...))) Dkt. No. ER09-1534-001 SUMMARY OF THE PREPARED REBUTTAL TESTIMONY OF DR. PAUL T. HUNT...

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern California Edison Company

)))

Dkt. No.

ER09-1534-001

PREPARED REBUTTAL TESTIMONY OF

DR. PAUL T. HUNT ON BEHALF OF

SOUTHERN CALIFORNIA EDISON COMPANY

(EXHIBIT SCE-49)

OCTOBER 2010




)))

Dkt. No.

ER09-1534-001

SUMMARY OF THE PREPARED REBUTTAL TESTIMONY OF

DR. PAUL T. HUNT (EXHIBIT SCE-49)

In his testimony, Dr. Hunt discusses issues related to SCE’s cost of capital and

estimates of cost escalation.

With respect to cost of capital, Dr. Hunt’s rebuttal testimony shows that there

are serious flaws in the analyses and recommendations of FERC Staff witness Keyton

(pp. 10-34), CPUC witness Cosman (pp. 45-63), M-S-R witness Lesser (pp. 63-73),

and SWP witnesses Malloy (pp. 74-76) and David Marcus (pp. 73-74). The

recommendations of these witnesses should not be adopted in this proceeding. With

respect to the recommendations of Six Cities witness Solomon, his methodology is

nearly identical to Dr. Hunt’s updated estimates (pp. 34-45) of return on equity and

would produce nearly identical results if applied to the data that Dr. Hunt used for his

update. Contrary to the suggestions of these witnesses, Dr. Hunt’s updated estimates

are consistent with FERC precedent and in particular, consistent with the recent

Commission order in another SCE docket related to the determination of return on

equity. (pp. 5-9, 77-78).

With respect to cost escalation, Dr. Hunt shows that FERC Staff witness Kerri

H. Miller’s calculation of SCE’s average salaries is incorrect, and that SCE’s

projected increases in its average salaries are consistent with the historical record. (pp.

78-91). He also shows that the criticisms of Six Cities witness Terry M. Myers, M-S-

R/LADWP witness David B. Cohen, and FERC Staff witness Craig E. Deters

regarding SCE’s use of labor escalation rates to escalate the indirect portion of non-

labor costs should rejected. Contrary to these witnesses’ arguments, the non-labor

escalation rate must be adjusted to reflect indirect labor costs included in the non-

labor expense in order to correctly calculate the non-labor escalation rates. (pp. 91-

112).



Southern California Edison Company )))

Dkt. No.

ER09-1534-001

TABLE OF CONTENTS OF THE PREPARED REBUTTAL TESTIMONY OF

DR. PAUL T. HUNT (EXHIBIT SCE-49)

I. PURPOSE OF REBUTTAL TESTIMONY....................................................... 3

II. RESPONSE REGARDING ISSUES RAISED BY MULTIPLE INTERVENORS................................................................................................. 5

III. RESPONSE TO TESTIMONY OF FERC STAFF REGARDING COST OF CAPITAL.......................................................................................................... 10

A. Return on Equity ........................................................................................... 10

B. Capital Structure............................................................................................ 30

C. Costs of Long-Term Debt and Preferred Equity ........................................... 33

IV. RESPONSE TO SIX CITIES TESTIMONY REGARDING COST OF CAPITAL.......................................................................................................... 34

A. Response to Mr. Solomon’s Analysis of SCE’s Cost of Capital .................. 34

B. Response to Mr. Solomon’s Comments on my Analysis.............................. 45

V. RESPONSE TO CPUC (COSMAN) TESTIMONY REGARDING COST OF CAPITAL.......................................................................................................... 45

A. Response to CPUC DCF Analysis ................................................................ 46

B. Response to Other Aspects of CPUC Affidavit and Exhibits....................... 54

VI. RESPONSE TO M-S-R (LESSER) TESTIMONY REGARDING COST OF CAPITAL.......................................................................................................... 63

A. Response to Dr. Lesser’s Analysis of SCE’s Return on Equity ................... 63

B. Response to Dr. Lesser’s Comments Regarding My Testimony.................. 71

VII. RESPONSE TO STATE WATER PROJECT TESTIMONY REGARDING COST OF CAPITAL ........................................................................................ 73

A. Response to Mr. Marcus’s Analysis of SCE’s Cost of Capital..................... 73

B. Response to Dr. Malloy’s Commentary........................................................ 74

VIII. UPDATED ESTIMATES OF COST OF CAPITAL ....................................... 77

A. Return on Equity ........................................................................................... 77

IX. RESPONSE TO OTHER PARTIES’ TESTIMONY REGARDING COST ESCALATION ................................................................................................. 78

A. Labor Escalation............................................................................................ 78

B. Non-Labor Escalation and Indirect Labor..................................................... 91

Dkt. No. ER09-1534-001 Exhibit SCE-49

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)))

Dkt. No.

ER09-1534-001

PREPARED REBUTTAL TESTIMONY OF DR. PAUL T. HUNT

ON BEHALF OF SOUTHERN CALIFORNIA EDISON COMPANY

Q. Please state your name and business address for the record.

A. My name is Dr. Paul T. Hunt, and my business address is 2244 Walnut Grove

Avenue, Rosemead, California 91770-3714.

Q. Have you submitted prior testimony in this proceeding?

A. Yes, I submitted direct testimony in Exhibits SCE-17 through SCE-21 on July

31, 2009.

Q. Are you adopting the direct testimony of Ms. Schiminske, Exhibit SCE-16,

as your own testimony in this proceeding?

A. Yes. I am adopting Ms. Schiminske’s testimony as my own. I assisted in the

drafting of that testimony and am able to attest that it is true and correct to the

best of my knowledge and belief.


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Q. Have you submitted testimony to the Federal Energy Regulatory

Commission since July 31, 2009?

A. Yes. I have submitted testimony in Docket No. ER10-160-000. I also

submitted affidavits in Docket Nos. EL10-1-000, EL10-81-000, ER08-375-

004, and ER09-187-002/ER10-160-000. This testimony and affidavits have

generally concerned issues related to cost of capital.

Q. Are there any changes to your professional qualifications since July 31,

2009?

A. Yes. In September 2010, I was promoted to Director of Regulatory Finance

and Economics at SCE.

Q. Have you written any publications on cost of capital since July 31, 2009 in

addition to the testimony and affidavits described above?

A. Yes. In late 2009, I was invited to write, with a co-author, a book chapter on

cost of capital in regulated industries. The book chapter is titled "Cost of

Capital in Regulated Industries," and it will appear in Cost of Capital in

Litigation: Applications and Examples,1 to be published by John Wiley &

Sons, Inc., later this year.

1 ISBN: 978-0-470-88094-4.


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I. PURPOSE OF REBUTTAL TESTIMONY 1

Q. What is the purpose of your rebuttal testimony in this proceeding?

A. The purpose of my testimony is to rebut the testimony of FERC Staff witness

Robert J. Keyton, CPUC witness R. Mihai Cosman, M-S-R witness Dr.

Jonathan A. Lesser, Six Cities witness J. Bertram Solomon, and SWP

witnesses Dr. Michael P. Malloy and David Marcus (collectively, “intervenor

ROE witnesses”) on rate of return on equity (“ROE”) and other issues related

to Southern California Edison Company’s (SCE’s) cost of capital. I also rebut

the testimony of Six Cities witness Terry M. Myers, M-S-R/LADWP witness

David B. Cohen, and FERC Staff witnesses Kerri H. Miller and Craig E.

Deters on issues related to cost escalation. Finally, I update my estimates of

Southern California Edison Company’s (“SCE’s”) cost of equity capital

presented in my direct testimony.

Q. Please provide a summary of your findings regarding the intervenor and

FERC Staff ROE witnesses’ recommendations regarding cost of capital.

A. I show that there are serious flaws in the analyses and recommendations of

FERC Staff witness Keyton, CPUC witness Cosman, M-S-R witness Lesser,

and SWP witnesses Malloy and David Marcus. The recommendations of these

witnesses should not be adopted in this proceeding. With respect to the

recommendations of Six Cities witness Solomon, I show that his methodology

is nearly identical to mine and that it would produce nearly identical DCF ROE


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estimates if applied to the data that I used for my updated DCF estimates,

which are based on the most recent data available. Contrary to the suggestions

of these witnesses my updated estimates are consistent with FERC precedent

and in particular, consistent with the recent Commission order in another SCE

docket related to the determination of return on equity.

Q. Please provide a summary of your findings regarding the intervenor and

FERC Staff witnesses’ recommendations regarding cost escalation.

A. I demonstrate that FERC Staff witness Kerri H. Miller’s calculation of SCE’s

average salaries is incorrect. I show that when the correct calculations are

performed, SCE’s average salaries have increased in the past, and that SCE’s

projected increases in its average salaries is consistent with the historical

record. I also show that the criticisms of Six Cities witness Terry M. Myers,

M-S-R/LADWP witness David B. Cohen, and FERC Staff witness Craig E.

Deters regarding SCE’s use of labor escalation rates to escalate the indirect

portion of non-labor costs should re rejected. I demonstrate that, contrary to

these witnesses’ arguments, the non-labor escalation rate must be adjusted to

reflect indirect labor costs included in the non-labor expense in order to

correctly calculate the non-labor escalation rates.


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II. RESPONSE REGARDING ISSUES RAISED BY MULTIPLE 1

INTERVENORS

Q. Are you familiar with the Bluefield and Hope decisions discussed by

several of the intervenor ROE witnesses?

A. Yes, I am familiar with Bluefield2 and Hope,3 as I discuss them in my own

testimony. Exhibit SCE-17, pp. 5-6. My concern is that the opposing

witnesses have overstepped reasonable bounds in their effort to seek a lower

authorized cost of capital for SCE. Mr. Cosman, for example states the

following: “Rates have to be just and reasonable even if they produce a

meager return on rate base.” Exhibit PUC-1, p. 37. I submit that Mr. Cosman

has it exactly backward. If the authorized rate of return on rate base is meager,

then that authorized rate of return is unreasonable.4

In my view, all of the intervenor ROE witnesses have presented ROE

recommendations that are inadequate. They are lower than SCE’s authorized

return on equity in its retail jurisdiction and they are lower than the ROE that

would be authorized if SCE were an RTO member, filing as an RTO member.

2 Bluefield Waterworks v. Public Svc. Comm., 262 U.S. 679 (1923). 3 FPC v. Hope Natural Gas, 320 U.S. 591 (1944). 4 The dictionary definition of meager is “[d]efficient in quantity, fullness, or extent;

scanty.” (See http://education.yahoo.com/reference/dictionary/entry/meager.) “Deficient in quantity” does not comport with the standards of Bluefield and Hope.


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Q. Several of the intervenor ROE witnesses have criticized your use of

midpoint estimates in this docket. How do you respond to their

criticisms?

A. Witnesses Keyton, Cosman, Lesser, Marcus and Solomon incorrectly criticize

my original DCF estimates in this docket because they are based on midpoint

estimates and not median estimates. Three points are important. The most

important point is that the FERC order cited by these witnesses was not issued

until April 15, 2010, over eight months after I submitted my direct testimony in

this case. Incidentally, my direct testimony contained median estimates.

Exhibit SCE-18, pp. 1-2, 8-9. I did not base my recommendation on those

median estimates for the reasons presented in my direct testimony. Exhibit

SCE-17, pp. 32-37. Another important point is that the midpoint/median

policy established in the recent CWIP order5 (“April 15 Order”) has been

challenged by SCE in an application for rehearing6 and is also potentially

subject to judicial review. So the issue is not settled.

5 Southern California Edison Company, 131 FERC ¶ 61,020 (2010). 6 Docket No. ER08-375-004, Application for Rehearing of Southern California Edison

Company (Acc. No. 20100517-5117), May 17, 2010.


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As I explained in my direct testimony, in the standard FERC DCF

procedure, before either the midpoint or median estimate is calculated,

unreasonable results from the bottom or the top of the range are excluded.

Exhibit SCE-17, pp. 28-30. All of the remaining individual company estimates

are therefore reasonable, and this extends to the individual estimates before any

averaging takes place.7 Therefore, given that the entire range of estimates

from which the midpoint is calculated is reasonable, the midpoint estimate

itself must be reasonable. As I explained in my direct testimony, “once t

unreasonable results are excluded, setting the ROE at the midpoint of the range

considers the full breadth of the reasonable results that comprise the range.”

Exhibit SCE-17, p. 32, ll. 10-12.

The Commission itself distinguishes between the use of the median

estimate and the midpoint estimate based on the industry structure and whether

the applicants make individual or joint ROE filings. However, when the proxy

group distribution is positively skewed (most commonly, when the “tail”

extends farther to the right), as it is in virtually all of the DCF estimates

7 For example, in the Atlantic Path 15 case, the Commission found that the reasonable

range of returns extended from 7.63% to 13.67%. Atlantic Path 15, LLC, 122 FERC ¶ 61,135, P 20 (2008). Inspection of Exhibit ATL-7 from that docket reveals that the range is based on the individual low and high DCF estimates for each company. Docket No. ER08-374-000, Exhibit ATL-7 (Acc. No. 20071227-0154), p. 2.


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presented in this case, (Exhibit SCE-51) the use of the median estimate

unfairly discriminates against the individual applicant, such as SCE, when

compared to a group of applicants, such as members of an RTO, who submit a

joint filing to the Commission.

This is not just an academic point. SCE competes for capital against

other utilities. If SCE is forced to accept a median-estimate-based ROE when

a midpoint-estimate-based ROE is awarded to other electric utilities, SCE will

be handicapped in its efforts to attract capital to finance the expansion of its

system, to the ultimate detriment of its customers. Basically, the Commission

has set up a system for calculating ROEs that discriminates in favor of RTO

member utilities that file jointly and against RTO member utilities that file

individually. There is no economic reason to believe that one of these groups

has a higher or lower cost of equity capital than the other and yet the joint filers

get a much higher ROE. The Federal Power Act prohibits discrimination in

setting rates, and I believe this should apply to the rules that the Commission

uses to set rates as well as the rate proposals of public utilities themselves.

Q. Mr. Cosman of the CPUC says that you failed to cite any academic journal

or scholarly publication that states that the midpoint is a better estimator

of central tendency of a population compared to the median. How do you

respond to this comment?

A. As a first comment, the issue at hand is not the estimation of the appropriate


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authorized return on equity for a population of electric utilities, but the

estimation of the appropriate authorized return on equity for Southern

California Edison Company.

However, in response to Mr. Cosman’s comment, I have done some

research on this issue. From a purely statistical perspective, the superiority of

the median estimate versus the midpoint estimate is not clearcut, as it depends

on the underlying probability distribution of the data. For example, if the

underlying distribution is uniform but the endpoints are unknown, then the

midpoint estimate is superior to the median estimate.8 When the underlying

distribution is symmetric but with a finite range, “the midrange [or midpoint] is

then an excellent location estimator.”9 Since the Commission’s DCF

procedure includes exclusion of low-end and high-end estimates, the

distribution must be finite.

8 Frederick James, Statistical Methods in Experimental Physics, (Singapore: World

Scientific Publishing Co. Pfc. Ltd., 2006), p. 209. 9 Id. Here, “location” refers to the center of the probability distribution.

Dkt. No. ER09-1534-001 Exhibit SCE-49 Page 10 of 113

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III. RESPONSE TO TESTIMONY OF FERC STAFF REGARDING COST 1

OF CAPITAL

A. Return on Equity

Q. What is your overall response to Mr. Keyton’s return on equity

recommendation?

A. My response is that Mr. Keyton’s recommendation is far too low. The reason

his result is so low is that he has chosen to define his proxy group using

artificial and overlapping criteria that are different from those employed by the

Commission. As I will discuss in more detail below, Mr. Keyton has

engineered his proxy group selection so that his ROE estimate is unreasonably

low. His proxy group selection criteria are inconsistent with FERC precedent

and produce an unsound result.

Q. Mr. Keyton claims that Commission precedent supports a small proxy

group. How do you respond to his claim?

A. I disagree. Most of the recent Commission decisions have used large proxy

groups. It is noteworthy that the most recent decision cited by Mr. Keyton,

Allegheny Power, was issued six and one-half years ago.10 More recent

Commission decisions, particularly the recent decision for SCE in its 2008

10 Allegheny Power, 106 FERC ¶ 61,241 (March 9, 2004).


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CWIP case, the April 15 Order,11 have been based on larger proxy groups. In

the April 15 Order, the Commission approved a DCF analysis based on a proxy

group of fifteen companies.12 The initial proxy group size was 23 companies;

the Commission excluded eight companies because certain DCF estimates for

those companies were too high or too low. Either way the number of

companies in the proxy group is counted, the Commission based its most

recent ROE order on a proxy group that is more than twice as large as the one

that Mr. Keyton proposes. Moreover, the Commission has consistently used

large proxy groups in setting ROEs for members of RTOs in recent years. It

has rejected using the members of the same RTO as the proxy group in favor

of much larger proxy groups consisting of the members of multiple RTOs. For

example, in Docket No. ER04-157, involving the ROE for the New England

transmission owners, the Commission rejected use of a proxy group consisting

only of the New England utilities in favor of a much larger proxy group

consisting of members of three RTOs. In addition, Mr. Keyton is the only

witness in this proceeding who has used a small proxy group. The other

witnesses hew closely to the Commission’s precedent.

