[Federal Register Volume 71, Number 150 (Friday, August 4, 2006)]
[Proposed Rules]
[Pages 44356-44408]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-6537]



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Part II





Department of Energy





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Office of Energy Efficiency and Renewable Energy



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10 CFR Part 431



Energy Conservation Program for Commercial Equipment: Distribution 
Transformers Energy Conservation Standards; Proposed Rule

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

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DEPARTMENT OF ENERGY

Office of Energy Efficiency and Renewable Energy

10 CFR Part 431

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

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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 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: [email protected]. 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 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/
STD-00-550, 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: 
[email protected].
    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: [email protected].

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

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    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
    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
    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 liquid-
immersed and medium-voltage, dry-type 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, dry-type, 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
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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 II.1 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 liquid-immersed 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 average life-cycle cost (LCC) savings) 
are positive.
    The national net present value (NPV) of TSL2 is $2.52 billion using 
a seven-percent 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

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to the year 2004. Using a real corporate discount rate of 8.9 percent, 
the Department estimates the liquid-immersed and medium-voltage, dry-
type 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 liquid-immersed and 
TSL2 for medium-voltage, 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.

II. Introduction

A. Consumer Overview

    The Department is proposing to set energy-efficiency standard 
levels for distribution transformers as shown in Tables II.1 and II.2. 
The proposed standard would apply to liquid-immersed and medium-
voltage, dry-type 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 II.1.--Proposed Standard Level, TSL2, for Liquid-Immersed Distribution Transformers
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                        Single-phase                                              Three-phase
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                                                                                                    Efficiency
                    kVA                      Efficiency  (%)                  kVA                       (%)
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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
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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 II.2.--Proposed Standard Level, TSL2, for Medium-Voltage, Dry-Type Distribution Transformers
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                                   Single-phase                                                                  Three-phase
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                                      20-45 kV        46-95 kV                                               46-95 kV         >=96 kV
             BIL  kVA                efficiency      efficiency        >=96 kV      20-45 kV  efficiency    efficiency      efficiency          kVA
                                         (%)             (%)       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

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                                                                                    2000................           99.27           99.18           99.15
                                                                                    2500................           99.31           99.23          99.20
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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 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(o)(4))
    Second, DOE is applying 42 U.S.C. 6295(o)(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--(A) 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 liquid-immersed and medium-voltage, dry-type 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

[[Page 44360]]

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'' (ORNL-6847) and NEMA 
Efficiency Standard for Distribution Transformers, ORNL-6925. This 
report assessed the suggested efficiency levels contained in the then-
newly 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
---------------------------------------------------------------------------

    \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/stds/tp1.cfm#download.
---------------------------------------------------------------------------

    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 
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 (TOC)), 
loading levels, utility impact analysis vis-a-vis deregulation, scope 
of environmental assessment, and harmonization of standards with other 
countries.
---------------------------------------------------------------------------

    \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/pdfs/trans_framework.pdf.
---------------------------------------------------------------------------

    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 liquid-immersed 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 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, pad-mounted 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

[[Page 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 three-phase, 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 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

[[Page 44362]]

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 highest-efficiency designs to establish the max-tech 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.1 and III.2 provide the complete list of max-
tech efficiency levels considered for all kVA ratings within each 
product class.

                   Table III.1.--Max-Tech Levels for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
                        Single-phase                                              Three-phase
----------------------------------------------------------------------------------------------------------------
                                                                                                    Efficiency
                    kVA                      Efficiency  (%)                  kVA                       (%)
----------------------------------------------------------------------------------------------------------------
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 III.2.--Max.-Tech Levels for Medium-Voltage, Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                      20-45 kV        46-95 kV                                               20-45 kV        46-95 kV         >=96 kV
             BIL  kVA                efficiency      efficiency      >=96 kV  (%)           kVA             efficiency      efficiency      efficiency
                                         (%)             (%)                                                    (%)             (%)             (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15...............................           99.05           98.54  ...............  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           99.22   112.5...............           99.25           98.84  ..............
100..............................           99.41           99.09           99.28   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.


