2

- i CHAPTER 2. ANALYTICAL FRAMEWORK

TABLE OF CONTENTS

2.1 INTRODUCTION

................................ ................................ ............................... 2

- 1 2.2 BACKGROUND

................................ ................................ ................................ . 2

- 2 2.2.1 Test Proce dure

................................ ................................ ................................ ..... 2

- 4 2.2.1.1 Multiple/Dual

- Voltage Windings

................................ ......................... 2

- 4 2.2.1.2 Weighted

- Average Losses from Multiple Loading Points

................... 2

- 5 2.2.1.3 Other Aspects of the Test Procedure

................................ .................... 2

- 6 2.3 SCOPE OF COVERAGE

................................ ................................ .................... 2

- 6 2.4 MARKET AND TECHNOLOG Y ASSESSMENT

................................ ............ 2

- 7 2.4.1 Equipment Classes

................................ ................................ ............................... 2

- 7 2.4.1.1 Less

- Flammable Liquid

- Immersed Transformers

................................ 2

- 8 2.4.2 Market Assessment

................................ ................................ .............................. 2

- 9 2.4.2.1 National Shipments Estimate

................................ ................................ 2

- 9 2.4.2.2 Distribution and Sales Channels

................................ ......................... 2

- 10 2.4.2.3 Total Owning Cost Evaluation

................................ ........................... 2

- 10 2.4.3 Technology Assessment

................................ ................................ ..................... 2

- 11 2. 4.3.1 Symmetric Core Designs

................................ ................................ .... 2

- 11 2.4.3.2 Core Deactivation Technology

................................ ........................... 2

- 13 2.5 SCREENING ANALYSIS

................................ ................................ ................ 2

- 15 2.5.1 Te chnology Options Screened Out

................................ ................................ .... 2

- 15 2.5.1.1 Nanotechnology Composites

................................ .............................. 2

- 16 2.6 ENGINEERING ANALYSIS

................................ ................................ ............ 2

- 16 2.6.1 Representative Units

................................ ................................ .......................... 2

- 17 2.6.2 Scaling Methodology

................................ ................................ ......................... 2

- 19 2.6.3 Design Option Combinations

................................ ................................ ............. 2

- 20 2.6.4 Materials Prices

................................ ................................ ................................ .. 2

- 21 2.6.5 Markups

................................ ................................ ................................ ............. 2

- 21 2.6.5.1 Markups for Prefabricated Amorphous Cores

................................ .... 2

- 22 2.6.5.2 Shipping Costs

................................ ................................ .................... 2

- 23 2.6.6 Ad ditional Costs for Amorphous Designs in Large Kilo

- Volt Ampere, Medium

Voltage Dry

- Type Design Lines

................................ ................................ ........ 2

- 23 2.6.7 Other Regulatory Imp acts on the Engineering Analysis

................................ .... 2

- 24 2.6.8 Baseline Efficiency and Candidate Standard Levels Analyzed

......................... 2

- 24 2.7 ENERGY USE AND END

- USE LOAD CHARACTERIZ ATION

................. 2

- 25 2.7.1.1 Overview of the Hourly Load Model

................................ ................. 2

- 26 2.7.1.2 Overview of the Monthly Load Model

................................ ............... 2

- 27 2.8 MARKUPS FOR EQUIPMEN T PRICE DETERMINATIO N

......................... 2

- 28 2.9 LIFE

- CYCLE COST AND PAYBA CK PERIOD ANALYSES

...................... 2

- 29 2.9.1 Electricity Price Analysis

................................ ................................ ................... 2

- 29 2.9.1.1 Hourly Marginal Electricity Price Model

................................ ........... 2

- 30 2.9.1.2 Monthly Marginal Electricity Price Model

................................ ......... 2

- 30 2.9.2 Transformer Service Lifetime

................................ ................................ ............ 2

- 302

- ii

2.9.3 Maintenance Costs

................................ ................................ ............................. 2

- 31 2.9.4 Emerging Technology Scenarios

................................ ................................ ....... 2

- 31 2.9.4.1 Symmetric Core Transformers

................................ ............................ 2

- 31 2.9.4.2 Core Deactivation Technology

................................ ........................... 2

- 31 2.10 SHIPMENTS ANALYSIS

................................ ................................ ................. 2

- 31 2.10.1 Inputs to Shipments Analysis

................................ ................................ ............. 2

- 32 2.10.1.1 Shipments Data

................................ ................................ ................... 2

- 32 2.10.2 Shipments Forecast

................................ ................................ ............................ 2

- 33 2.10.2.1 Efficiency Distribution and Efficiency Trend

................................ .... 2

- 33 2.11 NATIONAL IMPACT ANAL YSIS

................................ ................................ .. 2

- 34 2.12 LIFE

- CYCLE COST SUBGROUP ANALYSIS

................................ .............. 2

- 34 2.12.1 Proposed Subgroups

................................ ................................ ........................... 2

- 35 2.12.1.1 Municipal Utilities

................................ ................................ .............. 2

- 35 2.12.1.2 Rural Cooperatives

................................ ................................ ............. 2

- 35 2.12.1.3 Vault Transformers

................................ ................................ ............. 2

- 36 2.12.2 Consumer Participation

................................ ................................ ...................... 2

- 36 2.13 PRELIMINARY MANUFACT URER IMPACT ANALYSIS

......................... 2

- 36 2.13.1 Sources of Information for the Manufacturer Impact Analysis

......................... 2

- 37 2.13.2 Industry Cash

- Flow Analysis

................................ ................................ ............. 2

- 37 2.13.3 Manufacturer Subgroup Analysis

................................ ................................ ...... 2

- 37 2.13.4 Competitive Impacts Assessment

................................ ................................ ...... 2

- 38 2.13.5 Cumulative Regulatory Burden

................................ ................................ ......... 2

- 38 2.13.6 Preliminary Results for the Manufacturer Impact Analysis

.............................. 2

- 38 2.13.7 Core Steel Availability

................................ ................................ ....................... 2

- 38 2.13.8 Equipment Conversion Costs

................................ ................................ ............. 2

- 39 2.13.9 Intellectual Property

................................ ................................ ........................... 2

- 39 2.14 UTILITY IMPACT ANALY SIS

................................ ................................ ....... 2

- 40 2.15 EMPLOYMENT IMPACT AN ALYSIS

................................ ........................... 2

- 40 2.16 ENVIRONMENTAL ASSESS MENT

................................ .............................. 2

- 40 2.16.1 Carbon Dioxide

................................ ................................ ................................ .. 2

- 41 2.16.2 Sulfur Dioxide

................................ ................................ ................................ .... 2

- 41 2.16.3 N itrogen Oxides

................................ ................................ ................................ . 2

- 42 2.16.4 Mercury

................................ ................................ ................................ .............. 2

- 42 2.16.5 Particulate Matter

................................ ................................ ............................... 2

- 42 2.17 MONETIZATION OF EMIS SIONS REDUCTION BENE FITS

..................... 2

- 43 2.18 REGULATORY IMPACT AN ALYSIS

................................ ............................ 2

- 44

LIST OF TABLES

Table 2.4.1 Distribution Transformer Equipment Classes

................................ .............. 2

- 8 Table 2.4.2 National Distribution Transformer Shipment Estimates for 2009

............. 2

- 10 Table 2.4.3 Options and Impacts of Increasing Transformer Efficiency

...................... 2

- 11 Table 2.4.4 Symmetric Core Design Adjustments

................................ ........................ 2

- 13 Table 2.5.1 Design Options Screened Out of the Analysis

................................ ........... 2

- 16 Table 2.6.1 Engineering Design Lines and Representative Units for Analysis

............ 2

- 182

- iii LIST OF FIGURES

Figure 2.6.1 Method of Cost Accounting for Distribution Transformers Rulemaking 2

- 22 Figure 2.7.1 Load versus Marginal Price for Electricity Market Module Region: Southeastern Electric Reliability Council

................................ ................................ ...... 2

- 272

- 1 CHAPTER 2. ANALYTICAL FRAMEWORK

2.1 INTRODUCTION

This chapter provides a description of the general analytic framework the U.S. Department of Energy ( DOE or the Department ) is us ing to develop amended energy conservation standards for distribution transformers

. The chapter includes a description of the methodology, the analytical tools, and relationships among the various analyses that are part of this rulemaking

. In addition , chapter 2 provides an overview of any changes in the analysis between this rulemaking and DOE’s previous rulem aking on distribution transformers. Finally, chapter 2 provides citations and cross

- references to other chapters presented in this preliminary technical support document (TSD) that address DOE’s analytical approach, inputs, and findings.

The analyses pres ented in this preliminary TSD include :

a market and technology assessment to characterize the distribution transformer market and review techniques and approaches used to produce more efficient transformers;

a screening analysis to identify design option s that improve distribution transformer efficiency and to determine which ones DOE should evaluate and which it should screen out;

an engineering analysis to estimate the relationship between the manufacturer’s selling price (MSP) of a transformer and its efficiency level;

an energy use and end

- use load characterization to generate energy use estimates and end

- use load profiles of distribution transformers;

a markup process to convert manufacturer selling prices to customer installed prices;

a life

- cycle cost (LCC) analysis to calculate, at the customer level, the discounted savings in operating costs throughout the estimated average life of the distribution transformer, compared to any increase in the installed costs likely to result directly from the imposition of the amended standard ;

a payback period (PBP) analysis to calculate the amount of time it takes customers to recover the assumed higher purchase expense of more

- efficient equipment through lower operating costs;

a shipments analys is to estimate shipments of distribution transformers over the time period examined in the analysis; and2

- 2

a national impact analysis (NIA) to assess the aggregate national impacts of consumer payback, net present value (NPV) of total customer LCC, national energy savings (NES), and national employment ; and

a preliminary manufacturer impact analysis (MIA) to assess the potential impacts of amended energy conservation standards on manufacturers, such as impacts on capital conversion expenditures, marketing c osts, shipments, and research and development
costs.

The analyses DOE will perform in the subsequent Notice of Proposed Rulemaking (NOPR) stage include th e following:

a n LCC subgroup analysis to evaluate variations in customer characteristics that might cause a standard to affect particular customer sub

- populations, such as low

income households, differently from the overall population ;

a manufacturer impact analysis to estimate the financial impact of standards on manufacturers and to calculate impacts on competition, employment, and manufacturing capacity ;

a utility impact analysis to estimate the effects of proposed standards on electric, gas, or oil utilities ;

a n e mployment impact analysis to assess the aggregate impacts on national employment ;

a n environmental impact assessment to provide estimates of the effects of amended energy conservation standards on three pollutants

— sulfur dioxide (SO 2 ), nitrogen oxides (NO X ), and mercury (Hg)

— as well as carbon emissions ; and

a regulatory impact analysis to present major alternatives to proposed amended energy conservation standards that could achieve substantially the same regulatory goal at a lower cost.

In addition, DOE will revise the analyses it has performed in the preliminary stage based on comments and new information received.

2.2 BACKGROUND

Title III of the Energy Policy and Conservation Act (EPCA) of 1975, Pub. L. No. 94

- 163, (42 United States Code (U.S.C.) 6291 et s eq .) established an energy conservation program for major household appliances and industrial and commercial equipment. More specifically, part C of Title III (42 U.S.C. 6291

- 6309) establishes the ―Energy Conservation Program for Certain Industrial Equipme nt, ‖ a program covering the distribution transformers that are the focus of this document. EPCA requires DOE to promulgate energy conservation standards that achieve the2

- 3

maximum improvement in energy efficiency that DOE determines is both technologically feasible and economically justified. 42 U.S.C. 6295(o)(2)(A)

DOE published a final rule in October 2007 that created energy conservation standards for liquid

- immersed and medium

- voltage dry

- t ype (MVDT) distribution transformers. 10 CFR 431.196(b)

- (c); 72 FR 58190 (October 12, 2007) (the 2007 final rule) During the course of that rulemaking, the Energy Policy Act of 2005 (EPACT 2005), Pub

. L . No. 109

– 58

, amended EPCA to set standards for low

- voltage dry

- type (LVDT) distribution transformers. (42 U.S.C. 6295(y)) Consequently, DOE removed these transformers from the scope of the rulemaking. 72 FR at 58191.

After the publication of the 2007 final rule, certain parties filed petitions for review in the United States C ourts of Appeals for the Second and Ninth Circuits, challenging the final rule, and several additional parties were permitted to intervene in support of these petitions. (All of these parties are referred to below collectively as ―petitioners.‖) The petiti oners alleged that, in developing its energy conservation standards for distribution transformers, DOE did not comply with certain applicable provisions of EPCA and of the National Environmental Policy Act of 1969 (NEPA) , 42 U.S.C. 4321

- 4370f. DOE and the petitioners subsequently entered into a settlement agreement on July 10, 2009, to resolve the appeals. The settlement agreement outlined an expedited timeline for DOE to determine whether to amend the energy conservation standards for liquid

- immersed and M VDT distribution transformers. Under the settlement agreement, DOE must publish by October 1, 2011, either a determination that the standards for these distribution transformers do not need to be amended or a notice of proposed rulemaking (NOPR) that inclu des any proposed amended standards

, and that meets all applicable requirements of EPCA and NEPA. If DOE finds that amended standards are warranted, DOE must publish a final rule containing such amended standards by October 1, 2012. This document is DOE’s f irst step in satisfy ing the requirements of the settlement agreement.

DOE is initiating this rulemaking at the preliminary analysis stage rather than the framework document stage. In considering new or amended standards for a given product or type of equ ipment, DOE’s current practice generally is to publish a framework document as the first step in the rulemaking process, and to subsequently issue a preliminary technical support document ( TSD ) that contains DOE’s preliminary analyses as to potential stand ards. The framework document generally advises interested parties of the analytical methods, data sources, and key assumptions DOE plans to use in considering the adoption of standards for the product or type of equipment. Typically

, the document does not contain any analysis of the data. However, b ecause the previous rulemaking to develop standards for distribution transformers was completed relatively recently, DOE has a set of methodologies, data sources and assumptions that have recently been vetted and revised according to public comments and that the Department can use to perform the analyses needed for this rulemaking. DOE will conduct the analyses referenced by the petitioners according to standard practices for energy conservation standard rulemakin gs. Therefore, DOE is initiating this rulemaking at the preliminary analysis stage and has prepared a preliminary TSD on which it is requesting comment.

At present, DOE plans to examine in this rulemaking amended standards for LVDT distribution transform ers, as well as amended standards for liquid

- immersed and MVDT2

- 4

transformers. DOE is not required to consider LVDT distribution transformers as part of the settlement agreement. As such, DOE may subsequently opt to conduct a separate rulemaking for LVDT tra nsformers with a different timeline. However, the preliminary analysis considers LVDT distribution transformers along with liquid

- immersed and MVDT distribution transformers.