11 Southern California Edison Company, 131 FERC ¶ 61,020 (2010). Mr. Keyton cites this

order at Exhibit S-7, pp. 4, 16, 21, 23, 29. 12 Id. at PP 24, 57-58.


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In addition, it is well established in the statistical literature that larger

samples produce more reliable statistical estimates. This is known as the Law

of Large Numbers.13 There is a solid statistical basis for choosing a large

proxy group over a smaller one.

Q. Mr. Keyton states: “The fact that most publicly-traded electric utility

companies have the same business and financial risk that I used in my

screening criteria indicates that companies in the electric utility industry

generally have a similar level of overall business and financial risk.” How

do you respond to this comment?

A. This answer is inconsistent with his entire proxy group selection process. His

process uses a long list of screening criteria, several never used by the

Commission before, to eliminate a large number of electric utility companies

from the proxy group. If his statement above is true, then there is no reason to

exclude as many companies as Mr. Keyton does in his uniquely complex and

stringent proxy group selection process. It is only appropriate to eliminate

companies from the proxy group if there is a wide disparity in risk between

different groups of electric utilities and the target company. But if there is not

a wide disparity of risk, as Mr. Keyton concedes, then the accuracy of the final

13 D. A. S. Fraser, Statistics—An Introduction, (New York: John Wiley & Sons, Inc.,

1958), p. 119.


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ROE estimate is increased as the number of companies is larger. This is why

his approach of layering criterion upon criterion is exactly the wrong approach.

Because he has excluded so many companies from his proxy group, he has

dramatically increased the probability that his estimate will be distorted by the

estimates of just a few companies. This is the standard small-sample problem.

In a different context, it is the reason why professional opinion surveys are not

based on just a handful of responses, but many hundreds. If opinion surveys

were based on just a handful of responses, the chances of a large error would

be unacceptably large. The same sampling issue applies here.

Q. Did Mr. Keyton provide an explanation of why he deviated from the proxy

group that the Commission used in setting SCE’s ROE in its most recent

decision?

A. No. Mr. Keyton claims throughout his testimony that he is relying on

Commission precedent, but in this one instance he has ignored precedent and

developed a small proxy group using his own criteria that skews the result

downward by approximately a full percentage point. I can think of no good

reason why Mr. Keyton chose to ignore a Commission decision on proxy

group selection for SCE that was issued just a few months before he submitted

his testimony.


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Q. Which of Mr. Keyton’s proxy group selection criteria do you disagree

with?

A. At pages 13-14 of Exhibit S-7, Mr. Keyton lists eleven selection criteria. I

disagree with his use of the following criteria (numbered as in his testimony):

(1) operation in the continental United States and Standard & Poor’s (“S&P”)

classification as an electric utility; (3) Value Line safety rank of 3, (5) S&P

utility business risk profile of excellent or strong, (6) S&P utility financial risk

profile of intermediate, significant, or aggressive, and (7) dividend. Several of

these criteria have not been used before, and the Commission has never used

this particular combination of criteria in any previous case. Mr. Keyton has

not explained why he deviated from precedent in order to establish his own

unique set of redundant criteria in this case.

Q. Why do you disagree with Mr. Keyton’s use of these criteria?

A. I disagree with Mr. Keyton’s use of these criteria because they unreasonably

reduce the size of his proxy group by eliminating companies that are

appropriate comparisons for purposes of setting the ROE for SCE. These

criteria eliminate companies that the Commission has not eliminated in prior

cases and that the Commission has used to set ROEs for other electric utilities.

Before I discuss his criteria in more detail, I do want to clarify that of his

eleven criteria, the first nine are criteria that restrict the proxy group based on

characteristics of the company that is a candidate for inclusion. The last two


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are criteria that are based on the resulting DCF estimates for each company.

Criterion (10) excludes a company based on the relationship between the low-

end DCF estimate and the Moody’s bond yield index, and criterion (11)

excludes a company based on whether either of the DCF growth rates exceeds

a level that the Commission has found in the past to be unreasonably high. I

believe that it is helpful to distinguish between these two groups of criteria and

I will do so in the discussion that follows.

Turning back to the first nine criteria, I will address each in turn:

(1)(a) Operations in continental United States. There is no basis for

this criterion, as Hawaiian Electric Industries (“HEI”) competes for capital in

the same markets that SCE does. The capital markets do not care that HEI is

separated from the U.S. mainland. With respect to risk differences, the S&P

corporate credit rating shows an insufficient difference to exclude HEI from

the proxy group: its corporate credit rating is BBB, versus SCE’s BBB+. In

addition, HEI would have been included in the proxy group adopted by the

Commission in the April 15 Order, but for the fact that its low-end DCF

estimate was too low at the time.14 This criterion is arbitrary as it is not based

on any grounds related to the cost of equity capital. I am not aware that the

14 Southern California Edison Company, 131 FERC ¶ 61,020 (2010), at PP 24, 57-58.


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Commission has applied it in the past.

(1)(b) S&P classification as an electric utility. This is not a criterion

that the Commission employed in the April 15 Order, and I do not believe that

the Commission has ever employed it previously.15 If one starts with the 54

Value Line electric companies (as the Commission did in the prior SCE case),

then according to Mr. Keyton’s analysis, the use of the additional S&P

criterion excludes ten of those companies: Central Vermont Public Service,

CH Energy Group, Constellation Energy, Exelon Corporation, MGE Energy,

PPL Corporation, Public Service Enterprise Group, Sempra Energy, Unisource

Energy, and Vectren Corporation.16 There is no economic basis for excluding

these companies on the basis of the S&P classification.17 Several of these

companies have have been included in electric proxy groups in the recent past.

Constellation Energy, Exelon Corporation, PPL Corporation, Public Service

Enterprise Group and Sempra Energy were included in the national proxy

15 In a data request, SCE asked Mr. Keyton to provide a specific citation to a Commission

decision which adopted criterion (1)(b). Mr. Keyton could not provide such a citation. Exhibit SCE-50, p. 1.

16 At page 14 of Exhibit S-7, Mr. Keyton refers to page 63 of Exhibit S-9 as containing the companies that satisfy both the Value Line and S&P criteria. There are 44 companies in this list. I obtained the missing ten companies by comparing a list of all the Value Line electric utilities with Mr. Keyton’s list on page 63.

17 Some of these companies are reasonably excluded for other reasons.


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group that formed the basis for the Commission’s DCF ROE estimate in the

April 15 Order. Although the estimates for four of these companies were later

removed because of growth rate considerations consistent with Commission

precedent, they were and are appropriate candidates for proxy group inclusion.

No other witness in this case has proposed using this criterion to limit the

proxy group.

In addition, I must point out that Mr. Keyton’s definition of an S&P

electric utility is inaccurate. At pages 8 through 15 of Exhibit S-9, Mr. Keyton

reproduces an S&P report that lists U.S. regulated electric utilities. However,

there are companies that S&P classifies as electric utilities that are not included

in Mr. Keyton’s list. For example, S&P’s RatingsDirect service (available by

subscription) contains a list of electric utilities in the United States. SCE has

reproduced this list in Exhibit SCE-52.18 This list includes Central Vermont

Public Service, Constellation Energy, Exelon Corporation, and PPL

Corporation.

(2) S&P corporate credit rating ranging from “BBB” to “A-.” This is a

standard Commission criterion and I employ the same criterion.

(3) Value Line safety rank of 3. The use of this criterion is

18 SCE has removed the credit rating information in the list, as this is S&P’s proprietary

information.


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unreasonable. The Commission specifically rejected this criterion in the April

15 Order.19 In addition, this selection criterion should not be used because the

Value Line Safety Rank is not observed for SCE, and there is no reason to

believe that SCE’s Value Line Safety Rank would be the same as the Value

Line Safety Rank for its parent company, Edison International, if it did exist.

For example, while the Standard & Poor’s issuer credit rating for SCE is

BBB+, the Standard & Poor’s issuer credit rating for Edison International is

only BBB- at the present time.

I have examined Mr. Keyton’s safety rank data that he presents on page

63 of Exhibit S-9. This is a list of 44 companies which are classified as

electric utilities by Value Line and Standard & Poor’s, according to Mr.

Keyton. Taking the list of 44 companies, the S&P corporate credit ratings, and

the Value Line safety rankings, I am able to produce the following table that

relates the S&P corporate credit ratings to the Value Line safety rankings:



1 S&P Corporate Credit Ratings and Value Line Safety Rankings S&P Corporate Credit

Rating Value Line Safety

Ranking Number of Companies

in Category 1 1 2 0 A+

3 0 1 1 2 0 A

3 0 1 1 2 4 A-

3 1 1 0 2 7 BBB+

3 2 1 0 2 4 BBB

3 11 1 0 2 3 BBB-

3 7 1 0 2 0 BB+

3 0 1 0 2 0 BB

3 1 2

3

4

5

Focusing on the rows for S&P corporate credit ratings A-, BBB+, and

BBB, what the table shows is that applying a requirement that companies have

a Value Line safety rank of 3 would exclude five A- companies, seven BBB+


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companies, and four BBB companies. (These companies are indicated by the

shaded areas in the table.) Of the 30 companies that have these three S&P

corporate credit ratings, application of Mr. Keyton’s Value Line safety rank

criterion excludes 16 of them, more than half. This amounts to discarding an

enormous amount of useful information directly relevant to SCE’s cost of

equity capital based on an arbitrary criterion that the Commission has already

rejected. Application of this criterion is unreasonable.

(4) One billion dollars in annual revenues. This is a standard

Commission criterion and I employ the same criterion, with the qualification

that I (and the Commission) apply the criterion to electric revenues, not total

revenues. As my proxy group was adopted in many respects in the April 15

Order, 20 use of electric revenues is correct. In other words, Mr. Keyton does

not explain why the criterion that the Commission already approved is no

longer appropriate for use in this case and should be replaced by his own.


Paragraph 38, in particular, references annual electric revenues.


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(5) S&P utility business risk profile of excellent or strong and (6) S&P

utility financial risk profile of intermediate, significant, or aggressive. Use of

these criteria is inappropriate and inconsistent with precedent. The

Commission’s April 15 Order does not recognize these criteria and Mr. Keyton

does not explain why he deviated from the Commission’s decision here.

There is good reason why the Commission would not have used these

additional criteria. The S&P business risk profile and the S&P financial risk

profile are integral parts of the methodology that S&P uses to come up with

corporate credit ratings, as can be seen by inspection of the S&P criteria

methodology article included in Mr. Keyton’s testimony in this docket.

Exhibit S-9, pp. 57-62. As such, the information represented by these two

criteria is already accounted for by criterion (2), the range of the S&P

corporate credit rating. The only function of using these two additional criteria

is to exclude companies that should be included by virtue of their credit rating,

but that may have some factor not captured by the business risk profile and

financial risk profile. This is inappropriate. The S&P article points out this

very problem: in the section titled “How To Use The Matrix—And Its

Limitations,” the article states: “The rating matrix indicative outcomes are

what we typically observe—but are not meant to be precise indications or

guarantees of future rating opinions. Positive and negative nuances in our

analysis may lead to a notch higher or lower than the outcomes indicated in the


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various cells of the matrix.” Id., p. 60. Accordingly, to the extent that these

criteria have an effect, it is to unreasonably limit the members of the proxy

group.

(7) Dividend. Mr. Keyton employs a three-prong dividend criterion.

This criterion is too stringent, as it excludes companies that have reduced their

dividend level within the past three years. The April 15 Order only recognizes

“electric utilities that paid dividends” as a criterion.21 Excluding companies

that have reduced their dividend level within the past three years is not

reasonable, because the DCF calculation does not use dividend payments

before the beginning of the DCF calculation period (the first six months of

2010 for Mr. Keyton’s analysis). Mr. Keyton’s dividend criterion should be

revised so that it is consistent with the Commission’s April 15 Order and not

more restrictive.

(8) No announced or pending merger or spinoff activity during the DCF

period. I employ this criterion, but with the qualification that the merger or

spinoff activity be significant. My criterion for significance is that the merger

or spinoff involve more than five percent of the company’s assets. I revisit this

topic in particular instances below.

21 Southern California Edison Company, 131 FERC ¶ 61,020 (2010), at P 52.


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(9) Five-year earnings growth estimate listed on Yahoo! Finance. I

have no objection to this criterion; I believe that it is effectively the same as a

similar criterion that I use in my modeling, that a five-year IBES earnings

growth estimate from Thomson Reuters be available.

Q. What is your view of Mr. Keyton’s criterion (10), which relates to the low-

end DCF result?

A. I believe that the use of this criterion is consistent with the Commission’s April

15 Order. However, because of Mr. Keyton’s small proxy group and the fact

that he uses the median to calculate his proposed ROE, there is a perverse

interaction between his screening of the low-end DCF result and his overall

DCF ROE estimate that makes his recommendation unreasonable. The reason

for the low-end DCF screen is to ensure that DCF estimates that are too low do

not contaminate the overall result. When this approach was adopted in the

2000 Southern California Edison opinion,22 it made sense because in that case,

SCE’s ROE was set at the midpoint of the upper end of the zone of

reasonableness.23 Since the zone of reasonableness was defined by the lowest

and highest DCF estimates for the sample group (and where each company

22 Southern California Edison Company, 92 FERC ¶ 61,070 (2000), at 61,266. 23 Southern California Edison Company, 92 FERC ¶ 61,020 (2010), at 61,266-61,267.


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provided two candidate estimates for inclusion), the midpoint estimate was

used as the basis for SCE’s ROE.24

However, Mr. Keyton removed any company for which the low-end

DCF estimate was below 7.16% (100 basis points above the Moody’s Baa

bond yield).25 This causes him to exclude Integrys Energy Group from his

proxy group.26 However, if he had lowered his low-end DCF exclusion

threshold to 6.97% (81 basis points above the Moody’s Baa bond yield), the

Integrys Energy Group average DCF estimate of 11.46% would have entered

the median calculation, increasing the median estimate from 9.27% to 9.63%.

So reducing the threshold used in the DCF estimate by 19 basis points causes

an increase in the overall DCF median estimate that is nearly double that

amount. This unstable and perverse result obtains because of the small size of

Mr. Keyton’s proxy group and represents an additional reason why his study,

with its very small proxy group, should not be used.

24 Southern California Edison Company, 92 FERC ¶ 61,070 (2000), at 61,265-61.267. 25 Exhibit S-7, p. 20, ll. 19-21. Exhibit S-8, Schedule No. 3, p. 3. A basis point is 1/100th

of one percent. 26 Exhibit S-8, Schedule No. 6, p. 6. The Integrys Energy Group low-end DCF estimate is

highlighted.


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Q. What is your view of Mr. Keyton’s criterion (11), regarding the DCF

model growth rate?

A. Mr. Keyton states that he “rejected DCF model growth rates that were higher

than those rejected by the Commission in the past as being unsustainably

high.” Exhibit S-7, pp. 22-23. This portion of the screen is consistent with

Commission precedent as Mr. Keyton cites it. However, he then utilizes a

second criterion, not found in the Commission’s April 15 order, based on

comparing the growth rate (g) with the proxy group’s median DCF result. This

second criterion, which compares g to k in the DCF equation, is flawed and

unreasonable as Mr. Keyton has applied it.

For reference, the DCF equation is the following:

g

PDk

(1) 12

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Mr. Keyton points out that in this equation, k must exceed g. (Otherwise for

the equality to hold, the dividend D or price P must be negative.) However,

this is only true for each individual company DCF ROE calculation, because it

a purely mathematical condition pertaining to each individual company

estimate. Mr. Keyton tries to apply this to the relationship between individual

company growth rates and the overall median DCF ROE estimate from the

entire proxy group, which is completely wrong, as the k = D/P + g relationship

does not apply to the median estimate for the group as a whole. (There is no

D/P or g for the group as a whole and the group k is derived through the


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median calculation, not the k = D/P + g relationship.) The only reason for

excluding DPL Inc. is the relationship of its growth rate to 13.3%, not to the

median proxy group estimate. (To take the particular estimate that Mr. Keyton

uses to disqualify DPL Inc., it has the following characteristics: k = 19.28%,

D/P = 5.16%, and g = 14.11%. Except for rounding, these values satisfy the k

= D/P + g relationship. The fact that g = 14.11% for DPL Inc. and is higher

than the median k = 9.63% is meaningless because the k = D/P + g relationship

does not apply to the median k.) Mr. Keyton’s mistake demonstrates a

fundamental misunderstanding of the FERC DCF method.

Q. Mr. Keyton explains that “[a] few of the criteria didn’t eliminate any

companies. Nevertheless, for consistency purposes, I believe that it’s

important to show all the criteria I would normally use even if a particular

criterion does not eliminate any companies.”27 How do you respond to

these statements?

A. Based on Mr. Keyton’s filed testimony, these statements do not make sense.

According to his testimony, he has filed cost of capital testimony in two prior

proceedings before the Commission, RP08-306-000 and RP09-487-000.

Exhibit S-7, p. 3. In neither docket does his testimony reference criteria (1)(a),

27 Exhibit S-7, p. 14.


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(1)(b), (5), or (6) as selection criteria for his proxy groups in those dockets.28

(Mr. Keyton does reference the S&P business risk profile in each docket, but

only in the context of determining whether the target company deserves a

return on equity that differs from the median estimate.29) It is not possible to

reconcile his statement that he normally uses these criteria with what he

actually did in the two prior dockets in which he filed testimony.

