[Federal Register Volume 71, Number 150 (Friday, August 4, 2006)]
[Proposed Rules]
[Pages 44356-44408]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-6537]
[[Page 44355]]
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Part II
Department of Energy
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Office of Energy Efficiency and Renewable Energy
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10 CFR Part 431
Energy Conservation Program for Commercial Equipment: Distribution
Transformers Energy Conservation Standards; Proposed Rule
Federal Register / Vol. 71, No. 150 / Friday, August 4, 2006 /
Proposed Rules
[[Page 44356]]
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DEPARTMENT OF ENERGY
Office of Energy Efficiency and Renewable Energy
10 CFR Part 431
[Docket Number: EE-RM/STD-00-550]
RIN 1904-AB08
Energy Conservation Program for Commercial Equipment:
Distribution Transformers Energy Conservation Standards
AGENCY: Office of Energy Efficiency and Renewable Energy, Department of
Energy.
ACTION: Notice of proposed rulemaking and public meeting.
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SUMMARY: The Energy Policy and Conservation Act (EPCA or the Act)
authorizes the Department of Energy (DOE or the Department) to
establish energy conservation standards for various consumer products
and commercial and industrial equipment, including those distribution
transformers for which DOE determines that energy conservation
standards would be technologically feasible and economically justified,
and would result in significant energy savings. In this notice, the
Department is proposing energy conservation standards for distribution
transformers and is announcing a public meeting.
DATES: The Department will hold a public meeting on Wednesday,
September 27, 2006, from 9 a.m. to 4 p.m., in Washington, DC. The
Department must receive requests to speak at the public meeting before
4 p.m., Wednesday, September 13, 2006. The Department must receive a
signed original and an electronic copy of statements to be given at the
public meeting before 4 p.m., Wednesday, September 13, 2006.
The Department will accept comments, data, and information
regarding the notice of proposed rulemaking (NOPR) before and after the
public meeting, but no later than October 18, 2006. See section VII,
``Public Participation,'' of this NOPR for details.
ADDRESSES: The public meeting will be held at the U.S. Department of
Energy, Forrestal Building, Room 1E245, 1000 Independence Avenue, SW.,
Washington, DC. (Please note that foreign nationals visiting DOE
Headquarters are subject to advance security screening procedures,
requiring a 30-day advance notice. If you are a foreign national and
wish to participate in the workshop, please inform DOE of this fact as
soon as possible by contacting Ms. Brenda Edwards-Jones at (202) 586-
2945 so that the necessary procedures can be completed.)
You may submit comments, identified by docket number EE-RM/STD-00-
550 and/or Regulatory Information Number (RIN) 1904-AB08, by any of the
following methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the instructions for submitting comments.
E-mail: [email protected]. Include docket
number EE-RM/STD-00-550 and/or RIN 1904-AB08 in the subject line of the
message.
Mail: Ms. Brenda Edwards-Jones, U.S. Department of Energy,
Building Technologies Program, Mailstop EE-2J, NOPR for Distribution
Transformers Energy Conservation Standards, docket number EE-RM/STD-00-
550 and/or RIN 1904-AB08, 1000 Independence Avenue, SW., Washington, DC
20585-0121. Please submit one signed original paper copy.
Hand Delivery/Courier: Ms. Brenda Edwards-Jones, U.S.
Department of Energy, Building Technologies Program, Room 1J-018, 1000
Independence Avenue, SW., Washington, DC 20585. Telephone: (202) 586-
2945. Please submit one signed original paper copy.
Instructions: All submissions received must include the agency name
and docket number or RIN for this rulemaking. For detailed instructions
on submitting comments and additional information on the rulemaking
process, see section VII of this document (Public Participation).
Docket: For access to the docket to read background documents or
comments received, visit the U.S. Department of Energy, Forrestal
Building, Room 1J-018 (Resource Room of the Building Technologies
Program), 1000 Independence Avenue, SW., Washington, DC, (202) 586-
2945, between 9 a.m. and 4 p.m., Monday through Friday, except Federal
holidays. Please call Ms. Brenda Edwards-Jones at the above telephone
number for additional information regarding visiting the Resource Room.
Please note: The Department's Freedom of Information Reading Room
(formerly Room 1E-190 at the Forrestal Building) is no longer housing
rulemaking materials.
FOR FURTHER INFORMATION CONTACT: Antonio Bouza, Project Manager, Energy
Conservation Standards for Distribution Transformers, Docket No. EE-RM/
STD-00-550, U.S. Department of Energy, Energy Efficiency and Renewable
Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue,
SW., Washington, DC 20585-0121, (202) 586-4563, e-mail:
[email protected].
Thomas B. DePriest, Esq., U.S. Department of Energy, Office of
General Counsel, GC-72, 1000 Independence Avenue, SW., Washington, DC
20585, (202) 586-9507, e-mail: [email protected].
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Summary of the Proposed Rule
II. Introduction
A. Consumer Overview
B. Authority
C. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
3. Process Improvement
III. General Discussion
A. Test Procedures
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
C. Energy Savings
D. Economic Justification
1. Economic Impact on Manufacturers and Commercial Consumers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
IV. Methodology and Discussion of Comments
A. Market and Technology Assessment
1. Product Classes
2. Definition of a Distribution Transformer
B. Engineering Analysis
1. Engineering Analysis Methodology
2. Engineering Analysis Inputs
3. Engineering Analysis Outputs
C. Life-Cycle Cost and Payback Period Analysis
1. Inputs Affecting Installed Cost
a. Equipment Price
b. Installation Costs
c. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Power Factor
d. Electricity Costs
e. Electricity Price Trends
3. Inputs Affecting Present Value of Annual Operating Cost
Savings
a. Standards Implementation Date
b. Discount Rate
4. Candidate Standard Levels
5. Trial Standard Levels
6. Miscellaneous Life-Cycle Cost Issues
a. Tax Impacts
b. Cost Recovery Under Deregulation, Rate Caps
c. Other Issues
D. National Impact Analysis--National Energy Savings and Net
Present Value Analysis
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E. Commercial Consumer Subgroup Analysis
F. Manufacturer Impact Analysis
1. General Description
2. Industry Profile
3. Industry Cash-Flow Analysis
4. Subgroup Impact Analysis
5. Government Regulatory Impact Model Analysis
G. Employment Impact Analysis
H. Utility Impact Analysis
I. Environmental Analysis
V. Analytical Results
A. Economic Justification and Energy Savings
1. Economic Impacts on Commercial Consumers
a. Life-Cycle Cost and Payback Period
b. Rebuttable-Presumption Payback
c. Commercial Consumer Subgroup Analysis
2. Economic Impacts on Manufacturers
a. Industry Cash-Flow Analysis Results
b. Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Manufacturers that are Small Businesses
3. National Impact Analysis
a. Amount and Significance of Energy Savings
b. Energy Savings and Net Present Value
c. Impacts on Employment
4. Impact on Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation to Conserve Energy
7. Other Factors
B. Stakeholder Comments on the Selection of a Final Standard
C. Proposed Standard
1. Results for Liquid-Immersed Distribution Transformers
a. Liquid-Immersed Trial Standard Level 6
b. Liquid-Immersed Trial Standard Level 5
c. Liquid-Immersed Trial Standard Level 4
d. Liquid-Immersed Trial Standard Level 3
e. Liquid-Immersed Trial Standard Level 2
2. Results for Medium-Voltage, Dry-Type Distribution
Transformers
a. Medium-Voltage, Dry-Type Trial Standard Level 6
b. Medium-Voltage, Dry-Type Trial Standard Level 5
c. Medium-Voltage, Dry-Type Trial Standard Level 4
d. Medium-Voltage, Dry-Type Trial Standard Level 3
e. Medium-Voltage, Dry-Type Trial Standard Level 2
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Order 12866
B. Review Under the Regulatory Flexibility Act/Initial
Regulatory Flexibility Analysis
1. Reasons for the Proposed Rule
2. Objectives of, and Legal Basis for, the Proposed Rule
3. Description and Estimated Number of Small Entities Regulated
4. Description and Estimate of Compliance Requirements
5. Duplication, Overlap, and Conflict With Other Rules and
Regulations
6. Significant Alternatives to the Rule
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act
E. Review under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government
Appropriations Act of 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government
Appropriations Act of 2001
K. Review Under Executive Order 13211
L. Review Under Section 32 of the Federal Energy Administration
Act of 1974
M. Review Under the Information Quality Bulletin for Peer Review
VII. Public Participation
A. Attendance at Public Meeting
B. Procedure for Submitting Requests To Speak
C. Conduct of Public Meeting
D. Submission of Comments
E. Issues on Which DOE Seeks Comment
VIII. Approval of the Office of the Secretary
I. Summary of the Proposed Rule
Pursuant to the Energy Policy and Conservation Act, as amended, the
Department is proposing energy conservation standards for liquid-
immersed and medium-voltage, dry-type distribution transformers. The
Department believes these standards will achieve the maximum
improvement in energy efficiency that is technologically feasible and
economically justified, and will result in significant energy savings.
In the advance notice of proposed rulemaking (ANOPR) for distribution
transformers, the Department had also conducted analysis on low-
voltage, dry-type distribution transformers. 69 FR 45376 (July 29,
2004). However, the Energy Policy Act of 2005 (EPACT 2005) established
energy conservation standards for low-voltage, dry-type distribution
transformers. (42 U.S.C. 6295(y)) Because of these amendments, DOE
removed low-voltage, dry-type distribution transformers--product class
3 (low-voltage, dry-type, single-phase) and product class 4 (low-
voltage, dry-type, three-phase)--from this rulemaking. Table I.1 shows
the proposed standard levels for the product classes that are still
within the scope of this rulemaking.
Table I.1.--Proposed Standard Levels for Distribution Transformers
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Superclasses--product classes
(PC) Proposed standard levels
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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)
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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 liquid-immersed transformers and TSL2
for medium-voltage, dry-type transformers, would save a significant
amount of energy--an estimated 2.4 quads (quadrillion (1015)
British thermal units (BTU)) of cumulative energy over 29 years (2010-
2038). This amount is roughly equal to the total energy consumption of
the Commonwealth of Virginia in 2001. The economic impacts on
commercial consumers (i.e., the average life-cycle cost (LCC) savings)
are positive.
The national net present value (NPV) of TSL2 is $2.52 billion using
a seven-percent discount rate and $9.43 billion using a three-percent
discount rate, cumulative from 2010 to 2073 in 2004$. This is the
estimated total value of future savings minus the estimated increased
equipment costs, discounted
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to the year 2004. Using a real corporate discount rate of 8.9 percent,
the Department estimates the liquid-immersed and medium-voltage, dry-
type distribution transformer industry's NPV to be $558 million in
2004$. The impact of the proposed standard on liquid-immersed
transformer manufacturers' industry net present value (INPV) is
expected to be between a 2.4 percent loss and a 2.0 percent increase (-
$12.9 million to $10.7 million). The medium-voltage, dry-type
transformer industry is estimated to lose between 10.1 percent and 13.4
percent of its NPV (-$3.3 million to -$4.3 million) as a result of the
proposed standard. Based on the Department's interviews with the major
manufacturers of distribution transformers, DOE expects minimal plant
closings or loss of employment as a result of the proposed standards.
The proposed standards will lead to reductions in greenhouse gases,
resulting in cumulative (undiscounted) emission reductions of 167.1
million tons (Mt) of carbon dioxide (CO2). Additionally, the
standards would generate 46.4 thousand tons (kt) of nitrogen oxides
(NOX) emissions reductions or a similar amount of
NOX emissions allowance credits in areas where such
emissions are subject to emissions caps. The Department expects the
energy savings from the proposed standards to eliminate the need for
approximately 11 new 400-megawatt (MW) power plants by 2038.
Therefore, the Department concludes that the benefits (energy
savings, commercial consumer LCC savings, national NPV increases, and
emissions reductions) to the Nation of the proposed standards outweigh
their costs (loss of manufacturer NPV and commercial consumer LCC
increases for some users of distribution transformers). The Department
concludes that the proposed standards of TSL2 for liquid-immersed and
TSL2 for medium-voltage, dry-type transformers are technologically
feasible and economically justified. At present, both liquid-immersed
and medium-voltage, dry-type transformers are commercially available at
the TSL2 standard level.
II. Introduction
A. Consumer Overview
The Department is proposing to set energy-efficiency standard
levels for distribution transformers as shown in Tables II.1 and II.2.
The proposed standard would apply to liquid-immersed and medium-
voltage, dry-type distribution transformers manufactured for sale in
the United States, or imported to the United States, on or after
January 1, 2010. In preparing these tables, the Department identified
some areas where the analytical methods used to develop the efficiency
values resulted in discontinuities in the table of efficiencies.
Generally, larger transformers will have greater efficiency than
smaller transformers, all other factors being equal. Not all efficiency
ratings that result from the Department's analysis fit this pattern.
The Department invites comment on all the efficiency ratings.
Table II.1.--Proposed Standard Level, TSL2, for Liquid-Immersed Distribution Transformers
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Single-phase Three-phase
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Efficiency
kVA Efficiency (%) kVA (%)
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10......................................... 98.40 15................................ 98.36
15......................................... 98.56 30................................ 98.62
25......................................... 98.73 45................................ 98.76
37.5....................................... 98.85 75................................ 98.91
50......................................... 98.90 112.5............................. 99.01
75......................................... 99.04 150............................... 99.08
100........................................ 99.10 225............................... 99.17
167........................................ 99.21 300............................... 99.23
250........................................ 99.26 500............................... 99.32
333........................................ 99.31 750............................... 99.24
500........................................ 99.38 1000.............................. 99.29
667........................................ 99.42 1500.............................. 99.36
833........................................ 99.45 2000.............................. 99.40
2500.............................. 99.44
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Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test-
Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
Table II.2.--Proposed Standard Level, TSL2, for Medium-Voltage, Dry-Type Distribution Transformers
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Single-phase Three-phase
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20-45 kV 46-95 kV 46-95 kV >=96 kV
BIL kVA efficiency efficiency >=96 kV 20-45 kV efficiency efficiency efficiency kVA
(%) (%) efficiency (%) (%) (%) (%)
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15............................... 98.10 97.86 ............... 15.................. 97.50 97.19 ..............
25............................... 98.33 98.12 ............... 30.................. 97.90 97.63 ..............
37.5............................. 98.49 98.30 ............... 45.................. 98.10 97.86 ..............
50............................... 98.60 98.42 ............... 75.................. 98.33 98.12 ..............
75............................... 98.73 98.57 98.53 112.5............... 98.49 98.30 ..............
100.............................. 98.82 98.67 98.63 150................. 98.60 98.42 ..............
167.............................. 98.96 98.83 98.80 225................. 98.73 98.57 98.53
250.............................. 99.07 98.95 98.91 300................. 98.82 98.67 98.63
333.............................. 99.14 99.03 98.99 500................. 98.96 98.83 98.80
500.............................. 99.22 99.12 99.09 750................. 99.07 98.95 98.91
667.............................. 99.27 99.18 99.15 1000................ 99.14 99.03 98.99
833.............................. 99.31 99.23 99.20 1500................ 99.22 99.12 99.09
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2000................ 99.27 99.18 99.15
2500................ 99.31 99.23 99.20
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Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K,
Appendix A; 71 FR 24972.
B. Authority
Title III of EPCA sets forth a variety of provisions designed to
improve energy efficiency. Part B of Title III (42 U.S.C. 6291-6309)
provides for the Energy Conservation Program for Consumer Products
other than Automobiles. Part C of Title III (42 U.S.C. 6311-6317)
establishes a similar program for ``Certain Industrial Equipment,'' and
includes distribution transformers, the subject of this rulemaking. The
Department publishes today's NOPR pursuant to Part C of Title III,
which provides for test procedures, labeling, and energy conservation
standards for distribution transformers and certain other products, and
authorizes DOE to require information and reports from manufacturers.
The distribution transformer test procedure appears in Title 10 Code of
Federal Regulations (CFR) Part 431, Subpart K, Appendix A; 71 FR 24972.
EPCA contains criteria for prescribing new or amended energy
conservation standards. The Department must prescribe standards only
for those distribution transformers for which DOE: (1) Has determined
that standards would be technologically feasible and economically
justified and would result in significant energy savings, and (2) has
prescribed test procedures. (42 U.S.C. 6317(a)) Moreover, as indicated
above, the Department analyzed whether today's proposed standards for
distribution transformers will achieve the maximum improvement in
energy efficiency that is technologically feasible and economically
justified. (See 42 U.S.C. 6295(o)(2)(A), 6316(a), and 6317(a) and (c))
In addition, DOE will decide whether today's proposed standard is
economically justified, after receiving comments on the proposed
standard, by determining whether the benefits of the standard exceed
its costs. The Department will make this determination by considering,
to the greatest extent practicable, the following seven factors which
are set forth in 42 U.S.C. 6295(o)(2)(B)(i):
(1) The economic impact of the standard on manufacturers and
consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated
average life of products in the type (or class) compared to any
increase in the price, initial charges, or maintenance expenses for
the covered products that are likely to result from the imposition
of the standard;
(3) The total projected amount of energy savings likely to
result directly from the imposition of the standard;
(4) Any lessening of the utility or the performance of the
products likely to result from the imposition of the standard;
(5) The impact of any lessening of competition, as determined in
writing by the Attorney General, that is likely to result from the
imposition of the standard;
(6) The need for national energy conservation; and
(7) Other factors the Secretary considers relevant.
In developing energy conservation standards for distribution
transformers, DOE is also applying certain other provisions of 42
U.S.C. 6295. First, the Department will not prescribe a standard for
the product if interested persons have established by a preponderance
of the evidence that the standard is likely to result in the
unavailability in the United States of any type (or class) of this
product with performance characteristics, features, sizes, capacities,
and volume that are substantially the same as those generally available
in the United States. (See 42 U.S.C. 6295(o)(4))
Second, DOE is applying 42 U.S.C. 6295(o)(2)(B)(iii), which
establishes a rebuttable presumption that a standard is economically
justified if the Secretary finds that ``the additional cost to the
consumer of purchasing a product complying with an energy conservation
standard level will be less than three times the value of the energy *
* * savings during the first year that the consumer will receive as a
result of the standard, as calculated under the applicable test
procedure * * *'' The rebuttable-presumption test is an alternative
path to establishing economic justification.
Third, in setting standards for a type or class of equipment that
has two or more subcategories, DOE will specify a different standard
level than that which applies generally to such type or class of
equipment for any group of products ``which have the same function or
intended use, if * * * products within such group--(A) consume a
different kind of energy from that consumed by other covered products
within such type (or class); or (B) have a capacity or other
performance-related feature which other products within such type (or
class) do not have and such feature justifies a higher or lower
standard'' than applies or will apply to the other products. (See 42
U.S.C. 6295(q)(1)) In determining whether a performance-related feature
justifies such a different standard for a group of products, the
Department considers such factors as the utility to the consumer of
such a feature and other factors DOE deems appropriate. Any rule
prescribing such a standard will include an explanation of the basis on
which DOE established such higher or lower level. (See 42 U.S.C.
6295(q)(2))
Federal energy efficiency requirements for equipment covered by 42
U.S.C. 6317 generally supersede State laws or regulations concerning
energy conservation testing, labeling, and standards. (42 U.S.C.
6297(a)-(c) and 42 U.S.C. 6316(a)) The Department can, however, grant
waivers of preemption for particular State laws or regulations, in
accordance with the procedures and other provisions of section 327(d)
of the Act. (42 U.S.C. 6297(d) and 42 U.S.C. 6316(a))
C. Background
1. Current Standards
Presently, there are no national energy conservation standards for
the liquid-immersed and medium-voltage, dry-type distribution
transformers covered by this rulemaking. However, on August 8, 2005,
EPACT 2005 established energy conservation standards for low-voltage,
dry-type distribution transformers that
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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 then-
newly published National Electrical Manufacturers Association (NEMA)
Standards Publication No. TP 1-1996, Guide for Determining Energy
Efficiency for Distribution Transformers, along with the efficiency
levels previously considered by the Department in the determination
study.\1\ In its supplemental assessment, ORNL-6925, the ORNL research
team used a more accurate analytical model and better transformer
market and loading data developed following the publication of ORNL-
6847. Downloadable versions of both ORNL reports are available on the
DOE Web site at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html
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\1\ Note: NEMA later updated TP 1 in 2002 (NEMA TP 1-2002), in
which it increased some of the efficiency levels. The latest version
of TP 1 is available at the NEMA Web site: http://www.nema.org/stds/tp1.cfm#download.
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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.
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\2\ The Department published a notice of availability of the
Framework Document in the Federal Register. 65 FR 59761 (October 6,
2000). The Framework Document itself is available on the DOE Web
site: http://www.eere.energy.gov/buildings/appliance_standards/commercial/pdfs/trans_framework.pdf.
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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
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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 three-phase, low-voltage dry-type distribution transformers
in this rulemaking.
In conjunction with this NOPR, the Department also published on its
website the complete TSD and several spreadsheets. The TSD contains
technical documentation of each analysis conducted under this
rulemaking, providing specific information on the methodology and
results. The spreadsheets, discussed in the relevant TSD chapters,
represent the analytical tools and results that support today's
proposed rule. The engineering analysis spreadsheets represent the
Department's design database, providing the cost-efficiency
relationships for the 10 specific distribution transformer units
analyzed--five liquid-immersed and five medium-voltage, dry-type units.
The LCC spreadsheet calculates the LCC and payback periods at six
standard levels for these representative units. The national impact
analysis spreadsheet tool calculates impacts of efficiency standards on
distribution transformer shipments, as well as the NES and NPV of the
standard levels considered. The MIA spreadsheet evaluates the financial
impact of standards on distribution transformer manufacturers. All of
these spreadsheet tools are posted on the Department's Web site, along
with the complete NOPR TSD, at http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html html.
3. Process Improvement
The ``Process Rule,'' Procedures, Interpretations and Policies for
Consideration of New or Revised Energy Conservation Standards for
Consumer Products, Title 10 CFR Part 430, Subpart C, Appendix A,
applies to the development of energy-efficiency standards for consumer
products. While distribution transformers are considered a commercial
product, the Department decided to apply some of the provisions of the
``Process Rule'' to this rulemaking.
In today's notice, the Department describes the framework and
methodologies for developing the proposed standards. The framework and
methodologies reflect improvements made, and steps taken, in accordance
with the Process Rule, including DOE's use of economic models and
analytical tools. Since the rulemaking process is dynamic, if timely
new data, models, or tools that enhance the development of standards
become available, the Department will incorporate them into the
rulemaking.
III. General Discussion
A. Test Procedures
Section 7(b) of the Process Rule requires that the Department
propose necessary modifications to the test procedure for a product
before issuing a NOPR concerning efficiency standards for that product.
Section 7(c) of the Process Rule states that DOE will issue a final,
modified test procedure prior to issuing a proposed rule for energy
conservation standards. The test procedure for distribution
transformers was published as a final rule on April 27, 2006. 71 FR
24972.
B. Technological Feasibility
1. General
The Department considers design options technologically feasible if
they are in use by the respective industry or if research has
progressed to the development of a working prototype. The Process Rule
sets forth a definition of technological feasibility as follows:
``Technologies incorporated in commercially available products or in
working prototypes will be considered technologically feasible.'' 10
CFR Part 430, Subpart C, Appendix A, section 4(a)(4)(i).
In each standards rulemaking, the Department conducts a screening
analysis, which is based on information gathered regarding existing
technology options and prototype designs. In consultation with
manufacturers, design engineers, and other stakeholders, the Department
develops a list of design options for consideration in the rulemaking.
Once the Department has determined that a particular design option is
technologically feasible, it then further evaluates each design option
in light of the other three criteria in the Process Rule. 10 CFR Part
430, Subpart C, Appendix A, section 4(a)(3) and (4). The three
additional criteria are: (a) Practicability to manufacture, install, or
service, (b) adverse impacts on product utility or availability, or (c)
health or safety concerns that cannot be resolved. 10 CFR Part 430,
Subpart C, Appendix A, section 4(a). All design options that pass these
screening criteria are candidates for further assessment.
As discussed in the ANOPR for this rulemaking, the Department is
not considering the following design options because they do not meet
one or more of the screening criteria: Silver as a conductor material,
high-temperature superconductors, amorphous core material in stacked
core configuration, carbon composite materials for heat removal, high-
temperature insulating material, and solid-state (power electronics)
technology. 69 FR 45387. For the NOPR, there were no changes to the
list of technology options screened out of the ANOPR analysis.
Discussion of the application of the screening analysis criteria to the
design options appears in Chapter 4 of the TSD.
The Department believes that all of the efficiency levels evaluated
in today's notice are technologically feasible. The technologies
incorporated in the transformer design database have all been used (or
are being used) in commercially available products or working
prototypes. The designs all incorporate core steel and conductor types
that are commercially available in today's transformer materials supply
market. Any one manufacturer may not be using all the materials
considered by the Department for a given model analyzed, but these
materials could be purchased from multiple suppliers today if design
changes warranted it.
In addition, to prepare transformer designs for evaluation, DOE
used transformer design software that is also used by manufacturers in
the U.S. and abroad. The Department evaluated the transformer design
software by comparing the software's designs against six transformers
it purchased, tested, and disassembled. For these units, the software
accurately predicted the performance and manufacturer selling prices
when using the same material cost, labor cost, and manufacturer markup
assumptions that were used in the engineering analysis for the NOPR
(see TSD Chapter 5, section 5.7).
For liquid-immersed distribution transformers, the designs prepared
by the software were all wound-core designs. The least efficient design
used M6 core steel and the most efficient used amorphous material. All
designs
[[Page 44362]]
contained in the Department's design database could be built today. For
medium-voltage, dry-type transformers, DOE used commercially available
core steels, ranging from M6 through domain-refined 9-mil (0.009 inch)
high permeability, grain-oriented steel (H-O DR). Core-construction
techniques included butt-lap, mitered, and cruciform construction. The
conductors and insulation types used were all conventional, and are
commercially available in distribution transformers today. Thus, the
Department believes that all the efficiency levels discussed in today's
proposed rule are technologically feasible.
2. Maximum Technologically Feasible Levels
In developing today's proposed standards, the Department followed
the provisions of 42 U.S.C. 6295(p)(2), which states that, when the
Department proposes to adopt, or to decline to adopt, an amended or new
standard for each type (or class) of covered product, ``the Secretary
shall determine the maximum improvement in energy efficiency or maximum
reduction in energy use that is technologically feasible.'' The
Department determined the maximum technologically feasible (``max-
tech'') efficiency level in the engineering analysis (see TSD Chapter
5) using the most efficient materials not screened out and applying
design parameters that drove the transformer design software to create
designs at the highest efficiencies achievable. The Department then
used these highest-efficiency designs to establish the max-tech level
for the LCC analysis (see TSD Chapter 8). In the national impact
analysis (see TSD Chapter 10), the Department then scaled these max-
tech efficiencies to the other kVA ratings within a given design line,
establishing max-tech efficiencies at all the distribution transformer
kVA ratings. Tables III.1 and III.2 provide the complete list of max-
tech efficiency levels considered for all kVA ratings within each
product class.
Table III.1.--Max-Tech Levels for Liquid-Immersed Distribution Transformers
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
Efficiency
kVA Efficiency (%) kVA (%)
----------------------------------------------------------------------------------------------------------------
10......................................... 99.32 15................................ 99.31
15......................................... 99.39 30................................ 99.42
25......................................... 99.46 45................................ 99.47
37.5....................................... 99.51 75................................ 99.54
50......................................... 99.59 112.5............................. 99.58
75......................................... 99.59 150............................... 99.61
100........................................ 99.62 225............................... 99.65
167........................................ 99.66 300............................... 99.67
250........................................ 99.70 500............................... 99.71
333........................................ 99.72 750............................... 99.66
500........................................ 99.75 1000.............................. 99.68
667........................................ 99.77 1500.............................. 99.71
833........................................ 99.78 2000.............................. 99.73
2500.............................. 99.74
----------------------------------------------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-
Procedure. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
Table III.2.--Max.-Tech Levels for Medium-Voltage, Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
20-45 kV 46-95 kV 20-45 kV 46-95 kV >=96 kV
BIL kVA efficiency efficiency >=96 kV (%) kVA efficiency efficiency efficiency
(%) (%) (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 99.05 98.54 ............... 15.................. 98.75 98.08 ..............
25............................... 99.17 98.71 ............... 30.................. 98.95 98.38 ..............
37.5............................. 99.25 98.84 ............... 45.................. 99.05 98.54 ..............
50............................... 99.30 98.92 ............... 75.................. 99.17 98.71 ..............
75............................... 99.37 99.02 99.22 112.5............... 99.25 98.84 ..............
100.............................. 99.41 99.09 99.28 150................. 99.30 98.92 ..............
167.............................. 99.48 99.20 99.36 225................. 99.37 99.02 99.22
250.............................. 99.42 99.42 99.42 300................. 99.41 99.09 99.28
333.............................. 99.46 99.46 99.46 500................. 99.48 99.20 99.36
500.............................. 99.51 99.51 99.52 750................. 99.42 99.42 99.42
667.............................. 99.54 99.54 99.55 1000................ 99.46 99.46 99.46
833.............................. 99.57 99.57 99.57 1500................ 99.51 99.51 99.52
2000................ 99.54 99.54 99.55
2500................ 99.57 99.57 99.57
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-Procedure. 10 CFR Part 431, Subpart K,
Appendix A; 71 FR 24972.
[[Page 44363]]
C. Energy Savings
One of the criteria that govern the Department's adoption of
standards for distribution transformers is that the standard must
result in ``significant'' energy savings. (42 U.S.C. 6317(a)) While the
term ``significant'' is not defined by EPCA, a U.S. Court of Appeals,
in Natural Resources Defense Council v. Herrington, 768 F.2d 1355, 1373
(D.C. Cir. 1985), indicated that Congress intended ``significant''
energy savings in a similar context in Section 325 of the Act to be
savings that were not ``genuinely trivial.'' The energy savings for all
of the trial standard levels considered in this rulemaking are
nontrivial, and therefore the Department considers them ``significant''
as required by 42 U.S.C. 6317.
D. Economic Justification
As noted earlier, EPCA provides seven factors to be evaluated in
determining whether an energy conservation standard for distribution
transformers is economically justified. The following discusses how the
Department has addressed each of those seven factors thus far in this
rulemaking. (42 U.S.C. 6295(o)(2)(B)(i))
1. Economic Impact on Manufacturers and Commercial Consumers
The Process Rule established procedures, interpretations, and
policies to guide the Department in the consideration of new or revised
appliance efficiency standards. The provisions of the rule have direct
bearing on the implementation of the MIA. First, the Department used an
annual-cash-flow approach in determining the quantitative impacts of a
new or amended standard on manufacturers. This included both a short-
term assessment based on the cost and capital requirements during the
period between the announcement of a regulation and the time when the
regulation comes into effect, and a long-term assessment. Impacts
analyzed include industry NPV, cash flows by year, changes in revenue
and income, and other measures of impact, as appropriate. Second, the
Department analyzed and reported the impacts on different types of
manufacturers, with particular attention to impacts on small
manufacturers. Third, the Department considered the impact of standards
on domestic manufacturer employment, manufacturing capacity, plant
closures, and loss of capital investment. Finally, the Department took
into account cumulative impacts of different DOE regulations on
manufacturers.
For commercial consumers, measures of economic impact are the
changes in installed (first) cost and annual operating costs. To assess
the impact on first cost, the Department considered the percent
increase in the consumer equipment cost before installation. To assess
the impact on life-cycle costs, which include both consumer equipment
costs and annual operating costs, the Department conducted an LCC
analysis of the equipment at each candidate standard level (CSL) (see
below).
2. Life-Cycle Costs
The LCC is the sum of the purchase price, including the
installation, and the operating expense--including operating energy
consumption, maintenance, and repair expenditures--discounted over the
lifetime of the equipment. To determine the purchase price including
installation, DOE estimated the markups that are added to the
manufacturer selling price by distributors and contractors, and
estimated installation costs from an analysis of transformer
installation cost estimates for a wide range of weights and sizes. The
Department assumed that maintenance and repair costs are not dependent
on transformer efficiency. In estimating operating energy costs, DOE
used the full range of commercial consumer marginal energy prices,
which are the energy prices that correspond to incremental changes in
energy use.
For each distribution transformer representative unit, the
Department calculated both LCC and LCC savings from a base-case
scenario for six candidate standard efficiency levels. The six
candidate standard levels were chosen to correspond to the following:
NEMA TP 1-2002;
\1/3\ of efficiency difference between TP 1 and minimum
LCC;
\2/3\ of efficiency difference between TP 1 and minimum
LCC;
Minimum LCC;
Maximum energy savings with no change in LCC; and
Maximum technologically feasible.
In order to calculate the appropriate efficiency levels for kVA
ratings that were not analyzed (i.e., all the kVA ratings other than
the ten representative units), the Department applied a scaling rule to
extrapolate the findings on the ten representative units to these other
ratings. For information on the scaling rule, see section IV.B.1 and
TSD Chapter 5, section 5.2.2.
The Department presents the calculated LCC savings as a
distribution, with a mean value and range. The Department used a
distribution of consumer real discount rates for the calculations, with
mean values ranging from 3.3 to 7.5 percent, specific to the cost of
capital faced by purchasers of the representative units. Chapter 8 of
the TSD contains the details of the LCC calculations. The LCC is one of
the factors DOE considers in determining the economic justification for
a new or amended standard. (See 42 U.S.C. 6295(o)(2)(B)(i)(II))
3. Energy Savings
While significant conservation of energy is a separate statutory
requirement for imposing an energy conservation standard, in
determining the economic justification of a standard, the Department
considers the total projected energy savings that are expected to
result directly from the standard. (See 42 U.S.C.