2.2.1 Test Procedure

On April 27, 2006, DOE codified a test procedure final rule for di stribution transformers in appendix A to subpart K of Title 10 of the Code of Federal Regulations, Part 431 (10 CFR Part 431 ), ―Uniform Test Method for Measuring the Energy Consumption of Distribution Transformers

. ‖ 71 FR 24 972 The test procedure outlined how manufacturers must test their distribution transformers to certify to DOE that their equipment complies with energy conservation standards and to quantify the efficiency of their equipment

. Also, these test procedures must be used whenever testing is required in an enforcement action to determine whether covered equipment complies with efficiency standards

.

While t he current rulemaking is specifically considering revisions to the energy conservation standards for distribution transformers , DOE also i ntends to rev iew the current test procedure. DOE must amend each test procedure within seven years of its original publication. 42 U.S.C. 6314(a)(1) This requirement took effect with the Energy Independence and Security Act 2007 (EISA), so the distribution transformer test procedure must be amended by 2014. Therefore, DOE seeks comment on its current test procedure for distribution transformers. DOE received some feedback on the test procedure during its preliminary interviews with manufacturers, in particu lar relevant to the issue of multiple/dual

- voltage windings.

2.2.1.1 Multiple/Dual

- Voltage Windings

In the distribution transformer test procedure published in 2006, DOE stated that the manufacturer had to determine the basic model’s efficiency either at the voltage at which the highest losses occur or at each voltage at which the transformer is rated to operate. 71 FR 24985 (April 27, 2006). This provision addressed the case of transformers with windings that could be reconfigured to input or output at different voltages. In most cases, operating voltages for which windings are configured in parallel are associated with lowered efficiency.

DOE is aware that this provision has had unintended consequences for manufacturers

. Through manufacturer interviews, DOE has learned that this provision may have effectively raised the standard levels for equipment classes with dual

- or multiple

- voltage transformers

. The analysis from the previous rulemaking and the current rulemaking presumes the windings are connected in series, but the testing requirements demand compliance with the standard in the parallel confi guration , which is oftentimes less efficient

. Additionally, the requirement to measure losses at the voltage with the highest losses has potentially increased testing burden for manufacturers that do not rely on alternate efficiency determination m ethod s ( AEDMs ) for compliance testing. This is because the highest losses will ordinarily occur with paralleled winding s. However, I nstitute of Electrical and Electronics Engineers (I EEE ) requirements stipulate that transformers be shipped to customers with windin gs in series, and so manufacturers are obligated to reconfigure the windings after testing.2

- 5

DOE proposes to eliminate the requirement for manufacturers to test in the least efficient secondary configuration, instead allowing manufacturers to meet the effi ciency standard in any secondary configuration. This proposed change is based on several factors, in addition to the reduced testing burden discussed above. First, DOE understands that less than one percent of transformers are operated with their secondar y windings in parallel

, and furthermore, that they are often switched back into series with grid updates. Second, D OE believes that the differential efficiency between parallel and series operation is relatively small. It varies by model, but typically rep resents a very small percent of load losses. Finally, DOE believes that the efficiencies of parallel and series configured secondary windings will tend to increase or decrease together. In other words, many of the steps a manufacturer would take to increas e the efficiency of one configuration would also benefit the other.

DOE understands that dual

- voltage and multiple

- voltage distribution transformers with reconfigurable secondaries are most commonly employed in low kVA, single

- phase, liquid

immersed, pole

- mounted units

. Therefore, DOE could apply the exemption from testing in the configuration with the highest losses to that subset of transformers

. DOE seeks comment on its proposal to c hange the testing requirement to allow compliance testing in any secondary configuration

. Additionally, DOE seeks comment on whether the proposed revision should apply to all covered distribution transformers or a subset of transformers

. DOE welcomes the

s ubmission of any data that would support a conclusion.

DOE understands that some transformers are also built with reconfigurable primary windings, but that the different primary windings oftentimes exhibit larger differences in efficiency than the efficie ncy differences between secondary windings. For example, a primary of 2400 x 7620 V involves an uneven number of winding sections, thereby resulting in a significant difference in efficiency from one configuration to the other. For this reason, DOE
propose s to maintain the requirement that amended standards must be met at the least efficient primary configuration.

Finally, DOE understands that different winding configurations might have different basic impulse level ( BIL ) ratings

, such as for a primary wi nding of 7200 x 14400 V where the 7200 V is at 95 kV BIL and the 14400 V is at 125 kV. To remove any ambiguity regarding which BIL rating should be used to meet the amended standard

, DOE proposes that the lowest BIL for which a given configuration is rated should be used to show compliance with the standard

. DOE asks for comment on this proposal concerning the appropriate BIL to use for dual/multiple

- voltage distribution transformer compliance

.
2.2.1.2 Weighted

- Average Losses from Multiple Loading Points

DOE understands that distribution transformers experience varying levels of efficiency depending on the load applied. This loading varies throughout the course of operation, and also varies between the various end

- use applications for each distribution tra nsformer. As such, the current test procedure specifies a reference load factor equal to the root mean square (RMS) loading experienced across all tra n sformers of a particular type. LVDT transformers are currently tested with a 35 percent load, while liqui d

- immersed and MVDT transformers are tested at 50 percent load. These requirements allow a consistent benchmark across all2

- 6

transformers of a single type, and reflect the losses and efficiency at a loading consistent with the RMS loading experienced in serv ice.

Certain technolog ies enable distribution transformers to experience lower losses at low loading points compared with traditional designs. An example is core deactivation technology, which is described further in section 2.4.3.2 . This technology switches a system of transformer cores on and off in response to load demands, which enables energy savings at lower load factors compared to traditional transformer de signs. The current test procedure, specifying a single load factor, would not capture the energy savings benefit of this technology.

DOE proposes allowing a weighted

- average of losses from multiple loading points in determining the efficiency of technolog ie s such as core deactivation technology. By taking a weighted

- average of multiple load factors, the test procedure would better represent the energy savings potential of these technologies. The weighting applied to each load factor could be designated suc h that the weighted

- average losses equal the same losses as measured at the current test procedure loading for traditional transformer designs. For example, DOE believes the following weighting would yield total losses identical to the total losses at 35 p ercent loading for traditional LVDT transformer designs: 0.31 at 0 percent, 0.22 at 15 percent, 0.20 at 35 percent, 0.18 at 50 percent, and 0.09 at 75 percent. While this weighting would not affect the losses of traditional transformer designs, it would be tter represent the losses of a core deactivation system that experiences greater efficiencies at lower loading points.

DOE seeks comment on the proposal to designate a weighted

- average loss calculation using various loadings to capture the energy savings potential of technologies that do not follow the ― loading vs. losses ‖ relationship evident in traditional transformer designs. DOE welcomes comment on the appropriate weightings to use for the different load factors.

2.2.1.3 Other Aspects of the Test Procedur e
During preliminary manufacturer interviews, DOE received feedback on several aspects of the current test procedure for distribution transformers. Topics covered included reference load factors, reconfigurable secondaries, and harmonization with the IEEE te st procedure. DOE welcomes comment on all aspects of the current test procedure for distribution transformers.

2.3 SCOPE OF COVERAGE

This standards rulemaking concerns all distribution transformers, including liquid

immersed, LVDT , and MVDT distribution transformers

. The definition of a distribution transformer was presented in EPACT 2005, and then further refined by DOE when it was codified in Title 10 of the Code of Federal Regulations , Part 431 ( 10 CFR Part 431 ) on April 27, 2006

, 71 FR 2 4972

, 10 CFR 431.192 , as follows:

Distribution transformer means a transformer that

- (1) Has an input voltage of 34.5 kV or less; (2) Has an output voltage of 600 V or less; (3) Is rated for operation at a frequency of 60 Hz; and2

- 7

(4) Has a capacity of 10 kVA to 2500 kVA for liquid

- immersed units and 15 kVA to 2500 kVA for dry

- type units; but (5) The term ―distribution transformer‖ does not include a transformer that is an

– (i) Autotransformer; (ii) Drive (isolation) transformer; (iii) Grounding transfor mer; (iv) Machine

- t ool ( c ontrol) t ransformer; (v) Nonventilated t ransformer; (vi) Rectifier t ransformer; (vii) Regulating t ransformer; (viii) Sealed t ransformer; (ix) Special

- i mpedance t ransformer; (x) Testing t ransformer; (xi) Transformer with t ap r ange of 20 percent or more; (xii) Uninterruptible p ower s upply t ransformer; or (xiii) Welding t ransformer.

Further detail on the definition of each of these terms can be found in chapter 3.

2.4 MARKET AND TECHNOLOG Y ASSESSMENT

The market and technology assessment ( see c hapter 3 of the preliminary TSD ) characterizes the distribution transformer markets and existing technology options for making a transformer more efficient

. When DOE begins an energy conservation standards rulemaking, it develops information that pro vides an overall picture of the market for the equipment considered, including the nature of the equipment, market characteristics, and industry structure

. This activity consists of both quantitative and qualitative efforts

, based primarily on publicly ava ilable information.

The discussion below summarizes the analytical approach and key issues highlighted during DOE’s preliminary interviews with manufacturers in 2010

. A more detailed discussion on DOE’s approach can be found in the market and technology assessment (chapter 3 of the preliminary TSD).

2.4.1 Equipment Classes

DOE divided the covered distribution transformers into groups called equipment classes

. DOE divided transformers into equipment classes using the following criteria: ( a) the type of
energy u sed, ( b) capacity, and ( c) performance related features that affect customer utility or efficiency

. Different efficiency standards apply to different equipment classes

. DOE developed its equipment classes using information obtained from manufacturers, trad e associations, and other interested parties

.

The equipment classes for this rulemaking are the same as the equipment classes DOE examined for its previous rulemaking on distribution transformers

. Table 2.4

. 1 presents the equipment classes.2

- 8

Table 2.4

. 1 Distribution Transformer Equipment Classes EC # Insulation Voltage Phase BIL Rating kVA Range 1 Liquid

- Immersed Medium Single

- 10

- 833 kVA 2 Liquid

- Immersed Medium Three

- 15

- 2500 kVA 3 Dry

- Type Low Single

- 15

- 333 kVA 4 Dry

- Type Low Three

- 15

- 1000 kVA 5 Dry

- Type Medium Single 20

- 45kV BIL 15

- 833 kVA 6 Dry

- Type Medium Three 20

- 45kV BIL 15

- 2500 kVA 7 Dry

- Type Medium Single 46

- 95kV BIL 15

- 833 kVA 8 Dry

- Type Medium Three 46

- 95kV BIL 15

- 2500 kVA 9 Dry

- Type Medium Single ≥ 96kV BIL 75

- 833 kVA 10 Dry

- Type Medium Three ≥ 96kV BIL 225

- 2500 kVA

2.4.1.1 Less

- Flammable Liquid

- Immersed Transformers

For the 2007 final rule, DOE solicited comment on how it should treat distribution transformers filled with an insulating fluid of higher flash point than that of traditional mineral oil. 71 FR 44369 (August 4, 2006). Known as ―les s

- flammable, liquid

- immersed‖ (LFLI ) transformers , these units are marketed to some applications where a fire would be e specially costly , such as indoor applications traditionally served by the dry

- type market

. During preliminary interviews with manufacturers, DOE was informed that LFLI transformers might offer the same utility as a dry

- type transformer, since they were unlikely to catch fire. Furthermore, DOE heard that LFLI transformers could have an efficiency disadvantage relative to traditional liquid

- immersed transformers because their more viscous insulating fluid required more internal ducting to properly circulate.

In that 2007 rulemaking, DOE determined that LFLI transformers should be considered in the same equipment class as traditional liquid

- immersed transformers. DOE concluded that the design of a transformer (i.e., dry

- type or liquid

- immersed) was a performance

- related feature that affects the energy efficiency of the equipment and, therefore, dry

- type and liquid

- immersed should be analyzed separately. 72 FR 5820 2 (October 12, 2007). Furthermore, DOE found that LFLI transformers could meet the same efficiency levels as traditional liquid

- immersed units

. As a result, DOE did not separately analyze LFLI transformers, but relied on the analysis for the mineral oil liquid

- immersed transformers. 72 FR 58202 (October 12, 2007).

In the current rulemaking, DOE revisited the issue in light of additional research on LFLI transformers and conversations with manufacturers and industry experts. DOE first considered whether L FLI transformers offered the same utility as dry

- type equipment, and came to the same conclusion as in the last rulemaking. W hile LFLI transformers can be used in some applications that historically use dry

- type units, there are applications that cannot to lerate a leak or fire

. In these applications, customers assign higher utility to a dry

- type transformer. Since LFLI transformers can achieve higher efficiencies than comparable dry

- type units, including both types in one equipment class may result in stand ard levels that dry

- type units are unable to meet, either cost

- effectively or at all

. Therefore, DOE decided not to analyze LFLI transformers in the same equipment classes as dry

- type distribution transformers.2

- 9

Similarly, DOE revis i ted the issue of whethe r or not LFLI transformers should be analyzed separately from traditional liquid

- immersed units

. DOE con c luded, once again, that LFLI transformers could achieve any efficiency level that mineral oil units could achieve

. Although their insulating fluids are slightly more viscous, this disadvantage has little efficiency impact, and diminishes as efficiency increases and heat dissipation requirements decline. Furthermore, at least one manufacturer sugg ested that LFLI transformers might be capable of higher eff i ciencies than mineral oil units since their higher temperature tolerance may allow the unit to be downsized and r u n hotter than mineral oil units . For these reasons, LFLI transformers would not be disproportionately affected by standards set in the liquid

- immersed equipment classes based on mineral oil units

. T herefore, DOE is not considering LF LI in a separate equipment class.

2.4.2 Market Assessment

The market assessment examine d manufacturers, trade associations, and the quantities and types of equipment so ld and offered for sale

. Issues addressed in this market assessment included: ( 1) national transformer shipments; ( 2) identification of the largest players in the transformer industry; ( 3) existing non

- regulatory efficiency improvement initiatives; ( 4) developments around standards in States and neighboring countries; and ( 5) trends in equipment characteristics and retail markets

. The information collected served as resource material that DOE used throughout the rulemaking

. Detailed information can be found in chapter 3 of the preliminary TSD.

