FR Doc E7-19582

[Federal Register: October 12, 2007 (Volume 72, Number 197)]
[Rules and Regulations]
[Page 58189-58241]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12oc07-9]

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Part III

Department of Energy

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10 CFR Part 431

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

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DEPARTMENT OF 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; Final Rule

AGENCY: Department of Energy.

ACTION: Final rule.

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SUMMARY: The Department of Energy (DOE) has determined that energy
conservation standards for liquid-immersed and medium-voltage, dry-type
distribution transformers will result in significant conservation of
energy, are technologically feasible, and are economically justified.
On this basis, DOE is today adopting energy conservation standards for
liquid-immersed and medium-voltage, dry-type distribution transformers.
Today's rule does not set energy conservation standards for underground
mining distribution transformers.

DATES: Effective Date: The effective date of this rule is November 13,
2007. Standards for liquid-immersed and medium-voltage, dry-type
distribution transformers will be applicable starting January 1, 2010.

ADDRESSES: For access to the docket to read background documents, the
technical support document (TSD), transcripts of the public meetings in
this proceeding, 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: DOE's Freedom of Information Reading
Room (formerly Room 1E-190 at the Forrestal Building) no longer houses
rulemaking materials. You may also obtain copies of certain previous
rulemaking documents from this proceeding (i.e., Framework Document,
advance notice of proposed rulemaking (ANOPR), notice of proposed
rulemaking (NOPR or proposed rule)), draft analyses, public meeting
materials, and related test procedure documents from the Office of
Energy Efficiency and Renewable Energy's Web site at http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html
.

FOR FURTHER INFORMATION CONTACT: Antonio Bouza, Project Manager, Energy
Conservation Standards for Distribution Transformers, Docket No. EE-RM/
STD-00-550, U.S. Department of Energy, Energy Efficiency and Renewable
Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue,
SW., Washington, DC 20585-0121, (202) 586-4563, e-mail:
Antonio.Bouza@ee.doe.gov.

Francine Pinto, Esq., U.S. Department of Energy, Office of General
Counsel, GC-72, 1000 Independence Avenue, SW., Washington, DC 20585-
0121, (202) 586-7432, e-mail: Francine.Pinto@hq.doe.gov.

SUPPLEMENTARY INFORMATION:
I. Summary of the Final Rule and Its Benefits
A. The Standard Levels
B. Distribution Transformer Characteristics
C. Benefits to Transformer Customers
D. Impact on Manufacturers
E. National Benefits
F. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
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 Commercial Consumers and Manufacturers
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 on Methodology
A. Market and Technology Assessment
1. General
2. Mining Transformers
a. Comments Requesting Exemption
b. Mining Transformer Test Procedure Comments
3. Less-Flammable, Liquid-Immersed Transformers
4. Rebuilt or Refurbished Distribution Transformers
5. Uninterruptible Power System Transformers
B. Engineering Analysis
C. Life-Cycle Cost and Payback Period Analysis
1. Inputs Affecting Installed Cost
a. Installation Costs
b. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Electricity Costs
d. Electricity Price Trends
e. Natural Gas Price Impacts
3. Inputs Affecting Present Value of Annual Operating Cost
Savings
a. Standards Implementation Date
b. Discount Rate
c. Temperature Rise, Reliability, and Lifetime
D. National Impact Analysis--National Energy Savings and Net
Present Value Analysis
1. Discount Rate
a. Selection and Estimation Method
b. Discounting Energy and Emissions
E. Commercial Consumer Subgroup Analysis
F. Manufacturer Impact Analysis
G. Employment Impact Analysis
H. Utility Impact Analysis
I. Environmental Analysis
V. Discussion of Other Comments
A. Information and Assumptions Used in Analyses
1. Engineering Analysis
a. Primary Voltage Sensitivities
b. Increased Raw Material Prices
c. Amorphous Material Price
d. Material Availability
2. Shipments/National Energy Savings
3. Manufacturer Impact Analysis
B. Weighing of Factors
1. Economic Impacts
a. Economic Impacts on Consumers
b. Economic Impacts on Manufacturers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Products
a. Transformers Installed in Vaults
5. Impact of Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
a. Availability of High Primary Voltages
b. Materials Price Sensitivity Analysis
c. Materials Availability Analysis
d. Consistency Between Single-Phase and Three-Phase Designs
C. Other Comments
1. Development of Trial Standard Levels for the Final Rule
2. Linear Interpolation of Non-Standard Capacity Ratings
VI. Analytical Results and Conclusions
A. Trial Standard Levels
B. Significance of Energy Savings
C. Economic Justification
1. Economic Impact on Commercial Consumers
a. Life-Cycle Costs and Payback Period
b. Commercial Consumer Subgroup Analysis
2. Economic Impact 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 Net Present Value and Net National 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
D. Conclusion
1. Results for Liquid-Immersed Distribution Transformers

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a. Liquid-Immersed Transformers--Trial Standard Level 6
b. Liquid-Immersed Transformers--Trial Standard Level 5
c. Liquid-Immersed Transformers--Trial Standard Level A
d. Liquid-Immersed Transformers--Trial Standard Level 4
e. Liquid-Immersed Transformers--Trial Standard Level 3
f. Liquid-Immersed Transformers--Trial Standard Level B
g. Liquid-Immersed Transformers--Trial Standard Level C
2. Results for Medium-Voltage, Dry-Type Distribution
Transformers
a. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 6
b. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 5
c. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 4
d. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 3
e. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 2
VII. Procedural Issues and Regulatory Review
A. Review Under Executive Order 12866
B. Review Under the Regulatory Flexibility Act/Final Regulatory
Flexibility Analysis
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, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government
Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Review Under Section 32 of the Federal Energy Administration
Act of 1974
M. Review Under the Information Quality Bulletin for Peer Review
N. Congressional Notification
VIII. Approval of the Office of the Secretary

I. Summary of the Final Rule and Its Benefits

A. The Standard Levels

The Energy Policy and Conservation Act (EPCA), as amended, directs
the Department of Energy (DOE) to adopt energy conservation standards
for those distribution transformers for which standards would be
technologically feasible and economically justified, and would result
in significant energy savings. (42 U.S.C. 6317(a)(2)) The standards in
today's final rule, which apply to liquid-immersed and medium-voltage,
dry-type distribution transformers, satisfy these requirements and will
achieve the maximum improvements in energy efficiency that are
technologically feasible and economically justified. In the advance
notice of proposed rulemaking (ANOPR) in this proceeding, DOE had also
addressed standards for low-voltage, dry-type distribution
transformers. 69 FR 45376 (July 29, 2004). However, the Energy Policy
Act of 2005, Public Law 109-58, (EPACT 2005) amended EPCA to establish
energy conservation standards for those transformers. (EPACT 2005,
Section 135(c); 42 U.S.C. 6295(y)) Therefore, DOE removed low-voltage,
dry-type distribution transformers from the scope of this rulemaking.
The standards established in this final rule are minimum efficiency
levels. Tables I.1 and I.2 show the standard levels DOE is adopting
today. These standards will 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. As discussed in section V.C.2 of this notice, any
transformers whose kVA\1\ rating falls between the kVA ratings shown in
tables I.1 and I.2 shall have its minimum efficiency requirement
calculated by a linear interpolation of the minimum efficiency
requirements of the kVA ratings immediately above and below that
rating.
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\1\ kVA is an abbreviation for kilovolt-ampere, which is a
capacity metric used by industry to classify transformers. A
transformer's kVA rating represents its output power when it is
fully loaded (i.e., 100%).

Table I.1.--Standard Levels for Liquid-Immersed Distribution
Transformers, Tabular Form
------------------------------------------------------------------------
Single-phase Three-phase
------------------------------------------------------------------------
Efficiency Efficiency
kVA (%) kVA (%)
------------------------------------------------------------------------
10.......................... 98.62 15............. 98.36
15.......................... 98.76 30............. 98.62
25.......................... 98.91 45............. 98.76
37.5........................ 99.01 75............. 98.91
50.......................... 99.08 112.5.......... 99.01
75.......................... 99.17 150............ 99.08
100......................... 99.23 225............ 99.17
167......................... 99.25 300............ 99.23
250......................... 99.32 500............ 99.25
333......................... 99.36 750............ 99.32
500......................... 99.42 1000........... 99.36
667......................... 99.46 1500........... 99.42
833......................... 99.49 2000........... 99.46
............ 2500........... 99.49
------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load,
determined according to the DOE test procedure. 10 CFR Part 431,
Subpart K, Appendix A.

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37.5...................................... 98.49 98.30 ............ 45........................... 98.10 97.86 ...........
50........................................ 98.60 98.42 ............ 75........................... 98.33 98.12 ...........
75........................................ 98.73 98.57 98.53 112.5........................ 98.49 98.30 ...........
100....................................... 98.82 98.67 98.63 150.......................... 98.60 98.42 ...........
167....................................... 98.96 98.83 98.80 225.......................... 98.73 98.57 98.53
250....................................... 99.07 98.95 98.91 300.......................... 98.82 98.67 98.63
333....................................... 99.14 99.03 98.99 500.......................... 98.96 98.83 98.80
500....................................... 99.22 99.12 99.09 750.......................... 99.07 98.95 98.91
667....................................... 99.27 99.18 99.15 1000......................... 99.14 99.03 98.99
833....................................... 99.31 99.23 99.20 1500......................... 99.22 99.12 99.09
........... ........... ............ 2000......................... 99.27 99.18 99.15
........... ........... ............ 2500......................... 99.31 99.23 99.20
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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.

B. Distribution Transformer Characteristics

The minimum efficiency levels in today's standards can be met by
distribution transformer designs that already are available in the
market. DOE expects that distribution transformer designs that
incorporate different voltages and other design variations will still
be able to be manufactured under the new standards, maintaining all the
features and utility found in commercially available products today.
In analyzing the benefits and burdens of potential standards, DOE
represented the range of possible distribution transformer costs and
features by representative engineering design lines. Five design lines
(DL1, DL2, DL3, DL4, and DL5) represent the range of features and costs
for liquid-immersed transformers, while five design lines (DL9, DL10,
DL11, DL12, and DL13) represent medium-voltage, dry-type transformers.
Three design lines (DL6, DL7, and DL8) represented low-voltage dry-type
transformers and were included in DOE's ANOPR analysis. But as
indicated above, DOE subsequently removed these transformers from this
rulemaking when the Energy Policy Act of 2005 established minimum
efficiency levels for them.
On average, liquid-immersed transformers are already relatively
efficient. The annual operating costs for such transformers range from
approximately \1/10\ to \1/30\ of the installed cost. Medium-voltage,
dry-type transformers tend to have higher losses, and are subject to
higher electricity costs. Their annual operating costs tend to be
approximately \1/10\ of the installed cost.

C. Benefits to Transformer Consumers

The economic impacts on transformer consumers (i.e., the average
life-cycle cost (LCC) savings) are positive for the new energy
efficiency levels established by this rule. For liquid-immersed
transformers, an increase in first costs of 6-12 percent is accompanied
by a decrease in operating costs of 15-23 percent, corresponding to a
similar drop in electrical losses. For medium-voltage, dry-type
transformers, an increase in first costs of 3-13 percent is accompanied
by a decrease in losses and operating costs of 9-26 percent. On
average, the new standards provides net life-cycle benefits for all
categories of distribution transformers, although some liquid-immersed
transformers with smaller loads and relatively low electricity cost are
likely to incur a net cost from the new standards. For liquid-immersed
transformers, DOE estimates that approximately 25% of the market incurs
a net life-cycle cost from the standard while 75% of the market is
either not affected or incurs a net benefit. DOE also investigated how
these standards might affect municipal utilities and rural electric
cooperatives. While the benefits are positive for municipal utilities,
a majority of smaller, pole-mounted transformers for rural electric
cooperatives will incur a net life-cycle cost. However, because of a
relatively large per-transformer reduction in life-cycle cost for some
non-evaluating rural electric cooperatives (i.e., those that do not
take into consideration the cost of transformer losses when choosing a
transformer) rural electric cooperatives as a whole receive an average
life-cycle cost benefit.

D. Impact on Manufacturers

Using a real corporate discount rate of 8.9 percent, DOE estimated
the industry net present values (INPV) of the liquid-immersed and
medium-voltage, dry-type distribution transformer industries to be $609
million and $36 million, respectively, in 2006$. DOE expects the impact
of today's standards on the INPV of the liquid-immersed transformer
industry to be between an eight percent loss and an eight percent
increase (-$47 million to $47 million). DOE expects the impact of
today's standards on the INPV of the medium-voltage, dry-type
transformer industry to be between a 15 percent loss and a 9 percent
loss (-$5.2 million to -$3.2 million). Based on DOE's analysis and
interviews with distribution transformer manufacturers, DOE expects
minimal plant closings or loss of employment as a result of the
standards promulgated today.

E. National Benefits

The standards will provide significant benefits to the Nation. DOE
estimates the standards will save approximately 2.74 quads (quadrillion
(10\15\) British thermal units (BTU)) of energy over 29 years (2010-
2038). This is equivalent to all the energy consumed by 27 million
American households in a single year.
By 2038, DOE expects the energy savings from the standards to
eliminate the need for approximately six new 400-megawatt combined-
cycle gas turbine power plants. The total energy savings from the
standard will result in cumulative greenhouse gas emission reductions
of approximately 238 million tons (Mt) of carbon dioxide
(CO2) from a variety of generation sources. This is an
amount equal to what would be

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saved by removing 80 percent of all light vehicles from U.S. roads for
one year.
The national net present value (NPV) of the standards is $1.39
billion using a seven percent discount rate and $7.8 billion using a
three percent discount rate, cumulative from 2010 to 2073 in 2006$.
This is the estimated total value of future energy savings minus the
estimated increased equipment costs, discounted to the year 2007. The
benefits and costs of the standard can also be expressed in terms of
annualized 2006$ values over the forecast period 2010 through 2038.
Using a seven percent discount rate for the annualized cost
analysis, the cost of the standard is $463 million per year in
increased equipment and installation costs while the annualized
benefits are $602 million per year in reduced equipment operating
costs. Using a three percent discount rate, the cost of the standard is
$460 million per year while the benefits of today's standard are $904
million per year.

F. Conclusion

DOE concludes that the benefits (energy savings, transformer
consumer LCC savings, national NPV increases, and emissions reductions)
to the Nation of the standards outweigh their costs (loss of
manufacturer INPV and transformer consumer LCC increases for some users
of distribution transformers). DOE concludes that today's standards for
liquid-immersed and medium-voltage, dry-type transformers are
technologically feasible and economically justified, and will result in
significant energy savings. At present, both liquid-immersed and
medium-voltage, dry-type transformers that meet the new standard levels
are commercially available.

II. Introduction

A. 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. DOE
publishes today's final rule 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.
EPCA contains criteria for prescribing new or amended energy
conservation standards. DOE 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)(2)) Moreover, DOE analyzed whether
today's 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)) \2\
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\2\ DOE notes that 42 U.S.C. 6317(c) requires that DOE ``take
into consideration'' the criteria contained in section 325(n).''
However, Section 325(n), ``Petition For An Amended Standard,'' does
not contain the criteria for establishing new or amended standards,
rather as its title states, it contains the criteria DOE must apply
for determining whether to grant petitions for amending standards,
filed by any person with the Secretary of Energy. Section 325(o)
entitled, ``Criteria for Prescribing New or Amended Standards''
contains the appropriate criteria that 42 U.S.C. 6317(c) apparently
intends to reference. The reference in section 42 U.S.C. 6317(c) to
section 325(n) is an inadvertent error and DOE will apply the
criteria in section 325(o) instead.
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In addition, DOE decided whether each of today's standards for
distribution transformers is economically justified, after receiving
comments on the proposed standards, by determining whether the benefits
of each standard exceed its burdens by considering, to the greatest
extent practicable, the following seven factors that 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 today's energy conservation standards, DOE also has
applied certain other provisions of 42 U.S.C. 6295. First, DOE would
not prescribe a standard for distribution transformers if interested
persons 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 equipment with performance
characteristics (including reliability), features, sizes, capacities,
and volumes that are substantially the same as those generally
available at the time of the Secretary's finding. (See 42 U.S.C.
6295(o)(4))
Second, DOE has applied 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, DOE may specify a different standard level than that which
applies generally to a 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)) Any rule prescribing
such a standard includes an explanation of the basis on which DOE
establishes 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)) DOE can, however, grant waivers of
preemption for particular State laws or regulations,

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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))

B. 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 amended EPCA to establish energy conservation standards for
low-voltage, dry-type distribution transformers.\3\ (EPACT 2005,
Section 135(c); 42 U.S.C. 6295(y)) The standard levels for low-voltage
dry-type transformers appear in Table II.1.
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\3\ EPACT 2005 established that the efficiency of a low-voltage
dry-type distribution transformer manufactured on or after January
1, 2007 shall be the Class I Efficiency Levels for distribution
transformers specified in Table 4-2 of the ``Guide for Determining
Energy Efficiency for Distribution Transformers'' published by the
National Electrical Manufacturers Association (NEMA TP 1-2002).

Table II.1.--Energy Conservation Standards for Low-Voltage, Dry-Type
Distribution Transformers
------------------------------------------------------------------------
Single-phase Three-phase
------------------------------------------------------------------------
Efficiency Efficiency
kVA (%) kVA (%)
------------------------------------------------------------------------
15.......................... 97.7 15............. 97.0
25.......................... 98.0 30............. 97.5
37.5........................ 98.2 45............. 97.7
50.......................... 98.3 75............. 98.0
75.......................... 98.5 112.5.......... 98.2
100......................... 98.6 150............ 98.3
167......................... 98.7 225............ 98.5
250......................... 98.8 300............ 98.6
333......................... 98.9 500............ 98.7
............ 750............ 98.8
............ 1000........... 98.9
------------------------------------------------------------------------
Note: All efficiency values are at 35 percent of nameplate-rated load,
determined according to the DOE test procedure. 10 CFR Part 431,
Subpart K, Appendix A.

DOE incorporated these standards into its regulations, along with
the standards for several other types of products and equipment, in a
Final Rule published on October 18, 2005. 70 FR 60407, 60416-60417.
2. History of Standards Rulemaking for Distribution Transformers
On October 22, 1997, the Secretary of Energy published a notice
stating that DOE ``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 based this determination, in part, on analyses
conducted by DOE's Oak Ridge National Laboratory (ORNL). The two
reports containing these analyses--Determination Analysis of Energy
Conservation Standards for Distribution Transformers, ORNL-6847 (1996)
and Supplement to the ``Determination Analysis,'' ORNL-6847 (1997)--are
available on the DOE Web site at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html
.

As a result of its positive determination, in 2000 DOE developed
the Framework Document for Distribution Transformer Energy Conservation
Standards Rulemaking, which described the approaches DOE anticipated
using to develop energy conservation standards for distribution
transformers. This document is also available on the above-referenced
DOE website. On November 1, 2000, DOE held a public meeting to discuss
the proposed analytical framework. Manufacturers, trade associations,
electric utilities, energy efficiency organizations, regulators, and
other interested parties attended this meeting. Stakeholders also
submitted written comments on the Framework Document addressing a range
of issues.
In the first quarter of 2002, prior to issuing its ANOPR, DOE met
with manufacturers of liquid-immersed and dry-type distribution
transformers to solicit feedback on a draft engineering analysis report
DOE had published containing a proposed analytical structure for the
engineering analysis and some initial transformer designs. In addition,
DOE also posted draft screening, engineering, and LCC analysis reports
on its website, and held a live Webcast on the LCC analysis on October
17, 2002.\4\ DOE received comments from stakeholders on the draft
reports, and these comments helped improve the quality of the analyses
included in the ANOPR for this rulemaking, which was published on July
29, 2004. 69 FR 45376. In preparation for the September 28, 2004, ANOPR
public meeting, DOE held a Webcast to acquaint stakeholders with the
analytical tools and with other material DOE had published the previous
month.
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\4\ Copies of all the draft analyses published before the ANOPR
are available on DOE's Web site: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis.html
.

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On August 5, 2005, DOE posted its draft NOPR analysis for the
liquid-immersed and medium-voltage, dry-type distribution transformers
on its Web site for early public review, along with spreadsheets for
several of these analyses. This early publication of the draft NOPR
analysis included the draft engineering analysis, LCC analysis,
national impact analysis, and manufacturer impact analysis (MIA), and
the draft TSD chapters associated with each of these analyses. The
purpose of publishing these four draft analyses was to give
stakeholders an opportunity to review the analyses and prepare
recommendations for DOE as to the appropriate standard levels.\5\
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\5\ Copies of the four draft NOPR analyses published in August
2005 are available on DOE's Web site: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html
.

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On April 27, 2006, DOE published its Final Rule on Test Procedures
for

[[Page 58195]]

Distribution Transformers. In addition to establishing the procedure
for sampling and testing distribution transformers so that
manufacturers can make representations as to their efficiency as well
as establish that they comply with Federal standards, this final rule
also contained enforcement provisions, outlining the procedure the
Department would follow should it initiate an enforcement action
against a manufacturer. 71 FR 24972; 10 CFR 431.198.
On July 25, 2006, DOE published a NOPR proposing compliance
certification procedures for a range of consumer products and
commercial and industrial equipment, including distribution
transformers. This NOPR included both a compliance statement and a
certification report for distribution transformer manufacturers. 71 FR
42178. DOE is currently preparing its final rule for that proceeding,
which will establish requirements around the compliance statement and
certification report for distribution transformers and other products
and equipment.
On August 4, 2006, DOE published the distribution transformer
energy conservation standards NOPR. 71 FR 44355. In conjunction with
the NOPR, DOE also published on its Web site the complete TSD for the
proposed rule, which incorporated the final analyses DOE conducted and
technical documentation for each analysis. The TSD included the
engineering analysis spreadsheets, the LCC spreadsheet, the national
impact analysis spreadsheet, and the MIA spreadsheet--all of which are
available on DOE's Web site.\6\ Table II.2 presents the energy
conservation standard levels DOE proposed in the NOPR for liquid-
immersed distribution transformers, and Table II.3 presents the energy
conservation standard levels DOE proposed for medium-voltage, dry-type
distribution transformers.
---------------------------------------------------------------------------

\6\ The Web site address for all the spreadsheets developed for
this rulemaking proceeding are available at: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers_draft_analysis_nopr.html
.

Table II.2.--NOPR Proposed Energy Conservation Standard Levels for
Liquid-Immersed Distribution Transformers
------------------------------------------------------------------------
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
------------------------------------------------------------------------
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.

Table II.3.--NOPR Proposed Energy Conservation Standard Levels for Medium-Voltage, Dry-Type Distribution Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-phase Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
[gteqt]96
20-45 kV 46-95 kV [gteqt]96 kV 20-45 kV 46-95 kV 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
........... ........... ............ 2500......................... 99.31 99.23 99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE test procedure. 10 CFR Part 431, Subpart K,
Appendix A.

[[Page 58196]]

In the NOPR, DOE identified seven issues on which it was
particularly interested in receiving comments and views of interested
parties. 71 FR 44406.
On February 9, 2007, DOE issued a notice of data availability and
request for comments (NODA). 72 FR 6186. DOE published this notice in
response to stakeholders who had commented, in response to the NOPR,
that DOE's proposed standards might prevent or render impractical the
replacement of distribution transformers in certain space-constrained
(e.g., vault) installations. In the NODA, DOE sought comment on whether
it should include in the LCC analysis potential costs related to size
constraints of transformers installed in vaults. In the NODA, DOE
outlined different approaches as to how it might account for additional
installation costs for these space-constrained applications. In
addition, DOE also published the NODA in response to certain
stakeholders who commented that DOE should address the consistency
issues for liquid-immersed transformers in the table of efficiency
standards. DOE also requested comments on linking efficiency levels for
three-phase liquid-immersed units with those of single-phase units.
Specifically, in the NODA DOE discussed how it was inclined to consider
a final standard that is based on efficiency levels that are based on
TSL 2 and TSL 3 for three-phase units and TSLs 2, 3 and 4 for single-
phase units. 72 FR 6189. Based on comments on the August 2006 proposed
rule and the February 2007, NODA, DOE created new TSLs, including TSL
B, which is, generally speaking, a combination of TSL 2 for three-phase
units and TSL 3 for single-phase units. DOE received more than 20
written comments in response to this NODA on both the space constraint
issue and how to set final efficiency ratings, which are discussed in
the following sections of this final rule.
In response to the NODA, Cooper Power Systems commented that they
were concerned that the NODA did not indicate any specifics regarding
the proposed TSL levels for any design lines. Cooper states that DOE
needs to publish a new proposed table that represents the mix of
efficiency levels being considered in order for interested parties to
provide solid feedback on the impact of these proposals. (Cooper, No.
175 at p. 1) \7\ ABB provided a similar comment, expressing that they
disagree with DOE's action of indicating that it may adopt a new mix of
TSLs derived from a combination of TSLs 2, 3 and 4 as the final
standard level without specifying exactly which combination is being
considered. (ABB, No. 167 at p. 1) DOE appreciates these two comments,
but does not agree with the stakeholders criticism of DOE's actions and
the rulemaking process for the following reasons. First, the NODA
provided notice to stakeholders that DOE would consider a combination
of TSLs for liquid-immersed distribution transformers for the final
rule. Accordingly, stakeholders have been given an opportunity to
review the existing proposed standard levels and published NOPR
analysis, and provide comments to DOE as to the combination of
efficiency values they believe are the most justified, and why. Second,
DOE did not consider simply one new TSL in today's final rule, but
instead created four new TSLs (TSL A, B, C, and D) based on
combinations of efficiency values from previously proposed TSL 2, 3 and
4. These four combinations of TSLs enabled DOE to consider several
different efficiency values for liquid-immersed transformers for the
final rule, decreasing the burdens associated with inconsistencies
between three-phase and single-phase units and eliminating the
discontinuities of efficiency values between design lines. In addition,
the four combinations of TSLs attempt to maximize national and consumer
benefits and select appropriate, cost-justified, efficiency levels
across all the design lines. Third, all of the actual efficiency
ratings considered in the four new TSL combinations developed for
today's final rule were previously published in DOE's August 2006 NOPR.
For all of these reasons, DOE believes the NODA provides stakeholders
sufficient notice and opportunity for comment concerning the standard
level adopted by today's final rule.
---------------------------------------------------------------------------

\7\A notation in the form ``Cooper, No. 175 at p. 1'' identifies
a written comment DOE received and included in the docket for this
rulemaking. This particular notation refers to a comment (a) by
Cooper Power Systems (Cooper), (b) in document number 175 in the
docket of this rulemaking (maintained in the Resource Room of the
Building Technologies Program), and (c) appearing on page 1 of
document number 175.
---------------------------------------------------------------------------

III. General Discussion

A. Test Procedures

Section 7(c) of the Process Rule (Procedures for Consideration of
New or Revised Energy Conservation Standards for Consumer Products,
Title 10 CFR part 430, Subpart C, Appendix A; 61 FR 36974) \8\
indicates that DOE will issue a final test procedure, if one is needed,
prior to issuing a proposed rule for energy conservation standards. DOE
published its test procedure for distribution transformers as a final
rule on April 27, 2006. 71 FR 24972.
---------------------------------------------------------------------------

\8\ The Process Rule provides guidance on how DOE conducts its
energy conservation standards rulemakings, including the analytical
steps and sequencing of rulemaking stages (such as test procedures
and energy conservation standards).
---------------------------------------------------------------------------

B. Technological Feasibility

1. General
There are distribution transformers in the market at all of the
efficiency levels prescribed in today's final rule. Therefore, DOE
believes all of the efficiency levels adopted by today's final rule are
technologically feasible.
2. Maximum Technologically Feasible Levels
Applying the requirements of 42 U.S.C. 6295(p)(2), and as discussed
in the proposed rule, DOE determined ``the maximum improvement in
energy efficiency or maximum reduction in energy use that is
technologically feasible.'' 71 FR 44362. DOE determined the ``max-
tech'' efficiency levels in the engineering analysis (see Chapter 5 in
the TSD) and then used these highest efficiency designs to establish
the max-tech levels for the LCC analysis (see Chapter 8 in the TSD).
DOE then scaled these max-tech efficiencies to the other kVA ratings
within a given design line, establishing max-tech efficiencies for all
the distribution transformer kVA ratings.

C. Energy Savings

DOE forecasted energy savings in its national energy savings (NES)
analysis, through the use of an NES spreadsheet tool, as discussed in
the proposed rule. 71 FR 44361, 44363, 44380-44381, 44384, 44393,
44401.
One of the criteria that govern DOE's adoption of standards for
distribution transformers is that the standard must result in
``significant'' energy savings. (42 U.S.C. 6317(a)) While EPCA does not
define the term ``significant,'' 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 section 325 of EPCA to be savings that were not ``genuinely
trivial.'' The energy savings for the standard levels DOE is adopting
today are nontrivial, and therefore DOE considers them ``significant''
as required by 42 U.S.C. 6317(a).

