[Federal Register Volume 72, Number 197 (Friday, October 12, 2007)]
[Rules and Regulations]
[Pages 58190-58241]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-19582]



[[Page 58189]]

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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

  Federal Register / Vol. 72, No. 197 / Friday, October 12, 2007 / 
Rules and Regulations  

[[Page 58190]]


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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: 
[email protected].

    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: [email protected].


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

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    a. Liquid-Immersed Transformers--Trial Standard Level 6
    b. Liquid-Immersed Transformers--Trial Standard Level 5
    c. Liquid-Immersed Transformers--Trial Standard Level A
    d. Liquid-Immersed Transformers--Trial Standard Level 4
    e. Liquid-Immersed Transformers--Trial Standard Level 3
    f. Liquid-Immersed Transformers--Trial Standard Level B
    g. Liquid-Immersed Transformers--Trial Standard Level C
    2. Results for Medium-Voltage, Dry-Type Distribution 
Transformers
    a. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 6
    b. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 5
    c. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 4
    d. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 3
    e. Medium-Voltage, Dry-Type Transformers--Trial Standard Level 2
VII. Procedural Issues and Regulatory Review
    A. Review Under Executive Order 12866
    B. Review Under the Regulatory Flexibility Act/Final Regulatory 
Flexibility Analysis
    C. Review Under the Paperwork Reduction Act
    D. Review Under the National Environmental Policy Act
    E. Review Under Executive Order 13132
    F. Review Under Executive Order 12988
    G. Review Under the Unfunded Mandates Reform Act of 1995
    H. Review Under the Treasury and General Government 
Appropriations Act, 1999
    I. Review Under Executive Order 12630
    J. Review Under the Treasury and General Government 
Appropriations Act, 2001
    K. Review Under Executive Order 13211
    L. Review Under Section 32 of the Federal Energy Administration 
Act of 1974
    M. Review Under the Information Quality Bulletin for Peer Review
    N. Congressional Notification
VIII. Approval of the Office of the Secretary

I. Summary of the Final Rule and Its Benefits

A. The Standard Levels

    The Energy Policy and Conservation Act (EPCA), as amended, directs 
the Department of Energy (DOE) to adopt energy conservation standards 
for those distribution transformers for which standards would be 
technologically feasible and economically justified, and would result 
in significant energy savings. (42 U.S.C. 6317(a)(2)) The standards in 
today's final rule, which apply to liquid-immersed and medium-voltage, 
dry-type distribution transformers, satisfy these requirements and will 
achieve the maximum improvements in energy efficiency that are 
technologically feasible and economically justified. In the advance 
notice of proposed rulemaking (ANOPR) in this proceeding, DOE had also 
addressed standards for low-voltage, dry-type distribution 
transformers. 69 FR 45376 (July 29, 2004). However, the Energy Policy 
Act of 2005, Public Law 109-58, (EPACT 2005) amended EPCA to establish 
energy conservation standards for those transformers. (EPACT 2005, 
Section 135(c); 42 U.S.C. 6295(y)) Therefore, DOE removed low-voltage, 
dry-type distribution transformers from the scope of this rulemaking.
    The standards established in this final rule are minimum efficiency 
levels. Tables I.1 and I.2 show the standard levels DOE is adopting 
today. These standards will apply to liquid-immersed and medium-
voltage, dry-type distribution transformers manufactured for sale in 
the United States, or imported to the United States, on or after 
January 1, 2010. As discussed in section V.C.2 of this notice, any 
transformers whose kVA\1\ rating falls between the kVA ratings shown in 
tables I.1 and I.2 shall have its minimum efficiency requirement 
calculated by a linear interpolation of the minimum efficiency 
requirements of the kVA ratings immediately above and below that 
rating.
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    \1\ kVA is an abbreviation for kilovolt-ampere, which is a 
capacity metric used by industry to classify transformers. A 
transformer's kVA rating represents its output power when it is 
fully loaded (i.e., 100%).

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


                            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,

[[Page 58194]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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/pn/ndn0304.zip. For
                                 years 1950-1976, used
                                 EIA's electricity
                                 sales data. Source:
                                 http://www.eia.doe.gov/emeu/aer/txt/stb0805.xls.
Shipments forecast............  Years 2002-2035: Based  Years 2010-2038:
                                 on AEO2005.             Based on
                                                         AEO2007.
Dry-type/liquid-immersed        Based on EIA's          Based on EIA's
 market shares.                  electricity sales       electricity
                                 data and AEO2005.       sales data and
                                                         AEO2007.
Regular replacement market....  Based on a survival     No change.
                                 function constructed
                                 from a Weibull
                                 distribution function
                                 normalized to produce
                                 a 32-year mean
                                 lifetime. Source:
                                 ORNL 6804/R1, The
                                 Feasibility of
                                 Replacing or
                                 Upgrading Utility
                                 Distribution
                                 Transformers During
                                 Routine Maintenance,
                                 page D-1.
Elasticities, liquid-immersed.  For liquid-immersed     No change.
                                 transformers.
                                 Low: 0.00....
                                 Medium: -0.04
                                 High: -0.20..
Elasticities, dry-type........  For dry-type            No change.
                                 transformers.
                                 Low: 0.00....
                                 Medium: -0.02
                                 High: -0.20..
------------------------------------------------------------------------


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

[[Page 58200]]

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

A. Market and Technology Assessment

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

[[Page 58201]]

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

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

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

[[Page 58202]]

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

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

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

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

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

[[Page 58203]]

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

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

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

[[Page 58204]]

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

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

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

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

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

B. Engineering Analysis

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

[[Page 58205]]

methodology followed for the engineering analysis.

