3Milil

ORNL-6647

UZ= 1'1- 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)

 EE-RM/STD-00-550 COMMENT 03MM
ORNLEnergy Division

DETERMINATION ANALYSIS OF ENERGY CONSERVATION

STANDARDS 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

 EE-RM/STD-00-550 COMMENT 03MM
CO

LIST OF FIGURES .......

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

REFERENCES ................... ...... ... ...:4.. - . 1-5

CHARACTERIZATION 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 TRANSFORMERMARKET .... ........... 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 First 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) ............. 3-9

 EE-RM/STD-00-550 COMMENT 03MM
REFERENCES ............... 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 ESTIMATED 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 MANUFACTURERS ................................. 5-1

5.1.1 The Silicon-Core Material Market .............. ... ... 5-1

5.1.2 The Amorphous-Core material market .................... 5-2

5.1.3 The Copper and Aluminum Industries .................... 5-2

5.1.4 Distribution Transformer blanufacturers ................... 5-3

5.2 USERS ........................................ 5-4

REFERENCES ...................................... 5-6

6. CONCLUSIONS ...................................... 6-i

6.1 ENERGY SAVINGS AND COST S ............... 6-1

6.2 STAKEHOLDER IMPACTS ........................ 6-1

6.3 ECONOMIC JUSTIFICATION AND FEASIBILITY ............... 6-2

Appendix A: DISTRIBUTION TRANSFORMER 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

 EE-RM/STD-00-550 COMMENT 03MM
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 transformer efficiencies over the years for 75-kVA,

three-phase units ........... ..... ............. 1-3

2.1 Major internal elements of a transformer ........................ -2-2

2.2 Typical initial magnetization curve and typical hysteresis curve for

ferromagnetic material .............. .................... 2-5

2.3 Surface of cost vs losses for a typical25-kVA distribution transformer ........ 2-7

2.4 Typical 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

v

 EE-RM/STD-00-550 COMMENT 03MM
4.5 Cumulative quads ( 1015 Btu) of primary energy savings from 2000

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 difference

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

5.2 Change in payback period as functions of initial cost difference and

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

 EE-RM/STD-00-550 COMMENT 03MM
LIST OF TABLES

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 transformers . ........... 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

vii

 EE-RM/STD-00-550 COMMENT 03MM
D.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 transformers using 2 of 11 sizes ...................... D-9

 EE-RM/STD-00-550 COMMENT 03MM
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

 EE-RM/STD-00-550 COMMENT 03MM
 EE-RM/STD-00-550 COMMENT 03MM x
ACKNOWLEDGMENT'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 Manufacturers 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 Patterson, and Dorman Whitley of Asea Brown Boveri, Inc.; Don Kline, 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 ERMCO; Ed

Smith of Central 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 thanks 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
 EE-RM/STD-00-550 COMMENT 03MM xii
FOREWORD

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 lamps and distribution transformers for which the Secretary

makes a determination that energy conservation standards would be technologically

feasible and economically justified, 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 requirements under

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

transformers as required by par. (a)(1) above. The potential energy savings presented in this

document are preliminary estimates appropriate for a determination study. Subsequent studies on

this topic will involve more exact, detailed analysis on the effects of energy conservation

standards for distribution transformers.

xiil
 EE-RM/STD-00-550 COMMENT 03MM xiv
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
 EE-RM/STD-00-550 COMMENT 03MM xvi
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 theEnergy 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 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 material, 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 chain of electricalpower 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. Manycommercial 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 distribution 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

transformer 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 consumed by the units. These "nonevaluated" transformers may have -50% more

losses than utility transformers., The imam efficiencies of liquid-immersed distribution

xvii
Table 1. Characteristics of distribution tr . o . _ typically used in the United States

Transformer Phase Primary voltage Secondary voltage Capacities

type (kV) (V) (kVA)

Liquid-immersed 1 35 and below 600 and 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.

transformers 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 transformers,

although fewer in number, are less efficient and are estimated to consume an additional 80 billion

kWh of electric energy on the customer side of the electric meter. New transformers purchased

annually can be expected to consume -4.6 billion k ; thus, the potential for saving energy with

more efficient transformers could significant (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 conservation options were analyzed, the results of

..txNN-vain

1985 1 1975 1 9

YEM

Fig. 1. Distribution transformer efflciencks 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

xviii
which 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 lossesbut 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.

