UNITED STATES OF AMERICA

DEPARTMENT OF ENERGY

**PUBLIC MEETING**

ON

**ENERGY CONSERVATION STANDARD PRELIMINARY ANALYSIS FOR DISTRIBUTION TRANSFORMERS** 

U.S. Department of Energy 1000 Independence Avenue, SW Washington, DC 2058 5 Room 1E

- 245

Tuesday April 5, 2011

**Chair:**

James RabaExecutive Court Reporters (301) 565

- 0064 2

**Facilitator:**

Douglas Brookman Public Solutions 23 Bloomsbury Avenue Baltimore, MD 21228

**Participants Identified:**

Jerry Allen Metglas, Inc. 440 Allied Drive Conway, SC 29526

Pet er Amos Warner Power 40 Depot Street 03278 Warner, New Hampshire

Timothy Ballo EarthJustice 1625 Massachusetts Avenue Suite 702 Washington, DC 20036

Robert Berman Berman Economics 1915 Grand Court Vienna, VA 22187

David Brender Copper Development Assoc iation, Inc. 260 Madison Avenue New York, NY 10016

Ned Brush BBF & Associates 155 Pemaquid Loop New Harbor, ME 04554

Carl Bush PEMCO Corporation PO Box 1319 Bluefield, VA 24605Executive Court Reporters (301) 565

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Scott Choinski National Electrical Manufactures Association 1300 North 17 th Street Suite 1752 Rosslyn, VA 22209

Jim Creevy National Electrical Manufacturers Association 1300 North 17 th Street Suite 1752 Rosslyn, VA 22209

Andrew deLaski Appliance Standards Awareness Project 20 Belgrade Ave, Suite 1 Boston, MA 02131

Charles Drexl er Kentucky Association of Electric Cooperatives 4515 Bishop Lane Louisville, KY 40218

Keith Earhart Manufacturing Systems & Equipment, Inc. 2812 Chamber Drive Monroe, NC 28110

Gary Fernstrom Pacific Gas & Electric Company 13055 Parkhurst Dr Oakland, CA 94619

Paul K. Goethe Optimized Program Services 11 Bordeaux Place Olmeted Township, OH 44138

Paul Goldstein

Robert Greeson Federal Pacific PO Box 8200 Bristol, VA 24203Executive Court Reporters (301) 565

- 0064 4 Gerald Hodge Howard Industries, Inc. PO Box 1586 Laurel, MS 39441

Philip Hopkinso n HVolt, Inc. 3704 High Ridge Road Charlotte, NC 28270

Richard Lyke AK Steel Corporation 705 Curtis Street Middletown, OH 45043

John Hurst HEX TEC, LLC 2812 Chamber Drive Monroe, NC 28110

Joanna Mauer Appliance Standards Awareness Project 529 14 th St. N W, Suite 600 Washington, DC 20045

Dave Millure Metglas 440 Allied Drive Conway, SC 29526

Thomas Patzner Schneider Electric 1010 Airpark Carrier Drive Nashville, TN 37217

Nahid Pempin Optimized Program Service, LLC 14532 Pearl Road PO Box 360676 Strongs ville, OH 44136

John Phouminh Pepco Holdings, Inc. 3400 Benning Road, NE Washington, DC 20019Executive Court Reporters (301) 565

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Steven Rosenstock Edison Electric Institute 701 Pennsylvania Avenue NW Washington, DC 20004

Robin Roy Natural Resources Defense Council 1200 New York Avenue, N W, Suite 400 Washington, DC 20005

Paul Ryan Hitachi Metals America, Ltd. 800 Grand Avenue, Suite AG

- 6 Carlsbad, CA 92008

Mahesh P. Sampat EMS Consulting 1180 Brookview Drive Athens, GA 30606

Jerry Schoen AK Steel Corporation 705 Curtis Street Middletown , OH 45043

Ronald Stahara Central Moloney, Inc. 2400 West 6 th Avenue PO Box 6608 Pine Bluff AR 71611

Charlie Stephens Northwest Energy Efficiency Alliance 421 SW Sixth Avenue, Suite 600 Portland, OR 97204

Alan Traut Power Partners, Inc. 200 Newton Bridg e Road Athens, GA 30607

- 1180

Daniel Trombley American Council for an Energy Efficient Economy 529 14 th St. NW, Suite 600Executive Court Reporters (301) 565

- 0064 6 Washington, DC 20045

John W. Holt National Rural Electric Cooperative Association 4301 Wilson Boulevard Arlington, VA 22203

1801 K Street NW, Suite 500 **Partici pants from Navigant Consulting:** 

Washington, DC 20006

Hisham Araji

Rob Carmichael

Pamela Costello

Mahima Gupta

Brian Coffey

Matthew Hartl e y

William Kohse

Christopher Lau

Zhimei Luo

1 Cyclotron Road, MS 90

- 4000 **Participants form Lawrence Berkeley Na tional**  **Laboratory :** 

Berkeley, CA 94720

Gregory Rosenquist

Christopher Bolduc

Katie Coughlin

**Participants from the U.S. Department of Energy:**

James RabaExecutive Court Reporters (301) 565

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Jennifer Tiedeman

Robert van Buskirk

**Webinar Operator :** 

Hoi Yee La m Energetics, Inc.

**Presenters:**

Brian Coffey Navigant Consulting

Matthew Hartley Navigant Consulting

Gregory Rosenquist Lawrence Berkley National Laboratory

Katie Coughlin Lawrence Berkley National LaboratoryExecutive Court Reporters (301) 565

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AGENDA

**ITEM PAGE** 

Welcome James Raba 10

Introductions Douglas Brookman 11

Agenda Review Douglas Brookman 13

Opening Statements 16

Regulatory History Brian Coffey 26

Rulemaking Overview Brian Coffey 29

Sco pe of Coverage Brian Coffey 32

Test Procedure Brian Coffey 35

Market Assessment Brian Coffey 44

Technology Options Brian Coffey 47

Screening Analysis Brian Coffey 64

Engineering Analysis Matthew Hartley 66

Markups for Product Price Determination Gregory Rosenquist 140Executive Court Reporters (301) 565

- 0064 9 Energy Use and End

- Use Load Characterization Katie Coughlin 151

Life

- Cycle Cost and Payback Period Analysis Katie Coughlin 180

Shipments and National Impacts Analysis Gre gory Rosenquist 234

Preliminary Manufacturer Impact Analysis Matthew Hartley 256

NOPR Analyses Gregory Rosenquist 264

Closing Remarks 277Executive Court Reporters (301) 565

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MR. RABA: Good morning all. Welcome to 2

the US Department of Ene rgy public meeting on Energy 3

Conservation Preliminary Analysis for Distribution 4

Transformers Standards. My name is Jim Raba, I’m 5

the project manager for distribution transformers, 6

and today I’d like to welcome each and every one of 7

you. Today our team of experts will be presenting, 8

providing, informing and encouraging you

-- to you

- 9

- and from each one of you, we request your 10

comments, feedback, data, and information about 11

distribution transformers. 12 P R O C E E D I N G S

1

So, on behalf of the Department, I think 13

the best way to do a good rulemaking overall, in the 14

long run, is to work together. I heard some good 15

things out there about

-- everybody in the real 16

world

-- some good things about distribution 17

transformers that we’re hoping we can also work 18

together on this rulemaki ng. So with that, I would 19

invite

-- back to Doug again

-- to go around the 20

room. 21

MR. BROOKMAN: Right. It’s our tradition 22Executive Court Reporters (301) 565

- 0064 11 to have introductions right here at the outset. If 1

you’d say your name and organization or affiliation, 2

you can also get used to using these microphones. 3

For those of you who are seated at the table, you 4

need to push the button, get the little green LED to 5

come on, say you name and organizational 6

affiliation. Let’s start over here. 7

**Introductions** 8

MR. DREXLER: Charlie Drexler, Ke ntucky 9

Association of Electric Coops. 10

MR. FERNSTROM: I’m Gary Fernstrom, 11

Retired from and currently a temporary employee of 12

the Pacific Gas and Electric Company. 13

MR. HODGE: Jerry Hodge from Howard 14

Industries. 15

MR. PHOUMINH: John Phouminh, Pepco 16

Ho lding, Inc. 17

MR. AMOS: Peter Amos, Warner Power, 18

Warner, New Hampshire. 19

MR. PATZNER: Thomas Patzner, Schneider 20

Electric. 21

MR. SCHOEN: Jerry Schoen, AK Steel 22

Corporation. 23

MR. LYKE: Rick Lyke, AK Steel 24

Corporation. 25Executive Court Reporters (301) 565

- 0064 12 MR. ALLEN: Jerry Allen , Metgla s. 1

MR. RYAN: Paul Ryan, Hitachi Metals 2

America. 3

MR. ROSENSTOCK: Steve Rosenstock, Edison 4

Electric Institute. 5

MR. CREEVY: Jim Creevy, National 6

Electrical Manufacturers Association. 7

MR. BROOKMAN: That did not turn on. 8

MR. BERMAN: Robert Berman , Berman 9

Economics. 10

MR. BROOKMAN: Thank you. 11

MR. MILLURE: Dave Millure, Metglas. 12

MR. EARHART: Keith Earhart, MSE. 13

MR. HURST: John Hurst, HEX TEC, LLC. 14

MR. STEPHENS: Charlie Stephens, Northwest 15

Energy Efficiency Alliance. 16

MR. TRAUT: Alan T raut, Power Partners, 17

Incorporated. 18

MS. TIEDEMAN: Jennifer Tiedeman. 19

MR. BROOKMAN: And this will not be on the 20

record, but please stand and say your name. 21

MR. COFFEY: Brian Coffey, Navigant. 22

MR. HARTLEY: Matt Hartley, Navigant 23

Consulting. 24

MR. ROSENQUIST: Greg Rosenquist, Lawrence 25Executive Court Reporters (301) 565

- 0064 13 Berkley National Laboratories. 1

MR. ROY: Robin Roy, Natural Resources 2

Defense Council. 3

MS. MAUER: Joanna Mauer, Appliance 4

Standards Awareness Project. 5

MR. GOLDSTEIN: Paul Goldstein. 6

MS. PEMPIN: Nahid Pempi n. 7

MR. BRENDER: David Brender, Copper 8

Development Association. 9

MR. BRUSH: Ned Brush, consultant to 10

Copper Development Association. 11

MR. RABA: I think that that’s all. We 12

also have Hoy and also Hisham, right? Okay. 13

**Agenda Review**  14

MR. BROOKMAN: All of you received a 15

packet, I hope, as you registered this morning. It 16

involves a bunch of PowerPoint slides which the 17

Department and the Department’s contractors will be 18

going through during the course of the day. Also 19

the Federal Register

I’m going to do a very brief agenda 23

review. That’s on Page 2 of your slide packet. 24

Immediately following this agenda review, there are 25 Notice, a nd the notice of the 20

public meeting for this distribution transformers 21

meeting. 22Executive Court Reporters (301) 565

- 0064 14 a few introductory slides by DOE. Th ere’s an 1

opportunity for anybody that wishes to do so to make 2

brief introductory comments, key issues from your 3

perspective, succinct, brief comments. 4

From there we’re going to go to more 5

details on the Rulemaking Overview and Scope of 6

Coverage, the Test Procedure. We’ll take a break 7

mid

- morning, round about ten or 10:15, perhaps as 8

late as 10:30, and then we’ll move into more details 9

on Market Technology Assessment and the Screening 10

Analysis, Engineering Analysis. We’ll take lunch 11

round about noon toda y. Everybody’s on their own 12

for lunch as we get there, we’ll describe the 13

details concerning lunch. 14

Following lunch or whenever we get there, 15

Markups for Product Price Determination, followed by 16

Energy Use and End

- Use Load Characterization, Life

17

Cycle Cost and Payback Period Analysis, Shipments 18

and National Impacts Analysis. We’ll take a break 19

mid

- afternoon right about 2:45 or so, and then you 20

can see the remaining items. A description of 21

Preliminary Manufacturer Impact Analysis, the NOPR 22

Analyses, a nd then an opportunity for closing 23

remarks. 24

There’s yet another opportunity at the end 25Executive Court Reporters (301) 565

- 0064 15 of the day for anybody that wishes to do so, to put 1

some additional information into the record. This 2

will be

-- there will be a complete transcript of 3

this meeting t oday, and so I’d ask for your 4

consideration, if you would, please speak one at a 5

time. Please say your name for the record each time 6

you speak. You don’t need to say your 7

organizational affiliation unless you’re in the 8

habit of doing so, but please say y our name each 9

time you speak. 10

I’m going to be queuing people as best I 11

can to speak. I also wish to encourage follow

- on 12

comments. It’s very useful for the Department 13

sometimes, to have that back and forth. It enhances 14

the record. Please be concise, s hare the air time 15

today, there’s a lot to be said. There’s a lot to 16

cover here. You’ll see there are over 100 slides

- 17

- 140 some odd slides today to go through. 18

And if you please keep the focus here. 19

Please turn your cell phones on silent mode

-- I ’ll 20

do that myself, and if you keep the sidebars to a 21

minimum

-- you’ve already gotten used to using the 22

microphones, those of you that are seated at the 23

table. Those of you who are not seated at the 24

table, for comments, I would ask for you to find a 25Executive Court Reporters (301) 565

- 0064 16 micr ophone on the two sides, the two wings of the 1

tables there. 2

And then finally, the Department’s tried 3

to make these meetings accessible to anyone via the 4

web, so we have web participants that are going to 5

be following along, and they can see the slides. 6

We’re also wanting to invite those that are joining 7

the Department by web to write questions and 8

comments. We will be trying to answer them 9

selectively, especially if they haven’t been 10

answered previously, if they’re not redundant, if 11

they contribute va lue to the conversation. 12

One thing I’d say to everybody on the web 13

and everybody in the room, Jim will say this as 14

well, the Department really wants to receive your 15

written comments. In addition to what’s said here 16

today, please make sure that all your comments end 17

up in writing and timely to the Department. 18

So I think that that is pretty much what I 19

intended to cover. Have I forgotten anything major? 20

So far, so good. Okay. So then let’s go then to 21

Jim Raba for an overview. 22

**Opening Statements** 23

MR. RABA: This is in your packet. Well, 24

again, welcome to today’s public meeting on 25Executive Court Reporters (301) 565

- 0064 17 distribution transformers energy conservation 1

standards. And really, the purpose of our meeting 2

today is four

- fold, in a way, to present, provide, 3

encourage and inform. Th at is, to present the 4

procedural and analytical approaches to evaluating 5

energy conservation standards for distribution 6

transformers; provide a forum for public discussion; 7

and to encourage you to submit data, information, 8

and written documents for this ru lemaking process; 9

and to inform interested parties; and to facilitate 10

the rulemaking process. 11

And to do that, you’ll see in the course 12

of today’s public meeting, an issue box such as this 13

one here, where at certain break time, as 14

appropriate, we’ll inv ite your comments, data, and 15

information about the topic at hand and throughout 16

this presentation, identify specific issues, also 17

raise for discussion on a slide such as this. And 18

note that each of these issue boxes have a 19

corresponding number for the que stions in the 20

technical support document, Chapter 2, as well as 21

the executive summary. But the idea, there, is 22

again, to invite your comments, data, information 23

about distribution transformers. We need to hear 24

from you in particular. 25Executive Court Reporters (301) 565

- 0064 18 And in all your co rrespondence, we’re 1

looking for your feedback, and in this way, when you 2

do write to us or communicate, we request that you 3

would identify the distribution transformers 4

rulemaking with a docket number, a request for 5

information number for the record, and y ou can do 6

this either by e

- mail, postal mail, or hand courier. 7

And these are the addresses. 8

Please note that the comment period closes 9

April 18 th . We have a rather constrained time 10

schedule to this rulemaking. Know this is really 11

looking to the far en d

-- the end game, where it’ll 12

get tighter and tighter at the very end, to meet our 13

deadlines, but again, working together, as we said, 14

we look forward to that and we appreciate again, all 15

of us working together for this particular 16

rulemaking. 17

So for now , we’ll turn it back over to our 18

next presenter, and Doug

-- any opening statements 19

or remarks from the persons that are present today. 20

MR. BROOKMAN: Thank you. As reflected in 21

the agenda, an opportunity for opening remarks here 22

at the outset. I under stand we have a few that are 23

queued up to speak. Yes, please. Your name. 24

MR. PATZNER: Thomas Patzner. I’m a

-- 25Executive Court Reporters (301) 565

- 0064 19 from Schneider Electric, a local manufacturer of 1

distribution transformers. Our main concern is that 2

it does not seem like there’s been a timeline 3

established for the low voltage check, and we’d like 4

that established as soon as possible, because of the 5

potential need for capital expenditures. And second 6

of all, since the low voltage transformers are 7

actually written into the law, is there a ny other 8

processes that are going to occur in the timeline, 9

because it’s not just part of the rule, it’s 10

actually part of a law. 11

MR. BROOKMAN: Okay. 12

MR. PATZNER: So those are the two main 13

points we’d like to get clarified. 14

MR. BROOKMAN: Certainl y, the Department, 15

if you had a timeline in mind that would not pinch 16

industry, they would like to see that coming from 17

you. Yes, Jennifer. 18

MS. TIEDEMAN: Yes, Jennifer Tiedeman. 19

MR. RABA: Microphone, please. 20

MS. TIEDEMAN: Can you hear me better now? 21

We are constrained by the statute in terms of the 22

LVDT by EPACT 05, so there really

-- the standards 23

are out there, so there’s not much we can do. 24

MR. BROOKMAN: Jennifer, is that in the 25Executive Court Reporters (301) 565

- 0064 20 technical support document or someplace, what the 1

constraint as imposed by the statute? 2

MR. RABA: Well, we can have

-- I’m 3

thinking ahead here

-- we don’t have a switch the 4

TSD. Note that we can probably put our web 5

location. The intended timeline, because for the 6

statutory requirements to consent for things l ike 7

that, we have to meet certain deadlines, and then 8

there’s an effective date when the rule is final, 9

and compliance date. So those are pretty much set. 10

But in the meantime, we can show you maybe along the 11

way, the steps we’ll go through, with some sen se of 12

a timeline. We know it’s going to vary a little 13

bit, because of actual reality of the real world and 14

reviews we have to do here procedurally. So we will 15

look at getting something up there on the web for 16

everybody’s benefit, to know what the roadmap is 17

ahead. 18

MR. BROOKMAN: Okay. Yes. 19

MR. PATZNER: So Jennifer, based on your 20

comment, for low voltage to change, another law 21

would have to give you the ability to change it, or? 22

MS. TIEDEMAN: It sounds like it. I’ll 23

have to look into it and we’ll take it under 24

consideration. 25Executive Court Reporters (301) 565

- 0064 21 MR. PATZNER: So it would have to go in 1

front of Congress again? 2

MS. TIEDEMAN: It might. 3

MR. BROOKMAN: Thank you, Charles

-- or 4

thank you, Thomas. Steve Rosenstock. 5

MR. ROSENSTOCK: It’s not an opening 6

statement, it ’s a follow

- on question. 7

MR. BROOKMAN: Yes. 8

MR. ROSENSTOCK: If that’s okay. I don’t 9

want to interrupt. Since the standard was 10

established and it’s in a covered product under DOE, 11

so would it come under DOE regulatory, that it would 12

not have to

-- I thought that once Congress passed 13

the law and that, that it’s covered by DOE 14

regulations from now on, that it would be a DOE 15

regulatory purview, rather than a Congressional, 16

because it’s a covered product as far as

-- 17

MR. RABA: As I understand, we’re r eally 18

kind of

-- this will come up in just a moment here 19

when Brian Coffey goes over the regulatory history 20

of this rulemaking, but we’re kind of going back 21

over it again. It was in the regulations, but we 22

had it withdrawn by the courts for now for anothe r 23

look. So for now, we’re operating under current 24

statute, and then if there’s anything underlying, 25Executive Court Reporters (301) 565

- 0064 22 later on, it would have to go before the Congress. 1

However, for this proceeding and for the future that 2

we know of, it is a rulemaking under the Departmen t 3

of Energy’s rules and regulations, and procedures. 4

So proceed along these lines, as long as we can, 5

basically. 6

MR. BROOKMAN: Let’s see what the slides 7

say about the regulatory impacts. Other brief 8

opening remarks here at the outset. Yes, please

-- 9

that’s Charlie. 10

MR. DREXLER: Is this where I would read 11

an opening statement? 12

MR. BROOKMAN: Yes. 13

MR. DREXLER: I guess I don’t need to read 14

the whole thing. 15

MR. BROOKMAN: Yes, it’d be nice if you 16

could summarize. 17

MR. DREXLER: Okay. My name i s Charlie 18

Drexler with Kentucky Association of Electric Coops. 19

We’re going to also submit comments through NEMA, 20

but I guess our main point, or the main thing I 21

wanted to put across was that we think that the 22

single phase in the liquid field distribution 23

standards are adequate and already achieve

-- 24

represent the maximum energy savings that is 25Executive Court Reporters (301) 565

- 0064 23 economically justified. There’s few types of 1

equipment that have the efficiency and life and 2

longevity of distribution transformers, and we think 3

the regulation is high enough. 4

The other thing is I think I give a couple 5

examples in the write

- up that cover it

-- that shows 6

that there’s not a whole lot of gain in efficiency 7

in

-- the biggest gain has already been made. 8

MR. BROOKMAN: All right, he’s got to 9

speak more into the microphone. 10

MR. DREXLER: Also, we feel that

-- we’re 11

a small manufacturer and as a small manufacturer we 12

would have a higher amount of capital impact as far 13

as capital investment to meet any increased 14

efficiency standards as well as a larg e amount of 15

drainage capital. We’re also very concerned about 16

core steel supply, as pointed out in the DOE thing. 17

And that the rural electric coops are probably 18

adverse or more hit by the DOE regulations because 19

they serve, quite often the distribution 20

t ransformers have one customer per coop or per 21

transformer and are 25 percent loaded, so the energy 22

savings on a transformer situation like that are 23

quite less, and payback can be quite a bit longer 24

than normal. That’s all. Thank you. 25Executive Court Reporters (301) 565

- 0064 24 MR. BROOKMAN: So t hose written comments 1

will be helpful to the Department. Additional 2

comments here at the outset? Yes, Steve Rosenstock. 3

MR. ROSENSTOCK: Steve Rosenstock, Edison 4

Electric Institute. I just want to thank the 5

Department for releasing the technical suppo rt 6

document and for having this meeting. I realize 7

that under the revised procedure that was announced 8

last November, that information does not have to be 9

provided to stakeholders until the NOPR stage, so I 10

just want to thank the Department for providing this 11

information, having the public meeting, and allowing 12

us to make comments before the NOPR stage. I think 13

that will help the Department in its deliberations. 14

Thank you. 15

MR. BROOKMAN: Thank you. Other comments 16

here at the outset? Key issues from t he perspective 17

of those seated at the table? Yes. Gary Fernstrom. 18

MR. FERNSTROM: Gary Fernstrom, Pacific 19

Gas and Electric Company. As others in the meeting 20

today, PG&E is a large consumer and user of 21

distribution transformers. However, PG&E is also 22

directed by the California Public Utilities 23

Commission and state policy to be concerned about 24

energy efficiency. And PG&E would very much like to 25Executive Court Reporters (301) 565

- 0064 25 see the highest level of cost effective, economic 1

efficiency built into transformers. This 2

particularly inc ludes core losses, which are a 3

significant source of wasted energy in lightly 4

loaded transformers of all kinds, those in 5

distribution systems and buildings, namely, low 6

voltage dry type transformers as well as utility 7

distribution transformers. 8

MR. BROOK MAN: Thank you. Yes, please. 9

Your name? 10

MR. HURST: My name is John Hurst and I’m 11

with HEX TEC, LLC. As I read through these 12

documents and part of the reason for our presence, I 13

see that there’s a lot of absence of information, 14

definitive information , about what you’re referring 15

to as 120 degrees symmetric cores. And we’re 16

actually building in pilot production symmetric 17

cores, so we do have comparative labor costs and 18

material savings, and we will make sure that that is 19

sent to you by the 18 th . But I look at this table 20

and it says increased labor cost, plus 55 percent. 21

We actually find our labor costs lower than 22

conventional construction. 23

MR. BROOKMAN: Okay. Thank you and we 24

will be going through these slides one by one, so 25Executive Court Reporters (301) 565

- 0064 26 there’s more opportun ity for anybody to comment on 1

the substance that is in them as we’re going along 2

during the course of the day. But the Department is 3

constantly in a search for good data, so they will 4

certainly welcome that submission. Other brief 5

introductory remarks be fore we jump into the 6

details? 7

Okay, then, let’s proceed. We’re going to 8

hear next from Brian Coffey. 9

**Regulatory History** 10

MR. COFFEY: Hi, Brian Coffey, Navigant 11

Consulting. To the gentleman with the statutory 12

background question, that was aptly timed because 13

that’s the first thing I’m going to go into, so 14

hopefully, we can answer your question and if not, 15

there will be an opportunity to comment afterwards. 16

Here’s a little bit on the statutory 17

background of this rulemaking. The Energy Policy 18

Conserv ation Act of 1975, or EPCA, established the 19

energy standards program. EPACT, in 1992, directed 20

DOE to establish distribution transformers 21

standards. After that, EPACT 2005 set standards for 22

low voltage dry type units at the NEMA TP1 2002 23

level. NEMA TP1 was a voluntary standard, and EPACT 24

2005 codified that standard into law. 25Executive Court Reporters (301) 565

- 0064 27 In 2007, DOE set its own standards for 1

liquid immersed and medium voltage dry type 2

transformers. Because EPACT 2005 had established 3

standards for low voltage dry type, DOE stopp ed 4

considering standards for them in the 2007 5

rulemaking. After publishing that 2007 rule, DOE 6

was sued by the state of California and some others, 7

and part of the settlement agreement to that was 8

that DOE would reexamine its analysis and by October 9

of th is year, publish either a notice proposing new 10

standards, or a determination that standards 11

required no amendment. If it does propose standards 12

in October, DOE must then publish a final rule by 13

October 1, 2012. So that’s where this rulemaking 14

comes from. 15

MR. BROOKMAN: Let’s pause. Steve 16

Rosenstock. 17

MR. ROSENSTOCK: A couple of questions. 18

The first one, trying to address his question, are 19

low voltage dry type transformers considered a 20

covered product that would just from now on be DOE 21

regulatory pro cess versus Congressional act? I 22

think that was kind of the crux of his question. 23

MR. BROOKMAN: Jennifer, please, the 24

microphone. 25Executive Court Reporters (301) 565

- 0064 28 MR. ROSENSTOCK: And I have a follow

- on 1

question. 2

MS. TIEDEMAN: I do need to review the 3

statute, but we are going to be considering LVDT

-- 4

distribution transformers

-- amending this standard 5

here, and we may opt to conduct a separate 6

rulemaking for that. But again, I need to review. 7

MR. BROOKMAN: At this point, you’re not 8

certain? Okay. Yes, Steve. 9

MR. ROSENSTOC K: Yes, just a quick one. 10

And sort of a little with the dry

- types, you forgot 11

to put on the effective dates for the low voltage 12

dry

- types, effective date was January 1, 2007, and 13

for the liquid filled and medium voltage, the 14

effective date was January 1, 2010, 13 months ago, 15

the new standards went into effect. I’m going to 16

make comments later because technical support 17

document does not reflect some of that information, 18

that the standards just were bumped up 19

significantly, less than 14 months ago. Thank you. 20

MR. BROOKMAN: Okay. Thank you. 21

MR. COFFEY: Before publishing its 2007 22

standard, DOE published the test procedure for 23

distribution transformers. That was based on the 24

1998 version of an industry test procedure, NEMA 25Executive Court Reporters (301) 565

- 0064 29 TP2. EISA 2007 requires tha t DOE amend test 1

procedures within seven years of their publications. 2

And so DOE is taking this opportunity now to review 3

the test procedure and efficiency standards in 4

parallel. 5

DOE is directed by statute to consider 6

seven different factors in setting conservation 7

standards for distribution transformers, and it does 8

so in 11 specific analyses. Here you can see those 9

factors and their corresponding analyses. The total 10

projected energy savings, for example, are 11

considered in the National Impact Analysis . We will 12

be discussing each of these in greater detail today. 13

MR. BROOKMAN: So let’s just pause. I 14

don’t recognize some of you, so I presume some of 15

you are fairly new to this proceeding. Questions 16

about what’s been covered so far? Okay. 17

**Rulemaki ng Overview**  18

MR. COFFEY: There are four main phases of 19

a rulemaking: framework, preliminary analysis, 20

Notice of Proposed Rulemaking, and Final Rule. Each 21

stage includes a Federal Register Notice to place 22

information in public view. At multiple points in 23

the process, DOE invites both oral and written 24

comments on its analysis. Those comments can be in 25Executive Court Reporters (301) 565

- 0064 30 response to not only the Federal Register

Most ru lemakings begin with the 4

publication of a framework document. Because DOE 5

had published a distribution transformers final rule 6

so recently, however, it opted to begin with our 7

current stage, the preliminary analysis, wherein DOE 8

presents its initial analy tical results. Here you 9

see the different analyses that form the preliminary 10

analysis, and we’ll explore all of them in greater 11

detail today. 12 Notice,

1

but also technical support documentation, and 2

analytical spreadsheets posted on DOE’s website. 3

Before October 1 st of this year, DOE may 13

publish a Federal Register

In the final rule, DOE once again revises 22

its analysis and incorporates feedback received 23

during the NOPR stage. Let’s take a look at the 24

timeline for all these steps. So here you can see 25 Notice, proposing a 14

standard called a NOPR, and hold a public meeting, 15

similar to this one, to receive feedback on that 16

proposal. I say “may,” because it also has the 17

option of publishing a determination asserting that 18

new standards aren’t warranted. Here’s a diagram of 19

all the NOPR analyses, whi ch include a round of 20

revisions for preliminary analysis. 21Executive Court Reporters (301) 565

- 0064 31 all th ose milestones we just talked about. DOE 1

published the notice announcing this preliminary 2

analysis meeting on the 2 nd of this past March. It 3

will publish, this October, either a notice 4

proposing new standards, or as I said, a 5

determination asserting that no standards are 6

warranted. A final rule, if needed, would be 7

published in October of 2012 and have a compliance 8

date of not later than January 1, 2016. 9

Although the compliance date of any 10

amended standard would have to be no later than 11

January 1, 2016 , DOE may select an earlier one. DOE 12

welcomes comment on the compliance date, and whether 13

industry would feasibly be able to meet a date 14

earlier than January 1, 2016. 15

MR. BROOKMAN: So here you see the 16

Department’s first comment box, wherein they 17

active ly seek your comment as listed there on the 18

timeline and the preceding slides. Steve 19

Rosenstock. 20

MR. ROSENSTOCK: Steve Rosenstock, EEI. 21

With all other appliances that are covered by the 22

Department, typically the Department does give three 23

to five year s for manufacturers to comply with 24

standards, so that would be consistent with past 25Executive Court Reporters (301) 565

- 0064 32 regulations. 1

MR. BROOKMAN: Thank you. Yes. Question? 2

Additional comments? 3

**Rulemaking Scope of Coverage**  4

MR. COFFEY: So next I’ll talk about 5

rulemaking scope and the current standards. Here’s 6

an overview of the scope of this rulemaking, and of 7

the efficiency standards currently in place. This 8

may speak a little bit to the question that was 9

asked earlier. 10

Distribution transformers can be divided 11

into two categories : liquid immersed, and dry type. 12

Dry type can be further divided into medium and low 13

voltage dry type, depending upon input voltage. A 14

medium voltage can be even further subdivided by 15

BIL, or basic impulse insulation level. 16

The 2007 final rule set stan dards for 17

liquid immersed and all three medium voltage dry 18

type insulation levels. It didn’t set standards for 19

low voltage dry type, because standards had been 20

recently established in the EPACT 2005. So those 21

are the current standards, and now I’ll talk about 22

how all those terms are defined. 23

EPACT 2005 presented a definition of 24

distribution transformer term, which DOE refined 25Executive Court Reporters (301) 565

- 0064 33 during the 2006 test procedure rulemaking. 1

Distribution transformers are defined by input and 2

output voltage, frequency, and cap acity. At the 3

bottom here, you’ll see several types of 4

transformers that are not considered distribution 5

transformers, and therefore, are excluded from 6

standards. Auto transformers and rectifier 7

transformers, for example, are both currently 8

excluded. 9

S o here are definitions of the three types 10

of distribution transformers that I mentioned. 11

Liquid immersed units come in a huge range of sizes 12

and are popular with utilities for their slightly 13

higher efficiencies. Dry types, as I mentioned, are 14

split into medium and low voltage classes, depending 15

on whether their input voltage is above 600. Dry 16

types typically have lower efficiencies, but are 17

often used indoors or near waterways for their lower 18

risk of leakage or fire. 19

MR. BROOKMAN: We have a question o r a 20

comment. Please use the microphone, and say your 21

name for the record, please. 22

MR. BUSH: Carl Bush, PEMCO Corporation. 23

In that list of exceptions, hadn’t underground 24

mining transformers also been included in that list? 25Executive Court Reporters (301) 565

- 0064 34 MR. COFFEY: It had in the previous 1

rulemaking, although no standards were set for them. 2

I’m sorry, it was included in the scope of the 3

rulemaking. It was not included in the list of 4

exclusions. 5

MR. BUSH: So it should be included in the 6

list of exclusions? 7

MR. COFFEY: It was not excluded in the 8

past rulemaking. 9

MR. BUSH: Okay. We thought

-- the 10

industry was under the impression that it was 11

included

-- excluded. 12

MR. COFFEY: It’s sort of a subtlety. It 13

wasn’t specifically excluded, but no standards were 14

set for undergro und mining transformers. If that 15

makes sense. 16

MR. BUSH: That makes sense. Thank you. 17

MR. BROOKMAN: Okay. Thanks for that. 18

Other questions on this one? Yes, please. 19

MR. TRAUT: Alan Traut with Power 20

Partners. In the revision that’s in process right 21

now, is the area of the definition of the 22

transformer, or the kVA ranges that are covered up 23

for revision? Or is that fixed? 24

MR. COFFEY: DOE would welcome any 25Executive Court Reporters (301) 565

- 0064 35 feedback you have on the matter. 1

MR. TRAUT: Okay. 2

MR. BROOKMAN: Okay. There’s going to be 3

more opportunity for comment on this. Other 4

comments before we proceed? 5

**Test Procedure** 6

MR. COFFEY: So now we’ll go into a little 7

bit more detail on the test procedure and some of 8

the proposed changes that DOE is considering. 9

We mentione d that DOE published a test 10

procedure in April 2006, that was based on NEMA TP2, 11

and used for all three of our transformer 12

categories. That test procedure is codified in Part 13

431 of Title 10 of the CFR. Manufacturers gave 14

feedback suggesting some changes to the test 15

procedure, so I’ll talk a little bit about those on 16

the next slide. 17

So here’s a change that DOE’s considering. 18

Some transformers have secondary windings that can 19

be connected either in series or in parallel. This 20

is pretty common in smal l, liquid immersed pole 21

mounted transformers, for example. The test 22

procedure stipulates that testing must occur in the 23

configuration that produces the highest losses, 24

which is usually with the windings in parallel. The 25Executive Court Reporters (301) 565

- 0064 36 efficiency difference between seri es and parallel 1

secondary configurations, however, is pretty small, 2

and most transformers are shipped with their 3

secondary windings in series. IEEE standards 4

actually require that the units be shipped with 5

their windings in series, so currently a 6

manufact urer has to configure the windings in 7

parallel, test the unit, and then put them back in 8

series to ship the transformer. DOE is proposing 9

now to allow testing at any secondary winding 10

configuration. 11

Since efficiency as tested in parallel and 12

efficiency as tested in series usually increase or 13

decrease together, DOE believes that series testing 14

could not be used to circumvent standards. 15

On the fourth bullet here, manufacturers 16

noted that medium voltage dry type transformers may 17

have different BIL ratin gs in different 18

configurations and questioned which ratings should 19

be used to assess compliance. 20

In response to these concerns, DOE 21

proposes to allow testing in any secondary 22

configuration and at the lowest BIL rating. 23

So here is a request for comment on those 24

issues. DOE seeks comment on its proposal to amend 25Executive Court Reporters (301) 565

- 0064 37 the test procedure to allow compliance testing in 1

any secondary configuration. Should the proposed 2

amendment apply to all covered distribution 3

transformers or just a subset? DOE welcomes 4

submis sion of any data that would support a 5

conclusion. 6

And the next is that DOE welcomes comment 7

on its proposal to require compliance at the lowest 8

BIL at which dual or multiple voltage transformers 9

are rated to operate. 10

MR. BROOKMAN: Steve Rosenstock. 11

MR. ROSENSTOCK: Steve Rosenstock, EEI. 12

Nothing about the test procedure, just there does 13

seem to be a mismatch between the handouts and the 14

overheads

-- just to let you know. There does seem 15

significant sentences are kind of missing here, so. 16

MR. CO FFEY: There were some insertions 17

after those handouts were printed. 18

MR. BROOKMAN: Okay. So we’ll just leave 19

that there. 20

MR. COFFEY: But the slide numbers should 21

line up. 22

MR. BROOKMAN: Jim Raba. 23

MR. RABA: We did have some editorial 24

modificati ons ahead, so as this concludes today, 25Executive Court Reporters (301) 565

- 0064 38 within a short period of time, you’ll see the actual 1

presentation on our website. So what you see today, 2

you’ll see later on, but for now we’re working from 3

these as best we can do. Thank you very much for 4

bringing it up. 5

MR. BROOKMAN: So let’s just see if there 6

are any comments to respond to the Department’s 7

inquiry. Your name, please. 8

MR. HOPKINSON: Phil Hopkinson, HVolt, 9

Inc. The only thing that I would try to raise as an 10

issue is that in the transformers that are selected 11

to be designed as dual voltage rating, then in 12

general, they’re not an even multiple of the series 13

connection compared to the parallel connection, 14

which means that already there are unused windings 15

that will be in the parallel connection. So when 16

you set the BIL for testing on the lowest BIL 17

connection, what that really says is that the 18

efficiency, fundamentally, is higher as a 19

requirement for transformers that are tested that 20

way than they are if they were on the higher BIL and 21

so the du al voltage transformers, in effect, get a 22

double whammy, because they already have to be 23

designed bigger, just by the fact that there will be 24

unused windings. And the second element is that 25Executive Court Reporters (301) 565

- 0064 39 when they are tested on the lowest BIL efficiency 1

requirement, th en they have to be more efficient as 2

well so that dual voltage dry type transformers 3

tested that way, sound like they are being unduly 4

required to be more efficient than single voltage 5

transformers would be. 6

MR. BROOKMAN: Okay. Thank you. Other 7

commen ts in response to these issue boxes. Yes, 8

please. And your name. 9

MR. GREESON: Rob Greeson, Federal Pacific 10

Transformer. I agree with Mr. Hopkinson’s approach 11

there. On a reconnectable dry type

-- we’re a 12

manufacturer of dry type transformers

-- and if the 13

efficiency standards should be set at the lowest BIL 14

rating, because of

-- and this is not only for some 15

of the facts that he stated, but for the fact of air 16

clearances in dry type transformers

-- when you’re 17

at the higher voltage, operating voltage , you have 18

to have more air clearances in that transformer, 19

thus making it larger. So you are unduly 20

restraining

-- you’re making it more difficult to 21

make those higher efficiencies at lower BIL ratings. 22

The other part of that is, you know, 23

there’s real ly not a great deal of these 24

transformers. We build a few a year, but it just 25Executive Court Reporters (301) 565