6295(o)(2)(B)(i)(III)) The Department used the NES spreadsheet results
in its consideration of total projected savings. The savings figures
are discussed in section V.A.3 of this notice.
4. Lessening of Utility or Performance of Equipment
In establishing classes of products, and in evaluating design
options and the impact of potential standard levels, the Department
avoided having new standards for distribution transformers that lessen
the utility or performance of the equipment under consideration in this
rulemaking. None of the proposed trial standard levels reduces the
utility or performance of distribution transformers. (See 42 U.S.C.
6295(o)(2)(B)(i)(IV)) The Department's engineering options do not
change the utility and performance of distribution transformers. The
impact of any increase in transformer weight associated with efficiency
improvements is captured by the economic analysis. Specifically,
installation costs for pole-mounted transformers include estimates of
stronger pole and pole change-out costs that may be incurred with
heavier, more efficient transformers.
5. Impact of Any Lessening of Competition
The Department considers any lessening of competition that is
likely to result from standards. Accordingly, DOE has written to the
Attorney General to request that the Attorney General transmit to the
Secretary, not later than 60 days after the publication of this
proposed rule, a written determination of the impact, if any, of any
lessening of competition likely to result from the proposed standard,
together with an analysis of the nature and extent of such
[[Page 44364]]
impact. (See 42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii))
6. Need of the Nation To Conserve Energy
The non-monetary benefits of the proposed standard are likely to be
reflected in improvements to the security and reduced reliability costs
of the Nation's energy system--namely, reductions in the overall demand
for energy will result in reduced costs for maintaining reliability of
the Nation's electricity system. The Department conducts a utility
impact analysis to show the reduction in installed generation capacity
requirements. Reduced power demand (including peak power demand)
generally reduces the costs of maintaining the security and reliability
of the energy system.
The Department has determined that today's proposed standard should
result in reductions in greenhouse gas emissions. The Department
quantified a range of primary energy conversion factors and estimated
the emissions reductions associated with the generation displaced by
energy-efficiency standards. The environmental effects from each trial
standard level for this equipment are reported in the TSD environmental
assessment. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))
7. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, considers any other factors that the Secretary
deems to be relevant. (See 42 U.S.C. 6295(o)(2)(B)(i)(VII)) For today's
proposed standard, the Secretary took into consideration a factor
relating to several comments received at the ANOPR public meeting,
during the comment period following the meeting, and in the MIA
interviews. Stakeholders expressed concern about the increasing cost of
raw materials for building transformers, the volatility of material
prices, and the cumulative effect of material price increases on the
transformer industry (see section IV.B.2, Engineering Analysis Inputs).
The Department conducted supplementary engineering and LCC analyses
using first-quarter 2005 material prices and considered the impacts on
LCC savings and payback periods when evaluating the appropriate
standard levels for liquid-immersed and medium-voltage, dry-type
distribution transformers. The results of the engineering and LCC
analyses for the first-quarter 2005 material pricing analysis are in
TSD Appendix 5C.
IV. Methodology and Discussion of Comments
A. Market and Technology Assessment
1. Product Classes
In general, when evaluating and establishing energy-efficiency
standards, the Department divides covered products into classes by: (a)
The type of energy used, or (b) capacity, or other performance-related
features, such as those that affect both consumer utility and
efficiency. Different energy-efficiency standards may apply to
different product classes. As discussed in the ANOPR, the Department
received some guidance from stakeholders on establishing appropriate
product classes for the population of distribution transformers. 69 FR
45385. Originally, the Department created 10 product classes, dividing
up the population of distribution transformers by:
Type of transformer insulation--liquid-immersed or dry-
type;
Number of phases--single or three;
Voltage class--low or medium (for dry-type units only);
and
Basic impulse insulation level (for medium-voltage, dry-
type units only).
EPACT 2005 includes provisions establishing energy conservation
standards for two of the Department's product classes (PC3, low-
voltage, single-phase, dry-type and PC4, low-voltage, three-phase, dry-
type). (42 U.S.C. 6295(y)) With standards thereby established for low-
voltage, dry-type distribution transformers, the Department is no
longer considering these two product classes for standards. Table IV.1
presents the eight product classes that remain within the scope of this
rulemaking.
Table IV.1.--Distribution Transformer Product Classes for the NOPR
--------------------------------------------------------------------------------------------------------------------------------------------------------
PC No.* Insulation Voltage Phase BIL rating kVA range
--------------------------------------------------------------------------------------------------------------------------------------------------------
PC1............................... Liquid-Immersed...... ..................... Single............... ..................... 10-833 kVA.
PC2............................... Liquid-Immersed...... ..................... Three................ ..................... 15-2500 kVA.
PC5............................... Dry-Type............. Medium............... Single............... 20-45 kV BIL......... 15-833 kVA.
PC6............................... Dry-Type............. Medium............... Three................ 20-45 kV BIL......... 15-2500 kVA.
PC7............................... Dry-Type............. Medium............... Single............... 46-95 kV BIL......... 15-833 kVA.
PC8............................... Dry-Type............. Medium............... Three................ 46-95 kV BIL......... 15-2500 kVA.
PC9............................... Dry-Type............. Medium............... Single............... >=96 kV BIL.......... 75-833 kVA.
PC10.............................. Dry-Type............. Medium............... Three................ >=96 kV BIL.......... 225-2500 kVA.
--------------------------------------------------------------------------------------------------------------------------------------------------------
*Note: Although the PC3 and PC4 product classes are no longer included in this rulemaking, for consistency with prior material published under this
rulemaking, the Department has not renumbered the liquid-immersed and medium-voltage, dry-type product classes that remain.
DOE received no comments that requested modifications to the
Department's product classes as proposed in the ANOPR. However, Howard
Industries commented that it supported the independent categorization
of liquid-immersed and dry-type transformers. It pointed out that the
applications and type of customers for these two types of transformers
can vary widely. (Howard, No. 70 at p. 2) The Department agrees with
this comment and continues to treat liquid-immersed and dry-type
transformers separately in its analysis.
Concerning the use of three basic impulse insulation level (BIL)
groupings for medium-voltage, dry-type transformers, Federal Pacific
Transformer (FPT) noted that BIL levels do affect cost and efficiency,
and agreed that DOE should conduct its analysis by BIL grouping. It
commented that the efficiency levels should be modeled according to the
BIL levels as much as possible. (FPT, No. 64 at p. 3) NEMA commented
that it was willing to change the BIL groupings in TP 1-2002 from two
to three, so TP 1 would have the same BIL groupings for medium-voltage,
dry-type transformers as the Department's proposal. (NEMA, No. 60 at p.
2) The Alliance to Save Energy (ASE) commented that the Department's
refinement of BIL classifications over TP 1 is justified and should
result in more appropriate efficiency levels. (ASE, No. 52 at p. 2 and
No. 75 at p. 2) Finally, the Oregon Department of Energy (ODOE)
commented that it supports the refinements that created three BIL
groupings for these transformers. (ODOE, No. 66 at p. 2) The Department
did not receive any comments critical of the three BIL
[[Page 44365]]
groupings for medium-voltage, dry-type transformers, and therefore
continues to use these same BIL groupings in today's proposed rule.
Howard Industries and ASE commented on whether DOE should regulate
the efficiency of liquid-immersed transformers. Howard commented that,
for liquid-immersed transformers--especially for the utility,
municipal, and co-operative segments--energy-efficiency standards
should be voluntary because these transformer customers are already
considering life-cycle costs in their purchasing decisions. (Howard,
No. 70 at p. 4) Howard commented that it feels a voluntary program
would be better for the whole utility market than a mandatory standard.
Howard believes a mandatory program would contribute to standardization
of liquid-immersed transformer designs, and encourage manufacturers to
move to countries with lower labor costs. Howard suggested that the
ballast and electric motor industries are two examples of products
where mandatory standards were implemented and domestic manufacturing
declined. (Howard, No. 70 at p. 2) ASE agreed with the Department's
decision that liquid-immersed transformers fall within the scope of the
standard. (ASE, No. 75 at p. 2) Under 42 U.S.C. 6317, the Department is
charged in this rulemaking with determining whether standards for
distribution transformers are technologically feasible and economically
justified and would result in significant energy savings. Based on the
Department's analysis and information available to date, standards for
liquid-immersed transformers appear to be technologically feasible and
economically justified, and would result in significant energy savings.
The Department considered a voluntary program, NEMA TP-1 in its
Determination Analysis, but concluded that the ``efficiency levels
would capture the most cost effective energy savings but may not
capture substantial energy savings that appear to be economically
justified and technologically feasible.'' 62 FR 54816. In addition, the
Department considered the impact of voluntary programs in its
regulatory impact analysis (see the report in the TSD ``Regulatory
Impact Analysis for Electrical Distribution Transformers''), and found
that a voluntary program would not result in standards that achieve the
maximum efficiency level that is technologically feasible and
economically justified. Thus, in accordance with 42 U.S.C. 6317, the
Department intends to continue to consider liquid-immersed distribution
transformers for energy efficiency standards. To gain a better
understanding of the concern raised by Howard Industries about minimum
efficiency standards leading to design standardization, the Department
requests that other stakeholders comment on this issue.
2. Definition of a Distribution Transformer
The Department received several comments from stakeholders on the
definition of a distribution transformer. The Department has
established the definition (and scope of this rulemaking) in its final
rule on the test procedure for distribution transformers. 10 CFR Part
431, Subpart K; 71 FR 24972.
EPCA directed DOE to develop standards for those ``distribution
transformers'' for which energy conservation standards would be
technologically feasible and economically justified, and would result
in significant energy savings, but did not specify a definition for a
distribution transformer. (42 U.S.C. 6317(a)) Thus, the Department
began developing a definition in the determination analysis, and
refined that definition through the test procedure rulemaking and this
rulemaking. This process was obviated to a substantial extent by the
enactment of EPACT 2005, which amended EPCA to, among other things,
include a definition of a distribution transformer. (42 U.S.C.
6291(35)) The existing statutory definition establishes the scope of
coverage for this rulemaking.
Before the passage of EPACT 2005, stakeholders had submitted
comments on the definition of a distribution transformer presented in
the ANOPR. These comments are summarized here with discussion on
whether or not the new EPCA definition of a distribution transformer,
promulgated in EPACT 2005, addresses the issues raised by the
stakeholders. For more detail on the definition of a distribution
transformer, please see the test procedure final rule notice. 71 FR
24972.
PEMCO and Southern Company commented on exclusions for
dimensionally or physically constrained transformers. PEMCO noted that
an exclusion for replacement or retrofit transformers is needed because
they must have exactly the same physical dimensions as the ones they
are replacing. (PEMCO, No. 57 at p. 1) Southern Company agreed, noting
that in retrofit installations, size and weight are a factor. Southern
commented that, as transformer efficiency increases, the units become
larger and obstructions and required minimum clearances are more
difficult to achieve. Southern noted that this is true for both liquid-
immersed, pad-mounted units and dry-type transformers installed in
buildings. It concluded that the increased size is likely to cause both
delivery and installation problems in many locations. (Southern, No. 71
at p. 2) At the ANOPR public meeting, Ameren commented that the
Department should consider the impact of different size/configurations
resulting from increased efficiency on the speed and ease of emergency
replacement transformers. (Public Meeting Transcript, No. 56.12 at pp.
255-256) The Department accounted for generally applicable dimensional
and physical constraints on transformer installation through the
inclusion of size- and weight-dependent installation costs in its LCC
model. These costs include potential pole change-out costs for large
overhead transformers, and the size- and weight-dependent labor and
equipment costs associated with installing larger transformers. The
costs estimated by the Department do not include the costs of
rehabilitating confined spaces that may have to be modified for the
installation of larger transformers. This issue is similar to the
situation that arises when utilities and contractors need to increase
transformer size due to load growth. One method of modeling such costs
would be to include a space-occupancy cost to the cost of transformer
operation. The Department invites comment on whether space-occupancy
costs should be included in transformer cost estimates and which
methods are appropriate for estimating such costs.
Howard and FPT expressed concern about distribution transformers
designed for use in specific environments. Howard recommended that
underground and subway-style transformers be excluded from the
standards. Howard noted that these transformers are often being
retrofitted into existing concrete vaults and, in most cases, the whole
concrete structure would need to be replaced if DOE mandated a more
efficient unit. (Howard, No. 70 at p. 3) FPT recommended that the
Department consider exempting mining transformers designed for
installation inside equipment with severe space limitations, due to
their radically different loss characteristics. FPT noted that
efficiency standards could cause problems in applications where these
transformers would not fit. (Public Meeting Transcript, No. 56.12 at
pp. 54-56; FPT, No. 64 at p. 2) ODOE
[[Page 44366]]
commented that it had no objection to the Department excluding
specialty transformers for the mining industry, provided that the
exclusion can be written so as not to inadvertently create a loophole
for other end uses. (ODOE, No. 66 at p. 2) As amended, EPCA does not
exclude these types of dimensionally constrained transformers from its
definition of distribution transformer. Furthermore, although 42 U.S.C.
6291(35)(B)(iii) authorizes DOE to exclude additional types of
distribution transformers, DOE does not have a sufficient basis for
excluding dimensionally constrained transformers under this provision.
While these transformers apparently are designed for special
applications, in line with 42 U.S.C. 6291(35)(B)(iii)(I), DOE lacks
specific information on the other two criteria, namely, whether these
transformers would be likely to be used in general purpose
applications, and whether significant energy savings would result from
applying standards to them. Stakeholders have submitted neither data on
the energy savings potential of standards for these transformers, nor
information as to the likelihood they could be used in general purpose
applications. Therefore, the Department is not proposing to exclude any
of the transformers discussed in this paragraph under section
321(35)(B)(iii) of EPCA. (42 U.S.C. 6291(35)(B)(iii))
On the issue of harmonic mitigating and harmonic tolerating
transformers, most of the comments proposed eliminating the exemption
for these types of distribution transformers. At the ANOPR public
meeting, both the American Council for an Energy Efficient Economy
(ACEEE) and NEMA commented that they supported the elimination of the
exemption for harmonic mitigating and harmonic tolerating (or K-rated)
transformers. (Public Meeting Transcript, No. 56.12 at p. 27 and p. 35)
In written comments, ACEEE, Harmonics Limited, NEMA, and ODOE all
recommended eliminating the exemption for harmonic mitigating and
harmonic tolerating (or K-rated) transformers. (ACEEE, No. 50 at p. 2
and No. 76 at p. 4; Harmonics Limited, No. 59 at p. 1; NEMA, No. 48 at
p. 3 and No. 60 at p. 2; ODOE, No. 66 at p. 2) PEMCO commented that it
agrees with including K-factor transformers as covered equipment to
stop the current practice of using that exemption to avoid efficiency
requirements. (PEMCO, No. 57 at p. 2)
EMS International Consulting (EMSIC) provided a different viewpoint
on harmonic tolerating transformers (or K-factor designs); it commented
that it believes K-factor and harmonic mitigating transformers (up to a
certain level of K-factor) should be subject to standards. (EMSIC, No.
73 at p. 3) FPT went further, proposing a more detailed treatment of K-
factor designs. FPT recognizes that some parties are specifying K-
factor transformers as a means of getting around State standards
requiring TP 1, and that this would probably happen more if DOE exempts
K-factor transformers broadly. Therefore, FPT recommended that: (1)
Transformers rated up to 300 kVA and having a K-factor of K-13 or less
be required to comply with the efficiency standards, and (2)
transformers above 300 kVA and having a K-factor of K-4 or less be
required to comply with the efficiency standards. (FPT, No. 64 at p. 2)
The definition of a distribution transformer in EPACT 2005 does not
contain an explicit exemption for harmonic mitigating or harmonic
tolerating (K-rated) transformers. Furthermore, DOE does not have a
sufficient basis for excluding them under 42 U.S.C. 6291(35)(B)(iii).
While these transformers apparently are designed for special
applications, in line with 42 U.S.C. 6291(35)(B)(iii)(I), DOE lacks
specific information on the other two criteria, namely, whether these
transformers would be likely to be used in general purpose
applications, and whether significant energy savings would result from
applying standards to them. Therefore, the Department is not proposing
to exclude any of the transformers discussed in this paragraph under
section 321(35)(B)(iii) of EPCA. 42 U.S.C. 6291(35)(B)(iii).
On the issue of non-ventilated transformers, the Department
received a comment from NEMA indicating that it agrees with the
Department's exclusion of non-ventilated transformers because of the
inherent core losses in such designs. (NEMA, No. 60 at p. 1) This
exclusion is now required by EPCA, because EPACT 2005 included an
exemption for sealed and non-ventilated transformers.
On the issue of refurbished transformers, the Department received
comments representing different viewpoints. Georgia Power commented
that DOE's documentation is not clear on the reuse of transformers that
have been removed from service for refurbishment. It indicated that it
saves approximately 11.5 percent of its total transformer budget by
refurbishing and reusing transformers. Georgia Power concluded that, if
the Department requires these units to be regulated, it will have a
significant financial impact on utilities. (Georgia Power, No. 78 at p.
3)
Manufacturers, on the other hand, appear to be concerned that the
increased cost of new, standards-compliant transformers would cause
some customers to either purchase rebuilt transformers or refurbish
existing ones they own. ERMCO is concerned that if these products are
not subject to standards, it may be possible for an end user to avoid
the standard by always rewinding failed units. ERMCO stated that there
are several independent and utility-owned repair shops that refurbish:
Some make minor repairs, others rewind coils. (ERMCO, No. 58 at p. 2)
Howard commented that when the final rule is established, it is
absolutely essential that it apply to new transformers, used
transformers, and repaired transformers. (Howard, No. 70 at p. 3) HVOLT
recommended that the Department require any rebuilt transformer that
has a winding replaced to meet the new standard, stating that this is
necessary to remove a major loophole and would ultimately result in
improved energy efficiency for the country. (HVOLT, No. 65 at p. 3 and
Public Meeting Transcript, No. 56.12 at p. 59) EMSIC commented that it
believes that all refurbished (``repaired'') units should be subject to
the new standards to close a potential loophole. (EMSIC, No. 73 at p.
3) ODOE agreed that re-wound transformers should be required to meet
the new standards. ODOE also commented that some organizations in the
Pacific Northwest have been involved in promotion of high-quality
rewinding practices. Through these programs, it has become evident that
high-quality work in this area can produce a product that meets the
same performance specifications as a new product, while poor-quality
work can seriously degrade performance. (ODOE, No. 66 at p. 2)
EPACT 2005's definition of a distribution transformer does not
mention refurbished or repaired transformers, and therefore no guidance
on treatment of these transformers is provided by the statute.
Furthermore, the Department's regulatory authority with respect to
refurbished equipment is not clearly delineated. EPCA, as amended by
EPACT 2005, seems to require that only newly manufactured distribution
transformers meet Federal efficiency requirements. (42 U.S.C. 6302,
6316(a) and 6317(a)(1)) Thus, DOE believes it lacks authority to
require used and repaired transformers to comply with energy
conservation standards. The same may be true for rebuilt transformers,
although DOE's authority is an issue. Generally, EPCA provides that
products, when
[[Page 44367]]
``manufactured,'' are subject to efficiency standards. (42 U.S.C. 6302
and 6316) It is arguable, but by no means clear, that rebuilt
transformers (i.e., those with one or more coils re-wound) could be
considered to be ``manufactured'' again when they are rebuilt, and
therefore be classified as new distribution transformers subject to
standards. If, however, rebuilt products cannot be classified as newly
manufactured, DOE would be subject to the same lack of authority to
regulate them as applies to other used and repaired products. In
addition, the Department does not have authority to regulate the
efficiency of distribution transformers re-wound by their owners (i.e.,
ownership of the transformer is not transferred or sold to another
party), despite the suggestion of some commenters that DOE do so. EPCA
provides authority to regulate only products that are sold, imported,
or otherwise placed in commerce. (42 U.S.C. 6291, 6311, and 6317(f)(1))
Throughout the history of its appliance and commercial equipment
energy conservation standards program, DOE has not sought to regulate
used units that have been reconditioned or rebuilt, or that have
undergone major repairs. For transformers, regulating this part of the
market, including the enforcement of efficiency requirements, would be
a complex and burdensome task. By and large, the Department believes
EPCA indicates a Congressional intent that DOE focus on the market for
new products, and believes this is where the most energy savings can be
achieved. For distribution transformers in particular, the Department
understands that, at present, rebuilt transformers are only a small
part of the market.
For all of these reasons, the Department is proposing not to
include energy conservation standards for used, repaired, and rebuilt
distribution transformers in this rulemaking. Nevertheless, the
Department recognizes the concerns raised by commenters about possible
substitution of rebuilt transformers for new transformers. If
conditions change--for example, if rebuilt transformers become a larger
segment of the transformer market--DOE will reconsider its decision not
to subject them to energy conservation requirements. The Department
invites comment on this decision.
On the issue of excluding special impedance transformers, the
Department received one comment from Howard. In response to the ANOPR
table of normal impedance ranges, Howard provided a slightly revised
table of ``normal'' impedance ranges that it believes are more in line
with the American National Standards Institute (ANSI) standards with
which most utility systems comply. (Howard, No. 70 at p. 3) Howard's
table contains slightly narrower bands of ``normal'' impedance ranges,
which would result in fewer transformers being subject to standards and
more transformers being classified as exempt. The Department is
concerned that some transformers designed for electricity distribution
could be manufactured with impedances outside normal ranges so that
they would not be subject to otherwise applicable efficiency standards.
Such transformers could have a competitive advantage over standards-
compliant distribution transformers. If this occurred, it would subvert
the standards. The Department also notes that, in NEMA's revised test
procedure document, NEMA TP 2-2005, the tables of normal impedance
ranges for both liquid-immersed and dry-type transformers are exactly
the same as those published by the Department. Thus, in the test
procedure final rule notice, the Department retained its tables of
``normal'' impedance ranges. 71 FR 24972.
B. Engineering Analysis
The purpose of the engineering analysis was to evaluate a range of
transformer efficiency levels and associated manufacturing selling
prices. The engineering analysis considered technologies and design
option combinations that were not screened out by the four criteria in
the screening analysis. In the LCC analysis, the Department used the
manufacturer selling price-efficiency relationships developed in the
engineering analysis when it considered the consumer costs of moving to
higher efficiency levels.
For the distribution transformers engineering analysis, the
Department learned that manufacturers in both the liquid-immersed and
medium-voltage, dry-type sectors commonly use software to design a
distribution transformer to fill a customer's order. This software-
design approach follows from the actual dynamics in the transformer
market, where customers often specify certain performance
characteristics and requirements. Manufacturers then compete for the
contract based on the customized designs they generate using their
software, which takes into account the customer's requirements and
current material costs.
Consistent with this approach, the Department used transformer
design software to create a database of distribution transformer
designs spanning a range of efficiencies, while tracking all the
modifications to the core, coil, labor, and other cost components. The
software creates transformer designs and cost and performance
characteristics associated with those designs that, when compiled,
characterize the relationship between cost and efficiency. The
Department selected software developed by an independent company,
Optimized Program Service (OPS), not associated with any single
manufacturer or manufacturer's association. The engineering analysis
design runs span a broad range of efficiencies from lowest first cost
to maximum technologically feasible. The data used in the engineering
analysis is discussed in Chapter 5 of the TSD.
1. Engineering Analysis Methodology
There exist certain fundamental relationships between the kVA
ratings of transformers and their physical size and performance. Termed
the ``0.75 scaling rule,'' these size-versus-performance relationships
arise from equations describing how a transformer's cost and efficiency
change with kVA rating. The Department used the 0.75 scaling rule to
reduce the number of units that needed to be analyzed for establishing
minimum efficiency standards for distribution transformers as a whole.
The findings on those units analyzed were later scaled to other kVA
ratings using the 0.75 scaling rule. To maintain the accuracy of the
0.75 scaling rule, DOE established engineering ``design lines.'' Each
design line consists of distribution transformers that have a full
range of kVA ratings and that have similar construction and engineering
principles. Some design lines consist of an entire product class, but
none spans more than a product class. The Department then selected one
representative unit from each of these design lines for analysis. The
0.75 scaling rule was a critical underlying factor in the engineering
analysis, since it enabled DOE to reduce the number of units analyzed
to 10. Discussion on use of the 0.75 scaling rule can be found in TSD
Chapter 5, section 5.2.2. Technical detail on the derivation of the
0.75 scaling rule can be found in TSD Appendix 5B.
In the ANOPR, the Department solicited comments on the use of the
0.75 scaling rule. 69 FR 45416. ASE and ODOE wrote that they support
the use of the 0.75 scaling rule, and believe it is the correct and
necessary approach to simplify the analysis. (ASE, No. 52 at p. 3 and
No. 75 at p. 3; ODOE, No. 66 at p. 4) HVOLT commented at the ANOPR
public meeting that the 0.75 scaling rule was used to develop the NEMA
TP 1
[[Page 44368]]
tables, and there have been no major complaints about it. (Public
Meeting Transcript, No. 56.12 at p. 92) PEMCO commented that it
routinely uses the 0.75 scaling rule in its business operations, and
that the rule works for scaling component costs for consistent
construction practice and within reasonable size differences. PEMCO
cautioned, however, that the higher the voltage class of the windings
and the closer to the lower end of a kVA product range, the greater the
error from the 0.75 scaling rule. (PEMCO, No. 57 at p. 1) The
Department appreciates this comment from PEMCO, as it had created the
engineering design lines to minimize error, particularly with respect
to the medium-voltage, dry-type BIL groupings. In addition to the three
BIL groupings, the Department also subdivided some of the product
classes into two or more engineering design lines, so the kVA rating of
the representative unit would not be scaled more than an order of
magnitude up or down in any one design line. It took both of these
steps to minimize any error from scaling, and to provide a more robust
analytic foundation for the proposed standards. Based on these comments
and the cautionary note from PEMCO, the Department will continue to
apply the 0.75 scaling rule to extrapolate findings to those kVA
ratings not specifically analyzed within each of the design lines.
Another critical issue on which stakeholders commented pertained to
the use of OPS software in the development of the Department's database
of transformer designs. HVOLT commented that the Department's
percentage cost increases for the 25 kVA pole-type transformer were not
large enough. It believes that the percentage cost difference between
the standard levels considered should be greater. (HVOLT, No. 65 at p.
2) The Department appreciates this comment, and looked carefully at all
the OPS software inputs and results, and discussed these with
individual manufacturers during site visits in 2005. The Department
recognizes that the manufacturer selling prices in the ANOPR base case
for the 25 kVA unit were too high, and that the percentage increase
from a larger base price would be smaller for the same absolute dollar
cost increase. Following revisions to the engineering analysis for the
25 kVA liquid-immersed, pole-type transformer, the baseline unit
manufacturer selling price decreased from around $800 to approximately
$500 and, as a result, the percentage change in manufacturer selling
prices between efficiency values has increased.
FPT expressed concern that the manufacturer selling prices for dry-
type transformers may rise more rapidly than is represented in the
engineering analysis. FPT is concerned that this may skew the decision-
making process regarding what efficiency levels are cost-justified.
(FPT, No. 64 at p. 2) Similarly, Howard commented that it believes the
inputs and outputs of the OPS program are inaccurate, since it found
the outputs of the software to be different from its own calculations.
Howard expressed concern at the number of compromises, generalizations,
and assumptions that could dilute the effectiveness of the results.
(Howard, No. 70 at p. 3) NEMA commented that, because LCC results seem
to justify standards higher than TP 1, the OPS design software may not
be accurately modeling real-world units. (NEMA, No. 48 at p. 2) NEMA
also commented that it had tested an actual unit that had a similar
technical specification to an OPS design, and found different results
than were reported by the Department. NEMA noted that the designs in
the Department's database were not built and tested, and therefore are
not representative of real transformers. (Public Meeting Transcript,
No. 56.12 at p. 35) In a written submission, NEMA provided further
detail on this comparison, and again questioned the real-world
predictive capabilities of the software used. (NEMA, No. 60 at p. 3)
In response to these comments, the Department reviewed and refined
the inputs to the OPS software in consultation with transformer
manufacturers, OPS, and the Department's technical experts. It is
important to recognize that there are many inputs to both the
engineering and the LCC analytical models. For both analytical models,
the Department updated its data and cost estimates for the NOPR
analysis. These refinements changed the resulting designs and
associated manufacturer selling price-efficiency relationships
discussed in section IV.B of today's notice and Chapter 5 of the TSD.
The Department appreciates and thanks NEMA and its members for
taking the time to locate and test a transformer that was similar to
the one published. The Department found two critical problems with the
comparison made. First, the design NEMA reviewed was not one DOE used
in the ANOPR engineering analysis, but rather a draft design produced
for comment two years before the ANOPR, in August 2002. Based on
stakeholder feedback on that draft design, DOE modified the inputs to
the OPS software when generating the ANOPR engineering database; thus,
that design was not included. Second, the two designs NEMA compared,
while having the same kVA rating, were not similar transformers. The
OPS design and the unit NEMA tested had different BIL ratings and would
be grouped in different product classes; therefore, different testing
results would be expected.
Concerning the comments on the accuracy of the OPS software, the
Department recognizes that differences between the Department's
engineering analysis results and those of manufacturers can be caused
by a number of factors, including different material prices, labor
estimates, modeling parameters (e.g., impedance range, inductance),
markups, and the consideration of different non-active transformer
components (e.g., gauges, tanks). The Department discussed its inputs
both in the ANOPR and during the manufacturer site visits, and revised
them as necessary to be the best approximation of real-world practices.
In the process of verifying the OPS software, DOE found that, under
similar input conditions and modeling parameters, the cost and
performance estimates in the Department's database are consistent with
real-world transformer designs. This was verified both by comparing
designs during manufacturer interviews in May 2005 and through a tear-
down analysis of six transformers. The Department purchased six 75 kVA
three-phase, low-voltage, dry-type transformers, and had the units
tested, disassembled, and analyzed. It then used the OPS software to
model the physical designs and generate an electrical analysis report.
The OPS software accurately predicted the actual performance of the six
transformers. In addition, using the 2000-2004 average material prices,
the Department calculated the manufacturer selling prices for each of
these six units using the same method as it used for the engineering
analysis. The Department found that the cost-efficiency relationship
(slope) for these six units tracked the cost-efficiency relationship
developed for the NOPR analysis. A description of this tear-down
analysis and its results can be found in TSD Chapter 5, section 5.7.
In addition to consulting with manufacturers and conducting a tear-
down analysis, the Department arranged for a third-party transformer
design engineer to prepare transformer designs based on the same inputs
as those used by OPS. The transformer design engineer looked at three
of the representative units published in this NOPR, and prepared
designs at a low-
[[Page 44369]]
first-cost, TP 1, and high-efficiency point. The Department then
compared these designs to the OPS output for those same kVA ratings on
an efficiency and manufacturer's selling price basis. It found that the
transformer engineer's designs tracked the cost and efficiency
improvements of the OPS designs. This work is discussed in Chapter 5 of
the TSD.
The Department is confident of the accuracy of the OPS software,
given the above-mentioned: (1) Comparison of engineering results with
manufacturers during interviews; (2) tear-down analysis; (3) comparison
of OPS designs with those of a third-party design engineer; and (4)
discussions with manufacturers who use the OPS software and consulting
services.
The Department received a few comments from stakeholders concerning
the design lines and the representative units selected from those
design lines. ACEEE commented that additional design lines may be
necessary to better represent all transformers and better identify the
lowest life-cycle cost points. ACEEE recommended looking at single-
phase, liquid-immersed distribution transformers between 50 kVA and 500
kVA and three-phase units below 150 kVA. (ACEEE, No. 76 at p. 1 and
Public Meeting Transcript, No. 56.12 at p. 27) In response to this
comment, the Department reviewed its design lines and selection of
representative units for the NOPR. Concerning an additional
representative unit between 50 kVA and 500 kVA, the Department does not
believe one is required. The 50 kVA (and 25 kVA pole-mounted) unit
scales up to a maximum of 167 kVA--including the 75 kVA, 100 kVA, and
167 kVA rated units. The 500 kVA unit scales down to only two ratings,
250 kVA and 333 kVA. Use of the 0.75 scaling rule within these ranges
is reasonable and accurate. Concerning an additional representative
unit in the three-phase, liquid-immersed product class below 150 kVA,
the Department also does not believe such an addition is necessary or
would substantially improve the analysis. The 150 kVA unit is scaled
down to 15 kVA, which is the maximum range over which the Department
applies the 0.75 scaling rule in its analysis (one order of magnitude).
The Department believes the 0.75 scaling rule is reasonable and
accurate at this range. Additionally, creating an additional design
line and analyzing a representative unit at kVA ratings below 150 kVA
for three-phase, liquid-immersed transformers would not significantly
improve the analysis. The shipments of three-phase, liquid-immersed
transformers below 150 kVA represent just 1.6 percent of all three-
phase, liquid-immersed units shipped, and a fraction of a percent of
the liquid-immersed product classes. Therefore, the Department did not
add any new representative units to the NOPR engineering analysis.
The Department received one comment concerning the treatment of
medium-voltage, less-flammable, liquid-immersed transformers in the
engineering analysis. Cooper Industries recommended that the Department
consider combining these units as design option combinations in product
classes 5 through 10 (the medium-voltage, dry-type product classes).