C. Life-Cycle Cost and Payback Period Analysis

    The LCC is the total customer cost over the life of the equipment, 
including purchase expense and operating costs (including energy 
expenditures and maintenance). To compute the LCC, DOE summed the 
installed price of a transformer and the discounted annual future 
operating costs over the lifetime of the equipment. The PBP is the 
change in purchase expense due to an increased efficiency standard 
divided by the change in first-year operating cost that results from 
the standard. DOE expresses PBP in years. The data inputs to the PBP 
calculation are the purchase expense (otherwise known as the total 
installed consumer cost or first cost) and the annual operating costs 
for each selected design. The inputs to the transformer purchase 
expense are the equipment price and the installation cost, with 
appropriate markups to reflect price increases as the transformer 
passes through the distribution channel. The inputs to the operating 
costs are the annual energy consumption and the electricity price. The 
PBP calculation uses the same inputs as the LCC analysis but, since it 
is a simple payback, the operating cost is for the year the standard 
takes effect, assumed to be 2010.
    For each efficiency level DOE analyzed, the LCC analysis required 
input data for the total installed cost of the equipment, the operating 
cost, and the discount rate. Equipment price, installation cost, and 
baseline and standard design selection affect the installed cost of the 
equipment. Transformer loading, load growth, power factor, annual 
energy use and demand, electricity costs, electricity price trends, and 
maintenance costs affect the operating cost. The effective date of the 
standard, the discount rate, and the lifetime of equipment affect the 
calculation of the present value of annual operating cost savings from 
a proposed standard.
    The following sections contain brief discussions of comments on the 
inputs and key assumptions of DOE's LCC analysis and explain how DOE 
took these comments into consideration.
1. Inputs Affecting Installed Cost
a. Installation Costs
    Higher efficiency distribution transformers tend to be larger and 
heavier than less efficient designs. DOE therefore included the 
increased cost of installing larger, heavier transformers as a 
component of the first cost of more efficient transformers. In the 
NOPR, DOE presented the installation cost model and solicited comment 
from stakeholders. For details of the installation cost calculations, 
see TSD section 7.3.1.
    In response to both the NOPR and the NODA, many stakeholders 
commented that it is important for DOE to take into consideration the 
costs and reliability impacts of installing transformers in space-
constrained situations. ACEEE recommended that DOE factor into its 
calculations space-constraint costs, based on the percentage of 
transformers that will necessitate modification of the vaults in which 
they are installed and the average cost for such modifications. (Public 
Meeting Transcript, No. 108.6 at pp. 130-131) EEI noted that DOE's 
analysis should include a space occupancy factor, although it might be 
hard to estimate. (Public Meeting Transcript, No. 108.6 at p. 129) In 
addition, EEI expressed concern regarding size and weight implications 
for the reliability and cost of the transformer, especially for TSL4, 
noting that, for pole-mounted transformers, more weight will increase 
the stress on poles and noting that manufacturers doubt that they can 
produce all equipment needed at TSL4. (Public Meeting Transcript, No. 
108.6 at p. 31) HVOLT recommended that the analysis account for volume 
and weight in a mathematical equation to account for space occupancy 
costs. (Public Meeting Transcript, No. 108.6 at p. 129) NEMA commented 
that, with higher standards, manufacturers may use lower quality steel 
and switch from copper to aluminum, and that this may increase the 
weight and/or size of transformers. (Public Meeting Transcript, No. 
108.6 at p. 132) Metglas commented that transformers are smaller and 
lighter than those made 30-40 years ago, and stated that there will not 
be an issue with size and weight of amorphous core transformers. 
(Metglas, No. 144 at p. 3)
    DOE responded to the comments raised regarding space-constraint 
implications for installation costs by formulating a method and a cost 
equation for estimating the economic impacts of space constraints and 
issuing a NODA that solicited comments on the method and equations 
proposed for evaluating such costs. 72 FR 6186-6190. DOE then performed 
a subgroup analysis of space-constrained vault transformers, for which 
DOE modeled potential standards-induced vault modification costs with 
an appropriate equation that included both fixed and volume-dependent 
variable components. The results of this analysis are detailed in 
Chapter 11 of the TSD, and DOE took these costs into consideration in 
the selection of the standard level for this rule.
b. Baseline and Standard Design Selection
    A major factor in estimating the economic impact of a proposed 
standard is the selection of transformer designs in the base case and 
standards case scenarios. A key issue in the selection process is the 
degree to which transformer purchasers take into consideration the cost 
of transformer losses (A and B factors) when choosing a transformer 
(i.e., whether they ``evaluate''), both before and after the 
implementation of a standard. The purchase-decision model in the LCC 
spreadsheet selects which of the hundreds of designs in the engineering 
database are likely to be selected by transformer purchasers. The LCC 
transformer selection process is discussed in detail in TSD Chapter 8, 
section 8.2.
    DOE received several comments regarding the fraction of transformer 
purchasers that evaluate distribution transformer electrical losses 
before purchase and how transformer purchasers evaluate these losses. 
HVOLT estimates that 20 percent of the market for medium-voltage, dry-
type transformers evaluates and places a value of $3.00/watt on loss 
evaluation, while the market share of transformers meeting TP 1 levels 
for liquid-immersed transformers is 75 to 80 percent. (Public Meeting 
Transcript, No. 108.6 at p. 216) NEMA commented that 10 years ago there 
was a trend where customers bought cheaper and less efficient 
transformers every year due to less loss evaluation, but that the 
market has turned around and now an increasing percentage of customers 
are buying the more efficient TP 1 transformers. NEMA also noted that 
the shipments data it has submitted over the years to DOE have shown 
this changing trend. (Public Meeting Transcript, No. 108.6 at p. 220; 
NEMA, No. 125 at p. 3)
    In response to these comments, DOE developed its baseline market 
model using the most detailed and reliable data available. This 
included data that NEMA supplied providing TP 1 transformer market 
shares, in addition to publicly available data regarding evaluation 
parameters used by distribution transformer purchasers. For the final 
rule, DOE set average A and B values of 3.85 and 1.16 $/watt 
respectively for design lines 1, 2 and 4, and average A and B values of 
3.85 and 1.93 $/watt for design lines 3 and 5. These slight adjustments 
to the

[[Page 58206]]

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

[[Page 58207]]

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

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

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

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

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

[[Page 58208]]

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

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

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

[[Page 58209]]

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

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

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

E. Commercial Consumer Subgroup Analysis

    In analyzing the potential impacts of new or amended standards, DOE 
evaluates impacts on identifiable groups (i.e., subgroups) of 
customers, such as different types of businesses, which may be 
disproportionately affected by a national standard. For this 
rulemaking, DOE identified rural electric cooperatives and municipal 
utilities as transformer consumer subgroups that could be 
disproportionately affected, and examined the impact of proposed 
standards on these groups. The consumer subgroup analysis is discussed 
in detail in TSD Chapter 11.

[[Page 58210]]

F. Manufacturer Impact Analysis

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

G. Employment Impact Analysis

    Indirect employment impacts from distribution transformer standards 
consist of the net jobs created or eliminated in the national economy, 
other than in the manufacturing sector being regulated. These indirect 
employment impacts are a consequence of: (1) Reduced spending by end 
users on energy (electricity, gas--including liquefied petroleum gas--
and oil); (2) reduced spending on new energy supply by the utility 
industry; (3) increased spending on the purchase price of new 
distribution transformers; and (4) the effects of those three factors 
throughout the economy. DOE expects the net monetary savings from 
standards to be redirected to other forms of economic activity. DOE 
also expects these shifts in spending and economic activity to affect 
the demand for labor.
    DOE did not receive stakeholder comments on its net national 
employment estimation methodology. DOE therefore retained the same 
methodology that it used in the NOPR. For more details on the 
employment impact analysis, see TSD Chapter 14.

H. Utility Impact Analysis

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

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

I. Environmental Analysis

    DOE determined the environmental impacts of the proposed standards. 
Specifically, DOE calculated the reduction in power plant emissions of 
carbon dioxide (CO2), SO2, NOX, and 
mercury (Hg), using the NEMS-BT computer model. The environmental 
assessment published with the TSD, however, does not include the 
estimated reduction in power plant emissions of SO2 because, 
as discussed below, any such reduction resulting from an efficiency 
standard would not affect the overall level of SO2 emissions 
in the U.S.
    NEMS-BT is run similarly to the AEO2006 NEMS, except that in NEMS-
BT distribution transformer energy usage is reduced by the amount of 
energy (by fuel type) saved due to the proposed TSLs. DOE obtained the 
input of energy savings from the NES spreadsheet. For the environmental 
analysis, the output is the forecasted physical emissions. The net 
benefit of the standard is the difference between emissions estimated 
by NEMS-BT and the AEO2006 Reference Case. While DOE used AEO2007 for 
electricity price forecasts, the most recent version of NEMS-BT 
available to DOE for the environmental and utility analysis was based 
on AEO2006. As discussed above, DOE found that the differences between 
the marginal generation mix and emissions factors between AEO2007 and 
AEO2006 forecasts are very small which implies that generation, fuel 
consumption and emissions estimates will have a similarly small 
relative difference between AEO2007 and AEO2006. Therefore DOE 
performed no further updates to the environmental and utility analyses 
for the final rule analysis beyond the AEO2006 results. (See TSD 
Chapter 13)
    NEMS-BT tracks CO2 emissions using a detailed module 
that provides robust results because of its broad coverage of all 
sectors and inclusion of economic interactions between sectors that can 
impact emissions. DOE based the NOX reductions on forecasts 
of compliance with the Clean Air Interstate Rule recently promulgated 
by EPA. 69 FR 25184 (May 5, 2004); 69 FR 32684 (June 10, 2004); and 70 
FR 25162 (May 12, 2005). In the case of SO2, the Clean Air 
Act Amendments of 1990 set an emissions cap on all power generation. 
The attainment of this target, however, is flexible among generators 
and is enforced by applying market forces, through the use of emissions 
allowances and tradable permits. As a result, accurate simulation of 
SO2 trading tends to imply that the effect of efficiency 
standards on physical emissions will be near zero because emissions 
will always be at, or near, the ceiling. Thus, there is virtually no 
real possible SO2 environmental benefit from electricity 
savings as long as there is enforcement of the emissions ceilings. See 
the environmental assessment, a separate report within the TSD, for a 
discussion of these issues.
    In response to the NOPR, DOE received comments regarding the 
potential economic benefits of emissions reductions. ACEEE commented 
that the EIA forecast does

[[Page 58211]]

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

V. Discussion of Other Comments

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

A. Information and Assumptions Used in Analyses

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

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

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

[[Page 58212]]

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

[[Page 58213]]

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

B. Weighing of Factors

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

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

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

[[Page 58214]]

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

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

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

[[Page 58215]]

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

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

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

[[Page 58216]]

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

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

C. Other Comments

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

[[Page 58217]]

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

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

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

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

VI. Analytical Results and Conclusions

A. Trial Standard Levels

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

[[Page 58218]]

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

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

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

B. Significance of Energy Savings

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

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

C. Economic Justification

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

[[Page 58219]]



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


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


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


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


[[Page 58220]]


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


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


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


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


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


[[Page 58221]]


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

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

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


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


[[Page 58222]]

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

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


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

[[Page 58223]]