Q. At page 29 of his testimony, Mr. Keyton claims “slightly more overall risk

for the proxy group relative to SCE.” How do you respond to this

assertion?

A. This assertion is misleading. It is true that the BBB rating of all of Mr.

Keyton’s proxy group members is lower (credit quality) than SCE’s BBB+

rating. However, as I showed earlier, Mr. Keyton selected his proxy group in

such a way (primarily by using the Value Line safety ranking) that he excluded

all of the A- and BBB+-rated companies that should be in the proxy group. In

other words, he is eliminating many companies that have very similar risk

profiles as SCE with the result that he comes up with a very low ROE estimate,

and then turns around and claims he is comparing SCE with a riskier proxy

28 See RP08-306-000, Exhibit S-12; RP09-487-000, Exhibit S-12. 29 RP08-306-000, Exhibit S-12, pp. 30-32, Exhibit S-13, Schedule 8; RP09-487-000,

Exhibit S-12, pp. 31-33, Exhibit S-13, Schedule 8.


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group. If he had used a proxy group with a risk profile closer to that of SCE,

he would have calculated a higher ROE estimate.

In addition, it is important to remember that the DCF model is only

indirectly related to risk; it is primarily related to growth. (Unlike the Capital

Asset Pricing Model, which directly incorporates the risk measure beta, the

DCF model does not directly incorporate any risk measure.) Mr. Keyton’s

proxy group screening excludes the high DCF companies in the A-

/BBB+/BBB space. I believe that it is only coincidental that the remaining

companies, which have lower DCF estimates, are all BBB-rated companies.

Q. At page 33 of his testimony, Mr. Keyton states that “my [his] proxy group

was developed using a more comprehensive risk-based screen than that of

Dr. Hunt …” What is your view of this statement?

A. Mr. Keyton’s screening methodology is more “comprehensive” only in the

sense that he applies more screens, many of which are wrong. My analysis

above demonstrates that Mr. Keyton has “over-selected” his proxy group by

using inappropriate screening criteria. By applying more selection criteria than

I do (and the Commission does), he has arbitrarily eliminated companies with

comparable risk characteristics to SCE and reduced the proxy group to a

number that is much smaller than it should be. The result is that he has

produced a ROE estimate that is distorted and unreasonable.


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Q. At page 34 of his testimony, referring to your discussion of risks faced by

SCE, Mr. Keyton says “to whatever extent these risks exist, they

automatically compensated for in the DCF results.” What is your

response to this statement?

A. This statement is incorrect and indicates that Mr. Keyton does not understand

the DCF analysis. As I mentioned above, the DCF model does not contain a

direct measure of risk. It is easy to come up with a hypothetical

counterexample that disproves Mr. Keyton’s statement: a company facing

imminent bankruptcy. Such a company will have a zero dividend yield and in

all likelihood, a zero growth rate. The DCF estimate for that company will

thus be close to zero. Surely Mr. Keyton would not contend that the required

return for an investor to invest in a company facing imminent bankruptcy is

close to zero.

One of the weaknesses of DCF is that it is not explicitly based on a risk

measure. Dr. Roger Morin, a well-known cost of capital expert, wrote this:

“[T]he DCF model ignores the capital market evidence and financial theory

formalized in the CAPM and other risk premium models.”30

30 Roger A. Morin, New Regulatory Finance, (Arlington, Virginia: Public Utilities Reports,

Inc., 2006), pp. 431.


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B. Capital Structure

Q. Do you agree with Mr. Keyton’s calculation of SCE’s capital structure?

A. No, I do not. There are two main issues that Mr. Keyton’s calculation ignores:

(1) SCE has long-term debt that does not finance rate base; and (2) one must

take account of unamortized expenses, discounts/premiums, and losses on

reacquired debt to correctly calculate the amount of debt in the capital

structure.

Q. What SCE long-term debt does not finance rate base?

A. SCE’s Series 2009B bonds were issued for the purpose of financing SCE’s fuel

inventories.31 SCE’s fuel inventories are not part of SCE’s rate base in this

proceeding, and SCE is not permitted to use the proceeds from these bonds to

finance operating expenses or capital additions. Therefore, the Series 2009B

bonds should be excluded from any capital structure calculation in this docket.

31 The Series 2009B bonds were issued pursuant to authority granted by the CPUC in D.03-

11-018. This decision permits SCE to issue one or more series of debt securities and states in part: “SCE shall apply the proceeds of the indebtedness authorized to finance its fuel oil inventory, nuclear fuel inventories, natural gas fuel inventories, and coal inventory (collectively Fuels) as specified in the Application and shall not use the funds for operating expenses, capital additions or payment of dividends.” D.03-11-018, Ordering Paragraphs 1-2. A copy of D.03-11-018 can be obtained on the Internet at http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/32033.htm.


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Q. Why must one take account of unamortized expenses,

discounts/premiums, and losses on reacquired debt to correctly calculate

the amount of debt in the capital structure?

A. If one does not take account of these items, as Mr. Keyton does not, then the

utility, SCE in this case, will not recover its full cost of capital. I provide an

example in Exhibit SCE-53 that substantiates this point. Exhibit SCE-53

shows that calculating the capital structure in the manner that Mr. Keyton

advocates will cause SCE to under-recover its capital-related costs, particularly

the returns that must be paid to shareholders and bondholders.

Q. So your basic argument is that without consideration of these adjustments,

SCE will under-recover its cost of capital. Could there ever be a situation

where consideration of these adjustments could cause SCE to over-recover

its cost of capital?

A. It is extremely unlikely. A situation of over-recovery could only arise if SCE

consistently issued long-term debt at a premium to its face value. This

situation almost never arises nowadays. The process of issuing long-term debt

normally involves setting a coupon rate that is evenly divisible by five basis

points (such as 6.05% in the case of SCE’s 2009A Series bonds) for

administrative convenience. This rate is typically below the interest rate that

investors will demand for the issue, so the inclusion of a discount when the

issue is actually priced for offer raises the interest rate that investors will earn


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above the coupon rate. We simply don’t observe premiums associated with

debt issues, but only discounts. All of SCE’s currently outstanding long-term

debt issues were issued at a discount or at par (face value).

Q. Doesn’t the “cost of money” calculation that is used in calculating the

embedded cost of long-term debt account for this?

A. The “cost of money” calculation only accounts for it in the context of the cost

of each particular debt issue. It does not fully correct for the fact that SCE can

only finance rate base with the net proceeds of its debt issues, because the

discounts represent funds that are not received at the time of issue. Thus, the

face value of bonds issued exceeds the amount of funds that can actually be

invested in rate base assets. This difference between the face value of bonds

issued and the actual funds received causes the debt ratio to be too high and the

equity ratio to be too low in the capital structure calculation.

Q. How should Mr. Keyton’s capital structure calculation be adjusted?

A. Mr. Keyton’s capital structure calculation should be adjusted to recognize the

adjustments that I have described. The data request response that Mr. Keyton

reproduces at Exhibit S-9, pages 1-7 contains these adjustments. For

comparison with Mr. Keyton’s proposed capital structure at Exhibit S-8,

Schedule 1, page 1, the correct ratios should be as shown in the far right-hand

column of Exhibit S-9, page 7:


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Long-term debt: 42.94% Preferred equity: 5.92% Common equity: 51.14%

C. Costs of Long-Term Debt and Preferred Equity

Q. Do you agree with Mr. Keyton’s update of SCE’s projected costs of long-

term debt and preferred equity?

A. No, I do not. Mr. Keyton is assuming that SCE’s recorded costs of long-term

debt and preferred stock on a single date in 2010 is an accurate projection of

the average cost for the entire year. On the contrary, correct updated costs

would be 6.06% for long-term debt and 5.99% for preferred equity, not 6.07%

and 5.63% as Mr. Keyton recommends. These updated costs estimate the

average cost of long-term debt and preferred equity for the entire year, and are

not merely snapshot values, such as Mr. Keyton uses.32 The correct updated

costs are supported by Exhibits SCE-54 and SCE-55.

Q. Your updated cost of long-term debt is very close to Mr. Keyton’s

recommendation, but your updated cost of preferred equity is not. Why is

this?

32 Mr. Keyton uses only the June 2010 values for these embedded costs, not even the

quarterly average for the second quarter of 2010, which he requested and which SCE provided. Exhibit S-9, pp. 1, 3, 5. It should be noted that all of the monthly values shown on these pages are as of the end of the month. That is why four values are shown in computing the quarterly average.


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A. This result occurs because SCE is projecting that it will issue preferred equity

during the fourth quarter of 2010. Because Mr. Keyton’s recommended cost of

preferred equity is based only on data from the first half of 2010, it cannot

properly account for this.

IV. RESPONSE TO SIX CITIES TESTIMONY REGARDING COST OF 5

CAPITAL

Q. What areas of Mr. Solomon’s testimony are you addressing?

A. Mr. Solomon’s testimony contains his analysis of SCE’s cost of equity capital

and comments on my direct testimony regarding cost of capital. I will address

Mr. Solomon’s analysis first.

A. Response to Mr. Solomon’s Analysis of SCE’s Cost of Capital

Q. Overall, is Mr. Solomon’s DCF analysis very different from the one you

are presenting as an update in this rebuttal testimony?

A. No. There are minor differences between Mr. Solomon’s proxy group and my

proxy group, and in Mr. Solomon’s calculation of the fundamental growth rate

versus mine, but overall he applies the FERC methodology consistent with the

April 15 Order. The differences between his numerical recommendations and

mine are based on two major factors. First, he disagrees with my use of the

midpoint rather than the median to set the ROE. Second, his data have a

different vintage than mine. If he were to update his analysis to use the most

recent data, as I have in this testimony, his analysis would produce median and

midpoint ROE estimates that are within a few basis points of my estimates.


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Q. What time period did Mr. Solomon use for his DCF analysis?

A. Mr. Solomon used the six-month period ending with May 2010. Exhibit SC-1,

p. 8, ll. 10-12.

Q. Did Mr. Solomon use the same proxy group selection criteria that you

did?

A. Implicitly, he did. He states in his testimony: “[A]s shown on Exhibit No. SC-

2, my twenty-three company group is the same as Dr. Hunt's, except that my

group does not include [three companies].” Exhibit SC-1, pp. 7-8. Dr.

Solomon excluded three companies on the basis of annual revenues and merger

activity.

Q. Do you and Mr. Solomon differ on the application of the revenue

criterion?

A. No, I believe not. Mr. Solomon excludes Cleco Corporation from his proxy

group on the basis of its annual revenues. Exhibit SC-1, p. 8, ll. 2-3. Were I

performing my analysis for the same period (the six-month period ending with

May 2010), I would apply the same exclusion. With regard to Vectren

Corporation, which I exclude because its electric revenues are too low, Mr.

Solomon does not include it in his proxy group either. Exhibit SC-2, p. 1.

Q. How do you differ in the application of the merger or acquisition activity

criterion?


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A. Mr. Solomon excludes FirstEnergy and PPL Corporation on the basis of M&A

activity, but does not appear to exclude Integrys Energy or Pepco Holdings on

this basis. Exhibit SC-1, p. 8, ll. 4-8. Integrys Energy sold its wholesale

electric marketing and trading business during Mr. Solomon’s DCF analysis

period and Pepco Holdings sold Conectiv generating assets during this period.

The transactions are sufficiently large that these companies should have been

excluded from Mr. Solomon’s proxy group. For example, the Integrys Energy

transaction involved a sale of approximately 16 percent of its assets,33 while

the Pepco Holdings transaction involved a sale of approximately 10 percent of

its assets.34

Q. Are there any companies that Mr. Solomon incorrectly excluded?

A. Yes. Mr. Solomon should have included Exelon Corporation in his proxy

group. To my knowledge, Exelon Corporation meets all of the criteria that Mr.

Solomon used. (Exelon meets each of his six criteria: (1) covered by Value

Line; (2) has an S&P corporate credit rating of BBB; (3) has annual electric

33 Integrys Energy’s wholesale electric marketing and trading business had assets of $1.849

billion as of December 31, 2009, compared to Integrys Energy’s total assets of $11.848 billion on the same date. Integrys Energy, Form 10-K, dated February 25, 2010, pp. 28, 95.

34 The purchase price of the Conectiv generation assets is $1.65 billion. Pepco Holdings, Form 8-K, dated April 20, 2010, Item 1.01, p. 2. On March 31, 2010, Pepco Holdings had total assets of $15.832 billion. Pepco Holdings, Form 10-Q, dated May 7, 2010, p. 4.


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revenues of approximately $16.6 billion; (4) was not engaged in merger or

significant acquisition activity after July 2009; (5) paid dividends during the

analysis period and is expected to continue to pay dividends; and (6) is covered

by approximately 20 analysts.) It is possible that Mr. Solomon started with my

proxy group and did not realize that Exelon Corporation withdrew its offer for

NRG Energy on July 22, 2009,35 and is no longer excluded on the basis of the

M&A criterion.

According to my data, Mr. Solomon also should have included

IDACORP in his proxy group. To my knowledge, IDACORP meets all of the

criteria that Mr. Solomon used. (IDACORP meets each of his six criteria: (1)

covered by Value Line; (2) has an S&P corporate credit rating of BBB; (3) has

annual electric revenues of approximately $1.1 billion; (4) was not engaged in

merger or significant acquisition activity during the analysis period; (5) paid

dividends during the analysis period and is expected to continue to pay

dividends; and (6) is covered by approximately four analysts.) I do not know

why he did not do this.

35 Mr. Solomon writes: “my twenty-three company group is the same as Dr. Hunt’s, except

that my proxy group does not include Cleco Corporation …, FirstEnergy Corporation …, or PPL Corporation. Exhibit SC-1, p. 7, l. 23 through p. 8, l. 3.


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Q. In discussing his proxy group selection criteria, Mr. Solomon states that

“[e]xcept for the sixth criterion, SCE witness Hunt applied the same

criteria to develop his … national proxy group.”36 Is Mr. Solomon

correct?

A. Yes, he is correct with respect to my original DCF analysis found in Exhibit

SCE-18. However, in my updated estimates, presented later in this rebuttal

testimony, I do include a criterion related to the number of analysts who cover

a particular company, which corresponds to Mr. Solomon’s sixth criterion.

Q. You say that the differences between Mr. Solomon’s estimates and yours

are only a few basis points. Can you provide more specific details?

A. Yes. Exhibit SCE-56 provides a comparison of my May 2010 DCF estimates

with Mr. Solomon’s estimates.37 While there are a few variations between us

in dividend yields and I/B/E/S growth rates, the only consistent differences are

found in the calculation of the v component of the fundamental growth rate.

Q. How do these differences arise?

A. These differences primarily result from the calculation of the v component of

the fundamental growth rate. v is calculated as one minus the inverse of the

36 Exhibit SC-1, p. 7, ll. 22-23. 37 Mr. Solomon’s data are taken from a data request response that Six Cities provided to

SCE. These data can also be found in Exhibit SC-2.


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market-to-book ratio38 (or the price-to-book ratio, as Mr. Solomon describes

it), according to the following equation:

BVMV

v 11 (2)

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where MV is the company’s market value per share (stock price) and BV is the

company’s book value per share.39

Inspection of the spreadsheet formula that underlies Mr. Solomon’s

calculation of v at Exhibit SC-2, page 6 reveals that he calculates v according

to equation (2) above. However, there is a difference between us regarding the

calculation of the book value.

Both of us calculate the stock price, or MV in the v calculation, as the

average over the six-month period used to calculate the dividend yield for the

DCF ROE calculation. To be comparable, the book value needs to be

calculated as an average over the same period. I do this,40 but Mr. Solomon

38 Exhibit SCE-17, p. 27, ll. 13-15. 39 I describe this calculation in text at Exhibit SCE-17, p. 27, ll. 13-15. The formula is

presented in Mr. Keyton’s Exhibit S-9, pp. 84, 86, 88, 90, 92, 94, 96, 98, 100, 102, 104, 106. Mr. Keyton uses P to denote the market price and B to denote the book value. M-S-R witness Dr. Lesser calculates v differently, but he also calculates s differently as well, so that his calculation of the product sv is the same as mine.

40 For the book value calculation, I use an average of the end-of-month values over a seven-month period, which is equivalent to a six-month average of average monthly values, matching the calculation of the stock price over a six-month period.


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does not. Instead, Mr. Solomon uses an estimate of the book value one month

beyond the end of the period over which he calculates the average stock

price.41

Because book value increases over time,42 this causes Mr. Solomon to

overstate the book value and understate v. This is easier to see if equation (2)

is rewritten as

MVBVv 1

(3) 7

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Higher BV lowers v.

Q. Do the differences in the calculation of BV and v result in a large

difference in your DCF estimates, compared to Mr. Solomon’s?

A. No. For individual companies, the difference in our fundamental (br+sv)

growth rates ranges from minus two to nine basis points, averaging about two

basis points. Exhibit SCE-56, p. 3.

41 Mr. Solomon’s average stock price is calculated over the period from December 2009

through May 2010. Exhibit SC-2, pp. 2-5. His book value is calculated as of the end of June 2010. This can be seen by inspection of Exhibit SC-2, p. 6. In the lower block of the table, the book value (“Jun-10 BV”) is calculated as the average of the end-of-year values for 2009 and 2010.

