Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards, 44356-44408 [06-6537]
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
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
Office of Energy Efficiency and
Renewable Energy, Department of
Energy.
ACTION: Notice of proposed rulemaking
and public meeting.
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AGENCY:
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
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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: https://
www.regulations.gov. Follow the
instructions for submitting comments.
• E-mail: TransformerNOPR
Comment@ee.doe.gov. Include docket
number EE–RM/STD–00–550 and/or
RIN 1904–AB08 in the subject line of
the message.
• Mail: Ms. Brenda Edwards-Jones,
U.S. Department of Energy, Building
Technologies Program, Mailstop EE–2J,
NOPR for Distribution Transformers
Energy Conservation Standards, docket
number EE–RM/STD–00–550 and/or
RIN 1904–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,
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EE–2J, 1000 Independence Avenue,
SW., Washington, DC 20585–0121, (202)
586–4563, e-mail:
Antonio.Bouza@ee.doe.gov.
Thomas B. DePriest, Esq., U.S.
Department of Energy, Office of General
Counsel, GC–72, 1000 Independence
Avenue, SW., Washington, DC 20585,
(202) 586–9507, e-mail:
Thomas.Depriest@hq.doe.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Summary of the Proposed Rule
II. Introduction
A. Consumer Overview
B. Authority
C. Background
1. Current Standards
2. History of Standards Rulemaking for
Distribution Transformers
3. Process Improvement
III. General Discussion
A. Test Procedures
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible
Levels
C. Energy Savings
D. Economic Justification
1. Economic Impact on Manufacturers and
Commercial Consumers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of
Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
IV. Methodology and Discussion of
Comments
A. Market and Technology Assessment
1. Product Classes
2. Definition of a Distribution Transformer
B. Engineering Analysis
1. Engineering Analysis Methodology
2. Engineering Analysis Inputs
3. Engineering Analysis Outputs
C. Life-Cycle Cost and Payback Period
Analysis
1. Inputs Affecting Installed Cost
a. Equipment Price
b. Installation Costs
c. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Power Factor
d. Electricity Costs
e. Electricity Price Trends
3. Inputs Affecting Present Value of
Annual Operating Cost Savings
a. Standards Implementation Date
b. Discount Rate
4. Candidate Standard Levels
5. Trial Standard Levels
6. Miscellaneous Life-Cycle Cost Issues
a. Tax Impacts
b. Cost Recovery Under Deregulation, Rate
Caps
c. Other Issues
D. National Impact Analysis—National
Energy Savings and Net Present Value
Analysis
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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
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VII. Public Participation
A. Attendance at Public Meeting
B. Procedure for Submitting Requests To
Speak
C. Conduct of Public Meeting
D. Submission of Comments
E. Issues on Which DOE Seeks Comment
VIII. Approval of the Office of the Secretary
I. Summary of the Proposed Rule
Pursuant to the Energy Policy and
Conservation Act, as amended, the
Department is proposing energy
conservation standards for liquidimmersed and medium-voltage, drytype distribution transformers. The
Department believes these standards
will achieve the maximum
improvement in energy efficiency that is
technologically feasible and
economically justified, and will result
in significant energy savings. In the
advance notice of proposed rulemaking
(ANOPR) for distribution transformers,
the Department had also conducted
analysis on low-voltage, dry-type
distribution transformers. 69 FR 45376
(July 29, 2004). However, the Energy
Policy Act of 2005 (EPACT 2005)
established energy conservation
standards for low-voltage, dry-type
distribution transformers. (42 U.S.C.
6295(y)) Because of these amendments,
DOE removed low-voltage, dry-type
distribution transformers—product class
3 (low-voltage, dry-type, single-phase)
and product class 4 (low-voltage, drytype, three-phase)—from this
rulemaking. Table I.1 shows the
proposed standard levels for the product
classes that are still within the scope of
this rulemaking.
TABLE I.1.—PROPOSED STANDARD LEVELS FOR DISTRIBUTION TRANSFORMERS
Superclasses—product classes (PC)
Proposed standard levels
Liquid-immersed ....................................................................................................................................................
Single-phase (PC 1)
Three-phase (PC 2)
Medium-voltage, dry-type ......................................................................................................................................
Single-phase, 25–45 kV BIL (PC 5)
Three-phase, 25–45 kV BIL (PC 6)
Single-phase, 46–95 kV BIL (PC 7)
Three-phase, 46–95 kV BIL (PC 8)
Single-phase, ≥96 kV BIL (PC 9)
Three-phase, ≥96 kV BIL (PC 10)
Trial Standard Level 2.
Trial Standard Level 2.
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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 liquidimmersed transformers and TSL2 for
medium-voltage, dry-type transformers,
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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
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average life-cycle cost (LCC) savings) are
positive.
The national net present value (NPV)
of TSL2 is $2.52 billion using a sevenpercent discount rate and $9.43 billion
using a three-percent discount rate,
cumulative from 2010 to 2073 in 2004$.
This is the estimated total value of
future savings minus the estimated
increased equipment costs, discounted
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
to the year 2004. Using a real corporate
discount rate of 8.9 percent, the
Department estimates the liquidimmersed and medium-voltage, drytype distribution transformer industry’s
NPV to be $558 million in 2004$. The
impact of the proposed standard on
liquid-immersed transformer
manufacturers’ industry net present
value (INPV) is expected to be between
a 2.4 percent loss and a 2.0 percent
increase (¥$12.9 million to $10.7
million). The medium-voltage, dry-type
transformer industry is estimated to lose
between 10.1 percent and 13.4 percent
of its NPV (¥$3.3 million to ¥$4.3
million) as a result of the proposed
standard. Based on the Department’s
interviews with the major
manufacturers of distribution
transformers, DOE expects minimal
plant closings or loss of employment as
a result of the proposed standards.
The proposed standards will lead to
reductions in greenhouse gases,
resulting in cumulative (undiscounted)
emission reductions of 167.1 million
tons (Mt) of carbon dioxide (CO2).
Additionally, the standards would
generate 46.4 thousand tons (kt) of
nitrogen oxides (NOX) emissions
reductions or a similar amount of NOX
emissions allowance credits in areas
where such emissions are subject to
emissions caps. The Department expects
the energy savings from the proposed
standards to eliminate the need for
approximately 11 new 400-megawatt
(MW) power plants by 2038.
Therefore, the Department concludes
that the benefits (energy savings,
commercial consumer LCC savings,
national NPV increases, and emissions
reductions) to the Nation of the
proposed standards outweigh their costs
(loss of manufacturer NPV and
commercial consumer LCC increases for
some users of distribution transformers).
The Department concludes that the
proposed standards of TSL2 for liquidimmersed and TSL2 for mediumvoltage, dry-type transformers are
technologically feasible and
economically justified. At present, both
liquid-immersed and medium-voltage,
dry-type transformers are commercially
available at the TSL2 standard level.
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 liquidimmersed and medium-voltage, drytype distribution transformers
manufactured for sale in the United
States, or imported to the United States,
on or after January 1, 2010. In preparing
these tables, the Department identified
some areas where the analytical
methods used to develop the efficiency
values resulted in discontinuities in the
table of efficiencies. Generally, larger
transformers will have greater efficiency
than smaller transformers, all other
factors being equal. Not all efficiency
ratings that result from the Department’s
analysis fit this pattern. The Department
invites comment on all the efficiency
ratings.
TABLE II.1.—PROPOSED STANDARD LEVEL, TSL2, FOR LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS
Single-phase
Three-phase
Efficiency
(%)
kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
98.40
98.56
98.73
98.85
98.90
99.04
99.10
99.21
99.26
99.31
99.38
99.42
99.45
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1000 .............................................................................
1500 .............................................................................
2000 .............................................................................
2500 .............................................................................
98.36
98.62
98.76
98.91
99.01
99.08
99.17
99.23
99.32
99.24
99.29
99.36
99.40
99.44
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431,
Subpart K, Appendix A; 71 FR 24972.
TABLE II.2.—PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS
Single-phase
20–45 kV
efficiency
(%)
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BIL
kVA
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
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Three-phase
≥96 kV
efficiency
(%)
46–95 kV
efficiency
(%)
98.10
98.33
98.49
98.60
98.73
98.82
98.96
99.07
99.14
99.22
99.27
99.31
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97.86
98.12
98.30
98.42
98.57
98.67
98.83
98.95
99.03
99.12
99.18
99.23
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20–45 kV
efficiency
(%)
........................
........................
........................
........................
98.53
98.63
98.80
98.91
98.99
99.09
99.15
99.20
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1000 ......................
1500 ......................
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46–95 kV
efficiency
(%)
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97.50
97.90
98.10
98.33
98.49
98.60
98.73
98.82
98.96
99.07
99.14
99.22
04AUP2
≥96 kV
efficiency
(%)
97.19
97.63
97.86
98.12
98.30
98.42
98.57
98.67
98.83
98.95
99.03
99.12
kVA
........................
........................
........................
........................
........................
........................
98.53
98.63
98.80
98.91
98.99
99.09
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
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TABLE II.2.—PROPOSED STANDARD LEVEL, TSL2, FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS—
Continued
Single-phase
BIL
kVA
20–45 kV
efficiency
(%)
Three-phase
46–95 kV
efficiency
(%)
≥96 kV
efficiency
(%)
20–45 kV
efficiency
(%)
46–95 kV
efficiency
(%)
2000 ......................
2500 ......................
≥96 kV
efficiency
(%)
99.27
99.31
99.18
99.23
kVA
99.15
99.20
Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431,
Subpart K, Appendix A; 71 FR 24972.
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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):
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(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.
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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 liquidimmersed and medium-voltage, drytype distribution transformers covered
by this rulemaking. However, on August
8, 2005, EPACT 2005 established energy
conservation standards for low-voltage,
dry-type distribution transformers that
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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 thennewly published National Electrical
Manufacturers Association (NEMA)
Standards Publication No. TP 1–1996,
Guide for Determining Energy Efficiency
for Distribution Transformers, along
with the efficiency levels previously
considered by the Department in the
determination study.1 In its
supplemental assessment, ORNL–6925,
the ORNL research team used a more
accurate analytical model and better
transformer market and loading data
developed following the publication of
ORNL–6847. Downloadable versions of
both ORNL reports are available on the
DOE Web site at: https://
www.eere.energy.gov/buildings/
appliance_standards/commercial/
distribution_transformers.html
As a result of its positive
determination, the Department
developed the Framework Document for
Distribution Transformer Energy
Conservation Standards Rulemaking in
2000, describing the procedural and
analytic approaches the Department
anticipated using to evaluate the
1 Note: NEMA later updated TP 1 in 2002 (NEMA
TP 1–2002), in which it increased some of the
efficiency levels. The latest version of TP 1 is
available at the NEMA Web site: https://
www.nema.org/stds/tp1.cfm#download.
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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.
Stakeholder comments submitted
during the Framework Document
comment period elaborated on the
issues raised at the meeting and also
addressed the following issues: Options
for the screening analysis, approaches
for the engineering analysis, discount
rates, electricity prices, the number and
basis for the efficiency levels to be
analyzed, the national energy savings
(NES) and NPV analyses, the analysis of
the effects of a potential standard on
employment, the manufacturer impact
analysis (MIA), and the timing of the
analyses.
As part of the information gathering
and sharing process, the Department
met with manufacturers of liquidimmersed and dry-type distribution
transformers during the first quarter of
2002. The Department met with
companies that produced all types of
distribution transformers, ranging from
small to large manufacturers, and
including both NEMA and non-NEMA
members. The Department had three
objectives for these meetings: (1) Solicit
feedback on the methodology and
findings presented in the draft
engineering analysis update report that
the Department posted on its Web site
December 17, 2001, (2) obtain
information and comments on
2 The Department published a notice of
availability of the Framework Document in the
Federal Register. 65 FR 59761 (October 6, 2000).
The Framework Document itself is available on the
DOE Web site: https://www.eere.energy.gov/
buildings/appliance_standards/commercial/pdfs/
trans_framework.pdf.
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production costs and manufacturing
processes presented in the draft
engineering analysis update report, and
(3) provide to manufacturers an
opportunity, early in the rulemaking
process, to express specific concerns to
the Department.
Seeking early and frequent
consultation with stakeholders, the
Department posted draft reports on its
website as it prepared for the
publication of the ANOPR. The reports
included draft screening analysis
findings, and draft engineering analysis
and LCC analysis reports on 50 kVA
single-phase, liquid-immersed, padmounted transformers and 300 kVA
three-phase, medium-voltage, dry-type
transformers. The Department also held
a live, online Web cast on October 17,
2002, giving an overview of the LCC
analysis and a tutorial on the use of the
LCC spreadsheet. The Department
received comments from stakeholders
on all the draft publications, which
helped improve the quality of the
analysis included in the ANOPR
published on July 29, 2004. 69 FR
45376.
In the ANOPR, the Department
invited stakeholders to comment on the
following key issues: Definition and
coverage, product classes, engineering
analysis inputs, design option
combinations, the 0.75 scaling rule,
modeling of transformer load profiles,
distribution chain markups, discount
rate selection and use, baseline
determination through purchase
evaluation formulae, electricity prices,
load growth over time, life-cycle cost
subgroups, and utility deregulation
impacts.
In preparation for the September 28,
2004, ANOPR public meeting, the
Department held a Web cast on August
10, 2004, to acquaint stakeholders with
the analytical tools (spreadsheets) and
other material published the previous
month. During the ANOPR comment
period, which ended on November 9,
2004, stakeholders submitted comments
on the 13 issues listed above, as well as
on other issues. These comments are
discussed in section IV of this NOPR.
On August 5, 2005, the Department
posted on its Web site several draft
NOPR analyses for early public review,
including draft technical support
document (TSD) chapters on the
engineering analysis, the energy use and
end-use load characterization, the
markups for equipment price
determination, the LCC and payback
period analyses, the shipments analysis,
the national impact analysis, and the
MIA. The Department also posted draft
NOPR spreadsheets for the engineering
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analysis, LCC analysis, national impact
analysis, and MIA on its Web site.
On August 8, 2005, President Bush
signed into law EPACT 2005, Public
Law 109–58. Section 135(c)(4) of this
Act establishes minimum efficiency
levels for low-voltage, dry-type
transformers manufactured, or imported
into the U.S., on or after January 1,
2007. (42 U.S.C. 6295(y)) The levels are
those appearing in Table 4–2 of NEMA
TP 1–2002, Guide for Determining
Energy Efficiency for Distribution
Transformers. The Department
incorporated this standard along with
efficiency standards for several other
products and equipment in a Federal
Register Notice. 70 FR 60407 (October
18, 2005). Because EPACT 2005
established standards for low-voltage,
dry-type distribution transformers, the
Department is no longer considering
standards for the single- and threephase, low-voltage dry-type distribution
transformers in this rulemaking.
In conjunction with this NOPR, the
Department also published on its
website the complete TSD and several
spreadsheets. The TSD contains
technical documentation of each
analysis conducted under this
rulemaking, providing specific
information on the methodology and
results. The spreadsheets, discussed in
the relevant TSD chapters, represent the
analytical tools and results that support
today’s proposed rule. The engineering
analysis spreadsheets represent the
Department’s design database, providing
the cost-efficiency relationships for the
10 specific distribution transformer
units analyzed—five liquid-immersed
and five medium-voltage, dry-type
units. The LCC spreadsheet calculates
the LCC and payback periods at six
standard levels for these representative
units. The national impact analysis
spreadsheet tool calculates impacts of
efficiency standards on distribution
transformer shipments, as well as the
NES and NPV of the standard levels
considered. The MIA spreadsheet
evaluates the financial impact of
standards on distribution transformer
manufacturers. All of these spreadsheet
tools are posted on the Department’s
Web site, along with the complete
NOPR TSD, at https://
www.eere.energy.gov/buildings/
appliance_standards/commercial/
distribution_transformers_draft
_analysis_nopr.html.
3. Process Improvement
The ‘‘Process Rule,’’ Procedures,
Interpretations and Policies for
Consideration of New or Revised Energy
Conservation Standards for Consumer
Products, Title 10 CFR Part 430, Subpart
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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
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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
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contained in the Department’s design
database could be built today. For
medium-voltage, dry-type transformers,
DOE used commercially available core
steels, ranging from M6 through
domain-refined 9-mil (0.009 inch) high
permeability, grain-oriented steel (H–O
DR). Core-construction techniques
included butt-lap, mitered, and
cruciform construction. The conductors
and insulation types used were all
conventional, and are commercially
available in distribution transformers
today. Thus, the Department believes
that all the efficiency levels discussed in
today’s proposed rule are
technologically feasible.
2. Maximum Technologically Feasible
Levels
In developing today’s proposed
standards, the Department followed the
provisions of 42 U.S.C. 6295(p)(2),
which states that, when the Department
proposes to adopt, or to decline to
adopt, an amended or new standard for
each type (or class) of covered product,
‘‘the Secretary shall determine the
maximum improvement in energy
efficiency or maximum reduction in
energy use that is technologically
feasible.’’ The Department determined
the maximum technologically feasible
(‘‘max-tech’’) efficiency level in the
engineering analysis (see TSD Chapter
5) using the most efficient materials not
screened out and applying design
parameters that drove the transformer
design software to create designs at the
highest efficiencies achievable. The
Department then used these highestefficiency designs to establish the maxtech level for the LCC analysis (see TSD
Chapter 8). In the national impact
analysis (see TSD Chapter 10), the
Department then scaled these max-tech
efficiencies to the other kVA ratings
within a given design line, establishing
max-tech efficiencies at all the
distribution transformer kVA ratings.
Tables III.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
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
99.32
99.39
99.46
99.51
99.59
99.59
99.62
99.66
99.70
99.72
99.75
99.77
99.78
Efficiency
(%)
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1000 .............................................................................
1500 .............................................................................
2000 .............................................................................
2500 .............................................................................
99.31
99.42
99.47
99.54
99.58
99.61
99.65
99.67
99.71
99.66
99.68
99.71
99.73
99.74
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431,
Subpart K, Appendix A; 71 FR 24972.
TABLE III.2.—MAX.-TECH LEVELS FOR MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS
Single-phase
20–45 kV
efficiency
(%)
BIL
kVA
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15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
Three-phase
46–95 kV
efficiency
(%)
99.05
99.17
99.25
99.30
99.37
99.41
99.48
99.42
99.46
99.51
99.54
99.57
≥96 kV
(%)
98.54
98.71
98.84
98.92
99.02
99.09
99.20
99.42
99.46
99.51
99.54
99.57
kVA
........................
........................
........................
........................
99.22
99.28
99.36
99.42
99.46
99.52
99.55
99.57
20–45 kV
efficiency
(%)
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1000 ......................
1500 ......................
2000 ......................
2500 ......................
98.75
98.95
99.05
99.17
99.25
99.30
99.37
99.41
99.48
99.42
99.46
99.51
99.54
99.57
46–95 kV
efficiency
(%)
98.08
98.38
98.54
98.71
98.84
98.92
99.02
99.09
99.20
99.42
99.46
99.51
99.54
99.57
≥96 kV
efficiency
(%)
........................
........................
........................
........................
........................
........................
99.22
99.28
99.36
99.42
99.46
99.52
99.55
99.57
Note: BIL means basic impulse insulation level.
Note: All 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.
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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))
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1. Economic Impact on Manufacturers
and Commercial Consumers
The Process Rule established
procedures, interpretations, and policies
to guide the Department in the
consideration of new or revised
appliance efficiency standards. The
provisions of the rule have direct
bearing on the implementation of the
MIA. First, the Department used an
annual-cash-flow approach in
determining the quantitative impacts of
a new or amended standard on
manufacturers. This included both a
short-term assessment based on the cost
and capital requirements during the
period between the announcement of a
regulation and the time when the
regulation comes into effect, and a longterm assessment. Impacts analyzed
include industry NPV, cash flows by
year, changes in revenue and income,
and other measures of impact, as
appropriate. Second, the Department
analyzed and reported the impacts on
different types of manufacturers, with
particular attention to impacts on small
manufacturers. Third, the Department
considered the impact of standards on
domestic manufacturer employment,
manufacturing capacity, plant closures,
and loss of capital investment. Finally,
the Department took into account
cumulative impacts of different DOE
regulations on manufacturers.
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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
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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
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impact. (See 42 U.S.C.
6295(o)(2)(B)(i)(V) and (B)(ii))
6. Need of the Nation To Conserve
Energy
The non-monetary benefits of the
proposed standard are likely to be
reflected in improvements to the
security and reduced reliability costs of
the Nation’s energy system—namely,
reductions in the overall demand for
energy will result in reduced costs for
maintaining reliability of the Nation’s
electricity system. The Department
conducts a utility impact analysis to
show the reduction in installed
generation capacity requirements.
Reduced power demand (including peak
power demand) generally reduces the
costs of maintaining the security and
reliability of the energy system.
The Department has determined that
today’s proposed standard should result
in reductions in greenhouse gas
emissions. The Department quantified a
range of primary energy conversion
factors and estimated the emissions
reductions associated with the
generation displaced by energyefficiency standards. The environmental
effects from each trial standard level for
this equipment are reported in the TSD
environmental assessment. (See 42
U.S.C. 6295(o)(2)(B)(i)(VI))
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
7. Other Factors
The Secretary of Energy, in
determining whether a standard is
In general, when evaluating and
establishing energy-efficiency standards,
the Department divides covered
products into classes by: (a) The type of
energy used, or (b) capacity, or other
performance-related features, such as
those that affect both consumer utility
and efficiency. Different energyefficiency standards may apply to
different product classes. As discussed
in the ANOPR, the Department received
some guidance from stakeholders on
establishing appropriate product classes
for the population of distribution
transformers. 69 FR 45385. Originally,
the Department created 10 product
classes, dividing up the population of
distribution transformers by:
• Type of transformer 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, lowvoltage, three-phase, dry-type). (42
U.S.C. 6295(y)) With standards thereby
established for low-voltage, dry-type
distribution transformers, the
Department is no longer considering
these two product classes for standards.
Table IV.1 presents the eight product
classes that remain within the scope of
this rulemaking.
TABLE IV.1.—DISTRIBUTION TRANSFORMER PRODUCT CLASSES FOR THE NOPR
PC No.*
Insulation
Voltage
Phase
BIL rating
kVA range
PC1 ..............................
PC2 ..............................
PC5 ..............................
PC6 ..............................
PC7 ..............................
PC8 ..............................
PC9 ..............................
PC10 ............................
Liquid-Immersed ..........
Liquid-Immersed ..........
Dry-Type .....................
Dry-Type .....................
Dry-Type .....................
Dry-Type .....................
Dry-Type .....................
Dry-Type .....................
.....................................
.....................................
Medium .......................
Medium .......................
Medium .......................
Medium .......................
Medium .......................
Medium .......................
Single ..........................
Three ...........................
Single ..........................
Three ...........................
Single ..........................
Three ...........................
Single ..........................
Three ...........................
.....................................
.....................................
20–45 kV BIL ..............
20–45 kV BIL ..............
46–95 kV BIL ..............
46–95 kV BIL ..............
≥96 kV BIL ..................
≥96 kV BIL ..................
10–833 kVA.
15–2500 kVA.
15–833 kVA.
15–2500 kVA.
15–833 kVA.
15–2500 kVA.
75–833 kVA.
225–2500 kVA.
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*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.
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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,
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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
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groupings for medium-voltage, dry-type
transformers, and therefore continues to
use these same BIL groupings in today’s
proposed rule.
