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# RIDGE Nac,TIONAL BORATORY Determination Analysis of Energy Conservation Standards for istriutin Transformers

P. R. Barnes J. W. Van Dyke B. W. McConnell S. Das

MANAGED AND OPERATED BY LOCKHEED MARTIN ENERGY RESEARCH CORPORATION FOR THE UNITED STATES DEPARTMENT OF ENERGY
ORNL- 27 (3.98)

### ORNLEne rgy Di v i s ion



### DETERMINATION ANAL YSIS OF ENERGY CONSERVATION STANDA RD S FOR D ON TRANSFORMERS .

P. R. Barnes J. W. Van Dyke B. W. McConnell 

### S. Das

Published: July 1996



### Prepared for the Office of Building Technology U.S. DEPARTMENT OF ENERGY Budget Activity No. EC1401000 Prepared by OAK RIDGE NATIONAL LABORATORY

P.O. Box 2008 Oak Ridge , TN 37831 Managed by 

### LOCKHEED MARTIN ENERGY RESEARCH CORPORATION for the U.S. DEPARTMENT OF ENERGY under contract DE-AC0S-960R22464

### CO

LIST OF FIG URES

....... LIST OF TABLES ............. ABBREVIATIONS, ACRONYMS, AND IN] ISMS .................. Page

v vii

ACKNOWLEDGMENTS ................................... xi 

### FOREWORD ........................
.ABSTRACT .......................... 

### ECECUTIVE SUMMARY .............. Xiii

xv

1. INTRODUCTION ............... ...... 1-1 1.1 BACKGROUND ........ ..... ..... ..1-1 1.2 MARKETTRENDS ................., . , ,. 1-2 1.3 STUDY APPROACH ......................... ... 1-3 1.4 SCOPE AND CONTENT ..........................:.... 1-4 REFE RENCES ................... ...... ... ...:4.. - . 1-5 

### CHA RACTERIZATION OF DISTRIBUTION TRANSFORMERS S AND THEIR LOSSES ......... . . ...... ;.., ,.,.. , , .., ., ,., ,; ._, ..v.. 2-1 2.1 OVERVIEW ..................... ............... 2-1 2.1.1 Principles of Transformer Operation ...................... 2-2 2.1.2 Major Transformer Loss Mechanisms: No-Load and Load Losses .. .... 2-3 2.1.3 Characteristics of Liquid- and Dry-Type Transformers 2-6 2.2 TRANSFORMER EVALUATIOI AND`LOSS REDACTION METHODS 2-9 2.3 TRANSFORMER LOADING PRACTICES ...... ..... 2-10 REFERENCES . ....................................... 2-12 NOTES ........................................... 2-12 3. DISTRIBUTION TRANSFORMER MARKET .... ........... 3-1 3.1 MARKET TRENDS AN]) FORECASTS ......... .................. 3-1 3.2 CATEGORIZATION BY SIZE ............................ 3-3 3.2.1 Distribution Transformers in the 10-kVA to 2.5-MVA Range ......... 3-4 3.2.2 Distribution Transformers <10 kVA ...................... 3-5 3.3 MARKET STRUCTURE .. ............... ........... 3-5 3.4 PURCHASING PRACTICES ............................. 3-7 3.4.1 F irst Cost ....................... ........... . 3-7 3.4.2 Total Life-Cycle Owning Cost .......................... 3-8 3.4.3 Band of Equivalence .............................. 3-9 3.4.4 Oversizing ..... ............ ........ ........ 3-9 3.4.5 Choice of Winding Material (Aluminum vs Copper) ............. 3-9REFERENCES ............... 3-10 NOTES .................. 3-11 4. ENERGY CONSERVATION ALTERNATIVES . ........ ...... .... . 4-1 4.1 OVERVIEW ............ . ....................... 4-1 4.2 M[INEWUM TOTAL OWNING COST TRANSFORMER DESIGN CRITERION ..................................... 4-1 4.3 COST-EFFECTIVE TRANSFORMER DESIGNS ................. 4-2 4.4 FORMULATING ESTIMATES OF ENERGY SAVINGS ............. 4-3 4.4.1 Base Case .. 4-3 4.4.2 Conservation Cases ............................. 4-3 4.4.3 Calculating Savings .............................. 4-6 4.5 ES TIMATED SAVINGS ............................... 4-9 4.6 EGY SAVINGS AND ECONOMIC ATTRACTIVENESS .......... 4-15 REFERENCES ...................................... 4-16 NOTE ........................................... 4-16
IMPACTS ON MANUFACTURERS AND USERS ................... 5-1 5.1 MANUFACTURER S ................................. 5-1 5.1.1 The Silicon-Core Ma ter i al Mar ket .............. ... ... 5-1 5.1.2 The Amorphous -Core material market .................... 5-2 5.1.3 The Coppe r and Aluminum Industries .................... 5-2 5.1.4 Distribution Transfo rme r blanufacturers ................... 5-3 

### 5.2 USERS ........................................ 5-4 REFERENCES ...................................... 5-6 6. CONCLUSIONS ...................................... 6-i 6.1 ENER GY SAVINGS AND COST S

............... 6-1 6.2 STAKEHOLDER IMPACTS ........................ 6-1 6.3 ECONOMIC JUS TIFICATION AND FEASIBILITY ............... 6-2 Appendix A: DIS TRIB UTION TRAN SFORMER REVIEW GROUP ........... A-1 Appendix B : ASS ONS FOR THE A AND B FACTORS .............. B-i Appendix C: SURVEY FORMS ................................ C-i Appendix D: APPROACH FOR ESTIMATING CONSERVATION



### CASE SAVINGS ................................. D-1

1v

### T OFF'IG

Figure Page I Distribution transformer efficiencies over the yfor 75-kVA, three-phase units ............... ...... ..... ..... ..... xviii 2 Cumulative primary energy savings from 2000 to 2030 for a conservation case based on an average of the three lowest total-owning-cost designs ........... xxi 1.1 Efficiency improved with time for a 25-kVA liquid filled distribution transformer ................................. 1-2 1.2 Distribution tran sforme r efficiencies over the years for 75-kVA, thre e-phase units ........... ..... ............. 1-3 2.1 Major internal elements of a transformer ........................ -2-2 2.2 Typ ical initial magnetization curve and typical hysteresis curve for ferromagnetic material .............. .................... 2-5 2.3 Surface of cost vs losses for a typical 25-kVA distribution transformer ........ 2-7 2.4 Typ ical transformer efficiency vs per unit load relative to nameplate rating ...... 2-7 2.5 Typical total losses as functions of load, indicating trade

- off of relative load and no-load losses .... 2-8 3.1 Annual shipments of distribution transformers by megavolt-ampere (10 A2 .5 Ai), 1980-2030 .. 3-2 3.2 Annual shipments of distribution transformers by number of units (10 WA -2.5 MVA), 1980

-2030 ............................ 3-3 3.3 Market delivery channels for distribution transformers

................. 3-6 4.1 Estimated normalized annual savings for liquid

- type transformers by size and type for alternative conservation cases ...... .................... 4-10 4.2 Estimated normalized annual savings for dry-type transformers by size and type for alternative conservation cases . ........................ 4-11 4.3 Relative contribution to energy savings by type and size (in kilovolt-amperes) of transformer for the lowest total

- owning-cost conservation case ........... 4-12 4.4 Projected sales of distribution transformers ....................... 4-13

v4.5 Cumulative quads ( 1015 Btu) of primary energy savings from 2 000 to 2030 for alternative conservation cases ....................... 4-14 4.6 Sensitivity of cumulative energy savings for reducing the annual growth rate of dry-type sales to 1.0% for the average losses case and the 2-year payback case ................................... 4-14 4.7 Sensitivity of savings to the $0.75/W load loss evaluation and 0.2 effective capacity factor . .......... ...... .. ........... 4-15 4.8 Megawatts of generating capacity needed to produce the equivalent 

### annual energy saved for the first year of the alternative conservation policies ....................................... 4-16 5.1 Change in maximum efficiency as a function of initial cost diff erence 

### for a 25-kVA, pole- type , liquid -filled transformer ................... 5-5 5.2 Chan

ge in payback period as functions of initial cost difference and 

### energy cost for a 25-kVA, pole-type, liquid-filled transformer ............ 5-5

### LIST OF TA B LES

Table I Ch teristics of distribution transformers typically used in the United States

. . . . Page xviii
2 Energy savings for a conservation case based on an average of the

2.1 three lowest total

- owning

- cost designs .......................... Characteristics of distribution transformers typically used in the United States . . xxi 2-1
2.2 Loss reduction alternatives
................... ........... 2-10
3.1 Annual shipments of distribution transformers 

### (10 kVA-2.5 A), 1980-2030 ............................ 3-4
4.1 Description of alternative cases
............................. 4-3 4.2 Base case transformer loss assumptions
......................... 4-4
4.3 Minimum efficiency for liquid

-type transformers based on 2-year payback compared with efficiencies of recently purchased trans formers .
........... 4-5
4.4 Calculation of the first-year savings for dry-type transformers in 2000 for the average losses conservation case
.................... 4-7 4.5 Calculation of the first year savings for liquid-type transformers in 2000 for the average losses conservation case
.................... 4-8 

### 4.6 Rate of annual energy savings for the surveyed transformers
.............. 4-10
4.7 Estimated savings for alternative cases .
. ..................... 4-13 D.1 Basis for assumed fraction of distribution transformers
.............. . D.2 Example of how the energy savings adjustment factor was calculated for transformers that exceed conservation case efficiency
................. D-6 D.3 Proportion of annual sales used to weight the rate of energy savings for 

### each type of surveyed transformer and basis for allocation assumptions ........ D-8 D.4 Total losses for alternative designs calculated for 10- to 500-kVA, single

- phase, liquid-type transformers

.......................... D-8

viiD.5 Calculation of the weighted rate of reduction in losses for single-phase, liquid-type transformers ............. D-9 D.6 Approximation of the weighted rate of energy savings for single-phase, liquid- type tran sfo

rme rs using 2 of 11 sizes ...................... D-9

### ABBREVIATIONS, ACRO

A ac APPA BOE C&I CDA CSA DOE DSM EEI EPA . EPAC'I' EPRI GE PR kV kVA kWh lb mil A O&M OEM ORNL PCB T&D TOC V Vac 

## w ampere alternating current American Public Power Association band of equivalence commercial and industrial Copper Development Association cross-sectional area U.S. Department of Energy demand-side management Edison Electric Institute U.S. Environmental Protection Agency Energy Policy Act of 1992 Electric Power Research Institute General Electric Company resistive heating (current squared times resistance) kilovolt kilovolt-ampere kilowatt-hour pound 0.001 in. (2.54 x 10-5 in) megavolt-ampere Electric Manufacturers Association operation and maintenance original equipment manufacturer Oak Ridge National Laboratory polychlorinated biphenyl transmission and distribution total owning cost volt volt, alternating current watt

ix

### AC KN OWLED GM ENT'S
The authors thank Bob Brewer, Terry Logee , Larry Mansueti , Phil Overholt, Susan Rogers, and Ingrid Watson of the U.S. Department of Energy ; Jim VanCoevering of Oak Ridge National Laboratory ; John Gauthier and Kyle Pitsor of the National Electrical Manufacture rs Association; Ken Hall and Matt Mingoia of the Edison Electric Institute; Martin Gorden of the National Rural Electric Cooperative Association ; and Kurt Conger of the American Public Power Association for their support and guidance

. In addition , we thank Richard Almashy, Chuck Hastings, Phil Hopkinson , Wes Schwartz, and Lyman Tschanz of the Square D Company ; Greg Coulter , Donald Duckett , Jim Powers , and Walt Ros of the General Electric "Company; Stan' Linsenbardt,' 'om Lopp, Wesley P atte rson , and Dorman Wh itley of Asea Brown Boveri , Inc.; Don Klin e, a consultant for Southern Transformer ; Carl Bush , Timothy Holdway, and Robert Smith of Federal Pacific Transformer Company; Gerald Hodge of Howard Industries; Alan Wilks of ERM CO; Ed Smith of Cen tral Moloney , Inc.; and Merl Austin and David Rolling of Cooper Industry for their assistance in providing technical data on distribution transformers. The authors convey a special th anks to the organizations, task force committees , associations, and individuals that served on the ORNL Distribution Transformer Review Group (see Appendix A for the list of members). The many comments and helpful suggestions provided by the review group are gratefully acknowledged.

xi

### FO REWORD

Subtitle C , Sect

. 124 of the Energy Policy Act of 1992 (Pub. L

. 102-486, Oct. 24, 1992) contains an amendment to Sect

. 346 of the Energy Policy and Conservation Act (42 U. S.C. Sect

. 6317). A portion of that amendment is provided below:

Sec. 346 (a) (1) The Secretary shall , within 30 months after the date of the enactment of the Energy Policy Act of 1992, prescribe testing requirementsfor those high-intensity discharge lamp s and distribution transformers for which the Secretary makes a determination that energy conservation standards would be technologically feasible and economically just ified, and would result in significant energy savings. (2) The Secretary shall, within 18 months after the date on which testing requirements are prescribed by the Secretary pursuant to paragraph (1), prescribe, by rule, energy conservation sstandards for those high-intensity discharge lamps and distribution transformers for which the'Secretary prescribed testing requir ements und er paragraph (1). This report contains information to assist the U.S

. Department of Energy in making a determination on the feasibility and significance of energy conservation for distribution trans forme rs as requ ired by par. (a)(1) above