Cooper Industries noted that less-flammable, liquid-immersed
transformers are used in the same applications as dry-type transformers
and are recognized for this application in the National Electrical
Code. (Cooper, No. 62 at p. 2) As discussed in the ANOPR, the
Department considers liquid-immersed and dry-type transformers as
separate product classes. 69 FR 45385. It based this decision on input
from several manufacturers during site visits in 2002, a review of
industry standards--including those published by the Institute of
Electrical and Electronics Engineers, Inc. (IEEE), the NEMA TP 1-2002
voluntary standard, and four comments received from stakeholders on the
distribution transformer Framework Document. (Howard, No. 4 at p. 2;
NEMA, No. 7 at p. 5; TXU Electric and Gas, No. 12 at p. 5; ACEEE, No.
14 at p. 2) All of these stakeholders advised the Department to treat
liquid-immersed and dry-type distribution transformers separately when
establishing standards.
Countering the separate treatment of liquid-immersed and dry-type
transformers, Cooper asked that less-flammable, liquid-immersed units
(a special type of liquid-immersed transformer) be evaluated for
standards along with medium-voltage, dry-type units, because they can
be used in the same applications. The Department appreciates this
comment. However, energy efficiency standards are prescribed on the
basis of differences in features that affect energy use. (42 U.S.C.
6295(q)) An example of these different features is the cooling
mechanism for a transformer coil, whether it is air-cooled or liquid-
cooled. Standards are therefore not classified or organized on the
basis of whether they can service the same application. That said,
customer applications are taken into consideration for the Department's
economic analysis when a standard is developed and proposed (see the
LCC analysis, TSD Chapter 8). Thus, due to the fact that the efficiency
standard is applied on the basis of product class, not application, the
Department did not incorporate less-flammable, liquid-immersed units
into the medium-voltage dry-type analysis. The Department invites
comment on this issue and on the recommendation from Cooper.
2. Engineering Analysis Inputs
One of the critical issues identified by many stakeholders
commenting on the ANOPR analysis was whether DOE used prices that were
representative of current material prices. Georgia Power commented that
future transformer pricing may be affected by the decreasing number of
suppliers of transformer materials--such as mineral oil and core
steel--and that those still in business are already operating at full
capacity. At present there are only two domestic suppliers of core
steel: AK Steel and Allegheny Ludlum Steel Corporation (see TSD
Appendix 3A). Georgia Power noted that higher-efficiency transformers
will require more of these materials, which may result in material
shortages. It is concerned that this situation could have a major
impact on future transformer pricing and availability. (Georgia Power,
No. 78 at pp. 1-2) HVOLT submitted a similar comment, and mentioned
specifically that material prices have risen dramatically in step with
higher energy prices. HVOLT noted that virtually all material suppliers
now impose surcharges on top of their base material prices to yield the
net selling price. HVOLT recommended the Department conduct a more
detailed analysis of material prices. (HVOLT, No. 65 at pp. 2-3)
HVOLT and Edison Electric Institute (EEI) commented that material
prices at the time of the ANOPR public meeting (September 2004) had
increased relative to the material prices the Department used for its
ANOPR analysis (2001 prices). (Public Meeting Transcript, No. 56.12 at
p. 77; EEI, No. 63 at p. 3) The Southern Company commented that there
have been substantial price increases in many of the materials used to
build transformers, including copper and steel, and suggested that
these increases make high-efficiency transformers less cost-effective.
Southern recommended that recent raw material price increases and
reasonable projections of future prices be included in the updated cost
study produced for the NOPR. (Southern, No. 71 at p. 3) The National
Rural Electric Cooperative Association (NRECA) commented that it
supports and concurs with EEI's comments on the dramatic increase in
[[Page 44370]]
the prices of steel and copper in the last two years. (NRECA, No. 74 at
p. 2) In line with these statements, ERMCO commented that the 2004
material prices presented at the ANOPR public meeting looked
reasonable, although prices for mineral oil and wire (both aluminum and
copper) had increased substantially in the last month. ERMCO recognized
that material prices are volatile, and again emphasized the cost
increase for mineral oil. (ERMCO, No. 58 at p. 2)
In response to these comments and concerns about the increases in
material prices (many of which were also provided to the Department
verbally during the 2005 manufacturer site visits), the Department
conducted two material pricing scenarios for the NOPR, covering core
steel, conductors, insulation, and other key material inputs (see TSD
Chapter 5, section 5.4). One, the reference case scenario, uses a five-
year average of prices for these materials for the years 2000 through
2004. This scenario averages some of the material price volatility in
the market, including low and high material price points that occurred
during that time period. The second scenario is a ``current'' material
price analysis, using material prices from the first quarter of 2005.
This scenario provides a snapshot in time of material prices that were
of concern to the stakeholders who submitted comments to the
Department. When establishing a standard that will apply to all
distribution transformers manufactured after a date several years in
the future (here, January 1, 2010), the Department believes a material
price that incorporates average pricing over a time period is a better
basis for establishing the standard than using the material prices that
manufacturers typically pay in any one year. Thus, DOE used the
reference case (five-year average of material prices) as the basis for
the standards proposed today. The engineering analysis results based on
the material price reference case can be found in TSD Chapter 5. The
Department also calculated engineering analysis and LCC analysis
results based on the current (first quarter 2005) material price
scenario; these are provided in TSD Appendix 5C.
In addition, the Department worked to gain a better understanding
of the electrical core steel market, which is the main cost driver
behind the construction of distribution transformers. It conducted
interviews with both domestic core steel providers, two national steel
wholesalers, and two manufacturers of equipment that processes core
steel. The Department also reviewed publicly available information on
the steel market in general, including trends, pressures, and
constraints, such as input substitution opportunities and the supply-
demand effects of Chinese economic growth. The findings of the
Department's study of the electrical core steel market can be found in
TSD Appendix 3A. The Department used the information from this research
to improve its understanding of the core steel market and to verify the
comments received from stakeholders concerning the recent trend toward
increases in material prices, specifically electrical core steel.
During the ANOPR public meeting, ERMCO recommended that the
Department consider the impacts of tariffs on the availability (and
cost) of speciality steels. (Public Meeting Transcript, No. 56.12 at
pp. 243-244) The Department did consider the import duty on raw (un-
worked) Japanese core steel, specifically mechanically scribed, deep-
domain refined, core steel (ZDMH). For discussion on the treatment of
ZDMH core steel in this analysis, see TSD Chapter 5.
The Department also received a comment on the labor inputs used in
the engineering analysis. FPT commented that the labor calculations in
the ANOPR analysis for cutting and stacking core steel were incorrect.
It stated that the labor rates should not be based on hours/inch,
because of the different thicknesses of core steel. Stacking thinner
laminations of steels takes longer because more pieces of material must
be handled for each inch of core stack. (FPT, No. 64 at pp. 1-2) The
Department agrees with this comment and modified the methods used in
the engineering analysis for calculating the labor costs. The revised
method and stacking rates DOE used for the various grades of steel are
described in TSD Chapter 5.
3. Engineering Analysis Outputs
DOE received two comments on the energy losses associated with
auxiliary devices. During the ANOPR workshop, Ameren commented that the
Department should include the impact of losses from accessories in its
calculation and determination of national energy savings. (Public
Meeting Transcript, No. 56.12 at p. 254) ERMCO also commented on this
subject, requesting that an allowance be made for protective devices
for transformers (e.g., circuit breakers), which are sometimes
specified by utility companies. In its comment, ERMCO suggested two
possible approaches: (1) Have a separate table of efficiency ratings
for transformers with protective devices, or (2) do not include any
losses due to protective devices in the measurement of efficiency of
the transformer. (ERMCO, No. 58 at p. 1) The Department notes that the
measurement and representation of the efficiency of regulated
transformers is prescribed in the test procedures for distribution
transformers. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972. As
published, the test procedure directs manufacturers to provide an
efficiency representation for a regulated unit that does not include
losses from protective devices. The efficiency standard proposed today
only governs the performance of the basic transformer; it would not
apply to the protective devices and would not seek to regulate the
efficiency of these devices. The test procedure directs manufacturers
to either calculate and deduct losses from these protective devices, or
to by-pass the protective devices in the load-loss test set-up
configuration.
HVOLT, NEMA, and ODOE commented on manufacturer selling prices.
HVOLT commented during the ANOPR workshop that the actual selling
prices of liquid-immersed units are lower than was reported in DOE's
analysis. (Public Meeting Transcript, No. 56.12 at p. 78) HVOLT also
later stated that the price for a low-first-cost 25 kVA single-phase,
pole-mount transformer was on the order of $400, while the Department's
analysis reported $800. (Public Meeting Transcript, No. 56.12 at p. 96)
NEMA recommended that the Department contact individual manufacturers
and discuss the pricing of their lowest-first-cost transformers to
calibrate the engineering analysis. (NEMA, No. 48 at p. 2 and Public
Meeting Transcript, No. 56.12 at p. 35) ODOE echoed the comment from
NEMA, recommending that the Department check the pricing of
transformers sold by manufacturers. (ODOE, No. 66 at p. 3) Following
NEMA's and ODOE's recommendations, the Department spoke to individual
manufacturers (both NEMA members and non-NEMA members) about material
pricing, manufacturers' selling prices, OPS software inputs, and other
equipment costs (e.g., tanks, bushings, busbar). The adjustments DOE
made following these conversations resulted in a reduction in
manufacturer selling prices for some design lines. For example, the
low-first-cost design for the 25kVA single-phase, pole-mount
transformer went from approximately $800 per unit to around $500 per
unit using the five-year, average-material-price scenario.
DOE received two comments about the feasibility of manufacturing
the most
[[Page 44371]]
efficient designs produced in the engineering analysis. Cooper
conducted a design analysis of the 50 kVA pad-mount, the 150 kVA three-
phase, and the 1500 kVA three-phase, liquid-immersed units. It found
that it was not possible to meet the ANOPR candidate standard level 5
(CSL5) efficiency level. Furthermore, it found that, as the design
reaches ANOPR CSL3, the cost to produce the transformer generally
increases exponentially. Because of this, Cooper believes that the OPS
software does not account for realistic material performance
characteristics or realize the cost or productivity impact of these
design changes with regard to the manufacturing of a product. (Cooper,
No. 62 at p. 1) NRECA also questioned the validity of the highest
efficiency levels (ANOPR CSL4 and CSL5). It recommended that the
Department verify whether transformers with these efficiencies actually
exist or are merely theoretical designs on paper. (NRECA, No. 74 at p.
2)
As discussed in section IV.B.1, the Department took several steps
to verify the OPS software and the predictive capability of the
software to design transformers. The Department is confident in the
accuracy of the OPS software, given the: (1) Comparison of engineering
results with manufacturers during interviews; (2) tear-down analysis;
(3) comparison of OPS designs with those of a third-party design
engineer; and (4) discussions with manufacturers who use the OPS
software and consulting services. In response to Cooper's and NRECA's
comments on the maximum technologically feasible designs, the
Department notes that the design option combinations that achieved the
highest efficiencies in a given representative unit used non-
traditional materials, such as amorphous material and laser-scribed,
high-permeability, grain-oriented electrical steel. The core
destruction factors, packing factors, and other real-world adjustments
for production floor manufacturing are inputs that OPS has refined over
decades in consultation with its clients, some of which have
manufactured amorphous material and laser-scribed steel. If the core
material, winding, and construction are all built to the design report
specification, these are feasible designs. Details of the engineering
analysis can be found in TSD Chapter 5 and Appendices 5A, 5B, and 5C.
C. Life-Cycle Cost and Payback Period Analysis
This section describes the LCC and payback period (PBP) analysis
and the spreadsheet model DOE used for analyzing the economic impacts
on customers. Details of the spreadsheet model, and of all the inputs
to the LCC and PBP analysis, are in TSD Chapter 8. The Department
conducted the LCC and PBP analysis using a spreadsheet model developed
in Microsoft (MS) Excel for Windows 95 or above. When combined with
Crystal Ball (a commercially available software program), the LCC and
PBP model generates a Monte Carlo simulation to perform the analysis by
incorporating uncertainty and variability considerations. While the
Department included an annual maintenance cost as part of the LCC and
PBP calculation, it assumed that maintenance and repair costs are
independent of transformer efficiency.
The LCC is the total customer cost over the life of the equipment,
including purchase expense and operating costs (including energy
expenditures and maintenance). To compute the LCC, the Department
summed the installed price of a transformer and the discounted annual
future operating costs over the lifetime of the equipment. The PBP is
the change in purchase expense due to an increased efficiency standard
divided by the change in first-year operating cost that results from
the standard. The Department expresses PBP in years. The data inputs to
the PBP calculation are the purchase expense (otherwise known as the
total installed consumer cost or first cost) and the annual operating
costs for each selected design. The inputs to the transformer purchase
expense were the equipment price and the installation cost, with
appropriate markups. The inputs to the operating costs were the annual
energy consumption and the electricity price. The PBP calculation uses
the same inputs as the LCC analysis but, since it is a simple payback,
the operating cost is for the year the standard takes effect, assumed
to be 2010.
For each efficiency level analyzed, the LCC analysis required input
data for the total installed cost of the equipment, the operating cost,
and the discount rate. Table IV.2 summarizes the inputs and key
assumptions used to calculate the customer economic impacts of various
energy efficiency levels. Equipment price, installation cost, and
baseline and standard design selection affect the installed cost of the
equipment. Transformer loading, load growth, power factor, annual
energy use and demand, electricity costs, electricity price trends, and
maintenance costs affect the operating cost. The effective date of the
standard, the discount rate, and the lifetime of equipment affect the
calculation of the present value of annual operating cost savings from
a proposed standard. Table IV.2 shows how the Department modified these
inputs and key assumptions for the NOPR, relative to the ANOPR.
Table IV.2.--Summary of Inputs and Key Assumptions Used in the LCC and PBP Analyses
----------------------------------------------------------------------------------------------------------------
Inputs ANOPR description Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Equipment price......................... Derived by multiplying manufacturer Reduced distributor markup
selling price (from the engineering for dry-type added small
analysis) by distributor markup and distributor markup for
contractor markup plus sales tax for dry- liquid-immersed.
type transformers. For liquid-immersed
transformers, DOE used manufacturer
selling price plus sales tax. Shipping
costs were included for both types of
transformers.
Installation cost....................... Includes a weight-specific component, Added a pole replacement
derived from RS Means Electrical Cost component to design line
Data 2002 and a markup to cover 2.
installation labor, and equipment wear
and tear.
Baseline and standard design selection.. The selection of baseline and standard- Increased liquid-immersed
compliant transformers depended on transformer evaluation
customer behavior. For liquid-immersed percentage to 75%.
transformers, the fraction of purchases Divided dry-types into
evaluated was 50%, while for dry-type (1) small-capacity medium-
transformers, the fraction of evaluated voltage and (2) large-
purchases was 10%. The average A value capacity medium-voltage,
for evaluators was $5/watt, while the B with evaluation
value depended on expected transformer percentages of 50% and
load. 80%, respectively.
----------------------------------------------------------------------------------------------------------------
[[Page 44372]]
Affecting Operating Costs
----------------------------------------------------------------------------------------------------------------
Transformer loading..................... Loading depended on customer and Increased average peak
transformer characteristics. The average loading for medium-
initial liquid-immersed transformer voltage, dry-type
loading was 30% for 25 dry-type kVA and transformers from 75% to
59% for 1500 kVA transformers. The 85%.
average initial dry-type transformer
loading was 32% for 25 kVA and 37% for
2000 kVA transformers. The shipment-
weighted lifetime average loading was
33.6% for low-voltage, dry and 36.5% for
medium-voltage, dry. With load growth,
average installed liquid-immersed
transformer loading was 35% for 25 kVA
and 70% for 1500 kVA transformers with a
shipment-weighted lifetime average
loading of 52.9%.
Load growth............................. 1% per year for liquid-immersed and 0% per No change.
year for dry-type transformers.
Power factor............................ Assumed to be unity....................... No change.
Annual energy use and demand............ Derived from a statistical hourly use and No change.
demand load simulation for liquid-
immersed transformers, and estimated from
the 1995 Commercial Building Energy
Consumption Survey data for dry-type
transformers using factors derived from
hourly load data. Load losses varied as
the square of the load and were equal to
rated load losses at 100% loading.
Electricity costs....................... Derived from tariff-based and hourly based Updated tariff-based
electricity prices. Capacity costs electricity prices with
provided extra value for reducing losses 2004 tariff data.
at peak. Average marginal tariff-based Adjusted hourly based
retail electricity price: 6.4[cent]/kWh electricity prices for
for no-load losses and 7.4[cent]/kWh for inflation.
load losses. Average marginal wholesale
utility hourly based costs: 3.8[cent]/kWh
for no-load losses and 4.5[cent]/kWh for
load losses.
Electricity price trend................. Obtained from Annual Energy Outlook 2003 Updated to
(AEO2003). AEO2005.[dagger]
Maintenance cost........................ Annual maintenance cost did not vary cost No change.
as a function of efficiency.
----------------------------------------------------------------------------------------------------------------
Affecting Present Value of Annual Operating Cost Savings
----------------------------------------------------------------------------------------------------------------
Effective date.......................... Assumed to be 2007........................ Assumed to be 2010.
Discount rates.......................... Mean real discount rates ranged from 4.2% No change.
for owners of pole-mounted, liquid-
immersed transformers to 6.6% for dry-
type transformer owners.
Lifetime................................ Distribution of lifetimes, with mean No change.
lifetime for both liquid and dry-type
transformers assumed to be 32 years.
----------------------------------------------------------------------------------------------------------------
Candidate Standard Levels
----------------------------------------------------------------------------------------------------------------
Candidate standard levels............... Five efficiency levels for each design Six efficiency levels with
line with the minimum equal to TP 1 and the minimum equal to TP 1
the maximum from the most efficient and the maximum from the
designs from the engineering analysis. most efficient designs
from the engineering
analysis. Intermediate
efficiency levels for
each design line selected
using a redefined set of
LCC criteria (see section
III.D.1.b).
----------------------------------------------------------------------------------------------------------------
* The concept of using A and B loss evaluation combinations is discussed in TSD chapter 3, Total Owning Cost
Evaluation. Within the context of the LCC analysis, the A factor measures the value to a transformer
purchaser, in $/watt, of reducing no-load losses while the B factor measures the value, in $/watt, of reducing
load losses. The purchase decision model developed by the Department mimics the likely choices that consumers
make given the A and B values they assign to the transformer losses.
[dagger] The Department is aware of AEO2006, and the electricity price forecast does not differ significantly
from AEO2005.
The following sections contain brief discussions of the methods
underlying each of these inputs and key assumptions in the LCC
analysis. Where appropriate, the Department also summarizes stakeholder
comments on these inputs and key assumptions and explains how it took
these comments into consideration.
1. Inputs Affecting Installed Cost
a. Equipment Price
The equipment price of a transformer reflects the application of
supply-chain markups, and the addition of sales tax and shipping costs,
to the manufacturer's selling price. The markup is the percentage
increase in price as the transformer passes through the distribution
channel. Commercial and industrial customers most often purchase dry-
type transformers from electrical contractors who purchase the
transformers through distributors, whereas many liquid-immersed
transformers are purchased by utilities directly from manufacturers and
installed directly by utility staff. Therefore, DOE's markups for
liquid-immersed transformers are smaller than those for dry-type
transformers. In addition to the supply-chain markups, DOE's equipment
prices include shipping costs and sales tax for both types of
transformers. The Department did not have sufficient data to diversify
the distribution channels and markups beyond these two general
categories. Details of the installed cost inputs can be found in TSD
Chapter 7.
In the ANOPR analysis, the Department assumed that all liquid-
immersed transformers were purchased directly from manufacturers by
utilities. NEMA commented that distribution channels are more complex
than DOE assumed in the ANOPR analysis. It noted that some liquid-
immersed units may go through distributors and some dry-type units may
be sold directly from the manufacturer. NEMA also indicated that small
transformers are more likely to go through distributors and large
transformers are more likely to be sold
[[Page 44373]]
directly. (NEMA, No. 48 at p. 2) NRECA commented that most, if not all,
cooperative utilities purchase liquid-immersed transformers through
distributors. (Public Meeting Transcript, No. 56.12 at p. 120) In
response to NEMA's comment, the Department discussed distribution
channels and markup practices with utility technical staff to obtain
additional input for the NOPR analysis. Based on this input, the
Department adjusted the distributor markup to 7 percent for liquid-
immersed transformers and 15 percent for dry-type transformers. These
distributor markup values compare with 0 percent and 35 percent,
respectively, for the liquid-immersed and dry-type distributor markups
for the more simplified distribution channels that the Department
assumed for the ANOPR analysis.
b. Installation Costs
Higher-efficiency distribution transformers tend to be larger and
heavier than less efficient designs. The Department therefore included
the increased cost of installing larger, heavier transformers as a
component of the first cost of efficient transformers. In the ANOPR,
the Department presented the installation cost model and solicited
comment from stakeholders. For details of the installation cost
calculations, see TSD section 7.3.1.
EEI provided substantial comments regarding the installation cost
implications of more-efficient transformers that are physically larger
and heavier than less-efficient transformers. It asserted that
transformer size and weight may require physical modification to pole
structure or mounting pads, and that, in severe replacement
applications, increased transformer size may require building and
structural modifications. (EEI, No. 63 at pp. 4-5) NRECA expressed
similar concerns that the size and weight of more energy-efficient
transformers may dramatically affect installation cost. (NRECA, No. 74
at p. 2) Tampa Electric Company (TEC) commented that transformer
efficiency standards must take into account physical dimension
constraints to ensure compatibility with older units that will need to
be replaced. (TEC, No. 77 at p. 1) Georgia Power Company commented
that, as a result of the expected increase in physical size and weight
of higher efficiency transformers, installation costs will be increased
in several ways. First, it estimates that pole replacements will be
required for 80 percent of the transformer replacement installations
that have joint use applications (e.g., telephone line, cable
television) on the pole. Second, in addition to the pole replacements
at existing locations, Georgia Power projects that numerous larger
diameter and taller poles will be required at new transformer
installations. Third, it asserts that an increase in the size and
weight of pole-mounted and pad-mounted transformers will significantly
increase utility costs, and that this impact will be proportional to
the percent increase in transformer size and weight resulting from the
higher efficiency requirements. (Georgia Power, No. 78 at pp. 2-3)
Ameren also commented that it believes the Department should consider
the economic impact of transformer weight increases, such as the
necessity for using stronger poles, resulting from efficiency
improvements. (Public Meeting Transcript, No. 56.12 at pp. 253-254)
Howard commented that higher efficiency transformers will be
larger, resulting in increased shipping costs as well as handling
problems for the installers. (Howard, No. 70 at p. 3) Comments from EEI
included information from utility members of EEI, the American Public
Power Association (APPA), and NRECA, who reported that in many cases
increased transformer size and weight can affect the cost of new pole-
mounted transformer installations; costs vary from utility to utility
and depend on the size and weight increase. (EEI, No. 63 at pp. 20-62)
Southern Company asserted that increases in installation costs from the
weight increases of more-efficient transformers are not adequately
covered in the ANOPR analysis. (Southern, No. 71 at p. 2) National Grid
(NGrid) commented that high-efficiency transformers present utilities
with logistical and financial challenges, but they have found that the
benefits outweigh the costs when analyzed using a life-cycle cost
analysis method employed in the industry. (NGrid, No. 80 at p. 1)
While the Department's ANOPR included weight- and size-dependent
installation costs associated with the increased shipping, handling,
labor, and equipment costs of installing larger and heavier
transformers, the ANOPR did not include the costs of stronger poles or
pole replacement. In response to stakeholder comments on pole-
replacement costs, for the NOPR analysis the Department added a pole-
replacement-cost function to the installation cost equation for design
line 2, which covers pole-mounted transformers. This analysis assumed
that a pole change-out cost of $2,000 occurs for up to 25 percent of
pole-mounted transformers when the weight of the transformer exceeds
1,000 pounds. Because not all transformer installations require a
change-out of existing equipment even in the most extreme case, the
Department assumed a maximum change-out fraction. The Department
selected 25 percent as the maximum change-out fraction estimate based
on stakeholder input. (EEI No. 63 at p. 25)
c. Baseline and Standard Design Selection
A major factor in estimating the economic impact of a proposed
standard is the selection of transformer designs in the base case and
standards case scenarios. A key issue in the selection process is the
degree to which transformer purchasers take into consideration the cost
of transformer losses (A and B factors) when choosing a transformer--
both before and after the implementation of a standard. The purchase-
decision model in the LCC spreadsheet selects which of the hundreds of
designs in the engineering database are likely to be selected by
transformer purchasers. The LCC transformer selection process is
discussed in detail in TSD Chapter 8, section 8.2.
The Department received three types of comments on the design
selection and purchase behavior modeled in the LCC spreadsheets: (1)
Applicability of values used, (2) actual values that stakeholders have
observed in the market, and (3) percent of customers who use the
evaluation formulae. Concerning the applicability of values used, NRECA
questioned whether the B factors relative to the A factors used in the
LCC spreadsheet accurately represent the A and B factors for rural
cooperatives. (NRECA, No. 74 at pp. 2-3) Ameren asserted that the A and
B values used by the Department for the ANOPR analysis were not
representative of Midwestern electric utilities. (Public Meeting
Transcript, No. 56.12 at p. 113) NEMA said that both manufacturers and
utilities indicated at the public meeting that the A and B values
assumed by the Department to characterize the base case were higher
than those in current use, leading to a DOE base case that may reflect
higher transformer efficiencies than marketplace reality. (NEMA, No. 60
at p. 2) ODOE also commented that the method the Department used to
characterize the base case may result in higher average efficiencies
than are actually found in the current market. ODOE believes that the
value of losses is seldom a significant factor in purchase decisions
for transformers. (ODOE, No. 66 at p. 5)
[[Page 44374]]
Regarding the actual values observed in the market, HVOLT commented
that, for the 80 percent of electric utilities that currently evaluate
losses when purchasing a liquid-immersed transformer, the A factor is
between $2.00 and $2.50 and the B factor is approximately $0.75. HVOLT
noted that these evaluation formulae are higher than the A factor
($1.57) and B factor ($0.57) used to develop the TP 1 standard. (Public
Meeting Transcript, No. 56.12 at p. 107) AK Steel Corporation observed
that some transformer customers evaluate with an A value of between
$1.50 and $2.00. (Public Meeting Transcript, No. 56.12 at p. 109)
Relating to the percent of customers who use the evaluation
formulae, BBF & Associates (BBF&A) said its market study in the early
1990s indicated that 90 percent or more of transformers were evaluated
using A and B factors in the traditional approach. It pointed out that
a subsequent survey in 2001-2002 showed that less than 50 percent were
evaluated. (Public Meeting Transcript, No. 56.12 at p. 110) In the
context of a discussion on liquid-immersed transformers, HVOLT said
that around 80 percent of the market evaluates losses today. (Public
Meeting Transcript, No. 56.12 at p. 107) For dry-type transformers,
HVOLT suggested that there is probably less purchase evaluation than
the Department assumed in the analysis, but that an estimate of 10
percent evaluators is probably accurate. (Public Meeting Transcript,
No. 56.12 at p. 156) ACEEE stated that the efficiency of liquid-
immersed transformers is dropping as utilities move away from
evaluation of purchase decisions, due to regulatory uncertainty caused
by restructuring of the electric utility industry. (ACEEE, No. 76 at
pp. 1-2) Similarly, the Copper Development Association (CDA) observed
that at the ANOPR public meeting, stakeholders commented that 62
percent of the smaller-kVA distribution transformers sold in 2002 were
lowest-cost versions and several utility personnel indicated that A and
B evaluation values were zero. CDA commented that it believes these
statements illustrate that many transformers currently being purchased
are lowest-first-cost, low-efficiency units. (CDA, No. 69 at p. 4)
The Department responded to these stakeholder comments regarding A
and B values and the percent evaluators by using new data provided by
stakeholders, and newly collected data from the Internet, to adjust the
distributions and parameters it used to model purchase decisions (see
TSD Chapter 8, section 8.3.1). It used data provided by NRECA and data
collected from the Internet to revise its estimate of the mean A value
to $3.85/watt compared to the value of $5/watt used in the ANOPR
analysis. This addresses the stakeholder concerns that the A values
used in the ANOPR analysis may have been high. With regard to the
actual values, the Department characterized transformer loss evaluation
with a distribution of A values that includes the lower range of
values--$1.50/watt to $2.50/watt--mentioned by AK Steel. However, the
data collected by the Department were inconsistent with HVOLT's
assertion that 80 percent of electric utilities use an A factor between
$2.00 and $2.50.
With respect to the percentage of evaluators, the Department
obtained new data from NEMA regarding the percentage of transformers
sold that are consistent with the voluntary TP 1 standard. The
Department therefore adjusted the percentage of evaluators in its
customer choice model to be consistent with the new data provided by
NEMA. The Department believes that this method provides the most
precise and detailed estimate of the percentage of evaluators that is
consistent with actual market data.
The Department received several comments noting that shipments of
TP 1-compliant transformers have recently increased, and noting the
potential impact of States adopting TP 1 as their transformer standard.
NEMA stated that its members' shipments of TP 1-compliant transformers
increased in 2002 and 2003 compared to 2001 for all transformers
considered in the scope of this rulemaking. (NEMA, No. 48 at p. 3) An
EEI survey of nine of its members showed that an average of
approximately 65 percent of liquid-immersed transformers purchased are
already compliant with NEMA TP 1. (EEI, No. 63 at pp. 7-19) NGrid now
purchases energy-efficient, liquid-immersed transformers that meet or
exceed NEMA's TP 1 standard throughout its service territory in
Massachusetts, Rhode Island, New Hampshire, and New York. This is true
despite the fact that only Massachusetts requires TP 1-compliant,
liquid-immersed transformers. (NGrid, No. 80 at p. 1) Georgia Power
expressed doubt that the Department can accurately account for the
number of transformers that are already purchased with NEMA TP 1
efficiencies. (Georgia Power, No. 78 at pp. 1-2)
The Appliance Standards Awareness Project (ASAP) and Northwest
Power and Conservation Council (NPCC) commented that the base case
should reflect the impact of State-established transformer standards.
(Public Meeting Transcript, No. 56.12 at p. 248, Public Meeting
Transcript, No. 56.12 at pp. 180-181) ODOE commented that the
Department needs to pay careful attention to those States that have TP
1 as an existing standard because, by the time the DOE standard is
published, States mandating TP 1 could represent a quarter to a third
of transformer shipments. (Public Meeting Transcript, No. 56.12 at p.
185) NEMA said that, of those States that have adopted TP 1, most have
done it for low-voltage, dry-type distribution transformers, so the
other product classes would not be affected. (Public Meeting
Transcript, No. 56.12 at p. 182)
In response to these comments, the Department obtained from NEMA
new, detailed data regarding TP 1 compliance of shipped transformers.
The Department adjusted the parameters of the customer choice model
such that the base case TP 1 compliance in the LCC is consistent with
the most recent NEMA data available to the Department.
Southern Company and ODOE requested that the Department provide the
efficiency rating for the base case. (Public Meeting Transcript, No.
56.12 at p. 215 and p. 217) ACEEE agreed, noting that this information
would enable further independent analysis of the cost and savings data.
(ACEEE, No. 50 at p. 2 and No. 76 at p. 3) The Department complied with
this request and reported the base case efficiencies for the ANOPR
analysis in Supplemental Appendix 8E of the ANOPR TSD. These values
have been updated for the NOPR analysis, and can be found in Appendix
8E of the TSD.
2. Inputs Affecting Operating Costs
a. Transformer Loading
Transformer loading is an important factor in determining which
types of transformer designs will deliver a specified efficiency, and
for calculating transformer losses. Transformer losses have two
components: No-load losses and load losses. No-load losses are
independent of the load on the transformer, while load losses depend
approximately on the square of the transformer loading. Because load
losses increase exponentially with loading, there is a particular
concern that, during times of peak system load, load losses can impact
system capacity costs and reliability. Details of the transformer
loading models are presented in TSD Chapter 6.
For the ANOPR analysis, the Department estimated the loading
characteristics of transformers by
[[Page 44375]]
analyzing the statistics of available load data, and by assuming a
distribution of initial annual peak loadings. ASE commented that the
Department's analysis of load profiles is largely consistent with data
provided by other stakeholders. It also recognized that the Department
used publicly available data for utility loads, and commented that the
average loadings for liquid-immersed transformers were reasonable.
(ASE, No. 52 at p. 3 and No. 75 at p. 3) ODOE agreed with the
transformer loads estimated by the Department based on ODOE's
examination of loading studies conducted in the Pacific Northwest,
which produced lower loading levels than expected by many analysts.
(ODOE, No. 66 at p. 4)
HVOLT estimated that the average loading for dry-type, medium-
voltage units is about 50 percent, with a daytime average of 60 percent
and a nighttime average of 35 percent. (Public Meeting Transcript, No.
56.12 at pp. 131-132) HVOLT estimated that loading for liquid-immersed
transformers is about 50 percent, but noted that loads in the
residential sector can increase so much that loading can exceed the
transformer nameplate rating. (Public Meeting Transcript, No. 56.12 at
p. 131 and p. 133) In a written comment, HVOLT endorsed using loading
assumptions identical to those for NEMA TP 1. HVOLT is not familiar
with any publicly released loading studies that would alter the root
mean square (RMS)-equivalent load of 50 percent load for medium-voltage
transformers. (HVOLT, No. 65 at p. 3) EEI estimated that, according to
three surveyed members, average loading levels range from 30 percent to
58 percent. A survey of eight members yielded a range of high-loading
levels from 45 to 100 percent, and a range of low-loading levels from
35 to 75 percent. (EEI, No. 63 at pp. 7-19) TEC said that it strives to
load transformers higher than the 50 percent level assumed by DOE, and
recommended that the Department give consideration to efficiency
ratings at higher loading levels. (TEC, No. 77 at p. 1)
The Department concluded that the ANOPR statistical loading
analysis was largely consistent with stakeholder comments, with slight
adjustments necessary for the loading levels of medium-voltage, dry-
type transformers (see TSD Chapter 6, section 6.3.3.3). The Department
increased the loading on medium-voltage, dry-type transformers in
response to the comments by HVOLT, to be consistent with the relative
difference in loading levels used by NEMA TP 1 between low-voltage and
medium-voltage dry-type transformers.