Howard Industries and ASE
commented on whether DOE should
regulate the efficiency of liquidimmersed transformers. Howard
commented that, for liquid-immersed
transformers—especially for the utility,
municipal, and co-operative segments—
energy-efficiency standards should be
voluntary because these transformer
customers are already considering lifecycle costs in their purchasing
decisions. (Howard, No. 70 at p. 4)
Howard commented that it feels a
voluntary program would be better for
the whole utility market than a
mandatory standard. Howard believes a
mandatory program would contribute to
standardization of liquid-immersed
transformer designs, and encourage
manufacturers to move to countries with
lower labor costs. Howard suggested
that the ballast and electric motor
industries are two examples of products
where mandatory standards were
implemented and domestic
manufacturing declined. (Howard, No.
70 at p. 2) ASE agreed with the
Department’s decision that liquidimmersed transformers fall within the
scope of the standard. (ASE, No. 75 at
p. 2) Under 42 U.S.C. 6317, the
Department is charged in this
rulemaking with determining whether
standards for distribution transformers
are technologically feasible and
economically justified and would result
in significant energy savings. Based on
the Department’s analysis and
information available to date, standards
for liquid-immersed transformers appear
to be technologically feasible and
economically justified, and would result
in significant energy savings. The
Department considered a voluntary
program, NEMA TP–1 in its
Determination Analysis, but concluded
that the ‘‘efficiency levels would
capture the most cost effective energy
savings but may not capture substantial
energy savings that appear to be
economically justified and
technologically feasible.’’ 62 FR 54816.
In addition, the Department considered
the impact of voluntary programs in its
regulatory impact analysis (see the
report in the TSD ‘‘Regulatory Impact
Analysis for Electrical Distribution
Transformers’’), and found that a
voluntary program would not result in
standards that achieve the maximum
efficiency level that is technologically
feasible and economically justified.
Thus, in accordance with 42 U.S.C.
6317, the Department intends to
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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
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units become larger and obstructions
and required minimum clearances are
more difficult to achieve. Southern
noted that this is true for both liquidimmersed, pad-mounted units and drytype transformers installed in buildings.
It concluded that the increased size is
likely to cause both delivery and
installation problems in many locations.
(Southern, No. 71 at p. 2) At the ANOPR
public meeting, Ameren commented
that the Department should consider the
impact of different size/configurations
resulting from increased efficiency on
the speed and ease of emergency
replacement transformers. (Public
Meeting Transcript, No. 56.12 at pp.
255–256) The Department accounted for
generally applicable dimensional and
physical constraints on transformer
installation through the inclusion of
size- and weight-dependent installation
costs in its LCC model. These costs
include potential pole change-out costs
for large overhead transformers, and the
size- and weight-dependent labor and
equipment costs associated with
installing larger transformers. The costs
estimated by the Department do not
include the costs of rehabilitating
confined spaces that may have to be
modified for the installation of larger
transformers. This issue is similar to the
situation that arises when utilities and
contractors need to increase transformer
size due to load growth. One method of
modeling such costs would be to
include a space-occupancy cost to the
cost of transformer operation. The
Department invites comment on
whether space-occupancy costs should
be included in transformer cost
estimates and which methods are
appropriate for estimating such costs.
Howard and FPT expressed concern
about distribution transformers
designed for use in specific
environments. Howard recommended
that underground and subway-style
transformers be excluded from the
standards. Howard noted that these
transformers are often being retrofitted
into existing concrete vaults and, in
most cases, the whole concrete structure
would need to be replaced if DOE
mandated a more efficient unit.
(Howard, No. 70 at p. 3) FPT
recommended that the Department
consider exempting mining transformers
designed for installation inside
equipment with severe space
limitations, due to their radically
different loss characteristics. FPT noted
that efficiency standards could cause
problems in applications where these
transformers would not fit. (Public
Meeting Transcript, No. 56.12 at pp. 54–
56; FPT, No. 64 at p. 2) ODOE
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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
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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)
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Manufacturers, on the other hand,
appear to be concerned that the
increased cost of new, standardscompliant transformers would cause
some customers to either purchase
rebuilt transformers or refurbish existing
ones they own. ERMCO is concerned
that if these products are not subject to
standards, it may be possible for an end
user to avoid the standard by always
rewinding failed units. ERMCO stated
that there are several independent and
utility-owned repair shops that
refurbish: Some make minor repairs,
others rewind coils. (ERMCO, No. 58 at
p. 2) Howard commented that when the
final rule is established, it is absolutely
essential that it apply to new
transformers, used transformers, and
repaired transformers. (Howard, No. 70
at p. 3) HVOLT recommended that the
Department require any rebuilt
transformer that has a winding replaced
to meet the new standard, stating that
this is necessary to remove a major
loophole and would ultimately result in
improved energy efficiency for the
country. (HVOLT, No. 65 at p. 3 and
Public Meeting Transcript, No. 56.12 at
p. 59) EMSIC commented that it
believes that all refurbished (‘‘repaired’’)
units should be subject to the new
standards to close a potential loophole.
(EMSIC, No. 73 at p. 3) ODOE agreed
that re-wound transformers should be
required to meet the new standards.
ODOE also commented that some
organizations in the Pacific Northwest
have been involved in promotion of
high-quality rewinding practices.
Through these programs, it has become
evident that high-quality work in this
area can produce a product that meets
the same performance specifications as
a new product, while poor-quality work
can seriously degrade performance.
(ODOE, No. 66 at p. 2)
EPACT 2005’s definition of a
distribution transformer does not
mention refurbished or repaired
transformers, and therefore no guidance
on treatment of these transformers is
provided by the statute. Furthermore,
the Department’s regulatory authority
with respect to refurbished equipment is
not clearly delineated. EPCA, as
amended by EPACT 2005, seems to
require that only newly manufactured
distribution transformers meet Federal
efficiency requirements. (42 U.S.C.
6302, 6316(a) and 6317(a)(1)) Thus, DOE
believes it lacks authority to require
used and repaired transformers to
comply with energy conservation
standards. The same may be true for
rebuilt transformers, although DOE’s
authority is an issue. Generally, EPCA
provides that products, when
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‘‘manufactured,’’ are subject to
efficiency standards. (42 U.S.C. 6302
and 6316) It is arguable, but by no
means clear, that rebuilt transformers
(i.e., those with one or more coils rewound) could be considered to be
‘‘manufactured’’ again when they are
rebuilt, and therefore be classified as
new distribution transformers subject to
standards. If, however, rebuilt products
cannot be classified as newly
manufactured, DOE would be subject to
the same lack of authority to regulate
them as applies to other used and
repaired products. In addition, the
Department does not have authority to
regulate the efficiency of distribution
transformers re-wound by their owners
(i.e., ownership of the transformer is not
transferred or sold to another party),
despite the suggestion of some
commenters that DOE do so. EPCA
provides authority to regulate only
products that are sold, imported, or
otherwise placed in commerce. (42
U.S.C. 6291, 6311, and 6317(f)(1))
Throughout the history of its
appliance and commercial equipment
energy conservation standards program,
DOE has not sought to regulate used
units that have been reconditioned or
rebuilt, or that have undergone major
repairs. For transformers, regulating this
part of the market, including the
enforcement of efficiency requirements,
would be a complex and burdensome
task. By and large, the Department
believes EPCA indicates a Congressional
intent that DOE focus on the market for
new products, and believes this is
where the most energy savings can be
achieved. For distribution transformers
in particular, the Department
understands that, at present, rebuilt
transformers are only a small part of the
market.
For all of these reasons, the
Department is proposing not to include
energy conservation standards for used,
repaired, and rebuilt distribution
transformers in this rulemaking.
Nevertheless, the Department recognizes
the concerns raised by commenters
about possible substitution of rebuilt
transformers for new transformers. If
conditions change—for example, if
rebuilt transformers become a larger
segment of the transformer 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
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it believes are more in line with the
American National Standards Institute
(ANSI) standards with which most
utility systems comply. (Howard, No. 70
at p. 3) Howard’s table contains slightly
narrower bands of ‘‘normal’’ impedance
ranges, which would result in fewer
transformers being subject to standards
and more transformers being classified
as exempt. The Department is
concerned that some transformers
designed for electricity distribution
could be manufactured with
impedances outside normal ranges so
that they would not be subject to
otherwise applicable efficiency
standards. Such transformers could
have a competitive advantage over
standards-compliant distribution
transformers. If this occurred, it would
subvert the standards. The Department
also notes that, in NEMA’s revised test
procedure document, NEMA TP 2–2005,
the tables of normal impedance ranges
for both liquid-immersed and dry-type
transformers are exactly the same as
those published by the Department.
Thus, in the test procedure final rule
notice, the Department retained its
tables of ‘‘normal’’ impedance ranges.
71 FR 24972.
B. Engineering Analysis
The purpose of the engineering
analysis was to evaluate a range of
transformer efficiency levels and
associated manufacturing selling prices.
The engineering analysis considered
technologies and design option
combinations that were not screened out
by the four criteria in the screening
analysis. In the LCC analysis, the
Department used the manufacturer
selling price-efficiency relationships
developed in the engineering analysis
when it considered the consumer costs
of moving to higher efficiency levels.
For the distribution transformers
engineering analysis, the Department
learned that manufacturers in both the
liquid-immersed and medium-voltage,
dry-type sectors commonly use software
to design a distribution transformer to
fill a customer’s order. This softwaredesign approach follows from the actual
dynamics in the transformer market,
where customers often specify certain
performance characteristics and
requirements. Manufacturers then
compete for the contract based on the
customized designs they generate using
their software, which takes into account
the customer’s requirements and current
material costs.
Consistent with this approach, the
Department used transformer design
software to create a database of
distribution transformer designs
spanning a range of efficiencies, while
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tracking all the modifications to the
core, coil, labor, and other cost
components. The software creates
transformer designs and cost and
performance characteristics associated
with those designs that, when compiled,
characterize the relationship between
cost and efficiency. The Department
selected software developed by an
independent company, Optimized
Program Service (OPS), not associated
with any single manufacturer or
manufacturer’s association. The
engineering analysis design runs span a
broad range of efficiencies from lowest
first cost to maximum technologically
feasible. The data used in the
engineering analysis is discussed in
Chapter 5 of the TSD.
1. Engineering Analysis Methodology
There exist certain fundamental
relationships between the kVA ratings
of transformers and their physical size
and performance. Termed the ‘‘0.75
scaling rule,’’ these size-versusperformance relationships arise from
equations describing how a
transformer’s cost and efficiency change
with kVA rating. The Department used
the 0.75 scaling rule to reduce the
number of units that needed to be
analyzed for establishing minimum
efficiency standards for distribution
transformers as a whole. The findings
on those units analyzed were later
scaled to other kVA ratings using the
0.75 scaling rule. To maintain the
accuracy of the 0.75 scaling rule, DOE
established engineering ‘‘design lines.’’
Each design line consists of distribution
transformers that have a full range of
kVA ratings and that have similar
construction and engineering principles.
Some design lines consist of an entire
product class, but none spans more than
a product class. The Department then
selected one representative unit from
each of these design lines for analysis.
The 0.75 scaling rule was a critical
underlying factor in the engineering
analysis, since it enabled DOE to reduce
the number of units analyzed to 10.
Discussion on use of the 0.75 scaling
rule can be found in TSD Chapter 5,
section 5.2.2. Technical detail on the
derivation of the 0.75 scaling rule can be
found in TSD Appendix 5B.
In the ANOPR, the Department
solicited comments on the use of the
0.75 scaling rule. 69 FR 45416. ASE and
ODOE wrote that they support the use
of the 0.75 scaling rule, and believe it
is the correct and necessary approach to
simplify the analysis. (ASE, No. 52 at p.
3 and No. 75 at p. 3; ODOE, No. 66 at
p. 4) HVOLT commented at the ANOPR
public meeting that the 0.75 scaling rule
was used to develop the NEMA TP 1
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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.
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FPT expressed concern that the
manufacturer selling prices for dry-type
transformers may rise more rapidly than
is represented in the engineering
analysis. FPT is concerned that this may
skew the decision-making process
regarding what efficiency levels are
cost-justified. (FPT, No. 64 at p. 2)
Similarly, Howard commented that it
believes the inputs and outputs of the
OPS program are inaccurate, since it
found the outputs of the software to be
different from its own calculations.
Howard expressed concern at the
number of compromises,
generalizations, and assumptions that
could dilute the effectiveness of the
results. (Howard, No. 70 at p. 3) NEMA
commented that, because LCC results
seem to justify standards higher than TP
1, the OPS design software may not be
accurately modeling real-world units.
(NEMA, No. 48 at p. 2) NEMA also
commented that it had tested an actual
unit that had a similar technical
specification to an OPS design, and
found different results than were
reported by the Department. NEMA
noted that the designs in the
Department’s database were not built
and tested, and therefore are not
representative of real transformers.
(Public Meeting Transcript, No. 56.12 at
p. 35) In a written submission, NEMA
provided further detail on this
comparison, and again questioned the
real-world predictive capabilities of the
software used. (NEMA, No. 60 at p. 3)
In response to these comments, the
Department reviewed and refined the
inputs to the OPS software in
consultation with transformer
manufacturers, OPS, and the
Department’s technical experts. It is
important to recognize that there are
many inputs to both the engineering and
the LCC analytical models. For both
analytical models, the Department
updated its data and cost estimates for
the NOPR analysis. These refinements
changed the resulting designs and
associated manufacturer selling priceefficiency relationships discussed in
section IV.B of today’s notice and
Chapter 5 of the TSD.
The Department appreciates and
thanks NEMA and its members for
taking the time to locate and test a
transformer that was similar to the one
published. The Department found two
critical problems with the comparison
made. First, the design NEMA reviewed
was not one DOE used in the ANOPR
engineering analysis, but rather a draft
design produced for comment two years
before the ANOPR, in August 2002.
Based on stakeholder feedback on that
draft design, DOE modified the inputs to
the OPS software when generating the
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ANOPR engineering database; thus, that
design was not included. Second, the
two designs NEMA compared, while
having the same kVA rating, were not
similar transformers. The OPS design
and the unit NEMA tested had different
BIL ratings and would be grouped in
different product classes; therefore,
different testing results would be
expected.
Concerning the comments on the
accuracy of the OPS software, the
Department recognizes that differences
between the Department’s engineering
analysis results and those of
manufacturers can be caused by a
number of factors, including different
material prices, labor estimates,
modeling parameters (e.g., impedance
range, inductance), markups, and the
consideration of different non-active
transformer components (e.g., gauges,
tanks). The Department discussed its
inputs both in the ANOPR and during
the manufacturer site visits, and revised
them as necessary to be the best
approximation of real-world practices.
In the process of verifying the OPS
software, DOE found that, under similar
input conditions and modeling
parameters, the cost and performance
estimates in the Department’s database
are consistent with real-world
transformer designs. This was verified
both by comparing designs during
manufacturer interviews in May 2005
and through a tear-down analysis of six
transformers. The Department
purchased six 75 kVA three-phase, lowvoltage, dry-type transformers, and had
the units tested, disassembled, and
analyzed. It then used the OPS software
to model the physical designs and
generate an electrical analysis report.
The OPS software accurately predicted
the actual performance of the six
transformers. In addition, using the
2000–2004 average material prices, the
Department calculated the manufacturer
selling prices for each of these six units
using the same method as it used for the
engineering analysis. The Department
found that the cost-efficiency
relationship (slope) for these six units
tracked the cost-efficiency relationship
developed for the NOPR analysis. A
description of this tear-down analysis
and its results can be found in TSD
Chapter 5, section 5.7.
In addition to consulting with
manufacturers and conducting a teardown analysis, the Department arranged
for a third-party transformer design
engineer to prepare transformer designs
based on the same inputs as those used
by OPS. The transformer design
engineer looked at three of the
representative units published in this
NOPR, and prepared designs at a low-
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first-cost, TP 1, and high-efficiency
point. The Department then compared
these designs to the OPS output for
those same kVA ratings on an efficiency
and manufacturer’s selling price basis. It
found that the transformer engineer’s
designs tracked the cost and efficiency
improvements of the OPS designs. This
work is discussed in Chapter 5 of the
TSD.
The Department is confident of the
accuracy of the OPS software, given the
above-mentioned: (1) Comparison of
engineering results with manufacturers
during interviews; (2) tear-down
analysis; (3) comparison of OPS designs
with those of a third-party design
engineer; and (4) discussions with
manufacturers who use the OPS
software and consulting services.
The Department received a few
comments from stakeholders concerning
the design lines and the representative
units selected from those design lines.
ACEEE commented that additional
design lines may be necessary to better
represent all transformers and better
identify the lowest life-cycle cost points.
ACEEE recommended looking at singlephase, liquid-immersed distribution
transformers between 50 kVA and 500
kVA and three-phase units below 150
kVA. (ACEEE, No. 76 at p. 1 and Public
Meeting Transcript, No. 56.12 at p. 27)
In response to this comment, the
Department reviewed its design lines
and selection of representative units for
the NOPR. Concerning an additional
representative unit between 50 kVA and
500 kVA, the Department does not
believe one is required. The 50 kVA
(and 25 kVA pole-mounted) unit scales
up to a maximum of 167 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, liquidimmersed transformers would not
significantly improve the analysis. The
shipments of three-phase, liquidimmersed transformers below 150 kVA
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represent just 1.6 percent of all threephase, liquid-immersed units shipped,
and a fraction of a percent of the liquidimmersed product classes. Therefore,
the Department did not add any new
representative units to the NOPR
engineering analysis.
The Department received one
comment concerning the treatment of
medium-voltage, less-flammable, liquidimmersed transformers in the
engineering analysis. Cooper Industries
recommended that the Department
consider combining these units as
design option combinations in product
classes 5 through 10 (the mediumvoltage, dry-type product classes).
Cooper Industries noted that lessflammable, liquid-immersed
transformers are used in the same
applications as dry-type transformers
and are recognized for this application
in the National Electrical Code. (Cooper,
No. 62 at p. 2) As discussed in the
ANOPR, the Department considers
liquid-immersed and dry-type
transformers as separate product classes.
69 FR 45385. It based this decision on
input from several manufacturers during
site visits in 2002, a review of industry
standards—including those published
by the Institute of Electrical and
Electronics Engineers, Inc. (IEEE), the
NEMA TP 1–2002 voluntary standard,
and four comments received from
stakeholders on the distribution
transformer Framework Document.
(Howard, No. 4 at p. 2; NEMA, No. 7 at
p. 5; TXU Electric and Gas, No. 12 at p.
5; ACEEE, No. 14 at p. 2) All of these
stakeholders advised the Department to
treat liquid-immersed and dry-type
distribution transformers separately
when establishing standards.
Countering the separate treatment of
liquid-immersed and dry-type
transformers, Cooper asked that lessflammable, liquid-immersed units (a
special type of liquid-immersed
transformer) be evaluated for standards
along with medium-voltage, dry-type
units, because they can be used in the
same applications. The Department
appreciates this comment. However,
energy efficiency standards are
prescribed on the basis of differences in
features that affect energy use. (42
U.S.C. 6295(q)) An example of these
different features is the cooling
mechanism for a transformer coil,
whether it is air-cooled or liquid-cooled.
Standards are therefore not classified or
organized on the basis of whether they
can service the same application. That
said, customer applications are taken
into consideration for the Department’s
economic analysis when a standard is
developed and proposed (see the LCC
analysis, TSD Chapter 8). Thus, due to
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the fact that the efficiency standard is
applied on the basis of product class,
not application, the Department did not
incorporate less-flammable, liquidimmersed units into the mediumvoltage dry-type analysis. The
Department invites comment on this
issue and on the recommendation from
Cooper.
2. Engineering Analysis Inputs
One of the critical issues identified by
many stakeholders commenting on the
ANOPR analysis was whether DOE used
prices that were representative of
current material prices. Georgia Power
commented that future transformer
pricing may be affected by the
decreasing number of suppliers of
transformer materials—such as mineral
oil and core steel—and that those still
in business are already operating at full
capacity. At present there are only two
domestic suppliers of core steel: AK
Steel and Allegheny Ludlum Steel
Corporation (see TSD Appendix 3A).
Georgia Power noted that higherefficiency transformers will require
more of these materials, which may
result in material shortages. It is
concerned that this situation could have
a major impact on future transformer
pricing and availability. (Georgia Power,
No. 78 at pp. 1–2) HVOLT submitted a
similar comment, and mentioned
specifically that material prices have
risen dramatically in step with higher
energy prices. HVOLT noted that
virtually all material suppliers now
impose surcharges on top of their base
material prices to yield the net selling
price. HVOLT recommended the
Department conduct a more detailed
analysis of material prices. (HVOLT, No.
65 at pp. 2–3)
HVOLT and Edison Electric Institute
(EEI) commented that material prices at
the time of the ANOPR public meeting
(September 2004) had increased relative
to the material prices the Department
used for its ANOPR analysis (2001
prices). (Public Meeting Transcript, No.
56.12 at p. 77; EEI, No. 63 at p. 3) The
Southern Company commented that
there have been substantial price
increases in many of the materials used
to build transformers, including copper
and steel, and suggested that these
increases make high-efficiency
transformers less cost-effective.
Southern recommended that recent raw
material price increases and reasonable
projections of future prices be included
in the updated cost study produced for
the NOPR. (Southern, No. 71 at p. 3)
The National Rural Electric Cooperative
Association (NRECA) commented that it
supports and concurs with EEI’s
comments on the dramatic increase in
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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
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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
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due to protective devices in the
measurement of efficiency of the
transformer. (ERMCO, No. 58 at p. 1)
The Department notes that the
measurement and representation of the
efficiency of regulated transformers is
prescribed in the test procedures for
distribution transformers. 10 CFR Part
431, Subpart K, Appendix A; 71 FR
24972. As published, the test procedure
directs manufacturers to provide an
efficiency representation for a regulated
unit that does not include losses from
protective devices. The efficiency
standard proposed today only governs
the performance of the basic
transformer; it would not apply to the
protective devices and would not seek
to regulate the efficiency of these
devices. The test procedure directs
manufacturers to either calculate and
deduct losses from these protective
devices, or to by-pass the protective
devices in the load-loss test set-up
configuration.
HVOLT, NEMA, and ODOE
commented on manufacturer selling
prices. HVOLT commented during the
ANOPR workshop that the actual selling
prices of liquid-immersed units are
lower than was reported in DOE’s
analysis. (Public Meeting Transcript,
No. 56.12 at p. 78) HVOLT also later
stated that the price for a low-first-cost
25 kVA single-phase, pole-mount
transformer was on the order of $400,
while the Department’s analysis
reported $800. (Public Meeting
Transcript, No. 56.12 at p. 96) NEMA
recommended that the Department
contact individual manufacturers and
discuss the pricing of their lowest-firstcost transformers to calibrate the
engineering analysis. (NEMA, No. 48 at
p. 2 and Public Meeting Transcript, No.
56.12 at p. 35) ODOE echoed the
comment from NEMA, recommending
that the Department check the pricing of
transformers sold by manufacturers.
(ODOE, No. 66 at p. 3) Following
NEMA’s and ODOE’s recommendations,
the Department spoke to individual
manufacturers (both NEMA members
and non-NEMA members) about
material pricing, manufacturers’ selling
prices, OPS software inputs, and other
equipment costs (e.g., tanks, bushings,
busbar). The adjustments DOE made
following these conversations resulted
in a reduction in manufacturer selling
prices for some design lines. For
example, the low-first-cost design for
the 25kVA single-phase, pole-mount
transformer went from approximately
$800 per unit to around $500 per unit
using the five-year, average-materialprice scenario.