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

    The proposed rule provides additional information on the 
methodology, assumptions, and results of this analysis. 71 FR 44382, 
44390, 44399-44400, 44403. Chapter 12 of the TSD explains DOE's method 
for conducting the manufacturer impact analysis and presents the 
detailed results of that analysis.
b. Impacts on Employment
    For liquid-immersed transformers, DOE expects no significant, 
discernable direct employment impacts among transformer manufacturers 
for TSLs 1, 2, D, C, B, 3, and 4, but potentially significant changes 
in employment for TSLA (44 percent increase), TSL5 (18 percent 
increase), and TSL6 (38 percent increase). Employment impacts are 
changes in the numbers of employees involved with transformer 
production at the manufacturing facilities. These estimated changes are 
due to the increased labor time needed to construct the cores and 
assemble the transformers. At these higher TSLs, the cores tend to be 
larger and the processing time per pound of amorphous material is 
higher than that of silicon steel--both of these effects lead to the 
need for more labor. Thus, the larger cores would increase the direct 
employment at transformer manufacturing facilities.
    These conclusions--which are separate from any conclusions 
regarding employment impacts on the broader U.S. economy--are based on 
modeling results that address neither the possible relocation of 
domestic transformer manufacturing employment to lower labor-cost 
countries, nor the possibility of outsourcing amorphous core production 
under TSLs 3, 4, A, 5 and 6 to companies in other countries. The 
reported modeling results simply capture the changes in direct labor 
needed to produce transformers at each TSL. DOE discussed this scenario 
of outsourcing amorphous core production to other countries during 
several interviews with manufacturers of liquid-immersed transformers, 
and it appears that outsourcing would be a serious consideration for 
some liquid-immersed transformer manufacturers under TSLs 3, 4, A, 5, 
and 6.
    In addition, as discussed in the proposed rule, DOE expects today's 
standard to have a relatively minor differential impact on small 
manufacturers of liquid-immersed distribution transformers. 71 FR 
44382, 44392-44393, 44401-44403. For medium-voltage, dry-type 
manufacturers, however, all manufacturers would have to develop designs 
to enable compliance with TSL3 or higher, and small businesses would be 
at a relative disadvantage.
    DOE expects no significant, discernable employment impacts among 
medium-voltage, dry-type transformer manufacturers for any TSL compared 
to the base case. DOE's conclusion regarding employment impacts in the 
medium-voltage, dry-type transformer industry is separate from any 
conclusions regarding employment impacts on the broader U.S. economy. 
Increased employment levels are not expected at higher TSLs because the 
core-cutting equipment typically purchased by the medium-voltage, dry-
type industry is highly automated and includes core-stacking equipment.
    Another concern conveyed by some manufacturers of medium-voltage, 
dry-type transformers during the interviews is the potential impact 
stemming from cast-coil transformer competitiveness at higher TSLs. 
These manufacturers claimed that setting a standard above a certain 
threshold may trigger a market switch from open-wound ventilated 
transformers to cast-coil transformers. Manufacturers suggest that this 
crossover point likely occurs at TSL3 and higher. If the market does 
shift to cast-coil transformers, there is a risk of imported, pre-
fabricated cast coils dominating the market in the long term. This 
would have a significant impact on domestic industry value and domestic 
employment in the medium-voltage, dry-type industry.
    The basis for the conclusions presented above is set forth in 
Chapter 12 of the TSD, Sections 12.4.4.1 and 12.5.4.1 for liquid-
immersed and medium-voltage, dry-type transformers, respectively.
c. Impacts on Manufacturing Capacity
    For the liquid-immersed distribution transformer industry, DOE 
believes that there are only minor production capacity implications for 
a standard at TSLs 1, 2, D, C, and B. At TSL6, all liquid-immersed 
design lines would have to convert to amorphous technology, the most 
energy efficient core material. At TSL5, three design lines would have 
to convert to amorphous core designs. For TSLs A, 4, and 3, there would 
likely be partial conversion to amorphous core designs for one or two 
design lines. Conversion to amorphous core designs would render 
obsolete a large portion of the equipment used today for the affected 
design lines (e.g., annealing furnaces, core-cutting and winding 
equipment). Based on the manufacturer interviews, DOE believes that 
TSLs 3, 4, A, 5, and 6 would cause liquid-immersed transformer 
manufacturers to decide whether they would need to invest in retooling 
their production equipment for amorphous technology or attempt to 
purchase pre-fabricated amorphous cores (for the affected design 
lines). For TSL6, some manufacturers indicated that they would close 
their companies, rather than attempt to manufacturer transformers at 
that standard level. Manufacturers also indicated that, if they were to 
choose to produce amorphous cores themselves, they would face a 
critical decision about whether or not to relocate outside of the U.S., 
since much of their equipment would become obsolete. As mentioned 
above, if manufacturers choose to purchase pre-fabricated amorphous 
cores, they might purchase them from foreign manufacturers.
    Energy conservation standards will affect the medium-voltage, dry-
type industry's manufacturing capacity because the core stack heights 
(or core steel piece length) will increase and laminations will become 
thinner. Thinner laminations require more cuts and are more cumbersome 
to handle. Therefore, manufacturers would have to invest in additional 
core-mitering machinery or modifications and improvements to recover 
any losses in

[[Page 58224]]

productivity, and these factors might also contribute to a need for 
more plant floor space. Because more efficient transformers tend to be 
larger, this could also contribute to the need for additional 
manufacturing floor space.
d. Impacts on Manufacturers That Are Small Businesses
    Converting from a company's current basic product line involves 
designing, prototyping, testing, and manufacturing a new product. These 
tasks have associated capital investments and product conversion 
expenses. Small businesses, because of their limited access to capital 
and their need to spread conversion costs over smaller production 
volumes, may be affected more negatively than major manufacturers by an 
energy conservation standard. For these reasons, DOE specifically 
evaluated the impacts on small businesses of an energy conservation 
standard.
    The Small Business Administration defines a small business, for the 
distribution transformer industry, as a business that has 750 or fewer 
employees. DOE estimates that, of the approximately 25 U.S. 
manufacturers that make liquid-immersed distribution transformers, 
about 15 of them are small businesses. About five of the small-liquid-
immersed-transformer businesses have fewer than 100 employees. DOE 
estimates that, of the 25 U.S. manufacturers that make medium-voltage, 
dry-type distribution transformers, about 20 of them are small 
businesses. About one-half of the medium-voltage, dry-type small 
businesses have fewer than 100 employees. Medium-voltage, dry-type 
transformer manufacturing is more concentrated than liquid-immersed 
transformer manufacturing; the top three companies manufacture over 75 
percent of all transformers in this category.
    As discussed in the proposed rule, DOE expects minimum efficiency 
standards to have a relatively minor differential impact on small 
manufacturers of liquid-immersed distribution transformers. 71 FR 
44401-44402. Although DOE proposed to adopt TSL2, and is today 
promulgating a standard higher than that for all liquid-immersed design 
lines other than design line 4, DOE believes that the reasoning 
presented in the proposed rule is still relevant and valid: DOE does 
not expect today's standard to have a significant economic impact on a 
substantial number of small manufacturers of liquid-immersed 
transformers. Since the standard does not require manufacturers to 
change manufacturing equipment, DOE concludes that the standards 
adopted today will have minor differential impact on small 
manufacturers of liquid-immersed transformers. This is based on the 
fact that manufacturing equipment and materials that are currently 
available will be used to meet the standard which will provide 
manufacturers flexibility in meeting the standards, and manufacturers 
will not be required to re-tool in order to meet the standards. (See 
Section VII.B.4). For medium-voltage, dry-type manufacturers, DOE 
stated in the proposed rule that it would anticipate some small 
business impacts at all TSLs. However, DOE believes that the 
incremental impact on small businesses in moving from TSL2 to TSL3 is 
greater than that in moving from TSL1 to TSL2 (see Section VII.B.4 for 
a more detailed discussion). DOE explicitly considered impacts on small 
businesses in selecting TSL2 and rejecting higher levels for medium-
voltage, dry-type transformers. 71 FR 44382, 44392-44393, 44401-44403. 
See section VII.B on the Regulatory Flexibility Act for more discussion 
on this point.
3. National Net Present Value and Net National Employment
    The NPV analysis estimates the cumulative benefits or costs to the 
Nation that would result from particular standard levels. While the NES 
analysis estimates the energy savings from a proposed energy 
conservation standard, the NPV analysis provides estimates of the 
national economic impacts of a proposed standard relative to a base 
case of no new standard. Tables VI.17 and VI.18 provide an overview of 
the NPV results, using both a seven percent and a three percent real 
discount rate. See TSD Chapter 10 for more detailed NPV results.