[[Page 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 long-term 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

[[Page 44364]]

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 
energy-efficiency 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

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 energy-efficiency 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 insulation--liquid-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).
    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, low-voltage, 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.
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

[[Page 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 liquid-immersed transformers. Howard commented that, 
for liquid-immersed transformers--especially for the utility, 
municipal, and co-operative segments--energy-efficiency standards 
should be voluntary because these transformer customers are already 
considering life-cycle 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 liquid-immersed 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.
    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 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 liquid-
immersed, pad-mounted units and dry-type 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

[[Page 44366]]

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 p. 2)
    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, standards-compliant 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

[[Page 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 re-wound) 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 market--DOE 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 software-
design 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-versus-performance 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

[[Page 44368]]

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 price-efficiency 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, low-voltage, 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 tear-
down 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-

[[Page 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 single-
phase, 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 kVA--including 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, liquid-immersed transformers would not significantly 
improve the analysis. The shipments of three-phase, liquid-immersed 
transformers below 150 kVA represent just 1.6 percent of all three-
phase, liquid-immersed units shipped, and a fraction of a percent of 
the liquid-immersed 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, liquid-immersed 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 medium-voltage, dry-type product classes). 
Cooper Industries noted that less-flammable, 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 less-flammable, 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, liquid-immersed units 
into the medium-voltage 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 higher-efficiency 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

[[Page 44370]]

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-first-cost 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-material-price scenario.
    DOE received two comments about the feasibility of manufacturing 
the most

[[Page 44371]]

efficient designs produced in the engineering analysis. Cooper 
conducted a design analysis of the 50 kVA pad-mount, the 150 kVA three-
phase, and the 1500 kVA three-phase, liquid-immersed 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 laser-scribed, 
high-permeability, grain-oriented 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                                ANOPR description                   Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Equipment price.........................  Derived by multiplying manufacturer         Reduced distributor markup
                                           selling price (from the engineering         for dry-type added small
                                           analysis) by distributor markup and         distributor markup for
                                           contractor markup plus sales tax for dry-   liquid-immersed.
                                           type transformers. For liquid-immersed
                                           transformers, DOE used manufacturer
                                           selling price plus sales tax. Shipping
                                           costs were included for both types of
                                           transformers.
Installation cost.......................  Includes a weight-specific component,       Added a pole replacement
                                           derived from RS Means Electrical Cost       component to design line
                                           Data 2002 and a markup to cover             2.
                                           installation labor, and equipment wear
                                           and tear.
Baseline and standard design selection..  The selection of baseline and standard-     Increased liquid-immersed
                                           compliant transformers depended on          transformer evaluation
                                           customer behavior. For liquid-immersed      percentage to 75%.
                                           transformers, the fraction of purchases     Divided dry-types into
                                           evaluated was 50%, while for dry-type       (1) small-capacity medium-
                                           transformers, the fraction of evaluated     voltage and (2) large-
                                           purchases was 10%. The average A value      capacity medium-voltage,
                                           for evaluators was $5/watt, while the B     with evaluation
                                           value depended on expected transformer      percentages of 50% and
                                           load.                                       80%, respectively.
----------------------------------------------------------------------------------------------------------------

[[Page 44372]]