DOE received two comments about
the feasibility of manufacturing the most
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efficient designs produced in the
engineering analysis. Cooper conducted
a design analysis of the 50 kVA padmount, the 150 kVA three-phase, and
the 1500 kVA three-phase, liquidimmersed units. It found that it was not
possible to meet the ANOPR candidate
standard level 5 (CSL5) efficiency level.
Furthermore, it found that, as the design
reaches ANOPR CSL3, the cost to
produce the transformer generally
increases exponentially. Because of this,
Cooper believes that the OPS software
does not account for realistic material
performance characteristics or realize
the cost or productivity impact of these
design changes with regard to the
manufacturing of a product. (Cooper,
No. 62 at p. 1) NRECA also questioned
the validity of the highest efficiency
levels (ANOPR CSL4 and CSL5). It
recommended that the Department
verify whether transformers with these
efficiencies actually exist or are merely
theoretical designs on paper. (NRECA,
No. 74 at p. 2)
As discussed in section IV.B.1, the
Department took several steps to verify
the OPS software and the predictive
capability of the software to design
transformers. The Department is
confident in the accuracy of the OPS
software, given the: (1) Comparison of
engineering results with manufacturers
during interviews; (2) tear-down
analysis; (3) comparison of OPS designs
with those of a third-party design
engineer; and (4) discussions with
manufacturers who use the OPS
software and consulting services. In
response to Cooper’s and NRECA’s
comments on the maximum
technologically feasible designs, the
Department notes that the design option
combinations that achieved the highest
efficiencies in a given representative
unit used non-traditional materials,
such as amorphous material and laserscribed, high-permeability, grainoriented electrical steel. The core
destruction factors, packing factors, and
other real-world adjustments for
production floor manufacturing are
inputs that OPS has refined over
decades in consultation with its clients,
some of which have manufactured
amorphous material and laser-scribed
steel. If the core material, winding, and
construction are all built to the design
report specification, these are feasible
designs. Details of the engineering
analysis can be found in TSD Chapter 5
and Appendices 5A, 5B, and 5C.
C. Life-Cycle Cost and Payback Period
Analysis
This section describes the LCC and
payback period (PBP) analysis and the
spreadsheet model DOE used for
analyzing the economic impacts on
customers. Details of the spreadsheet
model, and of all the inputs to the LCC
and PBP analysis, are in TSD Chapter 8.
The Department conducted the LCC and
PBP analysis using a spreadsheet model
developed in Microsoft (MS) Excel for
Windows 95 or above. When combined
with Crystal Ball (a commercially
available software program), the LCC
and PBP model generates a Monte Carlo
simulation to perform the analysis by
incorporating uncertainty and
variability considerations. While the
Department included an annual
maintenance cost as part of the LCC and
PBP calculation, it assumed that
maintenance and repair costs are
independent of transformer efficiency.
The LCC is the total customer cost
over the life of the equipment, including
purchase expense and operating costs
(including energy expenditures and
maintenance). To compute the LCC, the
Department summed the installed price
of a transformer and the discounted
44371
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 selling price (from the engineering
analysis) by distributor markup and contractor markup plus sales tax for
dry-type transformers. For liquid-immersed transformers, DOE used manufacturer selling price plus sales tax. Shipping costs were included for
both types of transformers.
Includes a weight-specific component, derived from RS Means Electrical
Cost Data 2002 and a markup to cover installation labor, and equipment
wear and tear.
The selection of baseline and standard-compliant transformers depended
on customer behavior. For liquid-immersed transformers, the fraction of
purchases evaluated was 50%, while for dry-type transformers, the fraction of evaluated purchases was 10%. The average A value for evaluators was $5/watt, while the B value depended on expected transformer
load.
Reduced distributor markup for drytype added small distributor markup
for liquid-immersed.
Installation cost ................
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Added a pole replacement component
to design line 2.
Increased
liquid-immersed
transformer evaluation percentage to
75%. Divided dry-types into (1)
small-capacity medium-voltage and
(2) large-capacity medium-voltage,
with evaluation percentages of 50%
and 80%, respectively.
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TABLE IV.2.—SUMMARY OF INPUTS AND KEY ASSUMPTIONS USED IN THE LCC AND PBP ANALYSES—Continued
Inputs
ANOPR description
Changes for NOPR
Affecting Operating Costs
Transformer loading ........
Load growth .....................
Power factor ....................
Annual energy use and
demand.
Electricity costs ................
Electricity price trend .......
Maintenance cost ............
Loading depended on customer and transformer characteristics. The average initial liquid-immersed transformer loading was 30% for 25 dry-type
kVA and 59% for 1500 kVA transformers. The average initial dry-type
transformer loading was 32% for 25 kVA and 37% for 2000 kVA transformers. The shipment-weighted lifetime average loading was 33.6% for
low-voltage, dry and 36.5% for medium-voltage, dry. With load growth,
average installed liquid-immersed transformer loading was 35% for 25
kVA and 70% for 1500 kVA transformers with a shipment-weighted lifetime average loading of 52.9%.
1% per year for liquid-immersed and 0% per year for dry-type transformers
Assumed to be unity ........................................................................................
Derived from a statistical hourly use and demand load simulation for liquidimmersed transformers, and estimated from the 1995 Commercial Building Energy Consumption Survey data for dry-type transformers using factors derived from hourly load data. Load losses varied as the square of
the load and were equal to rated load losses at 100% loading.
Derived from tariff-based and hourly based electricity prices. Capacity costs
provided extra value for reducing losses at peak. Average marginal tariffbased retail electricity price: 6.4¢/kWh for no-load losses and 7.4¢/kWh
for load losses. Average marginal wholesale utility hourly based costs:
3.8¢/kWh for no-load losses and 4.5¢/kWh for load losses.
Obtained from Annual Energy Outlook 2003 (AEO2003) ...............................
Annual maintenance cost did not vary cost as a function of efficiency ..........
Increased average peak loading for
medium-voltage, dry-type transformers from 75% to 85%.
No change.
No change.
No change.
Updated tariff-based electricity prices
with 2004 tariff data. Adjusted hourly based electricity prices for inflation.
Updated to AEO2005.†
No change.
Affecting Present Value of Annual Operating Cost Savings
Effective date ...................
Discount rates ..................
Lifetime ............................
Assumed to be 2007 ........................................................................................
Mean real discount rates ranged from 4.2% for owners of pole-mounted, liquid-immersed transformers to 6.6% for dry-type transformer owners.
Distribution of lifetimes, with mean lifetime for both liquid and dry-type transformers assumed to be 32 years.
Assumed to be 2010.
No change.
No change.
Candidate Standard Levels
Candidate standard levels
Five efficiency levels for each design line with the minimum equal to TP 1
and the maximum from the most efficient designs from the engineering
analysis.
Six efficiency levels with the minimum
equal to TP 1 and the maximum
from the most efficient designs from
the engineering analysis. Intermediate efficiency levels for each
design line selected using a redefined set of LCC criteria (see section III.D.1.b).
* The concept of using A and B loss evaluation combinations is discussed in TSD chapter 3, Total Owning Cost Evaluation. Within the context
of the LCC analysis, the A factor measures the value to a transformer purchaser, in $/watt, of reducing no-load losses while the B factor 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.
† 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
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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
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price as the transformer passes through
the distribution channel. Commercial
and industrial customers most often
purchase dry-type transformers from
electrical contractors who purchase the
transformers through distributors,
whereas many liquid-immersed
transformers are purchased by utilities
directly from manufacturers and
installed directly by utility staff.
Therefore, DOE’s markups for liquidimmersed transformers are smaller than
those for dry-type transformers. In
addition to the supply-chain markups,
DOE’s equipment prices include
shipping costs and sales tax for both
types of transformers. The Department
did not have sufficient data to diversify
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the distribution channels and markups
beyond these two general categories.
Details of the installed cost inputs can
be found in TSD Chapter 7.
In the ANOPR analysis, the
Department assumed that all liquidimmersed transformers were purchased
directly from manufacturers by utilities.
NEMA commented that distribution
channels are more complex than DOE
assumed in the ANOPR analysis. It
noted that some liquid-immersed units
may go through distributors and some
dry-type units may be sold directly from
the manufacturer. NEMA also indicated
that small transformers are more likely
to go through distributors and large
transformers are more likely to be sold
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directly. (NEMA, No. 48 at p. 2) NRECA
commented that most, if not all,
cooperative utilities purchase liquidimmersed transformers through
distributors. (Public Meeting Transcript,
No. 56.12 at p. 120) In response to
NEMA’s comment, the Department
discussed distribution channels and
markup practices with utility technical
staff to obtain additional input for the
NOPR analysis. Based on this input, the
Department adjusted the distributor
markup to 7 percent for liquidimmersed transformers and 15 percent
for dry-type transformers. These
distributor markup values compare with
0 percent and 35 percent, respectively,
for the liquid-immersed and dry-type
distributor markups for the more
simplified distribution channels that the
Department assumed for the ANOPR
analysis.
b. Installation Costs
Higher-efficiency distribution
transformers tend to be larger and
heavier than less efficient designs. The
Department therefore included the
increased cost of installing larger,
heavier transformers as a component of
the first cost of efficient transformers. In
the ANOPR, the Department presented
the installation cost model and solicited
comment from stakeholders. For details
of the installation cost calculations, see
TSD section 7.3.1.
EEI provided substantial comments
regarding the installation cost
implications of more-efficient
transformers that are physically larger
and heavier than less-efficient
transformers. It asserted that transformer
size and weight may require physical
modification to pole structure or
mounting pads, and that, in severe
replacement applications, increased
transformer size may require building
and structural modifications. (EEI, No.
63 at pp. 4–5) NRECA expressed similar
concerns that the size and weight of
more energy-efficient transformers may
dramatically affect installation cost.
(NRECA, No. 74 at p. 2) Tampa Electric
Company (TEC) commented that
transformer efficiency standards must
take into account physical dimension
constraints to ensure compatibility with
older units that will need to be replaced.
(TEC, No. 77 at p. 1) Georgia Power
Company commented that, as a result of
the expected increase in physical size
and weight of higher efficiency
transformers, installation costs will be
increased in several ways. First, it
estimates that pole replacements will be
required for 80 percent of the
transformer replacement installations
that have joint use applications (e.g.,
telephone line, cable television) on the
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pole. Second, in addition to the pole
replacements at existing locations,
Georgia Power projects that numerous
larger diameter and taller poles will be
required at new transformer
installations. Third, it asserts that an
increase in the size and weight of polemounted and pad-mounted transformers
will significantly increase utility costs,
and that this impact will be
proportional to the percent increase in
transformer size and weight resulting
from the higher efficiency requirements.
(Georgia Power, No. 78 at pp. 2–3)
Ameren also commented that it believes
the Department should consider the
economic impact of transformer weight
increases, such as the necessity for
using stronger poles, resulting from
efficiency improvements. (Public
Meeting Transcript, No. 56.12 at pp.
253–254)
Howard commented that higher
efficiency transformers will be larger,
resulting in increased shipping costs as
well as handling problems for the
installers. (Howard, No. 70 at p. 3)
Comments from EEI included
information from utility members of
EEI, the American Public Power
Association (APPA), and NRECA, who
reported that in many cases increased
transformer size and weight can affect
the cost of new pole-mounted
transformer installations; costs vary
from utility to utility and depend on the
size and weight increase. (EEI, No. 63 at
pp. 20–62) Southern Company asserted
that increases in installation costs from
the weight increases of more-efficient
transformers are not adequately covered
in the ANOPR analysis. (Southern, No.
71 at p. 2) National Grid (NGrid)
commented that high-efficiency
transformers present utilities with
logistical and financial challenges, but
they have found that the benefits
outweigh the costs when analyzed using
a life-cycle cost analysis method
employed in the industry. (NGrid, No.
80 at p. 1)
While the Department’s ANOPR
included weight- and size-dependent
installation costs associated with the
increased shipping, handling, labor, and
equipment costs of installing larger and
heavier transformers, the ANOPR did
not include the costs of stronger poles
or pole replacement. In response to
stakeholder comments on polereplacement costs, for the NOPR
analysis the Department added a polereplacement-cost function to the
installation cost equation for design line
2, which covers pole-mounted
transformers. This analysis assumed
that a pole change-out cost of $2,000
occurs for up to 25 percent of polemounted transformers when the weight
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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)
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Regarding the actual values observed
in the market, HVOLT commented that,
for the 80 percent of electric utilities
that currently evaluate losses when
purchasing a liquid-immersed
transformer, the A factor is between
$2.00 and $2.50 and the B factor is
approximately $0.75. HVOLT noted that
these evaluation formulae are higher
than the A factor ($1.57) and B factor
($0.57) used to develop the TP 1
standard. (Public Meeting Transcript,
No. 56.12 at p. 107) AK Steel
Corporation observed that some
transformer customers evaluate with an
A value of between $1.50 and $2.00.
(Public Meeting Transcript, No. 56.12 at
p. 109)
Relating to the percent of customers
who use the evaluation formulae, BBF &
Associates (BBF&A) said its market
study in the early 1990s indicated that
90 percent or more of transformers were
evaluated using A and B factors in the
traditional approach. It pointed out that
a subsequent survey in 2001–2002
showed that less than 50 percent were
evaluated. (Public Meeting Transcript,
No. 56.12 at p. 110) In the context of a
discussion on liquid-immersed
transformers, HVOLT said that around
80 percent of the market evaluates
losses today. (Public Meeting
Transcript, No. 56.12 at p. 107) For drytype transformers, HVOLT suggested
that there is probably less purchase
evaluation than the Department
assumed in the analysis, but that an
estimate of 10 percent evaluators is
probably accurate. (Public Meeting
Transcript, No. 56.12 at p. 156) ACEEE
stated that the efficiency of liquidimmersed transformers is dropping as
utilities move away from evaluation of
purchase decisions, due to regulatory
uncertainty caused by restructuring of
the electric utility industry. (ACEEE,
No. 76 at pp. 1–2) Similarly, the Copper
Development Association (CDA)
observed that at the ANOPR public
meeting, stakeholders commented that
62 percent of the smaller-kVA
distribution transformers sold in 2002
were lowest-cost versions and several
utility personnel indicated that A and B
evaluation values were zero. CDA
commented that it believes these
statements illustrate that many
transformers currently being purchased
are lowest-first-cost, low-efficiency
units. (CDA, No. 69 at p. 4)
The Department responded to these
stakeholder comments regarding A and
B values and the percent evaluators by
using new data provided by
stakeholders, and newly collected data
from the Internet, to adjust the
distributions and parameters it used to
model purchase decisions (see TSD
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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 1compliant transformers increased in
2002 and 2003 compared to 2001 for all
transformers considered in the scope of
this rulemaking. (NEMA, No. 48 at p. 3)
An EEI survey of nine of its members
showed that an average of
approximately 65 percent of liquidimmersed transformers purchased are
already compliant with NEMA TP 1.
(EEI, No. 63 at pp. 7–19) NGrid now
purchases energy-efficient, liquidimmersed transformers that meet or
exceed NEMA’s TP 1 standard
throughout its service territory in
Massachusetts, Rhode Island, New
Hampshire, and New York. This is true
despite the fact that only Massachusetts
requires TP 1-compliant, liquidimmersed transformers. (NGrid, No. 80
at p. 1) Georgia Power expressed doubt
that the Department can accurately
account for the number of transformers
that are already purchased with NEMA
TP 1 efficiencies. (Georgia Power, No.
78 at pp. 1–2)
The Appliance Standards Awareness
Project (ASAP) and Northwest Power
and Conservation Council (NPCC)
commented that the base case should
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reflect the impact of State-established
transformer standards. (Public Meeting
Transcript, No. 56.12 at p. 248, Public
Meeting Transcript, No. 56.12 at pp.
180–181) ODOE commented that the
Department needs to pay careful
attention to those States that have TP 1
as an existing standard because, by the
time the DOE standard is published,
States mandating TP 1 could represent
a quarter to a third of transformer
shipments. (Public Meeting Transcript,
No. 56.12 at p. 185) NEMA said that, of
those States that have adopted TP 1,
most have done it for low-voltage, drytype distribution transformers, so the
other product classes would not be
affected. (Public Meeting Transcript, No.
56.12 at p. 182)
In response to these comments, the
Department obtained from NEMA new,
detailed data regarding TP 1 compliance
of shipped transformers. The
Department adjusted the parameters of
the customer choice model such that the
base case TP 1 compliance in the LCC
is consistent with the most recent
NEMA data available to the Department.
Southern Company and ODOE
requested that the Department provide
the efficiency rating for the base case.
(Public Meeting Transcript, No. 56.12 at
p. 215 and p. 217) ACEEE agreed, noting
that this information would enable
further independent analysis of the cost
and savings data. (ACEEE, No. 50 at p.
2 and No. 76 at p. 3) The Department
complied with this request and reported
the base case efficiencies for the ANOPR
analysis in Supplemental Appendix 8E
of the ANOPR TSD. These values have
been updated for the NOPR analysis,
and can be found in Appendix 8E of the
TSD.
2. Inputs Affecting Operating Costs
a. Transformer Loading
Transformer loading is an important
factor in determining which types of
transformer designs will deliver a
specified efficiency, and for calculating
transformer losses. Transformer losses
have two components: No-load losses
and load losses. No-load losses are
independent of the load on the
transformer, while load losses depend
approximately on the square of the
transformer loading. Because load losses
increase exponentially with loading,
there is a particular concern that, during
times of peak system load, load losses
can impact system capacity costs and
reliability. Details of the transformer
loading models are presented in TSD
Chapter 6.
For the ANOPR analysis, the
Department estimated the loading
characteristics of transformers by
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analyzing the statistics of available load
data, and by assuming a distribution of
initial annual peak loadings. ASE
commented that the Department’s
analysis of load profiles is largely
consistent with data provided by other
stakeholders. It also recognized that the
Department used publicly available data
for utility loads, and commented that
the average loadings for liquidimmersed transformers were reasonable.
(ASE, No. 52 at p. 3 and No. 75 at p.
3) ODOE agreed with the transformer
loads estimated by the Department
based on ODOE’s examination of
loading studies conducted in the Pacific
Northwest, which produced lower
loading levels than expected by many
analysts. (ODOE, No. 66 at p. 4)
HVOLT estimated that the average
loading for dry-type, medium-voltage
units is about 50 percent, with a
daytime average of 60 percent and a
nighttime average of 35 percent. (Public
Meeting Transcript, No. 56.12 at pp.
131–132) HVOLT estimated that loading
for liquid-immersed transformers is
about 50 percent, but noted that loads
in the residential sector can increase so
much that loading can exceed the
transformer nameplate rating. (Public
Meeting Transcript, No. 56.12 at p. 131
and p. 133) In a written comment,
HVOLT endorsed using loading
assumptions identical to those for
NEMA TP 1. HVOLT is not familiar
with any publicly released loading
studies that would alter the root mean
square (RMS)-equivalent load of 50
percent load for medium-voltage
transformers. (HVOLT, No. 65 at p. 3)
EEI estimated that, according to three
surveyed members, average loading
levels range from 30 percent to 58
percent. A survey of eight members
yielded a range of high-loading levels
from 45 to 100 percent, and a range of
low-loading levels from 35 to 75
percent. (EEI, No. 63 at pp. 7–19) TEC
said that it strives to load transformers
higher than the 50 percent level
assumed by DOE, and recommended
that the Department give consideration
to efficiency ratings at higher loading
levels. (TEC, No. 77 at p. 1)
The Department concluded that the
ANOPR statistical loading analysis was
largely consistent with stakeholder
comments, with slight adjustments
necessary for the loading levels of
medium-voltage, dry-type transformers
(see TSD Chapter 6, section 6.3.3.3). The
Department increased the loading on
medium-voltage, dry-type transformers
in response to the comments by HVOLT,
to be consistent with the relative
difference in loading levels used by
NEMA TP 1 between low-voltage and
medium-voltage dry-type transformers.
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On the issue of peak load
coincidence, the Department received
two comments. ASE agreed with the
Department’s peak load coincidence
analysis for the ANOPR. (ASE, No. 52 at
p. 3 and No. 75 at p. 3) The CDA
commented that peak coil losses may
have a high coincidence factor with
system peaks. (CDA, No. 51 at pp. 3–4)
The Department concluded that the
statistical model used for peak loading
in the ANOPR analysis was consistent
with stakeholder comments and did not
change peak loading statistics for the
NOPR analysis.
b. Load Growth
The LCC takes into account the
projected operating costs for
distribution transformers many years
into the future. This projection requires
an estimate of how, if at all, the
electrical load on transformers will
change over time. For dry-type
transformers, the Department assumed
no load growth. For liquid-immersed
transformers, the Department used as
the default scenario a one-percent-peryear load growth. It applied the load
growth factor to each transformer
beginning in 2010, the expected
effective date 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 liquidimmersed transformers, residential
consumption per household has
increased; for dry-types, commercial
and industrial loads grow over time
through more energy-intensive use of
floor space and plant expansion. (CDA,
No. 51 at pp. 1–2) ODOE stated that
DOE should select a growth rate 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 drytype and one percent for liquidimmersed transformers. However, to the
extent that building owners may defer
transformer upgrades because of high
unit costs, it noted that there may be
some load growth on older, less efficient
units. (NEMA, No. 48 at p. 2)
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
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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 liquidimmersed transformers, data showing
both growth in per-customer electrical
loads over time and increasing
transformer sizes purchased by utilities
support the Department’s approach (see
TSD Chapter 8).
Regarding another aspect of the issue
of load growth over time, 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
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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.
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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
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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
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to the analysis of the future economic
impacts of efficiency standards.
3. Inputs Affecting Present Value of
Annual Operating Cost Savings
a. Standards Implementation Date
The Department proposes that the
new energy-efficiency standard for
distribution transformers apply to all
units manufactured three years or more
after publication of the final rule. For
the NOPR analysis, the Department
assumed a 2007 final rule publication;
hence a 2010 implementation or
compliance date. The Department
calculated the LCC for customers as if
each new distribution transformer
purchase occurs in the year
manufacturers must comply with the
standard.
Several comments called for
acceleration of the rulemaking schedule.
ACEEE said the NOPR should be
published by July 2005 and the final
rule six months later. (ACEEE, No. 76 at
p. 4) The National Association of
Regulatory Utility Commissioners
(NARUC) urged DOE to establish a new
standard for distribution transformers as
soon as possible. (NARUC, No. 68 at pp.
2–5) NRDC asked DOE to make a
commitment to a schedule, with
appropriate milestones, that will allow
a final rule to be issued no later than
January 29, 2006. (NRDC, No. 61 at p.
3) ASE urged the Department to
maintain an 18-month schedule to
complete the rulemaking. (ASE, No. 52
at p. 1 and No. 75 at p. 1)
The Department understands that the
rulemaking schedule impacts the date
by which manufacturers of distribution
transformers must comply with any new
energy-efficiency standard. It is
committed to completing the
rulemaking in a timely fashion and
expects to publish a final rule by
September 2007.
b. Discount Rate
The discount rate is the rate at which
future expenditures are discounted to
estimate their present value. It is the
factor that determines the relative
weight of first costs and operating costs
in the LCC calculation. Consumers
experience discount rates in their dayto-day lives either as interest rates on
loans or as rates of return on
investments. Another characterization
of the discount rate is the ‘‘time value
of money.’’ The value of a dollar today
is one plus the discount rate times the
value of a dollar a year from now. The
Department estimated consumer
discount rates by calculating the
consumer cost of capital (see TSD
Chapter 8).