42 For every company in Mr. Solomon’s proxy group except Pepco Holdings (which should not be in Mr. Solomon’s proxy group in the first place), the book value for 2010 is greater than the book value for 2009. Exhibit SC-2, p. 6, columns “2009 BV” and “2010 BV.”


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Q. What is your response to Mr. Solomon’s comments regarding the price-to-

book or market-to-book ratio?

A. Mr. Solomon’s argument is incorrect. He cites a Commission decision as

stating that “"when the price-to-book ratio is greater than one, the rate of return

investors expect [the company] to earn on common equity is greater than the

rate of return investors require from their investment in [the company's]

common stock.” Exhibit SC-1, p. 12, ll. 1-4. This statement can only be true,

however, if the investment was purchased when the market value of an

investment in the company’s common stock was equal to the book value of

that investment.

The DCF model, because it uses a market price in the denominator of

the dividend yield calculation, produces a market return on equity. If the

market-to-book ratio of a stock is greater than one, then a new investor who is

seeking to earn the market return on equity will not purchase the stock until the

stock price has fallen to equal book value, unless the book return on equity is

set higher than the market return on equity. Expressed somewhat differently,

the investment made by a new investor is measured at the market price he or

she pays and the return that investor will require is the DCF return applied to

that market-valued investment. If the book value rate base to which the DCF

return is applied is less than the market-valued investment, the investor will not

earn his or her required return.


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Commenting on the DCF model, Dr. Roger Morin, a well-known cost of

capital expert, wrote:

The third and perhaps most third and perhaps most important reason for caution and skepticism [regarding DCF estimates of ROE for utilities] is that application of the DCF model produces estimates of common equity cost that are consistent with investors’ expected return only when stock price and book value are reasonably similar, that is, when M/B is close to unity. As shown below, application of the standard DCF model to utility stocks understates the investor’s expected return when the market-to-book (M/B) ratio of a given stock exceeds unity. … The converse is also true, that is, the DCF model overstates the investor’s return when the stock’s M/B ratio is less than unity. The reason for the distortion is that the DCF market return is applied to a book value rate base by the regulator, that is, a utility’s earnings are limited to earnings on a book value rate base. 43

Since the market-to-book (or price-to-book) ratio of Mr. Solomon’s

proxy group companies substantially exceeds one, it follows that his DCF ROE

estimate substantially undercompensates investors when it is applied to a book

value rate base.

Q. Can you provide an estimate of the magnitude of this problem?

A. Yes. In his book,44 Dr. Roger Morin starts with the standard DCF formula for

price as a function of dividend, required return on equity, and growth. He then

develops a formula that expresses the DCF cost of equity (K) as a function of

43 Roger A. Morin, New Regulatory Finance, (Arlington, Virginia: Public Utilities Reports,

Inc., 2006), pp. 434. 44 Roger A. Morin, New Regulatory Finance, (Arlington, Virginia: Public Utilities Reports,

Inc., 2006), p. 360.


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the book return on equity (r), the market-to-book ratio (M/B), and the retention

ratio (b).45 His formula can be rearranged to produce the following

relationship:

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BMb

KBM

r (4) 4

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Given the DCF estimated return on equity, the retention ratio and the market-

to-book ratio, equation (4) can be solved for r.

Mr. Solomon derives a DCF ROE estimate of 9.94%,46 which as I show

below, would be 10.30% if updated to the latest information. He cited a 1.37

price-to-book ratio (M/B) for his adjusted proxy group in his testimony.47

From the same table that shows the 1.37 price-to-book ratio, the average value

of the retention ratio b can be derived from the “2010-14 Avg b” column. It is

equal to 0.3729.

So for this example, K = 9.94% = 0.0994, M/B = 1.37, and b = 0.3729.

Inserting these values into equation (4) and solving for r, we find that r equals

11.96%. This is the return on equity that must be applied to the book value

45 The retention ratio is the fraction of earnings not paid out as dividends. 46 Exhibit SC-1, p. 10, ll. 6, 14. 47 Exhibit SC-1, p. 12, ll. 22-23. Exhibit SC-3, p. 28, bottom row.


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rate base to produce a market return of 9.94% for investors.

Q. It seems as though you are just reinforcing Mr. Solomon’s findings, since

his two average expected earned ROEs are 10.77% and 11.38%.48 What is

the difference?

A. Mr. Solomon turns the reader’s attention away from the critical finding. He

says that his expected earned ROEs are “an indication that the investors’

required ROE is substantially lower than the companies’ average expected

earned ROE.” Exhibit SC-1, p. 12, ll. 10-11. This is true as a numeric

comparison. However, he fails to make clear the critical distinction between

the required ROE on a market-valued asset and the expected ROE on a book-

valued asset. Investors can only realize the required ROE on a market-valued

asset (their shares in the company) if the company achieves the expected ROE

on the book-valued asset (rate base). But the Commission’s standard

ratemaking practice is to apply the required ROE on the market-valued asset

(the DCF estimate) directly to the book-valued asset (rate base) without any

adjustment. Investors are short-changed, since the utility is put at a

disadvantage in trying to achieve the expected ROEs calculated by Mr.

Solomon.

48 Exhibit SC-1, p. 12, ll. 19, 23.


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B. Response to Mr. Solomon’s Comments on my Analysis

Q. Mr. Solomon argues that your original analysis violated several aspects of

the April 15 Order. What is your response?

A. I produced my original analysis before the April 15 Order was issued. My

original analysis is updated in this testimony. The updated estimates follow

the procedures established in the April 15 Order.

Q. Are there any significant differences between the way that you now

estimate the DCF ROE and how Mr. Solomon estimates the DCF ROE?

A. No, except for the difference in calculating the v component of the

fundamental growth rate, which I have already discussed.

V. RESPONSE TO CPUC (COSMAN) TESTIMONY REGARDING COST 11

OF CAPITAL

Q. What is your overall response to Mr. Cosman’s return on equity

recommendation?

A. Mr. Cosman’s analysis is inconsistent with the methodology approved by the

Commission in several respects and his resulting recommendation is too low.

In examining Mr. Cosman’s estimates in detail, I found numerous errors and

inconsistencies with FERC precedents regarding DCF calculations. In

addition, Mr. Cosman’s general commentary contains substantial errors. Here

is a summary list of the deficiencies that I have identified in Mr. Cosman’s

exhibits:

Mr. Cosman incorrectly selected the proxy group for his analysis.


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Mr. Cosman’s fundamental growth calculation is wrong.

Regarding the DCF growth rate, Mr. Cosman incorrectly uses Zack’s

growth rate data, not I/B/E/S growth rate data.

His dividend yield calculation is not consistent with the Commission-

approved method.

Mr. Cosman’s exhibit incorrectly calculates the DCF zone of

reasonableness.

Because of these flaws, Mr. Cosman’s estimates should not be used by

the Commission in this docket. In addition to his DCF modeling errors, Mr.

Cosman presents other analysis that is misleading or incorrect, as I explain

below.

A. Response to CPUC DCF Analysis

Q. You claim that Mr. Cosman incorrectly selected his proxy group. What

evidence supports your claim?

A. I do not have the data that Mr. Cosman used to select his proxy group, as he

did not provide it in workpapers, and he did not provide it in response to a data

request. SCE-CPUC-L002 Q 1 (Exhibit SCE-50, p. 2). I have used my own data

to reproduce Mr. Cosman’s proxy group criteria as closely as I can. Based on

his own methodology (Exhibit PUC-1, p. 56, ll. 2-12), Mr. Cosman should have

included the following companies in his proxy group: CenterPoint Energy,

Dominion Resources, Duke Energy, Exelon Corporation, Great Plains Energy,


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IDACORP, NextEra Energy, Northeast Utilities, OGE Energy, Portland

General, Public Service Enterprise Group, TECO Energy, Westar Energy, and

Xcel Energy. Mr. Cosman does not provide an explanation as to why these

companies were not included in his proxy group. Also based on his own

methodology, Mr. Cosman should have excluded the following companies

from his proxy group: FirstEnergy (pending merger with Allegheny Energy),

Integrys Energy (substantial sale of assets), Pepco Holdings (substantial sale of

assets), and Vectren Corporation (insufficient electric revenues). Again, Mr.

Cosman does not provide an explanation of why these companies were not

excluded.

Q. What is your conclusion regarding Mr. Cosman’s proxy group?

A. It appears to be arbitrarily selected and inconsistent with the methodology he

claims to have employed. This fact alone should be sufficient to disregard his

conclusions.

Q. Mr. Cosman says that he used “revenue above $1 billion” as a proxy

group criterion. Vectren Corporation has annual revenues that exceed $1

billion. Why should it be excluded from Mr. Cosman’s proxy group?

A. Vectren Corporation should be excluded from the proxy group because its

electric revenues do not exceed $1 billion. The Commission’s April 15 Order

largely adopted SCE’s proxy group, but for changes having to do with the

growth rate and low-end DCF estimates. SCE’s proxy group in that docket


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was screened on electric revenues49 and Vectren Corporation was not a

member of the proxy group.50

Q. Are Mr. Cosman’s fundamental growth rates calculated correctly?

A. No, they are not. In his testimony, Mr. Cosman writes: “The growth rates I

utilized came from Value Line Investment Survey and Zack’s Investment

Survey.” Exhibit PUC-1, p. 57, ll. 5-6. Turning to his actual calculations, page

10 of Exhibit PUC-2 contains Mr. Cosman’s DCF ROE estimates. One of the

columns is labeled “Sustainable Growth/Value Line.” This is Mr. Cosman’s

name for the fundamental growth rate. It turns out that the numbers in this

column are not even growth rates--they are Value Line earnings per share

estimates for the companies for the 2013-15 period. They are not even

expressed in the same units (they are expressed as dollars per share, not

percentages per year). The first clue that these are earnings estimates and not

growth rates is that all of the numbers end with either zero or five--Value Line

rounds earnings per share estimates to the nearest nickel. To verify that they

are earnings estimates, all one needs to do is to inspect the Value Line data

49 Docket No. ER08-375-000, Exhibit SCE-7 (Acc. No. 20071228-0069), p. 19, December

21, 2007. Southern California Edison Company, 131 FERC ¶ 61,020 (2010), at PP 38, 51-52. Paragraph 38, in particular, references annual electric revenues.

50 Docket No. ER08-375-000, Exhibit SCE-7 (Acc. No. 20071228-0069), p. 19, December 21, 2007.


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provided by Mr. Solomon, Six Cities’ ROE witness at Exhibit SC-2, page 6.

Many of the purported growth rates in the Sustainable Growth column in Mr.

Cosman’s DCF results also appear in Mr. Solomon’s table in the top block

under the heading “2014 EPS.” The footnote explains that these data are “the

average for the period 2013-15.” Mr. Solomon also provides the supporting

Value Line pages in Exhibit SC-3, plus some Value Line pages for a few

companies that Mr. Solomon did not retain in his proxy group. In the Value

Line pages, there is a large table containing various financial data. The 2013-

15 earnings per share estimate appears on the right-hand side, under the

heading “2013-15” and on the line labeled “Earnings per share A.” Although

not in Mr. Solomon’s table on page 6 in Exhibit SC-2, the relevant estimates

for FirstEnergy Corporation and PPL Corporation can be found in Mr.

Solomon’s supporting Value Line pages. Exhibit SC-3, pp. 9, 18. Again, these

pages show that Mr. Cosman’s growth rates are really earnings per share

estimates and not growth rates at all. Mr. Solomon’s supporting Value Line

page for Wisconsin Energy shows an earnings per share estimate of $4.75 per

share and not an earnings per share estimate of $5.00, which would match the

growth rate in Mr. Cosman’s table, but a Value Line page dated June 25, 2010,

which Mr. Cosman could have used, shows an earnings per share estimate of

$5.00 for Wisconsin Energy, which matches Mr. Cosman’s growth rate. See

Exhibit SCE-57. This leaves only Entergy Corporation and Vectren


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Corporation. I have provided the relevant Value Line pages in Exhibit SCE-

57, and they show 2013-15 earnings per share estimates that match Mr.

Cosman’s purported growth rates for these companies.

In a data request, SCE asked the CPUC to provide “the precise

mathematical formulae used to calculate the b, r, s, and v terms discussed at

Exhibit PUC-1, page 57, lines 11-17.” The CPUC responded that “Mr. Cosman

did not calculate the b, r, s, and v terms.” SCE-CPUC-L002 Q 2 (Exhibit 50,

pp. 2-3). Compare this response with the exhibits provided by all of the other

ROE witnesses in this docket, which provide detailed data and calculations

regarding these variables.

Q. What is your conclusion from the above analysis?

A. Mr. Cosman has confused the fundamental growth rate with earnings per share.

These are entirely different measures, and use of earnings per share in the DCF

analysis as a substitute for the fundamental growth rate is inappropriate.

Q. Mr. Cosman says that he uses the Zack’s growth rate in place of the

I/B/E/S growth rate. Do you have any comment on this substitution?

A. The Commission requires use of I/B/E/S growth rates. Mr. Cosman claims that

I/B/E/S growth rate data are not publicly available and the CPUC does not

have access to them. As a first matter, I/B/E/S growth rate data can be

purchased. In addition, Mr. Cosman’s testimony indicates that he relied on

data from Yahoo! Finance. Exhibit PUC-1, pp. 55-56. Yahoo! Finance provides


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analyst estimates at http://finance.yahoo.com/q/ae?s=XXX, where “XXX” is

the ticker symbol for the company of interest. The long-term earnings growth

estimate is found three rows up from the bottom on this Yahoo! page, with the

row heading “Next 5 Years (per annum).” My experience is that this estimate

is very close to, if not identical to, the I/B/E/S estimate.

My affidavit submitted to the Commission on June 21, 2010 in Dockets

ER09-187/ER10-160, which responded in part to an affidavit submitted earlier

by Mr. Cosman, and which was available to Mr. Cosman before he filed his

testimony in this proceeding, discussed these same facts.51 Given these facts,

Mr. Cosman does not explain adequately why he did not use I/B/E/S growth

rates in order to comply with Commission precedent. In short, I/B/E/S growth

rates were available to use even if the CPUC chose not to acquire them directly

for purposes of this case.

Q. Does Mr. Cosman’s dividend yield calculation comply with the

Commission-approved method?

A. No. Mr. Cosman indicates that his dividend yield is calculated “by dividing

the annual dividend by the stock price.” Exhibit PUC-1, p. 56, l. 21. He then

goes on to explain that he estimates a high dividend yield by dividing the

51 Docket Nos. ER09-187-000/ER10-160-000, Affidavit of Paul T. Hunt for Southern

California Edison Company (Acc. No. 20100621-5106), P 23, dated June 21, 2010.


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average annual dividend by the average low price and a low dividend yield by

dividing the annual dividend by the average high stock price. Exhibit PUC-1,

p. 56, ll. 21-24.

This does not conform to FERC practice. The FERC-approved

methodology is set forth in prior cases.52 The Commission-approved approach

is to calculate a high and low dividend yield for each of the six months, then

average the low dividend yields across the six months to get the low dividend

yield for the DCF calculation, then to perform a similar averaging across the

high dividend yields to get the high dividend yield for the DCF calculation.53

This is the methodology that SCE used in its original DCF analysis in this

proceeding, and the Commission did not alter it in its April 15 Order. For

comparison purposes, FERC Staff witness Mr. Keyton and Six Cities’ witness

52 Virginia Electric and Power Company, 123 FERC ¶ 61,098. (“VEPCO Order”) Footnote

58 in this order, at paragraph 67, references Golden Spread Electric Cooperative, Inc. v. Southwestern Public Service Co., 115 FERC ¶ 63,043 at P 100 and Exhibit S-1, Schedule No. 10 (submitted in Docket Nos. EL05-19-002/ER05-168-001, Acc. No. 20060525-0189; this schedule may actually be in Exhibit S-2).

53 Exhibit S-1 in the Golden Spread docket (submitted in Docket Nos. EL05-19-002/ER05-168-001, Acc. No. 20060525-0189) refers to the “Commission-preferred, most recent six-month average low and high dividend yields.” (Exhibit S-1, p. 24.) The calculations are illustrated at Workpapers 1, 5, 9, and 13, found at pages 1, 5, 9, and 13 of Exhibit S-3 in Docket Nos. EL05-19-002/ER05-168-001 (Acc. No. 20060525-0191). The average low and high dividend yields calculated on these pages are the same as the low and high unadjusted dividend yields found in Exhibit S-1 (or S-2), Schedule No. 10 referenced in footnote 12.


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Mr. Solomon appear to have calculated the dividend yields correctly.

Q. On page 10 of Exhibit PUC-2, Mr. Cosman presents details of his DCF

estimates. Are the “ZONE MAX” (13.22%) and “ZONE MIN” (8.11%)

numbers at the bottom of the page correct?

A. Assuming that these numbers are intended to show the maximum and

minimum values of the zone of reasonableness, they are not correct, as they are

calculated from the company-average DCF estimates, not the individual low

and high DCF estimates for each company, as is standard FERC practice.54 By

way of comparison, FERC Staff witness Mr. Keyton and Six Cities witness

Mr. Solomon show the correct way to perform this calculation.55

It appears that Mr. Cosman understands the correct way to do this

calculation, but for unexplained reasons did not do it correctly in his testimony.