. The potential energy savings presented in this document are preliminary estimates appropriate for a dete rminati on study. Subsequent studies on this topic will involve more exact , detailed analysis on the effects of energy conservation standards for distribution tran sformers.

xiil

### ABSTRACT
The report contains information for the U.S. Department of Energy to use in making a determination on proposing energy conservation standards for distribution transformers as aired by the Energy Policy Act of 1992. The potential for saving energy with more efficient liquid-immersed and dry-type distribution transformers could be significant because these transformers account for an estimated 140 billion kWh of the annual energy lost in the delivery of electricity. The objective of this study was to determine whether energy conservation standards for distribution transformers would have the potential for significant energy savings, be technically feasible, and be economically justified from a national perspective. It was found that energy conservation for distribution transformers would be technically and economically feasible. Based on the energy conservation options analyzed, 3.6-13.7 quads of energy could be saved from 2000 to 2030.

xv

### E SUI..__ _,.,

Subtitle C, Sect. 124 of the Energy Policy Act of 1992, Pub. L. 102-486, Oct. 24, 1992, contains an amendment to Sect .'346 of the Energy Policy and Conservation Act (42 U.S.C. Sect. 6317) requirin g that the U.S. Department of Energy (DOE) assess the feasibility of energy conservation standards for distribution transformers

. The objective of this study was to determine whether energy conservation standards for distribution transformers would have the potential for significant energy savings , be technically feasible, and be economically justified from a national perspective. Distribution transformers are used to deliver electric power as part of the electrical distribution system

. Electrical energy is delivered to consumers by utility power transmission and distribution systems. The transmission network delivers power at high voltages (69-765 kV) from power plants to local distribution systems

. Transmission voltages are used to transmit high levels of power over long distances

. The high-transmission voltages require lower currents, which reduce line losses , conductor mate rial, and costs

. Once the electrical power has reached the distribution system , it is transformed to lower primary distribution voltages (ranging from 4 to 35 kV) that are more economical for the short distances within distribution systems. The primary distribution voltage is transformed by distribution transformers to lower secondary voltages (12 Vac) that are suitable for customer equipment

. These transformers provide the final link in the c hain of electrical power components from the generating sources to the ultimate power= con" ... ` g equipmnent. Distribution formers are very reliable devices with no moving parts and average lives of -30 years

. There are two basic types : liquid

- immersed and dry-type. Liquid-immersed transformers typically use oil as a combination coolant and dielectric medium ; they are normally used outdoors because of concerns about an oil spill or possible fire hazard

. Electric utilities own about of all liquid-immersed transformers

. Dry-type transformers are air

- cooled, fire-resistant , non-oil devices and thus do not need special oil-spill containment

. Recent advances in liquid materials offset these traditional " advantages " for dry units . Many commercial and industrial (C&I) customers use secondary distribution dry-type transformers within buildings to transform the building or plant voltage (typically 480 Vac) to a lower secondary voltage (120-240 Vac ): Large load center dry-type transformers are also used to transform the primary distribution voltage to the plant or building voltage

. There are -40 million liquid

- immersed distribution transformers owned by electric utilities and an additional 4 million non

- utility-owned liquid-immersed units in the United States ( Barnes etil

. 1995 ). Transformer manufacturers estimate that -12 million dry-type distribution transformers are used by C&I customers in the United States

. The definition for distrib ution transformers as considered in this study can be summarized as transformers that are continually energized ; these fall within the voltage classes and capacities shown in Table 1

. Utility- owned distribution transformer efficiencies steadily improved from the 1950s to the 1970s with the introduction of improved materials and manufacturing methods

. Following the energy price shocks of the 1970s some utilities began to use purchasing formulae that factored the effect of transformer efficiency into the purchasing decision

. Manufacturers responded by tailoring their products to the energy evaluation factors specified by customers , a practice that continues to this day. Thus, it is now possible to purchase a relatively high

- cost , high

- efficiency tran sformer or a unit with a lower first cost and lesser efficiency . Most of the nonutility distribution transformers are purchased on the lowest first

- cost basis without evaluating the cost of the energy cons umed by the units. These " nonevaluated " transformers may have -50% more losses than utility tran sformers ., The imam efficiencies of liquid -immersed distribution

xviiTable 1. Characteristics of di str ibution tr . o . _ typ i call y used in the U ni ted Sta tes

Transformer Phase Primary voltage Secondary voltage Capacities type (kV) (V) (kVA) Liquid-immersed 1 35 and below 600 an d below 10-833 Liquid-immersed 3 35.and

_b Blow 600 and below 15-2500 Dry-type 1 35 and below 600 and below 15-833 Dry-type 3 35 and below 600 and below 15-2500 Dry-type I and 3 35 and below 600 and below 025-<15 `£he smaller dry-type units are included for compl eteness, but they are a small contributor to the overall energy losses and are not likely to be included in an energy efficiency standard. The units below 9 kVA normally have primary voltages below 600 V.

tran sformers have improved over the past several decades, but nonevaluated dry- type units have decreased in efficiency because of the lack of economic incentives. Figure 1 shows efficiencies for 75-kVA, liquid and dry-type, three-phase transformers. Distribution transformers used by utilities account for -61 billion kWh of the annual energy lost in the delivery of electricity (Barnes et al. 1995 ). Nonutility liquid and dry-type transf ormers, although fewer in number , are less efficient and are es timated to consume an additional 80 billion kWh of electric energy on the custo me r side of the el ectric meter. New tran sformers purch ased annually can be ex pec ted to consume

- 4.6 billion k ; thus, the potential for saving energy with mo re efficient tran sformers could si gnificant (i.e., -0.9 billion kWh with a 20% reduction in losses). This report demonstrates the potential for distribution transformers to achieve cost-effective national energy savings . A number of energy c onservation options were anal yzed , the results of 

### ..txNN-vain

1985 1 1975 1 9

YEM Fig. 1. Distri bution trans forme r efflcien cks over years for 75 -kVA, dn*e-phase units. Sources: Barnes, P. R., et al . 1995. The Feasibility of Replacing or Upgrading Utility Distribution During Routine Maintenance, ORNL- 1. Martin Marietta Energy Systems , Oak Ridge Natl. Lab

. Also, transformer manufacturers' data

xviiiwhich provide DOE With information for ''making a determination on proposing a nationalenergy conservation policy for distribution transformers. Other countries are also considering energy conservation ' for distribution transformers. For example, Canada recently developed a national conservation policy based on maximum loss values for distribution, power, and dry-type transformers (Canadian Standards Association 1994). 

## t.. TC... .... ,_ Y
Without regard to cost, it is technically feasible to design and to build distribution transformers of all types that provide significant energy savings compared with the typical units purchased in 1994. If energy-saving designs are restricted to those that are economically feasible using national average energy costs, there is a potential for moderate savings per transformer from liquid-immersed units and for more significant savings per transformer from redesigned dry-type units. Because utilities routinely evaluate transformers for minimum total owning cost (TOC), the technical ability to provide low-loss liquid-immersed transformers is well established. In contrast, dry-type transformers are routinely sold on a first-cost basis and have significant potential for improved savings. The technology used to provide low-loss transformers is based upon changing the configuration and, hence, the relative amounts of materials the ease of lower-loss materials. and For example,' operating at a lower flux density by reducing volts per tum will reduce core losses but require more turns of the conductor and increase load losses. Similarly, lowering the conductor current density will reduce load losses but require more core material or a higher flux level, which produces higher no-load losses. l estnctrons on werg rt and'vc lume tray reduce the selection further; A low-loss'transformer requires the use of low-loss materials (i.e., high-silicon steel or amorphous metal for the core and increased amounts of copper or aluminum for the windings) configured in an optimal manner. The materials selected and the configuration define the cost of the transformer materials and the lalior requiredto assemble the system (i.e:, the transformer cost). Dry-type transformer technology can'provide transformers that offer lower losses at reasonable costs, but costs are higher for a given efficiency than for liquid-immersed transformers

. Because air is the basic cooling and insulating system for'dry-type ' transformers, all dry-type transformers will belarger than liquid-inunersed (units for the same voltage and capacity (kilovolt/kilovolt-ampere) rating. When operating at the same flux and current density, more material for core and coil implies higher' losses andhigher costs . Thesetrade offs are inherent in the design of dry-type units, but dry-type transformers have traditionally offered certain fire-resistant, environmental, and application advantages for industrial and commercial situations. Recent advances in liquid-filled units are reducing some of these advantages, but dry units will continue to be used in lbw-voltage, high-temperature-rise applications. 

### TH E DIS TRIB UTION _ . _ FF. The total value of product shipments in the distribution transformer market was estimated to be --$1.5 billion in 1992 , coming from more than 230 companies having annual shipments of $100,E or more. 'The outtoolc: for 1116 drserpbiition sforener industry is not expected to be different from that of the past decade. The liquid

- immersed utility transformer market is expected to grow at an overall growth rate of not more than I% annually

. The nonutility , predominantly dry-type transformer market growth is estimated to be a little higher ( 2

. 5%) than the ' utility-dominant liquid-immersed market. It ii estimated that m terms of annual capacity sold, the liquid

- immersed market (10 prom 64,631 MVA (1.14 million units)

xixin 1993 to 99,195 MVA (1.41 million units ) by the year 2030. For the same years the dry-type transformer market (0.25 kVA-2.5 MVA) is forecast to grow from 28,336 MVA (0.779 million units ) to 70,650 MVA ( 1.615 million units ). The market shares of open-wound and cast-resin, dry-type transformers compared with the total. capacity sold in 2030 will be 28% (47,361 A) and 12% (20,298 MVA) respectively. The structure of the distribution transformer market currently includes various market players and their interactions . Transformer purchasing decision makers play the most important role regarding energy efficiency

. Electrical contractors or agents (who are not the users paying the future electric bills) are currently responsible for most C&I purchases of dry

- type transformers. Utilities , on the other hand, establish their own loss evaluation criteria in buying their transformers

. Several criteria such as first cost , TOC, band-of-equivalence , oversizing, and the choice of winding material are currently used when transformers are purchased . TOC is the only criteria producing minimum overall cost. 

### POTENTIAL ENERGY SAVGS Potential energy savings based on cost-effective energy conservation could be significant. Average loss reductions per kilovolt

- ampere of capacity for cases developed in this study would be between 0.9 and 2.4 W/kVA of purchased transformer capacity. This translates into -8-21 kWh of electricity saved annually or 240

- 630 kWh over 30 years (the average life of a transformer) per kilovolt

- ampere of transformers purch ased. It is estimated that in 1993 the total sales of distribution transformers were about 93,000 A. By 2000 , sales are projected to be over 100 ,000 A. Savings from conservation would continue to grow with sales of new transformers. Table 2 indicates the initial \ rate of primary energy savings and the cumulative savings after 30 years. A national average power plant heat rate of 10 ,000 Btu/kWh has been assumed to estimate the primary energy savings shown in Table 2

. Figure 2 projects the growth in cumulative savings for a cost-effective national energy conservation policy
. Energy-efficient transformers would continue to provide savings over their useful lives . About 93% of these savings could be realized if distribution transformers below 10 kVA were excluded from an energy conservation policy

. The details of the approach used are given in Appendix D. 

### IMPACTS ON MANUFACTURERS AND USERS Energy-efficient transformers will increase the cost of production to transformer manufacturers because either more material or a better quality of material will be used . The effect on manufacturers ' revenues will_depend on how much of the cost increases caused by conservation can be passed through to consumers . If less, than the actual, higher production costs are passed through, profits will suffer, a pass - through above the increase in production costs will increase profits. A manufacturer's production costs will also be determined to some extent by the additional investments necessary for retooling to manufacture more -energy-efficient transformers . A cursory examination of the industry suggests that manufacturers of dry-type transformers will be more affected than manufacturers of liquid- immersed transformers because a greater number of dry-type transforrs. are not currently loss evaluated. Because the liquid- immersed transformer market is currently more than 90% loss evaluated , the impacts of energy conservation are expected to be small... The energy efficiency of transformers also raises issues regarding the production capability of raw material suppliers. Most raw material suppliers are domestic and are estimated to be at 80% of full production capability; this available capacity may not be adequate in certain cases to meet any surge in demand for increased supply of raw materials . There will be a shift in demand

xxTable 2. Energy sa vings for a co nse rvation cas e b ased on average of the three lowest TOC designs (quads of primary energy)' Annual savings Cumulative savings Transformer rate in 2000 2000-2030 rY A..y Liquid-immersed 0.0046 2.4 Dry-type 0.0108 6.5 Total 0.0154 8.9 aA quad of energy equals I quadrillion ( 1015) Btu . TOC = total owning cost.

10

2000 2003 2 006 2 009 2012 2015 2018 2021 YEAR 2024 ORNI-DWG 95-I609

2027 2030
Fig. 2. Cumulative prinuwy energy savings from 2000 to 2030 for a conserva tion case based on an average of the three lowest total-owning-cost designs. (See Subsect. 4.4.2.) toward higher performance core materials. If amorphous-core technology is to be relied on to meet efficiency goals, the higher investments required and the patents associated with the technology are important issues of concern. It is estimated that the capacity utilization level of the magnet wire industry would increase from the current level of 80-84% if energy efficiency improvements for distribution transformers were accomplished by the use of copper alone. 