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Discount rates depend on who is
borrowing and at what scale. Thus, the
discount rates in the LCC analysis are
different than those in the national
impact analysis. This section discusses
consumer discount rates that the
Department used in the LCC analysis.
With respect to consumer discount
rates in the ANOPR, stakeholders
expressed a diversity of views regarding
which discount rates are appropriate for
the LCC analysis. ASE and ODOE
commented that the Department should
use a three-percent real discount rate,
similar to the discount rate used by the
California Energy Commission (CEC) in
recent State-level energy efficiency
analyses. (ASE, No. 75 at p. 3; ODOE,
No. 66 at p. 5) NRDC said that the
Department’s use of discount rates
exceeding 5.5 percent real conflicts with
the explicit instructions in NRDC v.
Herrington, because of the court’s
instruction to consider payback times of
less than nine years as economically
justified. (NRDC, No. 61 at p. 6) ACEEE
commented that the Department’s
choice of discount rates for utilities was
appropriate. (ACEEE, No. 76 at p. 3)
HVOLT recommended that the
Department set efficiency standards on
a three-to five-year consumer
investment return, to represent
commercial customer preferences.
(HVOLT, No. 65 at p. 3)
The Department examined each of
these comments to see if any would lead
to a more accurate description of
consumer economic impacts. In
examining the three-percent discount
rate recommended by ASE and ODOE,
the Department found that the CEC, in
its rulemaking, estimated the consumer
cost of capital using a method similar to
that of the Department. However, the
CEC analyzed a different class of
consumers and used less detailed data.
Therefore, the Department considers its
discount rates to be more accurate for
the distribution transformer energyefficiency analysis than the discount
rates estimated by the CEC for other
products. The Department retained the
consumer discount rates that it used in
the ANOPR analysis, as shown in Table
IV.3. The consumer discount rates
shown in the table are based on a
detailed analysis of risk-adjusted cost of
capital for consumers, as described in
TSD Chapter 8.
TABLE IV.3.—WEIGHTED-AVERAGE DISCOUNT RATES BY DESIGN LINE AND OWNERSHIP CATEGORY
Transformer ownership category
Property
owners
Mean real discount rate ...........................
Design line
4.35%
7.55%
4.24
4.24
4.40
4.24
5.38
6.56
6.56
6.56
6.56
6.56
0.4
0.4
2.1
0.4
9.5
19.0
19.0
19.0
19.0
19.0
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
22:31 Aug 03, 2006
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Investorowned utilities
Publicly owned
utilities
4.16%
4.31%
3.33%
26.0
26.0
10.0
26.0
15.0
0.0
0.0
0.0
0.0
0.0
0.2
0.2
1.0
0.2
4.0
7.9
7.9
7.9
7.9
7.9
7.46%
Government
offices
Estimated ownership (%)
4. Candidate Standard Levels
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Commercial
companies
Weighted
average
discount rate
(%)
1 ...................................
2 ...................................
3 ...................................
4 ...................................
5 ...................................
9 ...................................
10 .................................
11 .................................
12 .................................
13 .................................
VerDate Aug<31>2005
Industrial
companies
0.5
0.5
2.4
0.5
9.5
19.0
19.0
19.0
19.0
19.0
0.9
0.9
4.5
0.9
27.0
54.0
54.0
54.0
54.0
54.0
point, when compared to TP 1, varies
significantly among design lines.
(ACEEE, No. 76 at p. 1) ACEEE said that
DOE should regroup the CSLs so that
CSL 1 is TP 1, CSL 3 is the minimum
life-cycle cost point, and CSLs 2 and 4
are slightly above and below the
minimum LCC. (ACEEE, No. 50 at p. 1
and No. 76 at p. 2) ACEEE suggested
that DOE realign the CSLs so that they
have approximately equivalent
economic performance. (Public Meeting
Transcript, No. 56.12 at p. 26) 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)
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72.0
72.0
80.0
72.0
35.0
0.0
0.0
0.0
0.0
0.0
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
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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
⁄ of diff. between TP
1 and min LCC
13
Design line
TP 1+
%
1 ........................
2 ........................
3 ........................
4 ........................
5 ........................
9 ........................
10 ......................
11 ......................
12 ......................
13 ......................
Effic’y
%
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TP 1+
%
98.9
98.7
99.3
98.9
99.3
98.6
99.1
98.5
99.0
99.0
3
⁄ of diff. between TP
1 and min LCC
Effic’y
%
0.14
0.03
0.08
0.18
0.06
0.22
0.12
0.17
0.12
0.15
TP 1+
%
99.04
98.73
99.38
99.08
99.36
98.82
99.22
98.67
99.12
99.15
5. Trial Standard Levels
4
Min LCC
23
Effic’y
%
0.29
0.06
0.16
0.36
0.12
0.44
0.23
0.34
0.23
0.30
TP 1+
%
99.19
98.76
99.46
99.26
99.42
99.04
99.33
98.84
99.23
99.30
Effic’y
%
0.43
0.09
0.24
0.55
0.17
0.66
0.35
0.51
0.35
0.45
TP 1+
%
99.33
98.79
99.54
99.45
99.47
99.26
99.45
99.01
99.35
99.45
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
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
5
Max energy savings
with no change in
LCC
6
Max energy savings
Effic’y
%
0.59
0.26
0.44
0.68
0.41
0.81
0.41
0.59
0.40
0.55
TP 1+
%
99.49
98.96
99.74
99.58
99.71
99.41
99.51
99.09
99.40
99.55
Effic’y
%
0.69
0.76
0.45
0.71
0.41
0.81
0.41
0.59
0.40
0.55
99.59
99.46
99.75
99.61
99.71
99.41
99.51
99.09
99.40
99.55
(Chapters 8 and 11), the Department
reports results in terms of CSLs. In
subsequent analyses (e.g., shipments in
Chapter 9, national impacts in Chapter
10, MIA in Chapter 12) and in this
NOPR, the Department reports all
results in terms of TSLs, mapping the
LCC results according to Table IV.5.
TABLE IV.5.—MAPPING OF THE CANDIDATE STANDARD LEVELS TO TRIAL STANDARD LEVELS
DL1
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TSL1
TSL2
TSL3
TSL4
TSL5
TSL6
.........
.........
.........
.........
.........
.........
CSL1
CSL1
CSL1
CSL2
CSL3
CSL6
.......
.......
.......
.......
.......
.......
DL2
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
.......
.......
.......
.......
.......
.......
DL3
CSL1
CSL2
CSL3
CSL4
CSL5
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)
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22:31 Aug 03, 2006
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DL4
.......
.......
.......
.......
.......
.......
CSL1
CSL2
CSL3
CSL3
CSL5
CSL6
DL5
.......
.......
.......
.......
.......
.......
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
.......
.......
.......
.......
.......
.......
DL9
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
.......
.......
.......
.......
.......
.......
DL10
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
The Department provides this
information in TSD Chapter 8.
6. Miscellaneous Life-Cycle Cost Issues
In response to the ANOPR analysis,
DOE examined several additional issues
relating to the LCC. These issues are
grouped for organizational clarity and
completeness, and are discussed below.
a. Tax Impacts
The Department did not include the
impact of income taxes in the LCC
analysis for the ANOPR. The
Department understands that there are
two ways in which taxes affect the net
impacts attributed to purchasing
equipment that is more energy-efficient
than baseline equipment: (1) Energyefficient equipment typically costs more
to purchase than baseline equipment,
which lowers net income and may
lower company taxes; and (2) moreefficient equipment typically costs less
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.......
.......
.......
.......
.......
.......
DL11
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
.......
.......
.......
.......
.......
.......
DL12
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
.......
.......
.......
.......
.......
.......
DL13
CSL1
CSL2
CSL3
CSL4
CSL5
CSL6
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
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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
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22:31 Aug 03, 2006
Jkt 208001
they cannot recover the additional costs
associated with more-efficient
transformers, but this will not be a
problem because utility regulation
throughout the country allows the
distribution utility to achieve a
regulated rate of return on all reasonable
and prudent investment. NRDC noted
that some utilities may find today’s
investments in high-efficiency
transformers to be economically
troublesome because they are subject to
rate caps, but these rate caps all expire
before the transformer efficiency
standard would go into effect. New rate
cases would then result in a new rate
structure consistent with the standardscompliant transformer investments.
(NRDC, No. 61 at pp. 7–8) ASE looked
into the issue of rate caps and found
that about 41 percent of electricity sales
are in States with restructured
electricity rate regulations, with about
27 percent of sales subject to rate caps,
but that these caps expire steadily from
2005 to 2010. (ASE, No. 52 at p. 4)
Georgia Power also asserted that utility
companies cannot raise their prices to
make up for the expected rise in
transformer prices that will result from
higher efficiency requirements without
proceeding through the regulatory
process. It stated, therefore, that DOE
needs to weigh the financial burden this
rulemaking may place on electric
utilities before issuing a final rule.
(Georgia Power, No. 78 at p. 4) NEMA
also expressed concern that the entity
paying the additional capital cost for a
more energy-efficient transformer would
frequently not be the beneficiary of the
resultant energy cost savings. (NEMA,
No. 48 at p. 1)
The concern expressed by
stakeholders regarding the potential lack
of cost recovery for distribution
transformer investments is a classic
example of ‘‘split incentives’’ for
efficiency investments. A split incentive
occurs when the entity that makes an
investment is different from the entity
that will receive the economic benefits
of the investment. Split incentives
prevent economically viable
investments because, without receiving
the benefits of an investment, the
investor loses motivation to make
investments that otherwise might have
good returns. If the Department were to
model split incentives in the LCC
analysis, it would need to divide
ownership of first costs and operating
cost savings for a fraction of the
transformers in the analysis. If the cost
of capital were the same for the owner
of the transformer and the owner of the
operating cost savings, then the average
LCC savings result would actually
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44379
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
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savings associated with, higherefficiency transformers are not
applicable to every utility in the Nation.
It noted that each utility is different and
there are too many variables that cannot
be accurately accounted for in such
calculations. (Georgia Power, No. 78 at
pp. 1–2) For the liquid-immersed design
lines (1–5), Georgia Power analyzed the
percentage change in price and TOC for
several kVA sizes for each of the CSLs
beyond TP 1. It found that, for all these
cases, the TOC actually increased in
contrast to the decrease in LCC found by
the Department, indicating that the
savings in energy do not economically
justify the increase in first cost. (Georgia
Power, No. 78 at pp. 4–5)
The Department recognizes that the
TOC approach used by utilities can
yield results that are substantially
different from the Department’s LCC
analysis. The standard TOC approach
used by electric utilities is typically
calculated according to the regulatory
mandates of cost recovery rate
regulation. For cost recovery, the annual
expenses associated with an investment
in equipment need to be increased (or
marked up) to generate revenue for
those utility costs that may not be
directly related to the equipment
investments but still need to be
recovered (i.e., operation and
maintenance expenses). This is
formulated in terms of a fixed charge
rate (FCR), which is used to calculate
the annual revenue required to cover the
expenses of a capital investment such
that a utility can stay in business. The
FCR used by utilities is generally larger
than the revenues required to cover just
the cost of capital. In the LCC analysis,
DOE only accounted for the capital and
investment expenses that are directly
related to the purchase of the equipment
being analyzed. The factor that
represents the annual expenses required
to recover capital costs is called the
capital recovery factor (CRF) and is
generally less than the FCR. The
Department therefore recognizes that
investments in efficiency that are
economically justified under EPCA, as
amended, may not be economically
justified with respect to utility TOC
evaluations that are performed under
the assumptions of utility rate-setting
regulation.
D. National Impact Analysis—National
Energy Savings and Net Present Value
Analysis
The national impact analysis
evaluates the impact of a proposed
standard from a national perspective
rather than from the consumer
perspective represented by the LCC.
When it evaluates a proposed standard
from a national perspective, the
Department must consider several other
factors that are not included in the LCC
analysis. One of the primary factors the
Department modeled in the national
impact analysis was the gradual
replacement of existing, less-efficient
transformers with more-efficient,
standard-compliant transformers over
time. This rate of replacement was
estimated by an equipment shipments
model that describes the sale of
transformers for replacement and for
inclusion in new electrical distribution
system infrastructure. A second major
factor included in the national impact
analysis was the fact that the national
cost of capital may differ from the
consumer cost of capital, and thus the
discount rate used in the national
impact analysis can be different from
that used in the LCC. The third factor
the Department included in the national
impact analysis was the difference
between the energy savings obtained by
the consumer and the energy savings
obtained by the Nation. Because of the
effect of distribution and generation
losses, the national energy savings from
a proposed standard are larger than the
sum of the individual consumers’
energy savings. The details of the
Department’s national impact analysis
are provided in Chapters 9 and 10 of the
TSD.
During the ANOPR review, the
Department received stakeholder
comments on its approach to two of
these three major factors. While it did
not receive comments indicating any
stakeholder disagreement with its
accounting of national versus consumer
energy savings, the Department did
receive stakeholder comments
concerning its shipments model and
national discount rates.
Regarding DOE’s shipments model,
HVOLT commented that DOE considers
the dry-type transformer market to have
inelastic pricing, but that it actually is
quite elastic and DOE should
incorporate a price response that allows
a shift to liquid-immersed transformers.
(Public Meeting Transcript, No. 56.12 at
pp. 173–174) NEMA agreed that drytype transformers have price elasticity
of demand, since deferring or foregoing
investments may be a viable alternative
for some customers. (NEMA, No. 48 at
p. 1)
The Department agrees with HVOLT
and NEMA that the sales of dry-type
transformers are likely to be elastic.
Since detailed shipments data that can
be used for elasticity estimates are not
available for dry-type transformers, the
Department estimated elasticities using
data from an economically similar
commercial appliance—commercial air
conditioners. Both commercial air
conditioners and distribution
transformers are integral elements of
building and facilities electromechanical design and construction,
and are installed during building
construction and rehabilitation. The
shipments elasticity scenarios the
Department examined are provided in
Table IV.6, and are explained in more
detail in TSD Chapter 9.
TABLE IV.6.—SUMMARY OF SHIPMENTS MODEL INPUTS
Input
ANOPR description
Changes for NOPR
Shipments data ................
Shipments backcast ........
Third-party expert (HVOLT) for the year 2001 ................................................
For years 1977–2000, used Bureau of Economic Analysis’ (BEA) manufacturing data for distribution transformers. Source: https://www.bea.doc.gov/
bea/pn/ndn0304.zip.
For years 1950–1976, used EIA’s electricity sales data. Source: https://
www.eia.doe.gov/emeu/aer/txt/stb0805.xls.
Years 2002–2035: Based on AEO2003 ..........................................................
No change.
Added three more years of BEA’s
manufacturing data—for years 2001
through 2003.
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Shipments forecast ..........
Dry-type/liquid-immersed
market shares.
Regular replacement market.
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Based on EIA’s electricity sales data and AEO2003 ......................................
Based on a survival function constructed from a Weibull distribution function
normalized to produce a 32-year mean lifetime. Source: ORNL 6804/R1,
The Feasibility of Replacing or Upgrading Utility Distribution Transformers
During Routine Maintenance, page D–1.
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Years
2010–2038:
Based
on
AEO2005.
Based on EIA’s electricity sales data
and AEO2005.
No change.
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TABLE IV.6.—SUMMARY OF SHIPMENTS MODEL INPUTS—Continued
Input
Elasticities ........................
ANOPR description
For
•
•
•
For
•
Changes for NOPR
liquid-immersed transformers:
Low: 0.00 ..................................................................................................
Medium: ¥0.04 ........................................................................................
High: ¥0.20 ..............................................................................................
dry-type transformers:
0.00 ...........................................................................................................
A summary of the NES and NPV
analytical model inputs are provided in
Table IV.7. More detailed discussion on
For liquid-immersed transformers:
No change.
For
•
•
•
dry-type transformers:
Low: 0.00
Medium: ¥0.02
High: ¥0.20
these inputs can be found in TSD
Chapter 10.
TABLE IV. 7.—SUMMARY OF NES AND NPV MODEL INPUTS
Input
ANOPR description
Shipments ........................
Implementation date of
standard.
Base case efficiencies .....
Annual shipments from shipments model ........................................................
Assumed to be 2007 ........................................................................................
No change.
Assumed to be 2010.
Constant efficiency through 2035. Equal to weighted-average efficiency in
2007.
Standards case efficiencies.
Constant efficiency at the specified standard level from 2007 to 2035 ..........
Annual energy consumption per unit.
Average rated transformer losses are obtained from the LCC analysis, and
are then scaled for different size categories, weighted by size market
share, and adjusted for transformer loading (also obtained from the LCC
analysis).
Weighted-average values as a function of efficiency level (from LCC analysis).
Energy and capacity savings for the two types of transformer losses are
each multiplied by the corresponding average marginal costs for capacity
and energy, respectively, for the two types of losses (marginal costs are
from the LCC analysis).
AEO2003 forecasts (to 2025) and extrapolation for 2035 and beyond ..........
Constant efficiency through 2038.
Equal to weighted-average efficiency in 2010.
Constant at the efficiency at the specified standard level from 2010 to
2038.
No change.
Total installed cost per
unit.
Electricity expense per
unit.
Escalation of electricity
prices.
Electricity site-to-source
conversion.
Discount rates ..................
Analysis year ...................
A time series conversion factor; includes electric generation, transmission,
and distribution losses. Conversion varies yearly and is generated by
DOE/EIA’s National Energy Modeling System (NEMS) program.
3% and 7% real ...............................................................................................
Equipment and operating costs are discounted to the year of equipment
price data, 2001.
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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.
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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
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No change.
No change.
Used AEO2005 forecasts (to 2025)
and extrapolation for 2038 and beyond.
Updated conversion factors from
NEMS.
No change.
Equipment and operating costs are
discounted to year 2004.
evaluated separately. (Public Meeting
Transcript, No. 56.12 at p. 211) In its
commercial consumer subgroup
analysis, the Department analyzed
municipal utilities and rural electric
cooperatives separately, including
additional data from cooperatives that
serve sparsely populated areas with long
radial distribution lines.
The results of the Department’s
commercial consumer subgroup
analysis are summarized in section
V.A.1.c below and described in detail in
TSD Chapter 11.
F. Manufacturer Impact Analysis
1. General Description
The Department performed an MIA to
estimate the financial impact of higher
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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
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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.
3. Industry Cash-Flow Analysis
2. Industry Profile
An energy conservation standard can
affect a manufacturer’s cash flow in
three distinct ways: (1) It may require
increased investment; (2) it may result
in higher production costs per unit; and
(3) it may alter revenue by virtue of
higher per-unit prices and changes in
sales volumes. As mentioned, the
Department uses the GRIM to quantify
the changes in cash flow that result in
a higher or lower industry value. The
GRIM analysis for this NOPR used a
number of inputs—annual shipments;
prices; material, labor, and overhead
costs; SG&A expenses; taxes; and capital
expenditures—to arrive at a series of
annual net cash flows beginning in 2004
and continuing to 2038. The Department
collected this information from a
number of sources, including publicly
available data; structured, detailed
interviews with six manufacturers; and
short telephone interviews with an
additional four small manufacturers.
The Department calculated INPV by
discounting and summing the annual
net cash flows. Chapter 12 of the TSD
contains additional information about
the GRIM analysis.
For the MIA, the Department
considered two distinct markup
scenarios: (1) The preservation-of-grossmargin-percentage scenario, and (2) the
preservation-of-operating-profit
scenario. Under the ‘‘preservation-ofgross-margin-percentage’’ scenario, DOE
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.
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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
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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
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equipment suppliers to the distribution
transformer industry.
EMSIC commented that investments
will not cause a significant impact on
manufacturers of liquid-immersed
transformers if the energy conservation
standard is set below a certain
threshold. EMSIC asserted that liquidimmersed transformers can be made
more efficient primarily by using better
materials, without the need for
significant investment. (EMSIC, No. 73
at p. 2) The Department concurs that
conversion capital expenditures would
be relatively modest for TSLs 1 through
4, which are the trial standard levels
that would not involve partial or full
conversion to amorphous core
technology. TSLs 5 and 6 would require
partial and full conversion to
amorphous core technology,
respectively, and the conversion capital
expenditures necessary at these TSLs
would be significant.
EMSIC commented that an energy
conservation standard would positively
affect liquid-immersed transformer
manufacturer revenue (through higher
prices), while also limiting product
diversity and thereby dampening the
cost increases at higher efficiencies.
EMSIC suggested that one mechanism
by which an energy conservation
standard would limit product diversity
would be the elimination of lower-grade
materials. (EMSIC, No. 73 at p. 2) In the
GRIM analysis, the Department
explicitly considered the positive
impact of standards on manufacturer
revenue. While the Department
recognizes that production cost
increases in moving to higher TSLs
could be dampened by limited product
diversity, the Department believes that
this effect will be small compared to the
other effects explicitly considered in its
analysis.
The final MIA-related comment
received by the Department pertained to
the Nation’s import tariff on raw core
steel. ZDMH is a mechanically scribed,
deep-domain refined, core steel that
survives the annealing process without
negatively impacting the low loss
properties of the steel. Since ZDMH core
steel is available from only one foreign
country, U.S. transformer manufacturers
would have to purchase ZDMH subject
to this tariff. This would give foreign
transformer manufacturers that do not
impose this tariff (e.g., in Mexico) an
advantage in producing transformers
using ZDMH core steel, since finished
cores or transformers would not be
subject to the tariff. ERMCO asked the
Department to keep this issue in mind
when choosing the standard, to avoid
putting domestic manufacturers at a
disadvantage. (ERMCO, No. 58 at p. 2)
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The Department addressed the ZDMH
issue in its engineering analysis by
modeling Mexican-made transformers,
because this would be the expected
production scenario for ZDMH
transformers. Since, according to the
Department’s analysis, ZDMH design
option combinations would not be the
most cost-effective at any trial standard
level, DOE did not explicitly address the
impact of the U.S. core steel tariff on
transformer manufacturing capacity in
the MIA. To review the costeffectiveness findings of ZDMH in
comparison to other transformer core
steels, see TSD Chapter 5.
G. Employment Impact Analysis
The Process Rule includes
employment impacts among the factors
that DOE considers in selecting a
proposed standard. Employment
impacts include direct and indirect
impacts. Direct employment impacts are
any changes in the number of
employees for distribution transformer
manufacturers, their suppliers, and
related service firms. Indirect impacts
are those changes of employment in the
larger economy that occur due to the
shift in expenditures and capital
investment that is caused by the
purchase and operation of more efficient
transformer equipment. The MIA
addresses direct employment impacts;
this section describes indirect impacts.
Indirect employment impacts from
distribution transformer standards
consist of the net jobs created or
eliminated in the national economy,
other than in the manufacturing sector
being regulated, as a consequence of: (1)
Reduced spending by end users on
energy (electricity, gas—including
liquefied petroleum gas—and oil); (2)
reduced spending on new energy supply
by the utility industry; (3) increased
spending on the purchase price of new
distribution transformers; and (4) the
effects of those three factors throughout
the economy. The Department expects
the net monetary savings from standards
to be redirected to other forms of
economic activity. The Department also
expects these shifts in spending and
economic activity to affect the demand
for labor.