2.4.2.1 National Shipments Estimate

DOE estimated the annual transformer shipments to prepare an estimate of the national impact of energy conservation standards for distribution transf ormers

. Unit shipments were calcula ted for each kVA rating within each equipment class

. The foundation for DOE’s shipment estimate came from data provided by the National Electrical Manufacturers Association (NEMA)

. This data represented only a portion of the total market, however, so DOE c ontracted a company with considerable knowledge of the U.S. transformer industry to develop a complete picture of the industry shipments

. The contractor used the NEMA data, its own knowledge of the market, and a limited number of consultative calls to comp ile a national estimate of shipments for liquid

- immersed, LVDT , and MVDT transformers.

In general, the shipment data collected for 2009 represents a contraction in the distribution transform er market

. This contraction results from the global economic down turn experienced during 2009, which lead to a reduction in new residential, commercial, and industrial development

. This reduction in development decreased demand for distribution transformers

. Table 2.4

. 2 shows a summary of the shipment data collected for each equipment class analyzed

. Additional detail can be found in chapter 3 of the preliminary TSD

.2

- 10

Table 2.4

. 2 National Distribution Transformer Shipment Estimates for 2009 Distribution Transformer Equipment Class Units Shipped MVA Capacity

Shipped Shipment Value

(200 9 US$million) Liquid

- immersed, medium

- voltage, single

- phase 683,726 21,994 714.8 Liquid

- immersed, medium

- voltage, three

- phase 49,739 32,266 786.0 Dry

- type, low

- voltage, single

- phase 17,740 647 22.0 Dry

- type, low

- voltage, three

- phase 206,929 15,778 394.4 Dry

- type, medium

- voltage, single

- phase, 20

- 45 kV BIL 709 23 0.7 Dry

- type, medium

- voltage, three

- phase, 20

- 45 kV BIL 522 257 6.2 Dry

- type, medium

- voltage, single

- phase, 46

- 95 kV BIL 546 23 0.8 Dry

- type, medium

- voltage, three

- phase, 46

- 95 kV BIL 2,074 3,655 98.7 Dry

- type, medium

- voltage, single

- phase, ≥ 96 kV BIL 202 9 0.3 Dry

- type, medium

- voltage, three

- phase, ≥ 96 kV BIL 1,286 2,206 66.2 Total 963,473 76,858 2,090.1

2.4.2.2 Distribution and Sales Channels

The market delivery channel for distribution transformers varies for different types of
customers

. Electric utilities generally purchase transformers directly from manufacturers

. For these purchases, the utility provide s a specification of the value it places on future core and coil losses over the life of the transformer

. These values are used to generate an optimized
tr ansformer design with the lowest tota l owning cost for the utility

. This market dynamic leads manufacturers to develop many custom designs.

The delivery channel for commercial and industrial customers can be complex, working through intermediaries such as stocking distributors and electrical contractors. This is because these customers typically purchase smaller quantities of transformers

. Some larger industrial customers buy transformers directly from distributors or manufacturers , and similarly, many ori ginal equipment manufacturers (OEMs) work directly with manufacturers.

2.4.2.3 Total Owning Cost Evaluation

The total owning cost (TOC) evaluation is a formula that incorporates core and winding losses into the purchase decision for a distribution transformer

. Following the energy price shocks of the 1970s, many transformer customers (such as utilities) began evaluating distribution transformer purchase decisions using a TOC evaluation

. The TOC consists of the quoted transformer price and energy losses in the co re and winding over the anticipated life of the unit.

Expressed as a formula,

TOC = (NL A) + (LL B) + Price Eq

. 2.4

. 1

where:

TOC = total owning cost ($), NL = no

- load loss (Watts), A = equivalent first

- cost of no

- load losses ($/Watt),2

- 11 LL = load loss at the transformer’s rated load (Watts), B = equivalent first

- cost of load losses ($/Watt), and Price = bid price (retail price)($).

The capitalized cost per watt of no

- load and load losses, the A and B factors, vary from

one customer to another

. Customers that use A and B factors compare two or more proposals from various manufacturers and select the one that offers them the lowest tot al owning cost (i.e., the lowest combination of first cost and operating cost over the life of the transformer)

. Additional detail can be found in chapter 3 of the preliminary TSD.

2.4.3 Technology Assessment

The technology assessment provides information about existing technology options and designs to construct more energy

- efficient distribution transformers

. There are two main types of losses in transformers: no

- load (core) losses and load (winding) losses

. M easures taken to reduce one type of loss typically i ncrease the other type of losses

. Some examples of design options to improve efficiency include: ( 1) higher

- grade electrical core steels, ( 2) use of different conductor types and materials, and ( 3) adjustments to core and coil configurations.

In consultat ion with interested parties, DOE identified several technology options and designs for consideration

. These technology options are presented in Table 2.4

. 3

. Further de tail on these technology options can be found in chapter 3 of the preliminary TSD.

Table 2.4

. 3 Options and Impacts of Increasing Transformer Efficiency
No

- load losses Load

losses Cost

impact To decrease no - load losses Use lower

- loss core materials Lower No change* Higher Decrease flux density by: (a) Increasing core cross

- sectional area (CSA) (b) Decreasing volts per turn Lower Lower Higher

Higher Higher

Higher Decrease flux path length by decreasing conductor CSA Lower Higher Lower Use 120 ̊ symmetry in three

- phase cores** Lower No change TBD To decrease load losses Use lower

- loss conductor material No change Lower Higher Decrease current density by increasing conductor CSA Higher Lower Higher Decrease current path length by: (a) Decreasing core CSA (b) Increasing volts per turn Higher Higher Lower

Lower Lower

Lower * Amorphous core materials would result in higher load losses because flux density drops, requiring a larger core volume. ** Sometimes referred to as a ―hexa

- transformer‖ design.

2.4.3.1 Symmetric Core Designs

DOE understands that several companies worldwide are commercially producing three

phase transformers with symmetric cores

– those in which each leg of the transformer is identically conn ected to the other two. The symmetric core uses a continuously wound core with 120 degree radial symmetry, resulting in a triangularly shaped core when viewed from above. In2

- 12

a traditional core, the center leg is magnetically distinguishable from the other two because it has a shorter average flux path to each. In a symmetric core, however, no leg is magnetically distinguishable from the other two.

One manufacturer of symmetric core transformers cite d several advantages to the symmetric core. These include reduced weight, volume, no

- load losses, noise, vibration, stray magnetic fields, inrush current, and power in the third harmonic. Thus far, DOE has only seen limited cost and efficiency data for a few symmetric core units from testing done by manufacturers

. DOE has not seen any designs for symmetric core units modeled in a software
program.

Because of zero

- sequence fluxes associated with wye

- wye connected transformers, symmetric core designs are best suited to delta

- delta or delta

- wye connections. While t r aditional

cores can circumvent the problem of zero

- sequence fluxes by introducing a fourth or fifth unwound leg

, core symmetry makes extra legs inherently impractical. Yet another way to mitigate zero

- sequence fluxes comes in the form of a tertiary winding , which is delta

- connected and has no external connections. This winding is dormant when the transformer’s load is balanced across its phases

. Although symmetric core designs may, in theory, be made tolerant of

zero

- sequence fluxes by employing this method

, this comes at extra cost and complexity.

Using this tertiary winding, DOE believes that symmetric core designs can service nearly all distribution transformer applications in the United States

. Most dry

- type transformers have a delta connection and wou ld not require a tertiary winding

. Similarly, most liquid

- immersed transformers serving the industrial sector have a delta connection

. These market segments could use the symmetric core design without any modification for a tertiary winding

. However, i n th e United States most utility

- operated distribution transformers are wye

- wye connected. These transformers would require the tertiary winding in a symmetric core design

. DOE understands that symmetric core designs are more challenging to manufacture and

re quire specialized equipment that is currently uncommon in the industry

. However , DOE did not find a reasonable basis to screen this technology option out of the analysis , and is aware of at least one manufacturer producing dry

- type symmetric core design s commercially in the United States

. While DOE lacked the necessary data to perform a thorough engineering analysis of symmetric core designs , DOE used several assumptions to roughly estimate the cost

- efficiency relationship of symmetric core designs. DOE adjusted its traditional core designs to simulate the cost and efficiency of a comparable symmetric core design. To do this, DOE reduced core losses and core weight while increasing labor costs to approximate the symmetric core designs. These adjustments w ere based on data received from manufacturers, published literature, and through conversations with manufacturers. Table 2.4

. 4 indicates the range of potential adjust ments for each variable that DOE considered and the mean value used in the analysis. The simulated cost

efficiency relationships for symmetric core designs are presented in chapter 5, and the life

- cycle cost savings are presented in chapter 8 of the prelim inary TSD

.2

- 13

Table 2.4

. 4 Symmetric Core Design Adjustments
Range Core Losses (W) Core Weight (lbs) Labor Hours [Percentage Change s ] Minimum

- 0.0

- 12.0 +10.0 Mean

- 15.5

- 17.5 +55.0 Maximum

- 25.0

- 25.0 +100.0

DOE applied these adjustments to each of the traditional three

- phase transformer designs to develop a cost

- efficiency relationship for symmetric core technology. DOE did not model a tertiary winding for the wye

- wye connected liquid

- immersed design lines (DL)

. Based on its research, DOE believes that the losses associated with the tertiary winding may offset the benefits of the symmetric core design , and the tertiary winding will al so add cost to the design. Instead, DOE modeled symmetric core desig ns for the three

- phase, liquid

- immersed design lines without a tertiary winding to examine the impact of symmetric core technology on the subgroup of applications that do n ot require the tertiary winding.

DOE seeks comment on symmetric core designs, their practicability to manufacture and install, and whether or not they offer potential for efficiency improvement. In particular, DOE seeks comment on any application types in which using a symmetric core design may be infeasible. DOE requests comment on the adjustments it used to estimate symmetric core cost

efficiency relationships, and welcomes any performance data generated from simulation or testing that demonstrate the performance of symmetric core designs.

2.4.3.2 Core Deactivation Technology

Core deactivation technology employs the concept that a system of smaller transformers can replace a single, larger transformer

. For example, three transformers sized at 25 kVA and operated in parallel could replace a single 75 kVA transformer

. Winding losses are proport ionally smaller at lower load factors, but for any given current

, a smaller transformer will experience greater winding losses than will a larger transformer. As a result, those losses may be more than offset by the smaller transformer’s reduced core losses. As loading increases, winding losses become proportionally larger and eventually outweigh the power saved by using the smaller core. At that point, the control unit (which consumes little power itself) switches on an additional transformer , which r educes winding losses at the cost of additional core losses

. The control unit knows how efficient each combination of transformers is for any given loading, and is constantly monitoring the unit’s power output so that it will use the optimal number of core s. In theory, there is no limit to the number of transformers that may be paralleled in this sort of system, but cost considerations would imply an optimal number.

DOE had the opportunity to speak with a company that is developing a core deactivation technology. Noting that many dry

- type transformers are operated at very low loadings a large percentage of the time ( e.g. , a building at night), the company seeks to reduce core losses by replacing a single, traditional transformer with two or more smaller units that could be activated and deactivated in response to load demands

. A special unit controls which transformers are activated and deactivated in real

- time in response to the load demands.2

- 14

As mentioned in section 2.2.1.2

, core deactivation technology could save energy over a real world loading cycle, but those savings might not be represented in the current DOE test procedure

. Presently, the test procedure specifies a single loading point of 50 percent for liquid

immersed and MVDT transformers, and 35 percent for LVDT

. The real gain in efficiency for this technology is at loading points below the RMS loading specified in the tes t procedure, where some transformers in the system could be deactivated

. At loadings where all transformers are activated, which may be the case at the test procedure l oading, the combined core and coil losses of the system of transformers could exceed tho se of a single, larger transformer

. This would result in a lower efficiency for the system of transformers compared to the single, larger transformer. Therefore, DOE proposes allowing a weighted

- average loss calculation using various loadings to capture th e energy savings potential of core deactivation technology.

For the preliminary analysis, DOE did not directly analyze core deactivation technology, though DOE believes it is possible to evaluate the technology using its existing transformer designs. To a nalyze this technology, DOE would consider core deactivation systems composed of three identical transformers, each with one

- third the kVA size of the analyzed design lines. This creates a core deactivation system of the same total kVA size as the analyzed design lines. Each of these core deactivation systems could be evaluated under various loading scenarios to identify the energy savings potential at loadings below and above the RMS load factor. While it is possible to manufacture core deactivation system s using different designs for each component transformer, it requires a dditional design complexities. For example, using different component transformer designs necessitates a similar winding design to maintain the impedance across each
tr ansformer at each load factor. These complexities would not need to be considered in the analysis when analyzing three identical component transformer designs.

To examine each component transformer design, DOE could scale the engineering analysis of its existing design lines to simulate a transformer of one

- third the kVA size. DOE would scale the loss es, MSP , weight, and dimensions using the 0.75 scaling rule explained in section 2.6.2 . The resulting designs could be analyzed as component transformers for the core deactivation system. DOE could then simulate a core deactivation system by combining three identical component transformers and considering the losses at each loading po int for the following three scenarios: (1) all three component transformers are activated, (2) two component transformers are activated, and (3) only one compo nent transformer is activated. Given this information, DOE could simulate the performance of a co re deactivation system by evaluating the scenario with the least losses for a given load factor.

DOE understands that core deactivation technology is most easily implemented in LVDT dis tribution transformer designs. Implementing core deactivation technolo gy in medium

- voltage distribution transformers is possible, but poses difficulties for switching the prim ary and secondary connections. DOE has not fully quantified these differences, but intends to examine core deactivation technology in more detail for a ll types of transformers during the analysis for the notice of proposed rulemaking. See chapter 5 of the preliminary TSD for further information.

DOE seeks comment on core deactiv ation technology

. DOE requests input on any considerations necessary for analyzing core deactivation systems composed of different2

- 15

component transformers , or core deactivation systems for medium

- voltage distribution transformers . DOE also seeks comment on the types of appli cations that might benefit from using the technology, and any other considerations relating the technology to the current test procedure. Finally, DOE seeks input on any intellectual property concerns related to employing core deactivation technology.

2.5 SCRE ENING ANALYSIS

After DOE identified the technologies that might improve the energy efficiency of distribution transformers, DOE conducted the screening analysis

. The purpose of the screening analysis is to determine which options to consider further and wh ich to screen out

. DOE consults with industry, technical experts, and other interested parties in developing a list of design options

. DOE then applies the following set of screening criteria to determine which design options are unsuitable for further con sideration in the rulemaking (10 CFR Part 430, subpart C, appendix A at 4(a)(4) and 5(b)):

Technological Feasibility: DOE will consider only those technologies incorporated in commercial equipment or in working prototypes to be technologically feasible.

Practicability to Manufacture, Install, and Service: If mass production of a technology in commercial equipment and reliable installation and servicing of the technology could be achieved on the scale necessary to serve the relevant market at the time of t he effective date of the standard, then DOE will consider that technology practicable to manufacture, install, and service.

