the analysis, 

because it would significantly 

complicate the analysis, and it has 

found that many businesses do not pay 

income taxes due to the many credits 

and deductions that are available in the 

current tax code. (ACEEE, No. 76 at p. 

4) ODOE stated that it believes the 

number of corporations actually paying 

income taxes has declined to the point 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44379

where the overall impact of including

income tax effects should be negligible.

(ODOE, No. 66 at p. 6) Southern

Company questioned how many firms

do not pay income taxes. (Public

Meeting Transcript, No. 56.12 at p. 164)

NPCC stated that the analysis should be

based on after-income-tax data, but also

noted that businesses do not necessarily

pay income tax. (Public Meeting

Transcript, No. 56.12 at p. 158)

The Department agrees with ACEEE

that the inclusion of income tax effects

would significantly complicate the

analysis. In analyzing the available

options for including income tax effects,

the Department could not find an

estimation method where-with the

existing data gaps-sufficient accuracy

could be obtained to justify the

increased analytical complexity. The

Department therefore did not include an

estimate of income tax impacts in the

LCC analysis.

b. Cost Recovery Under Deregulation,

Rate Caps

During the ANOPR review,

stakeholders expressed mixed concerns

regarding the potential impact of

distribution transformer efficiency

standards under utility deregulation.

Southern Company commented that the

impact on electric utilities of increasing

the cost of transformers will vary

depending on the regulatory scheme for

the different utilities. It recommended

that the Department include this issue

in the analysis, especially for the

utilities that are under rate cap

legislation. (Public Meeting Transcript,

No. 56.12 at p. 187) ODOE stated that

there is a small likelihood of future

electricity market deregulation and

recommended that the Department

ignore deregulation for the NOPR

analysis. (ODOE, No. 66 at p. 5)

For the ANOPR, stakeholders stated

many reasons why consumers may not

be able to recover the added investment

cost of higher efficiency distribution

transformers. EEI expressed concern

that political and economic risks related

to deregulation will force utilities to

make uneconomic (non-recoverable)

incremental investments in efficient

transformers. EEI requested that DOE

include the effect of reduced utility

earnings in the LCC analysis. (EEI, No.

63 at p. 4) ACEEE noted that utility

representatives pointed out that some

utilities currently have caps on their

rates, which limit their ability to recover

additional transformer costs. ACEEE

expects that regulators would be

supportive of cost recovery for

reasonable transformer cost increases.

(ACEEE, No. 76 at p. 3) NRDC

commented that many utilities believe

they cannot recover the additional costs

associated with more-efficient

transformers, but this will not be a

problem because utility regulation

throughout the country allows the

distribution utility to achieve a

regulated rate of return on all reasonable

and prudent investment. NRDC noted

that some utilities may find today's

investments in high-efficiency

transformers to be economically

troublesome because they are subject to

rate caps, but these rate caps all expire

before the transformer efficiency

standard would go into effect. New rate

cases would then result in a new rate

structure consistent with the standardscompliant transformer investments.

(NRDC, No. 61 at pp. 7-8) ASE looked

into the issue of rate caps and found

that about 41 percent of electricity sales

are in States with restructured

electricity rate regulations, with about

27 percent of sales subject to rate caps,

but that these caps expire steadily from

2005 to 2010. (ASE, No. 52 at p. 4)

Georgia Power also asserted that utility

companies cannot raise their prices to

make up for the expected rise in

transformer prices that will result from

higher efficiency requirements without

proceeding through the regulatory

process. It stated, therefore, that DOE

needs to weigh the financial burden this

rulemaking may place on electric

utilities before issuing a final rule.

(Georgia Power, No. 78 at p. 4) NEMA

also expressed concern that the entity

paying the additional capital cost for a

more energy-efficient transformer would

frequently not be the beneficiary of the

resultant energy cost savings. (NEMA,

No. 48 at p. 1)

The concern expressed by

stakeholders regarding the potential lack

of cost recovery for distribution

transformer investments is a classic

example of "split incentives" for

efficiency investments. A split incentive

occurs when the entity that makes an

investment is different from the entity

that will receive the economic benefits

of the investment. Split incentives

prevent economically viable

investments because, without receiving

the benefits of an investment, the

investor loses motivation to make

investments that otherwise might have

good returns. If the Department were to

model split incentives in the LCC

analysis, it would need to divide

ownership of first costs and operating

cost savings for a fraction of the

transformers in the analysis. If the cost

of capital were the same for the owner

of the transformer and the owner of the

operating cost savings, then the average

LCC savings result would actually

remain the same, although the spread of

LCC savings in the LCC distribution

results would increase. Some owners

would only incur costs, while others

would only receive benefits.

The Department decided not to

explicitly model split incentives in the

LCC analysis for the NOPR. Such

modeling would have little impact on

the total net LCC savings for the Nation.

While the cost and the benefits would

be divided between two different

owners in the split incentive case, the

sum would produce the same

approximate net LCC savings as a model

that does not include split incentives.

The Department does, however, report

the increase in first cost and the

decrease in operating cost savings for

each design line and efficiency level in

TSD Chapter 8. Stakeholders can

therefore evaluate the impact of

standards under a split-incentive

scenario where the increased

transformer cost and the operating cost

savings are owned by different entities.

c. Other Issues

HVOLT commented that DOE should

consider incremental price compared to

incremental benefit instead of total price

to total benefit, where the increments

are taken by comparing the results of

one standard level to the results of the

next highest standard level under

consideration. (Public Meeting

Transcript, No. 56.12 at p. 262) ACEEE

stated that incremental analysis is not

necessary. (Public Meeting Transcript,

No. 56.12 at p. 158) The Department

does not use incremental analysis in the

evaluation of standards because of legal

interpretations of the methodology it is

required to follow. As described in

section V.C of this NOPR, the

Department followed its normal

approach in selecting a proposed energy

conservation standard for distribution

transformers. It started by comparing the

maximum technologically feasible level

with the base case, and determined

whether that level was economically

justified. If it found the maximum

technologically feasible level to be

unjustified, the Department then

analyzed the next lower TSL to

determine whether that level was

economically justified. The Department

repeated this procedure until it

identified a TSL that was economically

justified. This procedure that the

Department followed for selecting

today's proposed standard level is that

which the Department has historically

determined is consistent with EPCA, as

amended.

Georgia Power commented that the

Department's calculations for the

economic justification of, and energy

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 200B/Proposed Rules 44379 

where the overall impact of including 

income tax effects should be negligible. 

(ODOE, No. 66 at p. 6) Southern 

Company questioned how many firms 

do not pay income taxes. (Public 

Meeting Transcript. No. 56.12 at p. 164) 

NPCC stated that the analysis should be 

based on after-income-tax data. but also 

noted that businesses do not necessarily 

pay income tax. (Public Meeting 

Transcript, No. 56.12 at p. 158) 

The Department agrees with ACEEE 

that the inclusion of income tax effects 

would significantly complicate the 

analysis. In analyzing the available 

options for including income tax effects, 

the Department could not find an 

estimation method where-with the 

existing data gaps-sufficient accuracy 

could be obtained to justify the 

increased analytical complexity. The 

Department therefore did not include an 

estimate of income tax impacts in the 

LCC analysis. 

b. Cost Recovery Under Deregulation, 

Rate Caps 

During the ANOPR review, 

stakeholders expressed mixed concerns 

regarding the potential impact of 

distribution transformer efficiency 

standards under utility deregulation. 

Southern Company commented that the 

impact on electric utilities of increasing 

the cost of transformers will vary 

depending on the regulatory scheme for 

the different utilities. It recommended 

that the Department include this issue 

in the analysis, especially for the 

utilities that are under rate cap 

legislation. (Public Meeting Transcript, 

No. 56.12 at p. 187) ODOE stated that 

there is a small likelihood of future 

electricity market deregulation and 

recommended that the Department 

ignore deregulation for the NOPR 

analysis. (ODOE. No. 66 at p. 5) 

For the ANOPR. stakeholders stated 

many reasons why consumers may not 

be able to recover the added investment 

cost of higher efficiency distribution 

transformers. EEl expressed concern 

that political and economic risks related 

to deregulation will force utilities to 

make uneconomic (non-recoverable) 

incremental investments in efficient 

transformers. EEl requested that DOE 

include the effect of reduced utility 

earnings in the LCC analysis. (EEl, No. 

63 at p. 4) ACEEE noted that utility 

representatives pointed out that some 

utilities currently have caps on their 

rates. which limit their ability to recover 

additional transformer costs. ACEEE 

expects that regulators would be 

supportive of cost recovery for 

reasonable transformer cost increases. 

(ACEEE. No. 76 at p. 3) NRDC 

commented that many utilities believe 

they cannot recover the additional costs 

associated with more-efficient 

transformers, but this will not be a 

problem because utility regulation 

throughout the country allows the 

distribution utility to achieve a 

regulated rate of return on all reasonable 

and prudent investment. NRDC noted 

that some utilities may find today's 

investments in high-efficiency 

transformers to be economically 

troublesome because they are subject to 

rate caps, but these rate caps all expire 

before the transformer efficiency 

standard would go into effect. New rate 

cases would then result in a new rate 

structure consistent with the standardscompliant transformer investments. 

(NRDC. No. 61 at pp. 7-8) ASE looked 

into the issue of rate caps and found 

that about 41 percent of electricity sales 

are in States with restructured 

electricity rate regulations. with about 

27 percent of sales subject to rate caps. 

but that these caps expire steadily from 

2005 to 2010. (ASE. No. 52 at p. 4) 

Georgia Power also asserted that utility 

companies cannot raise their prices to 

make up for the expected rise in 

transformer prices that will result from 

higher efficiency requirements without 

proceeding through the regulatory 

process. It stated. therefore. that DOE 

needs to weigh the financial burden this 

rulemaking may place on electric 

utilities before issuing a final rule. 

(Georgia Power. No. 78 at p. 4) NEMA 

also expressed concern that the entity 

paying the additional capital cost for a 

more energy-efficient transformer would 

frequently not be the beneficiary of the 

resultant energy cost savings. (NEMA. 

No. 48 at p. 1) 

The concern expressed by 

stakeholders regarding the potential lack 

of cost recovery for distribution 

transformer investments is a classic 

example of "split incentives" for 

efficiency investments. A split incentive 

occurs when the entity that makes an 

investment is different from the entity 

that will receive the economic benefits 

of the investment. Split incentives 

prevent economically viable 

investments because. without receiving 

the benefits of an investment. the 

investor loses motivation to make 

investments that otherwise might have 

good returns. If the Department were to 

model split incentives in the LCC 

analysis. it would need to divide 

ownership of first costs and operating 

cost savings for a fraction of the 

transformers in the analysis. If the cost 

of capital were the same for the owner 

of the transformer and the owner of the 

operating cost savings. then the average 

LCC savings result would actually 

remain the same. although the spread of 

LCC savings in the LCC distribution 

results would increase. Some owners 

would only incur costs. while others 

would only receive benefits. 

The Department decided not to 

explicitly model split incentives in the 

LCC analysis for the NOPR. Such 

modeling would have little impact on 

the total net LCC savings for the Nation. 

While the cost and the benefits would 

be divided between two different 

owners in the split incentive case. the 

sum would produce the same 

approximate net LCC savings as a model 

that does not include split incentives. 

The Department does. however. report 

the increase in first cost and the 

decrease in operating cost savings for 

each design line and efficiency level in 

TSD Chapter 8. Stakeholders can 

therefore evaluate the impact of 

standards under a split-incentive 

scenario where the increased 

transformer cost and the operating cost 

savings are owned by different entities. 

c. Other Issues 

HVOL T commented that DOE should 

consider incremental price compared to 

incremental benefit instead of total price 

to total benefit. where the increments 

are taken by comparing the results of 

one standard level to the results of the 

next highest standard level under 

consideration. (Public Meeting 

Transcript. No. 56.12 at p. 262) ACEEE 

stated that incremental analysis is not 

necessary. (Public Meeting Transcript. 

No. 56.12 at p. 158) The Department 

does not use incremental analysis in the 

evaluation of standards because of legal 

interpretations of the methodology it is 

required to follow. As described in 

section V.C of this NOPR. the 

Department followed its normal 

approach in selecting a proposed energy 

conservation standard for distribution 

transformers. It started by comparing the 

maximum technologically feasible level 

with the base case. and determined 

whether that level was economically 

justified. If it found the maximum 

technologically feasible level to be 

unjustified. the Department then 

analyzed the next lower TSL to 

determine whether that level was 

economicaJly justified. The Department 

repeated this procedure until it 

identified a TSL that was economically 

justified. This procedure that the 

Department followed for selecting 

today's proposed standard level is that 

which the Department has historically 

determined is consistent with EPCA. as 

amended. 

Georgia Power commented that the 

Department's calculations for the 

economic justification of. and energy 
44380 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

savings associated with, higherefficiency transformers are not

applicable to every utility in the Nation.

It noted that each utility is different and

there are too many variables that cannot

be accurately accounted for in such

calculations. (Georgia Power, No. 78 at

pp. 1-2) For the liquid-immersed design

lines (1-5), Georgia Power analyzed the

percentage change in price and TOC for

several kVA sizes for each of the CSLs

beyond TP 1. It found that, for all these

cases, the TOC actually increased in

contrast to the decrease in LCC found by

the Department, indicating that the

savings in energy do not economically

justify the increase in first cost. (Georgia

Power, No. 78 at pp. 4-5)

The Department recognizes that the

TOG approach used by utilities can

yield results that are substantially

different from the Department's LCC

analysis. The standard TOC approach

used by electric utilities is typically

calculated according to the regulatory

mandates of cost recovery rate

regulation. For cost recovery, the annual

expenses associated with an investment

in equipment need to be increased (or

marked up) to generate revenue for

those utility costs that may not be

directly related to the equipment

investments but still need to be

recovered (i.e., operation and

maintenance expenses). This is

formulated in terms of a fixed charge

rate (FCR), which is used to calculate

the annual revenue required to cover the

expenses of a capital investment such

that a utility can stay in business. The

FCR used by utilities is generally larger

than the revenues required to cover just

the cost of capital. In the LCC analysis,

DOE only accounted for the capital and

investment expenses that are directly

related to the purchase of the equipment

being analyzed. The factor that

represents the annual expenses required

to recover capital costs is called the

capital recovery factor (CRF) and is

generally less than the FCR. The

Department therefore recognizes that

investments in efficiency that are

economically justified under EPCA, as

amended, may not be economically

justified with respect to utility TOC

evaluations that are performed under

the assumptions of utility rate-setting

regulation.

D. National Impact Analysis-National

Energy Savings and Net Present Value

Analysis

The national impact analysis

evaluates the impact of a proposed

standard from a national perspective

rather than from the consumer

perspective represented by the LCC.

When it evaluates a proposed standard

from a national perspective, the

Department must consider several other

factors that are not included in the LCC

analysis. One of the primary factors the

Department modeled in the national

impact analysis was the gradual

replacement of existing, less-efficient

transformers with more-efficient,

standard-compliant transformers over

time. This rate of replacement was

estimated by an equipment shipments

model that describes the sale of

transformers for replacement and for

inclusion in new electrical distribution

system infrastructure. A second major

factor included in the national impact

analysis was the fact that the national

cost of capital may differ from the

consumer cost of capital, and thus the

discount rate used in the national

impact analysis can be different from

that used in the LCC. The third factor

the Department included in the national

impact analysis was the difference

between the energy savings obtained by

the consumer and the energy savings

obtained by the Nation. Because of the

effect of distribution and generation

losses, the national energy savings from

a proposed standard are larger than the

sum of the individual consumers'

energy savings. The details of the

Department's national impact analysis

are provided in Chapters 9 and 10 of the

TSD.

During the ANOPR review, the

Department received stakeholder

comments on its approach to two of

these three major factors. While it did

not receive comments indicating any

stakeholder disagreement with its

accounting of national versus consumer

energy savings, the Department did

receive stakeholder comments

concerning its shipments model and

national discount rates.

Regarding DOE's shipments model,

HVOLT commented that DOE considers

the dry-type transformer market to have

inelastic pricing, but that it actually is

quite elastic and DOE should

incorporate a price response that allows

a shift to liquid-immersed transformers.

(Public Meeting Transcript, No. 56.12 at

pp. 173-174) NEMA agreed that drytype transformers have price elasticity

of demand, since deferring or foregoing

investments may be a viable alternative

for some customers. (NEMA, No. 48 at

p. 1)

The Department agrees with HVOLT

and NEMA that the sales of dry-type

transformers are likely to be elastic.

Since detailed shipments data that can

be used for elasticity estimates are not

available for dry-type transformers, the

Department estimated elasticities using

data from an economically similar

commercial appliance-commercial air

conditioners. Both commercial air

conditioners and distribution

transformers are integral elements of

building and facilities electromechanical design and construction,

and are installed during building

construction and rehabilitation. The

shipments elasticity scenarios the

Department examined are provided in

Table IV.6, and are explained in more

detail in TSD Chapter 9.

TABLE IV.6.-SUMMARY OF SHIPMENTS MODEL INPUTS

Input

Shipments data ................

Shipments backcast ........

Shipments forecast ..........

Dry-type/liquid-immersed

market shares.

Regular replacement market.

ANOPR description

Third-party expert (HVOLT) for the year 2001 ................................................

For years 1977-2000 , used Bureau of Economic Analysis' (BEA) manufacturing data for distribution transformers. Source: http://www.bea.doc.gov/

bea1pn/ndn0304.zip.

For years 1950-1976, used EIA's electricity sales data . Source: http://

www. eia.doe.gov/emeu/aer/txt/stb0805.xls.

Years 2002-2035: Based on AE02003 ..........................................................

Based on EIA's electricity sales data and AE02003 ......................................

Based on a survival function constructed from a Weibull distribution function

normalized to produce a 32-year mean lifetime . Source: ORNL 6804/Ri,

The Feasibility of Replacing or Upgrading Utility Distribution Transformers

During Routine Maintenance, page D-1.

Changes for NOPR

No change.

Added three more years of BEA's

manufacturing data-for years 2001

through 2003.

Years 2010-2038: Based on

AE02005.

Based on EIA's electricity sales data

and AE02005.

No change.

 EE-RM/STD-00-550 COMMENT 91.1

44380 Federal Register I Vol. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 

savings associated with, higherefficiency transformers are not 

applicable to every utility in the Nation. 

It noted that each utility is different and 

there are too many variables that cannot 

be accurately accounted for in such 

calculations. (Georgia Power, No. 78 at 

pp. 1-2) For the liquid-immersed design 

lines (1-5), Georgia Power analyzed the 

percentage change in price and TOC for 

several kVA sizes for each of the CSLs 

beyond TP 1. It found that, for all these 

cases, the TOC actually increased in 

contrast to the decrease in LCC found by 

the Department, indicating that the 

savings in energy do not economically 

justify the increase in first cost. (Georgia 

Power, No. 78 at pp. 4-5) . The Department recognizes that the 

TOC approach used by utilities can 

yield results that are substantially 

different from the Department's LCC 

analysis. The standard TOC approach 

used by electric utilities is typically 

calculated according to the regulatory 

mandates of cost recovery rate 

regulation. For cost recovery, the annual 

expenses associated with an investment 

in equipment need to be increased (or 

marked up) to generate revenue for 

those utility costs that may not be 

directly related to the equipment 

investments but still need to be 

recovered (i.e., operation and 

maintenance expenses). This is 

formulated in terms of a fixed charge 

rate (FCR), which is used to calculate 

the annual revenue required to cover the 

expenses of a capital investment such 

that a utility can stay in business. The 

FCR used by utilities is generally larger 

than the revenues required to cover just 

the cost of capital. In the LCC analysis, 

DOE only accounted for the capital and 

investment expenses that are directly 

related to the purchase of the equipment 

being analyzed. The factor that 

represents the annual expenses required 

to recover capital costs is called the 

capital recovery factor (CRF) and is 

generally less than the FCR. The 

Department therefore recognizes that 

investments in efficiency that are 

economically justified under EPCA, as 

amended, may not be economically 

justified with respect to utility TOC 

evaluations that are performed under 

the assumptions of utility rate-setting 

regulation. 

D. National Impact Analysis-National 

Energy Savings and Net Present Value 

Analysis 

The national impact analysis 

evaluates the impact of a proposed 

standard from a national perspective 

rather than from the consumer 

perspective represented by the LCe. 

When it evaluates a proposed standard 

from a national perspective, the 

Department must consider several other 

factors that are not included in the LCC 

analysis. One of the primary factors the 

Department modeled in the national 

impact analysis was the gradual 

replacement of existing, less-efficient 

transformers with more-efficient, 

standard-compliant transformers over 

time. This rate of replacement was 

estimated by an equipment shipments 

model that describes the sale of 

transformers for replacement and for 

inclusion in new electrical distribution 

system infrastructure. A second major 

factor included in the national impact 

analysis was the fact that the national 

cost of capital may differ from the 

consumer cost of capital, and thus the 

discount rate used in the national 

impact analysis can be different from 

that used in the LCe. The third factor 

the Department included in the national 

impact analysis was the difference 

between the energy savings obtained by 

the consumer and the energy savings 

obtained by the Nation. Because of the 

effect of distribution and generation 

losses, the national energy savings from 

a proposed standard are larger than the 

sum of the individual consumers' 

energy savings. The details of the 

Department's national impact analysis 

are provided in Chapters 9 and 10 of the 

TSD. 

During the ANOPR review, the 

Department received stakeholder 

comments on its approach to two of 

these three major factors. While it did 

not receive comments indicating any 

stakeholder disagreement with its 

accounting of national versus consumer 

energy savings, the Department did 

receive stakeholder comments 

concerning its shipments model and 

national discount rates. 

Regarding DOE's shipments model, 

HVOL T commented that DOE considers 

the dry-type transformer market to have 

inelastic pricing, but that it actually is 

quite elastic and DOE should 

incorporate a price response that allows 

a shift to liquid-immersed transformers. 

(Public Meeting Transcript, No. 56.12 at 

pp. 173-174) NEMA agreed that drytype transformers have price elasticity 

of demand, since deferring or foregoing 

investments may be a viable alternative 

for some customers. (NEMA, No. 48 at 

p.1) 

The Department agrees with HVOL T 

and NEMA that the sales of dry-type 

transformers are likely to be elastic. 

Since detailed shipments data that can 

be used for elasticity estimates are not 

available for dry-type transformers, the 

Department estimated elasticities using 

data from an economically similar 

commercial appliance-commercial air 

conditioners. Both commercial air 

conditioners and distribution 

transformers are integral elements of 

building and facilities electromechanical design and construction, 

and are installed during building 

construction and rehabilitation. The 

shipments elasticity scenarios the 

Department examined are provided in 

Table IV.6, and are explained in more 

detail in TSD Chapter 9. 

TABLE IV.6.-SUMMARY OF SHIPMENTS MODEL INPUTS 

Input 

Shipments data ............... . 

Shipments backcast ....... . 

Shipments forecast ......... . 

Dry-type/liquid-immersed 

market shares. 

Regular replacement market. 

ANOPR description 

Third-party expert (HVOL T) for the year 2001 ............................................... . 

For years 1977-2000, used Bureau of Economic Analysis' (BEA) manufacturing data for distribution transformers. Source: http://www.bea.doc.gov/ 

bealpnlndn0304.zip. 

For years 1950-1976, used EIA's electricity sales data. Source: http:// 

www.eia.doe.govlemeulaerltxtlstbOB05.xls. 

Years 2002-2035: Based on AE02003 ......................................................... . 

Changes for NOPR 

No change. 

Added three more years of BEA's 

manufacturing data-for years 2001 

through 2003. 

Years 2010-2038: Based on 

AE02005. 

Based on EIA's electricity sales data and AE02003 ...................................... Based on EIA's electricity sales data 

and AE02005. 

Based on a survival function constructed from a Wei bull distribution function No change. 

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 0-1. 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

Input

Elasticities ........................

TABLE IV.6.-SUMMARY OF SHIPMENTS MODEL INPUTS-Continued

ANOPR description

For liquid-immersed transformers:

• Low: 0.00 ..................................................................................................

• Medium: -0.04 ........................................................................................

• High: -0.20 ..............................................................................................

For dry-type transformers:

• 0.00 ...........................................................................................................

A summary of the NES and NPV these inputs can be found in TSD

analytical model inputs are provided in Chapter 10.

Table IV.7. More detailed discussion on

Changes for NOPR

44381

For liquid-immersed transformers:

No change.

For dry-type transformers:

• Low: 0.00

• Medium: -0.02

• High: -0.20

TABLE IV. 7.-SUMMARY OF NES AND NPV MODEL INPUTS

Input

Shipments ........................

Implementation date of

standard.

Base case efficiencies .....

Standards case efficiencies.

Annual energy consumption per unit.

Total installed cost per

unit.

Electricity expense per

unit.

Escalation of electricity

prices.

Electricity site-to-source

conversion.

Discount rates ..................

Analysis year ...................

ANOPR description

Annual shipments from shipments model ........................................................

Assumed to be 2007 ........................................................................................

Constant efficiency through 2035. Equal to weighted -average efficiency in

2007.

Constant efficiency at the specified standard level from 2007 to 2035 ..........

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).

Weighted-average values as a function of efficiency level (from LCC analysis).

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).

AE02003 forecasts (to 2025) and extrapolation for 2035 and beyond ..........

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.

3% and 7% real ...............................................................................................

Equipment and operating costs are discounted to the year of equipment

price data, 2001.

E. Commercial Consumer Subgroup

Analysis

In analyzing the potential impacts of

new or amended standards, the

Department evaluates impacts on

identifiable groups (i.e., subgroups) of

customers, such as different types of

businesses, which may be

disproportionately affected by a national

standard. For this rulemaking, the

Department identified rural electric

cooperatives and municipal utilities as

transformer consumer subgroups that

could be disproportionately affected,

and examined the impact of proposed

standards on these groups. The

consumer subgroup analysis is

discussed in detail in TSD Chapter 11.

The Department's selection of

subgroups responded directly to

comments received on the ANOPR.

NRECA expressed concern that

transformers servicing a single customer

on a rural electric system may not be

represented in the general LCC analysis.

It requested the Department to take

steps to include more data from

cooperatives serving sparsely populated

areas with long radial distribution lines.

It commented that costs resulting from

the DOE standard could increase to an

unjustified level for rural electric

cooperatives, which purchase relatively

large numbers of transformers compared

to their system load. (NRECA, No. 74 at

p. 2) Southern Company commented

that municipal utilities and rural

electric cooperatives should be

Changes for NOPR

No change.

Assumed to be 2010.

Constant efficiency through 2038.

Equal to weighted-average efficiency in 2010.

Constant at the efficiency at the specified standard level from 2010 to

2038.

No change.

No change.

No change.

Used AE02005 forecasts (to 2025)

and extrapolation for 2038 and beyond.

Updated conversion factors from

NEMS.

No change.

Equipment and operating costs are

discounted to year 2004.

evaluated separately . (Public Meeting

Transcript, No. 56.12 at p. 211) In its

commercial consumer subgroup

analysis, the Department analyzed

municipal utilities and rural electric

cooperatives separately , including

additional data from cooperatives that

serve sparsely populated areas with long

radial distribution lines.

The results of the Department's

commercial consumer subgroup

analysis are summarized in section

V.A.1.c below and described in detail in

TSD Chapter 11.

F. Manufacturer Impact Analysis

1. General Description

The Department performed an MIA to

estimate the financial impact of higher

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 44381 

TABLE IV.6.-SUMMARY OF SHIPMENTS MODEL INPUTs-Continued 

Input ANOPR description Changes 'for NOPR 

Elasticities ...................... .. For liquid-immersed transformers: For liquid-immersed transformers: 

e Low: 0.00 ................................................................................................ .. No change. 

• Medium: - 0.04 ...................................................................................... .. 

• High: _ 0.20 ............................................................................................. . 

For dry-type transformers: For dry-type transformers: 

• 0.00 .......................................................................................................... . • Low: 0.00 

• Medium: - 0.02 

• High: - 0.20 

A summary of the NES and NPV 

analytical model inputs are provided in 

Table IV.7. More detailed discussion on 

these inputs can be found in TSD 

Chapter 10. 

Input 

Shipments ....................... . 

Implementation date of 

standard. 

Base case efficiencies ..... 

Standards case efficiencies. 

Annual energy consumption per unit. 

Total installed cost per 

unit. 

Electricity expense per 

unit. 

Escalation of electricity 

prices. 

ElectriCity site-to-source 

conversion. 

Discount rates ................ .. 

Analysis year .................. . 

TABLE IV. 7.-SUMMARY OF NES AND NPV MODEL INPUTS 

ANOPR description Changes for NOPR 

Annual shipments from shipments model............. ........................................... No change. 

Assumed to be 2007 ........................................................................................ Assumed to be 2010. 

Constant efficiency through 2035. Equal to weighted-average efficiency in 

2007. 

Constant efficiency at the specified standard level from 2007 to 2035 .......... 

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). 

Weighted-average values as a function of efficiency level (from LCC analysis). 

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). 

AE02003 forecasts (to 2025) and extrapolation for 2035 and beyond .......... 

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. 

3% and 7% real .............................................................................................. . 

Equipment and operating costs are discounted to the year of equipment 

price data, 2001. 

Constant efficiency through 2038. 

Equal to weighted-average efficiency in 2010. 

Constant at the efficiency at the specified standard level from 2010 to 

2038. 

No change. 

No change. 

No change. 

Used AE0200S forecasts (to 2025) 

and extrapolation for 2038 and beyond. 

Updated conversion factors from 

NEMS. 

No change. 

EqUipment and operating costs are 

discounted to year 2004. 

E. Commercial Consumer Subgroup 

Analysis 

The Department's selection of 

subgroups responded directly to 

comments received on the ANOPR. 

NRECA expressed concern that 

transformers servicing a single customer 

on a rural electric system may not be 

represented in the general LCC analysis. 

It requested the Department to take 

steps to include more data from 

cooperatives serving sparsely populated 

areas with long radial distribution lines. 

It commented that costs resulting from 

the DOE standard could increase to an 

unjustified level for rural electric 

cooperatives, which purchase relatively 

large numbers of transformers compared 

to their system load. (NRECA, No. 74 at 

p. 2) Southern Company commented 

that municipal utilities and rural 

electric cooperatives should be 

evaluated separately. (Public Meeting 

Transcript, No. 56.12 at p. 211) In its 

commercial consumer subgroup 

analysis, the Department analyzed 

municipal utilities and rural electric 

cooperatives separately, including 

additional data from cooperatives that 

serve sparsely populated areas with long 

radial distribution lines. 

In analyzing the potential impacts of 

new or amended standards, the 

Department evaluates impacts on 

identifiable groups (Le., subgroups) of 

customers, such as different types of 

businesses, which may be 

disproportionately affected by a national 

standard. For this rulemaking, the 

Department identified rural electric 

cooperatives and municipal utilities as 

transformer consumer subgroups that 

could be disproportionately affected, 

and examined the impact of proposed 

standards on these groups. The 

consumer subgroup analysis is 

discussed in detail in TSD Chapter 11. 

The results of the Department's 

commercial consumer subgroup 

analysis are summarized in section 

V.A.1.c below and described in detail in 

TSD Chapter 11. 

F. Manufacturer Impact Analysis 

1. General Description 

The Department performed an MIA to 

estimate the financial impact of higher 
44382 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

efficiency standards on distribution

transformer manufacturers 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

customized for this rulemaking. The

GRIM inputs are information regarding

the industry cost structure, shipments,

and revenues. The key output is the

INPV. Different sets of assumptions

(scenarios) produce different results.

The qualitative part of the MIA

addresses factors such as product

characteristics, characteristics of

particular firms, and market and

product trends, and includes assessment

of the impacts of standards on

subgroups of manufacturers. The

complete MIA is outlined in TSD

Chapter 12.

The Department outlined the MIA

approach in the ANOPR. 69 FR 45412.

In section II.C. of the ANOPR, the

Department asked stakeholders for

comments on significant one-time

additional costs manufacturers would

incur if efficiency standards were

introduced. 69 FR 45393. The MIA

approach was also discussed at the

September 28, 2004, ANOPR public

meeting.

The Department conducted the MIA

in three phases. Phase 1, "Industry

Profile," consisted of the preparation of

an industry characterization. Phase 2,

"Industry Cash Flow," focused on the

industry as a whole. In this phase, DOE

used the GRIM to prepare an industry

cash-flow analysis. The Department

used publicly available information

developed in Phase 1 to adapt the GRIM

structure to facilitate the analysis of

distribution transformer standards. In

Phase 3, "Subgroup Impact Analysis,"

the Department conducted structured,

detailed interviews with six

manufacturers. Two of the six

manufacturers are small businesses (750

or fewer employees). Three of the

manufacturers produce medium-voltage,

dry-type transformers, collectively

representing more than 70 percent of the

U.S. medium-voltage, dry-type market.

Four of the manufacturers produce

liquid-immersed transformers,

collectively representing more than 70

percent of the U.S. liquid-immersed

market. The purpose of the interviews

was to gather information about the

financial impacts of standards on

manufacturers, as well as the impacts of

standards on employment and

manufacturing capacity. The interviews

provided valuable information that the

Department used to evaluate the

impacts of an energy conservation

standard on manufacturers' cash flows,

manufacturing capacities, and

employment levels.

In addition to the six structured,

detailed interviews, the Department

conducted telephone interviews with

four additional small businesses. The

Department based the small-business

interviews on an interview guide that

was significantly different from that

used for the structured, detailed

interviews. Three of the small

businesses interviewed produce

medium-voltage, dry-type transformers,

and one produces liquid-immersed

transformers. Finally, in addition to the

six detailed interviews and the four

short telephone interviews with small

businesses, the Department conducted

telephone interviews with several

companies that supply materials and

equipment to the U.S. distribution

transformer industry. The material and

equipment suppliers included both U.S.

firms and foreign suppliers. The

Department visited one of the U.S. core

steel suppliers. The following

paragraphs describe more specifically

the steps DOE took in developing the

information on which the MIA was

based.

2. Industry Profile

Phase 1 of the MIA consisted of

preparing an industry profile. Before

initiating the detailed impact studies,

DOE collected information on the

present and past structure and market

characteristics of the distribution

transformer industry. This activity

involved both quantitative and

qualitative efforts to assess the industry

and equipment to be analyzed. The

information collected included (1)

manufacturer market shares,

characteristics, and financial

information; (2) product characteristics;

and (3) trends in the number of firms,

the market, and product characteristics.

The industry profile included a

topdown cost analysis of the

distribution transformer manufacturing

industry that DOE used to derive cost

and financial inputs for the GRIM, e.g.,

revenues; material, labor, overhead, and

depreciation costs; selling, general, and

administrative (SG&A) expenses; and

research and development (R&D)

expenses. The Department used public

sources of information to calibrate its

initial characterization of the industry,

including Securities and Exchange

Commission (SEC) 10-K reports,

corporate annual reports, the U.S.

Census Bureau's Economic Census, Dun

& Bradstreet reports, and industry

analysis from Ibbotson Associates.

3. Industry Cash-Flow Analysis

Phase 2 of the MIA focused on the

financial impacts of standards on the

industry as a whole. The analytical tool

DOE used for calculating the financial

impacts of standards on manufacturers

is the GRIM. In Phase 2, the Department

used the GRIM to perform a preliminary

industry cash-flow analysis. To perform

this analysis, DOE used the financial

values determined during Phase I and

the shipment projections used in the

NES analysis.

4. Subgroup Impact Analysis

In Phase 3 of the MIA, the Department

established two distinct subgroups of

distribution transformer manufacturers

that could be affected by efficiency

standards: Liquid-immersed and

medium-voltage, dry-type. The

Department also evaluated the impact of

the energy conservation standards on

small businesses. Small businesses, as

defined by the Small Business

Administration (SBA) for the

distribution transformer manufacturing

industry, are manufacturing enterprises

with 750 or fewer employees.

5. Government Regulatory Impact Model

Analysis

An energy conservation standard can

affect a manufacturer's cash flow in

three distinct ways: (1) It may require

increased investment; (2) it may result

in higher production costs per unit; and

(3) it may alter revenue by virtue of

higher per-unit prices and changes in

sales volumes. As mentioned, the

Department uses the GRIM to quantify

the changes in cash flow that result in

a higher or lower industry value. The

GRIM analysis for this NOPR used a

number of inputs-annual shipments;

prices; material, labor, and overhead

costs; SG&A expenses; taxes; and capital

expenditures-to arrive at a series of

annual net cash flows beginning in 2004

and continuing to 2038. The Department

collected this information from a

number of sources, including publicly

available data; structured, detailed

interviews with six manufacturers; and

short telephone interviews with an

additional four small manufacturers.

The Department calculated INPV by

discounting and summing the annual

net cash flows. Chapter 12 of the TSD

contains additional information about

the GRIM analysis.

For the MIA, the Department

considered two distinct markup

scenarios: (1) The preservation-of-grossmargin-percentage scenario, and (2) the

preservation-of-operating-profit

scenario. Under the "preservation-ofgross-margin-percentage" scenario, DOE

 EE-RM/STD-00-550 COMMENT 91.1

44382 Federal Register IVoI. 71, No. 150 I Friday, August 4, 2006 I Proposed Rules 

efficiency standards on distribution 

transformer manufacturers 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 

customized for this rulemaking. The 

GRIM inputs are information regarding 

the industry cost structure, shipments, 

and revenues. The key output is the 

INPV. Different sets of assumptions 

(scenarios) produce different results. 

The qualitative part of the MIA 

addresses factors such as product 

characteristics, characteristics of 

particular firms, and market and 

product trends, and includes assessment 

of the impacts of standards on 

subgroups of manufacturers. The 

complete MIA is outlined in TSD 

Chapter 12. 