THE DISTRIBUTION _ . _ 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)

xix
in 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 purchased. 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

xx
Table 2. Energy savings for a conservation case based 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 2006 2009 2012 2015 2018 2021

YEAR

2024

ORNI-DWG 95-I609

2027 2030

Fig. 2. Cumulative prinuwy energy savings from 2000 to 2030 for a conservation 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.

CONCLUSIONS

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

xxi
to 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
.ENTRODUCTION

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 (120-600 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

1-1
100

m

m

95

ORNL4DM 95.1717

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

FORMER OF MANUFACTURE

Fig. Effleiency improved with .time for a VA, liquid-filled distri bution trandormer.

are purchased on a lowest first-cost basis without evaluating the cost of the energy consumed by

the units. These "nonevaluated" transformers may have 50% more losses than utility

formers. The maximum 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.

Canada 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

customer side of the electric meter. Small 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 energy 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

expected to be different from that of the past decade. 7he liquid-immersed utility transformer

1-2
1950 1955' 1960' V966 1970 9975 4980 4985 1990 9995

Fig. la Distribution innsformer efficiencies over the years for 75-kVA, tin-a-a phase units. Sources: Barnes

et al. 1995. Feasibility of Replacing or Upgrading Utility Distribution T rs During Routine Maintenance,

0RNL- 1 Martin Marietta Energy Systems, 081c "ltidg Nail:I.ab, and tcaasformermanufacturers' data. "b "' - ,

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 transformer market 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-immersed

` 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:

1-3
Database 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

transformer loading factors was obtained from discussions with transformer manufacturers

and utilities and limited surveys of commercial and industrial users.

® Energy Conservation Options. Technically feasible energy conservation (low-loss) options

for distribution trarisformers were based on information provided by NEMA and individual

:transformer manufacturers. Cases with relatively low life-cycle costs were selected by the

Oak Ridge National 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 transformer 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
REFERENCES

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 in 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.trade-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 addresses those Mirisformers that perform the final transformation from utility

distribution voltages (typically 4-35 kV) to final utilization voltages (600 V and below); hence,

the designation "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 summarized 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 commercial, industrial, 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

loading increases the importance of losses at low-load levels, since energizing current must

always be oresent, even without load.

2-1
2.1.1 Principles of Transformer 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 in 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

SECONDARY VMDINQ

(RESR:rANcE.. Rp)

Mg. 2.1. Major Internal 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

2-2
be 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 current

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 winding (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 determnes,whether

sf . r is a, dry or liquid-immersed type and its intended,operating temperature.

Furthermore, the amount ofins .._'on required is dependent upon both steady-state and transient

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 windings is

surrounded by core material, as is shown in Fig. 2.1..There is no inherent difference in cost or

performance betgveen.the.two designs, and the design chosen is somewhat dependent upon the

setup of the manufacturing facility.

2.1.2 Major Transformer 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 No-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 is core loss, which is 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 _„ ---- There is alsjope inverse.dependence on core, temperature.

Hysteresis losses in transformer core materials occur because the core materials resist r a

realignment of the magnetic domains 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 dependent upon flux density, which is, in turn, dependent upon

terminal 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.

2-3
This 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 because 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 operating 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

separated 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 labor costs. Similarly, decreasing 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 increased by alloying iron and

silicon and cold-rolling the materials 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 turns and/or longer winding length); this generally increases core

cost and load losses.

All amorphous-core transfornvers, 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 drawbacks 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

2-4
ORNL-DING 95M-10052

MAGNETIC FIELD INTENSITY (H (Afm))

C305M-10081

Fig. 2.2. Typical iniVal gnetization a (top) and typical hystersis curve (bottom) for ferromagnedc

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 illustrated 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-TypeTransformers

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

2-6
ORNL-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 0.2d 0.40. 0.58 0.72 0.88 1.04

PER UNI'T' LOAD EPLATE RATING.=1.0)

Fig. 2A Typical a

1.20

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

2-7
500

450

400

350

300

250

200

150

100

0

0

PER UNIT LOAD (NAMEPLATE TING =1.0)

Fig. 2.5. Typical total losses functions of load, Indian ofrelative load and no-load lossm

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 transformers, there are a large number of manufacturers, and

turnover is high. Dry-type transformers are limited to operating voltages of less than 46 kV.

2.2 TRANSFORMER EVALUATION AND LOSS 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.

2-8
Typical 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 insulation

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 same 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).

2-9
Table 2.2. Loss reduction alternatives

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

® Decrease current path length by

(1) Decreasing core CSA Higher Lower Lower

(2) Increasing volts per turn Higher Lower Higher

'Amorphous-core materials would result in higher load losses.

bCSA = cross-sectional area.