 
                                            Affecting Operating Costs
----------------------------------------------------------------------------------------------------------------
Transformer loading.....................  Loading depended on customer and            Increased average peak
                                           transformer characteristics. The average    loading for medium-
                                           initial liquid-immersed transformer         voltage, dry-type
                                           loading was 30% for 25 dry-type kVA and     transformers from 75% to
                                           59% for 1500 kVA transformers. The          85%.
                                           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%.
Load growth.............................  1% per year for liquid-immersed and 0% per  No change.
                                           year for dry-type transformers.
Power factor............................  Assumed to be unity.......................  No change.
Annual energy use and demand............  Derived from a statistical hourly use and   No change.
                                           demand load simulation for liquid-
                                           immersed 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.
Electricity costs.......................  Derived from tariff-based and hourly based  Updated tariff-based
                                           electricity prices. Capacity costs          electricity prices with
                                           provided extra value for reducing losses    2004 tariff data.
                                           at peak. Average marginal tariff-based      Adjusted hourly based
                                           retail electricity price: 6.4[cent]/kWh     electricity prices for
                                           for no-load losses and 7.4[cent]/kWh for    inflation.
                                           load losses. Average marginal wholesale
                                           utility hourly based costs: 3.8[cent]/kWh
                                           for no-load losses and 4.5[cent]/kWh for
                                           load losses.
Electricity price trend.................  Obtained from Annual Energy Outlook 2003    Updated to
                                           (AEO2003).                                  AEO2005.[dagger]
Maintenance cost........................  Annual maintenance cost did not vary cost   No change.
                                           as a function of efficiency.
----------------------------------------------------------------------------------------------------------------
                            Affecting Present Value of Annual Operating Cost Savings
----------------------------------------------------------------------------------------------------------------
Effective date..........................  Assumed to be 2007........................  Assumed to be 2010.
Discount rates..........................  Mean real discount rates ranged from 4.2%   No change.
                                           for owners of pole-mounted, liquid-
                                           immersed transformers to 6.6% for dry-
                                           type transformer owners.
Lifetime................................  Distribution of lifetimes, with mean        No change.
                                           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      Six efficiency levels with
                                           line with the minimum equal to TP 1 and     the minimum equal to TP 1
                                           the maximum from the most efficient         and the maximum from the
                                           designs from the engineering analysis.      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.
[dagger] The Department is aware of AEO2006, and the electricity price forecast does not differ significantly
  from AEO2005.

    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 
liquid-immersed 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 liquid-
immersed 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

[[Page 44373]]

directly. (NEMA, No. 48 at p. 2) NRECA commented that most, if not all, 
cooperative utilities purchase liquid-immersed 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 liquid-
immersed 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 pole-mounted 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 pole-
replacement costs, for the NOPR analysis the Department added a pole-
replacement-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 
pole-mounted 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 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)

[[Page 44374]]

    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 dry-type 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 liquid-
immersed 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/watt--mentioned 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 liquid-immersed transformers purchased are 
already compliant with NEMA TP 1. (EEI, No. 63 at pp. 7-19) NGrid now 
purchases energy-efficient, liquid-immersed 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, 
liquid-immersed 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, dry-type 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

[[Page 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 liquid-immersed 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 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-per-year load 
growth. It applied the load growth factor to each transformer beginning 
in 2010, the expected effective date of the 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 liquid-immersed 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 of zero, 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 
dry-type and one percent for liquid-immersed 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)
    HVOLT 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) 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 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 liquid-immersed 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, EEI 
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, 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 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

[[Page 44376]]

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 AEO2003, 
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 AEO2005 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 AEO2005 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 day-
to-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).

[[Page 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 
energy-efficiency 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-owned  Publicly owned    Government
                                                              owners         companies       companies       utilities       utilities        offices
--------------------------------------------------------------------------------------------------------------------------------------------------------
Mean real discount rate.................................           4.35%           7.55%           7.46%           4.16%           4.31%           3.33%


--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
               Design line                   Weighted
                                              average
                                           discount rate
                                                (%)                                           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

[[Page 44378]]

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  TP 1          2  \1/3\ of diff.     3  \2/3\ of diff.        4  Min LCC           5  Max energy         6  Max energy
                                                             ---------------------- between TP 1 and min  between TP 1 and min ----------------------    savings with no           savings
                         Design line                                                         LCC                   LCC                                    change in LCC    ---------------------
                                                                          Effic'y  --------------------------------------------             Effic'y  ----------------------
                                                               TP 1+  %      %                  Effic'y               Effic'y    TP 1+  %      %                  Effic'y    TP 1+  %   Effic'y
                                                                                     TP 1+  %      %       TP 1+  %      %                             TP 1+  %      %                     %
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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 II.1 and II.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) 
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) 
Energy-efficient equipment typically costs more to purchase than 
baseline equipment, which lowers net income and may lower company 
taxes; and (2) more-efficient 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 
(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