### CONCLU SIONS A number of energy conservation options were analyzed

. All of the conservation options considered for a national policy in this study are economically justified based on national average electricity costs

. These options are also technically feasible, although some'retooling may be required for the more energy-efficient , dry-type transformer designs. Based on a conservation approach similar to the options analyzed , a national energy policy for distribution transformers would have the potential for energy savings of 4.2- 13.7 quads over the 30

- year period from 2000

xxito 2030, assuming transformer sales grow at a rate of -1-2% over the period. If the annual sales

of transformer capacity does not grow at the assumed rate of 1-2% but remains constant at the 1993 level (i.e., a zero growth case), then the savings will be reduced to a range of 3.6 to 7.1 quads for the conservation options considered in this study. About 93% of these savings could be realized if distribution transformer sizes below 10 kVA were excluded from an energy conservation policy. Improved efficiency in dry transformers accounts for the majority of these savings.


### REFERENCES Barnes, P. R., et al. 1995. The Feasibility of Replacing or Upgrading Utility Distribution Transformers During Routine Maintenance, ® 6804181, Martin Marietta Energy Systems, Oak Ridge Natl. Lab. Canadian Standards Association 1994. Maximum Losses for Distribution, Power, and Dry-Type Transformers, C802-94, Canadian Standards Association, Toronto, Ontario, Canada.

xxii

### .ENTR ODUCTION

1.1 BACKGRO Subtitle C, Sect. 124, of the Energy Policy Act of 1992, Pub. L. 102-486, Oct. 24, 1992, contains an amendment to Sect. 346 of the Energy Policy and Conservation Act (42 U.S.C Sect. 6317) requiring that the U.S. Department of Energy (DOE) assess the feasibility of energy conservation standards for distribution transformers. The objective of this study was to determine whether energy conservation standards for distribution transformers would have the potential for significant energy savings, be technically feasible, and be economically justified from a national perspective. Distribution transformers are part of electric power distribution systems. Electrical energy is delivered to consumers by utility power transmission and distribution (T&D) systems. The transmission network delivers bulk power at high voltages (69-765 kV) from power plants to local distribution systems where the electrical energy is transformed to lower primary distribution voltages (ranging from 4 to 35 kV). High transmission voltages are used to transmit high levels of power over long distances. The high transmission voltages result in lower currents, which reduce line, losses, the amount off conductor material needed, and costs. Once the electrical power has reached the distribution system, it is transfonned to lower primary distribution voltages that are more economical for the shore distances witi in distribution, systems. The primary distribution voltage is transformed by distribution ftandormers to lower secondary voltages (12 0-600 Vac) that are suitable for customer equipment. These transformers provide the final link in theca of electrical power components-from the generating sources to the ultimate power-consuming equipment. Distribution transformers are very reliable. devices: they have no moving parts and have average lives of -30 years There are two basic types of distribution transformers: liquid-immersed and dry type. Liquid-immersed transformers typically use oil as a coolant; these transformers are normally used outdoors because of concerns about a potential oil spill or possible fire hazard. Electric utilities own about.90% of all liquid-immersed transformers. Recent advances in liquid-filled units have greatly reduced these problems, and the units are now used indoors. Dry-type transformers are air-cooled , non-oil devices and

. thus do not need. special oil-spill containment . Many commercial and industrial (C&I) customers use secondary distribution, dry-type transformers within buildings to transform the building or plant voltage (typically 480 Vac) to a lower secondary voltage (120-240 Vac) Large-load-center, dry-type transformers are also used to transform the primary distribution voltage to the plant or building voltage. In the United States, -40 million liquid-immersed distribution transformers are, owned by electric utilities, and an additional 4 million liquid-immersed units are nonutility owned (Barnes et al. 1995). Transformer manufacturers estimate that -12 million dry-type distribution transformers are used by C&I customers in the United States. Utility-owned distribution transformer efficiencies steadily improved from the 1950s to the 1970s with the introduction of improved materials and manufacturing methods. Figure 1.1 shows the efficiency improvement for a typical single-phase, 25-kVA, liquid-filled, pole-mounted transformer, a common distribution. transformer used by electric utilities. Following the energy price shocks of the 1970s, some utilities began to use purchasing formulae that factored the effect of transf efficiency into the purchasing decision. Manufacturers responded by tailoring their products to the energy evaluation factors specified by customers, a practice that continues to this day. Thus, it is now possible to purchase a relatively high-cost, high-efficiency transformer or a unit with a lower first cost and lesser efficiency. Most of the nonutility distribution transformers

1-1100

m

m

95 ORNL4DM 95.1717

1950 1955 1960 1965 1 9701975 1960 1985 199Q.1995_

FO RMER OF MANUFACTURE Fig. Effleiency improved with .time for a VA, liquid-filled distri bution trand ormer. are purchased on a lowest first-cost bas is without evaluatin g the cost of the energy cons umed by the units

. These "noneval uated" transformers may have 50 % more losses than utility formers . The max imum efficiencies of liquid- i ised distribution transformers have improved over the past several es, but nonevaluated dry-type units have shown little or no improvements because of the lack of economic incentives

. Figure 1.2 shows efficiencies for 75-kVA, liquid and dry-type, three-phase traiisfoni Costsavings through energy conservation should provide an incentive to increase the efficiency of dry-type units and some utility-purchased transfor mers that are currently not evaluated on a Life

- cycle-cost basis. However, many C&I transformers are purchased by contractors who do not benefit from the cost savings of energy conservation

. For this reason , efficiency standards should be considered. Canad a has recently developed i iinuni loss values for distribution , power , and dry=type transformers ( Canadian Standards Association 1994). Distribution transformers used by utilities account for -61 billion kWh of the annual energy lost in the delivery of electricity (Baines et " al. 1995 ).` Dry-type transformers , although fewer, are less efficient and are estimated to consume an additional 80 billion kWh of electric energy on the custo me r side of the electric meter. S mall i.,.' ve. ts in transformer efficiencies of 0.5-1.0% could result in an annual savings of tens of billions of kilovolt

- hours

. Thus, the potential for saving energy with more efficient transformers could be significant. In this study, a number of energy conservation options were analyzed , the results of which provide DOE with information for making a determination on proposing a national ene rgy conservation policy for distribution transformers.


### 1.2 MAIUMT TRENDS The total value of product shipments in the distribution transformer market was estimated to be --$1

. 5 billion in 1992 , coming from more than 230 companies having annual shipments of $100 , 000 or more ( DOC 1994 ). The future outlook for the distribution transformer industry' is not expecte d to be different from that of the past decade. 7he liquid

- immersed utility transformer

1-21950 1955' 1960' V966 1970 9975 4980 4985 1990 9995

Fig. la Di stribution innsf o rmer effici encies over the yea rs for 75-kVA , tin-a- a phase units. Sources : Barnes et al. 1995

. Feasibility of Replacing or Upg rading Utility Distribution T rs D urin g Ro utine Maintenance, 0RNL- 1 Martin Marietta Energy Systems, 081c "b "' - , "ltidg Nail : I.ab, and tcaasformermanufacturers' data. market is expected to grow at an overall annual growth rate of not more than 1 % annually. Sales of liquid

- immersed utility distribution transformers depend primarily on new housing starts, while gross private domestic investment provides a good indicator for the nonutility transformer market. The nonutility transforme r marke t is expected to have an annual growth rate of -2.5% (see Subsect

. 3.1). Also, the average size of transformers is expected to increase annually by 0.5% for both liquid

- and dry-type transformers. It is estimated that

- 0.38 million 'dry-type and 1.14 million liquid-immersed transformers were sold during 1993. be ' dry -_q - - qe-ft ' market is expected to ncrease from 0:44 to 0.65 million units from 2000to 2020 : Tlie liquid-immersed transformer market is expected to have a comparatively slower growth , increasing from 1

. 18 to 1

. 33 million units during the same period

. In terms of capacity of transformers sold annually, the liquid

- immersed transformer market is expected to continue to increase from 64 , 631 MVA'in' 190516 78,690 and 88,350 MVA by the years 2010 and 2020 i+espectively

. The corresponding capacity volumes for dry-type units are 28 ,336, 43, 116, and 55 ,192 MVA : By the year 2030 , the number'of liquid

- i mmersed ` x _ .id. 

### dry-type transformers sold is projected to be 1.41 million units and 0.79 million units, respectively , with capacities of 99 , 195 MVA and 70,650 MVA
1.3 STUDY APPROACH The study methodology consisted of four major elements: development of a database, development of conservation options, assessments of the energy conservation options, and incorporation of feedback from "stakeholders." A database is required to accurately assess the potential energy savings for various energy conservation options. All of the options considered here are technically feasible. Each brief discussion of each element follows:

1-3Database Development

. Collecting and processing data was a major part of the study. Data on transformer designs, losses, and sales were provided by the National Electrical Manufacturers Association (NEMA ) and individual manufacturers

. The Edison Electric Institute (

EEl), the American Public Power Association (APPA), and selected utilities provided utility user information

. The database includes the results of a survey circulated by EEI and APPA to their member utilities as described in a previous report (Barnes et al. 1994). User information on dry-type transformers was provided by the American Institute of Plant Engineers

. In addition, the Federal Energy Regulatory Commission ' s Form 1, Energy Information Administration information, and trade journals were used

. The basic information required included historical information on user purchases and costs and. losses of new transformers for the various options considered in the study

. Information on tran sformer loading factors was obtained from discussions with transformer manufacturers and utilities and limited surveys of commercial and industrial users. ® Energy Conservation O ptions. Technically feasible energy conservation ( low-loss) options for distribution traris formers were based on information provided by NEMA and individual :transformer manufacturers. Cases with relatively low life-cycle costs were selected by the Oak Ridge Natio nal Laboratory (ORNL) for analysis. ® Assessments

. The technical and economic analyses provided estimates of appro priate transformer loading factors, losses, and cost

- effectiveness and energy savings for the energy conservation options. ® Stakeholders ' Input. A distribution trans former review group consisting of manufacturers, users, material, suppliers , and public interest groups was formed to provide and to review this study (see Appendix A). Input from these stakeholders was incorpo rated in the final report.



### 1.44 SCOPE AND CO This report documents the assumptions , models, data , and conclusions of this study on the feasibility of achieving cost

- effective energy conservation for distribution transformers. For purposes of this analysis , distribution transform eis'are'defrned as ' all transformers with a primary voltage of 480 V or more and a secondary voltage of 120-480 V with a rated capacity of 10-2500 kVA for both liquid-im'm'ersed and diy-type units. Smaller capacity dry-type units of 0.25-9 kVA that are used for the distribution of electric power are also considered for completeness

. This study is limited to the consideration of transformers used in power distribution systems. Special-purpose , control, and signal transformers , as well as bulk power transformers , were excluded from consideration because they are not classified as distribution transformers. Section 2 discusses the potential for higher-efficiency distribution transformers, and Sect. 3 describes the structure and elements of the transformer market

. An analysis of selected technical options for energy conservation and potential cost

- effective energy savings are described in Sect. 4. A preliminary assessment of the impacts of the energy conservation strategies on both manufacturers and users is presented in Sect. 5.

1-4

### REFERE NCES Barnes , P. R., et al. 1995. The Feasibility of Replacing or Upgrading Utility Distribution Transformers During Routine Maintenance, ORNL-6804/R1, Martin Marietta Energy Systems, Oak Ridge Natl. Lab. Canadian Standards Association 1994. Maximum Lossesfor Distribution, Power, and Dry-type Transformers, C802-94, Canadian Standards Association , Toronto, Ontario Canada. DOC (U. S. Department of Commerce) 1994.1992 Census of Manufactures Industry Series: Electrical Transmission and Distribution Equipment and Electrical Industrial Apparatus, MC92-1-36A, Bureau of the Census.

### 2. CHARACTERIZATION OFDf.S ._ __ .__,_. ®N.__ . _ ._._SF'®l LOSSES

2.1OVERVIEW . This section discusses

. he,key components of distribution transformers, the associated sources of energy losses , and the major differences between liquid and dry types. Transmission anddistributton

. of, ail. t acing current ( ac) electric power requires the conversion of voltage and current levels to match the desired application

. This conversion, accomplished by transformers, represents a significant portion of the investment in the T&D. system . While the transformers used i n the T&D_system are acknowledged to be very efficient, the cumulative _eff_ec of the Posses of large number of distribution transformers can represent a substantial cost

. to the system . A.major objective of transformer design is to achieve the lowest possible total owning cost (TOC) to owners/operators; this requires a. trad e-off between the. capital cost of transformers and the cost of the transformer losses . The value of these losses may not be specified in all applications , and in this case the TOC reflects only the capital cost of the transformers. This report ad dres ses those Miri sformers that perform the final transformation from utility distribution voltages (typically 4-35 kV) to final utilization voltages (600 V and below); hence, the desi gnati on "distribution transformer " These distribution transformers range in size from -.0.25 kVA single-p to 2S VA, -phase sfo rs. The definition for distribution , sf rs asconside in this study can be s ummarized as transformers- that are continually energized ; these fall within the voltage classes and capacities shown in Table 2.1. Table 2.1. cterist cs of disWbution, ns oriners _typically used in the United States Transfo Phase Primary voltage Secondary voltage Capacities type (kV) (V) (kVA) Liquid- immersed

, 35 and below,,, 600 and

. below

... 10-833 Liquid-imm 35 and below --600 and below, 15-2500 Dry-type 1 35 and below 600 and below 15-833 Dry-type 3 35 and below 600 and below 15-2500 Diy_type" 1 and 3 35 and below 600 and below 0.25-<15 T smaller dry-type units are included for completeness , but they are a small contributor to the overall energy losses and are not likely to be included in an energy efficiency standard . The units below 9 kVA normally have primary voltages below 600 V. The vast majority of distribution transformers on the utility

- owned distribution system are the liquid -immersed type, while those used in co mme rcial, indu strial, and institutional applications are predominately the dry type. The merits and limitations of.each type are discussed in.the following subsections. In general , distribution transformers operate over a oxide range of loads-sortie applications having substantial portions of the day and year near zero load. As is shown in Subsect

. 2.2, light l oadin g increases the importance of losses at low-load levels, since energizing current must always be ore sent, even without load.