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


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

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

[[Page 58225]]

the demand for labor as spending shifts from less labor-intensive to 
more labor-intensive sectors of the economy.
    As shown in Tables VI.19 and VI.20, DOE estimated net indirect 
employment impacts (i.e., those changes of employment in the larger 
economy, other than in the manufacturing sector being regulated) from 
today's distribution transformer energy conservation standards to be 
positive. According to DOE's analysis, the number of jobs that may be 
generated by 2038 through indirect impacts ranged from 4,000 to 14,000 
for liquid-immersed transformers, and from 400 to 1,500 for medium 
voltage, dry-type transformers for the range of TSLs considered in this 
rulemaking. While DOE's analysis suggests that the distribution 
transformer standards could result in a very small increase in the net 
demand for labor in the economy, relative to total national employment, 
this increase would likely be sufficient to offset fully any adverse 
impacts on employment that might occur in the distribution transformer 
or energy industries. For details on the employment impact analysis 
methods and results, see TSD Chapter 14.

                              Table VI.19.--Net National Change in Jobs (Thousands): Liquid-Immersed Transformer Standards
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Trial standard level
                   Year                    -------------------------------------------------------------------------------------------------------------
                                                1          2          D          C          B          3          4          A          5          6
--------------------------------------------------------------------------------------------------------------------------------------------------------
2010......................................        1.7        2.3        2.5        2.8        2.9        3.2        3.4        3.7        4.5        3.3
2020......................................        1.5          2        2.2        2.4        2.5        2.7        2.9        3.0        4.1        1.5
2030......................................        2.8        3.9        4.4        4.9        5.2        5.3        5.7        6.8        9.5        8.0
2038......................................          4        5.4        6.2        7.0        7.4        7.4        8.1         10         14       13.4
--------------------------------------------------------------------------------------------------------------------------------------------------------


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

4. Impact on Utility or Performance of Equipment
    As discussed in section V.A.4 of the proposed rule, DOE believes 
that, because of the steps it had taken in establishing classes of 
products and in evaluating design options and the impact of potential 
standard levels (71 FR 44394), as well as the additional steps taken in 
today's final rule, including the consideration of design constraints 
for vault-transformers (see section V.B.4.a) and the evaluation of 
higher BIL voltages (see section V.A.1.a), the new standards it is 
adopting today will not lessen the utility or performance of 
distribution transformers. (See also TSD, Chapters 4 and 5)
5. Impact of Any Lessening of Competition
    As previously discussed in the NOPR, 71 FR 44363-44364, 44394, and 
in section III.D.5 of this preamble, DOE considers any lessening of 
competition that is likely to result from standards. The Attorney 
General determines the impact, if any, of any such lessening of 
competition.
    DOJ concluded that the distribution transformer standards contained 
in the proposed rule may adversely affect competition with respect to 
distribution transformers used in industries, such as underground coal 
mining, where physical conditions limit the size of the equipment that 
may be effectively utilized. DOJ understands that manufacturers would 
not be able to satisfy the proposed standard without increasing the 
size (or decreasing the power) of each class of distribution 
transformer. Mining companies facing space constraints would incur 
significantly increased costs due to enlarging the required 
installation space (which, for example, could involve removal of solid 
rock around coal seams in underground mines) or reconfiguring the size 
and number of each class of distribution transformer at each site. The 
resulting cost increases could constitute production inefficiencies 
that could make certain products less competitive. For example, the 
rule could, by raising the costs of certain coal mines, adversely 
affect production decisions at those mines and potentially result in 
increased use of less efficient energy alternatives. DOJ urged the DOE 
to consider these concerns carefully in its analysis, and to consider 
creating an exception for distribution transformers used in industries 
with space constraints. (DOJ, No. 157 at p.2) DOE considered this input 
from DOJ, along with comments from several stakeholders, and as 
discussed in section IV.A.2 of this preamble, decided to treat space-
constrained underground mining transformers as a separate product class 
in this final rule, and not to apply today's standards to these 
transformers. DOE is also reserving a subsection in section 431.196 for 
underground mining transformer efficiency standards. Energy 
conservation standards for underground mining transformers are not 
included as part of today's final rule and will be determined at a 
later date.
6. Need of the Nation to Conserve Energy
    The Secretary of Energy recognizes the need of the Nation to save 
energy. Enhanced energy efficiency, where economically justified, 
improves the Nation's energy security, strengthens the economy, and 
reduces the environmental impacts or costs of energy production. The 
energy savings from distribution transformer standards result in 
reduced emissions of CO2. Reduced electricity demand from 
today's energy conservation standards is also likely to reduce the cost 
of maintaining the reliability of the electricity system, particularly 
during peak-load periods. As a measure of this reduced demand, DOE 
expects today's standards to eliminate the need for the construction of 
approximately six new 400-megawatt combined-cycle gas

[[Page 58226]]

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

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

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

D. Conclusion

    EPCA contains criteria for prescribing new or amended energy 
conservation standards. DOE must prescribe standards only for those 
distribution transformers for which DOE: (1) has determined that 
standards would be technologically feasible and economically justified 
and would result in significant energy savings, and (2) has prescribed 
test procedures. (42 U.S.C. 6317(a)) Moreover, DOE has analyzed whether 
today's standards for distribution transformers will achieve the 
maximum improvement in energy efficiency that is technologically 
feasible and economically justified. (See 42 U.S.C. 6295(o)(2)(A), 
6316(a), and 6317(a) and (c)) Today's final rule will not result in the 
unavailability in the U.S. of any covered product type (or class) of 
transformer with performance characteristics (i.e., reliability, 
features, sizes, capacities and voltages) that are substantively the 
same as those generally available in the U.S. prior to these new 
standards.
    In determining whether a standard is economically justified, DOE 
determines whether the benefits of the standard exceed its costs. (See 
42 U.S.C. 6295(o)(2)(B)(i)) Any new or amended standard for 
distribution transformers must result in significant energy savings. 
(42 U.S.C. 6317(a); 42 U.S.C. 6295 (o)(3)(B); see 42 U.S.C. 
6295(o)(2)(B))
    In selecting energy conservation standards for distribution 
transformers, DOE started by comparing the maximum technologically 
feasible levels with the base case, and determined whether those levels 
were economically justified. Upon finding the maximum technologically 
feasible levels not to be justified, DOE analyzed the next lower TSL to 
determine whether that level was economically justified. DOE repeated 
this procedure until it identified a TSL that was economically 
justified.
    Tables VI.22 and VI.23 summarize DOE's quantitative analysis 
results for each TSL. Each table presents the results or, in some 
cases, a range of results, for the underlying design lines for liquid-
immersed transformers (Table VI.22), and medium-voltage, dry-type 
transformers for (Table VI.23). The range of values reported in these 
tables for LCC, payback, and average increase in consumer equipment 
cost before installation encompasses the range of results DOE 
calculated for either the liquid-immersed or medium-voltage,

[[Page 58227]]

dry-type representative units. The range of values for manufacturer 
impact represents the results for the preservation-of-operating-profit 
scenario and preservation-of-gross-margin scenario at each TSL for 
liquid-immersed and medium-voltage, dry-type transformers.