[[Page 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 
standards-compliant 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

[[Page 44380]]

savings associated with, higher-efficiency 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 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 dry-type 
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 electro-
mechanical 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                                ANOPR description                   Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Shipments data..........................  Third-party expert (HVOLT) for the year     No change.
                                           2001.
Shipments backcast......................  For years 1977-2000, used Bureau of         Added three more years of
                                           Economic Analysis' (BEA) manufacturing      BEA's manufacturing data--
                                           data for distribution transformers.         for years 2001 through
                                           Source: http://www.bea.doc.gov/bea/pn/      2003.
                                           ndn0304.zip.
                                          For years 1950-1976, used EIA's
                                           electricity sales data. Source: http://www.eia.doe.gov/emeu/aer/txt/stb0805.xls.
Shipments forecast......................  Years 2002-2035: Based on AEO2003.........  Years 2010-2038: Based on
                                                                                       AEO2005.
Dry-type/liquid-immersed market shares..  Based on EIA's electricity sales data and   Based on EIA's electricity
                                           AEO2003.                                    sales data and AEO2005.
Regular replacement market..............  Based on a survival function constructed    No change.
                                           from a Weibull distribution function
                                           normalized to produce a 32-year mean
                                           lifetime. Source: ORNL 6804/R1, The
                                           Feasibility of Replacing or Upgrading
                                           Utility Distribution Transformers During
                                           Routine Maintenance, page D-1.

[[Page 44381]]

 
Elasticities............................  For liquid-immersed transformers:           For liquid-immersed
                                            Low: 0.00.......................   transformers:
                                            Medium: -0.04...................   No change.
                                            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.

                                Table IV. 7.--Summary of NES and NPV Model Inputs
----------------------------------------------------------------------------------------------------------------
                  Input                                ANOPR description                   Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Shipments...............................  Annual shipments from shipments model.....  No change.
Implementation date of standard.........  Assumed to be 2007........................  Assumed to be 2010.
Base case efficiencies..................  Constant efficiency through 2035. Equal to  Constant efficiency
                                           weighted-average efficiency in 2007.        through 2038. Equal to
                                                                                       weighted-average
                                                                                       efficiency in 2010.
Standards case efficiencies.............  Constant efficiency at the specified        Constant at the efficiency
                                           standard level from 2007 to 2035.           at the specified standard
                                                                                       level from 2010 to 2038.
Annual energy consumption per unit......  Average rated transformer losses are        No change.
                                           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).
Total installed cost per unit...........  Weighted-average values as a function of    No change.
                                           efficiency level (from LCC analysis).
Electricity expense per unit............  Energy and capacity savings for the two     No change.
                                           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).
Escalation of electricity prices........  AEO2003 forecasts (to 2025) and             Used AEO2005 forecasts (to
                                           extrapolation for 2035 and beyond.          2025) and extrapolation
                                                                                       for 2038 and beyond.
Electricity site-to-source conversion...  A time series conversion factor; includes   Updated conversion factors
                                           electric generation, transmission, and      from NEMS.
                                           distribution losses. Conversion varies
                                           yearly and is generated by DOE/EIA's
                                           National Energy Modeling System (NEMS)
                                           program.
Discount rates..........................  3% and 7% real............................  No change.
Analysis year...........................  Equipment and operating costs are           Equipment and operating
                                           discounted to the year of equipment price   costs are discounted to
                                           data, 2001.                                 year 2004.
----------------------------------------------------------------------------------------------------------------

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 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

[[Page 44382]]

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 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-gross-margin-percentage scenario, 
and (2) the preservation-of-operating-profit scenario. Under the 
``preservation-of-gross-margin-percentage'' scenario, DOE

[[Page 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 liquid-immersed 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 
cost-effectiveness 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 personal-computer-based, economic-analysis

[[Page 44384]]

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 the public domain, is a large, multi-
sectoral, 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\
---------------------------------------------------------------------------

    \3\ For more information on NEMS, please refer to the U.S. 
Department of Energy, Energy Information Administration 
documentation. A useful summary 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). NEMS-BT was previously 
called NEMS-BRS.
---------------------------------------------------------------------------

    The Department conducted the utility analysis as policy deviations 
from the AEO2005, 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 CO2, 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 AEO2005 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 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.