D. Economic Justification

As noted earlier, EPCA provides seven factors for DOE to evaluate
in determining whether an energy conservation standard for distribution
transformers is economically justified. The following discussion
explains how DOE has addressed each of these seven

[[Page 58197]]

factors in this rulemaking. (42 U.S.C. 6295(o)(2)(B)(i))
1. Economic Impact on Commercial Consumers and Manufacturers
DOE considered the economic impact of the standard on commercial
consumers and manufacturers, as discussed in the proposed rule. 71 FR
44361, 44363-44364, 44367, 44376-44277, 44379, 44381-44384, 44385-
44389, 44390-44393, 44394, 44396-44400, 44401-44404. DOE updated the
analyses to incorporate more recent material price information. One
significant change to the MIA was the inclusion of lower conversion-
capital expenditure estimates for those trial standard levels (TSLs)
which require or otherwise trigger manufacturers to switch to amorphous
core technology. DOE based the revised estimates on information
provided by industry experts (see Section V.A.3 below).
2. Life-Cycle Costs
DOE considered life-cycle costs of distribution transformers, as
discussed in the proposed rule. 71 FR 44362-44363, 44371-44376, 44378-
44379, 44385-44390, 44395-44396. It calculated the sum of the purchase
price and the operating expense--discounted over the lifetime of the
equipment--to estimate the range in LCC benefits that commercial
consumers would expect to achieve due to the new standards. DOE also
examined the economic justification for its proposed standards for
distribution transformers by applying section 325(o)(2)(B)(iii) of EPCA
(42 U.S.C. 6295(o)(2)(B)(iii)), which provides that 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, as calculated
under the applicable DOE test procedure. 71 FR 44388-44389. Some of the
standard levels DOE is adopting today satisfy the rebuttable
presumption test but others do not. However, DOE determined all of them
to be economically justified based on the above-described analyses.
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, DOE 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)) DOE used the
NES spreadsheet results in its consideration of total projected
savings. 71 FR 44361, 44363, 44380-44381, 44384, 44393, 44401.
4. Lessening of Utility or Performance of Equipment
In selecting today's standard levels, DOE avoided new standards for
distribution transformers that lessen the utility or performance of the
equipment under consideration in this rulemaking. (See 42 U.S.C.
6295(o)(2)(B)(i)(IV)) DOE sought to capture in the economic analysis
the impact of any increase in transformer size or weight associated
with efficiency improvements. Specifically when selecting the new
standards, DOE considered the installation costs for pole-mounted
transformers and vault transformers that may be incurred with larger,
heavier, more efficient transformers. 71 FR 44363, 44394. In addition,
DOE recognizes that underground mining transformers are subject to
unique and extreme dimensional constraints which impact the efficiency
and performance of these distribution transformers. Therefore, DOE is
establishing a separate product class for underground mining
transformers. In the future, DOE may consider establishing energy
conservation standards for underground mining transformers. DOE is not
setting a standard for underground mining transformers in today's final
rule, rather it is reserving a section and intends to develop analysis
that would establish an appropriate energy conservation standard for
underground mining transformers in the future. Finally, when selecting
today's standard, DOE carefully reviewed the results of an engineering
sensitivity analysis on primary winding voltages. This sensitivity
analysis considers higher primary voltages than those used in the
representative units studied in the engineering analysis. This
sensitivity analysis enables DOE to evaluate the impact on cost and
efficiency associated with the final rule TSLs. (see Section V.A.1.a in
this notice, and TSD Appendix 5D) Thus, the analysis in today's final
rule takes into consideration the additional costs associated with
space-constrained pole-mounted and vault transformers, and ensures that
higher primary voltages are not eliminated from the market. Based on
DOE's engineering analysis, DOE concludes that more efficient pole-
mounted and vault transformers are technologically feasible. However,
in some instances, DOE believes that transformer poles and vaults may
need to be replaced to accommodate the more efficient transformers as a
result of today's final rule. DOE included increased installation costs
of such pole-mounted and vault transformer in its analysis. In this
way, DOE has captured the costs and benefits of replacement pole-
mounted and vault transformers. Details of pole and vault replacement
cost estimation methods are provided in sections 7.3.1 and 7.3.5 of TSD
Chapter 7.
5. Impact of Any Lessening of Competition
DOE considers any lessening of competition that is likely to result
from standards. Accordingly, as discussed in the proposed rule, 71 FR
44363-44364, 44394, at DOE's request, the Department of Justice (DOJ)
reviewed the proposed standard level (i.e., the NOPR) and transmitted
to the Secretary a written determination of the impact of any lessening
of competition likely to result, 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)) DOE addressed the issues raised in the Attorney General's
response to the NOPR, as discussed in section VI.C.5 of today's final
rule. The letter DOJ submitted to DOE in response to the NOPR appears
at the end of this notice of final rulemaking.
Today's final rule, which follows publication of the NODA, adopts a
standard level that is higher than the standard proposed in the NOPR
for certain liquid-immersed distribution transformers. DOJ was provided
draft copies of the notice of final rulemaking and the final rule TSD
for review. The Attorney General did not express any concerns about
impacts associated with today's final rule. A copy of Attorney
General's letter to DOE in response to the final rule also appears at
the end of this notice of final rulemaking.
6. Need of the Nation To Conserve Energy
The Secretary recognizes that energy conservation benefits the
Nation in several important ways. The non-monetary benefits of a
standard are likely to be reflected in improvements to the security of
the Nation's energy system. In addition, reductions in the overall
demand for energy will result in reduced costs for maintaining
reliability of the Nation's electricity system. Finally, today's
standards will likely result in reductions in greenhouse gas emissions.
As discussed in the proposed rule, DOE has considered these factors in
adopting today's standards. 71 FR 44364, 44384, 44394-44395, 44398-
44400. (See 42 U.S.C. 6295(o)(2)(B)(i)(VI))

[[Page 58198]]

7. Other Factors
The Secretary of Energy, in determining whether a standard is
economically justified, considers any other factors the Secretary deems
to be relevant. (See 42 U.S.C. 6295(o)(2)(B)(i)(VII)) The results of
the utility impact analysis, and the analysis of national employment
impacts are ``other factors'' that the Secretary took into
consideration. In addition, for this rulemaking, the Secretary also
took into consideration stakeholder concerns 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, as discussed in the proposed rule. 71 FR 44364,
44395. Since issuance of the NOPR, DOE conducted two engineering
sensitivity evaluations--one considering current (2006) material prices
and a second considering transformers with alternative primary voltages
that have higher insulation requirements (and are therefore more
expensive and less efficient to manufacture). Also, as it had done in
the proposed rule, DOE conducted LCC sensitivities, evaluating
engineering analysis cost-efficiency curves generated using a high
material price scenario \9\ and a low material price scenario,\10\ and
other variable inputs in the LCC analysis. In selecting today's
standards, DOE also took into consideration the need to have
consistency in the efficiency requirements between single-phase and
three-phase liquid-immersed transformers. See section V.C.1 for
discussion on development of the final rule TSLs, including how single-
phase and three-phase consistency was maintained between the liquid-
immersed product classes.
---------------------------------------------------------------------------

\9\ The high material price scenario is based on using the year
with the highest material prices in the five-year sample (i.e., 2002
to 2006) of material prices updated for the final rule. In this
sample, the year with the highest overall material prices was 2006.
See TSD Chapter 5 for a discussion on material prices.
\10\ The low material price scenario is based on selecting the
year with the lowest M6 material price in the five-year sample
(i.e., 2002), and then applying a uniform 15 percent discount to all
the material prices from that year. See TSD Chapter 5 for a
discussion on material prices.
---------------------------------------------------------------------------

IV. Methodology and Discussion of Comments on Methodology

DOE used a number of analytical tools that it previously developed
and adapted for use in this rulemaking. The first tool is a spreadsheet
that calculates LCC and payback period (PBP). The second tool
calculates NES and national NPV. DOE also used the Government
Regulatory Impact Model (GRIM), among other methods, in its MIA.
Finally, DOE developed an approach using the National Energy Modeling
System (NEMS) to estimate impacts of distribution transformer energy
conservation standards on electric utilities and the environment.
Regarding the analytical methodology, DOE has continued to use the
spreadsheets and approaches explained in the proposed rule. 71 FR
44364-44384. It revised them, and applied them again to develop the
analysis for this final rule. The tables below summarize all the major
NOPR inputs to the LCC and PBP analysis, the Shipments Analysis and the
National Impact Analysis, and whether those inputs were revised for the
final rule. In addition to these updates, DOE also updated the material
prices it used for the engineering analysis, as discussed in TSD
Chapter 5.

Table IV.1.--Final Rule Inputs for the LCC and PBP Analyses
------------------------------------------------------------------------
Changes for
Inputs NOPR description final rule
------------------------------------------------------------------------
Affecting Installed Costs
------------------------------------------------------------------------
Equipment price............... Derived by multiplying No change.
manufacturer selling
price (from the
engineering analysis)
by distributor markup
and contractor markup
plus sales tax for
dry-type
transformers. For
liquid-immersed
transformers, DOE
used manufacturer
selling price plus
small distributor
markup plus sales
tax. Shipping costs
were included for
both types of
transformers.
------------------------------------------------------------------------
Installation cost............. Includes a weight- Added a case
specific component, with vault
derived from RS Means replacement
Electrical Cost Data costs as a
2002 and a markup to subgroup
cover installation analysis.
labor, pole
replacement costs for
design line 2 and
equipment wear and
tear.
Baseline and standard design The selection of No change in
selection. baseline and standard- percent of
compliant evaluators.
transformers depended Different
on customer behavior. values of
For liquid-immersed customer choice
transformers, the B parameter was
fraction of purchases estimated for
evaluated was 75%, small versus
while for dry-type large liquid-
transformers, the immersed
fraction of evaluated transformers.*
purchases was 50% for
small capacity medium
voltage and 80% for
large-capacity medium
voltage.
------------------------------------------------------------------------
Affecting Operating Costs
------------------------------------------------------------------------
Transformer loading........... Loading depended on Technical
customer and improvement was
transformer made for liquid-
characteristics. immersed
statistical
load model
where the 1995
Commercial
Building Energy
Consumption
Survey data was
used for load
factor
estimates.
------------------------------------------------------------------------
Load growth................... 1% per year for liquid- Adjusted to 0%
immersed and 0% per per year for
year for dry-type both liquid-
transformers. immersed and
dry-type.
Power factor.................. Assumed to be unity... No change.

[[Page 58199]]

Annual energy use and demand.. Derived from a No change.
statistical hourly
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- Adjusted
based and hourly electricity
based electricity prices for
prices. Capacity inflation.
costs provided extra
value for reducing
losses at peak.
Electricity price trend....... Obtained from Annual Updated to
Energy Outlook 2005 AEO2007.
(AEO2005).
Maintenance cost.............. Annual maintenance No change.
cost did not vary as
a function of
efficiency.
------------------------------------------------------------------------
Affecting Present Value of Annual Operating Cost Savings
------------------------------------------------------------------------
Effective date................ Assumed to be 2010.... No change.
Discount rates................ Mean real discount Discount rate
rates ranged from sensitivity
4.2% for owners of added to
pole-mounted, liquid- spreadsheet
immersed transformers tool.
to 6.6% for dry-type
transformer owners.
Lifetime...................... Distribution of No change.
lifetimes, with mean
lifetime for both
liquid and dry-type
transformers assumed
to be 32 years.
------------------------------------------------------------------------
Candidate Standard Levels
------------------------------------------------------------------------
Trial standard levels......... Six efficiency levels For liquid-
with the minimum immersed
equal to TP 1 and the transformers a
maximum from the most set of four
efficient designs recombinations
from the engineering of the NOPR
analysis. standard levels
Intermediate were formulated
efficiency levels for that have
each design line consistency
selected using a between single-
redefined set of LCC phase and three-
criteria.. phase
efficiency
levels
------------------------------------------------------------------------
\*\ 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.

Table IV.2.--Final Rule Inputs for the Shipments Analysis
------------------------------------------------------------------------
Changes for
Input NOPR description final rule
------------------------------------------------------------------------
Shipments data................ Third-party expert No change.
(HVOLT) for the year
2001.
Shipments backcast............ For years 1977-2003, No change.
used Bureau of
Economic Analysis'
(BEA) manufacturing
data for distribution
transformers. Source:
http://www.bea.doc.gov/bea/
For

years 1950-1976, used
EIA's electricity
sales data. Source:
http://www.eia.doe.gov/emeu/
.

Shipments forecast............ Years 2002-2035: Based Years 2010-2038:
on AEO2005. Based on
AEO2007.
Dry-type/liquid-immersed Based on EIA's Based on EIA's
market shares. electricity sales electricity
data and AEO2005. sales data and
AEO2007.
Regular replacement market.... Based on a survival No change.
function constructed
from a Weibull
distribution function
normalized to produce
a 32-year mean
lifetime. Source:
ORNL 6804/R1, The
Feasibility of
Replacing or
Upgrading Utility
Distribution
Transformers During
Routine Maintenance,
page D-1.
Elasticities, liquid-immersed. For liquid-immersed No change.
transformers.
Low: 0.00....
Medium: -0.04
High: -0.20..
Elasticities, dry-type........ For dry-type No change.
transformers.
Low: 0.00....
Medium: -0.02
High: -0.20..
------------------------------------------------------------------------

Table IV.3.--Final Rule Inputs for the National Impact Analysis
------------------------------------------------------------------------
Changes for
Input NOPR description final rule
------------------------------------------------------------------------
Shipments..................... Annual shipments from No change.
shipments model.
Implementation date of Assumed to be 2010.... No change.
standard.
Base case efficiencies........ Constant efficiency No change.
through 2035. Equal
to weighted-average
efficiency in 2010.
Standards case efficiencies... Constant efficiency at No change.
the specified
standard level from
2007 to 2038.

[[Page 58200]]

Annual energy consumption per Average rated No change.
unit. transformer losses
are obtained from the
LCC analysis, and are
then scaled for
different size
categories, weighted
by size market share,
and adjusted for
transformer loading
(also obtained from
the LCC analysis).
Total installed cost per unit. Weighted-average No change.
values as a function
of efficiency level
(from LCC analysis).
Electricity expense per unit.. Energy and capacity No change.
savings for the two
types of transformer
losses are each
multiplied by the
corresponding average
marginal costs for
capacity and energy,
respectively, for the
two types of losses
(marginal costs are
from the LCC
analysis).
Escalation of electricity AEO2005 forecasts (to Used AEO2007
prices. 2025) and forecasts (to
extrapolation for 2025) and
2038 and beyond. extrapolation
for 2038 and
beyond.
Electricity site-to-source A time series Updated
conversion. conversion factor; conversion
includes electric factors from
generation, NEMS.
transmission, and
distribution losses.
Conversion varies
yearly and is
generated by DOE/
EIA's National Energy
Modeling System
(NEMS) program.
Discount rates................ 3% and 7% real........ Results for 4.2%
reported in
TSD.
Analysis year................. Equipment and Equipment and
operating costs are operating costs
discounted to the are discounted
year of equipment to year 2006.
price data, 2004.
------------------------------------------------------------------------

A. Market and Technology Assessment

1. General
The methodology DOE followed in the market and technology
assessment was described in previous notices and is discussed in TSD
Chapter 3. This is the section of the analysis where DOE typically
discusses issues on the scope of coverage. DOE received a few comments
on this topic, including comments regarding mining transformers, less-
flammable liquid-immersed transformers, refurbished transformers, and
the waiver process. These comments are discussed in the following sub-
sections.
2. Mining Transformers
The definition of a distribution transformer and thereby the scope
of coverage of this rulemaking was finalized in the test procedure
final rule, published on April 27, 2006. 71 FR 24975-24982, 24995-
24997. In that notice, DOE indicated that comments supporting an
exclusion for mining transformers did not provide sufficient data and
information on mining transformers to warrant an exclusion or separate
treatment. 71 FR 24980-24981. In the August 2006 NOPR, DOE addressed
the issue of mining transformers in the preamble. DOE decided not to
exempt mining transformers under 42 U.S.C. 6291(35)(B)(iii)(I), noting
that DOE lacked specific information and data on whether these
transformers were likely to be used in general purpose applications or
whether significant energy savings would result from applying standards
to them. 71 FR 44365-44366.
a. Comments Requesting Exemption
DOE received several comments calling for mining transformers to be
exempt from any national efficiency standard. The Alaska Miners
Association (AMA), Arch Coal, Brooks Run Mining (BRM), Control
Transformer, Federal Pacific Transformer (FPT), HVOLT, NEMA, the
National Mining Association (NMA), the Ohio Valley Coal Company (OVCC),
Peabody Energy Corporation (PEC), PEMCO Corporation (PEMCO), and SMC
Electrical Products (SMC), all called for mining transformers to be
exempt from the national efficiency standard. These stakeholders
identified a number of reasons for this request, including safety,
minimal impact on energy savings, appropriateness of the representative
efficiency rating loading point, and lack of guidance in the test
procedure for measuring the efficiency of mining transformers that have
more than one secondary output connection. (AMA, No. 118 at p. 1; Arch
Coal, No. 115 at p. 1; BRM, No. 112 at p. 1; Control Transformer, No.
142 at p. 1; FPT, No. 102 at pp. 1-3; Public Meeting Transcript, No.
108.6 at p. 131; HVOLT, No. 141 at p. 5; NEMA, No. 125 at p. 3; NMA,
No. 116 at pp. 1-2; OVCC, No. 151 at p. 1; PEC, No. 146 at p. 1; PEMCO,
No. 130 at p. 2; SMC, No. 124 at pp. 1-2) FPT also submitted several
mining transformer designs they prepared to support its request to
exempt mining transformers from the standard. (FPT, No. 114 at pp. 1-
33) Howard Industries indicated that it would agree that mining
transformers should be exempted if such transformers are ``exactly
defined.'' (Howard, No. 143 at p. 5)
NMA and the Ohio Valley Coal Company (OVCC) commented that safety
was a concern and a reason for exempting mining transformers from
Federal efficiency standards. NMA commented that size constraints and
the need to move the transformers as the mining process advances
necessitate special designs. NMA also stated that DOE needs to consider
safety issues raised by the need to move transformers in mining
operations. (NMA, No. 116 at pp. 1-2) OVCC also noted the importance of
mining transformers being as small as possible, in part to prevent
safety problems as these transformers have to be moved frequently.
(OVCC, No. 151 at p. 1)
Stakeholders also commented on the fact that they did not believe
significant energy savings would result from DOE covering and
regulating mining transformers. (Arch Coal, No. 115 at p. 1) AMA
commented that mining transformers should be excluded based on the very
large impact on the cost of equipment that will be incurred under
standards and that this exclusion of mining transformers would have a
minimal impact on energy savings. (AMA, No. 118 at pp. 1-2) NEMA
commented that mining transformers account for considerably less than
one percent of all distribution transformers, and that they are part of
the medium-voltage, dry-type group of distribution transformers which
has far less significant energy savings opportunities than liquid-
immersed transformers. (NEMA, No. 125 at p. 3) Federal Pacific
estimated that, annually, the total market of mining transformers is
approximately 969.1 megavolt-amperes (MVA), or about 1.15 percent of
total

[[Page 58201]]

distribution transformer capacity. (FPT, No. 102 at p. 2) DOE notes
that 969.1 MVA of shipped capacity represents approximately 20 percent
of the medium-voltage, dry-type distribution transformer market, of
which mining transformers are a subset.
Arch Coal commented that mining transformers have large cores, and
thus higher core losses when compared to general purpose distribution
transformers. This puts mining transformers at a disadvantage for
achieving efficiency levels measured at 35 percent and 50 percent of
rated nameplate capacity. (Arch Coal, No. 115 at p. 1) SMC Electrical
Products commented that the smaller heights and lower-than-typical
impedance of mining transformers mean they contain more core steel and
have increased losses when measured at 50 percent of nameplate load.
(SMC, No. 124 at pp. 1-2) Control Transformer commented that mining
transformers are usually size constrained (normally in the height), and
therefore they have higher core losses than taller (standard)
transformers. The core loss constitutes a critical portion of the
efficiency rating, and may make the customer's dimensional constraints
difficult, if not impossible, to achieve. Control Transformer also
commented that very often impedance requirements are placed on these
transformers, which adds another constraint to the design. (Control
Transformer, No. 142 at p. 1) However, FPT commented at the workshop
that it is possible to make mining transformers more efficient without
sacrificing size. FPT notes that problems occur when the standard
levels become really high, but they believe there might be some
standard level that would be appropriate for mining transformers.
(Public Meeting Transcript, No. 108.6 at p. 253) FPT also commented
that mining transformers have different loading requirements than
typical distribution transformers, and their loading requirements are
dependent on the application. (Public Meeting Transcript, No. 108.6 at
pp. 245 and 255) HVOLT commented that mining transformers are used at
full load, and therefore may not be able to meet certain efficiency
levels, when measured at lower loading points. (Public Meeting
Transcript, No. 108.6 at p. 255) PEMCO Corporation estimates that
mining transformers have loading of 100 percent or better. (Public
Meeting Transcript, No. 108.6 at p. 255) However, one mining company,
OVCC, commented that its transformers are lightly loaded. It noted that
one of its mines has 30 mega-volt amperes (MVA) of dry-type transformer
capacity installed, but only has an electrical demand of 7 MVA--meaning
its transformers are lightly loaded and therefore would receive less
benefit from mandatory energy efficiency standards. (OVCC, No. 151 at
p. 1)
Finally, the Department of Justice (DOJ), commented that it was
concerned that the proposed standard level may adversely affect
competition with respect to distribution transformers used in
industries, such as underground coal mining. Consistent with
stakeholders commenting on the proposed rule, DOJ highlighted the
dimensional constraints imposed on mining transformers due to the
operating environments into which they are installed. DOJ is concerned
that these constraints contribute to higher costs than would otherwise
be associated with transformers not subject to the same dimensional
constraints. DOJ urged DOE to create an exception for distribution
transformers used in industries with space constraints. (DOJ, No. 157
at p. 2)
In comments requesting that DOE provide an exemption for mining
transformers, some comments referred simply to `mining transformers',
while other comments referred more specifically to `underground mining
transformers.' Considering the operating environments of these two
types of distribution transformers, DOE does not believe that those
transformers used in above-ground or open-pit mining operations are
subject to the same physical constraints as those transformers
installed in underground mining operations. DOE understands that both
underground and above-ground mining transformers are distribution
transformers,\11\ which serve a distribution function in the electrical
systems of the mines in which they operate. The critical difference
between these two types of transformers is that underground mining
transformers must be able to fit into a tight (i.e., dimensionally
constrained) space while above-ground mining transformers are designed
to operate on the surface, and thus are not required to be manufactured
to fit into a tunnel, shaft or other dimensionally constrained space.
Mining transformers used in above-ground mining operations have
considerably greater dimensional flexibility than transformers
installed in underground mining operations. Therefore, DOE considers
medium-voltage dry-type distribution transformers that are used in
above-ground mining operations to be medium-voltage dry-type
distribution transformers subject to the standards adopted by today's
rule.
---------------------------------------------------------------------------

\11\ The definition of the term `distribution transformer' is
discussed in TSD Chapter 3, section 3.2. The definition in the Code
of Federal Regulations (10 CFR section 431.192) is based on EPCA (42
U.S.C. 6291(35)(A)).
---------------------------------------------------------------------------

In the analysis for the proposed rule, DOE did not consider
underground mining transformers as a separate product class. Rather,
they were considered with all other medium-voltage dry-type
transformers. However, based on comments received, DOE recognizes that
underground mining transformers must comply with dimensional
constraints, design requirements, and safety considerations that are
different from those faced by other distribution transformers. DOE
concludes that underground mining transformers have a distinct utility
which limits the energy efficiency improvement potential possible for
such distribution transformers. While more efficient underground mining
transformers are technologically feasible, DOE does not have the data
needed to estimate either the energy efficiency improvement potential
or the cost of more efficient designs of underground mining
transformers. DOE reviewed the underground mining transformer designs
submitted (Federal Pacific, No. 114 at pp. 1-33) and the comments of a
mining transformer design engineer at the public meeting (Public
Meeting Transcript, No. 108.6 at p. 253), and believes that more
efficient underground mining transformer designs are technologically
feasible, but these comments didn't provide information on the extent
of improvement possible. Furthermore, none of the comments requesting
DOE exempt mining transformers provided an economic analysis
demonstrating that efficiency standards for such transformers would not
be cost-justified. Without engineering cost and efficiency data, DOE
was not able to perform an analysis of the impacts of standards on
underground mining transformers. Thus, DOE is not able to determine
whether energy conservation standards for underground mining
transformers are economically justified and would result in significant
energy savings. Based on the above, DOE concludes that underground
mining transformers are a class of medium-voltage dry-type distribution
standards, and since DOE cannot determine whether standards would meet
EPCA's statutory criteria, DOE is not setting standards for underground
mining transformers at this time.
In order that stakeholders understand which mining transformers are
subject to standards being promulgated today and which mining
transformers would

[[Page 58202]]

be subject to energy efficiency standards at some future date, DOE
incorporated into today's rule a definition for underground mining
distribution transformers. DOE received one comment from FPT with a
draft, proposed definition which read: ``Mining transformers shall be
considered to be installed underground in a mine, inside equipment for
use in mines or as a component of equipment used for underground
digging, tunneling or dredging operations. The nameplate shall identify
transformer for such use only.'' (FPT, No. 102 at p. 3) DOE considered
this definition, and researched technical sources for alternative
definitions, including IEEE and the Mine Safety and Health
Administration (MSHA), a division of the Department of Labor. Neither
the IEEE nor MSHA have a definition for an underground mining
distribution transformer. Based on consideration of the above comment,
DOE adopts the following definition for an underground mining
distribution transformer:

Underground mining distribution transformer means a medium-
voltage dry-type distribution transformer that is built only for
installation in an underground mine or inside equipment for use in
an underground mine, and that has a nameplate which identifies the
transformer as being for this use only.

DOE recognizes that this definition for underground mining
distribution transformers could be refined if DOE initiates a
rulemaking proceeding that evaluates energy conservation standards for
underground mining distribution transformers.
b. Mining Transformer Test Procedure Comments
Arch Coal commented that mining transformers often have more than
one secondary connection, and multiple options for secondary
connections, making it impossible to test using DOE's test procedure,
which provides no guidance for testing of multiple secondary
transformers. (Arch Coal, No. 115 at p. 1) SMC noted that DOE's test
procedure does not indicate how multiple winding transformers should be
loaded for the test. (SMC, No. 124 at pp. 1-2) FPT also noted that
mining transformers are normally designed with multiple secondary
windings at different kVA ratings. FPT indicated that DOE would need to
provide clarification in the test procedure on the appropriate overall
kVA rating and efficiency standard that would apply to these
transformers with multiple secondary windings. (FPT, No. 102 at pp. 1-
2)
DOE appreciates these comments and notes that while DOE's test
procedure contains a test method that can be used for transformers with
multiple secondary connections, it doesn't set the conditions for
testing such units. Based on comments received, DOE understands that
transformers with multiple secondary connections are used solely in
underground mining operations. Since underground mining transformers
are not subject to the standards adopted in today's final rule, DOE
doesn't need to amend its test procedures to address this issue at this
time. Before DOE establishes standards for underground mining
transformers, DOE will amend the test procedures to specify the testing
conditions for these units. DOE understands that the energy efficiency
of distribution transformers is generally related to kVA, and that
larger kVA units generally have a higher efficiency. DOE could, for
example, require that underground mining transformers be tested at the
secondary connection that yields the highest kVA value.
3. Less-Flammable, Liquid-Immersed Transformers
In the NOPR, DOE solicited comment on the issue of whether it
should include liquid-immersed distribution transformers that are less
flammable than most liquid-immersed models in the same product classes
as medium-voltage, dry-type transformers. In developing and presenting
the NOPR, DOE placed these less flammable liquid-immersed transformers
in product classes with other liquid-immersed models, separate from the
product classes for dry-type units (see TSD Chapter 3 for discussion on
product classes).
Cooper Power Systems commented that the less-flammable, liquid-
immersed transformers are used in the same applications as medium-
voltage, dry-type transformers and therefore should be held to the same
efficiency standards. (Public Meeting Transcript, No. 108.6 at p. 91;
Cooper, No. 154 at p. 2) Howard Industries commented that less-
flammable, liquid-immersed transformers should not be in the same
product class as medium-voltage, dry-type transformers. Howard agrees
that some less-flammable liquid-immersed transformers are used in some
of the same applications as medium-voltage dry-type transformers, but
many are used in applications that are not suitable for dry-type
transformers and therefore would not be competing against a less
efficient product. (Howard, No. 143 at p. 2)
DOE believes that the issue raised by Cooper and Howard is
essentially whether less-flammable, liquid-immersed transformers should
be treated as a separate class of liquid-immersed transformers and held
to the same standard as medium voltage dry-type transformers.
EPCA provides DOE direction for establishing product classes. (42
U.S.C. 6295(q)(1)) In general, when evaluating and establishing energy
efficiency standards, DOE classifies covered products into classes by:
(a) The type of energy used; or (b) the capacity or other performance-
related features that affect consumer utility or efficiency. In the
July 2004 ANOPR, DOE concluded that the design of the transformer
(i.e., dry-type or liquid-immersed) was a performance-related feature
which affects the energy efficiency of the equipment. 69 FR 45385.
Accordingly, DOE concludes that dry-type and liquid-immersed are
separate classes of transformers. Id. Furthermore, while less-
flammable, liquid-immersed transformers may have distinct applications
apart from other liquid-immersed transformers, DOE does not believe the
less-flammable cooling fluid affects the energy efficiency potential of
such transformers compared to liquid-immersed transformers using
mineral oil.\12\ DOE understands that, depending on the cooling fluid
used, less-flammable, liquid-immersed transformers can have the same
energy efficiency potential as mineral oil cooled liquid-immersed
transformers. (See TSD Section 5.3) Furthermore, DOE believes that all
less-flammable, liquid-immersed transformers can meet the standards
adopted today with any of the less-flammable cooling fluids currently
used. Thus, considering the above, DOE concludes that less-flammable,
liquid-immersed transformers have efficiency characteristics that are
similar to other liquid-immersed transformers and, therefore, is not
setting separate classes for less-flammable liquid-immersed
transformers. As a result, less-flammable, liquid-immersed transformers
must meet the same energy efficiency requirements as other liquid-
immersed transformers.
---------------------------------------------------------------------------

\12\ Currently, mineral oil is the standard cooling fluid used
in liquid-immersed distribution transformers.
---------------------------------------------------------------------------

4. Rebuilt or Refurbished Distribution Transformers
In the August 2006 NOPR, DOE requested comment on its treatment of
rebuilt or refurbished transformers and the potential impact on
consumers, manufacturers, and national energy use

[[Page 58203]]

if these transformers were not covered by the standard. In the NOPR,
DOE expressed doubt that its authority under EPCA extends to rebuilt or
refurbished products or equipment. 71 FR 44366-44367. It also noted
that throughout the program's history, DOE has not sought to regulate
``used'' products that had been reconditioned or undergone major
repairs. 71 FR 44367. However, DOE acknowledged that it could be argued
that rebuilt transformers are ``manufactured'' again when they are
rebuilt, and, therefore, under this argument, they could be classified
as new distribution transformers subject to standards.
DOE received numerous comments on the topic of rebuilt and
refurbished transformers, reflecting a diverse range of views on this
issue. The American Council for an Energy-Efficient Economy (ACEEE),
BBF & Associates (BBF), and the Copper Development Association (CDA)
all recommended that DOE cover and regulate rebuilt transformers.
(ACEEE, No. 127 at p. 10; BBF, No. 122 at p. 2; CDA, No. 111 at p. 2)
ERMCO, FPT, Howard Industries, HVOLT, NEMA, and NRDC all recommended
that DOE cover and regulate both rebuilt and refurbished transformers.
(ERMCO, No. 96 at p. 2; FPT, No. 102 at p. 3; Public Meeting
Transcript, No. 108.6 at p. 90; Public Meeting Transcript, No. 108.6 at
p. 82; Howard, No. 143 at p. 2; Public Meeting Transcript, No. 108.6 at
pp. 47, 80, and 87; HVOLT, No. 144 at p. 4; NEMA, No. 125 at p. 3;
Public Meeting Transcript, No. 108.6 at p. 81; NRDC, No. 117 at p. 12)
ACEEE suggested regulating rebuilt transformers through a phased-in
approach where rebuilt transformers become covered and regulated at a
later time. (ACEEE, No. 127 at p. 10) NRDC commented that if DOE
determines it does not have the authority under the current rule to
regulate remanufactured transformers, then it should establish a new
product class (remanufactured transformers) to regulate. NRDC
encouraged DOE to regulate refurbished transformers, perhaps on the
basis of organizing an informal, inclusive, consensus-seeking process.
(Public Meeting Transcript, No. 108.6 at p. 81; NRDC, No. 117 at p. 12)
NEMA commented that it believes DOE should establish, in its final
rule, a mechanism to monitor whether rebuilt or refurbished
transformers are being used as a means to circumvent the efficiency
standard, and stated that DOE should consider covering and regulating
such units, if necessary. (NEMA, No. 125 at p. 3) The California Energy
Commission (CEC) commented that it believes if a transformer is resold
into the marketplace, then it can be regulated. However, if it is
remanufactured internally, the standard would not apply. (Public
Meeting Transcript, No. 108.6 at p. 82)
The Edison Electric Institute (EEI) supported DOE's proposal not to
include used or refurbished transformers as part of the standard. EEI
stated that EPCA does not include products that are used, refurbished,
or rebuilt. It commented that any concern that customers will repair a
product instead of buying a new, standards-compliant product applies to
all regulated products, not just transformers. Furthermore, EEI noted
that rebuilt transformers are only a small part of the market. (Public
Meeting Transcript, No. 108.6 at p. 79) National Grid commented that it
believes national standards should not apply to refurbished or rebuilt
transformers. (NGrid, No. 138 at p. 2) Southern Company commented that
it agrees DOE does not have the authority to regulate refurbished
transformers. (Public Meeting Transcript, No. 108.6 at p. 64)
DOE has carefully considered its authority to establish energy
conservation standards for rebuilt and refurbished distribution
transformers in light of these comments, and, as discussed below,
concludes that its authority does not extend to rebuilt and refurbished
products. The relevant statutory provisions are discussed below, as
well as the agency's rationale in reaching this conclusion.
Section 332 of EPCA provides that it shall be unlawful for any
manufacturer or private labeler to distribute in commerce any new
covered product which is not in conformity with an applicable energy
conservation standard. (42 U.S.C. 6302(a)(5) (emphasis added)) \13\
Congress made section 332 applicable to distribution transformers in
section 346(f)(1) of EPCA. (42 U.S.C. 6317(f)(1)) Section 332(b)
defines ``new covered product'' to mean ``a covered product the title
of which has not passed to a purchaser who buys such product for
purposes other than (1) reselling such product, or (2) leasing such
product for a period in excess of one year.'' (42 U.S.C. 6302(b)) That
is, a new covered product is one for which the title has not passed to
a consumer.\14\
---------------------------------------------------------------------------

\13\ DOE only regulates equipment that is either specifically
enumerated as ``covered equipment'' or is equipment for which DOE
has been granted authority to regulate in another statutory
provision. Section 346 of EPCA (42 U.S.C. 6317) grants DOE authority
to regulate distribution transformers, without including the
specific language designating them as ``covered equipment.'' The
failure to include the words ``covered equipment'' in Section 346 of
EPCA or to include distribution transformers in Section 340 of EPCA,
which lists the covered equipment in Part C, does not mean that
distribution transformers will not be treated as ``covered
equipment'' for purposes of DOE exercising its regulatory authority.
\14\ In the context of this discussion, the term ``consumer'' is
used to identify a product's end user; e.g., ``consumer'' does not
include a party that takes title of a product solely for the purpose
of resale or for leasing the product for less than a year.
---------------------------------------------------------------------------