On the issue of peak load coincidence, the Department received two
comments. ASE agreed with the Department's peak load coincidence
analysis for the ANOPR. (ASE, No. 52 at p. 3 and No. 75 at p. 3) The
CDA commented that peak coil losses may have a high coincidence factor
with system peaks. (CDA, No. 51 at pp. 3-4) The Department concluded
that the statistical model used for peak loading in the ANOPR analysis
was consistent with stakeholder comments and did not change peak
loading statistics for the NOPR analysis.
b. Load Growth
The LCC takes into account the projected operating costs for
distribution transformers many years into the future. This projection
requires an estimate of how, if at all, the electrical load on
transformers will change over time. For dry-type transformers, the
Department assumed no load growth. For liquid-immersed transformers,
the Department used as the default scenario a one-percent-per-year load
growth. It applied the load growth factor to each transformer beginning
in 2010, the expected effective date of the standard. To explore the
LCC sensitivity to variations in load growth, the Department included
in the model the ability to examine scenarios with zero-percent, one-
percent, and two-percent load growth. Load growth is discussed in
detail in TSD Chapter 8, section 8.3.6.
The Department received a range of comments on its load growth
projections. CDA commented that loading on all transformers increases
with time. It stated that, for liquid-immersed transformers,
residential consumption per household has increased; for dry-types,
commercial and industrial loads grow over time through more energy-
intensive use of floor space and plant expansion. (CDA, No. 51 at pp.
1-2) ODOE stated that DOE should select a growth rate of zero, with
sensitivity analysis at one-percent growth. (ODOE, No. 66 at p. 6) NEMA
agreed with the Department's load growth estimates of zero percent for
dry-type and one percent for liquid-immersed transformers. However, to
the extent that building owners may defer transformer upgrades because
of high unit costs, it noted that there may be some load growth on
older, less efficient units. (NEMA, No. 48 at p. 2)
HVOLT commented that, in commercial and industrial complexes, new
transformers are added to handle additional loads when there is an
expansion, and there is not much information to suggest a substantial
load growth on those transformers. (Public Meeting Transcript, No.
56.12 at p. 40) HVOLT also stated that one-percent load growth for
liquid-immersed transformers seems too high. (Public Meeting
Transcript, No. 56.12 at p. 138) HVOLT also said that there is not much
load growth in residential applications, since transformers are
installed in a community with a cluster of homes, they come online
quickly, and after that, there are few factors producing load growth
for the rest of the transformer's life. (Public Meeting Transcript, No.
56.12 at p. 39)
The Department retained its estimate of zero-percent load growth
for dry-type transformers and one-percent load growth for liquid-
immersed transformers. While some stakeholders disagreed with the
Department's estimate of load growth for liquid-immersed transformers,
data showing both growth in per-customer electrical loads over time and
increasing transformer sizes purchased by utilities support the
Department's approach (see TSD Chapter 8).
Regarding another aspect of the issue of load growth over time, EEI
stated its concern that, because of load growth, higher efficiency
transformers optimized to the loading point prescribed by the test
procedure may have higher coil losses after being in service for
several years. That is, EEI is concerned that the ``balance point''
between higher coil losses and lower core losses may not be reached
until late in the operating life of a transformer. (EEI, No. 63 at pp.
3-4) Both the ANOPR and NOPR load analyses were responsive to this
comment. The Department's estimate of losses tracked losses based on
estimates of actual loads rather than test procedure loads. Both near-
term and long-term losses were included in LCC estimates, with a
weighting determined by the customer discount rate (see TSD Chapter 8).
c. Power Factor
The power factor is real power divided by apparent power. Real
power is the time average of the instantaneous product of voltage and
current. Apparent power is the product of the RMS voltage and the RMS
current. For the ANOPR, the Department used a power factor of 1.0. A
detailed discussion of the power factor can be found in TSD Chapter 8,
section 8.3.12.
The Department received two comments on power factor. Southern
Company commented that the power factor should be less than 1.0.
(Public Meeting Transcript, No. 56.12 at p. 164) NEMA, on the other
hand, stated that a
[[Page 44376]]
power factor assumption of 1.0 is appropriate. (NEMA, No. 60 at p. 2)
While the Department agrees with Southern Company that actual power
factors are less than 1.0, they are very close to 1.0, and the
Department agrees with NEMA that use of a power factor of 1.0 is
appropriate for the analysis of the efficiency standard. Using a power
factor less than 1.0 would slightly increase the estimated losses for
transformers, but would complicate the Department's analysis and affect
all components of the Department's analysis where losses are estimated.
The Department determined that the disadvantages of complicating the
analysis by using an estimated distribution of slightly lower power
factors outweighed the slight increase in analytical accuracy that
could result.
d. Electricity Costs
The Department needed estimates of electricity prices and costs to
place a value on transformer losses for the LCC calculation. As noted
earlier, the Department created two sets of electricity prices to
estimate annual energy expenses for its ANOPR: An hourly based estimate
of wholesale electricity costs for the liquid-immersed transformer
market, and a tariff-based estimate for the dry-type transformer market
(see TSD Chapter 8).
Southern Company questioned whether wholesale electricity prices
are the correct prices for liquid-immersed transformers, and suggested
that the Department consider the availability of very inexpensive
electricity generating capacity in some regions. (Public Meeting
Transcript, No. 56.12 at p. 125 and pp. 237-238) The Department's
analysis for both the ANOPR and the NOPR estimated the marginal, or
incremental, wholesale cost of electricity. The Department agrees with
Southern Company that inexpensive electricity generating capacity
exists in many regions of the country. The Department modeled a
national distribution of generation capacity costs by estimating the
marginal capacity cost of new generation as a function of the type of
plant serving the capacity and the utility cost of capital which the
Department obtained from a representative national sample of utilities
(see TSD Chapter 8).
e. Electricity Price Trends
For the relative change in electricity prices in future years, DOE
relied on price forecasts from the EIA's Annual Energy Outlook (AEO).
For its ANOPR, the Department used price forecasts from the AEO2003,
the most recent price forecasts available at the time. The application
of electricity price trends in the NOPR analysis is discussed in detail
in TSD Chapter 8, section 8.3.7.
ODOE and HVOLT commented that the price forecasts used by the
Department were too low. (ODOE, No. 66 at p. 4; Public Meeting
Transcript, No. 56.12 at p. 38) Some stakeholders stated that more
volatility should be added to the forecasts. The Natural Resources
Defense Council (NRDC) commented that DOE should consider a scenario
where electricity prices increase unexpectedly. (Public Meeting
Transcript, No. 56.12 at p. 45) The NPCC stated that the Department
assumed a monotonic wholesale electricity market and should model
forecasted prices with some volatility. (Public Meeting Transcript, No.
56.12 at p. 124) ODOE and ACEEE suggested that the price trends should
be updated with the most recent AEO forecasts; ACEEE added that DOE
should include a high electricity price scenario in the analysis.
(ODOE, No. 66 at p. 4; ACEEE, No. 76 at p. 3) Counter to the above
stakeholders, CDA and AK Steel thought the Department's price forecasts
were reasonable. CDA commented that the Department was correct to
assume a moderate rate of energy cost increases, although it also
believes a higher rate could be justified given recent experience.
(CDA, No. 51 at p. 3) AK Steel added that EIA's long-term electricity
price forecasts are good. (Public Meeting Transcript, No. 56.12 at p.
128)
For the NOPR, the Department updated its price forecasts with
trends from the AEO2005 as recommended by stakeholders, and addressed
other stakeholder concerns through use of sensitivity analysis. The
Department believes that price forecasts from the AEO are the most
reliable and credible estimates of future electricity prices. As
compared to AEO2003, the price trends from AEO2005 actually show
slightly lower forecasted prices. During the writing of this notice,
the EIA published AEO2006, but since the electricity price forecast did
not differ significantly from AEO2005, the Department did not update
its analysis results using AEO2006. The Department addresses
stakeholder concerns regarding the possibility of higher electricity
prices through the sensitivity section of the LCC analysis (see TSD
Chapter 8). This analysis estimates LCC results under conditions where
electricity prices are 15 percent higher than the Department's medium
scenario. However, as in the ANOPR analysis, the Department retained
the medium AEO forecast as the electricity price trend that is most
credible and authoritative with respect to the analysis of the future
economic impacts of efficiency standards.
3. Inputs Affecting Present Value of Annual Operating Cost Savings
a. Standards Implementation Date
The Department proposes that the new energy-efficiency standard for
distribution transformers apply to all units manufactured three years
or more after publication of the final rule. For the NOPR analysis, the
Department assumed a 2007 final rule publication; hence a 2010
implementation or compliance date. The Department calculated the LCC
for customers as if each new distribution transformer purchase occurs
in the year manufacturers must comply with the standard.
Several comments called for acceleration of the rulemaking
schedule. ACEEE said the NOPR should be published by July 2005 and the
final rule six months later. (ACEEE, No. 76 at p. 4) The National
Association of Regulatory Utility Commissioners (NARUC) urged DOE to
establish a new standard for distribution transformers as soon as
possible. (NARUC, No. 68 at pp. 2-5) NRDC asked DOE to make a
commitment to a schedule, with appropriate milestones, that will allow
a final rule to be issued no later than January 29, 2006. (NRDC, No. 61
at p. 3) ASE urged the Department to maintain an 18-month schedule to
complete the rulemaking. (ASE, No. 52 at p. 1 and No. 75 at p. 1)
The Department understands that the rulemaking schedule impacts the
date by which manufacturers of distribution transformers must comply
with any new energy-efficiency standard. It is committed to completing
the rulemaking in a timely fashion and expects to publish a final rule
by September 2007.
b. Discount Rate
The discount rate is the rate at which future expenditures are
discounted to estimate their present value. It is the factor that
determines the relative weight of first costs and operating costs in
the LCC calculation. Consumers experience discount rates in their day-
to-day lives either as interest rates on loans or as rates of return on
investments. Another characterization of the discount rate is the
``time value of money.'' The value of a dollar today is one plus the
discount rate times the value of a dollar a year from now. The
Department estimated consumer discount rates by calculating the
consumer cost of capital (see TSD Chapter 8).
[[Page 44377]]
Discount rates depend on who is borrowing and at what scale. Thus,
the discount rates in the LCC analysis are different than those in the
national impact analysis. This section discusses consumer discount
rates that the Department used in the LCC analysis.
With respect to consumer discount rates in the ANOPR, stakeholders
expressed a diversity of views regarding which discount rates are
appropriate for the LCC analysis. ASE and ODOE commented that the
Department should use a three-percent real discount rate, similar to
the discount rate used by the California Energy Commission (CEC) in
recent State-level energy efficiency analyses. (ASE, No. 75 at p. 3;
ODOE, No. 66 at p. 5) NRDC said that the Department's use of discount
rates exceeding 5.5 percent real conflicts with the explicit
instructions in NRDC v. Herrington, because of the court's instruction
to consider payback times of less than nine years as economically
justified. (NRDC, No. 61 at p. 6) ACEEE commented that the Department's
choice of discount rates for utilities was appropriate. (ACEEE, No. 76
at p. 3) HVOLT recommended that the Department set efficiency standards
on a three-to five-year consumer investment return, to represent
commercial customer preferences. (HVOLT, No. 65 at p. 3)
The Department examined each of these comments to see if any would
lead to a more accurate description of consumer economic impacts. In
examining the three-percent discount rate recommended by ASE and ODOE,
the Department found that the CEC, in its rulemaking, estimated the
consumer cost of capital using a method similar to that of the
Department. However, the CEC analyzed a different class of consumers
and used less detailed data. Therefore, the Department considers its
discount rates to be more accurate for the distribution transformer
energy-efficiency analysis than the discount rates estimated by the CEC
for other products. The Department retained the consumer discount rates
that it used in the ANOPR analysis, as shown in Table IV.3. The
consumer discount rates shown in the table are based on a detailed
analysis of risk-adjusted cost of capital for consumers, as described
in TSD Chapter 8.
Table IV.3.--Weighted-Average Discount Rates by Design Line and Ownership Category
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transformer ownership category
-----------------------------------------------------------------------------------------------
Property Industrial Commercial Investor-owned Publicly owned Government
owners companies companies utilities utilities offices
--------------------------------------------------------------------------------------------------------------------------------------------------------
Mean real discount rate................................. 4.35% 7.55% 7.46% 4.16% 4.31% 3.33%
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Design line Weighted
average
discount rate
(%) Estimated ownership (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1....................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2
2....................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2
3....................................... 4.40 2.1 2.4 4.5 80.0 10.0 1.0
4....................................... 4.24 0.4 0.5 0.9 72.0 26.0 0.2
5....................................... 5.38 9.5 9.5 27.0 35.0 15.0 4.0
9....................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9
10...................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9
11...................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9
12...................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9
13...................................... 6.56 19.0 19.0 54.0 0.0 0.0 7.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
4. Candidate Standard Levels
To conduct the LCC analysis, the Department first selected CSLs.
Based on its examination of the CSLs, the Department then selected
trial standard levels (TSLs). From those TSLs, it developed today's
proposed standards. Cooper Power Industries commented that DOE should
use a consistent method for all product classes to determine CSLs.
(Cooper, No. 62 at p. 3) ASAP stated that DOE should examine a CSL with
the maximum efficiency that maintains a positive economic impact for
each product class. (Public Meeting Transcript, No. 56.12 at p. 218)
ACEEE recommended that the Department examine TP 1 plus 0.2 percent,
0.3 percent, and 0.4 percent efficiency improvements for all design
lines. It encouraged the Department to carefully examine the cost and
other economic inputs, since the lowest life-cycle cost point, when
compared to TP 1, varies significantly among design lines. (ACEEE, No.
76 at p. 1) ACEEE said that DOE should regroup the CSLs so that CSL 1
is TP 1, CSL 3 is the minimum life-cycle cost point, and CSLs 2 and 4
are slightly above and below the minimum LCC. (ACEEE, No. 50 at p. 1
and No. 76 at p. 2) ACEEE suggested that DOE realign the CSLs so that
they have approximately equivalent economic performance. (Public
Meeting Transcript, No. 56.12 at p. 26) EEI and NRECA recommended that
DOE investigate CSLs that have rated efficiencies below TP 1, since
many transformers in the current market have efficiencies below TP 1.
(EEI, No. 63 at p. 2; NRECA, No. 74 at p. 2 ) Howard stated that it is
appropriate to round candidate standard efficiency levels to one
decimal place. (Howard, No. 70 at p. 3)
For the NOPR analysis, the Department complied with most of the
stakeholder recommendations regarding standard levels. As requested by
Cooper, DOE developed a consistent method for selecting standard levels
for each design line. In response to the request by ASAP, the
Department defined a standard level that represented the maximum energy
savings with approximately no change in LCC. In response to ACEEE, the
Department defined CSL 4 as the efficiency level with minimum LCC for
each design line, and realigned CSLs 4 and 5 to have equivalent
economic performance for each design line. The Department did not
comply with EEI's and NRECA's requests to examine standard levels lower
than TP 1 because--as described in this NOPR--the Department has found
that efficiencies higher than or equal to TP 1 are economically
[[Page 44378]]
justifiable, and thus the Department is obligated to pick a standard
level that has efficiencies greater than or equal to TP 1. If the
Department had reason to believe that any TP 1 levels were not
economically justifiable for a standard, it would have examined
efficiency levels below TP 1.
Table IV.4 lists the CSLs evaluated for each design line, expressed
in terms of efficiency, and in terms relative to NEMA TP 1 efficiency
levels.
Table IV.4.--Candidate Standard Levels Evaluated for Each Design Line
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CSL
-----------------------------------------------------------------------------------------------------------------------------------
1 TP 1 2 \1/3\ of diff. 3 \2/3\ of diff. 4 Min LCC 5 Max energy 6 Max energy
---------------------- between TP 1 and min between TP 1 and min ---------------------- savings with no savings
Design line LCC LCC change in LCC ---------------------
Effic'y -------------------------------------------- Effic'y ----------------------
TP 1+ % % Effic'y Effic'y TP 1+ % % Effic'y TP 1+ % Effic'y
TP 1+ % % TP 1+ % % TP 1+ % % %
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1........................................................... 0.0 98.9 0.14 99.04 0.29 99.19 0.43 99.33 0.59 99.49 0.69 99.59
2........................................................... 0.0 98.7 0.03 98.73 0.06 98.76 0.09 98.79 0.26 98.96 0.76 99.46
3........................................................... 0.0 99.3 0.08 99.38 0.16 99.46 0.24 99.54 0.44 99.74 0.45 99.75
4........................................................... 0.0 98.9 0.18 99.08 0.36 99.26 0.55 99.45 0.68 99.58 0.71 99.61
5........................................................... 0.0 99.3 0.06 99.36 0.12 99.42 0.17 99.47 0.41 99.71 0.41 99.71
9........................................................... 0.0 98.6 0.22 98.82 0.44 99.04 0.66 99.26 0.81 99.41 0.81 99.41
10.......................................................... 0.0 99.1 0.12 99.22 0.23 99.33 0.35 99.45 0.41 99.51 0.41 99.51
11.......................................................... 0.0 98.5 0.17 98.67 0.34 98.84 0.51 99.01 0.59 99.09 0.59 99.09
12.......................................................... 0.0 99.0 0.12 99.12 0.23 99.23 0.35 99.35 0.40 99.40 0.40 99.40
13.......................................................... 0.0 99.0 0.15 99.15 0.30 99.30 0.45 99.45 0.55 99.55 0.55 99.55
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
5. Trial Standard Levels
The TSLs are the efficiency levels considered by the Department for
the proposed standard. They are based on the CSLs selected for the LCC
analysis. However, because of special considerations concerning
manufacturer impacts and design lines (DLs) within the same product
class, some efficiency levels for DL1 and DL4 are drawn from the same
CSL. See TSD Chapter 10 for a more detailed explanation. Table IV.5
shows the mapping from the design line CSLs to the TSLs. In the LCC and
LCC subgroups chapters of the TSD (Chapters 8 and 11), the Department
reports results in terms of CSLs. In subsequent analyses (e.g.,
shipments in Chapter 9, national impacts in Chapter 10, MIA in Chapter
12) and in this NOPR, the Department reports all results in terms of
TSLs, mapping the LCC results according to Table IV.5.
Table IV.5.--Mapping of the Candidate Standard Levels to Trial Standard Levels
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
DL1 DL2 DL3 DL4 DL5 DL9 DL10 DL11 DL12 DL13
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TSL1............................ CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1.............. CSL1
TSL2............................ CSL1.............. CSL2.............. CSL2.............. CSL2.............. CSL2.............. CSL2.............. CSL2.............. CSL2.............. CSL2.............. CSL2
TSL3............................ CSL1.............. CSL3.............. CSL3.............. CSL3.............. CSL3.............. CSL3.............. CSL3.............. CSL3.............. CSL3.............. CSL3
TSL4............................ CSL2.............. CSL4.............. CSL4.............. CSL3.............. CSL4.............. CSL4.............. CSL4.............. CSL4.............. CSL4.............. CSL4
TSL5............................ CSL3.............. CSL5.............. CSL5.............. CSL5.............. CSL5.............. CSL5.............. CSL5.............. CSL5.............. CSL5.............. CSL5
TSL6............................ CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6.............. CSL6
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Georgia Power asked whether the efficiency values shown in Table
II.d of the ANOPR apply only to the representative transformer for each
design line, or if that efficiency is applicable to all of the kVA
sizes represented by that design line. It noted that the latter would
be too restrictive. (Georgia Power, No. 78 at pp. 3-4) The ANOPR
document did not provide efficiency levels for all kVA ratings in a
product class or design line. For the NOPR, the Department provides a
complete specification of the efficiency levels for all kVA ratings.
Tables II.1 and II.2 of this NOPR express the efficiency ratings for
all specific kVA ratings covered by today's proposed standard. This
additional information also responds to a comment by ACEEE. ACEEE asked
that the Department provide efficiency values for all the kVA ratings
in between the representative units analyzed. (ACEEE, No. 50 at p. 2)
The Department provides this information in TSD Chapter 8.
6. Miscellaneous Life-Cycle Cost Issues
In response to the ANOPR analysis, DOE examined several additional
issues relating to the LCC. These issues are grouped for organizational
clarity and completeness, and are discussed below.
a. Tax Impacts
The Department did not include the impact of income taxes in the
LCC analysis for the ANOPR. The Department understands that there are
two ways in which taxes affect the net impacts attributed to purchasing
equipment that is more energy-efficient than baseline equipment: (1)
Energy-efficient equipment typically costs more to purchase than
baseline equipment, which lowers net income and may lower company
taxes; and (2) more-efficient equipment typically costs less to operate
than baseline equipment, which increases net income and may increase
company taxes.
In general, the Department believes that the net impact of taxes on
the LCC analysis depends on firm profitability and expense practices
(i.e., how firms expense the purchase cost of equipment). In the ANOPR,
the Department sought input on whether commercial income tax effects
are significant enough to warrant inclusion in the LCC analysis. 69 FR
45396. ACEEE commented that income tax should not be included in the
analysis, because it would significantly complicate the analysis, and
it has found that many businesses do not pay income taxes due to the
many credits and deductions that are available in the current tax code.
(ACEEE, No. 76 at p. 4) ODOE stated that it believes the number of
corporations actually paying income taxes has declined to the point
[[Page 44379]]
where the overall impact of including income tax effects should be
negligible. (ODOE, No. 66 at p. 6) Southern Company questioned how many
firms do not pay income taxes. (Public Meeting Transcript, No. 56.12 at
p. 164) NPCC stated that the analysis should be based on after-income-
tax data, but also noted that businesses do not necessarily pay income
tax. (Public Meeting Transcript, No. 56.12 at p. 158)
The Department agrees with ACEEE that the inclusion of income tax
effects would significantly complicate the analysis. In analyzing the
available options for including income tax effects, the Department
could not find an estimation method where--with the existing data
gaps--sufficient accuracy could be obtained to justify the increased
analytical complexity. The Department therefore did not include an
estimate of income tax impacts in the LCC analysis.
b. Cost Recovery Under Deregulation, Rate Caps
During the ANOPR review, stakeholders expressed mixed concerns
regarding the potential impact of distribution transformer efficiency
standards under utility deregulation. Southern Company commented that
the impact on electric utilities of increasing the cost of transformers
will vary depending on the regulatory scheme for the different
utilities. It recommended that the Department include this issue in the
analysis, especially for the utilities that are under rate cap
legislation. (Public Meeting Transcript, No. 56.12 at p. 187) ODOE
stated that there is a small likelihood of future electricity market
deregulation and recommended that the Department ignore deregulation
for the NOPR analysis. (ODOE, No. 66 at p. 5)
For the ANOPR, stakeholders stated many reasons why consumers may
not be able to recover the added investment cost of higher efficiency
distribution transformers. EEI expressed concern that political and
economic risks related to deregulation will force utilities to make
uneconomic (non-recoverable) incremental investments in efficient
transformers. EEI requested that DOE include the effect of reduced
utility earnings in the LCC analysis. (EEI, No. 63 at p. 4) ACEEE noted
that utility representatives pointed out that some utilities currently
have caps on their rates, which limit their ability to recover
additional transformer costs. ACEEE expects that regulators would be
supportive of cost recovery for reasonable transformer cost increases.
(ACEEE, No. 76 at p. 3) NRDC commented that many utilities believe they
cannot recover the additional costs associated with more-efficient
transformers, but this will not be a problem because utility regulation
throughout the country allows the distribution utility to achieve a
regulated rate of return on all reasonable and prudent investment. NRDC
noted that some utilities may find today's investments in high-
efficiency transformers to be economically troublesome because they are
subject to rate caps, but these rate caps all expire before the
transformer efficiency standard would go into effect. New rate cases
would then result in a new rate structure consistent with the
standards-compliant transformer investments. (NRDC, No. 61 at pp. 7-8)
ASE looked into the issue of rate caps and found that about 41 percent
of electricity sales are in States with restructured electricity rate
regulations, with about 27 percent of sales subject to rate caps, but
that these caps expire steadily from 2005 to 2010. (ASE, No. 52 at p.
4) Georgia Power also asserted that utility companies cannot raise
their prices to make up for the expected rise in transformer prices
that will result from higher efficiency requirements without proceeding
through the regulatory process. It stated, therefore, that DOE needs to
weigh the financial burden this rulemaking may place on electric
utilities before issuing a final rule. (Georgia Power, No. 78 at p. 4)
NEMA also expressed concern that the entity paying the additional
capital cost for a more energy-efficient transformer would frequently
not be the beneficiary of the resultant energy cost savings. (NEMA, No.
48 at p. 1)
The concern expressed by stakeholders regarding the potential lack
of cost recovery for distribution transformer investments is a classic
example of ``split incentives'' for efficiency investments. A split
incentive occurs when the entity that makes an investment is different
from the entity that will receive the economic benefits of the
investment. Split incentives prevent economically viable investments
because, without receiving the benefits of an investment, the investor
loses motivation to make investments that otherwise might have good
returns. If the Department were to model split incentives in the LCC
analysis, it would need to divide ownership of first costs and
operating cost savings for a fraction of the transformers in the
analysis. If the cost of capital were the same for the owner of the
transformer and the owner of the operating cost savings, then the
average LCC savings result would actually remain the same, although the
spread of LCC savings in the LCC distribution results would increase.
Some owners would only incur costs, while others would only receive
benefits.
The Department decided not to explicitly model split incentives in
the LCC analysis for the NOPR. Such modeling would have little impact
on the total net LCC savings for the Nation. While the cost and the
benefits would be divided between two different owners in the split
incentive case, the sum would produce the same approximate net LCC
savings as a model that does not include split incentives. The
Department does, however, report the increase in first cost and the
decrease in operating cost savings for each design line and efficiency
level in TSD Chapter 8. Stakeholders can therefore evaluate the impact
of standards under a split-incentive scenario where the increased
transformer cost and the operating cost savings are owned by different
entities.
c. Other Issues
HVOLT commented that DOE should consider incremental price compared
to incremental benefit instead of total price to total benefit, where
the increments are taken by comparing the results of one standard level
to the results of the next highest standard level under consideration.
(Public Meeting Transcript, No. 56.12 at p. 262) ACEEE stated that
incremental analysis is not necessary. (Public Meeting Transcript, No.
56.12 at p. 158) The Department does not use incremental analysis in
the evaluation of standards because of legal interpretations of the
methodology it is required to follow. As described in section V.C of
this NOPR, the Department followed its normal approach in selecting a
proposed energy conservation standard for distribution transformers. It
started by comparing the maximum technologically feasible level with
the base case, and determined whether that level was economically
justified. If it found the maximum technologically feasible level to be
unjustified, the Department then analyzed the next lower TSL to
determine whether that level was economically justified. The Department
repeated this procedure until it identified a TSL that was economically
justified. This procedure that the Department followed for selecting
today's proposed standard level is that which the Department has
historically determined is consistent with EPCA, as amended.
Georgia Power commented that the Department's calculations for the
economic justification of, and energy
[[Page 44380]]
savings associated with, higher-efficiency transformers are not
applicable to every utility in the Nation. It noted that each utility
is different and there are too many variables that cannot be accurately
accounted for in such calculations. (Georgia Power, No. 78 at pp. 1-2)
For the liquid-immersed design lines (1-5), Georgia Power analyzed the
percentage change in price and TOC for several kVA sizes for each of
the CSLs beyond TP 1. It found that, for all these cases, the TOC
actually increased in contrast to the decrease in LCC found by the
Department, indicating that the savings in energy do not economically
justify the increase in first cost. (Georgia Power, No. 78 at pp. 4-5)
The Department recognizes that the TOC approach used by utilities
can yield results that are substantially different from the
Department's LCC analysis. The standard TOC approach used by electric
utilities is typically calculated according to the regulatory mandates
of cost recovery rate regulation. For cost recovery, the annual
expenses associated with an investment in equipment need to be
increased (or marked up) to generate revenue for those utility costs
that may not be directly related to the equipment investments but still
need to be recovered (i.e., operation and maintenance expenses). This
is formulated in terms of a fixed charge rate (FCR), which is used to
calculate the annual revenue required to cover the expenses of a
capital investment such that a utility can stay in business. The FCR
used by utilities is generally larger than the revenues required to
cover just the cost of capital. In the LCC analysis, DOE only accounted
for the capital and investment expenses that are directly related to
the purchase of the equipment being analyzed. The factor that
represents the annual expenses required to recover capital costs is
called the capital recovery factor (CRF) and is generally less than the
FCR. The Department therefore recognizes that investments in efficiency
that are economically justified under EPCA, as amended, may not be
economically justified with respect to utility TOC evaluations that are
performed under the assumptions of utility rate-setting regulation.
D. National Impact Analysis--National Energy Savings and Net Present
Value Analysis
The national impact analysis evaluates the impact of a proposed
standard from a national perspective rather than from the consumer
perspective represented by the LCC. When it evaluates a proposed
standard from a national perspective, the Department must consider
several other factors that are not included in the LCC analysis. One of
the primary factors the Department modeled in the national impact
analysis was the gradual replacement of existing, less-efficient
transformers with more-efficient, standard-compliant transformers over
time. This rate of replacement was estimated by an equipment shipments
model that describes the sale of transformers for replacement and for
inclusion in new electrical distribution system infrastructure. A
second major factor included in the national impact analysis was the
fact that the national cost of capital may differ from the consumer
cost of capital, and thus the discount rate used in the national impact
analysis can be different from that used in the LCC. The third factor
the Department included in the national impact analysis was the
difference between the energy savings obtained by the consumer and the
energy savings obtained by the Nation. Because of the effect of
distribution and generation losses, the national energy savings from a
proposed standard are larger than the sum of the individual consumers'
energy savings. The details of the Department's national impact
analysis are provided in Chapters 9 and 10 of the TSD.
During the ANOPR review, the Department received stakeholder
comments on its approach to two of these three major factors. While it
did not receive comments indicating any stakeholder disagreement with
its accounting of national versus consumer energy savings, the
Department did receive stakeholder comments concerning its shipments
model and national discount rates.
Regarding DOE's shipments model, HVOLT commented that DOE considers
the dry-type transformer market to have inelastic pricing, but that it
actually is quite elastic and DOE should incorporate a price response
that allows a shift to liquid-immersed transformers. (Public Meeting
Transcript, No. 56.12 at pp. 173-174) NEMA agreed that dry-type
transformers have price elasticity of demand, since deferring or
foregoing investments may be a viable alternative for some customers.
(NEMA, No. 48 at p. 1)
The Department agrees with HVOLT and NEMA that the sales of dry-
type transformers are likely to be elastic. Since detailed shipments
data that can be used for elasticity estimates are not available for
dry-type transformers, the Department estimated elasticities using data
from an economically similar commercial appliance--commercial air
conditioners. Both commercial air conditioners and distribution
transformers are integral elements of building and facilities electro-
mechanical design and construction, and are installed during building
construction and rehabilitation. The shipments elasticity scenarios the
Department examined are provided in Table IV.6, and are explained in
more detail in TSD Chapter 9.
Table IV.6.--Summary of Shipments Model Inputs
----------------------------------------------------------------------------------------------------------------
Input ANOPR description Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Shipments data.......................... Third-party expert (HVOLT) for the year No change.
2001.
Shipments backcast...................... For years 1977-2000, used Bureau of Added three more years of
Economic Analysis' (BEA) manufacturing BEA's manufacturing data--
data for distribution transformers. for years 2001 through
Source: http://www.bea.doc.gov/bea/pn/ 2003.
ndn0304.zip.
For years 1950-1976, used EIA's
electricity sales data. Source: http://www.eia.doe.gov/emeu/aer/txt/stb0805.xls.
Shipments forecast...................... Years 2002-2035: Based on AEO2003......... Years 2010-2038: Based on
AEO2005.
Dry-type/liquid-immersed market shares.. Based on EIA's electricity sales data and Based on EIA's electricity
AEO2003. sales data and AEO2005.
Regular replacement market.............. Based on a survival function constructed No change.
from a Weibull distribution function
normalized to produce a 32-year mean
lifetime. Source: ORNL 6804/R1, The
Feasibility of Replacing or Upgrading
Utility Distribution Transformers During
Routine Maintenance, page D-1.
[[Page 44381]]
Elasticities............................ For liquid-immersed transformers: For liquid-immersed
Low: 0.00....................... transformers:
Medium: -0.04................... No change.
High: -0.20.....................
For dry-type transformers: For dry-type transformers:
0.00............................ Low: 0.00
Medium: -0.02
High: -0.20
----------------------------------------------------------------------------------------------------------------
A summary of the NES and NPV analytical model inputs are provided
in Table IV.7. More detailed discussion on these inputs can be found in
TSD Chapter 10.
Table IV. 7.--Summary of NES and NPV Model Inputs
----------------------------------------------------------------------------------------------------------------
Input ANOPR description Changes for NOPR
----------------------------------------------------------------------------------------------------------------
Shipments............................... Annual shipments from shipments model..... No change.
Implementation date of standard......... Assumed to be 2007........................ Assumed to be 2010.
Base case efficiencies.................. Constant efficiency through 2035. Equal to Constant efficiency
weighted-average efficiency in 2007. through 2038. Equal to
weighted-average
efficiency in 2010.