SCE requested that the CPUC provide electronic copies of all workpapers,

including computer spreadsheets, that Mr. Cosman used to develop his

54 For example, in Atlantic Path 15, LLC, 122 FERC ¶ 61,135, P 20 (2008), the

Commission found a zone of reasonableness ranging from 7.63% to 13.67%. Inspection of Exhibit ATL-7 from that docket reveals that the range is based on individual low and high DCF estimates for each company. Docket No. ER08-374-000, Exhibit ATL-7 (Acc. No. 20071227-0154), p. 2. This is standard FERC practice for calculating the range of reasonableness that other witnesses in this case have correctly employed.

55 Exhibit S-8, Schedule No. 7, p. 8, “Absolute low” and “Absolute high” correctly display the zone of reasonableness for Mr. Keyton’s proxy group. Exhibit SC-2, p. 1, l. 27 correctly displays the zone of reasonableness for the Mr. Solomon’s proxy group.


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testimony. One of the spreadsheets that the CPUC provided was a copy of

Appendix C of Exhibit PUC-2, which contains page 10. Interestingly, the

spreadsheet contains the correct calculation of “ZONE MAX” and “ZONE

MIN,” which take the values 7.53% and 16.57%. Exhibit SCE-50, p. 7. Since

Mr. Cosman appears to have done the calculation correctly in his workpapers,

it is unclear why incorrect values were included in Mr. Cosman’s testimony.

B. Response to Other Aspects of CPUC Affidavit and Exhibits

Q. Mr. Cosman claims that “SCE’s assertion about uncertain regulatory risk

in California directly contradicts its neighboring IOU to the north…”

How do you respond to his comment?

A. Mr. Cosman quoted from PG&E Corporation’s 2008 Annual Report. SCE is

not Pacific Gas & Electric Company, nor PG&E Corporation, its parent.

Statements by PG&E Corporation do not reflect SCE’s situation. In addition, I

think that the Standard & Poor’s rating report on SCE, which is found in

Exhibit S-9 at pages 25-34, is instructive. Under the heading of “Weaknesses,”

this report includes the following: “California energy policy is complex and

dynamic and has shown itself capable of introducing rapid change that could

upend what currently is a stable environment for regulated electric utilities;

aggressive renewable and carbon policies are introducing changes to electricity

regulation and markets that are unprecedented, as compared with most other

regions of the U.S.”


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Q. How do you respond to Mr. Cosman’s comments regarding procurement

risk?

A. Mr. Cosman claims that SCE faces no risk concerning procurement of energy.

This is incorrect. All of SCE’s procurement activities are subject to review by

the CPUC and there is an annual proceeding, which commences on April 1 of

each year, that reviews SCE’s energy procurement for the prior calendar year.

Q. Mr. Cosman claims that SCE has no competitors. Is that correct?

A. Certainly not. SCE has existing franchise competition from municipal utilities,

community choice aggregation and spot municipalization.

Q. Mr. Cosman comments: “SCE operates in a rate base rate of return cost

of service industry. The latter term, cost of service, means that SCE get to

recover all of its prudently incurred costs. … The risk of bankruptcy is

virtually zero …” Is he correct?

A. Except for the first sentence, these statements are incorrect and indicate that

Mr. Cosman does not understand cost of service ratemaking as it is practiced in

California. California practices cost of service ratemaking with a forecast test

year, which means that with respect to base costs, which include depreciation,

return, capital-related taxes, and operation and maintenance expense, once the

forecast level (the “base rate revenue requirement”) is set, SCE is fully at risk

for its cost performance. Cost recovery for base rate costs only occurs on a

forecast basis, as there is no “true-up” after the fact.


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Mr. Cosman’s statements also fail to reflect the real risks inherent in

operating in a cost-of-service environment. As demonstrated by PG&E’s

bankruptcy during the California energy crisis, a bankruptcy can occur even

when the utility is supposedly allowed to recover prudently-occurred costs.

That is because bankruptcy is also a function of liquidity and cash flow. If cost

recovery does not occur in a timely manner, bankruptcy is still possible. In

fact, SCE avoided bankruptcy during this time only because it reached an

agreement with the CPUC shortly before it ran out of cash.

Q. How do you response to Mr. Cosman’s comments regarding virtual

bidding?

A. Mr. Cosman’s comments do not tell the full story. The second through sixth

pages of Mr. Cosman’s Attachment F (Exhibit PUC-2, pp. 28-32) list several

features that SCE advocated to mitigate risk in Virtual Bidding: (1) only allow

bids at the LAP levels, (2) do not allow virtual bids on the interties, (3) do not

allow virtual bids on the generator nodes, and (4) do not allow virtual bids at

the trading hubs. In contrast, the design submitted to the Commission by the

CAISO does not adopt these features.

In addition, SCE supported specific cost allocation mechanisms for the

uplifts created by Virtual Bids. The CAISO rejected this approach in their

filing at the Commission and has proposed a methodology SCE continues to

object to.


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In summary, the CAISO has filed with the Commission to implement a

much more aggressive approach than SCE advocated for (in Attachment F),

and SCE’s concerns over risk have not been fully mitigated base in the filed

design.

Q. Mr. Cosman says that about 55% of SCE’s revenue requirement is

“protected by balancing account recovery,” and implies that SCE has no

risk on this recovery. Is that true?

A. No. The 55% number is roughly correct, but the implication that SCE has no

risk on this recovery is false. These funds are dominated by SCE’s power

procurement costs, which as I explained above, are subject to annual

reasonableness review by the CPUC. The CPUC has the power to disallow

cost recovery in connection with this review. In addition, SCE’s transmission

costs are subject to this Commission’s exclusive jurisdiction.

Q. How do you respond to Mr. Cosman’s other comments regarding

balancing accounts?

A. Mr. Cosman generally decries the existence of balancing accounts and

legislation related to procurement and transmission construction. These exist

for a reason. SCE is much more exposed to the associated risks than other

utilities. SCE has a much higher percentage of purchased power, especially

from renewable generation, than the typical utility in the United States.

Similarly, SCE’s fossil generation and fossil purchased power are dominated


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by natural gas, not coal, as in most other states. SCE is engaged in one of the

largest transmission investment programs of any utility in the country.

Balancing accounts and legislation exist primarily to bring SCE’s risk profile

into line with the rest of the industry, but they do not eliminate risk for SCE’s

investors. If they did, SCE would have a AAA credit rating, not a BBB+ credit

rating.

Q. How do you respond to Mr. Cosman’s comments on SCE’s Commission-

approved transmission incentives?

A. Mr. Cosman appears determined to wipe out their constructive impact as much

as possible. His proposed ROE of 10.74% (Exhibit PUC-1, p. 61, l. 5), which

includes the positive effect of the FERC-approved incentives, is well below the

current CPUC-authorized ROE for SCE in its retail jurisdiction. Should his

recommendation stand, or the Commission adopt a lower ROE, it will be much

more difficult for SCE management to choose transmission investments over

investments in other parts of SCE’s business.

Q. How do you respond to Mr. Cosman’s comments regarding energy

efficiency incentives?

A. Mr. Cosman does not appear to understand the reason why the CPUC adopted

its energy efficiency (“EE”) incentive program. In the very first CPUC

decision decried by Mr. Cosman, the CPUC wrote: “There is an inherent

utility bias towards supply-side procurement under cost-of-service regulation,


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namely, that investor-owned utilities can generate earnings for shareholders

when they invest in ‘steel-in-the-ground’ supply-side resources, but not when

the utilities are successful in procuring cost-effective energy efficiency.”56 The

CPUC also stated in the same decision: “By aligning shareholder and

consumer interests through today’s adopted incentive mechanism, we create a

‘win-win’ regulatory framework for energy efficiency—one that provides both

a meaningful level of shareholder earnings and an estimated return of over

100% on ratepayers’ investment in energy efficiency as the utilities reach

towards and exceed our 2006-2008 energy savings goals. This return

represents the substantial cost savings created by displacing more expensive

supply-side alternatives with energy efficiency, resulting in lower utility

revenue requirements and lower customer bills.” (Emphasis in original;

footnote omitted.)57 The purpose of the EE mechanism is clear: to induce the

utilities to consider energy efficiency as a resource for meeting energy needs

by providing an incentive which is comparable to supply-side investments. In

its current Rulemaking, the CPUC is reviewing the energy efficiency incentive

mechanism in place for 2006-2008 for future use. The Rulemaking is intended

56 CPUC Decision No. 07-09-043, mimeo, pp. 3-4. 57 CPUC Decision No. 07-09-043, mimeo, pp. 2-3.


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to “consider a more transparent, more streamlined and less controversial RRIM

program”58 for energy efficiency in the future. As such, while the policy for an

energy efficiency incentive mechanism remains, the specific attributes of the

previous mechanism may be modified for the future.

Q. Is Mr. Cosman’s characterization of D.08-01-042 accurate?

A. No. D.08-01-042 focused on the question of how uncertainty caused by after-

the-fact adjustments to energy efficiency savings estimates would impact the

treatment of the energy efficiency incentive mechanism as a workable

mechanism for California. Because of accounting rules, this uncertainty

directly and adversely affected the ability of the utilities to record earnings

under the CPUC’s EE mechanism. While this might appear one-sided, if

utilities cannot record earnings because of uncertainty over the final outcome

of the mechanism, the incentive properties of the mechanism are greatly

reduced. As the CPUC itself stated: “[T]he effectiveness of the incentive

mechanism we adopted in D.07-09-043 will be seriously undermined unless

we take steps to ensure that the utilities are able to book any interim earnings

that we may authorize for portfolio performance.”59

58 CPUC Rulemaking No. 09-01-019, mimeo, p. 4. 59 CPUC Decision No. 08-01-042, mimeo, Finding of Fact 3, p. 19.


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Q. Mr. Cosman references the fact that the State of California has one of the

lowest credit ratings among the 50 states. What is your response to his

commentary on this point?

A. California’s low credit rating is indeed unfortunate for the state, as well as for

SCE. Standard & Poor’s said this in January of this year: “we believe

structural issues facing the state could ultimately lead to California becoming a

less desirable place to live. The state's array of challenges includes a fractured,

partisan legislature, a gubernatorial election this fall, and, significantly, a

daunting state budget deficit that is forecast to persist.” Exhibit S-9, p. 28.

This is not a credit positive situation for SCE. Indeed, it is possible that the

state’s budget problems could adversely affect the ability of the CPUC to

perform its functions.

Q. Does SCE’s capital investment program have a positive effect on

California employment?

A. Yes. In its last two CPUC retail general rate cases (for test years 2006 and

2009), SCE has commissioned a study of the economic effect of its capital

investment program, including transmission investment. In each case, the

studies found that the overall employment effect was positive.

Q. What is your response to Mr. Cosman’s comments about the “CPUC

range of reasonableness”?


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A. Mr. Cosman cites the so-called range of reasonableness when it benefits his

position and dismisses it when it does not. In particular, Mr. Cosman fails to

distinguish between a base ROE and incentives that are additional to that base

ROE. Incentives on top of the base ROE are intended to promote specific

behavior on the part of the utility.

The 10.20% to 11.50% CPUC range of reasonableness cited by Mr.

Cosman is equivalent to a base ROE, as there is no mention in CPUC Decision

07-12-049 of incentives to promote specific investments. Instead, the ROE

authorized by the CPUC was intended to apply broadly to all of SCE’s retail

jurisdictional assets.

Q. How do you respond to Mr. Cosman’s claim that SCE voluntarily chose to

forgo an ROE increase for 2010?

A. Mr. Cosman presents a distorted view of the facts, as he fails to provide

important information regarding why SCE decided to make that offer: the

terms of the agreement prevented SCE from having to submit a new cost of

capital to the CPUC in 2010; instead that submittal is deferred to 2012 for a

new CPUC-authorized cost of capital beginning in 2013.60 In the meantime,

SCE’s CPUC-authorized cost of capital will be governed by the behavior of

60 CPUC Decision No. 09-10-016, Ordering Paragraph 1.


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Moody’s Baa long-term public utility bond yield. SCE agreed to forgo a

higher ROE for 2010 in return for insulation from CPUC regulatory risk with

respect to cost of capital for two years.

VI. RESPONSE TO M-S-R (LESSER) TESTIMONY REGARDING COST 4

OF CAPITAL

Q. What areas of Dr. Lesser’s testimony are you addressing?

A. Dr. Lesser’s testimony contains a critique of my earlier analysis, and he then

presents his own analysis (which he styles as an “independent analysis”) of

what SCE’s authorized return on equity should be. I address his analysis first,

and then respond to his comments on my testimony.

A. Response to Dr. Lesser’s Analysis of SCE’s Return on Equity

Q. What deficiencies have you identified in Dr. Lesser’s return on equity

analysis?

A. Here is a summary list of the deficiencies that I have identified in Dr. Lesser’s

analysis:

Dr. Lesser has incorrectly selected his proxy group.

His dividend yield calculation is incorrect, because he uses dividends

declared during 2009 as his measure of the current dividend rate.

His calculation of the fundamental rate of growth is not consistent with

the Commission-approved method because of the way he calculates the

rate of growth in shares, s.


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His calculation of the br component of the fundamental rate of growth is

not consistent with the Commission-approved method because of the

time period over which he calculates it.

Dr. Lesser’s DCF analysis uses a dividend yield calculation from one

period and a growth rate calculation from another period.

Because of these flaws, Dr. Lesser’s estimates should not be used by the

Commission in this docket.

Q. You claim that Dr. Lesser incorrectly selected his proxy group. What

evidence supports your claim?

A. Dr. Lesser’s DCF analysis spans the period from December 2009 through May

2010. Exhibit MSR-1, p. 32, ll. 5-6; Exhibit MSR-6. In his main testimony,

Dr. Lesser identified two companies that he claims were engaged in M&A

activity during this period, Dominion Resources and Entergy Corporation.

Exhibit MSR-1, p. 32, ll. 3-11. Regarding Dominion Resources, Dr. Lesser is

incorrect, and it should not be excluded from Dr. Lesser’s proxy group.

Dominion Resources announced the sale of its Peoples Gas subsidiary in July

2008 and completed the transaction in February 2010.61 Exclusion on the basis

61 Exhibit MSR-1, p. 32, ll. 5-8. Dominion Resources, Form 10-Q, dated July 31, 2008, p.

13. Exhibit SCE-60, p. 2. Dominion Resources, Form 10-Q, dated April 29, 2010, p. 14. Exhibit SCE-60, p. 3.


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of this transaction is erroneous because this transaction involved a very small

portion of Dominion Resources’s overall business. In Dominion’s Form 10-Q

for the second quarter of 2008, which announced the transaction, Dominion’s

total assets were reported as $42.0 billion at June 30, 2008. Peoples Gas’

assets subject to the sale were reported as $1.3 billion, or only 3.1 percent of

Dominion’s total assets.62 This transaction is not large enough to justify

exclusion of Dominion Resources from the proxy group. Under the April 15

Order, a company is excluded from the proxy group if it has announced a

merger, not an asset sale of this relatively minor nature.63

Just as Dr. Lesser should not have excluded Dominion Resources from

his proxy group, he should not have included PPL Corporation in his proxy

group. On April 29, 2010, PPL Corporation announced that it was purchasing

E.ON-US utility assets in Kentucky, in a $7.2 billion transaction.64 The E.ON

transaction will increase PPL Corporation’s asset base by approximately 29

percent,65 so the transaction is of a sufficient size that it should have been

(Continued)

62 Dominion Resources, Form 10-Q, dated July 31, 2008, p. 6. Exhibit SCE-60, p. 1. 63 The wording in the Order is “electric utilities that did not announce a merger …”

(Emphasis added.) Southern California Edison Company, 131 FERC ¶ 61,020 (2010), at P 52.

64 PPL Corporation, Form 8-K, dated April 29, 2010, Exhibit 99.1. Exhibit SCE-61, p. 1. 65 PPL Corporation’s total assets at the end of the first quarter of 2009 were about $24.9


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accounted for, and PPL Corporation excluded from Dr. Lesser’s proxy group.

For a different reason, Dr. Lesser should not have included Vectren

Corporation in his proxy group. Dr. Lesser claims that Vectren Corporation

should be included because of its total revenues. Exhibit MSR-1, pp. 13-14. I

disagree. As I explained above in my rebuttal to CPUC witness Mr. Cosman,

Vectren Corporation should be excluded from the proxy group because its

electric revenues do not exceed $1 billion. The Commission’s April 15 Order

largely adopted SCE’s proxy group, and SCE’s proxy group in that docket was

screened on electric revenues.66 Vectren Corporation was not a member of that

proxy group.67

Q. Dr. Lesser excluded three firms from his proxy group because they cut

their dividends in 2009. Do you agree with this exclusion?

A. I do not agree. Except for the very end of 2009, what happened in 2009 is

outside the period of Dr. Lesser’s DCF period and is outside the period of my

Continued from the previous page

billion. PPL Corporation, Form 8-K, dated May 6, 2010, Exhibit 99.1. Exhibit SCE-61, p. 2-3.

66 Docket No. ER08-375-000, Exhibit SCE-7 (Acc. No. 20071228-0069), p. 19, December 21, 2007. Southern California Edison Company, 131 FERC ¶ 61,020 (2010), at PP 38, 51-52. Paragraph 38, in particular, references annual electric revenues.