- 0064 40 seems like it complicates those transformers too 1

much to try to

-- it almost essentially bumps it up 2

to the next standard level in efficiency for that 30 3

BIL, because you have s o much extra material in the 4

transformer. It just makes it very difficult to get 5

the core losses down. And so we support the idea 6

that on a reconnectable transformer, to just go with 7

the lowest BIL efficiency rating. I mean highest. 8

Sorry, got it backw ards. Thank you. 9

MR. BROOKMAN: All right, thank you. Yes, 10

Alan. 11

MR. TRAUT: Alan Traut, Power Partners. I 12

just wanted to comment on the first issue there, on 13

the reconnectable secondaries and liquid filled 14

transformers specifically. Just to differ entiate it 15

from what’s been discussed here, those windings are 16

almost always exactly two to one, so in both cases, 17

both the series and the parallel position, both 18

windings are fully engaged. The I 2 R loss is nearly 19

identical in either connection, and the o nly 20

difference in loss is a very subtle difference in 21

stray loss. So we support this issue and would 22

recommend that DOE adopt it. 23

MR. BROOKMAN: Thank you. Helpful 24

comments. Additional comments at this time? Okay. 25Executive Court Reporters (301) 565

- 0064 41 MR. COFFEY: To the two gentleme n that had 1

commented on the first issue

-- I’m sorry, the 2

second issue as it’s laid out on the slide

-- 3

sounded like you were agreeing with each other, but 4

maybe disagreeing with DOE’s proposals, so I would 5

encourage both of you and any other people who mi ght 6

agree with that, to submit a comment rehashing what 7

they said, and also proposing what test method might 8

be appropriate in these cases. 9

In addition to the secondary windings 10

issue, DOE received comments from manufacturers 11

suggesting other changes to the test procedure. One 12

is of whether reconfigurable primaries could also be 13

tested in their most efficient configuration. 14

Reconfigurable primaries experience larger 15

efficiency variation than secondaries, however, and 16

would still need to be tested in the ir least 17

efficient arrangement. 18

Another area of interest is reference 19

loading points. Currently they are 50 percent for 20

liquid immersed and medium voltage dry type, and 35 21

percent for low voltage dry type. DOE welcomes 22

comments on those items and on an y other issues 23

related to the test procedure. 24

MR. AMOS: Can I just make a comment on 25Executive Court Reporters (301) 565

- 0064 42 that. Peter Amos from Warner Power. And I would 1

like to mention we will follow up after the meeting 2

with written submissions concerning modified test 3

procedures which would better capture core 4

deactivation technologies which currently can’t be 5

picked up with the present test procedures. 6

MR. BROOKMAN: Thank you. Other

-- Gary 7

Fernstrom. 8

MR. FERNSTROM: Gary Fernstrom. Can I ask 9

for a clarification. What is a cor e deactivation 10

technology? 11

MR. BROOKMAN: Peter? 12

MR. AMOS: One of the speakers from 13

Pacific Gas and Electric, on my right, mentioned 14

that they had concerned about the core losses in 15

distribution transformers, particularly at low power 16

levels where the efficiency rolls off because the 17

core losses, of course, are constant, 24/7. And one 18

of the technologies that we’ve been working on at 19

Warner Power is the ability to reduce those core 20

losses at low levels of power consumption. This is 21

getting more and m ore important in buildings as 22

building efficiency measures start to kick in and 23

possibly looking ahead, the average power 24

consumption will actually go down in buildings, and 25Executive Court Reporters (301) 565

- 0064 43 transformer core losses will start to become more 1

significant. 2

MR. BROOKMAN: Th ank you. Steve 3

Rosenstock. 4

MR. ROSENSTOCK: May I follow up again for 5

clarification. Is that a control feature that’s 6

built into the transformer, or is an add

- on type of 7

component that an owner could

-- 8

MR. AMOS: Steve, it’s a very simple 9

thing. A s opposed to having one 75 kVA transformer, 10

we’re using three 25 kVAs, one of which is a base 11

load unit that runs all the time, and then the other 12

two are switched in and out on demand, with a 13

control system. 14

MR. ROSENSTOCK: So it’s a built

- in 15

feature? 16

MR. AMOS: Yes, it’s a built in feature. 17

MR. ROSENSTOCK: Thank you very much. 18

MR. BROOKMAN: Okay. Yes, is it

-- 19

Thomas. 20

MR. PATZNER: Thomas Patzner. I’d like to 21

expand on your question. There’s also research 22

going on to do more than just cont rolling the 23

transformer itself, so expect other items where 24

there would be add

- on features to do the same thing 25Executive Court Reporters (301) 565

- 0064 44 to control core losses. 1

MR. BROOKMAN: These comments though 2

relate to how you might modify the test procedure, 3

correct. 4

MR. PATZNER: I was just answering his 5

question. There could be add

- ons as well. 6

MR. BROOKMAN: So let’s press on then, 7

okay. 8

MR. COFFEY: And we will touch on the 9

subject in a little bit. 10

**Market and Technology Assessment and** 11

**Screening Analysis** 12

MR. COFFEY: Well, t hat brings us to the 13

Market and Technology Assessment and Screening 14

Analysis. Here’s an overview of the preliminary 15

analysis stage that we presented before. You can 16

see that these two analyses are circled and they’re 17

the two most upstream components. 18

Market and Technology Assessment 19

characterizes the distribution transformer market 20

and industry, identifies technology options that can 21

be used to improve efficiency and establishes 22

equipment classes. The Screening Analysis screens 23

out technology option s that DOE won’t consider in 24

the engineering analysis, based on four screening 25Executive Court Reporters (301) 565

- 0064 45 criteria that we’ll go through in a little bit. 1

So here’s a diagram of all that. You can 2

see that the Market and Technology Assessment 3

yields technology options that are con sidered in the 4

Screening Analysis. The technology options that 5

aren’t screened out are renamed design options and 6

passed on to the engineering analysis for further 7

consideration. The Market and Technology Assessment 8

also establishes equipment classes whi ch, unlike the 9

design options, just feed directly into the 10

Engineering Analysis. 11

DOE breaks its scope of coverage down into 12

equipment classes by the type of energy used, 13

capacity, and any performance

- related features that 14

affect consumer utility or effic iency. Equipment 15

classes are important because each equipment class 16

ultimately gets its own standard. There are a large 17

number of distribution transformer equipment 18

classes, so DOE placed them into ten groupings, 19

based on type of insulation, number of ph ases, 20

voltage level, and for medium voltage dry type, 21

basic impulse insulation level, BIL. 22

Here are the details of the ten equipment 23

class groupings. Simple one and three phase 24

groupings for liquid immersed and low voltage dry 25Executive Court Reporters (301) 565

- 0064 46 type. Medium voltage dry type was further 1

subdivided by insulation level, just as it was in 2

the 2007 rulemaking. So there are six medium 3

voltage dry type groupings instead of two. 4

MR. BROOKMAN: Let’s pause there. Alan. 5

MR. TRAUT: I’d like to make a comment on 6

the first cla ss there, a single phase liquid filled 7

transformers. What we’ve experienced in the year

8

plus now that these standards have been in effect, 9

is particularly above 500 kVA, single phase, it 10

becomes very difficult to manufacture transformers 11

to meet the effic iency and live within weight and 12

size constraint that our users can live with. 13

Looking at the shipment history for those 14

transformers, I think it’s in one of the tables in 15

here, there’s a total of five transformers that met 16

that category. I think the Department and energy 17

savings would be much further ahead to eliminate 18

transformers above 500 kVA, but perhaps consider 5 19

kVA single phase transformers. 20

MR. BROOKMAN: Thank you. Five models? 21

MR. TRAUT: No, instead of a lower limit 22

of ten kVA, consi der a lower limit of five kVA. 23

MR. BROOKMAN: Okay. 24

MR. COFFEY: So here are the market 25Executive Court Reporters (301) 565

- 0064 47 details on equipment class groupings, both by units 1

shipped and by MVA capacity. DOE used both NEMA 2

data and conducted its own research to generate 3

these numbers . DOE uses this information to focus 4

its attention on the market segments with the 5

highest volume, and the data is important in both 6

the national impact analysis and the shipments 7

analysis. You can see that the single phase liquid 8

immersed and three phas e low voltage dry type have 9

the highest shipment volumes, for example, and the 10

single phase medium voltage dry type have the 11

lowest. 12

**Technology Options** 13

MR. COFFEY: So now I’ll go into 14

technology options. Here are the technology options 15

that can be used to improve efficiency in 16

distribution transformers. Before I go through 17

these, I should say that there are two main types of 18

losses in transformers: core losses and coil losses. 19

Sometimes you can improve the efficiency of one 20

without affecting the other by using a lower loss 21

core or coil material. Those correspond to the 22

first two technology options listed. The third 23

technology option is modified geometry, which we’re 24

using to refer to say, changing the core winding 25Executive Court Reporters (301) 565

- 0064 48 cross section, or volts per turn. T he general 1

characteristic of these geometry modifications, in 2

contrast to materials changes, is that they usually 3

reduce either core or coil losses, but not both, and 4

they increase the one that doesn’t get reduced. 5

Manufacturers try to optimize geometry d epending on 6

materials, prices, and application. 7

The last two technology options are new 8

this time around. Symmetric core designs and core 9

deactivation technology. They weren’t considered in 10

the 2007 rulemaking, and so we’ll spend a minute 11

now, discus sing them. 12

So here’s symmetric core designs. They’re 13

only for three phase applications and different from 14

conventional three phase transformers, because each 15

leg is equally spaced from every other. Potential 16

advantages included reduced weight, volume , losses, 17

noise, vibration, stray magnetic fields, in rush 18

current, and harmonics. Some of the concerns with 19

this technology might be intellectual property, 20

manufacturability of volume, and the fact that it’s 21

not well suited for wye connections. 22

So here ’s a comment on that. DOE seeks 23

comment on symmetric core designs, the 24

practicability to manufacture, and whether they 25Executive Court Reporters (301) 565

- 0064 49 offer potential for efficiency improvement. In 1

particular, DOE seeks comment on applications where 2

symmetric core may be infeasible. F inally, DOE 3

seeks comment on concerns related to intellectual 4

property and manufacturability to scale. 5

MR. BROOKMAN: Steve Rosenstock. 6

MR. ROSENSTOCK: Steve Rosenstock. Yeah. 7

Is there a concern about this product under a 8

specific patent by one manu facturer or is that

-- is 9

that the concern? 10

MR. HURST: There shouldn’t be because 11

there are actually quite a number of 120 degree 12

symmetric transformers cores out, so there should be 13

plenty of variance. 14

MR. BROOKMAN: Thank you, John. Yes. 15

MR. HOPK INSON: Brian, I meant to say good 16

morning to you. 17

MR. COFFEY: Good morning, Phil. 18

MR. HOPKINSON: What I would try to kind 19

of give a little background on this particular

-- 20

symmetrical core technology goes back to at least 21

the 1930s when this concept had been patented back 22

at that time. So long since patents that 23

fundamentally relate to the configurations would be 24

expired. But there may be specific patents with 25Executive Court Reporters (301) 565

- 0064 50 different kinds of construction that go using the 1

fundamental nature. 2

I would, though, p oint to a couple other 3

things. I would say first that for utility 4

transformers, which fundamentally would be liquid 5

filled transformers, then the wye

- wye configuration 6

is by and far the most common configuration that is 7

going to be in the industry. So in order to use 8

this technology, one would need to add a delta 9

winding to it, which would take away from the 10

benefits of shared core that would go along with the 11

use of this technology and cancel the effect of it. 12

In the case of industrial and commercial 13

t ransformers, many of those are delta

- wye, and so in 14

that area it could, in fact, have application. But 15

we also must consider that there is not a whole lot 16

of volume for industrial transformers less than 300 17

kVA if they’re going to be medium voltage, bring ing 18

power into a facility. If they are low voltage dry 19

types, within the facility, those also could be 20

delta

- wye and that would be a possible area where 21

they could be used, except for the fact that the 22

configuration certainly would require wound core and 23

so that would be fundamentally different than stack 24

core which the industry largely is based on, in the 25Executive Court Reporters (301) 565

- 0064 51 low voltage drys. What that would say is that 1

manufacturers would have a considerable investment 2

required to change their facilities to use wound 3

core, and in fact then, to make it into a 4

configuration that would work here. 5

The other dimension, I would say, is that 6

when one goes to large wound cores that might affect 7

kVA sizes beyond 300 kVA, all the way up to the 2500 8

kVA, then there is

-- with wound core there is going 9

to be large sizes and those cores will tend to buzz, 10

and they will make an objectionable, audible noise. 11

So I would say there’s a lot of constraints in the 12

application that would suggest this technology is 13

going to have very limited us e. 14

MR. HURST: Can I respond to you, Phil? 15

MR. BROOKMAN: Say your name for the 16

record. 17

MR. HURST: John Hurst. We have actually 18

been three years looking at that, and unfortunately 19

since you don’t have direct information you have 20

some mistakes in wh at you commented. We will supply 21

data by the written comment time, but the 22

construction of a three phase wound core by the 23

configuration we use is not

-- does not induce 24

additional audible sound. The equipment to produce 25Executive Court Reporters (301) 565

- 0064 52 it is significantly less expensiv e than flat stack 1

steel equipment for the same size, and the labor 2

production times are lower. So I think that, 3

barring other information in the marketplace, I 4

think we’d invite you to come see. 5

MR. BROOKMAN: So John, that’s the kind of 6

information tha t the Department really likes to see, 7

so your written comments would be very helpful. 8

MR. HURST: Yes. 9

MR. BROOKMAN: I would invite all of you, 10

please look at slide 35. The Department is asking 11

for some rather specific comment. We’ve received 12

some g ood comment, I want to make sure we cover this 13

sufficiently on symmetric core design. 14

Practicability to manufacture, designs are feasible 15

or infeasible, and technology and feasibility of 16

manufacturing on large scale. No additional 17

comment? Okay. 18

MR. COFFEY: So that was the first new 19

technology option in this rulemaking, and now I’ll 20

talk about the second one, which is core 21

deactivation technology. This technology tries to 22

reduce core losses by replacing one transformer with 23

several smaller ones tha t can be switched on and off 24

in response to load variation. There’s a control 25Executive Court Reporters (301) 565

- 0064 53 unit that decides how many transformers to have in 1

service at any given time. 2

DOE is only aware of this technology being 3

used with low voltage dry type transformers, and as 4

we ’ll see on the next slide, core deactivation is 5

best suited for low root

- mean

- square loadings. 6

Here’s a sample efficiency versus loading 7

curve. The red line represents traditional low 8

voltage dry type transformer whose efficiency rises 9

sharply, peaks ar ound 35 percent, and gradually 10

falls with rising load losses. Core deactivation 11

bank has a more piecemeal curve as its units are 12

switched on and off. The important take

- away here 13

is that efficiency might exceed that of a 14

conventional transformer at low l oadings, but it 15

will always do worse at high loads due to the 16

inherently worse efficiency of the smaller 17

transformers. That’s all else held equal, of 18

course. 19

While core deactivation technology could 20

potentially save energy over certain load cycles, 21

the current test procedure tests at only one load 22

point, and wouldn’t reflect those energy savings. 23

One way of capturing the energy savings for core 24

deactivation technology, without altering the tested 25Executive Court Reporters (301) 565

- 0064 54 efficiency of conventional units, is to use a 1

weighted av erage of efficiencies at several load 2

factors. 3

Here’s a sample calculation. DOE would, 4

of course, need more research to determine the 5

appropriate loading points and their respective 6

weights to use in a calculation. 7

DOE did not analyze core deactiv ation 8

technology in the preliminary analysis, but does 9

intend to do so in the NOPR. It will mathematically 10

scale down conventional transformer designs, group 11

them into sets, and evaluate the combined cost and 12

efficiency over several loading arrangements. 13

One further twist is to use non

- identical 14

component transformers, which could offer the 15

greatest efficiency, but has the added challenge of 16

impedance matching. 17

Finally, DOE understands that applying 18

core deactivation in medium voltage applications ma y 19

have some additional challenges related to 20

switching. I don’t know if this non

- identical thing 21

is obvious to anyone. This is just the thought that 22

since one of the transformers would be in service 23

the most often, you’d like to allocate more of your 24

des ign resources to that, and less to the one that 25Executive Court Reporters (301) 565

- 0064 55 is the first to be switched off. 1

So now we have a comment. DOE seeks 2

comment on its proposal to use a weighted average 3

loss calculation to capture the efficiency segments 4

of core deactivation. And on the technology in 5

general, DOE requests input on any considerations 6

necessary for analyzing core deactivation systems of 7

non

- identical transformers on applications where 8

core deactivation would be useful and how core 9

deactivation would relate to the current te st 10

procedure. 11

MR. BROOKMAN: Yes, Please. Is it Robert? 12

MR. BERMAN: Just a question. Will DOE be 13

looking at effects of stress? 14

MR. BROOKMAN: Bob, is the little green 15

light on? 16

MR. BERMAN: Yeah. Will DOE also be 17

looking at the potential differ ences in stress and 18

wear on the transformer as you’re activating and 19

deactivating? 20

MR. COFFEY: You mean that if one is used 21

more often, it could wear more quickly? 22

MR. BERMAN: No, I’m talking about 23

equipment switched on and off, more often the stress 24

-- there might be additional stress for the 25Executive Court Reporters (301) 565

- 0064 56 switching of it on and off. 1

MR. COFFEY: DOE would certainly be 2

interested in learning about that. 3

MR. BERMAN: Are you

-- is DOE considering 4

any testing on that? 5

MR. COFFEY: We haven’t so far, but if 6

it’ s important and people comment on that, we’d 7

certainly look into it. 8

MR. BROOKMAN: Steve Rosenstock. 9

MR. ROSENSTOCK: Steve Rosenstock, EEI 10

again. Just to clarify, you’re only looking at this 11

for low voltage dry type transformer technologies, 12

not med ium voltage dry type or liquid filled, 13

correct? 14

MR. COFFEY: At the current time, that’s 15

correct. 16

MR. ROSENSTOCK: Okay. And again, is it

- 17

- again, what is going to be in this October

-- 18

well, again, it’s a difference in terms of again, 19

what the time frame to any revision to the test 20

procedure. That wasn’t me

-- it was talked about 21

you’re going to do it, but again, in terms of timing 22

of October 2011, October 2012, whether if you are 23

considering low voltage dry type, this could be a 24

big issue for manuf acturers. 25Executive Court Reporters (301) 565

- 0064 57 MR. BROOKMAN: Yes. Thomas. 1

MR. PATZNER: Thomas Patzner. I have 2

basically two questions. Number one, since it’s 3

basically a bank of transformers, are you going to 4

redefine the definition to include banks, because 5

today the definition of t ransformer says 6

transformer. Being in that case, all three 25s 7

would have to be measured at the 35 percent and then 8

banked together, based on the way I read the current 9

definition. 10

MR. BROOKMAN: Thank you. 11

MR. PATZNER: And number two. I don’t 12

under stand the need to change it. I see the 13

benefits of no core losses being turned off, but I 14

see that as an opportunity for manufacturers to work 15

with utilities and market to differentiate 16

themselves. I do not see a need for somebody that’s 17

using this techn ology to not have to comply at 35 18

percent. They would then be able to market to LEED 19

and other organizations the benefits of the losses. 20

MR. BROOKMAN: Thank you. Gary. 21

MR. FERNSTROM: Gary Fernstrom. This may 22

be a little off this subject, but as lo ng as we’re 23

talking about transformer loading, has DOE 24

considered the impact on losses of increasing non

- 25Executive Court Reporters (301) 565

- 0064 58 linearity and harmonics in building distribution 1

loads? 2

MR. COFFEY: I think DOE would certainly 3

be interested in receiving comment on that matter. 4

MR. FERNSTROM: Well, the question was, 5

has DOE considered that? 6

MR. COFFEY: Not expressly so far. 7

MR. FERNSTROM: Thank you. 8

MR. BROOKMAN: Yes, Peter. 9

MR. AMOS: Peter Amos, Warner Power. Let 10

me give a little background to this whole 11

considera tion of core deactivation technology. If 12

you go and dig down in the DOE’s own website, you’ll 13

find reports and data relating to the average level 14

of power running through building dry type 15

distribution transformers. And even though they’re 16

tested it at 35 percent, the average building 17

transformer is running at about 25 percent, and the 18

data isn’t clear on that, but there are some cases 19

which indicate lower. Certainly if you look at the 20

ASHRAE reports relative to schools, then the numbers 21

are lower still

. 22

So we have a legacy population, a lot of 23

transformers out there, running at considerably 24

below their optimum efficiency point. Then if you 25Executive Court Reporters (301) 565

- 0064 59 overlay that with efforts that are going on through 1

the DOE and other agencies, to improve building 2

efficiency, which after all is one of the biggest 3

ways this country can save energy. Buildings use 40 4

percent of the nation’s energy bill. That 25 5

percent average load in fact go down in the years to 6

come, and there’s talk of significant energy savings 7

in buildings that have been studied. 8

So, you know, if we do nothing about 9

transformers, we could see building transformers 10

running at 20 or even 15 percent of their nameplate 11

rating. That’s way off the sweet spot, and it’s 12

sliding down the curve, and at that point t he 13

efficiency becomes deplorable. So that is the 14

reason for this approach. 15

MR. BROOKMAN: Thank you. 16

MR. HURST: Can I go back

-- John Hurst. 17

Could I get an answer? I wonder if you were 18

referring to making harmonic mitigation transformers 19

and the im pact of that design on core efficiency and 20

total core weight? 21

MR. BROOKMAN: Gary. 22

MR. FERNSTROM: Gary Fernstrom. I’m not 23

sure I understand the question. I was simply asking 24

whether or not, with increasing harmonics in 25Executive Court Reporters (301) 565

- 0064 60 buildings, the impact of that had been considered on 1

energy losses. 2

MR. HURST: Well, we’re on the same 3

question, just perhaps a different look at it, 4

because if we build transformers that are well 5

suited to harmonic mitigation, we may change the 6

core construction and core content. And I don’t 7

know whether that’s interactive or be considered as 8

interactive in the process in particular looking at 9

low voltage distribution transformers. 10

MR. HURST: I don’t know the answer to the 11

question either, that’s why I asked. 12

MR. BROOKMAN: Ye s, please. Phil. 13

MR. HOPKINSON: Phil Hopkinson, HVolt, 14

Inc. I took an approach of trying to say, well, 15

let’s say that we take the exact example that has 16

been posed, which is a 75 kVA three phase

-- I’m 17

sorry, 75 kVA single phase and three 25 kVA singl e 18

phase, and so the very first thing I did was to make 19

the presumption that they were low voltage dry types 20

so that the energy efficiency measurement would be 21

at 35 percent load. And for each of the 22

transformers then, I wrote the losses down as one 23

would normally optimize, to what would be core loss 24

and what would be load loss. 25Executive Court Reporters (301) 565

- 0064 61 Then I took the DOE proposed load figures, 1

which were zero percent load, 15 percent load, 35 2

percent load, 50 percent load, and 75 percent load. 3

And then what I did was compute , on an Excel 4

spreadsheet, the losses that would go if we had a 25 5

kVA by itself running each of those loads, if we had 6

two 25 kVAs running each of those loads, if we had 7

three 25 kVAs running each of those loads, and one 8

75 kVA as the base running each of those loads. 9

What do you think the answer was? Well, 10

the answers worked out that at zero percent load, 11

there was a benefit. At 15 percent load, the 75 kVA 12

won, and at every higher load the 75 kVA won. So 13

what I would say from that, if the loading was 14

between zero and 15 percent, there would definitely 15

be an area where one could in fact potentially have 16

a benefit. 17

But I think maybe the right thing would 18

be, if in fact we have, as Peter proposed, a school 19

or something that had very low utilization, 20

especially at night, maybe on a clock you say, 21

okay, we’re just fundamentally going to turn 22

everything off except one transformer that feeds 23

clocks and I don’t know, stuff that is basically 24

trickle load. And then during the day, we’re just 25Executive Court Reporters (301) 565

- 0064 62 going to turn the real transformer on and forget it. 1

That might be the right way to handle this, 2

otherwise, you know, it didn’t seem to come out a 3

winner. 4

But this is an area that

-- it’s not the 5

first time it’s been posed. When I was working for 6

one of the major corporations, the same thing had 7

been posed, so basically I looked at it the same way 8

the last time, and I’m getting the same answers. 9

MR. BROOKMAN: Thank you. I want to make 10

sure that we’re trying to be responsive to the 11

questions that are in these co mment boxes, to the 12

extent possible. And as I read them, they’re really 13

quite specific. So to deal with the specific 14

questions that are here, that’ll be very helpful to 15

the Department. And I want to make sure as we go 16

along today that we try and stay fo cused on the 17

topic at hand, and not provide a more general 18

seminar. 19

MR. AMOS: I’d just like to make a very 20

brief comment as response to Phil. I’d like to 21

share with you some data, Phil, because intuitive, 22

you think you switch these on one

- third and two

23

third power, but that’s not the sweet spot. You can 24

optimize it further than that. We can talk about it 25Executive Court Reporters (301) 565

- 0064 63 off

- line. 1

MR. BROOKMAN: Yes, and there’ll be an 2

opportunity over lunch, for example. Then 3

additional comments on the specific questions you 4

see here listed in issue three and six. Okay. 5

We’re moving on. 6

MR. COFFEY: That wraps up the technology 7

portion, so now we’re at the screening analysis. 8

MR. BROOKMAN: Maybe we should pause and 9

take a break right now. 10

MR. COFFEY: That’s all right. 11

MR. BROOKMAN: Want to do that? It’s now 12

ten minutes after ten. How many of you are not used 13

to walking around in the Forrestal Building? Okay. 14

So, you need to wear your badge, visible, when 15

you’re walking around in the building, and there’s a 16

coffee s hop one floor below us. Either take the 17

elevators here, or you can go down the stairwell. 18

One floor below is a Dunkin Donuts. They’re not 19

very efficient, rather move slowly, so go quickly if 20

you’re going to get coffee. There are restrooms on 21

both ends of the hallway, and we’ll resume at 10:25. 22

(Whereupon, the meeting was recessed for a 23

21 minute period.) 24

MR. BROOKMAN: Let’s start. As a 25Executive Court Reporters (301) 565

- 0064 64 housekeeping matter, the Department likes to supply 1

a list, actually a Xerox copy of all the business 2

cards of th e attendees, and typically when people 3

register, the Department tries to grab a business 4

card, and a few of them are missing, and we’d like 5

to get them to Brenda, who is right over here, so 6

that they can make those copies. I have five or six 7

names here

-- Chris Bolduc, LBNL, Sampat, ASAP, Greg 8

Rosenquist, Paul Goethe, Gary Fernstrom, and William 9

Kohse from Navigant. So if you get a business card 10

to Brenda, then the Department can provide that 11

list. 12

So we’re going to then proceed

-- we’re 13

going to contin ue where we left off, which is slide 14

41, and we’re back with Brian Coffey. 15

**Screening Analysis** 16

MR. COFFEY: Okay. So just to remind 17

everybody, we finished with technology assessment, 18

and now we’re at the screening analysis. The 19

purpose of this is to rem ove the screening options 20

that DOE won’t consider in the engineering analysis. 21

DOE evaluates technology options on four criteria: 22

technological feasibility, practicability to 23

manufacturer install and service, adverse impacts on 24

equipment utility or availa bility to consumers, and 25Executive Court Reporters (301) 565

- 0064 65 on any impacts to health and safety. 1

Here’s a list of the technology options 2

DOE screened out and the criteria they failed on. 3

The majority were screened out due to technological 4

feasibility and having no working prototypes. A 5

couple of them were screened out on the basis of 6

practicability to manufacture. Nanotechnology 7

composites are new to this rulemaking, but the other 8

six options were also screened out in the 2007 9

rulemaking. 10

Comments on screening. DOE knows of no 11

cu rrent commercial efforts or prototype designs that 12

employ nanotechnology composites in distribution 13

transformers, but welcomes comments on such 14

technology and its implications for the future of 15

the industry. DOE invites comments on the 16

technology options tentatively eliminated during the 17

screening analysis. DOE also welcomes comment on 18

any proprietary concerns relevant to the design 19

options considered in the analysis. 20

MR. BROOKMAN: Jerry. Comment? Please 21

say your name for the record. 22

MR. ALLEN: Jerry Allen from Metglas. I 23

don’t know how this relates, but there are high 24

temperature transformers using Nomex and esters, and 25Executive Court Reporters (301) 565

- 0064 66 I don’t know that would be an advantage or 1

disadvantage, but their lines are being sold today, 2

with high temperature material in them. Nomex wire 3

insulation and ester fluids. 4

MR. COFFEY: Those actually are materials 5

that we do consider, and this would sort of refer to 6

materials not being used in transformers today. 7

MR. BROOKMAN: So elements that have been 8

screened out are the ones that are listed here. 9

Yes, please. Is it Dave? 10

MR. MILLURE: Yes, Dave Millure, Metglas. 11

We concur about amorphous metals in stack core 12

configuration is technically infeasible. 13

MR. BROOKMAN: Okay. Thank you. That’s 14

helpful to get that. And no comments so far on 15

nanotechnology composites. Anyone wish to weigh in 16

on that one since it’s a new item? Okay. We’re 17

going to move on then. 18

MR. COFFEY: Well, this actually concludes 19

my portion of the presentation, so I’ll invite my 20

colleague, Matt Hartley up to discuss the 21

engineering analysis. 22

**Engineering Analysis** 23

MR. HARTLEY: Hi. My name is Matt 24

Hartley. I’m with Navigant Consulting, and we are 25Executive Court Reporters (301) 565

- 0064 67 going to now discuss the engineering analysis. The 1

purpose of the engineering analysis is to develop a 2

relationship between the efficiency of a 3

distribution transformer and the manufacturer’s 4

selling price for that unit. DOE uses design 5

options discussed previously to characterize this 6

relationship. The cost and efficiency outputs of 7

the engine ering analysis are then used downstream 8

for the life cycle costs and payback period 9

analysis, and the national impacts analysis. 10

This slide shows how DOE

-- the key steps 11

that DOE used in the engineering analysis. First, 12

DOE subdivided its equipment cla ss groupings into 13 13

design lines with similar design principles, and 14

identified a representative unit for analysis within 15

each design line. Then DOE identified different 16

design option combinations to characterize the range 17

of possible efficiencies for th e rep unit. Next, 18

DOE developed cost inputs such as materials prices, 19

markups, and labor requirements. 20

DOE then used a software model to create 21

hundreds of optimized designs for each design option 22

combination, based on different A and B factors, 23

which I’ll explain in a few minutes. 24

These designs yielded varying levels of 25Executive Court Reporters (301) 565

- 0064 68 efficiency, so DOE developed candidate standard 1

levels, or CSLs, to identify specific levels of 2

efficiency for the analysis. Finally, DOE scaled 3

the results from the representative units to the 4

other unanalyzed kVA ratings and equipment classes. 5

As a general note, the majority of the 6

engineering analysis followed the same methodology 7

as DOE’s 2007 rulemaking. I’ll try to point out any 8

specific areas where the analysis differs fr om the 9

2007 rulemaking, but for those who were involved in 10

the previous rulemaking, much of this information 11

will seem familiar. 12

So as we saw previously, each of the ten 13

equipment class groupings span a range of kVA 14

ratings. In the engineering analysis, DOE 15

subdivided these equipment classes into 13 design 16

lines to group kVA ratings based on similar 17

principles of design construction, such as core 18

configuration. Since DOE will ultimately need to 19

scale to unanalyzed kVA ratings, it selected each 20

design li ne to span a range of ratings based

-- 21

where the 0.75 scaling rule would provide accurate 22

results. 23

24

Once the design lines were selected, DOE 25Executive Court Reporters (301) 565

- 0064 69 identified a single representative unit for each 1

design line. DOE bases its engineering analysis on 2

these repr esentative units. And representative 3

units selected were chosen based on high volume 4

ratings within a design line, and also to provide a 5

good reference point kVA for scaling to the other 6

unanalyzed ratings within that design line. 7

Again, for those who a re familiar with the 8

2007 rulemaking, these representative units will 9

look familiar because they are the same ones. 10

So we’ll now take a closer look at the 11

design lines and representative units selected for 12

the engineering analysis. So these colorful tab les 13

illustrate how DOE subdivided its equipment class 14

groupings. The larger tables here represent 15

equipment class groupings, while each colored 16

segment represents a different design line. Within 17

the design lines, a label indicates which kVA rating 18

was se lected as the represented unit. 19

So you can see for single phase, liquid 20

immersed units, DOE considered three design lines. 21

Design lines one and two span the same kVA range, 22

but examine any potential differences between 23

rectangular pad

- mounted units an d round pole mounted 24

units. And then design line three characterizes the 25Executive Court Reporters (301) 565

- 0064 70 set of larger single phase liquid immersed units, 1

with a representative unit of 500 kVA. 2

Similar tables to these can be found in 3

Chapter 5 of the TSD, including data for low voltag e 4

dry type and medium voltage dry type units. 5

This table shows additional descriptive 6

information about the representative units. You’re 7

looking at the first three design lines, and the 8

column all the way on the right indicates the 9

characteristics of th e representative unit that DOE 10

selected for its analysis. So, for example, the 11

bottom row shows that for its analysis of single 12

phase, liquid immersed distribution transformers, 13

between 250 and 833 kVA, DOE analyzed a 500 kVA unit 14

with a 65 degree tempera ture rise, operating at 60 15

hertz, with a 14400 volt primary and a 277 volt 16

secondary. 17

During its preliminary manufacturer 18

interviews, DOE heard that the primary voltage of 19

these single phase units should be changed to 12470 20

grounded wye / 7200 volt, whic h has a higher 21

shipment volume than the selected primary. However, 22

DOE retained its original primary voltage because 23

it’s in the same insulation class as the recommended 24

voltage, but may result in a costlier unit making it 25Executive Court Reporters (301) 565

- 0064 71 a more stringent analysis. 1

How ever, DOE would seek further comment on 2

the primary voltage used for these first three 3

design lines, or any other issue pertaining to the 4

representative units for single phase liquid 5

immersed units. 6

MR. BROOKMAN: So comments related to that 7

you see in i ssue box seven. Yes, Alan. 8

MR. TRAUT: Just a comment on the single 9

phase liquid immersed units. I would support the 10

change to the 14400 volt

-- because that increase 11

that you mentioned, as that provides a more 12

stringent analysis, you could take that t o the 13

extreme and look at 19920 as the extreme in that 14

case too and realize that all units below that would 15

be able to meet the standard. 16

One question I have in the details for 17

design lines one, two, and three, it’s not clear 18

that they’re all at the sa me BIL rating. Design 19

line one, I could not find a BIL rating. Design 20

line two is at 125; and design line three was at 150 21

BIL. I’m not sure if that was intentional or if 22

it’s just an inconsistency in the analysis. That’s 23

just a question. 24

MR. HARTLEY : So for liquid immersed 25Executive Court Reporters (301) 565

- 0064 72 transformers, DOE does not divide up its equipment 1

classes by BIL, however, we would welcome comment on 2

any other suggestions on how to approach that. 3

MR. BROOKMAN: Yes, Please, Alan. 4

MR. TRAUT: Just to follow up on that. 5

T he standard BIL rating for a 14400 liquid immersed 6

would be 125 BIL. 7

MR. BROOKMAN: In doing so, would you 8

describe what additional utility would be at having 9

that rating in there? 10

MR. TRAUT: Well, when you’re doing the 11

design work, you need to specif y the BIL, and as I 12

said, in the three design lines, they’re not 13

consistent. So I think at the minimum we would need 14

to be consistent and establish one BIL rating for 15

14400 volt for all three design lines to make them 16

consistent. 17

MR. BROOKMAN: Other co mments on liquid 18

immersed design lines and their representative 19

units. Yes. Please. 20

MR. HODGE: Jerry Hodge from Howard. I 21

think we would support the 125 BIL also, because in 22

general that’s what ANSI is calling for for 14400 23

volt transformers, so it m akes sense to use 125. 24

MR. BROOKMAN: Thank you. It’s helpful 25Executive Court Reporters (301) 565

- 0064 73 for the Department to receive affirmative comments 1

as well, just so you know. 2

MR. STAHARA: Ron Stahara, Central 3

Moloney. Just a technical comment on item two. You 4

have the rating for t he 25 kVA pole unit as 240/120, 5

and the standard is 120/240. It does have a 6

significant difference. 7

MR. BROOKMAN: Okay. Thank you. Good 8

clarification. Yes, please Alan. 9

MR. TRAUT: One additional comment on

-- 10

specifically on design line three. A s I mentioned 11

earlier, I think having standards above 500 kVA does 12

not really impact energy efficiency use nationally, 13

and also makes it very difficult and cumbersome for 14

both users and manufacturers of transformers. So we 15

would support a top limit of 500 kVA for the 16

standard, but retain 500 kVA as the design line for 17

that group. The reason being that size and weight 18

constraints are very critical, particularly in that 19

group of transformers. So I would also like to 20

encourage the Department to look at sett ing a 21

maximum weight, and perhaps a maximum tank size or 22

dimension on those transformers when doing the 23

analysis. 24

Some of the transformers that came out of 25Executive Court Reporters (301) 565

- 0064 74 the analysis were 6000 pounds, and there’s no way 1

anyone’s going to hang that up on a pole. So we 2

need to put some practical limits, and specifically 3

on design line three. 4

MR. BROOKMAN: So then your specific 5

thoughts on what they would be would be helpful. 6

MR. TRAUT: Right. I’ll do that in the 7

written comments to the Department. 8

MR. PHOUMINH: I have another comment as 9

well. 10

MR. BROOKMAN: Just one moment. Your name 11

is? 12

MR. PHOUMINH: John Phouminh. 13

MR. BROOKMAN: Thank you, John. Please. 14

MR. PHOUMINH: On top of the weight and 15

the sizes, I prefer the height as well, because 16

it’s, you know, changing out transformer, we don’t 17

want to change out the building, if possible. 18

MR. BROOKMAN: Okay. Gary Fernstrom. 19

MR. FERNSTROM: Maybe some of the

-- this 20

is Gary Fernstrom. Maybe some of the other 21

utilities around the table could respond to this. 22

I’m puzzled by the concern about weight for large 23

transformers. The ones that I typically see in the 24

PG&E service territory are pad mount, because of 25Executive Court Reporters (301) 565

- 0064 75 underground requirements, and we’re not typically 1

hanging large distribution transformers on p oles. 2

Is that unique to California and not a practice 3

across the country? 4

MR. BROOKMAN: Alan, you want to try that 5

one? 6

MR. TRAUT: Well, there are customers that 7

hang 500 kVAs on poles. 8

MR. FERNSTROM: Yes, but the question is, 9

certainly there are and must be, but is that 10

prevalent, or is it more prevalent to have surface 11

mounted transformers in that size range? 12

MR. TRAUT: I think for single phase 13

transformers, it’s probably more prevalent to be 14

pole mounted. 15

MR. BROOKMAN: I thought your comm ent, 16

Alan, went to the technology of the testing and all 17

that

-- your earlier comment. 18

MR. FERNSTROM: We were talking about the 19

size and weight issues. You’re talking about a 500 20

kVA single phase transformer? 21

MR. TRAUT: Yes. 22

MR. FERNSTROM: That a stonishes me too, 23

because we rarely see really, really large single 24

phase units when you start getting up into that 25Executive Court Reporters (301) 565

