Energy Conservation Program for Commercial Equipment: Distribution Transformers Energy Conservation Standards; Final Rule
Federal RegisterOct 12, 2007
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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.
SUMMARY:
The Department of Energy (DOE) has determined that energy conservation standards for liquid-immersed and medium-voltage, dry-type distribution transformers will result in significant conservation of energy, are technologically feasible, and are economically justified. On this basis, DOE is today adopting energy conservation standards for liquid-immersed and medium-voltage, dry-type distribution transformers. Today's rule does not set energy conservation standards for underground mining distribution transformers.
DATES:
Effective Date:
The effective date of this rule is November 13, 2007. Standards for liquid-immersed and medium-voltage, dry-type distribution transformers will be applicable starting January 1, 2010.
ADDRESSES:
For access to the docket to read background documents, the technical support document (TSD), transcripts of the public meetings in this proceeding, or comments received, visit the U.S. Department of Energy, Forrestal Building, Room 1J-018 (Resource Room of the Building Technologies Program), 1000 Independence Avenue, SW., Washington, DC, (202) 586-2945, between 9 a.m. and 4 p.m., Monday through Friday, except Federal holidays. Please call Ms. Brenda Edwards-Jones at the above telephone number for additional information regarding visiting the Resource Room. Please note: DOE's Freedom of Information Reading Room (formerly Room 1E-190 at the Forrestal Building) no longer houses rulemaking materials. You may also obtain copies of certain previous rulemaking documents from this proceeding (i.e., Framework Document, advance notice of proposed rulemaking (ANOPR), notice of proposed rulemaking (NOPR or proposed rule)), draft analyses, public meeting materials, and related test procedure documents from the Office of Energy Efficiency and Renewable Energy's Web site at
http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html.
FOR FURTHER INFORMATION CONTACT:
Antonio Bouza, Project Manager, Energy Conservation Standards for Distribution Transformers, Docket No. EE-RM/STD-00-550, U.S. Department of Energy, Energy Efficiency and Renewable Energy, Building Technologies Program, EE-2J, 1000 Independence Avenue, SW., Washington, DC 20585-0121, (202) 586-4563, e-mail:
Antonio.Bouza@ee.doe.gov.
Francine Pinto, Esq., U.S. Department of Energy, Office of General Counsel, GC-72, 1000 Independence Avenue, SW., Washington, DC 20585-0121, (202) 586-7432, e-mail:
Francine.Pinto@hq.doe.gov.
SUPPLEMENTARY INFORMATION:
I. Summary of the Final Rule and Its Benefits
A. The Standard Levels
B. Distribution Transformer Characteristics
C. Benefits to Transformer Customers
D. Impact on Manufacturers
E. National Benefits
F. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
III. General Discussion
A. Test Procedures
B. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
C. Energy Savings
D. Economic Justification
1. Economic Impact on Commercial Consumers and Manufacturers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
IV. Methodology and Discussion of Comments on Methodology
A. Market and Technology Assessment
1. General
2. Mining Transformers
a. Comments Requesting Exemption
b. Mining Transformer Test Procedure Comments
3. Less-Flammable, Liquid-Immersed Transformers
4. Rebuilt or Refurbished Distribution Transformers
5. Uninterruptible Power System Transformers
B. Engineering Analysis
C. Life-Cycle Cost and Payback Period Analysis
1. Inputs Affecting Installed Cost
a. Installation Costs
b. Baseline and Standard Design Selection
2. Inputs Affecting Operating Costs
a. Transformer Loading
b. Load Growth
c. Electricity Costs
d. Electricity Price Trends
e. Natural Gas Price Impacts
3. Inputs Affecting Present Value of Annual Operating Cost Savings
a. Standards Implementation Date
b. Discount Rate
c. Temperature Rise, Reliability, and Lifetime
D. National Impact Analysis—National Energy Savings and Net Present Value Analysis
1. Discount Rate
a. Selection and Estimation Method
b. Discounting Energy and Emissions
E. Commercial Consumer Subgroup Analysis
F. Manufacturer Impact Analysis
G. Employment Impact Analysis
H. Utility Impact Analysis
I. Environmental Analysis
V. Discussion of Other Comments
A. Information and Assumptions Used in Analyses
1. Engineering Analysis
a. Primary Voltage Sensitivities
b. Increased Raw Material Prices
c. Amorphous Material Price
d. Material Availability
2. Shipments/National Energy Savings
3. Manufacturer Impact Analysis
B. Weighing of Factors
1. Economic Impacts
a. Economic Impacts on Consumers