DOE believes that the definition of ``new covered product'' in
section 332 is ambiguous on the question of whether a rebuilt or
refurbished distribution transformer is subject to DOE's authority to
set energy conservation standards. On this point, DOE notes that
section 332 does not expressly provide that ``new covered product''
means a new product the title of which is transferred by the original
manufacturer to an original owner. Conversely, the definition of ``new
covered product'' does not expressly exclude substantially
remanufactured products that are subsequently resold (i.e., a product
sold or disposed of by the original owner that is rebuilt or
refurbished by an entity which resells it to another person). In order
to resolve this ambiguity regarding DOE's authority to regulate rebuilt
and refurbished distribution transformers, DOE considered both
congressional intent and the nature of the existing distribution
transformer market.
There is no legislative history that reflects Congress's intent.
However, DOE views the way Congress chose to define ``new covered
product'' in EPCA as the strongest indicator that the term was not
intended to apply to rebuilt or refurbished products. Specifically, it
is unlikely that Congress would have made transfer of ``title'' the
test of whether a product was ``new'' if it intended to cover rebuilt
or refurbished products. The most reasonable interpretation of the
statutory definition is that Congress intended that this provision
apply to newly manufactured products the title of which has not passed
for the first time to a consumer of the product. Such interpretation
provides certainty and clarity for the regulated entities subject to
these statutory provisions.
In addition, if DOE were to interpret ``new covered product'' as
applying to other than newly manufactured products EPCA's testing and
labeling provisions would be much harder to implement and enforce.
Identifying ``manufacturers'' under such an interpretation likely would
be difficult \15\ and it also likely would be

[[Page 58204]]

difficult for DOE to distinguish between rebuilt products that are not
covered and those products that were so extensively rebuilt as to be
considered ``new'', and therefore subject to these provisions.
---------------------------------------------------------------------------

\15\ For example, a business that rebuilds or remanufactures
products, instead of reselling them and transferring title, could
operate as a repair facility for consumers who already own the used
products. The business would simply rebuild the product for a fee
and return it to the owner; there would be no transfer of title.
---------------------------------------------------------------------------

In terms of the existing distribution transformer market, DOE
understands that rebuilt and refurbished transformers typically are
either: (1) A product sold by the original manufacturer or private
labeler, which after purchase by a consumer, is then modified and
resold by another party; or (2) a product that following purchase by a
consumer is modified and retained by that consumer. For the above-
stated reasons, DOE concludes that rebuilt and refurbished distribution
transformers are not ``new covered products'' under EPCA, and
therefore, are not subject to DOE's energy conservation standards or
test procedures.\16\ With respect to the first scenario, upon transfer
of the title of the distribution transformer to the consumer, the
distribution transformer is no longer a new covered product, therefore,
not subject to DOE regulations even if it is subsequently re-sold.
Similarly, with respect to distribution transformers that are
refurbished or rebuilt for or by the consumer (i.e., they are not re-
sold), DOE lacks authority over those transformers because they are
neither ``new'' covered products nor distributed in commerce.
Furthermore, if refurbished or rebuilt transformers that are sold to
another party were covered but not those that are refurbished or
rebuilt for the consumer, DOE believes this would likely create an
inequity that Congress would not have intended since a purpose of EPCA
was to establish a single national standard, not multiple standards for
the same product.
---------------------------------------------------------------------------

\16\ DOE notes that de minimis use of used or recycled parts
would not make a ``new product'' into a used product.
---------------------------------------------------------------------------

As discussed above, for distribution transformers in particular,
DOE understands that at present, rebuilt transformers are only a small
part of today's market. If conditions change--for example, if rebuilt
transformers become a larger share of the transformer market in
response to the energy conservation standards adopted today (e.g.,
there is a significant increase in the purchase of rebuilt or
refurbished transformers), DOE would consider appropriate action at
that time.
5. Uninterruptible Power System Transformers
The Energy Policy Act of 2005 (EPACT 2005) exempted
``Uninterruptible Power System transformer'' from the definition of
``distribution transformer.'' (42 U.S.C. 6291(35)(B)(ii)) DOE indicated
when it adopted the EPACT 2005 efficiency requirements for low-voltage
dry-type distribution transformers that it believed the name of this
exemption contained a clerical error. 70 FR 60408 (October 18, 2005).
DOE stated in the October 2005 final rule notice that it intended to
make corrections where necessary to the statutory language, and gave
the following example: ``the definition of ``distribution transformer''
in section 135(a)(2)(B) of EPACT 2005 uses the term ``Uninterruptible
Power System transformer'' instead of ``Uninterruptible Power Supply
transformer.'' DOE later codified the name change of UPS from
``System'' to ``Supply'' in the distribution transformer test procedure
final rule, and it noted ``DOE is amending its definition of
distribution transformer to correct use of * * * UPS transformers
[which] are commonly referred to as ``Uninterruptible Power Supply
transformers,'' not ``Uninterruptible Power System transformers.'' 71
FR 24977 (April 27, 2006).
In the April 2006 final rule notice, DOE also adopted the following
definition of an ``uninterruptible power supply transformer'':
``Uninterruptible Power Supply transformer means a transformer that
supplies power to an uninterruptible power system, which in turn
supplies power to loads that are sensitive to power failure, power
sags, over voltage, switching transients, line noise, and other power
quality factors.'' 71 FR 24997; 10 CFR section 431.192. This
definition, matches the definition of ``Uninterruptible Power Supply
transformer'' as published in NEMA TP 2-2005 ``Standard Test Method for
Measuring the Energy Consumption of Distribution Transformers.''
In a comment submitted to DOE in this rulemaking, NEMA expressed
its concern that DOE's revision of the term used for this exemption and
the definition of the term, had introduced some confusion as to the
applicability of this exemption. (NEMA, No. 174 at p. 2) NEMA requests
that DOE change the name of this exemption from ``Uninterruptible Power
Supply transformer'' back to the original name, as it appeared in EPACT
2005--``Uninterruptible Power System transformer.'' (NEMA, No. 174 at
p. 2) NEMA also asked that DOE revise the definition associated with
uninterruptible power system transformers, to clarify that the
exemption applies to transformers incorporated into uninterruptible
power systems rather than supplying power to them. (NEMA, No. 174 at p.
2)
In the rulemaking in which it codified the exclusion of
``Uninterruptible Power Supply transformer'' from the definition of
``distribution transformer,'' DOE received no comments about either the
exclusion or use of this term or DOE's definition of the term. In the
supplemental notice of proposed rulemaking (SNOPR) in which it had
proposed the exclusion, DOE stated that ``an uninterruptible power
supply transformer is not a distribution transformer'' and that ``[i]t
is used as part of the electric supply system for sensitive equipment
that cannot tolerate system interruptions or distortions, and
counteracts such irregularities.'' 69 FR 45505, 45512 (July 29, 2004).
DOE sees no reason to modify the term ``Uninterruptible Power Supply
transformer'' in its regulations, or to completely revise its
definition of this term. Nonetheless, DOE recognizes that, in
characterizing an uninterruptible power supply transformer as one that
``supplies power to'' an uninterruptible power system, 10 CFR 431.192,
DOE's definition may be confusing and slightly inconsistent with its
description in the SNOPR of this type of transformer. Therefore, to
make the definition consistent with its expressed intent in the SNOPR,
to which there was no objection, in today's rule DOE is clarifying its
definition of ``Uninterruptible Power Supply transformer'' by replacing
the phrase ``supplies power to'' with ``is used within.'' This
modification does not expand or reduce the intended group of
Uninterruptible Power Supply transformers that DOE wishes to exempt
from its standard. Rather, this change provides greater clarity of the
scope of this exemption.

B. Engineering Analysis

For the engineering analysis, which established the relationship
between cost and efficiency for certain distribution transformer kVA
ratings considered in this rulemaking, DOE continued to use transformer
design software developed for the rulemaking by Optimized Program
Service (OPS). DOE verified the findings of this software by comparing
designs during manufacturer interviews, and through a testing and
teardown analysis of six transformers. Chapter 5 of the TSD contains
detailed discussion on the

[[Page 58205]]

methodology followed for the engineering analysis.

C. Life-Cycle Cost and Payback Period Analysis

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, DOE 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. DOE 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 are the equipment price and the installation cost, with
appropriate markups to reflect price increases as the transformer
passes through the distribution channel. The inputs to the operating
costs are 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 DOE analyzed, the LCC analysis required
input data for the total installed cost of the equipment, the operating
cost, and the discount rate. 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.
The following sections contain brief discussions of comments on the
inputs and key assumptions of DOE's LCC analysis and explain how DOE
took these comments into consideration.
1. Inputs Affecting Installed Cost
a. Installation Costs
Higher efficiency distribution transformers tend to be larger and
heavier than less efficient designs. DOE therefore included the
increased cost of installing larger, heavier transformers as a
component of the first cost of more efficient transformers. In the
NOPR, DOE presented the installation cost model and solicited comment
from stakeholders. For details of the installation cost calculations,
see TSD section 7.3.1.
In response to both the NOPR and the NODA, many stakeholders
commented that it is important for DOE to take into consideration the
costs and reliability impacts of installing transformers in space-
constrained situations. ACEEE recommended that DOE factor into its
calculations space-constraint costs, based on the percentage of
transformers that will necessitate modification of the vaults in which
they are installed and the average cost for such modifications. (Public
Meeting Transcript, No. 108.6 at pp. 130-131) EEI noted that DOE's
analysis should include a space occupancy factor, although it might be
hard to estimate. (Public Meeting Transcript, No. 108.6 at p. 129) In
addition, EEI expressed concern regarding size and weight implications
for the reliability and cost of the transformer, especially for TSL4,
noting that, for pole-mounted transformers, more weight will increase
the stress on poles and noting that manufacturers doubt that they can
produce all equipment needed at TSL4. (Public Meeting Transcript, No.
108.6 at p. 31) HVOLT recommended that the analysis account for volume
and weight in a mathematical equation to account for space occupancy
costs. (Public Meeting Transcript, No. 108.6 at p. 129) NEMA commented
that, with higher standards, manufacturers may use lower quality steel
and switch from copper to aluminum, and that this may increase the
weight and/or size of transformers. (Public Meeting Transcript, No.
108.6 at p. 132) Metglas commented that transformers are smaller and
lighter than those made 30-40 years ago, and stated that there will not
be an issue with size and weight of amorphous core transformers.
(Metglas, No. 144 at p. 3)
DOE responded to the comments raised regarding space-constraint
implications for installation costs by formulating a method and a cost
equation for estimating the economic impacts of space constraints and
issuing a NODA that solicited comments on the method and equations
proposed for evaluating such costs. 72 FR 6186-6190. DOE then performed
a subgroup analysis of space-constrained vault transformers, for which
DOE modeled potential standards-induced vault modification costs with
an appropriate equation that included both fixed and volume-dependent
variable components. The results of this analysis are detailed in
Chapter 11 of the TSD, and DOE took these costs into consideration in
the selection of the standard level for this rule.
b. 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
(i.e., whether they ``evaluate''), 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.
DOE received several comments regarding the fraction of transformer
purchasers that evaluate distribution transformer electrical losses
before purchase and how transformer purchasers evaluate these losses.
HVOLT estimates that 20 percent of the market for medium-voltage, dry-
type transformers evaluates and places a value of $3.00/watt on loss
evaluation, while the market share of transformers meeting TP 1 levels
for liquid-immersed transformers is 75 to 80 percent. (Public Meeting
Transcript, No. 108.6 at p. 216) NEMA commented that 10 years ago there
was a trend where customers bought cheaper and less efficient
transformers every year due to less loss evaluation, but that the
market has turned around and now an increasing percentage of customers
are buying the more efficient TP 1 transformers. NEMA also noted that
the shipments data it has submitted over the years to DOE have shown
this changing trend. (Public Meeting Transcript, No. 108.6 at p. 220;
NEMA, No. 125 at p. 3)
In response to these comments, DOE developed its baseline market
model using the most detailed and reliable data available. This
included data that NEMA supplied providing TP 1 transformer market
shares, in addition to publicly available data regarding evaluation
parameters used by distribution transformer purchasers. For the final
rule, DOE set average A and B values of 3.85 and 1.16 $/watt
respectively for design lines 1, 2 and 4, and average A and B values of
3.85 and 1.93 $/watt for design lines 3 and 5. These slight adjustments
to the

[[Page 58206]]

evaluation parameters for the small transformers (i.e., design lines 1,
2, and 4) versus the large transformers (i.e., design lines 3 and 5)
were made because these two types of transformers have different load
profiles, which necessitate different loss valuations. DOE determined
the loss valuation variation for small versus large transformers
through its analysis of publicly available data on loss valuations
which indicated differences as a function of transformer capacity.
Estimation of the A and B values is discussed in detail in TSD Chapter
8, section 8.3.1.
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 with the square of the loading, there is a particular
concern that, during times of peak system load, load losses can impact
system capacity costs and reliability. For the final rule, DOE made a
slight technical adjustment to the loading model for liquid-immersed
transformers by relying on the more comprehensive 1995 Commercial
Building Energy Consumption Survey data for the relationship between
peak and average loads as a function of transformer size rather than
the older, regionally specific End-Use Load and Consumer Assessment
Program data used in the NOPR analysis. TSD Chapter 6 provides details
of DOE's transformer loading models.
Stakeholders appeared to generally agree with DOE's technical
approach to evaluating loading, although HVOLT commented that DOE
should mathematically evaluate the loading of single-phase and three-
phase transformers the same way. (Public Meeting Transcript, No. 108.6
at p. 151)
Because of greater load diversity and based on an analysis of
building load data described in Chapter 6 of the TSD, DOE generally
estimated the loading on larger transformers as greater than the
loading for smaller transformers, although DOE did in this rule set
efficiency levels for single-phase and three-phase transformers as
equal when the capacity per phase for the two different types of
transformers is equal.
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 (i.e., load growth). In the NOPR
analysis, for dry-type transformers, DOE assumed no load growth, while
for liquid-immersed transformers, DOE used as the default scenario a
one-percent-per-year load growth. It applied the load growth factor to
each transformer beginning in 2010, the expected effective date of the
standard. To explore the LCC sensitivity to variations in load growth,
DOE included in the model the ability to examine scenarios with zero
percent, one percent, and two percent load growth. Load growth is
discussed in detail in TSD Chapter 8, section 8.3.6.
DOE received substantial comment regarding its load growth
assumptions. CDA commented that it is entirely reasonable to deduce
that peak power per dwelling increases, and thus transformer loading
also increases over time, as people add home theaters, home offices,
appliances, and air conditioning to existing dwellings. (CDA, No. 111
at p. 2) EEI commented that load growth on transformers may be from
zero to half of a percent per year. (Public Meeting Transcript, No.
108.6 at pp. 147-148) HVOLT commented that after transformers are
installed in a residential area with a complement of houses, the load
basically stagnates. (Public Meeting Transcript, No. 108.6 at p. 145)
Pacific Gas and Electric (PG&E) commented that it assumes three percent
growth over the total 30 year life of a transformer corresponding to a
growth rate of one tenth of one percent per year. (Public Meeting
Transcript, No. 108.6 at pp. 149-150) Southern Company commented that,
for the transformer installed in the field, it sees no significant
growth once a transformer is installed. (Public Meeting Transcript, No.
108.6 at p. 144)
For the final rule, DOE responded to comments by examining more
recent data relevant to customer load growth. Since AEO forecasts
indicate that energy use per capita will be approximately constant over
time due to trends of increasing end-use efficiency, DOE set the load
growth parameter for the main analysis scenario as zero percent per
year for both dry-type and liquid-immersed transformers. However, DOE
retained the one-percent-per-year load growth scenario as a sensitivity
analysis.
c. Electricity Costs
DOE needed estimates of electricity prices and costs to place a
value on transformer losses for the LCC calculation. DOE created two
sets of electricity prices to estimate annual energy expenses for its
analysis: 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).
DOE received a few comments regarding electricity cost estimation.
HVOLT estimated that generation costs of electricity have been in the
four to six cents per kilowatt-hour (kWh) range. (Public Meeting
Transcript, No. 108.6 at p. 197) ACEEE commented that roughly half the
cost of electricity is due to generation, while the other half is
transmission and distribution and other expenses. (Public Meeting
Transcript, No. 108.6 at p. 204) Southern Company commented that DOE's
hourly marginal electricity price model looks conceptually correct, but
that there are many variables and it is possible to argue about every
one of them (Public Meeting Transcript, No. 108.6 at pp. 205-206).
DOE compared these comments with the estimates of its electricity
cost model and determined that these comments and suggestions were
consistent with the electricity cost model and estimates in the NOPR
analysis. DOE therefore used the same cost model for the final rule
with minor adjustments to take into account inflation and more recent
data. Electricity cost estimates are discussed in detail in TSD Chapter
8, section 8.3.5.
d. Electricity Price Trends
For the relative change in electricity prices in future years, DOE
relied on price forecasts from the Energy Information Administration
(EIA) Annual Energy Outlook (AEO). For the NOPR, DOE used price
forecasts from the AEO2005. The application of electricity price trends
in the final rule analysis is discussed in detail in TSD Chapter 8,
section 8.3.7.
In response to the NOPR, DOE received a large number of comments
regarding electricity price forecasts. ACEEE recommended that DOE look
at a range of forecasts, since EIA seems to be at the low end of the
range. (Public Meeting Transcript, No. 108.6 at p. 203) In its written
comments, ACEEE asked that, at a minimum, DOE use projections from AEO
2007, and suggested that DOE use the average of a basket of forecasts.
(ACEEE, No. 127 at p. 3) EMS Consulting, the Northwest Power and

[[Page 58207]]

Conservation Council (NPCC), and NRDC also recommended that DOE use a
wider range of price forecasts. (Public Meeting Transcript, No. 108.6
at pp. 199-210) CDA commented that electricity prices will not be
declining in future years since shortcomings in the generation and
transmission systems will become apparent. (CDA, No. 111 at p. 2) EEI
commented that DOE did a reasonable job, based on the information in
its NOPR TSD, and that in some years electricity prices actually go
down in real terms. (Public Meeting Transcript, No. 108.6 at pp. 201
and 211) HVOLT commented that it expects prices to increase at a
stable, even keel over the next 20 years. (Public Meeting Transcript,
No. 108.6 at p. 210)
For the final rule, DOE updated the price forecast to AEO2007 and
examined in increased detail the sensitivity of analysis results to
changes in electricity price trends and other parameters. Appendix 8D
of the TSD provides an expanded sensitivity analysis for all five
liquid-immersed transformer design lines and the medium-voltage dry-
type with the largest volume of transformer capacity shipments in the
market, DL12. This analysis shows that the effect of changes in
electricity price trends, compared to changes in other analysis inputs,
is relatively small. DOE evaluated a variety of potential
sensitivities, and the robustness of analysis results with respect to
the full range of sensitivities, in weighing the potential benefits and
burdens of the final rule.
e. Natural Gas Price Impacts
Even though distribution transformers use electricity rather than
natural gas for their energy supply, several comments expressed
concerns that DOE's NOPR analyses might be neglecting indirect energy
impacts of standards on natural gas demand and prices. The Alliance to
Save Energy (ASE) commented that the natural gas market is extremely
tight primarily due to increased use of natural gas to produce
electricity, and this has led to incredible volatility in prices.
(Public Meeting Transcript, No. 108.6 at p. 59) The American Chemistry
Council (ACC) asked DOE to consider the impacts on the natural gas
market in selecting the final standard. (ACC, No. 132 at p. 2) Dow
Chemical Company commented that, if DOE considers the impact of
standards on the U.S. natural gas market and prices, then higher levels
can be further substantiated. (Dow Chemical, No. 129 at pp. 1-2) NRDC
commented that energy efficiency in transformers can bring down natural
gas prices by reducing the demand on gas as a generation fuel. It
further commented that this can have a major benefit in reducing
natural gas prices to all users, not merely users of transformers.
(Public Meeting Transcript, No. 108.6 at p. 57; NRDC, No. 117 at p. 7)
DOE examined the potential size of the impact of distribution
transformer standards on natural gas demand in its updated utility
impact analysis, and reported the impact of the standard by generation
type in Chapter 13 of the TSD. DOE performed the updated analysis based
on AEO2006,\17\ which includes a forecast of relatively high natural
gas prices compared to earlier DOE forecasts. (See TSD Chapter 13) In
this utility impact forecast with high natural gas prices, most of the
electricity saved from the standard comes from coal-generated
electricity. In addition, DOE's hourly marginal price analysis already
incorporates the impact of volatile and high marginal natural gas
prices in the marginal price of electricity that DOE uses in its
analysis. One way that changes in demand can impact average prices in a
market as a whole is when the marginal demand of a commodity does not
pay the full marginal cost of supply; then prices in the market as a
whole must rise to balance costs in the market as a whole. In DOE's
analysis of electricity prices for distribution transformers, DOE
attempted to include the full marginal cost of supply for electricity
including the effect of high, volatile natural gas prices by using
volatile real-time electricity prices. Real-time electricity prices are
strongly influenced by the real-time marginal cost of natural gas when
gas turbines are supplying electricity to the market. Since DOE already
includes the effect of volatile marginal natural gas prices in its
electricity price analysis through real-time electricity prices, and
since a relatively small fraction of the electricity saved over the
long term is forecast from natural gas generation, DOE did not give
additional consideration to the impact on natural gas prices in this
rulemaking.
---------------------------------------------------------------------------

\17\ While the AEO2007 electricity price forecast data was
available in time for preparation of this final rule, the full
AEO2007 forecast was not available at the time DOE performed the
utility and environmental impact analysis. DOE therefore used
AEO2006 for the utility and environmental analysis. Following
completion of the utility and environmental analysis and after the
full AEO 2007 became available, DOE compared the AEO2006 and AEO2007
and found the forecasts of electricity prices, the marginal
generation mix and emissions factors in the AEO2007 and AEO2006
forecasts were very similar. The two forecasts provide the same
marginal fractions of coal and natural gas generation (within 3.5%),
and have marginal CO2 emission factors that differ by
less than 2%.
---------------------------------------------------------------------------

3. Inputs Affecting Present Value of Annual Operating Cost Savings
a. Standards Implementation Date
In the August 2006 NOPR, DOE proposed that the standards for
distribution transformers apply to all units manufactured on or after
January 1, 2010. 71 FR 44407. DOE calculated the LCC for customers as
if each new distribution transformer purchase occurs in the year
manufacturers must comply with the standard.
Some stakeholders suggested that DOE could implement a two-tier
standard with two effective dates. In response to the NODA, a group of
stakeholders consolidated their comments by creating a joint proposal
in this regard. ACEEE, NRDC, EEI, ASE, the American Public Power
Association (APPA), the Appliance Standards Awareness Project (ASAP),
and the Northeast Energy Efficiency Partnerships (NEEP) recommended in
their joint proposal that DOE adopt TSL2 in 2009 and TSL4 in 2013.
(Joint Comment) They recommended the delay in implementation of TSL4 so
that technical manufacturing problems could be addressed. (Joint
Comment, No. 158 at p. 2) On July 30, 2007, DOE received a letter from
two Senators urging DOE to adopt the Joint Comment.\18\ (Bingaman and
Domenici, No. 191 at p. 1) Howard commented that it is strongly opposed
to moving the effective date of the standard to January 1, 2009,
because it will need to perform an enormous amount of engineering and
design work to meet the new levels. (Howard, No. 180 at p. 4) NEMA
commented that it does not believe the proposed compliance date of
January 1, 2009 for TSL2 is achievable because transformer designs are
already in development now for delivery after January 1, 2009. NEMA
requests that the compliance date be moved to January 1, 2010. (NEMA,
No. 174 at p. 2) Southern Company commented that it supports a two-
tiered standard of TSL2 in 2009 and TSL4 in 2013 with a technical
conference in 2010 to make any necessary adjustments to the year 2013
level. (Southern, No. 178 at p. 1, 9)
---------------------------------------------------------------------------

\18\ Letter from Senator Jeff Bingaman and Senator Pete
Domenici, to Samuel Bodman, Secretary of Energy (July 30, 2007).
---------------------------------------------------------------------------

DOE rejects the two-tiered approach with TSL4 as the level of the
second tier for two reasons: DOE found that TSL4 is not economically
justified as described in section VI.1.d of this notice, and therefore
rejected TSL4. Second, DOE does not have the authority to amend
standards outside a

[[Page 58208]]

rulemaking proceeding.\19\ If DOE were to set a two-tier standard, with
one tier at TSL4, DOE would not be able to roll it back at a later date
because of the anti-backsliding provision of EPCA. DOE is expressly
prohibited from lowering standards once they have been established. (42
U.S.C. 6295 (o)(1), Natural Resources Defense Council v. Abraham, 355
F. 3d 179, 195-197 (2nd Cir. 2004)) Accordingly, DOE rejects the
proposal to adopt a two-tiered approach with potential to amend the
standard during a technical conference and, instead is adopting a set
of energy conservation standards with an implementation date of January
1, 2010, in today's final rule.
---------------------------------------------------------------------------

\19\ DOE's authority to set standards for distribution
transformers, by rulemaking, is set forth in 42 U.S.C. 6317(a)(2).
DOE is required to follow the procedures in 42 U.S.C. 6295(p) for
this rulemaking proceeding. (42 U.S.C. 6316(a))
---------------------------------------------------------------------------

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. DOE estimated a
statistical distribution of commercial consumer discount rates that
varied by transformer type by calculating the cost of capital for the
different types of transformer owners (see TSD Chapter 8).
In response to the NOPR, DOE received specific comments regarding
its methods for calculating discount rates. EEI commented that some
utility companies may have lower credit ratings due to rate decisions
that can increase the cost of capital to between 7 and 12 percent real.
(Public Meeting Transcript, 108.6 at pp. 123-124) NRDC made a number of
specific comments regarding the parameters DOE used in its equation to
estimate the cost of capital, suggesting that DOE erred in estimating
the reference risk-free discount rate, and in estimating average values
of inflation and cost of equity capital. (NRDC, No. 117 at pp. 8-9)
DOE has a two-step approach in calculating discount rates for
analyzing consumer economic impacts. The first step is to assume that
the actual consumer cost of capital approximates the appropriate
consumer discount rate. The second step is to use the use the capital
asset pricing model (CAPM) to calculate the equity capital component of
the consumer discount rate. Neither stakeholder disagreed with DOE's
general approach of estimating consumer discount rates from the cost of
capital. NRDC asserted that DOE was using incorrect parameters when it
calculated the consumer cost of equity capital with the CAPM. DOE uses
information from the Federal Reserve when it determines which
parameters are correct for use in the CAPM. The Federal Reserve
solicited input in 2005 from a range of stakeholders specifically on
how to perform CAPM cost of capital calculations and considered input
from a range of stakeholders in determining the best parameter values
to use in the CAPM. 70 FR 29512-29526 (May 23, 2005). Specifically, DOE
rejects NRDC's assertion that the long-term average of the rate of
return on short-term Treasury notes is the only correct way to
calculate the risk free interest rate because this is not consistent
with the information from the Federal Reserve which accepts long term
averages of both short-term and long-term Treasury note rates for use
in the CAPM. DOE added a discount rate sensitivity feature to its
consumer economic impact analysis tools to examine the sensitivity of
the analysis results to the details of DOE's capital cost estimates.
More detail regarding DOE's estimates of commercial consumer discount
rates is provided in section 8.3.8 of the TSD.
c. Temperature Rise, Reliability, and Lifetime
In response to the NOPR, DOE received many comments regarding
whether or not more efficient distribution transformers would have
longer lifetimes and whether this would be both a reliability and an
economic benefit that could accrue from standards.
ACC, ASAP, CEC, Dow Chemical Company, the North American Electric
Reliability Corporation (NERC), 23 members of the U.S. House of
Representatives, and two members of the U.S. Senate urged DOE to take
into consideration transformer operating temperatures and the impact
that this may have on transformer lifetime and reliability. (ACC, No.
132 at p. 2; Public Meeting Transcript, No. 108.6 at p. 175; Public
Meeting Transcript, No. 108.6 at p. 60; Dow, No. 129 at p. 2; NERC, No.
133 at p. 1; U.S. Congress, No. 125 at p. 1; U.S. Senate, No. 120 at p.
1) Several stakeholders, including EMS Consulting and Metglas, asserted
that lower operating temperatures may double or quadruple the life of
transformers. (Public Meeting Transcript, No. 108.6 at pp. 172 and 186;
Metglas, No. 144 at p. 6) Others, including Central Moloney, Inc.,
PG&E, HVOLT, and Southern Company, commented that they expected lower
operating temperatures to have potentially little or no impact on
transformer lifetimes in practice because designs and loading practices
would adjust to maintain current operating temperatures and lifetimes.
(Public Meeting Transcript, No. 108.6 at pp. 187, 174, 168, and 171)
ACEEE, ASAP, and an individual stakeholder all commented that DOE can
and should calculate the impacts of a higher efficiency standard on
transformer lifetimes and should include these impacts in its consumer
benefit calculations. (Public Meeting Transcript, No. 108.6 at pp. 40-
41; ASAP, No. 104 at p. 1; Zahn, No. 119 at p. 7)
DOE evaluated the possibility of estimating the effects of
efficiency on transformer lifetime and reliability, and the likely
accuracy of such estimates. DOE first calculated the average
temperature rise and operating temperature of the transformer designs
at each of the TSLs considered in today's final rule. These average
temperature rises are presented in TSD Appendix 8G.
From its review of transformer engineering references, DOE agrees
that if the only difference between more and less efficient
transformers is that more efficient transformers have lower operating
temperatures, then the lifetime of more efficient transformers may
increase because the electrical insulation within the transformer may
last longer. But given the full range of factors that can affect
transformer life and reliability, DOE cannot determine at this time
that decreasing temperature due to efficiency improvements will cause
high efficiency transformers to have increased transformer lifetimes on
average compared to lower efficiency transformers. There are many
differences between more and less efficient transformers in addition to
temperature rise, and there are many failure modes for a transformer in
addition to insulation degradation. More efficient transformers tend to
be larger and heavier, and for pole-mounted transformers this may
increase the likelihood of weather-related and support-structure
failures. Thus, higher efficiency transformers may at times have lower
lifetimes than lower efficiency transformers. Many transformers fail
due to corrosion, lightning, and animal-related short circuits. In
addition, many transformers are replaced during distribution system
upgrades or after a certain age, not due

[[Page 58209]]

to insulation degradation failure. Therefore, the fraction of
transformers that have longer service lifetimes when insulation
degradation rates are slow may be small. Furthermore, the most
significant decrease in transformer temperatures occurs with amorphous
core designs, with the potential lifetime extension benefits likely to
be seen after 25-35 years of service. DOE does not have at its disposal
or know of the existence of data that demonstrate an actual increase in
the lifetime of amorphous core transformers in this age range.
DOE already includes in its analysis the economic benefits of
reliability from more efficient transformers due to decreased peak
loading. It includes a reliability margin cost in generation,
transmission and distribution capacity costs that are included in the
marginal capacity cost estimates for both the LCC analysis and the
national impact analysis (NIA). As such, DOE fully includes the
decreased reliability capacity costs resulting from standards in its
benefits calculations. Electricity cost estimates, which include
capacity and reliability costs, are discussed in detail in TSD Chapter
8, section 8.3.5.