                                  Table VI.22.--Summary of Liquid-Immersed Distribution Transformers Analytical Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                   Trial standard level
            Criteria            ------------------------------------------------------------------------------------------------------------------------
                                    TSL1        TSL2        TSLD        TSLC        TSLB        TSL3        TSL4        TSLA        TSL5         TSL6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Energy saved (quads)...........        1.38        1.94        2.18        2.61        2.75        2.76        3.00        4.07        5.07         7.37
Generation capacity offset (GW)         1.4         1.9         2.1         2.5         2.7         2.7         2.9         3.9         5.0          7.2
NPV ($ billions)
    @ 7% discount..............        1.68        1.95        1.91        1.11        1.11        2.37        2.13      (1.89)      (4.89)       (23.3)
    @ 3% discount..............        5.57        7.06        7.56        6.95        7.26        9.17        9.33        4.47        1.40       (26.1)
Emission reductions, CO2 (Mt)..         125         176         199         238         251         248         272         369         464          674
Life-cycle cost *
    Net increase in LCC (%)....    1.4-12.1    1.4-20.7    1.4-20.7    2.5-42.5    8.1-42.5    2.0-18.9   12.4-44.3   32.4-79.6   57.7-84.8    84.8-99.5
    No change in LCC (%).......   42.0-66.7   20.6-66.1   20.6-59.0   16.5-56.5   16.5-47.1   13.0-66.1    2.1-50.0    0.1-13.0    0.0-10.0      0.0-0.0
    Net savings in LCC (%).....   28.2-45.9   31.9-58.7   33.2-58.7   36.5-58.7   36.5-58.7   31.9-68.2   33.2-68.2   20.3-54.6   15.2-32.3     0.5-15.2
Payback for average transformer     2.3-7.8    2.4-10.4    3.6-10.4    4.3-15.7    8.9-15.7    2.4-11.4    7.8-11.4   10.6-24.7   19.3-23.4    21.6-52.1
 (years) *.....................
Life-cycle cost, 2006 Material
 Price *
    Net increase in LCC (%)....    6.8-48.2   15.9-54.4   16.4-45.3   13.4-53.8   17.7-53.8   11.1-48.3   11.1-65.2   11.4-88.5   56.4-91.4    91.4-99.8
    No change in LCC (%).......   17.2-54.9   12.3-46.8    8.9-32.2    1.8-32.2    1.8-23.5    9.2-46.8    0.4-29.7    0.1-14.7     0.0-1.7      0.0-0.0
    Net savings in LCC (%).....   29.6-39.5   33.4-59.0   25.0-59.0   25.1-62.4   25.1-58.8   36.2-74.2   25.0-74.2   11.4-73.9    8.6-41.9      0.3-8.6
Payback for average                4.7-17.8    8.4-19.5    8.4-19.4    8.7-20.8   10.2-20.8    9.8-17.8   10.7-19.4   10.7-29.1   18.8-26.7    26.7-58.3
 transformer, 2006 Material
 Price (years) *...............
Average increase in consumer        3.2-7.1    2.7-20.7    8.1-20.7   10.0-21.1   10.0-22.1    2.7-45.9    8.0-45.9   20.0-60.6  24.7-138.6  132.9-161.3
 equipment cost before
 installation (%) *, **,
 [dagger]......................
Manufacturer impact ***
    INPV ($ millions)..........     (19)-13     (22)-28     (32)-37     (47)-47     (51)-53  (100)-(11)  (112)-(2.9    (169)-48    (252)-94    (576)-200
                                                                                                                  )
    INPV change (%)............   (3.2)-2.1   (3.7)-4.6   (5.2)-6.0   (7.7)-7.7   (8.3)-8.8  (17)-(1.9)  (18)-(0.5)    (28)-7.9     (41)-16      (95)-33
LCC selected designs with              0-13        0-14        0-14        0-14        0-14        0-95        0-95        0-84       0-100      100-100
 amorphous (%) *...............
LCC selected designs with core         1-54        2-79       2-100        2-84       2-100        2-99       2-100       4-100       4-100      100-100
 steel better than M3 (i.e.,
 M2, ZDMH, SA1) (%) *..........
Voltage sensitivity-achieve             Yes         Yes         Yes         Yes         Yes          No          No          No          No           No
 standard with silicon core
 steel.........................
Single-phase, three-phase               Yes          No         Yes         Yes         Yes          No          No         Yes          No           No
 consistency...................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Range represents the results for each of the five representative units derived from the individual design lines analyzed in the LCC.
** Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger] DOE recognizes that these cost changes are the average changes for the Nation, and that some individual customers will experience larger
  changes, particularly if these customers are not evaluating losses when purchasing transformers.
*** Range represents the results of the `preservation-of-operating-profit' and `preservation-of-gross-margin-percentage' scenarios in the MIA.


         Table VI.23.--Summary of Medium-Voltage, Dry-Type Distribution Transformers Analytical Results
----------------------------------------------------------------------------------------------------------------
                                                                Trial standard level
             Criteria              -----------------------------------------------------------------------------
                                        TSL1         TSL2         TSL3         TSL4         TSL5         TSL6
----------------------------------------------------------------------------------------------------------------
Energy saved (quads)..............         0.06         0.13         0.19         0.27         0.40         0.40
Generation capacity offset (GW)...          0.1          0.1          0.2          0.4          0.6          0.6
Discounted energy saved, 7%                0.02         0.04         0.05         0.10         0.11         0.11
 (quads)..........................
NPV ($ billions):
    @ 7% discount.................         0.16         0.28         0.38         0.45       (0.08)       (0.08)
    @ 3% discount.................         0.47         0.85         1.18         1.55         1.02         1.02
Emission reductions CO2 (Mt)......          5.8         11.8         17.1         24.8         36.9         36.9
Life-cycle cost: *
    Net increase in LCC (%).......     0.3-14.3     2.3-16.6     7.4-18.5    24.2-46.0    36.5-78.1    36.5-78.1
    No change in LCC (%)..........    36.4-71.4    27.2-56.5    10.8-45.4     0.0-16.7            0            0
    Net savings in LCC (%)........    23.1-60.3    36.6-67.2    47.2-76.1    52.6-74.4    21.9-63.5    21.9-63.5
Payback for average transformer         0.7-5.0      1.8-6.4      3.4-7.0      5.9-9.6     7.8-18.7     7.8-18.7
 (years) *........................
Average increase in consumer            0.6-7.4     3.4-15.1     9.7-24.2    20.4-39.6    43.6-95.1    43.6-95.1
 equipment cost before
 installation (%) *, **, [dagger].
Life-cycle cost, 2006 Material
 Price:*
    Net increase in LCC (%).......     0.7-23.8     4.2-61.3    18.7-54.5    33.7-62.7    49.7-88.3    49.7-88.3
    No change in LCC (%)..........    10.8-66.2     1.7-33.2     0.9-11.1        0-3.1          0-0          0-0
    Net savings in LCC (%)........    26.5-75.3      37-78.1    44.6-76.8    37.2-66.2    11.7-50.3    11.7-50.3

[[Page 58228]]

 
Payback for average transformer,        0.7-5.9     2.1-12.9     6.3-12.2     8.5-14.0    11.4-24.3    11.4-24.3
 2006 Material Price (years) *....
Manufacturer impact:***
    INPV ($ millions).............  (2.1)-(1.1)  (5.2)-(3.2)  (8.8)-(5.2)   (11)-(3.2)     (24)-0.9     (24)-0.9
    INPV change (%)...............  (5.9)-(3.1)   (15)-(8.9)    (25)-(15)   (29)-(8.9)     (67)-2.5     (67)-2.5
LCC designs with thin laminations         30-69        40-88       92-100      100-100      100-100     100-100
 of core steel (i.e., M3, HO) (%)
 *................................
----------------------------------------------------------------------------------------------------------------
* Range represents the results for each of the five representative units derived from the individual design
  lines analyzed in the LCC.
** Percent increase in consumer equipment cost before installation, five-year average material pricing.
[dagger]DOE recognizes that these cost changes are the average changes for the Nation, and that some individual
  customers will experience larger changes, particularly if these customers are not evaluating losses when
  purchasing transformers.
*** Range represents the results of the `preservation-of-operating-profit' and `preservation-of-gross-margin-
  percentage' scenarios in the MIA.

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

[[Page 58229]]

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

[[Page 58230]]

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

[[Page 58231]]

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

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

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

[[Page 58232]]

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

VII. Procedural Issues and Regulatory Review

A. Review Under Executive Order 12866

    Today's regulatory action is a ``significant regulatory action'' 
under section 3(f)(1) of Executive Order 12866, ``Regulatory Planning 
and Review.'' 58 FR 51735 (October 4, 1993). Accordingly, DOE has 
prepared and submitted to the Office of Management and Budget (OMB) for 
review the assessment of costs and benefits required under section 
6(a)(3) of the Executive Order. The Executive Order requires agencies 
to identify the specific market failure or other specific problem that 
it intends to address that warrants new agency action, as well as 
assess the significance of that problem, to enable assessment of 
whether any new regulations is warranted. (Executive Order 12866, Sec.  
1(b)(1)).
    The specific problem that the energy conservation standard 
addresses for distribution transformers is that a substantial portion 
of distribution transformer purchasers are not evaluating the cost of 
transformer losses when they make distribution transformer purchase 
decisions. Therefore, distribution transformers are being purchased 
that do not provide the minimum life-cycle cost service to equipment 
owners. DOE requested and received data on, and suggestions for 
evaluating the existence and extent of the problem, which DOE used to 
complete an assessment in the NOPR of the significance of the problem 
and the net benefits of regulation.