b. Economic Impacts on Manufacturers
2. Life-Cycle Costs
3. Energy Savings
4. Lessening of Utility or Performance of Products
a. Transformers Installed in Vaults
5. Impact of Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
a. Availability of High Primary Voltages
b. Materials Price Sensitivity Analysis
c. Materials Availability Analysis
d. Consistency Between Single-Phase and Three-Phase Designs
C. Other Comments
1. Development of Trial Standard Levels for the Final Rule
2. Linear Interpolation of Non-Standard Capacity Ratings
VI. Analytical Results and Conclusions
A. Trial Standard Levels
B. Significance of Energy Savings
C. Economic Justification
1. Economic Impact on Commercial Consumers
a. Life-Cycle Costs and Payback Period
b. Commercial Consumer Subgroup Analysis
2. Economic Impact on Manufacturers
a. Industry Cash-Flow Analysis Results
b. Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Manufacturers That Are Small Businesses
3. National Net Present Value and Net National Employment
4. Impact on Utility or Performance of Equipment
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
D. Conclusion
1. Results for Liquid-Immersed Distribution Transformers
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.
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
kVA
Efficiency (%)
Three-phase
kVA
Efficiency (%)
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
Single-phase
BIL
kVA
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
efficiency
(%)
Three-phase
BIL
kVA
20-45 kV
efficiency
(%)
46-95 kV
efficiency
(%)
≥96 kV
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
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.
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 (CO
2
) from a variety of generation sources. This is an amount equal to what would be
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
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.
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,
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
kVA
Efficiency (%)
Three-phase
kVA
Efficiency (%)
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
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
kVA
Efficiency (%)
Three-phase
kVA
Efficiency (%)
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
BIL
kVA
20-45 kV
Efficiency
(%)
46-95 kV
Efficiency
(%)
≥96 kV
Efficiency
(%)
Three-phase
BIL
kVA
20-45 kV
Efficiency
(%)
46-95 kV
Efficiency
(%)
≥96 kV
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.
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
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))
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
Inputs
NOPR description
Changes for final rule
Affecting Installed Costs
Equipment price
Derived by multiplying manufacturer selling price (from the engineering analysis) by distributor markup and contractor markup plus sales tax for dry-type transformers. For liquid-immersed transformers, DOE used manufacturer selling price plus small distributor markup plus sales tax. Shipping costs were included for both types of transformers
No change.
Installation cost
Includes a weight-specific component, derived from
RS Means Electrical Cost Data 2002
and a markup to cover installation labor, pole replacement costs for design line 2 and equipment wear and tear
Added a case with vault replacement costs as a subgroup analysis.
Baseline and standard design selection
The selection of baseline and standard-compliant transformers depended on customer behavior. For liquid-immersed transformers, the fraction of purchases evaluated was 75%, while for dry-type transformers, the fraction of evaluated purchases was 50% for small capacity medium voltage and 80% for large-capacity medium voltage
No change in percent of evaluators. Different values of customer choice B parameter was estimated for small versus large liquid-immersed transformers.*
Affecting Operating Costs
Transformer loading
Loading depended on customer and transformer characteristics
Technical improvement was made for liquid-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-immersed and 0% per year for dry-type transformers
Adjusted to 0% per year for both liquid-immersed and dry-type.
Power factor
Assumed to be unity
No change.
Annual energy use and demand
Derived from a 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
No change.
Electricity costs
Derived from tariff-based and hourly based electricity prices. Capacity costs provided extra value for reducing losses at peak
Adjusted electricity prices for inflation.
Electricity price trend
Obtained from
Annual Energy Outlook 2005 (AEO2005)
Updated to
AEO2007
.
Maintenance cost
Annual maintenance cost did not vary as a function of efficiency
No change.