D. National Impact Analysis--National Energy Savings and Net Present
Value Analysis

The NIA evaluates the impact of a proposed standard from a national
perspective rather than from the consumer perspective represented by
the LCC. When DOE evaluates a proposed standard from a national
perspective, it must consider several other factors that are different
from, or not included in, the LCC analysis. One of the factors DOE
modeled in the NIA was the replacement of existing, less efficient
transformers with more efficient transformers over time. DOE estimated
this rate of replacement using an equipment shipments model that
describes the sale of transformers for replacement and for inclusion in
new electrical distribution system infrastructure. A second factor
included in the NIA was a discount rate. Since the national cost of
capital may differ from the consumer cost of capital, the discount rate
used in the NIA can be different from that used in the LCC. The third
factor DOE included in the NIA 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
DOE's NIA are provided in Chapters 9 and 10 of the TSD.
DOE received comment on two issues related to discount rates in
response to the NOPR concerning the NIA analysis. The first was the
selection of the discount rate that is best for evaluating the NPV
benefits to the country, and the second was the process of applying a
discount rate to energy savings and emissions. In addition, there were
comments regarding the need for DOE to account for other national
benefits, such as potential decreases in natural gas prices and
increased electrical system reliability. These natural gas price and
electrical system reliability impacts are discussed above in the
description of the LCC methodology and comments in section IV.C.2.e and
at the end of section IV.C.3.c, respectively.
1. Discount Rate
a. Selection and Estimation Method
In response to the NOPR, DOE received a range of comments with
respect to the discount rate to use in evaluating national benefits.
ACEEE and Metglas recommended that DOE use a discount rate of 4.2
percent and 4.25 percent, respectively. (ACEEE, No. 127 at p. 1;
Metglas, No. 144 at p. 4) ASAP and NRDC recommended that DOE use the
three percent discount rate in evaluating national impacts. (Public
Meeting Transcript, No. 108.6 at p. 120; NRDC, No. 117 at p. 9) NRDC
further commented that the long-term average rate of return on
government bonds is 1.2 percent real. (Public Meeting Transcript, No.
108.6 at pp. 124-125) EEI commented that commercial customers seek a
20- or 25-percent nominal discount rate for returns. (Public Meeting
Transcript, No 108.6 at p. 122) Finally, Southern Company noted that
seven percent nominal is close to their cost of capital, and commented
that excessive transformer investments are likely to displace more
productive distribution system investments in other parts of the
company. (Public Meeting Transcript, No. 108.6 at pp. 120-121)
DOE follows OMB guidance in the selection of the discount rate for
evaluating national benefits. OMB Circular A-4 provides clear guidance
to DOE directing it to use discount rates of seven percent and three
percent in evaluating the impacts of regulations. To address comments,
DOE also reported results for the 4.2 percent discount rate in Appendix
10A of the TSD for this rulemaking. In selecting the discount rate
corresponding to a public investment, OMB directs agencies to use ``the
real Treasury borrowing rate on marketable securities of comparable
maturity to the period of analysis.'' Office of Management and Budget
(OMB) Circular No. A-94, ``Guidelines and Discount Rates for Benefit-
Cost Analysis of Federal Programs,'' dated October 29, 1992, section
8.c.1.
b. Discounting Energy and Emissions
In the NOPR, DOE reported both undiscounted and discounted energy
savings and emissions impacts and invited comment on the
appropriateness of the discount rates used. 71 FR 44407. CEC commented
that DOE should not use or report discounted emissions. (Public Meeting
Transcript, No. 108.6 at p. 109) EEI commented that discounted
emissions and energy savings are an interesting point of information,
but DOE should determine the standard based on the absolute numbers.
(Public Meeting Transcript, No. 108.6 at p. 111) NRDC objected to
discounting emissions and would advocate for a zero percent discount
rate for emissions. (Public Meeting Transcript, No. 108.6 at pp. 113-
114) Southern Company commented that discounting future sulfur dioxide
(SO2) emissions would be similar to discounting the future
price or value of gold, which would depend on the projected price in
the future, which will almost always be larger (not smaller) than the
current price. (Public Meeting Transcript, No. 108.6 at p. 121)
Consistent with Executive Order 12866, ``Regulatory Planning and
Review,'' 58 FR 51737, DOE follows the guidance of OMB regarding
methodologies and procedures for regulatory impact analysis that affect
more than one agency. In reporting energy and environmental benefits
from energy conservation standards, DOE will report both discounted and
undiscounted (i.e., zero discount-rate) values.

E. Commercial Consumer Subgroup Analysis

In analyzing the potential impacts of new or amended standards, DOE
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, DOE 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.

[[Page 58210]]

F. Manufacturer Impact Analysis

For the MIA, DOE introduced one change to the methodology it
described in the NOPR. In the proposed rule, DOE captured the costs of
conversion, by manufacturers of liquid-immersed transformers, to
production of amorphous core transformers at TSL6 (all DLs) and TSL5
(DL3 through DL5). For the final rule analysis and its associated
material pricing assumptions, DOE's LCC customer choice model indicates
that manufacturers would also produce significant volumes of amorphous
core transformers at TSL3, TSL4, and TSLA. For TSL3 and TSL4, the model
indicates that 95 percent of all transformers in DL4 would be
constructed from amorphous core technology. Similarly, for TSLA, 49
percent of DL4 transformers and 84 percent of DL5 transformers would be
amorphous core transformers. For the final rule, DOE modeled this
partial conversion to amorphous core construction for TSL3, TSL4, and
TSLA (with no change to the proposed rule methodology for TSL5 and
TSL6).

G. Employment Impact Analysis

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. These indirect
employment impacts are 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. DOE expects the net monetary savings from
standards to be redirected to other forms of economic activity. DOE
also expects these shifts in spending and economic activity to affect
the demand for labor.
DOE did not receive stakeholder comments on its net national
employment estimation methodology. DOE therefore retained the same
methodology that it used in the NOPR. For more details on the
employment impact analysis, see TSD Chapter 14.

H. Utility Impact Analysis

The utility impact analysis estimates the impacts that the energy
savings from a standard has on the nation's energy production and
distribution infrastructure. These impacts include the change in fuel
consumed by fuel type, and the change in generation capacity by
generator type.
DOE analyzed the effects of standards on electric utility industry
generation capacity and fuel consumption using a variant of EIA's NEMS.
NEMS, which is available in the public domain, is a large, multi-
sectoral, partial-equilibrium model of the U.S. energy sector that
estimates the economic supply and demand balance between the energy
sector and other sectors of the U.S. and international economies from
year to year. The EIA uses NEMS to produce the AEO, a widely recognized
baseline energy forecast for the U.S. DOE uses a variant known as NEMS-
BT for the appliance and equipment standards rulemakings. (See TSD
Chapter 13). Since DOE did not receive comments on the utility impact
analysis methods in response to the NOPR, DOE made no adjustments to
the methodology for the final rule analysis.
For the proposed rule, DOE used AEO2005 as input to the utility
analysis, which DOE updated to AEO2006 for this analysis. As in the
proposed rule, the utility impact analysis was conducted as policy
deviations from the AEO \20\ applying the same basic set of
assumptions. For example, the operating characteristics (e.g., energy
conversion efficiency and emissions rates) of future electricity
generating plants are as specified in the AEO2006 Reference Case, as
are the prospects for natural gas supply. The utility impact analysis
reports the changes in installed generation capacity and changes in
end-use electricity sales that result from each TSL.
---------------------------------------------------------------------------

\20\ While the AEO2007 electricity price forecast data was
available in time for preparation of this final rule, the full
AEO2007 forecast was not available at the time DOE performed the
utility and environmental impact analysis. DOE therefore used
AEO2006 for the utility and environmental analysis. Following
completion of the utility and environmental analysis and after the
full AEO 2007 became available, DOE compared the AEO2006 and AEO2007
and found the forecasts of electricity prices, the marginal
generation mix and emissions factors in the AEO2007 and AEO2006
forecasts were very similar. The two forecasts provide the same
marginal fractions of coal and natural gas generation (within 3.5%),
and have marginal CO2 emissions factors that differ by
less than 2%.
---------------------------------------------------------------------------

I. Environmental Analysis

DOE determined the environmental impacts of the proposed standards.
Specifically, DOE calculated the reduction in power plant emissions of
carbon dioxide (CO2), 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.
NEMS-BT is run similarly to the AEO2006 NEMS, except that in NEMS-
BT distribution transformer energy usage is reduced by the amount of
energy (by fuel type) saved due to the proposed TSLs. DOE 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 AEO2006 Reference Case. While DOE used AEO2007 for
electricity price forecasts, the most recent version of NEMS-BT
available to DOE for the environmental and utility analysis was based
on AEO2006. As discussed above, DOE found that the differences between
the marginal generation mix and emissions factors between AEO2007 and
AEO2006 forecasts are very small which implies that generation, fuel
consumption and emissions estimates will have a similarly small
relative difference between AEO2007 and AEO2006. Therefore DOE
performed no further updates to the environmental and utility analyses
for the final rule analysis beyond the AEO2006 results. (See TSD
Chapter 13)
NEMS-BT tracks CO2 emissions using a detailed module
that provides robust results because of its broad coverage of all
sectors and inclusion of economic interactions between sectors that can
impact emissions. DOE based the NOX reductions on forecasts
of compliance with the Clean Air Interstate Rule recently promulgated
by EPA. 69 FR 25184 (May 5, 2004); 69 FR 32684 (June 10, 2004); and 70
FR 25162 (May 12, 2005). 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. See
the environmental assessment, a separate report within the TSD, for a
discussion of these issues.
In response to the NOPR, DOE received comments regarding the
potential economic benefits of emissions reductions. ACEEE commented
that the EIA forecast does

[[Page 58211]]

not factor in any potential cost due to addressing CO2
emissions, and that this may lead to an underestimate of the potential
economic benefits of CO2 emissions reductions resulting from
standards. (Public Meeting Transcript, No. 108.6 at pp. 42-43) CEC also
commented that DOE did not include potential economic benefits and
costs of CO2 emissions in its electricity price forecast.
DOE did not include estimates of the economic benefits of
CO2 emissions reductions because of uncertainties in the
forecast of the economic value of such emissions reductions. DOE
instead provides fairly detailed reporting of the physical emissions
reductions in the environmental assessment report in the TSD so that
they can be evaluated as a separate environmental benefit in the
selection of an energy conservation standard. Details are provided in
the environmental assessment report in the TSD.

V. Discussion of Other Comments

Since DOE opened the docket for this rulemaking, it has received
more than 170 comments from a diverse set of parties, including
manufacturers and their representatives, States, energy conservation
advocates, and electric utilities. Comments DOE received in response to
the NOPR, on the soundness and validity of the methodologies DOE used,
are discussed in section IV. Other stakeholder comments in response to
the NOPR addressed the burdens and benefits associated with new energy
conservation standards, the information DOE used in its analyses,
results of and inferences drawn from the analyses, impacts of
standards, the merits of the different TSLs and standards options DOE
considered, other issues affecting adoption of standards for
distribution transformers, and the DOE rulemaking process. DOE
addresses these other stakeholder comments in response to the NOPR
below.

A. Information and Assumptions Used in Analyses

1. Engineering Analysis
DOE received comments on the engineering analysis in four areas:
primary voltage sensitivities, material prices, amorphous material
prices, and material availability.
a. Primary Voltage Sensitivities
As an analysis for the final rule, DOE considered alternative
primary voltages in its representative units designed in the
engineering analysis. ERMCO commented that the voltages DOE used for
its NOPR analysis were reasonable and common voltages for the
representative units from DL1-DL5. However, ERMCO was concerned that
there are certain voltages used in distribution networks in the U.S.
today that are unusual, and may not be achievable at TSL4. ERMCO also
stated that there may be impedance or size requirements, specified by
utilities, that lower efficiency. (ERMCO, No. 113 at p. 2) ERMCO
provided a second written comment, focusing on the voltage issue and
identifying dozens of voltages that it believes may be more problematic
than others for achieving TSL4. (ERMCO, No. 147 at pp. 3-4) ERMCO also
noted that, while primary voltages and basic impulse insulation level
(BIL) \21\ ratings have the most effect on the ability to achieve a
high efficiency design, a low secondary voltage of, for example, 208Y/
120 volts on a large kVA unit (1500 kVA) also can be difficult to
manufacture because of the large cross-sectional area of the secondary
winding. Finally, ERMCO noted that dual-voltage designs are more
difficult to manufacture because of complications with how the windings
are prepared. (ERMCO, No. 147 at pp. 1-2)
---------------------------------------------------------------------------

\21\ The BIL rating represents the amount of electrical
insulation incorporated into the transformer. The higher the BIL
rating, the more insulation and the greater the transformer's
ability to handle high voltages.
---------------------------------------------------------------------------

In response to this comment, DOE conducted an engineering
sensitivity analysis to understand more about the potential impact of
different voltages on the efficiency of the resulting designs. DOE
conducted sensitivity analysis runs on DL2 (i.e., 25 kVA pole-mount),
DL4 (150 kVA three-phase), and DL5 (1500 kVA three-phase). Using all
the same inputs (including material prices), but changing the primary
and/or secondary voltages, DOE found that some of the transformers with
the different primary and/or secondary voltages had a higher first cost
and were less efficient. The impact on DL4 was the most significant,
with efficiency shifts as great as 0.18 percent with certain BIL
ratings. This means that, all else being equal, a DL4 transformer
designed with the reference voltage may be 99.34 percent efficient,
while one with the higher BIL-rated primary voltage would be 99.16
percent efficient. This impact on the transformer designs was one of
the ``other factors'' taken into consideration by the Secretary when
reviewing each of the TSLs and selecting today's standard (see section
VI.D.1 of this final rule). The results of the voltage sensitivity
analysis can be found in Appendix 5D of the TSD.
b. Increased Raw Material Prices
DOE received comments expressing concern over material prices that
DOE used in developing the proposed standards, including prices for
core steel and conductors. ACEEE commented that material prices are
unusually high right now, citing press articles and futures markets
which are anticipating that materials prices may come down. ACEEE
believes electrical steel prices will come down because of announced
capacity additions in the industry. (ACEEE, No. 127 at p. 6) NPCC
commented that fluctuating material prices are not a reason for concern
in setting the standard because transformer material prices are
correlated with the materials used to construct power plants. NPCC
stated that if the standard is set low because of high material prices,
the cost of adding electricity generation capacity (i.e., powerplants)
will also be higher under any high material price scenario. (NPCC, No.
141 at p. 4)
Cooper Power Systems commented that it believes DOE should obtain
current material price data to determine which should be used as the
benchmark. Cooper found that the 2005 material price sensitivity
analysis conducted in the NOPR was more representative than DOE's five-
year average material price analysis. (Cooper, No. 154 at p. 3) Howard
Industries commented that its material prices have increased 30-40
percent in the last two to three years, and it believes DOE should
recalculate its engineering curves based on 2005/2006 material prices.
(Howard, No. 143 at p. 7) NEMA expressed concern that DOE's baseline
analysis used outdated material costs, and requested that DOE obtain
2005 and 2006 material pricing to use as the new benchmark. NEMA stated
that the demand for electrical products in China is very high, and this
demand is driving up the prices of commodity materials that are used in
the production of transformers. (Public Meeting Transcript, No. 108.6
at p. 142; NEMA, No. 125 at pp. 1-2) The National Rural Electric
Cooperative Association (NRECA) also expressed concern about core steel
availability and prices. (NRECA, No. 123 at p. 3)
In response to these comments, DOE developed a revised set of
reference material prices. The revised five-year average material price
for the final rule spans the years 2002 through 2006, and is based on
discussion with manufacturers and material suppliers. This approach is
consistent with a comment from EEI, which noted that commodity
materials can fluctuate over

[[Page 58212]]

time, and that EEI believed DOE was correct to use material price
averages in its analysis. (EEI, No. 137 at p. 5) Compared with the NOPR
average material prices, which spanned from 2000 through 2005, most of
the final rule material prices are approximately 15 to 30 percent
higher, after adjusting for inflation. Copper wire had a much more
dramatic increase in price, with as much as a 50% increase in its cost
per pound. Cold-rolled grain-oriented core steel increased by
approximately 25% per pound.
DOE used the new five-year average material prices to develop new
engineering analysis cost-efficiency curves, which it then incorporated
into the LCC spreadsheets for the final rule analysis. The new five-
year average material prices and revised engineering analysis cost-
efficiency curves can be found in Chapter 5 of the TSD.
c. Amorphous Material Price
DOE received several comments on amorphous core material,
questioning primarily the pricing that DOE used in the engineering
analysis prepared as a basis for the NOPR. ACEEE commented that DOE
should check Metglas' assertion that DOE had overestimated the cost of
amorphous core transformers. (ACEEE, No. 127 at p. 6) National Grid
commented that DOE should re-evaluate the information presented by the
amorphous material manufacturer. (NGrid, No. 138 at p. 2) Metglas
stated a concern that the DOE analysis portrayed amorphous metal
transformers as too expensive. Metglas commented that the software
input cost for a finished core should have been $1.75/lb and not $2.85/
lb, based on the fact that the raw material price for amorphous
material was $0.80 to $0.90/lb for 2000 to 2004, and $0.95/lb for the
first quarter of 2005. (Public Meeting Transcript, No. 108.6 at p. 36;
Metglas, No. 144 at p. 2)
In response to this comment, DOE reviewed its material pricing for
amorphous core material, as part of its review (discussed in the
previous subsection) of all the material prices used in its engineering
analysis. DOE's review found that the five-year average finished
amorphous core material price was $2.14 per pound. Details on the
review of raw material and mark-up costs associated with sourcing a
finished amorphous core can be found in Chapter 5 of the TSD.
d. Material Availability
DOE received several comments expressing concern over the
availability of materials--including core steel and conductors--for
building energy efficient distribution transformers. These issues
pertain to a global scarcity of materials as well as issues of
materials access for small manufacturers.
NEMA expressed concern over the effective date of the standard
because of a lack of core steel availability. (Public Meeting
Transcript, No. 108.6 at p. 220) NRECA also expressed concern about
core steel availability. (Public Meeting Transcript, No. 108.6 at p.
51; NRECA, No. 123 at p. 3) Central Moloney commented that it supports
TSL2 because it is concerned about the availability of materials needed
for higher efficiency transformers. (Public Meeting Transcript, No.
108.6 at p. 60) Howard Industries expressed a similar concern, stating
that it believes suppliers of raw materials (e.g., aluminum magnet
wire) cannot meet the demand that will be required at TSL2, and the
situation would be much worse at TSL4. Howard recommends TSL1. (Howard,
No. 143 at p. 6) HVOLT also supports TSL1, because there is a wide
array of materials that could be used to meet this level of the minimum
efficiency standard. (Public Meeting Transcript, No. 108.6 at p. 229)
Other stakeholders, however, emphasized the changes in the core
steel market that would increase availability and may mitigate the
impact of potential shortages of core steel. AK Steel stated that it is
expanding its steel production capacity to meet the demand needs of
more efficient transformers. It indicated that it will increase steel
production by 50,000 tons per year starting in early 2007, and that
other producers around the world are adding capacity as well. (Public
Meeting Transcript, No. 108.6 at pp. 34 and 228) Metglas commented that
core steel will become increasingly available, and cited DOE's core
steel report (Appendix 3A), showing that AK Steel, POSCO, and Wuhan are
each adding significant capacity by 2007. Therefore, Metglas stated
that core steel availability concerns should not deter DOE from
selecting TSL4. (Metglas, No. 144 at p. 4)
DOE wanted to ensure that it did not adopt a standard level that
could only be achieved by one type of core steel, which might be
proprietary. To better understand and address the issue of core steels
used by selected standards-compliant designs in the LCC, DOE evaluated
the types (e.g., M6, M3, SA1) of core steel selected by the LCC
consumer choice model at all the liquid-immersed TSLs. Knowing what
proportion of the selected designs are built with each of the steel
type for each TSL enabled DOE to consider this information in the
standard level selection. Details of core steel type proportions for
each TSL and each design line are provided in Appendix 8H of the TSD.
2. Shipments/National Energy Savings
DOE received a few comments regarding trends in transformer
efficiency and the impact that this may have on energy savings. ACEEE
commented that average transformer efficiencies appear to be coming
down. (ACEEE, No. 127 at p. 7) NEMA commented that 10 years ago there
was a trend where customers bought cheaper and less efficient
transformers every year, but that the market has turned around and now
an increasing percentage of customers are purchasing TP 1 transformers.
NEMA also noted that the shipments data it has submitted over the years
to DOE have shown this changing trend (Public Meeting Transcript, No.
108.6 at p. 220; NEMA, No. 125 at p. 3) NRECA commented that standards
may encourage some utilities to stop evaluating transformer purchases
for efficiency because the small differences between the energy savings
and costs of evaluated and standard-compliant transformers may no
longer justify the cost of performing evaluations. (NRECA, No. 123 at
p. 3)
DOE did not include any baseline efficiency trends in its shipments
and national energy savings models. As noted in comments received by
DOE, it is clear that transformer efficiencies have dropped over the
last decade. However, current data appears to indicate the trend
towards lower efficiencies has ended, but the data are inconclusive as
to whether efficiencies are remaining level or increasing slightly.
Furthermore, AEO forecasts show no long term trend in transmission and
distribution losses. Therefore, given the variation in comments, and
the data from AEO forecasts, DOE estimates that the probability of an
increasing efficiency trend and the probability of a decreasing
efficiency trend are approximately equal, and therefore used a zero
trend in baseline efficiency as the median scenario. DOE performed
sensitivity analyses for both the low and high baseline efficiency in
the LCC analysis with results presented in Appendix 8D of the TSD.
3. Manufacturer Impact Analysis
Metglas made two specific comments related to the MIA. First,
Metglas said that it was ``out of context'' for DOE to incorporate
conversion capital expenditures into the MIA. Since the engineering
analysis and LCC analysis assumed that U.S. transformer

[[Page 58213]]

manufacturers would purchase finished amorphous cores, Metglas
identified DOE's inclusion of capital expenditures associated with
conversion to amorphous core technology as inconsistent. Second,
Metglas stated that the conversion capital expenditures DOE estimated
were two to three times higher than actual experience has shown in
commercial production. (Metglas, Inc., No. 144 at pp. 2-3)
Regarding Metglas's first point, DOE recognizes that the
engineering and LCC analyses are based on a scenario where U.S.
transformer manufacturers purchase finished amorphous cores (for TSLs
6, 5, A, 4, and 3), while the MIA is based on a scenario where
manufacturers would largely convert their facilities to produce the
amorphous cores for the amorphous core transformers. For the
engineering and LCC analyses, DOE used actual market pricing in its
analysis to develop its production costs and transformer price
estimates. The engineering and LCC analyses are based on the assumption
that manufacturers who make a decision to build an amorphous core
transformer will purchase prefabricated (i.e., cut and formed)
amorphous cores.
During the manufacturer interviews prior to the August 2006 NOPR,
DOE learned that it was likely that many of the U.S. manufacturers
would convert their facilities to produce amorphous cores if the
standard required or otherwise triggered significant volumes of
amorphous core transformer purchases--manufacturers indicated that
production of cores is an important part of the value chain and they
would likely choose to continue to produce them. Therefore, DOE decided
to conduct the MIA as if manufacturers would convert their facilities
to produce amorphous core transformers for TSLs where the DOE customer
choice model indicated selection of amorphous core transformers in high
volume. In its assessment of manufacturer impacts, DOE is not
evaluating the assumption made for the engineering and LCC scenarios,
namely that manufacturers would purchase finished, prefabricated
amorphous cores. If it were modeled in the MIA, then the employment
engaged in fabricating cores would be shifted from domestic factories
to overseas businesses which would operate all the equipment needed to
manufacture amorphous cores. DOE believes that both transformer
production costs and transformer pricing would be similar under the two
scenarios. The difference between the two scenarios would affect only
the allocation of the production costs. In the MIA, instead of
manufacturers buying prefabricated cores (i.e., U.S.-sourced amorphous
ribbon processed in India), paying for trans-oceanic shipping, and
lowering their labor costs, manufacturers would allocate costs
differently by purchasing amorphous material and employing domestic
labor to manufacture the amorphous cores. The decision a manufacturer
makes between outsourcing amorphous core production and converting its
facilities to produce amorphous core transformers depends on multiple
competing factors, including the trade-off between labor and trans-
oceanic shipping costs. Because of these competing factors, it is not
obvious whether manufacturers would purchase amorphous cores from
abroad or produce them on-site (and manufacturers indicated during
interviews that they are not sure which path they would follow today)--
this is tantamount to saying that the cost difference between the two
scenarios is likely not major. For these reasons, DOE concludes it is
appropriate to use the pricing information (based on purchased cores)
together with appropriate conversion capital cost estimates in the MIA.
With respect to Metglas's second point about the magnitude of the
estimated conversion capital expenditures, DOE conducted a detailed
review of its amorphous-related conversion capital expenditure
estimates in the August 2006 NOPR. DOE found that the conversion costs
estimates in the NOPR could be reduced by using different core
manufacturing equipment than DOE had assumed in the NOPR. DOE's review
concluded that the final rule conversion capital expenditures at TSL5
and TSL6 are about half of those presented in the August 2006 NOPR.
DOE's conclusion is consistent with Metglas's assertion that the
investment costs in the August 2006 NOPR were two to three times too
high. See TSD Chapter 12, Section 12.4.1, for detailed information on
the capital expenditures associated with amorphous core conversion.

B. Weighing of Factors

1. Economic Impacts
a. Economic Impacts on Consumers
In response to the NOPR and NODA, DOE received comments regarding
the economic impacts of the proposed standards. The vast majority of
these comments discussed such impacts in terms of the life-cycle costs.
This preamble discusses these comments in section V.B.2, below.
b. Economic Impacts on Manufacturers
DOE received a comment from Metglas that relates to the burden that
would be placed on manufacturers if minimum efficiency standards were
implemented that required amorphous core transformers. Metglas
commented that while it cannot replace the entire conventional cores
steel market, it is currently making investments that will allow it to
double its production by mid-2007, and it has a commitment to expand as
the market develops. (Metglas, No. 144 at p. 3; Public Meeting
Transcript, No. 108.6 at p. 233) DOE appreciates this comment, but
while Metglas may have a commitment to expand production capacity with
an expanding market, this provides no guarantee that severe material
shortages will not occur if demand increases faster than Metglas'
ability to expand production. As part of DOE's weighing the benefits
and burdens of setting standards for distribution transformers, DOE
considered whether the standard would require amorphous core steel.
As discussed above, DOE is reluctant to set standard levels that
would require products to be constructed of a single, proprietary
design or material. In particular, in the case of amorphous material,
DOE is concerned because it understands that currently there is only
one significant supplier of amorphous ribbon to the U.S. market.\22\
DOE found, for example, at TSL6, all design lines' representative units
would necessarily be constructed of amorphous material and at TSL5 and
TSLA, design lines 3-5 would be constructed of amorphous material.
---------------------------------------------------------------------------

\22\ At certain very high efficiency levels, the only core
material that would enable compliant transformers would be amorphous
material.
---------------------------------------------------------------------------

DOE received comments from multiple parties about transformer
commoditization \23\ and foreign competition. Cooper Power Systems
suggested to DOE that a standard set toward the high end of the
efficiency range that can be met by large manufacturers would quickly
lead to commoditization and thus foreign competition. Cooper said that
it is important for there to be efficiencies that utilities desire and
specify above the minimum efficiency standard because foreign
manufacturers will find it more difficult to compete in the U.S.

[[Page 58214]]

when product variety is preserved. Cooper noted that recent trends
indicate that many utilities are again evaluating losses when
specifying transformers because utility deregulation is collapsing.
(Cooper Power Systems, No. 154 at p. 1) Howard Industries supported the
claim that a minimum efficiency standard will lead to offshore
production. Howard's comments did not indicate at which TSLs it felt
this effect would become problematic. (Howard Industries, No. 143 at p.
3)
---------------------------------------------------------------------------

\23\ The term `commoditization' in this context reflects a
concern expressed by stakeholders that the mandatory minimum
efficiency standards will simply become the most commonly requested
transformer efficiency levels in the market, and manufacturers who
currently are providing custom-build designs in a range of
efficiency levels may be put at a disadvantage relative to
manufacturers or importers who simply focus on mass-production of a
single standards-compliant design.
---------------------------------------------------------------------------

Duke Energy stated that the risk of increments of manufacturing
capacity being moved offshore is outweighed by the benefits of energy
savings. (Duke Energy Corporation, No. 134 at p. 3) ACEEE submitted
comments that are consistent with Duke Energy's. While ACEEE agreed
with manufacturers that efficiency standards do lead to more
standardization of product designs (i.e., commoditization), it believes
U.S. manufacturers can still market high efficiency products (e.g., if
the final standard were set high enough to exclude most silicon core
steel designs, manufacturers could market amorphous core transformers
as high-efficiency products). Furthermore, ACEEE contended that the
cost savings of establishing offshore production are not significant
for transformers since transformers are heavy and, consequently, costly
to ship. (ACEEE, No. 127 at p. 8; Public Meeting Transcript, No. 108.6
at p. 95) AK Steel expressed disagreement with ACEEE's view, stating
that many power transformers are shipped to the U.S. from abroad, so it
is therefore clear that transformer weight and shipping costs do not
deter offshore transformer manufacturing. (Public Meeting Transcript,
No. 108.6 at p. 96) ASAP pointed out that the incentive for
manufacturers to move offshore due to low labor costs in Asia will be
present with or without standards. (Public Meeting Transcript, No.
108.6 at p. 102) Finally, the Midwest Energy Efficiency Alliance (MEEA)
suggested that DOE cannot rely on the risk of outsourcing production to
lower labor cost countries in choosing TSL2 (instead of higher
standards) because it has not quantified the risk of this occurrence.
In contrast, MEEA pointed out, DOE quantified the indirect employment
benefits to the economy of higher TSLs. (MEEA, No. 126 at p. 4)
DOE appreciates the varied comments it received on the issue of
transformer commoditization, the outsourcing of production, and foreign
competition. While DOE understands that some manufacturers are
concerned that today's rule could lead to some commoditization of
liquid-immersed transformers, DOE's engineering analysis indicates that
many designs exist that are more efficient than today's minimum
efficiency standard. The designs available to manufacturers can be
constructed of either amorphous material or silicon core steels.
Moreover, today's minimum efficiency standard can be met with two or
more grades of silicon core steel, depending on the design line. In
addition, DOE notes that there are many other custom design factors
which are built into a distribution transformer in addition to the
efficiency of the unit. Utilities can (and do presently) specify
transformer designs with efficiencies that are both at and above (i.e.,
more efficient than) the minimum efficiency standard being adopted in
today's final rule. Because today's standard preserves multiple design
paths and a diversity of products, DOE does not expect that today's
standard will be a significant cause of increased levels of outsourced
production to lower labor cost countries or affect U.S. manufacturer's
ability to compete. DOE believes this is the situation for both liquid-
immersed and medium-voltage dry-type transformer manufacturing. While
concerns about outsourcing and foreign competition may be more relevant
and valid for standard levels higher than those promulgated today, DOE
rejected those standard levels based on impacts associated with other
EPCA criteria, and did not reject those higher standard levels based
upon explicit consideration of outsourcing and foreign competition.
2. Life-Cycle Costs
DOE received extensive comments regarding the life-cycle economic
burdens and benefits from standards, in response to both the NOPR and
the NODA. A large number of stakeholders recommended that DOE select a
standard that minimizes life-cycle costs and encouraged DOE to select
TSL4 on the ground that it achieved that goal. (ACEEE, No. 127 at p. 1-
3, 9; CEC, No. 98 at p. 1-2; NASEO, No. 131 at p. 1-2; NPCC, No. 141 at
p. 1-4; Public Meeting Transcript, No. 108.6 at p. 193; U.S. Congress,
No. 125 at p. 1-2; Metglas, Incorporated, No. 144 at p. 3, 6; NPCC, No.
141 at p. 1-4; Office of Consumer Affairs and Business Regulation,
Division of Energy Resources, Commonwealth of Massachusetts, No. 152 at
p. 1-2; PNM Resources and 9 other utilities, No. 140 at p. 1-2;
NYSERDA, No. 136 at p. 1; Public Meeting Transcript, No. 108.6 at p.
39; National Grid, No. 138 at p. 1-2; Public Meeting Transcript, No.
108.6 at p. 59)
Others commented that a standard that minimizes life-cycle costs
creates burdens on particular subgroups, or that the minimum life-cycle
cost level, TSL4, creates inconsistencies between three-phase and
single-phase transformers and that these burdens justify giving less
weight to life-cycle cost results than what was advocated by other
stakeholders. NRECA commented that it does not support TSL4, because it
believes this level would unfairly burden rural consumers who are
likely at an economic disadvantage compared to urban consumers. (NRECA,
No. 176 at p. 3) NRECA further commented that utilities can be
encouraged to minimize life-cycle costs by being total ownership cost
(TOC) evaluators. (NRECA, No. 123 at p. 1-2) ERMCO commented that
single-phase liquid-units are commonly ``banked'' to supply three-phase
power, therefore single-phase and three-phase units should have the
same efficiency requirements. (ERMCO, No. 165 at p. 1) NPCC commented
that TSL4 provides the maximum benefits compared to burdens except for
design line 4 transformers where they recommended adoption of TSL2.
(NPCC, No. 141 at p. 1-4)
While DOE gave substantial weight to the LCC results in selecting
the standard levels in today's rule, these results were not the sole
determining factor. DOE weighed all of the economic impacts in reaching
its decision. DOE agrees with stakeholders who commented that
differences in efficiencies between single-phase and three-phase
efficiency levels would create burdens on both manufacturers and
consumers. The levels selected by DOE are close to the minimum life-
cycle cost levels that maintain consistency between single-phase and
three-phase efficiency requirements. (see TSD Appendix 8I)
3. Energy Savings
In response to the NOPR, DOE received comments on the need to
maximize energy savings. Many stakeholders commented that the TSL2
level proposed by DOE in the NOPR did not maximize energy savings.
(ACEEE, No. 127 at p. 1-3, 9; Public Meeting Transcript, No. 108.6 at
p. 26; CEC, No. 98 at p. 1-2; CDA, No. 111 at p. 5; Dow Chemical
Company, No. 129 at p. 1-2; Exelon Corporation, No. 105 at p. 1; NARUC,
No. 106 at p. 1-5; NASEO, No. 131 at p. 1-2; NRDC, No. 117 at p. 1-6;
NPCC, No. 141 at p. 1-4; U.S. Congress, No. 125 at p. 1-2; U.S. Senate,
No. 120 at p. 1)
DOE also received comment that some levels could create unintended
consequences that could reduce energy savings. CEA expressed concerned
that