In developing this proposed rule, the
Department estimated indirect national
employment impacts using an input/
output model of the U.S. economy,
called IMBUILD (impact of building
energy efficiency programs). The
Department’s Office of Building
Technology, State, and Community
Programs (now the Building
Technologies Program) developed the
model. IMBUILD is a personalcomputer-based, economic-analysis
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model that characterizes the
interconnections among 35 sectors of
the economy as national input/output
structural matrices, using data from the
U.S. Bureau of Labor Statistics. The
IMBUILD model estimates changes in
employment, industry output, and wage
income in the overall U.S. economy
resulting from changes in expenditures
in the various sectors of the economy.
The Department estimated changes in
expenditures using the NES
spreadsheet. IMBUILD then estimated
the net national indirect employment
impacts of potential distribution
transformer efficiency standards on
employment by sector.
While both the IMBUILD input/
output model and the direct use of BLS
employment data suggest the proposed
distribution transformer standards could
increase the net demand for labor in the
economy, the gains would most likely
be very small relative to total national
employment. The Department therefore
concludes only that the proposed
distribution transformer standards are
likely to produce employment benefits
that are sufficient to offset fully any
adverse impacts on employment in the
distribution transformer or energy
industries.
For more details on the employment
impact analysis, see TSD Chapter 14.
The Department did not receive
stakeholder comments on these indirect
employment impact methods, which it
proposed in the ANOPR for use in the
NOPR analysis.
H. Utility Impact Analysis
The proposed distribution transformer
energy-efficiency standards have the
distinct feature of regulating a product
that also has electric utilities as one of
the major product consumers. The
Department therefore analyzed one
portion of the impacts on utilities from
the consumer perspective and another
portion of impacts from the utility
sector perspective. Those impacts that
the Department analyzed in the utility
impact analysis are from the utility
sector perspective and include the
impacts on the number of power plants
constructed and the fuel consumption of
the sector. Financial impacts on the
utility sector are described in the LCC
analysis.
The Department analyzed the effects
of proposed standards on electric utility
industry generation capacity and fuel
consumption using a variant of the
EIA’s National Energy Modeling System
(NEMS).3 NEMS, which is available in
3 For more information on NEMS, please refer to
the U.S. Department of Energy, Energy Information
Administration documentation. A useful summary
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the public domain, is a large, multisectoral, partial-equilibrium model of
the U.S. energy sector. The EIA uses
NEMS to produce its Annual Energy
Outlook—a widely recognized baseline
energy forecast for the U.S. The
Department used a variant known as
NEMS–BT.4
The Department conducted the utility
analysis as policy deviations from the
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
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.
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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.
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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 $1,382.00.
TABLE V.1.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.2 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 2, a
25 kVA, liquid-immersed, single-phase,
pole-mounted distribution transformer.
For this unit, the average efficiency of
2
98.9
4.9
65.2
29.9
93
11.4
3
98.9
4.9
65.2
29.9
93
11.4
4
98.9
4.9
65.2
29.9
93
11.4
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
5
99.04
16.6
50.9
32.5
98
21.9
6
99.19
52.8
14.7
32.5
5
36.0
99.59
90.5
0.0
9.5
¥688
45.0
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, and taxes)
was $737.00.
TABLE V.2.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 1 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.3 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 3, a
500 kVA, liquid-immersed, single-phase
distribution transformer. For this unit,
the average efficiency of the baseline
2
98.7
1.4
66.6
32.0
69
4.8
3
98.73
3.0
64.3
32.7
70
6.8
4
98.76
5.2
60.8
34.0
72
8.8
5
98.79
8.6
56.3
35.1
71
12.0
6
98.96
43.9
25.4
30.7
7
31.7
99.46
98.9
0.0
1.1
¥953
66.6
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, and taxes)
was $5,428.00.
transformers selected during the LCC
analysis was 99.36 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 99.07 percent, and the
consumer equipment cost before
gechino on PROD1PC61 with PROPOSALS
TABLE V.3.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
TABLE V.3.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 3 REPRESENTATIVE UNIT—Continued
Trial standard level
1
TP 1
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.4 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 4, a
150 kVA, liquid-immersed, three-phase
distribution transformer. For this unit,
the average efficiency of the baseline
73.7
26.1
1,746
1.4
2
3
65.2
33.4
2,267
4.3
4
49.5
44.4
2,775
10.4
5
4.0
56.1
2,876
19.8
6
0.1
33.6
627
29.3
0.0
29.2
¥410
32.3
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, and taxes)
was $3,335.00.
transformers selected during the LCC
analysis was 98.91 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 98.42 percent, and the
consumer equipment cost before
TABLE V.4.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 4 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.5 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 5, a
1500 kVA, liquid-immersed, three-phase
distribution transformer. For this unit,
the average efficiency of the baseline
98.9
3.3
63.7
33.0
556
8.5
2
3
4
99.08
16.8
40.8
42.4
629
18.1
99.26
41.0
11.3
47.7
450
21.5
99.26
41.0
11.3
47.7
450
21.5
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
5
6
99.58
64.4
0.8
34.8
56
29.2
99.61
75.5
0.0
25.5
¥572
34.9
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, and taxes)
was $11,931.00.
TABLE V.5.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 5 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.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
99.3
0.3
71.7
28.0
3,957
3.4
2
3
99.36
1.5
62.8
35.7
5,463
6.1
4
99.42
10.2
40.0
49.8
6,504
12.7
5
99.47
15.9
24.2
59.9
7,089
14.1
6
99.71
57.1
0.0
42.9
4,431
25.6
99.71
57.2
0.1
42.7
3,902
26.1
consumer equipment cost before
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, contractor
markup, and taxes) was $7,510.00.
average efficiency of the baseline
transformers selected during the LCC
analysis was 98.77 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 98.41 percent, and the
gechino on PROD1PC61 with PROPOSALS
TABLE V.6.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
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55.0
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
TABLE V.6.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 9 REPRESENTATIVE UNIT—Continued
Trial standard level
1
TP 1
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.7 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 10,
a 1500 kVA, medium-voltage, dry-type,
three-phase distribution transformer
with a 45 kV BIL. For this unit, the
57.8
41.6
988
1.5
2
3
46.3
52.6
1,968
2.4
4
29.7
65.0
3,103
5.4
5
0.5
73.8
3,532
12.4
6
0.0
43.7
1,181
21.7
0.0
45.0
1,274
21.5
consumer equipment cost before
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, contractor
markup, and taxes) was $33,584.00.
average efficiency of the baseline
transformers selected during the LCC
analysis was 99.17 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 98.79 percent, and the
TABLE V.7.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 10 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.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
99.1
4.4
63.3
32.3
4,041
7.7
2
3
99.20
5.1
56.9
37.6
5,227
8.3
4
99.30
8.9
44.4
46.7
6,818
10.0
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
5
99.39
21.0
23.2
55.8
7,699
13.4
6
99.51
66.3
0.0
33.7
1,279
28.7
99.51
66.2
0.0
33.8
1,124
29.4
consumer equipment cost before
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, contractor
markup, and taxes) was $10,945.00.
TABLE V.8.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 11 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings Period ($) .........................................
Mean Payback (years) .....................................................
Table V.9 presents the summary of the
LCC and PBP analysis for the
representative unit from design line 12,
a 1500 kVA, medium-voltage, dry-type,
three-phase distribution transformer
with a 95 kV BIL. For this unit, the
98.5
2.4
42.5
55.1
2,491
3.8
2
3
98.67
3.9
34.6
61.5
3,621
4.9
4
98.84
9.8
18.7
71.5
4,313
7.9
5
99.01
22.0
2.3
75.7
4,845
11.8
6
99.09
34.2
0.0
66.8
4,186
15.1
99.09
33.2
0.0
66.8
4,289
14.8
consumer equipment cost before
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, contractor
markup, and taxes) was $33,590.00.
average efficiency of the baseline
transformers selected during the LCC
analysis was 99.18 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 98.81 percent, and the
gechino on PROD1PC61 with PROPOSALS
TABLE V.9.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
TABLE V.9.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 12 REPRESENTATIVE UNIT—Continued
Trial standard level
1
TP 1
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
Table V.10 presents the summary of
the LCC and PBP analysis for the
representative unit from design line 13,
a 2000 kVA, medium-voltage, dry-type,
three-phase distribution transformer
with a 125 kV BIL. For this unit, the
75.1
23.5
2,600
4.6
2
3
71.9
26.6
3,973
4.7
4
56.9
37.3
5,485
8.3
28.2
53.6
6,812
12.7
5
0.0
29.4
¥650
29.3
6
0.0
29.9
¥655
29.3
consumer equipment cost before
installation (which includes
manufacturer selling price, shipping
costs, distributor markup, contractor
markup, and taxes) was $41,873.00.
average efficiency of the baseline
transformers selected during the LCC
analysis was 99.26 percent, the
minimum efficiency of the baseline
transformers selected during the LCC
analysis was 98.97 percent, and the
TABLE V.10.—SUMMARY LCC AND PBP RESULTS FOR DESIGN LINE 13 REPRESENTATIVE UNIT
Trial standard level
1
TP 1
Efficiency (%) ...................................................................
Transformers with Net LCC Increase (%) .......................
Transformers with No Change in LCC (%) .....................
Transformers with Net LCC Savings (%) ........................
Mean LCC Savings ($) ....................................................
Mean Payback Period (years) .........................................
gechino on PROD1PC61 with PROPOSALS
b. Rebuttable-Presumption Payback
As set forth in section 325(o)(2)(B)(iii)
of EPCA, 42 U.S.C. 6295(o)(2)(B)(iii),
there is a rebuttable presumption that an
energy conservation standard is
economically justified if the increased
installed cost for a product that meets
the standard is less than three times the
value of the first-year energy savings
resulting from the standard. However,
while the Department examined the
rebuttable-presumption criteria, the
Department determined economic
justification for the proposed standard
levels through a more detailed analysis
of the economic impacts of increased
efficiency pursuant to section
325(o)(2)(B)(i) of EPCA. (42 U.S.C.
6295(o)(2)(B)(i))
The Department calculated a
rebuttable-presumption payback period
for each trial standard level, to
determine if DOE could presume that a
standard at that level is economically
justified. Rather than using distributions
for input values, DOE used discrete
values and based the calculation on the
DOE distribution-transformer-testprocedure assumptions. As a result, the
Department calculated a single
rebuttable-presumption payback value
for each standard level, and not a
distribution of payback periods.
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76.0
20.2
662
9.7
2
3
99.15
1.5
72.9
25.6
3,125
5.8
99.30
4.4
58.9
36.7
5,430
8.0
To evaluate the rebuttable
presumption, the Department estimated
the additional cost of purchasing a more
efficient, standard-compliant product,
and compared this cost to the value of
the energy savings during the first year
of operation of the product as
determined by the applicable test
procedure. The Department interpreted
the increased cost of purchasing a
standard-compliant product to include
the cost of installing the product for use
by the purchaser. The Department then
calculated the rebuttable-presumption
payback period, or the ratio of the value
of the first year’s energy savings to the
increase in purchase price. When the
rebuttable-presumption payback period
is less than three years, the rebuttable
presumption is satisfied; when the
payback period is equal to or more than
three years, the rebuttable presumption
is not satisfied.
The rebuttable-presumption payback
period may differ from payback periods
presented in other parts of this NOPR in
at least two important ways:
• The rebuttable-presumption
payback period uses test procedure
loading levels to evaluate losses, rather
than the Department’s estimate of inservice loading conditions.
• Other payback periods may
consider total operating costs, whereas
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5.4
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6,435
19.5
5
6
99.55
75.7
0.0
24.3
¥5,303
32.5
99.55
75.7
0.0
24.3
¥5,218
32.4
the rebuttable-presumption payback
period considers only the value of
energy savings. In the case of
distribution transformers, however, the
Department estimates that the change in
operating costs is solely due to energy
savings.
There are three key inputs into the
rebuttable-presumption payback
calculation: (1) The average efficiency;
(2) the average installed cost; and (3) the
cost of electricity. Given the average
efficiency of the baseline and standardcompliant transformers, the Department
calculated the energy savings by taking
the difference in the annual losses
between the baseline and standardcompliant transformers, assuming the
loading conditions from the test
procedure. Multiplying the energy
savings times the cost of electricity
provided the value of the energy
savings. Dividing the value of the energy
savings into the installed-cost increase
for a standard-compliant transformer
provided the estimate of the rebuttablepresumption payback period. More
detailed discussion on the rebuttable
presumption is contained in TSD
Chapter 8, section 8.7.
Table V.11 shows the rebuttablepresumption payback period as a
function of design line and standard
level.
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TABLE V.11.—REBUTTABLE-PRESUMPTION PAYBACK IN YEARS
Rated
capacity
kVA
Design line
1 .............................................................................
2 .............................................................................
3 .............................................................................
4 .............................................................................
5 .............................................................................
9 .............................................................................
10 ...........................................................................
11 ...........................................................................
12 ...........................................................................
13 ...........................................................................
c. Commercial Consumer Subgroup
Analysis
In analyzing the potential impacts of
new or amended standards, the
Department evaluates impacts on
identifiable groups (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.
TSL1
(TP 1)
50
25
500
150
1,500
300
1,500
300
1,500
2,000
TSL2
7.0
2.1
0.5
3.9
2.6
0.7
3.2
2.0
2.3
5.0
7.0
3.6
2.2
7.4
4.5
1.3
3.8
2.6
2.5
3.3
The Department’s analysis indicated
that, for municipal utilities, the
economics are similar to those of the
national sample of utilities, but found
significant differences in the results for
rural cooperatives. Rural cooperatives
have lower transformer loading levels
than the average utility, and so their
operating cost savings from higher
standards would be smaller than those
for the average utility. Chapter 11 of the
TSD explains the Department’s method
for conducting the consumer subgroup
analysis and presents the detailed
results of that analysis.
Table V.12 shows the fraction of
transformers that are impacted by
TSL3
TSL4
7.0
4.3
5.1
12.0
6.5
2.5
4.8
3.8
3.3
4.1
10.1
5.2
9.7
12.0
9.0
5.6
6.1
5.3
5.3
8.2
TSL5
TSL6
16.0
15.2
22.7
17.2
20.0
11.3
12.4
7.0
13.6
16.7
27.2
42.4
25.1
20.7
20.0
11.3
12.4
7.0
13.6
16.7
different standard levels for the two
commercial consumer subgroups. A
transformer is impacted by a standard if
the transformer design has to change in
order to meet the performance
requirements of the standard. Table
V.13 shows the mean LCC savings from
proposed energy-efficiency standards,
and Table V.14 shows the mean payback
period (in years) for the two commercial
subgroups. Only the liquid-immersed
design lines are included in this
analysis since those types dominate the
transformers purchased by electric
utilities.
TABLE V.12.—FRACTION OF TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS IMPACTED BY
ENERGY-EFFICIENCY STANDARDS
[Percent]
TSL1
(TP 1)
Design line
TSL2
TSL3
TSL4
TSL5
TSL6
Municipal Utility Subgroup
1
2
3
4
5
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
35.3
33.9
26.1
35.9
27.9
35.3
34.7
35.2
60.2
36.0
35.3
39.3
50.4
88.3
59.1
48.6
44.1
96.0
88.3
75.6
84.8
74.9
99.9
99.2
99.9
100.0
100.0
100.0
100.0
99.9
88.7
42.8
50.6
94.3
60.4
98.0
48.1
97.7
93.9
79.2
99.0
81.1
99.9
99.4
99.9
100.0
100.0
100.0
100.0
100.0
Rural Cooperative Subgroup
1
2
3
4
5
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
35.6
35.6
27.6
36.9
29.1
49.8
38.0
35.1
61.5
37.6
TABLE V.13.—MEAN LIFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER
SUBGROUPS
gechino on PROD1PC61 with PROPOSALS
[Dollars]
Rated
capacity
kVA
Design line
TSL1
(TP 1)
TSL2
TSL3
TSL4
TSL5
TSL6
Municipal Utility Subgroup
1 .............................................................................
2 .............................................................................
3 .............................................................................
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50
25
500
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95
69
2,109
Fmt 4701
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95
66
2,765
95
70
3,607
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120
73
3,693
04AUP2
64
17
1,745
¥594
¥926
1,102
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TABLE V.13.—MEAN LIFE-CYCLE COST SAVINGS FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER
SUBGROUPS—Continued
[Dollars]
Rated
capacity
kVA
Design line
4 .............................................................................
5 .............................................................................
150
1,500
TSL1
(TP 1)
608
4,853
TSL2
808
6,649
TSL3
TSL4
TSL5
TSL6
512
8,128
512
9,013
435
7,680
¥165
7,453
79
67
1,669
183
3,084
58
63
1,579
183
3,239
¥91
¥25
¥1,630
¥599
¥3,617
¥861
¥1,040
¥2,573
¥1,320
¥3,775
Rural Cooperative Subgroup
1
2
3
4
5
.............................................................................
.............................................................................
.............................................................................
.............................................................................
.............................................................................
50
25
500
150
1,500
79
69
1,288
412
2,243
79
66
1,525
370
3,013
TABLE V.14.—MEAN PAYBACK PERIOD FOR TRANSFORMERS PURCHASED BY COMMERCIAL CONSUMER SUBGROUPS
[Years]
TSL1
(TP 1)
Design line
TSL2
TSL3
TSL4
TSL5
TSL6
Municipal Utility Subgroup
1
2
3
4
5
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
11.1
4.8
1.2
7.7
2.9
11.1
7.0
3.8
15.0
5.1
11.1
8.8
8.7
21.5
11.0
19.9
12.0
19.2
21.5
12.9
33.2
30.6
27.4
27.1
23.7
43.0
65.4
29.9
32.5
23.7
12.4
9.9
13.7
25.4
16.9
25.2
14.0
22.5
25.4
17.4
41.2
35.6
33.9
31.4
29.4
49.3
72.5
37.7
37.7
29.4
Rural Cooperative Subgroup
gechino on PROD1PC61 with PROPOSALS
1
2
3
4
5
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
...................................................................................................
The LCC results for the municipal
utilities subgroup are quite similar to
the results for the national sample of
utilities. Transformers purchased by
municipal utilities tend to serve more
diverse, urban loads than transformers
that serve more rural areas. The
increased load diversity increases the
load factor and the transformer loading,
thus increasing the potential savings
from reduced load losses. Thus,
compared to the other subgroup (rural
cooperatives), the benefits from
efficiency improvements are, on
average, greater.
In contrast to the results for municipal
utilities, the LCC savings tends to be
lower for rural cooperatives, and the
payback times tend to be longer. The
LCC and PBP results for the rural
cooperatives subgroup are mostly a
reflection of the fact that the loading on
rural transformers is lower, and thus the
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12.4
5.4
1.6
10.8
4.9
12.4
7.6
5.7
22.2
8.4
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.
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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).
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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 ....................................
Change in INPV ..................
Product Conversion Expenses.
Capital Investments .............
Total Investment Required ..
($ millions) ....
($ millions) ....
(%) ................
($ millions) ....
526
..................
..................
..................
532
5.8
1.1
0
537
10.7
2.0
0
553
27.0
5.1
0
561
34.9
6.6
0
549
22.3
4.2
109.2
552
25.8
4.9
161.2
($ millions) ....
($ millions) ....
..................
..................
2.5
2.5
5.0
5.0
7.8
7.8
8.0
8.0
94.1
203.3
326.5
487.7
Preservation-of-Operating-Profit Scenario
INPV ....................................
Change in INPV ..................
Product Conversion Expenses.
Capital Investments .............
Total Investment Required ..
($ millions) ....
($ millions) ....
(%) ................
($ millions) ....
526
..................
..................
..................
521
¥5.7
¥1.1
0
513
¥12.9
¥2.4
0
496
¥30.0
¥5.7
0
490
¥36.9
¥7.0
0
323
¥203.8
¥38.7
109.2
27
¥499.6
¥94.9
161.2
($ millions) ....
($ millions) ....
..................
..................
2.5
2.5
5.0
5.0
7.8
7.8
8.0
8.0
94.1
203.3
326.5
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
27
¥5.1
¥15.7
3.3
7.3
10.6
28
¥3.8
¥11.8
3.6
7.5
11.1
30
¥2.0
¥6.1
5.0
15.0
20.0
25
¥6.9
¥21.5
3.3
7.3
10.6
24
¥7.8
¥24.3
3.6
7.5
11.1
15
¥17.0
¥ 52.8
5.0
15.0
20.0
Preservation-of-Gross-Margin-Percentage Scenario
INPV ................................................
Change in INPV ..............................
Product Conversion Expenses ........
Capital Investments .........................
Total Investment Required ..............
($ millions) ..........
($ millions) ..........
(%) ......................
($ millions) ..........
($ millions) ..........
($ millions) ..........
32
....................
....................
....................
....................
....................
30
¥1.8
¥5.5
0
3.2
3.2
29
¥3.3
¥10.1
0
5.6
5.6
Preservation-of-Gross-Margin-Percentage Scenario
INPV ................................................
Change in INPV ..............................
Product Conversion Expenses ........
Capital Investments .........................
Total Investment Required ..............
($ millions) ..........
($ millions) ..........
(%) ......................
($ millions) ..........
($ millions) ..........
($ millions) ..........
gechino on PROD1PC61 with PROPOSALS
b. Impacts on Employment
The Department expects no
significant, discernable direct
employment impacts among liquidimmersed transformer manufacturers
under TSL1 through TSL4, but
potentially large increases in
employment for TSL5 and TSL6 (35
percent and 99 percent, respectively).
These conclusions—which are separate
from any conclusions regarding
employment impacts on the broader
U.S. economy—are based on modeling
results that address neither the possible
relocation of domestic transformer
manufacturing employment to lower
labor-cost countries, nor the possibility
of outsourcing amorphous core
production under TSL5 and TSL6 to
companies in other countries. The
Department discussed this scenario of
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32
....................
....................
....................
....................
....................
30
¥2.5
¥7.7
0
3.2
3.2
28
¥4.3
¥13.4
0
5.6
5.6
outsourcing amorphous core production
to other countries during several liquidimmersed manufacturer interviews, and
it appears that outsourcing would be a
serious consideration for the liquidimmersed industry under TSL5 or TSL6.
Liquid-immersed manufacturers
expressed concern during the MIA
interviews that establishing an energy
conservation standard would
‘‘commoditize’’ the liquid-immersed
transformer market, making it easier for
foreign manufacturers who specialize in
low-cost mass production of one design
to enter the U.S. market. If foreign
producers were to capture significant
market share, U.S. transformermanufacturing employment would be
negatively affected. As a point related to
‘‘commoditization,’’ but separate from
employment impacts, manufacturers
PO 00000
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also warned the Department about a
potential backsliding effect, whereby the
average efficiency of liquid-immersed
transformers could potentially decrease
under standards, since transformer
customers may stop evaluating and
instead simply purchase minimally
compliant designs. Manufacturers
reported having observed such a
backsliding phenomenon in customer
orders from Massachusetts, where TP1
is a mandatory standard.
The Department expects no
significant, discernable employment
impacts among medium-voltage, drytype transformer manufacturers for any
TSL compared to the base case. The
Department’s conclusion regarding
employment impacts in the mediumvoltage, dry-type transformer industry is
separate from any conclusions regarding
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gechino on PROD1PC61 with PROPOSALS
employment impacts on the broader
U.S. economy. Increased employment
levels are not expected at higher TSLs
because the core-cutting equipment
typically purchased by the mediumvoltage, dry-type industry is highly
automated and includes core-stacking
equipment.