Standards case efficiencies............. Constant efficiency at the specified Constant at the efficiency
standard level from 2007 to 2035. at the specified standard
level from 2010 to 2038.
Annual energy consumption per unit...... Average rated transformer losses are No change.
obtained from the LCC analysis, and are
then scaled for different size
categories, weighted by size market
share, and adjusted for transformer
loading (also obtained from the LCC
analysis).
Total installed cost per unit........... Weighted-average values as a function of No change.
efficiency level (from LCC analysis).
Electricity expense per unit............ Energy and capacity savings for the two No change.
types of transformer losses are each
multiplied by the corresponding average
marginal costs for capacity and energy,
respectively, for the two types of losses
(marginal costs are from the LCC
analysis).
Escalation of electricity prices........ AEO2003 forecasts (to 2025) and Used AEO2005 forecasts (to
extrapolation for 2035 and beyond. 2025) and extrapolation
for 2038 and beyond.
Electricity site-to-source conversion... A time series conversion factor; includes Updated conversion factors
electric generation, transmission, and from NEMS.
distribution losses. Conversion varies
yearly and is generated by DOE/EIA's
National Energy Modeling System (NEMS)
program.
Discount rates.......................... 3% and 7% real............................ No change.
Analysis year........................... Equipment and operating costs are Equipment and operating
discounted to the year of equipment price costs are discounted to
data, 2001. year 2004.
----------------------------------------------------------------------------------------------------------------
E. Commercial Consumer Subgroup Analysis
In analyzing the potential impacts of new or amended standards, the
Department evaluates impacts on identifiable groups (i.e., subgroups)
of customers, such as different types of businesses, which may be
disproportionately affected by a national standard. For this
rulemaking, the Department identified rural electric cooperatives and
municipal utilities as transformer consumer subgroups that could be
disproportionately affected, and examined the impact of proposed
standards on these groups. The consumer subgroup analysis is discussed
in detail in TSD Chapter 11.
The Department's selection of subgroups responded directly to
comments received on the ANOPR. NRECA expressed concern that
transformers servicing a single customer on a rural electric system may
not be represented in the general LCC analysis. It requested the
Department to take steps to include more data from cooperatives serving
sparsely populated areas with long radial distribution lines. It
commented that costs resulting from the DOE standard could increase to
an unjustified level for rural electric cooperatives, which purchase
relatively large numbers of transformers compared to their system load.
(NRECA, No. 74 at p. 2) Southern Company commented that municipal
utilities and rural electric cooperatives should be evaluated
separately. (Public Meeting Transcript, No. 56.12 at p. 211) In its
commercial consumer subgroup analysis, the Department analyzed
municipal utilities and rural electric cooperatives separately,
including additional data from cooperatives that serve sparsely
populated areas with long radial distribution lines.
The results of the Department's commercial consumer subgroup
analysis are summarized in section V.A.1.c below and described in
detail in TSD Chapter 11.
F. Manufacturer Impact Analysis
1. General Description
The Department performed an MIA to estimate the financial impact of
higher
[[Page 44382]]
efficiency standards on distribution transformer manufacturers and to
calculate the impact of such standards on employment and manufacturing
capacity. The MIA has both quantitative and qualitative aspects. The
quantitative part of the MIA primarily relies on the Government
Regulatory Impact Model (GRIM), an industry-cash-flow model customized
for this rulemaking. The GRIM inputs are information regarding the
industry cost structure, shipments, and revenues. The key output is the
INPV. Different sets of assumptions (scenarios) produce different
results. The qualitative part of the MIA addresses factors such as
product characteristics, characteristics of particular firms, and
market and product trends, and includes assessment of the impacts of
standards on subgroups of manufacturers. The complete MIA is outlined
in TSD Chapter 12.
The Department outlined the MIA approach in the ANOPR. 69 FR 45412.
In section II.C. of the ANOPR, the Department asked stakeholders for
comments on significant one-time additional costs manufacturers would
incur if efficiency standards were introduced. 69 FR 45393. The MIA
approach was also discussed at the September 28, 2004, ANOPR public
meeting.
The Department conducted the MIA in three phases. Phase 1,
``Industry Profile,'' consisted of the preparation of an industry
characterization. Phase 2, ``Industry Cash Flow,'' focused on the
industry as a whole. In this phase, DOE used the GRIM to prepare an
industry cash-flow analysis. The Department used publicly available
information developed in Phase 1 to adapt the GRIM structure to
facilitate the analysis of distribution transformer standards. In Phase
3, ``Subgroup Impact Analysis,'' the Department conducted structured,
detailed interviews with six manufacturers. Two of the six
manufacturers are small businesses (750 or fewer employees). Three of
the manufacturers produce medium-voltage, dry-type transformers,
collectively representing more than 70 percent of the U.S. medium-
voltage, dry-type market. Four of the manufacturers produce liquid-
immersed transformers, collectively representing more than 70 percent
of the U.S. liquid-immersed market. The purpose of the interviews was
to gather information about the financial impacts of standards on
manufacturers, as well as the impacts of standards on employment and
manufacturing capacity. The interviews provided valuable information
that the Department used to evaluate the impacts of an energy
conservation standard on manufacturers' cash flows, manufacturing
capacities, and employment levels.
In addition to the six structured, detailed interviews, the
Department conducted telephone interviews with four additional small
businesses. The Department based the small-business interviews on an
interview guide that was significantly different from that used for the
structured, detailed interviews. Three of the small businesses
interviewed produce medium-voltage, dry-type transformers, and one
produces liquid-immersed transformers. Finally, in addition to the six
detailed interviews and the four short telephone interviews with small
businesses, the Department conducted telephone interviews with several
companies that supply materials and equipment to the U.S. distribution
transformer industry. The material and equipment suppliers included
both U.S. firms and foreign suppliers. The Department visited one of
the U.S. core steel suppliers. The following paragraphs describe more
specifically the steps DOE took in developing the information on which
the MIA was based.
2. Industry Profile
Phase 1 of the MIA consisted of preparing an industry profile.
Before initiating the detailed impact studies, DOE collected
information on the present and past structure and market
characteristics of the distribution transformer industry. This activity
involved both quantitative and qualitative efforts to assess the
industry and equipment to be analyzed. The information collected
included (1) manufacturer market shares, characteristics, and financial
information; (2) product characteristics; and (3) trends in the number
of firms, the market, and product characteristics.
The industry profile included a topdown cost analysis of the
distribution transformer manufacturing industry that DOE used to derive
cost and financial inputs for the GRIM, e.g., revenues; material,
labor, overhead, and depreciation costs; selling, general, and
administrative (SG&A) expenses; and research and development (R&D)
expenses. The Department used public sources of information to
calibrate its initial characterization of the industry, including
Securities and Exchange Commission (SEC) 10-K reports, corporate annual
reports, the U.S. Census Bureau's Economic Census, Dun & Bradstreet
reports, and industry analysis from Ibbotson Associates.
3. Industry Cash-Flow Analysis
Phase 2 of the MIA focused on the financial impacts of standards on
the industry as a whole. The analytical tool DOE used for calculating
the financial impacts of standards on manufacturers is the GRIM. In
Phase 2, the Department used the GRIM to perform a preliminary industry
cash-flow analysis. To perform this analysis, DOE used the financial
values determined during Phase 1 and the shipment projections used in
the NES analysis.
4. Subgroup Impact Analysis
In Phase 3 of the MIA, the Department established two distinct
subgroups of distribution transformer manufacturers that could be
affected by efficiency standards: Liquid-immersed and medium-voltage,
dry-type. The Department also evaluated the impact of the energy
conservation standards on small businesses. Small businesses, as
defined by the Small Business Administration (SBA) for the distribution
transformer manufacturing industry, are manufacturing enterprises with
750 or fewer employees.
5. Government Regulatory Impact Model Analysis
An energy conservation standard can affect a manufacturer's cash
flow in three distinct ways: (1) It may require increased investment;
(2) it may result in higher production costs per unit; and (3) it may
alter revenue by virtue of higher per-unit prices and changes in sales
volumes. As mentioned, the Department uses the GRIM to quantify the
changes in cash flow that result in a higher or lower industry value.
The GRIM analysis for this NOPR used a number of inputs--annual
shipments; prices; material, labor, and overhead costs; SG&A expenses;
taxes; and capital expenditures--to arrive at a series of annual net
cash flows beginning in 2004 and continuing to 2038. The Department
collected this information from a number of sources, including publicly
available data; structured, detailed interviews with six manufacturers;
and short telephone interviews with an additional four small
manufacturers. The Department calculated INPV by discounting and
summing the annual net cash flows. Chapter 12 of the TSD contains
additional information about the GRIM analysis.
For the MIA, the Department considered two distinct markup
scenarios: (1) The preservation-of-gross-margin-percentage scenario,
and (2) the preservation-of-operating-profit scenario. Under the
``preservation-of-gross-margin-percentage'' scenario, DOE
[[Page 44383]]
applied a single, uniform ``gross margin percentage'' markup across all
efficiency levels. This scenario implies that, as production cost
increases with efficiency, the absolute dollar markup will increase.
The Department assumed that the non-production cost markup, which
includes SG&A expenses, R&D expenses, interest, and profit, was 1.25.
This markup is consistent with the one that the Department assumed in
the engineering analysis and the base case of the GRIM.
The implicit assumption behind the ``preservation-of-operating-
profit'' scenario is that the industry can maintain or preserve its
operating profit (in absolute dollars) after the standard. The industry
would do so by passing its increased costs on to its customers without
increasing its operating profits in absolute dollars. The Department
implemented this markup scenario in the GRIM by setting the non-
production cost markups at each TSL to yield approximately the same
operating profit in both the base case and the standard case in the
year after standard implementation (2011).
The Department received several comments concerning the one-time
expenditures that industry would incur in order to manufacture
transformers that comply with energy conservation standards. The
Department refers to such one-time expenditures as conversion capital
expenditures and product conversion expenses, where the latter includes
research, development, testing, and marketing expenditures related to
achieving compliance. NEMA commented that the Department should contact
individual manufacturers to learn about additional one-time conversion
capital costs. (NEMA, No. 48 at p. 2) PEMCO Corporation made a similar
comment, noting that mandatory energy conservation standards would
cause small manufacturers to make new capital investments above and
beyond those already made to improve transformer efficiency. (PEMCO,
No. 57 at p. 1) Finally, ODOE urged the Department to consider the
costs of transition to a standards-compliant industry. (ODOE, No. 66 at
p. 3) The Department considers conversion capital expenditures, and
also product conversion expenses, in setting energy conservation
standards for any product, recognizes the importance of these issues to
distribution transformer manufacturers, and explicitly considered such
expenditures in its MIA. The Department gathered information pertaining
to conversion expenditures by interviewing both transformer
manufacturers and equipment suppliers to the distribution transformer
industry.
EMSIC commented that investments will not cause a significant
impact on manufacturers of liquid-immersed transformers if the energy
conservation standard is set below a certain threshold. EMSIC asserted
that liquid-immersed transformers can be made more efficient primarily
by using better materials, without the need for significant investment.
(EMSIC, No. 73 at p. 2) The Department concurs that conversion capital
expenditures would be relatively modest for TSLs 1 through 4, which are
the trial standard levels that would not involve partial or full
conversion to amorphous core technology. TSLs 5 and 6 would require
partial and full conversion to amorphous core technology, respectively,
and the conversion capital expenditures necessary at these TSLs would
be significant.
EMSIC commented that an energy conservation standard would
positively affect liquid-immersed transformer manufacturer revenue
(through higher prices), while also limiting product diversity and
thereby dampening the cost increases at higher efficiencies. EMSIC
suggested that one mechanism by which an energy conservation standard
would limit product diversity would be the elimination of lower-grade
materials. (EMSIC, No. 73 at p. 2) In the GRIM analysis, the Department
explicitly considered the positive impact of standards on manufacturer
revenue. While the Department recognizes that production cost increases
in moving to higher TSLs could be dampened by limited product
diversity, the Department believes that this effect will be small
compared to the other effects explicitly considered in its analysis.
The final MIA-related comment received by the Department pertained
to the Nation's import tariff on raw core steel. ZDMH is a mechanically
scribed, deep-domain refined, core steel that survives the annealing
process without negatively impacting the low loss properties of the
steel. Since ZDMH core steel is available from only one foreign
country, U.S. transformer manufacturers would have to purchase ZDMH
subject to this tariff. This would give foreign transformer
manufacturers that do not impose this tariff (e.g., in Mexico) an
advantage in producing transformers using ZDMH core steel, since
finished cores or transformers would not be subject to the tariff.
ERMCO asked the Department to keep this issue in mind when choosing the
standard, to avoid putting domestic manufacturers at a disadvantage.
(ERMCO, No. 58 at p. 2) The Department addressed the ZDMH issue in its
engineering analysis by modeling Mexican-made transformers, because
this would be the expected production scenario for ZDMH transformers.
Since, according to the Department's analysis, ZDMH design option
combinations would not be the most cost-effective at any trial standard
level, DOE did not explicitly address the impact of the U.S. core steel
tariff on transformer manufacturing capacity in the MIA. To review the
cost-effectiveness findings of ZDMH in comparison to other transformer
core steels, see TSD Chapter 5.
G. Employment Impact Analysis
The Process Rule includes employment impacts among the factors that
DOE considers in selecting a proposed standard. Employment impacts
include direct and indirect impacts. Direct employment impacts are any
changes in the number of employees for distribution transformer
manufacturers, their suppliers, and related service firms. Indirect
impacts are those changes of employment in the larger economy that
occur due to the shift in expenditures and capital investment that is
caused by the purchase and operation of more efficient transformer
equipment. The MIA addresses direct employment impacts; this section
describes indirect impacts.
Indirect employment impacts from distribution transformer standards
consist of the net jobs created or eliminated in the national economy,
other than in the manufacturing sector being regulated, as a
consequence of: (1) Reduced spending by end users on energy
(electricity, gas--including liquefied petroleum gas--and oil); (2)
reduced spending on new energy supply by the utility industry; (3)
increased spending on the purchase price of new distribution
transformers; and (4) the effects of those three factors throughout the
economy. The Department expects the net monetary savings from standards
to be redirected to other forms of economic activity. The Department
also expects these shifts in spending and economic activity to affect
the demand for labor.
In developing this proposed rule, the Department estimated indirect
national employment impacts using an input/output model of the U.S.
economy, called IMBUILD (impact of building energy efficiency
programs). The Department's Office of Building Technology, State, and
Community Programs (now the Building Technologies Program) developed
the model. IMBUILD is a personal-computer-based, economic-analysis
[[Page 44384]]
model that characterizes the interconnections among 35 sectors of the
economy as national input/output structural matrices, using data from
the U.S. Bureau of Labor Statistics. The IMBUILD model estimates
changes in employment, industry output, and wage income in the overall
U.S. economy resulting from changes in expenditures in the various
sectors of the economy. The Department estimated changes in
expenditures using the NES spreadsheet. IMBUILD then estimated the net
national indirect employment impacts of potential distribution
transformer efficiency standards on employment by sector.
While both the IMBUILD input/output model and the direct use of BLS
employment data suggest the proposed distribution transformer standards
could increase the net demand for labor in the economy, the gains would
most likely be very small relative to total national employment. The
Department therefore concludes only that the proposed distribution
transformer standards are likely to produce employment benefits that
are sufficient to offset fully any adverse impacts on employment in the
distribution transformer or energy industries.
For more details on the employment impact analysis, see TSD Chapter
14. The Department did not receive stakeholder comments on these
indirect employment impact methods, which it proposed in the ANOPR for
use in the NOPR analysis.
H. Utility Impact Analysis
The proposed distribution transformer energy-efficiency standards
have the distinct feature of regulating a product that also has
electric utilities as one of the major product consumers. The
Department therefore analyzed one portion of the impacts on utilities
from the consumer perspective and another portion of impacts from the
utility sector perspective. Those impacts that the Department analyzed
in the utility impact analysis are from the utility sector perspective
and include the impacts on the number of power plants constructed and
the fuel consumption of the sector. Financial impacts on the utility
sector are described in the LCC analysis.
The Department analyzed the effects of proposed standards on
electric utility industry generation capacity and fuel consumption
using a variant of the EIA's National Energy Modeling System (NEMS).\3\
NEMS, which is available in the public domain, is a large, multi-
sectoral, partial-equilibrium model of the U.S. energy sector. The EIA
uses NEMS to produce its Annual Energy Outlook--a widely recognized
baseline energy forecast for the U.S. The Department used a variant
known as NEMS-BT.\4\
---------------------------------------------------------------------------
\3\ For more information on NEMS, please refer to the U.S.
Department of Energy, Energy Information Administration
documentation. A useful summary is National Energy Modeling System:
An Overview 2003, DOE/EIA-0581 (2003), March, 2003.
\4\ DOE/EIA approves use of the name NEMS to describe only an
official version of the model without any modification to code or
data. Because this analysis entails some minor code modifications
and the model is run under various policy scenarios that are
variations on DOE/EIA assumptions, the Department refers to it by
the name NEMS-BT (BT is DOE's Building Technologies Program, under
whose aegis this work has been performed). NEMS-BT was previously
called NEMS-BRS.
---------------------------------------------------------------------------
The Department conducted the utility analysis as policy deviations
from the AEO2005, applying the same basic set of assumptions. The
utility analysis reported the changes in installed capacity and
generation, by fuel type, that result for each TSL, as well as changes
in end-use electricity sales.
Details of the utility analysis methods and results are reported in
TSD Chapter 13. The Department did not receive stakeholder comments on
the utility impact analysis methods proposed in the ANOPR.
I. Environmental Analysis
The Department determined the environmental impacts of the proposed
standards. Specifically, DOE calculated the reduction in power plant
emissions of CO2, sulfur dioxide (SO2),
NOX , and mercury (Hg), using the NEMS-BT computer model.
The environmental assessment published with the TSD, however, does not
include the estimated reduction in power plant emissions of
SO2 because, as discussed below, any such reduction
resulting from an efficiency standard would not affect the overall
level of SO2 emissions in the U.S. Like SO2,
future emissions of NOX and Hg will be subject to emissions
caps. The Department calculated a forecast of emissions reductions for
these two types of emissions reductions, for emissions under an
uncapped scenario. Under emissions-cap regulation, the Department
assumes that the uncapped emissions reduction estimate corresponds to
the generation of emissions allowance credits under an emissions-cap
scenario.
The NEMS-BT is run similarly to the AEO2005 NEMS, except that
distribution transformer energy usage is reduced by the amount of
energy (by fuel type) saved due to the trial standard levels. The
Department obtained the input of energy savings from the NES
spreadsheet. For the environmental analysis, the output is the
forecasted physical emissions. The net benefit of the standard is the
difference between emissions estimated by NEMS-BT and the AEO2005
Reference Case.
The NEMS-BT tracks CO2 emissions using a detailed module
that provides robust results because of its broad coverage of all
sectors and inclusion of interactive effects. In the case of
SO2, the Clean Air Act Amendments of 1990 set an emissions
cap on all power generation. The attainment of this target, however, is
flexible among generators and is enforced by applying market forces,
through the use of emissions allowances and tradable permits. As a
result, accurate simulation of SO2 trading tends to imply
that the effect of efficiency standards on physical emissions will be
near zero because emissions will always be at, or near, the ceiling.
Thus, there is virtually no real possible SO2 environmental
benefit from electricity savings as long as there is enforcement of the
emissions ceilings. Though there may not be an actual reduction in
SO2 emissions from electricity savings, there still may be
an economic benefit from reduced emissions demand. Electricity savings
decrease the need to generate SO2 emissions from power
production, and consequently can decrease the need to purchase or
generate SO2 emissions allowance credits. This decreases the
costs of complying with regulatory caps on emissions. See the
environmental assessment, a separate report within the TSD, for a
discussion of these issues.
Regarding the environmental assessment, ASAP stated that DOE should
report other emissions impacts in addition to NOX and
CO2, such as Hg and particulates. (Public Meeting
Transcript, No. 56.12 at p. 247) The Department responded to this
comment by adding Hg to the emissions reported in the environmental
assessment. Particulates are a special case because they arise not only
from direct emissions, but also from complex atmospheric chemical
reactions that result from NOX and SO2 emissions.
Because of the highly complex and uncertain relationship between
particulate emissions and particulate concentrations that impact air
quality, the Department did not report particulate emissions.
[[Page 44385]]
V. Analytical Results
A. Economic Justification and Energy Savings
1. Economic Impacts on Commercial Consumers
a. Life-Cycle Cost and Payback Period
The Department's LCC and PBP analyses provided five key outputs for
each TSL that are reported in Tables V.1 through V.10 below. The first
three outputs are the proportion of transformer purchases where the
purchase of a standard-compliant design creates a net life-cycle cost,
no impact, or a net life-cycle savings for the consumer. The fourth
output is the average net life-cycle savings from a standard-compliant
design. Finally, the fifth output is the average payback period for the
consumer investment in a standard-compliant design. The payback period
is the number of years it would take for the customer to recover, as a
result of energy savings, the increased costs of higher-efficiency
equipment, based on the operating cost savings from the first year of
ownership. The payback period is an economic benefit-cost measure that
uses benefits and costs without discounting. Detailed information on
the LCC and PBP analyses can be found in TSD Chapter 8.
Table V.1 presents the summary of the LCC and PBP analysis for the
representative unit from design line 1, a 50 kVA, liquid-immersed,
single-phase, pad-mounted distribution transformer. For this unit, the
average efficiency of the baseline transformers selected during the LCC
analysis was 98.97 percent, the minimum efficiency of the baseline
transformers selected during the LCC analysis was 98.56 percent, and
the consumer equipment cost before installation (which includes
manufacturer selling price, shipping costs, distributor markup, and
taxes) was $1,382.00.
Table V.1.--Summary LCC and PBP Results for Design Line 1 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 98.9 98.9 98.9 99.04 99.19 99.59
Transformers with Net LCC Increase 4.9 4.9 4.9 16.6 52.8 90.5
(%)..............................
Transformers with No Change in LCC 65.2 65.2 65.2 50.9 14.7 0.0
(%)..............................
Transformers with Net LCC Savings 29.9 29.9 29.9 32.5 32.5 9.5
(%)..............................
Mean LCC Savings ($).............. 93 93 93 98 5 -688
Mean Payback Period (years)....... 11.4 11.4 11.4 21.9 36.0 45.0
----------------------------------------------------------------------------------------------------------------
Table V.2 presents the summary of the LCC and PBP analysis for the
representative unit from design line 2, a 25 kVA, liquid-immersed,
single-phase, pole-mounted distribution transformer. For this unit, the
average efficiency of the baseline transformers selected during the LCC
analysis was 98.74 percent, the minimum efficiency of the baseline
transformers selected during the LCC analysis was 98.23 percent, and
the consumer equipment cost before installation (which includes
manufacturer selling price, shipping costs, distributor markup, and
taxes) was $737.00.
Table V.2.--Summary LCC and PBP Results for Design Line 1 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 98.7 98.73 98.76 98.79 98.96 99.46
Transformers with Net LCC Increase 1.4 3.0 5.2 8.6 43.9 98.9
(%)..............................
Transformers with No Change in LCC 66.6 64.3 60.8 56.3 25.4 0.0
(%)..............................
Transformers with Net LCC Savings 32.0 32.7 34.0 35.1 30.7 1.1
(%)..............................
Mean LCC Savings ($).............. 69 70 72 71 7 -953
Mean Payback Period (years)....... 4.8 6.8 8.8 12.0 31.7 66.6
----------------------------------------------------------------------------------------------------------------
Table V.3 presents the summary of the LCC and PBP analysis for the
representative unit from design line 3, a 500 kVA, liquid-immersed,
single-phase distribution transformer. For this unit, the average
efficiency of the baseline transformers selected during the LCC
analysis was 99.36 percent, the minimum efficiency of the baseline
transformers selected during the LCC analysis was 99.07 percent, and
the consumer equipment cost before installation (which includes
manufacturer selling price, shipping costs, distributor markup, and
taxes) was $5,428.00.
Table V.3.--Summary LCC and PBP Results for Design Line 3 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 99.3 99.38 99.46 99.54 99.74 99.75
Transformers with Net LCC Increase 0.2 1.4 6.1 39.9 66.3 70.8
(%)..............................
[[Page 44386]]
Transformers with No Change in LCC 73.7 65.2 49.5 4.0 0.1 0.0
(%)..............................
Transformers with Net LCC Savings 26.1 33.4 44.4 56.1 33.6 29.2
(%)..............................
Mean LCC Savings ($).............. 1,746 2,267 2,775 2,876 627 -410
Mean Payback Period (years)....... 1.4 4.3 10.4 19.8 29.3 32.3
----------------------------------------------------------------------------------------------------------------
Table V.4 presents the summary of the LCC and PBP analysis for the
representative unit from design line 4, a 150 kVA, liquid-immersed,
three-phase distribution transformer. For this unit, the average
efficiency of the baseline transformers selected during the LCC
analysis was 98.91 percent, the minimum efficiency of the baseline
transformers selected during the LCC analysis was 98.42 percent, and
the consumer equipment cost before installation (which includes
manufacturer selling price, shipping costs, distributor markup, and
taxes) was $3,335.00.
Table V.4.--Summary LCC and PBP Results for Design Line 4 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 98.9 99.08 99.26 99.26 99.58 99.61
Transformers with Net LCC Increase 3.3 16.8 41.0 41.0 64.4 75.5
(%)..............................
Transformers with No Change in LCC 63.7 40.8 11.3 11.3 0.8 0.0
(%)..............................
Transformers with Net LCC Savings 33.0 42.4 47.7 47.7 34.8 25.5
(%)..............................
Mean LCC Savings ($).............. 556 629 450 450 56 -572
Mean Payback Period (years)....... 8.5 18.1 21.5 21.5 29.2 34.9
----------------------------------------------------------------------------------------------------------------
Table V.5 presents the summary of the LCC and PBP analysis for the
representative unit from design line 5, a 1500 kVA, liquid-immersed,
three-phase distribution transformer. For this unit, the average
efficiency of the baseline transformers selected during the LCC
analysis was 99.36 percent, the minimum efficiency of the baseline
transformers selected during the LCC analysis was 99.13 percent, and
the consumer equipment cost before installation (which includes
manufacturer selling price, shipping costs, distributor markup, and
taxes) was $11,931.00.
Table V.5.--Summary LCC and PBP Results for Design Line 5 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 99.3 99.36 99.42 99.47 99.71 99.71
Transformers with Net LCC Increase 0.3 1.5 10.2 15.9 57.1 57.2
(%)..............................
Transformers with No Change in LCC 71.7 62.8 40.0 24.2 0.0 0.1
(%)..............................
Transformers with Net LCC Savings 28.0 35.7 49.8 59.9 42.9 42.7
(%)..............................
Mean LCC Savings ($).............. 3,957 5,463 6,504 7,089 4,431 3,902
Mean Payback Period (years)....... 3.4 6.1 12.7 14.1 25.6 26.1
----------------------------------------------------------------------------------------------------------------
Table V.6 presents the summary of the LCC and PBP analysis for the
representative unit from design line 9, a 300 kVA, medium-voltage, dry-
type, three-phase distribution transformer with a 45kV BIL. For this
unit, the average efficiency of the baseline transformers selected
during the LCC analysis was 98.77 percent, the minimum efficiency of
the baseline transformers selected during the LCC analysis was 98.41
percent, and the consumer equipment cost before installation (which
includes manufacturer selling price, shipping costs, distributor
markup, contractor markup, and taxes) was $7,510.00.
Table V.6.--Summary LCC and PBP Results for Design Line 9 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 98.6 98.82 99.04 99.26 99.41 99.41
Transformers with Net LCC Increase 0.6 1.1 5.3 25.7 56.3 55.0
(%)..............................
[[Page 44387]]
Transformers with No Change in LCC 57.8 46.3 29.7 0.5 0.0 0.0
(%)..............................
Transformers with Net LCC Savings 41.6 52.6 65.0 73.8 43.7 45.0
(%)..............................
Mean LCC Savings ($).............. 988 1,968 3,103 3,532 1,181 1,274
Mean Payback Period (years)....... 1.5 2.4 5.4 12.4 21.7 21.5
----------------------------------------------------------------------------------------------------------------
Table V.7 presents the summary of the LCC and PBP analysis for the
representative unit from design line 10, a 1500 kVA, medium-voltage,
dry-type, three-phase distribution transformer with a 45 kV BIL. For
this unit, the average efficiency of the baseline transformers selected
during the LCC analysis was 99.17 percent, the minimum efficiency of
the baseline transformers selected during the LCC analysis was 98.79
percent, and the consumer equipment cost before installation (which
includes manufacturer selling price, shipping costs, distributor
markup, contractor markup, and taxes) was $33,584.00.
Table V.7.--Summary LCC and PBP Results for Design Line 10 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 99.1 99.20 99.30 99.39 99.51 99.51
Transformers with Net LCC Increase 4.4 5.1 8.9 21.0 66.3 66.2
(%)..............................
Transformers with No Change in LCC 63.3 56.9 44.4 23.2 0.0 0.0
(%)..............................
Transformers with Net LCC Savings 32.3 37.6 46.7 55.8 33.7 33.8
(%)..............................
Mean LCC Savings ($).............. 4,041 5,227 6,818 7,699 1,279 1,124
Mean Payback Period (years)....... 7.7 8.3 10.0 13.4 28.7 29.4
----------------------------------------------------------------------------------------------------------------
Table V.8 presents the summary of the LCC and PBP analysis for the
representative unit from design line 11, a 300 kVA, medium-voltage,
dry-type, three-phase distribution transformer with a 95 kV BIL. For
this unit, the average efficiency of the baseline transformers selected
during the LCC analysis was 98.42 percent, the minimum efficiency of
the baseline transformers selected during the LCC analysis was 98.05
percent, and the consumer equipment cost before installation (which
includes manufacturer selling price, shipping costs, distributor
markup, contractor markup, and taxes) was $10,945.00.
Table V.8.--Summary LCC and PBP Results for Design Line 11 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................... 98.5 98.67 98.84 99.01 99.09 99.09
Transformers with Net LCC Increase 2.4 3.9 9.8 22.0 34.2 33.2
(%)..............................
Transformers with No Change in LCC 42.5 34.6 18.7 2.3 0.0 0.0
(%)..............................
Transformers with Net LCC Savings 55.1 61.5 71.5 75.7 66.8 66.8
(%)..............................
Mean LCC Savings Period ($)....... 2,491 3,621 4,313 4,845 4,186 4,289
Mean Payback (years).............. 3.8 4.9 7.9 11.8 15.1 14.8
----------------------------------------------------------------------------------------------------------------
Table V.9 presents the summary of the LCC and PBP analysis for the
representative unit from design line 12, a 1500 kVA, medium-voltage,
dry-type, three-phase distribution transformer with a 95 kV BIL. For
this unit, the average efficiency of the baseline transformers selected
during the LCC analysis was 99.18 percent, the minimum efficiency of
the baseline transformers selected during the LCC analysis was 98.81
percent, and the consumer equipment cost before installation (which
includes manufacturer selling price, shipping costs, distributor
markup, contractor markup, and taxes) was $33,590.00.
Table V.9.--Summary LCC and PBP Results for Design Line 12 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
---------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)................................................. 99.0 99.12 99.23 99.35 99.51 99.51
Transformers with Net LCC Increase (%)......................... 1.4 1.5 5.8 18.2 70.6 70.1
[[Page 44388]]
Transformers with No Change in LCC (%)......................... 75.1 71.9 56.9 28.2 0.0 0.0
Transformers with Net LCC Savings (%).......................... 23.5 26.6 37.3 53.6 29.4 29.9
Mean LCC Savings ($)........................................... 2,600 3,973 5,485 6,812 -650 -655
Mean Payback Period (years).................................... 4.6 4.7 8.3 12.7 29.3 29.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.10 presents the summary of the LCC and PBP analysis for the
representative unit from design line 13, a 2000 kVA, medium-voltage,
dry-type, three-phase distribution transformer with a 125 kV BIL. For
this unit, the average efficiency of the baseline transformers selected
during the LCC analysis was 99.26 percent, the minimum efficiency of
the baseline transformers selected during the LCC analysis was 98.97
percent, and the consumer equipment cost before installation (which
includes manufacturer selling price, shipping costs, distributor
markup, contractor markup, and taxes) was $41,873.00.
Table V.10.--Summary LCC and PBP Results for Design Line 13 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------
1 TP 1 2 3 4 5 6
---------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)................................................. 99.0 99.15 99.30 99.45 99.55 99.55
Transformers with Net LCC Increase (%)......................... 3.8 1.5 4.4 42.6 75.7 75.7
Transformers with No Change in LCC (%)......................... 76.0 72.9 58.9 5.4 0.0 0.0
Transformers with Net LCC Savings (%).......................... 20.2 25.6 36.7 52.0 24.3 24.3
Mean LCC Savings ($)........................................... 662 3,125 5,430 6,435 -5,303 -5,218
Mean Payback Period (years).................................... 9.7 5.8 8.0 19.5 32.5 32.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
b. Rebuttable-Presumption Payback
As set forth in section 325(o)(2)(B)(iii) of EPCA, 42 U.S.C.
6295(o)(2)(B)(iii), there is a rebuttable presumption that an energy
conservation standard is economically justified if the increased
installed cost for a product that meets the standard is less than three
times the value of the first-year energy savings resulting from the
standard. However, while the Department examined the rebuttable-
presumption criteria, the Department determined economic justification
for the proposed standard levels through a more detailed analysis of
the economic impacts of increased efficiency pursuant to section
325(o)(2)(B)(i) of EPCA. (42 U.S.C. 6295(o)(2)(B)(i))
The Department calculated a rebuttable-presumption payback period
for each trial standard level, to determine if DOE could presume that a
standard at that level is economically justified. Rather than using
distributions for input values, DOE used discrete values and based the
calculation on the DOE distribution-transformer-test-procedure
assumptions. As a result, the Department calculated a single
rebuttable-presumption payback value for each standard level, and not a
distribution of payback periods.
