[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 (%)
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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.
Table I.2.--Standard Levels for Medium-Voltage, Dry-Type Distribution Transformers, Tabular Form
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Single-phase Three-phase
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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
(%) (%) (%) (%) (%) (%)
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15........................................ 98.10 97.86 ............ 15........................... 97.50 97.18 ...........
25........................................ 98.33 98.12 ............ 30........................... 97.90 97.63 ...........
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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\
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\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
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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
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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 wi