Can dry-transformer technology provide transformers with lower losses at reasonable costs?

As is indicated in the previous paragraph, all types of dry trasisforiners 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

2-10
upon 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 therefore 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 annual 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 assumed national

average. Specific forms of the equation for co rcialand industrial applications will require

careful study.

A subject of major concern,to unlit gs4is, projected equipment life. For distribution,.

transfbrrners a.io.. dii g guide has bee ., n established. (ANSI and IEEE 1981.). This guide provides a

method for determining the insulation's hottest spot temperature as a function 9f load and a

relationship between temperature 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 sizee. 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 voltage-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

temperature 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. "Depreciation 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, Newnes-Butterworths,

London.

NOTES

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 xB.. 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. Because 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 capacity.

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 in the distribution transformer market was estimated to be -6$1.5 billion in 1992,

coming from more than 230 companies having annual shipmentsof 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 States, 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

transformer products

. , _ .......,^..., _..,. .

It is estimated ,1Q% of tl►e pl liquid-immersed market serves lieA®nutili sector, and

most liquid-immersed.. __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., 506-6000) 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 (PCBs) in 1979.' .

The distrbut ®n trapssforr market generally consists of transformers of 10 kVA-2.5 A,

although numerous 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 markdata collected by the U.S.

Department of Commerce (DQC.19944) provide only the aggregate value of annual shipments;

the data are disaggregated neither by the kind of transformers nor in terms of size and number of

3-1
units. 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 distribution traDOEMMM by vol (10 kVA-2.5 A), 1990-2030-

3-2
vEM

MWMVWOMDRY D sr c u tv'WJrw ® uc urn w

Fig. IL Amuml shipments of i by number of units (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 transformer markets, 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 CATEGORIZATION BY 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 manufacturers. For <10 kVA (i.e., 0.25 WA-9 kVA), the

number of manufacturers increases to about. 5 in order to supply transformers to the numerousOEMs. 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.

3-3
3.2.1 Distribution Transformers 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-immersed 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 transformers 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 transformers (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 transformers (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 93,616 1,367 59,800 711 37,310 444

2030 99,195 1,410 67,659 786 39,213 455

3-4
3.2.2 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 manufacturers' ,representatives--including agencies (usually used by small

manufacturers) 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 in 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

3-5
ORNL-DWG VSM-1 5M

USED

TRANSFORMERS

OR

REPAIR

SHOPS

ALOWACTUFIER

-DRY

- VENTILATED

-CAST

-LIQUID

:OIL

SILICONE

- R TEMP.'-

MANUFACTURERS

REPRESENTATIVE

OEMs 1

f I AGENTS FOR END USER

I (A&E OR CONTRACTOR) r-WJ

G

DISTRI

STOC

BUTOR ELECTRICAL

CONTRACTOR

(LARGE USER OR CUSTOI,ORIDER)

--t

END USER

INDUSTRIAL

AND

COMMERCIAL

UTILITIES

Mg. 3.3. Market delivery for distrffintion trandwmers. Note: The most common route is marked by

solid lines. OEM = 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 because in many 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

3-6
4

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-efficientiransformep.-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

market. Distribution trapsfgmIpr OLciency'is often overlooked . by end users and_utility

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'areCl! 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 differenttypes 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;

3-7
however, 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 reases 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

translated 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 integration 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 TOC

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

3-8
purchasing 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 rmer 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 in 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

3-9
Patterson, 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 installed in

buildings. No truly nonflammable 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'

Developedin 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

then given by comparing efficiencies for,existiiig transformers with ._o se at cou c he achieved

using cost-effective designs.

4.2 M(INEHUM TTOTAL, OWNING COST TRANSFORMER DESIGN CRITERION

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 transformer's rated load, _ ry

B = capitalized cost per rated watt ofLL (thisis, 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 Isis 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, secondreason for,..

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

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

4-1
associated 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 TRANSFORMER DESIGNS

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-NEMAM 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.

4-2
The 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 SAVINGS

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 average of losses for the evaluated and the nonevaluated designs from survey

information. The percent of evaluated transformers was developed from information provided by

transformer manufacturers. Appendix D provides the details on how this was done..

The base case nonevaluated 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 Con 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 Lossesfront 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.

4-3
Table 4.2. Base case transformer loss assumptions

Size Rated NLL° Rated LL° Percent Effective'

(kVA) Type (W) (W) evaluatedb 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 was 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.

4-4
Table 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

1000, 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 submitteddesigns. 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

4-5
transformers. 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

-91