[[Page 58233]]

    For distribution transformers, the Institute of Electrical and 
Electronics Engineers, Inc. (IEEE) has voluntary guidelines for the 
economic evaluation of distribution transformer losses, IEEE 
PC57.12.33/D8. These guidelines document economic evaluation methods 
for distribution transformers that are common practice in the utility 
industry. But while economic evaluation of transformer losses is 
common, it is not a universal practice. DOE collected information 
during the course of the conservation standards rulemaking to estimate 
the extent to which distribution transformer purchases are evaluated. 
Data received from the National Electrical Manufacturers Association 
indicated that these guidelines or similar criteria are applied to 
approximately 75 percent of liquid-immersed transformer purchases, 50 
percent of small capacity medium-voltage dry-type transformer 
purchases, and 80 percent of large capacity medium-voltage dry-type 
transformer purchases. Therefore, 25 percent, 50 percent, and 20 
percent of distribution transformer purchases do not have economic 
evaluation of transformer losses. The benefits from the energy 
conservation standards result from eliminating those distribution 
transformers designs from the market that are purchased on a purely 
minimum first cost basis and which are unlikely to be purchased by 
equipment buyers when the economic value of equipment losses are 
properly evaluated. Detailed specifications of DOE's consumer purchase 
behavior model, and the consumer impact estimates are provided in 
Chapter 8 of the TSD.
    Of course, there are likely to be certain ``external'' benefits 
resulting from the improved efficiency of units that are not captured 
by the users of such equipment. These include both environmental and 
energy security-related externalities that are not already reflected in 
energy prices such as reduced emissions of greenhouse gases and reduced 
use of natural gas (and oil) for electricity generation. DOE invited 
comments on the weight that should be given to these factors in DOE's 
determination of the maximum efficiency level at which the total 
benefits are likely to exceed the total burdens resulting from a DOE 
standard. Discussion of the comments regarding these externalities is 
provided in sections IV.D.2.e and IV.I.
    DOE presented to OIRA for review the draft final rule and other 
documents prepared for this rulemaking, including the RIA, and has 
included these documents in the rulemaking record. They are available 
for public review in the Resource Room of DOE's Building Technologies 
Program, 1000 Independence Avenue, SW., Washington, DC, (202) 586-9127, 
between 9 a.m. and 4 p.m., Monday through Friday, except Federal 
holidays.
    The proposed rule contained a summary of the RIA, which evaluated 
the extent to which the major alternatives to standards for 
distribution transformers could achieve significant energy savings at 
reasonable cost, as compared to the effectiveness of the proposed rule. 
71 FR 44400-44401. The complete RIA, formally entitled, ``Regulatory 
Impact Analysis for Proposed Energy Conservation Standards for 
Electrical Distribution Transformers,'' is contained in the TSD 
prepared for today's rule. The RIA consists of: (1) A statement of the 
problem addressed by this regulation, and the mandate for government 
action; (2) a description and analysis of the feasible policy 
alternatives to this regulation; (3) a quantitative comparison of the 
impacts of the alternatives; and (4) the national economic impacts of 
the proposed standards.
    As explained in the NOPR, DOE determined that none of the 
alternatives it examined would save as much energy or have an NPV as 
high as the proposed standards. That same conclusion applies to the 
standards in today's rule. Also, several of the alternatives would 
require new enabling legislation, since authority to carry out those 
alternatives does not presently exist. Additional detail on the 
regulatory alternatives is found in the RIA report in the TSD.

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

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires 
preparation of an initial regulatory flexibility analysis (IRFA) for 
any rule that by law must be proposed for public comment, and a final 
regulatory flexibility analysis (FRFA) for any such rule that an agency 
adopts as a final rule, unless the agency certifies that the rule, if 
promulgated, will not have a significant economic impact on a 
substantial number of small entities. A regulatory flexibility analysis 
examines the impact of the rule on small entities and considers 
alternative ways of reducing negative impacts. Also, as required by 
Executive Order 13272, ``Proper Consideration of Small Entities in 
Agency Rulemaking,'' 67 FR 53461 (August 16, 2002), DOE published 
procedures and policies on February 19, 2003, to ensure that the 
potential impacts of its rules on small entities are properly 
considered during the rulemaking process. 68 FR 7990. DOE has made its 
procedures and policies available on the Office of General Counsel's 
Web site: http://www.gc.doe.gov.
    Small businesses, as defined by the Small Business Administration 
(SBA) for the distribution transformer manufacturing industry, are 
manufacturing enterprises with 750 employees or fewer. Prior to issuing 
the proposed rule in this rulemaking, DOE interviewed six small 
businesses affected by the rulemaking. DOE also obtained information 
about small business impacts while interviewing manufacturers that 
exceed the small business size threshold of 750 employees.
    DOE reviewed the proposed rule under the provisions of the 
Regulatory Flexibility Act and the procedures and policies published on 
February 19, 2003. 71 FR 44401. On the basis of this review, DOE 
determined that it could not certify that the proposed rule (TSL2), if 
promulgated, would have no significant economic impact on a substantial 
number of small entities. Id. DOE made this determination because of 
the potential impacts that the proposed standard levels for medium-
voltage, dry-type distribution transformers would have on the small 
businesses that manufacture them. However, DOE noted that it had 
explicitly considered the impacts on small businesses that manufacture 
medium-voltage, dry-type transformers in proposing to adopt TSL2 rather 
than a higher trial standard level. Id. In the proposed rule, DOE also 
stated and explained its belief that the proposed standards would not 
have significant economic impacts on a substantial number of small 
manufacturers of liquid-immersed transformers. 71 FR 44401-02.
    Because of the potential impacts of the proposed standards on small 
manufacturers of medium-voltage, dry-type transformers, DOE prepared an 
IRFA during the NOPR stage of this rulemaking. DOE provided the IRFA in 
its entirety in the NOPR, 71 FR 44401-03, and also transmitted a copy 
to the Chief Counsel for Advocacy of the SBA for review. In addition, 
DOE gave a presentation concerning the key portions of the IRFA to the 
Chief Counsel for Advocacy of the SBA. DOE did not receive any 
indication that the IRFA was insufficient either in writing or during 
the aforementioned presentation to the SBA. Chapter 12 of the TSD 
contains more information about the impact of this rulemaking on 
manufacturers.

[[Page 58234]]