2-12.1.1 Prin ciples of Tra nsf orm er Operation There are three basic elements in a transformer: the primary winding, the secondary winding, and the core. Figure 2.1 shows the key elements pictorially. The two windings are coils of wire wound around a core of high-magnetic-permeability material. By definition, the primary winding is the one connected to the electrical source, while the secondary winding is connected to the output or load. The core may be made of silicon steel or another magnetic material such as amorphous metal and provides a path for the magnetic flux that links all the windings. An alternating flux is set up in the core when the primary winding is connected to an ac voltage source. This alternating flux induces voltage in all windings that is proportional to the number of turns i n the specific winding (F y's law).` In the ideal transformer there are no losses or leakage flux, and the ratio of the voltages induced is equal to the ratio of the number of turns in the respective windings

. For example , a transformer with a 1000-Vac source applied to l0 turns in a primary winding will induce 100 V in a secondary winding with only 10 turns. By selecting the proper turns ratio, the designer can determine the ratio of input to output voltages. Simply put, the volts per turn is constant in each winding. , _
ORNL-DWG 95M-10061

LOAD

SECON DARY VMDINQ (RESR:rANcE.. Rp) Mg. 2.1. Maj or I nternal elements .of a transformer. Because the ideal transformer neither stores nor loses energy, the power input to the primary winding must equal the power output to the secondary winding . As the power input is the product of the voltage and current on the primary side , the power output must be equal to the product of the voltage current-on the secondary side. This implies that the ratio"of the pri . I... and secondary current is inversely proportional to the turns ratio . Hence, the ideal transformer simply changes the voltage between the windings in proportion to the turns ratio and changes the current in inverse proportion

. In the example given in the previous paragraph, the secondary current must



### 2-2be ten times the primary current

. Assuming that the transformer ' s load . is 5„kVA, then the primary current is 5 A, and the secondary current is ten times this, or 50 A or I , N1 = 12N2. Obviously , transformers are not ideal , and while the modern transforniervery closely approaches the ideal , there are losses

. Specifically , there is a voltage drop through the transformer under load so that the voltage ratio is not exactly equal to the turns ratio, and an excitation c urre nt flows in the transformer even when, noextetnal lid current is present

.. The excitation

_ current ,:. reflects the presence of no-load losses, while the losses at load are indirect proportion to the. product of the square of the current and the

. winding ' s effective electrical resistance , which is influenced by temperature , For these reasons, the turns ratio does

. not match the, ideal relati ®nship. Details of these loss mechanisms are dtscussed below. In the,transformer ; depicted in Fig. 2.1, the'windings are separated to avoid confusion In reality , the lower-voltage windings are placed next to the core, and.extend over the entire core leg; the high

- voltage windings are placed outside and over the low voltage windings. Because the core is at ground potential , this simplifies the problem of insulating the high voltage from the core material. Clearly , the windings must be insulated from ground and from low to high voltage. In addition , voltage drop in the windings requires an insulation from turn to.t ._ _.4jyer to layer of each windin g (and between phases in three-phase units ). The space required by the insulation effectively increases the size of both

. coil and core and hence the transformer ' s design volume. Multiple types of insulation systems are available, and the system selected dete rmnes , whether sf . r is a , dry or liquid-imm

## ersed 

## ty pe and its intended , operating tempera 

## ture . 

### F

## urth ermore, 

### the amount of ins 

### .._' on 

## required is dependent 

## upon both 

## steady

## - s

## tate and 

## tran sient voltage levels and 

### in....__ s_ with the transformer ' s rated voltage. ere are two basic methods of winding transf (1) the core form , in which the two sets of dings surround a core, and (2) the shell form , in which a single set of wi ndings is surrounded by core material , as is shown in Fig

. 2.1..There is no inherent difference in cost or performance betgveen

. the.tw o designs , and the design chosen is somewhat dependent upon the s etup of the manufac turin g facility. 

### 2.1.2 Ma jor Transf

ormer Mew

. ..... s_N°--_ .._..... __...__ Losses As is noted in Subsea. 2.1.1, there are two major types of losses in transformers : no-load loss„ and load loss. 

### 2.1,2.1 N o- load l ....:.... No-load losses are those losses required in the excitation-of the transformer ., load_losses._,,, include dielectric ;

losss, conductor loss-due-to excitation and circulating currents , and core loss. The dominant no-load loss i s core loss , which i s associated with the time

- varying nature of the magnetizing force and results from hysteresis and eddy currents in the core materials

. Core losses are dependent upon the excitation

. voltage and may increase sharply if the rated voltage of the transformer is ex _„ ---- Th ere is alsjope inverse

. dependence on core , temperature. Hysteresis losses in transformer core material s occur because the core materials resist r a realignment of the magnetic do main s in thematerial_. The power required to overcome this reluctance and change magnetic alignment is dependent upon the operating frequency, the amount and type of core material , and the magnitude of the magnetic flux density. Furthermore, the magnitude of hysteresis loss is depe ndent upon flux density, which is, in turn , dependent upon termin al voltage and the number of winding turns, This interdependence is generally referred to as the ' hine equation " and is a consequence of Faraday ' s law of electromagnetic induction.

2-3This relationship is expressed in the equation shown in note 1, which may be rearranged to

express Bm,,., in terms of induced voltage or volts per turn in terms of B,. The initial magnetization curve and a typical hysteresis curve for a ferromagnetic material are shown in Fig. 2.2. Clearly, the relationship between magnetic flux density and magnetic field intensity is nonlinear

. For maximum operating performance at minimum capital cost, it is generally desirable to operate the transformer just below the knee, or bend, in the magnetization curve , reducing the quantity of core material and the associated cost. Care must be taken to ensure that the operating voltage levels do not push the transformer into the saturation region of-the curve beyond the knee becaus e this sharply increases losses and harmonics

. Alternatively, reduction of the peak operating flux, while reducing hysteresis losses, results in the need for a larger cross section of core material and can thus increase transformer capital cost, weight, and volume. The use of different core materials also impacts size and capital cost. The alternating flux induces in the core material small circulating currents much like eddies in a stream, These eddy

- current losses in the core materials represent the other major component of core losses and are functions of the operatin g uency , the flux density, the volume of core material, and the resistivity of the core material

. To reduce eddy-current losses, the core materials are selected for high resistivity and are fo rmed into thin sheets called laminations , which are sep arated by thin layers of insulating oxide coating and oriented to minimize the induced currents
. These actions increase capital cost by increasing the core volume, the materials cost, and the assembly l abor costs. Similarly, d ecreas ing eddy currents by lowering the flux density increases the core material requirements and , potentially , the capital cost , weight , and volume. The resistivity of the core material has traditionally been in creased by alloying iron and silicon and cold-rolling the material s into thin laminated sheets of 7- to 12-mil thickness. These materials are then heat

-treated to reduce hysteresis losses. While great strides have been made in reducing the losses in high-silicon

- steel materials , a technique for producing materials in which the iron atoms are randomly oriented (amorphous metal) has been developed

. In this process, a molten alloy of iron , silicon , and boron is allowed to spill in a ribbon onto a rapidly rotating drum where it is chilled at the rate of about a million degrees per second , forming a glasslike ribbon of material about 1 mil thick without crystalline structure

. This material has good magnetic properties , low inherent hysteresis losses, and high resistivity . The very thin laminations greatly reduce eddy currents , but their extreme brittleness and the difficultly in handling them adds to the assembly cost

. Because the saturation flux density of amorphous material is lower and because amorphous material cannot be packed as tightly as high

- grade silicon steels, the effective operating flux levels in the core are reduced

. As a result, cores made of amorphous material are generally larger

- requiring more pounds of material, eroding the specific loss advantage of amorphous material , and increasing costs

. The larger core cross section also requires more material for the coil ( i.e., more turn s and/or longer winding length); this generally in crease s core cost and load losses. All amorphous-core tran sf ornvers, are liquid

- immersed , wound core and were , until recently, limited to <2500 kVA

. Transformer cores made of this amorphous

- core material have <25% of the losses per pound of material demonstrated by the best transformer cores made of high-grade silicon steel. The dra wbac ks of the amorphous

- core material include increased core costs, increased difficulty in fabrication , increased core volume and weight , and reduced saturation flux density. The present capital cost penalty relative to high-grade silicon steel appears to be -25%. The amorphous

- metal manufacturer and the Electric Power Research Institute (EPRI) are optimistic that in constant dollars this penalty can be reduced to less than 10% (Ng 1993). Aside from the core material properties , other issues enter into the core performance such as the use of wound core or stacked core and the manner in which the core laminations are stacked in so-called buttlap , mitered , and steplapped cores to reduce joint fringing. Also, the degree of

2-4ORNL-DING 95M-10052

MAGNETI C FI ELD I NTEN S ITY (H (Afm))

C305M -1 008 1

Fig. 2.2 . Typi cal iniVal gnetiz ation a (top) and typical hystersis curve ( bottom) for ferrom agnedc material.interleaving or booking in both wound and stacked cores ranges from single-sheet to four-sheet.

These techniques are used to reduce core losses, but the more elaborate techniques are labor-intensive and increase core costs for a specified material. Generally, the better-performing, higher-cost materials are used in configurations that also require more labor. 2.1.2.2 Load losses Those losses that are incident with the carrying of load are referred to as load losses. Unlike no-load losses, which are constant and always present, load losses vary with the square of the load current carried by the transformer and include ( 1) the resistive heating (PR) losses in the windings due to both load and eddy currents , ( 2) stray loss due to leakage fluxes in the windings, core clamps, and other parts , and (3) the loss due to circulating currents in parallel windings and parallel winding strands. For distribution transformers , the major source of load losses is the I'R losses in the windings. Load losses can be reduced by selecting lower-resistivity materials (such as copper) for the windings, by reducing the total length of the winding conductor, and by using a conductor with a larger cross-sectional area
. Eddy currents are controlled by subdividing the conductor into strands and insulating the conductor strands and by conductor shape and orientation
. Clearly, this involves a combination of material and geometric options that also depend upon the core dimensions. Because dry-type insulation systems lack the additional cooling and insulating properties of the oil-paper systems, for the same rating the dry-type transformers tend to be more costly, larger, and have greater losses than a corresponding liquid

- immersed unit. Moreover, for a given capital cost, volume , weight, and insulation system , transformers of the same voltage and kilovolt-ampere rating trade off no-load against load losses. This is illustrated conceptually by the cost vs losses surface in Fig
. 2.3, which in reality is a set of discrete points established by available core dimensions? Because load losses vary with the square of the load current , transformer efficiency is load-dependent ' Furthermore, it can be shown mathematically that maximum efficiency occurs at the load point for which load losses and no-load losses are equal. Most distribution transformers are generally lightly loaded for relatively long periods and are designed with lower no-load losses to operate with maximum efficiency at 25-500t load (Fig. 2

. 4). The curves shown in Fig

. 2.4, which are typical of distribution transformers, illustrate two different applications : the first

- called low no

- load loss, high load loss

- is for transformers that would be expected to be lightly loaded ( i.e., low capacity factor); the second

- labeled moderate no-load loss, low load loss

- would be applied to a transformer with a higher capacity factor (i.e., capacity factor = average load/transformer capacity). The curves are easily plotted using equations of the type illus trated in note 3, values for the nameplate rating , load losses, and no-load losses
. The effect on total losses is indicated by Fig. 2.5, which illustrates the general nature of this trade-off. 2.1.3 Characteristics of Liquid- and Dry-Type Transformers Liquid- immersed transformers are the predominant type of transformer, representing the oldest technology and having an established performance record . They offer the best balance of design properties for dielectric, thermal , and cost performance and are the basis for all other design types. The liquid- immersed units have outstanding thermal and dielectric properties, the lowest purchase cost, the smallest dimensions, and the lowest losses per purchase dollar and are relatively unaffected by the operating environment . The key disadvantages are the possible



### 2-6ORNL-DWG 95M-10063

. Surface of cod ®f ::_ atypical 25-UVA b1 ._ f® r. S07arrB: Pre] supplied by the National Electric Manufwnffm Association. using data

ORNL
- DWG 95M-10064 99.5
99.3 99.1
98.9 98.7
98.5 98.3 98.1
97.9
97.7 97.5 0.08 1.04

0.2d 0

. 40. 0.58 0.72 0.88 PER UNI 'T' LOAD EPLATE RATING.=1.0) Fig. 2A Typ i cal a 1.20

unit load relative to o plate rating . NL.L = no-load losses;

2-7500
450
400
350
300
250
200
150
100

0 

### 0 PER UNIT LOAD (NAMEPL A TE TING =1.0) Fig. 2.5 . Typ i cal to tal l osses functi ons of load , Indian of relative load and no-load l ossm RILL = no-load losses; LL = load losses. susceptibility to fire , a lower temperature rise, and potential oil leaks. Fire-resistant liquids have been developed and, aside from the disadvantages of leakage and more restrictive thermal operating limits, compete favorably with dry-type transformers. Dry-type transformers are available in several types but are generally open wound or encapsulated

. The design temperature rise and hot spot temperature imply that several different insulating systems are available for dry-type transformers , but all dry-type transformers depend strongly on the insulating and cooling properties of air

. The units are fire

- resistant and present no leakage problem . They are generally more costly and heavier and have higher losses than liquid

- immersed units

. The insulation systems used in dry-type transformers permit operation at higher temperatures than those used in liquid

- immersed units

. Because little capital investment is required to begin manufacturing dry transformer s, there are a large number of man ufacturers, and turnover is high. Dry-type transformers are limited to operating voltages of less than 46 kV.