Adverse Impacts on Equipment Utility or Equipment Availability: DOE will not further consider a technology i f DOE determines it wil l have a significant adverse impact on the utility of the equipment to significant subgroups of customers . DOE will also not further consider a technology that will result in the unavailability of any covered equipment type with performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as equipment generally available in the United States at the time.

Adverse Impacts on Health or Safety: DOE will not further consider a technology i f DOE de termines that the technology will have significant adverse impacts on health or safety.

For a complete discussion of the screening analysis, refer to chapter 4 of the preliminary TSD

.
2.5.1 Technology Options Screen ed Out

DOE developed an initial list of efficiency enhancement design options from the technologies identified in the technology assessment

. Then DOE reviewed the list to determine if the design options are practicable to manufacture, install, and service ; would adversely affect equipment utilit y or equipment availability ; or would have adverse impacts on health and safety

.2

- 16

In the engineering analysis, DOE considered those efficiency enhancement design options that satisfied the four screening criteria; it did not consider those options that fail ed to satisfy one or

m ore of the screening criteria

. The design options screened out are summarized in Table 2.5

. 1

.
Table 2.5

. 1 Design Options Screened Out of the Analysis

Design Option Excluded Eliminating Screening Criteria
Silver as a Conductor Material Practicability to manufacture, install, and service High

- Temperature Superconductors Technological feasibility; Practicability to manufacture, install, and service Amorphous Core Material in Stacked Core Configuration Technological feasibility; Practicability to manufacture, install, and service Carbon Composite Materials for Heat Removal Technological feasibilit y High

- Temperature Insulating Material Technological feasibility
Solid

- State (Power Electronics) Technology Technological feasibility ; Practicability to manufacture, install, and service Nanotechnology Composites Technological feasibility

Chapter 4 of this preliminary TSD discusses each of these screened out design options in more detail

, and also which design options DOE considered in the distribution transformer engineering analysis

. The chapter also includes a list of emerging technologi es that could impact future distribution transformer manufacturing costs

. The design options screened out of this analysis are the same as the design options that were screened out during DOE’s previous rulemaking on distribution transformers , with the add ition of nanotechnology composites

.
2.5.1.1 Nanotechnology Composites

DOE understands that the nanotechnology field is actively researching ways to produce bulk material with desirable features on a molecular scale. Some of these materials may have high resistivit y, high permeability, or other properties that make them attractive for use in electrical transformers. DOE knows of no current commercial efforts to employ these materials in distribution transformers and no prototype designs using this technology, but we lcomes comment on such technology and its implications for the future of the industry.

2.6 ENGINEERING ANALYSIS

The engineering analysis (Chapter 5) develops cost

- efficiency relationships for equipment types that are the subject of a rulemaking, estimating manufacturer costs of achieving increased efficiency levels

. DOE uses manufacturing costs to determine retail prices in the LCC analysis, and also uses them in the MIA

. The engineering analysis also determines the maximum technologically feasible energy ef ficiency level.

In general, the engineering analysis estimates the efficiency improvement potential of individual design options or combinations of design options that pass the four criteria in the screening analysis

. DOE uses this cost

- efficiency relatio nship, developed in the engineering analysis, in the LCC analysis.2

- 17

As described in Chapter 1, DOE considered those distribution transformers that are designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy (Secretary) determines is technologically feasible and economically justified

. (42 U.S.C. 6295(o)(2)(A)) Therefore, an important role of the engineering analysis was to identify the maximum technologically feasible efficiency level

. The maximum technologically feasi ble level is one that can be reached by adding efficiency improvements and/or design options, both commercially feasible and in prototypes, to the baseline units

. DOE believes that the design options comprising the maximum technologically feasible level mu st have been physically demonstrated in at least a prototype form to be considered technologically feasible.

In general, DOE can use three methodologies to generate the manufacturing costs needed for the engineering analysis

. These methods are:

1. the design

- option approach

– reporting the incremental costs of adding design options to a baseline model;

2. the efficiency

- level approach

– reporting relative costs of achieving improvements in energy efficiency; and

3. the reverse engineering or cost assessment approach

– involving a "bottom up" manufacturing cost assessment based on a detailed bill of materials derived from transformer teardowns.

DOE’s analysis for the distribution transformers rulemaking is based on the design

option approach, in which design software is used to assess the cost

- efficiency relationship between various design option combinations

. This is the same approach that was taken in the previous rulemaking for distribution transformers.

2.6.1 Representative Units

The engineering analysis analyz ed 13 key design lines that cover the range of equipment classes within the distribution transformer market

. Within each design line, DOE selected a representative unit to analyze in the engineering analysis

. Table 2.6

. 1 outlines the design lines and representative units selected for each equipment class.2

- 18

Table 2.6

. 1 Engineering Design Lines and Representative Units for Analysis

E C * DL Type of Distribution

Transformer kVA Range Representative Unit for this

Engineering Design Line

1 1 Liquid

- immersed, single

- phase,

rectangular tank 10

– 167 50 kVA, 65 C, single

- phase, 60Hz, 14400V primary, 240/120V secondary, rectangular tank

2 Liquid

- immersed, single

- phase, round tank 10

– 167 25 kVA, 65 C, single

- phase, 60Hz, 14400V primary, 120/240V secondary, round tank

3 Liquid

- immersed, single

- phase 250

– 833 500 kVA, 65 C, single

- phase, 60Hz, 14400V primary, 277V secondary

2 4 Liquid

- immersed, three

- phase 15

– 500 150 kVA, 65 C, three

- phase, 60Hz, 12470Y/7200V primary, 208Y/120V secondary

5 Liquid

- immersed, three

- phase 750

– 2500 1500 kVA, 65 C, three

- phase, 60Hz, 24940GrdY/14400V primary, 480Y/277V secondary

3 6 Dry

- type, low

- voltage, single

phase 15

– 333 25 kVA, 150 C, single

- phase, 60Hz, 480V primary, 120/240V secondary, 10kV BIL

4 7 Dry

- type, low

- voltage, three

phase 15

– 150 75 kVA, 150 C, three

- phase, 60Hz, 480V primary, 208Y/120V secondary, 10kV BIL

8 Dry

- type, low

- voltage, three

phase 225

– 1000 300 kVA, 150 C, three

- phase, 60Hz, 480V Delta primary, 208Y/120V secondary, 10kV BIL

6 9 Dry

- type, medium

- voltage,

three

- phase, 20

- 45kV BIL 15

– 500 300 kVA, 150 C, three

- phase, 60Hz, 4160V Delta primary, 480Y/277V secondary, 45kV BIL

10 Dry

- type, medium

- voltage, three

- phase, 20

- 45kV BIL 750

– 2500 1500 kVA, 150 C, three

- phase, 60Hz, 4160V primary, 480Y/277V secondary, 45kV BIL

8 11 Dry

- type, medium

- voltage,

three

- phase, 46

- 95kV BIL 15

– 500 300 kVA, 150 C, three

- phase, 60Hz, 12470V primary, 480Y/277V secondary, 95kV BIL

12 Dry

- type, medium

- voltage, three

- phase, 46

- 95kV BIL 750

– 2500 1500 kVA, 150 C, three

- phase, 60Hz, 12470V primary, 480Y/277V secondary, 95kV BIL

10 13 Dry

- type, medium

- voltage,

three

- phase, 96

- 150kV BIL 225

– 2500 2000 kVA, 150 C, three

- phase, 60Hz, 12470V primary, 480Y/277V secondary, 125kV BIL
* EC = Equipment Class.

DOE analyzed the same representative unit for each design line as it analyzed during the previous rulemaking on distribution transformers

. These representative units were chosen because they are a high volume segment of the market for their respective design lines

, and also provide a reasonable basis for scaling to the unanalyzed kVA ranges of the design line

. Durin g preliminary interviews with manufacturers, DOE received several comments on changes that

c ould be made to the representative units.

Several manufacturers stated that the primary voltage for DL1 through DL3 should be changed

. The current ly proposed prima ry voltage is 14400V , but manufacturers recommended DOE consider 7200V, such as 12470GrdY/7200V, or even 19900V

. Manufacturers pointed out that the 7200V unit has a higher shipment volume, and is thus more representative of the market

. DOE understands that the 14400V primary is in the same insulation class as the 12470V primary, but that the 14400V primary requires more turns of conductor and may require more space and thus be a costlier unit

. As such, the 14400V primary results in a more stringent analysis

, while the 12470V and 7200V would always be able to meet the same efficiency levels as the 14400V primary

. As such, DOE proposes to leave the primary voltage for DL1 through DL3 as 14400V.2

- 19

DOE welcomes comment on the representative units selected for the single

- phase, liquid

immersed units in DL1 through DL3

. Specifically, DOE seeks comment on its decision to use a 14400V primary voltage for DL1 through DL3.

Some manufacturers also suggested that DOE change the primary voltage for the DL5 representative unit from 24940GrdY/14400V to 12470 delta

. This change was recommended because 12470 delta units have a higher shipment volume than 24940GrdY/14400V units for this DL

. While most residential distribution transformers have a grounded wye primary, most indus trial distribution transformers have a delta primary

. DOE understands that units with a delta primary require full insulation on both ends of the winding and are fundamentally more costly than a comparable unit with a wye primary

.

DOE welcomes comment on the representative unit selected for DL5 , a 1500 kVA, three

phase, liquid

- immersed transformer

. Specifically, DOE asks for comment on the appropriate primary voltage for analyzing this representative unit.

Additionally, manufacturers of MVDT distribution transformers indicated that the primary voltage for the 2000 kVA representative unit for DL13 should be changed

. DL13 represents the 125 kV BIL insulation class

. Currently, DOE has a primary voltage of 12470V for this representative unit, but manufacturers stated that a primary voltage of 24940V is correct for a 125 kV BIL unit

. The representative unit must retain a BIL rating greater than 95 kV

. This is because DOE uses this representative unit to scale results for th e MVDT equipment classes 9 and 10, which have a BIL greater than or equal to 96 kV.

DOE seeks comment on the representative unit selected for DL13 , a 2000 kVA, three

phase, MVDT transformer

. DOE specifically would like comments on the most appropriate primary voltage for analyzing this representative unit.

Last, DOE received feedback on additional representative units that should be considered in its analysis

. Manufacturers suggested many dif ferent alternatives for representative units

. One example is a dual

- secondary

- voltage, liquid

- immersed, 25 kVA, single

- phase unit

. This recommendation was made to address any efficiency discrepancies between DOE’s previous analysis and a dual

- secondary

- vol tage transformer.

DOE welcomes comment on additional representative units or design lines that should be considered in its analysis

. DOE welcomes comment on a ll aspect s of its selected representative units and design lines.

2.6.2 Scaling Methodology

DOE perform ed detailed analysis on each representative unit and then extrapolated the results of its analysis from the unit studied to the other kVA ratings within that same engineering design line

. DOE performed this extrapolation in the national impacts analysis (s ee Chapter 10 of the preliminary TSD )

. The technique it used to extrapolate the findings on the representative unit to the other kVA ratings within a design line is referred to as ―the 0.75 scaling rule.‖ This rule states that, for similarly designed trans formers, costs of construction and losses scale to the ratio of kVA ratings raised to the 0.75 power

. The relationship is valid where the optimum efficiency2

- 20

loading points of the two transformers being scaled are the same

. DOE used the same methodology to scale its findings during the previous rulemaking on distribution transformers.

During preliminary interviews , manufacturers informed DOE t hat the application of this scaling rule during the previous rulemaking made it difficult to manufacture compliant transformers for certain kVA ranges

. Specifically, DOE was told that MVDT distribution transformers at the lowest kVA values were difficult to manufacture according to the current energy conservation standard

. The analysis for these units was based on a 30 0 kVA representative unit and then scaled down to a 15 kVA unit

. Manufacturers indicated that the scaling relationship did not hold for these transformers because they typically use a different core construction from what DOE analyzed for the 300 kVA unit

. The lower kVA units typically utilize a butt

- lap construction technique because it can be difficult to miter designs for these smaller units as is done for the 300 kVA units.

DOE welcomes comment on the scaling approach used and whether an improved scali ng methodology exists

. DOE also welcomes comment on the extent of the impact that the previous scaled standard levels have had on the low kVA units for MVDT or for any other market segments.

2.6.3 Design Option Combinations

There are many different combinations of design options that could be considered for each representative unit DOE analyzes

. While DOE cannot consider all the possible combinations of design options, DOE attempts to select design option combinations that are common in the industry while also sp anning the range of possible efficiencies for a given DL

. For each design option com bination chosen, DOE evaluates 518 designs based on different A and B factor combinations

. For the engineering analysis, DOE reused many of the design option combinations
t hat were analyzed in the previous rulemaking for distribution transformers.

DOE considered a design option combination that uses an amorphous core for each of the dry

- type design lines

. DOE’s previous rulemaking did not consider amorphous designs for the dry

- type design lines

. Instead, DOE considered H

- 0 domain refined (H

- 0 DR) steel as the maximum

- technologically feasible design

. However, DOE is aware that amorphous designs are now used in dry

- type distribution transformers

. As such, DOE considered amorph ous designs for each of the dry

- type design lines in th e preliminary analysis

. DOE accounted for special cost considerations for the amorphous designs that are 1500 kVA or greater, as outlined in section 2.6.6

. During preliminary interviews with manufacturers, DOE heard that it should consider additional design option combinations using aluminum for the primary conductor rather than
copper

. While manufacturers commented that copper is still used for the primary conductor in many distribution transformers, they noted that aluminum has become relatively more common

. This is due to the relative prices of copper and aluminum

. In recent years, copper has become

more expensive relative to aluminum.

DOE also noted that certain design lines are lacking a design to bridge the efficiency values between the low est efficiency amorphous designs and the next highest efficiency designs

.2

- 21

Currently, DOE evaluates ZDMH and M2 cor e steel as the highest efficiency designs below amorphous for the liquid

- immersed design lines

. Similarly, DOE evaluates H

- 0 DR and M3 core steel as the highest efficiency designs below amorphous for dry

- type design lines.

DOE seeks comment on the design option combinations selected for analyzing each design line

. DOE would like comments on any additional design option combinations that should be considered in the analysis

. In particular, DOE welcomes comment on any design option combinations that yield ef ficiency ratings greater than the domain refined steels used in DOE’s analysis. DOE considered ZDMH for liquid

- immersed designs and H

- 0 DR for dry

- type designs.