67 Docket No. ER08-375-000, Exhibit SCE-7 (Acc. No. 20071228-0069), p. 19, December 21, 2007.


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DCF update. Since Great Plains Energy cut its dividend in March 2009, there

has been plenty of time for investors to reform their expectations about the

company and it should be included in the proxy group. (Ameren and

Constellation Energy do not pass the bond rating criterion, so they should be

excluded on that basis.)

Q. Dr. Lesser excludes OGE Energy because, according to his data, it has

only one I/B/E/S analyst. Do you agree with this exclusion?

A. No, I do not. My data show that at the end of May 2010, five analysts were

following OGE Energy. I base my count on the number of analysts providing

earnings estimates for the current year since it is the best measure of the total

number of analysts who follow the company.

Q. Dr. Lesser excludes Westar Energy because, according to his data, its

bond rating is BBB-. Do you agree with the exclusion of Westar from the

proxy group?

A. Not entirely. My information is that Westar Energy was upgraded to BBB on

April 27, 2010. For Dr. Lesser’s DCF analysis period, Westar Energy was

rated outside the A-/BBB+/BBB category for the majority of the time, so it

would be appropriate to exclude it from his proxy group. However, for my

update, it would be appropriate to include it, because the BBB rating was in

place for the majority of my updated DCF analysis period.


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Q. Would NextEra Energy merit similar treatment?

A. Yes, as its corporate credit rating was reduced from A to A- on March 11,

2010. It is now appropriate to include NextEra Energy in the proxy group.

Q. Does Dr. Lesser calculate the dividend yield correctly in his DCF analysis?

A. No. Inspection of Dr. Lesser’s workpapers, provided in a response to an SCE

data request, reveals that he uses total dividends declared during 2009, as

calculated by Value Line, as his measure of the current dividend rate in the

DCF calculation.68 (See his testimony at Exhibit MSR-1, page 33, line 13,

through page 34, line 1, which indicates that the current stock dividend should

be used in the DCF calculation.) As dividends paid by electric utilities

generally increase over time, Dr. Lesser’s use of dividends declared during

2009 as a measure of the current stock dividend during 2010 will cause the

dividend yield to be underestimated.69 Thus his dividend yield calculation is

incorrect. He is the only witness to make this error, and I do not know of any

case where the Commission has accepted this practice.

68 See Exhibit SCE-58, which provides verification of this. 69 Dr. Lesser’s dividend yield calculation spans the period from December 2009 through

May 2010. Even the December 2009 dividend yield calculation is likely to be understated for any company that has increased its stock dividend during 2009.


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Q. You claim that Dr. Lesser calculated the fundamental rate of growth

incorrectly because of how he calculates the rate of growth in shares, s.

How do you know this?

A. Dr. Lesser’s workpapers, provided in a data request response to SCE, show

that he calculated the rate of growth of new shares s using data for 2008 and

2011. Exhibit SCE-50, pp. 9-10. He also states this in his testimony, where he

states that he determined the projected growth rate in shares over the 2008-

2011 period. Exhibit MSR-1, p. 36, ll. 9-14. This is inconsistent with the

Commission’s approved methodology, which uses a five-year period, as

demonstrated in the Golden Spread and VEPCO cases.70 In these cases, s was

calculated over a five-year period, not a three-year period.71 The

Commission’s April 15 Order accepted this five-year method.

70 These cases should be reviewed in reverse order. The VEPCO (Virginia Electric and

Power Company) case was Docket Nos. ER08-92-000/ER08-92-001/ER08-92-002/ER08-92-003, decided by the Commission in Virginia Electric and Power Company, 123 FERC ¶ 61,098. (“VEPCO Order”) Footnote 58 in this order, at paragraph 67, references Golden Spread Electric Cooperative, Inc. v. Southwestern Public Service Co., 115 FERC ¶ 63,043 at P 100 and Exhibit S-1, Schedule No. 10 (submitted in Docket Nos. EL05-19-002/ER05-168-001, Acc. No. 20060525-0189; this schedule may actually be in Exhibit S-2).

71 This calculation is found at Workpapers 1, 5, 9, and 13, found at pages 1, 5, 9, and 13 of Exhibit S-3 in Docket Nos. EL05-19-002/ER05-168-001 (Golden Spread case, Acc. No. 20060525-0191). These workpapers demonstrate that in the Golden Spread case, s was calculated over a five-year period from 2004 to 2009.


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Q. You say that Dr. Lesser’s calculation of the br component of the

fundamental rate of growth is not consistent with the Commission-

approved method because of the time period over which he calculates it.

Please explain the inconsistency.

A. Dr. Lesser calculated the br component using data from 2008 through 2011.

Exhibit MSR-1, p. 36, ll. 9-13 and Exhibit MSR-5, pp. 1-2. However, again

referring to the Golden Spread and VEPCO cases, we can see that this is not

the correct time period to use for this calculation.72 The April 15 Order

accepted the Golden Spread/VEPCO method.

Q. What time period did Dr. Lesser use for his DCF analysis?

A. Dr. Lesser did not use a consistent time period. For his dividend yield

calculation, he used the six-month period ending with May 2010. Exhibit

MSR-7, pp. 3-5. However, for his I/B/E/S growth rate, his corrected

workpapers indicate that he extracted data on June 15, 2010.73 It is incorrect to

(Continued)

72 These cases should be reviewed in reverse order. The VEPCO (Virginia Electric and Power Company) case was Docket Nos. ER08-92-000/ER08-92-001/ER08-92-002/ER08-92-003, decided by the Commission in Virginia Electric and Power Company, 123 FERC ¶ 61,098. (“VEPCO Order”) Footnote 58 in this order, at paragraph 67, references Golden Spread Electric Cooperative, Inc. v. Southwestern Public Service Co., 115 FERC ¶ 63,043 at P 100 and Exhibit S-1, Schedule No. 10 (submitted in Docket Nos. EL05-19-002/ER05-168-001, Acc. No. 20060525-0189; this schedule may actually be in Exhibit S-2).

73 Exhibit MSR-7, p. 2, bottom of page. Since Dr. Lesser’s testimony was submitted on


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calculate a DCF estimate using a dividend yield from one period and a growth

rate from a later period. Since the time difference between the end of Dr.

Lesser’s DCF calculation period and the date of his I/B/E/S growth rates is not

large, there probably is not a large impact on his estimates.

B. Response to Dr. Lesser’s Comments Regarding My Testimony

Q. Dr. Lesser criticizes you for including Dominion Resources in your proxy

group. What is your response?

A. I explained above that the sale of Peoples Gas is insufficiently large, when

compared with Dominion’s total assets, to justify exclusion from the proxy

group. Dr. Lesser’s criticism is without merit.

Q. Similarly, Dr. Lesser criticizes you for excluding Vectren Corporation

from your proxy group. What is your response?

A. As I explain elsewhere in this testimony, the correct proxy group screening

criterion is annual electric revenues, not annual revenues. Unless the criterion

is based on electric revenues, it would be possible to include very large

Continued from the previous page

June 30, 2010, it is impossible that he could have extracted his growth rates on July 14, 2010, as suggested on Exhibit MSR-7, p. 1, nor on July 1, 2010, as suggested at the top of Exhibit MSR-7, p. 2. However, since rates extracted on June 15, 2010 are outside the period of his DCF yield calculation by a couple of weeks, they are incorrect rates to use with Dr. Lesser’s dividend yield calculation.


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companies that have very small electric businesses in the proxy group, which

would be improper. My exclusion of Vectren Corporation is correct and Dr.

Lesser is incorrect.

Q. Dr. Lesser argues that your original analysis violated several aspects of the

April 15 Order. What is your response?

A. As I explain elsewhere, I produced my original analysis before the April 15

Order was issued. My original analysis is updated in this testimony. The

updated estimates follow the procedures established in the April 15 Order.

Q. Dr. Lesser argues that you used an incorrect risk-free rate in estimating

the Fama-French model. What is your response?

A. Dr. Lesser is incorrect. I use the one-month Treasury bill rate in my analysis.

This is the same risk-free rate that Fama and French use, which can be verified

by inspection at Kenneth French’s Internet site.74

Q. Dr. Lesser claims that the business and financial risks that you identify

are irrelevant to setting SCE’s base ROE. Do you agree?

A. No. As I have explained previously, investors in SCE must take account of all

of SCE’s risks because their investment is subject to all of SCE’s risks—SCE

does not issue financial instruments that are specific to generation assets,

74 See http://mba.tuck.dartmouth.edu/pages/faculty/ken.french/Data_Library/f-

f_factors.html. On this page, Rf is the risk-free rate.


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transmission assets, or distribution assets. Risks associated with generation

and power procurement, transmission investments and distribution investments

must all be accounted for if an investor wishes to accurately assess the risk of

an investment in SCE.

Q. What about the other risk issues discussed in Dr. Lesser’s testimony?

A. I respond to these issues in my rebuttal to other witnesses, so there is no need

to repeat that discussion here.

VII. RESPONSE TO STATE WATER PROJECT TESTIMONY 8

REGARDING COST OF CAPITAL

A. Response to Mr. Marcus’s Analysis of SCE’s Cost of Capital

Q. What is your reaction to Mr. Marcus’s analysis of SCE’s cost of capital?

A. Mr. Marcus based his analysis on DCF estimates that I produced previously for

the six month period ending in February 2010. Exhibit SWP-6, p. 12, ll. 1-4.

However, it is inconsistent with Commission precedent to base an ROE

determination on an analysis that precedes the effective date of rates, especially

when the rates are not locked in and when the case is being litigated, as this

one is. The Commission normally expects DCF analyses to be updated to a

date close to the commencement of hearing. There also is no reason to rely on

stale data when there is an opportunity to update the DCF analysis. In fact, Mr.

Marcus’s data are older than the data used by all of the other Staff and

intervenor witnesses in the case, and their data is also somewhat stale at this

point.


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Q. How do you respond to Mr. Marcus’s comments on the DCF analysis

contained in your original filed testimony?

A. As I read Mr. Marcus’s comments on my original DCF analysis, they appear to

be entirely based on the relationship between my original analysis and the

April 15 Order. As I noted above, the midpoint-versus-median issue is subject

to an application for rehearing that is still pending, hence that issue has not

been finally resolved. Regarding Mr. Marcus’s other criticisms, I have

acknowledged that my initial testimony was filed before the Commission’s

April 15 Order. Because my revised and updated analysis submitted with this

rebuttal testimony is consistent with the April 15 Order, it is not necessary for

me to respond all of the allegations found in Mr. Marcus’s testimony that no

longer apply.

B. Response to Dr. Malloy’s Commentary

Q. Dr. Malloy writes: “Southern California Edison’s submissions suggest a

degree of precision and rigidity in its application of DCF that is simply not

inherent in the methodology.”

A. My testimony attaches no more or less precision and rigidity to the DCF

analysis than is required by Commission precedent. The simple fact is that the

Commission uses the DCF model to set the authorized ROE and has done so

for many years.


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Q. What overall conclusion should the Commission draw from Dr. Malloy’s

testimony?

A. The conclusion that the Commission should draw is that events in the financial

sector during the last three years have dramatically restricted the availability of

capital and access to capital.

Dr. Malloy references the following situations in his testimony:

“[A] dramatic systemic failure of capital markets worldwide …”

(Exhibit SWP-46, p. 14, ll. 8-9);

“[M]ajor institutional investors have been confronted with significant

liquidity problems …” (Exhibit SWP-46, p. 15, ll. 2-3);

“The current state of the capital markets is fundamentally affected by

the ongoing systemic crisis …” (Exhibit SWP-46, p. 15, ll. 13-14);

“The contraction of credit that resulted from the meltdown is of material

significance to investors …” (Exhibit SWP-46, p. 17, ll. 2-3);

“Overall, it is clear that the financial services system is under critical

stress.” (Exhibit SWP-46, p. 18, ll. 18-19);

“U.S. and European banks face growing funding requirements,

particularly for long-term liabilities.” (Exhibit SWP-46, p. 19, ll. 12-14);

“However, to date little has been done to address any structural

problems in the regulatory system.” (Exhibit SWP-46, p. 21, ll. 3-4);

and


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“To begin with, almost two years into the financial crisis, Congress has

yet to enact regulatory reform … legislation, and the delay involves

costs to the market – serious liquidity, funding constraints, higher

transaction costs, and higher compliance costs.” Exhibit SWP-46, p. 24,

ll. 14-17

The common theme here is reduced availability of credit and greater

difficulty in attracting capital. To overcome these difficulties for utilities such

as SCE, who need to attract and retain equity capital on a continual basis, the

proper policy prescription is to increase authorized returns on equity, not

reduce them. Dr. Malloy fails to recognize the import of his own testimony.

Q. Concerning your DCF analysis of SCE’s required ROE, Dr. Malloy states:

“nothing in the analysis or the resulting recommendations adequately

takes into account the impact of the direct and indirect costs of the

meltdown …” How do you respond to this comment?

A. Dr. Malloy’s testimony in this docket shows that the easy availability of credit

that characterized financial markets prior to 2008 is gone. If the DCF

methodology does not take adequate account of more restrictive credit

requirements and decreased availability of capital, then the DCF ROE

estimates are too low and should be adjusted upward to accurate gauge SCE’s

required return on equity.


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VIII. UPDATED ESTIMATES OF COST OF CAPITAL 1

A. Return on Equity

Q. Have you updated your estimates of SCE’s return on equity?

A. Yes, I have updated my DCF analysis based on the most recent vintage data

available and using the methodology approved in the April 15 Order, although

as I explain above I do not agree with FERC used of the median to set the

ROE. My revised analysis results are shown in the following table. The DCF

estimates are calculated using data ending in September 2010. The median

estimate based on company averages is 10.30%.

Updated DCF Cost of Equity Estimates (Updating Table at Exhibit SCE-17, Page 16)

Model Low Midpoint Average High DCF 6.99% 11.33% 10.35% 15.67%

Q. Where can the details of your estimates be found?

A. They are contained in Exhibit SCE-59.

Q. Regarding the selection of your proxy group, have you followed the

screening procedure established in the Commission’s April 15 Order?

A. Yes.

Q. What are the companies in your proxy group?

A. They are Alliant Energy, American Electric Power, Centerpoint Energy,

Consolidated Edison, Dominion Resources, DPL, DTE Energy, Duke Energy,

Exelon, Great Plains Energy, Hawaiian Electric Industries, IDACORP,


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Integrys Energy, NextEra Energy, Northeast Utilities, OGE Energy, PG&E

Corporation, Portland General Electric, Progress Energy, Public Service

Enterprise Group, SCANA, Sempra Energy, TECO Energy, Westar Energy,

Wisconsin Energy, and Xcel Energy.

IX. RESPONSE TO OTHER PARTIES’ TESTIMONY REGARDING COST 5

ESCALATION

Q. What is the purpose of this portion of your rebuttal testimony in this

proceeding?

A. The primary purpose of this portion of my rebuttal testimony is to address the

criticisms of Six Cities witness Terry M. Myers, M-S-R/LADWP witness

David B. Cohen, and Staff witnesses Kerri H. Miller and Craig E. Deters

regarding SCE’s labor and non-labor escalation rates. My rebuttal testimony

and exhibits show that SCE uses the correct methodology to calculate and

forecast labor and non-labor escalation rates. I will first demonstrate that Ms.

Miller’s average salary calculations and labor escalation conclusions are

flawed. Next, I will address the criticisms of Mr. Myers, Mr. Cohen, and Mr.

Deters regarding the use of labor escalation rates to escalate the indirect labor

portion of non-labor escalation.

A. Labor Escalation

Q. What is the purpose of your rebuttal testimony on labor escalation?

A. I am addressing the direct testimony of FERC Staff Witness Kerri H. Miller

regarding SCE’s labor escalation rates as testified in Exhibit S-14, pp. 6-11.


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Q. What do you mean by “labor escalation rates,” and how are they used in

SCE’s filing?

A. When SCE’s witnesses forecast their Period II costs, they do so in year 2008

dollars. Those 2008 dollars are separated into “labor” (this is the direct labor

discussed in the testimony of SCE rebuttal witness Ms. Argandona, Exhibit

SCE-34) and “non-labor” components. Those 2008 dollars are then escalated

to year 2010 dollars by SCE witness Mr. Allstun in cost-of-service

calculations. I provided both the labor escalation rates and non-labor

escalation rates that Mr. Allstun used for this purpose.

Q. Have you reviewed the testimony of Ms. Miller regarding the

Transmission and Distribution Business Unit’s (TDBU) wages and

salaries?

A. Yes, I have. Ms. Miller testified that the Period II ISO transmission wages and

salaries should be escalated from 2008 to 2010 using a zero percent escalation

rate. Exhibit S-14, p. 11, ll. 6-9. Her recommendation is based on her

assessment of projected changes in TDBU wages and salaries, of which Period

II ISO transmission wages and salaries comprise one quarter of that total.

Q. Do you agree with Ms. Miller’s analysis of TDBU wages and salaries in

Exhibit S-14, Page 8?