### 2.2 TRANSFORMER EV AL UATION AND LO SS DI'i 

### 0 UCTION METAODS This section discusses the general nature of loss evaluation and trade

- offs in loss reductance. Without regard to cost, it is technically feasible to design and to build distribution transformers of all types that provide significant energy savings compared with the typical units purchased in 1994. However , if energy

- saving designs are restricted to those that are economically feasible using national average energy costs , there is a potential for moderate savings per transformer from liquid

- immersed units and for more significant savings per transformer from redesigned dry-type units. Because utilities roudnely'e iluate transformers for minimum TOC, the technical ability to provide low-loss liquid-immersed transformers is well established.

2-8Typical values for losses in distribution transformers are given in Table 4.2 by size and insulating system. As a result of improved performance in core materials from both silicon steel and amorphous-core materials and increased demand for lower TOCs by utilities, transformer losses in oil-paper systems have decreased steadily since the 1950s. Generally,`dry=eype transformers have not experienced a corresponding reduction in losses . This reflects the fact that dry-type transformers are usually not evaluated for TOCs and are purchased on a lowest first-cost basis. The TOC evaluation methodology, which has been used by utilities and some other large customers for a number of years, provides a balance between cost of purchase. and cost of energy losses . The wide range of no-load-loss evaluation values (A factor) and load-loss evaluation values (B factor) for liquid-type transformers .indicates the broad diversity of utility energy and capital expenses. Similar techniques could be used to develop A and B factors for dry-type transformer applications in industrial and commercial settings . However, while low-loss transformers are available for liquid- immersed applications, there has been limited incentive for manufacturers to supply low-loss, dry-type transformers . It appears that the limited customer demand for lower-loss, dry-type units has come from utility applications and special niche applications in industry. The design specifications and maximum losses will define the continuous capacity (kilovolt-ampere), the overload capability and hence the thermal performance of the i nsulation system, the short circuit or fault current capability and transformer impedance, the phasing desired, the normal and unusual service conditions , the voltage regulation ; and-the basic impulse level. Specification of losses, or efficiency is not common because this restricts the design. Instead, the utility practice is to specify loss evaluation values for no-load and load conditions and to allow the manufacturer to minimize the TOC. The technology used to provide low-loss transformers is based upon changing the configuration and hence the amounts of coil and core materials and lower loss materials. For example, operating at a lower flux density will reduce core losses but require more turns of conductor, increasing load losses. Similarly, lowering the conductor current density will reduce load losses but require more core material.ora higher flux level, which will produce higher no-load losses

. Restrictions on weight and volume may further limit the selection . To provide a low-loss transformer requires the use of low-loss materials (i.e., high-silicon steel or amorphous metal for the core and increased _amounis of copper or aluminum forthq windings) configured in an optimal manner . The increased, core volume and weight associated with amorphous cores requires longer turns of conductor, increasing coil losses . The configuration and the materials selected define the cost of the transformer materials and the labor required to assemble the system (i.e., the transformer cost). Table 2. 2 illustrates these trade-offs. It is evident from fig. 1.2 that maximum efficiencies forthree- phase , 75-kVA, dry-type transformers have declined from about 97.8% in 1970 to 96.9% in 1995, while liquid-immersed units have slowly increased in efficiency over the same time period. In 1970 the liquid-immersed unit was about 0.7% more efficient (98.5 vs 97.8%), which can be attributed to the difference in the insulating value of oil y4, ir andthe $esuititig smaller size of the liquid- immersed unit. In the intervening years the liquid- immersed twits have slowly evolved to efficiencies of about 98 9% However, nonloss evaluated transformers deteriorated in efficiency to under 98 .0% from the„ 98.5% level of 1970. If during the sam e tine period dry-type transformers had applied the same technology evolution, it is safe to project that dry-type transformers , if subject to a loss evaluation. by the customer, would now approach 98.2% efficiency instead of the 96.9, efficiency currently produced. These comparisons depend on evolutionary development of the technologies, not major breakthroughs. For a detailed analysis of transformer design methods, see Feinberg (1979) and Stigant and Franklin (1973).

2-9Table 2.2. Loss reduction alte rna tives No-load losses Load losses Cost To decrease no-load losses o Use lower-loss core materials Lower No changes Higher o Decrease flux density by (1) increasing core CSAb Lower Higher Higher (2) decreasing volts/turn Lower Higher Higher ® Decrease flux path length Lower Higher Lower by decreasing conductor CSA To decrease load losses • Use lower- loss conductor material No change Lower Higher • Decrease current density by Higher Lower Higher increasing conductor CSA ® Decreas e current path length by (1) Decreasing core CSA Higher Lower Lower (2) Increasing volts per turn Higher Lower Higher 'Amorphous-core materials would resul t in higher load losses. bCSA = cross- sectional area. Can dry-transformer technology provide transf orme rs with lower losses at reasonable costs? As is indicated in the previous para graph , all type s of dry trasi sforiners can be constructed with lower losses; however, costs will be higher for a given efficiency than for liquid

- immersed transformers

. Because air is the basic cooling and insulating system for dry-type transformers, all dry-type transformers will be larger than liquid-immersed units for the same kV/kVA rating; hence , it is not possible for a dry

- type transformer to have a lower TOC than a liquid

- immersed unit

. When operating at the same flux and current density , more material for core and coil implies higher losses and higher costs. However, dry-type transformers have traditionally offered fire

- resistant , environmental , and application advantages for industrial and commercial situations. Recent advances in liquid-filled units reduce these advantages. Therefore , the reduction in losses in dry- type transformers must be weighed against the increased capital costs of the units by using TOC or an equivalent evaluation method.



### 2.3 TRANSFORMER LOADWG P . Determination of both the size in kilovolt-amperes and the load factor of distribution transformers is an important task

. Both continuous load and overload impacts on insulation system life must be considered. Methodologies have been developed to enable utilities to better size the transformer to the load characteristics (Schneider and Hoad 1992). Studies seem to indicate that distribution transformers are lightly loaded most of the time but have short periods of time in which loads may be 50-I OD% above the rated load. In other words, a 10-kVA transformer might be loaded at 15-20 kVA for periods of a few hours per year with slight loss in useful life (DOE 1980; Nickel and Braunstein 1981). An important point to note is the relatively large spread in the peak load that implies a relatively large uncertainty in the transformer peak load or loading pattern. Nickel suggests a variable peak loading with an initial peak load of 0.6 to 1.0 and a final peak of 1.25 to 2.0 based

2-10upon a 1971 industry survey (DOE 1980; Nickel and Braunstein 1981 ). The transformer load is assumed to grow from the initial to the final peak at a specified rate , at which point the transformer is moved to a lower load

. ration orretired The ratio of average losses to losses at peak load is called the loss factor and is used in deriving the load-loss evaluation (B) factor ratio of; average load to peak load is

. referred to as the load factor and is equivalent to the transformer dative capacity ( see note, 3) only if the transformer ' s peak load is equal to the_nameplate rating and coincident with the system peak load. This study refers to a transformer effective capacity factor when referencing transformer load and theref

ore assumes a coincidence of the transformer and peaks and a relative peak load of 1.0

. The capacity factor, load factor, and loss factor

. are strongly dependent on the transformer's loading pattern. The effective capacity factor used in this study is a root- mean -square ann ual average of the transforeyaer ' s relative capacity

. An empirically developed formula relating the loss factor to the load factor is LSF 0

. 15 LF + 0 85 L , The general relationship between loss factor and load factor has men published (Manning 1965) The above form of the equation is based on several representative utilities, and, as with other factors , used in this analysis, for a given application there can be

_ significant deviation from the ass umed national average . S peci fic forms of the equation for co rcialand industrial applications will require c areful study. A subject of major concern , to unlit gs4is , projected equipment life. For distribution,. tran sfbrrners a.io.. dii g guide has ., been established . (ANSI and IEEE 1981.). This guide provides a method for determining the insulation's hottest spot tempe rature as a function 9f load and a relationship between tempe rature and, time

. that is used to compute transformer life Present distribution transformers are designed to operate 20 years at the design load and specified hot-spot temperature

. Underloaded transformers are clearly less stressed thermally and may have lives extending well beyond 30 years , but transformers loaded to greater than nameplate rating for extended times may have significantly shortened lifetimes

. The national average age data referenced below implies that distribution transformers may be significantly underloaded. For this report , a national average for

_ utili y distribution transformer

_life of 31.95 years and a standard deviation of 6.4 years were used ,.(Mougin 1992). Note that 30 years is the typical period used for evaluating TOCs. While the present average age is well beyond the 20

-year design life, there is evidence of attempts by utilities to more closely match load to.transforn ier size e. In making. the decision to reduce transformers ze , utilities must consider voltage regulation

. Voltage drop in the transformer due to sudden load change can result in customer

. complaints

. For example, an electric motor requires up to six times the operating current during startup , and if the motor is a. , large relative to the

. trapsfornter , voltage can be significantly reduced for up to 15 s until the motor reaches operating speed. A common solution, to motor caus ed v o ltage

- drop problems is to. oversize the transformer

. The net result is anunderloaded transformer with a relatively long life. While the annual operating costs of transform rs , depend upon the per unitlos ling and are reflected in the TOC evaluation methodology through the loss evaluation values , another factor that will play an important role in dry-type transformer evaluation is the temperature rating of the unit

. The increased importance results from the wider variation in the maximum , operating tem perature allowed in dry-type transformer insulation.

2-11

### REFERENCES

ANSI (American National Standards Institute ) and (Institute of Electrical and Electronics Engineers) 1981. "IEEE Guide for Loading Mineral-Oil-Immersed Overhead and Pad-Mounted Distribution Transformers Rated 500 kVA and Less with 65°C or 55°C Average Winding Rise," ANSI/IEEE C57.91, in IEEE Standards Collection, Distribution, Power and Regulating Transformers, 1994 ed., Institute of Electrical and Electronics Engineers , New York. DOE (U.S. Department of Energy) June 1980 . Optimization of Distribution Transformer Efficiency Characteristics, Final Report, March 1979, DOE/RA/3022-01. Feinberg, R. 1979. Modern Power Transformer Practice, Wiley, New York. Manning , L. W. 1965. "Load Characteristics," pp. 27-28 in Electric Utility Engineering Reference Book, Westinghouse Electric Corp., Pittsburgh. Mougin , C. E. 1992. "Deprec i ation Statistics from 100 Large United States Utilities- C Jurisdiction ," J. Soc. Depreciation Prof. 4(1). Nickel, D. L., and Briaunstein, H. R. February 1951. "Distribution Transformer Loss Evaluation: U-Load Characteristics and System Cost Parameters," IEEE Trans. Power Apparatus and Syst. P-i 2). Ng, H. April 1993. "AMTs Improve Energy Efficiency," IEEE Power Eng. Rev . 13(4), 55. Schneider , K. C., and Hoad, R. A. October-1092. "Initial Transforme r Sizing for Single-Phase Residential Load," IEEE Trans. on Power Delivery 7(4). Stigant, S. A., and Franklin, A. C. 1973. 7he J&P Tr. . 6r r Book, Ne wn es-Butterworths, London.


### NO TES 1. E= 4.443 x f x N x B x A"„, where E = rated coil voltage (volts ), f= operating frequency (hertz), N= number of turns in the winding , B. = maximum flux density in the core (tesla), and Ad ,„ = cross-sectional area of the core material in the coil window. 2. In addition to the voltage equation in note 1, a power equation expressing the volt-ampere rating in terms of the other input p arameters is also used in transformer design

. Specifically, the form of the equation is kVA = 4443 x f x N x B.. x Aa „ x J x A.,,, where f, N, B., -and Alw are as defined in note 1, J is the current density (A/nun) , and A,, is the coil cross

- sectional area (rn2) in the core window. 3. Efficiency (11) at a given load level is defined as output energy divided by the sum of output energy and losses. Assuming constant terminal voltage and no correction for temperature effects, _ Scos0 [S cos ®+ core losses + load losses x (I S J /Sa)2] where S = kVA load, SB = nameplate rating, and cos 9 = power factor. For this report, 'q is shown for cos ® = 1. B ecause voltage fluctuation under operating conditions is limited , the voltage assumption is acceptable for well

- designed distribution transformers . The ratio 1St /Sa is called the relative capac ity.