The Department outlined the MIA 

approach in the ANOPR. 69 FR 45412. 

In section II.C. of the ANOPR, the 

Department asked stakeholders for 

comments on significant one-time 

additional costs manufacturers would 

incur if efficiency standards were 

introduced. 69 FR 45393. The MIA 

approach was also discussed at the 

September 28, 2004, ANOPR public 

meeting. 

The Department conducted the MIA 

in three phases. Phase 1, "Industry 

Profile," consisted of the preparation of 

an industry characterization. Phase 2, 

"Industry Cash Flow," focused on the 

industry as a whole. In this phase, DOE 

used the GRIM to prepare an industry 

cash-flow analysis. The Department 

used publicly available information 

developed in Phase 1 to adapt the GRIM 

structure to facilitate the analysis of 

distribution transformer standards. In 

Phase 3, "Subgroup Impact Analysis," 

the Department conducted structured, 

detailed interviews with six 

manufacturers. Two ofthe six 

manufacturers are small businesses (750 

or fewer employees). Three ofthe 

manufacturers produce medium-voltage, 

dry-type transformers, collectively 

representing more than 70 percent of the 

U.S. medium-voltage, dry-type market. 

Four of the manufacturers produce 

liquid-immersed transformers, 

collectively representing more than 70 

percent of the U.S. liquid-immersed 

market. The purpose of the interviews 

was to gather information about the 

financial impacts of standards on 

manufacturers, as well as the impacts of 

standards on employment and 

manufacturing capacity. The interviews 

provided valuable information that the 

Department used to evaluate the 

impacts of an energy conservation 

standard on manufacturers' cash flows, 

manufacturing capacities, and 

employment levels. 

In addition to the six structured, 

detailed interviews, the Department 

conducted telephone interviews with 

four additional small businesses. The 

Department based the small-business 

interviews on an interview guide that 

was significantly different from that 

used for the structured, detailed 

interviews. Three of the small 

businesses interviewed produce 

medium-voltage, dry-type transformers, 

and one produces liquid-immersed 

transformers. Finally, in addition to the 

six detailed interviews and the four 

short telephone interviews with small 

businesses, the Department conducted 

telephone interviews with several 

companies that supply materials and 

equipment to the U.S. distribution 

transformer industry. The material and 

equipment suppliers included both U.S. 

firms and foreign suppliers. The 

Department visited one of the U.S. core 

steel suppliers. The following 

paragraphs describe more specifically 

the steps DOE took in developing the 

information on which the MIA was based. 

2. Industry Profile 

Phase 1 of the MIA consisted of 

preparing an industry profile. Before 

initiating the detailed impact studies, 

DOE collected information on the 

present and past structure and market 

characteristics of the distribution 

transformer industry. This activity 

involved both quantitative and 

qualitative efforts to assess the industry 

and equipment to be analyzed. The 

information collected included (1) 

manufacturer market shares, 

characteristics, and financial 

information; (2) product characteristics; 

and (3) trends in the number of firms, 

the market, and product characteristics. 

The industry profile included a 

topdown cost analysis of the 

distribution transformer manufacturing 

industry that DOE used to derive cost 

and financial inputs for the GRIM, e.g., 

revenues; material, labor, overhead, and 

depreciation costs; selling, general, and 

administrative (SG&A) expenses; and 

research and development (R&D) 

expenses. The Department used public 

sources of information to calibrate its 

initial characterization of the industry, 

including Securities and Exchange 

Commission (SEC) 10-K reports, 

corporate annual reports, the U.S. 

Census Bureau's Economic Census, Dun 

& Bradstreet reports, and industry 

analysis from Ibbotson Associates. 

3. Industry Cash-Flow Analysis 

Phase 2 of the MIA focused on the 

financial impacts of standards on the 

industry as a whole. The analytical tool 

DOE used for calculating the financial 

impacts of standards on manufacturers 

is the GRIM. In Phase 2, the Department 

used the GRIM to perform a preliminary 

industry cash-flow analysis. To perform 

this analysis, DOE used the financial 

values determined during Phase 1 and 

the shipment projections used in the 

NES analysis. 

4. Subgroup Impact Analysis 

In Phase 3 of the MIA, the Department 

established two distinct subgroups of 

distribution transformer manufacturers 

that could be affected by efficiency 

standards: Liquid-immersed and 

medium-voltage, dry-type. The 

Department also evaluated the impact of 

the energy conservation standards on 

small businesses. Small businesses, as 

defined by the Small Business 

Administration (SBA) for the 

distribution transformer manufacturing 

industry, are manufacturing enterprises 

with 750 or fewer employees. 

5. Government Regulatory Impact Model 

Analysis 

An energy conservation standard can 

affect a manufacturer's cash flow in 

three distinct ways: (1) It may require 

increased investment; (2) it may result 

in higher production costs per unit; and 

(3) it may alter revenue by virtue of 

higher per-unit prices and changes in 

sales volumes. As mentioned, the 

Department uses the GRIM to quantify 

the changes in cash flow that result in 

a higher or lower industry value. The 

GRIM analysis for this NOPR used a 

number of inputs-annual shipments; 

prices; material, labor, and overhead 

costs; SG&A expenses; taxes; and capital 

expenditures-to arrive at a series of 

annual net cash flows beginning in 2004 

and continuing to 2038. The Department 

collected this information from a 

number of sources, including publicly 

available data; structured, detailed 

interviews with six manufacturers; and 

short telephone interviews with an 

additional four small manufacturers. 

The Department calculated INPV by 

discounting and summing the annual 

net cash flows. Chapter 12 of the TSD 

contains additional information about 

the GRIM analysis. 

For the MIA, the Department 

considered two distinct markup 

scenarios: (1) The preservation-of-grossmargin-percentage scenario, and (2) the 

preservation-of-operating-profit 

scenario. Under the "preservation-ofgross-margin-percentage" scenario, DOE 
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules 44383

applied a single, uniform "gross margin

percentage" markup across all efficiency

levels. This scenario implies that, as

production cost increases with

efficiency, the absolute dollar markup

will increase. The Department assumed

that the non-production cost markup,

which includes SG&A expenses, R&D

expenses, interest, and profit, was 1.25.

This markup is consistent with the one

that the Department assumed in the

engineering analysis and the base case

of the GRIM.

The implicit assumption behind the

"preservation-of-operating-profit"

scenario is that the industry can

maintain or preserve its operating profit

(in absolute dollars) after the standard.

The industry would do so by passing its

increased costs on to its customers

without increasing its operating profits

in absolute dollars. The Department

implemented this markup scenario in

the GRIM by setting the non-production

cost markups at each TSL to yield

approximately the same operating profit

in both the base case and the standard

case in the year after standard

implementation (2011).

The Department received several

comments concerning the one-time

expenditures that industry would incur

in order to manufacture transformers

that comply with energy conservation

standards. The Department refers to

such one-time expenditures as

conversion capital expenditures and

product conversion expenses, where the

latter includes research, development,

testing, and marketing expenditures

related to achieving compliance. NEMA

commented that the Department should

contact individual manufacturers to

learn about additional one-time

conversion capital costs. (NEMA, No. 48

at p. 2) PEMCO Corporation made a

similar comment, noting that mandatory

energy conservation standards would

cause small manufacturers to make new

capital investments above and beyond

those already made to improve

transformer efficiency. (PEMCO, No. 57

at p. 1) Finally, ODOE urged the

Department to consider the costs of

transition to a standards-compliant

industry. (ODOE, No. 66 at p. 3) The

Department considers conversion

capital expenditures, and also product

conversion expenses, in setting energy

conservation standards for any product,

recognizes the importance of these

issues to distribution transformer

manufacturers, and explicitly

considered such expenditures in its

MIA. The Department gathered

information pertaining to conversion

expenditures by interviewing both

transformer manufacturers and

equipment suppliers to the distribution

transformer industry.

EMSIC commented that investments

will not cause a significant impact on

manufacturers of liquid-immersed

transformers if the energy conservation

standard is set below a certain

threshold. EMSIC asserted that liquidimmersed transformers can be made

more efficient primarily by using better

materials, without the need for

significant investment. (EMSIC, No. 73

at p. 2) The Department concurs that

conversion capital expenditures would

be relatively modest for TSLs 1 through

4, which are the trial standard levels

that would not involve partial or full

conversion to amorphous core

technology. TSLs 5 and 6 would require

partial and full conversion to

amorphous core technology,

respectively, and the conversion capital

expenditures necessary at these TSLs

would be significant.

EMSIC commented that an energy

conservation standard would positively

affect liquid-immersed transformer

manufacturer revenue (through higher

prices), while also limiting product

diversity and thereby dampening the

cost increases at higher efficiencies.

EMSIC suggested that one mechanism

by which an energy conservation

standard would limit product diversity

would be the elimination of lower-grade

materials. (EMSIC, No. 73 at p. 2) In the

GRIM analysis, the Department

explicitly considered the positive

impact of standards on manufacturer

revenue. While the Department

recognizes that production cost

increases in moving to higher TSLs

could be dampened by limited product

diversity, the Department believes that

this effect will be small compared to the

other effects explicitly considered in its

analysis.

The final MIA-related comment

received by the Department pertained to

the Nation's import tariff on raw core

steel. ZDMH is a mechanically scribed,

deep-domain refined, core steel that

survives the annealing process without

negatively impacting the low loss

properties of the steel. Since ZDMH core

steel is available from only one foreign

country, U.S. transformer manufacturers

would have to purchase ZDMH subject

to this tariff. This would give foreign

transformer manufacturers that do not

impose this tariff (e.g., in Mexico) an

advantage in producing transformers

using ZDMH core steel, since finished

cores or transformers would not be

subject to the tariff. ERMCO asked the

Department to keep this issue in mind

when choosing the standard, to avoid

putting domestic manufacturers at a

disadvantage. (ERMCO, No. 58 at p. 2)

The Department addressed the ZDMH

issue in its engineering analysis by

modeling Mexican-made transformers,

because this would be the expected

production scenario for ZDMH

transformers. Since, according to the

Department's analysis, ZDMH design

option combinations would not be the

most cost-effective at any trial standard

level, DOE did not explicitly address the

impact of the U.S. core steel tariff on

transformer manufacturing capacity in

the MIA. To review the costeffectiveness findings of ZDMH in

comparison to other transformer core

steels, see TSD Chapter 5.

G. Employment Impact Analysis

The Process Rule includes

employment impacts among the factors

that DOE considers in selecting a

proposed standard. Employment

impacts include direct and indirect

impacts. Direct employment impacts are

any changes in the number of

employees for distribution transformer

manufacturers, their suppliers, and

related service firms. Indirect impacts

are those changes of employment in the

larger economy that occur due to the

shift in expenditures and capital

investment that is caused by the

purchase and operation of more efficient

transformer equipment. The MIA

addresses direct employment impacts;

this section describes indirect impacts.

Indirect employment impacts from

distribution transformer standards

consist of the net jobs created or

eliminated in the national economy,

other than in the manufacturing sector

being regulated, as a consequence of: (1)

Reduced spending by end users on

energy (electricity, gas-including

liquefied petroleum gas-and oil); (2)

reduced spending on new energy supply

by the utility industry; (3) increased

spending on the purchase price of new

distribution transformers; and (4) the

effects of those three factors throughout

the economy. The Department expects

the net monetary savings from standards

to be redirected to other forms of

economic activity. The Department also

expects these shifts in spending and

economic activity to affect the demand

for labor.

In developing this proposed rule, the

Department estimated indirect national

employment impacts using an input/

output model of the U.S. economy,

called IMBUILD (impact of building

energy efficiency programs). The

Department's Office of Building

Technology, State, and Community

Programs (now the Building

Technologies Program) developed the

model. IMBUILD is a personalcomputer-based, economic-analysis

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006 I Proposed Rules 44383 

applied a single, uniform "gross margin 

percentage" markup across all efficiency 

levels. This scenario implies that, as 

production cost increases with 

efficiency, the absolute dollar markup 

will increase. The Department assumed 

that the non-production cost markup, 

which includes SG&A expenses, R&D 

expenses, interest. and profit. was 1.25. 

This markup is consistent with the one 

that the Department assumed in the 

engineering analysis and the base case 

of the GRIM. 

The implicit assumption behind the 

"preservation-of-operating-profit" 

scenario is that the industry can 

maintain or preserve its operating profit 

(in absolute dollars) after the standard. 

The industry would do so by passing its 

increased costs on to its customers 

without increasing its operating profits 

in absolute dollars. The Department 

implemented this markup scenario in 

the GRIM by setting the non-production 

cost markups at each TSL to yield 

approximately the same operating profit 

in both the base case and the standard 

case in the year after standard 

implementation (2011). 

The Department received several 

comments concerning the one-time 

expenditures that industry would incur 

in order to manufacture transformers 

that comply with energy conservation 

standards. The Department refers to 

such one-time expenditures as 

conversion capital expenditures and 

product conversion expenses. where the 

latter includes research. development. 

testing. and marketing expenditures 

related to achieving compliance. NEMA 

commented that the Department should 

contact individual manufacturers to 

learn about additional one-time 

conversion capital costs. (NEMA, No. 48 

at p. 2) PEMCO Corporation made a 

similar comment, noting that mandatory 

energy conservation standards would 

cause small manufacturers to make new 

capital investments above and beyond 

those already made to improve 

transformer efficiency. (PEMCO. No. 57 

at p. 1) Finally. ODOE urged the 

Department to consider the costs of 

transition to a standards-compliant 

industry. (ODOE. No. 66 at p. 3) The 

Department considers conversion 

capital expenditures, and also product 

conversion expenses. in setting energy 

conservation standards for any product. 

recognizes the importance ofthese 

issues to distribution transformer 

manufacturers. and explicitly 

considered such expenditures in its 

MIA. The Department gathered 

information pertaining to conversion 

expenditures by interviewing both 

transformer manufacturers and 

equipment suppliers to the distribution 

transformer industry. 

EMSIC commented that investments 

will not cause a significant impact on 

manufacturers of liquid-immersed 

transformers if the energy conservation 

standard is set below a certain 

threshold. EMSIC asserted that liquidimmersed transformers can be made 

more efficient primarily by using better 

materials, without the need for 

significant investment. (EMSIC, No. 73 

at p. 2) The Department concurs that 

conversion capital expenditures would 

be relatively modest for TSLs 1 through 

4. which are the trial standard levels 

that would not involve partial or full 

conversion to amorphous core 

technology. TSLs 5 and 6 would require 

partial and full conversion to 

amorphous core technology. 

respectively. and the conversion capital 

expenditures necessary at these TSLs 

would be significant. 

EMSIC commented that an energy 

conservation standard would positively 

affect liquid-immersed transformer 

manufacturer revenue (through higher 

prices), while also limiting product 

diversity and thereby dampening the 

cost increases at higher efficiencies. 

EMSIC suggested that one mechanism 

by which an energy conservation 

standard would limit product diversity 

would be the elimination of lower-grade 

materials. (EMSIC. No. 73 at p. 2) In the 

GRIM analysis. the Department 

explicitly considered the positive 

impact of standards on manufacturer 

revenue. While the Department 

recognizes that production cost 

increases in moving to higher TSLs 

could be dampened by limited product 

diversity. the Department believes that 

this effect will be small compared to the 

other effects explicitly considered in its 

analysis. 

The final MIA-related comment 

received by the Department pertained to 

the Nation's import tariff on raw core 

steel. ZDMH is a mechanically scribed, 

deep-domain refined. core steel that 

survives the annealing process without 

negatively impacting the low loss 

properties of the steel. Since ZDMH core 

steel is available from only one foreign 

country. U.S. transformer manufacturers 

would have to purchase ZDMH subject 

to this tariff. This would give foreign 

transformer manufacturers that do not 

impose this tariff (e.g., in Mexico) an 

advantage in producing transformers 

using ZDMH core steel, since finished 

cores or transformers would not be 

subject to the tariff. ERMCO asked the 

Department to keep this issue in mind 

when choosing the standard, to avoid 

putting domestic manufacturers at a 

disadvantage. (ERMCO. No. 58 at p. 2) 

The Department addressed the ZDMH 

issue in its engineering analysis by 

modeling Mexican-made transformers. 

because this would be the expected 

production scenario for ZDMH 

transformers. Since. according to the 

Department's analysis, ZDMH design 

option combinations would not be the 

most cost-effective at any trial standard 

level, DOE did not explicitly address the 

impact ofthe U.S. core steel tariff on 

transformer manufacturing capacity in 

the MIA. To review the costeffectiveness findings of ZDMH in 

comparison to other transformer core 

steels, see TSD Chapter 5. 

C. Employment Impact Analysis 

The Process Rule includes 

employment impacts among the factors 

that DOE considers in selecting a 

proposed standard. Employment 

impacts include direct and indirect 

impacts. Direct employment impacts are 

any changes in the number of 

employees for distribution transformer 

manufacturers. their suppliers. and 

related service firms. Indirect impacts 

are those changes of employment in the 

larger economy that occur due to the 

shift in expenditures and capital 

investment that is caused by the 

purchase and operation of more efficient 

transformer equipment. The MIA 

addresses direct employment impacts; 

this section describes indirect impacts. 

Indirect employment impacts from 

distribution transformer standards 

consist of the net jobs created or 

eliminated in the national economy, 

other than in the manufacturing sector 

being regulated. as a consequence of: (1) 

Reduced spending by end users on 

energy (electricity. gas-including 

liquefied petroleum gas-and oil); (2) 

reduced spending on new energy supply 

by the utility industry; (3) increased 

spending on the purchase price of new 

distribution transformers; and (4) the 

effects of those three factors throughout 

the economy. The Department expects 

the net monetary savings from standards 

to be redirected to other forms of 

economic activity. The Department also 

expects these shifts in spending and 

economic activity to affect the demand 

for labor. 

In developing this proposed rule. the 

Department estimated indirect national 

employment impacts using an input/ 

output model of the U.S. economy. 

called IMBUILD (impact of building 

energy efficiency programs). The 

Department's Office of Building 

Technology, State, and Community 

Programs (now the Building 

Technologies Program) developed the 

model. IMBUILD is a personalcomputer-based, economic-analysis 
44384 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

model that characterizes the

interconnections among 35 sectors of

the economy as national input/output

structural matrices, using data from the

U.S. Bureau of Labor Statistics. The

IMBUILD model estimates changes in

employment, industry output, and wage

income in the overall U.S. economy

resulting from changes in expenditures

in the various sectors of the economy.

The Department estimated changes in

expenditures using the NES

spreadsheet. IMBUILD then estimated

the net national indirect employment

impacts of potential distribution

transformer efficiency standards on

employment by sector.

While both the IMBUILD input/

output model and the direct use of BLS

employment data suggest the proposed

distribution transformer standards could

increase the net demand for labor in the

economy, the gains would most likely

be very small relative to total national

employment. The Department therefore

concludes only that the proposed

distribution transformer standards are

likely to produce employment benefits

that are sufficient to offset fully any

adverse impacts on employment in the

distribution transformer or energy

industries.

For more details on the employment

impact analysis, see TSD Chapter 14.

The Department did not receive

stakeholder comments on these indirect

employment impact methods, which it

proposed in the ANOPR for use in the

NOPR analysis.

H. Utility Impact Analysis

The proposed distribution transformer

energy-efficiency standards have the

distinct feature of regulating a product

that also has electric utilities as one of

the major product consumers. The

Department therefore analyzed one

portion of the impacts on utilities from

the consumer perspective and another

portion of impacts from the utility

sector perspective. Those impacts that

the Department analyzed in the utility

impact analysis are from the utility

sector perspective and include the

impacts on the number of power plants

constructed and the fuel consumption of

the sector. Financial impacts on the

utility sector are described in the LCC

analysis.

The Department analyzed the effects

of proposed standards on electric utility

industry generation capacity and fuel

consumption using a variant of the

EIA's National Energy Modeling System

(NEMS).3 NEMS, which is available in

a For more information on NEMS, please refer to

the U.S. Department of Energy, Energy Information

Administration documentation. A useful summary

the public domain, is a large, multisectoral, partial-equilibrium model of

the U.S. energy sector. The EIA uses

NEMS to produce its Annual Energy

Outlook-a widely recognized baseline

energy forecast for the U.S. The

Department used a variant known as

NEMS-BT.4

The Department conducted the utility

analysis as policy deviations from the

AE02005, applying the same basic set of

assumptions. The utility analysis

reported the changes in installed

capacity and generation, by fuel type,

that result for each TSL, as well as

changes in end-use electricity sales.

Details of the utility analysis methods

and results are reported in TSD Chapter

13. The Department did not receive

stakeholder comments on the utility

impact analysis methods proposed in

the ANOPR.

I. Environmental Analysis

The Department determined the

environmental impacts of the proposed

standards. Specifically, DOE calculated

the reduction in power plant emissions

of C02, sulfur dioxide (SO2), NOx , and

mercury (Hg), using the NEMS-BT

computer model. The environmental

assessment published with the TSD,

however, does not include the estimated

reduction in power plant emissions of

SO2 because, as discussed below, any

such reduction resulting from an

efficiency standard would not affect the

overall level of SO2 emissions in the

U.S. Like SO2, future emissions of NOx

and Hg will be subject to emissions

caps. The Department calculated a

forecast of emissions reductions for

these two types of emissions reductions,

for emissions under an uncapped

scenario. Under emissions-cap

regulation, the Department assumes that

the uncapped emissions reduction

estimate corresponds to the generation

of emissions allowance credits under an

emissions-cap scenario.

The NEMS-BT is run similarly to the

AE02005 NEMS, except that

distribution transformer energy usage is

reduced by the amount of energy (by

fuel type) saved due to the trial standard

levels. The Department obtained the

input of energy savings from the NES

spreadsheet. For the environmental

is National Energy Modeling System: An Overview

2003, DOE/EIA-0581 (2003), March, 2003.

4 DOE/EIA approves use of the name NEMS to

describe only an official version of the model

without any modification to code or data. Because

this analysis entails some minor code modifications

and the model is run under various policy scenarios

that are variations on DOE/EIA assumptions, the

Department refers to it by the name NEMS-BT (BT

is DOE's Building Technologies Program, under

whose aegis this work has been performed). NEMSBT was previously called NEMS-BRS.

analysis, the output is the forecasted

physical emissions. The net benefit of

the standard is the difference between

emissions estimated by NEMS-BT and

the AEO2005 Reference Case.

The NEMS-BT tracks CO2 emissions

using a detailed module that provides

robust results because of its broad

coverage of all sectors and inclusion of

interactive effects. In the case of SO2,

the Clean Air Act Amendments of 1990

set an emissions cap on all power

generation. The attainment of this target,

however, is flexible among generators

and is enforced by applying market

forces, through the use of emissions

allowances and tradable permits. As a

result, accurate simulation of SO2

trading tends to imply that the effect of

efficiency standards on physical

emissions will be near zero because

emissions will always be at, or near, the

ceiling. Thus, there is virtually no real

possible SO2 environmental benefit

from electricity savings as long as there

is enforcement of the emissions ceilings.

Though there may not be an actual

reduction in SO2 emissions from

electricity savings, there still may be an

economic benefit from reduced

emissions demand. Electricity savings

decrease the need to generate SO2

emissions from power production, and

consequently can decrease the need to

purchase or generate SO2 emissions

allowance credits. This decreases the

costs of complying with regulatory caps

on emissions. See the environmental

assessment, a separate report within the

TSD, for a discussion of these issues.

Regarding the environmental

assessment, ASAP stated that DOE

should report other emissions impacts

in addition to NOx and CO2, such as Hg

and particulates. (Public Meeting

Transcript, No. 56.12 at p. 247) The

Department responded to this comment

by adding Hg to the emissions reported

in the environmental assessment.

Particulates are a special case because

they arise not only from direct

emissions, but also from complex

atmospheric chemical reactions that

result from NOx and SO2 emissions.

Because of the highly complex and

uncertain relationship between

particulate emissions and particulate

concentrations that impact air quality,

the Department did not report

particulate emissions.

 EE-RM/STD-00-550 COMMENT 91.1

44384 Federal Register! Vol. 71, No. 150/ Friday, August 4, 2006/ Proposed Rules 

model that characterizes the 

interconnections among 35 sectors of 

the economy as national input!output 

structural matrices, using data from the 

U.S. Bureau of Labor Statistics. The 

IMBUILD model estimates changes in 

employment, industry output, and wage 

income in the overall U.S. economy 

resulting from changes in expenditures 

in the various sectors of the economy. 

The Department estimated changes in 

expenditures using the NES 

spreadsheet. IMBUILD then estimated 

the net national indirect employment 

impacts of potential distribution 

transformer efficiency standards on 

employment by sector. 

While both the IMBUILD input! 

output model and the direct use of BLS 

employment data suggest the proposed 

distribution transformer standards could 

increase the net demand for labor in the 

economy, the gains would most likely 

be very small relative to total national 

employment. The Department therefore 

concludes only that the proposed 

distribution transformer standards are 

likely to produce employment benefits 

that are sufficient to offset fully any 

adverse impacts on employment in the 

distribution transformer or energy 

industries. 

For more details on the employment 

impact analysis, see TSD Chapter 14. 

The Department did not receive 

stakeholder comments on these indirect 

employment impact methods, which it 

proposed in the ANOPR for use in the 

NOPR analysis. 

H. Utility Impact Analysis 

The proposed distribution transformer 

energy-efficiency standards have the 

distinct feature of regulating a product 

that also has electric utilities as one of 

the major product consumers. The 

Department therefore analyzed one 

portion of the impacts on utilities from 

the consumer perspective and another 

portion of impacts from the utility 

sector perspective. Those impacts that 

the Department analyzed in the utility 

impact analysis are from the utility 

sector perspective and include the 

impacts on the number of power plants 

constructed and the fuel consumption of 

the sector. Financial impacts on the 

utility sector are described in the LCC 

analysis. 

The Department analyzed the effects 

of proposed standards on electric utility 

industry generation capacity and fuel 

consumption using a variant of the 

EIA's National Energy Modeling System 

(NEMS).3 NEMS, which is available in 

3 For more information on NEMS. please refer to 

the U.S. Department of Energy. Energy Information 

Administration documentation. A useful summary 

the public domain, is a large, multisectoral, partial-equilibrium model of 

the U.S. energy sector. The EIA uses 

NEMS to produce its Annual Energy 

Outlook-a widely recognized baseline 

energy forecast for the U.S. The 

Department used a variant known as NEMS-BT.4 

The Department conducted the utility 

analysis as policy deviations from the 

AE02005, applying the same basic set of 

assumptions. The utility analysis 

reported the changes in installed 

capacity and generation, by fuel type, 

that result for each TSL, as well as 

changes in end-use electricity sales. 

Details of the utility analysis methods 

and results are reported in TSD Chapter 

13. The Department did not receive 

stakeholder comments on the utility 

impact analysis methods proposed in 

theANOPR. 

I. Environmental Analysis 

The Department determined the 

environmental impacts of the proposed 

standards. Specifically, DOE calculated 

the reduction in power plant emissions 

of CO2 , sulfur dioxide (S02), NOx , and 

mercury (Hg), using the NEMS-BT 

computer model. The environmental 

assessment published with the TSD, 

however, does not include the estimated 

reduction in power plant emissions of 

S02 because, as discussed below, any 

such reduction resulting from an 

effiCiency standard would not affect the 

overall level of S02 emissions in the 

U.S. Like S02, future emissions of NO x 

and Hg will be subject to emissions 

caps. The Department calculated a 

forecast of emissions reductions for 

these two types of emissions reductions, 

for emissions under an uncapped 

scenario. Under emissions-cap 

regulation, the Department assumes that 

the uncapped emissions reduction 

estimate corresponds to the generation 

of emissions allowance credits under an 

emissions-cap scenario. 

The NEMS-BT is run similarly to the 

AE02005 NEMS, except that 

distribution transformer energy usage is 

reduced by the amount of energy (by 

fuel type) saved due to the trial standard 

levels. The Department obtained the 

input of energy savings from the NES 

spreadsheet. For the environmental 

is National Energy Modeling System: An Overview 

2003. DOE/EIA-0581 (2003). March. 2003. 

4 DOE/EIA approves use of the name NEMS to 

describe only an official version of the model 

without any modification to code or data. Because 

this analysis entails some mioor code modifications 

and the model is run under various policy scenarios 

that are variations on DOE/EIA assumptions, the 

Department refers to it by the name NEMS-BT (BT 

is DOE's Buildiog Teclrnologies Program, under 

whose aegis this work has been performed). NEMSBT was previously called NEMS-BRS. 

analysis. the output is the forecasted 

physical emissions. The net benefit of 

the standard is the difference between 

emissions estimated by NEMS-BT and 

the AE02005 Reference Case. 

The NEMS-BT tracks CO2 emissions 

using a detailed module that provides 

robust results because of its broad 

coverage of all sectors and inclusion of 

interactive effects. In the case of S02, 

the Clean Air Act Amendments of 1990 

set an emissions cap on all power 

generation. The attainment of this target, 

however, is flexible among generators 

and is enforced by applying market 

forces, through the use of emissions 

allowances and tradable permits. As a 

result, accurate simulation of S02 

trading tends to imply that the effect of 

efficiency standards on physical 

emissions will be near zero because 

emissions will always be at, or near, the 

ceiling. Thus, there is virtually no real 

possible S02 environmental benefit 

from electricity savings as long as there 

is enforcement of the emissions ceilings. 

Though there may not be an actual 

reduction in S02 emissions from 

electricity savings, there still may be an 

economic benefit from reduced 

emissions demand. Electricity savings 

decrease the need to generate S02 

emissions from power production, and 

consequently can decrease the need to 

purchase or generate S02 emissions 

allowance credits. This decreases the 

costs of complying with regulatory caps 

on emissions. See the environmental 

assessment, a separate report within the 

TSD. for a discussion of these issues. 

Regarding the environmental 

assessment, ASAP stated that DOE 

should report other emissions impacts 

in addition to NOx and CO2, such as Hg 

and particulates. (Public Meeting 

Transcript, No. 56.12 at p. 247) The 

Department responded to this comment 

by adding Hg to the emissions reported 

in the environmental assessment. 

Particulates are a special case because 

they arise not only from direct 

emissions, but also from complex 

atmospheric chemical reactions that 

result from NOx and S02 emissions. 

Because of the highly complex and 

uncertain relationship between 

particulate emissions and particulate 

concentrations that impact air quality, 

the Department did not report 

particulate emissions. 
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules 44385

V. Analytical Results

A. Economic Justification and Energy

Savings

1. Economic Impacts on Commercial

Consumers

a. Life-Cycle Cost and Payback Period

The Department's LCC and PBP

analyses provided five key outputs for

each TSL that are reported in Tables V.1

through V.10 below. The first three

outputs are the proportion of

transformer purchases where the

purchase of a standard-compliant design

creates a net life-cycle cost, no impact,

or a net life-cycle savings for the

consumer. The fourth output is the

average net life-cycle savings from a

standard-compliant design. Finally, the

fifth output is the average payback

period for the consumer investment in

a standard-compliant design. The

payback period is the number of years

it would take for the customer to

recover, as a result of energy savings,

the increased costs of higher-efficiency

equipment, based on the operating cost

savings from the first year of ownership.

The payback period is an economic

benefit-cost measure that uses benefits

and costs without discounting. Detailed

information on the LCC and PBP

analyses can be found in TSD Chapter

8.

TABLE V.1.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT

Trial standard level

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.2 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 2, a

25 kVA, liquid-immersed, single-phase,

pole-mounted distribution transformer.

For this unit, the average efficiency of

TP 1

98.9

4.9

65.2

29.9

93

11.4

2

98.9

4.9

65.2

29.9

93

11.4

Table V.1 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 1, a

50 kVA, liquid-immersed, single-phase,

pad-mounted distribution transformer.

For this unit, the average efficiency of

the baseline transformers selected

during the LCC analysis was 98.97

percent, the minimum efficiency of the

baseline transformers selected during

the LCC analysis was 98.56 percent, and

the consumer equipment cost before

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, and taxes)

was $1,382.00.

3

98.9

4.9

65.2

29.9

93

11.4

4

99.04

16.6

50.9

32.5

98

21.9

5

99.19

52.8

14.7

32.5

5

36.0

6

99.59

90.5

0.0

9.5

-688

45.0

the baseline transformers selected

during the LCC analysis was 98.74

percent, the minimum efficiency of the

baseline transformers selected during

the LCC analysis was 98.23 percent, and

the consumer equipment cost before

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, and taxes)

was $737.00.

TABLE V.2.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT

Trial standard level

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.3 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 3, a

500 kVA, liquid-immersed, single-phase

distribution transformer. For this unit,

the average efficiency of the baseline

TP 1

98.7

1.4

66.6

32.0

69

4.8

2

98.73

3.0

64.3

32.7

70

6.8

transformers selected during the LCC

analysis was 99.36 percent, the

minimum efficiency of the baseline

transformers selected during the LCC

analysis was 99.07 percent, and the

consumer equipment cost before

3

98.76

5.2

60.8

34.0

72

8.8

4

98.79

8.6

56.3

35.1

71

12.0

5

98.96

43.9

25.4

30.7

7

31.7

6

99.46

98.9

0.0

1.1

-953

66.6

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, and taxes)

was $5,428.00.

TABLE V.3.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT

Trial standard level

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

TP 1

99.3

0.2

2

99.38

1.4

3

99.46

6.1

4

99.54

39.9

5

99.74

66.3

6

99.75

70.8

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44385 

V. Analytical Results 

A. Economic Justification and Energy 

Savings 

1. Economic Impacts on Commercial 

Consumers 

a. Life-Cycle Cost and Payback Period 

The Department's LCC and PEP 

analyses provided five key outputs for 

each TSL that are reported in Tables V.l 

through V.l0 below. The first three 

outputs are the proportion of 

transformer purchases where the 

purchase of a standard-compliant design 

creates a net life-cycle cost, no impact, 

or a net life-cycle savings for the 

consumer. The fourth output is the 

average net life-cycle savings from a 

standard-compliant design. Finally, the 

fifth output is the average payback 

period for the consumer investment in 

a standard-compliant design. The 

payback period is the number of years 

it would take for the customer to 

recover, as a result of energy savings, 

the increased costs of higher-efficiency 

equipment, based on the operating cost 

savings from the first year of ownership. 

The payback period is an economic 

benefit-cost measure that uses benefits 

and costs without discounting. Detailed 

information on the LCC and PBP 

analyses can be found in TSD Chapter 

8. 

Table V.l presents the summary of the 

LCC and PEP analysis for the 

representative unit from design line 1, a 

50 kVA, liquid-immersed, single-phase, 

pad-mounted distribution transformer. 

For this unit, the average efficiency of 

the baseline transformers selected 

during the LCC analysis was 98.97 

percent, the minimum efficiency of the 

baseline transformers selected during 

the LCC analysis was 98.56 percent, and 

the consumer equipment cost before 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, and taxes) 

was $1,382.00. 

TABLE V.i.-SUMMARY Lee AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT 

Trial standard level 

1 2 3 4 5 6 TP 1 

Efficiency (%) ................................................................... 98.9 98.9 98.9 99.04 99.19 99.59 

Transformers with Net LCC Increase (%) ....................... 4.9 4.9 4.9 16.6 52.8 90.5 

Transformers with No Change in LCC (%) ..................... 65.2 65.2 65.2 50.9 14.7 0.0 

Transformers with Net LCC Savings (%) ........................ 29.9 29.9 29.9 32.5 32.5 9.5 

Mean LCC Savings ($) .................................................... 93 93 93 98 5 -688 

Mean Payback Period (years) ......................................... 11.4 11.4 11.4 21.9 36.0 45.0 

Table V.2 presents the summary of the 

LCC and PEP analysis for the 

representative unit from design line 2, a 

25 kV A, liquid-immersed, single-phase, 

pole-mounted distribution transformer. 

For this unit, the average efficiency of 

the baseline transformers selected 

during the LCC analysis was 98.74 

percent, the minimum efficiency of the 

baseline transformers selected during 

the LCC analysis was 98.23 percent, and 

the consumer equipment cost before 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, and taxes) 

was $737.00. 

TABLE V.2.-:-SUMMARY Lee AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT 

Trial standard level 

1 2 TP 1 

Efficiency (%) ................................................................... 98.7 98.73 

Transformers with Net LCC Increase (%) ....................... 1.4 3.0 

Transformers with No Change in LCC (%) ..................... 66.6 64.3 

Transformers with Net LCC Savings (%) ........................ 32.0 32.7 

Mean LCC Savings ($) .................................................... 69 70 

Mean Payback Period (years) ......................................... 4.8 6.8 

Table V.3 presents the summary of the 

LCC and PBP analysis for the 

representative unit from design line 3, a 

500 kVA, liqUid-immersed, single-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the LCC 

analysis was 99.36 percent, the 

minimum efficiency of the baseline 

transformers selected during the LCC 

analysis was 99.07 percent, and the 

consumer equipment cost before 

3 4 5 6 

98.76 98.79 98.96 99.46 

5.2 8.6 43.9 98.9 

60.8 56.3 25.4 0.0 

34.0 35.1 30.7 1.1 

72 71 7 -953 

8.8 12.0 31.7 66.6 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, and taxes) 

was $5,428.00. 