2.6.4 Material s Prices

DOE conducted the engineering analysis using material s prices over a five

- year time period from 2006

- 2010, all in constant 2010$

. In the previous rulemaking for distribution transformers, DOE considered a five

- year average price for the reference case of the engineering analysis

. DOE then considered sensitivities of the material s pr ices by selecting prices from a year with high prices and a year with low prices.

Based on feedback from manufacturer interviews conducted over the summer of 2010, DOE decided to use current (2010) material s prices in its analysis for the reference case material s price scenario

. Manufacturers noted the difficulty in choosing a price that accurately projects future material s prices due to the recent variability in these prices

. Manufacturers also commented tha t the previous five years had seen steep increases in material s prices through 2008, after which prices declined as a result of the global economic recession

. Further detail on these factors can be found in appendix 3 A

. Due to the variability in material s prices over this five

- year timeframe, manufacturers do not believe a five

- year average price would be the best indicator , and recommended using the current material s prices

. As such, DOE used the current 2010 price as its reference case material s price sc enario

. Similar to what was done in the previous rulemaking, DOE consider ed high and low material s price sensitivities in its analysis

. The low price sensitivity wa s based on material s prices from 2006, while the high price sensitivity wa s based on materia l s prices from 2008.

DOE requests comment on its tentative decision to consider the current (2010) material s prices as the reference case material s price rather than a five

- year average price.

2.6.5 Markups
DOE derived the manufacturer’s selling price for each design in the engineering analysis by considering the full range of production costs and non

- production costs

. The full production
cost is a combination of direct labor, direct materials, and overhead

. The overhead contributing to full production cost incl udes indirect labor, indirect material, maintenance, depreciation, taxes, and insurance related to company assets

. Non

- production cost includes the cost of selling, general and administrative items (market research, advertising, sales representatives, logistics), research and development (R&D), interest payments, warranty and risk provisions, shipping, and profit factor

. Because profit factor is included in the non

- production cost, the sum of production and non

- production costs is an estimate of the man ufacturer’s selling price (MSP)

. DOE utilized2

- 22

various markups to arrive at the total cost for each component of the distribution transformer

. These markups are outlined in detail in chapter 5 of the preliminary TSD

. Figure 2.6

. 1 presents the components of the MSP.

Figure 2.6

. 1 Method of Cost Accounting for Distribution Transformers Rulemaking

2.6.5.1 Markups for Prefabricate d Amorphous Cores

For designs using an amorphous core, DOE assumed that a manufacturer would purchase a prefabricated amorphous core rather than purchasing amorphous ribbon and creating the core itself

. This is consistent with how amorphous designs were mo deled in the previous rulemaking on distribution transformers

. Since DOE assumes that the manufacturer bought a finished core, DOE reduced its markup for scrap and handling factor from 2.5 percent to 1.5 percent

. DOE also reduced components of the total la bor hours for amorphous designs to account for the prefabricated core

. These adjustments are consistent with how amorphous designs were treated in the previous rulemaking for distribution transformers.

DOE did not adjust the factory overhead markup for am orphous designs compared to the other designs

. During preliminary interviews with manufacturers, DOE received mixed feedback on whether or not a prefabricated amorphous core would result in a lower factory overhead markup compared to designs where manufact urers produced the core

. Since the factory overhead markup accounts for indirect production costs that are not easily tied to a particular design, it is applied consistently across all design types

. DOE did not find that there was sufficient substantiation to conclude that manufacturers would apply a reduced overhead markup for a design with a prefabricated core

. This approach is also consistent with the previous rulemaking for distribution transformers. Full Cost of Product

Full Production Cost

Direct Labor Direct

Material Overhead

Indirect Labor

Indirect Material

Maintenance
Depreciation

Taxes

Insurance related to assets Non

- Production Cost

Selling, General & Admin.

Mkt. research
Advertising

Point of Sale promotion

Cust. service
Sales person salary + travel + commission
Logistics R & D

Costs associated with efforts to find

new or improved products or production processes

Code Compliance

Modernization Interest

Costs of borrowing funds Warranty

& Risk Shipping

Costs of freight for final delivery Profit2

- 23

DOE welcomes comment on its tentative decision to us e the same factory overhead markup for designs using a prefabricated amorphous core as for designs where the manuf acturer produces the core.

2.6.5.2 Shipping Costs

During its preliminary interviews with manufacturers, DOE was informed that manufacturers oftentimes pay shipping (freight) costs to the customer

. Manufacturers indicated that they absorb the cost of shipping the units to the customer, and that they includ e these costs into their total cost structure when calculating profit markups

. As such, manufacturers apply a profit markup to their shipping costs just like any other cost of their production process

. Manufacturers indicated that these costs typically amo unt to anywhere from four to eight percent of revenue.

In the previous rulemaking for distribution transformers, DOE accounted for shipping
costs exclusively in th e LCC analysis

. These costs were paid by the customer, and thus did not include a markup fro m the manufacturer based on its profit factor

. In the preliminary analysis

, DOE included shipping costs in the manufacturer’s cost structure, which is then marked up by a profit factor

. These shipping costs account for shipping the units to the customer, w ho may then bear additional shipping costs to deliver the units to the final end

- use location

. As such, DOE accounts for the first leg of shipping costs in the engineering analysis and then any subsequent shipping costs in the LCC analysis

. The shipping co st is estimated to be $0.22 per pound of the transformer’s total weight, and typically amounts to four to eight percent of the total manufacturer selling price

. Additional detail on these shipping costs can be found in chapter 5 and chapter 8 of the prelim inary TSD.

DOE welcomes comment on its tentative decision to include shipping costs in the engineering analysis as a component of the manufacturer’s selling price

. Specifically, DOE seeks comment on whether profit markups are applied to the shipping cost and if shipping costs are typically four to eight percent of total revenue for the sale of all sizes and types of distribution transformers.

2.6.6 Additional Costs for Amorphous Designs in Large Kilo

- Volt Ampere , Medium

Voltage Dry

- Type Design Lines

DOE accounted for additional labor and hardware costs in the amorphous designs for dry

type design lines that are 1500 kVA or greater

. The affected design lines are DL s 10, 12, and 13

. Manufacturers and industry experts informed DOE that these large dry

- type d esign lines would require special handling considerations for an amorphous core since the amorphous material is very thin and can be difficult to work with in such a large core

. DOE increased the labor estimate for assembly, which includes all steps necess ary to complete the core/coil assembly

. DOE accounted for 6 hours of labor for all non

- amorphous designs in these design lines, but increased the labor estimate by 10 hours, to 16 hours total for the amorphous designs.

Additionally, DOE accounted for hard ware costs for the extra bracing that is necessary for dry

- type amorphous designs of this size

. The extra bracing is used to contain the coils and prevent short circuit problems that may arise. This extra bracing is necessary because the2

- 24

amorphous design uses a wound core rather than a round, cruciform core like the other designs in these design lines

. Manufacturers and industry experts estimated the weight of the bracing as 7 percent of the weight of the core and coil

. The cost of the bracing was based on the price of enclosure steel

. DOE added this additional hardware cost to each amorphous design in DLs 10, 12, and 13

. Additional detail can be found in chapter 5 of the preliminary TSD.

DOE seeks comment on the additional costs considered for amorphous d esigns in design lines 10, 12, and 13

. Additionally, DOE seeks comment on whether these additional costs should be considered for liquid

- immersed design lines that are 1500 kVA or greater, or whether the costs are specific to dry

- type designs.

2.6.7 Other Regula tory Impacts on the Engineering Analysis

In conducting an engineering analysis, DOE recognizes that regulatory changes occurring outside of the standards

- setting process can affect equipment manufacturing

. Some of these changes can also affect the efficien cy of the equipment

. DOE attempts to identify all ―outside‖ issues that can impact the engineering analysis.

2.6.8 Baseline Efficiency and Candidate Standard Levels Analyzed

DOE analyzed designs over a range of efficiency values for each representative unit

. Wit hin the efficiency range, DOE developed designs that approximate a continuous function of efficiency. However, DOE analyzes the incremental impacts of increased efficiency by comparing discrete efficiency benchmarks to a constant baseline efficiency. The b aseline efficiency evaluated for each representative unit is the existing standard level efficiency for distribution transformers established in DOE’s previous rulemaking. The incrementally higher efficiency levels, termed ―candidate standard levels‖ (CSLs ), are meant to characterize the cost

efficiency relationship above the baseline. These CSLs are ultimately used by DOE if it decides to amend the existing energy conservation standards.

For the preliminary analysis, DOE considered several criteria when s etti ng CSLs. First, DOE harmonized the efficiency values across single

- phase transformers and the per

- phase kVA equiva lent three

- phase transformers. For example, a 50 kVA single

- phase transformer would have the same efficiency as a 15 0 kVA three

- phase tran sformer. This approach is consistent with DOE’s methodology from the previous rulemaking. As such, DOE selected equivalent CSLs for several of the representative units that have equivalent per

- phase kVA ratings.

Second, DOE selected equally spaced CSLs by dividing the entire efficiency range into five to seven evenly spaced increments. The number of increments depended on the size of the efficiency range. This allowed DOE to examine impacts based on an appropriate resolution of efficiency for each representative unit.

Finally, DOE adjusted the position of some of the equally spaced CSLs and examined additional CSLs. The se minor adjustments to the equally spaced CSLs allowed DOE to consider important efficiency values based on the results of t he software design s. For example, DOE adjusted some CSLs slightly up or down in efficiency to consider the maximum efficiency potential of non

- amorphous design options. Other CSLs were added to consider important2

- 25

benchmark efficiencies, such as the NEMA Pr emium efficiency for LVDT distribution transformers. Last, DOE considered additional CSLs to characterize the maximum

technologically feasible design for representative units where the harmonized per

- phase efficiency value would have been unachievable for one of the representative units , or where symmetric core designs yielded an efficiency value greater than the highest efficiency achievable through traditional transformer designs . Additional detail on the CSLs selected for the preliminary analysis can be found in chapter 5 of the preliminary TSD.

For the NOPR, DOE will develop trial standard levels (TSLs) based on the CSL s for distribution transformers. DOE is considering several criteria in developing the TSLs, including, but not limited to, minimum LCC, maximum N PV, and maximum technologically feasible efficiency. These TSLs may include combinations of CSLs and the interaction between equipment classes. From the list of TSLs developed, DOE will select one as its proposed standard for the NOPR. DOE invite s comment on the criteria it should use as the basis for selection of TSLs.

2.7 ENERGY USE AND END

- USE LOAD CHARACTERIZ ATION

The energy use and end

- use load characterization analysis (chapter 6 of the preliminary TSD ) produced energy use estimates and end

- use load shapes for distribution transformers. The energy use estimates enabled evaluation of energy savings from the operation of distribution transformer equipment at various efficiency levels, while the end

- use load characterization allowed evaluation of th e impact on monthly and peak demand for electricity from the operation of transformers.

The energy used by distribution transformers is characterized by two types of losses. The first are no

- load losses, which are also known as core losses. No

- load losses are roughly constant and exist whenever the transformer is energized (i.e., connected to live power lines). The second are load losses, which are also known as resistance or I 2 R losses. Load losses vary with the square of the load being served by the tran sformer. Because the application of distribution transformers varies significantly by type of transformer (liquid

- immersed or dry

- type) and ownership (electric utilities own approximately 95 percent of liquid

- im mersed transformers, commercial and industria l (C&I) entities use mainly dry

- type), DOE performed two separate end

- use load analyses to evaluate distribution transformer efficiency. The analysis for liquid

immersed transformers assumes that these are owned by utilities and uses hourly load and price data to estimate the energy, peak demand

, and cost impacts of improved efficiency. For dry

- type transformers, the analysis assumes that these are owned by C&I customers, so the energy and cost savings estimates are based on monthly building

- level demand and energy consumption data and marginal electricity prices. In both cases, the energy and cost savings are estimated for individual transformers and aggregated to the national level using weights derived from either utility or C&I building data. Sections 2.7.1.1 and 2.7.1.2 provide an overview of the two methods of characterizing transformer loads.2

- 26

2.7.1.1 Overview of the Hourly Load Model

For utilities, the cost of serving the next increment of load varies as a function of the
current load on the system. To correctly estimate the cost impacts of improved transformer efficiency, it is therefore important to capture the correlation between electric system loads and operating costs

, and between individual transformer loads and s ystem loads . For this reason, DOE estimated hourly loads on individual liquid

- immersed transformers using a statistical model that simulates two relationships : ( 1) the relationship between system load and system marginal price; and ( 2) the relationship between the t ransformer load and system load. Both are estimated at a regional level.

The regions used in the hourly load model are those defined in the E nergy Information Administration’s (EIA) National Energy Modeling System (NEMS) Electricity Market Module 1 (EMM). These regions are based on existing national reliability regions and, where they exist, areas with integrated wholesale electricity markets. Eac h region is in turn composed of a number of electric utility service territories.

The relationship between system load values and system marginal prices is derived for each region from hourly data collected by the Federal Energy Regulatory Commission (FER C) Form 714 and

, where appropriate, day

- ahead market data from independent system operators. FERC data provide hourly system load and system lambda values, in which the system lambda is defined approximately as the operating cost of the generating unit on the dispatch margin. Day

ahead market data (collected for California, New England

, and Texas) include the hourly system load and the market

- clearing price. Data for 2008 were used

, as this is the most recent year for which data from all sources were avail able. An illustration of these data for the Southeastern Electric Reliability Council ( SERC ) region is given in Figure 2.7

. 1

.

DOE used a two

- step modeling approach to define the relationship between system loads and system marginal prices: The data are first sorted into bins based on the size of the system load. T hese bins are illustrated in Figure 2.7

. 1 using different colors.

1. Within each bin, the average marginal price is calculated.

2. Within each bin, the difference between the average marginal price and the actual hourly marginal price is calculated (this difference is referred to as a price

- delta), and a probability distribution for the price

- deltas is estimated. The probability distribution of the price

- deltas is modeled a s a triangular distribution.2

- 27

Figure 2.7

. 1 Load versus Marginal Price for E lectricity Market Module Region:

S outheastern E lectric R eliability C ouncil

To model the relationship between individual transformer loads and the system load, DOE used a joint probability distribution function ( J PDF). Conceptually, this function answers the question: given that the system load is at a particular level relative to its maximum, what is the probability that th e transformer load is at a given level relative to its maximum? Due to the lack of available data for individual transformer loads, DOE estimated the J PDF using hourly metered data for buildings.

DOE seeks comment on any additional sources of distributio n transformer load data that could be used to validate the analysis.

2.7.1.2 Overview of the Monthly Load Model

Dry

- type transformers are primarily installed on buildings and owned by the building owner/operator. Commercial and industrial (C&I) utility customers are typically billed monthly, with the bill based on both electricity consumption and demand. Hence, the value of improved transformer efficiency depends on both the load impacts on the customer’s electricity consumption and demand , as well as the customer ’s marginal prices.