### 2-12

### 3.DIS

FORECASTS Liquid-immersed and_dry-type are the two distinct types of distribution transformers , serving predominantly the utility and the nonutility sectors respectively . The total value of product shipments i n the distribution transformer market was estimated to be - 6$1.5 billion in 1992, coming from more than 230 companies having annual shipments of or more ( 1994a). Amorphous- core transformers. account for 10'd of new transformer sales (Howe 1993). The value of total V,$. orr rim its ( which includes all categories of transformers except electronic74tandard Industrial Classification 3612) has been more than the value of its exports during the past several years, accounting for -15 and 10%, respectively , of the total value of shipments in 1992 (IOC 1994b ). Canada and Mexico have been the major trading partners for the United S tates , and it is expected that the North... rican Free Trade Agreement will provide a big boost for the .U..S, transformer expoet .. market (DOC 1994b). Expected growth in the Mexican economy resulting from the passage of the North American Free Trade Agreement would stimulate the demand for electric _ ity in Mexico and hence increase

. the demand for tran sformer products . , _ .......,^..., _..,. . It is estimated ,1Q% of tl ►e pl liquid-immersed marke t serves lieA

®nutili sector, and most liquid -imme rsed .. __ gt rs in this M, t segment are -phase , pad-mounted and station types. (The use of _ the pole Pipe is declining , mainly owing to aesthetic concerns.) Conversely , more than .._of the total .dry-type market is in the nonutility ( sector. Total current annual , sales , volumesof liquid

- immersed and dry-type transformers in the 10 WA-2.5 . range are estimated to.be 1 1_milfion ,( 64,631 MVA) and 0.38 million , (28,336 A) units respectively

. In addition, about 1.4 million single

-phase , dry-type transformers in the 3 - to 5-kVA range are sold annually, of which 25

-30% are used for distribution transformer applications , Relative to the number of_manufacturers , the dry-type market is comparatively more volatile than the liquid-immersed market because manufacturing of dry-type transformers is less capital

- intensive and"has particularly low startup costs

. There are many dry-type manufacturers

- total numbers in the 10 WA- 2. 5 MVA range have been estimated anywhere from 200 to 400. However, only about 20 of these are. major dry-type transformer manufactarers ; most of the remaining manufacturers are only involved in either niche market segments (e.g., mining or railways ) or in transformer rewinding. The number of smaller size (<10 kVA), dry-type transformer

.manufacturers is large (i.e., 5 06-6000 ) in order to serve the numerous original equipment manufacturers , (QFMs). Dry-type transformers , >10 kVA are predominantly three

- phase compared with the single-phase dominance in the liquid-immersed transformer market

..Qpen wound and cast resin are the two major categories of dry- type transformers , the latter being more expensive and used primarily in harsh environments s>h as cement aril chemi „ cal plants and outdoor installations. Dry-type transformers gained a'much wider acceptance in the marketplace during the 1980s following the U S. Enylronme Pcotecdon Agency (EPA) ban on the manufacture of polychlorinated biphenyls (P CBs) in 1979.' . The distrbut ®n trapssforr market ge ne rally consists of transformers of 10 kVA-2.5 A, although nu me rous dry- fd <10kVA __._ classifled ^s disYribuei®n trsf® ri^i^rs (see Subsect . 3.2.2). Currently, no published disaggregated information is available on annual sales and shipments of distrtbutiontransfor rs. Tie mark data collected by the U.S. Department of Commerce (DQC.19944) provide only the aggre gate value of annual shipments; the data are disaggre gated neither by the kind of trans formers nor in terms of size and number of

3-1units. NEMA surveys the industry regularly to collect market information on distribution

transformers, including both liquid-immersed and dry-type. Several size (kilovolt-amperage) and voltage classes are considered under each type, and the liquid-immersed type also disaggregates further into pole, pad-mounted, subsurface, power, 'and secondary unit substation classes. The NEMA data do not reflect the entire industry, particularly when only 5% of dry-type distribution transformer manufacturers are members (Patterson 1994). The NEMA data currently represent 66% and 72% of the total dry-type and liquid-immersed'markets respectively (Hopkinson 1994). In the case of the liquid -immersed transformer market, the percentage of the total market represented by the NEMA data has continually decreased from 90% in 1980 to 72% in 1993 as some large non-NEMA manufacturers entered the market. Figures 3.1 and 3.2 show total annual shipments of distribution transformers in terms of size (megavolt-amperes) and number of units, respectively, for the period 1980-2030. The historical data in these figures are from NEMA and were updated to reflect the non-NEMA market share (as discussed previously); the exception is the cast resin dry-type market, for which historical data are based on Patterson (1994). Information on future years is based on ORNL projections. The future outlook for the distribution transformer 'industry is not expected to be different from that of the past decade. Based on current customer practices, the industry predicts an overall annual growth'rate of not more 2% (Patterson 1994; Schrieber 1994). Sales of .. . liquid-immersed utility distribution transformers depend. primarily on new housing starts, while gross private domestic investment provides a good indicator for the nonutility transformer market. Projections made here for the utility (i.e., liquid-iimnmersed) and the nonutility (i.e., open-wound dry-type, cast-resin dry-type, and liquid-i d) markets are based on these parameters. The recent trend of low demand for utility transformers, due to stagnant new residential construction and reduced utility growth, is expected to continue in the future. In addition, affordability and'demographic factors will cause new housing starts to grow more slowly than the overall economy (DOC 1994b; Christ '1994).'*Mi'ligi id =fmmersed utility transformer market is assumed in Figs. 3.1 and 3.2 to grow at an annual rate of 1%. The recovery

Pls. 3

. 1. Annual P 1 of di stri bution traDOEMMM by vol (10 kVA- 2.5 A), 1990-2030-

3-2vEM MWMVWOMDRY D sr c u tv'W Jrw ® uc urn w Fig. IL shi pments Amuml of i by number of uni ts ( 10 WA -25 IM-2030.

of the U.S . , ., u acturing sector is expected to result in a _. ,..rate demand for the nonutility transformer market 1 e ,U $ -Office ,of Management and budget predicts that low long-term interest rates (

particularly important for fixed business investment) will be sustained over the-rest of the 1990s and will result in a gross domestic product growth of 2.5-3%/year ( OMB 1994). Based on the historical data used here , annual growth rates during 1983

- 1993 for liquid-immersed and dry-type distribution transformers are estimated to be 1.1 and 6%/year respectively

. Thus , the assumed annual growth rates of 1 and 2

. 5% used here for theutility and nonutility tran sforme r mar kets , respectively , are conservatiye..compared with.the historical growth rates

. To forecast the number of units of liquid

- and dry-type transformers , it is also assumed that the average size of transformers will increase in both , cases annually by 0.5% (Fig. 3

. 2). The breakdown between the utility and nonutility liquid

- immersed transformers is based on the assumption that the nonutility share includes .( 1) 4% of the total single-phase, liquid

- immersed market and (2) 20% of the total three- phase, liquid

-immersed market (Austin 1994).


### 3.2 CATEGORIZATI ON B Y SIZE In the distribution

. transformer , l0-ICVA to 2.5

- MVA range, nearly all of the units are... manufactured by the 20 or so major manuf acturers . For <1 0 kVA (i.e., 0.25 WA-9 kVA), the number of manufacturers increases to about
. 5 in order to supply transformers to the numerousOEM s. These smaller size units are expected to be only

- 4% of the market based on capacity of sales in 2030

. An energy conservation policy that involved the 10 -kVA to 2.5 -Mi(A, range would affect 95% of the distribution transformer market A more detailed description of markets for the two size categories follows.

3-33.2.1 Distribution T rans form ers in the 10-kVA to 2.5-WA Range Table 3.1 shows the estimated annual shipments of liquid-immersed and dry-type distribution transformers for 1980-2030. As discussed earlier, forecast shipments (i.e., 1994-2030) of liquid-immersed and dry-type transformers shown in Figs. 3.1 and 3.2 are based on constant annual growth rates of 2.5 and 1.0%/year respectively. In the case of dry-type transformers, additional forecasts of shipments under an annual growth rate of 1.0% have also been made, as is shown in Table 3.1.. The annual sales volume of liquid

- i mmersed transformers has remained steady at -1 million units during the past two decades, as is shown in Fig. 3.2 and Table. 3.1. It is estimated that about 1.14 million units (or 64,631 A) or liquid-type transformers were sold during 1993. The liquid-immersed transformer market will increase to 1.18 and 1.33 million units by the years 2000 and 2020 respectively. The corresponding annual capacities to be sold during those years are forecasted to be 70,087 and 88,350 MVA respectively. Almost 1.41 million units (or 99,195 A) of liquid-immersed tran sformers will be sold in the year 2030. The market outlook for dry-type distribution transformers will grow substantially from its current level of 0.38 million units (or 28,336 _A) to 0.44 and 0.65 million units by the years 2000 and 2020, respectively, under the assumed annual growth rate of 2.5%/year. About 32,255 and 52 ,854 MVA, respectively , are forecast to be the corresponding annual capacity to be sold during those years. By the y2030 the annual sold capacity of dry-type transformers is projected to be 67,659 MVA (or 0.79 million units). The market share of open-wound and cast-resin dry-type transformers compared with the total capacity sold in 2030 will be 28 and 12% respectively. If the market growth rate of dry-type transformers is similar to that of liquid-immersed tran sformers (i.e., 1%/year), the total dry - market is forecasted to be less than 60% of the market estimated under the growth rate of 2.5%/year in 2030. About 0.46 million units (or 39,213 A) of dry-type distribution transformers will besold under the lower growth rate case* in the year 2030.

Table 3

. 1. ual shipments of butdon transf ormers (10 WA-2.5 A), 1980-2030 Liquid-irnmersed Dry-type 1.0%/year 2.5%/year 1.0%/year Units units Year MVA '000 units MVA ' (thousands) MVA (thousands) 1980 58,370 1,034 30,722 181 30,722 181 1985 70,613 1,131 17,920 213 17,920 213 1990 73,180 1,130 22,796 320 22,796 320 1995 66,145 1,148 28 ,509 394 27,681 382 2000 70,087 1,181 32,255 435 29,093 392 2005 74,264 1,215 , 36,494 490 30,577 402 2010 78,690 1,251 41,290 530 32,137 413 2015 83,380 1,289 46,716 .584 33,776 423 2020 88 ,350 1,327 52,854 645 _ _ 35,499 433 2025 616

93 1 367 800 59 711 37 310 444 , , , , 2030 99,195 1,410 67,659 786 39,213 455

3-43.2.2 Distribution Transformers <10 kVA

0 Generally, transformers under. 10. WA, are dry-type units although some liquid-immersed

units in this size range are produced. It is estimated that about 1.4 million dry-type units <10-kVA (with an. average of 1 kVA) were sold in 1993. These units are mostly single-phase units and are generally used by OEMs in machine tool applications. Distribution transformer applications in this size category usually average 3-5 kVA in capacity, and in 1993 they had a share of -400,000 units (equivalent to 1200 MVA) of the total market of 1.4 million units. The growth of this smaller size , dry-type distribution transformer market is assumed to be similar to that of the larger size (i.e., >10 kVA) market. Assuming an annual capacity growth rate of 2.5%, it is estimated that the capacity of this market will increase from 1200 lA in 1993 to 1426, 1826, and 2337 MVA by the years 2010, and 2020 respectively. In terms of number of units, the size of the lowerki1ov®le ampere , dry-type distribution transformer market is almost equal to that of the larger kilovolt-ampere market. It is projected that this marke.twill increase to 0.46.0.56; and 0.68 million units by years 2000, 2010, and 2020 respectively. Almost 0.83 million ,uni2s (or 2992 A) of lower kilovolt-ampere, dry-type distribution transformers will be sold in the year 2030..



### 3.3 TS U The structure of the distribution,transformer et, shown in Fig. 3.3, includes various market players and their interactions . The market delivery channel varies with the end user, particularly between utility and C& I customers . Once a transformer leaves the manuf_ s production plant, manufacturers ' representatives , OEMs, stocking distributors , agents, and electrical contractors play an important role in delivering transformers to end users. Factory-affiliated manuf acturers' , representatives

-- including agencies (usually used by small manuf acture rs) and salaried sales personnel from large manufacturers-are jut ermediaries that apt as the marketing arm for transformer manufacturers . They usually do not stock transformers and. are typically organized on a regional basis. These representatives act primarily as technical resources and brokers; all transformers are shipped directly from the manufacturer to the end user, or distributor. Stocking distributors are generally independent electric equipment sellers . that carry stock items , and their volume is. such that_they can obtain transformers directly from the factory or through manufa cturers' _representatives. The agents for end users mainly include either architect- engineers or engineering contractors who evaluate various transformer design options and make recommendations , for purchases but rarely procure the transformers themselves (doing so only i n the case of k

turnkey projects). The electrical contractor purchases transformers from the stocking distributors based on specifications developed by the agent or the contractor. More than of all utility transformer purchases are currently made directly from manufacturers ; technical specifications are written by the utilities themselves ., In,some

.. cases. (e.g., some municipalities and rural electrification authorities ) utilities buy transformers directly from distributors.: Electrical a®nitnctors purchase transformers for C&I custgmerg based on specifications written by agents or by the contractors themselves. Some heavy- industrial customers (e.g., General Motors Corporation) buy transformers directly from distributors based., on specifications developed by their in-house experts. For large turnkey projects for C&I customers , agents may purchase ftwdoormers. Any large-volume or custom-order.purchases (e.g., for the petrochemical or paper and pulp industry) are made directly from manufacturers. . v. , ,. - - Small-volume or stock.item purchases are not easily made directly from manufacturers these _ .. days. OEMs know exact transformer specifications and therefore usually buy from manufacturers



### 3-5ORNL-DWG VSM- 1 5M

USED TRANS FORM ERS OR REPAIR SHOPS

ALOWACTUFIER -DRY - VENTILATED -CAST -LIQUID :OIL SILICONE - R TEMP.'- MANUFACTURERS REPRESENTATIVE OEMs 

# 1

f I AGENTS FOR END USER r-WJ I (A&E OR CONTRACTOR)

G DISTRI STOC BUTOR ELECTRICAL

CONTRACTOR

(LARGE USER OR CUSTOI, ORIDER) --t END USER

INDUSTRIAL

AND

COMMERCIAL

UTILITIES
Mg. 3.3. Market delivery for distrffin tion trandwmers. Note: The most common route is marked by solid lines . O