TABLE V.3.-SUMMARY Lee AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT 

Trial standard level 

1 2 3 4 5 6 TP 1 

Efficiency (%) ................................................................... 99.3 99.38 99.46 99.54 99.74 99.75 

Transformers with Net LCC Increase ( ) % ....................... 0.2 1.4 6.1 39.9 66.3 70.8 
44386 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.3.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT-Continued

Trial standard level

TP 1

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.4 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 4, a

150 kVA, liquid-immersed, three-phase

distribution transformer. For this unit,

the average efficiency of the baseline

2

73.7 65.2

26.1 33.4

1,746 2,267

1.4 4.3

3

49.5

44.4

2,775

10.4

4

4.0

56.1

2,876

19.8

5

0.1

33.6

627

29.3

6

0.0

29.2

-410

32.3

transformers selected during the LCC

analysis was 98.91 percent, the

minimum efficiency of the baseline

transformers selected during the LCC

analysis was 98.42 percent, and the

consumer equipment cost before

TABLE V.4.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 4 REPRESENTATIVE UNIT

Trial standard level

TP 1

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.5 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 5, a

1500 kVA, liquid-immersed, three-phase

distribution transformer. For this unit,

the average efficiency of the baseline

98.9

3.3

63.7

33.0

556

8.5

2 1 3

99.08 99.26

16.8 41.0

40.8 11.3

42.4 47.7

629 450

18.1 21.5

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, and taxes)

was $3,335.00.

4

99.26

41.0

11.3

47.7

450

21.5

5

99.58

64.4

0.8

34.8

56

29.2

transformers selected during the LCC installation (which includes

analysis was 99.36 percent, the manufacturer selling price, shipping

minimum efficiency of the baseline costs, distributor markup, and taxes)

transformers selected during the LCC was $11,931.00.

analysis was 99.13 percent, and the

consumer equipment cost before

TABLE V.5.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 5 REPRESENTATIVE UNIT

TP 1 2

Efficiency (%) ................................................................... 99.3 99.36

Transformers with Net LCC Increase (%) ....................... 0.3 1.5

Transformers with No Change in LCC (%) ..................... 71.7 62.8

Transformers with Net LCC Savings (%) ........................ 28.0 35.7

Mean LCC Savings ($) .................................................... 3,957 5,463

Mean Payback Period (years) ......................................... 3.4 6.1

Table V.6 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 9, a

300 kVA, medium-voltage, dry-type,

three-phase distribution transformer

with a 45kV BIL. For this unit, the

Trial standard level

3

99.42

10.2

40.0

49.8

6,504

12.7

4

99.47

15.9

24.2

59.9

7,089

14.1

5

99.71

57.1

0.0

42.9

4,431

25.6

6

6

99.61

75.5

0.0

25.5

-572

34.9

99.71

57.2

0.1

42.7

3,902

26.1

average efficiency of the baseline

transformers selected during the LCC

analysis was 98.77 percent, the

minimum efficiency of the baseline

transformers selected during the LCC

analysis was 98.41 percent, and the

consumer equipment cost before

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, contractor

markup, and taxes) was $7,510.00.

TABLE V.6.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT

Trial standard level

TP 1

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

98.6

0.6

2

98.82

1.1

3

99.04

5.3

4

99.26

25.7

5

99.41

56.3

6

99.41

55.0

 EE-RM/STD-00-550 COMMENT 91.1

44386 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

TABLE V.3.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT-Continued 

Trial standard level 

1 2 TP 1 

Transformers with No Change in LCC (%) ..................... 73.7 65.2 

Transformers with Net LCC Savings (%) ........................ 26.1 33.4 

Mean LCC Savings ($) .................................................... 1,746 2,267 

Mean Payback Period (years) ......................................... 1.4 4.3 

Table V.4 presents the summary of the 

Lee and PBP analysis for the 

representative unit from design line 4, a 

150 kVA, liquid-immersed, three-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.91 percent, the 

minimum efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.42 percent, and the 

consumer equipment cost before 

3 4 5 6 

49.5 4.0 0.1 0.0 

44.4 56.1 33.6 29.2 

2,775 2,876 627 -410 

10.4 19.8 29.3 32.3 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markUp, and taxes) 

was $3,335.00. 

TABLE VA.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 4 REPRESENTATIVE UNIT 

Trial standard level 

1 2 TP 1 

Efficiency (%) ................................................................... 98.9 99.08 

Transformers with Net LCC Increase (%) ....................... 3.3 16.8 

Transformers with No Change in LCC (%) ..................... 63.7 40.8 

Transformers with Net LCC Savings (%) ........................ 33.0 42.4 

Mean LCC Savings ($) .................................................... 556 629 

Mean Payback Period (years) ......................................... 8.5 18.1 

Table V.5 presents the summary of the 

Lee and PBP analysis for the 

representative unit from design line 5, a 

1500 kVA, liquid-immersed, three-phase 

distribution transformer. For this unit, 

the average efficiency of the baseline 

transformers selected during the Lee 

analysis was 99.36 percent, the 

minimum effiCiency of the baseline 

transformers selected during the Lee 

analysis was 99.13 percent, and the 

consumer equipment cost before 

3 4 5 6 

99.26 99.26 99.58 99.61 

41.0 41.0 64.4 75.5 

11.3 11.3 0.8 0.0 

47.7 47.7 34.8 25.5 

450 450 56 -572 

21.5 21.5 29.2 34.9 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, and taxes) 

was $11,931.00. 

TABLE V.5.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 5 REPRESENTATIVE UNIT 

Trial standard level 

1 2 TP 1 

Efficiency (%) ................................................................... 99.3 99.36 

Transformers with Net LCC Increase (%) ....................... 0.3 1.5 

Transformers with No Change in LCC (%) ..................... 71.7 62.8 

Transformers with Net LCC Savings (%) ........................ 28.0 35.7 

Mean LCC Savings ($) .................................................... 3,957 5,463 

Mean Payback Period (years) ......................................... 3.4 6.1 

Table V.6 presents the summary of the 

Lee and PBP analysis for the 

representative unit from design line 9, a 

300 kVA, medium-voltage, dry-type, 

three-phase distribution transformer 

with a 45kV BIL. For this unit, the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.77 percent, the 

minimum efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.41 percent, and the 

3 4 5 6 

99.42 99.47 99.71 99.71 

10.2 15.9 57.1 57.2 

40.0 24.2 0.0 0.1 

49.8 59.9 42.9 42.7 

6,504 7,089 4,431 3,902 

12.7 14.1 25.6 26.1 

consumer equipment cost before 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, contractor 

markUp, and taxes) was $7,510.00. 

TABLE V.6.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT 

Trial standard level 

1 2 3 4 5 6 TP 1 

Efficiency (%) ................................................................... 98.6 98.82 99.04 99.26 99.41 99.41 

Transformers with Net LCC Increase ( % ) ....................... 0.6 1.1 5.3 25.7 56.3 55.0 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.6.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT-Continued

Trial standard level

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.7 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 10,

a 1500 kVA, medium-voltage, dry-type,

three-phase distribution transformer

with a 45 kV BIL. For this unit, the

TP 1

57.8

41.6

988

1.5

2

46.3

52.6

1,968

2.4

3

29.7

65.0

3,103

5.4

average efficiency of the baseline consumer equipment cost before

transformers selected during the LCC installation (which includes

analysis was 99.17 percent, the manufacturer selling price, shipping

minimum efficiency of the baseline costs, distributor markup, contractor

transformers selected during the LCC markup, and taxes) was $33,584.00.

analysis was 98.79 percent, and the

TABLE V.7.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 10 REPRESENTATIVE UNIT

Trial standard level

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.8 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 11,

a 300 kVA, medium-voltage, dry-type,

three-phase distribution transformer

with a 95 kV BIL. For this unit, the

TP 1

99.1

4.4

63.3

32.3

4,041

7.7

2

99.20

5.1

56.9

37.6

5,227

8.3

3

99.30

8.9

44.4

46.7

6,818

10.0

average efficiency of the baseline consumer equipment cost before

transformers selected during the LCC installation (which includes

analysis was 98.42 percent, the manufacturer selling price, shipping

minimum efficiency of the baseline costs, distributor markup, contractor

transformers selected during the LCC markup, and taxes) was $10,945.00.

analysis was 98.05 percent, and the

TABLE V.8.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 11 REPRESENTATIVE UNIT

Trial standard level

Efficiency (%) ...................................................................

Transformers with Net LCC Increase (%) .......................

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings Period ($) .........................................

Mean Payback (years) .....................................................

Table V.9 presents the summary of the

LCC and PBP analysis for the

representative unit from design line 12,

a 1500 kVA, medium-voltage, dry-type,

three-phase distribution transformer

with a 95 kV BIL. For this unit, the

TP 1

98.5

2.4

42.5

55.1

2,491

3.8

2

98.67

3.9

34.6

61.5

3,621

4.9

average efficiency of the baseline

transformers selected during the LCC

analysis was 99.18 percent, the

minimum efficiency of the baseline

transformers selected during the LCC

analysis was 98.81 percent, and the

3

98.84

9.8

18.7

71.5

4,313

7.9

4

0.5

73.8

3,532

12.4

4

99.39

21.0

23.2

55.8

7,699

13.4

4

99.01

22.0

2.3

75.7

4,845

11.8

5

0.0

43.7

1,181

21.7

5

99.51

66.3

0.0

33.7

1,279

28.7

5

99.09

34.2

0.0

66.8

4,186

15.1

44387

6

0.0

45.0

1,274

21.5

6

99.51

66.2

0.0

33.8

1,124

29.4

6

99.09

33.2

0.0

66.8

4,289

14.8

consumer equipment cost before

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, contractor

markup, and taxes) was $33,590.00.

TABLE V.9.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT

Trial standard level

TP 1 2 3 1 4 5

Efficiency (%) ................................................................... 99.0 99.12

ransformers with Net LCC Increase (%) ....................... .4

99.23 99.35 99.51

.5 5.8 18.2 70.6

6

99.51

70.1

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register! Vol. 71, No. 150/ Friday, August 4, 2006/ Proposed Rules 44387 

TABLE V.6.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT-Continued 

Trial standard level 

1 2 TP 1 

Transformers with No Change in LCC (%) ..................... 57.8 46.3 

Transformers with Net LCC Savings (%) ........................ 41.6 52.6 

Mean LCC Savings ($) .................................................... 988 1.968 

Mean Payback Period (years) ......................................... 1.5 2.4 

Table V.7 presents the summary ofthe 

Lee and PBP analysis for the 

representative unit from design line 10, 

a 1500 kV A. medium-voltage. dry-type. 

three-phase distribution transformer 

with a 45 kV BlL. For this unit. the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 99.17 percent. the 

minimum efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.79 percent. and the 

3 4 5 6 

29.7 0.5 0.0 0.0 

65.0 73.8 43.7 45.0 

3.103 3.532 1.181 1.274 

5.4 12.4 21.7 21.5 

consumer equipment cost before 

installation (which includes 

manufacturer selling price, shipping 

costs. distributor markup. contractor 

markup. and taxes) was $33,584.00. 

TABLE V.7.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 10 REPRESENTATIVE UNIT 

Trial standard level 

1 2 TP 1 

Efficiency (%) ................................................................... 99.1 99.20 

Transformers with Net LCC Increase (%) ....................... 4.4 5.1 

Transformers with No Change in LCC (%) ..................... 63.3 56.9 

Transformers with Net LCC Savings (%) ........................ 32.3 37.6 

Mean LCC Savings ($) .................................................... 4.041 5.227 

Mean Payback Period (years) ......................................... 7.7 8.3 

Table V.8 presents the summary ofthe 

Lee and PBP analysis for the 

representative unit from design line 11. 

a 300 kVA. medium-voltage. dry-type. 

three-phase distribution transformer 

with a 95 kV ElL. For this unit. the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.42 percent. the 

minimum efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.05 percent. and the 

3 4 5 6 

99.30 99.39 99.51 99.51 

8.9 21.0 66.3 66.2 

44.4 23.2 0.0 0.0 

46.7 55.8 33.7 33.8 

6.818 7.699 1.279 1.124 

10.0 13.4 28.7 29.4 

consumer equipment cost before 

installation (which includes 

manufacturer selling price. shipping 

costs. distributor markup. contractor 

markup, and taxes) was $10,945.00. 

TABLE V.8.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 11 REPRESENTATIVE UNIT 

Trial standard level 

1 2 TP 1 

Efficiency (%) ................................................................... 98.5 98.67 

Transformers with Net LCC Increase (%) ....................... 2.4 3.9 

Transformers with No Change in LCC (%) ..................... 42.5 34.6 

Transformers with Net LCC Savings (%) ........................ 55.1 61.5 

Mean LCC Savings Period ($) ......................................... 2,491 3.621 

Mean Payback (years) ..................................................... 3.8 4.9 

Table V.9 presents the summary of the 

Lee and PBP analysis for the 

representative unit from design line 12. 

a 1500 kVA. medium-voltage, dry-type, 

three-phase distribution transformer 

with a 95 kV ElL. For this unit. the 

average efficiency of the baseline 

transformers selected during the Lee 

analysis was 99.18 percent. the 

minimum efficiency of the baseline 

transformers selected during the Lee 

analysis was 98.81 percent. and the 

3 4 5 6 

98.84 99.01 99.09 99.09 

9.8 22.0 34.2 33.2 

18.7 2.3 0.0 0.0 

71.5 75.7 66.8 66.8 

4.313 4.845 4.186 4.289 

7.9 11.8 15.1 14.8 

consumer equipment cost before 

installation (which includes 

manufacturer selling price. shipping 

costs. distributor markup. contractor 

markup. and taxes) was $33.590.00. 

TABLE V.9.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT 

Trial standard level 

1 2 3 4 5 6 TP 1 

Efficiency (%) .................................................................... 99.0 99.12 99.23 99.35 99.51 99.51 

Transformers with Net LCC Increase (%) ....................... 1.4 1.5 5.8 18.2 70.6 70.1 
44388 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.9.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT-Continued

Trial standard level

1

TP 1

Transformers with No Change in LCC (%) .....................

Transformers with Net LCC Savings (%) ........................

Mean LCC Savings ($) ....................................................

Mean Payback Period (years) .........................................

Table V.10 presents the summary of

the LCC and PBP analysis for the

representative unit from design line 13,

a 2000 kVA, medium-voltage , dry-type,

three-phase distribution transformer

with a 125 kV BIL. For this unit, the

75.1

23.5

2,600

4.6

2

71.9

26.6

3,973

4.7

average efficiency of the baseline

transformers selected during the LCC

analysis was 99.26 percent, the

minimum efficiency of the baseline

transformers selected during the LCC

analysis was 98.97 percent, and the

4

28.2

53.6

6,812

12.7

5

0.0

29.4

-650

29.3

6

0.0

29.9

-655

29.3

consumer equipment cost before

installation (which includes

manufacturer selling price, shipping

costs, distributor markup, contractor

markup, and taxes) was $41,873.00.

TABLE V.10.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 13 REPRESENTATIVE UNIT

Trial standard level

1

TP 1 2

3

56.9

37.3

5,485

8.3

3 4 5 6

Efficiency (%) ................................................................... 99.0 99.15 99.30 99.45 99.55 99.55

Transformers with Net LCC Increase (%) ....................... 3.8 1.5 4.4 42.6 75.7 75.7

Transformers with No Change in LCC (%) ..................... 76.0 72.9 58.9 5.4 0.0 0.0

Transformers with Net LCC Savings (%) ........................ 20.2 25.6 36.7 52.0 24.3 24.3

Mean LCC Savings ($) .................................................... 662 3,125 5,430 6,435 -5,303 -5,218

Mean Payback Period (years) ......................................... 9.7 5.8 8.0 19.5 32.5 32.4

b. Rebuttable-Presumption Payback

As set forth in section 325(o)(2)(B)(iii)

of EPCA, 42 U.S.C. 6295(o)(2)(B)(iii),

there is a rebuttable presumption that an

energy conservation standard is

economically justified if the increased

installed 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. However,

while the Department examined the

rebuttable-presumption criteria, the

Department determined economic

justification for the proposed standard

levels through a more detailed analysis

of the economic impacts of increased

efficiency pursuant to section

325(o)(2)(B)(i) of EPCA. (42 U.S.C.

6295(o)(2)(B)(i))

The Department calculated a

rebuttable-presumption payback period

for each trial standard level, to

determine if DOE could presume that a

standard at that level is economically

justified. Rather than using distributions

for input values, DOE used discrete

values and based the calculation on the

DOE distribution-transformer-testprocedure assumptions. As a result, the

Department calculated a single

rebuttable-presumption payback value

for each standard level, and not a

distribution of payback periods.

To evaluate the rebuttable

presumption, the Department estimated

the additional cost of purchasing a more

efficient, standard-compliant product,

and compared this cost to the value of

the energy savings during the first year

of operation of the product as

determined by the applicable test

procedure. The Department interpreted

the increased cost of purchasing a

standard-compliant product to include

the cost of installing the product for use

by the purchaser. The Department then

calculated the rebuttable-presumption

payback period, or the ratio of the value

of the first year's energy savings to the

increase in purchase price. When the

rebuttable-presumption payback period

is less than three years, the rebuttable

presumption is satisfied; when the

payback period is equal to or more than

three years, the rebuttable presumption

is not satisfied.

The rebuttable-presumption payback

period may differ from payback periods

presented in other parts of this NOPR in

at least two important ways:

® The rebuttable-presumption

payback period uses test procedure

loading levels to evaluate losses, rather

than the Department's estimate of inservice loading conditions.

® Other payback periods may

consider total operating costs, whereas

the rebuttable-presumption payback

period considers only the value of

energy savings. In the case of

distribution transformers, however, the

Department estimates that the change in

operating costs is solely due to energy

savings.

There are three key inputs into the

rebuttable-presumption payback

calculation: (1) The average efficiency;

(2) the average installed cost; and (3) the

cost of electricity. Given the average

efficiency of the baseline and standardcompliant transformers, the Department

calculated the energy savings by taking

the difference in the annual losses

between the baseline and standardcompliant transformers, assuming the

loading conditions from the test

procedure. Multiplying the energy

savings times the cost of electricity

provided the value of the energy

savings. Dividing the value of the energy

savings into the installed-cost increase

for a standard-compliant transformer

provided the estimate of the rebuttablepresumption payback period. More

detailed discussion on the rebuttable

presumption is contained in TSD

Chapter 8, section 8.7.

Table V.11 shows the rebuttablepresumption payback period as a

function of design line and standard

level.

 EE-RM/STD-00-550 COMMENT 91.1

44388 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006 I Proposed Rules 

TABLE V.9.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT-Continued 

Trial standard level 

1 2 3 4 5 6 TP 1 

Transformers with No Change in LCC (%) ..................... 75.1 71.9 56.9 28.2 0.0 0.0 

Transformers with Net LCC Savings (%) ........................ 23.5 26.6 37.3 53.6 29.4 29.9 

Mean LCC Savings ($) .................................................... 2,600 3,973 5,485 6,812 -650 -655 

Mean Payback Period (years) ......................................... 4.6 4.7 

Table V.l0 presents the summary of 

the LCC and PBP analysis for the 

representative unit from design line 13, 

a 2000 kVA, medium-voltage, dry-type, 

three-phase distribution transformer 

with a 125 kV ElL. For this unit, the 

average efficiency of the baseline 

transformers selected during the LCC 

analysis was 99.26 percent, the 

minimum efficiency of the baseline 

transformers selected during the LCC 

analysis was 98.97 percent, and the 

8.3 12.7 29.3 29.3 

consumer equipment cost before 

installation (which includes 

manufacturer selling price, shipping 

costs, distributor markup, contractor 

markup, and taxes) was $41,873.00. 

TABLE V.10.-SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 13 REPRESENTATIVE UNIT 

Trial standard level 

1 2 3 4 5 6 TP 1 

Efficiency (%) ................................................................... 99.0 99.15 99.30 99.45 99.55 99.55 

Transformers with Net LCC Increase (%) ....................... 3.8 1.5 4.4 42.6 75.7 75.7 

Transformers with No Change in LCC (%) ..................... 76.0 72.9 58.9 5.4 0.0 0.0 

Transformers with Net LCC Savings (%) ........................ 20.2 25.6 36.7 52.0 24.3 24.3 

Mean LCC Savings ($) .................................................... 662 3,125 5,430 6,435 -5,303 -5,218 

Mean Payback Period (years) ......................................... 9.7 5.8 

b. Rebuttable-Presumption Payback 

As set forth in section 325(0)(2)(B)(iii) 

of EPCA, 42 U.S.c. 6295(0)(2)(B)(iii), 

there is a rebuttable presumption that an 

energy conservation standard is 

economically justified if the increased 

installed 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. However, 

while the Department examined the 

rebuttable-presumption criteria, the 

Department determined economic 

justification for the proposed standard 

levels through a more detailed analysis 

of the economic impacts of increased 

efficiency pursuant to section 

325(0)(2)(B)(i) of EPCA. (42 U.S.C. 

6295(o)(2)(B)(i)) 

The Department calculated a 

rebuttable-presumption payback period 

for each trial standard level, to 

determine if DOE could presume that a 

standard at that level is economically 

justified. Rather than using distributions 

for input values, DOE used discrete 

values and based the calculation on the 

DOE distribution-transformer-testprocedure assumptions. As a result, the 

Department calculated a single 

rebuttable-presumption payback value 

for each standard level, and not a 

distribution of payback periods. 

To evaluate the rebuttable 

presumption, the Department estimated 

the additional cost of purchasing a more 

efficient, standard-compliant product, 

and compared this cost to the value of 

the energy savings during the first year 

of operation of the product as 

determined by the applicable test 

procedure. The Department interpreted 

the increased cost of purchasing a 

standard-compliant product to include 

the cost of installing the product for use 

by the purchaser. The Department then 

calculated the rebuttable-presumption 

payback period, or the ratio of the value 

ofthe first year's energy savings to the 

increase in purchase price. When the 

rebuttable-presumption payback period 

is less than three years, the rebuttable 

presumption is satisfied; when the 

payback period is equal to or more than 

three years, the rebuttable presumption 

is not satisfied. 

The rebuttable-presumption payback 

period may differ from payback periods 

presented in other parts of this NOPR in 

at least two important ways: 

• The rebuttable-presumption 

payback period uses test procedure 

loading levels to evaluate losses, rather 

than the Department's estimate of inservice loading conditions. 

• Other payback periods may 

consider total operating costs, whereas 

8.0 19.5 32.5 32.4 

the rebuttable-presumption payback 

period considers only the value of 

energy savings. In the case of 

distribution transformers, however, the 

Department estimates that the change in 

operating costs is solely due to energy 

savings. 

There are three key inputs into the 

rebuttable-presumption payback 

calculation: (1) The average efficiency; 

(2) the average installed cost; and (3) the 

cost of electricity. Given the average 

efficiency ofthe baseline and standardcompliant transformers, the Department 

calculated the energy savings by taking 

the difference in the annual losses 

between the baseline and standardcompliant transformers, assuming the 

loading conditions from the test 

procedure. Multiplying the energy 

savings times the cost of electricity 

provided the value ofthe energy 

savings. Dividing the value of the energy 

savings into the installed-cost increase 

for a standard-compliant transformer 

provided the estimate of the rebuttablepresumption payback period. More 

detailed discussion on the rebuttable 

presumption is contained in TSD 

Chapter 8, section 8.7. 

Table V.ll shows the rebuttablepresumption payback period as a 

function of design line and standard 

level. 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.11.-REBUTTABLE-PRESUMPTION PAYBACK IN YEARS

44389

Design line

Rated

capacity

kVA

TSL1

JP 1) TSL2 TSL3 TSL4 TSL5 TSL6

1 ....................................................... ................. 50 7 .0 7.0 7.0 10.1 16.0 27.2

2 ............................................................................. 25 2. 1 3.6 4.3 5.2 15.2 42.4

3 ............................................................................. 500 0.5 2.2 5.1 9.7 22.7 25.1

4 ............................................................................. 150 3.9 7.4 12.0 12.0 17.2 20.7

5 ............................................................................. 1,500 2.6 4.5 6.5 9.0 20.0 20.0

9 ............................................................................. 300 0.7 1.3 2.5 5.6 11.3 11.3

10 ........................................................................... 1,500 3.2 3.8 4.8 6.1 12.4 12.4

11 ........................................................................... 300 2 .0 2.6 3 .8 5.3 7.0 7.0

12 ........................................................................... 1,500 2 .3 2.5 3.3 5.3 13.6 13.6

13 ........................................................................... 2,000 5.0 3.3 4. 1 8.2 16.7 16.7

c. Commercial Consumer Subgroup

Analysis

In analyzing the potential impacts of

new or amended standards, the

Department evaluates impacts on

identifiable groups (i.e., subgroups) of

customers, such as different types of

businesses, which may be

disproportionately affected by a national

standard. For this rulemaking, the

Department identified rural electric

cooperatives and municipal utilities as

transformer consumer subgroups that

could be disproportionately affected,

and examined the impact of today's

proposed standards on these groups.

The Department's analysis indicated

that, for municipal utilities, the

economics are similar to those of the

national sample of utilities, but found

significant differences in the results for

rural cooperatives. Rural cooperatives

have lower transformer loading levels

than the average utility, and so their

operating cost savings from higher

standards would be smaller than those

for the average utility. Chapter 11 of the

TSD explains the Department's method

for conducting the consumer subgroup

analysis and presents the detailed

results of that analysis.

Table V.12 shows the fraction of

transformers that are impacted by

different standard levels for the two

commercial consumer subgroups. A

transformer is impacted by a standard if

the transformer design has to change in

order to meet the performance

requirements of the standard. Table

V.13 shows the mean LCC savings from

proposed energy-efficiency standards,

and Table V.14 shows the mean payback

period (in years) for the two commercial

subgroups. Only the liquid-immersed

design lines are included in this

analysis since those types dominate the

transformers purchased by electric

utilities.

TABLE V.12.-FRACTION OF TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS IMPACTED BY

ENERGY-EFFICIENCY STANDARDS

[Percent]

Design line TSL1

(TP 1) TSL2

Municipal Utility Subgroup

TSL3 TSL4 TSL5 TSL6

1 ................................................................................................... 35.3 35.3 35.3 48.6 84.8 100.0

2 ................................................................................................... 33.9 34.7 39.3 44.1 74.9 100.0

3 ................................................................................................... 26.1 35.2 50.4 96.0 99.9 100.0

4 ................................................................................................... 35.9 60.2 88.3 88.3 99.2 100.0

5 ................................................................................................... 27.9 36.0 59.1 75.6 99.9 99.9

Rural Cooperative Subgroup

1 ................................................................................................... 35.6 49.8 88.7 98.0 99.0 100.0

2 ................................................................................................... 35.6 38.0 42.8 48.1 81.1 100.0

3 ................................................................................................... 27.6 35.1 50.6 97.7 99.9 100.0

4 ................................................................................................... 36.9 61.5 94.3 93.9 99.4 100.0

5 ................................................................................................... 29.1 37.6 60.4 79.2 99.9 100.0

TABLE V.13.-MEAN LIFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER

SUBGROUPS

[Dollars]

Design line

Rated

capacity

kVA

TSL1

(TP 1) TSL2

Municipal Utility Subgroup

TSL3 TSL4 TSL5 TSL6

1 ............................................................................. 50 95 95 95 120 64 -594

2 ............................................................................. 25 69 66 70 73 17 -926

3 ............................................................................. 500 2,109 2,765 3,607 3,693 1,745 1,102

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44389 

TABLE V.11.-REBUTTABLE-PRESUMPTION PAYBACK IN YEARS 

Design line 

Rated 

capacity 

kVA 

TSL1 

(TP 1) TSL2 

1 ............................................................................ . 50 

25 

500 

150 

1,500 

7.0 

2.1 

0.5 

3.9 

2.6 

0.7 

3.2 

2.0 

2.3 

5.0 

7.0 

3.6 

2.2 

7.4 

4.5 

1.3 

3.8 

2.6 

2.5 

3.3 

2 ............................................................................ . 

3 ............................................................................ . 

4 ........................................................................... .. 

5 ............................................................................ . 

9 ........................................................................... .. 300 

1,500 

300 

1,500 

2,000 

10 .......................................................................... . 

11 .......................................................................... . 

12 .......................................................................... . 

13 .......................................................................... . 

c. Commercial Consumer Subgroup 

Analysis 

In analyzing the potential impacts of 

new or amended standards, the 

Department evaluates impacts on 

identifiable groups (Le., subgroups) of 

customers, such as different types of 

businesses, which may be 

disproportionately affected by a national 

standard. For this rulemaking, the 

Department identified rural electric 

cooperatives and municipal utilities as 

transformer consumer subgroups that 

could be disproportionately affected, 

and examined the impact of today's 

proposed standards on these groups. 

The Department's analysis indicated 

that, for municipal utilities, the 

economics are similar to those of the 

national sample of utilities, but found 

significant differences in the results for 

rural cooperatives. Rural cooperatives 

have lower transformer loading levels 

than the average utility, and so their 

operating cost savings from higher 

standards would be smaller than those 

for the average utility. Chapter 11 of the 

TSD explains the Department's method 

for conducting the consumer subgroup 

analysis and presents the detailed 

results of that analysis. 

Table V.12 shows the fraction of 

transformers that are impacted by 

TSL3 

7.0 

4.3 

5.1 

12.0 

6.5 

2.5 

4.8 

3.8 

3.3 

4.1 

TSL4 

10.1 

5.2 

9.7 

12.0 

9.0 

5.6 

6.1 

5.3 

5.3 

8.2 

TSL5 

16.0 

15.2 

22.7 

17.2 

20.0 

11.3 

12.4 

7.0 

13.6 

16.7 

TSL6 

27.2 

42.4 

25.1 

20.7 

20.0 

11.3 

12.4 

7.0 

13.6 

16.7 

different standard levels for the two 

commercial consumer subgroups. A 

transformer is impacted by a standard if 

the transformer design has to change in 

order to meet the performance 

requirements of the standard. Table 

V.13 shows the mean LCC savings from 

proposed energy-efficiency standards, 

and Table V.14 shows the mean payback 

period (in years) for the two commercial 

subgroups. Only the liquid-immersed 

design lines are included in this 

analysis since those types dominate the 

transformers purchased by electric 

utilities. 

TABLE V.12.-FRACTION OF TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS IMPACTED BY 

ENERGy-EFFICIENCY STANDARDS 

[Percent] 

Design line 

Municipal Utility Subgroup 

1 .................................................................................................. . 

2 .................................................................................................. . 

3 .................................................................................................. . 

4 .................................................................................................. . 

5 .................................................................................................. . 

35.3 

33.9 

26.1 

35.9 

27.9 

35.3 

34.7 

35.2 

60.2 

36.0 

Rural Cooperative Subgroup 

1 .................................................................................................. . 

2 .................................................................................................. . 

3 .................................................................................................. . 

4 .................................................................................................. . 

5 .................................................................................................. . 

35.6 

35.6 

27.6 

36.9 

29.1 

49.8 

38.0 

35.1 

61.5 

37.6 

35.3 

39.3 

50.4 

88.3 

59.1 

88.7 

42.8 

50.6 

94.3 

60.4 

TSL6 

48.6 84.8 100.0 

44.1 74.9 100.0 

96.0 99.9 100.0 

88.3 99.2 100.0 

75.6 99.9 99.9 

98.0 99.0 100.0 

48.1 81.1 100.0 

97.7 99.9 100.0 

93.9 99.4 100.0 

79.2 99.9 100.0 

TABLE V.13.-MEAN LIFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER 

SUBGROUPS 

[Dollars] 

Rated TSL1 Design line capacity (TP 1) TSL2 TSL3 TSL4 TSL5 TSL6 

kVA 

Municipal Utility Subgroup 

1 ............................................................................ . -594 

2 ............................................................................ . -926 

3 ............................................................................ . 1,102 
44390 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.13.-MEAN LIFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER

SUBGROUPS-Continued

[Dollars]

Design line

Rated

capacity TSL1

(TP 1) TSL2 TSL3 TSL4 TSL5 TSL6

kVA

4 ............................................................................. 150 608 808 512 512 435 -165

5 ............................................................................. 1,500 4,853 6,649 8,128 9,013 7,680 7,453

Rural Cooperative Subgroup

1 ............................................................................. 50 79 79 79 58 - 91 -861

2 ............................................................................. 25 69 66 67 63 - 25 -1,040

3 ............................................................................. 500 1,288 1,525 1,669 1,579 -1,630 -2,573

4 ............................................................................. 150 412 370 183 183 -599 -1,320

5 ............................................................................. 1,500 2,243 3,013 3,084 3,239 -3,617 -3,775

TABLE V.14.-MEAN PAYBACK PERIOD FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS

[Years]

Design line TSL1

(TP 1) TSL2

Municipal Utility Subgroup

TSL3 TSL4 TSL5 TSL6

1 ................................................................................................... 11.1 11.1 11.1 19.9 33.2 43.0

2 ................................................................................................... 4.8 7.0 8.8 12.0 30.6 65.4

3 ................................................................................................... 1.2 3.8 8.7 19.2 27.4 29.9

4 ................................................................................................... 7.7 15.0 21.5 21.5 27.1 32.5

5 ................................................................................................... 2.9 5.1 11.0 12.9 23.7 23.7

Rural Cooperative Subgroup

1 ................................................................................................... 12.4 12.4 12.4 25.2 41.2 49.3

2 ................................................................................................... 5.4 7.6 9.9 14.0 35.6 72.5

3 ................................................................................................... 1.6 5.7 13.7 22.5 33.9 37.7

4 ................................................................................................... 10.8 22.2 25.4 25.4 31.4 37.7

5 ................................................................................................... 4.9 8.4 16.9 17.4 29.4 29.4

The LCC results for the municipal

utilities subgroup are quite similar to

the results for the national sample of

utilities. Transformers purchased by

municipal utilities tend to serve more

diverse, urban loads than transformers

that serve more rural areas. The

increased load diversity increases the

load factor and the transformer loading,

thus increasing the potential savings

from reduced load losses. Thus,

compared to the other subgroup (rural

cooperatives), the benefits from

efficiency improvements are, on

average, greater.

In contrast to the results for municipal

utilities, the LCC savings tends to be

lower for rural cooperatives, and the

payback times tend to be longer. The

LCC and PBP results for the rural

cooperatives subgroup are mostly a

reflection of the fact that the loading on

rural transformers is lower, and thus the

savings from reduced load losses are

more modest. Distribution transformers

purchased by rural cooperatives have

lower loading than transformers that

serve urban areas, primarily because the

need to mitigate voltage flicker often

results in the purchase of transformers

of higher capacities, and because

transformers purchased by rural

cooperatives tend to serve isolated loads

with lower load factors. The lower

loading decreases the potential savings

from reduced load losses, so the benefits

from efficiency improvements are, on

average, less than the municipal utility

case per affected transformer.

2. Economic Impacts on Manufacturers

The Department performed an MIA to

estimate the impact of higher efficiency

standards on distribution transformer

manufacturers. Chapter 12 of the TSD

explains the methodology, analysis, and

findings of this analysis in detail.

a. Industry Cash-Flow Analysis Results

Based on a real corporate discount

rate of 8.9 percent, the Department

estimated the distribution transformer

industry impacts at each TSL. Table

V.15 and Table V.16 show the estimated

impacts for the liquid-immersed and

medium-voltage, dry-type industries,

respectively. The primary metric from

the MIA is the change in INPV. These

tables also present the investments that

the industry would incur at each TSL.

Product conversion expenses include

engineering, prototyping, testing, and

marketing expenses incurred by a

manufacturer as it prepares to come into

compliance with a standard. Capital

investments are the one-time outlays for

equipment and buildings required for

the industry to come into compliance

(i.e., conversion capital expenditures).

 EE-RM/STD-00-550 COMMENT 91.1

44390 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

TABLE V.13.-MEAN liFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER 

SUBGROUPS-Continued 

Rated 

Design line capacity 

kVA 

4 ............................................................................. 150 

5 ............................................................................. 1,500 

[Dollars] 

TSL1 

(TP 1) 

608 

4,853 

TSL2 

808 

6,649 

Rural Cooperative Subgroup 

1 ............................................................................ . 

2 ............................................................................ . 

3 ............................................................................ . 

4 ............................................................................ . 

5 ............................................................................ . 

50 

25 

500 

150 

1,500 

79 

69 

1,288 

412 

2,243 

79 

66 

1,525 

370 

3,013 

TSL3 

512 

8,128 

79 

67 

1,669 

183 

3,084 

TSL4 

512 

9,013 

58 

63 

1,579 

183 

3,239 

TSL5 

435 

7,680 

-91 

-25 

-1,630 

-599 

-3,617 

TSL6 

-165 

7,453 

861 

-1,040 

-2,573 

-1,320 

-3,775 

TABLE V.14.-MEAN PAYBACK PERIOD FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS 

[Years] 

Design line 

Municipal Utility Subgroup 

1 .................................................................................................. . 11.1 

4.8 

1.2 

7.7 

2.9 

11.1 

7.0 

3.8 

15.0 

5.1 

2 .................................................................................................. . 

3 .................................................................................................. . 

4 .................................................................................................. . 

5 .................................................................................................. . 

Rural Cooperative Subgroup 

1 .................................................................................................. . 12.4 

5.4 

1.6 

10.8 

4.9 

12.4 

7.6 

5.7 

22.2 

8.4 

2 .................................................................................................. . 

3 .................................................................................................. . 

4 .................................................................................................. . 

5 .................................................................................................. . 

The LCC results for the municipal 

utilities subgroup are quite similar to 

the results for the national sample of 

utilities. Transformers purchased by 

municipal utilities tend to serve more 

diverse, urban loads than transformers 

that serve more rural areas. The 

increased load diversity increases the 

load factor and the transformer loading, 

thus increasing the potential savings 

from reduced load losses. Thus, 

compared to the other subgroup (rural 

cooperatives), the benefits from 

efficiency improvements are, on 

average, greater. 