[[Page 58215]]

TSL3 and TSL4 would force utilities to use larger kVA transformers to
meet efficiency requirements because these levels are especially hard
to meet for small transformers. The over-sizing of transformers because
of the unavailability of moderate cost small transformers may increase
losses overall compared to the case of no standards (CEA, No. 171 at p.
3) Cooper commented that higher standards for liquid-immersed
transformers compared to dry-types could shift the market toward
increased use of less efficient dry-type designs instead of non-
flammable liquid-filled models, negating energy savings. (Cooper, No.
175 at p. 2)
DOE recognizes that inconsistencies between the stringency of
efficiency levels between small and large transformers can lead to
market shifts that may decrease energy savings. DOE did not
quantitatively estimate such potential market shifts because of a lack
of data on such market shift elasticities. But DOE did solicit
stakeholder comment in the NODA regarding the possibility of
recombining the efficiency levels proposed in the NOPR. 72 FR 6189-
6190. In section V.C below, DOE addressed the burden of potential
market shifts described in stakeholder comments by recombining the
proposed efficiency levels to create more consistency between small,
large, single-phase, and three-phase liquid-immersed transformers. By
recombining efficiency levels into combinations that have fewer
economic burdens, DOE increases the energy savings that are
economically justified.
4. Lessening of Utility or Performance of Products
a. Transformers Installed in Vaults
DOE received comments that energy conservation standards may lessen
the utility and performance of transformers by resulting in
transformers that are heavier and larger, thus creating size and space
constraint issues. DOE quantified these effects in its analysis and
estimated the impacts in terms of increased installations costs. This
rulemaking describes the comments and DOE's response to these issues in
section IV.C.1.b above.
5. Impact of Lessening of Competition
DOE received comment from the Department of Justice, which
indicated that the proposed levels in the NOPR may adversely affect
competition with respect to distribution transformers used in
industries, such as underground coal mining, where physical conditions
limit the size of the equipment that can be effectively utilized. (DOJ,
No. 157 at p. 2) DOE considered this input from DOJ, along with
comments from several stakeholders, and as discussed above in section
IV.A.2 of today's notice, decided to treat space-constrained
underground mining transformers as a separate product class in this
final rule.
6. Need of the Nation To Conserve Energy
DOE received extensive comment from stakeholders on the need of the
Nation to conserve energy. NRDC commented that the need for the Nation
to conserve energy was urgent from both an environmental and public
benefit perspective. (NRDC, No. 117 at p. 1-6) NERC commented that the
energy savings may be important for helping maintain electric system
reliability. (NERC, No. 133 at p. 1) PNM Resources and nine other
utilities commented that energy savings from a standard can improve the
security and reduce reliability costs for the Nation's energy system,
can provide national economic benefits, reduce generation capacity
requirements, and reduce generation-related emissions. (PNM Resources
and nine other utilities, No. 140 at p. 1) And many stakeholders
commented on the need of the Nation to conserve energy when they
commented that the TSL2 level proposed in the NOPR did not maximize
energy savings. (ACEEE, No. 127 at p. 1-3, 9; Public Meeting
Transcript, No. 108.6 at p. 26; CEC, No. 98 at p. 1-2; CDA, No. 111 at
p. 5; Dow Chemical Company, No. 129 at p. 1-2; Exelon Corporation, No.
105 at p. 1; NARUC, No. 106 at p. 1-5; NASEO, No. 131 at p. 1-2; NRDC,
No. 117 at p. 1-6; NPCC, No. 141 at p. 1-4; U.S. Congress, No. 125 at
p. 1-2; U.S. Senate, No. 120 at p. 1)
DOE recognizes the need of the Nation to save energy. Enhanced
energy efficiency improves the Nation's energy security, strengthens
the economy, and reduces the environmental impacts or reduces the costs
of energy production. In recognition of this national need, DOE
recombined the levels proposed in the NOPR to create a new combination
of levels that could increase energy savings while maintaining economic
justification. The recombined levels considered by DOE are described in
more detail in section V.C below.
7. Other Factors
DOE received comments from stakeholders on certain other topics
that were considered by the Secretary in arriving at the standard
published today. These factors included: (a) Availability of higher BIL
rated primary voltages; (b) a materials price sensitivity analysis
using current material prices (in addition to the reference scenario of
the five-year average material prices); (c) a materials availability
analysis to ensure a diverse mix of core steels in the LCC-selected
designs; and (d) consistency between single-phase efficiency levels and
their three-phase equivalents. Each of these comments is discussed in
this rulemaking, in sections that more closely relate to the specific
analysis involved.
a. Availability of High Primary Voltages
Another consideration for DOE under the ``Other Factors'' EPCA
criterion was whether the standard level selected would impact the
availability of transformer designs that have voltages with BIL ratings
greater than the designs used in the engineering analysis (see footnote
on BIL ratings in section V.A.1.a above). DOE conducted supplementary
engineering analyses for selected design option combinations in four
liquid-immersed design lines. Relative to the basecase (reference)
transformers designed by the software, DOE found that changing the
primary voltages to have a higher BIL ratings would reduce the
efficiency and increase the cost of the cost-optimized transformer
designs. For certain design lines, this impact was particularly
significant. The results can be found in TSD Appendix 5D.
b. Materials Price Sensitivity Analysis
DOE is concerned about how material prices might change and impact
the market relative to the five-year average material price scenario
used for the reference analysis for the final rule. DOE therefore
conducted a separate engineering analysis and LCC using the 2006 \24\
annual average material prices in addition to the five-year average
price scenario. Relative to the five-year average price scenario (used
by DOE as the `reference' material price scenario), DOE found that the
LCC savings were generally lower and the payback periods were generally
longer under the 2006 (high) material price sensitivity analysis.
Material prices and the methodology followed to gather material prices
can be found in TSD Chapter 5. The engineering analysis results of the
material price sensitivity analysis can be found in TSD Appendix 5C and
the LCC results can be found in TSD Appendix 8F.
---------------------------------------------------------------------------

\24\ For this final rule, DOE used annual average material
prices representative of a medium to large-sized transformer
manufacturer. Since this analysis was performed in early 2007, the
most recent data in calculating average annual material prices was
data from 2006.

---------------------------------------------------------------------------

[[Page 58216]]

c. Materials Availability Analysis
DOE considered the availability of a variety of core steels that
could be used to meet the standard in order to address stakeholder
concerns about sources and availability of specific types of core
steel. This issue is particularly significant at the higher standard
levels where amorphous steel would be required. DOE wishes to ensure a
diversity of core steels in the LCC-selected designs, avoiding overly
constraining certain grades of steel. DOE found in its review of the
core steels selected by the LCC model that certain standard levels had
transformer designs based on a disproportionately large percentages of
a particular steel grade due to the minimum efficiency standard. The
analysis of the core steels selected by the LCC consumer choice model
can be found in TSD Appendix 8H.
d. Consistency Between Single-Phase and Three-Phase Designs
DOE is concerned about the consistency between the efficiency
values required for single-phase transformers and their three-phase
equivalents (per phase). DOE understands from comments submitted that
having different standards for single-phase and three-phase liquid-
immersed distribution transformers will cause disturbances or
distortions in the market if the efficiency requirements promulgated by
DOE are inconsistent between single-phase transformers and their three-
phase equivalents (see section V.C below).\25\ Thus, unless the
efficiency of the two per-phase equivalent transformers is equal,
distortions may be introduced into the market due to the minimum
efficiency standard. In DOE's analysis, this is an issue that only
affects liquid-immersed distribution transformers because liquid-
immersed single-phase and three-phase units were analyzed separately.
For medium-voltage dry-type distribution transformers, the three-phase
units were analyzed and the same standard level is being adopted for
both three-phase and single-phase units. DOE's evaluation of the
consistency of the TSLs considered in the proposed rule and the new
TSLs developed for the final rule which address this consistency issue,
can be found in TSD Appendix 8I.
---------------------------------------------------------------------------

\25\ For example, if the standard level were lower for single-
phase transformers than their three-phase equivalents, transformer
consumers may stop purchasing three-phase transformers, and instead
purchase three single-phase transformers, and connect them to
function as a three-phase transformer.
---------------------------------------------------------------------------

C. Other Comments

1. Development of Trial Standard Levels for the Final Rule
DOE received comments on three interrelated topics that led DOE to
create additional TSLs for liquid-immersed transformers for
consideration in deciding what standards to adopt: (1) Consistency of
minimum efficiency values for single and three-phase transformers; (2)
continuity across capacities (or kVA ratings) at the interfaces between
design lines; and (3) reasons for not setting standards for design line
4 at TSL3 or higher. These topics are interrelated because, taken
together, they produce a rationale for DOE's construction of additional
TSLs: TSLs A, B, C and D.
First, several manufacturers of liquid-immersed distribution
transformers recommended that DOE establish minimum efficiency
standards that equally treat a single-phase transformer with its
corresponding three-phase analog. (Cooper Power Systems, No. 154 at p.
2; Howard Industries, No. 143 at p. 2; Public Meeting Transcript, No.
108.6 at p. 65) For example, a 100 kVA single-phase transformer should
be held to the same standard as a 300 kVA three-phase transformer.
(Public Meeting Transcript, No. 108.6 at p. 46) (In this example, the
300 kVA three-phase transformer is the analog to the 100 kVA single-
phase transformer, that is, the per-phase capacities of the two
transformers are identical.) While expressing concern about the
inconsistent treatment of single-phase and three-phase transformers in
the proposed rule, ERMCO suggested that there may be some rationale for
more stringent regulation of the three-phase transformers. (ERMCO, No.
96 at p. 2)
NRDC also commented in support of the construction of a new TSL
that achieves consistency between single-phase and three-phase
transformers. (Public Meeting Transcript, No. 108.6 at pp. 162-163)
ACEEE supported averaging the efficiency values for the single-phase
and three-phase transformers to achieve the consistency requested by
manufacturers. ACEEE expressed opposition to a simple reduction in the
three-phase efficiency levels to match the single-phase levels. (ACEEE,
No. 127 at p. 8) DOE analyzed the consistency of its existing TSLs and
presents those findings in TSD Appendix 8I.
Second, stakeholders commented on the separate but related issue
concerning alleged inconsistent treatment of design lines in the
proposed rule. This related issue has to do with smoothing the
interfaces between small and large three-phase transformers (i.e.,
smoothing the interface between design lines 4 and 5). Stakeholders
asserted that where the small and large kVA design lines intersect,
DOE's proposal might contain a discontinuity, such as a lower
efficiency requirement for a higher kVA rating or a significant change
in the incremental step increases in efficiency with kVA. Stakeholders
suggested that DOE address these discontinuities in the final rule
through the use of a smoothing function. ERMCO, Howard Industries,
HVOLT, and NEMA are the stakeholders who commented on the
discontinuities between small and large three-phase transformers.
(Public Meeting Transcript, No. 108.6 at pp. 72, 76, 77, and 78; ERMCO,
No. 96 at p. 1; Howard Industries, No. 143 at pp. 1-2)
Third, DOE received comments which called to its attention the
problems associated with setting the standard for design line 4 at TSL3
or TSL4 (TSL3 and TSL4 are the same for this design line). NPCC
suggested that DOE regulate design line 4 at the TSL2 level. (NPCC, No.
141 at p. 4) Similarly, ERMCO commented that while designs based on
silicon core steel can meet TSL3 and TSL4 for DOE's chosen
representative units, there are examples of primary voltages that are
specified and purchased by utilities today which would not be able to
meet levels higher than TSL2 using conventional silicon core steel.
(ERMCO, No. 113 at pp. 1-2) In response, DOE conducted a voltage
sensitivity analysis considering higher primary voltages and BIL
ratings on design lines 2, 3, 4 and 5, and determined that the greatest
impact of the higher primary voltages was experienced by design line 4.
(See TSD Appendix 5D) DOE agrees with ERMCO's assertion that certain
primary voltages, when specified for design line 4, cannot meet TSL4
(or TSL3) using conventional silicon core steel. Furthermore, the DOE
customer choice model (in the LCC analysis) indicates that, for the
design line 4 representative unit, approximately 95 percent of the
transformers selected would be constructed with amorphous cores at TSL3
and TSL4. While TSL3 and TSL4 could be met for all voltage classes
using amorphous material, DOE has decided not to regulate to a level
that would require amorphous material, for reasons having to do with
material availability and the limited number of ribbon suppliers. (see
Section V.A.7.c above and Section V.B.1.b below)
In response to the above comments, DOE created TSLs A, B, C and D.
Each of these additional TSLs assures the following: (1) Consistency
between

[[Page 58217]]

single-phase and three-phase analogs; (2) that there are no
discontinuities between adjacent design lines of the same phase as kVA
increases; and (3) that the level for design line 4 is not at TSL3 or
higher (i.e., not at 99.26 percent or higher).
TSLA ensures single-phase versus three-phrase consistency by
mapping from the single-phase transformers to the three-phase
transformers. DOE constructed TSLA based on first selecting the highest
design line 1 efficiency level considered in the proposed rule that
does not exceed 99.26 percent, which is 99.19 percent (to ensure that
the level for design line 4 is not at TSL3 or higher). DOE then chose
this same level of 99.19 percent for the three-phase analog, design
line 4 (to achieve single-phase versus three-phase consistency). For
design line 2, DOE chose the level of 99.04 percent by implementing
0.75 scaling based on design line 1 (to achieve continuity between
adjacent design lines). For the last single-phase design line, design
line 3, DOE chose the highest efficiency level considered in the
proposed rule that yields positive mean LCC savings and does not create
a significant discontinuity with design line 1, that is, 99.54 percent
efficient. It used this same level for the three-phase analog, design
line 5 (to achieve single-phase versus three-phase consistency).
TSLB ensures single-phase versus three-phrase consistency by
mapping from the three-phase transformers to the single-phase
transformers (i.e., the mapping direction is reversed). DOE constructed
TSLB by choosing the highest design line 4 efficiency level considered
in the proposed rule that does not exceed 99.26 percent, which is 99.08
percent (to ensure that the level for design line 4 is not at TSL3 or
higher). DOE chose this same level of 99.08 percent for the single-
phase analog, design line 1 (to achieve single-phase versus three-phase
consistency). For design line 2, DOE chose the level of 98.91 percent
by implementing 0.75 scaling based off on design line 1 (to achieve
continuity between adjacent design lines). For the other three-phase
design line, design line 5, DOE chose the highest efficiency level
considered in the proposed rule that yields positive mean LCC savings,
99.47 percent. It used this same level for the single-phase analog,
design line 3 (to achieve single-phase versus three-phase consistency).
TSLC is similar to TSLB; the only difference is in the treatment of
the large kVA transformers (design line 3 and design line 5). For TSLC,
instead of choosing the highest NOPR efficiency level for design line 5
that yields positive mean LCC savings (99.47 percent), DOE chose the
next lower level of 99.42 percent. DOE used this same level for the
single-phase analog, design line 3 (to achieve single-phase versus
three-phase consistency).
TSLD is based on TSLC except it rounds down the single-phase levels
to TSLs evaluated in the proposed rule. This reduces the single-phase
versus three-phase consistency established in TSLC, but results in the
creation of a TSL--similar to TSLC--that is based on purely NOPR
levels. The resulting levels are 99.04 percent, 98.79 percent, 99.38
percent, 99.08 percent, and 99.42 percent for design lines 1-5,
respectively. These correspond to the NOPR TSLs 4, 4, 2, 2, and 3 for
design lines 1 through 5, respectively. While TSLD has better
consistency between single and three-phase transformers than other TSLs
that were considered in the NOPR, as shown in Appendix 8I, this
standard level is not perfectly consistent between single and three-
phase transformers (as are TSLA, TSLB and TSLC). In particular, at
TSLD, the three-phase standard is higher (more stringent) than the
single-phase standard at all kVA ratings.
2. Linear Interpolation of Non-Standard Capacity Ratings
NEMA and GE Energy both commented on the issue of non-standard
capacity (i.e., kVA) ratings. GE Energy requested clarification on how
it should derive the efficiency requirement for transformers which are
covered within the scope of this rulemaking, but have a kVA rating that
does not appear in the table of efficiency values--for example, 458
kVA. (GE Energy, No. 145 at p. 1) NEMA commented that they believe it
would be problematic if DOE were to hold efficiency standards for any
kVA ratings not appearing in the tables to the next higher efficiency
standard. (NEMA, No. 174 at pp. 3-4) GE Energy and NEMA both recommend
that DOE adopt a linear interpolation to scale the efficiency values of
the kVA ratings in the table that are immediately above and below the
rating that isn't shown in the table. (GE Energy, No. 145 at p. 1;
NEMA, No. 174 at p. 4) DOE discussed this issue with its technical
experts and reviewed industry practice for the treatment of
transformers that have non-standard kVA values. DOE is today adopting
this stakeholder recommendation, namely that transformers with kVA
ratings not appearing in the standards tables would be subject to
standard levels that are calculated by means of linear interpolation
from the efficiency requirements of the two kVA ratings immediately
above and below. For clarity, DOE is providing an example of the linear
interpolation equation for a 458 kVA three-phase medium-voltage dry-
type distribution transformer with a 60 kV BIL rating. As shown in
Table I.2, the kVA ratings and efficiency requirements immediately
above and below 458 kVA are 500 kVA at 98.83% and 300 kVA at 98.67%.
This data enables the user to prepare a table with the five known
values (i.e., x1, x2, x3,
y1, and y3) and the one value to solve for,
y2.

Table V.1.--Example Calculation for Linear Interpolation To Determine
Efficiency Requirement for kVA Ratings Not Appearing in Standards Tables
------------------------------------------------------------------------
kVA Rating Efficiency
------------------------------------------------------------------------
300 kVA (x1).......................................... 98.67% (y1)
458 kVA (x2).......................................... ? (y2)
500 kVA (x3).......................................... 98.83% (y3)
------------------------------------------------------------------------

The kVA and efficiency values (i.e., x1, x2,
x3, y1, and y3) should then be plugged
into the linear interpolation equation shown below, with the result
being rounded off to the hundredths decimal place:
[GRAPHIC] [TIFF OMITTED] TR12OC07.000

For this example, the resultant efficiency requirement (i.e.,
y2) calculated for a 458 kVA medium-voltage dry-type
distribution transformer with a 60 kV BIL is 98.80%.

VI. Analytical Results and Conclusions

A. Trial Standard Levels

For today's final rule, DOE examined 10 TSLs for liquid-immersed
distribution transformers (consisting of the six TSLs DOE considered in
the NOPR plus the four new TSLs discussed in section V.C. of this
Notice) and six TSLs for medium-voltage, dry-type distribution
transformers (the same TSLs that DOE considered in the NOPR since these
levels had no single-phase/three-phase consistency issues). Table VI.1
presents the TSLs analyzed and the efficiency level within each TSL for
each transformer design line. DOE used the specific transformers from
the design lines to represent a range of distribution transformers
within the each product class. This table presents the efficiency
values of TSLs A, B, C, and D, in the context of the other efficiency
values considered in TSL1 through TSL6. TSL6 is the maximum

[[Page 58218]]

technologically feasible level (max tech) for each class of product.

Table VI.1.--Efficiency Values (%) of the Trial Standard Levels by Design Line
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Type Design lines kVA Phase -----------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-Immersed................ DL1 50 1 98.90 98.90 99.04 99.08 99.08 98.90 99.04 99.19 99.19 99.59
DL2 25 1 98.70 98.73 98.79 98.91 98.91 98.76 98.79 99.04 98.96 99.46
DL3 500 1 99.30 99.38 99.38 99.42 99.47 99.46 99.54 99.54 99.74 99.75
DL4 150 3 98.90 99.08 99.08 99.08 99.08 99.26 99.26 99.19 99.58 99.61
DL5 1500 3 99.30 99.36 99.42 99.42 99.47 99.42 99.47 99.54 99.71 99.71
Medium-Voltage Dry-Type *...... DL9 300 3 98.60 98.82 ....... ....... ....... 99.04 99.26 ....... 99.41 99.41
DL10 1500 3 99.10 99.22 ....... ....... ....... 99.30 99.39 ....... 99.51 99.51
DL11 300 3 98.50 98.67 ....... ....... ....... 98.84 99.01 ....... 99.09 99.09
DL12 1500 3 99.00 99.12 ....... ....... ....... 99.23 99.35 ....... 99.51 99.51
DL13 2000 3 99.00 99.15 ....... ....... ....... 99.30 99.45 ....... 99.55 99.55
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Design Lines 9 through 13 represent medium-voltage dry-type distribution transformers, and there were no corresponding trial standard levels set for
TSLA through TSLD because their efficiency levels are consistent between single-phase and three-phase designs.

Table VI.1 illustrates how the recombined TSLs A, B, C, and D have
much greater consistency between the single-phase efficiency levels and
the levels for the three-phase counterparts. For example, design line 4
is the three-phase design line that is equivalent to using three design
line 1 transformers, while design line 5 is the three-phase design line
that is equivalent to three transformers from design line 3. For TSLs
A, B, and C, the efficiency levels for DL4 and DL1, and for DL5 and DL3
are equal.
DOE presents the tables of efficiency values for all the preferred
kVA ratings (i.e., not only the representative kVA ratings that were
analyzed) at each of the various TSLs in the Environmental Assessment
report, which is included in the Technical Support Document.

B. Significance of Energy Savings

To estimate the energy savings through 2038 due to new standards,
DOE compared the energy consumption of distribution transformers under
the base case (no new standards) to energy consumption of distribution
transformers under the standards. Table VI.2 summarizes DOE's NES
estimates. DOE based these estimates on the results of the revised NIA,
which uses energy price forecasts from AEO2007. These estimates are
described in more detail in TSD Chapter 10.

Table VI.2.--National Energy Savings (quads) of the Trial Standard Levels
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Type Discount rate -----------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-Immersed....................... none.................. 1.38 1.94 2.18 2.61 2.75 2.76 3.00 4.07 5.07 7.37
3%.................... 0.77 1.08 1.21 1.45 1.53 1.53 1.67 2.27 2.82 4.10
7%.................... 0.39 0.55 0.62 0.74 0.78 0.78 0.85 1.15 1.44 2.09
Medium-Voltage Dry-Type *............. none.................. 0.06 0.13 ....... ....... ....... 0.19 0.27 ....... 0.40 0.40
3%.................... 0.03 0.07 ....... ....... ....... 0.10 0.20 ....... 0.22 0.22
7%.................... 0.02 0.04 ....... ....... ....... 0.05 0.10 ....... 0.11 0.11
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Medium-voltage dry-type distribution transformers did not have any trial standard levels set for TSLA through TSLD.

C. Economic Justification

1. Economic Impact on Commercial Consumers
a. Life-Cycle Costs and Payback Period
Commercial consumers will be affected by the standards since they
will experience higher purchase prices and lower operating costs. To
estimate these impacts, DOE calculated the LCC and PBP for the ten
trial standards levels considered in this proceeding. DOE's LCC and PBP
analyses provided five outputs for each TSL, which are reported in
Tables VI.3 through VI.12 below. The first three outputs are the
proportion of transformer purchases where the purchase of a design that
complies with the TSL would create a net life-cycle cost, no impact, or
a net life-cycle savings for the consumer, respectively. The fourth
output is the average net life-cycle savings from purchase of a design
complying with the standard.
Finally, the fifth output is the PBP for the average consumer
purchase of a design that complies with the TSL. The PBP 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 PBP is an economic benefit-cost measure that uses benefits and
costs without discounting. However, DOE based the PBP analysis for
distribution transformers on energy consumption under actual in-service
loading conditions, whereas, in accordance with EPCA, the rebuttable
presumption test is based on consumption as determined using loading
levels prescribed by the DOE test procedure. As discussed above, while
DOE examined the rebuttable presumption criteria (see TSD section 8.7),
it determined today's standard levels to be economically justified
through an analysis of the economic impacts of increased efficiency
levels pursuant to section 325(o)(2)(B)(i) of EPCA. (42 U.S.C.
6295(o)(2)(B)(i)) Detailed information on the LCC and PBP analyses can
be found in TSD Chapter 8.

[[Page 58219]]

Table VI.3.--Summary Life-Cycle Cost and Payback Period Results for Design Line 1 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
----------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)..................................... 98.90 98.90 99.04 99.08 99.08 98.90 99.04 99.19 99.19 99.59
Transformers with Net Increase in LCC (%).......... 2.0 2.0 16.9 24.8 24.8 2.0 16.9 63.3 63.3 96.7
Transformers with No Change in LCC (%)............. 66.1 66.1 50.0 38.8 38.8 66.1 50.0 7.0 7.0 0.0
Transformers with Net Savings in LCC (%)........... 31.9 31.9 33.2 36.5 36.5 31.9 33.2 29.7 29.7 3.3
Mean LCC Savings ($)............................... 124 124 98 90 90 124 98 (62) (62) (1074)
Payback of Average Transformer (years)............. 2.4 2.4 9.7 11.4 11.4 2.4 9.7 20.9 20.9 37.9
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.4.--Summary Life-Cycle Cost and Payback Period Results for Design Line 2 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
----------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)..................................... 98.70 98.73 98.79 98.91 98.91 98.76 98.79 99.04 98.96 99.46
Transformers with Net Increase in LCC (%).......... 12.1 10.5 12.4 42.5 42.5 9.6 12.4 79.6 57.7 99.5
Transformers with No Change in LCC (%)............. 42.0 38.4 34.1 16.5 16.5 36.3 34.1 0.1 10.0 0.0
Transformers with Net Savings in LCC (%)........... 45.9 51.1 53.5 41.0 41.0 54.2 53.5 20.3 32.3 0.5
Mean LCC Savings ($)............................... 59 65 76 22 22 76 76 (113) (24) (1094)
Payback of Average Transformer (years)............. 7.6 7.8 8.0 15.6 15.6 7.1 8.0 24.0 19.7 52.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.5.--Summary Life-Cycle Cost and Payback Period Results for Design Line 3 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
----------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)..................................... 99.30 99.38 99.38 99.42 99.47 99.46 99.54 99.54 99.74 99.75
Transformers with Net Increase in LCC (%).......... 1.4 1.4 1.4 2.5 8.1 7.7 44.3 44.3 83.7 87.3
Transformers with No Change in LCC (%)............. 66.6 59.0 59.0 56.5 47.1 49.1 2.1 2.1 0.2 0.0
Transformers with Net Savings in LCC (%)........... 32.0 39.6 39.6 41.0 44.8 43.2 53.6 53.6 16.2 12.7
Mean LCC Savings ($)............................... 1132 1464 1464 1555 1597 1560 1308 1308 (2341) (3460)
Payback of Average Transformer (years)............. 2.3 3.6 3.6 4.3 6.1 6.2 10.6 10.6 23.5 26.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.6.--Summary Life-Cycle Cost and Payback Period Results for Design Line 4 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
----------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%)..................................... 98.90 99.08 99.08 99.08 99.08 99.26 99.26 99.19 99.58 99.61
Transformers with Net Increase in LCC (%).......... 9.6 20.7 20.7 20.7 20.7 18.9 18.9 32.4 78.0 86.9
Transformers with No Change in LCC (%)............. 54.4 20.6 20.6 20.6 20.6 13.0 13.0 13.0 0.1 0.0
Transformers with Net Savings in LCC (%)........... 36.0 58.7 58.7 58.7 58.7 68.2 68.2 54.6 21.9 13.1
Mean LCC Savings ($)............................... 368 503 503 503 503 737 737 397 (780) (1586)
Payback of Average Transformer (years)............. 7.8 10.4 10.4 10.4 10.4 11.3 11.3 13.6 22.0 26.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 58220]]

Table VI.7.-- Summary Life-Cycle Cost and Payback Period Results for Design Line 5 Representative Unit
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Efficiency (%).................................... 99.30 99.36 99.42 99.42 99.47 99.42 99.47 99.54 99.71 99.71
Transformers with Net Increase in LCC (%)......... 5.1 4.8 12.6 12.6 21.4 12.6 21.4 52.3 84.8 84.8
Transformers with No Change in LCC (%)............ 66.7 61.7 45.5 45.5 33.0 45.5 33.0 4.7 0.0 0.0
Transformers with Net Savings in LCC (%).......... 28.2 33.5 41.9 41.9 45.6 41.9 45.6 43.1 15.2 15.2
Mean LCC Savings ($).............................. 1597 2168 2480 2480 2626 2480 2626 1193 (5905) (5905)
Payback of Average Transformer (years)............ 5.1 6.0 7.4 7.4 8.9 7.4 8.9 13.8 21.6 21.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.8.--Summary Life-Cycle Cost and Payback Period Results for Design Line 9 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)...................................... 98.60 98.82 99.04 99.26 99.41 99.41
Transformers with Net Increase in LCC (%)........... 0.3 2.3 8.6 31.9 62.1 62.1
Transformers with No Change in LCC (%).............. 61.0 41.4 22.0 0.0 0.0 0.0
Transformers with Net Savings in LCC (%)............ 38.7 56.3 69.4 68.1 37.9 37.9
Mean LCC Savings ($)................................ 1032 1863 3114 3223 186 186
Payback of Average Transformer (years).............. 0.7 1.8 3.4 7.2 13.8 13.8
----------------------------------------------------------------------------------------------------------------

Table VI.9.--Summary Life-Cycle Cost and Payback Period Results for Design Line 10 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................................... 99.10 99.20 99.30 99.39 99.51 99.51
Transformers with Net Increase in LCC (%)......... 14.3 16.6 18.5 31.1 69.4 69.4
Transformers with No Change in LCC (%)............ 44.8 31.6 24.1 9.5 0.0 0.0
Transformers with Net Savings in LCC (%).......... 41.0 51.7 57.4 59.5 30.7 30.7
Mean LCC Savings ($).............................. 4370 5719 7408 7774 (2116) (2116)
Payback of Average Transformer (years)............ 5.0 6.4 7.0 8.3 15.2 15.2
----------------------------------------------------------------------------------------------------------------

Table VI.10.--Summary Life-Cycle Cost and Payback Period Results for Design Line 11 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-----------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%)...................................... 98.50 98.67 98.84 99.01 99.09 99.09
Transformers with Net Increase in LCC (%)........... 3.4 5.1 13.1 24.9 36.5 36.5
Transformers with No Change in LCC (%).............. 36.4 27.7 10.8 0.7 0.0 0.0
Transformers with Net Savings in LCC (%)............ 60.3 67.2 76.1 74.4 63.5 63.5
Mean LCC Savings ($)................................ 3110 4280 5057 5365 4472 4472
Payback of Average Transformer (years).............. 2.4 3.0 4.3 5.9 7.8 7.8
----------------------------------------------------------------------------------------------------------------

Table VI.11.--Summary Life-Cycle Cost and Payback Period Results for Design Line 12 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................................... 99.00 99.12 99.23 99.35 99.51 99.51
Transformers with Net Increase in LCC (%)......... 5.0 4.0 8.6 24.2 71.9 71.9
Transformers with No Change in LCC (%)............ 66.8 56.5 43.8 16.7 0.0 0.0
Transformers with Net Savings in LCC (%).......... 28.2 39.5 47.6 59.1 28.1 28.1
Mean LCC Savings ($).............................. 2790 4863 6471 7904 (3417) (3417)
Payback of Average Transformer (years)............ 3.4 3.9 4.9 6.7 16.0 16.0
----------------------------------------------------------------------------------------------------------------

[[Page 58221]]

Table VI.12.--Summary Life-Cycle Cost and Payback Period Results for Design Line 13 Representative Unit
----------------------------------------------------------------------------------------------------------------
Trial standard level
-------------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Efficiency (%).................................... 99.00 99.15 99.30 99.45 99.55 99.55
Transformers with Net Increase in LCC (%)......... 5.6 7.2 7.4 46.0 78.1 78.1
Transformers with No Change in LCC (%)............ 71.4 55.2 45.4 1.5 0.0 0.0
Transformers with Net Savings in LCC (%).......... 23.1 37.6 47.2 52.6 21.9 21.9
Mean LCC Savings ($).............................. 827 3658 6950 6832 (9886) (9886)
Payback of Average Transformer (years)............ 4.4 5.6 5.6 9.6 18.7 18.7
----------------------------------------------------------------------------------------------------------------

b. Commercial Consumer Subgroup Analysis
DOE estimated commercial consumer subgroup impacts by determining
the LCC impacts of the TSLs on rural electric cooperatives and
municipal utilities. DOE's analysis indicated that, for municipal
utilities, the economics are similar to those of the national sample of
utilities, but that rural cooperatives will achieve smaller operating
cost savings from higher standards than will the average utility.
Consequently, rural cooperatives, but not municipal utilities, will
generally have a longer payback period for any given standard level
than will the average utility. 71 FR 44389-90. (See TSD Chapter 11 for
information on the LCC Subgroup Analysis) Thus, on average, rural
cooperatives will benefit less per affected transformer from efficiency
improvements than either the average utility or municipal utilities.
For each of the two commercial consumer subgroups, Table VI.13
shows the mean LCC savings at each TSL, and Table VI.14 shows the mean
PBP (in years). DOE included only the liquid-immersed design lines in
this analysis since those types are more than ninety percent of the
transformers purchased by electric utilities.