[[Page 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 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.

                  Table V.1.--Summary LCC and PBP Results for Design Line 1 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                Trial standard level
                                   -----------------------------------------------------------------------------
                                       1 TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
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 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 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
                                   -----------------------------------------------------------------------------
                                       1 TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)....................        98.7         98.73        98.76        98.79        98.96        99.46
Transformers with Net LCC Increase         1.4          3.0          5.2          8.6         43.9         98.9
 (%)..............................
Transformers with No Change in LCC        66.6         64.3         60.8         56.3         25.4          0.0
 (%)..............................
Transformers with Net LCC Savings         32.0         32.7         34.0         35.1         30.7          1.1
 (%)..............................
Mean LCC Savings ($)..............        69           70           72           71            7         -953
Mean Payback Period (years).......         4.8          6.8          8.8         12.0         31.7         66.6
----------------------------------------------------------------------------------------------------------------

    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 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
                                   -----------------------------------------------------------------------------
                                       1 TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
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
 (%)..............................

[[Page 44386]]

 
Transformers with No Change in LCC        73.7         65.2         49.5          4.0          0.1          0.0
 (%)..............................
Transformers with Net LCC Savings         26.1         33.4         44.4         56.1         33.6         29.2
 (%)..............................
Mean LCC Savings ($)..............     1,746        2,267        2,775        2,876          627         -410
Mean Payback Period (years).......         1.4          4.3         10.4         19.8         29.3         32.3
----------------------------------------------------------------------------------------------------------------

    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 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 installation (which includes 
manufacturer selling price, shipping costs, distributor markup, and 
taxes) was $3,335.00.

                  Table V.4.--Summary LCC and PBP Results for Design Line 4 Representative Unit
----------------------------------------------------------------------------------------------------------------
                                                                Trial standard level
                                   -----------------------------------------------------------------------------
                                       1 TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)....................        98.9         99.08        99.26        99.26        99.58        99.61
Transformers with Net LCC Increase         3.3         16.8         41.0         41.0         64.4         75.5
 (%)..............................
Transformers with No Change in LCC        63.7         40.8         11.3         11.3          0.8          0.0
 (%)..............................
Transformers with Net LCC Savings         33.0         42.4         47.7         47.7         34.8         25.5
 (%)..............................
Mean LCC Savings ($)..............       556          629          450          450           56         -572
Mean Payback Period (years).......         8.5         18.1         21.5         21.5         29.2         34.9
----------------------------------------------------------------------------------------------------------------

    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 transformers selected during the LCC 
analysis was 99.36 percent, the minimum efficiency of the baseline 
transformers selected during the LCC analysis was 99.13 percent, and 
the consumer equipment cost before 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  TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)....................        99.3         99.36        99.42        99.47        99.71        99.71
Transformers with Net LCC Increase         0.3          1.5         10.2         15.9         57.1         57.2
 (%)..............................
Transformers with No Change in LCC        71.7         62.8         40.0         24.2          0.0          0.1
 (%)..............................
Transformers with Net LCC Savings         28.0         35.7         49.8         59.9         42.9         42.7
 (%)..............................
Mean LCC Savings ($)..............     3,957        5,463        6,504        7,089        4,431        3,902
Mean Payback Period (years).......         3.4          6.1         12.7         14.1         25.6         26.1
----------------------------------------------------------------------------------------------------------------

    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 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
                                   -----------------------------------------------------------------------------
                                      1  TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
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
 (%)..............................