- 0064 76 size, you know, we typically use three phase. 1

MR. BROOKMAN: Alan, go ahead. 2

MR. TRAUT: The volume in those sizes is 3

very small, howeve r there are utilities that buy 4

round tank transformers in design line three. 5

Design line three is a round tank transformer. They 6

do buy those transformers and hang them on poles. 7

The IEEE standards cover those transformers up to 8

500 kVA for pole mountin g, and it becomes very 9

difficult to make a transformer that will hang on a 10

pole and meet the existing standards, much less 11

further or more stringent efficiency requirements. 12

MR. FERNSTROM: I can appreciate that. 13

Maybe we should give some consideration to changing 14

the design and mounting that type of transformer on 15

the ground. 16

MR. BROOKMAN: Jerry, you were next in the 17

queue. 18

MR. HODGE: Yes, we too have

-- 19

MR. BROOKMAN: Jerry, say your name again. 20

MR. HODGE: Jerry Hodge from Howard 21

Industries. 22

MR. BROOKMAN: You need to say your name

- 23

- Wendy has got to get all this on the record, so 24

please say your name. Jerry. 25Executive Court Reporters (301) 565

- 0064 77 MR. HODGE: We too build transformers that 1

have to be mounted on a pole, and weight and 2

dimensions are very critical, and it’s so mething I 3

think needs to be addressed while we’re making these 4

rules. 5

MR. BROOKMAN: Okay. Thank you. So for 6

you, all of you to comment, weigh in with the 7

specifics, that’s what the Department will need. 8

Yes. 9

MR. PHOUMINH: John Phouminh. The bigge st 10

size of transformers that will be hanged on pole is 11

333 kVA. That was on the previous DOE, and before 12

then as well, TSL2 or NEMA TP1. With the new 13

standard coming in place, we don’t know what we’re 14

facing. Given the height, possible the height 15

extens ions, maybe the weight as well, maybe we will 16

consider reducing it to maybe 167 or 250. We don’t 17

know. But height is an issue, and weight

-- so does 18

the weight, but height is the most important to us. 19

MR. BROOKMAN: Okay. 20

MR. STAHARA: Ron Stahara, Central 21

Moloney. We’re a manufacturer of liquid filled 22

distribution transformers, and we do face a lot of 23

limitations for the larger kVAs, both in weight, 24

height, and many dimensions, round, tall. And 25Executive Court Reporters (301) 565

- 0064 78 another issue that we have not addressed, with the 1

D OE requirements impedance for specific utilities. 2

The impedance of the transformer becomes an issue as 3

we get larger for specific utilities. There may be 4

a standard impedance that we can utilize, but there 5

are requirements within certain industrial utili ties 6

that we find difficult to meet. 7

MR. BROOKMAN: Okay. Other comments on 8

this, in this series? Yes, please. Your name for 9

the record. 10

MR. SAMPAT: Yes, Mahesh Sampat, EMS 11

Consulting. Specifically for design line two, where 12

we are looking at 25 k VA transformer, the question I 13

had was the document says 25 percent of unit will 14

result in pole change. Can you comment on that, and 15

does that apply to all units within that

-- for all 16

kVA, or is it just for 25 kVA? It’s not clear. 17

MR. HARTLEY: When y ou say 25 percent 18

require pole change, I believe that number would 19

have come from our consumer impact analysis. I 20

don’t have the answer to that off the top of my 21

head. 22

MR. SAMPAT: It seems that number is high, 23

because typical pole limitation is 1000 po unds, so 24

like 10, 15, 25 kVA doesn’t reach anywhere near 1000 25Executive Court Reporters (301) 565

- 0064 79 pounds, and if you just keep those three kVA, that’s 1

70 percent of the units right there. So 70 percent 2

of the units don’t even come into picture. So I 3

will revisit that question. 4

MR. BROOKM AN: That’s helpful. Thank you. 5

Yes, please, Robert. 6

MR. BERMAN: Yes, when you do revisit that 7

question, you may also want to take into 8

consideration that the pole issue is often, in many 9

areas, an issue for joint pole association, because 10

poles do mo re than simply hang transformers. They 11

hang all kinds of telecommunications equipment, 12

sometimes with or without the permission of the 13

utility, which is a particular problem in some 14

areas. So to ascribe the cost of a pole to a 15

efficiency standard and a t ransformer seems like a 16

bit of a stretch, given what the reality is for how 17

poles are bought and considered. So you might want 18

to look into that. 19

MR. BROOKMAN: Good. Thank you. Other 20

comments? We’re about to move on to the next 21

section. Okay. 22

M R. HARTLEY: Similar to the previous 23

slide, this slide shows detailed information for two 24

other representative units that DOE is specifically 25Executive Court Reporters (301) 565

- 0064 80 seeking comment on. The representative units for 1

design lines five and 13. On this slide, DOE would 2

like to spec ifically call out the primary voltages 3

of the representative units, highlighted in red. 4

For design line five, DOE currently uses a primary 5

voltage of 24940 grounded wye / 14400 volt delta. 6

However, during preliminary manufacturer interviews, 7

some manufac turers recommended that DOE change the 8

primary voltage to be 12470 delta, because this 9

voltage has a higher shipment volume and is more 10

costly than a comparable wye primary. 11

DOE is aware that the grounded wye voltage 12

connection currently used is more common for 13

residential distribution transformers, while the 14

proposed delta primary connection is most common for 15

industrial distribution transformers. 16

Now looking at design line 13, DOE heard 17

that a different primary voltage would be more 18

appropriate than the 12470 volt primary selected for 19

this 125 kV BIL unit. Some manufacturers stated 20

that a 125 kV BIL insulation class should use a 21

primary voltage of 24940 volts rather than the 22

voltage currently selected. 23

So at this time, DOE requests comment on 24

th e appropriate primary voltages to use for these 25Executive Court Reporters (301) 565

- 0064 81 two representative units. 1

MR. HURST: John Hurst. In the real 2

world, dry type medium voltage three phase units, 3

2000 kVA 12470, 480/277 with a 95 kV BIL is the 4

workhorse of that market. 5

MR. HARTLEY: So I should point out that 6

design line 13 is the only representative unit, the 7

only design line that’s selected to specifically 8

look at the highest BIL insulation class. So as 9

Brian mentioned previously, we divide medium voltage 10

dry type into three BIL group ings, so the BIL 11

selected of 125 cannot change. That’s part of the 12

definition of this design line. However, we do 13

examine other BILs for other design lines, which 14

aren’t presented here on this slide. 15

MR. BROOKMAN: Please. Your name. 16

MR. GREESON: R obert Greeson, Federal 17

Pacific Transformer. In the area of the BIL, the 18

12470, as you pointed out, was predominantly more of 19

a 95 kV BIL, but given the fact this is specifically 20

for 96 to 150, we believe that a more appropriate 21

voltage would be 24900 volt s

-- or somebody said 22

24940. When we say 125 kV BIL for a dry type, it’s 23

usually in the 24

- 9 range. The maximum usually we 24

see, for say a 12470 is around 110, but majority are 25Executive Court Reporters (301) 565

- 0064 82 60 and 95. So for that design line, though, and 1

that BIL rating, I think 2494 0 or 24900 is 2

appropriate. 3

MR. BROOKMAN: Thank you. 4

MR. HURST: John Hurst again. What drives 5

the representative unit selection? History or the 6

marketplace? 7

MR. HARTLEY: So

-- as we mentioned, we 8

divide the equipment class groupings

-- we divide 9

the equipment classes into 13 equipment class 10

groupings. They’re not all pictured here, but these 11

are meant to span the entire range of covered 12

product, and then within those design lines, we 13

select a single representative unit. So I think 14

where your com ment is coming from, you’re talking 15

about a 95 kV BIL. DOE does examine a 16

representative unit at that level. It’s not 17

presented on this slide here. It wasn’t one that we 18

were specifically seeking comment on, although it is 19

outlined in Chapter 5, and for that unit, there is a 20

corresponding representative unit that we examined. 21

And we would welcome comment if any of the 22

specifications for that representative unit should 23

be changed. 24

MR. BROOKMAN: Other comments on these two 25Executive Court Reporters (301) 565

- 0064 83 design lines as described her e? Yes, Alan. 1

MR. TRAUT: One final comment on the three 2

phase liquid immersed. I guess we would support the 3

use of the 14400 volt 125 BIL coil voltage as the 4

means of analysis for all liquid filled design 5

lines. That would also include design line fo ur 6

which is not listed here. 7

MR. BROOKMAN: Okay. Thank you. Other 8

comments on this? We’d like to move on. Okay. 9

MR. HARTLEY: Okay. At this time DOE 10

requests comment on any other aspects pertaining to 11

the design lines and representative units s elected 12

for the engineering analysis. So here we went 13

through a few selected ones. All 13 are outlined in 14

the technical support document. We’d like to 15

receive comment on any other design line 16

representative units. 17

MR. BROOKMAN: Yes, Thomas. 18

MR. PAT ZNER: Thomas Patzner. For the low 19

voltage three phase, we would suggest you add a 20

third design line, and that third design line would 21

be the 15 kVA, and it’s not really required for the 22

engineering analysis, but we feel it would be 23

extremely beneficial i n the national impact 24

analysis, because those products are readily 25Executive Court Reporters (301) 565

- 0064 84 available in the marketplace, and excluded. So if 1

you raise the efficiencies of the 15 kVA, the market 2

might trend to go to a sealed transformer that is 3

currently excluded because they’re readily 4

available. So we believe it would be beneficial to 5

add the 15 kVAs so that when you do the national 6

impact, you could do the national impact with a 7

shift from distribution to sealed, with those 8

volumes. 9

MR. BROOKMAN: Phil

-- if you could

-- 10

tha nk you. Then other

-- you see the issue box 11

there. This is the all other comments on this 12

subject matter box. So additional comments? Okay. 13

We’re moving on then. 14

MR. HARTLEY: After identifying 15

representative units for analysis, DOE selected 16

design options to characterize the range of 17

efficiencies possible for each of these rep units. 18

DOE selected these design options from the list of 19

potential technology options that were not screened 20

out of the analysis. When selecting design options, 21

DOE tried t o capture the most common designs in the 22

industry, and also the maximum efficiency level for 23

each rep unit. 24

These include various core configurations, 25Executive Court Reporters (301) 565

- 0064 85 core steels, and winding materials. A table here 1

presents the various designs that were considered i n 2

the analysis for each of these options. So as you 3

can see, DOE considered a large variety of design 4

types, including wound and stacked cores with and 5

without mitering, various core steels from M12 all 6

the way up to SA1 amorphous, and both aluminum and 7

c opper windings. As a note, in this rulemaking, DOE 8

is considering amorphous cores for all of its dry 9

type design lines, whereas in the previous 2007 10

rulemaking, DOE only looked at amorphous core 11

designs for its liquid immersed design lines. 12

This slide p resents an example of the 13

different design option combinations selected for a 14

representative unit, and you’re looking at design 15

line seven, three phase, 75 kVA low voltage dry type 16

rep unit. In general, these options are presented 17

in ascending order of ef ficiency, starting with an 18

M12 stacked, but lapped core, and aluminum windings, 19

all the way up to an SA1 amorphous core, using 20

copper windings as the maximum efficiency level. 21

In the analysis, several design option 22

combinations using aluminum conductors were not 23

modeled in time to include in the downstream 24

analyses, such as design options seven and nine 25Executive Court Reporters (301) 565

- 0064 86 here. While these design options are not included 1

in the current life cycle cost or national impacts 2

analyses, DOE presents them in the engineering 3

analy sis for comment, and intends to include them in 4

the NOPR analyses. 5

DOE distinguishes these designs from the 6

reference case design option combinations and calls 7

them supplementary design option combinations in 8

Chapter 5 of the TSD. I should also add that all 9

design option combinations for each representative 10

unit are presented in Chapter 5 of the TSD. 11

MR. BROOKMAN: I hesitate to put you in a 12

mess. Mahesh. 13

MR. SAMPAT: Mahesh Sampat, EMS 14

Consulting. One of the design options that’s not 15

considered in low voltage dry is the wound core. 16

MR. HARTLEY: For dry types, we have not 17

looked at wound core, as we’ve heard and found that 18

typically the stack core would be most common. 19

While there are many design options that could be 20

considered, DOE has to focu s in on select ones, but 21

we do welcome comment on other considerations for 22

why wound core should be examined specifically. 23

MR. SAMPAT: It just

-- it may allow 24

manufacturer to stay with the conventional material 25Executive Court Reporters (301) 565

- 0064 87 but still gain the higher efficiency than the stack 1

core. So wound core, conventional construction, may 2

fit between stack and amorphous. 3

MR. BROOKMAN: So those written comments 4

would be really helpful, because this design option 5

combination

-- that’s important for the Department. 6

Gary. 7

MR. FERNSTROM: Gary Fernstrom. I’d like 8

to second that. I think it’s important for DOE in 9

its analysis to look at all of the opportunities, 10

particularly what I would characterize as the low 11

hanging fruit, or

-- you know, get the biggest 12

impact for the dolla r spent, and leaving this 13

particular design out, it is definitely an 14

oversight. 15

MR. BROOKMAN: Thank you. Andrew deLaski. 16

MR. deLASKI: So I just

-- I was trying to 17

understand the response back from DOE on why it 18

wasn’t considered in the initial analy sis? I 19

missed what you said, if you could just restate 20

that? 21

MR. HARTLEY: Sure. Obviously, there are 22

a multitude of different design option combinations 23

that could be selected, and DOE has to focus in on 24

key ones, so what we’ve tried to do is look at the 25Executive Court Reporters (301) 565

- 0064 88 ones that we consider to be the most popular in the 1

industry, and also the ones that can achieve the 2

highest efficiency level. Specifically here, we 3

were looking at design option combinations that were 4

analyzed in the previous rulemaking, and a few 5

a dditional combinations of materials. So for the 6

wound cores, I think that’s a material that if 7

stakeholders feel would be

-- have a significant 8

impact on the analysis, that’s something DOE’s 9

interested in hearing. 10

MR. deLASKI: Right. I think the 11

impor tant thing is to get

-- don’t forget that cost 12

to save energy, not just

-- you need the whole 13

curve, not

-- the whole continuum, not just what 14

people are doing today, and what the best is, but 15

what’s the continuum look like, and that’s what 16

we’re trying to show here. 17

And then I had a question about the models 18

that you starred here, the design options that you 19

starred. And if you have

-- these aluminum

-- using 20

aluminum as the both primary and secondary conductor 21

was something that you included in a subseq uent 22

analysis, so it’s not represented

-- just to be 23

clear

-- that did not flow through to the subsequent 24

levels of this analysis? 25Executive Court Reporters (301) 565

- 0064 89 MR. HARTLEY: That's correct. In this 1

case, design seven and nine, which we call 2

supplementary, were not completed in time to flow 3

through to the life cycle cost or national impacts. 4

They’re presented in Chapter 5 for comment, and DOE 5

does intend to use them moving forward in the 6

analyses, but they won’t be reflected in any of the 7

economic results. 8

MR. deLASKI: And do thos e options tend to 9

be lower cost options than the other options that 10

are modeled here? 11

MR. HARTLEY: In general, the aluminum 12

conductors, compared to the copper conductors, would 13

be a lower cost, and typically, a slightly lower 14

efficiency. So they just g enerate a different space 15

on our cost efficiency span. 16

MR. deLASKI: Okay. Thank you. 17

MR. BROOKMAN: Mahesh. 18

MR. SAMPAT: I guess before you come up 19

with the final ruling

-- Mahesh Sampat, EMS 20

Consulting, excuse me. But before you come up with 21

the final ruling, you will factor in the value of 22

the supplementary designs, is that correct? 23

MR. HARTLEY: Absolutely. Moving forward 24

in the analysis, the supplementary designs will be 25Executive Court Reporters (301) 565

- 0064 90 folded in to the reference case results. 1

MR. BROOKMAN: Okay. Steve Rosenstock. 2

MR. ROSENSTOCK: Steve Rosenstock, EEI. 3

Again, to follow on, basically so, you know, our 4

comment period is in two weeks, but these two 5

designs won’t be reflected until the NOPR stage, is 6

that correct? Until the technical support document 7

is updated for the

-- possible either the NOPR or 8

the determination stage? 9

MR. HARTLEY: They are reflected in 10

Chapter 5 of the technical support document, 11

currently. Soon actually we’ll be looking at just 12

an example of some of the outputs, a couple point s 13

to show that the different designs are considered. 14

They are included in Chapter 5, so DOE does seek 15

comment on them. We just wanted to clarify that 16

they did not flow through to the economic analyses, 17

so they won’t be reflected in the later analyses. 18

MR. ROSENSTOCK: Thank you. 19

MR. BROOKMAN: I was just flipping back to 20

the slide eight, where DOE says the comment period 21

closes April 18 th , is that correct? 22

MR. RABA: Yes. 23

MR. BROOKMAN: So you have

-- yes, pardon 24

me, Jerry. 25Executive Court Reporters (301) 565

- 0064 91 MR. ALLEN: (off micr ophone) 1

MR. BROOKMAN: Jerry, pardon me. Will you 2

turn your microphone on? 3

MR. ALLEN: Okay. When you say full 4

mitered, do you mean full miters as opposed to step 5

lap? 6

MR. HARTLEY: Yes. We’re looking at a 7

full miter core. 8

MR. ALLEN: Because I’ m wondering if step 9

lap should be considered in some of those bigger 10

units of dry types. 11

MR. BROOKMAN: What would be your logic 12

for that? 13

MR. ALLEN: Lower core losses. 14

MR. BROOKMAN: Okay. 15

MR. HURST: John Hurst. I must have been 16

behind the ti mes here because I thought we were 17

looking at seven and nine and the examples, and my 18

question really is, things that are not on this 19

list, if you get information can it at least be 20

considered in some kind of sidebar way according to 21

this? I mean we’re th inking 75 kVA amorphous 22

symmetrical core transformers. 23

MR. BROOKMAN: John, what are you 24

suggesting is missing that should be included? 25Executive Court Reporters (301) 565

- 0064 92 MR. HURST: I think that a

-- in the core 1

configuration, we make

-- we make symmetrical wound 2

core SA1 75 kVA distri bution transformers in a cost

3

competitive fashion in production with achieving the 4

same efficiencies using silicon steel. 5

MR. BROOKMAN: As I understand it, one 6

thing I really like about these slides, if you look 7

at the chevrons on the left hand side, it 8

illustrates in the stream of analysis that it’s 9

conducting, what they’re trying to accomplish in 10

that segment. And so as I understand it, these are 11

the possible design options, and you’re saying, 12

John, that what you do falls outside of this 13

representativ e range of design options? 14

MR. HURST: Yes. 15

MR. BROOKMAN: Okay. Good. That’s really 16

fine. 17

MR. HARTLEY: And I’d like to actually 18

add, DOE did consider a symmetric core sensitivity 19

analysis which we’ll be discussing in a few slides, 20

so we actually do look at symmetric cores for design 21

line seven. We’re distinguishing that from what’s 22

here which we consider to be a reference case at 23

this point. 24

MR. BROOKMAN: So additional comments on 25Executive Court Reporters (301) 565

- 0064 93 this, especially these two slides here? Okay. 1

MR. HARTLEY: We may have actually already 2

covered some of this ground, but DOE would like to 3

welcome comment on any other design option 4

combinations selected for the preliminary analysis, 5

specifically actually, we’re seeking comment on any 6

design option combinations that would yield an 7

efficiency between that of the domain refined steels 8

that were considered and the amorphous steel. 9

MR. BROOKMAN: We’ve covered it? No 10

additional comment? Okay. 11

MR. HARTLEY: In the next step of the 12

engineering analysis, DOE dev elops cost inputs. A 13

list of materials prices was determined for a five 14

year time frame and the total labor hours required 15

to build each design were determined through 16

conversations with manufacturers and industry 17

experts. DOE considered 2010 materials p rices for 18

its reference case analysis, but also looked at high 19

and low materials price sensitivities based on 2008 20

and 2006 data, respectively. 21

Next, DOE calculated markups to use in its 22

analysis to account for items such as scrap and 23

handling, factory overhead, and non

- production 24

costs. A fully burdened labor rate was also 25Executive Court Reporters (301) 565

- 0064 94 calculated to determine the total labor cost. These 1

markups are presented on a table on this slide which 2

shows the markup amount and a brief explanation. 3

For scrap and handling, DOE reduced the 4

standard 2.5 percent markup to 1.5 percent for 5

prefabricated amorphous cores. DOE also accounted 6

for additional scrap when analyzing fully mitered 7

cores. 8

For factory overhead, DOE applied a 12.5 9

percent markup to all designs, including amorphous 10

designs using a prefabricated core. Additionally, 11

DOE accounted for shipping costs in the 12

manufacturer’s cost calculation, because DOE 13

understands that these costs are typically borne by 14

the manufacturer and included in their profit markup 15

calc ulations. 16

This treatment of shipping costs is 17

different from what DOE did in the 2007 rulemaking, 18

where shipping costs are accounted for after the 19

manufacturer’s profit markup. 20

The remaining markups are explained in 21

this table, and also in further deta il in Chapter 5 22

of the TSD. 23

MR. BROOKMAN: Steve Rosenstock. 24

MR. ROSENSTOCK: Steve Rosenstock, Edison 25Executive Court Reporters (301) 565

- 0064 95 Electric Institute. Just kind of curious, that 1

shipping cost, is it

-- what fuel price was that set 2

on? 3

MR. HARTLEY: I don’t know the exact fue l 4

price off the top of my head. I believe it’s 5

outlined in Chapter 8 of the TSD. 6

MR. ROSENSTOCK: Because I

-- again, Steve 7

Rosenstock

-- I figure it would be directly related 8

to the cost of probably diesel fuel for commercial, 9

industrial type transport ation, and rather high 10

these days. Thanks. 11

MR. BROOKMAN: Okay. Mahesh. 12

MR. SAMPAT: I don’t know about the 13

markup, but if I look at the liquid filled 14

transformer, and if I look at the final price of the 15

unit, it’s significantly higher than market pr ice. 16

Somewhere in the cost rollup, either the material 17

cost is overstated or the markups are overstated. 18

The end result is significantly higher than the 19

market prices. 20

MR. BROOKMAN: As you look at this table, 21

can you tell where the discrepancy is? Or anybody 22

else? That’s what DOE’s asking for here. Robert. 23

MR. BERMAN: Yeah, I think one place where 24

the discrepancy may be is that

-- it’s been my 25Executive Court Reporters (301) 565

- 0064 96 experience that manufacturers don’t price this way, 1

necessarily. That they will look at what their 2

cost s are for the unit, and look at what the market 3

is in terms of competition, and what they’re going 4

to have to do in order to make a competitive bid. 5

The factory overhead, the shipping, 6

anything else that is on top of the cost

-- those 7

are all the same d ollars, and to try to account for 8

those separately and come up with a separate number 9

for each is going to end up overstating what the 10

total price or cost is going to be. 11

MR. BROOKMAN: How would you suggest then, 12

DOE approach this analysis? 13

MR. BERMAN : I think that we need to leave 14

the markup and the business strategy to the 15

manufacturer, and focus the analysis only at the 16

cost level, and stop right at what it costs to 17

manufacture

-- material and labor and so forth, to 18

assemble the finished unit, and stop there. 19

MR. HARTLEY: I’d just like to clarify. 20

These markups are used to develop the cost, with the 21

exception of non

- production markup, which includes a 22

profit factor. There are then subsequent markups to 23

account for distribution channels, and th ose will be 24

covered later on in the presentation. 25Executive Court Reporters (301) 565

- 0064 97 MR. BROOKMAN: DOE’s trying to figure out 1

some reasonable way to do this, and so any specific 2

ideas for how they can get it more accurate would be 3

most welcome. Andrew deLaski. 4

MR. deLASKI: Well, base d on the prior 5

comment, maybe this belongs later, but I’ll say it 6

now just to get it on the record, which is that one 7

approach to get the final cost

-- and I know you’re 8

doing right now, you’re doing the cost to 9

manufacturer

-- would be to go talk to utili ty 10

companies, find out what they pay. Go to the 11

market, you have a market here, readily, utility 12

companies that have to seek rates to pay for this 13

equipment from utility commissions, and I would 14

believe you’d have some success in getting data from 15

the mar ket. And if you do that, one of the things 16

you need to do is make sure you go to a range of 17

utility companies, because I suspect that the 18

largest companies face different pricing than a 19

small coop. I think you also need to look at that 20

range of prices th at are paid in the marketplace. 21

MR. BROOKMAN: Jerry. 22

MR. ALLEN: Yeah, one thing I did, I went 23

out on the internet and looked at public bids in the 24

utilities. The prices were way lower than your 25Executive Court Reporters (301) 565

- 0064 98 final costs. You’re probably up by 1.6, 1.7. And 1

thos e bids wouldn’t be the people who would get the 2

lowest cost anyway, because they’re not the big 3

utilities. 4

MR. BROOKMAN: So that’s publicly 5

available on the web? 6

MR. ALLEN: Publicly available on the 7

internet. I found a lot of them. I don’t know how 8

many of them would be out there if you dig for a few 9

days, but I got quite a

-- five or six examples

-- 10

price list of a range of kVAs of oil filled anyway, 11

and I think one dry type. 12

MR. BROOKMAN: Maybe in your written 13

comments you could say what the so urces were? 14

MR. ALLEN: Yeah. 15

MR. BROOKMAN: Okay. Thank you for that. 16

Steve Rosenstock. 17

MR. ROSENSTOCK: Steve Rosenstock. EEI. 18

We are going to submit some cost data

-- we had 19

asked the members what their experience had been 20

over the last few ye ars, so we’re going to have some 21

-- I’ll just say it’s data based on the information 22

received from member companies that we will submit 23

with our comments. 24

MR. BROOKMAN: Okay. Thanks. So 25Executive Court Reporters (301) 565

- 0064 99 additional comments, perhaps final? We’re about to 1

move on here. Okay. 2

MR. HARTLEY: Okay. I’m actually going to 3

go to a slide that you won’t have in your deck, so 4

please follow along with the screen. We’ve actually 5

already covered much of this ground, but I just want 6

to open up a few items specifically for comm ent. 7

First, DOE is seeking comment on its 8

decision to use 2010 materials prices in the 9

reference case scenario, and other years’ materials 10

prices for its sensitivity analyses, as opposed to 11

doing a five year average price. 12

Second, I’ll read them out here and then 13

we can just go through them. DOE is welcoming 14

comment on its decision to use the same factory 15

overhead markup for designs that use a prefabricated 16

amorphous core, as we do for designs where the 17

manufacturer actually produces the core. 18

And finally, DOE is seeking comment on its 19

decision to include shipping costs in the 20

engineering analysis as a component of 21

manufacturer’s selling price. 22

MR. BROOKMAN: Comments in response to 23

these comment boxes. Steve Rosenstock. 24

MR. ROSENSTOCK: Steve Rosenstock EEI. In 25Executive Court Reporters (301) 565

- 0064 100 terms of issue 13, we agree with that approach. We 1

think that’s

-- you know, there’s been quite the 2

gyration in commodities prices over the last several 3

years, so I think this approach is a real approach. 4

MR. BROOKMAN: Yes, Alan. 5

MR. TRAUT: With respect to the material 6

prices, I mean I agree with the sensitivity analysis 7

and 2010 is as good as any, although 2011 is proving 8

to be even higher commodity cost than 2010. Also it 9

appears that when you look at the individual 10

categories, for example, copper and aluminum, it 11

seems to be rather disjointed in perhaps the metal 12

prices that are underlying those costs are not 13

equal. For example, I think in some of the cases 14

the copper wires were too low and the aluminum wires 15

were too high. I t doesn’t appear that they were all 16

developed with the same base metal cost underlying 17

them. 18

It would be helpful if the Department 19

could develop a model for

-- specifically for 20

conductors

-- that worked off of published indices, 21

such as COMEX or LME for those metals, and added 22

convergent cost to get to the various wire sizes. 23

That way, we would know that the conductors, both 24

copper and aluminum, are on the same basis when the 25Executive Court Reporters (301) 565

- 0064 101 analysis is done. 1

MR. BROOKMAN: And would you repeat those 2

published sources are? 3

MR. TRAUT: COMEX, for example, for 4

copper, and the London Metals Exchange, LME for 5

aluminum. They’re very typical. 6

MR. BROOKMAN: Okay. 7

MR. HARTLEY: One thing I would add to 8

that, what would be useful for us is to know, once 9

we take those base prices, what sorts of markups and 10

what ... those markups should be applied to reach a 11

final price. 12

MR. BROOKMAN: Yes, Andy deLaski. 13

MR. deLASKI: Commenting on the issue 14

boxes, just to respond to those issues 14 and 15. 15

In 14 you say that you made a kind of a decision on 16

how to handle the markup for amorphous core, 17

basically treating it the same, whether it’s a 18

prefabricated core or whether the manufacturer is 19

putting up their own core. And why that decision? 20

MR. HARTLEY: So DOE is using the sa me 21

factor of markup on all its designs, and this is 22

meant to account for factory overhead that would be 23

plant

- wide, and from our experience, what we’ve seen 24

is that typically an amorphous core production area 25Executive Court Reporters (301) 565

- 0064 102 would be a relatively small part of the product ion 1

facility, and therefore we thought it would be 2

appropriate to give it the same markup as the rest 3

of the production floor, but we do welcome comment 4

on why that should be different. 5

MR. deLASKI: Okay. And then in the next 6

issue, again, did you find data in the market that 7

indicated this is the practice? 8

MR. HARTLEY: From conversations that 9

we’ve had with several manufacturers, we had 10

received this comment which is why we actually 11

changed the handling of shipment costs for this 12

rulemaking as oppos ed to how they were treated in 13

the previous rulemaking. That was not a complete 14

survey of all manufacturers, which is why we’re 15

asking for comment on it here. 16

MR. BROOKMAN: Alan. 17

MR. TRAUT: Just one comment on the markup 18

side, in my experience, the factory overhead is a 19

markup on labor content rather than materials, and 20

if it were done in that manner, this question might 21

go away, because the labor associated with making 22

the core would not be in there. Also, with 23

amorphous cores, I think there needs to be something 24

-- I’m speaking specifically on liquid filled right 25Executive Court Reporters (301) 565

- 0064 103

now

-- I think there needs to be an additional core 1

assembly time allowance for amorphous cores. That’s 2

presently not in the analysis. 3

MR. BROOKMAN: Factory overhead doesn’t 4

include ma terials, Alan? 5

MR. TRAUT: Typically, no. 6

MR. BROOKMAN: Wow. 7

MR. HURST: John Hurst. I support the 8

fact that many

-- at least I’m more experienced in 9

the dry type market

-- most dry type manufacturers 10

do burden labor with overhead, and then the other 11

question, having to do with

-- well, I guess I can 12

address this in comment

-- but, I certainly have the 13

experience to understand extra handling used for 14

large, fragile, amorphous cores. I made 2500 kVA ... 15

cores and they were challenging. But I think that 16

this leaves out construction methods that would make 17

that not the case, and I think that the hardware 18

also leaves out construction methods where that’s 19

not the case. So I will provide information 20

regarding that in my written comment. 21

MR. BROOKMAN: Thank you. So have we 22

moved to 16 yet? Let’s move on to the next slide 23

and cover that. 24

MR. HARTLEY: Okay. Actually, this is the 25Executive Court Reporters (301) 565

- 0064 104 item that Mr. Hurst was just referring to, so it’s a 1

special case. DOE adjusted its estimates for labor 2

hours and hardw are costs for large, dry type 3

designs, using an amorphous core. Manufacturers and 4

industry experts informed DOE that large dry type 5

designs using an amorphous core would require 6

special handling considerations, because the 7

amorphous material is very thin and could become 8

difficult to work with in such a large core. 9

As a result, DOE increased the labor 10

requirements for each of these amorphous designs by 11

ten hours over the other design options within those 12

rep units. Similarly, DOE heard that large dry type 13

amorphous designs would require additional bracing 14

to contain the coil and prevent short

- circuit 15

problems. Industry experts estimated this 16

incremental bracing as seven percent of the core and 17

coil weight, which equals about $230 to $330 dollars 18

per d esign. 19

At this time, DOE requests comment on 20

these additional cost considerations for amorphous 21

designs in large amorphous design lines, which would 22

be design lines 10, 12, and 13. DOE also seeks 23

comment on whether these additional costs should 24

apply to liquid immersed amorphous design lines that 25Executive Court Reporters (301) 565

- 0064 105 are 1500 kVA and greater. 1

MR. BROOKMAN: So Matt, this is something 2

of a midpoint representation or something, is that 3

right? 4

MR. HARTLEY: Which? 5

MR. BROOKMAN: Well, these additional 6

labor costs and h ardware costs. John, your comment 7

suggested that specialization could diminish these 8

costs. 9

MR. HURST: Yes. 10

MR. BROOKMAN: I thought I heard you, yes. 11

MR. HURST: I made both kinds, and what 12

I’m making now has substantially lower costs in 13

those are as. 14

MR. BROOKMAN: So those comments in 15

writing to the Department, most helpful. 16

MR. HARTLEY: And just to clarify, that 17

those designs

-- are you saying they’re not using 18

the distributed gap wound core configuration that we 19

look at for these amorphous designs? Is it 20

different? 21

MR. HURST: Well, a distributed gap is not 22

really a wound core. 23

MR. HARTLEY: I’m sorry, yeah. 24

MR. HURST: But yes, that’s what I’m 25Executive Court Reporters (301) 565

- 0064 106 saying. 1

MR. BROOKMAN: Thanks, John. That’s 2

helpful. Comments on slide 56? Okay. Let’ s keep 3

moving along here. 4

MR. HARTLEY: The next step in the 5

engineering analysis is to model optimized designs 6

for each of the design option combinations that were 7

previously identified. DOE contracted with 8

Optimized Program Service to model these opti mized 9

designs. For each design option combination, OPS 10

created designs based on over 500 combinations of 11

different A and B values. A and B values represent 12

the present value of future core losses and winding 13

losses, respectively. And these valuation inp uts 14

are oftentimes used by customers in the industry 15

when placing an order, and are described in more 16

detail in Chapter 5 of the TSD. 17

After running all the A and B combinations 18

for each design option, and removing any designs 19

below the minimum efficien cy level, DOE was left 20

with approximately 2500 unique designs for each of 21

the 13 representative units, not including 22

additional supplementary designs that we mentioned 23

previously. 24

For each of these designs, DOE receives 25Executive Court Reporters (301) 565

- 0064 107 data on the construction, windings , electrical 1

analysis, and bill of materials. Using the bill of 2

materials and the materials prices discussed 3

previously, DOE is able to determine the materials 4

cost of each design. DOE then applies the other 5

cost factors and markups to determine the tota l 6

manufacturer’s selling price. 7

A temperature corrected efficiency is also 8

determined from OPS’s electrical analysis report. 9

DOE uses these manufacturer’s selling price and 10

efficiency pairings for each design as outputs for 11

the engineering analysis an d inputs to its 12

downstream analyses. A complete listing of all 13

engineering outputs, including MSP and efficiency is 14

available on DOE’s distribution transformers 15

website. 16

And here we’re showing you a graph that 17

illustrates the basic outputs of the engin eering 18

analysis, the efficiency and manufacturer’s selling 19

price of the rep unit. Each of the dots on this 20

graph corresponds to a unique, optimized design, and 21

the different colors indicate the various design 22

option combinations considered for the rep uni t. 23

So for example, in this chart, the pink 24

dots represent designs that use an amorphous core 25Executive Court Reporters (301) 565

- 0064 108 and copper windings. And charts such as these are 1

available in Chapter 5 of the TSD. 2

Moving along, as Brian mentioned 3

previously, DOE considered symmetric c ore designs 4

for its preliminary analysis, though they were not 5

considered in DOE’s 2007 rulemaking. DOE’s 6

symmetric core analysis is presented as a 7

sensitivity in the preliminary analysis, separate 8

from the reference case results. DOE was unable to 9

ident ify a company that could model this core 10

configuration, but it was able to gather information 11

on this core design through manufacturing 12

interviews, published literature, and by examining a 13

handful of designs provided by manufacturers. 14

After analyzing the information gained 15

through these data sources, DOE identified three 16

design changes that are typical of symmetric core 17

designs, which are typically that core losses and 18

core weight are reduced, while labor requirements 19

are increased. While the data DOE re ceived showed 20

varying levels of impacts on these three 21

characteristics, DOE was able to identify ranges of 22

impacts. Based on these ranges, DOE selected a 23

median value that it used to make rough adjustments 24

to these three characteristics in each of its 25Executive Court Reporters (301) 565

- 0064 109 tra ditional core designs, as outlined in this table. 1

DOE understands that these approximations 2

are simply rough adjustments, but wanted to provide 3

data for discussion. 4

The next slide here is requesting comment 5

on symmetric core designs and specifically the 6

adjustments that were used to estimate symmetric 7

core cost efficiency relationships. So I think we 8

had already heard that, perhaps

-- the labor 9

requirement adjustment should not be increased, but 10

held constant. At this time, DOE would welcome any 11

fur ther comments on its analysis of symmetric core 12

designs. 13

MR. BROOKMAN: Yeah, let’s return to slide 14

60 on the screen. So let’s get comments on this. 15

Mahesh, do you want to

-- No? John, go ahead. 16

The adjustments that the Department’s 17

asking for comm ent on, as reflected in the bottom of 18

slide 60, reduced core losses, they call this a 19

range of impacts. Reduced core losses, 15.5 percent 20

-- minus 15.5 percent. Reduce the core weight, 21

minus 17.5 percent; and increase labor costs plus 55 22

percent. 23

MR. H URST: I guess my retirement plan is 24

worthless now. 25Executive Court Reporters (301) 565

- 0064 110 MR. BROOKMAN: So be more specific then. 1

MR. HURST: Comparing 75 kVA three phase 2

low voltage distribution transformer rated CSL3 or 3

in that vicinity, our labor time is exactly the same 4

as one of the major manufacturer’s labor time, and I 5

can build that same transformer with no additional 6

labor at 99.2 efficient. I certainly don’t need to 7

build it there, but

-- and my materials are now

-- 8

that’s comparing to a very, very bad cut core in 9

terms of the f act that the machine that is cutting 10

that butt lap core is very old and does a lot of 11

damage, so there may be people who are further along 12

in that business, but a major manufacturer is doing 13

that in the marketplace, and surviving. 14

So our complete core pr oduction time is 15

less than our cutting and stacking. The losses are 16

lower and the total materials cost is less. 17

MR. BROOKMAN: Thank you, so the specifics 18

would be very helpful to the Department. 19

MR. HURST: Certainly. 20

MR. AMOS: I would just like t o concur 21

with John. 22

MR. BROOKMAN: Peter, please. 23

MR. AMOS: Yes, Peter Amos. I would just 24

like to concur with John Hurst and maybe those of us 25Executive Court Reporters (301) 565