The customer sample of dry

- type distribution transformer owners is taken from the EIA Commercial Buildings Energy Consumption Survey (CBECS) databases. 2,3 Survey data for the years 1992 and 1995 were used, as these are the only years for which monthly customer electricity consumption (kWh) and peak demand (kW) are provi ded . To account for changes in the distribution of building floor space by building type and size, the weights defined in the 1992 and 1995 building samples were rescaled to reflect the distribution in the most recent 2003 CBECS survey. CBECS covers primar ily commercial buildings, but a significant fraction of transformers are shipped to industrial building owners. To account for this in the sample, data from the 2006 Manufacturing Energy Consumption Survey (MECS) were used to estimate the2

- 28

amount of floor s pace of buildings that might use the type of transformer covered by the rulemaking. The weights assigned to the building sample were rescaled to reflect this additional floor space . Only the weights of large buildings were rescaled.

For each DL , buildings with annual peak load less than the transformer capacity specified in the design we re screened out of the sample, as these buildings would not house such transformers. The CBECS sample contains a wide variety of building sizes with widely varying annual p eak loads. The larger buildings will undoubtedly contain multiple transformers, but DOE does not currently have any quantitative information on how the number of transformers installed in a building scales with either the building floor space or the buildi ng annual peak load. Thus, to account for the effect of multiple transformers on a single building, DOE used a simple approach in which the building sample weight is multiplied by the number of floors in the building. DOE seeks comment on whether this appr oach can be improved.

The transformer load characteristics needed for C&I building owners are the energy and demand savings associated with load losses. The energy savings depend on the load loss factor (LSF), which is proportional to the average value of the squared load. To estimate the load loss factor for each building, DOE used an expression that relates LSF to the load factor LF:

LSF = α*LF + (1

- α)*LF 2

where α is a parameter with α < 0.5. The load factor LF is equal to the ratio of the average hourly load to the peak load and is available from the CBECS data. DOE estimated a probability distribution for the parameter α based on hourly building load data from the End

- use Load and Consu mer Assessment Program ( ELCAP ) survey and additional confidential data. The demand savings depend on the coincidence between the transformer load and the building peak load, which is captured in a parameter known as the responsibility factor (RF). For a bu ilding with a single transformer the coincidence would be perfect and RF would equal one. In reality, the degree of coincidence depends on the details of how transformers are installed in buildings. Mathematically, the value of RF should also be correlated with the building load factor LF. To model diversity between transformer loads and the total building load, DOE constructed a statistical model that predicts RF as a function of LF. DOE estimated the parameters of this statistical model using the same hou rly building load data as were used to model the loss factor.

2.8 MARKUPS FOR EQUIPMEN T PRICE DETERMINATIO N

Chapter 7 of the preliminary TSD describes the process DOE used to determine the installed price of distribution transformers. DOE derived this installe d price by applying markups to the manufacturer selling price that were determined in the engineering analysis (chapter 5 of the preliminary TSD ). Markups, sales tax, and installation costs are the costs associated with bringing a manufactured transformer into service as an installed piece of electrical equipment. Electric utilities typically purchase liquid

- immersed transformers from manufacturer representatives, so the sales price includes a relatively small handling markup applied to the manufacturer sel ling price. Dry

- type transformers are subject to both distributor and contractor markups. Both liquid

- immersed and dry

- type distribution transformers are subject to sales tax and installation markups.2

- 29

In the previous distribution transformer rulemaking DOE analyzed shipping costs as one of the markups used to determine installed equipment price . In this Preliminary Analysis

, the markups for shipping costs have been moved into the engineering analysis ; this is described in greater detail in section 2.6.5.2

. In the previous distribution transformers rulemaking DOE estimated the distributer markups factors for liquid

- immersed and dry

- type transformers a s 1.07 and 1.15, respectively. These factors were based on stakeholder comment s . DOE welcomes comments on these markup factors.

2.9 LIFE

- CYCLE COST AND PAYBA CK PERIOD ANALYSES

Chapter 8 of the preliminary TSD describes the LCC analysis, which calculates the discounted savings in operating costs throughout the estimated average life of the covered equipment compared to any increase in the installed cost for the equipment that is likely to result directly from the imposition of a standard. In determining economic justification, t he Energy Policy and Conservation Act (EPCA) directs DOE to consider a number of different factors, including the economic impact of potential standards on consumers. (42 U.S.C. 6295 (o)(2)(B)(i))

To consider the economic impacts of standards, DOE calcula ted changes in life

- cycle cost ( LCC ) that are likely to result from the CSL , as well as a simple payback period ( PBP )

. DOE calculated both the LCC and the PBP using a Monte Carlo framework (described in Appendix 8B), so results are represented by distributions. The effect of amended standards on individual consumers includes a change in operating expense (usually decreas ed) and a change in purchase price (usually increased). DOE analyzed the net effect by calculating the change in LCC as compared to the base case. Inputs to the LCC calculation include the installed consumer cost (purchase price −including shipping, sales t ax, and installation cost), operating expenses (energy and maintenance costs), lifetime of the equipment, and a discount rate.

Chapter 8 of the preliminary TSD also describes the PBP analysis, which calculates the amount of time needed to recover the addi tional cost that consumers pay for increased efficiency. Numerically, the simple PBP is the ratio of the increase in purchase price to the decrease in annual energy costs.

2.9.1 Electricity Price Analysis

DOE performed two electricity price analyses to determin e the appropriate marginal prices for (1) liquid

- immersed distribution transformers owned primarily by utility companies and (2) dry

- type distribution transformers owned primarily by C&I building owners. For utility companies, the appropriate marginal pri ce is the hourly system lambda or market

- clearing price discussed in section 2.7 . For building owners, the electricity prices are derived from a tariff

based analys is. The two approaches are described in more detail below.2

- 30

2.9.1.1 Hourly Marginal Electricity Price Model

For liquid

- immersed transformers, DOE based its energy price analysis on hourly system load and system lambda data collected from FERC (for regions without w holesale markets) or on hourly system load and day

- ahead market clearing price data. In both cases, these prices represent the operating cost to the utility of meeting the next increment of load at any given time. In any given hour, a utility’s marginal pr ice can be higher or lower than its average price; in general

, the hourly price can be represented as a function of the system load level, as described in section 2.7.1.1

. In addition to the hourly energy cost, there is a capacity cost saving associated with improved transformer efficiency. If the efficiency of a utility’s transformers is increased, then the utility will require less generation and transmission capacity to serve its customers’ load. The size of the capacity savings is dependent on the total reduction in load over all the transformers owned by the utility during the hour of system peak. The reduction in system

- coincident transformer peak load is determined b y the joint probability distribution function between system and transformer loads. The cost of capacity is estimated using the 2010 annual auction clearing prices for regions with functioning capacity markets and using capacity cost factors from the AEO 2 010 for the other regions.

2.9.1.2 Monthly Marginal Electricity Price Model

For C&I building owners of dry

- type transformers, DOE used marginal prices derived from a detailed analysis of utility tariffs (Coughlin et al., 2006). The tariff data and calculation tools were first developed by DOE for use in the Commercial Unitary Air Conditi oning rulemaking. 4

For each of the CBECS 1992 and 1995 records used in the building sample, DOE used the monthly energy consumption and demand data, along with tariff data, to calculate a baseline electricity bill. To obtain marginal prices, two additional calculations were done. Because the electricity bill depends on both energy consumption and demand, separate marginal prices are needed to re present the effect of varying these two quantities independently. The monthly marginal energy consumption (or demand) price is calculated simply by decrementing the energy consumption (or demand) and recalculating the bill. The tariff data were collected i n 2004. To update prices to the analysis year (2010), two other datasets were used: t he report ― Average Regulated Retail Price of Electricity ‖ (Regulatory Research Associates, 2008) was used to estimate price increases between 2004 and 2007 ; and the ― Typic al Bill and Average Price Rep orts ‖ (Edison Electric Institute , 2007

– 2010 ) was used to estimate price increases from 2007 to 2010.

2.9.2 Transformer Service Lifetime

DOE defined distribution transformer service life as the age at which the transformer retires fro m service. DOE assumed, based on ORNL

- 6847, ― Determination Analysis of Energy Conservation Standards for Distribution Transformers ‖ (Barnes, 1996), that the average life of distribution transformers is 32 years. This lifetime assumption includes a constant failure rate of 0.5 percent/year due to lightning and other random failures unrelated to transformer age and an2

- 31

additional corrosive failure rate of 0.5 percent/year starting at year 15. DOE adjusted the retirement distribution to maintain an average life of 32 years.

2.9.3 Maintenance Costs

The maintenance cost is the cost to the consumer of maintaining equipment operation. The maintenance cost is not the cost associated with the replacement or repair of components that have failed. Rather, it is associated wit h general maintenance. DOE assumed that the cost for general maintenance will not change with increased efficiency. In practice, there is little scheduled maintenance for transformers. Maintenance consists of brief annual checks for dust buildup, vermin in festation, and accident al or lightning damage.

2.9.4 Emerging Technology Scenarios

DOE will also conduct additional analysis on the potential energy savings for the following emerging technologies: symmetric core designs and core deactivation technology. These t echnologies are only feasible for a subset of the available design lines ; therefore, the analysis of symmetric core transformers will be limited to three phase transformers, represented by DL s 4, 5 and 7−13; and transformers using core deactivation technol ogy will be limited to LVDT, represented by DL s 6−8. These technologies are described in detail in c hapter 5 of the preliminary TSD

.
2.9.4.1 Symmetric Core Transformers

Symmetric core transformers use a continuously wound core with 120 degree radial symmetry, resulting in a triangularly shaped core when viewed from above. One of the cited advantages of this core design lower no

- load losses at the expense of higher manufacturing costs. Symmetric core transformers are best suited to delta

- delta or delt a

- wye conne ctions

, and would require the addition of a tertiary winding for wye

- wye connections; this is described in greater detail in chapter 5 of the preliminary TSD . DOE recognize s that most utility

- operated distribution transformers are wye

- wye connected, and wi ll analyze symmetric core transformers for C&I sectors where delta connections are common practice.

2.9.4.2 Core Deactivation Technology

Core deactivation technology employs the concept that a system of smaller transformers can replace a single, larger transformer

. The smaller transformers that compose the system can then be activated and deactivated using core deactivation technology based on the loading demand, thus reducing the overall amount of core losses tha n would be seen with a single, larger, transformer. DOE only considered core deactivation technology for LVDT in the preliminary analysis. More information on core deactivation technology can be found in chapter 5.

2.10 SHIPMENTS ANALYSIS

One of the more important components of any estimate of future impacts fro m energy efficiency standards is equipment shipments (chapter 9). DOE must obtain forecasts of shipments for the base case and each potential standards case as inputs to the National Energy2

- 32

Savings (NES) Model. For the distribution transformer rulemaking, DOE chose an accounting model method to prepare shipment scenarios for the base case and the CSLs . The model keeps track of the aging and replacement of transformer capacity

, given a projection of future transformer sales growth. New transformer capacity d emand is created by growth in electrical demand. Transformer shipments, a retirement function, and the initial number of transformers in service influence how transformers in service and supply of transformer capacity change over time.

2.10.1 Inputs to Shipments Analysis

2.10.1.1 Shipments Data

The Department used historical transformer shipments data to calibrate a forecast of future transformer shipments and in

- service stocks. DOE contractors provided an estimate of sales for the year 2009, disaggregated by equipment class and kilovolt

- ampere (kVA) rating. In addition, the analysis made use of the sales data from the previous distribution transformers rulemaking for the year 2001, 5 also disaggregated by equipment class and kVA rating. The estimated sales data show a drop in shipments in 2009 relative to 2001 for liquid

- immersed and LVDT transformers. In terms of total capacity of l iquid

- immersed shipments, the drop is about 40 percent for single

- phase units and 25 percent for three

- phase units. The Department also observed a 33 percent drop in total capacity shipments for LVDT units. There are several factors contributing to the drop observed in the shipmen ts, including declining housing starts and slow economic activity in most sectors. The Department corroborated the drop in estimated shipments of l iquid

- immersed units by reviewing the quantity indices of ―Power, distribution, and specialty transformer man ufacturing ‖

– North American Industry Classification System ( NAICS ) code 335311, and ‖ Electric power generation, transmission, and distribution ‖

- NAICS code 221100. The quantity index data are available from the U.S. Bureau of Economic Affairs (BEA). NAICS code 335311 indicates a decline of 12 percent in 2008 a compared to 2001, while NAICS code 221100 registered a decline of 44 percent in 2008 compared to the 2001 quantity index. The Department considers NAICS code 221100 to reasonably represent the trend i n infrastructural spending of the utilities on distribution infrastructure b . The Department assumed the declining trend to continue into 2009, concluding that the drop in estimated shipments is validated through other comparable indicators.

The historical series of the power distribution and specialty transformer manufacturing (NAICS code 335311) quantity index for 1977 to 2008 is available from the BEA. The BEA transformer manufacturing quantity index provides information on how the aggregate shipments

o f transformers have changed over the 1977 to 2008 period. The Department used the 2001 and 2009 shipments estimate by equipment class and kVA rating to determine the market shares for both liquid

- immersed and dry

- type distribution transformers. The Departm ent used the BEA quantity index data to estimate aggregate transformer shipments from 1977 to 2000, and from 2002

- 2008, using the sales estimates for the period from 2001 and 2009 as reference points.

a 2008 is the latest year for which quantity index data is available from BEA.
b Edison Electric Institute estimates 25 percent

– 30 percent of utilities’ infrastructural spending on distribution (Transforming America’s Power Industry: Investment Challenge 2010

- 2030. 2008)2

- 33

2.10.2 Shipments Forecast

The Department constructed a simplif ied forecast of transformer shipments for the base case scenario based on the concept that long

- term growth in transformer shipments will be driven by long

- term growth in electricity consumption. The detailed dynamics of transformer shipments is highly com plex. This complexity can be seen in the fluctuations in the total quantity of transformers manufactured as expressed by the BEA transformer quantity index. The Department examined the possibility of modeling the fluctuations in transformers shipped using a bottom

- up model where the shipments are triggered by retirements and new capacity additions, but found that there were no sufficient data to calibrate model parameters within an acceptable margin of error. Hence, the Department de

- coupled the overall shi pments and retirement in the construction of the shipments forecast and maintained the age distribution of the in

- service transformer stock using the retirement function.

The Department constructed the transformer shipments forecast assuming that transfor mer shipments growth is equal to forecasted growth in electricity consumption as given by EIA’s AEO 2010 forecast up to the year 2035. For the years from 2036 to 2045, DOE extrapolated the AEO 2010 forecast with the growth rate of electricity consumption for the period from 2025 to 2035.