To evaluate the rebuttable presumption, the Department estimated
the additional cost of purchasing a more efficient, standard-compliant
product, and compared this cost to the value of the energy savings
during the first year of operation of the product as determined by the
applicable test procedure. The Department interpreted the increased
cost of purchasing a standard-compliant product to include the cost of
installing the product for use by the purchaser. The Department then
calculated the rebuttable-presumption payback period, or the ratio of
the value of the first year's energy savings to the increase in
purchase price. When the rebuttable-presumption payback period is less
than three years, the rebuttable presumption is satisfied; when the
payback period is equal to or more than three years, the rebuttable
presumption is not satisfied.
The rebuttable-presumption payback period may differ from payback
periods presented in other parts of this NOPR in at least two important
ways:
The rebuttable-presumption payback period uses test
procedure loading levels to evaluate losses, rather than the
Department's estimate of in-service loading conditions.
Other payback periods may consider total operating costs,
whereas the rebuttable-presumption payback period considers only the
value of energy savings. In the case of distribution transformers,
however, the Department estimates that the change in operating costs is
solely due to energy savings.
There are three key inputs into the rebuttable-presumption payback
calculation: (1) The average efficiency; (2) the average installed
cost; and (3) the cost of electricity. Given the average efficiency of
the baseline and standard-compliant transformers, the Department
calculated the energy savings by taking the difference in the annual
losses between the baseline and standard-compliant transformers,
assuming the loading conditions from the test procedure. Multiplying
the energy savings times the cost of electricity provided the value of
the energy savings. Dividing the value of the energy savings into the
installed-cost increase for a standard-compliant transformer provided
the estimate of the rebuttable-presumption payback period. More
detailed discussion on the rebuttable presumption is contained in TSD
Chapter 8, section 8.7.
Table V.11 shows the rebuttable-presumption payback period as a
function of design line and standard level.
[[Page 44389]]
Table V.11.--Rebuttable-Presumption Payback in Years
----------------------------------------------------------------------------------------------------------------
Rated
Design line capacity TSL1 (TP TSL2 TSL3 TSL4 TSL5 TSL6
kVA 1)
----------------------------------------------------------------------------------------------------------------
1........................... 50 7.0 7.0 7.0 10.1 16.0 27.2
2........................... 25 2.1 3.6 4.3 5.2 15.2 42.4
3........................... 500 0.5 2.2 5.1 9.7 22.7 25.1
4........................... 150 3.9 7.4 12.0 12.0 17.2 20.7
5........................... 1,500 2.6 4.5 6.5 9.0 20.0 20.0
9........................... 300 0.7 1.3 2.5 5.6 11.3 11.3
10.......................... 1,500 3.2 3.8 4.8 6.1 12.4 12.4
11.......................... 300 2.0 2.6 3.8 5.3 7.0 7.0
12.......................... 1,500 2.3 2.5 3.3 5.3 13.6 13.6
13.......................... 2,000 5.0 3.3 4.1 8.2 16.7 16.7
----------------------------------------------------------------------------------------------------------------
c. Commercial Consumer Subgroup Analysis
In analyzing the potential impacts of new or amended standards, the
Department evaluates impacts on identifiable groups (i.e., subgroups)
of customers, such as different types of businesses, which may be
disproportionately affected by a national standard. For this
rulemaking, the Department identified rural electric cooperatives and
municipal utilities as transformer consumer subgroups that could be
disproportionately affected, and examined the impact of today's
proposed standards on these groups.
The Department's analysis indicated that, for municipal utilities,
the economics are similar to those of the national sample of utilities,
but found significant differences in the results for rural
cooperatives. Rural cooperatives have lower transformer loading levels
than the average utility, and so their operating cost savings from
higher standards would be smaller than those for the average utility.
Chapter 11 of the TSD explains the Department's method for conducting
the consumer subgroup analysis and presents the detailed results of
that analysis.
Table V.12 shows the fraction of transformers that are impacted by
different standard levels for the two commercial consumer subgroups. A
transformer is impacted by a standard if the transformer design has to
change in order to meet the performance requirements of the standard.
Table V.13 shows the mean LCC savings from proposed energy-efficiency
standards, and Table V.14 shows the mean payback period (in years) for
the two commercial subgroups. Only the liquid-immersed design lines are
included in this analysis since those types dominate the transformers
purchased by electric utilities.
Table V.12.--Fraction of Transformers Purchased by Commercial Consumer Subgroups Impacted by Energy-Efficiency
Standards
[Percent]
----------------------------------------------------------------------------------------------------------------
TSL1 (TP
Design line 1) TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
1....................................... 35.3 35.3 35.3 48.6 84.8 100.0
2....................................... 33.9 34.7 39.3 44.1 74.9 100.0
3....................................... 26.1 35.2 50.4 96.0 99.9 100.0
4....................................... 35.9 60.2 88.3 88.3 99.2 100.0
5....................................... 27.9 36.0 59.1 75.6 99.9 99.9
----------------------------------------------------------------------------------------------------------------
Rural Cooperative Subgroup
----------------------------------------------------------------------------------------------------------------
1....................................... 35.6 49.8 88.7 98.0 99.0 100.0
2....................................... 35.6 38.0 42.8 48.1 81.1 100.0
3....................................... 27.6 35.1 50.6 97.7 99.9 100.0
4....................................... 36.9 61.5 94.3 93.9 99.4 100.0
5....................................... 29.1 37.6 60.4 79.2 99.9 100.0
----------------------------------------------------------------------------------------------------------------
Table V.13.--Mean Life-Cycle Cost Savings for Transformers Purchased by Commercial Consumer Subgroups
[Dollars]
----------------------------------------------------------------------------------------------------------------
Rated
Design line capacity TSL1 (TP TSL2 TSL3 TSL4 TSL5 TSL6
kVA 1)
----------------------------------------------------------------------------------------------------------------
Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
1........................... 50 95 95 95 120 64 -594
2........................... 25 69 66 70 73 17 -926
3........................... 500 2,109 2,765 3,607 3,693 1,745 1,102
[[Page 44390]]
4........................... 150 608 808 512 512 435 -165
5........................... 1,500 4,853 6,649 8,128 9,013 7,680 7,453
----------------------------------------------------------------------------------------------------------------
Rural Cooperative Subgroup
----------------------------------------------------------------------------------------------------------------
1........................... 50 79 79 79 58 -91 -861
2........................... 25 69 66 67 63 -25 -1,040
3........................... 500 1,288 1,525 1,669 1,579 -1,630 -2,573
4........................... 150 412 370 183 183 -599 -1,320
5........................... 1,500 2,243 3,013 3,084 3,239 -3,617 -3,775
----------------------------------------------------------------------------------------------------------------
Table V.14.--Mean Payback Period for Transformers Purchased by Commercial Consumer Subgroups
[Years]
----------------------------------------------------------------------------------------------------------------
TSL1 (TP
Design line 1) TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Municipal Utility Subgroup
----------------------------------------------------------------------------------------------------------------
1....................................... 11.1 11.1 11.1 19.9 33.2 43.0
2....................................... 4.8 7.0 8.8 12.0 30.6 65.4
3....................................... 1.2 3.8 8.7 19.2 27.4 29.9
4....................................... 7.7 15.0 21.5 21.5 27.1 32.5
5....................................... 2.9 5.1 11.0 12.9 23.7 23.7
----------------------------------------------------------------------------------------------------------------
Rural Cooperative Subgroup
----------------------------------------------------------------------------------------------------------------
1....................................... 12.4 12.4 12.4 25.2 41.2 49.3
2....................................... 5.4 7.6 9.9 14.0 35.6 72.5
3....................................... 1.6 5.7 13.7 22.5 33.9 37.7
4....................................... 10.8 22.2 25.4 25.4 31.4 37.7
5....................................... 4.9 8.4 16.9 17.4 29.4 29.4
----------------------------------------------------------------------------------------------------------------
The LCC results for the municipal utilities subgroup are quite
similar to the results for the national sample of utilities.
Transformers purchased by municipal utilities tend to serve more
diverse, urban loads than transformers that serve more rural areas. The
increased load diversity increases the load factor and the transformer
loading, thus increasing the potential savings from reduced load
losses. Thus, compared to the other subgroup (rural cooperatives), the
benefits from efficiency improvements are, on average, greater.
In contrast to the results for municipal utilities, the LCC savings
tends to be lower for rural cooperatives, and the payback times tend to
be longer. The LCC and PBP results for the rural cooperatives subgroup
are mostly a reflection of the fact that the loading on rural
transformers is lower, and thus the savings from reduced load losses
are more modest. Distribution transformers purchased by rural
cooperatives have lower loading than transformers that serve urban
areas, primarily because the need to mitigate voltage flicker often
results in the purchase of transformers of higher capacities, and
because transformers purchased by rural cooperatives tend to serve
isolated loads with lower load factors. The lower loading decreases the
potential savings from reduced load losses, so the benefits from
efficiency improvements are, on average, less than the municipal
utility case per affected transformer.
2. Economic Impacts on Manufacturers
The Department performed an MIA to estimate the impact of higher
efficiency standards on distribution transformer manufacturers. Chapter
12 of the TSD explains the methodology, analysis, and findings of this
analysis in detail.
a. Industry Cash-Flow Analysis Results
Based on a real corporate discount rate of 8.9 percent, the
Department estimated the distribution transformer industry impacts at
each TSL. Table V.15 and Table V.16 show the estimated impacts for the
liquid-immersed and medium-voltage, dry-type industries, respectively.
The primary metric from the MIA is the change in INPV. These tables
also present the investments that the industry would incur at each TSL.
Product conversion expenses include engineering, prototyping, testing,
and marketing expenses incurred by a manufacturer as it prepares to
come into compliance with a standard. Capital investments are the one-
time outlays for equipment and buildings required for the industry to
come into compliance (i.e., conversion capital expenditures).
[[Page 44391]]
Table V.15.--Manufacturer Impact Analysis for Liquid-Immersed Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ---------------------------------------------------------------------------
1 2 3 4 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV.................................. ($ millions)............ 526 532 537 553 561 549 552
Change in INPV........................ ($ millions)............ .......... 5.8 10.7 27.0 34.9 22.3 25.8
(%)..................... .......... 1.1 2.0 5.1 6.6 4.2 4.9
Product Conversion Expenses........... ($ millions)............ .......... 0 0 0 0 109.2 161.2
Capital Investments................... ($ millions)............ .......... 2.5 5.0 7.8 8.0 94.1 326.5
Total Investment Required............. ($ millions)............ .......... 2.5 5.0 7.8 8.0 203.3 487.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Operating-Profit Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV.................................. ($ millions)............ 526 521 513 496 490 323 27
Change in INPV........................ ($ millions)............ .......... -5.7 -12.9 -30.0 -36.9 -203.8 -499.6
(%).................... .......... -1.1 -2.4 -5.7 -7.0 -38.7 -94.9
Product Conversion Expenses........... ($ millions)............ .......... 0 0 0 0 109.2 161.2
Capital Investments................... ($ millions)............ .......... 2.5 5.0 7.8 8.0 94.1 326.5
Total Investment Required............. ($ millions)............ .......... 2.5 5.0 7.8 8.0 203.3 487.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table V.16.--Manufacturer Impact Analysis for Medium-Voltage, Dry-Type Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base case ----------------------------------------------------------------
1 2 3 4 5/6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV....................................... ($ millions)................. 32 30 29 27 28 30
Change in INPV............................. ($ millions)................. ........... -1.8 -3.3 -5.1 -3.8 -2.0
(%).......................... ........... -5.5 -10.1 -15.7 -11.8 -6.1
Product Conversion Expenses................ ($ millions)................. ........... 0 0 3.3 3.6 5.0
Capital Investments........................ ($ millions)................. ........... 3.2 5.6 7.3 7.5 15.0
Total Investment Required.................. ($ millions)................. ........... 3.2 5.6 10.6 11.1 20.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV....................................... ($ millions)................. 32 30 28 25 24 15
Change in INPV............................. ($ millions)................. ........... -2.5 -4.3 -6.9 -7.8 -17.0
(%).......................... ........... -7.7 -13.4 -21.5 -24.3 - 52.8
Product Conversion Expenses................ ($ millions)................. ........... 0 0 3.3 3.6 5.0
Capital Investments........................ ($ millions)................. ........... 3.2 5.6 7.3 7.5 15.0
Total Investment Required.................. ($ millions)................. ........... 3.2 5.6 10.6 11.1 20.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
b. Impacts on Employment
The Department expects no significant, discernable direct
employment impacts among liquid-immersed transformer manufacturers
under TSL1 through TSL4, but potentially large increases in employment
for TSL5 and TSL6 (35 percent and 99 percent, respectively). These
conclusions--which are separate from any conclusions regarding
employment impacts on the broader U.S. economy--are based on modeling
results that address neither the possible relocation of domestic
transformer manufacturing employment to lower labor-cost countries, nor
the possibility of outsourcing amorphous core production under TSL5 and
TSL6 to companies in other countries. The Department discussed this
scenario of outsourcing amorphous core production to other countries
during several liquid-immersed manufacturer interviews, and it appears
that outsourcing would be a serious consideration for the liquid-
immersed industry under TSL5 or TSL6.
Liquid-immersed manufacturers expressed concern during the MIA
interviews that establishing an energy conservation standard would
``commoditize'' the liquid-immersed transformer market, making it
easier for foreign manufacturers who specialize in low-cost mass
production of one design to enter the U.S. market. If foreign producers
were to capture significant market share, U.S. transformer-
manufacturing employment would be negatively affected. As a point
related to ``commoditization,'' but separate from employment impacts,
manufacturers also warned the Department about a potential backsliding
effect, whereby the average efficiency of liquid-immersed transformers
could potentially decrease under standards, since transformer customers
may stop evaluating and instead simply purchase minimally compliant
designs. Manufacturers reported having observed such a backsliding
phenomenon in customer orders from Massachusetts, where TP1 is a
mandatory standard.
The Department expects no significant, discernable employment
impacts among medium-voltage, dry-type transformer manufacturers for
any TSL compared to the base case. The Department's conclusion
regarding employment impacts in the medium-voltage, dry-type
transformer industry is separate from any conclusions regarding
[[Page 44392]]
employment impacts on the broader U.S. economy. Increased employment
levels are not expected at higher TSLs because the core-cutting
equipment typically purchased by the medium-voltage, dry-type industry
is highly automated and includes core-stacking equipment.
Another concern conveyed by some medium-voltage, dry-type
manufacturers during the interviews is the potential impact stemming
from the cast-coil transformer competitiveness at higher TSLs. These
manufacturers claim that setting a standard above a certain threshold
may trigger a market switch from open-wound ventilated transformers to
cast-coil transformers. Manufacturers suggest that this crossover point
likely occurs at TSL3 and higher. If the market does shift to cast-coil
transformers, there is a risk of imported pre-fabricated cast coils
dominating the market in the long term. This would have a significant
impact on domestic industry value and domestic employment in the
medium-voltage, dry-type industry.
c. Impacts on Manufacturing Capacity
For the liquid-immersed distribution transformer industry, the
Department believes that there are only minor production capacity
implications for a standard at TSL4 and below. At TSL6, all liquid-
immersed design lines would have to convert to amorphous technology,
the most efficient core material. At TSL5, three design lines would
have to convert to amorphous core designs. Conversion to amorphous core
designs would render obsolete a large portion of the equipment used in
the liquid-immersed industry today (e.g., annealing furnaces, core-
cutting and winding equipment). Based on the manufacturer interviews,
DOE believes that TSL5 and TSL6 would cause liquid-immersed transformer
manufacturers to decide whether they would tool for amorphous
technology, attempt to purchase pre-fabricated amorphous cores, or exit
the industry. Manufacturers also indicated that, if they were to choose
to produce amorphous cores themselves, they would face a critical
decision about whether or not to relocate outside of the U.S., since
much of their equipment would become obsolete. As mentioned above, if
manufacturers choose to purchase pre-fabricated amorphous cores, they
might purchase them from foreign manufacturers.
Energy conservation standards will affect the medium-voltage, dry-
type industry's manufacturing capacity because the core stack heights
(or core steel piece length) will increase and laminations will become
thinner. Thinner laminations require more cuts and are more cumbersome
to handle. Therefore, manufacturers would have to invest in additional
core-mitering machinery or modifications and improvements to recover
any losses in productivity, and these factors might also contribute to
a need for more plant floor space. Because more-efficient transformers
tend to be larger, this could also contribute to the need for
additional manufacturing floor space.
d. Impacts on Manufacturers That Are Small Businesses
Converting from a company's current basic product line involves
designing, prototyping, testing, and manufacturing a new product. These
tasks have associated capital investments and product conversion
expenses. Small businesses, because of their limited access to capital
and their need to spread conversion costs over smaller production
volumes, may be affected more negatively than major manufacturers by an
energy conservation standard. For these reasons, the Department
specifically evaluated the impacts on small businesses of an energy
conservation standard.
The Small Business Administration defines a small business, for the
distribution transformer industry, as a business that has 750 or fewer
employees. The Department estimates that, of the approximately 25 U.S.
manufacturers that make liquid-immersed distribution transformers,
about 15 of them are small businesses. About five of the small liquid-
immersed transformer businesses have fewer than 100 employees. The
liquid-immersed distribution transformer industry largely produces
customized transformers. Often, small businesses can compete in this
industry because a typical customer order can involve unique designs
produced in relatively small volumes. Small manufacturers in the
liquid-immersed industry tend not to compete on the higher-volume
products and often produce transformers for highly specific
applications. This strategy allows small manufacturers in the liquid-
immersed transformer industry to be competitive in certain product
markets. Implementation of an energy conservation standard would have a
relatively minor differential impact on small manufacturers (versus
large manufacturers) of liquid-immersed distribution transformers.
Disadvantages to small businesses, such as having little leverage over
suppliers (e.g., core steel suppliers), are present with or without an
energy conservation standard.
For medium-voltage, dry-type manufacturers, the situation is
different. The Department estimates that, of the 25 U.S. manufacturers
that make medium-voltage, dry-type distribution transformers, about 20
of them are small businesses. About one-half of the medium-voltage,
dry-type small businesses have fewer than 100 employees. Medium-
voltage, dry-type transformer manufacturing is more concentrated than
liquid-immersed transformer manufacturing; the top three companies
manufacture over 75 percent of all transformers in this category. The
entire medium-voltage, dry-type transformer industry has such low
shipments that no designs are produced at high volume. There is little
repeatability of designs, so small businesses can competitively produce
many medium-voltage, dry-type, open-wound designs. The medium-voltage,
dry-type industry as a whole primarily has experience producing
baseline transformers and transformers that would comply with TSL1. In
addition, the industry produces a significant number of units that
would comply with TSL2, but approximately one percent or less of the
market would comply with TSL3 or higher (today). Therefore, all
manufacturers, including small businesses, would have to develop
designs to enable compliance with TSL3 or higher. For these small
manufacturers, the R&D costs would be more burdensome, as product
redesign costs tend to be fixed and do not scale with sales volume.
Thus, small businesses would be at a relative disadvantage at TSL3 and
higher, because their R&D efforts would be on the same scale as those
for larger companies, but these expenses would be recouped over smaller
sales volumes.
At TSL3 and above, DOE estimates that net cash flows for the
medium-voltage, dry-type industry would go negative during the
compliance period. At these TSLs, the impacts on the industry as a
whole are large and affect businesses of all sizes, but there would be
some differential, increased impacts on small businesses. For example,
at TSL3 and above, the use of grain-oriented silicon steel of M3 grade
would be necessary. Cutting M3 core steel on the core-mitering
equipment typically purchased by smaller businesses can be problematic
because of the thinness of the material.
At TSL2, all medium-voltage, dry-type designs would have to be
mitered. (Mitering means the transformer core's joints intersect at 45
degree angles, rather than at 90 degree angles as is true for ``butt-
lap'' designs; buttlap designs are less energy efficient.) The mitered
[[Page 44393]]
core construction technique could constrain the core-mitering resources
of small businesses that share core-cutting capacity with production
lines for other transformers that are not covered by this rulemaking
(e.g., low-voltage, dry-type distribution transformers). At TSL1, many
kVA ratings could still be constructed using butt-lap joints,
alleviating the constraint on core-mitering resources. Thus, TSL1 is
less capital-intensive for small businesses than TSL2 (large businesses
would likely miter nearly all medium-voltage cores, even at TSL1). In
the medium-voltage, dry-type transformer industry, which is heavily
consolidated already, there is the risk that TSL2 could lead to further
advantage for the largest manufacturers and thus further concentrate
the industry's production.
3. National Impact Analysis
a. Amount and Significance of Energy Savings
The Department estimated the energy savings from a proposed energy-
efficiency standard in its NES analysis. The amount of energy savings
depends not only on the potential decrease in transformer losses due to
a standard, but also on the rate at which the stock of existing, less
efficient transformers will be replaced over time after the
implementation of a proposed energy-efficiency standard.
Another factor that affects national energy savings estimates is
the efficiency of the power plants and the transmission and
distribution system that supplies electricity to transformers. The
factor that relates energy savings at the transformer to fuel savings
at the power plant is the site-to-source conversion factor. The NES
analysis takes as an input estimates of the energy savings per
transformer resulting from proposed energy-efficiency standards that
are calculated in the LCC model. The NES model then accounts for
transformer stock replacement and site-to-source energy conversion to
estimate annual national energy savings through an extended forecast
period ending in 2038. The replacement of existing transformer stocks
by new, more efficient transformers is described by the Department's
shipments model, described in TSD Chapter 9. The Department calculated
the site-to-source conversion factor that relates transformer loss
reduction to fuel savings at the power plant using NEMS-BT, a variant
of the EIA's NEMS, which is described in TSD Chapter 13 (Utility Impact
Analysis).
Table V.17 summarizes the Department's NES estimates, which are
described in more detail in TSD Chapter 10. The Department reports both
undiscounted and discounted values of energy savings. The undiscounted
energy savings estimates increase steadily from 1.77 to 9.77 quads for
TSLs 1 through 6, where there are increasing energy savings as the
standard level increases. Discounted energy savings represent a policy
perspective where energy savings farther in the future are less
significant than energy savings closer to the present. The discounted
energy savings estimates are approximately one half and one fourth of
the undiscounted values for the three- and seven-percent discount
rates, respectively.
b. Energy Savings and Net Present Value
While the NES provides estimates of the energy savings from a
proposed energy-efficiency standard, the NPV provides estimates of the
national economic impacts of a proposed standard. The NPV calculation
for this rulemaking used first-cost data from the LCC analysis to
estimate the equipment and installation costs associated with purchase
and installation of higher efficiency transformers. The LCC analysis
also provided the marginal electricity cost data that the Department
used to estimate the economic value of energy savings associated with
lower transformer losses.
One key factor in the NPV calculation that was not obtained from
the LCC analysis is the discount rate. The Department discounted
transformer purchase costs, installation expenses, and operating costs
using a national average discount rate for policy evaluation that the
Department determined consistent with Office of Management and Budget
(OMB) guidance.
In accordance with the OMB guidelines on regulatory analysis (OMB
Circular A-4, section E, September 17, 2003), DOE calculated NPV using
both a seven-percent and a three-percent real discount rate. The seven-
percent rate is an estimate of the average before-tax rate of return to
private capital in the U.S. economy, and reflects returns to real
estate and small business capital as well as corporate capital. The
Department used this discount rate to approximate the opportunity cost
of capital in the private sector, since recent OMB analysis has found
the average rate of return to capital to be near this rate. In
addition, DOE used the three-percent rate to capture the potential
effects of standards on private consumption (e.g., through higher
prices for equipment and purchase of reduced amounts of energy). This
rate represents the rate at which ``society'' discounts future
consumption flows to their present value. This rate can be approximated
by the real rate of return on long-term government debt (e.g., yield on
Treasury notes minus annual rate of change in the Consumer Price
Index), which has averaged about three percent on a pre-tax basis for
the last 30 years. Table V.17 provides an overview of the NES and NPV
results. See TSD Chapter 10 for more detailed NES and NPV results.
Table V.17.--TSL Results Summary: National Energy Savings (Quads, 2010-2038) and Net Present Value
[Billion 2004$, at 3% and 7% discount rates, 2010-2073]
----------------------------------------------------------------------------------------------------------------
TSL1 (TP
1) TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Sum of all Product Classes
----------------------------------------------------------------------------------------------------------------
Energy Savings (quads).................. 1.77 2.39 3.15 3.63 6.90 9.77
Discounted Energy Savings (quads):
3%.................................. 0.90 1.21 1.58 1.82 3.47 4.91
7%.................................. 0.40 0.54 0.71 0.82 1.54 2.19
NPV (billion 2004$):
3%.................................. 7.43 9.43 10.11 11.07 10.88 -9.41
7%.................................. 2.15 2.52 2.28 2.26 -1.13 -14.09
----------------------------------------------------------------------------------------------------------------
[[Page 44394]]
c. Impacts on Employment
The Process Rule includes employment impacts among the factors DOE
considers in selecting a proposed standard. Employment impacts include
direct and indirect impacts. Direct employment impacts are any changes
in the number of employees for distribution transformer manufacturers.
Indirect impacts are those changes of employment in the larger economy
that occur due to the shift in expenditures and capital investment that
is caused by the purchase and operation of more efficient equipment.
The MIA addresses direct employment impacts; this section describes
indirect impacts.
In developing this proposed rule, the Department estimated indirect
national employment impacts using an input/output model of the U.S.
economy, called IMBUILD (impact of building energy efficiency
programs). Indirect employment impacts from distribution transformer
standards consist of the net jobs created or eliminated in the national
economy, other than in the manufacturing sector being regulated, as a
consequence of: (1) Reduced spending by end users on energy
(electricity, gas--including liquefied petroleum gas--and oil); (2)
reduced spending on new energy supply by the utility industry; (3)
increased spending on the purchase price of new distribution
transformers; and (4) the effects of those three factors throughout the
economy. The Department expects the net monetary savings from standards
to be redirected to other forms of economic activity. The Department
also expects these shifts in spending and economic activity to affect
the demand for labor.
As shown in table V.18, the Department estimates that net indirect
employment impacts from a proposed transformer energy-efficiency
standard are positive. According to the Department's analysis, the
number of jobs that may be generated through indirect impacts ranged
from 5,000 to 20,000 by 2038 for the proposed standard levels of TSL1
through TSL6 respectively. For shorter forecast periods, indirect
employment impacts are correspondingly smaller. While the Department's
analysis suggests that the proposed distribution transformer standards
could increase the net demand for labor in the economy, the gains would
most likely be very small relative to total national employment. The
Department therefore concludes only that the proposed distribution
transformer standards are likely to produce employment benefits that
are sufficient to offset fully any adverse impacts on employment that
might occur in the distribution transformer or energy industries. For
details on the employment impact analysis methods and results, see TSD
Chapter 14.
Table V.18.--Net National Change in Indirect Employment, Thousands of Jobs in 2038
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------
TSL1 TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed......................... 4.7 6.4 7.7 8.7 18.2 19.4
Dry-Type, Medium-Voltage................ 0.3 0.5 0.7 1.0 1.4 1.4
----------------------------------------------------------------------------------------------------------------
4. Impact on Utility or Performance of Equipment
In establishing classes of products, and in evaluating design
options and the impact of potential standard levels, the Department has
tried to avoid having new standards for distribution transformers
lessen the utility or performance of these products (see TSD Chapter 7,
section 7.3.1). The proposed standard level (TSL2) does not lessen the
performance of any of the distribution transformers being regulated.
The standard level could, however, potentially affect utility
through the larger size and weight of an energy-efficient distribution
transformer. The Department accounted for dimensionally or physically
constrained transformers in its LCC model by including the cost of
dealing with physical constraints in the installation cost estimate.
For all types of transformers, the Department included extra labor and
equipment costs that may be incurred in the installation of larger,
heavier, more efficient transformers. Design line 2 includes pole-
mounted transformers and presents a special case because of the extra
cost of installing or replacing electrical distribution poles on which
such transformers may be mounted by utilities. For single-phase, pole-
mounted, liquid-immersed transformers, the LCC spreadsheet model
includes an estimate of the additional installation costs for those
designs that would require an upgrade to the pole (see TSD Chapter 7,
section 7.3.1). Having accounted for this constraint on utility in its
economic model, the Department concludes that TSL2 does not reduce the
utility or performance of distribution transformers.
5. Impact of Any Lessening of Competition
The Department considers any lessening of competition that is
likely to result from standards. The Attorney General determines the
impact, if any, of any lessening of competition likely to result from a
proposed standard, and transmits such determination to the Secretary,
not later than 60 days after the publication of a proposed rule,
together with an analysis of the nature and extent of such impact. (See
42 U.S.C. 6295(o)(2)(B)(i)(V) and (B)(ii)).
To assist the Attorney General in making such a determination, the
Department has provided the Department of Justice (DOJ) with copies of
this notice and the TSD for review. At DOE's request, the DOJ reviewed
the MIA interview questionnaire to ensure that it would provide insight
concerning any lessening of competition due to any proposed TSLs.
6. Need of the Nation To Conserve Energy
Enhanced energy efficiency, where economically justified, improves
the Nation's energy security, strengthens the economy, and reduces the
environmental impacts or costs of energy production. The energy savings
from distribution transformer standards result in reduced emissions of
CO2, and reduced power sector demand for NOX, and
Hg emissions reduction investments. Reduced electricity demand from
energy-efficiency standards is also likely to reduce the cost of
maintaining the reliability of the electricity system, particularly
during peak-load periods. As a measure of this reduced demand, the
Department expects the proposed standard to eliminate the need for the
construction of approximately 11 new 400-megawatt power plants by 2038
and to save 2.39 quads of electricity (cumulative, 2010-2038).
Table V.19 provides the Department's estimate of cumulative
CO2, NOX, and Hg emissions reductions for an
uncapped emissions scenario for the six
[[Page 44395]]
TSLs considered in this rulemaking. In actuality, present and/or future
regulations will place caps on the emissions of NOX, and Hg
for the power sector, and thus the emissions reductions provided in the
table represent the Department's estimate of the potential reduced
demand for emissions reduction investments in future cap and trade
emissions markets. The expected energy savings from distribution
transformer standards will reduce the emissions of greenhouse gases
associated with energy production and household use of fossil fuels,
and it may reduce the cost of maintaining system-wide emissions
standards and constraints.
Table V.19.--Cumulative Emissions Reductions from Trial Standard Levels by Product Type, 2010-2038
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------
TSL1 TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Emissions reductions for liquid-immersed
transformers:
CO2 (Mt)............................ 117.4 158.2 205.4 232.8 451.2 647.6
NOX (kt)............................ 31.7 42.7 55.5 62.8 121.7 174.8
Hg (t).............................. 2.9 3.5 4.1 4.5 5.8 5.9
Emissions reductions for medium-voltage,
dry-type transformers:
CO2 (Mt)............................ 5.6 8.9 12.8 19.5 31.2 31.2
NOX (kt)............................ 2.3 3.7 5.3 8.1 12.9 12.9
Hg (t).............................. 0.10 0.17 0.24 0.36 0.58 0.58
----------------------------------------------------------------------------------------------------------------
The cumulative CO2, NOX, and Hg emissions
reductions range up to 678.8 Mt, 187.7 kt, and 6.48 t, respectively, in
2038 (sum of liquid-immersed and medium-voltage dry-type at TSL6).
Total CO2 and NOX emissions reductions for each
TSL are reported in the environmental assessment, a separate report in
the TSD.
In the ANOPR, the Department stated that, for its NOPR analysis, it
would calculate discounted values for future emissions. 69 FR 45376.
Accordingly, the Department here presents its results for discounted
emissions of CO2 and NOX. When NOX
emissions are subject to emissions caps, the Department's emissions
reduction estimate corresponds to incremental changes in emissions
allowance credits in cap and trade emissions markets rather than the
net physical emissions reductions that will occur. The Department used
the same discount rates that it used in calculating the NPV (seven
percent and three percent real) to calculate discounted cumulative
emission reductions. Table V.20 shows the discounted cumulative
emissions impacts for both liquid-immersed and dry-type, medium-voltage
transformers.
The seven-percent and three-percent real discount rate values are
meant to capture the present value of costs and benefits associated
with projects facing an average degree of risk. Other discount rates
may be more applicable to discount costs and benefits associated with
projects facing different risks and uncertainties. The Department seeks
input from interested parties on the appropriateness of using other
discount rates in addition to seven percent and three percent real to
discount future emissions reductions.