In contrast to the results for municipal 

utilities, the LCC savings tends to be 

lower for rural cooperatives, and the 

payback times tend to be longer. The 

LCC and PBP results for the rural 

cooperatives subgroup are mostly a 

reflection of the fact that the loading on 

rural transformers is lower, and thus the 

savings from reduced load losses are 

more modest. Distribution transformers 

purchased by rural cooperatives have 

lower loading than transformers that 

serve urban areas, primarily because the 

need to mitigate voltage flicker often 

results in the purchase of transformers 

of higher capacities, and because 

transformers purchased by rural 

cooperatives tend to serve isolated loads 

with lower load factors. The lower 

loading decreases the potential savings 

from reduced load losses, so the benefits 

from efficiency improvements are, on 

average, less than the municipal utility 

case per affected transformer. 

2. Economic Impacts on Manufacturers 

The Department performed an MIA to 

estimate the impact of higher efficiency 

standards on distribution transformer 

manufacturers. Chapter 12 of the TSD 

explains the methodology, analysis, and 

findings of this analysis in detail. 

TSL6 

11.1 19.9 33.2 43.0 

8.8 12.0 30.6 65.4 

8.7 19.2 27.4 29.9 

21.5 21.5 27.1 32.5 

11.0 12.9 23.7 23.7 

12.4 25.2 41.2 49.S 

9.9 14.0 35.6 72.5 

13.7 22.5 33.9 37.7 

25.4 25.4 31.4 37.7 

16.9 17.4 29.4 29.4 

a. Industry Cash-Flow Analysis Results 

Based on a real corporate discount 

rate of 8.9 percent, the Department 

estimated the distribution transformer 

industry impacts at each TSL. Table 

V.15 and Table V.16 show the estimated 

impacts for the liquid-immersed and 

medium-voltage, dry-type industries, 

respectively. The primary metric from 

the MIA is the change in INPV. These 

tables also present the investments that 

the industry would incur at each TSL. 

Product conversion expenses include 

engineering, proto typing, testing, and 

marketing expenses incurred by a 

manufacturer as it prepares to come into 

compliance with a standard. Capital 

investments are the one-time outlays for 

equipment and buildings required for 

the industry to come into compliance 

(Le., conversion capital expenditures). 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE V.15.-MANUFACTURER IMPACT ANALYSIS FOR LIQUID-IMMERSED INDUSTRY

Units Base case

2

Trial standard level

3

Preservation-of-Gross-Margin-Percentage Scenario

4 5

44391

6

INPV .................................... ($ millions) .... 526 532 537 553 561 549 552

Change in INPV .................. ($ millions) .... .................. 5.8 10.7 27.0 34.9 22.3 25.8

(%) ................ .................. 1.1 2.0 5.1 6.6 4.2 4.9

Product Conversion Ex- ($ millions) .... .................. 0 0 0 0 109.2 161.2

penses.

Capital Investments ............. ($ millions) .... .................. 2.5 5.0 7.8 8.0 94.1 326.5

Total Investment Required ($ millions) .... .................. 2.5 5.0 7.8 8.0 203.3 487.7

Preservation-of-Operating-Profit Scenario

INPV .................................... ($ millions) .... 526 521 513 496 490 323 27

Change in INPV .................. ($ millions) .... .................. -5.7 -12.9 -30.0 -36.9 -203.8 -499.6

(%) ................ .................. -1.1 -2.4 -5.7 -7.0 -38.7 -94.9

Product Conversion Ex- ($ millions) .... .................. 0 0 0 0 109.2 161.2

penses.

Capital Investments ............. ($ millions) .... .................. 2.5 5.0 7.8 8.0 94.1 326.5

Total Investment Required ($ millions) .... .................. 2.5 5.0 7.8 8.0 203.3 487.7

TABLE V.16.-MANUFACTURER IMPACT ANALYSIS FOR MEDIUM-VOLTAGE, DRY-TYPE INDUSTRY

Units Base case

1

Trial standard level

2

Preservation-of-Gross-Margin-Percentage Scenario

3 4 5/6

INPV ................................................ ($ millions) .......... 32 30 29 27 28 30

Change in INPV .............................. ($ millions) .......... .................... -1.8 -3.3 -5.1 -3.8 -2.0

(%) ...................... .................... -5.5 -10.1 -15.7 -11.8 -6.1

Product Conversion Expenses ........ ($ millions) .......... .................... 0 0 3.3 3.6 5.0

Capital Investments ......................... ($ millions) .......... .................... 3.2 5.6 7.3 7.5 15.0

Total Investment Required .............. ($ millions) .......... .................... 3.2 5.6 10.6 11.1 20.0

Preservation-of-Gross-Margin-Percentage Scenario

INPV ................................................ ($ millions) .......... 32 30 28 25 24 15

Change in INPV .............................. ($ millions) .......... .................... - 2.5 -4.3 - 6.9 -7.8 -17.0

(%) ...................... .................... -7.7 -13.4 -21.5 -24.3 - 52.8

Product Conversion Expenses ........ ($ millions) .......... .................... 0 0 3.3 3.6 5.0

Capital Investments ......................... ($ millions) .......... .................... 3.2 5.6 7.3 7.5 15.0

Total Investment Required .............. ($ millions) .......... .................... 3.2 5.6 10.6 11.1 20.0

b. Impacts on Employment

The Department expects no

significant, discernable direct

employment impacts among liquidimmersed transformer manufacturers

under TSL1 through TSL4, but

potentially large increases in

employment for TSL5 and TSL6 (35

percent and 99 percent, respectively).

These conclusions-which are separate

from any conclusions regarding

employment impacts on the broader

U.S. economy-are based on modeling

results that address neither the possible

relocation of domestic transformer

manufacturing employment to lower

labor-cost countries, nor the possibility

of outsourcing amorphous core

production under TSL5 and TSL6 to

companies in other countries. The

Department discussed this scenario of

outsourcing amorphous core production

to other countries during several liquidimmersed manufacturer interviews, and

it appears that outsourcing would be a

serious consideration for the liquidimmersed industry under TSL5 or TSL6.

Liquid-immersed manufacturers

expressed concern during the MIA

interviews that establishing an energy

conservation standard would

"commoditize" the liquid-immersed

transformer market, making it easier for

foreign manufacturers who specialize in

low-cost mass production of one design

to enter the U.S. market. If foreign

producers were to capture significant

market share, U.S. transformermanufacturing employment would be

negatively affected. As a point related to

"commoditization," but separate from

employment impacts, manufacturers

also warned the Department about a

potential backsliding effect, whereby the

average efficiency of liquid-immersed

transformers could potentially decrease

under standards, since transformer

customers may stop evaluating and

instead simply purchase minimally

compliant designs. Manufacturers

reported having observed such a

backsliding phenomenon in customer

orders from Massachusetts, where TP1

is a mandatory standard.

The Department expects no

significant, discernable employment

impacts among medium-voltage, drytype transformer manufacturers for any

TSL compared to the base case. The

Department's conclusion regarding

employment impacts in the mediumvoltage, dry-type transformer industry is

separate from any conclusions regarding

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44391 

TABLE V.15.-MANUFACTURER IMPACT ANALYSIS FOR liQUID-IMMERSED INDUSTRY 

Trial standard level 

Units Base case 1----~1-2--,---1-3--,---1-4---,---1-5--r1--6-

Preservation-of-Gross-Margin-Percentage Scenario 

INPV .................................... ($ millions) .... 526 532 537 553 561 549 552 

Change in INPV .................. ($ millions) .... . ................. 5.8 10.7 27.0 34.9 22.3 25.8 

(%) ................ .................. 1.1 2.0 5.1 6.6 4.2 4.9 

Product Conversion Ex- ($ millions) .... .................. 0 0 0 0 109.2 161.2 

penses. 

Capital Investments ............. ($ millions) .... .................. 2.5 5.0 7.8 8.0 94.1 326.5 

Total Investment Required .. ($ millions) .... . ................. 2.5 5.0 7.8 8.0 203.3 487.7 

Preservation-of-Operating-Profit Scenario 

INPV .................................... ($ millions) .... 526 521 513 496 490 323 27 

Change in INPV .................. ($ millions) .... . ................. -5.7 -12.9 -30.0 -36.9 -203.8 -499.6 

(%) ................ .................. -1.1 -2.4 -5.7 -7.0 -38.7 -94.9 

Product Conversion Ex- ($ millions) .... .................. 0 0 0 0 109.2 161.2 

penses. 

Capital Investments ............. ($ millions) .... .................. 2.5 5.0 7.8 8.0 94.1 326.5 

Total Investment Required .. ($ millions) .... . ................. 2.5 5.0 7.8 8.0 203.3 487.7 

TABLE V.16.-MANUFACTURER IMPACT ANALYSIS FOR MEDIUM-VOLTAGE, DRY-TYPE INDUSTRY 

Trial standard level 

Units Base case 

I 2 I I I 3 4 5/6 

Preservation-of-Gross-Margin-Percentage Scenario 

INPV ................................................ ($ millions) ......... . 32 

Change in INPV .............................. ($ millions) ......... . 

30 

-1.8 

29 

-3.3 

27 28 30 

-5.1 -3.8 -2.0 

(%) ..................... . -5.5 -10.1 -15.7 -11.8 -6.1 

Product Conversion Expenses ........ ($ millions) ......... . 

Capital Investments ......................... ($ millions) ......... . 

Total Investment Required .............. ($ millions) ......... . 

o 

3.2 

3.2 

o 

5.6 

5.6 

3.3 

7.3 

10.6 

3.6 5.0 

7.5 15.0 

11.1 20.0 

Preservation-of-Gross-Margin-Percentage Scenario 

INPV ................................................ ($ millions) ......... . 32 

Change in INPV .............................. ($ millions) ......... . 

30 

-2.5 

28 

-4.3 

25 24 15 

-6.9 -7.8 -17.0 

(%) ..................... . -7.7 -13.4 -21.5 -24.3 - 52.8 

Product Conversion Expenses ........ ($ millions) ......... . o 

3.2 

3.2 

Capital Investments ......................... ($ millions) ......... . 

Total Investment Required .............. ($ millions) ......... . 

b. Impacts on Employment 

The Department expects no 

significant, discernable direct 

employment impacts among liquidimmersed transformer manufacturers 

under TSLl through TSL4, but 

potentially large increases in 

employment for TSL5 and TSL6 (35 

percent and 99 percent, respectively). 

These conclusions-which are separate 

from any conclusions regarding 

employment impacts on the broader 

U.S. economy-are based on modeling 

results that address neither the possible 

relocation of domestic transformer 

manufacturing employment to lower 

labor-cost countries, nor the possibility 

of outsourcing amorphous core production under TSL5 and TSL6 to 

companies in other countries. The 

Department discussed this scenario of 

outsourcing amorphous core production 

to other countries during several liquidimmersed manufacturer interviews, and 

it appears that outsourcing would be a 

serious consideration for the liquidimmersed industry under TSL5 or TSL6. 

Liquid-immersed manufacturers 

expressed concern during the MIA 

interviews that establishing an energy 

conservation standard would 

"commoditize" the liquid-immersed 

transformer market, making it easier for 

foreign manufacturers who specialize in 

low-cost mass production of one design 

to enter the U.S. market. If foreign 

producers were to capture significant 

market share, U.S. transformermanufacturing employment would be 

negatively affected. As a point related to 

"commoditization," but separate from 

employment impacts, manufacturers 

o 

5.6 

5.6 

3.3 

7.3 

10.6 

3.6 

7.5 

11.1 

5.0 

15.0 

20.0 

also warned the Department about a 

potential backsliding effect, whereby the 

average efficiency of liquid-immersed 

transformers could potentially decrease 

under standards, since transformer 

customers may stop evaluating and 

instead simply purchase minimally 

compliant designs. Manufacturers 

reported having observed such a 

backsliding phenomenon in customer 

orders from Massachusetts, where TPl 

is a mandatory standard. 

The Department expects no 

significant, discernable employment 

impacts among medium-voltage, drytype transformer manufacturers for any 

TSL compared to the base case. The 

Department's conclusion regarding 

employment impacts in the mediumvoltage, dry-type transformer industry is 

separate from any conclusions regarding 
44392 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

employment impacts on the broader

U.S. economy. Increased employment

levels are not expected at higher TSLs

because the core-cutting equipment

typically purchased by the mediumvoltage, dry-type industry is highly

automated and includes core-stacking

equipment.

Another concern conveyed by some

medium-voltage, dry-type

manufacturers during the interviews is

the potential impact stemming from the

cast-coil transformer competitiveness at

higher TSLs. These manufacturers claim

that setting a standard above a certain

threshold may trigger a market switch

from open-wound ventilated

transformers to cast-coil transformers.

Manufacturers suggest that this

crossover point likely occurs at TSL3

and higher. If the market does shift to

cast-coil transformers, there is a risk of

imported pre-fabricated cast coils

dominating the market in the long term.

This would have a significant impact on

domestic industry value and domestic

employment in the medium-voltage,

dry-type industry.

c. Impacts on Manufacturing Capacity

For the liquid-immersed distribution

transformer industry, the Department

believes that there are only minor

production capacity implications for a

standard at TSL4 and below. At TSL6,

all liquid-immersed design lines would

have to convert to amorphous

technology, the most efficient core

material. At TSL5, three design lines

would have to convert to amorphous

core designs. Conversion to amorphous

core designs would render obsolete a

large portion of the equipment used in

the liquid-immersed industry today

(e.g., annealing furnaces, core-cutting

and winding equipment). Based on the

manufacturer interviews, DOE believes

that TSL5 and TSL6 would cause liquidimmersed transformer manufacturers to

decide whether they would tool for

amorphous technology, attempt to

purchase pre-fabricated amorphous

cores, or exit the industry.

Manufacturers also indicated that, if

they were to choose to produce

amorphous cores themselves, they

would face a critical decision about

whether or not to relocate outside of the

U.S., since much of their equipment

would become obsolete. As mentioned

above, if manufacturers choose to

purchase pre-fabricated amorphous

cores, they might purchase them from

foreign manufacturers.

Energy conservation standards will

affect the medium-voltage, dry-type

industry's manufacturing capacity

because the core stack heights (or core

steel piece length) will increase and

laminations will become thinner.

Thinner laminations require more cuts

and are more cumbersome to handle.

Therefore, manufacturers would have to

invest in additional core-mitering

machinery or modifications and

improvements to recover any losses in

productivity, and these factors might

also contribute to a need for more plant

floor space. Because more-efficient

transformers tend to be larger, this could

also contribute to the need for

additional manufacturing floor space.

d. Impacts on Manufacturers That Are

Small Businesses

Converting from a company's current

basic product line involves designing,

prototyping, testing, and manufacturing

a new product. These tasks have

associated capital investments and

product conversion expenses. Small

businesses, because of their limited

access to capital and their need to

spread conversion costs over smaller

production volumes, may be affected

more negatively than major

manufacturers by an energy

conservation standard. For these

reasons, the Department specifically

evaluated the impacts on small

businesses of an energy conservation

standard.

The Small Business Administration

defines a small business, for the

distribution transformer industry, as a

business that has 750 or fewer

employees. The Department estimates

that, of the approximately 25 U.S.

manufacturers that make liquidimmersed distribution transformers,

about 15 of them are small businesses.

About five of the small liquid-immersed

transformer businesses have fewer than

100 employees. The liquid-immersed

distribution transformer industry largely

produces customized transformers.

Often, small businesses can compete in

this industry because a typical customer

order can involve unique designs

produced in relatively small volumes.

Small manufacturers in the liquidimmersed industry tend not to compete

on the higher-volume products and

often produce transformers for highly

specific applications. This strategy

allows small manufacturers in the

liquid-immersed transformer industry to

be competitive in certain product

markets. Implementation of an energy

conservation standard would have a

relatively minor differential impact on

small manufacturers (versus large

manufacturers) of liquid-immersed

distribution transformers. Disadvantages

to small businesses, such as having little

leverage over suppliers (e.g., core steel

suppliers), are present with or without

an energy conservation standard.

For medium-voltage, dry-type

manufacturers, the situation is different.

The Department estimates that, of the 25

U.S. manufacturers that make mediumvoltage, dry-type distribution

transformers, about 20 of them are small

businesses. About one-half of the

medium-voltage, dry-type small

businesses have fewer than 100

employees. Medium-voltage, dry-type

transformer manufacturing is more

concentrated than liquid-immersed

transformer manufacturing; the top

three companies manufacture over 75

percent of all transformers in this

category. The entire medium-voltage,

dry-type transformer industry has such

low shipments that no designs are

produced at high volume. There is little

repeatability of designs, so small

businesses can competitively produce

many medium-voltage, dry-type, openwound designs. The medium-voltage,

dry-type industry as a whole primarily

has experience producing baseline

transformers and transformers that

would comply with TSL1. In addition,

the industry produces a significant

number of units that would comply

with TSL2, but approximately one

percent or less of the market would

comply with TSL3 or higher (today).

Therefore, all manufacturers, including

small businesses, would have to

develop designs to enable compliance

with TSL3 or higher. For these small

manufacturers, the R&D costs would be

more burdensome, as product redesign

costs tend to be fixed and do not scale

with sales volume. Thus, small

businesses would be at a relative

disadvantage at TSL3 and higher,

because their R&D efforts would be on

the same scale as those for larger

companies, but these expenses would be

recouped over smaller sales volumes.

At TSL3 and above, DOE estimates

that net cash flows for the mediumvoltage, dry-type industry would go

negative during the compliance period.

At these TSLs, the impacts on the

industry as a whole are large and affect

businesses of all sizes, but there would

be some differential, increased impacts

on small businesses. For example, at

TSL3 and above, the use of grainoriented silicon steel of M3 grade would

be necessary. Cutting M3 core steel on

the core-mitering equipment typically

purchased by smaller businesses can be

problematic because of the thinness of

the material.

At TSL2, all medium-voltage, drytype designs would have to be mitered.

(Mitering means the transformer core's

joints intersect at 45 degree angles,

rather than at 90 degree angles as is true

for "butt-lap" designs; buttlap designs

are less energy efficient.) The mitered

 EE-RM/STD-00-550 COMMENT 91.1

44392 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

employment impacts on the broader 

U.S. economy. Increased employment 

levels are not expected at higher TSLs 

because the core-cutting equipment 

typically purchased by the mediumvoltage, dry-type industry is highly 

automated and includes core-stacking 

equipment. 

Another concern conveyed by some 

medium-voltage, dry-type 

manufacturers during the interviews is 

the potential impact stemming from the 

cast-coil transformer competitiveness at 

higher TSLs. These manufacturers claim 

that setting a standard above a certain 

threshold may trigger a market switch 

from open-wound ventilated 

transformers to cast-coil transformers. 

Manufacturers suggest that this 

crossover point likely occurs at TSL3 

and higher. If the market does shift to 

cast-coil transformers, there is a risk of 

imported pre-fabricated cast coils 

dominating the market in the long term. 

This would have a significant impact on 

domestic industry value and domestic 

employment in the medium-voltage, 

dry-type industry. 

c. Impacts on Manufacturing Capacity 

For the liquid-immersed distribution 

transformer industry, the Department 

believes that there are only minor 

production capacity implications for a 

standard at TSL4 and below. At TSL6, 

all liquid-immersed design lines would 

have to convert to amorphous 

technology, the most efficient core 

material. At TSL5, three design lines 

would have to convert to amorphous 

core designs. Conversion to amorphous 

core designs would render obsolete a 

large portion ofthe equipment used in 

the liquid-immersed industry today 

(e.g., annealing furnaces, core-cutting 

and winding equipment). Based on the 

manufacturer interviews, DOE believes 

that TSL5 and TSL6 would cause liquidimmersed transformer manufacturers to 

decide whether they would tool for 

amorphous technology, attempt to 

purchase pre-fabricated amorphous 

cores, or exit the industry. 

Manufacturers also indicated that, if 

they were to choose to produce 

amorphous cores themselves, they 

would face a critical decision about 

whether or not to relocate outside ofthe 

U.S., since much of their equipment 

would become obsolete. As mentioned 

above, if manufacturers choose to 

purchase pre-fabricated amorphous 

cores, they might purchase them from 

foreign manufacturers. 

Energy conservation standards will 

affect the medium-voltage, dry-type 

industry's manufacturing capacity 

because the core stack heights (or core 

steel piece length) will increase and 

laminations will become thinner. 

Thinner laminations require more cuts 

and are more cumbersome to handle. 

Therefore, manufacturers would have to 

invest in additional core-mitering 

machinery or modifications and 

improvements to recover any losses in 

productivity, and these factors might 

also contribute to a need for more plant 

floor space. Because more-efficient 

transformers tend to be larger, this could 

also contribute to the need for 

additional manufacturing floor space. 

d. Impacts on Manufacturers That Are 

Small Businesses 

Converting from a company's current 

basic product line involves designing, 

prototyping, testing, and manufacturing 

a new product. These tasks have 

assOCiated capital investments and 

product conversion expenses. Small 

businesses, because of their limited 

access to capital and their need to 

spread conversion costs over smaller 

production volumes, may be affected 

more negatively than major 

manufacturers by an energy 

conservation standard. For these 

reasons, the Department specifically 

evaluated the impacts on small 

businesses of an energy conservation 

standard. 

The Small Business Administration 

defines a small business, for the 

distribution transformer industry, as a 

business that has 750 or fewer 

employees. The Department estimates 

that, ofthe approximately 25 U.S. 

manufacturers that make liquidimmersed distribution transformers, 

about 15 ofthem are small businesses. 

About five of the small liquid-immersed 

transformer businesses have fewer than 

100 employees. The liquid-immersed 

distribution transformer industry largely 

produces customized transformers. 

Often, small businesses can compete in 

this industry because a typical customer 

order can involve unique designs 

produced in relatively small volumes. 

Small manufacturers in the liquidimmersed industry tend not to compete 

on the higher-volume products and 

often produce transformers for highly 

specific applications. This strategy 

allows small manufacturers in the 

liquid-immersed transformer industry to 

be competitive in certain product 

markets. Implementation of an energy 

conservation standard would have a 

relatively minor differential impact on 

small manufacturers (versus large 

manufacturers) of liquid-immersed 

distribution transformers. Disadvantages 

to small businesses, such as having little 

leverage over suppliers (e.g., core steel 

suppliers), are present with or without 

an energy conservation standard. 

For medium-voltage, dry-type 

manufacturers, the situation is different. 

The Department estimates that, of the 25 

U.S. manufacturers that make mediumvoltage, dry-type distribution 

transformers, about 20 of them are small 

businesses. About one-half of the 

medium-voltage, dry-type small 

businesses have fewer than 100 

employees. Medium-voltage, dry-type 

transformer manufacturing is more 

concentrated than liquid-immersed 

transformer manufacturing; the top 

three companies manufacture over 75 

percent of all transformers in this 

category. The entire medium-voltage, 

dry-type transformer industry has such 

low shipments that no designs are 

produced at high volume. There is little 

repeatability of designs, so small 

businesses can competitively produce 

many medium-voltage, dry-type, openwound designs. The medium-voltage, 

dry-type industry as a whole primarily 

has experience producing baseline 

transformers and transformers that 

would comply with TSL1. In addition, 

the industry produces a significant 

number of units that would comply 

with TSL2, but approximately one 

percent or less of the market would 

comply with TSL3 or higher (today). 

Therefore, all manufacturers, including 

small businesses, would have to 

develop designs to enable compliance 

with TSL3 or higher. For these small 

manufacturers, the R&D costs would be 

more burdensome. as product redesign 

costs tend to be fixed and do not scale 

with sales volume. Thus, small 

businesses would be at a relative 

disadvantage at TSL3 and higher. 

because their R&D efforts would be on 

the same scale as those for larger 

companies, but these expenses would be 

recouped over smaller sales volumes. 

At TSL3 and above, DOE estimates 

that net cash flows for the mediumvoltage. dry-type industry would go 

negative during the compliance period. 

At these TSLs, the impacts on the 

industry as a whole are large and affect 

businesses of all sizes, but there would 

be some differential, increased impacts 

on small businesses. For example, at 

TSL3 and above. the use of grainoriented silicon steel of M3 grade would 

be necessary. Cutting M3 core steel on 

the core-mitering equipment typically 

purchased by smaller businesses can be 

problematic because of the thinness of 

the material. 

At TSL2, all medium-voltage, drytype designs would have to be mitered. 

(Mitering means the transformer core's 

joints intersect at 45 degree angles, 

rather than at 90 degree angles as is true 

for "butt-lap" designs; buttlap designs 

are less energy efficient.) The mitered 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44393

core construction technique could

constrain the core-mitering resources of

small businesses that share core-cutting

capacity with production lines for other

transformers that are not covered by this

rulemaking (e.g., low-voltage, dry-type

distribution transformers). At TSL1,

many kVA ratings could still be

constructed using butt-lap joints,

alleviating the constraint on coremitering resources. Thus, TSL1 is less

capital-intensive for small businesses

than TSL2 (large businesses would

likely miter nearly all medium-voltage

cores, even at TSL1). In the mediumvoltage, dry-type transformer industry,

which is heavily consolidated already,

there is the risk that TSL2 could lead to

further advantage for the largest

manufacturers and thus further

concentrate the industry's production.

3. National Impact Analysis

a. Amount and Significance of Energy

Savings

The Department estimated the energy

savings from a proposed energyefficiency standard in its NES analysis.

The amount of energy savings depends

not only on the potential decrease in

transformer losses due to a standard, but

also on the rate at which the stock of

existing, less efficient transformers will

be replaced over time after the

implementation of a proposed energyefficiency standard.

Another factor that affects national

energy savings estimates is the

efficiency of the power plants and the

transmission and distribution system

that supplies electricity to transformers.

The factor that relates energy savings at

the transformer to fuel savings at the

power plant is the site-to-source

conversion factor. The NES analysis

takes as an input estimates of the energy

savings per transformer resulting from

proposed energy-efficiency standards

that are calculated in the LCC model.

The NES model then accounts for

transformer stock replacement and siteto-source energy conversion to estimate

annual national energy savings through

an extended forecast period ending in

2038. The replacement of existing

transformer stocks by new, more

efficient transformers is described by

the Department's shipments model,

described in TSD Chapter 9. The

Department calculated the site-to-source

conversion factor that relates

transformer loss reduction to fuel

savings at the power plant using NEMSBT, a variant of the EIA's NEMS, which

is described in TSD Chapter 13 (Utility

Impact Analysis).

Table V.17 summarizes the

Department's NES estimates, which are

described in more detail in TSD Chapter

10. The Department reports both

undiscounted and discounted values of

energy savings. The undiscounted

energy savings estimates increase

steadily from 1.77 to 9.77 quads for

TSLs 1 through 6, where there are

increasing energy savings as the

standard level increases. Discounted

energy savings represent a policy

perspective where energy savings

farther in the future are less significant

than energy savings closer to the

present. The discounted energy savings

estimates are approximately one half

and one fourth of the undiscounted

values for the three- and seven-percent

discount rates, respectively.

b. Energy Savings and Net Present Value

While the NES provides estimates of

the energy savings from a proposed

energy-efficiency standard, the NPV

provides estimates of the national

economic impacts of a proposed

standard. The NPV calculation for this

rulemaking used first-cost data from the

LCC analysis to estimate the equipment

and installation costs associated with

purchase and installation of higher

efficiency transformers. The LCC

analysis also provided the marginal

electricity cost data that the Department

used to estimate the economic value of

energy savings associated with lower

transformer losses.

One key factor in the NPV calculation

that was not obtained from the LCC

analysis is the discount rate. The

Department discounted transformer

purchase costs, installation expenses,

and operating costs using a national

average discount rate for policy

evaluation that the Department

determined consistent with Office of

Management and Budget (OMB)

guidance.

In accordance with the OMB

guidelines on regulatory analysis (OMB

Circular A-4, section E, September 17,

2003), DOE calculated NPV using both

a seven-percent and a three-percent real

discount rate. The seven-percent rate is

an estimate of the average before-tax rate

of return to private capital in the U.S.

economy, and reflects returns to real

estate and small business capital as well

as corporate capital. The Department

used this discount rate to approximate

the opportunity cost of capital in the

private sector, since recent OMB

analysis has found the average rate of

return to capital to be near this rate. In

addition, DOE used the three-percent

rate to capture the potential effects of

standards on private consumption (e.g.,

through higher prices for equipment and

purchase of reduced amounts 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

(e.g., yield on Treasury notes minus

annual rate of change in the Consumer

Price Index), which has averaged about

three percent on a pre-tax basis for the

last 30 years. Table V.17 provides an

overview of the NES and NPV results.

See TSD Chapter 10 for more detailed

NES and NPV results.

TABLE V.17.-TSL RESULTS SUMMARY: NATIONAL ENERGY SAVINGS (QUADS, 2010-2038) AND NET PRESENT VALUE

[Billion 2004$, at 3% and 7% discount rates, 2010-2073]

TSL1

(TP 1) TSL2

Sum of all Product Classes

TSL3 TSL4 TSL5 TSL6

Energy Savings (quads) .............................................................. 1.77 2.39 3. 15 3.63 6.90 9.77

Discounted Energy Savings (quads):

3% ......................................................................................... 0.90 1.21 1 .58 1.82 3.47 4.91

7% ......................................................................................... 0.40 0.54 0.71 0.82 1.54 2.19

NPV (billion 2004$):

3% ......................................................................................... 7.43 9.43 10.11 11.07 10.88 -9.41

7% ......................................................................................... 2.15 2.52 2.28 2.26 -1.13 -14.09

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. lSD/Friday, August 4, 2006/Proposed Rules 44393 

core construction technique could 

constrain the core-mitering resources of 

small businesses that share core-cutting 

capacity with production lines for other 

transformers that are not covered by this 

rulemaking (e.g., low-voltage, dry-type 

distribution transformers). At TSL1, 

many kVA ratings could still be 

constructed using butt-lap joints, 

alleviating the constraint on coremitering resources. Thus, TSLl is less 

capital-intensive for small businesses 

than TSL2 (large businesses would 

likely miter nearly all medium-voltage 

cores, even at TSL1). In the mediumvoltage, dry-type transformer industry, 

which is heavily consolidated already, 

there is the risk that TSL2 could lead to 

further advantage for the largest 

manufacturers and thus further 

concentrate the industry's production. 

3. National Impact Analysis 

a. Amount and Significance of Energy 

Savings 

The Department estimated the energy 

savings from a proposed energyefficiency standard in its NES analysis. 

The amount of energy savings depends 

not only on the potential decrease in 

transformer losses due to a standard, but 

also on the rate at which the stock of 

existing, less efficient transformers will 

be replaced over time after the 

implementation of a proposed energyefficiency standard. 

Another factor that affects national 

energy savings estimates is the 

efficiency of the power plants and the 

transmission and distribution system 

that supplies electricity to transformers. 

The factor that relates energy savings at 

the transformer to fuel savings at the 

power plant is the site-to-source 

conversion factor. The NES analysis 

takes as an input estimates of the energy 

savings per transformer resulting from 

proposed energy-efficiency standards 

that are calculated in the LCC model. 

The NES model then accounts for 

transformer stock replacement and siteto-source energy conversion to estimate 

annual national energy savings through 

an extended forecast period ending in 

2038. The replacement of existing 

transformer stocks by new, more 

efficient transformers is described by 

the Department's shipments model, 

described in TSD Chapter 9. The 

Department calculated the site-to-source 

conversion factor that relates 

transformer loss reduction to fuel 

savings at the power plant using NEMSBT, a variant of the EIA's NEMS, which 

is described in TSD Chapter 13 (Utility 

Impact Analysis). 

Table V.17 summarizes the 

Department's NES estimates, which are 

described in more detail in TSD Chapter 

10. The Department reports both 

undiscounted and discounted values of 

energy savings. The undiscounted 

energy savings estimates increase 

steadily from 1.77 to 9.77 quads for 

TSLs 1 through 6, where there are 

increasing energy savings as the 

standard level increases. Discounted 

energy savings represent a policy 

perspective where energy savings 

farther in the future are less significant 

than energy savings closer to the 

present. The discounted energy savings 

estimates are approximately one half 

and one fourth of the undiscounted 

values for the three- and seven-percent 

discount rates, respectively. 

b. Energy Savings and Net Present Value 

While the NES provides estimates of 

the energy savings from a proposed 

energy-efficiency standard, the NPV 

provides estimates of the national 

economic impacts of a proposed 

standard. The NPV calculation for this 

rulemaking used first-cost data from the 

LCC analysis to estimate the equipment 

and installation costs associated with 

purchase and installation of higher 

efficiency transformers. The LCC 

analysis also provided the marginal 

electricity cost data that the Department 

used to estimate the economic value of 

energy savings associated with lower 

transformer losses. 

One key factor in the NPV calculation 

that was not obtained from the LCC 

analysis is the discount rate. The 

Department discounted transformer 

purchase costs, installation expenses, 

and operating costs using a national 

average discount rate for policy 

evaluation that the Department 

determined consistent with Office of 

Management and Budget (OMB) 

guidance. 

In accordance with the OMB 

guidelines on regulatory analysis (OMB 

Circular A-4, section E, September 17, 

2003), DOE calculated NPV using both 

a seven-percent and a three-percent real 

discount rate. The seven-percent rate is 

an estimate of the average before-tax rate 

ofreturn to private capital in the U.S. 

economy, and reflects returns to real 

estate and small business capital as well 

as corporate capital. The Department 

used this discount rate to approximate 

the opportunity cost of capital in the 

private sector, since recent OMB 

analysis has found the average rate of 

return to capital to be near this rate. In 

addition, DOE used the three-percent 

rate to capture the potential effects of 

standards on private consumption (e.g., 

through higher prices for equipment and 

purchase of reduced amounts 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 

(e.g., yield on Treasury notes minus 

annual rate of change in the Consumer 

Price Index), which has averaged about 

three percent on a pre-tax basis for the 

last 30 years. Table V.17 provides an 

overview of the NES and NPV results. 

See TSD Chapter 10 for more detailed 

NES and NPV results. 

TABLE V.17.-TSL RESULTS SUMMARY: NATIONAL ENERGY SAVINGS (QUADS, 2010-2038) AND NET PRESENT VALUE 

[Billion 2004$, at 3% and 7% discount rates, 2010-2073] 

TSL1 

(TP 1) TSL2 

Sum of all Product Classes 

Energy Savings (quads) .............................................................. 1.77 2.39 

Discounted Energy Savings (quads): 

3% ......................................................................................... 0.90 1.21 

7% ......................................................................................... 0.40 0.54 

NPV (billion 2004$): 

3% ......................................................................................... 7.43 9.43 

7% ......................................................................................... 2.15 2.52 

TSL3 TSL4 TSL5 TSL6 

3.15 3.63 6.90 9.77 

1.58 1.82 3.47 4.91 

0.71 0.82 1.54 2.19 

10.11 11.07 10.88 -9.41 

2.28 2.26 -1.13 -14.09 
44394 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

c. Impacts on Employment

The Process Rule includes

employment impacts among the factors

DOE considers in selecting a proposed

standard. Employment impacts include

direct and indirect impacts. Direct

employment impacts are any changes in

the number of employees for

distribution transformer manufacturers.

Indirect impacts are those changes of

employment in the larger economy that

occur due to the shift in expenditures

and capital investment that is caused by

the purchase and operation of more

efficient equipment. The MIA addresses

direct employment impacts; this section

describes indirect impacts.

In developing this proposed rule, the

Department estimated indirect national

employment impacts using an input/

output model of the U.S. economy,

called IMBUILD (impact of building

energy efficiency programs). Indirect

employment impacts from distribution

transformer standards consist of the net

jobs created or eliminated in the

national economy, other than in the

manufacturing sector being regulated, as

a consequence of: (1) Reduced spending

by end users on energy (electricity,

gas-including liquefied petroleum

gas-and oil); (2) reduced spending on

new energy supply by the utility

industry; (3) increased spending on the

purchase price of new distribution

transformers; and (4) the effects of those

three factors throughout the economy.

The Department expects the net

monetary savings from standards to be

redirected to other forms of economic

activity. The Department also expects

these shifts in spending and economic

activity to affect the demand for labor.

As shown in table V.18, the

Department estimates that net indirect

employment impacts from a proposed

transformer energy-efficiency standard

are positive. According to the

Department's analysis, the number of

jobs that may be generated through

indirect impacts ranged from 5,000 to

20,000 by 2038 for the proposed

standard levels of TSL1 through TSL6

respectively. For shorter forecast

periods, indirect employment impacts

are correspondingly smaller. While the

Department's analysis suggests that the

proposed distribution transformer

standards could increase the net

demand for labor in the economy, the

gains would most likely be very small

relative to total national employment.

The Department therefore concludes

only that the proposed distribution

transformer standards are likely to

produce employment benefits that are

sufficient to offset fully any adverse

impacts on employment that might

occur in the distribution transformer or

energy industries. For details on the

employment impact analysis methods

and results, see TSD Chapter 14.

TABLE V.18.-NET NATIONAL CHANGE IN INDIRECT EMPLOYMENT, THOUSANDS OF JOBS IN 2038

Trial standard level

TSL1

Liquid-Immersed ..........................................................................

Dry-Type, Medium-Voltage ..........................................................

4. Impact on Utility or Performance of

Equipment

In establishing classes of products,

and in evaluating design options and

the impact of potential standard levels,

the Department has tried to avoid

having new standards for distribution

transformers lessen the utility or

performance of these products (see TSD

Chapter 7, section 7.3.1). The proposed

standard level (TSL2) does not lessen

the performance of any of the

distribution transformers being

regulated.