Distribution transformer shipments are organized into two categories: replacements and new capacity. Replacements occur when old transformers break down, corrode, are struck by lightning, or otherwise need to be replaced . New capacity purchases occur due to increases in electricity use that may be driven by increasing population, increasing commercial and industrial activity, or growth in electricity distribution systems. The model starts with an estimate of the overall g rowth in transformer capacity and then estimates shipments for particular design lines and transformer sizes using estimates of the relative market share for different design and size categories. Chapter 9 of the preliminary TSD provides a detailed descrip tion of how DOE conducted its shipments forecasts.

DOE seeks comment on recent changes in utility distribution transformer replacement and maintenance practices. In particular, DOE would like comments on any additional sources of utility replacement rates or maintenance and repair costs that should be considered in the analysis.

2.10.2.1 Efficiency Distribution and Efficiency Trend

The key inputs for calculating energy losses in the NIA include inputs from the LCC analysis that provide average rated losses for both no

- load and load losses for each equipment class . These inputs incorporate efficiency distribution of the transformer market for the considered product, and therefore efficiency distribution is not treated separately in the NIA. The Department has conside r ed a frozen efficiency for the analysis period.

DOE seeks comment on recent changes in distribution transformer sizing practices. In particular, DOE would like comments on any additional sources of trends in market share across equipment class es for eith er liquid

- immersed or dry

- type transformers that should be considered in the analysis.2

- 34

The Department seeks further comment on its tentative decision to use frozen efficiencies for the analysis period. Specifically, DOE would like comments on additional source s of data on trends in efficiency improvement.

2.11 NATIONAL IMPACT ANAL YSIS

The NIA assesses the NPV to the Nation of total consumer LCC and NES . DOE determined both the NPV and NES for the efficiency levels considered for the equipment class es analyzed. The NES and NPV impacts are the cumulative energy and economic effects of a transformer energy conservation standard (chapter 10 of the preliminary TSD ). DOE projected the impacts from the year the standard would take effect through a selected number of y ears in the future. DOE analyzed energy savings, energy cost savings, equipment costs, and NPV of savings (or costs) for each CSL . The national energy and cost savings (or increases) that would result from energy conservation standards depend on the projec ted energy savings per transformer and the anticipated numbers of transformers sold. DOE created base case transformer shipments projections that include units at various efficiency levels. It based the projections on historical information plus forecasts of market influences, national economic growth, and electricity consumption. DOE then derived energy savings for various CSLs from the cost

- efficiency schedules.

As discussed in chapter 10 of the preliminary TSD, the NIA assesses the NPV of total national economic impacts. Analyzing impacts of Federal energy efficiency standards requires a comparison of projected U.S. energy consumption with and without amended standards. The base case, which is the projected U.S. energy consumption without amended standar ds, includes the mix of efficiencies being sold at the time the amended standard becomes effective.

DOE estimated national energy consumption for each year beginning with the expected effective date of the amended standard. It calculated national annual energy savings as the difference between two projections: a base case and a n amended standards case. The analysis included estimated energy savings by fuel type used for generating electricity. DOE estimated energy consumption and savings based on site ene rgy (kilowatt

- hours (kWh) of electricity) and then converted the electricity consumption and savings to primary energy consumption.

2.12 LIFE

- CYCLE COST SUBGROUP ANALYSIS

DOE will conduct the LCC sub

- group analysis after the preliminary analysis and report the results in the NOPR.

While DOE expects amended distribution transformer energy conservation standards to reduce overall costs to the economy and consumers, there may be groups of consumers who see some increase in cost. In the next phase of the rulemaking , DOE will consider the results from the LCC analysis to evaluate the cost impacts on consumer sub

- groups, such as other categories of transformer owners, including utilities, to see if they are differentially affected by potential amended energy conservat ion standards in a significant manner.2

- 35

The analysis of these subgroups of transformer owners depends on identifying characteristics related to transformer use or economics that sets the subgroup apart from other transformer owners. DOE will analyze the ef fects on these groups by comparing the transformer owners’ capital and operating costs with and without an amended energy conservation standard. DOE will use LCC analysis methods for consumer sub

- group analysis by modifying cost assumptions to reflect the situations of the subgroups. Factors that could result in differential impacts to subgroups include differences in energy prices and transformer loading.

DOE plans to evaluate variations in regional energy prices, variations in energy use, and variations in installation costs that might affect the NPV of a n amended standard to consumer sub

- populations. To the extent possible, DOE obtains estimates of the variability in each input quantity and considers this variability in its calculation of consumer impact s. The analysis is structured to answer questions such as: How many companies are better off with amended standards and by how much? How many companies are not better off and by how much? DOE discusses the variability in each input quantity and likely s ources of information with the interested parties.

2.12.1 Proposed Subgroups

In the 2007 final rule

, DOE evaluated the impacts of a standard on the following subgroups : municipal utilities, rural cooperatives and vault transformers 5 . DOE intends to repeat these analyses in the NOPR. The subgroups to be examined are both subsets of the entire national electric utility sample and, hence, the a nalysis will be limited to liquid

- immersed distribution transformers, represented by DL s 1

– 5. DOE did not include dry

- type distribution transformers, represented by DL s 6

– 13, in the LCC subgroup analysis since electric utilities use few, if any, dry

- type t ransformers.

2.12.1.1 Municipal Utilities

Distribution transformers purchased by municipal utilities tend to serve more diverse, urban loads than transformers that serve more rural areas. The increased load diversity increases the load factor and the transformer lo ading, thus increasing the potential savings from reduced load losses. When evaluated in the 2007 final rule

, the increased savings from reduced load losses resulted in LCC savings for the municipal utilities subgroup that are slightly higher than for the national sample 6 . The extra LCC savings vary as a function of both the design line and the standard level, because the relative importance of load losses varies with both design line and transformer efficiency.

2.12.1.2 Rural Cooperatives

Distribution transformers purchased by rural cooperatives tend to serve smaller loads than transformers that serve urban areas. The lower loading decreases the potentia l savings from reduced load losses and, thus, the benefits from efficiency improvements. When evaluated in the 2007 final rule

, the reduced savings from reduced load losses resulted in LCC savings for the rural cooperatives subgroup that are slightly less than for the national sample. 6 The diminished LCC savings vary as a function of both the design line and the standard level, becaus e the2

- 36

relative importance of load losses varies with both design line and transformer efficiency. The LCC savings for rural cooperatives are also, on average, less than for the municipal utility case per affected transformer.

2.12.1.3 Vault Transformers

Distributio n transformers at higher efficiency levels have larger volumes and higher installation costs

, due to required modifications to enlarge the vaults that house them . This can dramatically decrease the economic benefits from the highest standard levels.

DOE will be sensitive to purchase price increases that might negative ly impact identifiable population groups. Additionally, DOE will assess the likely impacts of purchase price increases on equipment sales.

2.12.2 Consumer Participation

DOE seeks to inform and invol ve consumers and consumer representatives in the process of developing amended standards. This includes notification of consumer representatives during the rulemaking process and, where appropriate, seeking direct consumer input.

2.13 PRELIMINARY MANUFACT URER I MPACT ANALYSIS

The purpose of the MIA is to identify and quantify the likely impacts of amended energy conservation standards on manufacturers. DOE will identify and discuss a wide range of quantitative and qualitative industry impacts in interviews with m anufacturers and other interested parties during the NOPR stage of the analysis

. DOE will use the manufacturer i nterviews as well as the methodology described below in its evaluation of amended standards for distribution transformers.

DOE will conduct the MIA in three phases, and will further tailor the analytical framework based on the comments it receives. In Phase I, DOE will create an industry profile to characterize the industry and identify important issues that require considerat ion. In Phase II, DOE will prepare an industry cash flow model and a detailed interview questionnaire to guide subsequent discussions with manufacturers . In Phase III, DOE will interview manufacturers and assess the impacts of amended energy conservation s tandards both quantitatively and qualitatively. DOE assesses industry and subgroup cash flow impacts and industry NPV using the Government Regulatory Impact Model (GRIM) , which considers potential investments, production costs, revenue impacts, and differe nt shipment scenarios to assess the financial impact on the industry . DOE also assesses impacts on competition, manufacturing capacity, employment, and regulatory burden based on manufacturer interview feedback and discussions.

Until recently, DOE reporte d MIA results in its standards rulemakings only in the NOPR stage of the rulemaking. However, DOE is now evaluating and reporting preliminary MIA information at this preliminary analytical stage. DOE gathered the information for the analysis during the man ufacturer interviews conducted after the engineering analysis. See chapter 12 of the preliminary TSD for more detail on the MIA.2

- 37

2.13.1 Sources of Information for the M anufacturer I mpact A nalysis

Many of the previously described analyses provide important informa tion applicable to the MIA. Such information includes manufacturing costs and prices from the engineering analysis, as well as retail price and shipment forecasts. DOE will supplement this information with company financial data and other information gathe red during interviews with manufacturers.

The interview process plays a key role in the MIA because it allows interested parties to express their views on important issues privately . DOE’s contractor has a non

- disclosure agreement in place with interviewe es to allow consideration of confidential or sensitive information in the decision

- making process. Confidential information will not be made available in the public record. To preserve confidentiality, DOE’s contractor aggregates these perspectives

across manufacturers, creating a combined opinion or estimate for DOE to use in analyzing the impacts standards will have on manufacturers. This process enables DOE to account for sensitive information shared by manufacturers during the rulemaking process.

The p rocess also includes detailed interviews with manufacturers to gain insight into the range of potential impacts of amended energy conservation standards. Typically, the interviews solicit both quantitative and qualitative information on the potential impac ts of efficiency levels on sales, direct employment, capital assets, and industry competitiveness. An interactive interview process, rather than a written response to a questionnaire, is used because it helps clarify responses and identify additional issue s. Before the interviews, DOE will circulate a draft document showing estimates of the financial parameters based on publicly available information. DOE will solicit comments on these estimates during the interviews. See chapter 12 of the preliminary TSD f

or more detail on the methodology used in the MIA.

2.13.2 Industry Cash

- Flow Analysis

The industry cash

- flow analysis relies primarily on the GRIM. DOE uses the GRIM to analyze the expected financial impacts of more stringent energy conservation standards on the industry.

The GRIM analysis uses several factors to determine annual cash flows from an amended energy conservation standard: annual expected revenues; manufacturer costs, including cost of goods sold, depreciation, research and development, selling, gene ral and administrative expenses; taxes; and conversion capital expenditures. DOE compares the results against base case projections that involve no amended energy conservation standards. The financial impact of amended energy conservation standards is the difference between the two sets of discounted annual cash flows. Other performance metrics, such as return on invested capital, also are available from the GRIM. See chapter 12 of the preliminary TSD for more information on the industry cash

- flow analysis.

2.13.3 Manufacturer Subgroup Analysis

Industry cost estimates are inadequate to assess differential impacts among subgroups of manufacturers because these subgroups may have different cost structures or regulatory2

- 38

frameworks that affect their respective business models. For example, small and niche manufacturers, or manufacturers whose cost structure differs significantly from the industry average, could experience a more negative impact. While considering impacts on an individual firm basis would be ideal, such an approach is typically impractical given the number of firms involved

. In place of this approach, DOE typically groups manufacturers exhibiting similar characteristics together to characterize the industry.

During the interview process, DOE will discuss the potential subgroups and subgroup members it has identified for the analysis. DOE will encourage manufacturers to recommend subgroups or characteristics that are appropriate for the subgroup analysis. See chapter 12 of the preliminary TSD for more deta il on the manufacturer subgroup analysis.

2.13.4 Competitive Impacts Assessment

Section 342 (6)(B)(i)(V) of EPCA directs DOE to consider any lessening of competition likely to result from imposition of standards. DOE will consider whether an amended energy

conser vation standard is likely to reduce industry competition and will ask the U.S. Attorney General to determine the impacts, if any. The assessment will be based on manufactur er cost data and other information collected from manufacturer interviews. DOE will make a determined effort to gather and report firm

- specific financial information and impacts. When assessing competitive impacts, DOE’s interviews generally focus on assessing asymmetrical cost increases, the potential increase in business risks from an increased proportion of fixed costs, and potential barriers to market entry ( e.g. , proprietary technologies). The competitive analysis may also focus on assessing any differential impacts on smaller manufacturers.

2.13.5 Cumulative Regulatory Burden

DOE recognize s and seeks to mitigate the overlapping effects on manufacturers of new or amended DOE standards and other regulatory actions affecting the same equipment. DOE will analyze and consider the impact on manufacturers of multiple, equipment

- specific regulatory actions.

2.13.6 Preliminary Results for the Manufacturer Impact Analysis

DOE conducted a series of preliminary interviews with manufacturers to discuss impacts that may result from a revised regulatory standard for distribution transformers

. In general, manufacturers and other parties identified three areas of concern: ( 1 ) core steel availability, ( 2 ) equipment conversion costs , and (3) intellectual property

. DOE requests comment on its identification of key issues and requests data and infor mation from interested parties that can assist in evaluating the potential impact of amended standards on manufacturers.

2.13.7 Core Steel Availability

Manufacturers commented that there is limited global supply for the types of core steel necessary to build high er efficiency distribution transformers

. In particular, a standard level that required the use of an M2 grade steel or better could result in supply issues due to a lack of2

- 39

qualified supply sources

. Only a handful of global steel providers are capable of s upplying M2 grade steel and only one supplier is able to produce amorphous ribbon

. As such, a sudden increase in demand for these core materials would likely result in a shortage, according to manufacturers

. The increased demand for electrical steel from g rowing economies like China and India exacerbates the tight supply market

. While the current global economic downturn has abated most supply issues, manufacturers indicated that a return of solid economic growth would only further strain the limited supply of these high quality core steels.

DOE welcomes comment on the supply of core steels used in its designs

. In particular, DOE seeks comment on the global supply of M3, M2, and amorphous core steels compared to the projected consumption based on candidate standard levels.

2.13.8 Equipment Conversion Costs

Some manufacturers commented that certain technology options considered in the analysis may require large capital investments and retooling and strand existing assets

. For example, entirely new machinery and manu facturing processes would be required to create symmetric core transformer designs

. Similarly, if manufacturers decided to create their own amorphous cores for the amorphous design types, they would need to make large investments in new machinery to handle the amorphous material

. While manufacturers could purchase prefabricated amorphous cores, a n amended standard level that necessitates an amorphous design could cause the manufacturer to pursue its own amorphous core production to develop a competitive adv antage in the marketplace

. Last, a n amended standard level requiring that mitered core construction completely replace butt

- lapped cores would require some manufacturers to purchase additional mitering machines

. Most small manufacturers do not currently ha ve mitering capabilities, so they would have to outsource core production or face large capital investments

. For each of the capital investments described, some portion of the manufacturers’ existing machinery for core production would be stranded. Addit ionally, manufacturers indicated that there are often very long lead times for obtain ing advanced machinery

. Several manufacturers commented that it would take approximately two years between the purchase request and the completed installation of new machi nery for some of these capital investments.