    The IRFA divided potential impacts on small businesses into two 
broad categories: (1) Impacts associated with transformer design and 
manufacturing; and (2) impacts associated with demonstrating compliance 
with the standard using DOE's test procedure. DOE's test procedure rule 
does not require manufacturers to take any action in the absence of 
final energy conservation standards for distribution transformers, and 
thus any impact of that rule on small businesses would be triggered by 
the promulgation of today's standards. Thus, the IRFA discussed the 
potential impacts of the proposed standards on small manufacturers of 
medium-voltage, dry-type transformers, and of the compliance 
demonstration costs on all small manufacturers of distribution 
transformers.
    DOE has prepared a FRFA for this rulemaking, and it is presented in 
the following discussion. DOE has transmitted a copy of this FRFA to 
the Chief Counsel for Advocacy of the SBA for review. The FRFA below is 
written in accordance with the requirements of the Regulatory 
Flexibility Act, and addresses the stakeholder comments received in 
response to the IRFA.
1. Need for and Objectives of the Rule
    Today's rule is needed to satisfy the requirement in EPCA that DOE 
prescribe energy conservation standards for those distribution 
transformers for which DOE determines that standards would be 
technologically feasible and economically justified, and would result 
in significant energy savings. (42 U.S.C. 6317(a)) DOE had previously 
determined that standards for distribution transformers appear to be 
technologically feasible and economically justified, and are likely to 
result in significant savings. 62 FR 54809 (October 22, 1997).
    In accordance with EPCA, the objective of today's final rule is to 
set energy conservation standards that achieve the maximum improvement 
in the energy efficiency of distribution transformers that are 
technologically feasible and economically justified. (See 42 U.S.C. 
6295(o)(2)(A), 6313(a), and 42 U.S.C. 6317(a) and (c)) After DOE 
reviewed the comments received on the proposed rule and conducted 
further analyses, DOE determined that the economic benefits of today's 
standards exceed the costs to the greatest extent practicable, taking 
into consideration the seven factors set forth in 42 U.S.C. 
6295(o)(2)(B)(i) (see Section II.A of this notice of final rulemaking). 
DOE concluded, therefore, that today's standards are economically 
justified. Further information concerning the background of this 
rulemaking is provided in Chapter 1 of the TSD.
2. Description and Estimated Number of Small Entities Regulated
    By researching the distribution transformer market, developing a 
database of manufacturers, and conducting interviews with manufacturers 
(both large and small), DOE was able to estimate the number of small 
entities that would be regulated under an energy conservation standard. 
See chapter 12 of the TSD for further discussion about the methodology 
used in DOE's manufacturer impact analysis and its analysis of small 
business impacts.
    Liquid-immersed transformers account for about $1.3 billion in 
annual sales and employment of about 4,230 production employees in the 
United States. DOE estimates that, of the approximately 25 U.S. 
manufacturers that make liquid-immersed distribution transformers, 
about 15 of them are small businesses. About five of the small 
businesses have fewer than 100 employees.
    Medium-voltage, dry-type transformers account for about $84 million 
in annual sales and employment of about 250-330 production employees in 
the United States. The medium-voltage, dry-type market is relatively 
small compared to that of liquid-immersed transformers. The revenue 
attributable to the medium-voltage, dry-type transformers represents 
only about six percent of the total revenue of the industry affected by 
this rulemaking (i.e., the sum of revenues from the liquid-immersed and 
the medium-voltage, dry-type transformers). DOE estimates that, of the 
25 U.S. manufacturers that make medium-voltage, dry-type distribution 
transformers, about 20 of them are small businesses. About ten of these 
small businesses have fewer than 100 employees. Thus, in relative 
terms, small businesses play a more dominant role in the market for 
medium-voltage, dry-type transformers than for liquid-immersed 
transformers.
3. Description and Estimate of Compliance Requirements
    Potential impacts on small businesses come from two broad 
categories of compliance requirements: (1) Impacts associated with 
transformer design and manufacturing, and (2) impacts associated with 
demonstrating compliance with the standard using the DOE test 
procedure.
    With respect to impacts associated with transformer design and 
manufacturing, the margins and/or market share of small businesses in 
the medium-voltage, dry-type transformers could be hurt in the long 
term by today's promulgated level, TSL2. At TSL2, as opposed to TSL1, 
small manufacturers would have less flexibility in choosing a design 
path. However, as explained in part 6 of the IRFA, ``Significant 
Alternatives to the Rule,'' DOE explicitly considered the impacts on 
small manufacturers of medium-voltage, dry-type transformers in 
selecting TSL2, rather than selecting a higher trial standard level. 71 
FR 44403. DOE expects that the differential impact on small 
manufacturers of medium-voltage, dry-type transformers (versus large 
businesses) would be smaller in moving from TSL1 to TSL2 than it would 
be in moving from TSL2 to TSL3.
    With respect to compliance demonstration, DOE's test procedure for 
distribution transformers allows manufacturers to use an Alternative 
Efficiency Determination Method (AEDM) which would ease the burden on 
manufacturers. 10 CFR Part 431, Subpart K, Appendix A; 71 FR 24972. The 
AEDM involves a sampling procedure to compare manufactured products' 
efficiencies with those predicted by computer design software. Where 
the manufacturer uses an AEDM for a basic model, it would not be 
required to test units of the basic model to determine its efficiency 
for purposes of establishing compliance with DOE requirements. The 
professional skills necessary to execute the AEDM include the 
following: (1) Transformer design software expertise (or access to such 
expertise possessed by a third party); and (2) electrical testing 
expertise and moderate expertise with experimental statistics (or 
access to such expertise possessed by a third party). DOE's test 
procedure would require periodic verification of the AEDM.
    DOE's test procedure also requires manufacturers to calibrate 
equipment used for testing the efficiency of transformers. Calibration 
records will need to be maintained as a result of today's standard.
    The testing, reporting, and recordkeeping requirements associated 
with an energy conservation standard and its related test procedure 
would be identical, irrespective of the trial standard level chosen. 
Therefore, for both liquid-immersed and medium-voltage, dry-type 
transformers, the testing, reporting, and recordkeeping requirements 
have not entered into DOE's choice of trial standard level for today's 
final rule.

[[Page 58235]]

4. Significant Issues Raised by Public Comments
    NEMA submitted a comment that supports DOE's assessment that TSLs 
higher than TSL2 would have serious impacts on small manufacturers of 
medium-voltage dry-type transformers and would lead to further industry 
consolidation. (NEMA, No. 156 at p. 1) NEMA also commented that TSL2 
would disproportionately affect small manufacturers and greatly limit 
the range of ratings that they could produce. NEMA stated that small 
manufacturers do not have the investment capital to procure the 
equipment necessary to produce the most efficient designs, and that 
small manufacturers' current designs cannot meet TSL4 for many ratings 
(it was unclear in this specific comment whether NEMA was referring to 
medium-voltage dry-type transformers, liquid-immersed transformers, or 
both types). (NEMA, No. 125 at p. 2) NEMA also indicated that material 
availability and quota issues (for core steel, copper, and aluminum) 
impact small manufacturers more severely than large manufacturers, 
since small manufacturers have less leverage over suppliers and 
typically have less diverse businesses. (NEMA, No. 156 at pp. 2-3) 
HVOLT supported NEMA's view that small manufacturers are affected more 
than large manufacturers by material availability issues. (HVOLT, Inc., 
No. 144 at p. 2) HVOLT adds that the material availability problems 
that would arise at TSL2 or higher would drive small manufacturers out 
of business. (HVOLT, Inc., No. 155 at p. 3; Public Meeting Transcript, 
No. 108.6 at p. 138)
    The PEMCO Corporation, a small manufacturer of medium-voltage dry-
type transformers, submitted a comment that conflicts with NEMA and 
HVOLT and supports the information that DOE received during the 
manufacturer interview process prior to the IRFA and the NOPR. During 
the interviews, DOE learned that small manufacturers of medium-voltage 
dry-type transformers can still choose to produce their own cores at 
TSL2 (although some will purchase cores) and can profitably compete at 
TSL2. 71 FR 44403. In its comment in response to the IRFA, PEMCO stated 
that, with additional capital expenditures and major changes in 
manufacturing practices, it can meet TSL2. PEMCO further stated that 
levels above TSL2 would make it impossible for PEMCO to compete. (PEMCO 
Corporation, No. 130 at p. 1) The PEMCO comment is consistent with 
DOE's understanding of the potential impacts on small, medium-voltage 
dry-type manufacturers. DOE's MIA suggests that while TSL2 presents 
greater difficulties for small businesses than TSL1, the impacts at 
TSL3 would be much greater. DOE expects that small businesses will 
generally be able to profitably compete at TSL2. DOE's MIA is based on 
its interviews of both small and large manufacturers, and consideration 
of small business impacts explicitly enters into DOE's choice of TSL2 
in promulgating minimum efficiency standards for medium-voltage dry-
type transformers.
    DOE also notes that today's promulgated standard of TSL2 can be met 
with a variety of materials, including multiple core steels and both 
copper and aluminum windings. Because TSL2 can be met with a variety of 
materials, DOE does not expect that material availability issues will 
represent a substantial problem in the long-term.
    ACEEE submitted a comment stating that small, medium-voltage dry-
type manufacturers would not be forced out of business at higher 
standard levels because they could either install the necessary 
mitering equipment or purchase finished cores. (ACEEE, No. 127 at p. 9) 
DOE recognizes both of these possibilities. While DOE agrees that 
standard levels higher than TSL2 would not necessarily cause all small 
businesses to exit, there is a risk that a significant number of small 
businesses would exit the market at TSL3 or higher. As reported in the 
IRFA, the thin steels required at TSL3 and higher (M3 or better) pose 
operational difficulties for the type of core-mitering equipment 
typically purchased by small manufacturers. In addition, small 
businesses would be at a relative disadvantage at TSL3 and higher 
because research and development efforts would be on the same scale as 
those for larger companies, but these expenses would be recouped over 
much smaller sales volumes. These research and development efforts 
would be required by all manufacturers (not just small manufacturers) 
at TSL3 and higher because these designs are demanded only in very low 
volumes today. 71 FR 44403.
    As a separate matter, DOE also received comments pertaining to 
small manufacturers in the liquid-immersed distribution transformer 
industry (the IRFA did not pertain to liquid-immersed transformers). In 
the NOPR, DOE concluded that there will be no significant economic 
impact on a substantial number of small liquid-immersed manufacturers. 
DOE's conclusion in the proposed rule was based on DOE's understanding 
of the strategy followed by (and role played by) small liquid-immersed 
transformer manufacturers in the market. Since liquid-immersed 
distribution transformers are largely customized, small businesses can 
compete because many of these transformers are unique designs produced 
in relatively small quantities by a given customer's order. Small 
manufacturers of liquid-immersed transformers tend not to compete on 
the higher-volume products and often produce transformers for highly 
specific applications. This strategy allows small manufacturers of 
liquid-immersed units to be competitive in certain liquid-immersed 
product markets. In the NOPR, DOE stated that implementation of an 
energy conservation standard would have a relatively minor differential 
impact on small manufacturers of liquid-immersed distribution 
transformers. Disadvantages to small businesses, such as having little 
leverage over suppliers (e.g., core steel suppliers), are present with 
or without an energy conservation standard. Due to the purchasing 
characteristics of their customers, small manufacturers of liquid-
immersed transformers currently produce transformers at TSL2, the 
proposed level. Thus, DOE expected that conversion costs (i.e., 
research and development costs and capital investments) and the 
associated manufacturer impacts on small businesses would be 
insignificant at the proposed level, TSL2. 71 FR 44401-44402. Below, 
DOE revisits this expectation in light of the standards promulgated 
today, which are higher than TSL2.
    Cooper Power Systems stated that TSL1 would help U.S. manufacturers 
while TSL2 would greatly limit the range of designs that small 
manufacturers of liquid-immersed transformers could produce. Cooper 
also stated that TSL4 would eliminate small manufacturers. (Cooper 
Power Systems, No. 154 at p. 2)
    NEMA commented that DOE underestimated the impacts on small 
manufacturers of liquid-immersed transformers because DOE failed to 
consider materials availability issues and the quotas typically placed 
on small manufacturers. NEMA pointed to quotas on both core steel and 
winding materials and also the need to outsource core production. 
(NEMA, No. 156 at pp. 1, 3) NEMA asserted that small manufacturers lack 
the sophistication to create the most efficient designs and that high 
efficiency requirements would lead to the outsourcing of core 
production (especially distributed gap wound cores). (NEMA, No. 156 at 
p. 3) HVOLT submitted similar comments,