The standard level could, however,

potentially affect utility through the

larger size and weight of an energyefficient distribution transformer. The

Department accounted for

dimensionally or physically constrained

transformers in its LCC model by

including the cost of dealing with

physical constraints in the installation

cost estimate. For all types of

transformers, the Department included

extra labor and equipment costs that

may be incurred in the installation of

larger, heavier, more efficient

transformers. Design line 2 includes

pole-mounted transformers and presents

a special case because of the extra cost

of installing or replacing electrical

distribution poles on which such

4.7

0.3

TSL2

6.4

0.5

transformers may be mounted by

utilities. For single-phase, polemounted, liquid-immersed transformers,

the LCC spreadsheet model includes an

estimate of the additional installation

costs for those designs that would

require an upgrade to the pole (see TSD

Chapter 7, section 7.3.1). Having

accounted for this constraint on utility

in its economic model, the Department

concludes that TSL2 does not reduce

the utility or performance of

distribution transformers.

5. Impact of Any Lessening of

Competition

The Department considers any

lessening of competition that is likely to

result from 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, not later than 60 days after

the publication of a proposed rule,

together with an analysis of the nature

and extent of such impact. (See 42

U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)).

To assist the Attorney General in

making such a determination, the

Department has provided the

Department of Justice (DOJ) with copies

of this notice and the TSD for review.

At DOE's request, the DOJ reviewed the

TSL3

7.7

0.7

TSL4

8.7

1.0

TSL5 TSL6

MIA interview questionnaire to ensure

that it would provide insight concerning

any lessening of competition due to any

proposed TSLs.

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. The energy savings

from distribution transformer standards

result in reduced emissions of CO2, and

reduced power sector demand for NOx,

and Hg emissions reduction

investments. Reduced electricity

demand from energy-efficiency

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 this

reduced demand, the Department

expects the proposed standard to

eliminate the need for the construction

of approximately 11 new 400-megawatt

power plants by 2038 and to save 2.39

quads of electricity (cumulative, 2010-

2038).

Table V.19 provides the Department's

estimate of cumulative CO2, NOx, and

Hg emissions reductions for an

uncapped emissions scenario for the six

 EE-RM/STD-00-550 COMMENT 91.1

44394 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

c. Impacts on Employment 

The Process Rule includes 

employment impacts among the factors 

DOE considers in selecting a proposed 

standard. Employment impacts include 

direct and indirect impacts. Direct 

employment impacts are any changes in 

the number of employees for 

distribution transformer manufacturers. 

Indirect impacts are those changes of 

employment in the larger economy that 

occur due to the shift in expenditures 

and capital investment that is caused by 

the purchase and operation of more 

efficient equipment. The MIA addresses 

direct employment impacts; this section 

describes indirect impacts. 

In developing this proposed rule, the 

Department estimated indirect national 

employment impacts using an input/ 

output model of the U.S. economy, 

called IMBUILD (impact of building 

energy efficiency programs). Indirect 

employment impacts from distribution 

transformer standards consist of the net 

jobs created or eliminated in the 

national economy, other than in the 

manufacturing sector being regulated, as 

a consequence of: (1) Reduced spending 

by end users on energy (electricity, 

gas-including liquefied petroleum 

gas-and oil); (2) reduced spending on 

new energy supply by the utility 

industry; (3) increased spending on the 

purchase price of new distribution 

transformers; and (4) the effects of those 

three factors throughout the economy. 

The Department expects the net 

monetary savings from standards to be 

redirected to other forms of economic 

activity. The Department also expects 

these shifts in spending and economic 

activity to affect the demand for labor. 

As shown in table V.18, the 

Department estimates that net indirect 

employment impacts from a proposed 

transformer energy-efficiency standard 

are positive. According to the 

Department's analysis, the number of 

jobs that may be generated through 

indirect impacts ranged from 5,000 to 

20,000 by 2038 for the proposed 

standard levels of TSLl through TSL5 

respectively. For shorter forecast 

periods, indirect employment impacts 

are correspondingly smaller. While the 

Department's analysis suggests that the 

proposed distribution transformer 

standards could increase the net 

demand for labor in the economy, the 

gains would most likely be very small 

relative to total national employment. 

The Department therefore concludes 

only that the proposed distribution 

transformer standards are likely to 

produce employment benefits that are 

sufficient to offset fully any adverse 

impacts on employment that might 

occur in the distribution transformer or 

energy industries. For details on the 

employment impact analysis methods 

and results, see TSD Chapter 14. 

TABLE V.18.-NET NATIONAL CHANGE IN INDIRECT EMPLOYMENT, THOUSANDS OF JOBS IN 2038 

Trial standard level 

TSL1 TSL2 

Liquid-Immersed ......................................................................... . 4.7 

0.3 

6.4 

Dry-Type, Medium-Voltage ......................................................... . 0.5 

4. Impact on Utility or Performance of 

Equipment 

In establishing classes of products, 

and in evaluating design options and 

the impact of potential standard levels, 

the Department has tried to avoid 

having new standards for distribution 

transformers lessen the utility or 

performance ofthese products (see TSD 

Chapter 7, section 7.3.1). The proposed 

standard level (TSL2) does not lessen 

the performance of any of the 

distribution transformers being 

regulated. 

The standard level could, however, 

potentially affect utility through the 

larger size and weight of an energyefficient distribution transformer. The 

Department accounted for 

dimensionally or physically constrained 

transformers in its LCC model by 

including the cost of dealing with 

physical constraints in the installation 

cost estimate. For all types of 

transformers, the Department included 

extra labor and equipment costs that 

may be incurred in the installation of 

larger, heavier, more efficient 

transformers. Design line 2 includes 

pole-mounted transformers and presents 

a special case because of the extra cost 

of installing or replacing electrical 

distribution poles on which such 

transformers may be mounted by 

utilities. For single-phase, polemounted, liquid-immersed transformers, 

the LCC spreadsheet model includes an 

estimate of the additional installation 

costs for those designs that would 

require an upgrade to the pole (see TSD 

Chapter 7, section 7.3.1). Having 

accounted for this constraint on utility 

in its economic model, the Department 

concludes that TSL2 does not reduce 

the utility or performance of 

distribution transformers. 

5. Impact of Any Lessening of 

Competition 

The Department considers any 

lessening of competition that is likely to 

result from 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, not later than 50 days after 

the publication of a proposed rule, 

together with an analysis of the nature 

and extent of such impact. (See 42 

U.S.C. 5295(0)(2)(B)(i)(V) and (B)(ii)). 

To assist the Attorney General in 

making such a determination, the 

Department has provided the 

Department of Justice (DOn with copies 

of this notice and the TSD for review. 

At DOE's request, the DO} reviewed the 

TSL3 TSL4 TSL5 TSL6 

7.7 

0.7 

8.7 

1.0 

18.2 

1.4 

19.4 

1.4 

MIA interview questionnaire to ensure 

that it would provide insight concerning 

any lessening of competition due to any 

proposed TSLs. 

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. The energy savings 

from distribution transformer standards 

result in reduced emissions of C02, and 

reduced power sector demand for NOx, 

and Hg emissions reduction 

investments. Reduced electricity 

demand from energy-efficiency 

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 this 

reduced demand, the Department 

expects the proposed standard to 

eliminate the need for the construction 

of approximately 11 new 400-megawatt 

power plants by 2038 and to save 2.39 

quads of electricity (cumulative, 2010-

2038). 

Table V.19 provides the Department's 

estimate of cumulative C02, NOx, and 

Hg emissions reductions for an 

uncapped emissions scenario for the six 
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules 44395

TSLs considered in this rulemaking. In

actuality, present and/or future

regulations will place caps on the

emissions of NOx, and Hg for the power

sector, and thus the emissions

reductions provided in the table

represent the Department's estimate of

the potential reduced demand for

emissions reduction investments in

future cap and trade emissions markets.

The expected energy savings from

distribution transformer standards will

reduce the emissions of greenhouse

gases associated with energy production

and household use of fossil fuels, and it

may reduce the cost of maintaining

system-wide emissions standards and

constraints.

TABLE V.19.-CUMULATIVE EMISSIONS REDUCTIONS FROM TRIAL STANDARD LEVELS BY PRODUCT TYPE, 2010-2038

Trial standard level

Emissions reductions for liquid-immersed transformers:

CO2 (Mt) ................................................................................

NOx (kt) ................................................................................

Hg (t) .....................................................................................

Emissions reductions for medium-voltage, dry-type transformers:

CO2 (Mt) ................................................................................

NOx (kt) ................................................................................

Hg (t) .....................................................................................

The cumulative CO2, NOx, and Hg

emissions reductions range up to 678.8

Mt, 187.7 kt, and 6.48 t, respectively, in

2038 (sum of liquid-immersed and

medium-voltage dry-type at TSL6).

Total CO2 and NOx emissions

reductions for each TSL are reported in

the environmental assessment, a

separate report in the TSD.

In the ANOPR, the Department stated

that, for its NOPR analysis, it would

calculate discounted values for future

emissions. 69 FR 45376. Accordingly,

the Department here presents its results

for discounted emissions of CO2 and

NOx. When NOx emissions are subject

TSL1

117.4

31.7

2.9

5.6

2.3

0.10

to emissions caps, the Department's

emissions reduction estimate

corresponds to incremental changes in

emissions allowance credits in cap and

trade emissions markets rather than the

net physical emissions reductions that

will occur. The Department used the

same discount rates that it used in

calculating the NPV (seven percent and

three percent real) to calculate

discounted cumulative emission

reductions. Table V.20 shows the

'discounted cumulative emissions

impacts for both liquid-immersed and

dry-type, medium-voltage transformers.

TSL3

205.4

55.5

4.1

12.8

5.3

0.24

TSL4

232.8

62.8

4.5

19.5

8.1

0.36

TSL5

451.2

121.7

5.8

31.2

12.9

0.58

TSL6

647.6

174.8

5.9

31.2

12.9

0.58

The seven-percent and three-percent

real discount rate values are meant to

capture the present value of costs and

benefits associated with projects facing

an average degree of risk. Other

discount rates may be more applicable

to discount costs and benefits associated

with projects facing different risks and

uncertainties. The Department seeks

input from interested parties on the

appropriateness of using other discount

rates in addition to seven percent and

three percent real to discount future

emissions reductions.

TABLE V.20.-DISCOUNTED CUMULATIVE EMISSIONS REDUCTIONS, LIQUID-IMMERSED AND DRY-TYPE, MEDIUM-VOLTAGE

TRANSFORMERS, 2010-2038

Discounted cumulative emissions reduction

Liquid-Immersed, 3% discount, CO2 (Mt) ....................................

Dry-Type, 3% discount, CO2 (Mt) ................................................

Liquid-Immersed, 7% discount, CO2 (Mt) ....................................

Dry-Type, 7% discount, CO2 (Mt) ................................................

Liquid-Immersed, 3% discount, NOx (kt) ....................................

Dry-Type, 3% discount, NOx (kt) ................................................

Liquid-Immersed, 7% discount, NOx (kt) ....................................

Dry-Type, 7% discount, NOx (kt) ................................................

7. Other Factors

The Secretary of Energy, in

determining whether a standard is

economically justified, considers any

other factors that the Secretary deems to

be relevant. (See 42 U.S.C.

6295(o)(2)(B)(i)(VII)) For today's

proposed standard, the Secretary took

into consideration transformermanufacturing-material price

volatility-a factor that received several

comments at the ANOPR public

TSL 1

(TP 1)

TSL2

158.2

42.7

3.5

8.9

3.7

0.17

TSL 2

58.2 78.4

2.8 4.4

25.3 34.0

1.2 1.9

16.3 21.9

1.2 1.8

7.5 10.1

0.5 0.8

meeting, during the comment period

following the meeting, and in the MIA

interviews. Stakeholders expressed

concern about the increasing cost of raw

materials for building transformers, the

volatility of material prices, and the

cumulative effect of material price

increases on the transformer industry

(see section IV.B.2, Engineering

Analysis Inputs). The Department

conducted supplemental engineering

and LCC analyses using first-quarter

TSL 3

101.9

6.4

44.3

2.8

28.6

2.7

13.2

1.2

TSL 4

115.5

9.7

50.1

4.2

32.4

4.0

15.0

1.8

TSL 5

223.5

15.5

96.9

6.7

62.6

6.5

28.9

2.9

TSL 6

321.1

15.5

139.4

6.7

90.0

6.5

41.6

2.9

2005 material prices, and considered the

impacts on LCC savings and payback

periods when evaluating the appropriate

standard levels for liquid-immersed and

medium-voltage, dry-type distribution

transformers. The results of the

engineering and LCC analyses for the

first-quarter 2005 material price analysis

are in the TSD Appendix 5C.

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44395 

TSLs considered in this rulemaking. In 

actuality, present and/or future 

regulations will place caps on the 

emissions of NOx, and Hg for the power 

sector, and thus the emissions 

reductions provided in the table 

represent the Department's estimate of 

the potential reduced demand for 

emissions reduction investments in 

future cap and trade emissions markets. 

The expected energy savings from 

distribution transformer standards will 

reduce the emissions of greenhouse 

gases associated with energy production 

and household use of fossil fuels, and it 

may reduce the cost of maintaining 

system-wide emissions standards and 

constraints. 

TABLE V.19.-CUMULATIVE EMISSIONS REDUCTIONS FROM TRIAL STANDARD LEVELS BY PRODUCT TYPE, 2010-2038 

Trial standard level 

TSL1 TSL2 

Emissions reductions for liquid-immersed transformers: 

CO2 (Mt) ............................................................................... . 117.4 158.2 

NOx (kt) .............................................................................. .. 31.7 42.7 

Hg (t) .................................................................................... . 2.9 3.5 

Emissions reductions for medium-voltage, dry-type transformers: 

CO2 (Mt) .............................................................................. .. 5.6 8.9 

NOx (kt) ............................................................................... . 2.3 3.7 

Hg (t) ................................................................................... .. 0.10 0.17 

The cumulative CO2, NOx, and Hg 

emissions reductions range up to 678.8 

Mt, 187.7 kt, and 6.48 t, respectively, in 

2038 (sum of liquid-immersed and 

medium-voltage dry-type at TSL6). 

Total CO2 and NOx emissions 

reductions for each TSL are reported in 

the environmental assessment, a 

separate report in the TSD. 

In the ANOPR, the Department stated 

that, for its NOPR analysis, it would 

calculate discounted values for future 

emissions. 69 FR 45376. Accordingly, 

the Department here presents its results 

for discounted emissions of C02 and 

NOx. When NOx emissions are subject 

to emissions caps, the Department's 

emissions reduction estimate 

corresponds to incremental changes in 

emissions allowance credits in cap and 

trade emissions markets rather than the 

net physical emissions reductions that 

will occur. The Department used the 

same discount rates that it used in 

calculating the NPV (seven percent and 

three percent real) to calculate 

discounted cumulative emission 

reductions. Table V.20 shows the 

discounted cumulative emissions 

impacts for both liquid-immersed and 

dry-type, medium-voltage transformers. 

TSL3 TSL4 TSL5 TSL6 

205.4 232.8 451.2 647.6 

55.5 62.8 121.7 174.8 

4.1 4.5 5.8 5.9 

12.8 19.5 31.2 31.2 

5.3 8.1 12.9 12.9 

0.24 0.36 0.58 0.58 

The seven-percent and three-percent 

real discount rate values are meant to 

capture the present value of costs and 

benefits associated with projects facing 

an average degree of risk. Other 

discount rates may be more applicable 

to discount costs and benefits associated 

with projects facing different risks and 

uncertainties. The Department seeks 

input from interested parties on the 

appropriateness of using other discount 

rates in addition to seven percent and 

three percent real to discount future 

emissions reductions. 

TABLE V.20.-DISCOUNTED CUMULATIVE EMISSIONS REDUCTIONS, liQUID-IMMERSED AND DRY-TYPE, MEDIUM-VOLTAGE 

TRANSFORMERS, 2010-2038 

Discounted cumulative emissions reduction 

TSL 1 TSL2 (TP 1) 

Liquid-Immersed, 3% discount, CO2 (Mt) .................................... 58.2 78.4 

Dry-Type, 3% discount, C02 (Mt) ................................................ 2.8 4.4 

Liquid-Immersed, 7% discount, C02 (Mt) .................................... 25.3 34.0 

Dry-Type, 7% discount, C02 (Mt) ................................................ 1.2 1.9 

Liquid-Immersed, 3% discount, NOx (kt) .................................... 16.3 21.9 

Dry-Type, 3% discount, NOx (kt) ................................................ 1.2 1.8 

Liquid-Immersed, 7% discount, NOx (kt) .................................... 7.5 10.1 

Dry-Type, 7% discount, NOx (kt) ................................................ 0.5 0.8 

7. Other Factors 

The Secretary of Energy, in 

determining whether a standard is 

economically justified, considers any 

other factors that the Secretary deems to 

be relevant. (See 42 U.S.C. 

6295(0)(2)(B)(i)(VII)) For today's 

proposed standard, the Secretary took 

into consideration transformermanufacturing-material price 

volatility-a factor that received several 

comments at the ANOPR public 

meeting, during the comment period 

following the meeting, and in the MIA 

interviews. Stakeholders expressed 

concern about the increasing cost of raw 

materials for building transformers, the 

volatility of material prices, and the 

cumulative effect of material price 

increases on the transformer industry 

(see section IV.B.2, Engineering 

Analysis Inputs). The Department 

conducted supplemental engineering 

and LCC analyses using first-quarter 

TSL 3 TSL4 TSL5 TSL6 

101.9 115.5 223.5 321.1 

6.4 9.7 15.5 15.5 

44.3 50.1 96.9 139.4 

2.8 4.2 6.7 6.7 

28.6 32.4 62.6 90.0 

2.7 4.0 6.5 6.5 

13.2 15.0 28.9 41.6 

1.2 1.8 2.9 2.9 

2005 material prices, and considered the 

impacts on LCC savings and payback 

periods when evaluating the appropriate 

standard levels for liquid-immersed and 

medium-voltage, dry-type distribution 

transformers. The results of the 

engineering and LCC analyses for the 

first-quarter 2005 material price analysis 

are in the TSD AppendiX 5C. 
44396 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

B. Stakeholder Comments on the

Selection of a Final Standard

During the public comment period on

the ANOPR, the Department received

numerous comments from stakeholders

relating to the selection of the

appropriate standard level for

distribution transformers. Stakeholders

expressed a range of opinions on what

efficiency levels the Department should

select for a standard, some relating

specifically to liquid-immersed

transformers and others to both liquidimmersed and medium-voltage, drytype units.

Concerning liquid-immersed

distribution transformers, Cooper

Industries recommended that NEMA TP

1 be adopted for design lines 1, 2, and

4. For design lines 3 and 5, Cooper

recommended CSL2, which is one level

higher than the TP 1 level. (Note that for

the ANOPR, the CSLs were slightly

different from the levels considered for

the NOPR; for the ANOPR, CSL2 for

design line 3 was 99.40 percent and

CSL2 for design line 5 was 99.40

percent.) For design line 5, Cooper

stated that the majority of users are

industrial customers, who would

typically require the value of annual

energy savings resulting from efficiency

level increases to pay back the cost of

those increases in two to four years, or

provide a 15 to 30 percent annual rate

of return on such cost. (Cooper, No. 62

at pp. 4-6) EMSIC commented that

mandatory efficiency standards can be

set at TP 1 + 0.4 percent for all liquidimmersed products without undue

burden on any stakeholders. (EMSIC,

No. 73 at p. 2) The Department

considered these comments from

Cooper Industries and EMSIC while

reviewing the analytical results and

selecting a proposed standard level for

liquid-immersed distribution

transformers.

Howard stated that it does not believe

the Department should establish

mandatory efficiency standards for

liquid-immersed distribution

transformers because, through TOC

evaluation, the market already drives

these transformers to cost-effective

efficiency levels. Howard participates in

the Energy Star program, and believes

the Department should take a voluntary

approach to standards. (Howard, No. 70

at p. 2) As discussed earlier in this

notice, the Department is charged with

determining whether standards for

distribution transformers are

technologically feasible and

economically justified and would result

in significant energy savings. (42 U.S.C.

6317(a)) Based on the analysis and

information available to date, it appears

that standards for liquid-immersed

distribution transformers would be

technologically feasible and

economically justified, and would result

in significant energy savings. Thus, the

Department will continue to evaluate

minimum efficiency standards for

liquid-immersed transformers.

Howard continued by stating that if

DOE must mandate efficiency levels for

liquid-immersed transformers, then it

recommends the Department use

specific efficiency levels provided in its

comment. For single-phase

transformers, the levels proposed by

Howard start at 98.8 percent for 10 kVA

transformers and rise to 99.4 percent for

75 kVA transformers, above which the

proposed level is constant. For threephase transformers, the levels proposed

by Howard start at 98.5 percent for 15

kVA transformers and rise to 99.4

percent for 225 kVA transformers, above

which the proposed level is constant.

(Howard, No. 70 at pp. 3 and 5) The

Department considered these

recommended levels from Howard

while reviewing the analytical results

and selecting a proposed standard level

for liquid-immersed distribution

transformers.

The Department also received several

cross-cutting comments that pertained

to the appropriate standard level for all

product classes being evaluated.

HVOLT, NGrid, and Southern provided

comments in support of NEMA TP 1.

HVOLT stated that, based on its

involvement in the development of

NEMA TP 1, it recommends setting the

new DOE standard at NEMA TP 1

levels, which have a 3-5-year payback

period at the nationwide average cost of

energy. It noted that this level would

guarantee wide support for the standard.

(HVOLT, No. 65 at p. 3) NGrid stated

that a standard that encourages utilities

to install transformers that meet the

efficiency levels outlined in NEMA TP

1-1996 is in the best interests of the

company and its customers. (NGrid, No.

80 at p. 2) Similarly, Southern Company

commented that the minimum

efficiency standard should be no higher

than NEMA TP 1. It added that the

choice of transformers with efficiencies

higher than TP 1 should be left to the

customer. (Southern, No. 71 at p. 3) The

Department included TP 1 in its

analysis but determined that a higher

efficiency level was economically

justified for the liquid-immersed and

medium-voltage, dry-type super classes,

and would result in significant energy

savings.

EEI and NRECA commented that the

Department should select a standard

level based on the percentage of

transformer consumers with positive

LCC savings, and that the standard

should result in net positive LCC

savings for at least 90 percent of affected

consumers. (EEI, No. 63 at p. 3; NRECA,

No. 74 at p. 2) The Department

considered the percentage of

transformer users with positive LCC

savings in identifying the proposed

standard level but not did set a specific

threshold for users with positive LCC

savings. Discussion of this and other

factors DOE considered in selecting the

proposed standard level appears in

section V.C of this notice.

The Department also received

comments encouraging consideration of

standard levels higher than TP 1. ASE

recommended that efficiency standard

levels be set at the levels with maximum

LCC savings. (ASE, No. 52 at p. 4 and

No. 75 at p. 4) LCC savings is one of

several criteria EPCA considers when

determining whether a standard is

economically justified, and therefore it

is one of the criteria the Department

used to select today's proposed standard

level.

CDA stated that the standard level

should be set at higher efficiencies than

TP 1 because actual loading exceeds the

35 percent and 50 percent loading

assumptions used in the TP 1 analysis.

(CDA, No. 69 at p. 3) CDA urged the

Department to set a minimum efficiency

level that represents a challenge to the

industry, beyond a minimal standard

that all can achieve. It noted that it does

not believe TP 1 is challenging enough

to transformer manufacturers. (CDA, No.

51 at p. 4 and No. 69 at p. 4) The

Department selected the highest

efficiency level that its analysis

identified as justified under EPCA's

criteria. The selected standard will

impact the industry, but the Department

did not specifically use "industry

challenge" as a decision criterion.

Today's proposed standard is not

based on any one factor or criterion as

some commenters suggested. Rather, the

Department arrived at its decision by

weighing the costs and benefits of the

trial standard levels using the seven

factors described in section II.B of this

notice. The proposed standard is set at

the highest level that is technologically

feasible and economically justified (and

would result in significant energy

savings).

C. Proposed Standard

The Department evaluated whether its

TSLs for distribution transformers

achieve the maximum improvement in

energy efficiency that is technologically

feasible and economically justified (and

would result in significant energy

savings). In determining whether a

standard is economically justified, DOE

 EE-RM/STD-00-550 COMMENT 91.1

44396 Federal Register/Vol. 71, No. 150/Friday, August 4, 200S/Proposed Rules 

B. Stakeholder Comments on the 

Selection of a Final Standard 

During the public comment period on 

the ANOPR, the Department received 

numerous comments from stakeholders 

relating to the selection of the 

appropriate standard level for 

distribution transformers. Stakeholders 

expressed a range of opinions on what 

efficiency levels the Department should 

select for a standard, some relating 

specifically to liquid-immersed 

transformers and others to both liquidimmersed and medium-voltage, drytype units. 

Concerning liquid-immersed 

distribution transformers, Cooper 

Industries recommended that NEMA TP 

1 be adopted for design lines 1, 2, and 

4. For design lines 3 and 5, Cooper 

recommended CSL2, which is one level 

higher than the TP 1 level. (Note that for 

the ANOPR, the CSLs were slightly 

different from the levels considered for 

the NOPR; for the ANOPR, CSL2 for 

design line 3 was 99.40 percent and 

CSL2 for design line 5 was 99.40 

percent.) For design line 5, Cooper 

stated that the majority of users are 

industrial customers, who would 

typically require the value of annual 

energy savings resulting from efficiency 

level increases to pay back the cost of 

those increases in two to four years, or 

provide a 15 to 30 percent annual rate 

of return on such cost. (Cooper, No. 62 

at pp. 4-6) EMSIC commented that 

mandatory efficiency standards can be 

set at TP 1 + 0.4 percent for all liquidimmersed products without undue 

burden on any stakeholders. (EMSIC, 

No. 73 at p. 2) The Department 

considered these comments from 

Cooper Industries and EMSIC while 

reviewing the analytical results and 

selecting a proposed standard level for 

liquid-immersed distribution 

transformers. 

Howard stated that it does not believe 

the Department should establish 

mandatory efficiency standards for 

liquid-immersed distribution 

transformers because, through TOC 

evaluation, the market already drives 

tliese transformers to cost-effective 

efficiency levels. Howard partiCipates in 

the Energy Star program, and believes 

the Department should take a voluntary 

approach to standards. (Howard, No. 70 

at p. 2) As discussed earlier in this 

notice, the Department is charged with 

determining whether standards for 

distribution transformers are 

technologically feasible and 

economically justified and would result 

in significant energy savings. (42 U.S.C. 

6317(a)) Based on the analysis and 

information available to date, it appears 

that standards for liquid-immersed 

distribution transformers would be 

technologically feasible and 

economically justified, and would result 

in significant energy savings. Thus, the 

Department will continue to evaluate 

minimum efficiency standards for 

liquid-immersed transformers. 

Howard continued by stating that if 

DOE must mandate efficiency levels for 

liquid-immersed transformers, then it 

recommends the Department use 

specific efficiency levels provided in its 

comment. For single-phase 

transformers, the levels proposed by 

Howard start at 98.8 percent for 10 kVA 

transformers and rise to 99.4 percent for 

75 kV A transformers, above which the 

proposed level is constant. For threephase transformers, the levels proposed 

by Howard start at 98.5 percent for 15 

kVA transformers and rise to 99.4 

percent for 225 kVA transformers, above 

which the proposed level is constant. 

(Howard, No. 70 at pp. 3 and 5) The 

Department considered these 

recommended levels from Howard 

while reviewing the analytical results 

and selecting a proposed standard level 

for liquid-immersed distribution 

transformers. 

The Department also received several 

cross-cutting comments that pertained 

to the appropriate standard level for all 

product classes being evaluated. 

HVOLT, NGrid, and Southern provided 

comments in support of NEMA TP 1. 

HVOL T stated that, based on its 

involvement in the development of 

NEMA TP 1, it recommends setting the 

new DOE standard at NEMA TP 1 

levels, which have a 3-5-year payback 

period at the nationwide average cost of 

energy. It noted that this level would 

guarantee wide support for the standard. 

(HVOLT, No. 65 at p. 3) NGrid stated 

that a standard that encourages utilities 

to install transformers that meet the 

efficiency levels outlined in NEMA TP 

1-1996 is in the best interests of the 

company and its customers. (NGrid, No. 

80 at p. 2) Similarly, Southern Company 

commented that the minimum 

efficiency standard should be no higher 

than NEMA TP 1. It added that the 

choice of transformers with efficiencies 

higher than TP 1 should be left to the 

customer. (Southern, No. 71 at p. 3) The 

Department included TP 1 in its 

analysis but determined that a higher 

efficiency level was economically 

justified for the liquid-immersed and 

medium-voltage, dry-type super classes, 

and would result in significant energy 

savings. 

EEl and NRECA commented that the 

Department should select a standard 

level based on the percentage of 

transformer consumers with positive 

LCC savings, and that the standard 

should result in net positive LCC 

savings for at least 90 percent of affected 

consumers. (EEL No. 63 at p. 3; NRECA, 

No. 74 at p. 2) The Department 

considered the percentage of 

transformer users with positive LCC 

savings in identifying the proposed 

standard level but not did set a specific 

threshold for users with positive LCC 

savings. Discussion of this and other 

factors DOE considered in selecting the 

proposed standard level appears in 

section V.C of this notice. 

The Department also received 

comments encouraging consideration of 

standard levels higher than TP 1. ASE 

recommended that efficiency standard 

levels be set at the levels with maximum 

LCC savings. (ASE, No. 52 at p. 4 and 

No. 75 at p. 4) LCC savings is one of 

several criteria EPCA considers when 

determining whether a standard is 

economically justified, and therefore it 

is one of the criteria the Department 

used to select today's proposed standard 

level. 

CDA stated that the standard level 

should be set at higher efficiencies than 

TP 1 because actual loading exceeds the 

35 percent and 50 percent loading 

assumptions used in the TP 1 analysis. 

(CDA, No. 69 at p. 3) CDA urged the 

Department to set a minimum efficiency 

level that represents a challenge to the 

industry, beyond a minimal standard 

that all can achieve. It noted that it does 

not believe TP 1 is challenging enough 

to transformer manufacturers. (CDA, No. 

51 at p. 4 and No. 69 at p. 4) The 

Department selected the highest 

efficiency level that its analysis 

identified as justified under EPCA's 

criteria. The selected standard will 

impact the industry, but the Department 

did not specifically use "industry 

challenge" as a decision criterion. 

Today's proposed standard is not 

based on anyone factor or criterion as 

some commenters suggested. Rather, the 

Department arrived at its decision by 

weighing the costs and benefits of the 

trial standard levels using the seven 

factors described in section ILB of this 

notice. The proposed standard is set at 

the highest level that is technologically 

feasible and economically justified (and 

would result in significant energy 

savings). 

C. Proposed Standard 

The Department evaluated whether its 

TSLs for distribution transformers 

achieve the maximum improvement in 

energy efficiency that is technologically 

feasible and economically justified (and 

would result in significant energy 

savings). In determining whether a 

standard is economically justified, DOE 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44397

determines whether the benefits of the

standard exceed its costs. Any new or

amended standard for distribution

transformers must result in significant

energy savings.

In selecting a proposed energy

conservation standard for distribution

transformers, the Department followed

its normal approach. It started by

comparing the maximum

technologically feasible level with the

base case, and determined whether that

level was economically justified. Upon

finding the maximum technologically

feasible level not to be justified, the

Department analyzed the next lower

TSL to determine whether that level was

economically justified. The Department

repeated this procedure until it

identified a TSL that was economically

justified. The Department made its

determination of economic justification

on the basis of the NOPR analysis

results published today and the

comments that were submitted by

stakeholders. Beginning with the most

efficient level, this section discusses

each TSL for liquid-immersed

transformers and then each TSL for

medium-voltage, dry-type transformers.

The following two tables summarize

DOE's analytical results. They will aid

the reader in the discussion of costs and

benefits of each TSL. Each table

presents the results or, in some cases, a

range of results, for the underlying

design lines for liquid-immersed (Table

V.21) and medium-voltage, dry-type

(Table V.22) distribution transformers.

The range of values reported in these

tables for LCC, payback, and average

increase in consumer equipment cost

before installation encompass the range

of results calculated for either the

liquid-immersed or medium-voltage,

dry-type representative units. The range

of values for the manufacturer impact

represents the results for the

preservation-of-operating-profit scenario

and preservation-of-gross-margin

scenario at each TSL for liquidimmersed and medium-voltage, drytype transformers.

TABLE V.21.-SUMMARY OF LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS

Trial standard level

uritena

TSL1 TSL2 TSL3 TSL4 TSL5 TSL6

Energy saved (quads) .............................. 1.70 2.28 2.99 3.38 6. 51 9.38

Generation Capacity Offset (GW) ............ 3.1 4.3 5.5 6.2 12.1 17.3

Discounted energy saved , 7% (quads) ... 0.38 0.51 0.67 0.76 1.45 2.10

NPV ($ billions):

@ 7% discount ................................. 2.02 2. 31 2.01 1 .92 (1.14) ( 14.10)

* 3% discount ................................. 7.02 8 .78 9.20 9 .83 9.94 (10.31)

Emission reductions:

CO2 (Mt) ............................................ 117.4 158.2 205.4 232.8 451.2 647.6

NOx (kt) ..........................................•• 31.7 42.7 55.5 62.8 121.7 174.8

Life-Cycle Cost:

Net Savings (%) ................................ 26.1-32.0 32.5-42.4 32.5-49.8 35 . 1-67.7 30.7-42.9 1.1-42.7

Net Increase (%) ............................... 0.2-4.9 1.4-16.8 5.2-52.8 8.6-39.9 43.9-66.3 57.2-98.9

No Change (%) ................................. 63.7-73.7 40.8-65.2 11.3-60.8 4.0-56.3 0.0-25.4 0.0-0.1

Payback (years) ................................ 1.4-11.4 4.3-18.1 8.8-21 .5 12.0-21.9 25.6-36.0 25.6-67

Average increase in consumer

equipment cost before installation

(%) * t ........................................... 1.4-4.2 2.7-12.8 3.0-38.3 4.2-40.6 15.5-141 .9 106.9-160

Manufacturer Impact:

INPV ($ millions) ............................... (5.7)-5.8 ( 12.9)-10.7 (30.0)-27.0 (36.9)-34.9 (203.8)-22.3 (499.6)-25.8

INPV change (%) .............................. ( 1.1)-1.1 (2.4)-2.0 (5.7)-5.1 (7.0)-6.6 (38 .7)-4.2 (94 .9)-4.9

Percent increase in consumer equipment cost before installation , five-year average material pricing.

tThe Department recognizes that these cost changes are the average changes for the Nation , and that some individual customers will experience larger changes, particularly if these customers are not evaluating losses when purchasing transformers.

TABLE V.22.-SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS

Trial standard level

untena

TSL1 TSL2 TSL3 TSL4 TSL5 TSL6

Energy saved (quads) .............................. 0.07 0.11 0.16 0.25 0.39 0.39

Generation Capacity Offset (GW) ............ 0.1 0.2 0.3 0.4 0.6 0.6

Discounted energy saved , 7% (quads) .. 0.02 0.03 0.04 0.06 0.09 0.09

NPV ($ billions):

@ 7% discount ................................. 0.13 0.21 0.28 0.34 0.03 0.03

@ 3% discount ................................. 0.44 0.68 0.95 1.29 1.05 1.05

Emission reductions:

5.6 8.9 12.8 19.5 31.2 31.2

2.3 3.7 5.3 8.1 12.9 12.9

Life-Cycle Cost:

Net Savings (%) ................................ 20.2-55.1 25.6-61.5 36.7-71.5 52.0-75.7 24.3-66.8 24.3-66.8

Net Increase (%) ............................... 0.6-4.4 1.1-5.1 4.4-9.8 18.2-42.6 34.2-75.7 33.2-75.7

No Change (%) ................................. 42.5-76.0 34.6-72.9 18.7-58.9 0.5-28.2 0.0 0.0

Payback (years) ................................ 1.5-9.7 2.4-8.3 5.4-10.0 11.8-19.5 15.1-32.5 14.8-32.4

Increase in consumer equipment

cost before installation (%) * ...... 0.7-4.4 2.2-7.2 5.4-13.6 13.5-30.4 36.4-78.5 36.4-78.4

Manufacturer Impact:

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44397 

determines whether the benefits of the 

standard exceed its costs. Any new or 

amended standard for distribution 

transformers must result in significant 

energy savings. 

In selecting a proposed energy 

conservation standard for distribution 

transformers, the Department followed 

its normal approach. It started by 

comparing the maximum 

technologically feasible level with the 

base case, and determined whether that 

level was economically justified. Upon 

finding the maximum technologically 

feasible level not to be justified, the 

Department analyzed the next lower 

TSL to determine whether that level was 

economically justified. The Department 

repeated this procedure until it 

identified a TSL that was economically 

justified. The Department made its 

determination of economic justification 

on the basis of the NOPR analysis 

results published today and the 

comments that were submitted by 

stakeholders. Beginning with the most 

efficient level, this section discusses 

each TSL for liquid-immersed 

transformers and then each TSL for 

medium-voltage, dry-type transformers. 

The following two tables summarize 

DOE's analytical results. They will aid 

the reader in the discussion of costs and 

benefits of each TSL. Each table 

presents the results or, in some cases, a 

range of results, for the underlying 

design lines for liquid-immersed (Table 

V.21) and medium-voltage, dry-type 

(Table V.22) distribution transformers. 