2.13.9 Intellectual Property

Manufacturers expressed concerns about intellectual property rights pertaining to symmetric core designs

. While the concept of a symmetric core transformer has existed for over a century, t he practical implementation of the design was not developed until relatively recently

. There are currently a small handful of companies in the world that have developed feasible symmetric core designs

. Each of these companies owns patents for the designs, which are then licensed to other manufacturers who produce their own symmetric cores

. This intellectual property would be a high hurdle for any manufacturer seeking to produce the technology on a large

- scale.2

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2.14 UTILITY IMPACT ANALY SIS

The utility impact anal ysis includes an analysis of the effects of new energy conservation standards on the electric utility industry. For this analysis, DOE adapted NEMS, which is a large, multi

- sectoral, partial

- equilibrium model of the U.S. energy sector that the EIA has deve loped throughout the past decade, primarily for preparing EIA’s Annual Energy Outlook ( AEO ). In previous rulemakings, a variant of NEMS a , was developed to better address the specific impacts of an amended energy conservation standard. NEMS, which is available in the public domain, produces a widely recognized baseline energy forecast for the United States through the year 2035. The typical NEMS outputs include forecasts of electricity sales, prices, and electric generating capacity.

DOE typically con ducts the utility impact analysis as a scenario that departs from the latest AEO reference case. In other words, the energy savings impacts from amended energy conservation standards are modeled using NEMS

- BT to generate forecasts that deviate from the AEO reference case.

2.15 EMPLOYMENT IMPACT AN ALYSIS

The imposition of standards can affect employment both directly and indirectly. Direct employment impacts are changes, produced by new standards, in the number of employees at plants that produce the covered equi pment and at the affiliated distribution and service companies. DOE evaluated direct employment impacts in the manufacturer impact analysis. Indirect employment impacts that occur because of the imposition of standards may result from customers shifting ex penditures between goods (the substitution effect) and from changes in income and overall expenditure levels (the income effect).

DOE plans to utilize Pacific Northwest National Laboratory’s impact of sector energy technologies (ImSET) model to investigat e the combined direct and indirect employment impacts. The ImSET model, which was developed for DOE’s Office of Planning, Budget, and Analysis, estimates the employment and income effects energy

- saving technologies produced in buildings, industry, and tran sportation. In comparison with simple economic multiplier approaches, ImSET allows for more complete and automated analysis of the economic impacts of energy conservation investments.

2.16 ENVIRONMENTAL ASSESS MENT

Pursuant to the National Environmental Policy Act of 1969 and the requirements of 42 U.S.C. 6295(o)(2)(B)(i)(VI) and 6316(a), DOE intends to prepare an environmental assessment of the impacts of amended energy conservation standards distribution transformers. The primary environmental effects of these standards would be reduced power plant emissions resulting from reduced consumption of electricity. DOE will assess these environmental effects by using

a currently termed NEMS

- BT, BT referring to DOE’s Building Technologies Program2

- 41

NEMS

- BT to provide key inputs to its analysis. The portion of the environmental assessment that will b e produced by NEMS

- BT considers carbon dioxide (CO 2 ), nitrogen oxides ( NO x ), and mercury (Hg). The environmental assessment also considers impacts on SO 2 emissions and discusses particulate matter (PM) emissions. After a brief discussion of general methodo logy, this section will address each of the relevant emissions. The following section, Section 2.16.1, explains how DOE plans to monetize the benefits associated with emissions reductions.

2.16.1 Carbon Dioxide

In the absence of any Federal emissions control regu lation of power plant emissions of CO 2 , a DOE standard is likely to result in reductions of these emissions. The CO 2 emission reductions likely to result from a standard will be estimated using NEMS

- BT and national energy savings estimates drawn from the N IA spreadsheet model. The net benefit of the standard is the difference between emissions estimated by NEMS

- BT at each standard level considered and the AEO Reference Case. NEMS

- BT tracks CO 2 emissions using a detailed module that provides results with bro ad coverage of all sectors and inclusion of interactive effects.

2.16.2 Sulfur Dioxide

SO 2 emissions from affected electric generating units (EGUs) are subject to nationwide and regional emissions cap and trading programs, and DOE has preliminarily determined tha t these programs create uncertainty about the potential standards’ impact on SO 2 emissions. Title IV of the Clean Air Act sets an annual emissions cap on SO 2 for affected EGUs in the 48 contiguous states and the District of Columbia (D.C.). SO 2 emissions f rom 28 eastern states and D.C. are also limited under the Clean Air Interstate Rule (CAIR, 70 Fed. Reg. 25162 (May 12, 2005)), which created an allowance

- based trading program. Although CAIR has been remanded to EPA by the U.S. Court of Appeals for the Dis trict of Columbia Circuit (D.C. Circuit), see North Carolina v. EPA , 550 F.3d 1176 (D.C. Cir. 2008), it remains in effect temporarily, consistent with the D.C. Circuit’s earlier opinion in North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008). On July 6, 2 010, EPA issued the Transport Rule proposal, a replacement for CAIR, which would limit emissions from EGUs in 32 states, potentially through the interstate trading of allowances, among other options. 75 FR 45210 (Aug. 2, 2010).

The attainment of emission s caps is typically flexible among EGUs and is enforced through the use of emissions allowances and tradable permits. Under existing EPA regulations, and under the Transport Rule if it is finalized, any excess SO 2 emissions allowances resulting from the lo wer electricity demand caused by the imposition of an efficiency standard could be used to permit offsetting increases in SO 2 emissions by any regulated EGU. However, if the standard resulted in a permanent increase in the quantity of unused emissions allo wances, there would be an overall reduction in SO 2 emissions from the standards. While there remains some uncertainty about the ultimate effects of efficiency standards on SO 2 emissions covered by the existing cap and trade system, the NEMS

- BT modeling sys tem that DOE uses to forecast emissions reductions currently indicates that no physical reductions in power sector emissions would occur for SO 2
.2

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2.16.3 Nitrogen Oxides

A cap on NO x emissions, affecting electric generating units in the CAIR region, would mean that the standards for distribution transformers may have little or no physical effect on NO x emissions in the 28 eastern states and the D.C. covered by CAIR or any states cover ed by the proposed Transport Rule if the Transport Rule if finalized. The standards would, however, reduce NO x emissions in those 22 states not affected by the CAIR. As a result, DOE plans to use NEMS

- BT to estimate the emissions reductions from possible s tandards in the states where emissions are not capped.

2.16.4 Mercury

Similar to emissions of SO 2 and NO x , future emissions of Hg would have been subject to emissions caps. In May 2005, E PA issued the Clean Air Mercury Rule (CAMR). 70 FR 28606 (May 18, 2005). CA MR would have permanently capped emissions of mercury for new and existing coal

- fired power plants in all states by 2010. However, on February 8, 2008, the D.C. Circuit issued a decision in New Jersey v. Environmental Protection Agency , in which it vacated CAMR. 517 F.3d 574 (D.C. Cir. 2008). EPA has decided to develop emissions standards for power plants under the Clean Air Act (Section 112), consistent with the D.C. Circuit’s opinion on CAMR. See http://www.epa.gov/air/mercuryrule/pdfs/certpetition_withdrawal.pdf . Pending EPA's forthcoming revisions to the rule, DOE is excluding CAMR from its environmental assessment. In the absence of CAMR, a DOE standard would likely reduce Hg emissions and DOE plans to use NEMS

- BT to estimate these emission reductions. However, DOE continues to review the impact of rules that reduce energy consumption on Hg emissions, and may revise its assessment of Hg emission reductions in future rulemak ings.

2.16.5 Particulate Matter

DOE acknowledges that particulate matter (PM) exposure can impact human health. Power plant emissions can have either direct or indirect impacts on PM. A portion of the pollutants emitted by a power plant are in the form of particu lates as they leave the smoke stack. These are direct, or primary, PM emissions. However, the great majority of PM emissions associated with power plants are in the form of secondary sulfates, which are produced at a significant distance from power plants by complex atmospheric chemical reactions that often involve the gaseous (non

- particulate) emissions of power plants, mainly SO 2 and NO x . The quantity of the secondary sulfates produced is determined by a very complex set of factors including the atmospher ic quantities of SO 2 and NO x , and other atmospheric constituents and conditions. Because these highly complex chemical reactions produce PM comprised of different constituents from different sources, EPA does not distinguish direct PM emissions from power plants from the secondary sulfate particulates in its ambient air quality requirements, PM monitoring of ambient air quality, or PM emissions inventories. For these reasons, it is not currently possible to determine how the amended standard impacts either direct or indirect PM emissions. Therefore, DOE is not planning to assess the impact of these standards on PM emissions. Further, as described previously, it is uncertain whether efficiency standards will result in a net decrease in power plant emissions of SO 2 , which are now largely regulated by cap and trade systems.2

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DOE seeks input on its plans to use NEMS

- BT to conduct the environmental assessment for the equipment covered by this rulemaking.

2.17 MONETIZATION OF EMIS SIONS REDUCTION BENE FITS

DOE plan s to consider the estimated monetary benefits likely to result from the reduced emissions of CO 2 and other pollutants that are expected to result from each of the standard levels considered.

In order to estimate the monetary value of benefits resulting from reduced emissions of CO 2 , DOE plans to use the most current Social Cost of Carbon (SCC) values developed and/or agreed to by an interagency process. The SCC is intended to be a monetary measure of the incremental damage resulting from greenhouse gas ( GHG) emissions, including, but not limited to, net agricultural productivity loss, human health effects, property damage from sea level rise, and changes in ecosystem services. Any effort to quantify and to monetize the harms associated with climate change will raise serious questions of science, economics, and ethics. But with full regard for the limits of both quantification and monetization, the SCC can be used to provide estimates of the social benefits of reductions in GHG emissions.

At the time of this notice, the most recent interagency estimates of the potential global benefits resulting from reduced CO 2 emissions in 2010, expressed in 2009$, were $4.9, $22.1, $36.3, and $67.1 per metric ton avoided. For emission reductions that occur in later ye ars, these values grow in real terms over time. Additionally, the interagency group determined that a range of values from 7 percent to 23 percent should be used to adjust the global SCC to calculate domestic effects, although DOE will give preference to c onsideration of the global benefits of reducing CO 2 emissions. To calculate a present value of the stream of monetary values, DOE will discount the values in each of the four cases using the discount rates that had been used to obtain the SCC values in eac h case.

DOE recognizes that scientific and economic knowledge continues to evolve rapidly as to the contribution of CO 2 and other GHG to changes in the future global climate and the potential resulting damages to the world economy. Thus, these values are subject to change.

DOE also intends to estimate the potential monetary benefit of reduced NO X emissions resulting from the standard levels it considers. For NO x emissions, available estimates suggest a very wide range of monetary values for NO X emissio ns, ranging from $447 to $4,591 per ton in 2009$). a In accordance with U.S. Office of Management and Budget (OMB) guidance, DOE will conduct two calculations of the monetary benefits derived using each of the economic values used for NO x , one using a real discount rate of 3 percent and another using a real discount rate of 7 percent. b

a F or additional information , refer to U.S. Office of Management and Budget , Office of Information and Regulatory Affairs, 2006 Report to Congress on the Costs and Benefits of Federal Regulations and Unfunded Mandates on State, Local, and Tribal Entities , Washington, DC

. b OMB, Circular A

- 4: Regulatory Analysis ( Sept. 17, 2003).2

- 44

DOE does not plan to monetize estimates of Hg in this rulemaking. DOE is aware of multiple agency efforts to determine the appropriate range of values used in evaluating the potential economic benefits of reduced Hg emissions. DOE has decided to await further guidance regarding consistent valuation and reporting of Hg emissions before it once again monetizes Hg in its rulemakings.

2.18 REGULATORY IMPACT AN ALYSIS

In the NOPR stage, DOE will prepare a regulatory impact analysis (RIA) pursuant to Executive Order 12866, ― Regulatory Planning and Review, ‖ 58 FR 51735 ( October 4, 1993 )

, which is subject to review under the Executive Order by the Office of Information and Regulatory Affairs at the Office of Management and Budget. The RIA addresses the potential for

non

- regulatory approaches to supplant or augment energy conservation standards in order to improve the energy efficiency or reduce the energy consumption of the equipment covered under this rulemaking.

DOE recognizes that voluntary or other non

- regulatory efforts by manufacturers, utilities, and other interested parties can substantially affect energy efficiency or reduce energy consumption. DOE tentatively plans to base its asses sment on the actual impacts of any such initiatives to date, but also will also consider, to the extent possible, information presented by interested parties regarding the impacts existing initiatives might have in the future ( see c hapter 17 of the preliminary TSD )

.2

- 45 REFERENCES

1. Energy Information Administration

- Office of Integrated Analysis and Forecasting The National Energy Modeling System . (U.S. Department of Energy: Washington DC, 2009).at <http://www.eia.doe.gov/oiaf /aeo/overview/>

2. U.S. Department of Energy

- Energy Information Administration 1992 Commercial Buildings Energy Consumption Survey (CBECS). (1992).at <http://www.eia.doe.gov/emeu/cbecs/92microdat.html>

3. U.S. Department of Energy

- Energy Information Admin istration 1995 Commercial Building Energy Consumption and Expenditures (CBECS). (1995).at <http://www.eia.gov/emeu/cbecs/microdat.html>

4. U.S. Department of Energy

– Office of Energy Efficiency and Renewable Energy Appendix 8E. Technical Aspects of The T ariff

- Based Approach For Room Air Conditioner Energy Price. Residential Clothes Dryers and Room Air Conditioners Preliminary Technical Support Document (2010).at <http://www1.eere.energy.gov/buildings/appliance_standards/residential/pdfs/clothesdryers_ts d /clothesdryers_roomac_preanalysis_app8e.pdf>

5. Office of Energy Efficiency and Renewable Energy Energy Conservation Program for Commercial and Industrial Equipment: Energy Conservation Standards for Distribution Transformers; Final Rule

. 10 CFR Part 431 (2007).

6. U.S. Department of Energy

- Office of Building Technologies Chapter 11. Life

- Cycle Cost Subgroup Analysis. Distribution Transformers Energy Conservation Standard Technical Support Document (2007).