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October 6, 2011

Members of the NEMA/ DOE Rulemaking Group

I would like to share some thoughts that I hope will provoke us all into our making more good decisions as we move forward with this project.

From what I am reading there seems to be a need to have a little better understanding of what the “A” and “B” factors can really do for our analysis.

As we examine these factors, we must remember that they are developed for the sole purpose to indicate the additional revenues that are needed by the electric utility companies to fund the components in their respective fixed charge rates. As we all know, the “A” and “B” factors are important parts of the TOC calculation, as they represent the additional revenue coefficients that are applied to the losses of the transformers purchased by the electric utilities.

We need to remember that for, say a 20% annual fixed charge rate (FCR), the components comprising this rate include: sinking fund factor depreciation, pr operty taxes, the utility’s weighted cost of capital, and

a few other smaller items.

Suppose the utility is buying a transformer for $ 1000 that has no losses (0 watts of NL and LL losses). Annually this transformer must generate revenue of $ 200 (@ a 20% annual FCR). The equivalent first

cost of the transformer is $ 1000 but the present worth of the annual revenue requirement over 30 years at a 7% annual discount rate is $ 200 X 12.4 = $ 2481 .80, where 12.4 is the present worth factor of a uniform annual cost (at year’s end) over 30 years.

Below is a table that shows the relationship of equivalent first cost

, annual cost from a FCR , and present worth

.

. 

### Conversion Factors FOR

Uniform Annual Cost
Equivalent First Cost

Present Worth

GIVEN DESIRED MULTIPLY GIVEN

BY

UNIFORM ANNUAL

COST EQUIVALENT FIRST

COST 1/(FCR)

UNIFORM ANNUAL

COST PRESENT WORTH (PWF)

EQUIVALENT FIRST

COST UNIFORM ANNUAL

COST (FCR)

EQUIVALENT FIRST

COST PRESENT WORTH (FCR) (PWF)

PRESENT WORTH UNIFORM ANNUAL

COST 1/(PWF)

PRESENT WORTH EQUIVALENT FIRST

COST 1/((PWF)(FCR))

FCR = ANNUAL FIXED CHARGE RATE

PWF=PRESENT WORTH FACTORPage 2

Now let’s suppose this $ 1000 transformer has some NL losses and Load losses. To the annual revenue requirement to recover the $ 1000 investment the co st of losses must be added. In most cases that amount on an equivalent first cost basis will be equal to or greater than the selling price of the transformer. This is the TOC appr oach for evaluating transformers.

My basic point is that the TOC is not a life cycle cost for the transformer. It is the revenue requirement to cover the transformer price and its associated cost of losses.

We could claim the TOC a life cycle co st but that claim would apply on fo r only electric utility customers.

For the Institutional

, Commercial , and Industrial customers ( ICI customers) TOC and “A” and “B” factors should not be applied, because these types of businesses don’t have what is known as an annual fixed charge rate (FCR). This is the reason that IC I types of customers employ the concept of a payback period for a quantitative input on investment decisions . Most ICI customers will not make incremental investments that have payback peri ods in excess of 3 years due to risk and uncertainty factors.

From the discussions and communications I’ve seen on this most recent endeavor to ascertain the proper transformer efficiencies, it appears that we just acce pt “A” and “B” as given values that are absolutely accurate and correct for a particular utility. This may not be so.

The Value of “A” = [1/FCR] * [PLANT$ * FCR + 8760 *($/kw-hr)] * [Core Loss in KW]

The Value of “B” = [1/FCR] * [ 

### K 2 ] * [PLANT$ * FCR * RsFAC + 8760 * ($/kw-hr) * Loss Factor)] * (Cond Loss in KW)

Looking at the core loss expression for “A” we must remember that not only is the utility’ s cost per kw-hr involved; but also their investment in generatin g plants plus transmission & distribution systems ( PLANT$ ) must be considered. So far in our communications about the ICI customers we’ve included only the cost of energy but ignored the demand charge (representing equipment investment by the utility)

in our PW valuations of the cost of losses.

Note in the expression for “B”: K 2

, is the PW of the peak loads in p.u. of NP, the responsibility factor is the portion of the time that the peak load on the transformer coincides with the utility’s system peak, and

the loss factor is the portion of time during the year that the actual peak load on the transformer would have to be present to equal the total load losses that were actually incurred. If each of these special factors were equal to 1.00 , “B” would be equal to “A”. But these parameters are not equal to 1.00 usually. For Low Voltage Dry and Medium Voltage transformers we’ve considered K 2 to be equal to either (.35) 2

or (.5) 2 . And these K 2 values may be much lower based on some excellent input by Mr. Tom Patzner of Schneider. Typically responsibility factors will range from 0.7 to 0.9, and loss factors will be somewhere in the 0.5 range. So we can say we’re right to show the values of “B” to be less than “A”.

But what we can’t say without a lot more research is what the order of magnitude should be for “A” and “B”. For instance if the system cost is $4000/kw and the energy cost is 10¢ per kw-hr,, with a FCR of 20%, “A” would be equal $ 8380/KW or $ 8.38/watt.

I suspect the system cost is more nearly in the range of $ 2000/KW and from Mr. Phil Hopkinson’s excellent paper the utility energy co st is $0.045/kWH. With these values “A” becomes equal to $ 3871/KW or $ 3.71/watt.

Having caused the readers to grit your teeth throug h all of this boring and mundane analysis ,in which I have tried to emphasize how the TOC arithmetic sh ould be understood and mention all of the complex judgments that go into the choosing of the correc t factors and costs, may I suggest the following:

1. For the Liquids: We select an efficiency level that causes the utility customer to pay no more than 70¢ for each Total Owning Cost $ saved with a higher efficiency (TSL) than the present

DOE 2010 efficiencies

2. For the Drys: (LV and MV): We select an efficiency level (TSL) that allows the end user to experience a payback period of no longer than 5 years.Page 3

Unless we are presented better information for the el ectricity cost values, for the recommendations in numbers 1 and 2 above I propose that we should us e the values presented in Phil Hopkinson’s 9/24/11 report sent to the negotiating committee.

Thank you for consideration of this recommendation and I welcome comments and corrections to this

letter.

Very truly yours,

Bob Smith, Negotiating Committee Alternate Product Manager

Federal Pacific