The range of values reported in these 

tables for LCC, payback, and average 

increase in consumer equipment cost 

before installation encompass the range 

of results calculated for either the 

liquid-immersed or medium-voltage, 

dry-type representative units. The range 

of values for the manufacturer impact 

represents the results for the 

preservation-of-operating-profit scenario 

and preservation-of-gross-margin 

scenario at each TSL for liquidimmersed and medium-voltage, drytype transformers. 

TABLE V.21.-SUMMARY OF liQUID-IMMERSED DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS 

Trial standard level 

Criteria 

TSL1 TSL2 TSL3 TSL4 TSL5 TSL6 

Energy saved (quads) .............................. 1.70 2.28 2.99 3.38 6.51 9.38 

Generation Capacity Offset (GW) ............ 3.1 4.3 5.5 6.2 12.1 17.3 

Discounted energy saved, 7% (quads) ... 0.38 0.51 0.67 0.76 1.45 2.10 

NPV ($ billions): 

@ 7% discount ................................. 2.02 2.31 2.01 1.92 (1.14) (14.10) 

@ 3% discount ................................. 7.02 8.78 9.20 9.83 9.94 (10.31) 

Emission reductions: 

CO2 (Mt) ............................................ 117.4 158.2 205.4 232.8 451.2 647.6 

NOx (kt) ............................................ 31.7 42.7 55.5 62.8 121.7 174.8 

Life-Cycle Cost: 

Net Savings (%) ................................ 26.1-32.0 32.5-42.4 32.5-49.8 35.1-67.7 30.7-42.9 1.1-42.7 

Net Increase (%) ............................... 0.2-4.9 1.4-16.8 5.2-52.8 8.6-39.9 43.9-66.3 57.2-98.9 

No Change (%) ................................. 63.7-73.7 40.8-65.2 11.3-60.8 4.0-56.3 0.0-25.4 0.0--0.1 

Payback (years) ................................ 1.4-11.4 4.3-18.1 8.8-21.5 12.0-21.9 25.6-36.0 25.6-67 

Average increase in consumer 

equipment cost before installation 

(%) * t ........................................... 1.4-4.2 2.7-12.8 3.0-38.3 4.2-40.6 15.5-141.9 106.9-160 

Manufacturer Impact: 

INPV ($ millions) ............................... (5.7)-5.8 (12.9)-10.7 (30.0)-27.0 (36.9)-34.9 (203.8)-22.3 (499.6)-25.8 

INPV change (%) .............................. (1.1)-1.1 (2.4)-2.0 (5.7)-5.1 (7.0)-6.6 (38.7)-4.2 (94.9)-4.9 

* Percent increase in consumer equipment cost before installation, five-year average material pricing. 

t The Department recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience larger changes, particularly if these customers are not evaluating losses when purchasing transformers. 

TABLE V.22.-SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS 

Trial standard level 

Criteria 

TSL1 TSL2 TSL3 TSL4 TSL5 TSL6 

Energy saved (quads) .............................. 0.07 0.11 0.16 0.25 0.39 0.39 

Generation Capacity Offset (GW) ............ 0.1 0.2 0.3 0.4 0.6 0.6 

Discounted energy saved, 7% (quads) ... 0.02 0.03 0.04 0.06 0.09 0.09 

NPV ($ billions): 

@ 7% discount ................................. 0.13 0.21 0.28 0.34 0.03 0.03 

@ 3% discount ................................. 0.44 0.68 0.95 1.29 1.05 1.05 

Emission reductions: 

C02 (Mt) ............................................ 5.6 8.9 12.8 19.5 31.2 31.2 

NOx (kt) ............................................ 2.3 3.7 5.3 8.1 12.9 12.9 

Life-Cycle Cost: 

Net Savings (%) ................................ 20.2-55.1 25.6-61.5 36.7-71.5 52.0-75.7 24.3-66.8 24.3-66.8 

Net Increase (%) ............................... 0.6-4.4 1.1-5.1 4.4-9.8 18.2-42.6 34.2-75.7 33.2-75.7 

No Change (%) ................................. 42.5-76.0 34.6-72.9 18.7-58.9 0.5-28.2 0.0 0.0 

Payback (years) ................................ 1.5-9.7 2.4-8.3 5.4-10.0 11.8-19.5 15.1-32.5 14.8-32.4 

Increase in consumer eqUipment 

cost before installation (%) * t ...... 0.7-4.4 2.2-7.2 5.4-13.6 13.5-30.4 36.4-78.5 36.4-78.4 

Manufacturer Impact: 
44398 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

TABLE V.22.-SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTSContinued

Criteria

INPV ($ millions) ...............................

INPV change (%) ..............................

TSL1

(2.5)-(1.8)

(7.7)-(5.5)

TSL2

(4.3)-(3.3)

(13.4)-(10.1)

Trial standard level

TSL3 TSL4

(7.8)-(3.8)

(24.3)-(11.8)

(6.9)-(5.1)

(21.5)-(15.7)

TSL5

(17.0)-(2.0)

(52.8)-(6.1)

TSL6

(17.0)-(2.0)

(52.8)-(6.1)

Percent increase in consumer equipment cost before installation , five-year average material pricing.

The Department recognizes that these cost changes are the average changes for the Nation , and that some individual customers will experience larger changes, particularly if these customers are not evaluating losses when purchasing transformers.

1. Results for Liquid-Immersed

Distribution Transformers

a. Liquid-Immersed Trial Standard

Level 6

First, the Department considered the

most efficient level (max tech), which

would save an estimated total of 9.4

quads of energy through 2038, a

significant amount of energy.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 2.1 quads. For the Nation

as a whole, TSL6 would have a net cost

of $14 billion at a seven-percent

discount rate. At this level, the majority

of customers would experience an

increase in life-cycle costs. As shown in

Table V.21, only about 1 to 43 percent

of customers would experience lower

life-cycle costs, depending on the design

line. The payback periods at this

standard level are between 26 and 67

years, some of which exceed the

anticipated operating life of the

transformer. The impacts on

manufacturers would be very significant

because TSL6 would require a complete

conversion to amorphous core

technology. These costs would reduce

the INPV by as much as 95 percent

under the preservation-of-operatingprofit scenario. The Department

estimates that $59 million of existing

assets would be stranded (i.e., rendered

useless) and $327 million of conversion

capital expenditures would be required

to enable the industry to manufacture

compliant distribution transformers.

The energy savings at TSL6 would

reduce the installed generating capacity

by 17.3 gigawatts (GW), or roughly 40

large, 400 MW powerplants.5 The

estimated emissions reductions through

this same time period are 647.6 Mt of

CO2 and 174.8 kt of NOx. The

Department concludes that at this TSL,

the benefits of energy savings,

generating capacity reductions, and

emission reductions would be

outweighed by the potential multibillion dollar negative net economic

5 DOE estimates 18 coal-fired power plants and 22

gas-fired power plants can be avoided. See TSD

Chapter 13.

cost to the Nation, the economic burden

on customers as indicated by large

payback periods, and the stranded asset

and conversion capital costs that could

result in the large reduction in INPV for

manufacturers. Consequently, the

Department concludes that TSL6, the

max tech level, is not economically

justified.

b. Liquid-Immersed Trial Standard

Level 5

Next, the Department considered

TSL5, which would save an estimated

total of 6.5 quads of energy through

2038, a significant amount of energy.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 1.45 quads. For the

Nation as a whole, TSL5 would have a

net cost of $1.1 billion at a sevenpercent discount rate. At this level,

about 31 to 43 percent of customers

would experience lower life-cycle costs,

depending on the design line. At this

level, 44 to 66 percent of customers

would have increased life-cycle costs.

The payback periods at this standard

level are between 26 and 36 years, some

of which exceed the anticipated

operating life of the transformer. The

impacts on manufacturers would be

very significant because TSL5 would

require partial conversion to amorphous

core technology. The resulting costs

would contribute to as much as a 39

percent reduction in the INPV under the

preservation-of-operating-profit

scenario . The Department estimates that

$16 million of existing assets would be

stranded and approximately $94 million

in conversion capital expenditures

would be required to enable the

industry to manufacture compliant

transformers. The energy savings at

TSL5 would reduce the installed

generating capacity by 12.1 GW, or

roughly 30 large, 400 MW powerplants.

The estimated emissions reductions

through this same time period are 451.2

Mt of CO2 and 121.7 kt of NOx. The

Department concludes that at this TSL,

the benefits of energy savings,

generating capacity reductions, and

emission reductions would be

outweighed by the potential negative

net economic cost to the Nation, the

economic burden on customers as

indicated by large payback periods, and

the stranded asset and conversion

capital costs that could result in the

large reduction in INPV for

manufacturers. Consequently, the

Department concludes that TSL5 is not

economically justified.

c. Liquid-Immersed Trial Standard

Level 4

Next, the Department considered

TSL4, which would save an estimated

total of 3.4 quads of energy through

2038, a significant amount of energy.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.76 quads. For the

Nation as a whole, TSL4 would result in

a net savings of $1.9 billion at a sevenpercent discount rate. For customers,

lower life-cycle costs would be

experienced by between 35 and 68

percent, depending on the design line,

meaning that for some design lines,

more than half of the customers would

be better off, while for others less than

half would benefit. The payback periods

for three of the five liquid-immersed

design line representative units would

be more than half the anticipated

operating life of the transformer. For one

design line, the payback period is as

long as 22 years. The consumer

equipment cost before installation

would increase by 41 percent for one

design line, a significant increase for

transformer customers. The energy

savings at TSL4 would reduce the

installed generating capacity by 6.2 GW,

or roughly 16 large, 400 MW

powerplants. The estimated emissions

reductions through this same time

period are 232.8 Mt of CO2 and 62.8 kt

of NOx. The Department concludes that

at this TSL, the benefits of energy

savings, generating capacity reductions,

emission reductions and national NPV

would be outweighed by the economic

burden on some customers as indicated

by long payback periods and

significantly greater first costs.

Consequently, the Department

 EE-RM/STD-00-550 COMMENT 91.1

44398 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

TABLE V.22.-SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTSContinued 

Trial standard level 

Criteria 

TSL1 TSL2 TSL3 TSL4 TSL5 TSL6 

INPV ($ millions) ............................... (2.5)-( 1.8) (4.3)-(3.3) (6.9)--(5.1) (7.8)-(3.8) (17.0)--(2.0) (17.0)-(2.0) 

INPV change ('Yo) .............................. (7.7)-(5.5) (13.4)-(10.1 ) (21.5)-(15.7) (24.3)-(11.8) (52.8)--(6.1) (52.8)-(6.1 ) 

• * Percent Increase In consumer equipment cost before Installation, five-year average material pricing. 

, The Department recoQnlzes t~at these cost changes are the average changes for the Nation, and that some individual customers will experi- ence larger changes, particularly If these customers are not evaluating losses when purchasing transformers. 

1. Results for Liquid-Immersed 

Distribution Transformers 

a. Liquid-Immersed Trial Standard 

Level 6 

First, the Department considered the 

most efficient level (max tech), which 

would save an estimated total of 9.4 

quads of energy through 2038, a 

significant amount of energy. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 2.1 quads. For the Nation 

as a whole, TSL6 would have a net cost 

of $14 billion at a seven-percent 

discount rate. At this level, the majority 

of customers would experience an 

increase in life-cycle costs. As shown in 

Table V.21, only about 1 to 43 percent 

of customers would experience lower 

life-cycle costs, depending on the design 

line. The payback periods at this 

standard level are between 26 and 67 

years, some of which exceed the 

anticipated operating life of the 

transformer. The impacts on 

manufacturers would be very significant 

because TSL6 would require a complete 

conversion to amorphous core 

technology. These costs would reduce 

the INPV by as much as 95 percent 

under the preservation-of-operatingprofit scenario. The Department 

estimates that $59 million of existing 

assets would be stranded (Le., rendered 

useless) and $327 million of conversion 

capital expenditures would be required 

to enable the industry to manufacture 

compliant distribution transformers. 

The energy savings at TSL6 would 

reduce the installed generating capacity 

by 17.3 gigawatts (GW), or roughly 40 

large, 400 MW powerplants. 5 The 

estimated emissions reductions through 

this same time period are 647.6 Mt of 

C02 and 174.8 kt of NOx. The 

Department concludes that at this TSL, 

the benefits of energy savings, 

generating capacity reductions, and 

emission reductions would be 

outweighed by the potential multibillion dollar negative net economic 

5 DOE estimates 18 coal-fired power plants and 22 

gas-fired power plants can be avoided. See TSD 

Chapter 13. 

cost to the Nation, the economic burden 

on customers as indicated by large 

payback periods, and the stranded asset 

and conversion capital costs that could 

result in the large reduction in INPV for 

manufacturers. Consequently, the 

Department concludes that TSL6, the 

max tech level, is not economically 

justified. 

b. Liquid-Immersed Trial Standard 

Level 5 

Next, the Department considered 

TSL5, which would save an estimated 

total of 6.5 quads of energy through 

2038, a significant amount of energy. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 1.45 quads. For the 

Nation as a whole, TSL5 would have a 

net cost of $1.1 billion at a sevenpercent discount rate. At this level, 

about 31 to 43 percent of customers 

would experience lower life-cycle costs, 

depending on the design line. At this 

level, 44 to 66 percent of customers 

would have increased life-cycle costs. 

The payback periods at this standard 

level are between 26 and 36 years, some 

of which exceed the anticipated 

operating life of the transformer. The 

impacts on manufacturers would be 

very significant because TSL5 would 

require partial conversion to amorphous 

core technology. The resulting costs 

would contribute to as much as a 39 

percent reduction in the INPV under the 

preservation-of-operating-profit 

scenario. The Department estimates that 

$16 million of existing assets would be 

stranded and approximately $94 million 

in conversion capital expenditures 

would be required to enable the 

industry to manufacture compliant 

transformers. The energy savings at 

TSL5 would reduce the installed 

generating capacity by 12.1 GW, or 

roughly 30 large, 400 MW powerplants. 

The estimated emissions reductions 

through this same time period are 451.2 

Mt of CO2 and 121.7 kt of NOx. The 

Department concludes that at this TSL, 

the benefits of energy savings, 

generating capacity reductions, and 

emission reductions would be 

outweighed by the potential negative 

net economic cost to the Nation, the 

economic burden on customers as 

indicated by large payback periods, and 

the stranded asset and conversion 

capital costs that could result in the 

large reduction in INPV for 

manufacturers. Consequently, the 

Department concludes that TSL5 is not 

economically justified. 

c. Liquid-Immersed Trial Standard 

Level 4 

Next, the Department considered 

TSL4, which would save an estimated 

total of 3.4 quads of energy through 

2038, a significant amount of energy. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.76 quads. For the 

Nation as a whole, TSL4 would result in 

a net savings of $1.9 billion at a sevenpercent discount rate. For customers, 

lower life-cycle costs would be 

experienced by between 35 and 68 

percent, depending on the design line, 

meaning that for some design lines, 

more than half of the customers would 

be better off, while for others less than 

half would benefit. The payback periods 

for three of the five liquid-immersed 

design line representative units would 

be more than half the anticipated 

operating life of the transformer. For one 

design line, the payback period is as 

long as 22 years. The consumer 

equipment cost before installation 

would increase by 41 percent for one 

design line, a significant increase for 

transformer customers. The energy 

savings at TSL4 would reduce the 

installed generating capacity by 6.2 GW, 

or roughly 16 large, 400 MW 

powerplants. The estimated emissions 

reductions through this same time 

period are 232.8 Mt of CO2 and 62.8 kt 

of NOx. The Department concludes that 

at this TSL, the benefits of energy 

savings, generating capacity reductions, 

emission reductions and national NPV 

would be outweighed by the economic 

burden on some customers as indicated 

by long payback periods and 

significantly greater first costs. 

Consequently, the Department 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44399

concludes that TSL4 is not

economically justified.

d. Liquid-Immersed Trial Standard

Level 3

Next, the Department considered

TSL3, which would save an estimated

total of 3 quads of energy through 2038,

a significant amount of energy.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.67 quads. For the

Nation as a whole, TSL3 would have a

net savings of $2 billion at a sevenpercent discount rate. At this level,

lower life-cycle costs would be

experienced by between 32 and 50

percent of customers, depending on the

design line, meaning that for all the

design lines, one-half or less of

customers are better off. One of the

payback periods is 22 years, exceeding

half the anticipated operating life of a

transformer. Additionally, the consumer

equipment cost before installation

increases by 38 percent for one design

line, a significant increase for

customers. The energy savings at TSL3

would reduce the installed generating

capacity by 5.5 GW, or roughly 14 large,

400 MW powerplants. The estimated

emission reductions through this same

time period are 205.4 Mt of CO2 and

55.5 kt of NOx. The Department

concludes that at this TSL, the benefits

of energy savings, generating capacity

reductions, emission reductions and

national NPV would be outweighed by

the economic burden on some

customers as indicated by long payback

periods and significantly greater first

costs. Consequently, the Department

concludes that TSL3 is not

economically justified.

e. Liquid-Immersed Trial Standard

Level 2

Next, the Department considered

TSL2, which would save an estimated

total of 2.3 quads of energy through

2038, a significant amount of energy.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.51 quads. For the

Nation as a whole, TSL2 would have the

highest NPV of all the TSLs for liquidimmersed distribution transformers, an

estimated $2.3 billion at the sevenpercent discount rate. At this level, as

shown in Table V.21, between 32 and 42

percent of customers would experience

lower life-cycle costs, depending on the

design line. The payback periods under

TSL2 are between 4 and 18 years, which

at most is approximately half the

anticipated operating life of the

transformer. The energy savings at TSL2

would reduce the installed generating

capacity by 4.3 GW, or roughly 11 large,

400 MW powerplants. The estimated

emissions reductions through this same

time period are 158.2 Mt of CO2 and

42.7 kt of NOx. At TSL2, the relatively

low costs are outweighed by the

benefits, including significant energy

savings, generating capacity reductions,

emission reductions, maximum national

NPV, and benefits to a majority of those

customers affected by the standard.

After considering the costs and benefits

of TSL2, the Department finds that this

trial standard level will offer the

maximum improvement in efficiency

that is technologically feasible and

economically justified, and will result

in significant conservation of energy.

Therefore, the Department today

proposes to adopt the energy

conservation standards for liquidimmersed distribution transformers at

TSL2.

2. Results for Medium-Voltage, DryType Distribution Transformers

a. Medium-Voltage, Dry-Type Trial

Standard Level 6

First, the Department considered the

most efficient level (max tech), which

would save an estimated total of 0.4

quads of energy through 2038.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.09 quads. For the

Nation as a whole, TSL6 would result in

a $30 million benefit at a seven-percent

discount rate. However, at this level, the

percentage of customers experiencing

lower life-cycle costs would be less than

35 percent for the majority of the units

analyzed, with one representative unit

as low as 24 percent. This means that

more than three-quarters of transformer

customers making purchases in that

design line would experience increases

in life-cycle cost. Customer payback

periods at this standard level for the

majority of units analyzed are 28 years

or greater, with one representative unit

as high as 32 years, which is

approximately the operating life of a

transformer. The impacts on

manufacturers would be significant,

with TSL 6 contributing to a 53-percent

reduction in the INPV under the

preservation-of-operating-profit

scenario. The Department projects that

manufacturers will experience negative

net annual cash flows during the

compliance period, irrespective of the

markup scenario. The magnitude of the

peak, negative, net annual cash flow

would be more than twice that of the

positive-base-case cash flow. The energy

savings at TSL6 would reduce installed

generating capacity by 0.6 GW, or

roughly 1.5 large, 400 MW powerplants.

The Department estimates the

associated emissions reductions through

2038 of 31.2 Mt of CO2 and 12.9 kt of

NOx. The Department concludes that at

this TSL, the benefits of energy savings,

generating capacity reductions,

emission reductions and national NPV

would be outweighed by the economic

burdens on customers as indicated by

long payback periods and significantly

greater first costs, and manufacturers

who may experience a drop in INPV of

up to 53 percent. Consequently, the

Department concludes that TSL6, the

max tech level, is not economically

justified.

b. Medium-Voltage, Dry-Type Trial

Standard Level 5

Next, the Department considered

TSL5, which is identical to TSL6 (i.e.,

for all the representative units, TSL5

and TSL6 have all the same percentage

efficiency values). Thus, for the same

reasons described above in section

V.C.2.a, the Department concludes that

TSL5 is not economically justified.

c. Medium-Voltage, Dry-Type Trial

Standard Level 4

Next, the Department considered

TSL4, which would save a total of 0.3

quads of energy through 2038.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.06 quads. For the

Nation as a whole, TSL4 would have a

net savings of $0.34 billion at a sevenpercent discount rate, the maximum

NPV for medium-voltage, dry-type

distribution transformers. Because for

TSL5 and TSL6 the energy savings

comes at a high incremental equipment

cost, the national net savings for TSL4

is substantially higher than TSL5/6. The

percentage of customers experiencing

lower life-cycle costs would range

between 52 and 76 percent, depending

on the design line. However, payback

periods at this standard level are as high

as 20 years for one design line, which

is more than half the operating life of a

transformer. In addition, the consumer

equipment cost before installation

would increase by as much as 30

percent for one design line, a significant

increase for customers. Furthermore, the

impacts of TSL4 on manufacturers

would be significant, contributing to as

much as a 24-percent reduction in the

INPV under the preservation-ofoperating-profit scenario. Additionally,

DOE projects that manufacturers will

experience negative net annual cash

flows during the compliance period,

irrespective of the markup scenario. The

magnitude of the peak, negative, net

annual cash flow is approximately half

of that of the positive-base-case cash

flow. The energy savings at TSL4 would

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150 I Friday, August 4, 2006/Proposed Rules 44399 

conciudes that TSL4 is not 

economically justified. 

d. Liquid-Immersed Trial Standard 

Level 3 

Next, the Department considered 

TSL3, which would save an estimated 

total of 3 quads of energy through 2038, 

a significant amount of energy. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.67 quads. For the 

Nation as a whole, TSL3 would have a 

net savings of $2 billion at a sevenpercent discount rate. At this level, 

lower life-cycle costs would be 

experienced by between 32 and 50 

percent of customers, depending on the 

design line, meaning that for all the 

design lines, one-half or less of 

customers are better off. One of the 

payback periods is 22 years, exceeding 

half the anticipated operating life of a 

transformer. Additionally, the consumer 

equipment cost before installation 

increases by 38 percent for one design 

line, a significant increase for 

customers. The energy savings at TSL3 

would reduce the installed generating 

capacity by 5.5 GW, or roughly 14 large, 

400 MW powerplants. The estimated 

emission reductions through this same 

time period are 205.4 Mt of C02 and 

55.5 kt of NOx. The Department 

concludes that at this TSL, the benefits 

of energy savings, generating capacity 

reductions, emission reductions and 

national NPV would be outweighed by 

the economic burden on some 

customers as indicated by long payback 

periods and significantly greater first 

costs. Consequently, the Department 

concludes that TSL3 is not 

economically justified. 

e. Liquid-Immersed Trial Standard 

Level 2 

Next, the Department considered 

TSL2, which would save an estimated 

total of 2.3 quads of energy through 

2038, a significant amount of energy. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.51 quads. For the 

Nation as a whole, TSL2 would have the 

highest NPV of all the TSLs for liquidimmersed distribution transformers, an 

estimated $2.3 billion at the sevenpercent discount rate. At this level, as 

shown in Table V.21, between 32 and 42 

percent of customers would experience 

lower life-cycle costs, depending on the 

design line. The payback periods under 

TSL2 are between 4 and 18 years, which 

at most is approximately half the 

anticipated operating life of the 

transformer. The energy savings at TSL2 

would reduce the installed generating 

capacity by 4.3 GW, or roughly 11 large, 

400 MW powerplants. The estimated 

emissions reductions through this same 

time period are 158.2 Mt of CO2 and 

42.7 kt of NOx. At TSL2, the relatively 

low costs are outweighed by the 

benefits, including significant energy 

savings, generating capacity reductions, 

emission reductions, maximum national 

NPV, and benefits to a majority ofthose 

customers affected by the standard. 

After considering the costs and benefits 

of TSL2, the Department finds that this 

trial standard level will offer the 

maximum improvement in efficiency 

that is technologically feasible and 

economically justified, and will result 

in significant conservation of energy. 

Therefore, the Department today 

proposes to adopt the energy 

conservation standards for liquidimmersed distribution transformers at 

TSL2. 

2. Results for Medium-Voltage, DryType Distribution Transformers 

a. Medium-Voltage, Dry-Type Trial 

Standard Level 6 

First, the Department considered the 

most efficient level (max tech), which 

would save an estimated total of 0.4 

quads of energy through 2038. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.09 quads. For the 

Nation as a whole, TSL6 would result in 

a $30 million benefit at a seven-percent 

discount rate. However, at this level, the 

percentage of customers experiencing 

lower life-cycle costs would be less than 

35 percent for the majority of the units 

analyzed, with one representative unit 

as low as 24 percent. This means that 

more than three-quarters of transformer 

customers making purchases in that 

design line would experience increases 

in life-cycle cost. Customer payback 

periods at this standard level for the 

majority of units analyzed are 28 years 

or greater, with one representative unit 

as high as 32 years, which is 

approximately the operating life of a 

transformer. The impacts on 

manufacturers would be significant, 

with TSL 6 contributing to a 53-percent 

reduction in the INPV under the 

preservation-of-operating-profit 

scenario. The Department projects that 

manufacturers will experience negative 

net annual cash flows during the 

compliance period, irrespective ofthe 

markup scenario. The magnitude of the 

peak, negative, net annual cash flow 

would be more than twice that of the 

positive-base-case cash flow. The energy 

savings at TSL6 would reduce installed 

generating capacity by 0.6 GW, or 

roughly 1.5 large, 400 MW powerplants. 

The Department estimates the 

associated emissions reductions through 

2038 of 31.2 Mt of C02 and 12.9 kt of 

NOx. The Department concludes that at 

this TSL, the benefits of energy savings, 

generating capacity reductions, 

emission reductions and national NPV 

would be outweighed by the economic 

burdens on customers as indicated by 

long payback periods and significantly 

greater first costs, and manufacturers 

who may experience a drop in INPV of 

up to 53 percent. Consequently, the 

Department concludes that TSL6, the 

max tech level, is not economically 

justified. 

b. Medium-Voltage, Dry-Type Trial 

Standard Level 5 

Next, the Department considered 

TSL5, which is identical to TSL6 (Le., 

for all the representative units, TSL5 

and TSL6 have all the same percentage 

efficiency values). Thus, for the same 

reasons described above in section 

V.C.2.a, the Department concludes that 

TSL5 is not economically justified. 

c. Medium-Voltage, Dry-Type Trial 

Standard Level 4 

Next, the Department considered 

TSL4, which would save a total of 0.3 

quads of energy through 2038. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.06 quads. For the 

Nation as a whole, TSL4 would have a 

net savings of $0.34 billion at a sevenpercent discount rate, the maximum 

NPV for medium-voltage, dry-type 

distribution transformers. Because for 

TSL5 and TSL6 the energy savings 

comes at a high incremental equipment 

cost, the national net savings for TSL4 

is substantially higher than TSL5/6. The 

percentage of customers experiencing 

lower life-cycle costs would range 

between 52 and 76 percent, depending 

on the design line. However, payback 

periods at this standard level are as high 

as 20 years for one design line, which 

is more than half the operating life of a 

transformer. In addition, the consumer 

equipment cost before installation 

would increase by as much as 30 

percent for one design line, a significant 

increase for customers. Furthermore, the 

impacts of TSL4 on manufacturers 

would be significant, contributing to as 

much as a 24-percent reduction in the 

INPV under the preservation-ofoperating-profit scenario. Additionally, 

DOE projects that manufacturers will 

experience negative net annual cash 

flows during the compliance period, 

irrespective of the markup scenario. The 

magnitude of the peak, negative, net 

annual cash flow is approximately half 

of that of the positive-base-case cash 

flow. The energy savings at TSL4 would 
44400 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

reduce the installed generating capacity

by 0.4 GW, or roughly one large, 400

MW powerplant. The Department

estimates associated emissions

reductions through 2038 of 19.5 Mt of

CO2 and 8.1 kt of NOx. Thus, the

Department concludes that at this TSL,

the benefits of energy savings,

generating capacity reductions, positive

national NPV, and emission reductions

would be outweighed by the long

payback periods and significantly

greater first costs for some transformer

customers and the economic impacts on

manufacturers. Consequently, the

Department concludes that TSL4 is not

economically justified.

d. Medium-Voltage, Dry-Type Trial

Standard Level 3

Next, the Department considered

TSL3, which would save an estimated

0.2 quads of energy through 2038.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.04 quads. For the

Nation as a whole, TSL3 would have a

net savings of $0.3 billion at a sevenpercent discount rate. The percentage of

transformer customers who would

experience lower life-cycle costs ranges

between 37 and 71 percent, depending

on the design line, with payback periods

of 10 years or less. The impacts on

manufacturers at TSL3 would be

significant, however, contributing to as

much as a 22-percent reduction in the

INPV under the preservation-ofoperating-profit scenario. In addition,

DOE projects the net annual cash flows

to be negative during the compliance

period, irrespective of the markup

scenario. The magnitude of the peak

negative net annual cash flow would be

approximately half of the positive-basecase cash flow. The energy savings at

TSL3 would reduce the installed

generating capacity by 0.3 GW, or

roughly 0.8 of a large, 400 MW

powerplant. The Department estimates

the associated emissions reductions

through 2038 of 12.8 Mt of CO2 and 5.3

kt of NOx. Thus, the Department

concludes that at this TSL, the benefits

of energy savings, generating capacity

reductions, positive national NPV, LCC

savings, and emission reductions would

be outweighed by the economic impacts

on manufacturers. Consequently, the

Department concludes that TSL3 is not

economically justified.

e. Medium-Voltage, Dry-Type Trial

Standard Level 2

Next, the Department considered

TSL2, which would save an estimated

total of 0.1 quad of energy through 2038.

Discounted at 7 percent, the energy

savings through 2038 would reduce to

approximately 0.03 quads. For the

Nation as a whole, TSL2 would have a

net savings of $0.2 billion at a sevenpercent discount rate. The percentage of

transformer customers experiencing

lower life-cycle costs ranges between 26

and 61 percent, depending on the

design line, with payback periods of

eight years or less. The Department

considers impacts on manufacturers at

this standard level (at most a 13-percent

reduction in the INPV under the

preservation-of-operating-profit

scenario) to be reasonable. The energy

savings at TSL2 would reduce the

installed generating capacity by 0.2 GW,

or roughly half of a large, 400 MW

powerplant. The Department estimates

associated emissions reductions through

2037 of 8.9 Mt of CO2 and 3.7 kt of NOx.

Thus, the Department concludes that

this TSL has positive energy savings,

generating capacity reductions,

emission reductions, national NPV,

benefits to transformer customers, and

reasonable impacts on transformer

manufacturers. After considering the

costs and benefits of TSL2, the

Department finds that this trial standard

level will offer the maximum

improvement in efficiency that is

technologically feasible and

economically justified, and will result

in significant conservation of energy.

Therefore, the Department today

proposes to adopt the energy

conservation standards for mediumvoltage, dry-type distribution

transformers at TSL2.

VI. Procedural Issues and Regulatory

Review

A. Review Under Executive Order 12866

The Department has determined

today's regulatory action is a

"significant regulatory action" under

section 3(f)(1) of Executive Order 12866,

"Regulatory Planning and Review." 58

FR 51735 (October 4, 1993).

Accordingly, today's action required a

regulatory impact analysis (RIA) and,

under the Executive Order, was subject

to review by the Office of Information

and Regulatory Affairs (OIRA) in the

Office of Management and Budget

(OMB). The Department presented to

OIRA for review the draft proposed rule

and other documents prepared for this

rulemaking, including the RIA, and has

included these documents in the

rulemaking record. They are available

for public review in the Resource Room

of DOE's Building Technologies

Program, 1000 Independence Avenue,

SW., Washington, DC, (202) 586-9127,

between 9 a.m. and 4 p.m., Monday

through Friday, except Federal holidays.

Regarding the Department's

preparation of a regulatory alternatives

analysis, ASE said the Department

should fully describe non-regulatory

alternatives, including penetration rates,

in the NOPR analysis. (Public Meeting

Transcript, No. 56.12 at pp. 252-253)

The Department followed the examples

established by prior rulemakings in

regulatory impact reporting. The RIA,

formally entitled, "Regulatory Impact

Analysis for Proposed Energy

Conservation Standards for Electrical

Distribution Transformers," is contained

in the TSD prepared for the rulemaking.

The RIA consists of: (1) A statement of

the problem addressed by this

regulation, and the mandate for

government action; (2) a description and

analysis of the feasible policy

alternatives to this regulation; (3) a

quantitative comparison of the impacts

of the alternatives; and (4) the national

economic impacts of the proposed

standard.

The RIA calculates the effects of

feasible policy alternatives to

distribution transformer standards, and

provides a quantitative comparison of

the impacts of the alternatives. The

Department evaluated each alternative

in terms of its ability to achieve

significant energy savings at reasonable

costs, and compared it to the

effectiveness of the proposed rule. The

Department analyzed these alternatives

using a series of regulatory scenarios as

input to the NES/shipments model for

distribution transformers, which it

modified to allow inputs for voluntary

measures.

The Department identified the

following major policy alternatives for

achieving increased distribution

transformer energy efficiency:

® No new regulatory action

® Consumer rebates

• Consumer tax credits

® Manufacturer tax credits

® Voluntary energy-efficiency targets

® Early replacement

• Bulk government purchases

The Department evaluated each

alternative in terms of its ability to

achieve significant energy savings at

reasonable costs (see Table VIA), and

compared it to the effectiveness of the

proposed rule.

 EE-RM/STD-00-550 COMMENT 91.1

44400 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

reduce the installed generating capacity 

by 0.4 GW, or roughly one large, 400 

MW powerplant. The Department 

estimates associated emissions 

reductions through 2038 of 19.5 Mt of 

C02 and 8.1 kt of NOx. Thus, the 

Department concludes that at this TSL, 

the benefits of energy savings, 

generating capacity reductions, positive 

national NPV, and emission reductions 

would be outweighed by the long 

payback periods and significantly 

greater first costs for some transformer 

customers and the economic impacts on 

manufacturers. Consequently, the 

Department concludes that TSL4 is not 

economically justified. 

d. Medium-Voltage, Dry-Type Trial 

Standard Level 3 

Next, the Department considered 

TSL3, which would save an estimated 

0.2 quads of energy through 2038. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.04 quads. For the 

Nation as a whole, TSL3 would have a 

net savings of $0.3 billion at a sevenpercent discount rate. The percentage of 

transformer customers who would 

experience lower life-cycle costs ranges 

between 37 and 71 percent, depending 

on the design line, with payback periods 

of 10 years or less. The impacts on 

manufacturers at TSL3 would be 

significant, however, contributing to as 

much as a 22-percent reduction in the 

INPV under the preservation-ofoperating-profit scenario. In addition, 

DOE projects the net annual cash flows 

to be negative during the compliance 

period, irrespective ofthe markup 

scenario. The magnitude of the peak 

negative net annual cash flow would be 

approximately half of the positive-basecase cash flow. The energy savings at 

TSL3 would reduce the installed 

generating capacity by 0.3 GW, or 

roughly 0.8 of a large, 400 MW 

powerplant. The Department estimates 

the associated emissions reductions 

through 2038 of 12.8 Mt of CO2 and 5.3 

kt of NOx. Thus, the Department 

concludes that at this TSL, the benefits 

of energy savings, generating capacity 

reductions, positive national NPV, LCC 

savings, and emission reductions would 

be outweighed by the economic impacts 

on manufacturers. Consequently, the 

Department concludes that TSL3 is not 

economically justified. 

e. Medium-Voltage, Dry-Type Trial 

Standard Level 2 

Next, the Department considered 

TSL2, which would save an estimated 

total of 0.1 quad of energy through 2038. 

Discounted at 7 percent, the energy 

savings through 2038 would reduce to 

approximately 0.03 quads. For the 

Nation as a whole, TSL2 would have a 

net savings of $0.2 billion at a sevenpercent discount rate. The percentage of 

transformer customers experiencing 

lower life-cycle costs ranges between 26 

and 61 percent, depending on the 

design line, with payback periods of 

eight years or less. The Department 

considers impacts on manufacturers at 

this standard level (at most a 13-percent 

reduction in the INPV under the 

preservation-of-operating-profit 

scenario) to be reasonable. The energy 

savings at TSL2 would reduce the 

installed generating capacity by 0.2 GW, 

or roughly half of a large, 400 MW 

powerplant. The Department estimates 

associated emissions reductions through 

2037 of 8.9 Mt of C02 and 3.7 kt of NOx. 

Thus, the Department concludes that 

this TSL has positive energy savings, 

generating capacity reductions, 

emission reductions, national NPV, 

benefits to transformer customers, and 

reasonable impacts on transformer 

manufacturers. After considering the 

costs and benefits of TSL2, the 

Department finds that this trial standard 

level will offer the maximum 

improvement in efficiency that is 

technologically feasible and 

economically justified, and will result 

in significant conservation of energy. 

Therefore, the Department today 

proposes to adopt the energy 

conservation standards for mediumvoltage, dry-type distribution 

transformers at TSL2. 

VI. Procedural Issues and Regulatory 

Review 

A. Review Under Executive Order 12866 

The Department has determined 

today's regulatory action is a 

"significant regulatory action" under 

section 3(f)(1) of Executive Order 12866, 

"Regulatory Planning and Review." 58 

FR 51735 (October 4,1993). 