Another concern conveyed by some
medium-voltage, dry-type
manufacturers during the interviews is
the potential impact stemming from the
cast-coil transformer competitiveness at
higher TSLs. These manufacturers claim
that setting a standard above a certain
threshold may trigger a market switch
from open-wound ventilated
transformers to cast-coil transformers.
Manufacturers suggest that this
crossover point likely occurs at TSL3
and higher. If the market does shift to
cast-coil transformers, there is a risk of
imported pre-fabricated cast coils
dominating the market in the long term.
This would have a significant impact on
domestic industry value and domestic
employment in the medium-voltage,
dry-type industry.
c. Impacts on Manufacturing Capacity
For the liquid-immersed distribution
transformer industry, the Department
believes that there are only minor
production capacity implications for a
standard at TSL4 and below. At TSL6,
all liquid-immersed design lines would
have to convert to amorphous
technology, the most efficient core
material. At TSL5, three design lines
would have to convert to amorphous
core designs. Conversion to amorphous
core designs would render obsolete a
large portion of the equipment used in
the liquid-immersed industry today
(e.g., annealing furnaces, core-cutting
and winding equipment). Based on the
manufacturer interviews, DOE believes
that TSL5 and TSL6 would cause liquidimmersed transformer manufacturers to
decide whether they would tool for
amorphous technology, attempt to
purchase pre-fabricated amorphous
cores, or exit the industry.
Manufacturers also indicated that, if
they were to choose to produce
amorphous cores themselves, they
would face a critical decision about
whether or not to relocate outside of the
U.S., since much of their equipment
would become obsolete. As mentioned
above, if manufacturers choose to
purchase pre-fabricated amorphous
cores, they might purchase them from
foreign manufacturers.
Energy conservation standards will
affect the medium-voltage, dry-type
industry’s manufacturing capacity
because the core stack heights (or core
steel piece length) will increase and
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laminations will become thinner.
Thinner laminations require more cuts
and are more cumbersome to handle.
Therefore, manufacturers would have to
invest in additional core-mitering
machinery or modifications and
improvements to recover any losses in
productivity, and these factors might
also contribute to a need for more plant
floor space. Because more-efficient
transformers tend to be larger, this could
also contribute to the need for
additional manufacturing floor space.
d. Impacts on Manufacturers That Are
Small Businesses
Converting from a company’s current
basic product line involves designing,
prototyping, testing, and manufacturing
a new product. These tasks have
associated capital investments and
product conversion expenses. Small
businesses, because of their limited
access to capital and their need to
spread conversion costs over smaller
production volumes, may be affected
more negatively than major
manufacturers by an energy
conservation standard. For these
reasons, the Department specifically
evaluated the impacts on small
businesses of an energy conservation
standard.
The Small Business Administration
defines a small business, for the
distribution transformer industry, as a
business that has 750 or fewer
employees. The Department estimates
that, of the approximately 25 U.S.
manufacturers that make liquidimmersed distribution transformers,
about 15 of them are small businesses.
About five of the small liquid-immersed
transformer businesses have fewer than
100 employees. The liquid-immersed
distribution transformer industry largely
produces customized transformers.
Often, small businesses can compete in
this industry because a typical customer
order can involve unique designs
produced in relatively small volumes.
Small manufacturers in the liquidimmersed industry tend not to compete
on the higher-volume products and
often produce transformers for highly
specific applications. This strategy
allows small manufacturers in the
liquid-immersed transformer industry to
be competitive in certain product
markets. Implementation of an energy
conservation standard would have a
relatively minor differential impact on
small manufacturers (versus large
manufacturers) of liquid-immersed
distribution transformers. Disadvantages
to small businesses, such as having little
leverage over suppliers (e.g., core steel
suppliers), are present with or without
an energy conservation standard.
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For medium-voltage, dry-type
manufacturers, the situation is different.
The Department estimates that, of the 25
U.S. manufacturers that make mediumvoltage, dry-type distribution
transformers, about 20 of them are small
businesses. About one-half of the
medium-voltage, dry-type small
businesses have fewer than 100
employees. Medium-voltage, dry-type
transformer manufacturing is more
concentrated than liquid-immersed
transformer manufacturing; the top
three companies manufacture over 75
percent of all transformers in this
category. The entire medium-voltage,
dry-type transformer industry has such
low shipments that no designs are
produced at high volume. There is little
repeatability of designs, so small
businesses can competitively produce
many medium-voltage, dry-type, openwound designs. The medium-voltage,
dry-type industry as a whole primarily
has experience producing baseline
transformers and transformers that
would comply with TSL1. In addition,
the industry produces a significant
number of units that would comply
with TSL2, but approximately one
percent or less of the market would
comply with TSL3 or higher (today).
Therefore, all manufacturers, including
small businesses, would have to
develop designs to enable compliance
with TSL3 or higher. For these small
manufacturers, the R&D costs would be
more burdensome, as product redesign
costs tend to be fixed and do not scale
with sales volume. Thus, small
businesses would be at a relative
disadvantage at TSL3 and higher,
because their R&D efforts would be on
the same scale as those for larger
companies, but these expenses would be
recouped over smaller sales volumes.
At TSL3 and above, DOE estimates
that net cash flows for the mediumvoltage, dry-type industry would go
negative during the compliance period.
At these TSLs, the impacts on the
industry as a whole are large and affect
businesses of all sizes, but there would
be some differential, increased impacts
on small businesses. For example, at
TSL3 and above, the use of grainoriented silicon steel of M3 grade would
be necessary. Cutting M3 core steel on
the core-mitering equipment typically
purchased by smaller businesses can be
problematic because of the thinness of
the material.
At TSL2, all medium-voltage, drytype designs would have to be mitered.
(Mitering means the transformer core’s
joints intersect at 45 degree angles,
rather than at 90 degree angles as is true
for ‘‘butt-lap’’ designs; buttlap designs
are less energy efficient.) The mitered
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core construction technique could
constrain the core-mitering resources of
small businesses that share core-cutting
capacity with production lines for other
transformers that are not covered by this
rulemaking (e.g., low-voltage, dry-type
distribution transformers). At TSL1,
many kVA ratings could still be
constructed using butt-lap joints,
alleviating the constraint on coremitering resources. Thus, TSL1 is less
capital-intensive for small businesses
than TSL2 (large businesses would
likely miter nearly all medium-voltage
cores, even at TSL1). In the mediumvoltage, dry-type transformer industry,
which is heavily consolidated already,
there is the risk that TSL2 could lead to
further advantage for the largest
manufacturers and thus further
concentrate the industry’s production.
3. National Impact Analysis
a. Amount and Significance of Energy
Savings
The Department estimated the energy
savings from a proposed energyefficiency standard in its NES analysis.
The amount of energy savings depends
not only on the potential decrease in
transformer losses due to a standard, but
also on the rate at which the stock of
existing, less efficient transformers will
be replaced over time after the
implementation of a proposed energyefficiency standard.
Another factor that affects national
energy savings estimates is the
efficiency of the power plants and the
transmission and distribution system
that supplies electricity to transformers.
The factor that relates energy savings at
the transformer to fuel savings at the
power plant is the site-to-source
conversion factor. The NES analysis
takes as an input estimates of the energy
savings per transformer resulting from
proposed energy-efficiency standards
that are calculated in the LCC model.
The NES model then accounts for
transformer stock replacement and siteto-source energy conversion to estimate
annual national energy savings through
an extended forecast period ending in
2038. The replacement of existing
transformer stocks by new, more
efficient transformers is described by
the Department’s shipments model,
described in TSD Chapter 9. The
Department calculated the site-to-source
conversion factor that relates
transformer loss reduction to fuel
savings at the power plant using 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$, at 3% and 7% discount rates, 2010–2073]
TSL1
(TP 1)
TSL2
TSL3
TSL4
TSL5
TSL6
gechino on PROD1PC61 with PROPOSALS
Sum of all Product Classes
Energy Savings (quads) ..............................................................
Discounted Energy Savings (quads):
3% .........................................................................................
7% .........................................................................................
NPV (billion 2004$):
3% .........................................................................................
7% .........................................................................................
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1.77
3.15
3.63
6.90
9.77
0.90
0.40
1.21
0.54
1.58
0.71
1.82
0.82
3.47
1.54
4.91
2.19
7.43
2.15
Fmt 4701
2.39
9.43
2.52
10.11
2.28
11.07
2.26
10.88
¥1.13
¥9.41
¥14.09
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c. Impacts on Employment
The Process Rule includes
employment impacts among the factors
DOE considers in selecting a proposed
standard. Employment impacts include
direct and indirect impacts. Direct
employment impacts are any changes in
the number of employees for
distribution transformer manufacturers.
Indirect impacts are those changes of
employment in the larger economy that
occur due to the shift in expenditures
and capital investment that is caused by
the purchase and operation of more
efficient equipment. The MIA addresses
direct employment impacts; this section
describes indirect impacts.
In developing this proposed rule, the
Department estimated indirect national
employment impacts using an input/
output model of the U.S. economy,
called IMBUILD (impact of building
energy efficiency programs). Indirect
employment impacts from distribution
transformer standards consist of the net
jobs created or eliminated in the
national economy, other than in the
manufacturing sector being regulated, as
a consequence of: (1) Reduced spending
by end users on energy (electricity,
gas—including liquefied petroleum
gas—and oil); (2) reduced spending on
new energy supply by the utility
industry; (3) increased spending on the
purchase price of new distribution
transformers; and (4) the effects of those
three factors throughout the economy.
The Department expects the net
monetary savings from standards to be
redirected to other forms of economic
activity. The Department also expects
these shifts in spending and economic
activity to affect the demand for labor.
As shown in table V.18, the
Department estimates that net indirect
employment impacts from a proposed
transformer energy-efficiency standard
are positive. According to the
Department’s analysis, the number of
jobs that may be generated through
indirect impacts ranged from 5,000 to
20,000 by 2038 for the proposed
standard levels of TSL1 through TSL6
respectively. For shorter forecast
periods, indirect employment impacts
are correspondingly smaller. While the
Department’s analysis suggests that the
proposed distribution transformer
standards could increase the net
demand for labor in the economy, the
gains would most likely be very small
relative to total national employment.
The Department therefore concludes
only that the proposed distribution
transformer standards are likely to
produce employment benefits that are
sufficient to offset fully any adverse
impacts on employment that might
occur in the distribution transformer or
energy industries. For details on the
employment impact analysis methods
and results, see TSD Chapter 14.
TABLE V.18.—NET NATIONAL CHANGE IN INDIRECT EMPLOYMENT, THOUSANDS OF JOBS IN 2038
Trial standard level
TSL1
Liquid-Immersed ..........................................................................
Dry-Type, Medium-Voltage ..........................................................
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4. Impact on Utility or Performance of
Equipment
In establishing classes of products,
and in evaluating design options and
the impact of potential standard levels,
the Department has tried to avoid
having new standards for distribution
transformers lessen the utility or
performance of these products (see TSD
Chapter 7, section 7.3.1). The proposed
standard level (TSL2) does not lessen
the performance of any of the
distribution transformers being
regulated.
The standard level could, however,
potentially affect utility through the
larger size and weight of an energyefficient distribution transformer. The
Department accounted for
dimensionally or physically constrained
transformers in its LCC model by
including the cost of dealing with
physical constraints in the installation
cost estimate. For all types of
transformers, the Department included
extra labor and equipment costs that
may be incurred in the installation of
larger, heavier, more efficient
transformers. Design line 2 includes
pole-mounted transformers and presents
a special case because of the extra cost
of installing or replacing electrical
distribution poles on which such
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TSL2
4.7
0.3
6.4
0.5
transformers may be mounted by
utilities. For single-phase, polemounted, liquid-immersed transformers,
the LCC spreadsheet model includes an
estimate of the additional installation
costs for those designs that would
require an upgrade to the pole (see TSD
Chapter 7, section 7.3.1). Having
accounted for this constraint on utility
in its economic model, the Department
concludes that TSL2 does not reduce
the utility or performance of
distribution transformers.
5. Impact of Any Lessening of
Competition
The Department considers any
lessening of competition that is likely to
result from standards. The Attorney
General determines the impact, if any,
of any lessening of competition likely to
result from a proposed standard, and
transmits such determination to the
Secretary, not later than 60 days after
the publication of a proposed rule,
together with an analysis of the nature
and extent of such impact. (See 42
U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)).
To assist the Attorney General in
making such a determination, the
Department has provided the
Department of Justice (DOJ) with copies
of this notice and the TSD for review.
At DOE’s request, the DOJ reviewed the
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TSL3
TSL4
7.7
0.7
8.7
1.0
TSL5
TSL6
18.2
1.4
19.4
1.4
MIA interview questionnaire to ensure
that it would provide insight concerning
any lessening of competition due to any
proposed TSLs.
6. Need of the Nation To Conserve
Energy
Enhanced energy efficiency, where
economically justified, improves the
Nation’s energy security, strengthens the
economy, and reduces the
environmental impacts or costs of
energy production. The energy savings
from distribution transformer standards
result in reduced emissions of 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
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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
Emissions reductions for liquid-immersed transformers:
CO2 (Mt) ................................................................................
NOX (kt) ................................................................................
Hg (t) .....................................................................................
Emissions reductions for medium-voltage, dry-type transformers:
CO2 (Mt) ................................................................................
NOX (kt) ................................................................................
Hg (t) .....................................................................................
The cumulative CO2, NOX, and Hg
emissions reductions range up to 678.8
Mt, 187.7 kt, and 6.48 t, respectively, in
2038 (sum of liquid-immersed and
medium-voltage dry-type at TSL6).
Total CO2 and NOX emissions
reductions for each TSL are reported in
the environmental assessment, a
separate report in the TSD.
In the ANOPR, the Department stated
that, for its NOPR analysis, it would
calculate discounted values for future
emissions. 69 FR 45376. Accordingly,
the Department here presents its results
for discounted emissions of CO2 and
NOX. When NOX emissions are subject
TSL2
TSL3
TSL4
TSL5
TSL6
117.4
31.7
2.9
158.2
42.7
3.5
205.4
55.5
4.1
232.8
62.8
4.5
451.2
121.7
5.8
647.6
174.8
5.9
5.6
2.3
0.10
8.9
3.7
0.17
12.8
5.3
0.24
19.5
8.1
0.36
31.2
12.9
0.58
31.2
12.9
0.58
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)
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Liquid-Immersed, 3% discount, CO2 (Mt) ....................................
Dry-Type, 3% discount, CO2 (Mt) ................................................
Liquid-Immersed, 7% discount, CO2 (Mt) ....................................
Dry-Type, 7% discount, CO2 (Mt) ................................................
Liquid-Immersed, 3% discount, NOX (kt) ....................................
Dry-Type, 3% discount, NOX (kt) ................................................
Liquid-Immersed, 7% discount, NOX (kt) ....................................
Dry-Type, 7% discount, NOX (kt) ................................................
7. Other Factors
The Secretary of Energy, in
determining whether a standard is
economically justified, considers any
other factors that the Secretary deems to
be relevant. (See 42 U.S.C.
6295(o)(2)(B)(i)(VII)) For today’s
proposed standard, the Secretary took
into consideration transformermanufacturing-material price
volatility—a factor that received several
comments at the ANOPR public
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TSL 2
58.2
2.8
25.3
1.2
16.3
1.2
7.5
0.5
78.4
4.4
34.0
1.9
21.9
1.8
10.1
0.8
meeting, during the comment period
following the meeting, and in the MIA
interviews. Stakeholders expressed
concern about the increasing cost of raw
materials for building transformers, the
volatility of material prices, and the
cumulative effect of material price
increases on the transformer industry
(see section IV.B.2, Engineering
Analysis Inputs). The Department
conducted supplemental engineering
and LCC analyses using first-quarter
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TSL 3
101.9
6.4
44.3
2.8
28.6
2.7
13.2
1.2
TSL 4
115.5
9.7
50.1
4.2
32.4
4.0
15.0
1.8
TSL 5
223.5
15.5
96.9
6.7
62.6
6.5
28.9
2.9
TSL 6
321.1
15.5
139.4
6.7
90.0
6.5
41.6
2.9
2005 material prices, and considered the
impacts on LCC savings and payback
periods when evaluating the appropriate
standard levels for liquid-immersed and
medium-voltage, dry-type distribution
transformers. The results of the
engineering and LCC analyses for the
first-quarter 2005 material price analysis
are in the TSD Appendix 5C.
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B. Stakeholder Comments on the
Selection of a Final Standard
During the public comment period on
the ANOPR, the Department received
numerous comments from stakeholders
relating to the selection of the
appropriate standard level for
distribution transformers. Stakeholders
expressed a range of opinions on what
efficiency levels the Department should
select for a standard, some relating
specifically to liquid-immersed
transformers and others to both liquidimmersed and medium-voltage, drytype units.
Concerning liquid-immersed
distribution transformers, Cooper
Industries recommended that NEMA TP
1 be adopted for design lines 1, 2, and
4. For design lines 3 and 5, Cooper
recommended CSL2, which is one level
higher than the TP 1 level. (Note that for
the ANOPR, the CSLs were slightly
different from the levels considered for
the NOPR; for the ANOPR, CSL2 for
design line 3 was 99.40 percent and
CSL2 for design line 5 was 99.40
percent.) For design line 5, Cooper
stated that the majority of users are
industrial customers, who would
typically require the value of annual
energy savings resulting from efficiency
level increases to pay back the cost of
those increases in two to four years, or
provide a 15 to 30 percent annual rate
of return on such cost. (Cooper, No. 62
at pp. 4–6) EMSIC commented that
mandatory efficiency standards can be
set at TP 1 + 0.4 percent for all liquidimmersed products without undue
burden on any stakeholders. (EMSIC,
No. 73 at p. 2) The Department
considered these comments from
Cooper Industries and EMSIC while
reviewing the analytical results and
selecting a proposed standard level for
liquid-immersed distribution
transformers.
Howard stated that it does not believe
the Department should establish
mandatory efficiency standards for
liquid-immersed distribution
transformers because, through TOC
evaluation, the market already drives
these transformers to cost-effective
efficiency levels. Howard participates in
the Energy Star program, and believes
the Department should take a voluntary
approach to standards. (Howard, No. 70
at p. 2) As discussed earlier in this
notice, the Department is charged with
determining whether standards for
distribution transformers are
technologically feasible and
economically justified and would result
in significant energy savings. (42 U.S.C.
6317(a)) Based on the analysis and
information available to date, it appears
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that standards for liquid-immersed
distribution transformers would be
technologically feasible and
economically justified, and would result
in significant energy savings. Thus, the
Department will continue to evaluate
minimum efficiency standards for
liquid-immersed transformers.
Howard continued by stating that if
DOE must mandate efficiency levels for
liquid-immersed transformers, then it
recommends the Department use
specific efficiency levels provided in its
comment. For single-phase
transformers, the levels proposed by
Howard start at 98.8 percent for 10 kVA
transformers and rise to 99.4 percent for
75 kVA transformers, above which the
proposed level is constant. For threephase transformers, the levels proposed
by Howard start at 98.5 percent for 15
kVA transformers and rise to 99.4
percent for 225 kVA transformers, above
which the proposed level is constant.
(Howard, No. 70 at pp. 3 and 5) The
Department considered these
recommended levels from Howard
while reviewing the analytical results
and selecting a proposed standard level
for liquid-immersed distribution
transformers.
The Department also received several
cross-cutting comments that pertained
to the appropriate standard level for all
product classes being evaluated.
HVOLT, NGrid, and Southern provided
comments in support of NEMA TP 1.
HVOLT stated that, based on its
involvement in the development of
NEMA TP 1, it recommends setting the
new DOE standard at NEMA TP 1
levels, which have a 3–5-year payback
period at the nationwide average cost of
energy. It noted that this level would
guarantee wide support for the standard.
(HVOLT, No. 65 at p. 3) NGrid stated
that a standard that encourages utilities
to install transformers that meet the
efficiency levels outlined in NEMA TP
1–1996 is in the best interests of the
company and its customers. (NGrid, No.
80 at p. 2) Similarly, Southern Company
commented that the minimum
efficiency standard should be no higher
than NEMA TP 1. It added that the
choice of transformers with efficiencies
higher than TP 1 should be left to the
customer. (Southern, No. 71 at p. 3) The
Department included TP 1 in its
analysis but determined that a higher
efficiency level was economically
justified for the liquid-immersed and
medium-voltage, dry-type super classes,
and would result in significant energy
savings.
EEI and NRECA commented that the
Department should select a standard
level based on the percentage of
transformer consumers with positive
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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
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determines whether the benefits of the
standard exceed its costs. Any new or
amended standard for distribution
transformers must result in significant
energy savings.
In selecting a proposed energy
conservation standard for distribution
transformers, the Department followed
its normal approach. It started by
comparing the maximum
technologically feasible level with the
base case, and determined whether that
level was economically justified. Upon
finding the maximum technologically
feasible level not to be justified, the
Department analyzed the next lower
TSL to determine whether that level was
economically justified. The Department
repeated this procedure until it
identified a TSL that was economically
justified. The Department made its
determination of economic justification
on the basis of the NOPR analysis
results published today and the
comments that were submitted by
stakeholders. Beginning with the most
efficient level, this section discusses
each TSL for liquid-immersed
transformers and then each TSL for
medium-voltage, dry-type transformers.
The following two tables summarize
DOE’s analytical results. They will aid
the reader in the discussion of costs and
benefits of each TSL. Each table
presents the results or, in some cases, a
range of results, for the underlying
design lines for liquid-immersed (Table
V.21) and medium-voltage, dry-type
(Table V.22) distribution transformers.
The range of values reported in these
tables for LCC, payback, and average
increase in consumer equipment cost
before installation encompass the range
of results calculated for either the
liquid-immersed or medium-voltage,
dry-type representative units. The range
of values for the manufacturer impact
represents the results for the
preservation-of-operating-profit scenario
and preservation-of-gross-margin
scenario at each TSL for liquidimmersed and medium-voltage, drytype transformers.
TABLE V.21.—SUMMARY OF LIQUID-IMMERSED DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS
Trial standard level
Criteria
TSL1
Energy saved (quads) ..............................
Generation Capacity Offset (GW) ............
Discounted energy saved, 7% (quads) ...
NPV ($ billions):
@ 7% discount .................................
@ 3% discount .................................
Emission reductions:
CO2 (Mt) ............................................
NOX (kt) ............................................
Life-Cycle Cost:
Net Savings (%) ................................
Net Increase (%) ...............................
No Change (%) .................................
Payback (years) ................................
Average increase in consumer
equipment cost before installation
(%) * † ...........................................
Manufacturer Impact:
INPV ($ millions) ...............................
INPV change (%) ..............................
TSL2
TSL3
TSL4
TSL5
TSL6
1.70
3.1
0.38
2.28
4.3
0.51
2.99
5.5
0.67
3.38
6.2
0.76
6.51
12.1
1.45
9.38
17.3
2.10
2.02
7.02
2.31
8.78
2.01
9.20
1.92
9.83
(1.14)
9.94
(14.10)
(10.31)
117.4
31.7
158.2
42.7
205.4
55.5
232.8
62.8
451.2
121.7
647.6
174.8
26.1–32.0
0.2–4.9
63.7–73.7
1.4–11.4
32.5–42.4
1.4–16.8
40.8–65.2
4.3–18.1
32.5–49.8
5.2–52.8
11.3–60.8
8.8–21.5
35.1–67.7
8.6–39.9
4.0–56.3
12.0–21.9
30.7–42.9
43.9–66.3
0.0–25.4
25.6–36.0
1.1–42.7
57.2–98.9
0.0–0.1
25.6–67
1.4–4.2
2.7–12.8
3.0–38.3
4.2–40.6
15.5–141.9
106.9–160
(5.7)–5.8
(1.1)–1.1
(12.9)–10.7
(2.4)–2.0
(30.0)–27.0
(5.7)–5.1
(36.9)–34.9
(7.0)–6.6
(203.8)–22.3
(38.7)–4.2
(499.6)–25.8
(94.9)–4.9
* Percent increase in consumer equipment cost before installation, five-year average material pricing.