Table V.20.--Discounted Cumulative Emissions Reductions, Liquid-Immersed and Dry-Type, Medium-Voltage
Transformers, 2010-2038
----------------------------------------------------------------------------------------------------------------
Discounted cumulative emissions reduction
-----------------------------------------------------------------------
TSL 1 (TP
1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6
----------------------------------------------------------------------------------------------------------------
Liquid-Immersed, 3% discount, CO2 (Mt).. 58.2 78.4 101.9 115.5 223.5 321.1
Dry-Type, 3% discount, CO2 (Mt)......... 2.8 4.4 6.4 9.7 15.5 15.5
Liquid-Immersed, 7% discount, CO2 (Mt).. 25.3 34.0 44.3 50.1 96.9 139.4
Dry-Type, 7% discount, CO2 (Mt)......... 1.2 1.9 2.8 4.2 6.7 6.7
Liquid-Immersed, 3% discount, NOX (kt).. 16.3 21.9 28.6 32.4 62.6 90.0
Dry-Type, 3% discount, NOX (kt)......... 1.2 1.8 2.7 4.0 6.5 6.5
Liquid-Immersed, 7% discount, NOX (kt).. 7.5 10.1 13.2 15.0 28.9 41.6
Dry-Type, 7% discount, NOX (kt)......... 0.5 0.8 1.2 1.8 2.9 2.9
----------------------------------------------------------------------------------------------------------------
7. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, considers any other factors that the Secretary
deems to be relevant. (See 42 U.S.C. 6295(o)(2)(B)(i)(VII)) For today's
proposed standard, the Secretary took into consideration transformer-
manufacturing-material price volatility--a factor that received several
comments at the ANOPR public meeting, during the comment period
following the meeting, and in the MIA interviews. Stakeholders
expressed concern about the increasing cost of raw materials for
building transformers, the volatility of material prices, and the
cumulative effect of material price increases on the transformer
industry (see section IV.B.2, Engineering Analysis Inputs). The
Department conducted supplemental engineering and LCC analyses using
first-quarter 2005 material prices, and considered the impacts on LCC
savings and payback periods when evaluating the appropriate standard
levels for liquid-immersed and medium-voltage, dry-type distribution
transformers. The results of the engineering and LCC analyses for the
first-quarter 2005 material price analysis are in the TSD Appendix 5C.
[[Page 44396]]
B. Stakeholder Comments on the Selection of a Final Standard
During the public comment period on the ANOPR, the Department
received numerous comments from stakeholders relating to the selection
of the appropriate standard level for distribution transformers.
Stakeholders expressed a range of opinions on what efficiency levels
the Department should select for a standard, some relating specifically
to liquid-immersed transformers and others to both liquid-immersed and
medium-voltage, dry-type units.
Concerning liquid-immersed distribution transformers, Cooper
Industries recommended that NEMA TP 1 be adopted for design lines 1, 2,
and 4. For design lines 3 and 5, Cooper recommended CSL2, which is one
level higher than the TP 1 level. (Note that for the ANOPR, the CSLs
were slightly different from the levels considered for the NOPR; for
the ANOPR, CSL2 for design line 3 was 99.40 percent and CSL2 for design
line 5 was 99.40 percent.) For design line 5, Cooper stated that the
majority of users are industrial customers, who would typically require
the value of annual energy savings resulting from efficiency level
increases to pay back the cost of those increases in two to four years,
or provide a 15 to 30 percent annual rate of return on such cost.
(Cooper, No. 62 at pp. 4-6) EMSIC commented that mandatory efficiency
standards can be set at TP 1 + 0.4 percent for all liquid-immersed
products without undue burden on any stakeholders. (EMSIC, No. 73 at p.
2) The Department considered these comments from Cooper Industries and
EMSIC while reviewing the analytical results and selecting a proposed
standard level for liquid-immersed distribution transformers.
Howard stated that it does not believe the Department should
establish mandatory efficiency standards for liquid-immersed
distribution transformers because, through TOC evaluation, the market
already drives these transformers to cost-effective efficiency levels.
Howard participates in the Energy Star program, and believes the
Department should take a voluntary approach to standards. (Howard, No.
70 at p. 2) As discussed earlier in this notice, the Department is
charged with determining whether standards for distribution
transformers are technologically feasible and economically justified
and would result in significant energy savings. (42 U.S.C. 6317(a))
Based on the analysis and information available to date, it appears
that standards for liquid-immersed distribution transformers would be
technologically feasible and economically justified, and would result
in significant energy savings. Thus, the Department will continue to
evaluate minimum efficiency standards for liquid-immersed transformers.
Howard continued by stating that if DOE must mandate efficiency
levels for liquid-immersed transformers, then it recommends the
Department use specific efficiency levels provided in its comment. For
single-phase transformers, the levels proposed by Howard start at 98.8
percent for 10 kVA transformers and rise to 99.4 percent for 75 kVA
transformers, above which the proposed level is constant. For three-
phase transformers, the levels proposed by Howard start at 98.5 percent
for 15 kVA transformers and rise to 99.4 percent for 225 kVA
transformers, above which the proposed level is constant. (Howard, No.
70 at pp. 3 and 5) The Department considered these recommended levels
from Howard while reviewing the analytical results and selecting a
proposed standard level for liquid-immersed distribution transformers.
The Department also received several cross-cutting comments that
pertained to the appropriate standard level for all product classes
being evaluated. HVOLT, NGrid, and Southern provided comments in
support of NEMA TP 1. HVOLT stated that, based on its involvement in
the development of NEMA TP 1, it recommends setting the new DOE
standard at NEMA TP 1 levels, which have a 3-5-year payback period at
the nationwide average cost of energy. It noted that this level would
guarantee wide support for the standard. (HVOLT, No. 65 at p. 3) NGrid
stated that a standard that encourages utilities to install
transformers that meet the efficiency levels outlined in NEMA TP 1-1996
is in the best interests of the company and its customers. (NGrid, No.
80 at p. 2) Similarly, Southern Company commented that the minimum
efficiency standard should be no higher than NEMA TP 1. It added that
the choice of transformers with efficiencies higher than TP 1 should be
left to the customer. (Southern, No. 71 at p. 3) The Department
included TP 1 in its analysis but determined that a higher efficiency
level was economically justified for the liquid-immersed and medium-
voltage, dry-type super classes, and would result in significant energy
savings.
EEI and NRECA commented that the Department should select a
standard level based on the percentage of transformer consumers with
positive LCC savings, and that the standard should result in net
positive LCC savings for at least 90 percent of affected consumers.
(EEI, No. 63 at p. 3; NRECA, No. 74 at p. 2) The Department considered
the percentage of transformer users with positive LCC savings in
identifying the proposed standard level but not did set a specific
threshold for users with positive LCC savings. Discussion of this and
other factors DOE considered in selecting the proposed standard level
appears in section V.C of this notice.
The Department also received comments encouraging consideration of
standard levels higher than TP 1. ASE recommended that efficiency
standard levels be set at the levels with maximum LCC savings. (ASE,
No. 52 at p. 4 and No. 75 at p. 4) LCC savings is one of several
criteria EPCA considers when determining whether a standard is
economically justified, and therefore it is one of the criteria the
Department used to select today's proposed standard level.
CDA stated that the standard level should be set at higher
efficiencies than TP 1 because actual loading exceeds the 35 percent
and 50 percent loading assumptions used in the TP 1 analysis. (CDA, No.
69 at p. 3) CDA urged the Department to set a minimum efficiency level
that represents a challenge to the industry, beyond a minimal standard
that all can achieve. It noted that it does not believe TP 1 is
challenging enough to transformer manufacturers. (CDA, No. 51 at p. 4
and No. 69 at p. 4) The Department selected the highest efficiency
level that its analysis identified as justified under EPCA's criteria.
The selected standard will impact the industry, but the Department did
not specifically use ``industry challenge'' as a decision criterion.
Today's proposed standard is not based on any one factor or
criterion as some commenters suggested. Rather, the Department arrived
at its decision by weighing the costs and benefits of the trial
standard levels using the seven factors described in section II.B of
this notice. The proposed standard is set at the highest level that is
technologically feasible and economically justified (and would result
in significant energy savings).
C. Proposed Standard
The Department evaluated whether its TSLs for distribution
transformers achieve the maximum improvement in energy efficiency that
is technologically feasible and economically justified (and would
result in significant energy savings). In determining whether a
standard is economically justified, DOE
[[Page 44397]]
determines whether the benefits of the standard exceed its costs. Any
new or amended standard for distribution transformers must result in
significant energy savings.
In selecting a proposed energy conservation standard for
distribution transformers, the Department followed its normal approach.
It started by comparing the maximum technologically feasible level with
the base case, and determined whether that level was economically
justified. Upon finding the maximum technologically feasible level not
to be justified, the Department analyzed the next lower TSL to
determine whether that level was economically justified. The Department
repeated this procedure until it identified a TSL that was economically
justified. The Department made its determination of economic
justification on the basis of the NOPR analysis results published today
and the comments that were submitted by stakeholders. Beginning with
the most efficient level, this section discusses each TSL for liquid-
immersed transformers and then each TSL for medium-voltage, dry-type
transformers.
The following two tables summarize DOE's analytical results. They
will aid the reader in the discussion of costs and benefits of each
TSL. Each table presents the results or, in some cases, a range of
results, for the underlying design lines for liquid-immersed (Table
V.21) and medium-voltage, dry-type (Table V.22) distribution
transformers. The range of values reported in these tables for LCC,
payback, and average increase in consumer equipment cost before
installation encompass the range of results calculated for either the
liquid-immersed or medium-voltage, dry-type representative units. The
range of values for the manufacturer impact represents the results for
the preservation-of-operating-profit scenario and preservation-of-
gross-margin scenario at each TSL for liquid-immersed and medium-
voltage, dry-type transformers.
Table V.21.--Summary of Liquid-Immersed Distribution Transformers Analytical Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Criteria -----------------------------------------------------------------------------------------------
TSL1 TSL2 TSL3 TSL4 TSL5 TSL6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Energy saved (quads).................................... 1.70 2.28 2.99 3.38 6.51 9.38
Generation Capacity Offset (GW)......................... 3.1 4.3 5.5 6.2 12.1 17.3
Discounted energy saved, 7% (quads)..................... 0.38 0.51 0.67 0.76 1.45 2.10
NPV ($ billions):
@ 7% discount....................................... 2.02 2.31 2.01 1.92 (1.14) (14.10)
@ 3% discount....................................... 7.02 8.78 9.20 9.83 9.94 (10.31)
Emission reductions:
CO2 (Mt)............................................ 117.4 158.2 205.4 232.8 451.2 647.6
NOX (kt)............................................ 31.7 42.7 55.5 62.8 121.7 174.8
Life-Cycle Cost:
Net Savings (%)..................................... 26.1-32.0 32.5-42.4 32.5-49.8 35.1-67.7 30.7-42.9 1.1-42.7
Net Increase (%).................................... 0.2-4.9 1.4-16.8 5.2-52.8 8.6-39.9 43.9-66.3 57.2-98.9
No Change (%)....................................... 63.7-73.7 40.8-65.2 11.3-60.8 4.0-56.3 0.0-25.4 0.0-0.1
Payback (years)..................................... 1.4-11.4 4.3-18.1 8.8-21.5 12.0-21.9 25.6-36.0 25.6-67
Average increase in consumer equipment cost before 1.4-4.2 2.7-12.8 3.0-38.3 4.2-40.6 15.5-141.9 106.9-160
installation (%) * [dagger]........................
Manufacturer Impact:
INPV ($ millions)................................... (5.7)-5.8 (12.9)-10.7 (30.0)-27.0 (36.9)-34.9 (203.8)-22.3 (499.6)-25.8
INPV change (%)..................................... (1.1)-1.1 (2.4)-2.0 (5.7)-5.1 (7.0)-6.6 (38.7)-4.2 (94.9)-4.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger] The Department recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience
larger changes, particularly if these customers are not evaluating losses when purchasing transformers.
Table V.22.--Summary of Medium-Voltage, Dry-Type Distribution Transformers Analytical Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Criteria -----------------------------------------------------------------------------------------------
TSL1 TSL2 TSL3 TSL4 TSL5 TSL6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Energy saved (quads).................................... 0.07 0.11 0.16 0.25 0.39 0.39
Generation Capacity Offset (GW)......................... 0.1 0.2 0.3 0.4 0.6 0.6
Discounted energy saved, 7% (quads)..................... 0.02 0.03 0.04 0.06 0.09 0.09
NPV ($ billions):
@ 7% discount....................................... 0.13 0.21 0.28 0.34 0.03 0.03
@ 3% discount....................................... 0.44 0.68 0.95 1.29 1.05 1.05
Emission reductions:
CO2 (Mt)............................................ 5.6 8.9 12.8 19.5 31.2 31.2
NOX (kt)............................................ 2.3 3.7 5.3 8.1 12.9 12.9
Life-Cycle Cost:
Net Savings (%)..................................... 20.2-55.1 25.6-61.5 36.7-71.5 52.0-75.7 24.3-66.8 24.3-66.8
Net Increase (%)................................... 0.6-4.4 1.1-5.1 4.4-9.8 18.2-42.6 34.2-75.7 33.2-75.7
No Change (%)....................................... 42.5-76.0 34.6-72.9 18.7-58.9 0.5-28.2 0.0 0.0
Payback (years)..................................... 1.5-9.7 2.4-8.3 5.4-10.0 11.8-19.5 15.1-32.5 14.8-32.4
Increase in consumer equipment cost before 0.7-4.4 2.2-7.2 5.4-13.6 13.5-30.4 36.4-78.5 36.4-78.4
installation (%) * [dagger]........................
Manufacturer Impact:
[[Page 44398]]
1INPV ($ millions).................................. (2.5)-(1.8) (4.3)-(3.3) (6.9)-(5.1) (7.8)-(3.8) (17.0)-(2.0) (17.0)-(2.0)
INPV change (%)..................................... (7.7)-(5.5) (13.4)-(10.1) (21.5)-(15.7) (24.3)-(11.8) (52.8)-(6.1) (52.8)-(6.1)
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger] The Department recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience
larger changes, particularly if these customers are not evaluating losses when purchasing transformers.
1. Results for Liquid-Immersed Distribution Transformers
a. Liquid-Immersed Trial Standard Level 6
First, the Department considered the most efficient level (max
tech), which would save an estimated total of 9.4 quads of energy
through 2038, a significant amount of energy. Discounted at 7 percent,
the energy savings through 2038 would reduce to approximately 2.1
quads. For the Nation as a whole, TSL6 would have a net cost of $14
billion at a seven-percent discount rate. At this level, the majority
of customers would experience an increase in life-cycle costs. As shown
in Table V.21, only about 1 to 43 percent of customers would experience
lower life-cycle costs, depending on the design line. The payback
periods at this standard level are between 26 and 67 years, some of
which exceed the anticipated operating life of the transformer. The
impacts on manufacturers would be very significant because TSL6 would
require a complete conversion to amorphous core technology. These costs
would reduce the INPV by as much as 95 percent under the preservation-
of-operating-profit scenario. The Department estimates that $59 million
of existing assets would be stranded (i.e., rendered useless) and $327
million of conversion capital expenditures would be required to enable
the industry to manufacture compliant distribution transformers. The
energy savings at TSL6 would reduce the installed generating capacity
by 17.3 gigawatts (GW), or roughly 40 large, 400 MW powerplants.\5\ The
estimated emissions reductions through this same time period are 647.6
Mt of CO2 and 174.8 kt of NOX. The Department
concludes that at this TSL, the benefits of energy savings, generating
capacity reductions, and emission reductions would be outweighed by the
potential multi-billion dollar negative net economic cost to the
Nation, the economic burden on customers as indicated by large payback
periods, and the stranded asset and conversion capital costs that could
result in the large reduction in INPV for manufacturers. Consequently,
the Department concludes that TSL6, the max tech level, is not
economically justified.
---------------------------------------------------------------------------
\5\ DOE estimates 18 coal-fired power plants and 22 gas-fired
power plants can be avoided. See TSD Chapter 13.
---------------------------------------------------------------------------
b. Liquid-Immersed Trial Standard Level 5
Next, the Department considered TSL5, which would save an estimated
total of 6.5 quads of energy through 2038, a significant amount of
energy. Discounted at 7 percent, the energy savings through 2038 would
reduce to approximately 1.45 quads. For the Nation as a whole, TSL5
would have a net cost of $1.1 billion at a seven-percent discount rate.
At this level, about 31 to 43 percent of customers would experience
lower life-cycle costs, depending on the design line. At this level, 44
to 66 percent of customers would have increased life-cycle costs. The
payback periods at this standard level are between 26 and 36 years,
some of which exceed the anticipated operating life of the transformer.
The impacts on manufacturers would be very significant because TSL5
would require partial conversion to amorphous core technology. The
resulting costs would contribute to as much as a 39 percent reduction
in the INPV under the preservation-of-operating-profit scenario. The
Department estimates that $16 million of existing assets would be
stranded and approximately $94 million in conversion capital
expenditures would be required to enable the industry to manufacture
compliant transformers. The energy savings at TSL5 would reduce the
installed generating capacity by 12.1 GW, or roughly 30 large, 400 MW
powerplants. The estimated emissions reductions through this same time
period are 451.2 Mt of CO2 and 121.7 kt of NOX.
The Department concludes that at this TSL, the benefits of energy
savings, generating capacity reductions, and emission reductions would
be outweighed by the potential negative net economic cost to the
Nation, the economic burden on customers as indicated by large payback
periods, and the stranded asset and conversion capital costs that could
result in the large reduction in INPV for manufacturers. Consequently,
the Department concludes that TSL5 is not economically justified.
c. Liquid-Immersed Trial Standard Level 4
Next, the Department considered TSL4, which would save an estimated
total of 3.4 quads of energy through 2038, a significant amount of
energy. Discounted at 7 percent, the energy savings through 2038 would
reduce to approximately 0.76 quads. For the Nation as a whole, TSL4
would result in a net savings of $1.9 billion at a seven-percent
discount rate. For customers, lower life-cycle costs would be
experienced by between 35 and 68 percent, depending on the design line,
meaning that for some design lines, more than half of the customers
would be better off, while for others less than half would benefit. The
payback periods for three of the five liquid-immersed design line
representative units would be more than half the anticipated operating
life of the transformer. For one design line, the payback period is as
long as 22 years. The consumer equipment cost before installation would
increase by 41 percent for one design line, a significant increase for
transformer customers. The energy savings at TSL4 would reduce the
installed generating capacity by 6.2 GW, or roughly 16 large, 400 MW
powerplants. The estimated emissions reductions through this same time
period are 232.8 Mt of CO2 and 62.8 kt of NOX.
The Department concludes that at this TSL, the benefits of energy
savings, generating capacity reductions, emission reductions and
national NPV would be outweighed by the economic burden on some
customers as indicated by long payback periods and significantly
greater first costs. Consequently, the Department
[[Page 44399]]
concludes that TSL4 is not economically justified.
d. Liquid-Immersed Trial Standard Level 3
Next, the Department considered TSL3, which would save an estimated
total of 3 quads of energy through 2038, a significant amount of
energy. Discounted at 7 percent, the energy savings through 2038 would
reduce to approximately 0.67 quads. For the Nation as a whole, TSL3
would have a net savings of $2 billion at a seven-percent discount
rate. At this level, lower life-cycle costs would be experienced by
between 32 and 50 percent of customers, depending on the design line,
meaning that for all the design lines, one-half or less of customers
are better off. One of the payback periods is 22 years, exceeding half
the anticipated operating life of a transformer. Additionally, the
consumer equipment cost before installation increases by 38 percent for
one design line, a significant increase for customers. The energy
savings at TSL3 would reduce the installed generating capacity by 5.5
GW, or roughly 14 large, 400 MW powerplants. The estimated emission
reductions through this same time period are 205.4 Mt of CO2
and 55.5 kt of NOX. The Department concludes that at this
TSL, the benefits of energy savings, generating capacity reductions,
emission reductions and national NPV would be outweighed by the
economic burden on some customers as indicated by long payback periods
and significantly greater first costs. Consequently, the Department
concludes that TSL3 is not economically justified.
e. Liquid-Immersed Trial Standard Level 2
Next, the Department considered TSL2, which would save an estimated
total of 2.3 quads of energy through 2038, a significant amount of
energy. Discounted at 7 percent, the energy savings through 2038 would
reduce to approximately 0.51 quads. For the Nation as a whole, TSL2
would have the highest NPV of all the TSLs for liquid-immersed
distribution transformers, an estimated $2.3 billion at the seven-
percent discount rate. At this level, as shown in Table V.21, between
32 and 42 percent of customers would experience lower life-cycle costs,
depending on the design line. The payback periods under TSL2 are
between 4 and 18 years, which at most is approximately half the
anticipated operating life of the transformer. The energy savings at
TSL2 would reduce the installed generating capacity by 4.3 GW, or
roughly 11 large, 400 MW powerplants. The estimated emissions
reductions through this same time period are 158.2 Mt of CO2
and 42.7 kt of NOX. At TSL2, the relatively low costs are
outweighed by the benefits, including significant energy savings,
generating capacity reductions, emission reductions, maximum national
NPV, and benefits to a majority of those customers affected by the
standard. After considering the costs and benefits of TSL2, the
Department finds that this trial standard level will offer the maximum
improvement in efficiency that is technologically feasible and
economically justified, and will result in significant conservation of
energy. Therefore, the Department today proposes to adopt the energy
conservation standards for liquid-immersed distribution transformers at
TSL2.
2. Results for Medium-Voltage, Dry-Type Distribution Transformers
a. Medium-Voltage, Dry-Type Trial Standard Level 6
First, the Department considered the most efficient level (max
tech), which would save an estimated total of 0.4 quads of energy
through 2038. Discounted at 7 percent, the energy savings through 2038
would reduce to approximately 0.09 quads. For the Nation as a whole,
TSL6 would result in a $30 million benefit at a seven-percent discount
rate. However, at this level, the percentage of customers experiencing
lower life-cycle costs would be less than 35 percent for the majority
of the units analyzed, with one representative unit as low as 24
percent. This means that more than three-quarters of transformer
customers making purchases in that design line would experience
increases in life-cycle cost. Customer payback periods at this standard
level for the majority of units analyzed are 28 years or greater, with
one representative unit as high as 32 years, which is approximately the
operating life of a transformer. The impacts on manufacturers would be
significant, with TSL 6 contributing to a 53-percent reduction in the
INPV under the preservation-of-operating-profit scenario. The
Department projects that manufacturers will experience negative net
annual cash flows during the compliance period, irrespective of the
markup scenario. The magnitude of the peak, negative, net annual cash
flow would be more than twice that of the positive-base-case cash flow.
The energy savings at TSL6 would reduce installed generating capacity
by 0.6 GW, or roughly 1.5 large, 400 MW powerplants. The Department
estimates the associated emissions reductions through 2038 of 31.2 Mt
of CO2 and 12.9 kt of NOX. The Department
concludes that at this TSL, the benefits of energy savings, generating
capacity reductions, emission reductions and national NPV would be
outweighed by the economic burdens on customers as indicated by long
payback periods and significantly greater first costs, and
manufacturers who may experience a drop in INPV of up to 53 percent.
Consequently, the Department concludes that TSL6, the max tech level,
is not economically justified.
b. Medium-Voltage, Dry-Type Trial Standard Level 5
Next, the Department considered TSL5, which is identical to TSL6
(i.e., for all the representative units, TSL5 and TSL6 have all the
same percentage efficiency values). Thus, for the same reasons
described above in section V.C.2.a, the Department concludes that TSL5
is not economically justified.
c. Medium-Voltage, Dry-Type Trial Standard Level 4
Next, the Department considered TSL4, which would save a total of
0.3 quads of energy through 2038. Discounted at 7 percent, the energy
savings through 2038 would reduce to approximately 0.06 quads. For the
Nation as a whole, TSL4 would have a net savings of $0.34 billion at a
seven-percent discount rate, the maximum NPV for medium-voltage, dry-
type distribution transformers. Because for TSL5 and TSL6 the energy
savings comes at a high incremental equipment cost, the national net
savings for TSL4 is substantially higher than TSL5/6. The percentage of
customers experiencing lower life-cycle costs would range between 52
and 76 percent, depending on the design line. However, payback periods
at this standard level are as high as 20 years for one design line,
which is more than half the operating life of a transformer. In
addition, the consumer equipment cost before installation would
increase by as much as 30 percent for one design line, a significant
increase for customers. Furthermore, the impacts of TSL4 on
manufacturers would be significant, contributing to as much as a 24-
percent reduction in the INPV under the preservation-of-operating-
profit scenario. Additionally, DOE projects that manufacturers will
experience negative net annual cash flows during the compliance period,
irrespective of the markup scenario. The magnitude of the peak,
negative, net annual cash flow is approximately half of that of the
positive-base-case cash flow. The energy savings at TSL4 would
[[Page 44400]]
reduce the installed generating capacity by 0.4 GW, or roughly one
large, 400 MW powerplant. The Department estimates associated emissions
reductions through 2038 of 19.5 Mt of CO2 and 8.1 kt of
NOX. Thus, the Department concludes that at this TSL, the
benefits of energy savings, generating capacity reductions, positive
national NPV, and emission reductions would be outweighed by the long
payback periods and significantly greater first costs for some
transformer customers and the economic impacts on manufacturers.
Consequently, the Department concludes that TSL4 is not economically
justified.
d. Medium-Voltage, Dry-Type Trial Standard Level 3
Next, the Department considered TSL3, which would save an estimated
0.2 quads of energy through 2038. Discounted at 7 percent, the energy
savings through 2038 would reduce to approximately 0.04 quads. For the
Nation as a whole, TSL3 would have a net savings of $0.3 billion at a
seven-percent discount rate. The percentage of transformer customers
who would experience lower life-cycle costs ranges between 37 and 71
percent, depending on the design line, with payback periods of 10 years
or less. The impacts on manufacturers at TSL3 would be significant,
however, contributing to as much as a 22-percent reduction in the INPV
under the preservation-of-operating-profit scenario. In addition, DOE
projects the net annual cash flows to be negative during the compliance
period, irrespective of the markup scenario. The magnitude of the peak
negative net annual cash flow would be approximately half of the
positive-base-case cash flow. The energy savings at TSL3 would reduce
the installed generating capacity by 0.3 GW, or roughly 0.8 of a large,
400 MW powerplant. The Department estimates the associated emissions
reductions through 2038 of 12.8 Mt of CO2 and 5.3 kt of
NOX. Thus, the Department concludes that at this TSL, the
benefits of energy savings, generating capacity reductions, positive
national NPV, LCC savings, and emission reductions would be outweighed
by the economic impacts on manufacturers. Consequently, the Department
concludes that TSL3 is not economically justified.
e. Medium-Voltage, Dry-Type Trial Standard Level 2
Next, the Department considered TSL2, which would save an estimated
total of 0.1 quad of energy through 2038. Discounted at 7 percent, the
energy savings through 2038 would reduce to approximately 0.03 quads.
For the Nation as a whole, TSL2 would have a net savings of $0.2
billion at a seven-percent discount rate. The percentage of transformer
customers experiencing lower life-cycle costs ranges between 26 and 61
percent, depending on the design line, with payback periods of eight
years or less. The Department considers impacts on manufacturers at
this standard level (at most a 13-percent reduction in the INPV under
the preservation-of-operating-profit scenario) to be reasonable. The
energy savings at TSL2 would reduce the installed generating capacity
by 0.2 GW, or roughly half of a large, 400 MW powerplant. The
Department estimates associated emissions reductions through 2037 of
8.9 Mt of CO2 and 3.7 kt of NOX. Thus, the
Department concludes that this TSL has positive energy savings,
generating capacity reductions, emission reductions, national NPV,
benefits to transformer customers, and reasonable impacts on
transformer manufacturers. After considering the costs and benefits of
TSL2, the Department finds that this trial standard level will offer
the maximum improvement in efficiency that is technologically feasible
and economically justified, and will result in significant conservation
of energy. Therefore, the Department today proposes to adopt the energy
conservation standards for medium-voltage, dry-type distribution
transformers at TSL2.
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Order 12866
The Department has determined today's regulatory action is a
``significant regulatory action'' under section 3(f)(1) of Executive
Order 12866, ``Regulatory Planning and Review.'' 58 FR 51735 (October
4, 1993). Accordingly, today's action required a regulatory impact
analysis (RIA) and, under the Executive Order, was subject to review by
the Office of Information and Regulatory Affairs (OIRA) in the Office
of Management and Budget (OMB). The Department presented to OIRA for
review the draft proposed rule and other documents prepared for this
rulemaking, including the RIA, and has included these documents in the
rulemaking record. They are available for public review in the Resource
Room of DOE's Building Technologies Program, 1000 Independence Avenue,
SW., Washington, DC, (202) 586-9127, between 9 a.m. and 4 p.m., Monday
through Friday, except Federal holidays.
Regarding the Department's preparation of a regulatory alternatives
analysis, ASE said the Department should fully describe non-regulatory
alternatives, including penetration rates, in the NOPR analysis.
(Public Meeting Transcript, No. 56.12 at pp. 252-253) The Department
followed the examples established by prior rulemakings in regulatory
impact reporting. The RIA, formally entitled, ``Regulatory Impact
Analysis for Proposed Energy Conservation Standards for Electrical
Distribution Transformers,'' is contained in the TSD prepared for the
rulemaking. The RIA consists of: (1) A statement of the problem
addressed by this regulation, and the mandate for government action;
(2) a description and analysis of the feasible policy alternatives to
this regulation; (3) a quantitative comparison of the impacts of the
alternatives; and (4) the national economic impacts of the proposed
standard.
The RIA calculates the effects of feasible policy alternatives to
distribution transformer standards, and provides a quantitative
comparison of the impacts of the alternatives. The Department evaluated
each alternative in terms of its ability to achieve significant energy
savings at reasonable costs, and compared it to the effectiveness of
the proposed rule. The Department analyzed these alternatives using a
series of regulatory scenarios as input to the NES/shipments model for
distribution transformers, which it modified to allow inputs for
voluntary measures.
The Department identified the following major policy alternatives
for achieving increased distribution transformer energy efficiency:
No new regulatory action
Consumer rebates
Consumer tax credits
Manufacturer tax credits
Voluntary energy-efficiency targets
Early replacement
Bulk government purchases
The Department evaluated each alternative in terms of its ability
to achieve significant energy savings at reasonable costs (see Table
VI.1), and compared it to the effectiveness of the proposed rule.
[[Page 44401]]
Table VI.1.--Non-Regulatory Alternatives and the Proposed Standard
----------------------------------------------------------------------------------------------------------------
Net present value (billion
Primary energy $2004)
Policy alternatives Type savings -------------------------------
(quads) 7% discount 3% discount
rate rate
----------------------------------------------------------------------------------------------------------------
No New Regulatory Action.............. ........................ 0.0 0.0 0.0
Consumer Rebates...................... Liquid.................. 0.0 0.0 0.0
MV* Dry................. 0.007 0.013 0.042
-------------------------------------------------------------------------
Total................... 0.007 0.013 0.042
-------------------------------------------------------------------------
Consumer Tax Credits.................. Liquid.................. 0.058 0.058 0.218
MV Dry.................. 0.004 0.008 0.025
-------------------------------------------------------------------------
Total................... 0.06 0.07 0.24
-------------------------------------------------------------------------
Manufacturer Tax Credits.............. Liquid.................. 0.029 0.028 0.108
MV Dry.................. 0.002 0.004 0.013
-------------------------------------------------------------------------
Total................... 0.03 0.03 0.12
-------------------------------------------------------------------------
Proposed Standards at TSL2............ Liquid.................. 2.28 2.31 8.78
MV Dry.................. 0.113 0.207 0.683
-------------------------------------------------------------------------
Total................... 2.40 2.52 9.47
----------------------------------------------------------------------------------------------------------------
* MV = medium-voltage.
Table VI.1 shows the NES and NPV of each of the applicable non-
regulatory alternatives. The results are reported for liquid-immersed
and medium-voltage, dry-type transformers as well as in total. The case
in which no regulatory action is taken with regard to distribution
transformers constitutes the base case (or ``No Action'') scenario.
Since this is the base case, energy savings and NPV are zero by
definition. For comparison, the table includes the impacts of the
proposed energy conservation standards. The NPV amounts shown in Table
VI.1 refer to the NPV based on two discount rates (seven percent and
three percent real). DOE did not consider three of the policy
alternatives, voluntary energy-efficiency targets, early replacement,
and bulk government purchases, because, as discussed in the RIA, DOE
believes they would not significantly impact the distribution
transformers covered by this NOPR.
None of the alternatives DOE examined would save as much energy or
have an NPV as high as the proposed standards. Also, several of the
alternatives would require new enabling legislation, such as consumer
or manufacturer tax credits, since authority to carry out those
alternatives does not presently exist. Additional detail on the
regulatory alternatives is found in the RIA report of the TSD.
B. Review Under the Regulatory Flexibility Act/Initial Regulatory
Flexibility Analysis
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
preparation of an initial regulatory flexibility analysis for any rule
that by law must be proposed for public comment, unless the agency
certifies that the rule, if promulgated, will not have a significant
economic impact on a substantial number of small entities. As required
by Executive Order 13272, ``Proper Consideration of Small Entities in
Agency Rulemaking,'' 67 FR 53461 (August 16, 2002), DOE published
procedures and policies on February 19, 2003, to ensure that the
potential impacts of its rules on small entities are properly
considered during the rulemaking process. 68 FR 7990. The Department
has made its procedures and policies available on the Office of General
Counsel's Web site: http://www.gc.doe.gov.
Small businesses, as defined by the Small Business Administration
(SBA) for the distribution transformer manufacturing industry, are
manufacturing enterprises with 750 employees or fewer. The Department
reviewed today's proposed rule under the provisions of the Regulatory
Flexibility Act and the procedures and policies published on February
19, 2003. On the basis of the foregoing, DOE determined that it cannot
certify that the proposed rule (trial standard level 2, or TSL2), if
promulgated, would have no significant economic impact on a
substantialnumber of small entities. The Department made this
determination because of the potential impacts that the proposed
standard levels for medium-voltage, dry-type distribution transformers
would have on the small businesses that manufacture them. However, the
Department notes that it explicitly considered the impacts on small
medium-voltage, dry-type businesses in selecting TSL2, rather than
selecting a higher trial standard level.