[[Page 58236]]

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

C. Review Under the Paperwork Reduction Act

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

[[Page 58237]]

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

D. Review Under the National Environmental Policy Act

    DOE prepared an environmental assessment of the impacts of today's 
standards (DOE/EA-1565), which is available from: U.S. Department of 
Energy, Office of Energy Efficiency and Renewable Energy, Forrestal 
building, Mail Station EE-41, 1000 Independence Avenue, SW., 
Washington, DC 20585-0121, (202) 586-0854. DOE found the environmental 
effects associated with various standard efficiency levels for 
distribution transformers to be not significant, and therefore it is 
publishing, elsewhere in this issue of the Federal Register, a Finding 
of No Significant Impact pursuant to the National Environmental Policy 
Act of 1969 (42 U.S.C. 4321 et seq.), the regulations of the Council on 
Environmental Quality (40 CFR parts 1500-1508), and DOE's regulations 
for compliance with the National Environmental Policy Act (10 CFR part 
1021).

E. Review Under Executive Order 13132

    DOE reviewed this rule pursuant to Executive Order 13132, 
``Federalism,'' 64 FR 43255 (August 4, 1999), which imposes certain 
requirements on agencies formulating and implementing policies or 
regulations that preempt State law or that have federalism 
implications. The Executive Order requires agencies to examine the 
constitutional and statutory authority supporting any action that would 
limit the policymaking discretion of the States and to carefully assess 
the necessity for such actions. The Executive Order also requires 
agencies to have an accountable process to ensure meaningful and timely 
input by State and local officials in the development of regulatory 
policies that have federalism implications. On March 14, 2000, DOE 
published a statement of policy describing the intergovernmental 
consultation process it will follow in the development of such 
regulations. 65 FR 13735. The Department has examined today's final 
rule and has determined that it would not have a substantial direct 
effect on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government. EPCA governs 
and prescribes Federal preemption of State regulations as to energy 
conservation for the equipment that is the subject of today's final 
rule. States can petition the Department for exemption from such 
preemption to the extent, and based on criteria, set forth in EPCA. (42 
U.S.C. 6297) No further action is required by Executive Order 13132.

F. Review Under Executive Order 12988

    With respect to the review of existing regulations and the 
promulgation of new regulations, section 3(a) of Executive Order 12988, 
``Civil Justice Reform'' 61 FR 4729 (February 7, 1996) imposes on 
Federal agencies the general duty to adhere to the following 
requirements: (1) Eliminate drafting errors and ambiguity; (2) write 
regulations to minimize litigation; and (3) provide a clear legal 
standard for affected conduct rather than a general standard and 
promote simplification and burden reduction. Section 3(b) of Executive 
Order 12988 specifically requires that Executive agencies make every 
reasonable effort to ensure that the regulation: (1) Clearly specifies 
the preemptive effect, if any; (2) clearly specifies any effect on 
existing Federal law or regulation; (3) provides a clear legal standard 
for affected conduct while promoting simplification and burden 
reduction; (4) specifies the retroactive effect, if any; (5) adequately 
defines key terms; and (6) addresses other important issues affecting 
clarity and general draftsmanship under any guidelines issued by the 
Attorney General. Section 3(c) of Executive Order 12988 requires 
Executive agencies to review regulations in light of applicable 
standards in section 3(a) and section 3(b) to determine whether they 
are met or it is unreasonable to meet one or more of them. DOE has 
completed the required review and determined that, to the extent 
permitted by law, this final rule meets the relevant standards of 
Executive Order 12988.

G. Review Under the Unfunded Mandates Reform Act of 1995

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

[[Page 58238]]

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

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

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

I. Review Under Executive Order 12630

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

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

    Section 515 of the Treasury and General Government Appropriations 
Act, 2001 (44 U.S.C. 3516 note) provides for agencies to review most 
disseminations of information to the public under guidelines 
established by each agency pursuant to general guidelines issued by 
OMB. OMB's guidelines were published at 67 FR 8452 (February 22, 2002), 
and DOE's guidelines were published at 67 FR 62446 (October 7, 2002). 
DOE has reviewed today's final rule under the OMB and DOE guidelines 
and has concluded that it is consistent with applicable policies in 
those guidelines.

K. Review Under Executive Order 13211

    Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use,'' 66 FR 28355 
(May 22, 2001) requires Federal agencies to prepare and submit to the 
Office of Information and Regulatory Affairs of the OMB a Statement of 
Energy Effects for any significant energy action. DOE determined that 
the proposed rule was not a ``significant energy action'' within the 
meaning of Executive Order 13211. 71 FR 44405. Accordingly, it did not 
prepare a Statement of Energy Effects on the proposed rule. DOE 
received no comments on this issue in response to the NOPR. As with the 
proposed rule, DOE has concluded that today's final rule is not a 
significant energy action within the meaning of Executive Order 13211, 
and has not prepared a Statement of Energy Effects on the rule.

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

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

M. Review Under the Information Quality Bulletin for Peer Review

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

N. Congressional Notification

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

VIII. Approval of the Office of the Secretary

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

List of Subjects in 10 CFR Part 431

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

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

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

[[Page 58239]]

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

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

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


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


Sec.  431.192  Definitions.

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

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


Sec.  431.196  Energy conservation standards and their effective dates.

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


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

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

                            Table I.2.--Standard Levels for Medium-Voltage, Dry-Type Distribution Transformers, Tabular Form
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Single-phase                                                                  Three-phase
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                              20-45 kV     46-95 kV      >=96 kV                                     20-45 kV     46-95 kV     >=96 kV
                 BIL  kVA                    efficiency   efficiency   efficiency              BIL  kVA             efficiency   efficiency   efficiency
                                                (%)          (%)           (%)                                         (%)          (%)          (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
15........................................        98.10        97.86                15...........................        97.50        97.18
25........................................        98.33        98.12                30...........................        97.90        97.63
37.5......................................        98.49        98.30                45...........................        98.10        97.86
50........................................        98.60        98.42                75...........................        98.33        98.12
75........................................        98.73        98.57        98.53   112.5........................        98.49        98.30
100.......................................        98.82        98.67        98.63   150..........................        98.60        98.42
167.......................................        98.96        98.83        98.80   225..........................        98.73        98.57        98.53
250.......................................        99.07        98.95        98.91   300..........................        98.82        98.67        98.63
333.......................................        99.14        99.03        98.99   500..........................        98.96        98.83        98.80
500.......................................        99.22        99.12        99.09   750..........................        99.07        98.95        98.91

[[Page 58240]]

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

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

Appendix

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

Department of Justice

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

January 16, 2007.

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

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

 Yours sincerely,

J. Bruce McDonald,
Acting Assistant Attorney General.

Department of Justice

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

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

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

[[Page 58241]]

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

 Yours sincerely,

Deborah A. Garza,
Acting Assistant Attorney General.

[FR Doc. E7-19582 Filed 10-11-07; 8:45 am]
BILLING CODE 6450-01-P