† The Department recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience larger changes, particularly if these customers are not evaluating losses when purchasing transformers.
TABLE V.22.—SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS
Trial standard level
Criteria
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TSL1
Energy saved (quads) ..............................
Generation Capacity Offset (GW) ............
Discounted energy saved, 7% (quads) ...
NPV ($ billions):
@ 7% discount .................................
@ 3% discount .................................
Emission reductions:
CO2 (Mt) ............................................
NOX (kt) ............................................
Life-Cycle Cost:
Net Savings (%) ................................
Net Increase (%) ...............................
No Change (%) .................................
Payback (years) ................................
Increase in consumer equipment
cost before installation (%) * † ......
Manufacturer Impact:
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TSL2
TSL3
TSL4
TSL5
TSL6
0.07
0.1
0.02
0.11
0.2
0.03
0.16
0.3
0.04
0.25
0.4
0.06
0.39
0.6
0.09
0.39
0.6
0.09
0.13
0.44
0.21
0.68
0.28
0.95
0.34
1.29
0.03
1.05
0.03
1.05
5.6
2.3
8.9
3.7
12.8
5.3
19.5
8.1
31.2
12.9
31.2
12.9
20.2–55.1
0.6–4.4
42.5–76.0
1.5–9.7
25.6–61.5
1.1–5.1
34.6–72.9
2.4–8.3
36.7–71.5
4.4–9.8
18.7–58.9
5.4–10.0
52.0–75.7
18.2–42.6
0.5–28.2
11.8–19.5
24.3–66.8
34.2–75.7
0.0
15.1–32.5
24.3–66.8
33.2–75.7
0.0
14.8–32.4
0.7–4.4
2.2–7.2
5.4–13.6
13.5–30.4
36.4–78.5
36.4–78.4
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TABLE V.22.—SUMMARY OF MEDIUM-VOLTAGE, DRY-TYPE DISTRIBUTION TRANSFORMERS ANALYTICAL RESULTS—
Continued
Trial standard level
Criteria
TSL1
INPV ($ millions) ...............................
INPV change (%) ..............................
TSL2
(2.5)–(1.8)
(7.7)–(5.5)
TSL3
(4.3)–(3.3)
(13.4)–(10.1)
(6.9)–(5.1)
(21.5)–(15.7)
TSL4
TSL5
(7.8)–(3.8)
(24.3)–(11.8)
(17.0)–(2.0)
(52.8)–(6.1)
TSL6
(17.0)–(2.0)
(52.8)–(6.1)
* Percent increase in consumer equipment cost before installation, five-year average material pricing.
† The Department recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience larger changes, particularly if these customers are not evaluating losses when purchasing transformers.
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1. Results for Liquid-Immersed
Distribution Transformers
a. Liquid-Immersed Trial Standard
Level 6
First, the Department considered the
most efficient level (max tech), which
would save an estimated total of 9.4
quads of energy through 2038, a
significant amount of energy.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 2.1 quads. For the Nation
as a whole, TSL6 would have a net cost
of $14 billion at a seven-percent
discount rate. At this level, the majority
of customers would experience an
increase in life-cycle costs. As shown in
Table V.21, only about 1 to 43 percent
of customers would experience lower
life-cycle costs, depending on the design
line. The payback periods at this
standard level are between 26 and 67
years, some of which exceed the
anticipated operating life of the
transformer. The impacts on
manufacturers would be very significant
because TSL6 would require a complete
conversion to amorphous core
technology. These costs would reduce
the INPV by as much as 95 percent
under the preservation-of-operatingprofit scenario. The Department
estimates that $59 million of existing
assets would be stranded (i.e., rendered
useless) and $327 million of conversion
capital expenditures would be required
to enable the industry to manufacture
compliant distribution transformers.
The energy savings at TSL6 would
reduce the installed generating capacity
by 17.3 gigawatts (GW), or roughly 40
large, 400 MW powerplants.5 The
estimated emissions reductions through
this same time period are 647.6 Mt of
CO2 and 174.8 kt of NOX. The
Department concludes that at this TSL,
the benefits of energy savings,
generating capacity reductions, and
emission reductions would be
outweighed by the potential multibillion dollar negative net economic
5 DOE estimates 18 coal-fired power plants and 22
gas-fired power plants can be avoided. See TSD
Chapter 13.
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cost to the Nation, the economic burden
on customers as indicated by large
payback periods, and the stranded asset
and conversion capital costs that could
result in the large reduction in INPV for
manufacturers. Consequently, the
Department concludes that TSL6, the
max tech level, is not economically
justified.
b. Liquid-Immersed Trial Standard
Level 5
Next, the Department considered
TSL5, which would save an estimated
total of 6.5 quads of energy through
2038, a significant amount of energy.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 1.45 quads. For the
Nation as a whole, TSL5 would have a
net cost of $1.1 billion at a sevenpercent discount rate. At this level,
about 31 to 43 percent of customers
would experience lower life-cycle costs,
depending on the design line. At this
level, 44 to 66 percent of customers
would have increased life-cycle costs.
The payback periods at this standard
level are between 26 and 36 years, some
of which exceed the anticipated
operating life of the transformer. The
impacts on manufacturers would be
very significant because TSL5 would
require partial conversion to amorphous
core technology. The resulting costs
would contribute to as much as a 39
percent reduction in the INPV under the
preservation-of-operating-profit
scenario. The Department estimates that
$16 million of existing assets would be
stranded and approximately $94 million
in conversion capital expenditures
would be required to enable the
industry to manufacture compliant
transformers. The energy savings at
TSL5 would reduce the installed
generating capacity by 12.1 GW, or
roughly 30 large, 400 MW powerplants.
The estimated emissions reductions
through this same time period are 451.2
Mt of CO2 and 121.7 kt of NOX. The
Department concludes that at this TSL,
the benefits of energy savings,
generating capacity reductions, and
emission reductions would be
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outweighed by the potential negative
net economic cost to the Nation, the
economic burden on customers as
indicated by large payback periods, and
the stranded asset and conversion
capital costs that could result in the
large reduction in INPV for
manufacturers. Consequently, the
Department concludes that TSL5 is not
economically justified.
c. Liquid-Immersed Trial Standard
Level 4
Next, the Department considered
TSL4, which would save an estimated
total of 3.4 quads of energy through
2038, a significant amount of energy.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.76 quads. For the
Nation as a whole, TSL4 would result in
a net savings of $1.9 billion at a sevenpercent discount rate. For customers,
lower life-cycle costs would be
experienced by between 35 and 68
percent, depending on the design line,
meaning that for some design lines,
more than half of the customers would
be better off, while for others less than
half would benefit. The payback periods
for three of the five liquid-immersed
design line representative units would
be more than half the anticipated
operating life of the transformer. For one
design line, the payback period is as
long as 22 years. The consumer
equipment cost before installation
would increase by 41 percent for one
design line, a significant increase for
transformer customers. The energy
savings at TSL4 would reduce the
installed generating capacity by 6.2 GW,
or roughly 16 large, 400 MW
powerplants. The estimated emissions
reductions through this same time
period are 232.8 Mt of CO2 and 62.8 kt
of NOX. The Department concludes that
at this TSL, the benefits of energy
savings, generating capacity reductions,
emission reductions and national NPV
would be outweighed by the economic
burden on some customers as indicated
by long payback periods and
significantly greater first costs.
Consequently, the Department
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concludes that TSL4 is not
economically justified.
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d. Liquid-Immersed Trial Standard
Level 3
Next, the Department considered
TSL3, which would save an estimated
total of 3 quads of energy through 2038,
a significant amount of energy.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.67 quads. For the
Nation as a whole, TSL3 would have a
net savings of $2 billion at a sevenpercent discount rate. At this level,
lower life-cycle costs would be
experienced by between 32 and 50
percent of customers, depending on the
design line, meaning that for all the
design lines, one-half or less of
customers are better off. One of the
payback periods is 22 years, exceeding
half the anticipated operating life of a
transformer. Additionally, the consumer
equipment cost before installation
increases by 38 percent for one design
line, a significant increase for
customers. The energy savings at TSL3
would reduce the installed generating
capacity by 5.5 GW, or roughly 14 large,
400 MW powerplants. The estimated
emission reductions through this same
time period are 205.4 Mt of CO2 and
55.5 kt of NOX. The Department
concludes that at this TSL, the benefits
of energy savings, generating capacity
reductions, emission reductions and
national NPV would be outweighed by
the economic burden on some
customers as indicated by long payback
periods and significantly greater first
costs. Consequently, the Department
concludes that TSL3 is not
economically justified.
e. Liquid-Immersed Trial Standard
Level 2
Next, the Department considered
TSL2, which would save an estimated
total of 2.3 quads of energy through
2038, a significant amount of energy.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.51 quads. For the
Nation as a whole, TSL2 would have the
highest NPV of all the TSLs for liquidimmersed distribution transformers, an
estimated $2.3 billion at the sevenpercent discount rate. At this level, as
shown in Table V.21, between 32 and 42
percent of customers would experience
lower life-cycle costs, depending on the
design line. The payback periods under
TSL2 are between 4 and 18 years, which
at most is approximately half the
anticipated operating life of the
transformer. The energy savings at TSL2
would reduce the installed generating
capacity by 4.3 GW, or roughly 11 large,
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400 MW powerplants. The estimated
emissions reductions through this same
time period are 158.2 Mt of CO2 and
42.7 kt of NOX. At TSL2, the relatively
low costs are outweighed by the
benefits, including significant energy
savings, generating capacity reductions,
emission reductions, maximum national
NPV, and benefits to a majority of those
customers affected by the standard.
After considering the costs and benefits
of TSL2, the Department finds that this
trial standard level will offer the
maximum improvement in efficiency
that is technologically feasible and
economically justified, and will result
in significant conservation of energy.
Therefore, the Department today
proposes to adopt the energy
conservation standards for liquidimmersed distribution transformers at
TSL2.
2. Results for Medium-Voltage, DryType Distribution Transformers
a. Medium-Voltage, Dry-Type Trial
Standard Level 6
First, the Department considered the
most efficient level (max tech), which
would save an estimated total of 0.4
quads of energy through 2038.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.09 quads. For the
Nation as a whole, TSL6 would result in
a $30 million benefit at a seven-percent
discount rate. However, at this level, the
percentage of customers experiencing
lower life-cycle costs would be less than
35 percent for the majority of the units
analyzed, with one representative unit
as low as 24 percent. This means that
more than three-quarters of transformer
customers making purchases in that
design line would experience increases
in life-cycle cost. Customer payback
periods at this standard level for the
majority of units analyzed are 28 years
or greater, with one representative unit
as high as 32 years, which is
approximately the operating life of a
transformer. The impacts on
manufacturers would be significant,
with TSL 6 contributing to a 53-percent
reduction in the INPV under the
preservation-of-operating-profit
scenario. The Department projects that
manufacturers will experience negative
net annual cash flows during the
compliance period, irrespective of the
markup scenario. The magnitude of the
peak, negative, net annual cash flow
would be more than twice that of the
positive-base-case cash flow. The energy
savings at TSL6 would reduce installed
generating capacity by 0.6 GW, or
roughly 1.5 large, 400 MW powerplants.
The Department estimates the
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associated emissions reductions through
2038 of 31.2 Mt of CO2 and 12.9 kt of
NOX. The Department concludes that at
this TSL, the benefits of energy savings,
generating capacity reductions,
emission reductions and national NPV
would be outweighed by the economic
burdens on customers as indicated by
long payback periods and significantly
greater first costs, and manufacturers
who may experience a drop in INPV of
up to 53 percent. Consequently, the
Department concludes that TSL6, the
max tech level, is not economically
justified.
b. Medium-Voltage, Dry-Type Trial
Standard Level 5
Next, the Department considered
TSL5, which is identical to TSL6 (i.e.,
for all the representative units, TSL5
and TSL6 have all the same percentage
efficiency values). Thus, for the same
reasons described above in section
V.C.2.a, the Department concludes that
TSL5 is not economically justified.
c. Medium-Voltage, Dry-Type Trial
Standard Level 4
Next, the Department considered
TSL4, which would save a total of 0.3
quads of energy through 2038.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.06 quads. For the
Nation as a whole, TSL4 would have a
net savings of $0.34 billion at a sevenpercent discount rate, the maximum
NPV for medium-voltage, dry-type
distribution transformers. Because for
TSL5 and TSL6 the energy savings
comes at a high incremental equipment
cost, the national net savings for TSL4
is substantially higher than TSL5/6. The
percentage of customers experiencing
lower life-cycle costs would range
between 52 and 76 percent, depending
on the design line. However, payback
periods at this standard level are as high
as 20 years for one design line, which
is more than half the operating life of a
transformer. In addition, the consumer
equipment cost before installation
would increase by as much as 30
percent for one design line, a significant
increase for customers. Furthermore, the
impacts of TSL4 on manufacturers
would be significant, contributing to as
much as a 24-percent reduction in the
INPV under the preservation-ofoperating-profit scenario. Additionally,
DOE projects that manufacturers will
experience negative net annual cash
flows during the compliance period,
irrespective of the markup scenario. The
magnitude of the peak, negative, net
annual cash flow is approximately half
of that of the positive-base-case cash
flow. The energy savings at TSL4 would
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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.
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d. Medium-Voltage, Dry-Type Trial
Standard Level 3
Next, the Department considered
TSL3, which would save an estimated
0.2 quads of energy through 2038.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.04 quads. For the
Nation as a whole, TSL3 would have a
net savings of $0.3 billion at a sevenpercent discount rate. The percentage of
transformer customers who would
experience lower life-cycle costs ranges
between 37 and 71 percent, depending
on the design line, with payback periods
of 10 years or less. The impacts on
manufacturers at TSL3 would be
significant, however, contributing to as
much as a 22-percent reduction in the
INPV under the preservation-ofoperating-profit scenario. In addition,
DOE projects the net annual cash flows
to be negative during the compliance
period, irrespective of the markup
scenario. The magnitude of the peak
negative net annual cash flow would be
approximately half of the positive-basecase cash flow. The energy savings at
TSL3 would reduce the installed
generating capacity by 0.3 GW, or
roughly 0.8 of a large, 400 MW
powerplant. The Department estimates
the associated emissions reductions
through 2038 of 12.8 Mt of CO2 and 5.3
kt of NOX. Thus, the Department
concludes that at this TSL, the benefits
of energy savings, generating capacity
reductions, positive national NPV, LCC
savings, and emission reductions would
be outweighed by the economic impacts
on manufacturers. Consequently, the
Department concludes that TSL3 is not
economically justified.
e. Medium-Voltage, Dry-Type Trial
Standard Level 2
Next, the Department considered
TSL2, which would save an estimated
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total of 0.1 quad of energy through 2038.
Discounted at 7 percent, the energy
savings through 2038 would reduce to
approximately 0.03 quads. For the
Nation as a whole, TSL2 would have a
net savings of $0.2 billion at a sevenpercent discount rate. The percentage of
transformer customers experiencing
lower life-cycle costs ranges between 26
and 61 percent, depending on the
design line, with payback periods of
eight years or less. The Department
considers impacts on manufacturers at
this standard level (at most a 13-percent
reduction in the INPV under the
preservation-of-operating-profit
scenario) to be reasonable. The energy
savings at TSL2 would reduce the
installed generating capacity by 0.2 GW,
or roughly half of a large, 400 MW
powerplant. The Department estimates
associated emissions reductions through
2037 of 8.9 Mt of CO2 and 3.7 kt of NOX.
Thus, the Department concludes that
this TSL has positive energy savings,
generating capacity reductions,
emission reductions, national NPV,
benefits to transformer customers, and
reasonable impacts on transformer
manufacturers. After considering the
costs and benefits of TSL2, the
Department finds that this trial standard
level will offer the maximum
improvement in efficiency that is
technologically feasible and
economically justified, and will result
in significant conservation of energy.
Therefore, the Department today
proposes to adopt the energy
conservation standards for mediumvoltage, dry-type distribution
transformers at TSL2.
VI. Procedural Issues and Regulatory
Review
A. Review Under Executive Order 12866
The Department has determined
today’s regulatory action is a
‘‘significant regulatory action’’ under
section 3(f)(1) of Executive Order 12866,
‘‘Regulatory Planning and Review.’’ 58
FR 51735 (October 4, 1993).
Accordingly, today’s action required a
regulatory impact analysis (RIA) and,
under the Executive Order, was subject
to review by the Office of Information
and Regulatory Affairs (OIRA) in the
Office of Management and Budget
(OMB). The Department presented to
OIRA for review the draft proposed rule
and other documents prepared for this
rulemaking, including the RIA, and has
included these documents in the
rulemaking record. They are available
for public review in the Resource Room
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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.
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TABLE VI.1.—NON-REGULATORY ALTERNATIVES AND THE PROPOSED STANDARD
Policy alternatives
Primary energy
savings
(quads)
Type
No New Regulatory Action ..................................................
Consumer Rebates .............................................................
Net present value
(billion $2004)
7% discount
rate
3% discount
rate
0.0
0.0
0.042
0.007
0.013
0.042
Liquid ....................................
MV Dry .................................
0.058
0.004
0.058
0.008
0.218
0.025
0.06
0.07
0.24
Liquid ....................................
MV Dry .................................
0.029
0.002
0.028
0.004
0.108
0.013
Total .....................................
0.03
0.03
0.12
Liquid ....................................
MV Dry .................................
2.28
0.113
2.31
0.207
8.78
0.683
Total .....................................
Proposed Standards at TSL2 .............................................
0.0
0.0
0.013
Total .....................................
Manufacturer Tax Credits ...................................................
0.0
0.0
0.007
Total .....................................
Consumer Tax Credits ........................................................
..............................................
Liquid ....................................
MV* Dry ................................
2.40
2.52
9.47
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* 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
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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: https://
www.gc.doe.gov.
Small businesses, as defined by the
Small Business Administration (SBA)
for the distribution transformer
manufacturing industry, are
manufacturing enterprises with 750
employees or fewer. The Department
reviewed today’s proposed rule under
the provisions of the Regulatory
Flexibility Act and the procedures and
policies published on February 19,
2003. On the basis of the foregoing, DOE
determined that it cannot certify that the
proposed rule (trial standard level 2, or
TSL2), if promulgated, would have no
significant economic impact on a
substantialnumber of small entities. The
Department made this determination
because of the potential impacts that the
proposed standard levels for mediumvoltage, dry-type distribution
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transformers would have on the small
businesses that manufacture them.
However, the Department notes that it
explicitly considered the impacts on
small medium-voltage, dry-type
businesses in selecting TSL2, rather
than selecting a higher trial standard
level.
The revenue attributable to the
medium-voltage, dry-type superclass
represents only about six percent of the
total revenues of the industry affected
by this rulemaking (i.e., the sum of
revenues from the liquid-immersed
superclass and the medium-voltage, drytype superclass). Because of the
potential impacts of today’s proposed
rule on small, medium-voltage, dry-type
manufacturers, DOE has prepared an
initial regulatory flexibility analysis
(IRFA) for this rulemaking. The IRFA
divides potential impacts on small
businesses into two broad categories: (1)
Impacts associated with transformer
design and manufacturing, and (2)
impacts associated with demonstrating
compliance with the standard using
DOE’s test procedure. The Department’s
test procedure rule does not require
manufacturers to take any action in the
absence of final energy conservation
standards for distribution transformers,
and thus any impact of that rule on
small businesses would be triggered by
the promulgation of the standard
proposed today.
The Department believes that there
will be no significant economic impact
on a substantial number of small liquidimmersed manufacturers because the
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transformers in the liquid-immersed
superclass are largely customized, and
small businesses can compete because
many of these transformers are unique
designs produced in relatively small
quantities for a given order. Small
manufacturers of liquid-immersed
transformers tend not to compete on the
higher-volume products and often
produce transformers for highly specific
applications. This strategy allows small
manufacturers of liquid-immersed units
to be competitive in certain liquidimmersed product markets.
Implementation of an energy
conservation standard would have a
relatively minor differential impact on
small manufacturers of liquid-immersed
distribution transformers. Disadvantages
to small businesses, such as having little
leverage over suppliers (e.g., core steel
suppliers), are present with or without
an energy conservation standard. Due to
the purchasing characteristics of their
customers, small manufacturers of
liquid-immersed transformers currently
produce transformers at TSL2, the
proposed level. Thus, conversion costs
(e.g., research and development costs,
capital investments) and the associated
manufacturer impacts on small
businesses are expected to be
insignificant at the proposed level,
TSL2.
The potential impacts on mediumvoltage, dry-type manufacturers (and
also the compliance demonstration cost
for liquid-immersed manufacturers) are
discussed in the following sections. The
Department has transmitted a copy of
this IRFA to the Chief Counsel for
Advocacy of the Small Business
Administration for review.
1. Reasons for the Proposed Rule
Part C of Title III of the Energy Policy
and Conservation Act (EPCA) provides
for an energy conservation program for
certain commercial and industrial
equipment. (42 U.S.C. 6311–6317) In
particular, section 346 of EPCA states
that the Secretary of Energy must
prescribe testing requirements and
energy conservation standards for those
distribution transformers for which the
Secretary determines that standards
would be technologically feasible and
economically justified, and would result
in significant energy savings, although
section 325(v) of EPCA in effect
modifies this provision by specifying
standards for low voltage, dry-type
distribution transformers. (42 U.S.C.
6295(v) and 6317(a))
On October 22, 1997, the Secretary of
Energy issued a determination that
‘‘based on its analysis of the information
now available, the Department has
determined that energy conservation
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standards for transformers appear to be
technologically feasible and
economically justified, and are likely to
result in significant savings.’’ 62 FR
54809. Recognizing that fact, EPACT
2005 set minimum efficiency levels for
low-voltage dry-type distribution
transformers and allowed the
Department to continue its analysis and
rulemaking for liquid-immersed and
medium-voltage dry-type distribution
transformers.
2. Objectives of, and Legal Basis for, the
Proposed Rule
The Department selects any new or
amended standard to achieve the
maximum improvement in energy
efficiency that is technologically
feasible and economically justified. (See
42 U.S.C. 6295(o)(2)(A), 6313(a), and 42
U.S.C. 6317(a) and (c)) If a proposed
standard is not designed to achieve the
maximum improvement in energy
efficiency or the maximum reduction in
energy use that is technologically
feasible, the Secretary states the reasons
for this in the proposed rule. To
determine whether economic
justification exists, the Department
reviews comments received and
conducts analysis to determine whether
the economic benefits of the proposed
standard exceed the costs to the greatest
extent practicable, taking into
consideration the seven factors set forth
in 42 U.S.C. 6295(o)(2)(B)(i) (see Section
II.B of this Notice). Further information
concerning the background of this
rulemaking is provided in Chapter 1 of
the TSD.