- 0064 111 who are involved in some of these symmetric cores 1

have not been as effective in communicating with DOE 2

as w e should, but I think it certainly needs to be 3

addressed in the written response, because there are 4

some significant errors here which I think would 5

create

-- essentially the wrong output from this 6

whole exercise, and I think that would be a real 7

pity. 8

M R. BROOKMAN: I think some of you are 9

fairly new to these proceedings. Your data can be 10

shielded when sent to Navigant

-- that’s correct, 11

right? So that you can disclose whatever your level 12

of comfort is, knowing that it won’t be seen by 13

anybody else. O kay, final comments on this segment? 14

MR. HARTLEY: Okay. Once DOE generated 15

all its designs in the engineering analysis, it 16

selected several candidate standard levels, or CSLs, 17

to analyze various efficiency benchmarks. The CSLs 18

span the range of dist ribution transformer 19

efficiencies for each representative unit, from the 20

baseline efficiency of the current standard level, 21

to the maximum technologically feasible efficiency 22

level. 23

When selecting CSLs, DOE considered 24

several criteria. First, DOE sele cted levels that 25Executive Court Reporters (301) 565

- 0064 112 harmonized across its single phase and three phase 1

rep units. So, for example, DOE considered an 2

efficiency level of 99.27 percent for design line 3

one, a 50 kVA single phase unit, and then the same 4

efficiency for design line four, a 150 k VA three 5

phase unit. 6

Second, DOE examined equally spaced 7

efficiency increments between the baseline 8

efficiency and the max tech efficiency. 9

Lastly, DOE considered several benchmark 10

efficiency levels such as NEMA Premium for low 11

voltage dry type tra nsformers. 12

These discrete CSLs allowed DOE to analyze 13

incremental increases in efficiency and serve as the 14

basis for trial standard levels selected in the 15

NOPR, which we’ll discuss in just a moment. 16

So here we’re showing you the same graph 17

from befor e, but with the various CSLs superimposed 18

over the data. Here CSL zero through six 19

characterize the efficiency increments DOE examined 20

between the baseline efficiency and the max

- tech 21

efficiency. As you can see, multiple design option 22

combinations can me et the efficiency levels for CSL 23

zero through two. However, CSLs three through six 24

can only be met using an amorphous core design. 25Executive Court Reporters (301) 565

- 0064 113 The supporting designs for this chart can 1

be found in the engineering analysis file as posted 2

on DOE’s distribution tran sformers website, and 3

figures such as this one for all the design lines 4

can be found in Chapter 5 of the TSD. 5

MR. BROOKMAN: Steve Rosenstock. 6

MR. ROSENSTOCK: Steve Rosenstock, Edison 7

Electric Institute. You said something about 8

equally spaced eff iciency increments. Is that 9

really necessary? I just

-- I mean there’s 10

different increments on different design lines, so I 11

don’t

-- again, it’s a matter of

-- it’s minor, but 12

last time the numbers changed. I know the levels 13

changed between the prelimin ary analysis and the 14

NOPR, so these candidate standard levels can change 15

as they turn into trial standard levels at a 16

potential NOPR stage, correct? 17

MR. HARTLEY: That's correct. 18

MR. ROSENSTOCK: And I guess the other 19

thing is, CSL zero really represen ts, again from the 20

last rulemaking, that was trial standard level three 21

or four for this design line

-- this was, in the 22

last rulemaking again. It’s shown as baseline, and 23

it’s kind of missing from the technical support 24

documents, it’s not showing just th e baseline is so 25Executive Court Reporters (301) 565

- 0064 114 much more improved compared to 2005 or 2007 unit out 1

there. Again, I can’t remember if it was level 2

three or level four, this design line that was 3

eventually chosen for the standard, but that 4

baseline unit is significantly more efficient than 5

what’s out there in the marketplace that’s currently 6

in use today. And I think that is an element that’s 7

missing from a lot of this analysis. 8

MR. BROOKMAN: Gary Fernstrom. 9

MR. FERNSTROM: That’s sort of, I think, 10

Steve phrased a philosophical qu estion, is the 11

purpose of this proceeding to reassess the past 12

decision, or is it to look at where we are and 13

evaluate a further improvement? 14

MR. BROOKMAN: Do you have a point of 15

advocacy? 16

MR. FERNSTROM: Well, I believe the 17

purpose of the proceeding was to reassess the prior 18

decision. 19

MR. BROOKMAN: Andrew deLaski. 20

MR. deLASKI: Just a clarification 21

question. So in your table, or on this scatter 22

chart, does this scatter plot include the alternate 23

designs that we discussed earlier? 24

MR. HARTLEY: It does. In Chapter 5 of 25Executive Court Reporters (301) 565

- 0064 115 the TSD, we show this chart without the alternative 1

designs, and then again with the alternative 2

designs, so you can identify the new ones. 3

MR. deLASKI: Okay. So this information 4

in the table includes the alternate design? 5

MR. HARTLEY: That's correct. So, for 6

example, on this one, the red dots, the amorphous, 7

SA1 amorphous with aluminum conductors, those are a 8

supplementary design. 9

MR. deLASKI: Okay, but I didn’t

-- I did 10

not see the design option seven, which was H0

- DR 11

aluminum

- aluminum. 12

MR. HARTLEY: The chart here is design 13

line one, which is different from the one I 14

presented earlier. 15

MR. deLASKI: Okay. Thanks for clearing 16

that up. 17

MR. BROOKMAN: Steve Rosenstock. 18

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 19

think

-- I want to thank you for this chart, I think 20

it’s extremely helpful to show people what you’ve 21

done with the analysis, and basically my looking 22

through the technical support document, all the 23

other charts are in Chapter 5 of the technical 24

support d ocuments, so for other people, the charts 25Executive Court Reporters (301) 565

- 0064 116

are

-- I think they’re very helpful, and they’re in 1

Chapter 5 for people’s reference. 2

MR. HARTLEY: And just to piggyback on 3

that, there’s also an Excel file, three of them, 4

posted on DOE’s website, that contains design 5

information for every single one of these dots. So 6

if you’re interested in digging to the details, it 7

is there. 8

MR. BROOKMAN: Phil, yes. Find a 9

microphone. 10

MR. HOPKINSON: Phil Hopkinson, HVOLT, 11

Inc. Matt, very nice presentation, but one

-- a 12

couple thoughts that I have. First, I would suggest 13

that it really is a reassessment of what we looked 14

at the last time around based on, perhaps, new 15

economic parameters. So the cost of electric energy 16

that would power the transformers, the cost of th e 17

materials that goes into the transformers, and maybe 18

the look at what loadings might be for the 19

foreseeable future. 20

In looking at it for a national standard, 21

we should have something that is doable, with known 22

technology, and not require an invention, and not 23

require putting a lot of manufacturers out of 24

business. So in looking at that, I would just 25Executive Court Reporters (301) 565

- 0064 117 encourage the DOE not to get too exuberant to going 1

into materials that would push that envelope to the 2

point where manufacturers are crowded out of the 3

i ndustry that already is under stress. 4

A second parameter I would have is, as I 5

have looked at the material costs that are in the 6

base of going forward, I think that

-- I applaud the 7

concept of using 2010 data to the extent that we 8

have access and know wh at it is. I have looked at 9

one piece of data and I’m

-- somewhat calibrated

-- 10

and on that one I question whether, in fact, we 11

really have the 2010 data. And that really comes 12

down to copper foil or copper wire. When I see 13

something that I’m looking at in the newspaper 14

daily, which is the COMEX price of copper, that 15

would be copper bullion, and that’s not copper that 16

has work done to it to make it into foil or make it 17

into wire. And copper bullion today is in the order 18

of $4.30 a pound. But the materia l for the copper 19

foil in the optimization studies was shown as $4.30 20

a pound as well. 21

And when I then talked to a few 22

manufacturers, I’m hearing numbers more like $6.50 a 23

pound for the finished foil. So I would say that 24

the concept of using 2010 data is absolutely great, 25Executive Court Reporters (301) 565

- 0064 118 but make sure we really have a good calibration on 1

that and are using current prices that are reality. 2

MR. BROOKMAN: Thank you. Alan. 3

MR. TRAUT: Just to follow up on Phil’s 4

comment, and support it actually. That’s what I was 5

ta lking about earlier by using a COMEX base metal 6

cost plus conversion cost to get those materials 7

into workable conductor arrangements like strip or 8

wire, the same process. 9

MR. BROOKMAN: Okay. Yes, John. 10

MR. HURST: John Hurst again. The 11

fabrication cost varies with the diameter of the 12

wire, and the aluminum small wire is more expensive 13

fabrication than copper. Some of those things get 14

fairly complex, don’t they? 15

MR. TRAUT: Yes, I mean you can take it 16

down to the individual wire size. I think the DOE’s 17

done a reasonable job of breaking those up into 18

ranges. For example, I think one is seven to ten 19

gauge wire, and then wires smaller than that. But, 20

I mean, I’d be happy to get into those details at 21

the appropriate time. 22

MR. BROOKMAN: That’d be great, not only 23

the break points, but how to go from COMEX listing 24

to the more finished product, that would be helpful 25Executive Court Reporters (301) 565

- 0064 119 to them. Thomas. 1

MR. PATZNER: Thomas. To follow up on 2

Steve’s comment, it would be nice if we could label 3

CSL zero instead of CSL z ero, that it’s the 2005 4

energy act for the low voltage, it’s 431 for the 5

medium and the liquid. Because then we’d know that 6

it went into effect in 2010 or 2007. So if we could 7

not call it CSL zero, we could call

-- you know, 8

label it exactly what those l evels were, where it 9

was mandated. 10

MR. BROOKMAN: Yes, Joanna. 11

MS. MAUER: Joanna Mauer. In the

-- with 12

the model that was used to come up with these data 13

points, is it possible to specify an efficiency 14

level and have the model kind of come up with th e 15

optimum combination of core material, core 16

configuration, et cetera? Or is this

-- or do you 17

have to specify the design options? 18

MR. HARTLEY: The way that DOE does the 19

analysis is we specify the design options and then 20

we provide OPS with a list of o ver 500 A and B 21

values, which will then generate a span of different 22

efficiencies. I don’t know if perhaps OPS could 23

address the question of whether or not the targeted 24

efficiency level could be designed. 25Executive Court Reporters (301) 565

- 0064 120 MR. BROOKMAN: Your name, please. 1

2

MS. PEMPIN: It’s Nahid, OPS. I want to 3

make sure that I understood your question. You were 4

mentioning that if our program or software, you 5

would specify a specific efficiency, and then the 6

program optimize that efficiency

-- is that what the 7

question was? 8

MS. MA UER: Yes, instead of specifying the 9

core material

-- 10

MS. PEMPIN: No, it’s not exactly working 11

just to the efficiency. The program considers all 12

the costs. It considers the core, the conductor, 13

and the kind of strength, the impedance

-- they have 14

the boundary for impedance. It also looks at the

-- 15

flux density it has the

-- what is most commonly 16

used for specific core material, it will go

-- it 17

will tell the minimum flux density and then the 18

maximum flux density, and maybe a starter design 19

with the in itial flux density. And then based on 20

the A and B value, whether the A value’s overcoming 21

the B, which one is higher, then it decides to 22

design to the highest flux density or the lower flux 23

density. And so there’s a lot of different points 24

that you have to consider, plus the losses. So if 25Executive Court Reporters (301) 565

- 0064 121 you take the prices maybe, in such a way that you 1

just want to meet the efficiency, but it’s not going 2

to be practical because it’s going to be very 3

expensive. So you’re not going to be looking only 4

at the efficiency, you have to look at the costs 5

also. 6

MS. MAUER: But you couldn’t specify an 7

efficiency and come up with the lowest cost design 8

to meet that efficiency level? 9

MS. PEMPIN: In a way, at the end, it will 10

work out that way, because it will come and say thi s 11

is the lowest

-- because it has to keep iterate to 12

get the best out of the material, but if the copper 13

is more expensive than the aluminum, then it decides 14

to use prices that are lower than

-- at the 15

comparison. So it goes to the lower pricing because 16

w e know the cost will go down, and then at the end, 17

it’s sometimes just one design by itself, could be 18

like 4000 iterations before it comes up with the 19

solution, and maybe we look at that solution and 20

then if we want to do changes, maybe, then it would 21

star t over again to make sure that the final 22

solution is acceptable. 23

MR. BROOKMAN: Would you say your name 24

again, please? 25Executive Court Reporters (301) 565

- 0064 122 MS. PEMPIN: Nahid. 1

MR. BROOKMAN: Thank you. Robert, there 2

was a gentleman in the back that had a comment. 3

Please find a microph one. Your name, please. 4

MR. LAU: Chris Lau with Navigant 5

Consulting. Just to follow on those comments. Phil 6

had expressed concern about some of the higher 7

efficiency design options impacting manufacturers. 8

That’s part of the rulemaking process. DOE does 9

consider impact on manufacturers. It’s one of the 10

selection criteria, and we’ll cover this in more 11

detail after the lunch break. However, shortly 12

after this public meeting, DOE will begin scheduling 13

manufacturer interviews to get a better 14

understan ding of how these design options will 15

impact industry. And manufacturers that wish to 16

participate in those interviews can talk to Matt or 17

myself, and we will speak with you and schedule 18

those. 19

To address one of Doug’s earlier comments, 20

in those manufact urer interviews, it is possible to 21

place an NDA agreement with Navigant Consulting, and 22

share confidential information. That will then be 23

anonymized into industry values and will be used in 24

the rulemaking, and will not be publicly 25Executive Court Reporters (301) 565

- 0064 123 distributed. 1

MR. BROOK MAN: Thank you. Robert. 2

MR. BERMAN: Robert Berman, Berman 3

Economics. To follow up on the question there and 4

to clarify my understanding of the optimization 5

process, a number of utilities that we talked to 6

will not supply an A and B factor on the orde r, but 7

will just give me a transformer of a particular size 8

that meets DOE standards at the least initial cost, 9

least fixed cost. Can the model do something 10

without A and B factors, or do you have to do 11

something with A and B factors in order to get the 12

m odel to optimize? 13

MR. BROOKMAN: Whoever answers, find a 14

microphone. Your name, please. 15

MR. GOETHE: Paul Goethe, Optimized 16

Program Service. This optimization routine that we 17

use has been in the public use for the past 47 18

years, and over that time we have enhanced many 19

features to accommodate new materials, new 20

processes, new means of constructing transformers. 21

And we work pretty close with many manufacturers 22

that keep us honest in our results. But the 23

procedure we’re using for the DOE now is techni cally 24

optimizing for cost, and as we do that, we use the A 25Executive Court Reporters (301) 565

- 0064 124 and B factors knowing the utilities may not use 1

those. But they are mechanist to drive our programs 2

towards higher and higher efficiency, each run. And 3

so we get the results we want by having a r ange of 4

designs with different efficiencies plotted against 5

their cost. So unfortunately, we don’t optimize 6

specifically for cost. We’ve had people ask for 7

that, and some day we might, but presently we 8

optimize for cost, with that solution influenced by 9

material cost and the A and B factors that Navigant 10

has given us to use. 11

MR. BROOKMAN: Okay. Thank you. 12

MR. HARTLEY: And this is Matt Hartley, I 13

would also just like to add, while we do base the 14

designs on A and B factors, later on you’ll hear 15

from Lawrence Berkley National Labs in the life

16

cycle cost analysis we look at consumer impacts 17

where they do consider what they call a consumer 18

choice model, where some consumers will purchase 19

based on an A and B decision, and others will 20

purchase based on a l owest first cost. 21

MR. BROOKMAN: So we’re going to keep 22

going here. 23

MR. HARTLEY: Okay. Assuming DOE decides 24

that amended standards are justified, it will select 25Executive Court Reporters (301) 565

- 0064 125 trial standard levels, or TSLs, based on various 1

groupings of CSLs during the NOPR phase of the 2

rulemaking. For example, DOE may group CSLs based 3

on per phase harmonization, minimum life cycle 4

costs, or maximum net present value across various 5

representative units. These TSLs help DOE to 6

characterize any interaction between different 7

design lines or equipment classes. Also, during the 8

NOPR phase, DOE selects its proposed standard level 9

from one of these TSLs. 10

At this time, DOE invites comment on the 11

criteria it should use as the basis for selecting 12

TSLs in the NOPR. 13

MR. BROOKMAN: Comments on the criteria 14

the Department should use as the basis for selection 15

of TSLs. Steve Rosenstock. 16

MR. ROSENSTOCK: Steve Rosenstock, EEI. 17

Just remembering from last time, you know there’s a 18

ton of data in the technical support document, and 19

then ag ain on the timing, it would be very helpful 20

to have summary tables of any proposed trial 21

standard levels and how they relate to the candidate 22

standard levels, because last time there were 23

differences and it was rather interesting process to 24

see where all t he new numbers were compared to the 25Executive Court Reporters (301) 565

- 0064 126 old numbers, and then how that affected all of the 1

economic analysis, life cycle cost analysis, energy 2

analysis, et cetera. So, if there is a way

-- if 3

the decision is that there will be new standards, 4

and if there are going to be significantly different 5

TSLs from CSLs, which obviously could happen, 6

especially if you’re optimizing rather to energy 7

savings than present value, then please, if at all 8

possible, provide summary tables, especially in the 9

Federal Register

MR. BROOKMAN: Phil. 18 Noti ce, so that people can see 10

exactly old versus new and then kind of see where 11

maybe

-- and maybe on some of these charts, show the 12

old CSLs and maybe the new TSLs so people can see 13

kind of what’s really going on in terms of the new 14

values, because they do m ake a significant 15

difference in terms of impacts on manufacturers and 16

customers

-- utilities. Thank you. 17

MR. HOPKINSON: Well, let me talk about 19

life cycle cost minimization. And when a lot of the 20

manufacturers looked at what was considered the life 21

cycle cost minimization the last time around, and 22

for single phase transformers somewhere between TSL 23

four and five, came out as the answer. When I was 24

getting feedback, some manufacturers felt at the 25Executive Court Reporters (301) 565

- 0064 127 time that the time period used wa s for a life longer 1

than for 30 years. I would certainly encourage us 2

not to use more than 30 years in the face of trying 3

to determine what the minimum life cycle cost would 4

be for the transformer. 5

And of course, energy cost is a huge 6

piece, so that i s the electric

-- what is going to 7

be the cost of electricity? So if we have low cost 8

electricity, then you don’t end up with as valuable 9

a benefit from reducing the losses. If we have 10

extremely high cost electricity, then, in fact, we 11

can drive much, mu ch further with efficiency. But 12

it all ought to be economic driven, and it all ought 13

to be life cycle cost minimization, or when we did 14

TP1, we set it on a basis of a three to five year 15

return on incremental investment, based on what we 16

thought the willin gness to pay. But fundamentally, 17

it’s got to be economics that drives it. Okay. 18

MR. BROOKMAN: Okay. Thanks. Andrew 19

deLaski. 20

MR. deLASKI: I think it’s been the 21

Department’s practice, but I just want to reinforce 22

that two levels, you know, we cer tainly want to see 23

as part of the TSL would be the minimum LCC point 24

and also the maximum level that’s cost effective, 25Executive Court Reporters (301) 565

- 0064 128 which typically would be above the LCC. 1

I also would encourage the Department to 2

consider a TSL that retained a variety of core 3

materia ls as an option, something that’s modeled at 4

the maximum level that retains a variety of core 5

materials, and I’ll figure out how to phrase that 6

more clearly in my written comments. 7

And I think also just to emphasize that of 8

late the Department has tended to include a pretty 9

wide range of TSLs, and I think that’s a good 10

practice and would urge the Department to continue 11

to have a wide range of TSLs for consideration. 12

MR. BROOKMAN: Robert. 13

MR. BERMAN: Robert Berman, Berman 14

Economics. I’d like to foll ow up on that also with 15

a suggestion that we should keep in mind that what 16

this is is an energy savings pro

-- 17

MR. BROOKMAN: I’m sorry, closer to the 18

microphone. 19

MR. BERMAN: We should keep in mind that 20

what this is is standards are all about is energ y 21

savings, in particular savings of kilowatt hours, so 22

what

-- one of the things we might want to look at, 23

once we develop our savings estimates, is what’s the 24

cost per kilowatt hour saved, and how does that 25Executive Court Reporters (301) 565

- 0064 129 compare with the other energy savings programs. 1

MR. BROOKMAN: Okay. Yes, Jerry. 2

MR. SCHOEN: Jerry Schoen, AK Steel 3

Corporation. One of the concerns I have of working 4

for industrial company is, you have an existing 5

fleet out there, transformers that in some extent is 6

a resource, and those resourc es can be refurbished 7

and put back into service. You have to keep an eye 8

on what is the cost of refurbishing distribution 9

transformers because today it’s not commonly done. 10

But if distribution transformers get to be an 11

extremely expensive item, utilities can very easily 12

put back what they used to do, which was have 13

essentially an in

- house shop to take transformers 14

out of service and refurbish them. Often the 15

insulation is the aspect that needs to be replaced. 16

The core is fine, it’ll last 30 years, 100 y ears, as 17

long as it’s kept in, you know, not shorted out or 18

corroded. But that needs to be, I think, a concern, 19

that if you impose a very high economic cost for new 20

equipment on utilities, they’ll look at their 21

existing inventory and figure out how to ess entially 22

patch it up for another 20 years. 23

MR. BROOKMAN: Okay. Thank you. Paul, do 24

you have a comment? No? Okay. Joanna. 25Executive Court Reporters (301) 565

- 0064 130 MS. MAUER: Joanna Mauer. Just two quick 1

clarification questions regarding the TSLs in the 2

preliminary TSD. For the equipme nt classes that 3

only encompass one design line, do the TSL numbers 4

correspond to the same CSL numbers? In other words, 5

does TSL3 correspond to CSL3? 6

MR. HARTLEY: They don’t necessarily have 7

to. To the extent, possible, DOE might maintain 8

that, but a T SL is typically a grouping of different 9

CSLs and sometimes that will align with the same CSL 10

number, but other times, certain TSLs might be 11

composed of three different equipment class 12

groupings, where one out of those three would not 13

match the number. 14

MR . BROOKMAN: Yes, Mahesh. 15

MR. SAMPAT: Mahesh Sampat. I guess to 16

follow up on Jerry’s comment. If the transformer is 17

refurbished by an outside entity, then they have to 18

comply with the new regulation. So

-- 19

MR. BROOKMAN: Jerry, go ahead. 20

MR. SAMP AT: If the utilities themselves 21

repair it, then it’s not, but if it’s done by 22

another company, it’s just like buying another 23

transformer. 24

MR. BROOKMAN: Jerry’s next, go ahead. 25Executive Court Reporters (301) 565

- 0064 131 MR. SCHOEN: Jerry Schoen. As we 1

understood it, if the transformer change s 2

possession, which is legal possession, but a 3

transformer could be taken out of service by a 4

utility, shipped to a subcontractor to have it 5

refurbished, without changing ownership, it would 6

still be the possession of the utility. It’s done 7

all the time, and it’s a very common practice in 8

heavy industry today. We do it at our firm as well. 9

MR. BROOKMAN: At which point that 10

refurbished transformer would not need to meet the 11

new standard? 12

MR. SCHOEN: As we understand it, yes, 13

that’s true. 14

MR. BROOKM AN: Steve Rosenstock. 15

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 16

was just going to give an analogy to another 17

appliance, like a refrigerator. A 20

- year

- old 18

refrigerator that’s repaired does not have to meet 19

the new standards, whether it’s done by the 20

h omeowner or by a repair shop. You know, they need 21

to put in new gaskets or new insulation, or even a 22

new compressor, that refrigerator is not required to 23

meet the new energy efficiency standards. 24

MR. BROOKMAN: Mahesh. 25Executive Court Reporters (301) 565

- 0064 132 MR. SAMPAT: Yes, Mahesh Sampat again. My 1

understanding was if the ownership changes, then it 2

has to comply. If it’s subcontract, then I agree, 3

it does not have to. And that fits with the 4

representative analogy. Ownership doesn’t change. 5

MR. BROOKMAN: Okay. We’re going to move 6

on to our next set of slides. 7

MR. HARTLEY: Okay. We’re on our last 8

point here, and I’ll try to move quickly for the 9

sake of everyone getting lunch. The final step in 10

the engineering analysis is to scale the efficiency 11

levels of the representative units to the other 12

unanalyzed kVA ratings. Similar to the 2007 13

rulemaking, DOE did not directly analyze single 14

phase medium voltage dry type units because of their 15

low shipment volume and MVA capacity shipped, as 16

Brian discussed previously. 17

Rather, DOE scaled to these equipment 18

classes by dividing the kVA rating of the three 19

phase medium voltage dry type units by three, so as 20

to maintain the per phase kVA amount. The table on 21

this slide shows the kVA rating for each three phase 22

representative unit that was di rectly analyzed for 23

the medium voltage dry type design lines, and the 24

corresponding scaled kVA rating for the single phase 25Executive Court Reporters (301) 565

- 0064 133 medium voltage dry type design lines. 1

Aside from scaling to the single phase 2

medium voltage dry type design lines, DOE also 3

scaled to each kVA rating that was not directly 4

analyzed by a representative unit. To do this 5

scaling, DOE relied on the 0.75 scaling rule, which 6

states that total transformer losses scale by the 7

ratio of kVA sizes raised to the 0.75 power, when 8

design character istics, such as frequency, and basic 9

impulse insulation level ratings are maintained 10

constant. By holding certain parameters constant, 11

DOE can use the 0.75 scaling rule to scale losses, 12

dimensions, and costs from its analyzed rep units to 13

the unanalyzed k VA ratings. 14

So for example, consider design line 15

seven, a three phase, low voltage dry type design 16

line that spans kVAs from 15 to 150. DOE analyzed a 17

representative unit at 75 kVA for this design line. 18

The corresponding efficiencies for the remaining kVA 19

ratings within design line seven can be determined 20

using the 0.75 scaling rule. This approach is 21

similar to what was done in DOE’s 2007 rulemaking, 22

and further detail on the 0.75 scaling rule can be 23

found in Appendix 5B of the TSD. 24

During preliminar y manufacturer 25Executive Court Reporters (301) 565

- 0064 134 interviews, some manufacturers indicated that the 1

scaled results from the 2007 rulemaking made it 2

difficult to manufacture compliant transformers for 3

certain kVA ranges. 4

DOE welcomes comment on the accuracy of 5

the 0.75 scaling rule, and wh ether an improved 6

scaling methodology exists. DOE also seeks comment 7

on the extent of the impact that the previous scaled 8

standard levels have had on certain kVA ranges, and 9

any considerations that DOE should account for in 10

this analysis. 11

MR. BROOKMAN: As a process note, very 12

shortly we’re going to go to lunch, for those of you 13

that are getting antsy, so let’s respond to this 14

issue box here about the 0.75 scaling rule, and 15

other potential methodologies. Steve Rosenstock. 16

MR. ROSENSTOCK: Steve Rosens tock, EEI. 17

Just as a follow up, this equation says, again, 18

total losses. That’s core and coil losses that 19

you’re modeling for these different design lines, is 20

that

-- is that correct? 21

MR. HARTLEY: Yes. 22

MR. ROSENSTOCK: And so the next part is, 23

are y ou then transferring that into costs, using 24

that same scaling factor? 25Executive Court Reporters (301) 565

- 0064 1 35 MR. HARTLEY: There is a scaling factor 1

outlined in Appendix 8B for cost, and there are 2

slightly different variations, depending which 3

variables you’re holding constant, different 4

form ulas that you can use for costs or dimensions. 5

They’re all outlined in Appendix 8B. 6

MR. ROSENSTOCK: Okay. It just seemed 7

like it sounded like you’re using this specific 8

formula for all those other parameters that may or 9

may not be associated with the losses, so

-- okay, 10

thank you. 11

MR. BROOKMAN: Comments on the 0.75 12

scaling rule? Or other potential approaches? Alan. 13

MR. TRAUT: Specifically, with the liquid 14

filled design line three, the large kVA 15

transformers, I think that’s part of what led to 16

p erhaps our frustration with the very large 17

transformers, is that the design work was done with 18

the 500 kVA and extrapolated to 833, and those 19

extrapolations just don’t hold true. There’s too 20

many outside constraints, both from a utilities 21

specifications s tandpoint and from the manufacturer 22

limitations standpoint. I think in very large 23

transformers, those scaling rules break down. 24

MR. BROOKMAN: What would you suggest? 25Executive Court Reporters (301) 565

- 0064 136 MR. TRAUT: I think in the

-- in design 1

line three, we probably need to analyze not just the 2

mid

- point, but perhaps the smallest and the largest 3

within that category. 4

MR. BROOKMAN: Yes, please, your name. 5

MR. GREESON: Rob Greeson, Federal Pacific 6

Transformer. It’s been our experience that for the 7

dry type, on the lower end kVAs, it ’s much more 8

difficult to meet the efficiency levels for the 9

current requirements than the higher. It probably 10

has something to do with this

-- I don’t really know 11

what the answer is, because the beauty of that 0.75 12

rule is it allowed an enormous amount o f analysis to 13

be done. Without it, I mean, it would have been 14

extremely difficult. It might be better to try to 15

introduce some other designs, but then on the other 16

hand, you may have to take some good with the bad, 17

because the analysis could become a lit tle bit 18

overwhelming as far as the complexity of it. 19

Bottom line, I’m not really sure what the 20

answer is, but I’m going to

-- we’re going to try to 21

send some information on that might show how that 22

0.75 rule really relates to our real world designs, 23

and see where those curves fall. But in reality, I 24

don’t know if in the long run we’re going to have 25Executive Court Reporters (301) 565

- 0064 137 enough time to really sort out all these issues, and 1

we may just have to live with it, but we’re going to 2

do what we can to try to submit some information to 3

maybe kind of look at this information about the 4

0.75 rule, to get closer. 5

It works very well at closer kVAs. But if 6

they get too far in the extremities, that’s where 7

you can run into some issues. 8

MR. BROOKMAN: Jerry. Microphone, Jerry, 9

microphone. 10

MR. ALLEN: Sorry about that. Scaling 11

rule applies, but it assumes that you have the same 12

percentage insulation in the cross section of 13

conductor in all the transformers. Part of the 14

thing that’s happening is they get smaller, you’ve 15

got more insulatio n because the BIL’s the same. In 16

bigger ones, you may have cooling problems in 17

addition to weight problems. So then, and when you 18

get into really large sizes, you’re sitting at 5.75 19

percent impedance and it’s going to change. So 20

there’s going to be vari ations, but I agree, the

-- 21

I don’t know what to do about it, because like you 22

said, the analysis is getting huge as it is. 23

MR. BROOKMAN: I think it’s pretty clear 24

the Department’s trying to find some way for a 25Executive Court Reporters (301) 565

- 0064 138 reasonable representation that’s simple, r ight, or 1

simpler. And so some thought on how they might do 2

that would be very, very helpful to the Department. 3

Steve Rosenstock. 4

MR. ROSENSTOCK: Steve Rosenstock, EEI. 5

Based on this conversation, if you go back to the 6

previous slide, from what I’m he aring it sounds like 7

for this one in particular, it sounds like, again, 8

it seems like the scaling within one data point 9

might be okay, but you’re going out two or three 10

data points, you might need a different scale it 11

sounds like. I’m sorry to do that to you, but 12

that’s what it

-- just based on this conversation, 13

it’s like there might be a certain range where it 14

works really well, but then, get out the range, it’s 15

like standard deviation, you get outside that 16

standard deviation, you might need a new formul a. 17

MR. BROOKMAN: As I cast my eyes around 18

the room, I see a lot of head nodding up and down to 19

that comment, so perhaps in your written comments 20

you could be a little more specific so the 21

Department has some additional guidance on this 22

point. Yes, Phil

. 23

MR. HOPKINSON: Thank you. I can see more 24

people on this side of the room than the other side. 25Executive Court Reporters (301) 565

- 0064 139 I’ve done looks at these scaling factors for years 1

and frankly, I like them pretty well, and they do a 2

good job. But I would say that there are limits for 3

the materials sizes so that

-- the size of material 4

might not really be available to the extent that you 5

thought that it was going to be there, and you will 6

end up not being exact using these scaling factors, 7

but it’s pretty close. So I encourage us to s tay 8

with the same scaling factors we’ve got. 9

MR. BROOKMAN: Okay. Thank you. Or find 10

some way to specify the exceptions, or whatever they 11

would be, right. Final comments on this section, 12

because we’re about to go to lunch. I think I’ve 13

cast the die r ight there. 14

Let’s go to lunch. It’s ten minutes after 15

12. It takes an hour pretty much to eat. Don’t go 16

off campus. Do not leave the building. 17

(Whereupon, at 12:11 p.m., the meet ing in 18

the above captioned matter was adjourned for lunch 19

recess , to reconvene at 1:14 p .m.) 20

21Executive Court Reporters (301) 565

- 0064 140

1:14 p.m. 2 AFTERNOON SESSION 1

MR. BROOKMAN: Over the lunch break, the 3

Department has made Xerox copies of business cards 4

as promised, and I think that Brenda has distributed 5

them. If you don’t have a copy, then you can still 6

get one at the registration desk. 7

So we made really good progress this 8

morning, the nature and tenor of the comment was 9

really useful. Let’s proceed. Greg Rosenquist. 10

**Markups for Product Price Determination** 11

**and Payback Period Analysis** 12

MR. ROSENQUIST: I am Greg Rosenquist from 13

Lawrence Berkley National Laboratory. I’ll be 14

starting the afternoon off with talking about the 15

markups analysis. And this is to reorient you to 16

the flow diagram for the preliminary analyses, the 17

outputs from the market analysi s gets fed into the 18

life cycle cost and payback period analysis. 19

The purpose is fairly straightforward, 20

it’s to transfer the manufacturing cost in the 21

engineering analysis into prices seen by the 22

customers purchasing these transformers. First step 23

is to characterize how the equipment is being 24

distributed from the manufacturer to the customer, 25Executive Court Reporters (301) 565

- 0064 141 and for each party involved in that distribution, 1

the Department looks at that party’s direct costs, 2

expenses and profits to determine the markup. 3

Now for all ma rkups with the exception of 4

the manufacturer markup, DOE relied on RS means 5

electrical cost data. This was able to be used to 6

develop the markups for our contractor materials, 7

labor, equipment, and those items. Also the 8

Department used sales tax rates by the census 9

division for each census division and large state, 10

and then aggregated that up to a national value for 11

purposes downstream in the NIA analysis, but that 12

data came from a place called the Sales Tax Clearing 13

house. 14

The output from all of this i s what’s 15

called baseline markups. These are the markups 16

associated with transforming current transformer 17

manufacturing cost for equipment being sold today, 18

into prices that the customer has to pay. So these 19

markups do not change with the standard level, they 20

stay constant over all the efficiency levels that 21

were analyzed. 22

This shows some graphics of distribution 23

channels that the Department developed. There’s one 24

distribution channel for liquid immersed and one for 25Executive Court Reporters (301) 565

- 0064 142 dry type transformers. Most of the t ransformers 1

liquid immersed go to utility customers, so DOE 2

developed a relatively simple distribution channel 3

that goes from the manufacturer to manufacturer’s 4

representative, or distributor, and finally to the 5

utility. In the case of dry type transforme rs, most 6

of those transformers go to commercial and 7

industrial installations, which are installed by 8

electrical contractor. So in addition to the 9

manufacturer markup, the manufacturer’s 10

representative or distributor markup, there’s also 11

an electrical cont ractor markup before it gets to 12

the point of installation. 13

MR. BROOKMAN: Yes, please, Steve. 14

MR. ROSENSTOCK: Steve Rosenstock, EEI. 15

As I thought we did with some other appliances, 16

commercial appliances, we

-- another distribution 17

channel was manufac turer or manufacturer’s 18

representative to I’ll say chain accounts or 19

multisite accounts where they might have their own 20

staff that might be installing, or their own 21

contractors, so there might be another distribution 22

channel where they may or may not be us ing the 23

electrical contractors. So I think that was 24

discussed with other commercial products out there 25Executive Court Reporters (301) 565

- 0064 143 in the past and incorporated

-- especially if it was 1

like roof

- top PAC units, for example. Thank you. 2

MR. BROOKMAN: John. 3

MR. HURST: John Hurst. What about ESCOs? 4

Increasingly representing a channel to the 5

industrial sector. 6

MR. ROSENSTOCK: I’m just talking about 7

the C&I customer

-- but absolutely, yes. 8

MR. ROSENQUIST: Again, the Department has 9

characterized that using the simple distributi on 10

channel that if there’s input that could

-- from you 11

all about different distribution channels that are 12

more appropriate, it certainly would be considered 13

for the NOPR. 14

I’ll move on then to show the results from 15

the markup analysis. You can see this tabulates 16

results for liquid immersed transformers and dry 17

type transformers. All the same players are 18

involved in both types of transformers with the 19

exception for dry type, it has a markup on the 20

contract materials. The result is an overall markup 21

of 1 .64 for the liquid immersed, and 1.93 for the 22

dry type. 23

And the issue here that the DOE is 24

specifically seeking comment on is on the 25Executive Court Reporters (301) 565

- 0064 144 distributor markups. 1

MR. BROOKMAN: We have a discrepancy

-- 2

MR. ROSENQUIST: Yeah, in your handout, 3

those number s are incorrect. That was a late catch. 4

These are the numbers that are actually being used. 5

And I think as Doug mentioned before, this 6

presentation

-- or Jim Raba mentioned before

-- this 7

presentation will be on the DOE website. 8

So the issue at hand h ere is DOE is 9

looking for a specific comment on the markups, but 10

more specifically on the distributor markups because 11

information from the last rulemaking analysis from 12

2007, were used to develop these markups and DOE is 13

concerned that information may be o ut of date. So 14

again, it’s looking for any input as to whether 15

these numbers are still relevant. 16

MR. BROOKMAN: So how do they look? Yes, 17

Robert. 18

MR. BERMAN: Robert Berman, Berman 19

Economics. I’m not sure I’m reading this right. 20

Are you saying that you don’t

-- that there isn’t a 21

distribution channel that goes from manufacturer 22

direct to utility? 23

MR. ROSENQUIST: Well, it is in the form 24

of the manufacturer’s representative. So, there’s a 25Executive Court Reporters (301) 565