Affecting Present Value of Annual Operating Cost Savings
Effective date
Assumed to be 2010
No change.
Discount rates
Mean real discount rates ranged from 4.2% for owners of pole-mounted, liquid-immersed transformers to 6.6% for dry-type transformer owners
Discount rate sensitivity added to spreadsheet tool.
Lifetime
Distribution of lifetimes, with mean lifetime for both liquid and dry-type transformers assumed to be 32 years
No change.
Candidate Standard Levels
Trial standard levels
Six efficiency levels with the minimum equal to TP 1 and the maximum from the most efficient designs from the engineering analysis. Intermediate efficiency levels for each design line selected using a redefined set of LCC criteria.
For liquid-immersed transformers a set of four recombinations of the NOPR standard levels were formulated that have consistency between single-phase and three-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
Input
NOPR description
Changes for final rule
Shipments data
Third-party expert (HVOLT) for the year 2001
No change.
Shipments backcast
For years 1977-2003, 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
No change.
Shipments forecast
Years 2002-2035: Based on
AEO2005
Years 2010-2038: Based on
AEO2007.
Dry-type/liquid-immersed market shares
Based on EIA's electricity sales data and
AEO2005
Based on EIA's electricity sales data and
AEO2007.
Regular replacement market
Based on a survival function constructed from a Weibull distribution function normalized to produce a 32-year mean lifetime. Source: ORNL 6804/R1,
The Feasibility of Replacing or Upgrading Utility Distribution Transformers During Routine Maintenance,
page D-1
No change.
Elasticities, liquid-immersed
For liquid-immersed transformers
• Low: 0.00
• Medium: −0.04
• High: −0.20
No change.
Elasticities, dry-type
For dry-type transformers
• Low: 0.00
• Medium: −0.02
• High: −0.20
No change.
Table IV.3.—Final Rule Inputs for the National Impact Analysis
Input
NOPR description
Changes for final rule
Shipments
Annual shipments from shipments model
No change.
Implementation date of standard
Assumed to be 2010
No change.
Base case efficiencies
Constant efficiency through 2035. Equal to weighted-average efficiency in 2010
No change.
Standards case efficiencies
Constant efficiency at the specified standard level from 2007 to 2038
No change.
Annual energy consumption per unit
Average rated transformer losses are obtained from the LCC analysis, and are then scaled for different size categories, weighted by size market share, and adjusted for transformer loading (also obtained from the LCC analysis)
No change.
Total installed cost per unit
Weighted-average values as a function of efficiency level (from LCC analysis)
No change.
Electricity expense per unit
Energy and capacity savings for the two types of transformer losses are each multiplied by the corresponding average marginal costs for capacity and energy, respectively, for the two types of losses (marginal costs are from the LCC analysis)
No change.
Escalation of electricity prices
AEO2005
forecasts (to 2025) and extrapolation for 2038 and beyond
Used
AEO2007
forecasts (to 2025) and extrapolation for 2038 and beyond.
Electricity site-to-source conversion
A time series conversion factor; includes electric generation, transmission, and distribution losses. Conversion varies yearly and is generated by DOE/EIA's National Energy Modeling System (NEMS) program
Updated conversion factors from NEMS.
Discount rates
3% and 7% real
Results for 4.2% reported in TSD.
Analysis year
Equipment and operating costs are discounted to the year of equipment price data, 2004
Equipment and operating costs are discounted to year 2006.
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
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.
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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
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.
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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
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
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
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
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
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 CO
2
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
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
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 (SO
2
) 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.
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 CO
2
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 (CO
2
), SO
2
, NO
X
, 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 SO
2
because, as discussed below, any such reduction resulting from an efficiency standard would not affect the overall level of SO
2
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 CO
2
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 NO
X
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 SO
2
, 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 SO
2
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 SO
2
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
not factor in any potential cost due to addressing CO
2
emissions, and that this may lead to an underestimate of the potential economic benefits of CO
2
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 CO
2
emissions in its electricity price forecast.
DOE did not include estimates of the economic benefits of CO
2
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)
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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)
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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
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
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.
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DOE found, for example, at TSL6, all design lines' representative
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