3. Description and Estimated Number of
Small Entities Regulated
By researching the distribution
transformer market, developing a
database of manufacturers, and
conducting interviews with
manufacturers (both large and small),
the Department was able to estimate the
number of small entities that would be
regulated under an energy conservation
standard. See chapter 12 of the TSD for
further discussion about the
methodology used in the Department’s
manufacturer impact analysis and its
analysis of small-business impacts.
The liquid-immersed superclass
accounts for about $1.3 billion in annual
sales and employment of about 4,250
production employees in the United
States. The Department estimates that,
of the approximately 25 U.S.
manufacturers that make liquidimmersed distribution transformers,
about 15 of them are small businesses.
About five of the small businesses have
fewer than 100 employees.
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The medium-voltage, dry-type
superclass accounts for about $84
million in annual sales and employment
of about 250–330 production employees
in the United States. The mediumvoltage, dry-type market is relatively
small compared to that of the liquidimmersed superclass. The Department
estimates that, of the 25 U.S.
manufacturers that make mediumvoltage, dry-type distribution
transformers, about 20 of them are small
businesses. About ten of these small
businesses have fewer than 100
employees.
4. Description and Estimate of
Compliance Requirements
Potential impacts on small businesses
come from two broad categories of
compliance requirements: (1) Impacts
associated with transformer design and
manufacturing, and (2) impacts
associated with demonstrating
compliance with the standard using the
Department’s test procedure.
In regard to impacts associated with
transformer design and manufacturing,
the margins and/or market share of
small businesses in the medium-voltage,
dry-type superclass could be hurt in the
long term by today’s proposed level,
TSL2. At TSL2, as opposed to TSL1,
small manufacturers would have less
flexibility in choosing a design path.
However, as discussed under subsection
6 (Significant alternatives to the rule)
below, the Department expects that the
differential impact on small, mediumvoltage, dry-type businesses (versus
large businesses) would be smaller in
moving from TSL1 to TSL2 than it
would be in moving from TSL2 to TSL3.
The rationale for the Department’s
expectation is best discussed in a
comparative context and is therefore
elaborated upon in subsection 6
(Significant alternatives to the rule). As
discussed in the introduction to this
IRFA, DOE expects that the differential
impact associated with transformer
design and manufacturing on small,
liquid-immersed businesses would be
negligible.
In regard to compliance
demonstration, the Department’s test
procedure for distribution transformers
employs an Alternative Efficiency
Determination Method (AEDM) which
would ease the burden on
manufacturers. 10 CFR Part 431,
Subpart K, Appendix A; 71 FR 24972.
The AEDM involves a sampling
procedure to compare manufactured
products’ efficiencies with those
predicted by computer design software.
Where the manufacturer uses an AEDM
for a basic model, it would not be
required to test units of the basic model
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to determine its efficiency for purposes
of establishing compliance with DOE
requirements. The professional skills
necessary to execute the AEDM include
the following: (1) Transformer design
software expertise (or access to such
expertise possessed by a third party),
and (2) electrical testing expertise and
moderate expertise with experimental
statistics (or access to such expertise
possessed by a third party). The
Department’s test procedure would
require periodic verification of the
AEDM.
The Department’s test procedure also
requires manufacturers to calibrate
equipment used for testing the
efficiency of transformers. Calibration
records would need to be maintained, if
the proposed energy conservation
standard is promulgated.
The testing, reporting, and
recordkeeping requirements associated
with an energy conservation standard
and its related test procedure would be
identical, irrespective of the trial
standard level chosen. Therefore, for
both the liquid-immersed and mediumvoltage, dry-type superclasses, testing,
reporting, and recordkeeping
requirements have not entered into the
Department’s choice of trial standard
level for today’s proposed rule.
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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.
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The entire medium-voltage, dry-type
industry has such low shipments that
no designs are produced at high volume.
There is little repeatability of designs, so
small businesses can competitively
produce many medium-voltage, drytype, open-wound designs. The
medium-voltage, dry-type industry as a
whole primarily has experience
producing baseline transformers and
transformers that would comply with
TSL1. In addition, the industry
produces a significant number of units
that would comply with TSL2, but
approximately one percent or less of the
market would comply with TSL3 or
higher. Therefore, all manufacturers,
including small businesses, would have
to develop designs to enable compliance
with TSL3 or higher—such research and
development costs would be more
burdensome to small businesses.
Product redesign costs tend to be fixed
and do not scale with sales volume.
Thus, small businesses would be at a
relative disadvantage at TSL3 and
higher because research and
development efforts would be on the
same scale as those for larger
companies, but these expenses would be
recouped over smaller sales volumes.
At TSL3 and above, DOE estimates
that net cash flows for the mediumvoltage, dry-type industry would go
negative during the compliance period.
At TSL3 and above, the impacts on the
industry as a whole are large and affect
businesses of all sizes, but there would
be some differential, increased impacts
on small businesses. For example, at
TSL3 and above, the use of grainoriented silicon core steel of M3 or
better will be needed. Cutting M3 core
steel on the core-mitering equipment
typically purchased by smaller
businesses can be problematic because
of the extremely thin laminations.
At TSL2, the level proposed today, all
medium-voltage, dry-type transformer
designs would have to have mitered
cores. (Mitering means the transformer
core’s joints intersect at 45 degree
angles, rather than at 90 degree angles
as is true for ‘‘butt-lap’’ designs; buttlap
designs are less energy efficient.) The
mitered core construction technique
could constrain the core-mitering
resources of small businesses that share
core-cutting capacity with production
lines for other transformers that are not
covered by this rulemaking (e.g., lowvoltage, dry-type distribution
transformers). At TSL1, many kVA
ratings could still be constructed using
butt-lap joints, alleviating this
constraint on core-mitering resources.
Thus, TSL1 is less capital-intensive for
small businesses than TSL2 (large
businesses would likely miter nearly all
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medium-voltage cores, even at TSL1). In
an industry such as the medium-voltage,
dry-type transformer industry, which is
heavily consolidated already, there is
the risk that TSL2 could lead to further
advantage for the largest manufacturers
and thus further concentrate the
industry’s production. The top three
manufacturers produce over 75 percent
of all the transformers in the mediumvoltage, dry-type superclass. Of these
three, two of them are small businesses.
The primary difference between TSL1
and TSL2 from the manufacturers’
viewpoint is that TSL1 preserves more
design pathways, each trading off
material for capital. Butt-lap designs
would be cost-effective at TSL1 for some
kVA ratings, which would allow small
businesses to remain more competitive
because they would not necessarily
have to make large capital outlays. TSL2
cannot be met cost-effectively with buttlap designs; thus TSL2 could hurt the
margins or decrease the market share of
small businesses in the long run. Some
small businesses might opt to purchase
pre-mitered cores at TSL2 rather than
investing in core-mitering equipment,
which would likely hurt their margins.
However, the differential impact on
small businesses (versus large
businesses) is expected to be lower in
moving from TSL1 to TSL2 than in
moving from TSL2 to TSL3. Today, the
market already demands significant
quantities of medium-voltage, dry-type
transformers that meet TSL2.
Chapter 12 of the TSD contains more
information about the impact of this
rulemaking on manufacturers. The
Department interviewed six small
businesses affected by this rulemaking
(see also section IV.F.1 above). The
Department also obtained information
about small business impacts while
interviewing manufacturers that exceed
the small business size threshold of 750
employees.
C. Review Under the Paperwork
Reduction Act
Adoption of today’s proposed rule
would have the effect of requiring that
manufacturers follow certain recordkeeping requirements in the test
procedure for distribution transformers,
not just for purposes of making
representations, but also to determine
compliance even in the absence of any
representation. As set forth in the test
procedure, manufacturers will become
subject to the record-keeping
requirements when today’s proposed
energy conservation standard for
distribution transformers takes effect. 10
CFR Part 431, Subpart K, Appendix A;
71 FR 24972. Thus, the standard will
impose new information or record
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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
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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
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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
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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.
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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
https://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
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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.
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L. Review Under Section 32 of the
Federal Energy Administration Act of
1974
The Department is required by section
32 of the Federal Energy Administration
Act (FEAA) of 1974 to inform the public
of the use and background of any
commercial standard in a proposed rule.
(15 U.S.C. 788) While the Department
had considered a commercial voluntary
standard (NEMA TP 1–2002) as one of
the trial standard levels, it did not
choose to regulate either liquidimmersed or medium-voltage dry-type
distribution transformers at this
efficiency level. Because today’s
proposed rule adopts more stringent
efficiency levels, Section 32 of the
FEAA does not apply.
M. Review Under the Information
Quality Bulletin for Peer Review
On December 16, 2004, the Office of
Management and Budget (OMB), in
consultation with the Office of Science
and Technology (OSTP), issued its Final
Information Quality Bulletin for Peer
Review (the Bulletin). (70 FR 2664,
January 14, 2005) The Bulletin
establishes that certain scientific
information shall be peer reviewed by
qualified specialists before it is
disseminated by the federal government,
including influential scientific
information related to agency regulatory
actions. The purpose of the bulletin is
to enhance the quality and credibility of
the Government’s scientific information.
The Department’s Office of Energy
Efficiency and Renewable Energy,
Building Technologies Program, held
formal in-progress peer reviews
covering the analyses (e.g., screening/
engineering analysis, life-cycle cost
analysis, manufacturing impact
analysis, and utility impact analysis)
used in conducting the energy efficiency
standards development process on June
28–29, 2005. The in-progress review is
a rigorous, formal and documented
evaluation process using objective
criteria and qualified and independent
reviewers to make a judgment of the
technical/scientific/business merit, the
actual or anticipated results, and the
productivity and management
effectiveness of programs and/or
projects. The Building Technologies
Program staff is preparing a peer review
report which, upon completion, will be
disseminated on the Office of Energy
Efficiency and Renewable Energy’s Web
site and included in the administrative
record for this rulemaking.
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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.
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B. Procedure for Submitting Requests To
Speak
Any person who has an interest in
today’s notice, or who is a
representative of a group or class of
persons that has an interest in these
issues, may request an opportunity to
make an oral presentation. Such persons
may hand-deliver requests to speak,
along with a computer diskette or CD in
WordPerfect, Microsoft Word, PDF, or
text (ASCII) file format to the address
shown in the ADDRESSES section at the
beginning of this notice of proposed
rulemaking between the hours of 9 a.m.
and 4 p.m., Monday through Friday,
except Federal holidays. Requests may
also be sent by mail or e-mail to:
Brenda.Edwards-Jones@ee.doe.gov.
Persons requesting to speak should
briefly describe the nature of their
interest in this rulemaking and provide
a telephone number for contact. The
Department requests persons selected to
be heard to submit an advance copy of
their statements at least two weeks
before the public meeting. At its
discretion, DOE may permit any person
who cannot supply an advance copy of
their statement to participate, if that
person has made advance alternative
arrangements with the Building
Technologies Program. The request to
give an oral presentation should ask for
such alternative arrangements.
C. Conduct of Public Meeting
The Department will designate a DOE
official to preside at the public meeting
and may also use a professional
facilitator to aid discussion. The
meeting will not be a judicial or
evidentiary-type public hearing, but
DOE will conduct it in accordance with
5 U.S.C. 553 and section 336 of EPCA,
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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:
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TransformerNOPRComment@ee.doe.
gov. Submit electronic comments in
WordPerfect, Microsoft Word, PDF, or
text (ASCII) file format and avoid the
use of special characters or any form of
encryption. Comments in electronic
format should be identified by the
docket number EE–RM/STD–00–550
and/or RIN number 1904–AB08, and
wherever possible carry the electronic
signature of the author. Absent an
electronic signature, comments
submitted electronically must be
followed and authenticated by
submitting the signed original paper
document. No telefacsimiles (faxes) will
be accepted.
According to 10 CFR 1004.11, any
person submitting information that he
or she believes to be confidential and
exempt by law from public disclosure
should submit two copies: One copy of
the document including all the
information believed to be confidential,
and one copy of the document with the
information believed to be confidential
deleted. The Department of Energy will
make its own determination about the
confidential status of the information
and treat it according to its
determination.
Factors of interest to the Department
when evaluating requests to treat
submitted information as confidential
include: (1) A description of the items;
(2) whether and why such items are
customarily treated as confidential
within the industry; (3) whether the
information is generally known by or
available from other sources; (4)
whether the information has previously
been made available to others without
obligation concerning its
confidentiality; (5) an explanation of the
competitive injury to the submitting
person which would result from public
disclosure; (6) when such information
might lose its confidential character due
to the passage of time; and (7) why
disclosure of the information would be
contrary to the public interest.
E. Issues on Which DOE Seeks Comment
The Department is particularly
interested in receiving comments and
views of interested parties concerning:
(1) The proposed tables of efficiency
ratings, and specifically areas where the
underlying analytical methods followed
for developing the efficiency values
resulted in discontinuities.
(2) The Department’s treatment of
rebuilt or refurbished transformers in
this rulemaking and the potential
impact on consumers, manufacturers,
and national energy use if they were
excluded.
(3) Whether less-flammable, liquidimmersed distribution transformers
E:\FR\FM\04AUP2.SGM
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Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
should be included in the same product
class as medium-voltage, dry-type
transformers. Currently the Department
considers dry-type transformers and
liquid-immersed transformers as
members of separate product classes.
(4) Whether stakeholders believe a
minimum efficiency standard for liquidimmersed distribution transformers
would contribute to design
standardization, and encourage
manufacturers to move to countries with
lower labor costs.
(5) The appropriateness of using
discount rates of seven percent and
three percent real to discount future
energy savings and emissions
reductions.
(6) Whether the Department should
include space occupancy costs in the
cost of transformers as a means of
accounting for space constraints.
(7) The IRFA and the potential
impacts on small businesses affected by
this rulemaking. Although the
Department is expressly inviting
comments related to the 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
Single-phase
Federal Regulations, Subpart K of Part
431 is proposed to be amended to read
as set forth below.
PART 431—ENERGY EFFICIENCY
PROGRAM FOR CERTAIN
COMMERCIAL AND INDUSTRIAL
EQUIPMENT
1. The authority citation for part 431
continues to read as follows:
Authority: 42 U.S.C. 6291–6317.
2. Section 431.196 is amended by
revising paragraphs (b) and (c) to read
as follows:
§ 431.196 Energy conservation standards
and their effective dates.
*
*
*
*
*
(b) Liquid-Immersed Distribution
Transformers. Liquid-immersed
distribution transformers manufactured
on or after January 1, 2010, shall have
an efficiency no less than:
Three-phase
Efficiency
(%) *
kVA
10 ..................................................................................
15 ..................................................................................
25 ..................................................................................
37.5 ...............................................................................
50 ..................................................................................
75 ..................................................................................
100 ................................................................................
167 ................................................................................
250 ................................................................................
333 ................................................................................
500 ................................................................................
667 ................................................................................
833 ................................................................................
98.40
98.56
98.73
98.85
98.90
99.04
99.10
99.21
99.26
99.31
99.38
99.42
99.45
Efficiency
(%) *
kVA
15 .................................................................................
30 .................................................................................
45 .................................................................................
75 .................................................................................
112.5 ............................................................................
150 ...............................................................................
225 ...............................................................................
300 ...............................................................................
500 ...............................................................................
750 ...............................................................................
1000 .............................................................................
1500 .............................................................................
2000 .............................................................................
2500 .............................................................................
98.36
98.62
98.76
98.91
99.01
99.08
99.17
99.23
99.32
99.24
99.29
99.36
99.40
99.44
* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 °C, and (2) for load-losses,
at the temperature of 55°C and 50 percent of nameplate load.
(c) Medium-Voltage Dry-Type
Distribution Transformers. Medium-
voltage dry-type distribution
transformers manufactured on or after
Single-phase
20–45 kV
efficiency
(%) *
gechino on PROD1PC61 with PROPOSALS
BIL
kVA
15 ..........................
25 ..........................
37.5 .......................
50 ..........................
75 ..........................
100 ........................
167 ........................
250 ........................
333 ........................
500 ........................
667 ........................
833 ........................
VerDate Aug<31>2005
22:31 Aug 03, 2006
Three-phase
≥96 kV
efficiency
(%) *
46–95 kV
efficiency
(%) *
98.10
98.33
98.49
98.60
98.73
98.82
98.96
99.07
99.14
99.22
99.27
99.31
Jkt 208001
January 1, 2010, shall have an efficiency
no less than:
97.86
98.12
98.30
98.42
98.57
98.67
98.83
98.95
99.03
99.12
99.18
99.23
PO 00000
BIL
kVA
........................
........................
........................
........................
98.53
98.63
98.80
98.91
98.99
99.09
99.15
99.20
15 ..........................
30 ..........................
45 ..........................
75 ..........................
112.5 .....................
150 ........................
225 ........................
300 ........................
500 ........................
750 ........................
1000 ......................
1500 ......................
2000 ......................
Frm 00053
Fmt 4701
Sfmt 4702
20–45 kV
efficiency
(%) *
E:\FR\FM\04AUP2.SGM
97.50
97.90
98.10
98.33
98.49
98.60
98.73
98.82
98.96
99.07
99.14
99.22
99.27
04AUP2
46–95 kV
efficiency
(%) *
97.19
97.63
97.86
98.12
98.30
98.42
98.57
98.67
98.83
98.95
99.03
99.12
99.18
≥96 kV
efficiency
(%) *
........................
........................
........................
........................
........................
........................
98.53
98.63
98.80
98.91
98.99
99.09
99.15
44408
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 / Proposed Rules
Single-phase
20–45 kV
efficiency
(%) *
BIL
kVA
Three-phase
46–95 kV
efficiency
(%) *
≥96 kV
efficiency
(%) *
BIL
kVA
20–45 kV
efficiency
(%) *
2500 ......................
99.31
46–95 kV
efficiency
(%) *
99.23
≥96 kV
efficiency
(%) *
99.20
* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 °C, and (2) for load-losses,
at the temperature of 75 °C and 50 percent of nameplate load.
[FR Doc. 06–6537 Filed 8–3–06; 8:45 am]
gechino on PROD1PC61 with PROPOSALS
BILLING CODE 6450–01–P
VerDate Aug<31>2005
22:31 Aug 03, 2006
Jkt 208001
PO 00000
Frm 00054
Fmt 4701
Sfmt 4702
E:\FR\FM\04AUP2.SGM
04AUP2
]]>Agencies
[Federal Register Volume 71, Number 150 (Friday, August 4, 2006)]
[Proposed Rules]
[Pages 44356-44408]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-6537]
[[Page 44355]]
-----------------------------------------------------------------------
Part II
Department of Energy
-----------------------------------------------------------------------
Office of Energy Efficiency and Renewable Energy
-----------------------------------------------------------------------
10 CFR Part 431
Energy Conservation Program for Commercial Equipment: Distribution
Transformers Energy Conservation Standards; Proposed Rule
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 /
Proposed Rules
[[Page 44356]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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: https://www.regulations.gov.
Follow the instructions for submitting comments.
E-mail: TransformerNOPR Comment@ee.doe.gov. Include docket
number EE-RM/STD-00-550 and/or RIN 1904-AB08 in the subject line of the
message.
Mail: Ms. Brenda Edwards-Jones, U.S. Department of Energy,
Building Technologies Program, Mailstop EE-2J, NOPR for Distribution
Transformers Energy Conservation Standards, docket number EE-RM/STD-00-
550 and/or RIN 1904-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:
Antonio.Bouza@ee.doe.gov.
Thomas B. DePriest, Esq., U.S. Department of Energy, Office of
General Counsel, GC-72, 1000 Independence Avenue, SW., Washington, DC
20585, (202) 586-9507, e-mail: Thomas.Depriest@hq.doe.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Summary of the Proposed Rule
II. Introduction
A. Consumer Overview
B. Authority
C. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
3. Process Improvement
III. General Discussion
A. Test Procedures
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
C. Energy Savings
D. Economic Justification
1. Economic Impact on Manufacturers and Commercial Consumers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
IV. Methodology and Discussion of Comments
A. Market and Technology Assessment
1. Product Classes
2. Definition of a Distribution Transformer
B. Engineering Analysis
1. Engineering Analysis Methodology
2. Engineering Analysis Inputs
3. Engineering Analysis Outputs
C. Life-Cycle Cost and Payback Period Analysis
1. Inputs Affecting Installed Cost
a. Equipment Price
b. Installation Costs
c. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Power Factor
d. Electricity Costs
e. Electricity Price Trends
3. Inputs Affecting Present Value of Annual Operating Cost
Savings
a. Standards Implementation Date
b. Discount Rate
4. Candidate Standard Levels
5. Trial Standard Levels
6. Miscellaneous Life-Cycle Cost Issues
a. Tax Impacts
b. Cost Recovery Under Deregulation, Rate Caps
c. Other Issues
D. National Impact Analysis--National Energy Savings and Net
Present Value Analysis
[[Page 44357]]
E. Commercial Consumer Subgroup Analysis
F. Manufacturer Impact Analysis
1. General Description
2. Industry Profile
3. Industry Cash-Flow Analysis
4. Subgroup Impact Analysis
5. Government Regulatory Impact Model Analysis
G. Employment Impact Analysis
H. Utility Impact Analysis
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
------------------------------------------------------------------------
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
[[Page 44358]]
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
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
Efficiency
kVA Efficiency (%) 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
----------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
[[Page 44359]]
2000................ 99.27 99.18 99.15
2500................ 99.31 99.23 99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K,
Appendix A; 71 FR 24972.
B. Authority
Title III of EPCA sets forth a variety of provisions designed to
improve energy efficiency. Part B of Title III (42 U.S.C. 6291-6309)
provides for the Energy Conservation Program for Consumer Products
other than Automobiles. Part C of Title III (42 U.S.C. 6311-6317)
establishes a similar program for ``Certain Industrial Equipment,'' and
includes distribution transformers, the subject of this rulemaking. The
Department publishes today's NOPR pursuant to Part C of Title III,
which provides for test procedures, labeling, and energy conservation
standards for distribution transformers and certain other products, and
authorizes DOE to require information and reports from manufacturers.
The distribution transformer test procedure appears in Title 10 Code of
Federal Regulations (CFR) Part 431, Subpart K, Appendix A; 71 FR 24972.
EPCA contains criteria for prescribing new or amended energy
conservation standards. The Department must prescribe standards only
for those distribution transformers for which DOE: (1) Has determined
that standards would be technologically feasible and economically
justified and would result in significant energy savings, and (2) has
prescribed test procedures. (42 U.S.C. 6317(a)) Moreover, as indicated
above, the Department analyzed whether today's proposed standards for
distribution transformers will achieve the maximum improvement in
energy efficiency that is technologically feasible and economically
justified. (See 42 U.S.C. 6295(o)(2)(A), 6316(a), and 6317(a) and (c))
In addition, DOE will decide whether today's proposed standard is
economically justified, after receiving comments on the proposed
standard, by determining whether the benefits of the standard exceed
its costs. The Department will make this determination by considering,
to the greatest extent practicable, the following seven factors which
are set forth in 42 U.S.C. 6295(o)(2)(B)(i):
(1) The economic impact of the standard 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: https://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: https://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: https://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 https://www.eere.energy.gov/buildings/
appliance_standards/commercial/distribution_transformers_draft_
analysis_nopr. html.
3. Process Improvement
The ``Process Rule,'' Procedures, Interpretations and Policies for
Consideration of New or Revised Energy Conservation Standards for
Consumer Products, Title 10 CFR Part 430, Subpart C, Appendix A,
applies to the development of energy-efficiency standards for consumer
products. While distribution transformers are considered a commercial
product, the Department decided to apply some of the provisions 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........................