Table VI.13.--Mean Life-Cycle Cost Savings for Liquid-Immersed Transformers Purchased by Certain Consumer Subgroups ($)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Design line ---------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Municipal Utility Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
1......................................................... 118 118 116 109 109 118 116 (23) (23) (1003)
2......................................................... 55 59 75 21 21 74 75 (106) (19) (1073)
3......................................................... 1357 1691 1690 1798 1920 1885 1674 1674 (1779) (2837)
4......................................................... 435 577 577 577 577 661 661 442 (563) (1338)
5......................................................... 2370 3154 3708 3708 4094 3708 4094 2096 (3192) (3192)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rural Cooperative Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
1......................................................... 120 120 61 49 49 120 61 (131) (131) (1218)
2......................................................... 54 61 67 4 4 71 67 (148) (51) (1174)
3......................................................... 835 1151 1151 1215 1155 1114 786 786 (3324) (4518)
4......................................................... 247 353 353 353 353 653 653 173 (1216) (2064)
5......................................................... 945 1371 1537 1537 1505 1537 1505 292 (8122) (8122)
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.14.-- Payback Period for Average Liquid-Immersed Transformers Purchased by Certain Consumer Subgroups (Years)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Design line ---------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Municipal Utility Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
1......................................................... 2.5 2.5 9.0 10.6 10.6 2.5 9.0 18.5 18.5 35.4
2......................................................... 8.4 8.6 8.0 15.6 15.6 7.1 8.0 24.0 18.5 50.6
3......................................................... 2.0 3.3 3.3 3.9 5.5 5.5 9.7 9.7 21.8 24.2
4......................................................... 7.0 9.8 9.8 9.8 9.8 11.8 11.8 13.3 20.5 24.2
5......................................................... 4.3 5.3 6.6 6.6 8.0 6.6 8.0 14.1 20.5 20.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rural Cooperative Subgroup
--------------------------------------------------------------------------------------------------------------------------------------------------------
1......................................................... 2.5 2.5 11.9 13.4 13.4 2.5 11.9 24.8 24.8 44.6
2......................................................... 8.4 8.6 8.8 16.9 16.9 7.8 8.8 26.7 21.5 58.1
3......................................................... 3.3 4.7 4.7 5.5 7.8 7.9 12.7 12.7 27.6 31.0
4......................................................... 9.6 11.8 11.8 11.8 11.8 12.0 12.0 15.6 25.1 30.0
5......................................................... 7.9 8.8 10.5 10.5 12.2 10.5 12.2 16.9 27.6 27.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 58222]]

Chapter 11 of the TSD explains DOE's method for conducting the
commercial consumer subgroup analysis and presents the detailed results
of that analysis.
2. Economic Impact on Manufacturers
DOE determined the economic impacts of today's standard on
manufacturers, as described in the proposed rule. 71 FR 44363, 44376,
44381-44383, 44390-44393. As described in Section IV.F above, for this
final rule DOE modeled the partial conversion to amorphous core
construction for TSL3, TSL4, and TSLA (with no change in the
methodology for TSL5 and TSL6). DOE analyzed manufacturer impacts under
two scenarios--the `preservation-of-gross-margin-percentage' scenario
and the `preservation-of-operating-profit' scenario. Under the
preservation-of-gross-margin-percentage scenario, DOE applied a single
uniform ``gross margin percentage'' markup across all efficiency
levels. As production costs increase with efficiency, this scenario
implies that the absolute dollar markup will increase. Under the
preservation-of-operating-profit scenario, operating profit is defined
as earnings before interest and taxes. The implicit assumption behind
this markup scenario is that the industry can maintain its operating
profit (in absolute dollars) after the standard. The industry would do
so by passing through its increased costs to customers without
increasing its operating profits in absolute dollars. DOE fully
describes these two scenarios and the complete manufacturer impact
analysis in Chapter 12 of the TSD.
a. Industry Cash-Flow Analysis Results
Using the two markup scenarios, Tables VI.15 and VI.16 show the
estimated impacts for the liquid-immersed and medium-voltage, dry-type
transformer industries, respectively. These tables show the change in
INPV, which is the primary metric from the MIA. DOE calculated the INPV
in the base and standards cases by discounting the projected free cash
flows at the real corporate discount rate of 8.9 percent. This method
of calculating INPV provides one measure of the value of the industry
in present value terms. The impact of new standards on INPV is then the
difference between the INPV in the base case and the INPV in the
standards case (with new standards). The tables also present the
product conversion expenses and capital 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).

Table VI.15.--Manufacturer Impact Analysis for Liquid-Immersed Transformer Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base -----------------------------------------------------------------------------------------
case 1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Product Conversion Expenses..... ($M)*.............. *n/a 0 0 0 0 0 87 89 103 120 176
Capital Investments............. ($M)............... n/a 5.2 2.8 2.8 8.0 5.4 17 17 18 41 178
Total Investment Required....... ($M)............... n/a 5.2 2.8 2.8 8.0 5.4 104 106 121 161 354
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV............................ ($M)............... 609 622 637 646 656 662 598 606 657 703 809
Change in INPV.................. ($M)............... n/a 13 28 37 47 53 (11) (2.9) 48 94 200
(%)................ n/a 2.1 4.6 6.0 7.7 8.8 (1.9) (0.5) 7.9 16 33
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Operating-Profit Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV............................ ($M)............... 609 590 587 577 562 558 509 497 440 357 33.3
Change in INPV.................. ($M)............... n/a (19) (22) (32) (47) (51) (100) (112) (169) (252) (576)
(%)................ n/a (3.2) (3.7) (5.2) (7.7) (8.3) (17) (18) (28) (41) (95)
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ($M) = millions of dollars; n/a = not applicable.

Table VI.16.--Manufacturer Impact Analysis for Medium-Voltage, Dry-Type Transformer Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Units Base -----------------------------------------------------------
case 1 2 3 4 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Product Conversion Expenses.................... ($M)*............................. *n/a 0 0 3.7 4.1 5.8 5.8
Capital Investments............................ ($M).............................. n/a 2.1 5.5 6.8 7.1 15 15
Total Investment Required...................... ($M).............................. n/a 2.1 5.5 10.5 11.2 20.8 20.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Gross-Margin-Percentage Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV........................................... ($M).............................. 36 35 33 31 33 37 37
Change in INPV................................. ($M).............................. n/a (1.1) (3.2) (5.2) (3.2) 0.9 0.9
(%)............................... n/a (3.1) (8.9) (15) (8.9) 2.5 2.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Preservation-of-Operating-Profit Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
INPV........................................... ($M).............................. 36 ........ ........ ........ ........ ........ ........

[[Page 58223]]

Change in INPV................................. ($M).............................. n/a (2.1) (5.2) (8.8) (11) (24) (24)
(%)............................... n/a (5.9) (15) (25) (29) (67) (67)
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ($M) = millions of dollars; n/a = not applicable.

The proposed rule provides additional information on the
methodology, assumptions, and results of this analysis. 71 FR 44382,
44390, 44399-44400, 44403. Chapter 12 of the TSD explains DOE's method
for conducting the manufacturer impact analysis and presents the
detailed results of that analysis.
b. Impacts on Employment
For liquid-immersed transformers, DOE expects no significant,
discernable direct employment impacts among transformer manufacturers
for TSLs 1, 2, D, C, B, 3, and 4, but potentially significant changes
in employment for TSLA (44 percent increase), TSL5 (18 percent
increase), and TSL6 (38 percent increase). Employment impacts are
changes in the numbers of employees involved with transformer
production at the manufacturing facilities. These estimated changes are
due to the increased labor time needed to construct the cores and
assemble the transformers. At these higher TSLs, the cores tend to be
larger and the processing time per pound of amorphous material is
higher than that of silicon steel--both of these effects lead to the
need for more labor. Thus, the larger cores would increase the direct
employment at transformer manufacturing facilities.
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 TSLs 3, 4, A, 5 and 6 to companies in other countries. The
reported modeling results simply capture the changes in direct labor
needed to produce transformers at each TSL. DOE discussed this scenario
of outsourcing amorphous core production to other countries during
several interviews with manufacturers of liquid-immersed transformers,
and it appears that outsourcing would be a serious consideration for
some liquid-immersed transformer manufacturers under TSLs 3, 4, A, 5,
and 6.
In addition, as discussed in the proposed rule, DOE expects today's
standard to have a relatively minor differential impact on small
manufacturers of liquid-immersed distribution transformers. 71 FR
44382, 44392-44393, 44401-44403. For medium-voltage, dry-type
manufacturers, however, all manufacturers would have to develop designs
to enable compliance with TSL3 or higher, and small businesses would be
at a relative disadvantage.
DOE expects no significant, discernable employment impacts among
medium-voltage, dry-type transformer manufacturers for any TSL compared
to the base case. DOE's conclusion regarding employment impacts in the
medium-voltage, dry-type transformer industry is separate from any
conclusions regarding 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 manufacturers of medium-voltage,
dry-type transformers during the interviews is the potential impact
stemming from cast-coil transformer competitiveness at higher TSLs.
These manufacturers claimed 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.
The basis for the conclusions presented above is set forth in
Chapter 12 of the TSD, Sections 12.4.4.1 and 12.5.4.1 for liquid-
immersed and medium-voltage, dry-type transformers, respectively.
c. Impacts on Manufacturing Capacity
For the liquid-immersed distribution transformer industry, DOE
believes that there are only minor production capacity implications for
a standard at TSLs 1, 2, D, C, and B. At TSL6, all liquid-immersed
design lines would have to convert to amorphous technology, the most
energy efficient core material. At TSL5, three design lines would have
to convert to amorphous core designs. For TSLs A, 4, and 3, there would
likely be partial conversion to amorphous core designs for one or two
design lines. Conversion to amorphous core designs would render
obsolete a large portion of the equipment used today for the affected
design lines (e.g., annealing furnaces, core-cutting and winding
equipment). Based on the manufacturer interviews, DOE believes that
TSLs 3, 4, A, 5, and 6 would cause liquid-immersed transformer
manufacturers to decide whether they would need to invest in retooling
their production equipment for amorphous technology or attempt to
purchase pre-fabricated amorphous cores (for the affected design
lines). For TSL6, some manufacturers indicated that they would close
their companies, rather than attempt to manufacturer transformers at
that standard level. 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

[[Page 58224]]

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, DOE 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. DOE 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. DOE
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.
As discussed in the proposed rule, DOE expects minimum efficiency
standards to have a relatively minor differential impact on small
manufacturers of liquid-immersed distribution transformers. 71 FR
44401-44402. Although DOE proposed to adopt TSL2, and is today
promulgating a standard higher than that for all liquid-immersed design
lines other than design line 4, DOE believes that the reasoning
presented in the proposed rule is still relevant and valid: DOE does
not expect today's standard to have a significant economic impact on a
substantial number of small manufacturers of liquid-immersed
transformers. Since the standard does not require manufacturers to
change manufacturing equipment, DOE concludes that the standards
adopted today will have minor differential impact on small
manufacturers of liquid-immersed transformers. This is based on the
fact that manufacturing equipment and materials that are currently
available will be used to meet the standard which will provide
manufacturers flexibility in meeting the standards, and manufacturers
will not be required to re-tool in order to meet the standards. (See
Section VII.B.4). For medium-voltage, dry-type manufacturers, DOE
stated in the proposed rule that it would anticipate some small
business impacts at all TSLs. However, DOE believes that the
incremental impact on small businesses in moving from TSL2 to TSL3 is
greater than that in moving from TSL1 to TSL2 (see Section VII.B.4 for
a more detailed discussion). DOE explicitly considered impacts on small
businesses in selecting TSL2 and rejecting higher levels for medium-
voltage, dry-type transformers. 71 FR 44382, 44392-44393, 44401-44403.
See section VII.B on the Regulatory Flexibility Act for more discussion
on this point.
3. National Net Present Value and Net National Employment
The NPV analysis estimates the cumulative benefits or costs to the
Nation that would result from particular standard levels. While the NES
analysis estimates the energy savings from a proposed energy
conservation standard, the NPV analysis provides estimates of the
national economic impacts of a proposed standard relative to a base
case of no new standard. Tables VI.17 and VI.18 provide an overview of
the NPV results, using both a seven percent and a three percent real
discount rate. See TSD Chapter 10 for more detailed NPV results.

Table VI.17.--Overview of National Net Present Value ($, Billion) for Liquid-Immersed Transformers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Type Discount -----------------------------------------------------------------------------------------------
rate (%) 1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-Immersed Single-Phase............... 3 3.15 3.42 3.58 2.97 2.98 3.74 3.60 (0.31) 1.02 (24.5)
7 0.98 1.04 0.94 0.14 0.14 1.17 0.93 (2.28) (1.33) (18.5)
Liquid-Immersed Three-Phase................ 3 2.42 3.64 3.98 3.98 4.28 5.42 5.72 4.78 0.38 (1.58)
7 0.71 0.91 0.96 0.96 0.97 1.20 1.21 0.38 (3.56) (4.75)
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.18.--Overview of National Net Present Value ($, Billion) for Medium-Voltage, Dry-Type Transformers
----------------------------------------------------------------------------------------------------------------
Trial standard level
Type Discount ---------------------------------------------------------------
rate (%) 1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
Medium-Voltage Dry-Type Single- 3 0.005 0.008 0.011 0.015 0.010 0.010
Phase............................. 7 0.002 0.003 0.004 0.004 0.001 0.001
Medium-Voltage Dry-Type Three-Phase 3 0.461 0.843 1.170 1.531 1.008 1.008
7 0.157 0.280 0.375 0.441 (0.086) (0.086)
----------------------------------------------------------------------------------------------------------------

DOE also estimated the national employment impacts that would
result from each of the TSLs. As discussed in the proposed rule, 71 FR
44383-44384, 44394, DOE expects the net monetary savings from standards
to be redirected to other forms of economic activity. DOE also expects
these shifts in spending and economic activity to affect

[[Page 58225]]

the demand for labor as spending shifts from less labor-intensive to
more labor-intensive sectors of the economy.
As shown in Tables VI.19 and VI.20, DOE estimated net indirect
employment impacts (i.e., those changes of employment in the larger
economy, other than in the manufacturing sector being regulated) from
today's distribution transformer energy conservation standards to be
positive. According to DOE's analysis, the number of jobs that may be
generated by 2038 through indirect impacts ranged from 4,000 to 14,000
for liquid-immersed transformers, and from 400 to 1,500 for medium
voltage, dry-type transformers for the range of TSLs considered in this
rulemaking. While DOE's analysis suggests that the distribution
transformer standards could result in a very small increase in the net
demand for labor in the economy, relative to total national employment,
this increase would likely be 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 VI.19.--Net National Change in Jobs (Thousands): Liquid-Immersed Transformer Standards
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Year -------------------------------------------------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
2010...................................... 1.7 2.3 2.5 2.8 2.9 3.2 3.4 3.7 4.5 3.3
2020...................................... 1.5 2 2.2 2.4 2.5 2.7 2.9 3.0 4.1 1.5
2030...................................... 2.8 3.9 4.4 4.9 5.2 5.3 5.7 6.8 9.5 8.0
2038...................................... 4 5.4 6.2 7.0 7.4 7.4 8.1 10 14 13.4
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table VI.20.--Net National Change in Jobs (Thousands): Dry-Type, Medium-Voltage Transformer Standards
----------------------------------------------------------------------------------------------------------------
Trial standard level
Year -----------------------------------------------------------
1 2 3 4 5 6
----------------------------------------------------------------------------------------------------------------
2010................................................ 0.1 0.2 0.2 0.3 0.4 0.4
2020................................................ 0.1 0.2 0.3 0.4 0.5 0.5
2030................................................ 0.2 0.3 0.4 0.6 0.8 0.8
2038................................................ 0.3 0.5 0.8 1.1 1.5 1.5
----------------------------------------------------------------------------------------------------------------

4. Impact on Utility or Performance of Equipment
As discussed in section V.A.4 of the proposed rule, DOE believes
that, because of the steps it had taken in establishing classes of
products and in evaluating design options and the impact of potential
standard levels (71 FR 44394), as well as the additional steps taken in
today's final rule, including the consideration of design constraints
for vault-transformers (see section V.B.4.a) and the evaluation of
higher BIL voltages (see section V.A.1.a), the new standards it is
adopting today will not lessen the utility or performance of
distribution transformers. (See also TSD, Chapters 4 and 5)
5. Impact of Any Lessening of Competition
As previously discussed in the NOPR, 71 FR 44363-44364, 44394, and
in section III.D.5 of this preamble, DOE considers any lessening of
competition that is likely to result from standards. The Attorney
General determines the impact, if any, of any such lessening of
competition.
DOJ concluded that the distribution transformer standards contained
in the proposed rule may adversely affect competition with respect to
distribution transformers used in industries, such as underground coal
mining, where physical conditions limit the size of the equipment that
may be effectively utilized. DOJ understands that manufacturers would
not be able to satisfy the proposed standard without increasing the
size (or decreasing the power) of each class of distribution
transformer. Mining companies facing space constraints would incur
significantly increased costs due to enlarging the required
installation space (which, for example, could involve removal of solid
rock around coal seams in underground mines) or reconfiguring the size
and number of each class of distribution transformer at each site. The
resulting cost increases could constitute production inefficiencies
that could make certain products less competitive. For example, the
rule could, by raising the costs of certain coal mines, adversely
affect production decisions at those mines and potentially result in
increased use of less efficient energy alternatives. DOJ urged the DOE
to consider these concerns carefully in its analysis, and to consider
creating an exception for distribution transformers used in industries
with space constraints. (DOJ, No. 157 at p.2) DOE considered this input
from DOJ, along with comments from several stakeholders, and as
discussed in section IV.A.2 of this preamble, decided to treat space-
constrained underground mining transformers as a separate product class
in this final rule, and not to apply today's standards to these
transformers. DOE is also reserving a subsection in section 431.196 for
underground mining transformer efficiency standards. Energy
conservation standards for underground mining transformers are not
included as part of today's final rule and will be determined at a
later date.
6. Need of the Nation to Conserve Energy
The Secretary of Energy recognizes the need of the Nation to save
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. Reduced electricity demand from
today's energy conservation standards is also likely to reduce the cost
of maintaining the reliability of the electricity system, particularly
during peak-load periods. As a measure of this reduced demand, DOE
expects today's standards to eliminate the need for the construction of
approximately six new 400-megawatt combined-cycle gas

[[Page 58226]]

turbine power plants by 2038 and to save 2.74 quads of electricity
(cumulative, 2010-2038). The energy savings are higher in the final
rule analysis compared to DOE's NOPR savings of 2.4 quads of
electricity over the same period. Table VI.21 provides DOE's estimate
of cumulative power sector CO2 reductions for an uncapped
emissions scenario for the TSLs considered in this rulemaking.
As discussed in the NOPR, the Clean Air Interstate Rule (CAIR),
which the U.S. Environmental Protection Agency (EPA) issued on March
10, 2005, will permanently cap emissions of NOX in 28
eastern states and the District of Columbia. 70 FR 25162 (May 12,
2005). As with SO2 emissions, for which a cap was previously
in place, a cap on NOX emissions means that equipment
efficiency standards may have no physical effect on these emissions.
Similarly, emissions of Hg for the power sector are also subject to
emissions caps during the evaluation period, so that distribution
transformer standards may similarly result in no physical effect on
these emissions. DOE evaluated the emissions forecasts from AEO2006 and
AEO2007 and found that, because these new regulations capped most power
sector NOX and Hg emissions, decreasing energy use from the
proposed standard would not have any net physical emissions reduction.
The economic effects of emissions reductions are included in the
forecasted projection of electricity prices and thus are included in
DOE's NPV analysis, but are not reported separately. For details of the
emissions reduction calculations and discussion, see the environmental
analysis report in the TSD.
DOE also calculated discounted values for future emissions, using
the same seven percent and three percent real discount rates that it
used in calculating the NPV. Table VI.21 also shows the discounted
cumulative emissions impacts for both liquid-immersed and dry-type,
medium-voltage transformers.

Table VI.21.--CO2 Emission Reductions of the Trial Standard Levels
[In millions of metric tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Type Discount rate ---------------------------------------------------------------------
1 2 D C B 3 4 A 5 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Liquid-Immersed................................ none............................. 125 176 199 238 251 248 272 369 464 674
3%............................... 62 87 99 118 124 123 135 183 230 334
7%............................... 27 38 43 51 54 53 59 80 100 145
Medium-Voltage Dry-Type*....................... none............................. 5.8 11.8 ..... ..... ..... 17.1 24.8 ..... 36.9 36.9
3%............................... 2.9 5.8 ..... ..... ..... 8.5 12.3 ..... 18.3 18.3
7%............................... 1.2 2.5 ..... ..... ..... 3.7 5.3 ..... 8.0 8.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Medium-voltage dry-type distribution transformers did not have any trial standard levels set for TSLA through TSLD.

Emissions are roughly proportional to energy savings. The emissions
reductions are slightly higher in the final rule analysis compared to
DOE's NOPR analysis because of the slightly greater amount of coal-
generated electricity in the updated AEO2006 and AEO2007 forecasts that
DOE used for the utility and environmental analysis (See TSD Chapter 13
and the Environmental Impact Analysis Report in the TSD).
7. Other Factors
In developing today's standard, the Secretary took into
consideration four `Other Factors': (1) Availability of high BIL
primary voltages (see TSD Appendix 5D); (2) materials price sensitivity
analysis (see TSD Appendices 5C and 8F); (3) materials availability
analysis (see TSD Appendix 8H); and (4) consistency between single-
phase and three-phase designs (for liquid-immersed distribution
transformers only, see TSD Appendix 8I). Each of these factors is
described briefly in section V.7 of today's rule and discussed in some
detail in other parts of today's rule. Specifically section V.A.1.a
discusses voltage issues, section V.A.1.b discusses materials price
issues, in section V.A.1.d describes materials availability issues, and
section V.B.7.d describes single-phase and three-phase consistency
issues.

D. Conclusion

EPCA contains criteria for prescribing new or amended energy
conservation standards. DOE 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, DOE has analyzed whether
today's 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)) Today's final rule will not result in the
unavailability in the U.S. of any covered product type (or class) of
transformer with performance characteristics (i.e., reliability,
features, sizes, capacities and voltages) that are substantively the
same as those generally available in the U.S. prior to these new
standards.
In determining whether a standard is economically justified, DOE
determines whether the benefits of the standard exceed its costs. (See
42 U.S.C. 6295(o)(2)(B)(i)) Any new or amended standard for
distribution transformers must result in significant energy savings.
(42 U.S.C. 6317(a); 42 U.S.C. 6295 (o)(3)(B); see 42 U.S.C.
6295(o)(2)(B))
In selecting energy conservation standards for distribution
transformers, DOE started by comparing the maximum technologically
feasible levels with the base case, and determined whether those levels
were economically justified. Upon finding the maximum technologically
feasible levels not to be justified, DOE analyzed the next lower TSL to
determine whether that level was economically justified. DOE repeated
this procedure until it identified a TSL that was economically
justified.
Tables VI.22 and VI.23 summarize DOE's quantitative analysis
results for each TSL. Each table presents the results or, in some
cases, a range of results, for the underlying design lines for liquid-
immersed transformers (Table VI.22), and medium-voltage, dry-type
transformers for (Table VI.23). The range of values reported in these
tables for LCC, payback, and average increase in consumer equipment
cost before installation encompasses the range of results DOE
calculated for either the liquid-immersed or medium-voltage,

[[Page 58227]]

dry-type representative units. The range of values for 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 VI.22.--Summary of Liquid-Immersed Distribution Transformers Analytical Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trial standard level
Criteria ------------------------------------------------------------------------------------------------------------------------
TSL1 TSL2 TSLD TSLC TSLB TSL3 TSL4 TSLA TSL5 TSL6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Energy saved (quads)........... 1.38 1.94 2.18 2.61 2.75 2.76 3.00 4.07 5.07 7.37
Generation capacity offset (GW) 1.4 1.9 2.1 2.5 2.7 2.7 2.9 3.9 5.0 7.2
NPV ($ billions)
Emission reductions, CO2 (Mt).. 125 176 199 238 251 248 272 369 464 674
Life-cycle cost *
Net increase in LCC (%).... 1.4-12.1 1.4-20.7 1.4-20.7 2.5-42.5 8.1-42.5 2.0-18.9 12.4-44.3 32.4-79.6 57.7-84.8 84.8-99.5
No change in LCC (%)....... 42.0-66.7 20.6-66.1 20.6-59.0 16.5-56.5 16.5-47.1 13.0-66.1 2.1-50.0 0.1-13.0 0.0-10.0 0.0-0.0
Net savings in LCC (%)..... 28.2-45.9 31.9-58.7 33.2-58.7 36.5-58.7 36.5-58.7 31.9-68.2 33.2-68.2 20.3-54.6 15.2-32.3 0.5-15.2
Payback for average transformer 2.3-7.8 2.4-10.4 3.6-10.4 4.3-15.7 8.9-15.7 2.4-11.4 7.8-11.4 10.6-24.7 19.3-23.4 21.6-52.1
(years) *.....................
Life-cycle cost, 2006 Material
Price *
Net increase in LCC (%).... 6.8-48.2 15.9-54.4 16.4-45.3 13.4-53.8 17.7-53.8 11.1-48.3 11.1-65.2 11.4-88.5 56.4-91.4 91.4-99.8
No change in LCC (%)....... 17.2-54.9 12.3-46.8 8.9-32.2 1.8-32.2 1.8-23.5 9.2-46.8 0.4-29.7 0.1-14.7 0.0-1.7 0.0-0.0
Net savings in LCC (%)..... 29.6-39.5 33.4-59.0 25.0-59.0 25.1-62.4 25.1-58.8 36.2-74.2 25.0-74.2 11.4-73.9 8.6-41.9 0.3-8.6
Payback for average 4.7-17.8 8.4-19.5 8.4-19.4 8.7-20.8 10.2-20.8 9.8-17.8 10.7-19.4 10.7-29.1 18.8-26.7 26.7-58.3
transformer, 2006 Material
Price (years) *...............
Average increase in consumer 3.2-7.1 2.7-20.7 8.1-20.7 10.0-21.1 10.0-22.1 2.7-45.9 8.0-45.9 20.0-60.6 24.7-138.6 132.9-161.3
equipment cost before
installation (%) *, **,
[dagger]......................
Manufacturer impact ***
INPV ($ millions).......... (19)-13 (22)-28 (32)-37 (47)-47 (51)-53 (100)-(11) (112)-(2.9 (169)-48 (252)-94 (576)-200
)
INPV change (%)............ (3.2)-2.1 (3.7)-4.6 (5.2)-6.0 (7.7)-7.7 (8.3)-8.8 (17)-(1.9) (18)-(0.5) (28)-7.9 (41)-16 (95)-33
LCC selected designs with 0-13 0-14 0-14 0-14 0-14 0-95 0-95 0-84 0-100 100-100
amorphous (%) *...............
LCC selected designs with core 1-54 2-79 2-100 2-84 2-100 2-99 2-100 4-100 4-100 100-100
steel better than M3 (i.e.,
M2, ZDMH, SA1) (%) *..........
Voltage sensitivity-achieve Yes Yes Yes Yes Yes No No No No No
standard with silicon core
steel.........................
Single-phase, three-phase Yes No Yes Yes Yes No No Yes No No
consistency...................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Range represents the results for each of the five representative units derived from the individual design lines analyzed in the LCC.
** Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger] DOE 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.
*** Range represents the results of the `preservation-of-operating-profit' and `preservation-of-gross-margin-percentage' scenarios in the MIA.

Table VI.23.--Summary of Medium-Voltage, Dry-Type Distribution Transformers Analytical Results
----------------------------------------------------------------------------------------------------------------
Trial standard level
Criteria -----------------------------------------------------------------------------
TSL1 TSL2 TSL3 TSL4 TSL5 TSL6
----------------------------------------------------------------------------------------------------------------
Energy saved (quads).............. 0.06 0.13 0.19 0.27 0.40 0.40
Generation capacity offset (GW)... 0.1 0.1 0.2 0.4 0.6 0.6
Discounted energy saved, 7% 0.02 0.04 0.05 0.10 0.11 0.11
(quads)..........................
NPV ($ billions):
Emission reductions CO2 (Mt)...... 5.8 11.8 17.1 24.8 36.9 36.9
Life-cycle cost: *
Net increase in LCC (%)....... 0.3-14.3 2.3-16.6 7.4-18.5 24.2-46.0 36.5-78.1 36.5-78.1
No change in LCC (%).......... 36.4-71.4 27.2-56.5 10.8-45.4 0.0-16.7 0 0
Net savings in LCC (%)........ 23.1-60.3 36.6-67.2 47.2-76.1 52.6-74.4 21.9-63.5 21.9-63.5
Payback for average transformer 0.7-5.0 1.8-6.4 3.4-7.0 5.9-9.6 7.8-18.7 7.8-18.7
(years) *........................
Average increase in consumer 0.6-7.4 3.4-15.1 9.7-24.2 20.4-39.6 43.6-95.1 43.6-95.1
equipment cost before
installation (%) *, **, [dagger].
Life-cycle cost, 2006 Material
Price:*
Net increase in LCC (%)....... 0.7-23.8 4.2-61.3 18.7-54.5 33.7-62.7 49.7-88.3 49.7-88.3
No change in LCC (%).......... 10.8-66.2 1.7-33.2 0.9-11.1 0-3.1 0-0 0-0
Net savings in LCC (%)........ 26.5-75.3 37-78.1 44.6-76.8 37.2-66.2 11.7-50.3 11.7-50.3

[[Page 58228]]

Payback for average transformer, 0.7-5.9 2.1-12.9 6.3-12.2 8.5-14.0 11.4-24.3 11.4-24.3
2006 Material Price (years) *....
Manufacturer impact:***
INPV ($ millions)............. (2.1)-(1.1) (5.2)-(3.2) (8.8)-(5.2) (11)-(3.2) (24)-0.9 (24)-0.9
INPV change (%)............... (5.9)-(3.1) (15)-(8.9) (25)-(15) (29)-(8.9) (67)-2.5 (67)-2.5
LCC designs with thin laminations 30-69 40-88 92-100 100-100 100-100 100-100
of core steel (i.e., M3, HO) (%)
*................................
----------------------------------------------------------------------------------------------------------------
* Range represents the results for each of the five representative units derived from the individual design
lines analyzed in the LCC.
** Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger]DOE 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.
*** Range represents the results of the `preservation-of-operating-profit' and `preservation-of-gross-margin-
percentage' scenarios in the MIA.