[[Page 44387]]

 
Transformers with No Change in LCC        57.8         46.3         29.7          0.5          0.0          0.0
 (%)..............................
Transformers with Net LCC Savings         41.6         52.6         65.0         73.8         43.7         45.0
 (%)..............................
Mean LCC Savings ($)..............       988        1,968        3,103        3,532        1,181        1,274
Mean Payback Period (years).......         1.5          2.4          5.4         12.4         21.7         21.5
----------------------------------------------------------------------------------------------------------------

    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 average efficiency of the baseline transformers selected 
during the LCC analysis was 99.17 percent, the minimum efficiency of 
the baseline transformers selected during the LCC analysis was 98.79 
percent, and the 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  TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)....................        99.1         99.20        99.30        99.39        99.51        99.51
Transformers with Net LCC Increase         4.4          5.1          8.9         21.0         66.3         66.2
 (%)..............................
Transformers with No Change in LCC        63.3         56.9         44.4         23.2          0.0          0.0
 (%)..............................
Transformers with Net LCC Savings         32.3         37.6         46.7         55.8         33.7         33.8
 (%)..............................
Mean LCC Savings ($)..............     4,041        5,227        6,818        7,699        1,279        1,124
Mean Payback Period (years).......         7.7          8.3         10.0         13.4         28.7         29.4
----------------------------------------------------------------------------------------------------------------

    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 average efficiency of the baseline transformers selected 
during the LCC analysis was 98.42 percent, the minimum efficiency of 
the baseline transformers selected during the LCC analysis was 98.05 
percent, and the 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  TP 1         2            3            4            5            6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)....................        98.5         98.67        98.84        99.01        99.09        99.09
Transformers with Net LCC Increase         2.4          3.9          9.8         22.0         34.2         33.2
 (%)..............................
Transformers with No Change in LCC        42.5         34.6         18.7          2.3          0.0          0.0
 (%)..............................
Transformers with Net LCC Savings         55.1         61.5         71.5         75.7         66.8         66.8
 (%)..............................
Mean LCC Savings Period ($).......     2,491        3,621        4,313        4,845        4,186        4,289
Mean Payback (years)..............         3.8          4.9          7.9         11.8         15.1         14.8
----------------------------------------------------------------------------------------------------------------

    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 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 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 TP 1         2            3            4            5            6
---------------------------------------------------------------------------------------------------------------------------------------------
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

[[Page 44388]]

 
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          8.3         12.7         29.3         29.3
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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 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 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            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-test-procedure 
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 in-service 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 standard-compliant transformers, the Department 
calculated the energy savings by taking the difference in the annual 
losses between the baseline and standard-compliant 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 rebuttable-presumption payback period. More 
detailed discussion on the rebuttable presumption is contained in TSD 
Chapter 8, section 8.7.
    Table V.11 shows the rebuttable-presumption payback period as a 
function of design line and standard level.

[[Page 44389]]



                              Table V.11.--Rebuttable-Presumption Payback in Years
----------------------------------------------------------------------------------------------------------------
                                 Rated
         Design line           capacity    TSL1 (TP      TSL2        TSL3        TSL4        TSL5        TSL6
                                  kVA         1)
----------------------------------------------------------------------------------------------------------------
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]
----------------------------------------------------------------------------------------------------------------
                                           TSL1  (TP
               Design line                    1)         TSL2        TSL3        TSL4        TSL5        TSL6
----------------------------------------------------------------------------------------------------------------
                                           Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
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]
----------------------------------------------------------------------------------------------------------------
                                 Rated
         Design line           capacity    TSL1  (TP     TSL2        TSL3        TSL4        TSL5        TSL6
                                  kVA         1)
----------------------------------------------------------------------------------------------------------------
                                            Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
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

[[Page 44390]]

 
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]
----------------------------------------------------------------------------------------------------------------
                                           TSL1  (TP
               Design line                    1)         TSL2        TSL3        TSL4        TSL5        TSL6
----------------------------------------------------------------------------------------------------------------
                                           Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
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).