A. No, I do not agree with Ms. Miller’s analysis. In Exhibit S-14, on page 8, lines

12-16, Ms. Miller claims “In SCE’s data response to MSR/LADWP-SCE-


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64(f), Exhibit S-17, page 4, SCE provides data which show that the average

wages and salaries of a Transmission Distribution Business Unit (TDBU)

worker have remained relatively unchanged since 2007.” Ms. Miller

repeatedly cites the “average wages and salaries of a Transmission Distribution

Business Unit (TDBU) worker” within her testimony, although the SCE

response to MSR/LADWP-SCE-64(f), did not contain an average wage or

salary of a Transmission and Distribution employee.

Q. In MSR/LADWP-SCE-64(f), Exhibit No. S-17, page 4 did SCE provide

Ms. Miller with average wages and salaries of TDBU employees?

A. No, in data request MSR/LADWP-SCE-64(f) SCE was not asked, nor did we

provide, data on average wages and salaries for TDBU employees.

Q. Did Ms. Miller request this information in a different data request?

A. No.

Q. Did Ms. Miller attempt to calculate a TDBU average salary on her own?

A. Yes, she did.

Q. Did Ms. Miller correctly calculate an average salary based upon the data

provided in MSR/LADWP-SCE-64(f)?

A. No, she did not. The response to data request MSR/LADWP-SCE-64 provided

two data sets: total wages and salaries and end of year head count. Ms. Miller

did not request “the average salary of a TDBU employee” or, more

appropriately, “the average hourly earnings of a TDBU employee.” Ms. Miller


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incorrectly imputed an average salary from the two data sets by dividing

salaries by end of year headcount.

Q. Why do you state that Ms. Miller’s calculation of average salary escalation

is incorrect?

A. The two sets of data – total wages and salaries and end of year headcount – are

not directly linked and do not represent data sets that can be combined and

compared on a period to period basis without first “normalizing” the data. One

represents costs during the course of an entire year, while the other represents

the headcount at a particular time of year. The end of year headcount figure

cannot be used to represent a unit of work because it counts all employees

equally, even though not all employees included in the headcount worked a full

year. In order to use the data together, the data must be “normalized” so that it

is reflective of conditions throughout the year.

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Q. Can you provide a simple example showing this, and in that process show

what “normalization” is?

A. Yes. Assume that you are trying to determine the average salary that a

company paid its employees during 2007 and 2008, and you used the method

Ms. Miller used. Now assume that in 2007, the company had four employees

as of January 1, all of whom worked the whole year, and thus had a total of

four employees at the end of the year. Assume that each employee was paid

$100,000 per year. Using Ms. Miller’s method, you would sum the salaries


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paid to the four employees during the year ($100,000 times 4), and divide the

total ($400,000) by 4. You would determine that the company’s average salary

in 2007 was $100,000.

Now let’s turn to 2008. In 2008, assume that the company has four

employees as of the start of the year, and hired one new employee on July 1,

2008. The company paid each employee an annual salary of $104,000, and

thus had five employees as of the end of 2008. Using Ms. Miller’s method,

you would sum the salaries paid to the five employees during the year

($104,000 times 4, plus $52,000 for the employee hired on July 1), and divide

the total ($468,000) by 5. You would determine that the company’s average

salary in 2008 was $93,600, even though in fact it was $104,000.

Q. What happened?

A. I didn’t normalize the headcount data to make it reflective of conditions

throughout the year. This is exactly the same error that Ms. Miller made, and

why she arrived at the wrong conclusion.

Q. What happens when you normalize the headcount data in the above

example?

A. You get a headcount of 4.5. Dividing $468,000 by 4.5 yields an average salary

of $104,000, the correct answer.


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Q. Can you elaborate on why end of year headcount and total salaries should

not be used in an average salary calculation?

A. Yes. The example above illustrates the problem, but let me provide additional

detail. End of year headcount does not include employees that have terminated

or changed jobs, but does include employees that have been in their position

for less than a year. Both of these skew the calculation. Total salaries and

wages also is not a normalized data set. It includes all employees’ salaries and

wages associated with TDBU accumulated through the year, whether the

employee worked a full year or partial year. The non-normalized salaries may

include partial year salaries, and include overtime and double time, which

fluctuate from period to period and ultimately skew period-to-period

comparisons.

Q. Are you stating that the average salary calculated by Ms. Miller for TDBU

employees as referenced in Exhibit No. S-17 is inaccurate?

A. Yes. In addition, comparing non-normalized data sets from period to period

will produce skewed results, so her conclusions on labor cost escalation are

incorrect as well. (I will address that later). This data needs to be normalized

to make period to period comparisons.

Q. Does SCE calculate historical wage escalation?

A. Yes. Historical average hourly earnings (“AHE”) are calculated during the

labor escalation process and represent the basis for SCE’s historical labor wage


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escalation through 2008.

Q. Are there external experts that calculate labor escalation rates?

A. Yes, IHS Global Insight calculates labor escalation.

Q. Who is IHS Global Insight?

A. IHS Global Insight is a reliable, independent, and accurate source for labor

escalation and O&M cost forecasting. Utilities have used IHS Global Insight

projections in numerous proceedings before the Commission.

Q. Does IHS Global Insight calculate wage escalation at the salary level?

A. No, IHS Global Insight uses AHE, a normalized data asset, to calculate and

escalate labor wages for the data sets used in SCE’s labor wage escalation

calculations.

Q. What are the basic requirements for calculating historical labor cost

escalation?

A. Proper mathematical escalation of labor requires a normalized data set of

wages into a unit of work. A normalized data set should be a homogenous unit

of work, such as an average hourly wage. Only normalized data can be used to

calculate inflation or escalation on a year to year basis.

Q. Can you provide an example of how a normalized wage, or normalized

unit of work (that can be used to calculate period to period changes), is

calculated?


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A. Yes. If we assume that all employees were paid their standard wages, without

overtime or double time, then the weighted average hourly wage is a

normalized homogenous unit of work data set. This can be mathematically

represented as:

Total Wages 5

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Total Hours

With the introduction of overtime and double time wages, the hourly wage data

should be normalized to properly represent the normal wage paid per hour. In

order to normalize the double and overtime wages, a mathematical adjustment

is made to the overtime (wages/1.5) and double time (wages/2) wages to de-

escalate the wage to an accurate normal time wage. This can be expressed

mathematically as:

Normal Time Wages + (Overtime Wages / 1.5) + (Double Time Wages/ 2) 13

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Total Hours

Once the data set is normalized, dividing the total adjusted wages by the total

hours will achieve a normalized hourly wage that can be properly compared on

a period to period basis.

Q. Is the use of non-normalized data in a labor wage escalation process a

proper method to use when comparing year to year wage data?

A. No. By not performing a process to normalize the data, you introduce

statistical anomalies that will skew the results of the data and produce

inaccurate results.


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Q. Is the use of total salaries divided by end of year headcount, as referenced

by Exhibit No. S-14, on Page 8, lines 12-16, which is mathematically

represented as,

Total wages and salaries 4

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End of year headcount

a proper method for calculating historical wage escalation?

A. No, the data set is not normalized and does not represent a homogenous unit of

work that can be compared over multiple periods. If all workers included in

the headcount worked a full year’s work and the headcount directly

represented the total salaries of the headcount workers, and there was no

overtime or double time – then yes. This was the case for 2007 in the example

I provided above. If one were to attempt to use SCE TDBU total wages and

salaries and end of year headcount to calculate a year to year labor escalation

rate, however, one would be required to perform numerous adjustments to

normalize the data. For instance, in order to normalize the data you would

have to make the following adjustments to the data including, but not limited

to:

Wage adjustments: 18

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• Adjust wages for overtime wages

• Adjust wages for double time wages

• Adjust for wages paid to employees not included in headcount

• Employees that shift departments must be properly allocated across


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Period/Hour Adjustments: 2

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• Adjust each employee that did not work a full year

• Adjust new hires during the year since they are over-weighted

• Adjust for employees that left prior to end of year since they are not

included and in data are underweighted

• Employees that shift departments must be properly allocated to the

particular departments

By not performing the adjustments to normalize the data, you introduce

statistical anomalies that may skew the results of the data. For instance, if an

employee were hired on December 31, they are still counted as one FTE in the

year end headcount, although they should be properly weighted as 0.3846%

(8/2080 hours) of an FTE.

Q. Did the Transmission Unit experience inflation in its historical wage

escalation from 2006 - through 2008?

A. Yes. SCE’s Transmission average hourly earnings for 2006 through 2008 were

$37.24, $38.46, and $40.54 which represent a 3.3% and 5.4% increase for 2007

and 2008 respectively. The 2008 wage escalation was previously reported in

Ms. Schiminske’s workpapers WP-AH/AI- 6 of 10.


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Q. In order to avoid confusion, did the Distribution Unit also experience

inflation in its historical wage escalation from 2006 through 2008?

A. Yes, SCE’s Distribution average hourly earnings for 2006 through 2008 were

$33.63, $34.70 and $36.41, which represent a 3.16% and 4.9% increase for

2007 and 2008 respectively.

Q. In Exhibit S-14, does Ms. Miller admit that there is inflation in the labor

and material markets?

A. Yes, she does. In Exhibit S-14, page 8, lines 8-9 Ms. Miller admits: “there is

inflation in the markets.”

Q. Does Ms. Miller acknowledge that there are contractual obligations for

labor rate increases for represented employees?

A. Yes. In Exhibit No. S-14, page 8, lines 8-9, she states so.

Q. Yet based upon Ms. Miller’s “average salary calculations” she claims that

on page 8, lines 16-17, “for 2008 and 2009 SCE has had nearly 0%

inflation to its average wages and salaries.” Do you agree?

A. No. Ms. Miller incorrectly imputed an “average salary” and then made a

comparison of two incorrectly calculated, non-normalized numbers and

ultimately provided incorrect conclusions on inflation to average wages. SCE

definitely experienced wage escalation in 2006-2008 as referenced above and

this is further supported by contractual obligations, and actual historical

inflation in labor markets.


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Q. What is the basis for Ms. Miller’s adjustments?

A. She appears to contend that SCE’s estimates were not reasonable when made,

although she does not state this explicitly. If that is her argument, then her

focus should have been on the data that were available to SCE when it filed its

rate case, which would not include the 2009 data upon which she relies. My

testimony above shows that Ms. Miller’s calculation of SCE’s escalation rates

for 2007 and 2008 was in error (she does not rely upon the 2007 escalation

rate, since her own data show a 5.5 percent increase). Exhibit S-17, p. 2, l. 11.

These are the data that were available to SCE when it filed its rate case, and

they demonstrate that SCE’s projections of its estimated escalation rates were

reasonable when made. These escalation rates were above SCE’s projections.

While Ms. Miller also refers to 2009 data, those data were not available

at the time of SCE’s filing, and are thus irrelevant unless FERC Staff

demonstrates that SCE’s projections would yield unreasonable results. Ms.

Miller’s calculations do not show that SCE’s projections yield unreasonable

results, as all of her calculations are flawed and cannot be relied upon for any

purpose. I showed this by explaining the error of her method and by

comparing her results to actual 2007 and 2008 results. Specifically, Ms. Miller

calculates SCE’s 2008 escalation rate at -1.2% (Exhibit S-17, p. 2, l. 11), when

it fact it was 5.4% (transmission) and 4.9% (distribution). Because of the

change in SCE’s accounting system, I am not aware of the same data as I


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provided for 2007 and 2008 being available for 2009. In either event, the point

is moot, as such data were not available when SCE prepared its projections,

and no one has demonstrated that SCE’s projections yield unreasonable results.

Q. Are there any other incorrect statements in Ms. Miller’s testimony on this

issue?

A. Yes. On page 8, line 3, of her testimony, Ms. Miller states that SCE has

consistently over-forecasted its labor escalation rates. As I explain above, her

data are improperly calculated, and cannot be used for any purpose. However,

even using her own data, her assertions are incorrect. Her data show that on

average, SCE’s wages and salaries rose 2.85% over these years, close to the

2.71% rate SCE estimates for 2010. Exhibit S-17, p. 2 ll. 8-13. Thus, even her

own data provide no basis for reducing SCE’s wages and salaries escalation

rate to 0%. And, if her calculation of the 2008 rate is replaced by the actual

rate of about 5%, her average rate rises to 3.89% per year, which is higher than

SCE’s estimates for each of 2009 (3.62%) and 2010 (2.71%). While I do not

believe that would be a correct calculation for any year other than 2008, it

shows that Ms. Miller’s own data, with just one year corrected, support SCE’s

escalation.

Ms. Miller also suggests that, based on her analysis, SCE should

examine why its forecasts are “so inaccurate.” Exhibit S-14, p. 9, l. 5. It is not

SCE’s forecasts that are inaccurate, but rather Ms. Miller’s incorrect


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calculation of SCE’s historical cost escalation. For example, Ms. Miller’s

flawed methodology led her to conclude that SCE’s 2008 transmission and

distribution wages declined by 1.2 percent (Exhibit S-17, p. 2, l. 12) when in

fact they rose by 5.4 and 4.9 percent, respectively.

Having incorrectly determined that SCE’s wages are not rising, Ms.

Miller then speculates regarding a possible reason for the zero growth (which

in fact was real growth). She appears to suggest that lower paid employees are

replacing higher paid employees, and that is holding SCE’s wages flat. Exhibit

S-14 at 9-10. There are two problems with this. First, of course, the data show

that SCE’s wages are increasing in line with its projections, contrary to Ms.

Miller’s assertion. Second, Ms. Miller provides no evidence to support her

employee turnover theory. It is pure speculation on her part. In either event,

the issue is moot, as wages did rise in line with SCE’s projections. Her

adjustment should be rejected.

B. Non-Labor Escalation and Indirect Labor

Q. What is the purpose of your rebuttal testimony on non-labor escalation?

A. I am addressing the direct testimony of Six Cities witness Terry M. Myers, M-

S-R/LADWP witness David B. Cohen, and Staff witness Craig E. Deters

regarding SCE’s non-labor escalation calculations and the process of escalating

indirect labor expenses with a labor escalation rate.


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Q. In your first answer and in the title to this section, you state that you are

addressing “indirect labor,” whereas Mr. Deters and Mr. Myers refer to

non-labor expense that is actually labor. Please explain the difference, if

any, between these two terms.

A. They refer to the same thing. In our direct testimony, we referred to the

indirect labor expense that is included within labor expense as “non-labor

labor”. To be consistent with Ms. Argandona’s testimony, I refer to this labor

as “indirect labor.” “Indirect labor” and “non-labor Labor” mean the same

thing.

Q. Can you address Mr. Deters’ criticism in Exhibit No. S-1, page 16, lines

18-19 that states SCE’s annual percentages of non-labor expense that are

actually labor expense are completely unsupported, Mr. Myers’ criticisms

in Exhibit SC-4, page 23, lines 8-10 and on page 23, line 13 that claim

SCE’s provides no evidence or support for adjustments for indirect labor

in non-labor, and Mr. Cohen’s criticism in Exhibit ML-1, page 67, lines

11-13, that SCE has not adequately explained or justified its adjustments

for the indirect labor costs in non-labor?

A. Yes. I will demonstrate that these adjustments to non-labor are accurate,

reasonable and completely supported. First, Ms. Argandona’s testimony

addresses the definition and use of indirect labor, and how the SCE accounting

system books indirect labor as part of non-labor expense. In Ms. Argandona’s


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testimony we have demonstrated how the SCE accounting system reasonably

books indirect labor charges into the non-labor category by way of labor

allocations and chargebacks. Lastly, Ms. Argandona addresses how all labor

costs are identified, and, more specifically, how indirect labor is identified –

via the True Labor study.

Q. What is the True Labor study?

A. Ms. Argandona’s testimony addresses this issue. Briefly, the True Labor study

is an annual SCE study that identifies and separates direct and indirect labor.

In other words, it extracts the indirect labor expense from non-labor expense.

The indirect labor expense, plus the direct labor expense, shown in the True

Labor study is referred to as “True Labor,” because it represents the actual

amount of labor expense included in SCE’s books and records.

Q. What do you mean by “FERC Labor” and “FERC Non-labor”?

A. These are terms used by SCE witness Ms. Schiminske in her workpapers

(which I have adopted). “FERC Labor” is the same as the direct labor

described by Ms. Argandona. “FERC Non-labor” includes both non-labor and

indirect labor expenses. The sum of FERC Labor and FERC Non-labor ties to

the FERC Form 1 Electric Operation and Maintenance Expenses at page 320-

323 which reflects total company O&M expenses.

Q. Does FERC Labor expense differ from True Labor expense?


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A. Yes. As I explained above, FERC Labor expense does not include indirect

labor expense. Indirect labor expense is included in FERC Non-labor expense.

True Labor, in contrast, moves the indirect labor expense from FERC Non-

labor to True Labor. Ms. Argandona explains this in more detail in her rebuttal

testimony. The important point is that there are two separate calculations of

labor expense: FERC Labor, which does not include indirect labor; and True

Labor, which does include indirect labor expense. The purpose of this exercise

is to extract the indirect labor from the FERC Non-labor expense, and include

it as part of True-Labor. True Labor is reported in SCE’s FERC Form 1 on

pages 354-55 (wages and salaries). To make sure the terminology I use is

clear: Although True Labor is reported in the FERC Form 1, True Labor is

different from what I refer to as “FERC Labor,” for the reasons given in this

answer.

Q. Now that you have addressed that indirect labor expenses is included in

FERC Non-labor, and have explained what True Labor and FERC Labor

are, can you explain how to identify any indirect labor expense that is

included within FERC Non-labor?