EM = original equipment manufacturer ; A&E = architect and ent ' . directly. C&I customers buy OEM products either directly through OEMs or through agents or electrical contractors. Rather than being repaired, transformers with major damage are usually replaced. When repair does take place, it usually occurs either in repair shops or at the original manufacturer's (typically when failure occurs within the warranty period). The only units that are normally repaired are medium-voltage units. Utilities will frequently repair their own distribution transformers bec ause in man y cases repair costs less than disposal and replacement

. A recent ORNL study indicates that , on average, electric utilities are making reasonable decisions regarding the replacement or refurbishment of distribution transformers that are removed from service (Barnes et al. 1995). Most of the refurbishments occur on transformers that are <20 years old and have a significant amount of remaining life. The retirement age of transformers removed from service for a variety of reasons ranges from 14 to 35 years; the-average is -25 years. However, the average life of liquid-immersed transformers that remain in service is -30 years or more. C&I customers sometimes purchase used transformers from an electrical contractor who has removed them because they are no longer adequate for the original C&I accounts. Although all market participants play a role in expanding the market for energy-efficient transformers (i.e., those transformers purchased by utilities and nonutilities that consider energy cost in their purchasing decision), the most influential are individuals who are involved in writing technical specifications to purchase transformers. In cases where end users write their own technical specifications and buy transformers directly from manufacturers, lower loss transformers are usually purchased. More than 90% of utilities and some heavy industries (e.g., paper and pulp or petrochemicals) currently buy energy-efficient transformers. However, most C&I end users do not buy energy-efficient transformers. In these cases transformer requirements are specified either by an agent or by an electrical contractor who tries to minimize costs by buying cheaper transformers. These agents and contractors, not being the final users of the facilities and therefore not being those who pay electric bills, have little incentive toward energy



### 3-64 efficiency. C&I building owners usually do not pay electric bills either, since that is the responsibility of the tenant Still others. in the,market.(i.e., distributors, manufacturing representatives, and ®. who try to maximize profits by increasing sales volumes ) do not promote more expensive, energy-efficient transformers. OEMs, usually specify technical characteristics (e.g., voltage ....:... .... . regulation or exciting current) and are more interested in Underwriters Laboratories certification. Communications between OEMs and their customers seldom inv^glve disculssons of energy efficiency. In addition, these various market players lack the training and incentives to promote energy-efficient iransformep.-LLirently , the limited number of ayailable , ev„aluation tools are not widely used..to.facilatatecost justification and determineeAergy savings. EPA recently launched, the Energy Star Transformer Program in which electric utilities sign agreements to purchase cost-effective, high-efficiency transformersfor.thejr,distribution systems (Thigpen 1995). In addition, leading manufacturers of distribution transformers have committed to producing Energy Star transformers and marketing them to electric utilitiesA provides technical data and resources.to utilities to help them perform complicated benefit cost analyses of their transformer purchases. End user, de . _. . d is the most important issue in promoting an energy-efficient iransfforrr

sf g mIpr OLciency'is often overlooked

. by end users and_utility market. Distribution trap demand-side management (DSM) programs because even nm of-the-milt units,,a _ppear to be very efficient wlikkqempared with energy conversion , such. as, motors pr lighting

. For example, a good high-efficiency motor might have a full-load efficiency of 96% compared with a typical efficiency of 97% for a distribution transfornier.Yany end users,are currently unaware of the, economics of 1®wer gsst __M,foramers, as is evidenced by their purchasing practices, which are discussed indetagl in the fol4owing subsection Thus, in the order of their importance to ...... promoting distribution transformer energy efficiency-ranging from the most influential to the least

- the market players'are Cl! end

. users, utilities , OEMs , distributors , and manufacturers.__


### 3e4P, C.._._ .IIVGP._.C^'I^ ._._.. ,.__ The discussion of thedistribution transformer market structure in the previous subsection This illustrates how differentmarket players influence transformer purchase decision making subsection discusses five different types of purchasing practices used by these market players in the transformer mardcet . ^, These practices are first cost , TOC, band of equivalence (BOE), oversizing , and choice ofmdpding material

. The last two practices are the only ones not based on economics , but they play an important role in transformer purchase decision making for some end users. 

### 3A.I. Fhg Purchases , of transforms ape often based on she first cost . ( without any consideration of - long

- term economics) when transformer evaluation and purchase decisions are not made by the end-user . This is, particularly true where agents , or electrical, contractors make purchase, decisions on the basis of, temperature rise.and

. low flit cost forI_ end-users buying dry-type, pad-mounted transformers

..These agents or contractors may have little . incentive to _takeinto . consideration any economic factors first cost. End-user concerns about higher first costs discourage OEMs and.contractors

_ from offering or recommending the more expensive , efficient options to customers who do not specifically request them

. Transformer purchases are _,. _as,capital expenditures for equipment with an expected life of 30 -40 years;

3-7however, lack of capital causes most small and midsized end-users to favor the short-term

purchasing criteria (i.e., the first cost) with short payback periods (i.e., 1-3 years). In addition, these users are not always aware of, and in some cases are uncertain about, the costs and benefits of using energy-efficient transformers. 

### 3.4.2 Total Life-Cycle Ownin In recent years the inc rease s in capital and operating costs for power plants , difficulties in siting new facilities, and concerns for the environment have forced utilities to evaluate energy efficiency. Both efficiency in generation and distribution and efficiency by utility customers (through DSM programs) have developed. Utilities invest in DSM programs to effect changes in their system load curve, typically improving load factor or reducing demand in order to avoid or to delay large investments in new generation facilities

. Technical measures in some DSM programs include high-efficiency lighting, bansformers, motors and cooling systems, or improved insulation and building envelopes. These concerns for energy efficiency have been transl ated by utilities into loss evaluations for their transformer and equipment purchases, expressed as dollars per kilowatt

- hour saved . The higher the loss evaluation , the more the premium on minimizing energy losses

. Recent developments such as deregulation of electric utilities will er boost the procurement of energy-efficient transformers. Deregulation will lead to vertical inte gration of the electric utility industry , and there will be more incentive than before to maintain system efficiency (particularly distribution and transmission) to be rate competitive. It tends to be a less attractive alternative for procurement of energy

- efficient transformers for utilities when payback due to efficiency is a number of years in the future. Since the early to mid-1980s, U.S. electric utilities have typically purchased distribution transformers using EEI ' s loss evaluation methodology to arrive at TOC2 for comparing and selecting transformer bids from among suppliers (EEI 1981 ). TOC is a capitalized value, making the first cost of the transformer comparable to the lifetime energy costs

. The "loss evaluation rates " (i.e., the rates that a utility is willing to pay per watt reduction in rated core and conductor losses) that are needed to calculate TOC are currently supplied by most electric utility purchasers after evaluating the specific application situation (e.g., duty cycle, cost of capital, and expected life ). These 'loss values usually range from $2 to $4 /W for core (no-load) losses and from $0.50 to $1.50/W for conductor (load) losses. Most pole- and pad-mounted transformers are currently loss-evaluated, while almost no dry-type transformers are evaluated

. In some cases , utilities also offer rebates to customers for undertaking loss evaluations and then monetary assistance to "buy down" a more expensive, more energy-efficient transformer where it meets utility savings criteria

. For example , Bonneville Power Administration offers a one-time incentive of up to $0.15/kWh saved in the first year of operation to its utility and industrial customers (Howe 1993 ). Unfortunately , these programs rarely extend to the smaller distribution transformers that are common in C&I facilities. Thus, most commercial , institutional , and light

- duty industrial end users , for whom a transformer purchase decision is more peripheral to their business than it is for a utility , do not use loss evaluations such asTOC , which require extensive analysis and the input of many variables. Because of tightening in the availability of capital budgets these days, there is a growing trend even among utilities to use either some form of TOC ( see Subsect . 3.4.3) or first-cost criteria for making liquid-filled transformer purchase decisions. The move away from the T OC purchasing criterion results in the selection of a less efficient transformer and hence reduces the energy conservation potential

. A continuous improvement in the efficiency of liquid transformers (see Figs

. 1.1 and 1.2) over the years could be attributed to a large extent to the use of the TOC



### 3-8purchasing criterion by utilities. Estimates of the.potential energy that could be saved if distribution transformers were more efficient using the TOC approach are discussed in detail in

B Sect. 4.

3.4,3 Band of Equivalence Many utilities using the TOC approach also apply a BOE in the. selection process

. This is used to

. compensate for uncertainties in loss evaluation factor assumptions , such as inflation, interest rates, and fuel costs , while making the final selection among transformer offerings from several suppliers

. Since each capitalized present

- value

- dollar

. cost of losses is equal to a dollar of first cost in the TOC formula, BOE broadly considers all transfo rmers within a band of TOC-typically Ito 3% of the lowest TOC offering-as equal in TOC

.. The lowest price candidate is then selected as the winner from those pwittinthe , bandof equivalent " TOC. The BOE practice is normally applied in one direction ( i.e., to lower the efficiency ), and hence it typically results in the selection of a less , efficient transformer than would have been purchased if a rigid lowest TOC -criterion were used

. As results from each bid cycle provrde a basis or`" reference for the next bid by each supplier, TOC and losses get compounded over time. The approach of selecting the lowest TOC transfo rme r is known in the utility and transformer industries as a "hard evaluation " method of purchasing transformers

. There is a need to develop a better method ( other than BOE ) to incorporate uncertainty into the TOC selection process. A minimum efficiency criterion may be one of the ways to promote purchases of more efficient transformers. 3.4.4 Oversizing It is not yet a common practice in the-industry (particularly in the C&I sector) to examine the estimated load and duty cycle of each transformer, the resulting 11R conductor loss, and the impact of this loss on the cost of operation before purchasing transformers Transformers are..U generally oversized in order to provide reliability under future anticipated loads, better motor performance, longer life, and lower load losses A ,recent ORNL survey of local C&I establishments indicates their annual load factors to be in the 04-0 ? range (median around 059) for commercial users and 0.54,8 (median around 0.64) for industrial users.3 Low-voltage transformers are comparatively underloaded at -35%. A study by Williams, Duckett, and LaVallette (1990) also indicates that currently 33% of transformers are pnderloaded_(having less than 60% of normal thermal capacity) because of low usage and that 85% of the undeerloaded transformers occur in C&I applications. Annual operating costs of transformers depend on load losses and, no-load losses, where load losses are a function of the percentage of time the transformers were, operated at full load as well as at different loads during the year. Reducing the number of underloaded transformers would minimize a company ' s capital investment i n transformers but not necessarily reduce losses due to improper loading. This can be accomplished by initially sizing the transformers correctly and by replacing grossly underloaded transformers with, smaller units.' 3,4.S Choice of Winding Material (Aluminum vs Copper) Some end users purchase transformers on the basis of type of winding material. Copper-wound transformers may be preferred over aluminum-wound ones ause they are assumed to provide better efficiency and reliability. This may be due in part to .(1) a perception relating to reliability problems rn alununum house wiring as well as (2) the observation that

3-9Patterson , W. Oct. 11, 1994. ABB Power T&D Company, Raleigh, INC., personal communication to Sujit Das, Martin Marietta Energy Systems , Oak Ridge Natl. Lab. Schrieber, R. Sept. 25, 1994. ABB Power T&D Company, Jefferson City, Mo., personal communication to Sujit Das, Martin Marietta Energy Systems , Oak Ridge Natl. Lab. Thigpen, S. R. May 23, 1995. Atmospheric Pollution Prevention Division, U.S. Environmental Protection Agency, Washington , D.C., personal communication to Sujit Das, Lockheed Martin Energy Systems, Oak Ridge Natl. Lab. Williams, C. W., Duckett, D. A., and LaVallette, V. K. May 17,1990. " An Econometric and Thermal Model for Three

- Phase Transformer Loading : Sizing Transformers for Commercial Customers ," paper presented to the Edison Electric Institute T&D Committee, Minneapolis, Minn.



### NOTES 1. PCBs are nonflammable liquids once used as insulating fluids in transformers ins talled in buildings

. No truly nonfl ammable liquid replacement for PCBs has been developed, and following the ban on the maatufacture

_af PCAs, dry-type transformers were chosen increasingly for this market segment. 2. TOC is defined as the total of transformer first price plus cost of future transformer losses (i.e., core and conductor ) discounted to present value. 3. Annual load factor = annual energy consumption (k )/[annual peak demand (kW) x 87601. 4. To determine the amount of load as a percentage of full load so that maximum efficiency can be obtained , the following equation is used: (NLL/LL) in = % RL/100, where NLL = no-load loss (watts ), LL = load loss (watts ), and RL = rated load (Morgan 1992).