[[Page 44391]]



                                         Table V.15.--Manufacturer Impact Analysis for Liquid-Immersed Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Trial standard level
                                                  Units            Base case ---------------------------------------------------------------------------
                                                                                   1            2            3            4            5           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 Expenses...........  ($ millions)............  ..........          0            0            0            0         109.2       161.2
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 Expenses...........  ($ millions)............  ..........          0            0            0            0         109.2       161.2
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  ----------------------------------------------------------------
                                                                                              1            2            3            4           5/6
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 liquid-immersed 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 liquid-immersed manufacturer interviews, and it appears 
that outsourcing would be a serious consideration for the liquid-
immersed 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. transformer-
manufacturing 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, dry-type transformer manufacturers for 
any TSL compared to the base case. The Department's conclusion 
regarding employment impacts in the medium-voltage, dry-type 
transformer industry is separate from any conclusions regarding

[[Page 44392]]

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 medium-voltage, 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 liquid-immersed 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 liquid-immersed 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 
liquid-immersed 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 medium-voltage, 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, 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 (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 
medium-voltage, 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 grain-oriented 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, dry-type 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

[[Page 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 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 
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.
3. National Impact Analysis
a. Amount and Significance of Energy Savings
    The Department estimated the energy savings from a proposed energy-
efficiency 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 energy-efficiency 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 site-to-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 NEMS-BT, 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$, at 3% and 7% discount rates, 2010-2073]
----------------------------------------------------------------------------------------------------------------
                                           TSL1  (TP
                                              1)         TSL2        TSL3        TSL4        TSL5        TSL6
----------------------------------------------------------------------------------------------------------------
                                           Sum of all Product Classes
----------------------------------------------------------------------------------------------------------------
Energy Savings (quads)..................        1.77        2.39        3.15        3.63        6.90        9.77
Discounted Energy Savings (quads):
    3%..................................        0.90        1.21        1.58        1.82        3.47        4.91
    7%..................................        0.40        0.54        0.71        0.82        1.54        2.19
NPV (billion 2004$):
    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
----------------------------------------------------------------------------------------------------------------


[[Page 44394]]

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        TSL2        TSL3        TSL4        TSL5        TSL6
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed.........................         4.7         6.4         7.7         8.7        18.2        19.4
Dry-Type, Medium-Voltage................         0.3         0.5         0.7         1.0         1.4         1.4
----------------------------------------------------------------------------------------------------------------

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 energy-efficient 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, pole-
mounted, 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 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

[[Page 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        TSL3        TSL4        TSL5        TSL6
----------------------------------------------------------------------------------------------------------------
Emissions reductions for liquid-immersed
 transformers:
    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
    Hg (t)..............................         2.9         3.5         4.1         4.5         5.8         5.9
Emissions reductions for medium-voltage,
 dry-type transformers:
    CO2 (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
    Hg (t)..............................        0.10        0.17        0.24        0.36        0.58        0.58
----------------------------------------------------------------------------------------------------------------

    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 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.
    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  (TP
                                              1)         TSL 2       TSL 3       TSL 4       TSL 5       TSL 6
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed, 3% discount, CO2 (Mt)..        58.2        78.4       101.9       115.5       223.5       321.1
Dry-Type, 3% discount, CO2 (Mt).........         2.8         4.4         6.4         9.7        15.5        15.5
Liquid-Immersed, 7% discount, CO2 (Mt)..        25.3        34.0        44.3        50.1        96.9       139.4
Dry-Type, 7% discount, CO2 (Mt).........         1.2         1.9         2.8         4.2         6.7         6.7
Liquid-Immersed, 3% discount, NOX (kt)..        16.3        21.9        28.6        32.4        62.6        90.0
Dry-Type, 3% discount, NOX (kt).........         1.2         1.8         2.7         4.0         6.5         6.5
Liquid-Immersed, 7% discount, NOX (kt)..         7.5        10.1        13.2        15.0        28.9        41.6
Dry-Type, 7% discount, NOX (kt).........         0.5         0.8         1.2         1.8         2.9         2.9
----------------------------------------------------------------------------------------------------------------

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 transformer-
manufacturing-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 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.