- 0064 145 step that goes from

-- if the manufacturer is 1

selling to th e utility, it goes from the 2

manufacturer, to a manufacturer’s representative, 3

which may or may not be in house, and then to the 4

utility. 5

MR. BERMAN: So you have two manufacturer 6

markups, one for his representative and one for the 7

manufacturer? 8

MR. RO SENQUIST: That’s right. 9

MR. BERMAN: Okay. Thanks for the 10

clarification. 11

MR. BROOKMAN: Mahesh. 12

MR. SAMPAT: Mahesh Sampat. I think the 13

manufacturer’s represent company, but the position 14

of transformer goes from manufacturer to end user or 15

utility directly. Manufacturer’s representative 16

doesn’t take position. 17

MR. ROSENQUIST: Okay. So you’re saying 18

that there shouldn’t be a markup associated with 19

that? 20

MR. SAMPAT: Right. They are paid 21

commission on sale, but there is no markup. 22

MR. BROO KMAN: Okay. All that cost is 23

embedded in the manufacturer’s cost. 24

MR. SAMPAT: Right. 25Executive Court Reporters (301) 565

- 0064 146 MR. BROOKMAN: You’re saying? 1

MR. SAMPAT: Yes. 2

MR. BROOKMAN: Okay. Andrew deLaski. 3

MR. deLASKI: I’ll ask the question a 4

little different way, which is tha t in the current 5

analysis, is the markup for a manufacturer’s 6

representative and a distributor the same, or

-- 7

MR. ROSENQUIST: Yes. 8

MR. deLASKI: It is the same? 9

MR. ROSENQUIST: Yes. 10

MR. deLASKI: You’re treating a 11

manufacturer rep as if they act ed the same as a 12

distributor. 13

MR. ROSENQUIST: That's correct. 14

MR. deLASKI: That just seems improper to 15

me, and needs to be revisited. It’s a different 16

relationship when a manufacturer sends directly to a 17

customer than through a distributor, that’s a 18

different relationship. You need to problem that 19

some. 20

MR. BROOKMAN: Thank you, Paul. 21

MR. RYAN: Paul Ryan, Hitachi Metal Sub. 22

Following on that comment, is this assume a 100 23

percent of the time, this channel? Because as it 24

states in the second bu llet, the manufacturer is 25Executive Court Reporters (301) 565

- 0064 147 going directly to the large utility with, in many 1

cases, without even a representative or distribution 2

sale channel. So there would be no markup in that 3

case. In a large percentage of cases. So I think 4

your applying this to 100 percent of the cases is 5

not correct. 6

MR. BROOKMAN: Okay. Thank you. Other 7

comments, not only on these representations of the 8

actual markups, but also on the assigned values 9

here. As Greg said, the Department is very 10

interested if things have change d from when these 11

were done previously in 2007, if current conditions 12

mean these should change. Steve Rosenstock. 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. 14

There might be a difference in the sales tax, I know 15

that some jurisdictions have raised sales ta xes over 16

the last couple years, due to budget issues. 17

MR. ROSENQUIST: The sales tax are 18

current, or relatively current. It’s just the 19

distributor markups that aren’t. 20

MR. ROSENSTOCK: Thank you. 21

MR. BROOKMAN: So generally, these look 22

pretty good. John. 23

MR. SCHOEN: You don’t see too many 24

contractors who are picking up 52 percent. 25Executive Court Reporters (301) 565

- 0064 148 MR. ROSENQUIST: Again, that’s actually 43 1

percent. These are the correct numbers, not the 2

ones in your handout. 3

MR. BROOKMAN: Yes, we

-- for the record, 4

the inst allation under liquid immersed

-- 5

installation labor

- slash

- equipment, should be 1.43. 6

So additional comments and specifics on these 7

markups, because we’re about to move on. Andrew. 8

MR. deLASKI: Are you now on equipment 9

prices or

-- 10

MR. ROSENQUIST: This will be it. 11

MR. deLASKI: This is Andrew deLaski from 12

ASAP. Earlier I suggested that the Department 13

should go verify its pricing by talking to some 14

utilities, and then over lunch it occurred to us 15

that one utility that should be able to provide DO E 16

good data is Bonneville Power Administration. DOE 17

has got within bounds of this one building, a major 18

-- within this one building, there’s a major buyer 19

of distribution transformers in the form of 20

Bonneville. They should be able to provide good 21

data fo r the Department and there may be others that 22

the Department has access to through the federal 23

power agencies, that may be able to give good data. 24

Just one source to look into. 25Executive Court Reporters (301) 565

- 0064 149 MR. ROSENQUIST: Right. And there was an 1

attempt on our part to go through the internet, as I 2

think someone mentioned this morning, and we found 3

bids for transformers. The problem we have I that 4

we didn’t find any settlements to actually confirm 5

that was the price that was actually used to 6

purchase the equipment, so we felt

-- d idn’t feel 7

entirely comfortable going out with those bids. 8

MR. BROOKMAN: Charlie Stephens. 9

MR. STEPHENS: Charlie Stephens. My 10

organizations actually is funded by 135 different 11

electric utilities, and some of them are fairly 12

large, and some of them a re very, very, very small. 13

But I think I can probably get you some data from at 14

least some of those utilities, and I will go home 15

and do what I can to pull that together. 16

MR. BROOKMAN: Thank you. Gary, done? 17

Final comments on this? Anything else you want to 18

say about pricing? That was it. Okay. Phil, find 19

a microphone. 20

MR. HOPKINSON: As I sit here thinking 21

about the ramifications, if a transformer became a 22

whole lot more energy efficient and therefore more 23

expensive, would that say that they wo uld be the 24

same contractor flavor that would go in it, or would 25Executive Court Reporters (301) 565

- 0064 150 it change? 1

MR. ROSENQUIST: Right now we’re assuming 2

it doesn’t change. 3

MR. HOPKINSON: Well, I want to be a 4

contractor. 5

MR. SCHOEN: No you don’t. 6

MR. ROSENQUIST: Looking for comment on 7

that, because as I mentioned before, we assume that 8

the markups do not change from the baseline to the 9

higher efficiency transformers. 10

MR. BROOKMAN: Steve Rosenstock. 11

MR. ROSENSTOCK: I think there is one 12

issue on the liquid filled side, in partic ular, is 13

that if there’s certain increments, whether it’s 14

weight or size, or height, that not efficiency

15

related, but have to do with installation, then some 16

of those values might be

-- will increase more, you 17

know, if there’s structural reinforcement or i f 18

there’s any sort of vault change

- out, things like 19

that. There might be some non

- efficiency issues 20

that would tend to possibly, on the installation 21

side in particular, increase some of those factors. 22

MR. ROSENQUIST: For volt transformers, 23

specifically , that’s why the subgroups that we’ve 24

identified, for the subgroup analysis. So, at least 25Executive Court Reporters (301) 565

- 0064 151 that one we plan on covering. 1

MR. BROOKMAN: Okay. Then. 2

**Energy Use and End**

**- Use Load Characterization**  3

MS. COUGHLIN: My name is Katie Coughlin. 4

I work at Lawre nce Berkley National Lab, and I’ll be 5

taking you through the energy use and the LCC 6

analyses. 7

So for the energy use determination, the 8

purpose here is to develop the annual energy use 9

parameters that are needed for the LCC, 10

specifically. So it’s not a g eneral study of energy 11

use in transformers, it’s really to develop those 12

aspects of energy use that affect the economic 13

valuation of the losses. 14

And so just to provide an overview. The 15

energy use, obviously, refers to the losses in the 16

transformers, a nd we have two sources of losses. 17

We’ve changed terminology, the core losses here are 18

called the no

- load losses, because they exist 19

irrespective of whether there’s any load on the 20

transformers, and then the coil losses are referred 21

to as the load losses. So in some sense there’s a 22

sort of simplified analysis that you can do to 23

summarize the losses on a unit. The no

- load losses, 24

assuming the transformer is energized 8760 hours per 25Executive Court Reporters (301) 565

- 0064 152 year, is just the engineering parameter which we 1

call NL, which is the no

- l oad loss rate times the 2

number of hours. And for the load losses there is 3

an engineering parameter which we call LL, which 4

gives you the rate of load loss when the 5

transformers is loaded at its rated capacity. That 6

varies with the square of the load on t he 7

transformer. In the engineering literature, this is 8

often represented through something called the loss 9

factor, LSF, which is the average value of the 10

square of the load on the transformer. And if you 11

knew that average value to high accuracy for a uni t, 12

you could just multiply that by the number of hours 13

and that would give you the total annual load 14

losses. 15

Now, for this particular analysis, we 16

wanted to do something slightly more elaborate 17

because in a real system, you have both varying load 18

losses hour by hour, day by day, and you have 19

varying electricity costs. So the energy use 20

analysis is designed to try to capture the effect of 21

the variability in losses and associate that with 22

variability in electricity costs. 23

And so the equation at the bot tom here is 24

just the actual operating cost of the transformer is 25Executive Court Reporters (301) 565

- 0064 153 the sum over all the time periods of the transformer 1

loss in a time period times the electricity loss in 2

that time period. And this creates sort of a 3

separation in our analysis procedure for the two 4

equipment classes, because liquid immersed 5

transformers are primarily owned by utilities, so 6

the appropriate cost to use there is sort of a 7

production cost of electricity, and that varies on

- 8

- we’re using an hourly variation to capture that. 9

Fo r the dry type transformers, the 10

assumption in the LCC is that these are primarily 11

owned by building owners and operators, so they are 12

typically billed for electricity on a tariff, so the 13

assumption there is that’s a monthly bill that they 14

have to pay, and so the energy use parameters that 15

we need to determine for dry type transformers are 16

the inputs that determine their monthly bill. 17

In the next few slides, in the energy use 18

analysis, I’ll explain first what we have done for 19

the liquid immersed, and then what we did for the 20

dry type transformers. 21

So to represent the utility system within 22

the United States for the liquid immersed, we’re 23

using regional breakdown of the country. We’re 24

using the electricity market module of regions that 25Executive Court Reporters (301) 565

- 0064 154 are used in the Nat ional Energy Modeling System. 1

The map on the bottom gives the regional breakdown. 2

So there’s 13 of these regions and they follow, 3

roughly, NERC regions with some subdivisions in the 4

western area. And the data that we need for this 5

analysis are

-- to get the hourly price estimate, 6

we’re using FERC Form 714 filings. These are filed 7

each year by utilities. They give an hourly load 8

for the utility service area or control area, and an 9

hourly either a system lambda, which you can think 10

of as the cost of the next unit that will be 11

dispatched in that hour, or we also, for regions 12

that have electricity wholesale markets, we use the 13

day ahead market clearing price. So these again are 14

intended to represent the margin cost of meeting the 15

next increment of load. B ecause improvements in 16

efficiency are going to decrease that marginal 17

demand. 18

So, as I said

-- 19

MR. BROOKMAN: Steve Rosenstock. 20

MR. ROSENSTOCK: A question. I believe 21

you said you used the cost production of power. 22

Shouldn’t the cost not be the ge neration, 23

transmission, and distribution cost, because we’re 24

talking about distribution transformers here. So G, 25Executive Court Reporters (301) 565

- 0064 155 T, and D adds to the cost at the point of the 1

distribution transformer, not just the G factor. 2

MS. COUGHLIN: That’s right. So in the 3

LCC, we have essentially a capacity cost component 4

of the total operating costs, so

-- 5

MR. ROSENSTOCK: But it

-- but you

-- I 6

don’t

-- when you say you have the capacity cost 7

component, I thought I understood you to say that 8

was from the market generating pr ice. 9

MS. COUGHLIN: No, there’s a separate

-- 10

when I get to the LCC

-- the operating cost include 11

an energy term, essentially, and a capacity term. 12

MR. ROSENSTOCK: And the capacity term 13

includes the transmission and distribution? 14

MS. COUGHLIN: Righ t. 15

MR. ROSENSTOCK: Thank you. 16

MS. COUGHLIN: Yes, so this is just the 17

energy use part. This is the equation. We have the 18

load loss parameter times the hourly load scaled to 19

the maximum load, times the marginal production 20

costs. And for this analysi s, or for this 21

discussion, was to assume that the hourly load is 22

scaled by the transformer capacity. The LCC is 23

slightly more complicated, but the complications are 24

not that relevant here. 25Executive Court Reporters (301) 565

- 0064 156 MR. ROSENSTOCK: Maybe one more quick 1

question. In determining the load, do you use the 2

kVA load or the kW load? 3

MS. COUGHLIN: I think the

-- 4

MR. ROSENSTOCK: This goes to my earlier 5

question about power factor, harmonics, all of that. 6

So, the load that’s meaningful on the transformer is 7

the kVA load, including harmonic parasitics that may 8

not contribute to the work being done, but 9

contribute to the transformer loss. 10

MS. COUGHLIN: Yeah, I don’t think that 11

the LLC contains a parameter to include a power 12

factor, but I don’t know that we have used or put a 13

lot of analysis in determining what that number 14

should be. 15

MR. ROSENSTOCK: Okay. So my 16

recommendation is that some factor be utilized to 17

account for harmonics and power factor or kVA load 18

if it isn't already. 19

MS. COUGHLIN: Okay. So overall, the goal 20

of t his analysis is to understand what’s the 21

correlation between the load on an individual 22

transformer and the price that is set overall for 23

the system in which that transformer exists. And 24

the way we approach this, is we break it down into 25Executive Court Reporters (301) 565

- 0064 157 two pieces. 1

No w we know that from just looking at the 2

system

- wide data from FERC, that the hourly system 3

price is correlated with the hourly system load, so 4

we will have one model that captures that 5

correlation. And then we expect that since, in some 6

sense, the system load is simply the sum of all the 7

loads of the components within the system, there 8

should be a correlation between the load on the 9

transformer in a given hour, and the load on the 10

given system. So we have the second piece of the 11

model that captures that c orrelation. 12

And so for the first one, the relationship 13

between hourly system load and hourly system price, 14

the plot here shows for one of the NERC region

-- I 15

think this is the northeast

-- there is a scatter 16

plot

-- this is 2008 data. On the vertical a xis is 17

the system price, and on the horizontal axis is the 18

system load. Yes. 19

MR. ROSENSTOCK: Steve Rosenstock, EEI. 20

So this is just

-- this is just one of the systems, 21

not

-- because I

-- 22

MS. COUGHLIN: Right. 23

MR. ROSENSTOCK:

-- I saw all of the

-- I 24

saw different colors, you’ve got to look

-- this is 25Executive Court Reporters (301) 565

- 0064 158 just a representative of one of the regional 1

systems? 2

MS. COUGHLIN: Yes, that’s correct. So we 3

have 13 of these plots, one for each region. 4

MR. ROSENSTOCK: And do these

-- do the 5

different col ors represent different generation 6

technologies, or just different loads, different 7

energy uses? 8

MS. COUGHLIN: I’ll get to that in just a 9

moment, yes. Essentially that’s just a visual aide 10

to help understand how we did the model. 11

MR. ROSENSTOCK: Oka y. And this is

-- 12

you’re just using 2008 data. The reason I ask is 13

that especially for 2010 in areas like ERCOT (ph) 14

and Pacific northwest, with so much wind coming on 15

line, there were times when low loads, that 16

basically the system price went down to on e cent per 17

kilowatt hour or less. Because there was all this 18

generation that you can’t turn off, and there wasn’t 19

a load to match it, so some of them actually, at 20

least at the lower loads, the price went down 21

significantly. 22

MS. COUGHLIN: That’s right, and some of 23

these plots you could see

-- 24

MR. BROOKMAN: We wish. 25Executive Court Reporters (301) 565

- 0064 159 MR. ROSENSTOCK: Yes, great idea, but. 1

MR. FERNSTROM: So this is Gary Fernstrom. 2

I have one more thought too, thinking about this in 3

business terms, you’re using essentially the utili ty 4

cost of power in your transformer analysis. Those 5

kilowatt hours could be sold, and the revenue that 6

the utility is deprived of is a consequence of these 7

losses, is not its cost, it’s what it could have 8

sold the kilowatt hours for. So I would suggest 9

that we ought to be using the customer price across 10

the board, not the utility cost. 11

MS. COUGHLIN: Yeah, I’ll just mention 12

that the

-- this is basically consistent

-- there’s 13

an IEEE document on valuing transformer losses that 14

builds up these costs out of energy production costs 15

and capacity costs, and that was our motivation for 16

using this approach. 17

MR. FERNSTROM: If I may, either way the 18

IEEE thinks about it, it’s the responsibility of the 19

government to find the most cost

- effective energy 20

efficiency standards, and from a business point of 21

view, it’s the lost revenue that is affecting 22

utility operations, not just the lost cost. 23

MR. BROOKMAN: Steve Rosenstock. 24

MR. ROSENSTOCK: Steve Rosenstock, EEI. 25Executive Court Reporters (301) 565

- 0064 160 Based on

-- different utilities will treat thos e 1

transformer losses in multiple ways. Some will use 2

just use the wholesale, and some will say it’s a 3

kilowatt hour that could be sold, then some have 4

pretty sophisticated models in terms of how they 5

value what’s happening at the liquid filled 6

transformer side. So there’s a range of how 7

utilities treat the value of the transformer energy 8

losses. I’m encouraging utilities to submit 9

information to DOE in terms of how they treat the 10

value of these losses. 11

MR. FERNSTROM: Indeed, but I thought this 12

proceed ing was about society, and I think the 13

business perspective is the society perspective. 14

MR. BROOKMAN: Robert. 15

MR. BERMAN: I just have a question. Are 16

you also looking at, particularly where there’s more 17

efficient transformers due to the more efficie nt 18

core, that there is a capacity savings as well? 19

MS. COUGHLIN: Yes. 20

MR. BERMAN: Other than the kilowatt hours 21

savings, which may be quite substantial in systems 22

like PJM? 23

MS. COUGHLIN: Yes, that’s considered in 24

the LCC, yeah. 25Executive Court Reporters (301) 565

- 0064 161 MR. HURST: John Hurst. Did you make any 1

attempt at all to understand what the cost of 2

upgrading transmission and distribution to feed 3

concentrated power demands, locations, which would 4

be utility costs in the trillions of dollars, where 5

efficiency can basically defer par t of that cost? 6

Did you make any judgment on that? 7

MS. COUGHLIN: Well, let’s see

-- yeah, in 8

the extent that we have location

- specific costs 9

associated with transmission and distribution, 10

they’re taken out of NEMS (ph). 11

MR. HURST: No, what I’m sayin g is that 12

New York city is using more power than is readily 13

available. If ... Point comes off line, that’ll be a 14

lot more. But how are you going to get power there? 15

What you’re going to have to do is upgrade the 16

transmission and distribution, and the tran smission 17

and distribution cost is trillions of dollars, and 18

so the utility is going to have to pass that cost on 19

and it should be reflected in terms of the benefits 20

of reducing the

-- or improving the efficiency and 21

reducing the losses in those concentrate d areas, so 22

that you don’t have to transmit so much energy into 23

them. 24

MR. BROOKMAN: Charlie. 25Executive Court Reporters (301) 565

- 0064 162 MR. STEPHENS: Charlie Stephens. The 1

Northwest has discovered that that’s actually 2

economically true, that a lot of envisioned 3

investments in transmission an d distribution that 4

were planned and expected never happened because of 5

the efficiency that was actually occurring at the 6

end of the line and in the middle. And so we have 7

now been able to avoid hundreds of millions of 8

dollars, actually, in transmission a nd distribution 9

investments on the basis of the efficiencies, so I 10

would have to concur. 11

MR. BROOKMAN: Steve Rosenstock. 12

MR. ROSENSTOCK: Steve Rosenstock, EEI. 13

Again, this is starting to get to mix apples and 14

oranges a little bit. A lot of that eff iciency was 15

on the customer side, not on the transformer side, 16

and so obviously, as you increase customer 17

efficiency, the loads go down or you might not need 18

as much capacity. There are going to be some 19

situations, talking about New York City, where if 20

on e power plant or one key supply line goes down, 21

you’ll have to build a new one out regardless. 22

They’re going to have to build a separate line, or a 23

separate power plant or other configurations where 24

you’re not going to be able to defer any costs. 25Executive Court Reporters (301) 565

- 0064 163 MR. BE RMAN: That’s not what I’m referring 1

to. I’m not referring to specifics. I’m referring 2

to the general circumstance. Our transmission and 3

distribution network in the United States is archaic 4

and falling apart. 5

MR. ROSENSTOCK: I disagree with that 6

stro ngly, sir. 7

MR. BERMAN: Well, you’re wrong. 8

MR. ROSENSTOCK: No, I’m right. Thank 9

you. 10

MR. BERMAN: Who do you work for? 11

MR. ROSENSTOCK: The Edison Electric 12

Institute, and

-- 13

MR. BERMAN: I know who you are. 14

MR. BROOKMAN: You guys can ta ke that out 15

on the road. Additional comments on this series of 16

issues, and let’s return to Katie. 17

MS. COUGHLIN: So going back to this, so 18

again, this analysis attempts to model something 19

that’s fairly generic, so that’s one of the reasons 20

why perhaps s ome of these issues haven’t been dealt 21

with. So what we’re doing here

-- again, the goal 22

of this particular piece of the calculation is 23

simply to express the correlation that exists 24

between system loads and system prices. So the 25Executive Court Reporters (301) 565

- 0064 164 stripes on this graph, es sentially, the way we do it 1

is fairly straightforward. We take the data and 2

then we just sort it into bins based on the size of 3

the load, which is along the horizontal axis, and 4

then within each bin we calculate the average price, 5

and we calculate a distr ibution of positive and 6

negative increments to the average price for each 7

bin. And that defines a model that allows us, given 8

a value for the system load, to come up with an 9

estimate of the system price. So we can use this to 10

develop an hourly simulation of a system price. 11

And then the second component of the 12

calculation is to understand the correlation between 13

the load on an individual transformer, and the load 14

on the system as a whole, that the transformer is a 15

part of. So this is essentially a stati stical 16

problem. If you think conceptually, the system load 17

is the sum of the loads in all the transformers. 18

What we’re asking is, what is the

-- given that I 19

know that the system load is, say, at 50 percent of 20

its maximum value, what is the probability t hat any 21

single one of those transformers is at a given load 22

value relative to its maximum capacity. 23

So this is defined in the analysis using a 24

joint probability distribution function, which is 25Executive Court Reporters (301) 565

- 0064 165 what’s plotted here, so that tells you that if the 1

system loa d is

-- so both sets of data are divided 2

up into bins between the minimum value and the 3

maximum value. And the probability is just the 4

number of times you find that the system load in one 5

of its bins, and the transformer load in the other 6

one of its bins. But what this allows us to do 7

within the calculation is if we know the system load 8

value, then we can predict, based on this 9

distribution, an estimate of the transformer load 10

value. 11

So we have the system load value. We have 12

a price that gets associate d with the system load. 13

And we have a transformer load that gets associated 14

with the system load, and that allows us to 15

construct this model of the operating cost. 16

MR. BROOKMAN: I saw Robert first. 17

MR. BERMAN: Robert Berman, Berman 18

Economics. Did y ou ground proof any of this with 19

coincident/non

- coincident peaks on primary and 20

secondary for actual systems, or with load factors 21

for maximum utility systems versus the system load 22

factors? 23

MS. COUGHLIN: We have very little data 24

that is specific to tra nsformers. We used building 25Executive Court Reporters (301) 565

- 0064 166 data to try to validate the modeling approach. So 1

we have hourly building load data for approximately 2

800 buildings

-- 3

MR. BERMAN: So you didn’t look at the 4

utilities’ figures on load factors? 5

MS. COUGHLIN: We don’t have those on an 6

individual transformer level. We made some effort 7

to get data about transformers, but we were not 8

successful. So that’s something that we’d be very 9

interested in seeing. I would say that on a 10

technical level, any data that is provided to th e 11

Department could very easily be incorporated into 12

this analysis, so, yes, we’re very interested in 13

receiving information that’s specific to 14

transformers. 15

MR. BROOKMAN: Jerry. 16

MR. SCHOEN: Jerry Schoen, AK Steel. When 17

you talk about looking at the l oad factors, the way 18

I’m reading this is you’re looking at them through 19

the course of a 24 hour day. Did you look at them, 20

for example, in the course of the 24 hour day that I 21

would care the most about is the 24 hour day in 22

August? 23

MS. COUGHLIN: This i s actually a year. 24

This is 8760 hours of a year. 25Executive Court Reporters (301) 565

- 0064 167 MR. SCHOEN: Is that accurate? Because 1

frankly, what little I know about the utilities, 2

when they are in trouble, it’s in August. The 3

summer air conditioning peak, or peak demand load, 4

and that’s when everything is running flat out, 5

including the transformers. Because people are 6

running their air conditioners. And again, that 7

would be regionally sensitive. 8

MR. BROOKMAN: Steve Rosenstock. 9

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 10

think there’s

-- yeah, peak loads are either mid

11

summer or mid

- winter, depending on the utility, 12

where located, et cetera. Again, this is just an 13

average day

-- this has been over 8760 hours. 14

They’re not looking at the peak day for at least 15

this part of the analysis, so they’re just combining 16

all the data. And I guess the other question I was 17

going to say is you’re saying commercial buildings. 18

Do you have some data that breaks out commercial 19

versus industrial buildings, because the load 20

factors will be significantly di fferent between 21

commercial and industrial buildings. 22

MS. COUGHLIN: In the previous analysis, 23

they did do some detailed analysis of the load 24

shapes associated with commercial versus industrial, 25Executive Court Reporters (301) 565

- 0064 168 but did not actually find significant difference, 1

and so

-- 2

MR. ROSENSTOCK: Steve Rosenstock, EEI. 3

I’m very surprised. I’ve got use of the EPRI (ph) 4

data that for a lot of commercial buildings, the 5

load factor

-- the overall load factor, not on a per 6

transformer basis, when you look at the building, 7

typical lo ad factors of a commercial building tend 8

to be at the 50, 55 percent. Industrial buildings, 9

especially if they run two or three shifts, they 10

tend to have load factors in the 70, 80, even 90 11

percent range. So that does surprise me. 12

MR. BROOKMAN: Follow on, Robert. 13

MR. BERMAN: Robert Berman, Berman 14

Economics. Continuing on with that, at the 15

residential level, you’re going to be looking at 16

load factors probably well south of 45 percent in 17

some cases, in the high 30s, and indeed they will, 18

as the gentl eman points out, design those 19

transformers for at least the maximum load at the 20

peak time, and probably by 20 percent on top of that 21

just to be sure, in some cases, which is going to 22

make the load factor against name plate even 23

smaller. 24

MS. COUGHLIN: Ye s, we did separate 25Executive Court Reporters (301) 565

- 0064 169 residential buildings from commercial and industrial 1

for developing the distribution function. 2

MR. BERMAN: But as residential buildings, 3

excuse me, is that a single family house or is that 4

an apartment building in New York? 5

MS. COUG HLIN: I think these are mostly 6

single family and small multifamily. There’s no 7

question that the data set that we have is limited. 8

MR. BERMAN: Because your transformer 9

sizes at that point, they’re going to be very 10

different, and I’m wondering whether or not a 11

neighborhood or a system average load factor, which 12

isn’t transformer specific, but might be assumed to 13

be the same for all transformers within a secondary 14

system, might be more accurate than trying to 15

identify particular transformers or particul ar 16

buildings? 17

MS. COUGHLIN: Well, again, the purpose 18

here is to estimate the annual operating cost 19

associated with energy losses. So again, what

-- 20

all we really need in terms of the transformer loads 21

is the degree to which they are correlated with the 22

ups and downs of these hourly varying system prices. 23

So, in some sense, the precision of this calculation 24

does not need to be as high as other aspects of 25Executive Court Reporters (301) 565

- 0064 170 loading analysis. 1

MR. BROOKMAN: Charlie Stephens. 2

MR. STEPHENS: Yeah, I would just add, we 3

do this all the time with all the end uses that we 4

serve in the Pacific Northwest, looking at all kinds 5

of

-- the valuation of energy saved or load saved. 6

And what I’m seeing here looks fairly consistent 7

with what I’m seeing. Your numbers, at least the 8

dist ributions I’m seeing in front of me here look 9

fairly consistent, in general terms, with what we 10

see when we do our modeling. So I don’t really see 11

an issue so far here, and I’m not sure there’s a lot 12

of industrial that’s relevant to this. Some, but a 13

lot of it looks like commercial, and a lot of 14

residential looks like commercial, like high rise 15

buildings in New York. In fact, they are classified 16

as commercial in our system. 17

So anyway, I think you’re on a good track 18

here from what I can see, and I don’t see anything 19

inconsistent with what we know where we are. 20

MR. BROOKMAN: Okay. 21

MS. COUGHLIN: So that’s it for the liquid 22

immersed. So for the dry type transformers, again, 23

the assumption here is that they are built in the 24

same way that general commercial industrial 25Executive Court Reporters (301) 565

- 0064 171 installations are built, which is there’s a tariff 1

and you get a monthly bill. And in the LCC, the 2

sample of transformer owners is built out of the 3

CBEC’s sample of buildings. We use buildings from 4

1992 and 1995, because for a large su bset of those, 5

through surveys, we have monthly data for the 6

building on electricity consumption and electricity 7

demand, so that allows us to define a monthly load 8

factor for each building. And based on those 9

monthly load factors and some statistical mode ling, 10

we estimate the loss factor and also responsibility 11

factor, which are then used to calculate the total 12

cost for that month, of the losses. 13

So I will review that part of the 14

calculation again when we get to the LCC. The next 15

two slides, I’m just go ing to explain how we did the 16

modeling of the loss factor and responsibility 17

factor as a function of the load factor. And again, 18

we have this collection that I mentioned of a few 19

hundred commercial and industrial buildings. So 20

essentially what you can do is you can just go and 21

calculate for all of those buildings, the monthly 22

value of the loss factor, the load factor, and the 23

responsibility factor, which is defined here as the 24

square of the individual load in the hour of the 25Executive Court Reporters (301) 565

- 0064 172 peak of the aggregate load. 1

So based on all that data, we just 2

constructed some relevant, but simple statistical 3

models. First of all, for the loss factor, we used 4

this expression. I think there’s an error in the 5

notes that LF2 in the equation

-- that 2 should be a 6

superscript. So this is a rule that’s often used in 7

trying to estimate loss factors based on load 8

factors. The value, K, is a parameter that is in 9

between zero and one. So this equation is sort of 10

mathematically correct, and there’s always some 11

value of K that will sat isfy this equation. 12

So what we did is we took our building 13

data and our calculations for each month and each 14

building loss factor and load factor, and deduced 15

the value of K that went with that, and then we used 16

these distributions of values of K for t his group of 17

buildings. And what you find is that there’s a 18

dependence of the shape of the distribution on the 19

range of the load factor for the building. So the 20

model uses three distributions, one for low load 21

factors, one for medium load factors, and on e for 22

high load factors. 23

Again, the load factor is part of the data 24

set in our customers sample. So you know the load 25Executive Court Reporters (301) 565

- 0064 173 factor, you use the distribution to pull out a value 1

of this parameter K, and then you calculate the loss 2

factor. 3

MR. BROOKMAN: Woul d you say that there’s 4

a discrepancy between this and the notes? 5

MS. COUGHLIN: Just in the equation, the 6

LF squared is written LF2

-- 7

MR. BROOKMAN: Is see, thank you. Wanted 8

to point that out. Gary Fernstrom. 9

MR. FERNSTROM: Could you please help me 10

to understand what the responsibility factor is 11

supposed to mean? 12

MS. COUGHLIN: Sure. Responsibility 13

factor is

-- this is the way of looking

-- again, so 14

for the commercial installations, you get a monthly 15

demand charge, so we’re trying to estimat e what the 16

transformer load might contribute to the building 17

peak demand. That is what the responsibility factor 18

tells you. 19

MR. FERNSTROM: Thank you. 20

MS. COUGHLIN: And, so again, the approach 21

that we use is data driven. We take the data that 22

we ha ve, we simply calculate responsibility factors 23

and the scatter plot here shows the responsibility 24

factors as a function of load factor. So again, you 25Executive Court Reporters (301) 565

- 0064 174 see there’s some correlation. Obviously, if the 1

load factor is very high, that means the loads are 2

very flat, that means the responsibility factor will 3

be close to one. If the load factor is very low, 4

that means the load is very variable and the 5

responsibility factor is more difficult to predict. 6

So that general effect is captured in the 7

model that we use here, essentially

-- I won’t go 8

into details, but we model this distribution of 9

responsibility factors as a function of the load 10

factor. 11

MR. BROOKMAN: Question? Steve. 12

MR. ROSENSTOCK: Steve Rosenstock, EEI. 13

And again, this is for the data that yo u have for 14

both commercial and industrial facilities? 15

MS. COUGHLIN: Right. They’re mixed 16

together, yes. 17

MR. ROSENSTOCK: So they’re all together 18

in this graph here

-- this data set? Okay. It does 19

-- if you look at it again, each dot is a data 20

point , it just seems like even with low load 21

factors, it does seem to be significant number that 22

have responsibility factors that are well above 23

point seven or point eight. I thought it would be a 24

little bit more spread out, but it seems like 25Executive Court Reporters (301) 565

- 0064 175 they’re all clust ered, kind of up high. I’m just 1

kind of curious as to why the data isn’t a little 2

bit more spread out on this graph. It seems like 3

there’s a heavier weight, even at the lower load 4

factors. 5

MS. COUGHLIN: Yes, this is

-- it’s 6

difficult to say, again, we have a limited amount of 7

data and more data is always better, so if

-- 8

MR. ROSENSTOCK: So again, I’m not sure in 9

which part of the technical support document, is 10

there a general kind of result in terms of what the 11

responsibility

-- overall responsibil ity factor is? 12

MS. COUGHLIN: Again, what we do is we 13

take this and we use this to construct another 14

distribution function. So given the load factor, 15

then you pick the responsibility factor from the 16

distribution, and that’s what goes into the LCC. 17

MR. BROOKMAN: Robert. 18

MR. van BUSKIRK: Robert van Buskirk, DOE. 19

Also these responsibility factors are based on 20

monthly data, right? 21

MS. COUGHLIN: That’s right. 22

MR. van BUSKIRK: Yes, so a big thing

-- a 23

big factor that affects the responsibility fa ctor is 24

the correlation between the peak on the transformer 25Executive Court Reporters (301) 565

- 0064 176 and the peak of the overall load, and when you’re 1

shortening the time period to a month, rather than 2

the year, those correlations are going to be more on 3

top of each other, and that’s why that pro bably 4

looks different than most of the responsibility 5

factors. 6

MR. BROOKMAN: Thank you. Other questions 7

at this juncture? We’re going to keep going here. 8

MS. COUGHLIN: Okay. Well, we do have

-- 9

so we have isolated a couple of issues. Of course, 10

c omment on anything is welcome. Metered hourly data 11

-- everybody wants it, nobody has it. So if there’s 12

any possibility of getting any kind of field 13

measured data for transformers, we are very 14

interested in seeing it and using it to validate or 15

improving these models. 16

Another question that we ran into is 17

understanding the way that dry type transformers are 18

installed in large buildings, so essentially, for 19

this analysis, we are forced to use the whole 20

building load as a stand

- in for a transformer load, 21

bu t within a large building, depending on how 22

they’re installed and wired into the building 23

circuits, that may or may not be a good 24

approximation. So any information about 25Executive Court Reporters (301) 565

- 0064 177 installation practices for, say, a 30 story 1

building, would be very useful. 2

MR. BRO OKMAN: Steve. 3

MR. ROSENSTOCK: Steve Rosenstock, EEI. 4

For the first issue, as I recall and I think I 5

mentioned it the last time, NYSERDA (ph) did a 6

pretty big study in the 90s about building 7

transformer loads. They did some end use studies. 8

It’s ten year old data, probably, but it still might 9

be relevant for your information, for your model. 10

In terms of installation practices, I’ll 11

just, looking at your Chapter 8, basically, for the 12

dry type design lines that you have, it basically 13

says property ow ners, commercial companies, 14

government offices are about 81 percent of the 15

owners for the dry type, medium or low voltage, and 16

19 percent are industrial. At least in office 17

buildings, at least in ones I’ve been kind of 18

familiar with, doing audits, a lot o f times the dry 19

type transformers really are just knocking it down 20

from 277480 down to 12208, and they’re really just 21

serving receptacles, lights, office equipment, 22

computers, networks, et cetera. They tend to

-- 23

I’ll say it’s kind of a non

- HVAC load in a way, at 24

least in some of the office buildings, or they’re 25Executive Court Reporters (301) 565

- 0064 178 just in there for tenant use, when they decide to 1

use it, especially for multi

- story office buildings. 2

Again, for the low voltage ones in 3

particular, a lot of them tend to be non

- HVAC so 4

they may have less of an impact in terms of 5

responsibility factor. 6

MR. HURST: John Hurst. Have you ever 7

been in New York? 8

MR. ROSENSTOCK: I’m sorry? 9

MR. HURST: Have you ever been in New 10

York? 11

MR. ROSENSTOCK: I have, yes. 12

MR. HURST: All right. Ther e are 30,000 13

network transformers in New York. 14

MR. ROSENSTOCK: I’m talking about 15

building ones, not

-- 16

MR. HURST: Those are building 17

transformers, that’s how the building is served, 480 18

volts. 19

MR. ROSENSTOCK: Right. But then there’s 20

the other on es that can knock it down even further, 21

12208 for all the other stuff too. 22

MR. HURST: Or for that matter

-- I’m just 23

saying there’s lots of buildings where HVAC in large 24

installations is served by dry type transformers 25Executive Court Reporters (301) 565

- 0064 179 indoors. There’s a lot more than little 600 volt. 1

MR. BROOKMAN: John, thank you. Tom is 2

next. 3

MR. PATZNER: I’m going to supply this 4

data in my comments, but you guys actually published 5

the percentage of buildings that are appliances, 6

computers, electronics and so forth. From that data 7

you can break it down into 480 volt loads and 208 8

volt loads. So for the dry type distribution, the 9

building percentages have already been tracked by 10

EEAI, so you guys published it. So I have it on a 11

slide already, I’ll put it in my written comments

. 12

But you will see that the low voltage dry is only 13

going to be approximately 25 percent of electricity 14

in the building, that’s all that’s still using 120 15

volts, and then the medium voltage are going to be 16

75 percent of electricity, because that’s all the 17

480 Y 277. So you guys actually track all those 18

other appliances, and we know which of those 19

appliances are at 120, and which ones are at 480 or 20

277, so you can quickly get the split for the dry 21

type transformers for your loading factors. And 22

I’ll add t hat to my comment. 23

MR. BROOKMAN: Thank you. Other sources 24

of data that we would identify at this point? The 25Executive Court Reporters (301) 565

- 0064 180 Department, of course, always looking for data. 1

Thomas. Please. 2

MR. PATZNER: I would suggest that the 3

DOE, or their consultant firms, adds to their 4

interview, performance contract companies. Since 5

the 90s, actually the last five years, there’s a 6

large number of companies that are tracking the 7

losses in buildings because they assign performance 8

contractors with the end users. They’re proba bly 9

going to be reluctant to give the information to the 10

DOE, but they probably would work with your 11

consultant and there’s a lot of data out there, 12

because it’s really easy to meter all the way down 13

to outlets today. And companies are doing it, they 14

are signing performance contracts with the people 15

that are installing the data, and so there’s an 16

avenue of a stakeholder that I do not believe you 17

guys have looked at yet, that should be able to 18

supply you some of that data. 19

MR. BROOKMAN: Okay. Thank you. We’re 20

about

-- final comments on this? 21

**Life**

**- Cycle Cost**  **and Payback Period Analysis**  22

MS. COUGHLIN: Okay. So now we’ll 23

move on to the LCC, the life cycle cost analysis. 24

So life cycle cost is where we combine everything 25Executive Court Reporters (301) 565

- 0064 181 you’ve heard about up to this po int into an estimate 1

of what is essentially the total

-- life cycle cost 2

is the total ownership cost of the transformer. 3

So the purpose here is to understand the 4

way the life cycle cost is impacted by the standard, 5

and this analysis for transformers di ffers somewhat 6

from other products because the way that the 7

efficiency standard affects the population of 8

designs is simply to eliminate some designs from the 9

overall set of designs that would be available. So 10

it’s quite possible for a set of designs to b e 11

available under all standard levels. 12

So the way that the

-- I’ll give you an 13

overview of the way the LCC works, and then we’re 14

going to walk through each one of the individual 15

inputs to the LCC. So what we have set up in this 16

spreadsheet is

-- what we ’re trying to do is 17

simulate a population of transformers, and we’re 18

actually trying to simulate the loads on the 19

transformers as they would be installed in the 20

field. So it’s more complicated than just the 21

loading assumed in the test procedure. 22

Typical ly, these are the things

-- if you 23

open up the spreadsheet you can set a lot of these 24

parameters yourself when you do a run. Typical run 25Executive Court Reporters (301) 565