Accordingly, today's action required a 

regulatory impact analysis (RIA) and, 

under the Executive Order, was subject 

to review by the Office of Information 

and Regulatory Affairs (OIRA) in the 

Office of Management and Budget 

(OMB). The Department presented to 

OIRA for review the draft proposed rule 

and other documents prepared for this 

rulemaking, including the RIA, and has 

included these documents in the 

rulemaking record. They are available 

for public review in the Resource Room 

of DOE's Building Technologies 

Program, 1000 Independence Avenue, 

SW., Washington, DC, (202) 586-9127, 

between 9 a.m. and 4 p.m., Monday 

through Friday, except Federal holidays. 

Regarding the Department's 

preparation of a regulatory alternatives 

analysis, ASE said the Department 

should fully describe non-regulatory 

alternatives, including penetration rates, 

in the NOPR analysis. (Public Meeting 

Transcript, No. 56.12 at pp. 252-253) 

The Department followed the examples 

established by prior rulemakings in 

regulatory impact reporting. The RIA, 

formally entitled, "Regulatory Impact 

Analysis for Proposed Energy 

Conservation Standards for Electrical 

Distribution Transformers," is contained 

in the TSD prepared for the rulemaking. 

The RIA consists of: (1) A statement of 

the problem addressed by this 

regulation, and the mandate for 

government action; (2) a description and 

analysis of the feasible policy 

alternatives to this regulation; (3) a 

quantitative comparison of the impacts 

of the alternatives; and (4) the national 

economic impacts of the proposed 

standard. 

The RIA calculates the effects of 

feasible policy alternatives to 

distribution transformer standards, and 

provides a quantitative comparison of 

the impacts of the alternatives. The 

Department evaluated each alternative 

in terms of its ability to achieve 

significant energy savings at reasonable 

costs, and compared it to the 

effectiveness of the proposed rule. The 

Department analyzed these alternatives 

using a series of regulatory scenarios as 

input to the NES/shipments model for 

distribution transformers, which it 

modified to allow inputs for voluntary 

measures. 

The Department identified the 

following major policy alternatives for 

achieving increased distribution 

transformer energy efficiency: 

" No new regulatory action 

.. Consumer rebates 

" Consumer tax credits 

.. Manufacturer tax credits 

.. Voluntary energy-efficiency targets 

" Early replacement 

.. Bulk government purchases 

The Department evaluated each 

alternative in terms of its ability to 

achieve significant energy savings at 

reasonable costs (see Table Vl.1), and 

compared it to the effectiveness of the 

proposed rule. 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

TABLE VI.1.-NON-REGULATORY ALTERNATIVES AND THE PROPOSED STANDARD

44401

Net present value

Primary energy

i

(billion $2004)

Policy alternatives Type sav ngs

(quads) 7% discount 3% discount

rate rate

No New Regulatory Action .................................................. .............................................. 0.0 0.0 0.0

Consumer Rebates ............................................................. Liquid .................................... 0.0 0.0 0.0

MV* Dry ................................ 0.007 0.013 0.042

Total ..................................... 0.007 0.013 0.042

Consumer Tax Credits ........................................................ Liquid .................................... 0.058 0.058 0.218

MV Dry ................................. 0.004 0.008 0.025

Total ..................................... 0.06 0.07 0.24

Manufacturer Tax Credits ................................................... Liquid .................................... 0.029 0.028 0.108

MV Dry ................................. 0.002 0.004 0.013

Total ..................................... 0.03 0.03 0.12

Proposed Standards at TSL2 ............................................. Liquid .................................... 2.28 2.31 8.78

MV Dry ................................. 0.113 0.207 0.683

Total ..................................... 2.40 1

2.52 9.47

* MV = medium-voltage.

Table VI.1 shows the NES and NPV of

each of the applicable non-regulatory

alternatives. The results are reported for

liquid-immersed and medium-voltage,

dry-type transformers as well as in total.

The case in which no regulatory action

is taken with regard to distribution

transformers constitutes the base case

(or "No Action") scenario. Since this is

the base case, energy savings and NPV

are zero by definition. For comparison,

the table includes the impacts of the

proposed energy conservation

standards. The NPV amounts shown in

Table VI.1 refer to the NPV based on

two discount rates (seven percent and

three percent real). DOE did not

consider three of the policy alternatives,

voluntary energy-efficiency targets,

early replacement, and bulk government

purchases, because, as discussed in the

RIA, DOE believes they would not

significantly impact the distribution

transformers covered by this NOPR.

None of the alternatives DOE

examined would save as much energy or

have an NPV as high as the proposed

standards. Also, several of the

alternatives would require new enabling

legislation, such as consumer or

manufacturer tax credits, since authority

to carry out those alternatives does not

presently exist. Additional detail on the

regulatory alternatives is found in the

RIA report of the TSD.

B. Review Under the Regulatory

Flexibility Act/Initial Regulatory

Flexibility Analysis

The Regulatory Flexibility Act (5

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

of an initial regulatory flexibility

analysis 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

(August 16, 2002), DOE published

procedures and policies on February 19,

2003, to ensure that the potential

impacts of its rules on small entities are

properly considered during the

rulemaking process. 68 FR 7990. The

Department has made its procedures

and policies available on the Office of

General Counsel's Web site: http://

www.gc.doe.gov.

Small businesses, as defined by the

Small Business Administration (SBA)

for the distribution transformer

manufacturing industry, are

manufacturing enterprises with 750

employees or fewer. The Department

reviewed today's proposed rule under

the provisions of the Regulatory

Flexibility Act and the procedures and

policies published on February 19,

2003. On the basis of the foregoing, DOE

determined that it cannot certify that the

proposed rule (trial standard level 2, or

TSL2), if promulgated, would have no

significant economic impact on a

substantialnumber of small entities. The

Department made this determination

because of the potential impacts that the

proposed standard levels for mediumvoltage, dry-type distribution

transformers would have on the small

businesses that manufacture them.

However, the Department notes that it

explicitly considered the impacts on

small medium-voltage, dry-type

businesses in selecting TSL2, rather

than selecting a higher trial standard

level.

The revenue attributable to the

medium-voltage, dry-type superclass

represents only about six percent of the

total revenues of the industry affected

by this rulemaking (i.e., the sum of

revenues from the liquid-immersed

superclass and the medium-voltage, drytype superclass). Because of the

potential impacts of today's proposed

rule on small, medium-voltage, dry-type

manufacturers, DOE has prepared an

initial regulatory flexibility analysis

(IRFA) for this rulemaking. The IRFA

divides potential impacts on small

businesses into two broad categories: (1)

Impacts associated with transformer

design and manufacturing, and (2)

impacts associated with demonstrating

compliance with the standard using

DOE's test procedure. The Department's

test procedure rule does not require

manufacturers to take any action in the

absence of final energy conservation

standards for distribution transformers,

and thus any impact of that rule on

small businesses would be triggered by

the promulgation of the standard

proposed today.

The Department believes that there

will be no significant economic impact

on a substantial number of small liquidimmersed manufacturers because the

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. l50/Friday, August 4, 2006/Proposed Rules 44401 

TABLE VI.1.-NoN-REGULATORY ALTERNATIVES AND THE PROPOSED STANDARD 

Net present value 

Policy altematives 

Primary energy (billion $2004) 

Type 

No New Regulatory Action ............... ...... ................ ............. .. ........................................... . 

Consumer Rebates ............................................................. Liquid ................................... . 

MV' Dry .............................. .. 

Total ................................... .. 

Consumer Tax Credits ........................................................ Liquid ................................... . 

MV Dry ................................ . 

Total .................................... . 

Manufacturer Tax Credits ................................................... Liquid ................................... . 

MV Dry ................................ . 

Total ................................... .. 

Proposed Standards at TSL2 ... .............. ................. ........... Liquid ................................... . 

• MV = medium-voltage. 

Table VI.l shows the NES and NPV of 

each of the applicable non-regulatory 

alternatives. The results are reported for 

liquid-immersed and medium-voltage, 

dry-type transformers as well as in total. 

The case in which no regulatory action 

is taken with regard to distribution 

transformers constitutes the base case 

(or "No Action") scenario. Since this is 

the base case, energy savings and NPV 

are zero by definition. For comparison, 

the table includes the impacts of the 

proposed energy conservation 

standards. The NPV amounts shown in 

Table VI.l refer to the NPV based on 

two discount rates (seven percent and 

three percent real). DOE did not 

consider three of the policy alternatives, 

voluntary energy-efficiency targets, 

early replacement, and bulk government 

purchases, because, as discussed in the 

RIA, DOE believes they would not 

significantly impact the distribution 

transformers covered by this NOPR. 

None of the alternatives DOE 

examined would save as much energy or 

have an NPV as high as the proposed 

standards. Also, several of the 

alternatives would require new enabling 

legislation, such as consumer or 

manufacturer tax credits, since authority 

to carry out those alternatives does not 

presently exist. Additional detail on the 

regulatory alternatives is found in the 

RIA report ofthe TSD. 

B. Review Under the Regulatory 

Flexibility Act/Initial Regulatory 

Flexibility Analysis 

The Regulatory Flexibility Act (5 

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

MV Dry ............................... .. 

Total .................................... . 

of an initial regulatory flexibility 

analysis 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 

(August 16, 2002), DOE published 

procedures and policies on February 19, 

2003, to ensure that the potential 

impacts of its rules on small entities are 

properly considered during the 

rulemaking process. 68 FR 7990. The 

Department has made its procedures 

and policies available on the Office of 

General Counsel's Web site: http:// 

www.gc.doe.gov. 

Small businesses, as defined by the 

Small Business Administration (SBA) 

for the distribution transformer 

manufacturing industry, are 

manufacturing enterprises with 750 

employees or fewer. The Department 

reviewed today's proposed rule under 

the provisions of the Regulatory 

Flexibility Act and the procedures and 

policies published on February 19, 

2003. On the basis of the foregoing, DOE 

determined that it cannot certify that the 

proposed rule (trial standard level 2, or 

TSL2), if promulgated, would have no 

significant economic impact on a 

substantialnumber of small entities. The 

Department made this determination 

because of the potential impacts that the 

proposed standard levels for mediumvoltage, dry-type distribution 

savings 

(quads) 7% discount 3% discount 

rate rate 

0.0 0.0 0.0 

0.0 0.0 0.0 

0.007 0.013 0.042 

0.007 0.013 0.042 

0.058 0.058 0.218 

0.004 0.008 0.025 

0.06 0.07 0.24 

0.029 0.028 0.108 

0.002 0.004 0.013 

0.03 0.03 0.12 

2.28 2.31 8.78 

0.113 0.207 0.683 

2.40 2.52 9.47 

transformers would have on the small 

businesses that manufacture them. 

However, the Department notes that it 

explicitly considered the impacts on 

small medium-voltage, dry-type 

businesses in selecting TSL2, rather 

than selecting a higher trial standard 

level. 

The revenue attributable to the 

medium-voltage, dry-type superclass 

represents only about six percent of the 

total revenues of the industry affected 

by this rulemaking (Le., the sum of 

revenues from the liquid-immersed 

superclass and the medium-voltage, drytype superclass). Because of the 

potential impacts of today's proposed 

rule on small, medium-voltage, dry-type 

manufacturers, DOE has prepared an 

initial regulatory flexibility analysis 

(IRF A) for this rulemaking. The IRF A 

divides potential impacts on small 

businesses into two broad categories: (1) 

Impacts associated with transformer 

design and manufacturing, and (2) 

impacts associated with demonstrating 

compliance with the standard using 

DOE's test procedure. The Department's 

test procedure rule does not require 

manufacturers to take any action in the 

absence of final energy conservation 

standards for distribution transformers, 

and thus any impact of that rule on 

small businesses would be triggered by 

the promulgation of the standard 

proposed today. 

The Department believes that there 

will be no significant economic impact 

on a substantial number of small liquidimmersed manufacturers because the 
44402 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

transformers in the liquid-immersed

superclass are largely customized, and

small businesses can compete because

many of these transformers are unique

designs produced in relatively small

quantities for a given order. Small

manufacturers of liquid-immersed

transformers tend not to compete on the

higher-volume products and often

produce transformers for highly specific

applications. This strategy allows small

manufacturers of liquid-immersed units

to be competitive in certain liquidimmersed product markets.

Implementation of an energy

conservation standard would have a

relatively minor differential impact on

small manufacturers of liquid-immersed

distribution transformers. Disadvantages

to small businesses, such as having little

leverage over suppliers (e.g., core steel

suppliers), are present with or without

an energy conservation standard. Due to

the purchasing characteristics of their

customers, small manufacturers of

liquid-immersed transformers currently

produce transformers at TSL2, the

proposed level. Thus, conversion costs

(e.g., research and development costs,

capital investments) and the associated

manufacturer impacts on small

businesses are expected to be

insignificant at the proposed level,

TSL2.

The potential impacts on mediumvoltage, dry-type manufacturers (and

also the compliance demonstration cost

for liquid-immersed manufacturers) are

discussed in the following sections. The

Department has transmitted a copy of

this IRFA to the Chief Counsel for

Advocacy of the Small Business

Administration for review.

1. Reasons for the Proposed Rule

Part C of Title III of the Energy Policy

and Conservation Act (EPCA) provides

for an energy conservation program for

certain commercial and industrial

equipment. (42 U.S.C. 6311-6317) In

particular, section 346 of EPCA states

that the Secretary of Energy must

prescribe testing requirements and

energy conservation standards for those

distribution transformers for which the

Secretary determines that standards

would be technologically feasible and

economically justified, and would result

in significant energy savings, although

section 325(v) of EPCA in effect

modifies this provision by specifying

standards for low voltage, dry-type

distribution transformers. (42 U.S.C.

6295(v) and 6317(a))

On October 22, 1997, the Secretary of

Energy issued a determination that

"based on its analysis of the information

now available, the Department has

determined that energy conservation

standards for transformers appear to be

technologically feasible and

economically justified, and are likely to

result in significant savings." 62 FR

54809. Recognizing that fact, EPACT

2005 set minimum efficiency levels for

low-voltage dry-type distribution

transformers and allowed the

Department to continue its analysis and

rulemaking for liquid-immersed and

medium-voltage dry-type distribution

transformers.

2. Objectives of, and Legal Basis for, the

Proposed Rule

The Department selects any new or

amended standard to achieve the

maximum improvement in energy

efficiency that is technologically

feasible and economically justified. (See

42 U.S.C. 6295(o)(2)(A), 6313(a), and 42

U.S.C. 6317(a) and (c)) If a proposed

standard is not designed to achieve the

maximum improvement in energy

efficiency or the maximum reduction in

energy use that is technologically

feasible, the Secretary states the reasons

for this in the proposed rule. To

determine whether economic

justification exists, the Department

reviews comments received and

conducts analysis to determine whether

the economic benefits of the proposed

standard exceed the costs to the greatest

extent practicable, taking into

consideration the seven factors set forth

in 42 U.S.C. 6295(o)(2)(B)(i) (see Section

II.B of this Notice). Further information

concerning the background of this

rulemaking is provided in Chapter 1 of

the TSD.

3. Description and Estimated Number of

Small Entities Regulated

By researching the distribution

transformer market, developing a

database of manufacturers, and

conducting interviews with

manufacturers (both large and small),

the Department was able to estimate the

number of small entities that would be

regulated under an energy conservation

standard. See chapter 12 of the TSD for

further discussion about the

methodology used in the Department's

manufacturer impact analysis and its

analysis of small-business impacts.

The liquid-immersed superclass

accounts for about $1.3 billion in annual

sales and employment of about 4,250

production employees in the United

States. The Department estimates that,

of the approximately 25 U.S.

manufacturers that make liquidimmersed distribution transformers,

about 15 of them are small businesses.

About five of the small businesses have

fewer than 100 employees.

The medium-voltage, dry-type

superclass accounts for about $84

million in annual sales and employment

of about 250-330 production employees

in the United States. The mediumvoltage, dry-type market is relatively

small compared to that of the liquidimmersed superclass. The Department

estimates that, of the 25 U.S.

manufacturers that make mediumvoltage, dry-type distribution

transformers, about 20 of them are small

businesses. About ten of these small

businesses have fewer than 100

employees.

4. Description and Estimate of

Compliance Requirements

Potential impacts on small businesses

come from two broad categories of

compliance requirements: (1) Impacts

associated with transformer design and

manufacturing, and (2) impacts

associated with demonstrating

compliance with the standard using the

Department's test procedure.

In regard to impacts associated with

transformer design and manufacturing,

the margins and/or market share of

small businesses in the medium-voltage,

dry-type superclass could be hurt in the

long term by today's proposed level,

TSL2. At TSL2, as opposed to TSL1,

small manufacturers would have less

flexibility in choosing a design path.

However, as discussed under subsection

6 (Significant alternatives to the rule)

below, the Department expects that the

differential impact on small, mediumvoltage, dry-type businesses (versus

large businesses) would be smaller in

moving from TSL1 to TSL2 than it

would be in moving from TSL2 to TSL3.

The rationale for the Department's

expectation is best discussed in a

comparative context and is therefore

elaborated upon in subsection 6

(Significant alternatives to the rule). As

discussed in the introduction to this

IRFA, DOE expects that the differential

impact associated with transformer

design and manufacturing on small,

liquid-immersed businesses would be

negligible.

In regard to compliance

demonstration, the Department's test

procedure for distribution transformers

employs an Alternative Efficiency

Determination Method (AEDM) which

would ease the burden on

manufacturers. 10 CFR Part 431,

Subpart K, Appendix A; 71 FR 24972.

The AEDM involves a sampling

procedure to compare manufactured

products' efficiencies with those

predicted by computer design software.

Where the manufacturer uses an AEDM

for a basic model, it would not be

required to test units of the basic model

 EE-RM/STD-00-550 COMMENT 91.1

44402 Federal Register! Vol. 71, No. 150 I Friday, August 4, 2006 I Proposed Rules 

transformers in the liquid-immersed 

superclass are largely customized, and 

small businesses can compete because 

many of these transformers are unique 

designs produced in relatively small 

quantities for a given order. Small 

manufacturers of liquid-immersed 

transformers tend not to compete on the 

higher-volume products and often 

produce transformers for highly specific 

applications. This strategy allows small 

manufacturers of liquid-immersed units 

to be competitive in certain liquidimmersed product markets. 

Implementation of an energy 

conservation standard would have a 

relatively minor differential impact on 

small manufacturers of liquid-immersed 

distribution transformers. Disadvantages 

to small businesses, such as having little 

leverage over suppliers (e.g., core steel 

suppliers), are present with or without 

an energy conservation standard. Due to 

the purchasing characteristics of their 

customers, small manufacturers of 

liquid-immersed transformers currently 

produce transformers at TSL2, the 

proposed level. Thus, conversion costs 

(e.g., research and development costs, 

capital investments) and the associated 

manufacturer impacts on small 

businesses are expected to be 

insignificant at the proposed level, 

TSL2. 

The potential impacts on mediumvoltage, dry-type manufacturers (and 

also the compliance demonstration cost 

for liquid-immersed manufacturers) are 

discussed in the following sections. The 

Department has transmitted a copy of 

this IRF A to the Chief Counsel for 

Advocacy of the Small Business 

Administration for review. 

1. Reasons for the Proposed Rule 

Part C of Title III of the Energy Policy 

and Conservation Act (EPCA) provides 

for an energy conservation program for 

certain commercial and industrial 

equipment. (42 U.S.c. 6311-6317) In 

particular, section 346 of EPCA states 

that the Secretary of Energy must 

prescribe testing requirements and 

energy conservation standards for those 

distribution transformers for which the 

Secretary determines that standards 

would be technologically feasible and 

economically justified, and would result 

in significant energy savings, although 

section 325(v) of EPCA in effect 

modifies this provision by specifying 

standards for low voltage, dry-type 

distribution transformers. (42 U.S.c. 

6295(v) and 6317(a)) 

On October 22, 1997, the Secretary of 

Energy issued a determination that 

"based on its analysis of the information 

now available, the Department has 

determined that energy conservation 

standards for transformers appear to be 

technologically feasible and 

economically justified, and are likely to 

result in significant savings." 62 FR 

54809. Recognizing that fact, EP ACT 

2005 set minimum efficiency levels for 

low-voltage dry-type distribution 

transformers and allowed the 

Department to continue its analysis and 

rulemaking for liquid-immersed and 

medium-voltage dry-type distribution 

transformers. 

2. Objectives of, and Legal Basis for, the 

Proposed Rule 

The Department selects any new or 

amended standard to achieve the 

maximum improvement in energy 

efficiency that is technologically 

feasible and economically justified. (See 

42 U.S.c. 6295(0)(2)(A), 6313(a), and 42 

U.S.C. 6317(a) and (c)) If a proposed 

standard is not designed to achieve the 

maximum improvement in energy 

efficiency or the maximum reduction in 

energy use that is technologically 

feasible, the Secretary states the reasons 

for this in the proposed rule. To 

determine whether economic 

justification exists, the Department 

reviews comments received and 

conducts analysis to determine whether 

the economic benefits of the proposed 

standard exceed the costs to the greatest 

extent practicable, taking into 

consideration the seven factors set forth 

in 42 U.S.C. 6295(0)(2)(B)(i) (see Section 

n.B of this Notice). Further information 

concerning the background of this 

rulemaking is provided in Chapter 1 of 

the TSD. 

3. Description and Estimated Number of 

Small Entities Regulated 

By researching the distribution 

transformer market, developing a 

database of manufacturers, and 

conducting interviews with 

manufacturers (both large and small), 

the Department was able to estimate the 

number of small entities that would be 

regulated under an energy conservation 

standard. See chapter 12 of the TSD for 

further discussion about the 

methodology used in the Department's 

manufacturer impact analysis and its 

analysis of small-business impacts. 

The liquid-immersed superclass 

accounts for about $1.3 billion in annual 

sales and employment of about 4,250 

production employees in the United 

States. The Department estimates that, 

of the approximately 25 U.S. 

manufacturers that make liquidimmersed distribution transformers, 

about 15 of them are small businesses. 

About five ofthe small businesses have 

fewer than 100 employees. 

The medium-voltage, dry-type 

superclass accounts for about $84 

million in annual sales and employment 

of about 250-330 production employees 

in the United States. The mediumvoltage, dry-type market is relatively 

small compared to that of the liquidimmersed superclass. The Department 

estimates that, of the 25 U.S. 

manufacturers that make mediumvoltage, dry-type distribution 

transformers, about 20 of them are small 

businesses. About ten of these small 

businesses have fewer than 100 

employees. 

4. Description and Estimate of 

Compliance Requirements 

Potential impacts on small businesses 

come from two broad categories of 

compliance requirements: (1) Impacts 

associated with transformer design and 

manufacturing, and (2) impacts 

associated with demonstrating 

compliance with the standard using the 

Department's test procedure. 

In regard to impacts associated with 

transformer design and manufacturing, 

the margins andlor market share of 

small businesses in the medium-voltage, 

dry-type superclass could be hurt in the 

long term by today's proposed level, 

TSL2. At TSL2, as opposed to TSLl, 

small manufacturers would have less 

flexibility in choosing a design path. 

However, as discussed under subsection 

6 (Significant alternatives to the rule) 

below, the Department expects that the 

differential impact on small, mediumvoltage, dry-type businesses (versus 

large businesses) would be smaller in 

moving from TSLl to TSL2 than it 

would be in moving from TSL2 to TSL3. 

The rationale for the Department's 

expectation is best discussed in a 

comparative context and is therefore 

elaborated upon in subsection 6 

(Significant alternatives to the rule). As 

discussed in the introduction to this 

IRF A, DOE expects that the differential 

impact associated with transformer 

design and manufacturing on small, 

liquid-immersed businesses would be 

negligible. 

In regard to compliance 

demonstration, the Department's test 

procedure for distribution transformers 

employs an Alternative Efficiency 

Determination Method (AEDM) which 

would ease the burden on 

manufacturers. 10 CFR Part 431, 

Subpart K, Appendix A; 71 FR 24972. 

The AEDM involves a sampling 

procedure to compare manufactured 

products' efficiencies with those 

predicted by computer design software. 

Where the manufacturer uses an AEDM 

for a basic model, it would not be 

required to test units of the basic model 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44403

to determine its efficiency for purposes

of establishing compliance with DOE

requirements. The professional skills

necessary to execute the AEDM include

the following: (1) Transformer design

software expertise (or access to such

expertise possessed by a third party),

and (2) electrical testing expertise and

moderate expertise with experimental

statistics (or access to such expertise

possessed by a third party). The

Department's test procedure would

require periodic verification of the

AEDM.

The Department's test procedure also

requires manufacturers to calibrate

equipment used for testing the

efficiency of transformers. Calibration

records would need to be maintained, if

the proposed energy conservation

standard is promulgated.

The testing, reporting, and

recordkeeping requirements associated

with an energy conservation standard

and its related test procedure would be

identical, irrespective of the trial

standard level chosen. Therefore, for

both the liquid-immersed and mediumvoltage, dry-type superclasses, testing,

reporting, and recordkeeping

requirements have not entered into the

Department's choice of trial standard

level for today's proposed rule.

5. Duplication, Overlap, and Conflict

With Other Rules and Regulations

The Department is not aware of any

rules or regulations that duplicate,

overlap, or conflict with the rule being

proposed today.

6. Significant Alternatives to the Rule

The primary alternatives to the

proposed rule considered by the

Department are the other trial standard

levels besides the one being proposed

today, TSL2. These alternative trial

standard levels and their associated

impacts on small business are discussed

in the subsequent paragraphs. In

addition to the other trial standard

levels considered, the TSD associated

with this proposed rule includes a

report referred to in section VI.A above

as the RIA. This report discusses the

following policy alternatives: (1) No

new regulatory action, (2) consumer

rebates, (3) consumer tax credits, and (4)

manufacturer tax credits. The energy

savings and beneficial economic

impacts of these regulatory alternatives

are one to two orders of magnitude

smaller than those expected from

today's proposed rule. Finally, the

Department has not considered

abbreviated testing requirements for

small businesses, but invites

stakeholder comment on abbreviating

such requirements for small businesses.

The entire medium-voltage, dry-type

industry has such low shipments that

no designs are produced at high volume.

There is little repeatability of designs, so

small businesses can competitively

produce many medium-voltage, drytype, open-wound designs. The

medium-voltage, dry-type industry as a

whole primarily has experience

producing baseline transformers and

transformers that would comply with

TSL1. In addition, the industry

produces a significant number of units

that would comply with TSL2, but

approximately one percent or less of the

market would comply with TSL3 or

higher. Therefore, all manufacturers,

including small businesses, would have

to develop designs to enable compliance

with TSL3 or higher-such research and

development costs would be more

burdensome to small businesses.

Product redesign costs tend to be fixed

and do not scale with sales volume.

Thus, small businesses would be at a

relative disadvantage at TSL3 and

higher because research and

development efforts would be on the

same scale as those for larger

companies, but these expenses would be

recouped over smaller sales volumes.

At TSL3 and above, DOE estimates

that net cash flows for the mediumvoltage, dry-type industry would go

negative during the compliance period.

At TSL3 and above, the impacts on the

industry as a whole are large and affect

businesses of all sizes, but there would

be some differential, increased impacts

on small businesses. For example, at

TSL3 and above, the use of grainoriented silicon core steel of M3 or

better will be needed. Cutting M3 core

steel on the core-mitering equipment

typically purchased by smaller

businesses can be problematic because

of the extremely thin laminations.

At TSL2, the level proposed today, all

medium-voltage, dry-type transformer

designs would have to have mitered

cores. (Mitering means the transformer

core's joints intersect at 45 degree

angles, rather than at 90 degree angles

as is true for "butt-lap" designs; buttlap

designs are less energy efficient.) The

mitered core construction technique

could constrain the core-mitering

resources of small businesses that share

core-cutting capacity with production

lines for other transformers that are not

covered by this rulemaking (e.g., lowvoltage, dry-type distribution

transformers). At TSL1, many kVA

ratings could still be constructed using

butt-lap joints, alleviating this

constraint on core-mitering resources.

Thus, TSL1 is less capital-intensive for

small businesses than TSL2 (large

businesses would likely miter nearly all

medium-voltage cores, even at TSL1). In

an industry such as the medium-voltage,

dry-type transformer industry, which is

heavily consolidated already, there is

the risk that TSL2 could lead to further

advantage for the largest manufacturers

and thus further concentrate the

industry's production. The top three

manufacturers produce over 75 percent

of all the transformers in the mediumvoltage, dry-type superclass. Of these

three, two of them are small businesses.

The primary difference between TSL1

and TSL2 from the manufacturers'

viewpoint is that TSL1 preserves more

design pathways, each trading off

material for capital. Butt-lap designs

would be cost-effective at TSL1 for some

kVA ratings, which would allow small

businesses to remain more competitive

because they would not necessarily

have to make large capital outlays. TSL2

cannot be met cost-effectively with buttlap designs; thus TSL2 could hurt the

margins or decrease the market share of

small businesses in the long run. Some

small businesses might opt to purchase

pre-mitered cores at TSL2 rather than

investing in core-mitering equipment,

which would likely hurt their margins.

However, the differential impact on

small businesses (versus large

businesses) is expected to be lower in

moving from TSL1 to TSL2 than in

moving from TSL2 to TSL3. Today, the

market already demands significant

quantities of medium-voltage, dry-type

transformers that meet TSL2.

Chapter 12 of the TSD contains more

information about the impact of this

rulemaking on manufacturers. The

Department interviewed six small

businesses affected by this rulemaking

(see also section IV.F.1 above). The

Department also obtained information

about small business impacts while

interviewing manufacturers that exceed

the small business size threshold of 750

employees.

C. Review Under the Paperwork

Reduction Act

Adoption of today's proposed rule

would have the effect of requiring that

manufacturers follow certain recordkeeping requirements in the test

procedure for distribution transformers,

not just for purposes of making

representations, but also to determine

compliance even in the absence of any

representation. As set forth in the test

procedure, manufacturers will become

subject to the record-keeping

requirements when today's proposed

energy conservation standard for

distribution transformers takes effect. 10

CFR Part 431, Subpart K, Appendix A;

71 FR 24972. Thus, the standard will

impose new information or record

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44403 

to determine its efficiency for purposes 

of establishing compliance with DOE 

requirements. The professional skills 

necessary to execute the AEDM include 

the following: (1) Transformer design 

software expertise (or access to such 

expertise possessed by a third party), 

and (2) electrical testing expertise and 

moderate expertise with experimental 

statistics (or access to such expertise 

possessed by a third party). The 

Department's test procedure would 

require periodic verification of the 

AEDM. 

The Department's test procedure also 

requires manufacturers to calibrate 

equipment used for testing the 

efficiency of transformers. Calibration 

records would need to be maintained, if 

the proposed energy conservation 

standard is promulgated. 

The testing, reporting, and 

recordkeeping requirements associated 

with an energy conservation standard 

and its related test procedure would be 

identical, irrespective of the trial 

standard level chosen. Therefore, for 

both the liquid-immersed and mediumvoltage, dry-type superclasses, testing, 

reporting, and recordkeeping 

requirements have not entered into the 

Department's choice of trial standard 

level for today's proposed rule. 

5. Duplication. Overlap, and Conflict 

With Other Rules and Regulations 

The Department is not aware of any 

rules or regulations that duplicate, 

overlap, or conflict with the rule being 

proposed today. 

6. Significant Alternatives to the Rule 

The primary alternatives to the 

proposed rule considered by the 

Department are the other trial standard 

levels besides the one being proposed 

today, TSL2. These alternative trial 

standard levels and their associated 

impacts on small business are discussed 

in the subsequent paragraphs. In 

addition to the other trial standard 

levels considered, the TSD associated 

with this proposed rule includes a 

report referred to in section VLA above 

as the RIA. This report discusses the 

following policy alternatives: (1) No 

new regulatory action, (2) consumer 

rebates, (3) consumer tax credits, and (4) 

manufacturer tax credits. The energy 

savings and beneficial economic 

impacts of these regulatory alternatives 

are one to two orders of magnitude 

smaller than those expected from 

today's proposed rule. Finally, the 

Department has not considered 

abbreviated testing requirements for 

small businesses, but invites 

stakeholder comment on abbreviating 

such requirements for small businesses. 

The entire medium-voltage. dry-type 

industry has such low shipments that 

no designs are produced at high volume. 

There is little repeatability of designs. so 

small businesses can competitively 

produce many medium-voltage, drytype, open-wound designs. The 

medium-voltage, dry-type industry as a 

whole primarily has experience 

producing baseline transformers and 

transformers that would comply with 

TSL1. In addition, the industry 

produces a significant number of units 

that would comply with TSL2. but 

approximately one percent or less of the 

market would comply with TSL3 or 

higher. Therefore, all manufacturers, 

including small businesses. would have 

to develop designs to enable compliance 

with TSL3 or higher-such research and 

development costs would be more 

burdensome to small businesses. 

Product redesign costs tend to be fixed 

and do not scale with sales volume. 

Thus, small businesses would be at a 

relative disadvantage at TSL3 and 

higher because research and 

development efforts would be on the 

same scale as those for larger 

companies, but these expenses would be 

recouped over smaller sales volumes. 

At TSL3 and above, DOE estimates 

that net cash flows for the mediumvoltage, dry-type industry would go 

negative during the compliance period. 

At TSL3 and above, the impacts on the 

industry as a whole are large and affect 

businesses of all sizes, but there would 

be some differential, increased impacts 

on small businesses. For example, at 

TSL3 and above, the use of grainoriented silicon core steel of M3 or 

better will be needed. Cutting M3 core 

steel on the core-mitering equipment 

typically purchased by smaller 

businesses can be problematic because 

of the extremely thin laminations. 

At TSL2, the level proposed today, all 

medium-voltage, dry-type transformer 

designs would have to have mitered 

cores. (Mitering means the transformer 

core's joints intersect at 45 degree 

angles, rather than at 90 degree angles 

as is true for "butt-lap" designs; buttlap 

designs are less energy efficient.) The 

mitered core construction technique 

could constrain the core-mitering 

resources of small businesses that share 

core-cutting capacity with production 

lines for other transformers that are not 

covered by this rulemaking (e.g .• lowvoltage, dry-type distribution 

transformers). At TSLl, many kVA 

ratings could still be constructed using 

butt-lap joints. alleviating this 

constraint on core-mitering resources. 

Thus, TSLl is less capital-intensive for 

small businesses than TSL2 (large 

businesses would likely miter nearly all 

medium-voltage cores, even at TSL1). In 

an industry such as the medium-voltage, 

dry-type transformer industry, which is 

heavily consolidated already, there is 

the risk that TSL2 could lead to further 

advantage for the largest manufacturers 

and thus further concentrate the 

industry'S production. The top three 

manufacturers produce over 75 percent 

of all the transformers in the mediumvoltage, dry-type superclass. Of these 

three, two of them are small businesses. 

The primary difference between TSLl 

and TSL2 from the manufacturers' 

viewpoint is that TSLl preserves more 

design pathways, each trading off 

material for capital. Butt-lap designs 

would be cost-effective at TSLl for some 

kVA ratings, which would allow small 

businesses to remain more competitive 

because they would not necessarily 

have to make large capital outlays. TSL2 

cannot be met cost-effectively with buttlap designs; thus TSL2 could hurt the 

margins or decrease the market share of 

small businesses in the long run. Some 

small businesses might opt to purchase 

pre-mitered cores at TSL2 rather than 

investing in core-mitering equipment, 

which would likely hurt their margins. 

However, the differential impact on 

small businesses (versus large 

businesses) is expected to be lower in 

moving from TSLl to TSL2 than in 

moving from TSL2 to TSL3. Today, the 

market already demands significant 

quantities of medium-voltage, dry-type 

transformers that meet TSL2. 

Chapter 12 of the TSD contains more 

information about the impact of this 

rulemaking on manufacturers. The 

Department interviewed six small 

businesses affected by this rulemaking 

(see also section IV.F.l above). The 

Department also obtained information 

about small business impacts while 

interviewing manufacturers that exceed 

the small business size threshold of 750 

employees. 

C. Review Under the Paperwork 

Reduction Act 

Adoption of today's proposed rule 

would have the effect of requiring that 

manufacturers follow certain recordkeeping requirements in the test 

procedure for distribution transformers, 

not just for purposes of making 

representations, but also to determine 

compliance even in the absence of any 

representation. As set forth in the test 

procedure. manufacturers will become 

subject to the record-keeping 

requirements when today's proposed 

energy conservation standard for 

distribution transformers takes effect. 10 

CFR Part 431, Subpart K, Appendix A; 

71 FR 24972. Thus. the standard will 

impose new information or record 
44404 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

keeping requirements, and Office of

Management and Budget clearance is

required under the Paperwork

Reduction Act. (44 U.S.C. 3501 et seq.)

The test procedure for distribution

transformers requires manufacturers to

calibrate equipment used for testing the

efficiency of transformers. 10 CFR Part

431, Subpart K, Appendix A; 71 FR

24972. Manufacturers must also

document (1) the basis for their

calibration of any equipment for which

no national calibration standard exists,

(2) their calibration procedures, and (3)

the date when they calibrated their

equipment. The Department drew these

provisions from, and in some cases they

are identical to, provisions in NEMA TP

2-1998. The Department understands

that NEMA, in turn, based them on

provisions of the International

Standards Organization (ISO) 9000

series documents. These documents are

voluntary standards widely recognized

throughout industry and internationally

as setting forth sound quality assurance

methods. The Department incorporated

such provisions in its test procedure

because it believes that any

manufacturer doing testing should

employ them to assure sound and

accurate results. The Department

understands that they are already

widely followed by manufacturers, in

the interest of assuring they provide to

their customers equipment that meets

customer specifications. Thus, DOE

believes that little or no additional

record-keeping burden would be

imposed by today's proposed rule.