1. Results for Liquid-Immersed Distribution Transformers
a. Liquid-Immersed Transformers--Trial Standard Level 6
First, DOE considered the most efficient level (max tech), which
would save an estimated total of 7.37 quads of energy through 2038, a
significant amount of energy. For the Nation as a whole, TSL6 would
have a net cost of $23.3 billion and $26.1 billion at seven percent and
three percent discount rates, respectively. At this level, the majority
of customers would experience an increase in life-cycle costs. As shown
in Table VI.22, only 0.5-15.2 percent of customers would experience
lower life-cycle costs, depending on the design line. Under the 2006
materials price sensitivity analysis, this percentage reduces to 0.3 to
8.6 percent of customers. The payback periods for the five-year average
materials price scenario at this standard level are between 21.6 and
52.1 years, some of which exceed the anticipated operating life of the
transformer (i.e., 32 years). Under the 2006 materials price
sensitivity analysis, the paybacks periods are longer, ranging from
26.7 to 58.3 years. The consumer equipment cost before installation
would more than double for all design lines, a significant increase for
consumers. The impacts on manufacturers would be very significant
because TSL6 would require a complete conversion to amorphous core
technology. These conversion costs would reduce the INPV by as much as
95 percent under the preservation-of-operating-profit scenario. DOE
estimates that $49 million of existing assets would be stranded (i.e.,
rendered useless) and $178 million of conversion capital expenditures
would be required to enable the industry to manufacture compliant
distribution transformers. Additionally, TSL6 would be disruptive for
manufacturers because it does not achieve the consistent treatment of
single-phase and three-phase transformers (see Appendix 8I). This lack
of consistency may cause large market distortions (i.e., shifts between
single-phase and three-phase transformers) and impact manufacturers or
plants that specialize in either single-phase or three-phase
construction. Furthermore, DOE is concerned that TSL6 requires all
distribution transformers to be constructed of amorphous material, and
there isn't sufficient amorphous-ribbon production capacity to replace
silicon core steel. Moreover, DOE's primary voltage sensitivity
analysis found that TSL6 cannot be achieved using even the most
efficient conventional silicon steels for any of the four design lines
studied (see TSD Appendix 5D), and thus TSL6 could eliminate certain
voltages from the marketplace unless amorphous core transformers were
constructed.
The energy savings at TSL6 would reduce the installed generating
capacity by 7.2 gigawatts (GW), or roughly 18 large, 400 MW power
plants. The estimated emissions reductions through this same time
period are 674 Mt of CO2. DOE 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, significant increases
in installed cost, and the large percentage of customers who would
experience life-cycle cost increases, the stranded asset and conversion
capital costs that could result in a large reduction in INPV for
manufacturers, the requirement of amorphous material construction, and
the inconsistency between single-phase and three-phase efficiency
requirements. Consequently, DOE concludes that TSL6, the max tech
level, is not economically justified.
b. Liquid-Immersed Transformers--Trial Standard Level 5
Next, DOE considered TSL5, which would save an estimated total of
5.07 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSL5 would have a net cost of $4.89 billion at a
seven percent discount rate or a net saving of $1.40 billion at a three
percent discount rate. Under the five-year average materials price
scenario, between 15.2 to 32.3 percent of customers would experience
lower life-cycle costs, and 57.7 to 84.8 percent of customers would
have increased life-cycle costs, depending on the design line. Under
the 2006 materials price sensitivity analysis, the percentage of
customers with increased life-cycle costs ranges between 56.4 and 91.4
percent. The payback periods for the five-year average material price
at this standard level are between 19.3 and 23.4 years. Under the 2006
materials price sensitivity analysis, these payback periods range
between 18.8 and 26.7 years. The consumer equipment cost before
installation would increase by as much as 138.6 percent for one of the
design lines analyzed, a significant increase for consumers. The
impacts on manufacturers would be very significant because TSL5 would
require partial conversion to amorphous core technology. The conversion
costs would contribute to as much as a 41 percent reduction in the INPV
under the preservation-of-operating-profit scenario. DOE estimates that
$13 million of existing assets would be stranded and approximately $41
million in conversion capital expenditures would be required to enable
the industry to manufacture compliant

[[Page 58229]]

transformers. Additionally, TSL5 would be disruptive for manufacturers
because it does not achieve the consistent treatment of single-phase
and three-phase transformers (see Appendix 8I). This lack of
consistency may cause large market distortions (i.e., shifts between
single-phase and three-phase transformers) and impact manufacturers or
plants that specialize in either single-phase or three-phase
construction. Furthermore, DOE is concerned that TSL5 requires three
design lines to be constructed of amorphous material, and there may not
be sufficient amorphous-ribbon production capacity to replace silicon
core steel for these design lines. Moreover, DOE's primary voltage
sensitivity analysis found that TSL5 cannot be achieved using even the
most efficient conventional silicon steels for three of the four design
lines studied (see TSD Appendix 5D), and thus TSL5 could eliminate
certain voltages from the marketplace unless amorphous core
transformers were constructed. As explained above, DOE has decided not
to set a standard that requires the use of amorphous material, even if
the requirement would affect only a small portion of the market.
The energy savings at TSL5 would reduce the installed generating
capacity by 5.0 GW, or roughly 13 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 464 Mt
of CO2. DOE 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 long payback
periods, significant increases in installed cost, and the large
percentage of customers who would experience life-cycle cost increases,
the stranded asset and conversion capital costs that could result in a
large reduction in INPV for manufacturers, the requirement of amorphous
material construction for certain design lines, and the inconsistency
between single-phase and three-phase efficiency requirements.
Consequently, DOE concludes that TSL5 is not economically justified.
c. Liquid-Immersed Transformers--Trial Standard Level A
Next, DOE considered TSLA, which would save an estimated total of
4.07 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSLA would have a net cost of $1.89 billion at a
seven percent discount rate or a net saving of $4.47 billion at three
percent discount rate. Under the five-year average materials price
scenario, 20.3 to 54.6 percent of customers would experience lower
life-cycle costs, while between 32.4 to 79.6 percent of customers would
have increased life-cycle costs. Under the 2006 materials price
sensitivity analysis, 88.5 percent of consumers would experience a net
increase in life-cycle costs for one design line. Under the five-year
average materials price scenario, the payback periods at this standard
level are between 10.6 and 24.7 years. Under the 2006 materials price
sensitivity analysis, the payback periods are longer, ranging between
10.7 and 29.1 years. The consumer equipment cost before installation
would increase by as much as 60.6 percent for one of the design lines
analyzed, a significant increase for consumers. The impacts on
manufacturers would be significant because TSLA would likely trigger
partial conversion to amorphous core technology (design lines 4 and 5).
The conversion costs would contribute to as much as a 28 percent
reduction in the INPV under the preservation-of-operating-profit
scenario. DOE estimates that $3.5 million of existing assets would be
stranded and approximately $18 million in conversion capital
expenditures would be required to enable the industry to manufacture
compliant transformers. Furthermore, DOE is concerned that TSLA
requires 84 percent of one design line to be constructed of amorphous
material, and there may not be sufficient amorphous-ribbon production
capacity to replace silicon core steel for that design line and others
that use amorphous material. Moreover, DOE's primary voltage
sensitivity analysis found that TSLA cannot be achieved using even the
most efficient conventional silicon steels for two of the four design
lines studied (see TSD Appendix 5D), and thus TSLA could eliminate
certain voltages from the marketplace unless amorphous core
transformers were constructed. As explained above, DOE has decided not
to set a standard that requires the use of amorphous material, even if
the requirement would affect only a small portion of the market.
The energy savings at TSLA would reduce the installed generating
capacity by 3.9 GW, or roughly 10 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 369 Mt
of CO2. DOE 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, significant increases in installed cost for certain design
lines, and the large percentage of customers who would experience life-
cycle cost increases, the stranded asset and conversion capital costs
that could result in a significant reduction in INPV for manufacturers,
and the high proportion of amorphous material for certain design lines.
Consequently, DOE concludes that TSLA is not economically justified.
d. Liquid-Immersed Transformers--Trial Standard Level 4
Next, DOE considered TSL4, which would save an estimated total of
3.00 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSL4 would result in a net savings of $2.13
billion and $9.33 billion at seven percent and three percent discount
rates, respectively. Under the five-year average materials price
scenario, lower life-cycle costs would be experienced by between 33.2
and 68.2 percent of customers, depending on the design line. Under this
same materials price scenario, 12.4 to 44.3 percent of customers would
have increased life-cycle costs. Under the 2006 materials price
sensitivity analysis, increased life-cycle costs are experienced by up
to 65.2 percent of customers for one design line. Under the five-year
average materials price scenario, the payback periods are between 7.8
and 11.4 years. Under the 2006 materials price sensitivity analysis,
the payback periods increase to between 10.7 and 19.4 years. The
consumer equipment cost before installation would increase by 45.9
percent for one design line, a significant increase for transformer
consumers. The LCC consumer choice model estimates that for one design
line, approximately 95 percent of the transformers sold would have
amorphous cores. The impacts on manufacturers would be significant
because TSL4 would therefore likely trigger partial conversion to
amorphous core technology (design line 4). The manufacturer conversion
costs would contribute to as much as an 18 percent reduction in the
INPV under the preservation-of-operating-profit scenario. DOE estimates
that $8.2 million of existing assets would be stranded and
approximately $17 million in conversion capital expenditures would be
required to enable the industry to manufacture compliant transformers.
Additionally, TSL4 would be disruptive for manufacturers because it
does not achieve the consistent treatment of single-phase and three-
phase transformers (see Appendix 8I).

[[Page 58230]]

This lack of consistency may cause large market distortions (i.e.,
shifts between single-phase and three-phase transformers) and impact
manufacturers or plants that specialize in either single-phase or
three-phase construction. Moreover, DOE's primary voltage sensitivity
analysis found that TSL4 cannot be achieved using even the most
efficient conventional silicon steels for one of the four design lines
studied (see TSD Appendix 5D), and thus TSL4 could eliminate certain
voltages from the marketplace unless amorphous core transformers were
constructed. As explained above, DOE has decided not to set a standard
that requires the use of amorphous material, even if the requirement
would affect only a small portion of the market.
The energy savings at TSL4 would reduce the installed generating
capacity by 2.9 GW, or roughly 7 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 272 Mt
of CO2. DOE 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
customers as indicated by the increased life-cycle costs for certain
design lines under the 2006 materials price sensitivity analysis and
large increases in installed equipment cost for some transformers, the
stranded asset and conversion capital costs that could result in a
significant reduction in INPV for manufacturers, the inconsistent
treatment of single-phase and three-phase transformers, and the partial
conversion to amorphous core material for at least one design line.
Consequently, DOE concludes that TSL4 is not economically justified.
e. Liquid-Immersed Transformers--Trial Standard Level 3
Next, DOE considered TSL3, which would save an estimated total of
2.76 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSL3 would result in a net savings of $2.37
billion and $9.17 billion at seven percent and three percent discount
rates, respectively. Under the five-year average materials price
scenario, lower life-cycle costs would be experienced by between 31.9
and 68.2 percent of customers, while between 2.0 to 18.9 percent of
customers would have increased life-cycle costs. Under the 2006
materials price sensitivity analysis, increased life-cycle costs are
experienced by between 11.1 and 48.3 percent of customers. Under this
five-year average materials price scenario, the payback periods are
between 2.4 and 11.4 years. Under the 2006 materials price sensitivity
analysis, the payback periods are between 9.8 and 17.8 years. The
consumer equipment cost before installation would increase by 45.9
percent for one design line, a significant increase for transformer
consumers. The LCC consumer choice model estimates that for one design
line, approximately 95 percent of the transformers sold would have
amorphous cores. The impacts on manufacturers would be significant
because TSL3 would therefore likely trigger partial conversion to
amorphous core technology; partial conversion is disruptive in and of
itself (but cannot be quantified). The manufacturer conversion costs
would contribute to as much as a 17 percent reduction in the INPV under
the preservation-of-operating-profit scenario. DOE estimates that $8.2
million of existing assets would be stranded and approximately $17
million in conversion capital expenditures would be required to enable
the industry to manufacture compliant transformers. Additionally, TSL3
would be disruptive for manufacturers because it does not achieve the
consistent treatment of single-phase and three-phase transformers (see
Appendix 8I). This lack of consistency may cause large market
distortions (i.e., shifts between single-phase and three-phase
transformers) and impact manufacturers or plants that specialize in
either single-phase or three-phase construction. Moreover, DOE's
primary voltage sensitivity analysis found that TSL3 cannot be achieved
using even the most efficient conventional silicon steels for one of
the four design lines studied (see TSD Appendix 5D), and thus TSL3
could eliminate certain voltages from the marketplace unless amorphous
core transformers were constructed. As explained above, DOE has decided
not to set a standard that requires the use of amorphous material, even
if the requirement would affect only a small portion of the market.
The energy savings at TSL3 would reduce the installed generating
capacity by 2.7 GW, or roughly 7 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 248 Mt
of CO2. DOE 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
customers as indicated by large increases in installed equipment cost
for some transformers, the stranded asset and conversion capital costs
that could result in a significant reduction in INPV for manufacturers,
the inconsistent treatment of single-phase and three-phase
transformers, and the partial conversion to amorphous core material for
at least one design line. Consequently, DOE concludes that TSL3 is not
economically justified.
f. Liquid-Immersed Transformers--Trial Standard Level B
Next, DOE considered TSLB, which would save an estimated total of
2.75 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSLB would result in a net savings of $1.11
billion and $7.26 billion at seven percent and three percent discount
rates, respectively. Under the five-year average materials price
scenario, lower life-cycle costs would be experienced by between 36.5
and 58.7 percent of customers, while 8.1 to 42.5 percent of customers
would have increased life-cycle costs. Under the 2006 materials price
sensitivity analysis, increased life-cycle costs are experienced by
between 17.7 and 53.8 percent of customers. Under the five-year average
materials price scenario, the payback periods are between 8.9 and 15.7
years, which at most is approximately half the anticipated operating
life of the transformer. Under the 2006 materials price sensitivity
analysis, the payback periods are slightly longer, ranging from 10.2 to
20.8 years. The manufacturer conversion costs would contribute to an 8
percent reduction in the INPV under the preservation-of-operating-
profit scenario. TSLB concerns DOE because most (i.e., 87 percent ) of
the transformers manufactured for design line 5 at this level would
require the most efficient conventional silicon core steel, M2. The LCC
consumer choice model shows that no transformers in design line 5 would
be built with M3 (or lower grade) core steel. DOE is uncertain whether
there would be adequate supplies of M2 steel and whether this steel
would be available to all manufacturers. These factors may force
manufacturers to more expensive options, including amorphous core
material.
The energy savings at TSLB would reduce the installed generating
capacity by 2.7 GW, or roughly 7 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 251 Mt
of CO2. DOE 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 placed on
manufacturers as the vast majority

[[Page 58231]]

would have to rely on the most efficient conventional silicon core
steel for one design line. A clear cost disadvantage would be imposed
on those manufacturers who could not secure sufficient or consistent M2
core steel supplies, potentially necessitating the use of amorphous
material. Consequently, DOE concludes that TSLB is not economically
justified.
g. Liquid-Immersed Transformers--Trial Standard Level C
Next, DOE considered TSLC, which would save an estimated total of
2.61 quads of energy through 2038, a significant amount of energy. For
the Nation as a whole, TSLC would result in a net savings of $1.11
billion and $6.95 billion at seven percent and three percent discount
rates, respectively. Under the five-year average materials price
scenario, lower life-cycle costs would be experienced by between 36.5
and 58.7 percent of customers, depending on the design line. At this
level, 2.5 to 42.5 percent of customers would have increased life-cycle
costs, depending on the design line. Under the 2006 materials price
sensitivity analysis, increased life-cycle costs will be experienced by
between 13.4 and 53.8 percent of customers. Under the five-year average
materials price scenario, the payback periods are between 4.3 and 15.7
years, which at most is approximately half the anticipated operating
life of the transformer. Under the 2006 materials price sensitivity
analysis, the payback periods range between 8.7 and 20.8 years. The
conversion costs of manufacturers would contribute to an 8 percent
reduction in the INPV under the preservation-of-operating-profit
scenario. The quantified impact on manufacturers is not prohibitive. In
comparison to TSLB, TSLC does not raise the same material availability
concerns for design line 5. At TSLC, the LCC consumer choice model
shows that 63% of designs would be constructed with M2 core steel, and
27% would be constructed with M3. DOE is satisfied that this provides
reasonable diversity of core steel construction options for
manufacturers. Additionally, the voltage sensitivity analysis found
that even the highest BIL ratings do not eliminate the use of M3 or M2
core steel for any of the four liquid-immersed design lines analyzed.
The energy savings at TSLC would reduce the installed generating
capacity by 2.5 GW, or roughly 6 large, 400 MW powerplants. The
estimated emissions reductions through this same time period are 238 Mt
of CO2. After considering the benefits and burdens of TSLC,
DOE 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 energy savings.
Therefore, DOE today is adopting TSLC as the energy conservation
standard for liquid-immersed distribution transformers.
2. Results for Medium-Voltage, Dry-Type Distribution Transformers
a. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 6
First, DOE considered the most efficient level (max tech), which
would save an estimated total of 0.40 quads of energy through 2038. For
the Nation as a whole, TSL6 would have a net cost of $80 million at a
seven percent discount rate and a net benefit of $1.02 billion at three
percent discount rate. At this level, the percentage of customers
experiencing lower life-cycle costs would be less than 37.9 percent for
the majority of the units analyzed, with one representative unit as low
as 21.9 percent. 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 13.8 years or greater, with one
representative unit as high as 18.7 years. The consumer equipment cost
before installation would increase by as much as 95.1 percent for one
design line, a significant increase for customers. At TSL6, the impacts
on manufacturers would be significant, with this level contributing to
a 67 percent reduction in the INPV under the preservation-of-operating-
profit scenario. DOE projects that manufacturers would experience
negative net annual cash flows during the time period between the final
rule and the effective date of the standard, irrespective of the markup
scenario. The magnitude of the peak, negative, net annual cash flow
would be approximately twice that of the positive-base-case cash flow.
DOE is also concerned that, at TSL6, the thin core steels (i.e., M3,
HO) selected by the LCC (see TSD Appendix 8H) pose operational
difficulties for the type of core-mitering equipment typically
purchased by small manufacturers.
Under the 2006 materials price sensitivity analysis, the percentage
of transformer customers who would experience higher life-cycle costs
increases relative to their life-cycle costs under the average
materials price scenario. For the 2006 materials price sensitivity,
four of the five design lines have the majority of transformer
customers experiencing higher life-cycle costs. Payback periods also
increase under the 2006 material price scenario, to between 11.4 and
24.3 years, with four of the five design lines having average payback
periods in excess of 20 years.
The energy savings at TSL6 would reduce installed generating
capacity by 0.6 GW, or roughly 1.5 large, 400 MW powerplants. DOE
estimates the associated emissions reductions through 2038 of 36.9 Mt
of CO2. DOE 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 under both the average materials price and 2006
materials price sensitivity scenario, the economic impacts on
manufacturers who may experience a drop in INPV of up to 67 percent,
and the materials handling issue for small manufacturers. Consequently,
DOE concludes that TSL6, the max tech level, is not economically
justified.
b. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 5
Since TSL5 is identical to TSL6 \26\ (i.e., for all the
representative units, TSL5 and TSL6 have the efficiency values), DOE
found that TSL5 was not economically justified for the same reasons as
TSL6, as described above in section VI.D.2.a.
---------------------------------------------------------------------------

\26\ DOE's criteria for establishing TSLs were discussed in the
NOPR. 71 FR 44378. TSL6 represents the maximum technologically
feasible standard level. TSL5 represents the standard level that has
maximum energy savings with approximately no net increase in LCC.
For medium-voltage dry-type distribution transformers, the
efficiency point values selected under these two criteria for TSL6
and TSL5 are the same, therefore the results are the same.
---------------------------------------------------------------------------

c. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 4
Next, DOE considered TSL4, which would save a total of 0.27 quads
of energy through 2038. For the Nation as a whole, TSL4 would have a
net savings of $0.45 billion and $1.55 billion at a seven percent and
three percent discount rate, respectively. For both discount rates,
this TSL represents the maximum NPV for medium-voltage, dry-type
distribution transformers. The percentage of customers experiencing
lower life-cycle costs would range between 52.6 and 74.4 percent,
depending on the design line. Payback periods at this standard level
range from 5.9 to 9.6 years. The consumer equipment cost before
installation

[[Page 58232]]

would increase by as much as 39.6 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 29
percent reduction in the INPV under the preservation-of-operating-
profit scenario. Additionally, DOE projects that manufacturers would
experience negative net annual cash flows during the time period
between the final rule and the effective date of the standard,
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. Under the 2006 materials price
sensitivity analysis, the percentage of transformer customers who would
experience higher life-cycle costs increases relative to their life-
cycle costs under the average materials price scenario. For the 2006
materials price sensitivity, three of the five design lines have the
majority of transformer customers experiencing higher life-cycle costs.
Payback periods also increase under the 2006 material price scenario,
to between 8.5 and 14.0 years.
The energy savings at TSL4 would reduce the installed generating
capacity by 0.4 GW, or roughly one large, 400 MW powerplant. DOE
estimates associated emissions reductions through 2038 of 24.8 Mt of
CO2. DOE 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, the
economic impacts associated with the 2006 materials price sensitivity
and the economic impacts on manufacturers, including materials handling
for small manufacturers. Consequently, DOE concludes that TSL4 is not
economically justified.
d. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 3
Next, DOE considered TSL3, which would save an estimated 0.19 quads
of energy through 2038. For the Nation as a whole, TSL3 would have a
net savings of $0.38 billion and $1.18 billion at a seven percent and
three percent discount rate, respectively. The percentage of
transformer customers who would experience lower life-cycle costs
ranges between 47.2 and 76.1 percent, depending on the design line,
with payback periods of 7.0 years or less. The impacts on manufacturers
at TSL3 would be significant, contributing to as much as a 25 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 time period between the final rule and the
effective date of the standard, irrespective of the markup scenario.
The magnitude of the peak negative net annual cash flow would be
approximately one-third of the positive-base-case cash flow. DOE is
also concerned that, at TSL3, the thin core steels (i.e., M3, HO)
selected by the LCC (see TSD Appendix 8H) pose operational difficulties
for the type of core-mitering equipment typically purchased by small
manufacturers. Under the 2006 materials price sensitivity analysis, the
percentage of transformer customers who would experience higher life-
cycle costs increases relative to their life-cycle costs under the
average materials price scenario. For the 2006 materials price
sensitivity, one design line has the majority of transformer customers
experiencing higher life-cycle costs. Payback periods also increase
under the 2006 material price scenario, nearly doubling with respect to
payback periods for the five-year average material price.
The energy savings at TSL3 would reduce the installed generating
capacity by 0.2 GW, or roughly 0.5 of a large, 400 MW powerplant. DOE
estimates the associated emissions reductions through 2038 of 17.1 Mt
of CO2. DOE 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, the materials handling for small
manufacturers and the economic impacts associated with the 2006
materials price sensitivity. Consequently, DOE concludes that TSL3 is
not economically justified.
e. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 2
Next, DOE considered TSL2, which would save an estimated total of
0.13 quads of energy through 2038. For the Nation as a whole, TSL2
would have a net savings of $0.28 billion and $0.85 billion at a seven
percent and three percent discount rate, respectively. The percentage
of transformer customers experiencing lower life-cycle costs ranges
between 37 and 67 percent, depending on the design line, with payback
periods of six years or less. DOE considers impacts on manufacturers at
this standard level (at most a 15 percent reduction in the INPV under
the preservation-of-operating-profit scenario) to be reasonable. At
TSL2, DOE is satisfied that there is a sufficiently diverse variety of
core steels selected by the LCC (see TSD Appendix 8H), including M5 and
M4, so that there will not be operational difficulties for the type of
core-mitering equipment typically purchased by small manufacturers.
The energy savings at TSL2 would reduce the installed generating
capacity by 0.1 GW, or roughly one-quarter of a large, 400 MW
powerplant. DOE estimates associated emissions reductions through 2037
of 11.8 Mt of CO2. DOE 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, DOE 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, DOE today adopts the energy conservation standards
for medium-voltage, dry-type distribution transformers at TSL2.

VII. Procedural Issues and Regulatory Review

A. Review Under Executive Order 12866

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, DOE has
prepared and submitted to the Office of Management and Budget (OMB) for
review the assessment of costs and benefits required under section
6(a)(3) of the Executive Order. The Executive Order requires agencies
to identify the specific market failure or other specific problem that
it intends to address that warrants new agency action, as well as
assess the significance of that problem, to enable assessment of
whether any new regulations is warranted. (Executive Order 12866, Sec.
1(b)(1)).
The specific problem that the energy conservation standard
addresses for distribution transformers is that a substantial portion
of distribution transformer purchasers are not evaluating the cost of
transformer losses when they make distribution transformer purchase
decisions. Therefore, distribution transformers are being purchased
that do not provide the minimum life-cycle cost service to equipment
owners. DOE requested and received data on, and suggestions for
evaluating the existence and extent of the problem, which DOE used to
complete an assessment in the NOPR of the significance of the problem
and the net benefits of regulation.

[[Page 58233]]

For distribution transformers, the Institute of Electrical and
Electronics Engineers, Inc. (IEEE) has voluntary guidelines for the
economic evaluation of distribution transformer losses, IEEE
PC57.12.33/D8. These guidelines document economic evaluation methods
for distribution transformers that are common practice in the utility
industry. But while economic evaluation of transformer losses is
common, it is not a universal practice. DOE collected information
during the course of the conservation standards rulemaking to estimate
the extent to which distribution transformer purchases are evaluated.
Data received from the National Electrical Manufacturers Association
indicated that these guidelines or similar criteria are applied to
approximately 75 percent of liquid-immersed transformer purchases, 50
percent of small capacity medium-voltage dry-type transformer
purchases, and 80 percent of large capacity medium-voltage dry-type
transformer purchases. Therefore, 25 percent, 50 percent, and 20
percent of distribution transformer purchases do not have economic
evaluation of transformer losses. The benefits from the energy
conservation standards result from eliminating those distribution
transformers designs from the market that are purchased on a purely
minimum first cost basis and which are unlikely to be purchased by
equipment buyers when the economic value of equipment losses are
properly evaluated. Detailed specifications of DOE's consumer purchase
behavior model, and the consumer impact estimates are provided in
Chapter 8 of the TSD.
Of course, there are likely to be certain ``external'' benefits
resulting from the improved efficiency of units that are not captured
by the users of such equipment. These include both environmental and
energy security-related externalities that are not already reflected in
energy prices such as reduced emissions of greenhouse gases and reduced
use of natural gas (and oil) for electricity generation. DOE invited
comments on the weight that should be given to these factors in DOE's
determination of the maximum efficiency level at which the total
benefits are likely to exceed the total burdens resulting from a DOE
standard. Discussion of the comments regarding these externalities is
provided in sections IV.D.2.e and IV.I.
DOE presented to OIRA for review the draft final 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.
The proposed rule contained a summary of the RIA, which evaluated
the extent to which the major alternatives to standards for
distribution transformers could achieve significant energy savings at
reasonable cost, as compared to the effectiveness of the proposed rule.
71 FR 44400-44401. The complete RIA, formally entitled, ``Regulatory
Impact Analysis for Proposed Energy Conservation Standards for
Electrical Distribution Transformers,'' is contained in the TSD
prepared for today's rule. 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 standards.
As explained in the NOPR, DOE determined that none of the
alternatives it examined would save as much energy or have an NPV as
high as the proposed standards. That same conclusion applies to the
standards in today's rule. Also, several of the alternatives would
require new enabling legislation, since authority to carry out those
alternatives does not presently exist. Additional detail on the
regulatory alternatives is found in the RIA report in the TSD.

B. Review Under the Regulatory Flexibility Act/Final Regulatory
Flexibility Analysis

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
preparation of an initial regulatory flexibility analysis (IRFA) for
any rule that by law must be proposed for public comment, and a final
regulatory flexibility analysis (FRFA) for any such rule that an agency
adopts as a final rule, unless the agency certifies that the rule, if
promulgated, will not have a significant economic impact on a
substantial number of small entities. A regulatory flexibility analysis
examines the impact of the rule on small entities and considers
alternative ways of reducing negative impacts. Also, 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. DOE 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. Prior to issuing
the proposed rule in this rulemaking, DOE interviewed six small
businesses affected by the rulemaking. DOE also obtained information
about small business impacts while interviewing manufacturers that
exceed the small business size threshold of 750 employees.
DOE reviewed the proposed rule under the provisions of the
Regulatory Flexibility Act and the procedures and policies published on
February 19, 2003. 71 FR 44401. On the basis of this review, DOE
determined that it could not certify that the proposed rule (TSL2), if
promulgated, would have no significant economic impact on a substantial
number of small entities. Id. DOE 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, DOE noted that it had
explicitly considered the impacts on small businesses that manufacture
medium-voltage, dry-type transformers in proposing to adopt TSL2 rather
than a higher trial standard level. Id. In the proposed rule, DOE also
stated and explained its belief that the proposed standards would not
have significant economic impacts on a substantial number of small
manufacturers of liquid-immersed transformers. 71 FR 44401-02.
Because of the potential impacts of the proposed standards on small
manufacturers of medium-voltage, dry-type transformers, DOE prepared an
IRFA during the NOPR stage of this rulemaking. DOE provided the IRFA in
its entirety in the NOPR, 71 FR 44401-03, and also transmitted a copy
to the Chief Counsel for Advocacy of the SBA for review. In addition,
DOE gave a presentation concerning the key portions of the IRFA to the
Chief Counsel for Advocacy of the SBA. DOE did not receive any
indication that the IRFA was insufficient either in writing or during
the aforementioned presentation to the SBA. Chapter 12 of the TSD
contains more information about the impact of this rulemaking on
manufacturers.

[[Page 58234]]

The IRFA divided 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. DOE'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 today's standards. Thus, the IRFA discussed the
potential impacts of the proposed standards on small manufacturers of
medium-voltage, dry-type transformers, and of the compliance
demonstration costs on all small manufacturers of distribution
transformers.
DOE has prepared a FRFA for this rulemaking, and it is presented in
the following discussion. DOE has transmitted a copy of this FRFA to
the Chief Counsel for Advocacy of the SBA for review. The FRFA below is
written in accordance with the requirements of the Regulatory
Flexibility Act, and addresses the stakeholder comments received in
response to the IRFA.
1. Need for and Objectives of the Rule
Today's rule is needed to satisfy the requirement in EPCA that DOE
prescribe energy conservation standards for those distribution
transformers for which DOE determines that standards would be
technologically feasible and economically justified, and would result
in significant energy savings. (42 U.S.C. 6317(a)) DOE had previously
determined that standards for distribution transformers appear to be
technologically feasible and economically justified, and are likely to
result in significant savings. 62 FR 54809 (October 22, 1997).
In accordance with EPCA, the objective of today's final rule is to
set energy conservation standards that achieve the maximum improvement
in the energy efficiency of distribution transformers that are
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)) After DOE
reviewed the comments received on the proposed rule and conducted
further analyses, DOE determined that the economic benefits of today's
standards 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.A of this notice of final rulemaking).
DOE concluded, therefore, that today's standards are economically
justified. Further information concerning the background of this
rulemaking is provided in Chapter 1 of the TSD.
2. 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), DOE 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 DOE's manufacturer impact analysis and its analysis of small
business impacts.
Liquid-immersed transformers account for about $1.3 billion in
annual sales and employment of about 4,230 production employees in the
United States. DOE 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.
Medium-voltage, dry-type transformers account 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 liquid-immersed transformers. The revenue
attributable to the medium-voltage, dry-type transformers represents
only about six percent of the total revenue of the industry affected by
this rulemaking (i.e., the sum of revenues from the liquid-immersed and
the medium-voltage, dry-type transformers). DOE 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. Thus, in relative
terms, small businesses play a more dominant role in the market for
medium-voltage, dry-type transformers than for liquid-immersed
transformers.
3. 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 DOE test
procedure.
With respect to impacts associated with transformer design and
manufacturing, the margins and/or market share of small businesses in
the medium-voltage, dry-type transformers could be hurt in the long
term by today's promulgated level, TSL2. At TSL2, as opposed to TSL1,
small manufacturers would have less flexibility in choosing a design
path. However, as explained in part 6 of the IRFA, ``Significant
Alternatives to the Rule,'' DOE explicitly considered the impacts on
small manufacturers of medium-voltage, dry-type transformers in
selecting TSL2, rather than selecting a higher trial standard level. 71
FR 44403. DOE expects that the differential impact on small
manufacturers of medium-voltage, dry-type transformers (versus large
businesses) would be smaller in moving from TSL1 to TSL2 than it would
be in moving from TSL2 to TSL3.
With respect to compliance demonstration, DOE's test procedure for
distribution transformers allows manufacturers to use 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 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). DOE's test
procedure would require periodic verification of the AEDM.
DOE's test procedure also requires manufacturers to calibrate
equipment used for testing the efficiency of transformers. Calibration
records will need to be maintained as a result of today's standard.
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 liquid-immersed and medium-voltage, dry-type
transformers, the testing, reporting, and recordkeeping requirements
have not entered into DOE's choice of trial standard level for today's
final rule.