- 0064 182 is 10,000 iterations or 10,000 transformers. And 1

for each one of those transformers, we go through 2

each one of the st eps that I’m going to outline, and 3

we calculate the life cycle cost for that 4

transformer. And we repeat that whole set of 10,000 5

calculations for each candidate standard level. So 6

we have a distribution of LCC results at every 7

single standard level that we can consider. 8

Within the simulation, there are a number 9

of variables that contain some random variation. 10

This includes the specific choice of design for the 11

baseline and for the standard level at each 12

candidate standard level. The transformer loa ding 13

parameters have some random variability in them. 14

The transformer price load correlation, as I 15

described, would have some variability, and the 16

transformer lifetime will have some variability. 17

As I said, the effect of an amended 18

standard is to take s ome of the designs that are 19

available at even the base case, and remove them 20

from the choices in the overall design set. 21

So let me just give you a graphical 22

illustration of what I mean by that. This is a plot 23

for design line one, candidate standard leve l one. 24

On the vertical axis we have the load losses, and on 25Executive Court Reporters (301) 565

- 0064 183 the horizontal axis, the no

- load losses. These are 1

the engineering parameters. And then this cloud of 2

points represents all of the designs that are in the 3

table that we received from the enginee ring 4

analysis. 5

In the

-- the triangles represent designs 6

that would be selected in the base case of the 7

current standard, and then the green circles are 8

designs that would be selected under some

-- under 9

candidate standard level one. So you see there’s a 10

decent number of designs that are not selected under 11

any standard level, and there’s a decent number of 12

designs that survive

-- that are selected under both 13

scenarios. 14

And then the effect of the standard is 15

roughly approximated by this dashed line. It’s 16

going to cut off some designs that have low 17

efficiency according to the test procedure. 18

So this flow chart illustrates the series 19

of calculations that we go through for each 20

individual transformer. We have these A and B 21

parameters, which are used t o define the customer 22

choice model, the process of the customer choosing a 23

transformer. And we have the

-- we have actual data 24

for A and B values. Then we have the table of 25Executive Court Reporters (301) 565

- 0064 184 transformer designs, so we have a customer, and the 1

customer gets assigned an A a nd B value that is 2

translated into the choice of the design, then we 3

can calculate the markups and installed cost. Then 4

we move down and we do the loading calculation, so 5

we have a model for the transformer loading, and we 6

have our electricity costs and p rices. So we do 7

this simulation of the operating cost and the

-- and 8

so we calculate annual operating cost based on that 9

simulation of the load and price variation. 10

Then we take the annual operating cost and 11

we want to extend that out over the lifetime of the 12

transformer, so we have some trends that escalate 13

the electricity price, that gives us the operating 14

cost over the lifetime of the transformer. 15

And then to finish up with the economics, 16

we have a discount rate which is applied to future 17

operatin g cost savings, and we apply that discount 18

rate, we get a net present value associated with the 19

lifetime operating cost. And then within all these 20

calculations there is some ability to adjust for 21

different compliance dates and variability in the 22

lifetime. 23

So the next few slides, we’re going to 24

step through, essentially, these blue boxes, the 25Executive Court Reporters (301) 565

- 0064 185 ones that we haven’t discussed yet in any detail, 1

and go over the additional inputs to this analysis. 2

MR. BROOKMAN: Why don’t you just pause 3

for a moment. Questi ons about any of this? The 4

flow chart is really complicated, I think many have 5

seen it before. Questions before we proceed? Okay. 6

MS. COUGHLIN: And I just remind you once 7

again that because of the different ownership 8

categories and the different el ectricity pricing 9

structures for liquid immersed versus dry type 10

transformers, there are some differences within

-- I 11

mean, overall, both sets of spreadsheets work the 12

same, but there are some differences in the details 13

of how the operating cost savings ar e calculated. 14

So again, liquid immersed, the operating 15

cost is evaluated using hourly variation in both 16

transformer loads and prices, and for dry type, it’s 17

monthly variation in the transformer load parameters 18

and the electricity prices. 19

So with these A and B values, essentially 20

what we want to represent in the model is the sort 21

of, in some general sense, what people do when they 22

purchase a transformer. So, again, we use this IEEE 23

document that I mentioned earlier as a guideline to 24

kind of standardize method for evaluating the total 25Executive Court Reporters (301) 565

- 0064 186 emission cost of the transformer, and in that type 1

of calculation, we have these two parameters, A and 2

B. So A is essentially the net present value or the 3

equivalent first cost as it is called, a no

- load 4

loss, in dollars pe r watt; and B is the equivalent 5

first cost

-- there’s an error here, that should be 6

load losses for the Bs in dollars per watt. 7

So the percentage of purchasers who 8

actually go through the trouble of evaluating the 9

total ownership cost is a variable in th e LCC. And 10

those purchasers are referred to as evaluators. The 11

assumption is is if you’re not an evaluator, you are 12

simply going to buy the cheapest design that meets 13

your other engineering criteria. And within the 14

LCC, we set up certain

-- a number of scenarios 15

where the percentage of owners who do this 16

evaluation is defined as shown in this table. And 17

the default scenario is that for liquid immersed, 18

about 75 percent of purchasers are going to 19

evaluate. For low voltage dry type, it’s ten 20

percent. Fo r medium, it’s 50 percent, and for high, 21

it’s 80 percent. And we also consider sensitivity 22

scenarios in which no one evaluates, and scenarios 23

in which everyone evaluates. 24

MR. BROOKMAN: Steve Rosenstock. 25Executive Court Reporters (301) 565

- 0064 187 MR. ROSENSTOCK: Steve Rosenstock, EEI. 1

For l iquid immersed, I haven’t asked, but several 2

years ago it seemed like the ratio was 50:50 of 3

these investor owned utilities that were evaluating 4

versus non evaluating. I don’t know what the ratio 5

is now. I’m going to encourage members to provide 6

informat ion to DOE to let you know if they’re 7

evaluating on the TOC basis. 8

MR. BROOKMAN: Steve, you actually did a 9

survey or something? 10

MR. ROSENSTOCK: Last time, last go round, 11

I believe, or there was

-- in 2005, I think there 12

was other data, other surveys out there that 13

discussed it. I don’t know if Oak Ridge did it or 14

some of there was some information, especially after 15

deregulation, a lot of people stopped evaluating, in 16

the late 90s. 17

But on the other hand, for the dry type 18

in particular, and I said this last time, I’ve 19

worked with commercial customers and I don’t know of 20

any commercial or industrial customers that use both 21

A or B values to evaluate any equipment that they’re 22

buying. They’re looking at dollar per kilowatt 23

hour, or dollar per ... peak demand. They’re not 24

assigning different values to no

- load versus load 25Executive Court Reporters (301) 565

- 0064 188 losses on a transformer. It’s just like any other 1

appliance, you have different initial cost, you have 2

different energy uses, they’re doing life cycle 3

cost, they’re saying okay, which one

-- if they’re 4

doing life cycle, which one is lower energy cost, 5

they don’t care whether it’s load or no

- load. It’s 6

just an energy cost is an energy cost. 7

So again, I understand and appreciate all 8

the Department’s done, but especially for commercial 9

and industrial owners, using A and B is not really a 10

good model of the marketplace out there because 11

they’re not evaluating them separately. For them, 12

it’s just energy cost, regardless of the loading of 13

the transformer, and they want to model them and 14

dec ide which one has life cycle cost. It’s LCC. 15

MS. COUGHLIN: So we’ve actually attempted 16

to take that into account. We call it A and B, and 17

we need the A and B parameters because we need that 18

to link with the designs that are in the engineering 19

table, b ut for the dry type transformers, our method 20

of estimating A and B is actually based on their 21

monthly marginal demand and energy prices. So it 22

does correspond much more closely to the way the

-- 23

an owner who is billed by a tariff would evaluate 24

those loss es. 25Executive Court Reporters (301) 565

- 0064 189 MR. BROOKMAN: Keep going, Steve. 1

MR. ROSENSTOCK: Steve Rosenstock, EEI. 2

And again, but it’s not

-- they’re not necessarily

- 3

- those transformers are not necessarily doing 4

marginal, they’re doing base load consumption as 5

well. It’s not just marg inal. That’s the other 6

key. 7

MR. BROOKMAN: You’re

-- 8

MR. ROSENSTOCK: I’m talking about the dry 9

type, I’m sorry. They’re not

-- the transformers 10

are not

-- they’re not just using electricity at the 11

margin, they’re using it at the base load as well. 12

MR. BROOKMAN: Thomas and then Charlie. 13

MR. PATZNER: Steve, I’d like to

-- Thomas 14

Patzner

-- I’d like to expand. In my opinion, A and 15

B are sufficient, but I believe it would be 16

unoccupied where you only have no

- load, and then 17

occupied, which is how customers are starting to 18

look at their consumption. And then the occupied 19

would be A plus B. So if you’re talking to a 20

commercial user, they’re looking at when they’re not 21

occupied in the building, where the no

- load is going 22

to be there, and then they’ re looking at when 23

they’re occupied, where you’re going to have people 24

plugging in devices and turning them on. So it 25Executive Court Reporters (301) 565

- 0064 190 would be A plus B for the second scenario, and just 1

A for the first scenario. And you could take it 2

back to your transformer designs. 3

MR. BROOKMAN: Charlie. 4

MR. STEPHENS: Charlie Stephens. We’ve 5

been doing efficiency programs with our commercial 6

and industrial customers for 30 years now, and 7

pretty much uniformly in most of them, not all of 8

them, but most of them are sophisticated e nough that 9

they know what their loads are going to be on the 10

building. They estimate them, they take the trouble 11

to estimate them anyway, and they know what kind of 12

a transformer they’re going to need. And if you’ve 13

got an industrial customer that’s runn ing an 80 14

percent load factor on the system because they are 15

three shift paper mill, they know that they need a 16

transformer with low load losses, and that’s what 17

they buy. So they’re doing it. They’re not stupid. 18

It costs them a lot of money to pick the wrong 19

transformer, especially if you’re a big customer, 20

which includes a big 30 story commercial building, 21

like UNICO owns a lot of. 22

So we work with these folks, to this day, 23

and in fact, we’re working with a lot of our 24

industrial customers right now, to help them 25Executive Court Reporters (301) 565

- 0064 191 increase the sophistication of their load models so 1

that they can do a better job of estimating their 2

losses. So this is going on all the time, but I 3

would say that your choices of ten percent, 50 and 4

80, based on the size of the transformer are 5

probably not

-- they’re not unreasonable. 6

MR. BROOKMAN: But Charlie, are you 7

talking about the northwest? 8

MR. STEPHENS: No, actually, I’m just 9

talking about the business community that we work 10

with. Most of the corporations that we work with 11

ar e not northwest corporations, they’re national and 12

international corporations, and the people that do 13

this are

-- some of them are based in Philadelphia, 14

and they’re doing the load calcs for a paper mill in 15

Oregon. So, you know, they’re not

-- these are 16

b usiness people who understand that it’s costing 17

them more and more money to have losses they don’t 18

need to have if they just do their homework. 19

MR. BROOKMAN: Robert. 20

MR. van BUSKIRK: So Robert van Buskirk, 21

Department of Energy. I’d like to clarify t hat, to 22

some extent the use of A and B factors on the dry 23

type transformers is more a mathematical convenience 24

than the decision of how DOE thinks customers are 25Executive Court Reporters (301) 565

- 0064 192 making their decisions. There’s an equivalence to 1

some extent between a minimum life cycle cos t 2

calculation and an equivalent A and B for that 3

particular transformer choice. And when the 4

Department is estimating an A and B factor for that 5

dry type transformer selection decision, the 6

Department is trying to pick the A and B values that 7

are equivale nt, mathematically equivalent, to the 8

minimum life cycle cost calculation that a customer 9

might actually go through. 10

MR. BROOKMAN: So I think it might be 11

useful to have confirmation of what Charlie’s 12

talking about, that

-- I guess both medium to large 13

c ommercial and industrial, they’re making some 14

pretty informed decisions here, I guess. I don’t 15

know on the residential side, but

-- 16

MR. HURST: John Hurst. 17

MR. BROOKMAN: Yes. 18

MR. HURST: Most data processing

-- I mean 19

most buildings, most commercia l buildings, run large 20

data processing loads. A contractor estimating 21

nowadays is going to estimate more power per square 22

foot than he would have ten years ago, or 20 years 23

ago, and it’s a 24 hour cycle. The original cycle 24

for those buildings used to be like, let’s see, I 25Executive Court Reporters (301) 565

- 0064 193 think it used to be like 80 percent or 90 percent 1

during the day and half of that during the midday, 2

and then at night it was dropped down. Those things 3

are not true in large commercial buildings any 4

longer. 5

MR. BROOKMAN: Yes, Paul. 6

MR. RYAN: Paul Ryan. Just want to go 7

back to liquid filled side. I urge the DOE or its 8

consultants to reevaluate the evaluation scenario, 9

75 percent is much too high. The IOUs as Robert 10

Berman commented earlier, often ask the transformer 11

OEM to give them DOE’s as cheaply as they can. 12

That’s a first cost analysis. It’s not a TOC 13

analysis. I would guess that that’s probably a 14

maximum value of 15 percent. So 15 and 75, there’s 15

a big deviation there, so I think the Department and 16

its consultants needs to reevaluate the evaluation 17

of TOC. 18

MR. BROOKMAN: Gary Fernstrom. Thank you. 19

MR. FERNSTROM: Are we talking with this 20

number

-- the number of individual utilities, or are 21

we taking into account the size of utilities with 22

respect to number of custom ers served, or portion of 23

the country served. I can assure you that PG&E uses 24

some life cycle cost approach for looking at 25Executive Court Reporters (301) 565

- 0064 194 transformers, and I would venture a guess that most 1

of the other large utilities that serve a large 2

portion of the nation do similar ly. 3

MS. COUGHLIN: Yes, so this percentage is 4

the percentage of transformers in simulation. So 5

the probability that a transformer will be owned by 6

one of the utilities is defined by the total annual 7

sales of that utility. So more of the transformers 8

will be owned by the larger utilities. But yes, the 9

75 percent is just for the population of 10

transformers, and we have not, I believe, 11

implemented any kind of rule about to take utility 12

information and define whether that utility would be 13

more likely to e valuate. But we could implement 14

that if we receive reliable data on how that should 15

be done. 16

MR. BROOKMAN: It seems like we’re getting 17

not clarity on how we’re segmenting all of this, but 18

maybe someone would comment about what they think 19

the faults mig ht be. Jerry, you’re next in the 20

queue. 21

MR. SCHOEN: Jerry Schoen, AK Steel. All 22

of these transformers are now regulated to some 23

extent to a minimum efficiency level. So isn't 24

there a default TOC built into that evaluation? So 25Executive Court Reporters (301) 565

- 0064 195 there is no such thing as a non

- evaluator? They are 1

just DOE compliant, would be the first box, and then 2

above that

-- 3

MR. BROOKMAN: I saw Robert first, and 4

then Andrew. 5

MR. BERMAN: In answer to your question, 6

you can design to A and B factors and get a TOC 7

based on your A and B factors. Or you can say give 8

me DOE as cheaply as possible, at which point I’ll 9

take the efficiency number, don’t even think about A 10

and B, and see how cheaply I can build a transformer 11

that’s going to meet that efficiency value. That’s 12

a very di fferent cost than if I build a transformer 13

to TOC, and say what’s the initial cost of that 14

transformer, and buy based on that initial cost 15

versus the TOC. I’m still buying a TOC transformer. 16

So if I evaluate it based on TOC and I’m really 17

looking at it b ased on initial cost, I’ve got a very 18

significant upward bias in the cost of the 19

transformer. 20

In addition to that, if we say TOC, 21

there’s a number of utilities out there that do 22

something called band of equivalence, which doesn’t 23

give you TOC, and is a way of doing risk analysis 24

that makes the economy shudder. 25Executive Court Reporters (301) 565

- 0064 196 MR. BROOKMAN: So that last comment was 1

from Jerry. Andrew is in the queue and then Steve. 2

MR. deLASKI: I wanted to make the band of 3

equivalence point as well, and so now I’m hearing 4

quite a

-- the 75 percent number, I believe, is the 5

same number that was used in the last rulemaking, is 6

that correct? For evaluation of the liquid 7

immersed? 8

MS. COUGHLIN: Yes. 9

MR. deLASKI: So I guess there’s a few 10

comments on that. One is that it strikes me that 11

there’s a reasonable possibility that some utilities 12

that were evaluating before, now aren’t, for what 13

has been described before. I see some nodding 14

around the table here. And now there are minimum 15

DOE standards, let’s just buy the minimum. Giv e me 16

the minimum, DOE’s taking care of this, I’m not 17

going to worry about A and B any more. I think it 18

may

-- I think it’s worth checking into, has 19

practice changed because now there is a standard 20

where there wasn’t one before? 21

And then I think the othe r thing that I am 22

concerned about is, is if you ask the utility, do 23

you do any evaluation, and they say yes, what does 24

that mean? 25Executive Court Reporters (301) 565

- 0064 197 PARTICIPANT: Everybody’s going to say 1

they do it. 2

MR. deLASKI: Of course they’re going to 3

say they do it. Yeah, of co urse I do evaluation. 4

It’s almost a question of pride. But my 5

understanding, and this is from talking to people 6

while I’ve been in and out of this technology over 7

the last 15 years, is that there has been this 8

practice of band of equivalence, which is yo u do the 9

analysis, and then you ignore it. So I think we 10

have to

-- this 75 percent number is

-- strikes me 11

as probably too high. I wish I had a better number 12

for you. I heard 15 percent over here. The 13

manufacturers probably have a better sense than I 14

do, I’m sure they do, and utilities have the best 15

sense. 16

MR. BROOKMAN: Does anybody

-- since we’re 17

on our number right now, anybody wish to speculate 18

what that number is? Any additional thoughts on 19

that number? 20

PARTICIPANT: Which number now? Hold o n. 21

MR. BROOKMAN: We’re talking about the 22

default number. 23

MS. COUGHLIN: Default evaluators. 24

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 25Executive Court Reporters (301) 565

- 0064 198 gave an estimate based on, again, older data. It 1

seemed like it was half and half, based on whether 2

it was EI surv ey or just other trade press data. 3

MR. BROOKMAN: This is a thing for which 4

comment would be very

-- 5

MR. ROSENSTOCK: I am going to urge my 6

members to provide to DOE are they using TOC, how 7

they’re evaluating, why that information

-- and also 8

in terms of band of equivalence, another way to look 9

at it is in Monte Carlo analysis. You’re getting 10

multiple bids from multiple vendors, multiple 11

losses, multiple prices

-- they’re all into their 12

calculations, there’s spreadsheets, and then as we 13

know, because you’re forecasting over a 30 year 14

lifetime, you’re going to do a band of equivalence 15

because of high, low, medium, any sort of cost 16

parameters that might be going on. That’s why they 17

do a band of equivalence, because for the long term, 18

there’s that bandwi dth that they’re looking at in 19

terms of what’s really going to happen over the next 20

30 years. 21

Just like a lot of people

-- just like EIA 22

does with their high, medium reference of load, they 23

predict different outcomes based on different 24

parameters. In a way, it’s their version of band of 25Executive Court Reporters (301) 565

- 0064 1 99 equivalence. Thank you. 1

MR. BROOKMAN: Yes. 2

MR. deLASKI: Just to follow onto that. 3

So my understanding of that process, Steve, correct 4

me, because people know better than I do, but that 5

process tends to lead to a l owest first cost 6

transformer purchase. That’s what I understand 7

happens. 8

MR. ROSENSTOCK: It’s hard to

-- but 9

again,

-- 10

MR. deLASKI: But what it leads to is 11

lowest first cost, not to actually evaluate 12

transformers. 13

MR. PATZNER: But my fear in thi s climate 14

is going to be

-- you’re going to go to the 15

utilities and every single one of them say, of 16

course we evaluate, DOE requires it and they’ll give 17

you the numbers that are in the rule, because that’s 18

actually what they’re using. 19

MR. BROOKMAN: Tha nk you, Jerry, and I 20

also saw the other Jerry, pardon me. Yes. Jerry, 21

you had a comment as well? Okay. 22

Well, let me ask, Katie, is there anything 23

else that you want to put to this crowd that you 24

would like them to talk about? 25Executive Court Reporters (301) 565

- 0064 200 MS. COUGHLIN: I don’t think so. I mean 1

we actually have identified this as one of the 2

issues, so we’ll come back to it as an issue box, 3

but I think

-- we may be overestimating in this 4

discussion the importance of the fraction of people 5

who evaluate. Because if a utility is ev aluating, 6

is putting some value on losses, and they’re doing 7

that accurately, it’s very likely that they won’t be 8

impacted by the standard. Because the design that 9

they would purchase would be available under the 10

standard. It’s a fairly subtle point, tho ugh. 11

MR. BROOKMAN: Mahesh. 12

MR. SAMPAT: Mahesh Sampat. I think the

- 13

- if you go about asking the question, do you 14

evaluate? Everybody’s going to say they are going 15

to evaluate, okay. I think maybe the different way 16

to phrase the question would be, do you buy DOE or 17

DOE plus? And how many people buy DOE plus? And 18

that number is probably what needs to go there. 19

MS. COUGHLIN: Yes, I believe

-- we’ve 20

looked at the purchases

-- the market share of TP1 21

or TP2 or whatever, and that helps inform these 22

numbers, but yes, it’s just an estimate. 23

MR. SAMPAT: It’s more efficient than DOE. 24

How many people really buy more efficient than DOE? 25Executive Court Reporters (301) 565

- 0064 201 That’s the question. 1

MS. COUGHLIN: Okay. Let’s move on. I’m 2

not sure

-- we spent a lot of time talking about 3

th is, I don’t want to spend too much time on the 4

subject. This is essentially the A and B values 5

that are in the spreadsheet model, were taken from 6

data. So we have the older survey data that was 7

used in the first analysis, and then we did our own 8

survey j ust going through the internet, looking for 9

transformer bids which provide the A and B values. 10

We did an analysis to check whether or not 11

the distribution of A and B has changed 12

significantly between the most recent year and the 13

earlier data years, and w e couldn’t find any 14

evidence of a trend in either A or B. 15

So within the LCC spreadsheet, there’s a 16

little

-- again, a little statistical model that if 17

your customer is an evaluator, that we assign to 18

them an A and a B value, and then once we have that, 19

we get the design from the design table. 20

And as I mentioned, for the dry type, we 21

call it an A and B so that we can connect to the 22

design table, but really it’s based on a very 23

simplified ownership cost based on that building’s 24

cost of electricity. 25Executive Court Reporters (301) 565

- 0064 202 The issues for comment

-- well, evaluation 1

rates, so we covered that. Again, we’re also 2

interested in anything that might change

-- if 3

you’re dealing with buildings, large buildings with 4

multiple transformers, whether there’s any reason 5

why some subcatego ries of transformers would be 6

treated differently than others. And how we might 7

relate that purchase practice to the data that we 8

have for the buildings, such as the building size, 9

the number of floors, the principal building 10

activity. 11

MR. BROOKMAN: So you can see the comment 12

boxes. Please take a peek, see if there’s any 13

additional comments are warranted at this time. 14

Okay, so we’re moving on. 15

MS. COUGHLIN: Okay. So the total 16

installed cost is what goes into the LCC, so we get 17

the purchase price w ith the manufacturer markups 18

from the engineering analysis, and then as Greg 19

Rosenquist went through, we add the

-- 20

MR. BROOKMAN: Can you just pause for a 21

moment? 22

MS. COUGHLIN: Sure. 23

MR. BROOKMAN: Let’s just everybody stand 24

up. Just for just a

- - just stretch for just a 25Executive Court Reporters (301) 565

- 0064 203 minute. We’ve hit kind of a dead spot here and 1

we’re not going to allow that to persist. Okay. 2

Get a breath of fresh air

-- well, air. Okay. Now 3

let’s resume. Okay. Total installed costs. 4

MS. COUGHLIN: So total installe d costs 5

include the markups, sales taxes, and then any 6

additional installation costs that are required. 7

And this is where consideration of weight and size 8

do come into the LCC. 9

For the electricity prices, for the liquid 10

immersed, the hourly marginal e lectricity production 11

costs come from the FERC filings, and as I said, in 12

areas where the wholesale market, we use the day 13

ahead market clearing price, otherwise we use the 14

system lambda. And we have prices for each of these 15

EMM regions that are defined w ithin the national 16

energy modeling system. 17

Now we do include in the LCC, the capacity 18

savings that would be associated with improved 19

transformer efficiency. So based on our statistical 20

model of the loads, we can estimate this 21

responsibility factor, the transformer load at the 22

hour of the system peak. And then we use data that 23

we pull out of NEMS on capacity costs for generation 24

capacity either for base load or for peaking load, 25Executive Court Reporters (301) 565

- 0064 204 or really mid

- merit load, and transmission 1

distribution costs, and then the capital recovery 2

factors that essentially give you financing costs 3

associated with those investments. 4

So those are used to define the capacity 5

cost piece of the operating costs for the 6

transformer. This is only done for liquid immersed. 7

For dry type, it’s essentially

-- this is 8

the demand piece of the monthly electricity billing. 9

MR. BROOKMAN: Robert. 10

MR. BERMAN: Robert Berman, Berman 11

Economics. I’m a little confused about an apparent 12

inconsistency and I’m just wondering why it’s there. 13

You’re using tariff rate or price for the dry type 14

and utility cost for the liquid immersed. What are 15

we looking at the cost of? Or the cost to? 16

MS. COUGHLIN: The cost of providing the 17

electricity that is dissipated in the transformer. 18

MR. BERMAN: So that would still be the 19

utility cost for the dry type as well. The tariff 20

rate that they’re getting, and a large number of 21

these customers aren’t even on tariff, they’re on 22

contract that you may not even see, is

-- it’s going 23

to include a T&D of the customer component as well, 24

it’s what the tariff is based on. The cost that 25Executive Court Reporters (301) 565

- 0064 205 you’re using on the liquid immersed side is 1

basically generation cost, or generation and 2

transmission cost. The bus bar, if you will. 3

MS. COUGHLIN: Well, it’s avoided capacity 4

cost. 5

MR. BERMAN: Avoided capacity cost. But 6

it’s not an avoided capacity cost for the dry type, 7

and I think you probably ought to be doing it 8

consistently, at least so that you could add the 9

numbers together. 10

MS. COUGHLIN: Well, the dry type

-- the 11

assum ption is that essentially the meter is before 12

the transformer, so the customer pays for the 13

electricity that is being dissipated by the 14

transformer. So the value to the customer, or the 15

person who is buying the transformer is what they 16

pay according to th e tariff. And that’s what the 17

LCC calculates. 18

MR. BROOKMAN: Is that true? The meter is 19

there before the transformer? Yes. Okay. Gary. 20

MR. FERNSTROM: I’m still confused about 21

this capacity component, so could you go

-- there we 22

go. You say the c apacity component is derived from 23

the auctions for regions with function capacity 24

markets. So you have a factor, then, that you apply 25Executive Court Reporters (301) 565

- 0064 206 to the market capacity cost, through which you 1

derive the T&D

-- 2

MS. COUGHLIN: Right. Well, this is just 3

for the gene ration capacity, so that essentially 4

what we’re after is an annualized dollars per 5

kilowatt that we can say when you know, you shave 6

the peak load by a certain number of kilowatts and 7

we assign a value. There are some regions where 8

there is a capacity mar ket, so we used capacity 9

market data to get that dollars per kilowatt. 10

MR. FERNSTROM: Okay. So I’m trying to 11

understand where the T&D cost shows up. 12

MS. COUGHLIN: The T&D cost is added to 13

the generation cost. The T&D cost is taken from the 14

NEMS, wh at’s used in NEMS to value T&D additions. 15

MR. FERNSTROM: So that’s some factor 16

applied to the generalized generation capacity cost? 17

MS. COUGHLIN: It’s added. So you have 18

the shaving of the peak, which is kilowatts, and 19

then you have two pieces in th e avoided cost. You 20

have the avoided generation and the avoided T&D. 21

MR. FERNSTROM: Where do you get the 22

avoided T&D from? 23

MS. COUGHLIN: From NEMS, from

-- so 24

there’s a table in NEMS that is used within the 25Executive Court Reporters (301) 565

- 0064 207 annual energy outlook to define the cost o f 1

expanding the system. 2

MR. FERNSTROM: Okay. Thank you. 3

MR. BROOKMAN: Robert. You okay? Got it. 4

Okay. So this

-- other questions or comments on 5

this dense material? I thought it was well covered, 6

but I thought it was pretty dense. Okay. So we ’re 7

moving on and for those of you that are wondering, 8

it’s about 10, 15 minutes or so we’re going to take 9

a break. 10

MS. COUGHLIN: So okay. For the 11

electricity price for the dry type transformers, 12

probably the most important thing on this slide is 13

the r eference, if you’re interested, there’s a 14

report on how

-- the methodology that we have used 15

to develop a tariff

- based marginal electricity 16

price, or average electricity price for commercial 17

buildings. Within the LCC, the main thing that you 18

need to know is that each building actually has a 19

dollars per kilowatt hour value for energy, and a 20

dollars per kilowatt value for changes in demand. 21

So the energy savings, and the demand savings are 22

both accounted for at the level of an individual 23

customer in the LCC

. 24

And again, those are converted to an 25Executive Court Reporters (301) 565

- 0064 208 annual operating cost. We include the seasonal 1

rates variation in electricity rates, and then the 2

whole annual cost is escalated, using the AEO price 3

forecast. 4

MR. BROOKMAN: Yes, please, Steve. 5

MR. ROSENSTOC K: Steve Rosenstock, Edison 6

Electric Institute. A couple questions. In your 7

TSD you show that about 20 percent of the 8

transformers of the dry type ones are owned by 9

industrial customers. Are you using MEC’s data for 10

the industrial customer for that por tion of the 11

analysis? 12

MS. COUGHLIN: We don’t have

-- MEC’s 13

provides very little data at the building level, so 14

what we have done is we took a subset of the CBEC’s 15

buildings, which we believed would have loads that 16

are similar to industrial buildings, an d then we

-- 17

so those are large buildings or buildings like 18

refrigerated warehouse, which are very use specific 19

-- and then we adjusted the weights using 20

information from MEC’s on floor space associated 21

with industrial buildings. 22

MR. ROSENSTOCK: Okay. And in terms of 23

the utility tariffs, how are they broken out in 24

terms of

-- do you have

-- are they covered

-- for 25Executive Court Reporters (301) 565

- 0064 209 example, investor

- owned utilities serve about 70 1

percent of the customers, and unions and coops serve 2

about 30 percent. Are the tariffs brok en out in a 3

similar percentage in terms of customers served? 4

MS. COUGHLIN: Yes, the tariffs 5

essentially have a weight associated with them that 6

is related to the customer accounts that are in EIA 7

for each utility. 8

MR. ROSENSTOCK: Thank you. 9

MS. COU GHLIN: Okay. So moving along, 10

this is the energy price forecast that comes out of 11

the energy outlook. So we have three scenarios: the 12

reference case scenario, then there’s the high price 13

and the low price scenario. So what you have here 14

is essentially, this is an escalation factor that’s 15

used over the lifetime of the transformer to scale 16

the value of the operating costs. And this has been 17

converted to a real dollar escalation factor. And I 18

believe the AEO forecast stops in 2020, so we use a 19

different method to estimate the growth beyond 2020 20

to

-- so that we can look at the operating cost over 21

the full lifetime of the transformer. 22

MR. BROOKMAN: Yes, Robert. 23

MR. BERMAN: Robert Berman, Berman 24

Economics. If I’m reading this graph right, you’re 25Executive Court Reporters (301) 565

- 0064 210 fore casting a price in real terms for 2035 that’s 1

five percent higher than what it was in 2008? Yes, 2

2008. 3

MS. COUGHLIN: Yes, this is what AEO gives 4

us this year, yes. 5

MR. BERMAN: Okay, just

-- 6

MR. PHOUMINH: Yes, John Phouminh. I’m 7

looking at your graph there and it seems like you 8

used 35 years life expectancy of the transformers? 9

MS. COUGHLIN: We’ll get to that. It’s a 10

distribution with a mean of 32 years. 11

MR. PHOUMINH: Thirty

- two? 12

MS. COUGHLIN: Yes. 13

MR. PHOUMINH: I believe there ough t to be 14

used at 30 years, not 32. AOE draft, you know the 15

one that you reference on slide 89, if I’m not 16

mistaken, I think they use a 30, not 32. 17

MR. BROOKMAN: I think they’re going to 18

describe that a little further. 19

MS. COUGHLIN: Yes. 20

MR. BROOKMA N: Now, there were a few more 21

-- in a little bit, to describe the distribution 22

life. 23

MS. COUGHLIN: Yes, we’ll get to that in a 24

moment, yes. 25Executive Court Reporters (301) 565

- 0064 211 MR. BROOKMAN: Gary Fernstrom. 1

MR. FERNSTROM: So you’re showing a 2

dramatic drop in price from maybe 2007 to 2011, and 3

then a very gradual increase after that. I’d like 4

to know where I can sign up for that deal. That 5

looks almost too good to be true. 6

MS. COUGHLIN: Yeah, and as I said, this 7

is the Annual Energy Outlook, so it’s really

-- we 8

don’t really have any control over these numbers, so 9

I

-- yeah. This is the Energy Information Agency 10

forecast. 11

MR. BROOKMAN: Energy Information 12

Administration. Go ahead Steve. 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. 14

Yeah, what they’re doing is they’re looking 15

back wards, based on

-- the values from 2005 to 2009 16

are just based on the past history, based on the 17

actual data. Because 2008, remember, $140 per 18

barrel of oil and $12.00 per million BTU natural 19

gas. That’s why you see that spike up. Natural gas 20

now, we’re $1.40 per million BTU, that’s had a huge 21

difference on electric prices, that’s why you see

-- 22

again, that’s just referring what actually happened 23

in the marketplace, especially for someone on the 24

marginal generation. And then just trying to 25Executive Court Reporters (301) 565

- 0064 212 predict afte rwards, you’ll see

-- and they always 1

have the band width. 2

MR. BROOKMAN: Well it’s their forecast 3

that DOE is using, so let’s move on. 4

MS. COUGHLIN: So we have discount rates. 5

Discount rates are used to discount the value of 6

future operating cost sa vings. We use debt and 7

equity

-- cost of debt and equity. Cost of equity 8

is used, standard modeling procedure, the capital 9

asset pricing model. We use data obtained from this 10

DemaDor (ph) online website, and essentially try to 11

break down the cost of cap ital for different 12

categories of transformer purchasers and then come 13

up with a weighted average based on the distribution 14

of transformer purchases across those different 15

categories. 16

So this table gives the ownership 17

categories and then the discount ra te that’s 18

calculated for that ownership category. The third 19

column, the number of observations is just the 20

original data set. That doesn’t have anything to do 21

with the way they’re weighted in the LCC 22

calculation. 23

MR. ROSENSTOCK: Steve Rosenstock, EEI. 24

Just out of curiosity, do you have information on 25Executive Court Reporters (301) 565

- 0064 213 what kind of variance or standard deviation within 1

these categories? 2

MS. COUGHLIN: That might be in the TSD, 3

yeah. I don’t know. 4

MR. ROSENSTOCK: Which chapter? I’m 5

sorry. 6

MS. COUGHLIN: It’s in the spreadsheet. 7

You can look at that in the spreadsheet. In the 8

spreadsheet the discount rate is treated as a 9

distribution and you will find that within the 10

distribution in there. 11

MR. ROSENSTOCK: Okay. Thank you. 12

MS. COUGHLIN: Service lifetime. So we’re 13

using the document prepared by ORNL that came up 14

with a service lifetime of 32 years. The 15

transformer simulation uses a distribution of 16

lifetime, so each individual transformer will have a 17

lifetime drawn from that distribution. We assume a 18

failu re rate of half a percent per year, due to 19

whatever random defects or problems, and then in the 20

15 th year of the transformer’s life, additional rate 21

of failure of half percent per year kicks in due to 22

wear and tear, corrosion, that sort of thing. 23

MR. B ERMAN: Robert Berman, Berman 24

Economics. Have you thought about using the 25Executive Court Reporters (301) 565

- 0064 214 regulatory R curves that the

-- the depreciation 1

curves that the regulatory commissions use? We’re 2

talking about, particularly for utilities, 3

transformers and

-- 4

MR. BROOKMAN: R obert, is your microphone 5

on? 6

MR. BERMAN: Yes. Have you thought about 7

using the R curves that utility commissions, 8

regulators, use. 9

MS. COUGHLIN: I’m not familiar with that, 10

sir. 11

MR. BERMAN: This is the depreciation, 12

standard depreciation curves for different types of 13

equipment. 14

MS. COUGHLIN: This is just the lifetime. 15

This is not a depreciation. So this is just failure 16

rates. 17

MR. BERMAN: That’s what those curves are 18

based on. 19

MR. BROOKMAN: Let’s hear Charlie Stephens 20

here. 21

MR. STEPHE NS: Yeah, I would argue against 22

using depreciation curves for anything. I’ve never 23

found one in recent times that has anything to do 24

with physical reality, and I think you can 25Executive Court Reporters (301) 565

- 0064 215 depreciate 90 percent of a commercial investment in 1

a building in eight years, so that doesn’t mean the 2

building dies in ten or 12. So I think you probably 3

need to

-- I like the 32 years, and I read the

-- I 4

actually read the ORNL report, or most of it, at one 5

point, and I think they came up with a reasonable 6

number. So I don’t th ink it would make much of a 7

difference if it moved to 30 or moved to 34, 8

actually. 9

MR. BROOKMAN: Robert, you want to chime 10

in here? 11

MR. van BUSKIRK: Yes, Robert van Buskirk, 12

DOE. If

-- I think if DOE was to consider using 13

depreciation curves, it wou ld need, in addition to 14

that comment, the method for converting depreciation 15

curves into a physical lifetime curve. Because the 16

model uses a physical lifetime curve. Yes, Robert 17

van Buskirk, DOE. If

-- I think if DOE was to 18

consider using depreciation c urves, it would need, 19

in addition to that comment, the method for 20

converting depreciation curves into a physical 21

lifetime curve. Because the model uses a physical 22

lifetime curve. 23

MR. BROOKMAN: Thank you. So it’s 24

useful that you provided the OR&L cita tion here, so 25Executive Court Reporters (301) 565