The test procedure also allows

manufacturers, under certain

circumstances, to determine the

efficiencies of their distribution

transformers through use of methods

other than testing. The test procedure

includes Alternative Efficiency

Determination Methods (AEDM) to

reduce testing burden. 10 CFR Part 431,

Subpart K, Appendix A; 71 FR 24972.

Each manufacturer that has used an

AEDM must have available for

inspection by the Department records

showing: The method or methods used;

the mathematical model, the

engineering or statistical analysis,

computer simulation or modeling, and

other analytic evaluation of performance

data on which the AEDM is based;

complete test data, product information,

and related information that the

manufacturer has used to substantiate

the AEDM; and the calculations used to

determine the efficiency and total power

losses of each basic model to which the

AEDM was applied. 10 CFR Part 431,

Subpart K, Appendix A; 71 FR 24972.

This information must be recorded and

maintained for each AEDM the

manufacturer uses. This requirement is

designed to enable the Department to

determine, if necessary, that these

mathematical models have been

properly used to rate transformer

efficiencies.

The Department is submitting to the

OMB, simultaneously with the

publication of this proposed rule, these

record-keeping requirements for review

and approval under the Paperwork

Reduction Act, 44 U.S.C. 3501 et seq.

An agency may not impose, and a

person is not required to respond to,

such a requirement unless it has been

reviewed and assigned a control number

by OMB. Interested persons may obtain

a copy of the Paperwork Reduction Act

submission from the contact person

named in this notice.

Interested persons are invited to

submit comments to OMB addressed to:

Department of Energy Desk Officer,

Office of Information and Regulatory

Affairs, OMB, 725 17th Street, NW.,

Washington DC, 20503. Persons

submitting comments to OMB also are

requested to send a copy to the DOE

contact person at the address given in

the addresses section of this notice.

OMB is particularly interested in

comments on: (1) The necessity of the

proposed record-keeping provisions,

including whether the information will

have practical utility; (2) the accuracy of

the Department's estimates of the

burden; (3) ways to enhance the quality,

utility, and clarity of the information to

be maintained; and (4) ways to

minimize the burden of the

requirements on respondents.

D. Review Under the National

Environmental Policy Act

The Department is preparing an

environmental assessment of the

impacts of the proposed rule and DOE

anticipates completing a Finding of No

Significant Impact (FONSI) before

publishing the final rule on distribution

transformers, pursuant to the National

Environmental Policy Act of 1969 (42

U.S.C. 4321 et seq.), the regulations of

the Council on Environmental Quality

(40 CFR parts 1500-1508), and the

Department's regulations for compliance

with the National Environmental Policy

Act (10 CFR part 1021).

E. Review Under Executive Order 13132

Executive Order 13132, "Federalism,"

64 FR 43255 (August 4, 1999) imposes

certain requirements on agencies

formulating and implementing policies

or regulations that preempt State law or

that have federalism implications. The

Executive Order requires agencies to

examine the constitutional and statutory

authority supporting any action that

would limit the policymaking discretion

of the States and to carefully assess the

necessity for such actions. The

Executive Order also requires agencies

to have an accountable process to

ensure meaningful and timely input by

State and local officials in the

development of regulatory policies that

have federalism implications. On March

14, 2000, DOE published a statement of

policy describing the intergovernmental

consultation process it will follow in the

development of such regulations. 65 FR

13735. The Department has examined

today's proposed rule and has

determined that it does not preempt

State law and does not have a

substantial direct effect on the States, on

the relationship between the national

government and the States, or on the

distribution of power and

responsibilities among the various

levels of government. EPCA governs and

prescribes Federal preemption of State

regulations as to energy conservation for

the products that are the subject of

today's proposed rule. States can

petition the Department 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" 61 FR 4729 (February 7, 1996)

imposes on Federal agencies the general

duty to adhere to the following

requirements: (1) Eliminate drafting

errors and ambiguity; (2) write

regulations to minimize litigation; and

(3) provide a clear legal standard for

affected conduct rather than a general

standard and promote simplification

and burden reduction. Section 3(b) of

Executive Order 12988 specifically

requires that Executive agencies make

every reasonable effort to ensure that the

regulation: (1) Clearly specifies the

preemptive effect, if any; (2) clearly

specifies any effect on existing Federal

law or regulation; (3) provides a clear

legal standard for affected conduct

while promoting simplification and

burden reduction; (4) specifies the

retroactive effect, if any; (5) adequately

defines key terms; and (6) addresses

other important issues affecting clarity

and general draftsmanship under any

guidelines issued by the Attorney

General. Section 3(c) of Executive Order

12988 requires Executive agencies to

review regulations in light of applicable

standards in section 3(a) and section

3(b) to determine whether they are met

or it is unreasonable to meet one or

 EE-RM/STD-00-550 COMMENT 91.1

44404 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

keeping requirements, and Office of 

Management and Budget clearance is 

required under the Paperwork 

Reduction Act. (44 U.S.c. 3501 et seq.) 

The test procedure for distribution 

transformers requires manufacturers to 

calibrate equipment used for testing the 

efficiency of transformers. 10 CFR Part 

431, Subpart K, Appendix A; 71 FR 

24972. Manufacturers must also 

document (1) the basis for their 

calibration of any equipment for which 

no national calibration standard exists, 

(2) their calibration procedures, and (3) 

the date when they calibrated their 

equipment. The Department drew these 

provisions from, and in some cases they 

are identical to, provisions in NEMA TP 

2-1998. The Department understands 

that NEMA, in turn, based them on 

provisions of the International 

Standards Organization (ISO) 9000 

series documents. These documents are 

voluntary standards widely recognized 

throughout industry and internationally 

as setting forth sound quality assurance 

methods. The Department incorporated 

such provisions in its test procedure 

because it believes that any 

manufacturer doing testing should 

employ them to assure sound and 

accurate results. The Department 

understands that they are already 

widely followed by manufacturers, in 

the interest of assuring they provide to 

their customers equipment that meets 

customer specifications. Thus, DOE 

believes that little or no additional 

record-keeping burden would be 

imposed by today's proposed rule. 

The test procedure also allows 

manufacturers, under certain 

circumstances, to determine the 

efficiencies of their distribution 

transformers through use of methods 

other than testing. The test procedure 

includes Alternative Efficiency 

Determination Methods (AEDM) to 

reduce testing burden. 10 CFR Part 431, 

Subpart K, Appendix A; 71 FR 24972. 

Each manufacturer that has used an 

AEDM must have available for 

inspection by the Department records 

showing: The method or methods used; 

the mathematical model, the 

engineering or statistical analysis, 

computer simulation or modeling, and 

other analytic evaluation of performance 

data on which the AEDM is based; 

complete test data, product information, 

and related information that the 

manufacturer has used to substantiate 

the AEDM; and the calculations used to 

determine the efficiency and total power 

losses of each basic model to which the 

AEDM was applied. 10 CFR Part 431, 

Subpart K, Appendix A; 71 FR 24972. 

This information must be recorded and 

maintained for each AEDM the 

manufacturer uses. This requirement is 

designed to enable the Department to 

determine, if necessary, that these 

mathematical models have been 

properly used to rate transformer 

efficiencies. 

The Department is submitting to the 

OMB, simultaneously with the 

publication of this proposed rule, these 

record-keeping requirements for review 

and approval under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

An agency may not impose, and a 

person is not required to respond to, 

such a requirement unless it has been 

reviewed and assigned a control number 

by OMB. Interested persons may obtain 

a copy of the Paperwork Reduction Act 

submission from the contact person 

named in this notice. 

Interested persons are invited to 

submit comments to OMB addressed to: 

Department of Energy Desk Officer, 

Office of Information and Regulatory 

Affairs, OMB, 725 17th Street, NW., 

Washington DC, 20503. Persons 

submitting comments to OMB also are 

requested to send a copy to the DOE 

contact person at the address given in 

the addresses section of this notice. 

OMB is particularly interested in 

comments on: (1) The necessity of the 

proposed record-keeping provisions, 

including whether the information will 

have practical utility; (2) the accuracy of 

the Department's estimates of the 

burden; (3) ways to enhance the quality, 

utility, and clarity of the information to 

be maintained; and (4) ways to 

minimize the burden of the 

requirements on respondents. 

D. Review Under the National 

Environmental Policy Act 

The Department is preparing an 

environmental assessment of the 

impacts of the proposed rule and DOE 

anticipates completing a Finding of No 

Significant Impact (FONSI) before 

publishing the final rule on distribution 

transformers, pursuant to the National 

Environmental Policy Act of 1969 (42 

U.S.C. 4321 et seq.), the regulations of 

the Council on Environmental Quality 

(40 CFR parts 1500-1508), and the 

Department's regulations for compliance 

with the National Environmental Policy 

Act (10 CFR part 1021). 

E. Review Under Executive Order 13132 

Executive Order 13132, "Federalism," 

64 FR 43255 (August 4, 1999) imposes 

certain requirements on agencies 

formulating and implementing policies 

or regulations that preempt State law or 

that have federalism implications. The 

Executive Order requires agencies to 

examine the constitutional and statutory 

authority supporting any action that 

would limit the policymaking discretion 

of the States and to carefully assess the 

necessity for such actions. The 

Executive Order also requires agencies 

to have an accountable process to 

ensure meaningful and timely input by 

State and local officials in the 

development of regulatory policies that 

have federalism implications. On March 

14,2000, DOE published a statement of 

policy describing the intergovernmental 

consultation process it will follow in the 

development of such regulations. 65 FR 

13735. The Department has examined 

today's proposed rule and has 

determined that it does not preempt 

State law and does not have a 

substantial direct effect on the States, on 

the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government. EPCA governs and 

prescribes Federal preemption of State 

regulations as to energy conservation for 

the products that are the subject of 

today's proposed rule. States can 

petition the Department 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" 61 FR 4729 (February 7, 1996) 

imposes on Federal agencies the general 

duty to adhere to the following 

requirements: (1) Eliminate drafting 

errors and ambiguity; (2) write 

regulations to minimize litigation; and 

(3) provide a clear legal standard for 

affected conduct rather than a general 

standard and promote simplification 

and burden reduction. Section 3(b) of 

Executive Order 12988 specifically 

requires that Executive agencies make 

every reasonable effort to ensure that the 

regulation: (1) Clearly specifies the 

preemptive effect, if any; (2) clearly 

specifies any effect on existing Federal 

law or regulation; (3) provides a clear 

legal standard for affected conduct 

while promoting simplification and 

burden reduction; (4) specifies the 

retroactive effect, if any; (5) adequately 

defines key terms; and (6) addresses 

other important issues affecting clarity 

and general draftsmanship under any 

guidelines issued by the Attorney 

General. Section 3(c) of Executive Order 

12988 requires Executive agencies to 

review regulations in light of applicable 

standards in section 3(a) and section 

3(b) to determine whether they are met 

or it is unreasonable to meet one or 
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules 44405

more of them. The Department 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 (Pub. L. 104-4)

(UMRA) requires each Federal agency to

assess the effects of Federal regulatory

actions on State, local, and Tribal

governments and the private sector. 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) (also available at

http://www.gc.doe.gov). The proposed

rule published today contains neither an

intergovernmental mandate nor a

mandate that may result in expenditure

of $100 million or more in any year, so

these requirements do not apply.

H. Review Under the Treasury and

General Government Appropriations

Act of 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

The Department has determined,

under Executive Order 12630,

"Governmental Actions and Interference

with Constitutionally Protected Property

Rights," 53 FR 8859 (March 18, 1988),

that this regulation would not result in

any takings which might require

compensation under the Fifth

Amendment to the United States

Constitution.

J. Review Under the Treasury and

General Government Appropriations

Act of 2001

Section 515 of the Treasury and

General Government Appropriations

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

provides for agencies to review most

disseminations of information to the

public under guidelines established by

each agency pursuant to general

guidelines issued by OMB. The 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). The

Department has reviewed today's notice

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 the Office of

Information and Regulatory Affairs

(OIRA), Office of Management and

Budget, a Statement of Energy Effects for

any proposed significant energy action.

A "significant energy action" is defined

as any action by an agency that

promulgated or is expected to lead to

promulgation of a final rule, and that:

(1) Is a significant regulatory action

under Executive Order 12866, or any

successor order; and (2) is likely to have

a significant adverse effect on the

supply, distribution, or use of energy, or

(3) is designated by the Administrator of

OIRA as a significant energy action. For

any 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.

While this proposed rule is a

significant regulatory action under

Executive Order 12866, it is not likely

to have a significant adverse effect on

the supply, distribution, or use of

energy, nor has it been designated by

the Administrator of OIRA as a

significant energy action. Thus, DOE has

not prepared a Statement of Energy

Effects.

L. Review Under Section 32 of the

Federal Energy Administration Act of

1974

The Department is required by section

32 of the Federal Energy Administration

Act (FEAA) of 1974 to inform the public

of the use and background of any

commercial standard in a proposed rule.

(15 U.S.C. 788) While the Department

had considered a commercial voluntary

standard (NEMA TP 1-2002) as one of

the trial standard levels, it did not

choose to regulate either liquidimmersed or medium-voltage dry-type

distribution transformers at this

efficiency level. Because today's

proposed rule adopts more stringent

efficiency levels, Section 32 of the

FEAA does not apply.

M. Review Under the Information

Quality Bulletin for Peer Review

On December 16, 2004, the Office of

Management and Budget (OMB), in

consultation with the Office of Science

and Technology (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.

The Department's Office of Energy

Efficiency and Renewable Energy,

Building Technologies Program, held

formal in-progress peer reviews

covering the analyses (e.g., screening/

engineering analysis, life-cycle cost

analysis, manufacturing impact

analysis, and utility impact analysis)

used in conducting the energy efficiency

standards development process on June

28-29, 2005. The in-progress review is

a rigorous, formal and documented

evaluation process using objective

criteria and qualified and independent

reviewers to make a judgment of the

technical/scientific/business merit, the

actual or anticipated results, and the

productivity and management

effectiveness of programs and/or

projects. The Building Technologies

Program staff is preparing a peer review

report which, upon completion, will be

disseminated on the Office of Energy

Efficiency and Renewable Energy's Web

site and included in the administrative

record for this rulemaking.

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. lSD/Friday, August 4, 2006/Proposed Rules 44405 

more of them. The Department 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 (Pub. L. 104-4) 

(UMRA) requires each Federal agency to 

assess the effects of Federal regulatory 

actions on State, local. and Tribal 

governments and the private sector. 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 anyone year (adjusted annually for 

inflation), section 202 of UMRA requires 

a Federal agency to publish a written 

statement that estimates the resulting 

costs, benefits, and other effects on the 

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

The UMRA also requires a Federal 

agency to develop an effective process 

to permit timely input by elected 

officers of State, local, and Tribal 

governments on a proposed "significant 

intergovernmental mandate," and 

requires an agency plan for giving notice 

and opportunity for timely input to 

potentially affected small governments 

before establishing any requirements 

that might significantly or uniquely 

affect small governments. On March 18, 

1997, DOE published a statement of 

policy on its process for 

intergovernmental consultation under 

UMRA (62 FR 12820) (also available at 

http://www.gc.doe.gov). The proposed 

rule published today contains neither an 

intergovernmental mandate nor a 

mandate that may result in expenditure 

of $100 million or more in any year, so 

these requirements do not apply. 

H. Review Under the Treasury and 

General Government Appropriations 

Act of 1999 

Section 654 of the Treasury and 

General Government Appropriations 

Act, 1999 (Pub. 1. 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. 

1. Review Under Executive Order 12630 

The Department has determined, 

under Executive Order 12630, 

"Governmental Actions and Interference 

with Constitutionally Protected Property 

Rights," 53 FR 8859 (March 18, 1988), 

that this regulation would not result in 

any takings which might require 

compensation under the Fifth 

Amendment to the United States 

Constitution. 

J. Review Under the Treasury and 

General Government Appropriations 

Act of2001 

Section 515 ofthe Treasury and 

General Government Appropriations 

Act, 2001 (44 U.S.c. 3516, note) 

provides for agencies to review most 

disseminations of information to the 

public under guidelines established by 

each agency pursuant to general 

guidelines issued by OMB. The 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). The 

Department has reviewed today's notice 

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 the Office of 

Information and Regulatory Affairs 

(OIRA), Office of Management and 

Budget, a Statement of Energy Effects for 

any proposed significant energy action. 

A "significant energy action" is defined 

as any action by an agency that 

promulgated or is expected to lead to 

promulgation of a final rule, and that: 

(1) Is a significant regulatory action 

under Executive Order 12866, or any 

successor order; and (2) is likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy, or 

(3) is designated by the Administrator of 

OIRA as a significant energy action. For 

any proposed significant energy action, 

the agency must give a detailed 

statement of any adverse effects on 

energy supply, distribution, or use 

should t4e proposal be implemented, 

and of reasonable alternatives to the 

action and their expected benefits on 

energy supply, distribution, and use. 

While this proposed rule is a 

significant regulatory action under 

Executive Order 12866, it is not likely 

to have a significant adverse effect on 

the supply, distribution, or use of 

energy, nor has it been deSignated by 

the Administrator of OIRA as a 

significant energy action. Thus, DOE has 

not prepared a Statement of Energy 

Effects. 

L. Review Under Section 32 of the 

Federal Energy Administration Act of 

1974 

The Department is required by section 

32 of the Federal Energy Administration 

Act (FEAA) of 1974 to inform the public 

of the use and background of any 

commercial standard in a proposed rule. 

(15 U.S.C. 788) While the Department 

had considered a commercial voluntary 

standard (NEMA TP 1-2002) as one of 

the trial standard levels, it did not 

choose to regulate either liquidimmersed or medium-voltage dry-type 

distribution transformers at this 

effiCiency level. Because today's 

proposed rule adopts more stringent 

efficiency levels, Section 32 of the 

FEAA does not apply. 

M. Review Under the Information 

Quality Bulletin for Peer Review 

On December 16,2004, the Office of 

Management and Budget (OMB), in 

consultation with the Office of Science 

and Technology (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. 

The Department's Office of Energy 

Efficiency and Renewable Energy, 

Building Technologies Program, held 

formal in-progress peer reviews 

covering the analyses (e.g., screening/ 

engineering analysis, life-cycle cost 

analysis, manufacturing impact 

analysis, and utility impact analysis) 

used in conducting the energy effiCiency 

standards development process on June 

28-29, 2005. The in-progress review is 

a rigorous, formal and documented 

evaluation process using objective 

criteria and qualified and independent 

reviewers to make a judgment of the 

technical/scientific/business merit, the 

actual or anticipated results, and the 

productivity and management 

effectiveness of programs and/or 

projects. The Building Technologies 

Program staff is preparing a peer review 

report which, upon completion, will be 

disseminated on the Office of Energy 

Efficiency and Renewable Energy's Web 

site and included in the administrative 

record for this rulemaking. 
44406 Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules

VII. Public Participation

A. Attendance at Public Meeting

The time and date of the public

meeting are listed in the DATES section

at the beginning of this notice of

proposed rulemaking. The public

meeting will be held at the U.S.

Department of Energy, Forrestal

Building, Room 1E245, 1000

Independence Avenue, SW.,

Washington, DC 20585-0121. To attend

the public meeting, please notify Ms.

Brenda Edwards-Jones at (202) 586-

2945. Foreign nationals visiting DOE

Headquarters are subject to advance

security screening procedures, requiring

a 30-day advance notice. Any foreign

national wishing to participate in the

meeting should advise DOE of this fact

as soon as possible by contacting Ms.

Brenda Edwards-Jones to initiate the

necessary procedures.

B. Procedure for Submitting Requests To

Speak

Any person who has an interest in

today's notice, or who is a

representative of a group or class of

persons that has an interest in these

issues, may request an opportunity to

make an oral presentation. Such persons

may hand-deliver requests to speak,

along with a computer diskette or CD in

WordPerfect, Microsoft Word, PDF, or

text (ASCII) file format to the address

shown in the ADDRESSES section at the

beginning of this notice of proposed

rulemaking between the hours of 9 a.m.

and 4 p.m., Monday through Friday,

except Federal holidays. Requests may

also be sent by mail or e-mail to:

Brenda.Edwards-jones@ee.doe.gov.

Persons requesting to speak should

briefly describe the nature of their

interest in this rulemaking and provide

a telephone number for contact. The

Department requests persons selected to

be heard to submit an advance copy of

their statements at least two weeks

before the public meeting. At its

discretion, DOE may permit any person

who cannot supply an advance copy of

their statement to participate, if that

person has made advance alternative

arrangements with the Building

Technologies Program. The request to

give an oral presentation should ask for

such alternative arrangements.

C. Conduct of Public Meeting

The Department 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

5 U.S.C. 553 and section 336 of EPCA,

42 U.S.C. 6306. A court reporter will be

present to record the proceedings and

prepare a transcript. The Department

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. The

Department will present summaries of

comments received before the public

meeting, allow time for presentations by

participants, and encourage all

interested parties to share their views on

issues affecting this rulemaking. Each

participant will be allowed to make a

prepared general statement (within time

limits determined by DOE), before the

discussion of specific topics. The

Department will permit 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.

Department 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.

The Department will make the entire

record of this proposed rulemaking,

including the transcript from the public

meeting, available for inspection at the

U.S. Department of Energy, Forrestal

Building, Room 1J-018 (Resource Room

of the Building Technologies Program),

1000 Independence Avenue, SW.,

Washington, DC, (202) 586-9127,

between 9 a.m. and 4 p.m., Monday

through Friday, except Federal holidays.

Any person may buy a copy of the

transcript from the transcribing reporter.

D. Submission of Comments

The Department will accept

comments, data, and information

regarding the proposed rule before or

after the public meeting, but no later

than the date provided at the beginning

of this notice of proposed rulemaking.

Please submit comments, data, and

TransformerNOPRComment@ee. doe.

gov. Submit electronic comments in

WordPerfect, Microsoft Word, PDF, or

text (ASCII) file format and avoid the

use of special characters or any form of

encryption. Comments in electronic

format should be identified by the

docket number EE-RM/STD-00-550

and/or RIN number 1904-ABO8, and

wherever possible carry the electronic

signature of the author. Absent an

electronic signature, comments

submitted electronically must be

followed and authenticated by

submitting the signed original paper

document. No telefacsimiles (faxes) will

be accepted.

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 two copies: One copy of

the document including all the

information believed to be confidential,

and one copy of the document with the

information believed to be confidential

deleted. The Department of Energy will

make its own determination about the

confidential status of the information

and treat it according to its

determination.

Factors of interest to the Department

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.

E. Issues on Which DOE Seeks Comment

The Department is particularly

interested in receiving comments and

views of interested parties concerning:

(1) The proposed tables of efficiency

ratings, and specifically areas where the

underlying analytical methods followed

for developing the efficiency values

resulted in discontinuities.

(2) The Department's treatment of

rebuilt or refurbished transformers in

this rulemaking and the potential

impact on consumers, manufacturers,

and national energy use if they were

excluded.

information electronically. Send them to (3) Whether less-flammable, liquidthe following e-mail address: immersed distribution transformers

 EE-RM/STD-00-550 COMMENT 91.1

44406 Federal Register/Vol. 71, No. 150/Friday, August 4, 200B/Proposed Rules 

VII. Public Participation 

A. Attendance at Public Meeting 

The time and date of the public 

meeting are listed in the DATES section 

at the beginning of this notice of 

proposed rulemaking. The public 

meeting will be held at the U.S. 

Department of Energy, Forrestal 

Building, Room lE245. 1000 

Independence Avenue, SW., 

Washington, DC 20585-0121. To attend 

the public meeting, please notify Ms. 

Brenda Edwards-Jones at (202) 586-

2945. Foreign nationals visiting DOE 

Headquarters are subject to advance 

security screening procedures, requiring 

a 30-day advance notice. Any foreign 

national wishing to participate in the 

meeting should advise DOE of this fact 

as soon as possible by contacting Ms. 

Brenda Edwards-Jones to initiate the 

necessary procedures. 

B. Procedure for Submitting Requests To 

Speak 

Any person who has an interest in 

today's notice, or who is a 

representative of a group or class of 

persons that has an interest in these 

issues, may request an opportunity to 

make an oral presentation. Such persons 

may hand-deliver requests to speak, 

along with a computer diskette or CD in 

WordPerfect, Microsoft Word, PDF, or 

text (ASCII) file format to the address 

shown in the ADDRESSES section at the 

beginning of this notice of proposed 

rulemaking between the hours of 9 a.m. 

and 4 p.m., Monday through Friday, 

except Federal holidays. Requests may 

also be sent by mail or e-mail to: 

Brenda.Edwards-Jones@ee.doe.gov. 

Persons requesting to speak should 

briefly describe the nature of their 

interest in this rulemaking and provide 

a telephone number for contact. The 

Department requests persons selected to 

be heard to submit an advance copy of 

their statements at least two weeks 

before the public meeting. At its 

discretion, DOE may permit any person 

who cannot supply an advance copy of 

their statement to participate, if that 

person has made advance alternative 

arrangements with the Building 

Technologies Program. The request to 

give an oral presentation should ask for 

such alternative arrangements. 

C. Conduct of Public Meeting 

The Department 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 

5 U .S.C. 553 and section 336 of EPCA, 

42 U.S.C. 6306. A court reporter will be 

present to record the proceedings and 

prepare a transcript. The Department 

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. The 

Department will present summaries of 

comments received before the public 

meeting, allow time for presentations by 

participants, and encourage all 

interested parties to share their views on 

issues affecting this rulemaking. Each 

participant will be allowed to make a 

prepared general statement (within time 

limits determined by DOE), before the 

discussion of specific topics. The 

Department will permit 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. 

Department 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. 

The Department will make the entire 

record of this proposed rulemaking, 

including the transcript from the public 

meeting, available for inspection at the 

U.S. Department of Energy, Forrestal 

Building, Room IJ-018 (Resource Room 

of the Building Technologies Program), 

1000 Independence Avenue, SW., 

Washington, DC, (202) 586-9127, 

between 9 a.m. and 4 p.m., Monday 

through Friday, except Federal holidays. 

Any person may buy a copy of the 

transcript from the transcribing reporter. 

D. Submission of Comments 

The Department will accept 

comments, data, and information 

regarding the proposed rule before or 

after the public meeting, but no later 

than the date provided at the beginning 

of this notice of proposed rulemaking. 

Please submit comments, data, and 

information electronically. Send them to 

the following e-mail address: 

TransformerNOPRComment@ee.doe. 

gOY. Submit electronic comments in 

WordPerfect, Microsoft Word, PDF, or 

text (ASCII) file format and avoid the 

use of special characters or any form of 

encryption. Comments in electronic 

format should be identified by the 

docket number EE-RM/STD-OO-550 

and/or RIN number 1904-AB08, and 

wherever possible carry the electronic 

signature of the author. Absent an 

electronic signature, comments 

submitted electronically must be 

followed and authenticated by 

submitting the signed original paper 

document. No telefacsimiles (faxes) will 

be accepted. 

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 two copies: One copy of 

the document including all the 

information believed to be confidential, 

and one copy of the document with the 

information believed to be confidential 

deleted. The Department of Energy will 

make its own determination about the 

confidential status of the information 

and treat it according to its 

determination. 

Factors of interest to the Department 

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. 

E. Issues on Which DOE Seeks Comment 

The Department is particularly 

interested in receiving comments and 

views of interested parties concerning: 

(1) The proposed tables of efficiency 

ratings, and specifically areas where the 

underlying analytical methods followed 

for developing the efficiency values 

resulted in discontinuities. 

(2) The Department's treatment of 

rebuilt or refurbished transformers in 

this rulemaking and the potential 

impact on consumers, manufacturers, 

and national energy use if they were 

excluded. 

(3) Whether less-flammable, liquidimmersed distribution transformers 
Federal Register /Vol. 71, No. 150 /Friday, August 4, 2006 /Proposed Rules 44407

should be included in the same product

class as medium-voltage, dry-type

transformers. Currently the Department

considers dry-type transformers and

liquid-immersed transformers as

members of separate product classes.

(4) Whether stakeholders believe a

minimum efficiency standard for liquidimmersed distribution transformers

would contribute to design

standardization, and encourage

manufacturers to move to countries with

lower labor costs.

(5) The appropriateness of using

discount rates of seven percent and

three percent real to discount future

energy savings and emissions

reductions.

(6) Whether the Department should

include space occupancy costs in the

cost of transformers as a means of

accounting for space constraints.

(7) The IRFA and the potential

impacts on small businesses affected by

this rulemaking. Although the

Department is expressly inviting

comments related to the mediumvoltage, dry-type superclass, the

Department also welcomes comment on

its understanding that there would be

no significant economic impact on a

substantial number of small entities

within the liquid-immersed superclass

alone.

VIII. Approval of the Office of the

Secretary

The Secretary of Energy has approved

publication of today's notice of

proposed rulemaking.

List of Subjects in 10 CFR Part 431

Administrative practice and

procedure, Confidential business

information, Energy conservation,

Reporting and record keeping

requirements.

Issued in Washington, DC, on July 20,

2006.

Alexander A. Karsner,

Assistant Secretary, Energy Efficiency and

Renewable Energy.

For the reasons set forth in the

preamble, Chapter II of Title 10, Code of

Federal Regulations, Subpart K of Part

431 is proposed to be amended 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. Section 431.196 is amended by

revising paragraphs (b) and (c) to read

as follows:

§ 431.196 Energy conservation standards

and their effective dates.

(b) Liquid-Immersed Distribution

Transformers. Liquid-immersed

distribution transformers manufactured

on or after January 1, 2010, shall have

an efficiency no less than:

Single-phase Three-phase

WA Efficiency kVA Efficiency

10 .................................................................................. 98.40 15 ................................................................................. 98.36

15 .................................................................................. 98.56 30 ................................................................................. 98.62

25 .................................................................................. 98.73 45 ................................................................................. 98.76

37.5 ............................................................................... 98.85 75 ................................................................................. 98.91

50 .................................................................................. 98.90 112.5 ............................................................................ 99.01

75 .................................................................................. 99.04 150 ............................................................................... 99.08

100 ................................................................................ 99.10 225 ............................................................................... 99.17

167 ................................................................................ 99.21 300 ............................................................................... 99.23

250 ................................................................................ 99.26 500 ............................................................................... 99.32

333 ................................................................................ 99.31 750 ............................................................................... 99.24

500 ................................................................................ 99.38 1000 ............................................................................. 99.29

667 ................................................................................ 99.42 1500 ............................................................................. 99.36

833 ................................................................................ 99.45 2000 ............................................................................. 99.40

2500 ............................................................................. 99.44

* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 °C, and (2) for load-losses,

at the temperature of 55°C and 50 percent of nameplate load.

(c) Medium-Voltage Dry-Type voltage dry-type distribution January 1, 2010, shall have an efficiency

Distribution Transformers. Medium- transformers manufactured on or after no less than:

Single-phase Three-phase

BIL

WA

20-45 kV

efficiency

(%) *

46-95 kV

efficiency

(%) *

>_96 kV

efficiency

(%) *

BIL

kVA

20-45 kV

efficiency

(%) *

46-95 kV

efficiency (%) *

>96 kV

efficiency (%) *

15 .......................... 98.10 97.86 ........................ 15 .......................... 97.50 97.19 ........................

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

 EE-RM/STD-00-550 COMMENT 91.1

Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 44407 

should be included in the same product 

class as medium-voltage, dry-type 

transformers. Currently the Department 

considers dry-type transformers and 

liquid-immersed transformers as 

members of separate product classes. 

(4) Whether stakeholders believe a 

minimum efficiency standard for liquidimmersed distribution transformers 

would contribute to design 

standardization, and encourage 

manufacturers to move to countries with 

lower labor costs. 

(5) The appropriateness of using 

discount rates of seven percent and 

three percent real to discount future 

energy savings and emissions 

reductions. 

(6) Whether the Department should 

include space occupancy costs in the 

cost of transformers as a means of 

accounting for space constraints. 

(7) The IRF A and the potential 

impacts on small businesses affected by 

this rulemaking. Although the 

Department is expressly inviting 

comments related to the mediumSingle-phase 

kVA 

voltage, dry-type superclass, the 

Department also welcomes comment on 

its understanding that there would be 

no significant economic impact on a 

substantial number of small entities 

within the liquid-immersed superclass 

alone. 

VIII. Approval ofthe Office ofthe 

Secretary 

The Secretary of Energy has approved 

publication of today's notice of 

proposed rulemaking. 

List of Subjects in 10 CFR Part 431 

Administrative practice and 

procedure, Confidential business 

information, Energy conservation, 

Reporting and record keeping 

requirements. 

Issued in Washington, DC, on July 20, 

2006. 

Alexander A. Karsner, 

Assistant Secretary, Energy Efficiency and 

Renewable Energy. 

For the reasons set forth in the 

preamble, Chapter II of Title 10, Code of 

Efficiency 

(%)* 

Federal Regulations, Subpart K of Part 

431 is proposed to be amended 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. Section 431.196 is amended by 

revising paragraphs (b) and (c) to read 

as follows: 

§ 431.196 Energy conservation standards 

and their effective dates. 

* * * * * 

(b) Liquid-Immersed Distribution 

Transformers. Liquid-immersed 

distribution transformers manufactured 

on or after January 1, 2010, shall have 

an efficiency no less than: 

Three-phase 

kVA Efficiency 

(%)* 

10 ................................................................................. . 98.40 

98.56 

98.73 

98.85 

98.90 

99.04 

99.10 

99.21 

99.26 

99.31 

99.38 

99.42 

99.45 

15 ................................................................................ . 98.36 

98.62 

98.76 

98.91 

99.01 

99.08 

99.17 

99.23 

99.32 

99.24 

99.29 

99.36 

99.40 

99.44 

15 ................................................................................. . 30 ................................................................................ . 

25 ................................................................................. . 45 ................................................................................ . 

37.5 .............................................................................. . 75 ................................................................................ . 

50 ................................................................................. . 112.5 ........................................................................... . 

75 ................................................................................. . 150 .............................................................................. . 

100 ............................................................................... . 225 .............................................................................. . 

167 ............................................................................... . 300 .............................................................................. . 

250 ............................................................................... . 500 .............................................................................. . 

333 ............................................................................... . 750 .............................................................................. . 

500 ............................................................................... . 1000 ............................................................................ . 

667 ............................................................................... . 1500 ............................................................................ . 

833 ............................................................................... . 2000 ............................................................................ . 

2500 ............................................................................ . 

* Efficiencies are detennined at the following reference conditions: (1) For no-load losses, at the temperature of 20 °e, and (2) for load-losses, 

at the temperature of 55°e and 50 percent of nameplate load. 

(c) Medium-Voltage Dry-Type 

Distribution Transformers. Mediumvoltage dry-type distribution 

transformers manufactured on or after 

BIL 

kVA 

15 ......................... . 

25 ......................... . 

37.5 ...................... . 

50 ......................... . 

75 ......................... . 

100 ....................... . 

167 ....................... . 

250 ....................... . 

333 ....................... . 

500 ....................... . 

667 ....................... . 

833 ....................... . 

Single-phase 

20-45 kV 

efficiency 

(%) * 

98.10 

98.33 

98.49 

98.60 

98.73 

98.82 

98.96 

99.07 

99.14 

99.22 

99.27 

99.31 

46-95 kV 

efficiency 

(%) * 

97.86 

98.12 

98.30 

98.42 

98.57 

98.67 

98.83 

98.95 

99.03 

99.12 

99.18 

99.23 

2:96 kV 

efficiency 

(%) * 

........................ 

.. ~ ..................... ........................ 

........................ 

98.53 

98.63 

98.80 

98.91 

98.99 

99.09 

99.15 

99.20 

BIL 

kVA 

15 . ......................... 30 . ......................... 45 . ......................... 75 . ......................... 112.5 ..................... 150 ........................ 225 ........................ 

300 ........................ 

500 ........................ 750 ........................ 1000 ...................... 

1500 ...................... 

2000 ...................... 

January 1, 2010, shall have an efficiency 

no less than: 

Three-phase 

20-45 kV 

efficiency 

(%) * 

97.50 

97.90 

98.10 

98.33 

98.49 

98.60 

98.73 

98.82 

98.96 

99.07 

99.14 

99.22 

99.27 

46-95 kV 

efficiency 

(%) * 

97.19 

97.63 

97.86 

98.12 

98.30 

98.42 

98.57 

98.67 

98.83 

98.95 

99.03 

99.12 

99.18 

2:96 kV 

efficiency 

(%) * 

. ....................... 

. ....................... 

. ....................... 

. ....................... 

.. ...................... 

.. ...................... 98.53 

98.63 

98.80 

98.91 

98.99 

99.09 

99.15 
44408 Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules

Single-phase Three-phase

BIL

20-45 kV 46-95 kV >96 kV BIL 20-45 kV 46-95 kV ?96 kV

WA efficiency efficiency efficiency kVA efficiency

*

efficiency

*

efficiency *

(%) * (%) * (%) * (%) (%) (%)

2500 ...................... 99.31 99.23 99.20

* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 °C, and (2) for load-losses,

at the temperature of 75 °C and 50 percent of nameplate load.

[FR Doc. 06-6537 Filed 8-3-06; 8:45 am]

BILLING CODE 6450-01-P

 EE-RM/STD-00-550 COMMENT 91.1

44408 Federal Register/Vol. 71, No. 150/Friday, August 4, 2006/Proposed Rules 

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 

("!o) * ("!o) * ("!o) * ("!o) * ("!o) * ("!o) * 

2500 ...................... 99.31 99.23 99.20 

* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 ce, and (2) for load-losses, 

at the temperature of 75 ce and 50 percent of nameplate load. 

[FR Doc. 06-6537 Filed 8-3-06; 8:45 am] 

BILLING CODE 6450-01-P