### 4. ENERGY, CONWRVATIQN ALTERNATIVES

6 4.1 OVER'

Developed

in thiuection are. estimates of the potential energy that could be savedif distribution transformers were, more efficient , First , the basis for designing a cost effective transformer is discussed Data fromua survey of transformer manufacturers were used do define conservation cases based on maximum core and coil losses Estimates of savings for each case are se at cou c he achieved then given by comparing efficiencies for,existiiig transformers with ._o using cost

- effective designs.
4.2 M(INEHUM TTOT AL, O WNING COST TRANSF ORME R DESIGN C RITERI ON Utilities typically evaluate new transformers through a loss formula. T?ie loss formula indicates how a specific utility estimates the capitalized value of no-load and load fosses for new transformers over ,the service life.' For instance , if values were $ 3 00/W of rated no

- load loss and $1.00/W of rated load , loss,}then a transformwr tIat had rated losses of 1 (no-lod) and 280 W (load), would have a capitalized value of losses for the entire study period of $3 (no-load) and $280 (load), or $ 580 total

. If it is_as~sumed that the initial cost of a new transformer is $500 , then the . _.. . of the

_ fo rover the 30-year study period would, be $1080 (i.e., $580 + $500 ). Therefore,



### W

T'OC=NLLxA+LLXB_+C where TO total owning cost, l`tLL = no- load loss in watts, A = capitalized cost per rated watt ..ofNI L (this is termed the A factor), LL = load loss

.. n wattsatshe transf o rmer ' s rated load, _ ry B = capitalized cost per rated watt ofLL (this is, termed, the B factor), C = the initial

. cost
.. of the transformer including transportation , sales taxes,

and other costs to prepare it for service The per watt of core ,loss. ya_lue Is is typically called the A factor ; the per watt ofcoil

_ loss ,value, the B factor. While both ,A aniB factors reflect the capitalized cost of losses , they differ in their rates for two main reasons First, a watt of core loss represents a continuous , loss that occurs whenever a transformer , is energized , which is normally 100% of the time for most distribution , , transformers

. This

. cgntuipous loss of energy increases the cost

.per rated watt of core loss. compared with a rated watt of coilloss, which occurs only while power is drawn through the transformer . _Tlie. coil loss is roughly proportional to the square of the transformer Toad with tlic rated loss occurring at full , load. Iviast transformers ogerate at less than full load for most of the. time and may have extended operation , such as at night , at near zero load . The, second reason for,..

inr for the A and B factors is the cost of energy assoc iated with the, losses;, ., , the diff eren Load losses

. W, proportionally higher during peak periods when theper unit cost of producing electricity is relatively high. In general , there are usually much higher cumulative energy losses per unit time associated with a rated watt of no-load loss, and this more than balances the usually higher rate of costs

4-1associated with load losses. As a rule of thumb, the capitalized value of no-load and load losses

for utilities is often assumed to be $3 and $1/W respectively. The results of a recent survey of 90 large utilities indicated (1) an average no-load value of $3.43 (A factor) with a standard deviation of $1.84 and (2) an average load value (B factor) of $1.09 (Powers 1994) with a standard deviation of $0.90. Of the 90 utilities, 6 were publicly owned. The survey was for <100-kVA, single-phase, liquid-immersed transformers. Some utilities have different B factors for larger transformers; these B factors tend to be higher because they tend to serve customers that utilize transformers at higher capacity factors. In an ORNL study of transformer replacement policy, a national average A value of $3.53 and a B value of $1.44 were used (Barnes et al. 1995). For this study, two pairs of values were used to capture the effect of variations in transformer loads on the value of load losses. The value of losses for transformers <50 kVA was assumed to be $3.50 for no-load and $0.75 for load losses. The value of losses for 50 kVA and larger transformers was assumed to be $3.50 per rated watt for no-load and $2.25 per rated watt for load losses. (Appendix B presents the rationale for selecting these values.)



### 403 COST-EFFECTIVE TRANSF ORMER DESI GNS Much of the data on losses associated with cost-effective transformer designs used in this study are from a survey of transformer manufacturers, called the NEMA- ORNL survey,'- developed by ORNL and sent by NEMA to its members. Several non-NEMA M A manufacturers also submitted data. Utilities usually request that manufacturers submit bids fbr the 'lowest TOC. transformer that they can design. Utilities specify the transformer features and their A and B factors. The NEMA-ORNL survey took this approach. It included what were believed to be the most common features that would be requested for each size and type of transformer. Transformer manufacturers were asked to submit the losses and price for the lowest TOC transformer they could design. The value of losses was determined by the A and B values presented above. Appendix C reproduces the questionnaire that was used in the survey. It requests that manufacturers reveal the transformer design that has the lowest TOC in terms of core losses, coil losses at rated load , and transformer price. As is indicated in Appendix C, the survey requested losses and prices for three separate designs. The $0/$0 combination of A and B values is the design for a nonevaluated transformer. Most transformers that are purchased by nonutilities, including most dry-type transformers, are not evaluated. In the $0/$0 design, only the first cost is considered, and the price of the transformer is taken to be the TOC (i.e., the value of losses is not included in the purchase decision). Not considering the value of losses results in selecting transformer designs that have much higher life-cycle costs. This study considers conservation policies based on incorporating the value of losses into the transformer design and purchase decisions. A change in existing purchasing practices could result in saving both life-cycle costs and energy. Therefore, the $0/$0 design was requested in the survey to help establish a baseline efficiency. The transformer types surveyed included six different liquid-immersed and six dry-type transformers. The liquid type included single-phase,' 25- and 50-kVA pole-mounted transformers and a 50-kVA pad-mounted transformer. The other liquid-type, pad-mounted transformers were three-phase transformers of 150, 750, and 2000 kVA. The six dry-type transformers included 1- and 10-kVA single-phase sizes and 45-,' 1500-,'20 0-, and 2500-kVA three-phase sizes. Clearly, not all sizes and types of transformers are present in the survey. Appendix D discusses the method used to relate the limited number of sizes and types in the survey to the various types and sizes of transformers that are purchased.

4-2The actual data for the

. survey results are proprietary and cannot be reported
. There were 216 transformer designs submitted for 12 different types of transformers. Each type had at least three designs for each
. of the three Arnd

_ B_eotnbinataons

. The liquid

- immersed , 25-kVA pole, 50-kVA pole, and 50-kVA pad each had

. eight designs for each of the three A and B combinations. 6 

### 4.4 E LA .._G .:. GFeENERGY SA VINGS

Six conservation cases have been developed (Table 4.1), and energy savings for these cases have been estimated. These cases are defined by transformers that meet maximum rated loss criteria. The energy losses (i.e., energy consumed by the transformers) for each conservation case were subtracted from energy losses for the. base case , to provide. an estimate of savings. The base case defines energy use for existing transformer purchasing practices. The base case parameters are presented in Table 4.2. 4.4.1 B 

### C The limited number of transformers in.the survey were selected to represent the range of typical types and sizes of transfonners
. recently sold

. Losses for the base case were estimated by the weighted ave rage of losses for the evaluated and the nonevaluated designs from survey information. The percent of evaluated transformers was developed from informati on provided by tran sformer manufacturers . Appendix D provides the details on how this was done.. 

### The base case noneval uated transformers were ass med

. to have the average losses that were reported for the three lowest priced transformers for the $O /$0 evaluation in the NEMA-ORNL,

... survey. It was assumed that the base case evaluated transformers have the same losses as transformers , that have been rsecently purchased by utilities

. These losses were

_ calculated from the average no - load and load loss ratings reported in the EEI-ORNI survey Appendix D details the approach used for making base case loss assumptions. 

### a2 Co n rvatioh_ ...._..._.. The conservation ,cases have beedefined from the information reported in the NEl i-0RNL. survey or additional information collected from transformer manufacturers. The` NEMA-ORNL survey requested lowest TOC transformerdesigns for three pairs of A and B values

. One pair of A and. B: values,was $O/$ 0, indicating nonevaluated transformer designs. With Table 4.1. Description of alternative cases Case .

Average losses Average losses of the three lowest IPC designs High-efficiency High -efficiency designs 2-year payback Efficiency improvement that corresponds to approximately a 2-year payback of the increased capital investment Basis of losses. Base Current purchasing practice Low TOC Losses from lowest TOC design Median TOC Losses front median TOG design

OAll conservation cases are derived from_ttansformerdesigns submitted to Oak Ridge National'Laboratory by the National Electric. ManufacwrersAssociation or,-„ directly by manufacturers except the 2-year payback case that was provided by a transformer manufa}ttrer. TOC-total. osyning cost.

4-3Table 4.2. Base case t ransfo rmer loss assumptions Size Rated NLL° Rated LL° Percent Effective' (kVA) Type ( W) (W) evaluated b capacity facto' Liquid 25 Pole 62 333 85 0.2 50 Pole 106 549 85 0.5 50 Pad 104 569 85 0.5 150 Pad 320 1,702 85 0.5 750 Pad 1,061 6,267 85 0.5 2000 Pad 2,543 Dry 15,108 60 0.5

I Small 24 83 1 0.2 10 Small 131 176 1 0.2 45 Lighting 375 1,792 1 0.2 1500 Epoxy cast 5,273 13,290 5 0.5 2000 Load center 6,383 22,362 15 0.5 2500 Epoxy cast 7,554 18,517 .15 0.5

°NLL = no-load losses; LL = load losses.

' Assumed from discussions with industry sources.

` See Subsect

. 2.3 for a definition of effective capacity factor. the exception of the "2-year payback case," the conservation cases were defined from the survey responses for A/

R values of $3.50/$2:2.5 and $3.50!$0.75. These two pair of A/B values were selected to represent national averages in valuing transformer losses (see Appendix B). This low TOC criterion ensures that the designs are cost-effective for the average end user. The bases for the five conservation cases are listed in Table 4.1. These conservation cases define maximum load and no

- load losses for all new transformers

. To estimate total annual losses, the average transformer losses consistent with the maximum load and no

- load loss values were multiplied by projected transformer sales

. To'estimate total savings, the energy losses associated with the conservation cases were subtracted from those for the base case. The 2-year payback case w as based on efficiency improvement that could be justified by recovering the additional capital cost of a more efficient transformer over approximately a 2-year time frame. This case was provided to ORNL by one transformer manufacturer ; it should be recognized that similar cases developed by other manufacturers could result in different design efficiencies owing to differences in factors such as the base case assumptions and price. The rationale for this case is that it would appeal .to end users that . have a very short time horizon in which to recover any additional capital investment . This 2-year payback case does not recover all the energy savings that are economical

. Rather, it skims off only the most profitable part of energy savings

. For instance , this case would result in almost no savings for transformers that are purchased by utilities because most of the least efficient utility-purchased transformers have efficiencies that already meet this 2-year payback case . Table 4. 3 compares the minimum efficiencies required by the 2-year payback case with the efficiencies reported in a survey of transformers that have been recently purchased by utilities. As Table 4.3 shows, these minimum efficiencies would affect very few utility purchasing practices . Also, they would have a minimal effect for those transformer purchases not meeting the minimum efficiency requirements for liquid-type transformers.

4-4Table 4.3. Minimum efficiency for liquid -type transformers based on 2-year payback compared with efficiencies of reptly purchased t o cls_ Average for observations 2-year with efficiencies

below 2-year Observations Percent not Transformer size payback payback Observations not meeting meeting (kVA), type, and efficiency' proposal ' in 2-year 2-year number of phases ("') (%) survey payback payback 10, pole, single-phase 98.40...: 98.33 38 4 11^ 15, pole, single-phase 98.50 98.43 33 3 9 25, pole, single-phase 98.70_ 98.67 54 3 6 37.5, pole, single-phase 98.80 NA 17 0 50, pole, single-phase 98.90 NA 

## 52 0 

## 0 50, pad, single-phase 98.90 98.66 51 2 4 75, pad , single-phase 99.00 98.83 36 

## 2 6 167, pad , single-phase 99.20 99.15 39 6 15 225, pad , three-phase 99.00 98.84 28 1 4 500, pad, three- phase 99.20 99.07 50 7 14 1 000, pad, three-phase 99.30 99.27 45 3 7

''All at 50 % effective capacity factor. 'a

The "low TOC case " is based on the design from the NEMA-ORNL
. survey with the lowest TOC for each type of transformer

. The "median TOC,case " is, based on the design that represents the median TOC 4from submitted designs

. Because the amorphous

- core transformers had significantly different losses , they were excluded from selection for these two,cases. The "average losses case " is based on.averaging the losses for the designs with the three lowest TOCs, and if high

- efficiency designs qualified as one of the th ree lowest TOCs , they were included in these averages

. A final conservation case was defined as the "high-efficiency case ." This case included the lowest TOC amorphous

- core transformer for each transformer in the survey for which at least one high

- efficiency design was submitted
. No amorphous designs were submitted for the six dry-type transformers and.for

_ the.2000

-kVAliquid

-type transformer

. For transformer categories where no amorphous

- core designs were submitted , the most efficient of the nonamorphous designs was selected. The present distribution transformer industry utilizes • a number of competing technologies. Market forces play an important role in the determination of the technologies that are appropriate to achieve specific design goals

. It is not the intent of this study to restrict transformer designs to a particular technology

. The rationale for excluding the amorphous

- core transformers in the low and median TOC options was to develop moderate high

- efficiency cases that do not depend on a particular technology. For the A and B factors used to develop the low and median TOCc ases, the amorphous-core designs submitted to ORNL tendedto beTOC competitive
. Therefore, if a national energy conservation policy was based on either the low or median TOC_option, amorphous-core technology would not be excluded in the low TOC purchase decision process. The average losses case may be more representative than the other cases for

. estirnating energy savings for transformers purchased under a cost

- effective criterion such as lowest TOC This-case represents in some measure the; random nature of cost

- effective transformer designs. In general, there can be significant divergence in losses and capital costs for equally cost

- effective



### 4-5transformers. Because it incorporates several designs, the average losses case may be a better

representation of the diversity in cost-effective designs than the other cases. It may be more representative of the real world than the cases that are based on selecting a single design. It should be reiterated that the transformer losses used to represent the average losses case do not represent the losses of a specific transformer design. Rather, they represent an average of the losses of the three lowest TOC transformers submitted for each category in the survey. To understand the survey results in the context of cost-effectiveness, all the conservation cases based on the survey designs should be considered. The maximum. loss values used to calculate energy consumption reflect specific designs for the low TOC case, the median TOC
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