- 0064 216 anybody can take a peek at that that wanted to. 1

MS. COUGHLIN: So this just shows the 2

graph of the distribution that’s used, so the blue 3

bars are essentially the failure rates

-- it’s the 4

reliability, and then the pink bars give you the 5

age . So along the horizontal axis we have the 6

transformer age, and the pink bars are the fraction 7

of transformers that are retired at a particular 8

age. So although the mean in this distribution is 9

32 years, you can see that it’s quite broad. So 10

there’s qu ite a bit of variability in the 11

transformer lifetimes that are used in the LCC 12

calculation. 13

So this is an issue where we realize that 14

more information would be very helpful since the 15

transformer lifetime does have a big impact on the 16

economics. So any i nformation, any quantitative 17

information on transformer lifetimes, or early 18

replacement, or anything else that might affect this 19

distribution would be appreciated. 20

MR. BROOKMAN: And then you see a comment 21

box, issue 25. Any additional things to be said 22

about replacement and maintenance practices, other 23

sources of data? At this time? John. 24

MR. PHOUMINH: Well, I was going to 25Executive Court Reporters (301) 565

- 0064 217 comment that, you know, with reference to the 1

maintenance practice and the cost associated with 2

that, it’s so hard to quantify because not all the 3

units are the same, even the same unit you install 4

today, five months or six years later, five years 5

later, ten years later, one might fail and one would 6

not. I cannot see that you will get that data 7

easily. This is from the utility p erspective. And 8

with the lifetime of the transformer for 32 years, I 9

think that’s a little long. I would say between 25 10

to 30 would be maybe is doable. That’s my comment. 11

MR. BROOKMAN: Okay. I’m going to suggest 12

we take a break right now. It’s 2:50 . Let’s see if 13

we can do this in ten minutes. We’re running a 14

little bit behind. Last

-- the last slides that 15

will be presented today, tend to go more quickly 16

than the ones that preceded it. But we still need 17

to get back here and make it through the re st of 18

this. So we’ll resume, try and resume at three 19

o’clock. 20

(Whereupon, the meeting was recessed for a 21

10 minute period.) 22

MR. BROOKMAN: Here we go. Okay. 23

MS. COUGHLIN: So we finished the 24

discussion of the inputs to the LCC, and I’m going 25Executive Court Reporters (301) 565

- 0064 218 to present very briefly some results for three 1

representative design lines. So we have design line 2

one, which is a liquid immersed, single phase. This 3

unit is 50 kVA, pad mounted. Design line seven is 4

the dry type, three phase, low voltage. The unit 5

bein g analyzed here is 75 kVA. And then design line 6

12 is the three phase dry type medium voltage. In 7

this case, the representative unit is 1500 kVA. So 8

I’m just going to show a couple of charts of results 9

for each one of these design lines. 10

So the first set of charts, this is the 11

total installed cost as a function of the test 12

procedure efficiency level. So this is the purchase 13

price plus all the other costs, the markups and 14

installation costs. And so you can see the cost 15

increases by approximately a fac tor of two over the 16

range of efficiencies considered, a little bit less 17

for DL12. 18

Now there’s going to be three plots that 19

summarize the LCC savings. So what we’re attempting 20

to do here is show you the distribution of LCC 21

savings results on a single c hart. So what we do to 22

get LCC savings, we have our base case set of 23

designs and our 10,000 transformers, and we get 24

aggregate LCCs

-- we get an LCC for each one of 25Executive Court Reporters (301) 565

- 0064 219 those transformers in the base case. And then we go 1

through each standard level, and a pa rticular 2

transformer may find that as you go up to a 3

different standard level the design has to change 4

because a design has been eliminated at that 5

standard level that was used in the base case. So 6

in that case, for that transformer, you’re going to 7

get a change in the LCC. They will have LCC 8

savings. 9

Any transformer that picks the same design 10

for all standard levels will not have any savings 11

associated with it. 12

So we have a distribution of LCC savings 13

for each of the CSLs. The two farthest apart p oints 14

on these plots are the five percent and 95 15

percentiles for the LCC savings, which is on the 16

vertical axis. And then the rectangle is the 25 to 17

75 percentile of the LCC savings. And then there’s 18

a little

-- it printed out, but for some reason it’s 19

n ot showing up on this chart, but you’ll see it on 20

your printout, there’s a little bar in the center 21

that represents the median, and then there’s a box 22

that represents the average LCC savings. 23

So, for example, for design line one, for 24

CSLs two, three, and four, there’s essentially 25Executive Court Reporters (301) 565

- 0064 220 positive LCC savings for 95 percent of the designs, 1

and then there’s

-- for CSL one there’s negative LCC 2

savings, which means an overall cost associated with 3

the standard for roughly 25 percent, and then over 4

on CSL five and six, you’re also seeing a tail of 5

negative LCC savings. 6

And then design line seven, you see a 7

similar pattern. So essentially there’s a point at 8

which LCC savings start to become negative as you go 9

up in standard level, which is generally what we 10

would expe ct. And this is design line 12. 11

So there’s a

-- I believe it’s an appendix 12

to the TSD has

-- 8C

-- Appendix 8C has charts like 13

this and tables for all the design lines, giving the 14

distribution of LCC savings under these candidate 15

standard levels. 16

MR. BROOKMAN: Andrew deLaski. 17

MR. deLASKI: I’m wondering

-- this is, as 18

you said, what you would typically expect in this 19

sort of distribution. I’m a little curious about 20

the CSL one and design line one and design line 12 21

where you show that the whisker has a negative LCC 22

at CSL one. It’s a little unusual to see that. 23

MS. COUGHLIN: What that means is 24

essentially the

-- people pick designs that on the 25Executive Court Reporters (301) 565

- 0064 221 total ownership cost basis are actually costing them 1

money because the losses are very high. So if yo u 2

pick the cheapest transformer that has the lowest 3

purchase price, you may still end up losing money 4

in an LCC sense because you have to pay for the

-- 5

you have to pay the operating costs. And since we 6

have all this variability in our estimate of the 7

op erating costs, you’re going to have cases where 8

you may have a highly loaded transformer with a long 9

lifetime, where the operating costs in the 10

simulation will deviate from a simple approximation. 11

I think

-- is that

-- yes, that’s it, so 12

that’s the last LCC slide. 13

MR. SAMPAT: May I ask just one quick 14

question. Is it fair to say the one at the lower 15

CLS is cost of losses, and the one at the other 16

extreme is initial cost of the product is what’s 17

driving LCC lower? Or that’s too generalization? 18

MS. CO UGHLIN: Almost, yes. Yeah, I mean 19

there is this factor again, because the load loss is 20

dependent on the loading, it’s a little bit hard to 21

separate them, but certainly, in a statistical 22

sense, the loads are the same, no matter how much 23

you pay for the t ransformer. So the different 24

variation here is due to the valuation of the 25Executive Court Reporters (301) 565

- 0064 222 losses. 1

MR. BROOKMAN: Steve Rosenstock. 2

MR. ROSENSTOCK: Steve Rosenstock. 3

MR. BROOKMAN: Turn on your mike, Steve. 4

MR. ROSENSTOCK: Sorry, Steve Rosenstock, 5

EEI. I guess it was the title, you’re showing a 6

level seven for design line one in Chapter 8. I 7

guess that was a typo. There is no CSL seven. You 8

just repeated it, sorry. Same thing, sorry about 9

that, thank you. 10

MR. BROOKMAN: Joanna. 11

MS. MAUER: Joanna Mauer. I just had a 12

couple of clarifying questions regarding the payback 13

period calculations. The mean payback period, which 14

I believe is what’s summarized in the executive 15

summary, is that essentially an average of the 16

10,000 payback periods that are calculat ed in the 17

Monte Carlo analysis? 18

MS. COUGHLIN: Yes. 19

MS. MAUER: And then in the LCC in payback 20

period chapter, I think both the mean and the 21

payback of an average transformer are reported and 22

my understanding is that the payback of the average 23

transfor mer is the average incremental cost divided 24

by the average operating, or first year operating 25Executive Court Reporters (301) 565

- 0064 223 cost savings? 1

MS. COUGHLIN: I think it’s three years. 2

It’s three years. I think there’s a

-- what we call 3

a simple payback. So it’s the purchase price with, 4

I think it’s the first three years of the operating 5

cost savings. And it’s different from the LCC which 6

does the entire lifetime. 7

MS. MAUER: Thank you. And I think 8

there’s a number of cases, both different design 9

lines and different CSL levels where there’s a 10

significant difference between the mean payback 11

period and the payback period of the average 12

transformer, with the mean payback period often 13

beings significantly higher. Could you explain a 14

little bit about what’s driving that difference? 15

MS. COUGHLIN: Well, yes, in a general 16

sense, because you have a lot of variability, if you 17

do the calculation individually for each 18

transformer, and then you take the average of all 19

those calculations, you’ll get one answer. But 20

because you’re doing a ratio, if you take the 21

average of the numerator, and then the average of 22

the denominator, and take that ratio, you can get a 23

slightly different answer. And it really just 24

depends on how much variability there is in the 25Executive Court Reporters (301) 565

- 0064 224 individual

-- in each individual case. 1

MS. MAUER: And is it fair to say that it 2

might be kind of a small number of transformers 3

either that are

-- have low loading or something 4

that could essentially skew the mean? 5

MS. COUGHLIN: It can be. Yeah, it can 6

have like sort of outliers that will sort of skew 7

the

-- some of the averages, yeah. It’s difficult 8

to say in a very general way. 9

MS. MAUER: And just

-- sorry, one more 10

question. One more question, I think. In other 11

rulemakings, I think DOE often reports both a mean 12

and a median, and th ey seem to often refer more to 13

the median in summary tables and such. I assume, to 14

kind of avoid this situation

-- 15

MS. COUGHLIN: Yeah, the median is sort of 16

the dividing point, so the median is the number such 17

that half of the transformers in the sampl e have a 18

lower LCC, and half of them would have a higher LCC. 19

So, yes, it’s just another piece of information. 20

And the median is in those charts, and it’s usually 21

very close to the average, but again, if you have a 22

very strangely shaped distribution, you can have a 23

difference between the median and the average. 24

MS. MAUER: And was there a particular 25Executive Court Reporters (301) 565

- 0064 225 reason for reporting the mean payback periods in the 1

executive summary, or was that just

-- 2

MS. COUGHLIN: I think it’s just 3

customary. 4

MS. MAUER: Tha nk you. 5

MR. BROOKMAN: Robert. 6

MR. BERMAN: Robert Berman, Berman 7

Economics. Joanna makes a very good point. The 8

mean of the payback period does not equal to the 9

mean of the mean transformer size. What you’re 10

looking for under the Monte Carlo, I gue ss, is the 11

mythical typical representative transformer, based 12

on those distributions, what transformer is most 13

likely to be selected? Once you’ve selected that 14

transformer, calculate the payback period for that 15

transformer, don’t calculate the average of the 16

payback periods. 17

MS. COUGHLIN: Right, that’s what we do. 18

I mean, this is really

-- these are sort of ways of 19

presenting summary results, right. But we’re really 20

working with this full distribution of calculations. 21

MR. BERMAN: If you’re looking at the 22

output of the Monte Carlo model under payback 23

period, it’s giving you the mean of the paybacks. 24

MS. COUGHLIN: Right, which would be the 25Executive Court Reporters (301) 565

- 0064 226 mean of the distribution of paybacks. 1

MR. BERMAN: That’s what it’s giving you, 2

that’s correct. That’s a di fferent number than if 3

you calculate the payback period associated with the 4

mean transformer. And the number that you want for 5

evaluation purposes is the payback period associated 6

with that particular transformer, with that average 7

or representative tran sformer that you’ve selected, 8

not the average of the payback periods of all the 9

transformers you’ve looked at. 10

MR. BROOKMAN: Jerry. Go ahead. 11

MR. ALLEN: (Mic not on) If you add up 12

all the payback periods together, you’ll always get 13

a number that’s larger than what you’ll get if you 14

take the transformer ... figure out what the payback 15

of each individual one of those, add them all up, 16

and you divide by the denominator, so it skews the 17

payback period is longer than it really is. You 18

can’t average the pa yback period

-- 19

MS. COUGHLIN: Right, well there’s no

-- 20

okay, again. The LCC models the population of 21

transformers. So the analysis is trying to actually 22

model a population. So the statistical description 23

of that is through the median and the mean of the 24

population, because in reality you have a population 25Executive Court Reporters (301) 565

- 0064 227 of transformers, and that’s what this analysis is 1

trying to represent. 2

MR. BROOKMAN: Jerry, go ahead. 3

MR. ALLEN: You have to take each 4

individual year, figure each individual payback, 5

figure o ut ... add them all up, divide by the number 6

of transformers and get the payback that way. You 7

can’t add the payback years together. If you do 8

that, it’s skewing and you’ll always get a bigger 9

number. 10

MR. BROOKMAN: Okay. Steve Rosenstock. 11

MR. ROSENST OCK: Steve Rosenstock, EEI 12

again. Looking at Appendix 8C, and for design line 13

one, which is one one of the graphs, it talks about 14

-- there’s a chart in here about the payback period, 15

and it says, “transformers having an undefined 16

payback”

-- I’m assuming those are the transformers 17

that have higher life cycle cost, there is no 18

payback

-- is that a correct assumption? 19

MS. COUGHLIN: That’s right. 20

MR. ROSENSTOCK: Okay. So that’s

-- okay, 21

higher LCC on that one. Okay. Just wanted to 22

double check that just in case I wasn’t missing 23

anything. Now in terms

-- so obviously that’s not 24

shown in these charts here, just as undefined can’t 25Executive Court Reporters (301) 565

- 0064 228 be shown in there. Because under CSL one there’s 1

seven percent having undefined payback or higher LCC 2

costs under your sim ulations. Okay. Thank you. 3

MR. BROOKMAN: Charlie? Okay. We’re 4

moving on. Andrew first. 5

MR. deLASKI: I think the reason why this 6

last issue is important, the Department reports both 7

numbers, and a casual reader goes, okay, mean, 8

average means the same thing, but that’s not clear 9

in the materials presented thus far. So I 10

understand that you’re providing both, they’re both 11

provide some information. One’s in the executive 12

summary, which gives a lot of prominence to it. So 13

it’s an issue of presenta tion here and I think I’m 14

getting arguments about which numbers are proper 15

numbers, basically for decision making, and they 16

actually

-- in some cases they diverge quite a bit. 17

MS. COUGHLIN: Okay. So we have just two 18

slides left, and this is

-- these ar e to discuss 19

these emerging technologies that were described in 20

the engineering analysis. So this is extremely 21

preliminary, and the emerging technologies have not 22

been included in the LCC, per se. So what we’re 23

trying to do here is just get a very rough picture 24

of what the economics of these designs might look 25Executive Court Reporters (301) 565

- 0064 229 like. And again, within the specific context of how 1

we have set up the LCC models. 2

And one of the things that we are not able 3

to do at this point is include these designs as one 4

of the choices for the existing

-- within the 5

existing set of designs. So, for the symmetric core 6

technologies, to get a picture of the economics, 7

what we did is we just created an LCC in which all 8

of the designs use symmetric core, and we just 9

wanted to see if they wou ld be affordable using the 10

estimates of total life cycle cost. 11

So the procedure was exactly the same as 12

what I’ve outlines for the regular designs, except 13

all of these now have symmetric cores. And so 14

essentially what you see is that you can run these 15

d esigns through our LCC and the additional purchase 16

price appears to be compensated by operating cost 17

savings. So the LCC results are comparable to what 18

they were for the rest of the design lines. 19

And then the second issue is for the core 20

deactivation te chnology. So this was an even cruder 21

calculation than the

-- we didn’t actually do an LCC 22

here, so what we did

-- so let me first say, again, 23

this is not meant to be a statement about core 24

deactivation in general. This is question of 25Executive Court Reporters (301) 565

- 0064 230 whether we can bring core deactivation technologies 1

into the LCC the way we have currently structured 2

it. 3

So, to remind you, the idea behind core 4

deactivation technology is, instead of installing a 5

unit

-- a transformer that has capacity K, I install 6

three transformers with capacity K divided by three, 7

and I have a control system that will deenergize

-- 8

turn two of them on and off, depending on the load 9

level. So if you do this, you could end up with a 10

decrease in the no

- load losses, because when the 11

loads are very low, I j ust shut off the extra two 12

transformers. 13

The problem that arises when you try to 14

take this design and fit it into our LCC picture is 15

how am I going to decide when someone would not buy 16

a transformer of capacity K and buy three that are 17

capacity K over three? I mean, what is the decision 18

process for doing that? So as a first draft to 19

understanding the economics, we just said, well 20

let’s just assume we have a load loss and no

- load 21

loss parameter for the large capacity transformer. 22

Let’s just assume we replace it with three that have 23

the same engineering parameters in the small 24

capacity. So if we do that replacement, it’s a very 25Executive Court Reporters (301) 565

- 0064 231 simple calculation to estimate the losses that would 1

occur under that configuration. 2

Now, of course, if you

-- this may be 3

c lear to some of you who have looked at transformer 4

loading a lot. Because of this scaling rule, when 5

you decrease the size of a transformer, you don’t 6

decrease the losses by as much as you decrease the 7

capacity. So in general, when you take

-- just 8

repla ce a larger transformer with three smaller 9

ones, and don’t change any of the design parameters, 10

and you use the same distribution of loads that we 11

were using for the low voltage, which is the 35 12

percent RMS, then you end up not really actually 13

getting any energy savings. And the cost of three 14

small transformers is slightly larger than one large 15

transformer. So in that replacement scenario, it’s 16

not cost effective. 17

And the message here, I think, for further 18

analysis of this technology is that in order to 19

understand when the control technology is going to 20

be useful, you really need to have a better 21

understanding of the load distribution. And that’s 22

going to have an enormous impact on your evaluation 23

of the losses. And with the current setup in the 24

LCC an d the engineering, we really only consider the 25Executive Court Reporters (301) 565

- 0064 232 load loss and no

- load loss rates, and we don’t 1

actually have a way of associating a load 2

distribution with a customer selection process. 3

So that is the problem that we need to 4

address to understand how to in corporate this 5

technology into our consideration of improved 6

efficiency. And any comments on that would be 7

appreciated. 8

MR. BROOKMAN: Phil. 9

MR. HOPKINSON: Yeah, I’ve got one. I 10

think that there are another set of costs, switches 11

that would turn the se transformers on and off is 12

certainly a cost. There is a consideration too, for 13

regulation in Flicker (ph) that we didn’t talk 14

about, but it would be a serious, serious deal. If 15

you took a 75 k VA intended application, and only a 16

25 k VA on, and on came a motor that was significant, 17

then it’s lights out time. So we’ve got that, and 18

then we’ve got end rush currents associated with 19

turning these transformers on and off. So this is 20

not a cake walk, and should not be entertained too 21

lightly, and I didn’t fi nd any benefit in it anyway, 22

when I did the analysis. 23

MR. BROOKMAN: Okay. Thank you. So we 24

want to receive final comment on core deactivation. 25Executive Court Reporters (301) 565

- 0064 233 Peter. 1

MR. AMOS: A real quick one, to Phil’s 2

comment. This core deactivation technology was 3

really mean t to address, say, a multi

- occupancy 4

residential building where you have lots of small 5

incremental loads, but you don’t just have a 1000 6

horsepower motor or something kicking in, like you 7

might find in industrial premises. So when you look 8

at lots of litt le loads turning on and off, the 9

flicker issue goes away. 10

We were also thinking that the best 11

manifestation of this is with the 120 degree 12

symmetric core transformers, which have much lower 13

end rush currents than stacked core transformers. 14

MR. BROOKM AN: Thank you. So I’m eager 15

for us to keep going here. 16

MR. ROSENSTOCK: Just a quick question of 17

clarification on that. On the last slide, the 18

symmetric core slide, Katie, did you say

-- where 19

does amorphous material become the core material? 20

At whic h CSL? 21

MS. COUGHLIN: All of them. 22

MR. ROSENSTOCK: Those are all amorphous? 23

MS. COUGHLIN: All of them are amorphous, 24

yes. Is that right? Which one

-- Okay, two, three 25Executive Court Reporters (301) 565

- 0064 234 and above, sorry. 1

MR. ROSENSTOCK: Excuse me? 2

MS. COUGHLIN: CSL two or thr ee. 3

MR. ROSENSTOCK: Is where amorphous 4

material comes in? 5

MS. COUGHLIN: Yes. 6

(Discussion off microphones) 7

MR. BROOKMAN: Okay. Next we’re going to hear from 8

Greg Rosenquist. 9

**Shipments and National Impacts Analysis** 10

MR. ROSENQUIST: Okay. I’m bac k here. 11

I’m Greg Rosenquist from Lawrence Berkley National 12

Laboratory. I’m going to walk your through the 13

National Impacts Analysis. And again, to reorient 14

you all to these analyses and where they fit in the 15

flow diagram, they are at the end of the anal ysis. 16

Again, for the National Impacts Analysis, it takes 17

the outputs from the LCC and payback period 18

analysis, as well as the shipments forecast for the 19

shipments analysis to determine the national 20

impacts. 21

Okay. So shipments analysis is actually a 22

key part of the national impact analysis, and its 23

purpose is to basically estimate the impact of 24

standards on base case shipments forecast, that is, 25Executive Court Reporters (301) 565

- 0064 235 shipments without standards, any new standards. 1

The method it uses to do this is to 2

develop a shipments mo del that relies on various 3

inputs, most importantly, historical shipments, and 4

again, it does this only for the products that are 5

under this rulemaking, which are dry type and liquid 6

type of transformers. 7

Again, there’s two purposes, I mean, two 8

main f unctions of this shipments model, one is to 9

calculate shipments annually, over time, for each of 10

the equipment classes that we’re analyzing, and also 11

to keep track of the inventory or stock of 12

equipment, and furthermore, also to keep track of 13

the age of th at stock, because there are inputs that 14

are going to be fed from the LLC analysis that are 15

going to be age

- dependent, and so we need to know 16

that in order to assign those values properly to the 17

age of the stock. 18

The purpose of the National Impacts 19

Analys is is to determine the national energy 20

savings, the national economic impacts to the 21

standards, and for the national energy savings, this 22

is determine in quads or quadrillion BTUs, or 10 to 23

the 15 th BTUs, and it’s determined as source energy 24

savings, that is, taking into account transmission 25Executive Court Reporters (301) 565

- 0064 236 and distribution losses, as well as the power plant 1

efficiency. Again, these energy savings are 2

calculated annually over a forecast period of 30 3

years from the assumed compliance date of 2016, out 4

to 2045. 5

The nati onal economic impacts are 6

calculated in billions of dollars with a term called 7

the net present value, or NPV. Keeps track annually 8

of the operating cost savings and the increased 9

total installed cost over time, and then discounts 10

both of those future fore cast values to a present 11

value using discount rates. 12

This slide goes over all the inputs that 13

are fed into the shipments model. I’ll go over this 14

relatively quickly, so stop me if you have any 15

questions. Again, as I said before, historical 16

shipments ar e a key part of the shipments model. 17

Two data sources were used to come up with 18

historical shipments. Shipments from HVOLT for the 19

years 2001 and 2009, and then quantity index data 20

from the US Bureau of Economic Analysis for 1997 to 21

2008. 22

Market sha re data is also important to 23

define what share of transformers are dry type 24

versus liquid type, and also what share of 25Executive Court Reporters (301) 565

- 0064 237 transformers are by kVA or capacity. The market 1

shares by transformer type are forecasted based upon 2

the growth rate in electricity sale s forecasted by 3

the EIA, the Energy Information Administration. And 4

the market share by kVA or capacity was determined 5

with HVOLT data for the years 2001 and 2009. 6

The shipments model keeps track of 7

replacements, which again is a fraction of overall 8

s hipments, by using the same retirement function 9

that was developed for the life cycle cost analysis. 10

And again, since the shipments model keeps track of 11

the stock, or inventory of transformers. This 12

retirement function tells us at what age these 13

transfor mers fail and they need to be replaced. 14

Base case shipments are forecasted, again, 15

as I mentioned earlier, when electricity growth 16

sales from the EIA. For liquid immersed 17

transformers it’s done with the electricity sales to 18

all sectors, while for dry ty pe transformers, it’s 19

done with electricity sales to the commercial and 20

industrial sectors. 21

New capacity shipments are those shipments 22

for just that, new installed capacity due to 23

electrical system expanding. And these are deduced 24

by taking the differen ce between the forecasted 25Executive Court Reporters (301) 565

- 0064 238 shipments in the base case, and the replacement 1

shipments. 2

And then finally, the standard case 3

forecasted shipments are based upon the exact same 4

inputs that were used for the base case shipments, 5

except one important differenc e, an elasticity is 6

developed

-- a purchase price elasticity is 7

developed to figure out how these standards impact 8

the base case shipments forecast. 9

So now I’m going to focus a little bit 10

more on what was done to estimate market shares. As 11

I briefly wen t over before, the equipment class 12

market shares are based upon data by HVOLT, at least 13

for 2009, and then they were forecast out to the 14

future based upon these growth rates in electricity 15

sales by the EIA. And the market share data was 16

based upon, again, data by HVOLT for the year 2009 17

by capacity, by kVA rating, and the values in 2009 18

were held constant over the forecast period from 19

2016 to 2045. 20

So this comes to the first issue in the 21

National Impacts Analysis, which is basically 22

looking for comment o n the market share data. I 23

mean, there’s very little market share data that was 24

used here, but we just had to rely on something to 25Executive Court Reporters (301) 565

- 0064 239 try to get again, the fraction that our dry type and 1

liquid immersion and also what fraction our 2

transformers are by kVA rat ing. 3

MR. BROOKMAN: Yes, Jerry. 4

MR. ALLEN: It would be

-- 5

MR. BROOKMAN: Jerry, turn on your 6

microphone, please. Jerry, turn on your microphone. 7

MR. ALLEN: I did it again, sorry. ... 8

there are a lot more low voltage and medium voltage 9

dry types than indicated in here, and my gut feeling 10

is that the numbers are more like this, because I 11

just don’t see that many dry types compared to 12

liquid filled. But I’m hoping somebody out there’s 13

got better data on that. 14

And the other thing I wanted to sa y on 15

those big ones, like 667 kVA single phase and 883, 16

833, those are strange units, I agree, but I 17

actually found one order for eight 667s from one 18

company. So I’m not real sure whether we’re catching 19

everything. 20

MR. ROSENQUIST: Are you looking at the 21

next slide? Is that what you’re

-- 22

MR. ALLEN: I’m looking at

-- I’m talking 23

about when you distribute the MVA per year, when you 24

-- one of them’s distribution over kVA which was the 25Executive Court Reporters (301) 565

- 0064 240 second part of what I said. The first part of what 1

I said is the MVA and low voltage dry type per year, 2

and the MVA and medium voltage dry type per year 3

seem to be low according to a couple of sources that 4

I have that I can’t divulge. I just hope somebody 5

can find something out. 6

MR. BROOKMAN: But Jerry, you’re not 7

refe rring to a document we have in front of us yet? 8

The numbers

-- the numbers you’re talking about, we 9

don’t have

-- that’s your personal experience? 10

MR. ALLEN: Yeah. 11

MR. BROOKMAN: Yeah, okay. Just wanted 12

to confirm. Good, that’s useful, and for you to 13

find a way to disclose them and do a non

- disclosure 14

agreement or whatever so that that data can make it 15

into the right hands and be shielded at the same 16

time. 17

MR. ALLEN: I’ll try with one guy anyway. 18

MR. BROOKMAN: Okay. 19

MR. HOPKINSON: Could I just make a 20

comment on that? 21

MR. BROOKMAN: Phil, go ahead. 22

MR. HOPKINSON: Phil Hopkinson, HVOLT. In 23

the first place what I would tell you is I didn’t 24

just make up these numbers by myself, that there are 25Executive Court Reporters (301) 565

- 0064 241 a lot of spies that I have all over the pl ace, and I 1

pulled them all in and most of the manufacturers 2

have people that are good spy sources for me and so 3

have done a pretty good job of keeping me 4

calibrated, and I certainly called those numbers in. 5

Now, the other dimension, I’d say, is 6

compared to 2002 kind of data, so that recognize 7

that 2009 was quite a blip downward, so that when 8

some of us calibrated what was going on back in the 9

2002, 2003 timeframe, and remember I did this market 10

survey back at that time too, and this is very much 11

like chur ch. If you can demonstrate you can do a 12

job once, it’s yours for life. So the volume did 13

decrease significantly in 2009. Now is that 14

something that is going to be with us for a long 15

period of time is

-- you know, Jerry, I can’t really 16

tell you. We can’ t even forecast a tsunami very 17

well. 18

But I would say that whatever we have in 19

2009, certainly I think is pretty close to what 2009 20

was. But is it going to be representative of the 21

next 30 years? That’s an awfully interesting 22

question, isn’t it. And I think that you’re going 23

to have to have a significant resumption of housing 24

for liquid filled transformers, and you’re going to 25Executive Court Reporters (301) 565

- 0064 242 have actually a significant resumption of 1

manufacturing in the United States, right, in order 2

to get the industrial and commerci al transformers 3

going strong again. So it’s a snapshot in time. 4

MR. BROOKMAN: Okay. Thank you. Steve. 5

MR. ROSENSTOCK: Steve Rosenstock, EEI. 6

Looking at this slide, you know, again, with all the 7

other things happening out there in terms of either 8

housing markets or just especially end use 9

efficiency, this

-- the projection again, and it is 10

obviously just a projection, of increasing

-- 11

obviously there’s hopefully an increase from 2009

-- 12

but if you look at the trend, especially since I’ll 13

say 1980, it’s been flat or declining. If you do 14

like a best fit curve, or a best

-- it’s not showing 15

an increase. And obviously you’re going with 2009 16

and you’re adjusting from a horrible year, 17

obviously. But to show the values going well above 18

100,000, I don’t know. Maybe, but it just

-- just 19

look at those

-- again, a 30 year compared to 20

obviously six years is a difference, but I don’t 21

know. I have my doubts. Thank you. 22

MR. BROOKMAN: Okay. Thank you. 23

MR. ROSENQUIST: I think everyone’s now 24

referring to the next slide, which shows the actual 25Executive Court Reporters (301) 565

- 0064 243 forecast. And of course, the shipments model is 100 1

percent accurate with the back cast, right, but it’s 2

-- but you both have been speaking to, which is the 3

forecast, and again, it’s just based upon the 4

electricity sales growth from the EIA, and of course 5

it’s not going to capture all those peaks and 6

valleys that are seen in the historical data. So if 7

people feel it’s more representative to just do a 8

line fit to the data, rather than to tie it to that 9

electricity sa les forecast, then DOE would certainly 10

like to hear that. 11

MR. BROOKMAN: Gary. 12

MR. FERNSTROM: Gary Fernstrom. Well, in 13

looking at the forecast, did you include not only 14

unit shift to account for growth, but ones to 15

account for failures of the large g rowth in 16

transformers that occurred in the 60s and 70s, that 17

would probably be reaching the end of their useful 18

life? 19

MR. ROSENQUIST: Well, to the extent that 20

they’re failing in these out years, yes. But I have 21

to remind you that again, the growth rate in the 22

overall base case forecast is tied to that growth 23

rate in the electricity sales. And so we are 24

calculating replacements as a function of

-- by 25Executive Court Reporters (301) 565

- 0064 244 using this retirement function, right, but then that 1

difference between base case shipments forecast, 2

wh ich is the overall shipments, and the replacements 3

is just made up with new capacity shipments. So

-- 4

MR. FERNSTROM: So replacements are 5

included in the base? 6

MR. ROSENQUIST: Replacements are included 7

in the base case, right. 8

MR. FERNSTROM: Thank you. 9

MR. ROSENQUIST: And they’re always less 10

than the overall growth. 11

MR. BROOKMAN: Steve Rosenstock. 12

MR. ROSENSTOCK: Steve Rosenstock, EEI. 13

Again, just for historical reasons, growth rate in 14

the 70s, early 80s was about three percent, then it 15

was down to two percent

-- and again, I’m talking 16

about electric sales. And then it was one percent

- 17

- one and a half percent in the 90s, and 2000s. 18

There were a few years where the growth rate was 19

negative, and EEI’s projecting about a point four 20

percen t, compared to years when they were probably 21

projecting two or three or four percent. So again, 22

that also, in terms of these increasing MVAs, again, 23

you know, EIA’s been showing lower and lower growth 24

rates which should have an impact on the shipment 25Executive Court Reporters (301) 565

- 0064 245 valu e, puts you on the slope. 1

MR. BROOKMAN: Gary, yes. 2

MR. FERNSTROM: Gary Fernstrom. Maybe 3

just with more thought about that, I think energy 4

efficiency has had an effect, at least out in 5

California, so maybe electric sales haven’t grown 6

that much, but the number of customers, and I think 7

consequently the number of transformers has 8

continued to grow. So it’s not unreasonable to 9

think that we don’t have dramatically increased 10

sales, but there are increases in the transmission 11

and distribution system, inc luding transformers. 12

MR. BROOKMAN: Okay. 13

MR. ROSENSTOCK: Steve Rosenstock EEI, as 14

a follow up. The current rate of customers has also 15

gone down in the last several years. Look at the 16

EIA data. 17

MR. BROOKMAN: Okay. Thanks. 18

MR. FERNSTROM: Wel l, the growth rate may 19

have gone down, but there’s still growth. So, you 20

know, there hasn’t been a decline of residences and 21

buildings, at least that I know of. 22

MR. ROSENSTOCK: No, but there’s a high

-- 23

Steve Rosenstock, EEI

-- there’s higher vacancy 24

r ates in residential buildings, and

-- which 25Executive Court Reporters (301) 565

- 0064 246 obviously destroys a load, and then also industrial, 1

there has been a reduction in the number of 2

industrial customers. Look at the 2009 data. 3

MR. FERNSTROM: Yeah, but the transformer 4

that is there doesn’t com e out. We don’t follow 5

around to every building that’s vacant and take the 6

transformer out. It’s still there incurring losses. 7

And not producing much revenue to boot. 8

MR. BROOKMAN: Charlie Stephens. 9

MR. STEPHENS: I would have to agree with 10

Gary. Our own forecasts, recent forecasts in the 11

Northwest Six Power Plan, basically suggests almost 12

no growth in electricity sales, electricity 13

generation and consumption. But we do show over a 14

million people coming to our region during that same 15

period. 16

M R. BROOKMAN: So, Greg, keep going. 17

MR. ROSENQUIST: Okay, so I just went over 18

this slide with the base case shipments forecast. 19

This slide’s about estimating what the standards 20

case shipments forecast are. And again, as I said 21

earlier, all the same in puts that were used to 22

develop the base case shipments forecast are used to 23

develop the standards case with this one important 24

exception. We developed a purchase price elasticity 25Executive Court Reporters (301) 565

- 0064 247 to take into account the increased purchase price 1

and the operating cost sav ing due to standards and 2

their impact on the base case shipments forecast. 3

So for immersed liquid transformers, this was done 4

by predicting the variability in the observed 5

capacity, the peak ratio, and developing a function 6

for it as a function of the var iability of 7

transformer price and efficiency. 8

What we did to do this is that we got this 9

historical data from FERC Form 1, which provides, by 10

utility, the installed capacity, as well as the 11

maximum load or peak capacity of each utility. So 12

again, for al l these utilities we have these 13

capacity to peak ratios, and we can come up with a 14

nationally representative value by doing a weighted 15

average calculation based upon the installed 16

capacity of each utility. 17

Again, we plot that, or look at that 18

against the changes in price and efficiency for 19

liquid immersed transformers and derive this 20

elasticity of

- 0.04, meaning that in general, a ten 21

percent increase in price results in a point four 22

percent drop in shipments. So this elasticity is 23

fairly inelastic, and what that implies is that 24

utility customers are not all that sensitive to 25Executive Court Reporters (301) 565

- 0064 248 purchase price, and that they’re more concerned 1

about having an excess capacity for probably

-- 2

maybe continued electricity growth. 3

I’ll stop there and see if anyone has any 4

quest ions. 5

MR. BROOKMAN: Steve. 6

MR. ROSENSTOCK: Steve Rosenstock, EEI. 7

Is there

-- I’m just kind of curious, is there more 8

recent FERC data that could be used? 9

MR. ROSENQUIST: For whatever reason, they 10

stopped publishing this data in 2001. 11

MR. ROSEN STOCK: Okay. And the reason I 12

ask is especially for like commodity prices are 13

three to four times higher than they were in the 14

1990s. 15

MR. BROOKMAN: Okay. Thank you. 16

MR. ROSENQUIST: For dry type transformers 17

there were no historical prices to use, so we had to 18

use a proxy piece of equipment to derive a purchase 19

price elasticity, and DOE chose to use commercial 20

interior air conditioners, again, because it’s a 21

commercial piece of equipment and dry type 22

transformers are installed in commercial building s 23

as well as industrial installations. The elasticity 24

from that analysis on commercial interior air 25Executive Court Reporters (301) 565

- 0064 249 conditioners from 2005 yielded a very inelastic 1

price elasticity of

- 0.02, again representing the 2

fact that if you had a ten percent in purchase 3

price, you ’d have only a point two percent drop in 4

shipments. 5

Which is seen by these next two charts, 6

showing forecast for the base case in each of these 7

candidate standard levels for liquid immersed and 8

dry type transformers. You see because of the very 9

inelasti c elasticities, there’s a very, very small 10

drop even at the max tech levels for each of the 11

transformer types. 12

MR. BROOKMAN: Steve. 13

MR. ROSENSTOCK: Steve Rosenstock, EEI. 14

There was a discussion of refurbishing rates and 15

there are utilities that refu rbish transformers, and 16

again, looking at the executive summary for some of 17

these CSLs where, for example, design line one, CSL 18

one, incremental cost selling price estimated at 19

$234 versus CSL six of $2109. I think there might 20

be a bigger impact than what you’re showing here. I 21

can’t honestly

-- I can model it, but I’m going to 22

ask my members their thoughts on the impact on 23

shipments, especially at the higher CSL levels. 24

Thank you. 25Executive Court Reporters (301) 565

- 0064 250 MR. ROSENQUIST: Okay. This next slide 1

talks about the affected stock, that is the 2

percentage of the stock that’s actually impacted by 3

a new standard. The way we do this, again, 4

shipments model that tracks the inventory or stock 5

of transformers by vintage. And again, that allows 6

us to figure out how many shipments are comi ng in at 7

what age. And these charts illustrate this concept 8

I’m trying to get across that the affected stock 9

grows over time, due to a standard. 10

For example, in 2018, which is just two 11

years after the assumed compliance date, there’s 12

only a small fracti on of the stock that’s affected, 13

basically the new shipments that have come in in the 14

two years after the compliance date. But when you 15

get to 2035 and 2045, a much greater share of the 16

affected stock

-- there’s a much greater share of 17

the affected stock. And again, this illustrates the 18

fact that the impact of standards are not immediate, 19

right, it grows over time as the transformer stock 20

turns over due to the replacements an the addition 21

of new transformers with the added electrical 22

capacity of the power system. 23

And this next slide goes over all the 24

inputs to the National Impacts Analysis besides the 25Executive Court Reporters (301) 565

- 0064 251 shipments forecasts. And the first three inputs are 1

the total customer cost, repair and maintenance cost 2

annual load and no

- load losses come from the life 3

cycle cost analysis as average values. In addition 4

to those three inputs, there’s also the peak 5

responsibility factor and the RMS loading

-- again, 6

they all come from the LCC analysis as average 7

values. 8

Now, another important aspect to the NIA 9

is that

-- are these customer evaluation rates which 10

Katie spoke about earlier. Again, all of these 11

inputs I just described are dependent upon what 12

percentage of transformer purchasers are evaluating 13

their decision

-- evaluating their decision on how

- 14

- what sort of efficiency transformer they should 15

purchase. So all the inputs from the LCC analysis 16

reflect that customer evaluation rate. So all the 17

inputs coming from the LCC analysis reflect, again, 18

those customer evaluation rates before they go into 19

the NIA. 20

Then next inputs are the marginal energy 21

and demand prices. Again, those average prices are 22

taken from the LCC analysis, and as Katie mentioned 23

in the LCC analysis, we just use the same forecast 24

from the AEO 2010 to forecast how those prices 25Executive Court Reporters (301) 565