[[Page 44396]]

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 liquid-immersed and 
medium-voltage, dry-type 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 liquid-immersed 
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 three-
phase 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

[[Page 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 liquid-immersed and medium-
voltage, dry-type 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           1.4-4.2        2.7-12.8        3.0-38.3        4.2-40.6      15.5-141.9       106.9-160
     installation (%) * [dagger]........................
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.
[dagger] 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:
    CO2 (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                   0.7-4.4         2.2-7.2        5.4-13.6       13.5-30.4       36.4-78.5       36.4-78.4
     installation (%) * [dagger]........................
Manufacturer Impact:

[[Page 44398]]

 
    1INPV ($ 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 (%).....................................     (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.
[dagger] 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-operating-profit 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 multi-billion dollar 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 TSL6, the max tech level, is not 
economically justified.
---------------------------------------------------------------------------

    \5\ DOE estimates 18 coal-fired power plants and 22 gas-fired 
power plants can be avoided. See TSD Chapter 13.
---------------------------------------------------------------------------

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 seven-percent 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 seven-percent 
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

[[Page 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 seven-percent 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 liquid-immersed 
distribution transformers, an estimated $2.3 billion at the seven-
percent 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 liquid-immersed distribution transformers at 
TSL2.
2. Results for Medium-Voltage, Dry-Type 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 
seven-percent 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-of-operating-
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

[[Page 44400]]

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 
seven-percent 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-of-operating-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-base-case 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 seven-percent 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 medium-voltage, 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 
VI.1), and compared it to the effectiveness of the proposed rule.

[[Page 44401]]



                       Table VI.1.--Non-Regulatory Alternatives and the Proposed Standard
----------------------------------------------------------------------------------------------------------------
                                                                                    Net present value  (billion
                                                                  Primary energy              $2004)
          Policy alternatives                     Type                savings    -------------------------------
                                                                      (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            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 medium-voltage, 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, dry-type 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 liquid-immersed manufacturers 
because the

[[Page 44402]]

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 
liquid-immersed 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 medium-voltage, 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 liquid-immersed 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 medium-voltage, dry-type market is 
relatively small compared to that of the liquid-immersed superclass. 
The Department estimates that, of the 25 U.S. manufacturers that make 
medium-voltage, 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, medium-voltage, 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

[[Page 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 medium-voltage, 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, dry-type, 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 
medium-voltage, 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 grain-oriented 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., low-
voltage, 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 medium-voltage, 
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 butt-lap 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 record-keeping 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

[[Page 44404]]

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

[[Page 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 liquid-immersed 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.

[[Page 44406]]

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: [email protected].
    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 information 
electronically. Send them to the following e-mail address: [email protected]. 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-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, liquid-immersed distribution 
transformers

[[Page 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 
liquid-immersed 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 medium-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 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:


Sec.  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
----------------------------------------------------------------------------------------------------------------
                                             Efficiency  (%)                                        Efficiency
                    kVA                             *                         kVA                      (%) *
----------------------------------------------------------------------------------------------------------------
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 [deg]C, and (2) for load-losses, at the temperature of 55[deg]C and 50 percent of nameplate load.

    (c) Medium-Voltage Dry-Type Distribution Transformers. Medium-
voltage dry-type distribution transformers manufactured on or after 
January 1, 2010, shall have an efficiency no less than:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   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  (%)        BIL  kVA          efficiency      efficiency      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

[[Page 44408]]

 
                                                                                    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 [deg]C, and (2) for load-losses,
  at the temperature of 75 [deg]C and 50 percent of nameplate load.

[FR Doc. 06-6537 Filed 8-3-06; 8:45 am]
BILLING CODE 6450-01-P