The revenue attributable to the medium-voltage, dry-type superclass
represents only about six percent of the total revenues of the industry
affected by this rulemaking (i.e., the sum of revenues from the liquid-
immersed superclass and the medium-voltage, dry-type superclass).
Because of the potential impacts of today's proposed rule on small,
medium-voltage, dry-type manufacturers, DOE has prepared an initial
regulatory flexibility analysis (IRFA) for this rulemaking. The IRFA
divides potential impacts on small businesses into two broad
categories: (1) Impacts associated with transformer design and
manufacturing, and (2) impacts associated with demonstrating compliance
with the standard using DOE's test procedure. The Department's test
procedure rule does not require manufacturers to take any action in the
absence of final energy conservation standards for distribution
transformers, and thus any impact of that rule on small businesses
would be triggered by the promulgation of the standard proposed today.
The Department believes that there will be no significant economic
impact on a substantial number of small liquid-immersed manufacturers
because the
[[Page 44402]]
transformers in the liquid-immersed superclass are largely customized,
and small businesses can compete because many of these transformers are
unique designs produced in relatively small quantities for a given
order. Small manufacturers of liquid-immersed transformers tend not to
compete on the higher-volume products and often produce transformers
for highly specific applications. This strategy allows small
manufacturers of liquid-immersed units to be competitive in certain
liquid-immersed product markets. Implementation of an energy
conservation standard would have a relatively minor differential impact
on small manufacturers of liquid-immersed distribution transformers.
Disadvantages to small businesses, such as having little leverage over
suppliers (e.g., core steel suppliers), are present with or without an
energy conservation standard. Due to the purchasing characteristics of
their customers, small manufacturers of liquid-immersed transformers
currently produce transformers at TSL2, the proposed level. Thus,
conversion costs (e.g., research and development costs, capital
investments) and the associated manufacturer impacts on small
businesses are expected to be insignificant at the proposed level,
TSL2.
The potential impacts on medium-voltage, dry-type manufacturers
(and also the compliance demonstration cost for liquid-immersed
manufacturers) are discussed in the following sections. The Department
has transmitted a copy of this IRFA to the Chief Counsel for Advocacy
of the Small Business Administration for review.
1. Reasons for the Proposed Rule
Part C of Title III of the Energy Policy and Conservation Act
(EPCA) provides for an energy conservation program for certain
commercial and industrial equipment. (42 U.S.C. 6311-6317) In
particular, section 346 of EPCA states that the Secretary of Energy
must prescribe testing requirements and energy conservation standards
for those distribution transformers for which the Secretary determines
that standards would be technologically feasible and economically
justified, and would result in significant energy savings, although
section 325(v) of EPCA in effect modifies this provision by specifying
standards for low voltage, dry-type distribution transformers. (42
U.S.C. 6295(v) and 6317(a))
On October 22, 1997, the Secretary of Energy issued a determination
that ``based on its analysis of the information now available, the
Department has determined that energy conservation standards for
transformers appear to be technologically feasible and economically
justified, and are likely to result in significant savings.'' 62 FR
54809. Recognizing that fact, EPACT 2005 set minimum efficiency levels
for low-voltage dry-type distribution transformers and allowed the
Department to continue its analysis and rulemaking for liquid-immersed
and medium-voltage dry-type distribution transformers.
2. Objectives of, and Legal Basis for, the Proposed Rule
The Department selects any new or amended standard to achieve the
maximum improvement in energy efficiency that is technologically
feasible and economically justified. (See 42 U.S.C. 6295(o)(2)(A),
6313(a), and 42 U.S.C. 6317(a) and (c)) If a proposed standard is not
designed to achieve the maximum improvement in energy efficiency or the
maximum reduction in energy use that is technologically feasible, the
Secretary states the reasons for this in the proposed rule. To
determine whether economic justification exists, the Department reviews
comments received and conducts analysis to determine whether the
economic benefits of the proposed standard exceed the costs to the
greatest extent practicable, taking into consideration the seven
factors set forth in 42 U.S.C. 6295(o)(2)(B)(i) (see Section II.B of
this Notice). Further information concerning the background of this
rulemaking is provided in Chapter 1 of the TSD.
3. Description and Estimated Number of Small Entities Regulated
By researching the distribution transformer market, developing a
database of manufacturers, and conducting interviews with manufacturers
(both large and small), the Department was able to estimate the number
of small entities that would be regulated under an energy conservation
standard. See chapter 12 of the TSD for further discussion about the
methodology used in the Department's manufacturer impact analysis and
its analysis of small-business impacts.
The liquid-immersed superclass accounts for about $1.3 billion in
annual sales and employment of about 4,250 production employees in the
United States. The Department estimates that, of the approximately 25
U.S. manufacturers that make liquid-immersed distribution transformers,
about 15 of them are small businesses. About five of the small
businesses have fewer than 100 employees.
The medium-voltage, dry-type superclass accounts for about $84
million in annual sales and employment of about 250-330 production
employees in the United States. The medium-voltage, dry-type market is
relatively small compared to that of the liquid-immersed superclass.
The Department estimates that, of the 25 U.S. manufacturers that make
medium-voltage, dry-type distribution transformers, about 20 of them
are small businesses. About ten of these small businesses have fewer
than 100 employees.
4. Description and Estimate of Compliance Requirements
Potential impacts on small businesses come from two broad
categories of compliance requirements: (1) Impacts associated with
transformer design and manufacturing, and (2) impacts associated with
demonstrating compliance with the standard using the Department's test
procedure.
In regard to impacts associated with transformer design and
manufacturing, the margins and/or market share of small businesses in
the medium-voltage, dry-type superclass could be hurt in the long term
by today's proposed level, TSL2. At TSL2, as opposed to TSL1, small
manufacturers would have less flexibility in choosing a design path.
However, as discussed under subsection 6 (Significant alternatives to
the rule) below, the Department expects that the differential impact on
small, medium-voltage, dry-type businesses (versus large businesses)
would be smaller in moving from TSL1 to TSL2 than it would be in moving
from TSL2 to TSL3. The rationale for the Department's expectation is
best discussed in a comparative context and is therefore elaborated
upon in subsection 6 (Significant alternatives to the rule). As
discussed in the introduction to this IRFA, DOE expects that the
differential impact associated with transformer design and
manufacturing on small, liquid-immersed businesses would be negligible.
In regard to compliance demonstration, the Department's test
procedure for distribution transformers employs an Alternative
Efficiency Determination Method (AEDM) which would ease the burden on
manufacturers. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972. The
AEDM involves a sampling procedure to compare manufactured products'
efficiencies with those predicted by computer design software. Where
the manufacturer uses an AEDM for a basic model, it would not be
required to test units of the basic model
[[Page 44403]]
to determine its efficiency for purposes of establishing compliance
with DOE requirements. The professional skills necessary to execute the
AEDM include the following: (1) Transformer design software expertise
(or access to such expertise possessed by a third party), and (2)
electrical testing expertise and moderate expertise with experimental
statistics (or access to such expertise possessed by a third party).
The Department's test procedure would require periodic verification of
the AEDM.
The Department's test procedure also requires manufacturers to
calibrate equipment used for testing the efficiency of transformers.
Calibration records would need to be maintained, if the proposed energy
conservation standard is promulgated.
The testing, reporting, and recordkeeping requirements associated
with an energy conservation standard and its related test procedure
would be identical, irrespective of the trial standard level chosen.
Therefore, for both the liquid-immersed and medium-voltage, dry-type
superclasses, testing, reporting, and recordkeeping requirements have
not entered into the Department's choice of trial standard level for
today's proposed rule.
5. Duplication, Overlap, and Conflict With Other Rules and Regulations
The Department is not aware of any rules or regulations that
duplicate, overlap, or conflict with the rule being proposed today.
6. Significant Alternatives to the Rule
The primary alternatives to the proposed rule considered by the
Department are the other trial standard levels besides the one being
proposed today, TSL2. These alternative trial standard levels and their
associated impacts on small business are discussed in the subsequent
paragraphs. In addition to the other trial standard levels considered,
the TSD associated with this proposed rule includes a report referred
to in section VI.A above as the RIA. This report discusses the
following policy alternatives: (1) No new regulatory action, (2)
consumer rebates, (3) consumer tax credits, and (4) manufacturer tax
credits. The energy savings and beneficial economic impacts of these
regulatory alternatives are one to two orders of magnitude smaller than
those expected from today's proposed rule. Finally, the Department has
not considered abbreviated testing requirements for small businesses,
but invites stakeholder comment on abbreviating such requirements for
small businesses.
The entire medium-voltage, dry-type industry has such low shipments
that no designs are produced at high volume. There is little
repeatability of designs, so small businesses can competitively produce
many medium-voltage, dry-type, open-wound designs. The medium-voltage,
dry-type industry as a whole primarily has experience producing
baseline transformers and transformers that would comply with TSL1. In
addition, the industry produces a significant number of units that
would comply with TSL2, but approximately one percent or less of the
market would comply with TSL3 or higher. Therefore, all manufacturers,
including small businesses, would have to develop designs to enable
compliance with TSL3 or higher--such research and development costs
would be more burdensome to small businesses. Product redesign costs
tend to be fixed and do not scale with sales volume. Thus, small
businesses would be at a relative disadvantage at TSL3 and higher
because research and development efforts would be on the same scale as
those for larger companies, but these expenses would be recouped over
smaller sales volumes.
At TSL3 and above, DOE estimates that net cash flows for the
medium-voltage, dry-type industry would go negative during the
compliance period. At TSL3 and above, the impacts on the industry as a
whole are large and affect businesses of all sizes, but there would be
some differential, increased impacts on small businesses. For example,
at TSL3 and above, the use of grain-oriented silicon core steel of M3
or better will be needed. Cutting M3 core steel on the core-mitering
equipment typically purchased by smaller businesses can be problematic
because of the extremely thin laminations.
At TSL2, the level proposed today, all medium-voltage, dry-type
transformer designs would have to have mitered cores. (Mitering means
the transformer core's joints intersect at 45 degree angles, rather
than at 90 degree angles as is true for ``butt-lap'' designs; buttlap
designs are less energy efficient.) The mitered core construction
technique could constrain the core-mitering resources of small
businesses that share core-cutting capacity with production lines for
other transformers that are not covered by this rulemaking (e.g., low-
voltage, dry-type distribution transformers). At TSL1, many kVA ratings
could still be constructed using butt-lap joints, alleviating this
constraint on core-mitering resources. Thus, TSL1 is less capital-
intensive for small businesses than TSL2 (large businesses would likely
miter nearly all medium-voltage cores, even at TSL1). In an industry
such as the medium-voltage, dry-type transformer industry, which is
heavily consolidated already, there is the risk that TSL2 could lead to
further advantage for the largest manufacturers and thus further
concentrate the industry's production. The top three manufacturers
produce over 75 percent of all the transformers in the medium-voltage,
dry-type superclass. Of these three, two of them are small businesses.
The primary difference between TSL1 and TSL2 from the
manufacturers' viewpoint is that TSL1 preserves more design pathways,
each trading off material for capital. Butt-lap designs would be cost-
effective at TSL1 for some kVA ratings, which would allow small
businesses to remain more competitive because they would not
necessarily have to make large capital outlays. TSL2 cannot be met
cost-effectively with butt-lap designs; thus TSL2 could hurt the
margins or decrease the market share of small businesses in the long
run. Some small businesses might opt to purchase pre-mitered cores at
TSL2 rather than investing in core-mitering equipment, which would
likely hurt their margins. However, the differential impact on small
businesses (versus large businesses) is expected to be lower in moving
from TSL1 to TSL2 than in moving from TSL2 to TSL3. Today, the market
already demands significant quantities of medium-voltage, dry-type
transformers that meet TSL2.
Chapter 12 of the TSD contains more information about the impact of
this rulemaking on manufacturers. The Department interviewed six small
businesses affected by this rulemaking (see also section IV.F.1 above).
The Department also obtained information about small business impacts
while interviewing manufacturers that exceed the small business size
threshold of 750 employees.
C. Review Under the Paperwork Reduction Act
Adoption of today's proposed rule would have the effect of
requiring that manufacturers follow certain record-keeping requirements
in the test procedure for distribution transformers, not just for
purposes of making representations, but also to determine compliance
even in the absence of any representation. As set forth in the test
procedure, manufacturers will become subject to the record-keeping
requirements when today's proposed energy conservation standard for
distribution transformers takes effect. 10 CFR Part 431, Subpart K,
Appendix A; 71 FR 24972. Thus, the standard will impose new information
or record
[[Page 44404]]
keeping requirements, and Office of Management and Budget clearance is
required under the Paperwork Reduction Act. (44 U.S.C. 3501 et seq.)
The test procedure for distribution transformers requires
manufacturers to calibrate equipment used for testing the efficiency of
transformers. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
Manufacturers must also document (1) the basis for their calibration of
any equipment for which no national calibration standard exists, (2)
their calibration procedures, and (3) the date when they calibrated
their equipment. The Department drew these provisions from, and in some
cases they are identical to, provisions in NEMA TP 2-1998. The
Department understands that NEMA, in turn, based them on provisions of
the International Standards Organization (ISO) 9000 series documents.
These documents are voluntary standards widely recognized throughout
industry and internationally as setting forth sound quality assurance
methods. The Department incorporated such provisions in its test
procedure because it believes that any manufacturer doing testing
should employ them to assure sound and accurate results. The Department
understands that they are already widely followed by manufacturers, in
the interest of assuring they provide to their customers equipment that
meets customer specifications. Thus, DOE believes that little or no
additional record-keeping burden would be imposed by today's proposed
rule.
The test procedure also allows manufacturers, under certain
circumstances, to determine the efficiencies of their distribution
transformers through use of methods other than testing. The test
procedure includes Alternative Efficiency Determination Methods (AEDM)
to reduce testing burden. 10 CFR Part 431, Subpart K, Appendix A; 71 FR
24972. Each manufacturer that has used an AEDM must have available for
inspection by the Department records showing: The method or methods
used; the mathematical model, the engineering or statistical analysis,
computer simulation or modeling, and other analytic evaluation of
performance data on which the AEDM is based; complete test data,
product information, and related information that the manufacturer has
used to substantiate the AEDM; and the calculations used to determine
the efficiency and total power losses of each basic model to which the
AEDM was applied. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972.
This information must be recorded and maintained for each AEDM the
manufacturer uses. This requirement is designed to enable the
Department to determine, if necessary, that these mathematical models
have been properly used to rate transformer efficiencies.
The Department is submitting to the OMB, simultaneously with the
publication of this proposed rule, these record-keeping requirements
for review and approval under the Paperwork Reduction Act, 44 U.S.C.
3501 et seq. An agency may not impose, and a person is not required to
respond to, such a requirement unless it has been reviewed and assigned
a control number by OMB. Interested persons may obtain a copy of the
Paperwork Reduction Act submission from the contact person named in
this notice.
Interested persons are invited to submit comments to OMB addressed
to: Department of Energy Desk Officer, Office of Information and
Regulatory Affairs, OMB, 725 17th Street, NW., Washington DC, 20503.
Persons submitting comments to OMB also are requested to send a copy to
the DOE contact person at the address given in the addresses section of
this notice. OMB is particularly interested in comments on: (1) The
necessity of the proposed record-keeping provisions, including whether
the information will have practical utility; (2) the accuracy of the
Department's estimates of the burden; (3) ways to enhance the quality,
utility, and clarity of the information to be maintained; and (4) ways
to minimize the burden of the requirements on respondents.
D. Review Under the National Environmental Policy Act
The Department is preparing an environmental assessment of the
impacts of the proposed rule and DOE anticipates completing a Finding
of No Significant Impact (FONSI) before publishing the final rule on
distribution transformers, pursuant to the National Environmental
Policy Act of 1969 (42 U.S.C. 4321 et seq.), the regulations of the
Council on Environmental Quality (40 CFR parts 1500-1508), and the
Department's regulations for compliance with the National Environmental
Policy Act (10 CFR part 1021).
E. Review Under Executive Order 13132
Executive Order 13132, ``Federalism,'' 64 FR 43255 (August 4, 1999)
imposes certain requirements on agencies formulating and implementing
policies or regulations that preempt State law or that have federalism
implications. The Executive Order requires agencies to examine the
constitutional and statutory authority supporting any action that would
limit the policymaking discretion of the States and to carefully assess
the necessity for such actions. The Executive Order also requires
agencies to have an accountable process to ensure meaningful and timely
input by State and local officials in the development of regulatory
policies that have federalism implications. On March 14, 2000, DOE
published a statement of policy describing the intergovernmental
consultation process it will follow in the development of such
regulations. 65 FR 13735. The Department has examined today's proposed
rule and has determined that it does not preempt State law and does not
have a substantial direct effect on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government.
EPCA governs and prescribes Federal preemption of State regulations as
to energy conservation for the products that are the subject of today's
proposed rule. States can petition the Department for exemption from
such preemption to the extent, and based on criteria, set forth in
EPCA. (42 U.S.C. 6297) No further action is required by Executive Order
13132.
F. Review Under Executive Order 12988
With respect to the review of existing regulations and the
promulgation of new regulations, section 3(a) of Executive Order 12988,
``Civil Justice Reform'' 61 FR 4729 (February 7, 1996) imposes on
Federal agencies the general duty to adhere to the following
requirements: (1) Eliminate drafting errors and ambiguity; (2) write
regulations to minimize litigation; and (3) provide a clear legal
standard for affected conduct rather than a general standard and
promote simplification and burden reduction. Section 3(b) of Executive
Order 12988 specifically requires that Executive agencies make every
reasonable effort to ensure that the regulation: (1) Clearly specifies
the preemptive effect, if any; (2) clearly specifies any effect on
existing Federal law or regulation; (3) provides a clear legal standard
for affected conduct while promoting simplification and burden
reduction; (4) specifies the retroactive effect, if any; (5) adequately
defines key terms; and (6) addresses other important issues affecting
clarity and general draftsmanship under any guidelines issued by the
Attorney General. Section 3(c) of Executive Order 12988 requires
Executive agencies to review regulations in light of applicable
standards in section 3(a) and section 3(b) to determine whether they
are met or it is unreasonable to meet one or
[[Page 44405]]
more of them. The Department has completed the required review and
determined that, to the extent permitted by law, this proposed rule
meets the relevant standards of Executive Order 12988.
G. Review Under the Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-
4) (UMRA) requires each Federal agency to assess the effects of Federal
regulatory actions on State, local, and Tribal governments and the
private sector. For a proposed regulatory action likely to result in a
rule that may cause the expenditure by State, local, and Tribal
governments, in the aggregate, or by the private sector of $100 million
or more in any one year (adjusted annually for inflation), section 202
of UMRA requires a Federal agency to publish a written statement that
estimates the resulting costs, benefits, and other effects on the
national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a
Federal agency to develop an effective process to permit timely input
by elected officers of State, local, and Tribal governments on a
proposed ``significant intergovernmental mandate,'' and requires an
agency plan for giving notice and opportunity for timely input to
potentially affected small governments before establishing any
requirements that might significantly or uniquely affect small
governments. On March 18, 1997, DOE published a statement of policy on
its process for intergovernmental consultation under UMRA (62 FR 12820)
(also available at http://www.gc.doe.gov). The proposed rule published
today contains neither an intergovernmental mandate nor a mandate that
may result in expenditure of $100 million or more in any year, so these
requirements do not apply.
H. Review Under the Treasury and General Government Appropriations Act
of 1999
Section 654 of the Treasury and General Government Appropriations
Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family
Policymaking Assessment for any rule that may affect family well-being.
This rule would not have any impact on the autonomy or integrity of the
family as an institution. Accordingly, DOE has concluded that it is not
necessary to prepare a Family Policymaking Assessment.
I. Review Under Executive Order 12630
The Department has determined, under Executive Order 12630,
``Governmental Actions and Interference with Constitutionally Protected
Property Rights,'' 53 FR 8859 (March 18, 1988), that this regulation
would not result in any takings which might require compensation under
the Fifth Amendment to the United States Constitution.
J. Review Under the Treasury and General Government Appropriations Act
of 2001
Section 515 of the Treasury and General Government Appropriations
Act, 2001 (44 U.S.C. 3516, note) provides for agencies to review most
disseminations of information to the public under guidelines
established by each agency pursuant to general guidelines issued by
OMB. The OMB's guidelines were published at 67 FR 8452 (February 22,
2002), and DOE's guidelines were published at 67 FR 62446 (October 7,
2002). The Department has reviewed today's notice under the OMB and DOE
guidelines and has concluded that it is consistent with applicable
policies in those guidelines.
K. Review Under Executive Order 13211
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use,'' 66 FR 28355
(May 22, 2001) requires Federal agencies to prepare and submit to the
Office of Information and Regulatory Affairs (OIRA), Office of
Management and Budget, a Statement of Energy Effects for any proposed
significant energy action. A ``significant energy action'' is defined
as any action by an agency that promulgated or is expected to lead to
promulgation of a final rule, and that: (1) Is a significant regulatory
action under Executive Order 12866, or any successor order; and (2) is
likely to have a significant adverse effect on the supply,
distribution, or use of energy, or (3) is designated by the
Administrator of OIRA as a significant energy action. For any proposed
significant energy action, the agency must give a detailed statement of
any adverse effects on energy supply, distribution, or use should the
proposal be implemented, and of reasonable alternatives to the action
and their expected benefits on energy supply, distribution, and use.
While this proposed rule is a significant regulatory action under
Executive Order 12866, it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy, nor has it been
designated by the Administrator of OIRA as a significant energy action.
Thus, DOE has not prepared a Statement of Energy Effects.
L. Review Under Section 32 of the Federal Energy Administration Act of
1974
The Department is required by section 32 of the Federal Energy
Administration Act (FEAA) of 1974 to inform the public of the use and
background of any commercial standard in a proposed rule. (15 U.S.C.
788) While the Department had considered a commercial voluntary
standard (NEMA TP 1-2002) as one of the trial standard levels, it did
not choose to regulate either liquid-immersed or medium-voltage dry-
type distribution transformers at this efficiency level. Because
today's proposed rule adopts more stringent efficiency levels, Section
32 of the FEAA does not apply.
M. Review Under the Information Quality Bulletin for Peer Review
On December 16, 2004, the Office of Management and Budget (OMB), in
consultation with the Office of Science and Technology (OSTP), issued
its Final Information Quality Bulletin for Peer Review (the Bulletin).
(70 FR 2664, January 14, 2005) The Bulletin establishes that certain
scientific information shall be peer reviewed by qualified specialists
before it is disseminated by the federal government, including
influential scientific information related to agency regulatory
actions. The purpose of the bulletin is to enhance the quality and
credibility of the Government's scientific information.
The Department's Office of Energy Efficiency and Renewable Energy,
Building Technologies Program, held formal in-progress peer reviews
covering the analyses (e.g., screening/engineering analysis, life-cycle
cost analysis, manufacturing impact analysis, and utility impact
analysis) used in conducting the energy efficiency standards
development process on June 28-29, 2005. The in-progress review is a
rigorous, formal and documented evaluation process using objective
criteria and qualified and independent reviewers to make a judgment of
the technical/scientific/business merit, the actual or anticipated
results, and the productivity and management effectiveness of programs
and/or projects. The Building Technologies Program staff is preparing a
peer review report which, upon completion, will be disseminated on the
Office of Energy Efficiency and Renewable Energy's Web site and
included in the administrative record for this rulemaking.
[[Page 44406]]
VII. Public Participation
A. Attendance at Public Meeting
The time and date of the public meeting are listed in the DATES
section at the beginning of this notice of proposed rulemaking. The
public meeting will be held at the U.S. Department of Energy, Forrestal
Building, Room 1E245, 1000 Independence Avenue, SW., Washington, DC
20585-0121. To attend the public meeting, please notify Ms. Brenda
Edwards-Jones at (202) 586-2945. Foreign nationals visiting DOE
Headquarters are subject to advance security screening procedures,
requiring a 30-day advance notice. Any foreign national wishing to
participate in the meeting should advise DOE of this fact as soon as
possible by contacting Ms. Brenda Edwards-Jones to initiate the
necessary procedures.
B. Procedure for Submitting Requests To Speak
Any person who has an interest in today's notice, or who is a
representative of a group or class of persons that has an interest in
these issues, may request an opportunity to make an oral presentation.
Such persons may hand-deliver requests to speak, along with a computer
diskette or CD in WordPerfect, Microsoft Word, PDF, or text (ASCII)
file format to the address shown in the ADDRESSES section at the
beginning of this notice of proposed rulemaking between the hours of 9
a.m. and 4 p.m., Monday through Friday, except Federal holidays.
Requests may also be sent by mail or e-mail to: [email protected].
Persons requesting to speak should briefly describe the nature of
their interest in this rulemaking and provide a telephone number for
contact. The Department requests persons selected to be heard to submit
an advance copy of their statements at least two weeks before the
public meeting. At its discretion, DOE may permit any person who cannot
supply an advance copy of their statement to participate, if that
person has made advance alternative arrangements with the Building
Technologies Program. The request to give an oral presentation should
ask for such alternative arrangements.
C. Conduct of Public Meeting
The Department will designate a DOE official to preside at the
public meeting and may also use a professional facilitator to aid
discussion. The meeting will not be a judicial or evidentiary-type
public hearing, but DOE will conduct it in accordance with 5 U.S.C. 553
and section 336 of EPCA, 42 U.S.C. 6306. A court reporter will be
present to record the proceedings and prepare a transcript. The
Department reserves the right to schedule the order of presentations
and to establish the procedures governing the conduct of the public
meeting. After the public meeting, interested parties may submit
further comments on the proceedings as well as on any aspect of the
rulemaking until the end of the comment period.
The public meeting will be conducted in an informal, conference
style. The Department will present summaries of comments received
before the public meeting, allow time for presentations by
participants, and encourage all interested parties to share their views
on issues affecting this rulemaking. Each participant will be allowed
to make a prepared general statement (within time limits determined by
DOE), before the discussion of specific topics. The Department will
permit other participants to comment briefly on any general statements.
At the end of all prepared statements on a topic, DOE will permit
participants to clarify their statements briefly and comment on
statements made by others. Participants should be prepared to answer
questions by DOE and by other participants concerning these issues.
Department representatives may also ask questions of participants
concerning other matters relevant to this rulemaking. The official
conducting the public meeting will accept additional comments or
questions from those attending, as time permits. The presiding official
will announce any further procedural rules or modification of the above
procedures that may be needed for the proper conduct of the public
meeting.
The Department will make the entire record of this proposed
rulemaking, including the transcript from the public meeting, available
for inspection at the U.S. Department of Energy, Forrestal Building,
Room 1J-018 (Resource Room of the Building Technologies Program), 1000
Independence Avenue, SW., Washington, DC, (202) 586-9127, between 9
a.m. and 4 p.m., Monday through Friday, except Federal holidays. Any
person may buy a copy of the transcript from the transcribing reporter.
D. Submission of Comments
The Department will accept comments, data, and information
regarding the proposed rule before or after the public meeting, but no
later than the date provided at the beginning of this notice of
proposed rulemaking. Please submit comments, data, and information
electronically. Send them to the following e-mail address: [email protected]. Submit electronic comments in WordPerfect,
Microsoft Word, PDF, or text (ASCII) file format and avoid the use of
special characters or any form of encryption. Comments in electronic
format should be identified by the docket number EE-RM/STD-00-550 and/
or RIN number 1904-AB08, and wherever possible carry the electronic
signature of the author. Absent an electronic signature, comments
submitted electronically must be followed and authenticated by
submitting the signed original paper document. No telefacsimiles
(faxes) will be accepted.
According to 10 CFR 1004.11, any person submitting information that
he or she believes to be confidential and exempt by law from public
disclosure should submit two copies: One copy of the document including
all the information believed to be confidential, and one copy of the
document with the information believed to be confidential deleted. The
Department of Energy will make its own determination about the
confidential status of the information and treat it according to its
determination.
Factors of interest to the Department when evaluating requests to
treat submitted information as confidential include: (1) A description
of the items; (2) whether and why such items are customarily treated as
confidential within the industry; (3) whether the information is
generally known by or available from other sources; (4) whether the
information has previously been made available to others without
obligation concerning its confidentiality; (5) an explanation of the
competitive injury to the submitting person which would result from
public disclosure; (6) when such information might lose its
confidential character due to the passage of time; and (7) why
disclosure of the information would be contrary to the public interest.
E. Issues on Which DOE Seeks Comment
The Department is particularly interested in receiving comments and
views of interested parties concerning:
(1) The proposed tables of efficiency ratings, and specifically
areas where the underlying analytical methods followed for developing
the efficiency values resulted in discontinuities.
(2) The Department's treatment of rebuilt or refurbished
transformers in this rulemaking and the potential impact on consumers,
manufacturers, and national energy use if they were excluded.
(3) Whether less-flammable, liquid-immersed distribution
transformers
[[Page 44407]]
should be included in the same product class as medium-voltage, dry-
type transformers. Currently the Department considers dry-type
transformers and liquid-immersed transformers as members of separate
product classes.
(4) Whether stakeholders believe a minimum efficiency standard for
liquid-immersed distribution transformers would contribute to design
standardization, and encourage manufacturers to move to countries with
lower labor costs.
(5) The appropriateness of using discount rates of seven percent
and three percent real to discount future energy savings and emissions
reductions.
(6) Whether the Department should include space occupancy costs in
the cost of transformers as a means of accounting for space
constraints.
(7) The IRFA and the potential impacts on small businesses affected
by this rulemaking. Although the Department is expressly inviting
comments related to the medium-voltage, dry-type superclass, the
Department also welcomes comment on its understanding that there would
be no significant economic impact on a substantial number of small
entities within the liquid-immersed superclass alone.
VIII. Approval of the Office of the Secretary
The Secretary of Energy has approved publication of today's notice
of proposed rulemaking.
List of Subjects in 10 CFR Part 431
Administrative practice and procedure, Confidential business
information, Energy conservation, Reporting and record keeping
requirements.
Issued in Washington, DC, on July 20, 2006.
Alexander A. Karsner,
Assistant Secretary, Energy Efficiency and Renewable Energy.
For the reasons set forth in the preamble, Chapter II of Title 10,
Code of Federal Regulations, Subpart K of Part 431 is proposed to be
amended to read as set forth below.
PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND
INDUSTRIAL EQUIPMENT
1. The authority citation for part 431 continues to read as
follows:
Authority: 42 U.S.C. 6291-6317.
2. Section 431.196 is amended by revising paragraphs (b) and (c) to
read as follows:
Sec. 431.196 Energy conservation standards and their effective dates.
* * * * *
(b) Liquid-Immersed Distribution Transformers. Liquid-immersed
distribution transformers manufactured on or after January 1, 2010,
shall have an efficiency no less than:
----------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
----------------------------------------------------------------------------------------------------------------
Efficiency (%) Efficiency
kVA * kVA (%) *
----------------------------------------------------------------------------------------------------------------
10......................................... 98.40 15................................ 98.36
15......................................... 98.56 30................................ 98.62
25......................................... 98.73 45................................ 98.76
37.5....................................... 98.85 75................................ 98.91
50......................................... 98.90 112.5............................. 99.01
75......................................... 99.04 150............................... 99.08
100........................................ 99.10 225............................... 99.17
167........................................ 99.21 300............................... 99.23
250........................................ 99.26 500............................... 99.32
333........................................ 99.31 750............................... 99.24
500........................................ 99.38 1000.............................. 99.29
667........................................ 99.42 1500.............................. 99.36
833........................................ 99.45 2000.............................. 99.40
2500.............................. 99.44
----------------------------------------------------------------------------------------------------------------
* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature
of 20 [deg]C, and (2) for load-losses, at the temperature of 55[deg]C and 50 percent of nameplate load.
(c) Medium-Voltage Dry-Type Distribution Transformers. Medium-
voltage dry-type distribution transformers manufactured on or after
January 1, 2010, shall have an efficiency no less than:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
20-45 kV 46-95 kV >=96 kV 20-45 kV 46-95 kV >=96 kV
BIL kVA efficiency efficiency efficiency (%) BIL kVA efficiency efficiency efficiency
(%) * (%) * * (%) * (%) * (%) *
--------------------------------------------------------------------------------------------------------------------------------------------------------
15............................... 98.10 97.86 ............... 15.................. 97.50 97.19 ..............
25............................... 98.33 98.12 ............... 30.................. 97.90 97.63 ..............
37.5............................. 98.49 98.30 ............... 45.................. 98.10 97.86 ..............
50............................... 98.60 98.42 ............... 75.................. 98.33 98.12 ..............
75............................... 98.73 98.57 98.53 112.5............... 98.49 98.30 ..............
100.............................. 98.82 98.67 98.63 150................. 98.60 98.42 ..............
167.............................. 98.96 98.83 98.80 225................. 98.73 98.57 98.53
250.............................. 99.07 98.95 98.91 300................. 98.82 98.67 98.63
333.............................. 99.14 99.03 98.99 500................. 98.96 98.83 98.80
500.............................. 99.22 99.12 99.09 750................. 99.07 98.95 98.91
667.............................. 99.27 99.18 99.15 1000................ 99.14 99.03 98.99
833.............................. 99.31 99.23 99.20 1500................ 99.22 99.12 99.09
2000................ 99.27 99.18 99.15
[[Page 44408]]
2500................ 99.31 99.23 99.20
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* Efficiencies are determined at the following reference conditions: (1) For no-load losses, at the temperature of 20 [deg]C, and (2) for load-losses,
at the temperature of 75 [deg]C and 50 percent of nameplate load.
[FR Doc. 06-6537 Filed 8-3-06; 8:45 am]
BILLING CODE 6450-01-P