[[Page 58235]]

4. Significant Issues Raised by Public Comments
NEMA submitted a comment that supports DOE's assessment that TSLs
higher than TSL2 would have serious impacts on small manufacturers of
medium-voltage dry-type transformers and would lead to further industry
consolidation. (NEMA, No. 156 at p. 1) NEMA also commented that TSL2
would disproportionately affect small manufacturers and greatly limit
the range of ratings that they could produce. NEMA stated that small
manufacturers do not have the investment capital to procure the
equipment necessary to produce the most efficient designs, and that
small manufacturers' current designs cannot meet TSL4 for many ratings
(it was unclear in this specific comment whether NEMA was referring to
medium-voltage dry-type transformers, liquid-immersed transformers, or
both types). (NEMA, No. 125 at p. 2) NEMA also indicated that material
availability and quota issues (for core steel, copper, and aluminum)
impact small manufacturers more severely than large manufacturers,
since small manufacturers have less leverage over suppliers and
typically have less diverse businesses. (NEMA, No. 156 at pp. 2-3)
HVOLT supported NEMA's view that small manufacturers are affected more
than large manufacturers by material availability issues. (HVOLT, Inc.,
No. 144 at p. 2) HVOLT adds that the material availability problems
that would arise at TSL2 or higher would drive small manufacturers out
of business. (HVOLT, Inc., No. 155 at p. 3; Public Meeting Transcript,
No. 108.6 at p. 138)
The PEMCO Corporation, a small manufacturer of medium-voltage dry-
type transformers, submitted a comment that conflicts with NEMA and
HVOLT and supports the information that DOE received during the
manufacturer interview process prior to the IRFA and the NOPR. During
the interviews, DOE learned that small manufacturers of medium-voltage
dry-type transformers can still choose to produce their own cores at
TSL2 (although some will purchase cores) and can profitably compete at
TSL2. 71 FR 44403. In its comment in response to the IRFA, PEMCO stated
that, with additional capital expenditures and major changes in
manufacturing practices, it can meet TSL2. PEMCO further stated that
levels above TSL2 would make it impossible for PEMCO to compete. (PEMCO
Corporation, No. 130 at p. 1) The PEMCO comment is consistent with
DOE's understanding of the potential impacts on small, medium-voltage
dry-type manufacturers. DOE's MIA suggests that while TSL2 presents
greater difficulties for small businesses than TSL1, the impacts at
TSL3 would be much greater. DOE expects that small businesses will
generally be able to profitably compete at TSL2. DOE's MIA is based on
its interviews of both small and large manufacturers, and consideration
of small business impacts explicitly enters into DOE's choice of TSL2
in promulgating minimum efficiency standards for medium-voltage dry-
type transformers.
DOE also notes that today's promulgated standard of TSL2 can be met
with a variety of materials, including multiple core steels and both
copper and aluminum windings. Because TSL2 can be met with a variety of
materials, DOE does not expect that material availability issues will
represent a substantial problem in the long-term.
ACEEE submitted a comment stating that small, medium-voltage dry-
type manufacturers would not be forced out of business at higher
standard levels because they could either install the necessary
mitering equipment or purchase finished cores. (ACEEE, No. 127 at p. 9)
DOE recognizes both of these possibilities. While DOE agrees that
standard levels higher than TSL2 would not necessarily cause all small
businesses to exit, there is a risk that a significant number of small
businesses would exit the market at TSL3 or higher. As reported in the
IRFA, the thin steels required at TSL3 and higher (M3 or better) pose
operational difficulties for the type of core-mitering equipment
typically purchased by small manufacturers. In addition, 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
much smaller sales volumes. These research and development efforts
would be required by all manufacturers (not just small manufacturers)
at TSL3 and higher because these designs are demanded only in very low
volumes today. 71 FR 44403.
As a separate matter, DOE also received comments pertaining to
small manufacturers in the liquid-immersed distribution transformer
industry (the IRFA did not pertain to liquid-immersed transformers). In
the NOPR, DOE concluded that there will be no significant economic
impact on a substantial number of small liquid-immersed manufacturers.
DOE's conclusion in the proposed rule was based on DOE's understanding
of the strategy followed by (and role played by) small liquid-immersed
transformer manufacturers in the market. Since liquid-immersed
distribution transformers are largely customized, small businesses can
compete because many of these transformers are unique designs produced
in relatively small quantities by a given customer's 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. In the NOPR, DOE stated that 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, DOE expected that conversion costs (i.e.,
research and development costs and capital investments) and the
associated manufacturer impacts on small businesses would be
insignificant at the proposed level, TSL2. 71 FR 44401-44402. Below,
DOE revisits this expectation in light of the standards promulgated
today, which are higher than TSL2.
Cooper Power Systems stated that TSL1 would help U.S. manufacturers
while TSL2 would greatly limit the range of designs that small
manufacturers of liquid-immersed transformers could produce. Cooper
also stated that TSL4 would eliminate small manufacturers. (Cooper
Power Systems, No. 154 at p. 2)
NEMA commented that DOE underestimated the impacts on small
manufacturers of liquid-immersed transformers because DOE failed to
consider materials availability issues and the quotas typically placed
on small manufacturers. NEMA pointed to quotas on both core steel and
winding materials and also the need to outsource core production.
(NEMA, No. 156 at pp. 1, 3) NEMA asserted that small manufacturers lack
the sophistication to create the most efficient designs and that high
efficiency requirements would lead to the outsourcing of core
production (especially distributed gap wound cores). (NEMA, No. 156 at
p. 3) HVOLT submitted similar comments,

[[Page 58236]]

adding that small manufacturers often do not have the requisite
relationships with material suppliers to enable them to purchase scarce
or highly sought after materials such as aluminum wire. (HVOLT, No. 155
at pp. 1-2)
Another manufacturer, Howard Industries notes that if size and
weight increases are reasonable then most of the existing manufacturing
equipment should still be usable (if fundamental technology changes are
not required). (Howard Industries, No. 143 at p. 4) DOE infers that
Howard's reference to ``fundamental technology changes'' concerns a
requirement for amorphous core technology. The information provided by
Howard is relevant to today's promulgated standard because TSLC will
not require fundamental technology changes and therefore existing
manufacturing facilities will not have to undergo substantial upgrades.
DOE appreciates the comments pertaining to the potential impacts on
small liquid-immersed transformer manufacturers. DOE believes that its
conclusion as stated in the IRFA is still valid, despite promulgating a
standard today that is higher than the proposed level of TSL2 for all
liquid-immersed design lines, except design line 4. The comments
received on the August 2006 NOPR that were suggestive of prohibitive
small business impacts that fall into two categories--those concerning
materials availability and pricing and those pertaining to the
outsourcing of distributed gap wound cores. In regard to the first
category--materials availability and pricing--DOE recognizes that there
are materials availability issues in the market today and that they are
more serious for small businesses. DOE believes that such disadvantages
for small businesses exist with or without an energy conservation
standard. DOE does not expect that the standards promulgated today will
exacerbate the problem. The standard promulgated today can be met
through a variety of design paths including the use of more than one
type of silicon core steel; in addition, the possibility of using
multiple core steels may serve to alleviate material availability
concerns in the long-term. With respect to the need of small
manufacturers of liquid-immersed transformers to outsource distributed
gap wound cores, evidence has not been presented by small businesses or
their representatives to support the claim that this practice will be
widespread. The equipment used in the liquid-immersed transformer
industry to produce distributed gap wound cores is relatively
inexpensive, and existing capacity is unlikely to become constrained
because the equipment's processing time is proportional to the mass of
steel processed (and does not increase significantly as thinner core
steels are processed). In addition, unlike some core steel processing
equipment presently used for stacked core construction, distributed gap
wound core machines are readily able to handle steel laminations as
thin as M2 without modification. See Section 12.4.1 of the TSD for
further discussion.
HVOLT believes that TSL4 would hurt small manufacturers. To make
this point, HVOLT and ERMCO pointed out at the public meeting that
ERMCO cannot generate three-phase liquid-immersed designs which meet
TSL4. HVOLT added that small businesses would have even greater
difficulty than a sophisticated manufacturer such as ERMCO. (Public
Meeting Transcript, No. 108.6 at p. 153 and pp. 163-164) ERMCO later
submitted a comment which implied that TSL4 is a feasible standard
level for all design lines except for design line 4. (ERMCO, No. 182 at
p. 1) Since today's final rule requires design line 4 to meet the lower
level in the proposed rule (TSL2), DOE believes that HVOLT's concern
expressed at the public meeting about the feasibility of TSL4 and its
implications for small businesses have been addressed. Today's standard
is below TSL4 for the three-phase designs, and in particular, regulates
design line 4 to the proposed level of TSL2.
5. Steps DOE Has Taken To Minimize the Economic Impact on Small Medium-
Voltage Dry-Type Manufacturers
In consideration of the benefits and burdens of standards,
including the burdens posed to small manufacturers, DOE concluded TSL2
is the highest level that can be justified for medium-voltage, dry-type
transformers. As explained in part 6 of the IRFA, ``Significant
Alternatives to the Rule,'' DOE explicitly considered the impacts on
small manufacturers of medium-voltage, dry-type transformers in
selecting TSL2, rather than selecting a higher trial standard level. It
is DOE's belief that levels at TSL3 or higher would place excessive
burdens on small manufacturers of medium-voltage, dry-type
transformers. Such burdens would include large product redesign costs
and also operational problems associated with the extremely thin
laminations of core steel that would be needed to meet these levels.
TSL2 essentially eliminates butt-lap core designs and will therefore
put more burden on small manufacturers than would TSL1. However, the
differential impact on small businesses (versus large businesses) is
expected to be lower in moving 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. 71 FR 44403.
Section VI.D above discusses how small business impacts entered
into DOE's selection of today's standards for medium-voltage, dry-type
transformers. DOE made its decision regarding standards by beginning
with the highest level considered (TSL6) and successively eliminating
TSLs until it finds a TSL that is both technologically feasible and
economically justified (TSL2 in this case), taking into account other
EPCA criteria. Because DOE believes that TSL2 is economically justified
(including consideration of small business impacts), the reduced impact
on small businesses that would have been realized in moving down to
TSL1 was not considered in DOE's decision (but the reduced impact on
small businesses that is realized in moving down to TSL2 from TSL3 was
explicitly considered in the weighing of benefits and burdens).
Finally, DOE notes that it received no comments in reference to any
undue burden placed on small manufacturers by the DOE test procedure
and associated compliance requirements. In the IRFA, DOE requested
feedback concerning the need to abbreviate test procedure requirements.
71 FR 44403. DOE received no comments on this issue from small
businesses and is therefore not considering abbreviated test procedure
requirements for small businesses at this time. DOE notes that the AEDM
feature of the test procedure reduces the testing burden significantly
for all manufacturers. Where manufacturers use an AEDM for a basic
model, they would not be required to test units of the basic model to
determine its efficiency for purposes of establishing compliance with
DOE requirements. 71 FR 24990 and 24997-24998.

C. Review Under the Paperwork Reduction Act

Adoption of today's final rule will have the effect of requiring
that manufacturers follow DOE's test procedure for distribution
transformers, not just for purposes of making representations, but also
to determine compliance even in the absence of any representation.
Thus, manufacturers will become subject to the record-keeping
requirements contained in the test procedure when today's energy
conservation standards for distribution

[[Page 58237]]

transformers take effect. 10 CFR Part 431, Subpart K, Appendix A; 71 FR
24972, 24998, 25007-08. As described in the Notice and Request for
Comments published on April 27, 2006, these record-keeping requirements
concern documentation of (1) the calibration of equipment that
manufacturers use in performing testing and (2) the use by
manufacturers of methods other than testing to determine the efficiency
of their distribution transformers. 71 FR 24844-24845. Because adoption
of today's standard will have the effect of imposing new information or
record-keeping requirements on liquid-immersed and medium-voltage dry-
type transformer manufacturers, DOE is seeking OMB clearance for these
test procedure requirements under the Paperwork Reduction Act (44
U.S.C. 3501 et seq.). 71 FR 24844. When today's standards become
operative on January 1, 2010, manufacturers of those products also will
be required to comply with the record-keeping provisions in today's
rule. Section 431.197(a)(4)(i) requires manufacturers of distribution
transformers to have records as to alternative efficiency determination
methods available for DOE inspection; section 6.2 of Appendix A
requires maintenance of calibration records. As a result, concurrent
with or shortly after publication of today's rule, the Department will
publish a notice seeking public comment under the Paperwork Reduction
Act, with respect to manufacturers of liquid-immersed and medium-
voltage dry-type distribution transformers, on the record-keeping
requirements in today's rule. After considering any public comments
received in response to that notice, DOE will submit the proposed
collection of information to OMB for approval pursuant to 44 U.S.C.
3507.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The information collection
requirements in section 431.197(a)(4)(i) and section 6.2 of Appendix A
will not become effective until OMB approves them. The Department will
publish a document in the Federal Register advising liquid-immersed and
medium-voltage dry-type manufacturers of their effective date. That
document also will display the OMB control number.

D. Review Under the National Environmental Policy Act

DOE prepared an environmental assessment of the impacts of today's
standards (DOE/EA-1565), which is available from: U.S. Department of
Energy, Office of Energy Efficiency and Renewable Energy, Forrestal
building, Mail Station EE-41, 1000 Independence Avenue, SW.,
Washington, DC 20585-0121, (202) 586-0854. DOE found the environmental
effects associated with various standard efficiency levels for
distribution transformers to be not significant, and therefore it is
publishing, elsewhere in this issue of the Federal Register, a Finding
of No Significant Impact 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 DOE's regulations
for compliance with the National Environmental Policy Act (10 CFR part
1021).

E. Review Under Executive Order 13132

DOE reviewed this rule pursuant to Executive Order 13132,
``Federalism,'' 64 FR 43255 (August 4, 1999), which 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 final
rule and has determined that it would 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 equipment that is the subject of today's final
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 more of them. DOE has
completed the required review and determined that, to the extent
permitted by law, this final rule meets the relevant standards of
Executive Order 12988.

G. Review Under the Unfunded Mandates Reform Act of 1995

DOE reviewed this regulatory action under Title II of the Unfunded
Mandates Reform Act of 1995 (Pub. L. 104-4) (UMRA), which requires each
Federal agency to assess the effects of Federal regulatory actions on
State, local and Tribal governments and the private sector. Today's
final rule may impose expenditures of $100 million or more on the
private sector. It does not contain a Federal intergovernmental
mandate.
Section 202 of UMRA authorizes an agency to respond to the content
requirements of UMRA in any other statement or analysis that
accompanies the proposed rule. 2 U.S.C. 1532(c). The content
requirements of section 202(b) of UMRA relevant to a private sector
mandate substantially overlap the economic analysis requirements that
apply under section 325(o) of EPCA and Executive Order 12866. The
SUPPLEMENTARY INFORMATION section of the notice of final rulemaking and
the ``Regulatory Impact Analysis'' section of the TSD for this final
rule respond to those requirements.
Under section 205 of UMRA, the Department is obligated to identify
and

[[Page 58238]]

consider a reasonable number of regulatory alternatives before
promulgating a rule for which a written statement under section 202 is
required. DOE is required to select from those alternatives the most
cost-effective and least burdensome alternative that achieves the
objectives of the rule unless DOE publishes an explanation for doing
otherwise or the selection of such an alternative is inconsistent with
law. As required by sections 325(o), 345(a) and 346(a) of EPCA (42
U.S.C. 6295(o), 6316(a) and 6317(a)), today's final rule establishes
energy conservation standards for distribution transformers that are
designed to achieve the maximum improvement in energy efficiency that
DOE has determined to be both technologically feasible and economically
justified. A full discussion of the alternatives considered by DOE is
presented in the ``Regulatory Impact Analysis'' section of the TSD for
today's final rule.

H. Review Under the Treasury and General Government Appropriations Act,
1999

DOE determined that, for this rulemaking, it need not prepare a
Family Policymaking Assessment under section 654 of the Treasury and
General Government Appropriations Act, 1999 (Pub. L. 105-277). 71 FR
44405. DOE received no comments concerning section 654 in response to
the NOPR, and, therefore, is taking no further action in today's final
rule with respect to this provision.

I. Review Under Executive Order 12630

DOE determined, under Executive Order 12630, ``Governmental Actions
and Interference with Constitutionally Protected Property Rights,'' 53
FR 8859 (March 18, 1988), that today's rule would not result in any
takings which might require compensation under the Fifth Amendment to
the United States Constitution. 71 FR 44405. DOE received no comments
concerning Executive Order 12630 in response to the NOPR, and,
therefore, is taking no further action in today's final rule with
respect to this Executive Order.

J. Review Under the Treasury and General Government Appropriations Act,
2001

Section 515 of the Treasury and General Government Appropriations
Act, 2001 (44 U.S.C. 3516 note) provides for agencies to review most
disseminations of information to the public under guidelines
established by each agency pursuant to general guidelines issued by
OMB. OMB's guidelines were published at 67 FR 8452 (February 22, 2002),
and DOE's guidelines were published at 67 FR 62446 (October 7, 2002).
DOE has reviewed today's final rule 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 of the OMB a Statement of
Energy Effects for any significant energy action. DOE determined that
the proposed rule was not a ``significant energy action'' within the
meaning of Executive Order 13211. 71 FR 44405. Accordingly, it did not
prepare a Statement of Energy Effects on the proposed rule. DOE
received no comments on this issue in response to the NOPR. As with the
proposed rule, DOE has concluded that today's final rule is not a
significant energy action within the meaning of Executive Order 13211,
and has not prepared a Statement of Energy Effects on the rule.

L. Review Under Section 32 of the Federal Energy Administration Act of
1974

Section 32 of the Federal Energy Administration Act (FEAA) of 1974
precludes DOE from adopting by rule any commercial standard unless the
agency has consulted with the Attorney General and the Chairman of the
Federal Trade Commission, and neither recommends against such
requirement. (15 U.S.C. 788) DOE indicated in the proposed rule, in a
slightly different context, that it was not proposing in this
rulemaking to require use of a commercial standard, and it concluded
that section 32 of the FEAA did not apply. DOE received no comments on
this issue. As with the proposed rule, today's rule neither
incorporates nor requires compliance with a voluntary commercial
standard. Therefore, section 32 of the FEAA does not apply to this
rule.

M. Review Under the Information Quality Bulletin for Peer Review

On December 16, 2004, OMB, in consultation with the Office of
Science and Technology (OSTP), issued its ``Final Information Quality
Bulletin for Peer Review'' (Bulletin). 70 FR 2664 (January 14, 2005).
The Bulletin establishes that certain scientific information shall be
peer reviewed by qualified specialists before it is disseminated by the
federal government, including influential scientific information
related to agency regulatory actions. The purpose of the Bulletin is to
enhance the quality and credibility of the Government's scientific
information. Under the Bulletin, the energy conservation standards
rulemakings analyses are ``influential scientific information.'' The
Bulletin defines ``influential scientific information'' as ``scientific
information the agency reasonably can determine will have, or does
have, a clear and substantial impact on important public policies or
private sector decisions.'' 70 FR 2667 (January 14, 2005).
In response to OMB's Bulletin, DOE conducted formal in-progress
peer reviews of the energy conservation standards development process
and analyses and has prepared a Peer Review Report pertaining to the
energy conservation standards rulemaking analyses. The ``Energy
Conservation Standards Rulemaking Peer Review Report'' dated February
2007 has been disseminated and is available at the following Web site:
http://www.eere.energy.gov/buildings/appliance_standards/peer_review.html
.

N. Congressional Notification

As required by 5 U.S.C. 801, DOE will submit to Congress a report
regarding the issuance of today's final rule prior to the effective
date set forth at the outset of this notice. The report will state that
it has been determined that the rule is a ``major rule'' as defined by
5 U.S.C. 804(2). DOE also will submit the supporting analyses to the
Comptroller General in the U.S. Government Accountability Office (GAO)
and make them available to each House of Congress.

VIII. Approval of the Office of the Secretary

The Secretary of Energy has approved publication of today's final
rule.

List of Subjects in 10 CFR Part 431

Administrative practice and procedure, Confidential business
information, Energy conservation, Reporting and recordkeeping
requirements.

Issued in Washington, DC, on September 28, 2007.
Alexander A. Karsner,
Assistant Secretary, Energy Efficiency and Renewable Energy.

0
For the reasons set forth in the preamble, Chapter II of Title 10, Code
of Federal Regulations, Subpart K of Part 431 is amended to read as set
forth below.

[[Page 58239]]

PART 431--ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND
INDUSTRIAL EQUIPMENT

0
1. The authority citation for part 431 continues to read as follows:

Authority: 42 U.S.C. 6291-6317.

0
2. Section 431.192 is amended by adding in alphabetical order the
definition of ``underground mining distribution transformer'' and by
revising the definition of an ``uninterruptible power supply
transformer.''

Sec. 431.192 Definitions.

* * * * *
Underground mining distribution transformer means a medium-voltage
dry-type distribution transformer that is built only for installation
in an underground mine or inside equipment for use in an underground
mine, and that has a nameplate which identifies the transformer as
being for this use only.
Uninterruptible power supply transformer means a transformer that
is used within an uninterruptible power system, which in turn supplies
power to loads that are sensitive to power failure, power sags, over
voltage, switching transients, line noise, and other power quality
factors.

0
3. Section 431.196 is amended by revising the introductory text in
paragraph (a), revising paragraphs (b) and (c), and by adding paragraph
(d) to read as follows:

Sec. 431.196 Energy conservation standards and their effective dates.

(a) Low-Voltage Dry-Type Distribution Transformers. The efficiency
of a low-voltage dry-type distribution transformer manufactured on or
after January 1, 2007, shall be no less than that required for their
kVA rating in the table below. Low-voltage dry-type distribution
transformers with kVA ratings not appearing in the table shall have
their minimum efficiency level determined by linear interpolation of
the kVA and efficiency values immediately above and below that kVA
rating.
* * * * *
(b) Liquid-Immersed Distribution Transformers. The efficiency of a
liquid-immersed distribution transformer manufactured on or after
January 1, 2010, shall be no less than that required for their kVA
rating in the table below. Liquid-immersed distribution transformers
with kVA ratings not appearing in the table shall have their minimum
efficiency level determined by linear interpolation of the kVA and
efficiency values immediately above and below that kVA rating.

------------------------------------------------------------------------
Single-phase Three-phase
------------------------------------------------------------------------
Efficiency Efficiency
kVA (%) kVA (%)
------------------------------------------------------------------------
10.......................... 98.62 15............. 98.36
15.......................... 98.76 30............. 98.62
25.......................... 98.91 45............. 98.76
37.5........................ 99.01 75............. 98.91
50.......................... 99.08 112.5.......... 99.01
75.......................... 99.17 150............ 99.08
100......................... 99.23 225............ 99.17
167......................... 99.25 300............ 99.23
250......................... 99.32 500............ 99.25
333......................... 99.36 750............ 99.32
500......................... 99.42 1000........... 99.36
667......................... 99.46 1500........... 99.42
833......................... 99.49 2000........... 99.46
............ 2500........... 99.49
------------------------------------------------------------------------
Note: All efficiency values are at 50 percent of nameplate-rated load,
determined according to the DOE Test-Procedure. 10 CFR Part 431,
Subpart K, Appendix A.

(c) Medium-Voltage Dry-Type Distribution Transformers. The
efficiency of a medium-voltage dry-type distribution transformer
manufactured on or after January 1, 2010, shall be no less than that
required for their kVA and BIL rating in the table below. Medium-
voltage dry-type distribution transformers with kVA ratings not
appearing in the table shall have their minimum efficiency level
determined by linear interpolation of the kVA and efficiency values
immediately above and below that kVA rating.

Table I.2.--Standard Levels for Medium-Voltage, Dry-Type Distribution Transformers, Tabular Form
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 97.18
25........................................ 98.33 98.12 30........................... 97.90 97.63
37.5...................................... 98.49 98.30 45........................... 98.10 97.86
50........................................ 98.60 98.42 75........................... 98.33 98.12
75........................................ 98.73 98.57 98.53 112.5........................ 98.49 98.30
100....................................... 98.82 98.67 98.63 150.......................... 98.60 98.42
167....................................... 98.96 98.83 98.80 225.......................... 98.73 98.57 98.53
250....................................... 99.07 98.95 98.91 300.......................... 98.82 98.67 98.63
333....................................... 99.14 99.03 98.99 500.......................... 98.96 98.83 98.80
500....................................... 99.22 99.12 99.09 750.......................... 99.07 98.95 98.91

[[Page 58240]]

667....................................... 99.27 99.18 99.15 1000......................... 99.14 99.03 98.99
833....................................... 99.31 99.23 99.20 1500......................... 99.22 99.12 99.09
2000......................... 99.27 99.18 99.15
2500......................... 99.31 99.23 99.20
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test-
Procedure. 10 CFR Part 431, Subpart K, Appendix A.

(d) Underground Mining Distribution Transformers. [RESERVED]
* * * * *

Appendix

[The following letters from the Department of Justice will not
appear in the Code of Federal Regulations.]

Department of Justice

Antitrust Division, Main Justice Building, 950 Pennsylvania Avenue,
NW., Washington, DC 20530-0001, (202) 514-2401/(202) 616-2645 (Fax),
E-mail: antitrust@usdoj.gov, Web site: http://www.usdoj.gov/atr.

January 16, 2007.

Warren Belmar, Esq.,
Deputy General Counsel for Energy Policy, U.S. Department of Energy,
Washington, DC 20585.

Dear Deputy General Counsel Belmar: I am responding to your
November 14, 2006 letters seeking the views of the Attorney General
about the potential impact on competition of proposed energy
efficiency standards relating to (1) liquid-immersed and medium-
voltage, dry-type distribution transformers (``distribution
transformers''), and (2) residential furnaces and boilers
(``furnaces and boilers''). The Energy Policy and Conservation Act
(``EPCA'') authorizes the Department of Energy (``DOE'') to
establish energy conservation standards for a number of appliances
where DOE determines that those standards would be technologically
feasible, economically justified, and result in significant energy
savings.
Your requests were submitted pursuant to Section 325(o)(2)(B)(I)
of the Energy Policy and Conservation Act, 42 U.S.C. 6291. 6295
(``EPCA''), which states that, before the Secretary of Energy may
prescribe a new or amended energy conservation standard, the
Secretary shall ask the Attorney General to make a determination of
``the impact of any lessening of competition * * * that is likely to
result from the imposition of the standard.'' The Attorney General's
responsibility for responding to requests from other departments
about the effect of a program on competition has been delegated to
the Assistant Attorney General for the Antitrust Division in 28 CFR
0.40(g). In conducting its analysis the Antitrust Division examines
whether a standard may lessen competition, for example, by placing
certain manufacturers of a product at an unjustified competitive
disadvantage compared to other manufacturers, or by inducing
avoidable inefficiencies in production or distribution of particular
products. In addition to harming consumers directly through higher
prices, these effects could undercut the ultimate goals of the
legislation.
Your requests included the Notices of Proposed Rulemaking
(``NOPR'') that were published in the Federal Register and
transcripts of public hearings relating to the proposed standards.
The NOPR relating to distribution transformers proposed Trial
Standard Level 2 and explained why DOE had decided not to propose
higher trial standard levels. The NOPR relating to furnaces and
boilers proposed the following standards: 80% annual fuel
utilization efficiency (``AFUE'') for non-weatherized gas furnaces
and mobile home gas furnaces; 82% AFUE for oil-fired furnaces; 83%
AFUE for weatherized gas furnaces and oil-fired boilers; and 84%
AFUE for gas boilers. Our review regarding distribution transformers
and furnaces and boilers has focused upon the standards DOE has
proposed adopting; we have not determined the impact on competition
of more stringent standards than those set forth in the NOPRs.
In addition to the NOPRs and transcripts, your staff provided us
comments that had been submitted to DOE regarding the proposed
standards. (We understand that the docket has not closed with
respect to furnaces and that more comments may be forthcoming.) We
have reviewed these materials and additionally conducted interviews
with members of the industries.
Based on this inquiry, the Division is concerned that the
distribution transformer Trial Standard Level 2 may adversely affect
competition with respect to distribution transformers used in
industries, such as underground coal mining, where physical
conditions limit the size of equipment that can be effectively
utilized. We understand manufacturers would not be able to satisfy
the proposed standard without increasing the size (or decreasing the
power) of each class of distribution transformer. Firms facing space
constraints would incur significantly increased costs due to
enlarging the required installation space (which, for example, could
involve removal of solid rock around coal seams in underground
mines) or reconfiguring the size and number of each class of
distribution transformers at each site. The resulting cost increases
could constitute production inefficiencies that could make certain
products less competitive. For example, the rule could, by raising
the costs of certain coal mines, adversely affect production
decisions at those mines and potentially result in increased use of
less efficient energy alternatives. We urge the DOE to consider
these concerns carefully in its analysis, and to consider creating
an exception for distribution transformers used in industries with
space constraints.
The Division is also concerned that the standards for
weatherized gas furnaces and gas boilers could adversely affect
competition. We understand that manufacturers would have difficulty
designing products that safely meet the proposed standards. For
weatherized gas furnaces, meeting the standard would like result in
increased condensation, potentially resulting in significant
deterioration that would jeopardize the safety of the product, and,
for weatherized gas-fired water boilers, meeting the standard would
make effective carbon dioxide venting more difficult. Any resulting
costs incurred to solve these issues could adversely affect the
competitiveness of these products in relation to electric heat pumps
and water heaters. We urge the DOE to carefully consider its
proposed standards in light of these concerns.
Aside from the discussion above, the Division does not otherwise
believe the proposed standards would adversely impact competition.

Yours sincerely,

J. Bruce McDonald,
Acting Assistant Attorney General.

Department of Justice

Antitrust Division, Main Justice Building, 950 Pennsylvania Avenue,
NW., Washington, DC 20530-0001, (202) 514-2401 / (202) 616-2645
(Fax), E-mail: antitrust@usdoj.gov, Web site: http: //http://www.usdoj.gov/atr
.

September 6, 2007.
Warren Belmar, Esq.,
Deputy General Counsel for Energy Policy, U.S. Department of Energy,
Washington, DC 20585.

Dear Deputy General Counsel Belmar: I am responding to your
August 7, 2007 letter seeking the views of the Attorney General
about the potential impact on competition of the proposed final rule
regarding energy

[[Page 58241]]

conservation standards for liquid-immersed and medium-voltage, dry-
type distribution transformers (``distribution transformers''). The
Energy Policy and Conservation Act (``EPCA'') authorizes the
Department of Energy (``DOE'') to establish energy conservation
standards for a number of appliances where DOE determines that those
standards would be technologically feasible, economically justified,
and result in significant energy savings.
Your request was submitted pursuant to Section 325(o)(2)(B)(I)
of the Energy Policy and Conservation Act, 42 U.S.C. 6291.6295
(``EPCA''), which states that before the Secretary of Energy may
prescribe a new or amended energy conservation standard, the
Secretary shall ask the Attorney General to make a determination of
``the impact of any lessening of competition * * * that is likely to
result from the imposition of the standard.'' The Attorney General's
responsibility for responding to requests from other departments
about the effect of a program on competition has been delegated to
the Assistant Attorney General for the Antitrust Division in 28 CFR
0.40(g). In conducting its analysis the Antitrust Division examines
whether a standard may lessen competition, for example, by placing
certain manufacturers of a product at an unjustified competitive
disadvantage compared to other manufacturers, or by inducing
avoidable inefficiencies in production or distribution of particular
products. In addition to harming consumers directly through higher
prices, these effects could undercut the ultimate goals of the
legislation.
Along with your request, you sent us the draft final rule and a
number of other documents relating to distribution transformers,
including the comments that had been submitted to DOE in response to
the Notice of Proposed Rulemaking (``NOPR''), the Notice of Data
Availability (``NODA'') issued by DOE earlier this year that
discussed standards DOE was considering, and comments DOE received
regarding the NODA.
In November of 2006, you requested DOJ's views regarding the
NOPR, which proposed Trial Standard Level 2. By letter dated January
16, 2007, we responded that, based on our inquiry, we were concerned
that the distribution transformer standard might adversely affect
competition with respect to distribution transformers used in
industries, such as underground coal mining, where physical
conditions limit the size of equipment that can be effectively
utilized. We urged DOE to consider creating an exception for
distribution transformers used in industries with space constraints.
You have addressed our concern by establishing a separate
product class for underground mining transformers and excluding that
class from the proposed final rule. Although our January 16, 2007
letter did not limit our concern to underground mining transformers,
we believe DOE's decision to exclude underground mining transformers
from the proposed final rule adequately addresses our concern.
Our review of the NOPR was limited to the impact of Trial
Standard Level 2 on competition. The proposed final rule would
establish a more stringent standard than Trial Standard Level 2 for
certain distribution transformers. Specifically, it establishes
Trial Standard Level 3 as the standard for certain three phase
liquid-immersed distribution transformers, with a commensurate
standard for certain single phase liquid-immersed distribution
transformers. To ascertain whether the more stringent standard would
adversely impact competition, we have evaluated the comments DOE
received in response to the NODA, which had stated DOE was
contemplating Trial Standard Level 2 or 3 for three phase liquid-
immersed distribution transformers. We have also conducted industry
interviews. Based on this review, we have concluded that the
proposed final rule's application of Trial Standard Level 3 to
certain three phase liquid-filled distribution transformers and the
comparable standard to certain single phase liquid-filled
distribution transformers would not adversely affect competition.
In conclusion, the Antitrust Division does not believe the
proposed final rule would adversely affect competition.

Yours sincerely,

Deborah A. Garza,
Acting Assistant Attorney General.

[FR Doc. E7-19582 Filed 10-11-07; 8:45 am]

BILLING CODE 6450-01-P