- 0064 252 change over t ime. 1

We then have electricity site to source 2

conversion factors, which are used again to convert 3

those site savings to source savings, taking into 4

account distribution and transmission losses and the 5

power plant efficiency. To convert the load losses 6

-- I mean the no

- load losses, average heat rates, or 7

average conversion factors from the AEO are used for 8

the entire power sector. To convert the load losses 9

from site savings to source savings, the average 10

heat rates or conversion factors for gas fired pow er 11

plants are used. 12

Next set of inputs are the discount rates. 13

These come straight from the Office of Management 14

and Budget. They’re seven percent and three 15

percent. Again, these are used to convert future 16

operating costs and future equipment cost t o a 17

present value, and it’s brought to a present value 18

to a present year, which is 2010 for this analysis. 19

I’ll keep on going if there’s no 20

questions. One of the things that was touched upon 21

in the engineering analysis is the fact that the 22

analysis in the engineering in the LCC was done for 23

13 design lines, and for each one of those 13 design 24

lines a representative unit was chosen. But in the 25Executive Court Reporters (301) 565

- 0064 253 NIA we have to take care of all 115 kVA or capacity 1

ratings, so some conversion has to be done to 2

convert those LCC inputs that are for specific 3

representative units and specific design lines into 4

these 115 different kVA ratings. 5

And this is done with this 0.75 scaling 6

rule that was discussed earlier in the engineering 7

analysis. 8

Next are the customer evaluati on rates. 9

This table you saw again earlier in the LCC analysis 10

that was presented by Katie. Again, what’s 11

important to say is that the LCC inputs are 12

dependent upon these customer evaluation rates, 13

reflect those customers that are purchasing

-- 14

making th eir decisions based upon these customer 15

evaluation rates. Again, as pointed out earlier, 16

variability in the As and Bs are used to capture the 17

variability in these evaluation rates. 18

So is there any

-- I’m going to stop here 19

again if there’s any questions about this. If not, 20

I’ll continue to move on to the next issue, which 21

are these customer evaluation rates in the LCC 22

analysis again, they were used to determine what 23

percent of customers are evaluating their economic 24

decision. In the NIA analysis, we as sume that the 25Executive Court Reporters (301) 565

- 0064 254 percentage of the population evaluating is constant 1

over time, as well as the evaluation criteria 2

staying constant over time. 3

So DOE is looking for input as to whether 4

that’s a valid assumption, and if it isn’t how those 5

evaluation rates and evaluation criteria would 6

change. 7

MR. BROOKMAN: So we’ve had actually a 8

fair amount of discussion on this previously, but 9

additional thoughts on both criteria and rates. 10

Steve Rosenstock. 11

MR. ROSENSTOCK: Steve Rosenstock, EEI. I 12

don’t know if y ou’re going to be able to do it, but 13

is there a way to model scenarios based on

-- at 14

different CSLs, because that could have a huge 15

impact in terms of evaluation

-- what percentage of 16

customers are going to evaluate. 17

MR. ROSENQUIST: Yeah, we can do it in the 18

spreadsheet model, it’s just a question of what to 19

base those rates on. 20

MR. ROSENSTOCK: Thank you. 21

MR. BROOKMAN: So let’s do the last. 22

MR. ROSENQUIST: Okay. This slide just 23

shows an example of the sort of output generated for 24

the national economic impacts. And this is showing 25Executive Court Reporters (301) 565

- 0064 255 the non

- discounted impacts for CSL three. First you 1

have the overall chart on the top, and then 2

desegregated into liquid immersed and dry type on 3

the bottom. The blue columns on the top represent 4

the operating cost savings due to the standard 5

level, and it grows over time as transformers 6

saturate into the stock. And the green bars 7

represent the non

- discounted increases in equipment 8

costs. The red line is the net of those two, and 9

you can see in this case that the c rossover point 10

where operating costs equal equipment cost is around 11

ten years after the compliance date. 12

The other thing to note too is that again, 13

our forecast period is from 2016 to 2045, but the 14

model tracks the operating cost savings of all the 15

units installed into the stock before 2045. So that 16

long tail is due to all these units, again, slowly 17

retiring over time. And since the retirement 18

function has such a long tail, I think around 60 19

years, they actually track this out to 2100. 20

And this last slide just shows a summary 21

of the National Impacts Analysis results for each 22

candidate standard level, and for liquid immerse and 23

dry type transformers. I don’t think there’s any 24

need to go over the specific numbers here, but if 25Executive Court Reporters (301) 565

- 0064 256 you do have any questions, I’ll certainly entertain 1

trying to answer them. 2

MR. BROOKMAN: No questions on that? 3

Okay, so let’s move to the final segment. 4

**Preliminary Manufacturer Impact Analysis** 5

MR. HARTLEY: Okay. Again, my name is 6

Matt Hartley with Navigant Consulting. W e’re going 7

to now speak about the preliminary manufacturer 8

impact analysis. You can see here in the flow 9

diagram where it comes into the analyses. It’s a 10

little bit separate during the preliminary analysis. 11

The purpose of the manufacturer impact 12

analys is, or the MIA, is to qualitatively and 13

quantitatively assess the impacts of amended energy 14

conservation standards on manufacturers of 15

distribution transformers. A key output of this 16

analysis is the change in industry net present 17

value, or INPV, resulting from amended standards. 18

DOE normally performs the MIA in three 19

phases, which we’ll explore on the next slide. In 20

the first phase, DOE creates an industry profile 21

that builds on the market and technology assessment. 22

This market profile is then updated through 23

interviews with the manufacturers, and this 24

typically takes place during the preliminary 25Executive Court Reporters (301) 565

- 0064 257 analysis, which is the phase of rulemaking that 1

we’re discussing currently. 2

During this time, DOE identifies the key 3

issues concerning manufacturers, which b rings us 4

into phase two. In phase two, which spans the NOPR 5

and the final rule analyses, DOE builds a straw man 6

industry cash flow model called the government 7

regulatory impact model, or the GRIM, to forecast 8

free cash flows in the industry. It does this for 9

the base case and the standards case, and calculates 10

an industry net present value, which is the main 11

output of the GRIM. 12

Also in phase two, DOE develops an 13

interview guide that it will use to guide its 14

subsequent discussions with manufacturers duri ng MIA 15

interviews, which will take place in phase three. 16

During these interviews, DOE speaks with a variety 17

of different manufacturers to receive feedback on 18

the items listed in the interview guide. And this 19

is what previously, before lunch, Chris had 20

me ntioned we’ll be scheduling soon after this 21

meeting, and taking place over the next few months. 22

As he also mentioned, these interviews are 23

nearly always conducted with a non

- disclosure 24

agreement in place, so that no proprietary 25Executive Court Reporters (301) 565

- 0064 258 information would be share d publicly, but rather 1

aggregated across all the responses. 2

Following the interviews, DOE will refine 3

the GRIM and evaluate other qualitative issues, such 4

as manufacturer capacity, employment impacts, and 5

impacts on competition. 6

But taking a step bac k to what was done 7

for the preliminary analysis, during our preliminary 8

manufacturing impact analysis, DOE identified three 9

main issues for manufacturers. First, we identified 10

a potential issue of core steel availability. 11

Manufacturers indicated that the re’s a limited 12

global supply of higher efficiency steels such as M2 13

and amorphous steel, and that higher standard levels 14

may not be feasible for volume production given the 15

current steel supply. 16

Second, manufacturers expressed concern 17

over equipment conv ersion costs, large capital 18

investments, retooling, and stranded assets. 19

Certain technologies, such as mitering and symmetric 20

cores require specialized equipment which would 21

require a large capital investment for 22

manufacturers. 23

And then lastly, intell ectual property 24

concerns could be an issue for manufacturers, 25Executive Court Reporters (301) 565

- 0064 259 because many symmetric core and core deactivation 1

designs are patented. And if higher standard levels 2

were based on these technologies, it could place 3

certain manufacturers at a disadvantage in the 4

marketplace. 5

MR. BROOKMAN: Dave. 6

MR. ROSENSTOCK: Steve Rosenstock, EEI. 7

MR. BROOKMAN: Steve, Dave’s first. 8

MR. ROSENSTOCK: I’m sorry. 9

MR. BROOKMAN: Sorry, Steve. 10

MR. MILLURE: Dave Millure, Metglas. 11

There are actually two global sup pliers now of 12

amorphous metal, the other one being An Tai in 13

Beijing. They’ve announced aggressive expansion in 14

their plants, at least 40 kilotons, although to our 15

knowledge, they’re not doing any export, all that 16

steel stayed in China. But we have hear d them going 17

to 100, so at some point their exports will probably 18

be coming. 19

MR. BROOKMAN: And all the manufacturing 20

is in China at this time. 21

MR. MILLURE: Of An Tai, yes. 22

MR. BROOKMAN: Steve. 23

MR. ROSENSTOCK: Steve Rosenstock, EEI. 24

If there’s public information available, do these 25Executive Court Reporters (301) 565

- 0064 260 patents last well past any sort of, well, I’ll say 1

2016 or 2017 when a new standard would take effect? 2

If that information is available? 3

MR. HARTLEY: It’s not information that we 4

have readily available. 5

MR. BROO KMAN: Robert. 6

MR. ROSENSTOCK: Steve, I’m sorry, I think 7

that’s incredibly important because, depending on 8

the candidate standard level, if these are the 9

technologies that are basically mandated, and 10

there’s a patent, then there’s a lot of

-- obviously 11

a lot of market issues involved with that, so if 12

there’s information available, I think that it would 13

help stakeholders in some of their comments in terms 14

of gee, if the patents last well past 2016, let’s 15

say to 2020 or 17 year patent, could be 2025 plus, 16

that could be a very big deal. 17

MR. BROOKMAN: Robert. 18

MR. BERMAN: Robert Berman, Berman 19

Economics. I’d like to point out that it’s not 20

really the supply today that’s relevant, but it’s 21

the shape of the supply curve that’s relevant. What 22

you’re obser ving as supply, assuming the market is 23

functioning, is also demand. If the demand changes, 24

one would hope that the supply would change, and 25Executive Court Reporters (301) 565

- 0064 261 that over time lines can be added to both the steel 1

production as well as amorphous production. The 2

question is ho w do costs behave as lines are added, 3

and it looks like those are constant cost 4

industries. 5

MR. BROOKMAN: Charlie Stephens. 6

MR. STEPHENS: Charlie Stephens. I 7

thought we heard earlier from the symmetric core 8

design folks that the design really wasn’ t patented. 9

It wasn’t that there weren’t some patents associated 10

with some of the equipment being produced, but the 11

design itself wasn’t patented. 12

MR. HARTLEY: Yeah, DOE has received 13

different information on this. We do know several 14

designs that are p atented. We’ve not had a chance 15

to follow up with Mr. Hurst who made that comment 16

about the designs that aren’t patented. 17

MR. BROOKMAN: Gary Fernstrom. 18

MR. FERNSTROM: Earlier we talked about 19

wound core using conventional electrical steel as an 20

optio n that hadn’t been considered. I hope you will 21

consider that and see how it fits into this 22

conclusion. 23

MR. BROOKMAN: Thank you. Do you have a 24

comment, Jerry? Okay. Yes. 25Executive Court Reporters (301) 565

- 0064 262 MR. FERNSTROM: And maybe one more thing. 1

My comment is with respect to low v oltage dry type 2

transformers, because utility ones are wound core 3

already. 4

MR. HARTLEY: The last slide we have here 5

is just a request for comment. So DOE requests 6

comment on the identification of key issues that 7

were presented on the previous slide, an d we also 8

welcome comment on the supply of core steels that 9

are used in the analysis, and specifically looking 10

at grain oriented silicone steel, such as M3 and M2 11

and as we discussed, amorphous steel. 12

MR. BROOKMAN: Andrew. 13

MR. deLASKI: So just to be clear, in your 14

prior slide, you identified only one supplier for 15

amorphous ribbon. Dave commented that there was 16

another in China now. Are there any patent issues 17

that you’re aware of in relationship to other 18

manufacturers entering that market? A questi on for 19

Dave, maybe. 20

MR. SCHOEN: Amorphous? 21

MR. deLASKI: Yes. 22

MR. MILLURE: The basic patent was called 23

planar flow

- casting, and that ran out in ’99. So 24

there are really no patent barriers to entering 25Executive Court Reporters (301) 565

- 0064 2 63 amorphous metal production. It’s just know

- how 1

barriers. 2

MR. HARTLEY: What we have heard from 3

other information sources is that just the process 4

of developing the material can be very difficult. 5

It’s been compared to more of an art than a science. 6

And so we’re aware of other companies who have 7

at tempted to create it and have not achieved a 8

material that has the same specifications of what 9

would be considered a Metglas amorphous steel. 10

MR. SAMPAT: Yes, Mahesh Sampat. In that 11

respect, electrical steel is also an art. Not a lot 12

of people can mak e that. 13

PARTICIPANT: I appreciate that, Mahesh. 14

MR. BROOKMAN: Okay, I

-- yes. Paul. 15

MR. RYAN: Paul Ryan. My concern with 16

bullet number two is certain technology options 17

often require large capital investments. I think 18

you need to define a large capital investment, 19

because I’m looking at the technologies that you 20

list there, and from my understanding and knowledge, 21

none of those

-- well, other than the miter, the 22

miter does require a large capital investment, but 23

the other, core

-- amorphous core production, 24

symmetric core technology, I don’t think requires a 25Executive Court Reporters (301) 565

- 0064 264 large capital investment. So I think you need to 1

define what “large” means. 2

MR. HARTLEY: Sure, and at this point, 3

these are general

-- almost by design, this is 4

really just identifying ke y issues of which DOE will 5

hone in in more detail during the next phase of the 6

rulemaking 7

MR. BROOKMAN: Okay. Let’s press on then. 8

MR. HARTLEY: Okay. At this point, I’ll 9

invite Greg Rosenquist up to discuss the NOPR 10

analyses. 11

**NOPR Analyses** 12

MR. RO SENQUIST: You saw this slide at the 13

beginning of today’s presentation. It shows all the 14

different analyses that are done for the NOPR. One 15

set is the revision to the preliminary analyses, 16

which are engineering, LCC, and national impact 17

analysis. This i s based on all of your comments and 18

other stakeholder comments. And then the rest of 19

these analyses are also performed, which are all 20

downstream of the NIA. 21

So with regards to the revisions to the 22

preliminary analysis, as I just said, what DOE does 23

is i t looks at all the comments that are submitted 24

and determines what those issues are and how they’re 25Executive Court Reporters (301) 565

- 0064 265 going to address them. And so based upon how they 1

determine they’re going to address them, they’ll 2

revise the engineering analyses, the life cycle cost 3

and the national impact analyses accordingly. 4

Okay. So the next phase is the life cycle 5

cost subgroup analysis, and its purpose is to 6

evaluate impacts to any subset of customers that may 7

be disproportionately impacted by the standards. 8

The method is the s ame approach that’s used for the 9

overall LCC and payback period analysis, same tools, 10

same inputs. It’s just analyzed for that smaller 11

set of customers. The output is the same, which is 12

just life cycle cost savings and payback periods. 13

For the 2007 ana lysis, DOE looked at three 14

subgroups. One were municipal utilities because 15

they serve more diverse urban loads. Another were 16

rural electric cooperatives because they serve 17

smaller loads. And the third were vault installed 18

transformers because there are space constraints on 19

those type of transformers, so if a transformer has 20

to get larger, these types of transformers would 21

have to incur an additional cost beyond a normal 22

transformer. 23

DOE also wants to note that they are 24

particularly sensitive to how increase in purchase 25Executive Court Reporters (301) 565

- 0064 266 price may impact on some subset

-- some subgroup of 1

consumers beyond those just listed. 2

So the next phase is the manufacturer 3

impact analysis which Matt just went over quickly. 4

A full blown MIA will be done for the NOPR. 5

The nex t analysis is the unit utility 6

impact analysis, and its purpose is to investigate 7

the impact of standards on electric utilities, 8

primarily on electrical sales and installed 9

generation capacity, and that the mix of that 10

generation capacity. The method reli es on taking 11

national energy savings results from the national 12

impact analysis and feeding them into the national 13

energy modeling system, also called NEMS. NEMS is 14

used to conduct the forecast for the annual energy 15

output. 16

And as I just mentioned, aga in, the 17

outputs are electricity sales by region, the mix of 18

how the installed generation capacity is affected, 19

and also how that mix of electricity generation 20

capacity is affected. 21

The next analysis is an employment impact 22

analysis, and its purpose is to determine how 23

standards impact national employment. And the model 24

that’s used is called ImSET, which is a model that 25Executive Court Reporters (301) 565

- 0064 267 was developed by PNNL and analyzes 188 different 1

sectors throughout the economy to see how the impact 2

on transformer price and operating cost savings 3

ripple throughout the economy, and resulting in what 4

type of job loss or gain from that rippling through 5

the economy. 6

I did want to note that the direct 7

employment impacts for transformer manufacturers are 8

analyzed directly in the manufactur er impact 9

analysis. And again, the output is looking at how 10

these standards affect overall job employment in the 11

United States. 12

The next analysis is the environmental 13

assessment and its purpose is to determine how 14

standards impact emissions from power p lants in the 15

case of distribution transformers. Again, the 16

method relies on taking the energy savings results 17

from the national impact analysis, and inputting 18

them into NEMS. And the output are estimates of 19

national emission reductions of CO2, NOX and 20

me rcury. So CO2 is the primary emission reported, 21

followed by mercury, and followed by NOX, and NOX 22

are only reported for those 22 states where there 23

aren’t currently capped on the emission of NOX. 24

And I just wanted to note that SO2, 25Executive Court Reporters (301) 565

- 0064 268 because it’s capped by Clear Air Act amendments, no 1

physical emissions reductions are being reported for 2

SO2. 3

MR. ROSENSTOCK: Question? 4

MR. BROOKMAN: Please, Steve. 5

MR. ROSENSTOCK: Steve Rosenstock, EEI. A 6

couple weeks ago the EPA announced a rule called the 7

Util ity Mac Rule on utility boiler mercury and 8

particularly in the matter of emissions. That rule 9

is going to take effect in 2014. Will that rule be 10

incorporated into the analysis? 11

MR. ROSENQUIST: Yes, it will because the 12

AEO of 2011 will incorporate any legislation that’s 13

on the books in its forecast, so if that is actually 14

a final rule, then it will be addressed by the AEO. 15

MR. ROSENSTOCK: It’s a final rule. I 16

don’t know

-- are you talking about AEO 2012? 17

Because wasn’t 2011 published yet? 18

MR. RO SENQUIST: Yes, you’re right, it’ll 19

be in AEO 2012, not 11, unless 11 tried to forecast 20

that legislation coming down the pike, but typically 21

it doesn’t do that. 22

MR. ROSENSTOCK: So for the purposes of 23

the

-- so for the purposes of the decision in 24

October , can it be accounted for? 25Executive Court Reporters (301) 565

- 0064 269 MR. ROSENQUIST: We can explore that, 1

because there have been cases in the past where 2

legislation has come on the books and the folks over 3

at EIA have been willing to try to do some 4

incorporation of those. 5

MR. ROSENSTOCK: St eve Rosenstock. Yeah, 6

this is a regulation under the Clean Air Act. It’s 7

not a law, this is a regulation announced by EPA. 8

MR. ROSENQUIST: Yes, it tries to also 9

account for those sort of final rules that come out 10

from the regulatory agencies. 11

MR. R OSENSTOCK: Thank you. 12

MR. ROSENQUIST: Okay. The next slide 13

goes over the fact that DOE is now monitizing 14

emission of reductions, specifically for carbon and 15

NOX. For CO2, DOE is now calculating a social cost 16

to carbon based upon the dollar per ton va lue to C 17

here on this slide, and these dollar per ton values 18

came about from an interagency assessment. So this 19

is not dealt, necessarily, by DOE alone, but through 20

government agencies throughout the government. 21

I just also want to note too that NOX is 22

currently being monitized

-- NOX reductions are 23

currently being monitized by DOE. 24

MR. BROOKMAN: Gary Fernstrom. 25Executive Court Reporters (301) 565

- 0064 270 MR. FERNSTROM: Question on the prior 1

slide. I’d like to make sure I understand that. 2

You saying in states where emissions are capped, 3

th ose particular emissions are not considered? 4

MR. ROSENQUIST: That’s right. That's 5

correct. 6

MR. FERNSTROM: That is

-- help ignorant 7

me to understand that. That is why? Because

-- 8

wouldn’t

-- because presumably there’s no reduction 9

as a result of th ese savings? 10

MR. ROSENQUIST: That’s right. Because 11

there’s rules in place in the 28 states that are 12

capped that

-- I think it’s more or less modeled, I 13

think, how the SO2 is dealt with, that is, through 14

trading and capping. So I don’t have all the 15

details on that but there have been, I think, an EPA 16

rule

-- I think it’s a clean air interstate rule 17

that does result in capped emissions in those 28 18

states. 19

MR. BROOKMAN: The perception is that 20

they’ll stay the same. 21

MR. FERNSTROM: But it seems to me that if 22

there is a savings by a reduction in an emission 23

source, that that would still be a savings, even 24

though there may be a cap. 25Executive Court Reporters (301) 565

- 0064 271 MR. BROOKMAN: Phil, do you want to chime 1

in here? 2

MR. HOPKINSON: Greg, I can’t have any 3

problem with SOX reduction , NOX reduction, mercury 4

or methane, but what’s this CO2 stuff? That’s plant 5

food. 6

MR. ROSENQUIST: It’s a larger issue than 7

is in this room at the moment. Do you want to

-- 8

MR. ROSENSTOCK: Steve Rosenstock, EEI. 9

What the issue is, especially for S O2 under the acid 10

rain program, there’s been a declining cap the last 11

20 years. So if you look at the numbers, the amount 12

of SO2 actually emitted has gone by about 70 percent 13

over the last 20 years. But since it can be traded, 14

basically if you save those kilowatt hours in one 15

area utility, that power pool can trade it with 16

another area so that there’s no physical reduction 17

just because it can be either traded or it allows 18

the plant to transfer it to somewhere else. 19

MR. FERNSTROM: Well, if it’s a nation al 20

standard, I guess it could be traded to some area 21

that doesn’t have a cap? Is that it? 22

MR. ROSENQUIST: No, it’s a matter of 23

basically saying that

-- again, if the amount was 24

ten last year and it’s five this year, and someone 25Executive Court Reporters (301) 565

- 0064 272 else is at three and two , and the person gets down 1

to two, they can sell it to someone else and they’ll 2

go up to three if they want to. It’s still at five, 3

regardless of what happens to the end use. What 4

happens at the power plant is going to basically 5

stay the same because of the cap. I hope I kind of 6

-- that’s kind of in general what the theory is 7

behind what’s happening with their saying it’s not 8

going to have an impact on the power plant 9

emissions. 10

MR. FERNSTROM: So emissions resulting 11

from the federal standards can be s old by those who 12

comply with the standards? That

-- I don’t 13

understand this. Presumably it all makes sense, but 14

-- thank you. 15

MR. BROOKMAN: Do you understand the SO2 16

stuff? 17

MR. FERNSTROM: No. 18

MR. BROOKMAN: No, you don’t. That’s a 19

cap and trad e thing. 20

MS. COUGHLIN: If I can just make a 21

clarifying comment? This is Katie Coughlin from 22

LBL. The standard will lower the cost of complying 23

with the cap, that’s the general expected economic 24

impact of the standard, but it will not change total 25Executive Court Reporters (301) 565

- 0064 273 emis sions under the cap. 1

MR. BROOKMAN: Robert. 2

MR. BERMAN: Robert Berman, Berman 3

Economics. That statement is exactly right. The 4

other piece of that too, or to extend on that, is 5

that to the extent that you are doing your analysis 6

on a transformer leve l, then those benefits should 7

be attributed to the particular transformer and 8

standard that’s responsible for the reduction. 9

MR. BROOKMAN: Okay. And then Greg, you 10

have another slide or two? 11

MR. ROSENQUIST: Okay, which comes to our 12

next issue which speaks to how to value the carbon

- 13

- CO2 and NOX emissions savings from the standard. 14

Basically, DOE is inviting comment on the values 15

that it plans to use for doing this monitization. 16

MR. BROOKMAN: Steve Rosenstock. 17

MR. ROSENSTOCK: Steve Rosenstoc k, EEI. 18

You’re asking about energy security related 19

externalities? I don’t know if I’ve seen that in 20

other rulemakings. Is that

-- are you

-- is that in 21

terms of imported oil or imported other fuels or 22

imported materials? I guess I’m not sure how DOE i s 23

going to talk about energy security in the context 24

of this rulemaking. 25Executive Court Reporters (301) 565

- 0064 274 MR. ROSENQUIST: Well, to the extent that 1

can be quantified in the price of carbon, then it 2

will be, but if it can’t be, then

-- then it won’t. 3

MR. BROOKMAN: Does that phrase, “e nergy 4

security related externalities,” does it relate to 5

the emissions listed in 140? 6

MR. ROSENQUIST: Not necessarily. I mean, 7

again, when we talked about energy security 8

externalities it’s different than the externalities 9

associated with the carbon sa vings. 10

MR. ROSENSTOCK: Steve Rosenstock, EEI. 11

Thank you. That energy security is a totally 12

different issue than emissions. 13

MR. ROSENQUIST: Right. So currently, 14

current DOE rules that, to my knowledge, is not 15

being captured. 16

MR. BROOKMAN: Jerr y. Get the microphone, 17

Jerry. 18

MR. ALLEN: I’m wondering in this whole 19

thing, you talk about the social cost of carbon. 20

Aren’t you really just saying that there’s a social 21

cost of, let’s say sulfur dioxide. It’s not money 22

that the utility could get, bu t it’s whether it 23

would

-- agricultural productivity loss, human 24

health effects, et cetera. Since those aren’t 25Executive Court Reporters (301) 565

- 0064 275 changing since there’s already a cap, you’re not 1

considering them, and that’s really what the logic 2

is? 3

MR. ROSENQUIST: There’s no cap on car bon. 4

MR. ALLEN: No, there’s no cap on carbon, 5

but I’m saying you’re considering social cost of all 6

these things. 7

MR. ROSENQUIST: There isn’t a market 8

price for CO2 right now in the US, at least not 9

nationwide, so that’s the reason it’s being called 10

s ocial cost to carbon. 11

MR. ALLEN: Yeah, but what I’m saying is 12

if you’re considering, let’s say on sulfur dioxide, 13

you’re considering that a social cost, then if it’s 14

capped and it’s not going to get any lower because 15

of what you do, then you don’t count it. Isn’t that 16

the logic behind what they’re doing? Isn’t that it? 17

It’s social cost, not what it saves the utility by 18

trading the money to somebody else. 19

MR. BROOKMAN: Steve Rosenstock. 20

MR. ROSENSTOCK: Steve Rosenstock, EEI. 21

With SO2 or NOX, th ose aren’t social costs. Those 22

are estimated market cost based on the trading on 23

the market place. The carbon is a

-- it’s also, 24

with SO2 and NOX, DOE is looking domestically. 25Executive Court Reporters (301) 565

- 0064 276 Social cost is a “global cost” and they’re taking it 1

out to the year 2300 and trying to do a present 2

value of that. 3

MR. BROOKMAN: We have one more slide to 4

cover. 5

MR. ROSENQUIST: The last step in the NOPR 6

analyses is what’s called the regulatory impact 7

analysis, and its purpose is to investigate 8

alternatives to mandatory stan dards, that is, non

9

regulatory alternatives to standards. And these can 10

include things like manufacturer tax credits, 11

consumer tax credits, rebates, all government 12

purchase programs, early replacement programs, 13

things of that like. 14

The method is to make modifications to the 15

spreadsheet that’s developed for the national impact 16

analysis and make changes to key inputs, 17

specifically, how equipment efficiency is changed by 18

these different non

- regulatory alternatives. 19

And the output is very similar to the 20

na tional impact analysis. It provides both national 21

energy savings and net present value due to each one 22

of these alternatives. 23

MR. BROOKMAN: Comments on that 24

description of regulatory impact analysis? That was 25Executive Court Reporters (301) 565

- 0064 277 your final slide? Thank you, Greg. 1

I think that we had really excellent 2

presentations today, so I think maybe we should 3

actually do a round of applause. We seldom do that. 4

(Applause.) 5

MR. BROOKMAN: Well done. That was pretty 6

complicated stuff. 7

**Closing Remarks** 8

MR. BROOKMAN: Now is an opportunity for 9

anybody that wishes to do so, to make a closing 10

remark, brief summary remarks about things that have 11

not yet been covered sufficiently. 12

Okay, so then

-- yes, please. Say your 13

name again. 14

MR. STAHARA: Ron Stahara, Central 15

Moloney. We’re a manufacturer of liquid filled 16

transformers. One thing that we didn’t address

-- 17

we kind of addressed the issues relative to weight 18

and dimensions and possibly impedances. One thing 19

that as a product line that we did not address is 20

vaults or subme rsible type transformers. There are 21

existing vaults that they have to go in, whether 22

they be round or rectangular, whatever shape, and 23

that would be my concern of any increase in 24

efficiency. 25Executive Court Reporters (301) 565

- 0064 278 I think there are some limitations now 1

with where we’re at wit h the efficiencies to meet 2

existing dimensional requirements for submersible 3

type transformers. And that’s something that would 4

be of concern. 5

MR. BROOKMAN: Okay. Ned spoke with me at 6

lunch, he had a few other issues he wished to raise. 7

Please. 8

MR . BRUSH: Ned Brush. Just very quickly, 9

I’d like to suggest that DOE look into and perhaps 10

evaluate going to much larger sizes of transformers, 11

because to sort of resolve the conflict here that 12

Mahesh suggested for the current covered range of 13

kVA sizes, many people that I’ve talked with among 14

the utilities, and I’ve attended most of the 15

electric transformer meetings and so on, say, well 16

yes, we’re buying to DOE. Well, the DOE standards 17

translates, if Phil is still here, to about an A 18

value of roughly $4. 00 as I recall, $4.00 plus or 19

minus, and B of $1.00, $1.10, something like that. 20

Well, a number of these utilities say they have been 21

buying to that standard. 22

Well, if you were to increase this up to 23

perhaps, I think the suggestion is 10 MVA

-- I saw 24

so me of that in writing

-- but even going up to 30, 25Executive Court Reporters (301) 565

- 0064 279 you then cover the substation transformers, which 1

are part of the distribution system in the sense 2

that you’re dropping from overhead transmission 3

levels down to maybe 13

- 8 for distribution, or 4

something li ke that. 5

But anyway, there are perhaps from the 6

2500 kVA up to 30 MVA, you’re talking about maybe 7

7000 units a year, and there are huge disparities 8

here because some of these customers, some of these 9

utilities are actually buying to lowest first cost, 10

which in that range, not covered by DOE

-- I mean 11

they say they’re buying to DOE, but some of them are 12

buying them closer to zero

- zero for those much 13

larger units. They’re heavier loaded than these 14

units that are currently covered but are further 15

down the distribution system, closer to the 16

customer. 17

However, there is some good news on this 18

also. Because I spoke with three different 19

utilities that are actually buying to DOE plus, 20

which is what Mahesh was referring to here, and 21

they’re actually buying to A values that are between 22

six and eight dollars. For the DOE covered units, 23

some of those same utilities, however, are buying 24

the larger units, which are typically substation 25Executive Court Reporters (301) 565

- 0064 280 size and so on, to things like $1.80, $3.20 and so 1

on. In other words, values f or A that are below the 2

values of the currently covered units that are up 3

through 2500 kVA. 4

So I’d just like to suggest that that be 5

looked at and perhaps expand the definition of what 6

you are covering so that some utility that says, 7

yes, we’re buying to DOE or DOE plus, they in fact 8

are doing that, because the national energy savings 9

for the heavily loaded units there could be much 10

larger at the 7000 or so units a year in that 11

category. Very substantial. 12

MR. BROOKMAN: Okay. Thanks, Ned. 13

Additional comments? Yes, Jerry. 14

MR. SCHOEN: Jerry Schoen, AK Steel. In 15

the assessment of emission reductions, the wording 16

that I see in here is all focused on carbon, which 17

is an implication that those plants are going to be 18

coal fired. If

-- when coal costs $ 1.67 per million 19

BTUs, methane costs about three times that, and my 20

suspicion would be most of the plants that would be 21

brought up and down would be gas fired, as opposed 22

to coal fired. And is that calculation

-- is this 23

calculation going to look at what plants would be 24

handling the

-- what’s the right word

-- over base 25Executive Court Reporters (301) 565

- 0064 281 load? 1

MR. BROOKMAN: So the contractor crews are 2

nodding their heads saying “yes.” For the record. 3

Gary Fernstrom. 4

MR. FERNSTROM: That’s true for the I

5

squared R coil losses, but the core losses are base 6

loaded. 7

MR. BROOKMAN: Let’s let Robert go first. 8

MR. BERMAN: Robert Berman, Berman 9

Economics. Core losses are not base load. Core 10

losses are basically the loss associated with the 11

plant that could be taken off line, the saving s is 12

the power. Currently it’s likely to be an older 13

plant. It’s going to have the highest cost. It’s 14

going to have a cost much higher than the average 15

fuel cost. It’s going to have a cost higher than 16

what’s reflected in the A values, as a matter of 17

fa ct. But no, it is very definitely not the base 18

load. 19

MR. FERNSTROM: Well, maybe I’m 20

misunderstanding something. I thought that these 21

transformers, when they were connected to the grid 22

continuously incurred magnetic hysteresis losses 23

and that’s what w e’re talking about here, and that 24

would be base load because

-- 25Executive Court Reporters (301) 565

- 0064 282 MR. BERMAN: No, excuse me. You are 1

correct that they continually incur those losses, 2

but those losses have different values at different 3

times. The base load is there all the time, but 4

th at base load will never be taken down if you 5

reduce the demand. The unit that is taken down when 6

you reduce the demand is the high cost unit, not the 7

low cost unit. It’s the last unit that’s dispatched 8

that’s taken down. 9

MR. SCHOEN: If I may, they w ould look at 10

that from a standpoint of what does it cost me in 11

terms of fuel to generate that last amp of 12

electricity? Typically, that highest cost unit 13

would be solar or natural gas. Coal, nuclear power 14

plants, the wind ... and hydros are running 15

continuo usly. 16

MR. BROOKMAN: Steve Rosenstock. 17

MR. ROSENSTOCK: Steve Rosenstock, EEI. 18

And in terms of some of this, you have to remember 19

that there’s over 30 states that have renewable 20

portfolio standards, and certain states, like Texas, 21

six years ago wind c omprised about one and a half 22

percent of the electricity produced in the ERCOT 23

(ph) area. In 2010, that was eight percent. There 24

were times in Texas when wind was 20, 25 percent of 25Executive Court Reporters (301) 565

- 0064 283 the generation in Texas. So

-- in other areas, 1

obviously. There’s certa in areas in California, 2

they’re putting in a bunch of solar, so and 3

sometimes part of that peak load will be solar or 4

wind, and if you’re looking at emissions, there is 5

no impact on emissions with those power plants being 6

part of the peak mix, or base load mix, depending on 7

-- especially for wind, especially, typically 8

operates at the highest load at night. 9

MR. FERNSTROM: Okay. So I think our 10

confusion stems from what’s meant by base load, and 11

the point I want to have everyone agree on is these 12

core los ses occur continuously. 13

MR. BROOKMAN: Okay. Thank you. Andrew 14

deLaski. 15

MR. deLASKI: I just want to follow on the 16

comment made by the gentleman from Central Moloney 17

about vault transformers. This was discussed a 18

great deal on the docket in 2007, th ere was a lot of 19

discussion to it. I think there was some discussion 20

about some transformers that aren’t covered by the 21

proceeding and some that are. 22

I think it’s a valid issue. It should be 23

looked at. I’d also want to recognize that I would 24

say uti lities that serve some of the densest urban 25Executive Court Reporters (301) 565

- 0064 284 neighborhoods in the country, ultimately supported 1

the CSL

-- or TSL4 last docket, were comfortable 2

with that, despite the impacts on size. 3

Working at higher levels now, that implies 4

other changes, but the Depa rtment has to be very 5

careful in analyzing this issue because of

-- it is 6

a complicated issue because it involves vault size 7

and the step ups that are involved. When you 8

actually trigger those costs, one that deserves 9

consideration, but it needs to be loo ked at very 10

carefully. 11

MR. BROOKMAN: John. 12

MR. PHOUMINH: Thank you. I’d like to 13

compliment Central Moloney for bringing up the 14

issue. Pepco, especially in this area, we serve in 15

this building too, maybe outside of this building, 16

we have a vault out side in the public space, and 17

those vault is limited, typically 6 **×** 14, 6 **×** 18. 18

If you were to increase the unit efficiency, that 19

could be higher, that could be larger, could be 20

longer, could be wider, and if we have to replace 21

the units, if they fail for some reason, or maybe 22

time to change out when it reaches its useful life, 23

we have a problem, big time. 24Executive Court Reporters (301) 565

- 0064 285 MR. BROOKMAN: Got you, understand. Okay. 1

These final comments, I think, have been interesting 2

and useful. Additional final comments before I turn 3

it back to Jim Raba for is closing remarks. Steve 4

Rosenstock. 5

MR. ROSENSTOCK: Steve Rosenstock, EEI. 6

Just one thing. I think, especially with the

-- I 7

think there were new participants which I’m always 8

happy to see. It might be helpful, especially with 9

a lot of the information that DOE is asking for, to 10

have a comment period that’s later than April 18 th

. 11

Thank you. 12

MR. BROOKMAN: Okay. Thank you. Jim 13

Raba, it’s back to you. 14

MR. RABA: Well, I think we all agree that 15

today’s been most producti ve from the Department’s 16

point of view. Certainly the participation of 17

yourselves, coming this way to be present, and those 18

in our webinar, again, thank you for being with us 19

today. A special appreciation to facilitator Doug 20

Brookman, webinar operator Ho i Y ee

. 21

(Applause.) 22

MR. RABA: Our transcriber in the 23

background here, and our presenters, and those 24

behind the scenes whom you didn’t see worked very 25Executive Court Reporters (301) 565

- 0064 286 hard to support the presenters too. 1

So on behalf of the Department of Energy, 2

I appreciate your be ing here so much. 3

We now move on to the next phase, 4

rulemaking process, which will either be a 5

determination that standards for distribution 6

transformers need not be amended, or a Notice of 7

Proposed Rulemaking to amend those standards, based 8

upon your comments and input, data and information 9

which you see where to send and when it’s due. 10

Thank you very much, the Department of Energy 11

appreciates all. You deserve a round of applause 12

again. Thank you. 13

(Applause.) 14

(Whereupon, at 4:30 p.m., the meetin g in 15

the above captioned matter was adjourned.) 16