A. Yes. I’d like to start with providing further detail on how to mathematically

calculate indirect labor in non-labor. A guiding principle in this calculation is

that when True Labor costs, or total labor costs, are greater than FERC Labor

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within FERC Non-labor.

First, we first start with identifying the relevant FERC accounts for

FERC Labor and FERC Non-labor:

FunctionSteam 500 to 514Nuclear 517 to 532Hydro 535 to 545Other 546 to 554Transmission 560 to 573Distribution 580 to 598Customer Accounts 901 to 905CS&I 907 to 910

FERC Accounts

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Next, we adjust for removing FERC Non-labor accounts for fuel (FERC

account 501, 518 and 547):

Items to Exclude: Acct. ReasonSteam 501 FuelNuclear 518 FuelOther 547 Fuel 7

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By summing the FERC Labor and Non-labor accounts and adjusting for

fuel we have the following FERC Labor and Non-labor charges:

FERC Nonlabor 2002 2003 2004 2005 2006 2007 2008Steam 34,631,520 31,923,360 34,497,523 32,307,849 24,163,701 31,239,724 50,374,656Nuclear 132,220,354 119,131,832 163,254,437 98,963,910 169,278,876 144,320,043 181,563,572Hydro 18,018,077 17,037,923 19,129,858 17,844,989 20,861,428 23,442,470 17,049,316Other 20,329,287 13,695,827 13,971,255 13,119,368 11,864,547 8,659,799 15,957,662Transmission 95,290,054 106,469,596 191,357,994 280,577,363 253,327,019 175,880,391 231,308,992Distribution 164,356,476 177,521,560 300,986,490 215,202,740 246,507,859 247,021,750 163,719,036Customer Accounts 96,138,354 129,578,937 102,497,218 90,755,050 87,928,812 98,059,369 100,192,662CS&I 95,296,550 149,108,865 169,333,629 265,134,743 280,687,582 415,574,952 458,970,792 10


FERC Labor 2002 2003 2004 2005 2006 2007 2008Steam 27,183,958 28,573,164 27,060,099 26,399,103 17,326,360 6,294,387 3,630,984Nuclear 135,520,447 138,573,755 168,579,324 156,250,092 185,189,798 187,133,147 208,244,965Hydro 11,345,263 12,394,274 13,053,172 13,487,843 15,516,632 16,696,414 19,648,952Other 898,328 999,757 1,182,834 1,449,894 1,919,315 8,020,557 5,673,331Transmission 31,936,912 34,275,292 37,623,031 39,773,025 45,706,098 52,439,628 54,268,508Distribution 86,851,775 95,240,213 112,773,525 113,267,301 123,820,180 133,070,719 171,164,970Customer Accounts 90,224,295 92,929,184 95,114,059 97,195,495 98,566,141 102,626,213 107,200,921CS&I 28,792,534 32,337,393 36,009,165 38,607,044 43,768,160 53,346,635 72,097,386 1

2 Next we identify True Labor:

True Labor 2002 2003 2004 2005 2006 2007 2008Steam 29,995,520 30,910,523 29,673,438 27,969,921 17,941,880 6,660,008 3,760,659Nuclear 154,188,385 151,125,151 181,608,874 172,230,054 201,938,933 198,497,015 210,915,217Hydro 13,825,288 15,203,301 15,796,223 17,483,717 18,428,153 20,574,701 22,709,228Other 948,236 1,068,260 1,263,713 1,662,075 6,589,513 8,383,528 11,161,204Transmission 49,599,318 52,890,926 53,661,327 61,161,859 70,523,753 79,522,253 65,014,731Distribution 122,418,351 137,140,734 149,046,796 160,185,863 171,359,133 187,863,612 185,038,528Customer Accounts 109,138,674 112,206,068 116,311,420 115,462,920 117,081,377 117,724,084 111,880,219CS&I 31,177,841 35,572,403 38,903,635 44,110,102 48,594,427 60,076,147 74,849,808 3

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To identify the indirect labor in FERC Non-labor, simply calculate the

difference between True Labor and FERC labor. Subtract FERC Labor from

True Labor:

True Labor Minus FERC Labor = Indirect Labor In NonlaborLabor in Nonlabor 2002 2003 2004 2005 2006 2007 2008Steam 2,811,563 2,337,359 2,613,339 1,570,818 615,520 365,621 129,675 Nuclear 18,667,938 12,551,396 13,029,550 15,979,961 16,749,136 11,363,869 2,670,252 Hydro 2,480,025 2,809,026 2,743,051 3,995,875 2,911,521 3,878,287 3,060,275 Other 49,908 68,504 80,879 212,181 4,670,198 362,972 5,487,873 Transmission 17,662,406 18,615,635 16,038,295 21,388,834 24,817,655 27,082,625 10,746,223 Distribution 35,566,576 41,900,521 36,273,271 46,918,562 47,538,954 54,792,893 13,873,557 Customer Accounts 18,914,380 19,276,884 21,197,361 18,267,425 18,515,236 15,097,871 4,679,298 CS&I 2,385,307 3,235,011 2,894,470 5,503,057 4,826,268 6,729,512 2,752,422 7

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This amount represents the indirect labor that is charged to the FERC

Non-labor function.

For example, assume FERC Labor for transmission is $70, and True

Labor for transmission is $80. The $10 difference between these two amounts


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represents the amount of indirect labor that has been recorded in the FERC

Non-labor function.

Q. Where do the above numbers come from?

A. Like the numbers below, they come from SCE’s books and records.

Q. Now that we have identified the indirect labor expense embedded in non-

labor expense, how do we calculate the ratio of indirect labor embedded

within non-labor?

A. To calculate the ratio of indirect labor embedded within non-labor, simply

divide the identified indirect labor (True Labor – FERC Labor) by total FERC

Non-labor. This can be mathematically represented as:

Indirect Labor embedded within Non-labor 11

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FERC Non-labor Or

(True Labor – FERC Labor) 14

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FERC Non-labor

Q. Can you demonstrate this calculation?

A. Yes, in the preceding pages we identified indirect labor that is charged to the

FERC Non-labor function:

True Labor Minus FERC Labor = Indirect Labor In NonlaborLabor in Nonlabor 2002 2003 2004 2005 2006 2007 2008Steam 2,811,563 2,337,359 2,613,339 1,570,818 615,520 365,621 129,675 Nuclear 18,667,938 12,551,396 13,029,550 15,979,961 16,749,136 11,363,869 2,670,252 Hydro 2,480,025 2,809,026 2,743,051 3,995,875 2,911,521 3,878,287 3,060,275 Other 49,908 68,504 80,879 212,181 4,670,198 362,972 5,487,873 Transmission 17,662,406 18,615,635 16,038,295 21,388,834 24,817,655 27,082,625 10,746,223 Distribution 35,566,576 41,900,521 36,273,271 46,918,562 47,538,954 54,792,893 13,873,557 Customer Accounts 18,914,380 19,276,884 21,197,361 18,267,425 18,515,236 15,097,871 4,679,298 CS&I 2,385,307 3,235,011 2,894,470 5,503,057 4,826,268 6,729,512 2,752,422 20

21 Then identify FERC Non-labor:


FERC Nonlabor 2002 2003 2004 2005 2006 2007 2008Steam 34,631,520 31,923,360 34,497,523 32,307,849 24,163,701 31,239,724 50,374,656Nuclear 132,220,354 119,131,832 163,254,437 98,963,910 169,278,876 144,320,043 181,563,572Hydro 18,018,077 17,037,923 19,129,858 17,844,989 20,861,428 23,442,470 17,049,316Other 20,329,287 13,695,827 13,971,255 13,119,368 11,864,547 8,659,799 15,957,662Transmission 95,290,054 106,469,596 191,357,994 280,577,363 253,327,019 175,880,391 231,308,992Distribution 164,356,476 177,521,560 300,986,490 215,202,740 246,507,859 247,021,750 163,719,036Customer Accounts 96,138,354 129,578,937 102,497,218 90,755,050 87,928,812 98,059,369 100,192,662CS&I 95,296,550 149,108,865 169,333,629 265,134,743 280,687,582 415,574,952 458,970,792 1

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Next, divide Indirect Labor in non-labor by FERC Non-labor to

determine the ratio of indirect labor embedded within non-labor and calculate

the average by function:

Ratio of Indirect Labor Embedded within FERC Non-labor2002 2003 2004 2005 2006 2007 2008 Average

Steam 8.12% 7.32% 7.58% 4.86% 2.55% 1.17% 0.26% 4.55%Nuclear 14.12% 10.54% 7.98% 16.15% 9.89% 7.87% 1.47% 9.72%Hydro 13.76% 16.49% 14.34% 22.39% 13.96% 16.54% 17.95% 16.49%Other 0.25% 0.50% 0.58% 1.62% 39.36% 4.19% 34.39% 11.56%Transmission 18.54% 17.48% 8.38% 7.62% 9.80% 15.40% 4.65% 11.70%Distribution 21.64% 23.60% 12.05% 21.80% 19.28% 22.18% 8.47% 18.43%Customer Accounts 19.67% 14.88% 20.68% 20.13% 21.06% 15.40% 4.67% 16.64%CS&I 2.50% 2.17% 1.71% 2.08% 1.72% 1.62% 0.60% 1.77% 5

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Q. Why do you calculate this ratio, and what is it used for?

A. As I explain below, the ratio is used to calculate the escalation rates for non-

labor expense. I will explain how it used mathematically, and provide an

example.

Q. Is this ratio calculated based on the prior year’s data?

A. No. We calculate this ratio based on the average of several years’ data; here,

2002 to 2008.


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Q. Can you please address why SCE used a multi-year average of indirect

labor in non-labor to calculate escalation rates?

A. Yes. As noted by Mr. Deters in Exhibit S-1, page 16, line 21, “these

percentages have widely varied from year to year.” In SCE’s response to

FERC STAFF-SCE-L001 Q 17, the data indicate that the amount of indirect

labor in non-labor can vary, up or down, from year to year. Exhibit SCE-50,

pp. 12-17. When faced with a data set that varies up and down from year to

year it is both reasonable and appropriate to use an historical average to

estimate future values, if those historical averages are appropriate for use in

estimating those future values.

Q. Can you address how SCE uses this indirect labor in non-labor rates?

A. Yes. SCE uses the ratio of indirect labor embedded within non-labor to weight

the labor portion of FERC non-labor escalation calculation.

Q. Can you summarize the escalation process and identify how the ratio of

indirect labor embedded within non-labor is used?

A. Yes. In order to accurately calculate escalation rates, you must first identify

the source of your costs that are being escalated. In the case of FERC Non-

labor, you have a non-labor component and an (indirect) labor component.

The next step is to identify and calculate escalation rates. The non-labor

escalation rates are forecast by IHS Global Insight, by functional category

(steam, hydro, transmission, etc.). The labor escalation rates are calculated


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using a weighted average of known contractual obligations and IHS Global

Insight forecast labor rates, by functional category (steam, hydro, transmission,

etc.).

The ratio of indirect labor embedded within non-labor (or “indirect

labor ratio”) is used to weight the indirect labor embedded within non-labor.

The ratios and escalation rates are calculated by function. Using this ratio for

weighting labor and non-labor, the non-labor escalation rate can be

mathematically represented as:

Non-labor Escalation rate = (Non-labor Escalation rate) * (1-Indirect Labor in Non-labor

Ratio) + (Labor Escalation rate) * (Indirect Labor in Non-labor Ratio)

Q. What do you mean by the non-labor escalation rate and labor escalation

rate?

A. I am referring to the labor and non-labor escalation rates as described in the

prior answer, for a particular function (e.g., transmission).

Q. Can you provide an example of these calculations?

A. Yes. Assume that the non-labor escalation rate for transmission is 2%, and that

the labor escalation rate for transmission is more than double that, or 5%. Note

that if do not make the adjustment that we are about to perform, the non-labor

escalation rate would remain at 2%, and would not reflect the fact that some of

the costs being escalated using the non-labor escalation rate are labor costs,

and rising at an annual rate of 5%. If we do not reflect these higher labor

escalation rates in the non-labor escalation rate, we will underestimate the


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amount of escalation in non-labor expense.

Continuing with the example, assume that the indirect labor ratio is as

calculated in the above example (.33). Under these assumptions, the non-labor

escalation rate would be equal to (2% * .67) + (5% * .33). Solving this

equation yields a non-labor escalation rate of 3%.

Q. Why is the non-labor escalation rate now higher than the 2% rate you

began with?

A. Because the non-labor escalation rate is now the weighted average of the non-

labor and labor components. It is the same mathematics as are involved in

calculating a weighted cost of capital. The non-labor escalation rate must

reflect the fact that one third of the transmission non-labor expense is actually

labor costs (indirect labor), which are rising at a 5% annual rate rather than a

2% rate. A blended 3% rate captures this.

Q. Did SCE revise its 2008 FERC Form 1 to correct some errors in January

of 2010?

A. Yes.

Q. Does your analysis contained in this rebuttal testimony reflect these

changes?

A. Yes, my indirect labor analysis above reflects the revised 2008 FERC Form 1

data.


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Function Original Revised DifferenceSteam Generation 4.55% 4.55% 0.000%Nuclear Generation 9.72% 9.72% 0.000%Hydro Generation 16.51% 16.49% -0.020%Other Generation 11.56% 11.56% 0.000%Transmission 11.73% 11.70% -0.035%Distribution 18.38% 18.43% 0.049%Customer Accounts 16.64% 16.64% 0.000%CS&I 1.77% 1.77% 0.000%

2008 FERC Form 1 Revision SummaryIndirect Labor in Nonlabor Rate Comparison

Q. Did the 2008 FERC Form 1 revision change the indirect labor in non-

labor ratios provided by Ms. Schiminske in the response to FERC Staff

settlement data request, question 59?

A. Yes. In the response to this data request, Ms. Schiminske corrected some

errors in filed workpapers and Table 4 in her testimony. However, that

response did not reflect the revision to the FERC Form 1. FERC Form 1

revision caused a slight change in the labor in non-labor rates provided by Ms.

Schiminske in FERC Staff settlement data request, question 59, Exhibit SCE-

50, pp. 18-20. The analysis of the difference is provided here:

Q. Did the change in the indirect labor in non-labor rates affect non-labor

escalation?

A. No. The revision did not change the forecast non-labor escalation rates.

Q. How does the change to the 2010 Distribution non-labor escalation rate

impact your TRR?

A. According to the impact analysis performed by Mr. Allstun, it would reduce

the requested TRR by $12,000.


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Q. Did you read Mr. Deters’ testimony provided in Exhibit S-1?

A. Yes, I did.

Q. What part of Mr. Deters’ testimony will you be addressing?

A. I will be addressing his testimony regarding Exhibit S-1, pages 15-17

regarding his testimony on “Non-labor Expense that is Actually Labor.”

Q. Do you agree with Mr. Deters’ recommendation in Exhibit S-1 Page 17,

line 14-16, “Given that SCE has not supported its calculation or use of

non-labor labor, the appropriate cost treatment is to remove the non-labor

labor from SCE’s labor ratio?”

A. No. In the above example, ignoring the adjustment that I have discussed

would result in a non-labor escalation rate of 2% rather than 3%. That would

escalate our non-labor costs (which include indirect labor) at the wrong rate.

To simply ignore the costs of indirect labor, which have been fully explained

and supported by our testimony and exhibits, would be irresponsible.

Otherwise, a misallocation will occur, and customers will be under-charged or

over-charged, neither of which is desirable.

Q. Did you read the testimony provided by Mr. David B. Cohen in Exhibit

ML-1?

A. Yes, I did.


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Q. Regarding Mr. Cohen’s testimony in Exhibit ML-1 on page 49-50

regarding non-labor O&M expenses, do you agree with Mr. Cohen’s

testimony concerning SCE’s non-labor O&M expenses?

A. No, for same reasons as I discuss regarding Mr. Deters’ testimony.

Q. Do you agree with Mr. Cohen’s definition of non-labor expenses in Exhibit

ML-1 on page 49 lines 12-14?

A. No. I do not agree with his simple definition. Mr. Cohen defined non-labor

O&M expenses as “expenses that are not related to the wages SCE pays or to

its salary costs.” This is incorrect. As presented in Ms. Argandona’s

testimony, labor allocations or interdepartmental chargebacks of indirect labor

expenses represent are also part of non-labor costs. However, Mr. Cohen does

provide some good examples of O&M non-labor expenses, such as helicopter

expenses, the cost of insulator trucks and material costs. All of these non-labor

expenses have indirect labor expenses included within them, as Ms.

Argandona’s explains.

Q. Can you elaborate on how Mr. Cohen’s examples of non-labor expenses

include an indirect labor component?

A. As described in SCE accounting systems testimony by Ms. Argandona, many

non-labor activities do in fact contain portions of indirect labor. That is the

way SCE’s accounting system was designed. The helicopter and insulator

truck expenses that Mr. Cohen cites as a non-labor O&M expenses are good


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examples. The maintenance charges for the helicopter and insulator truck

include the portion of labor attributable to maintaining the vehicles. In

addition, the costs of fleet management are examples of labor allocated to the

cost of these non-labor items. This practice is reasonable, supported, and

accepted by both Federal and State regulatory agencies. The wages and

salaries that SCE pays to the mechanic who maintains the helicopter are just as

much labor expenses as are the wages and salaries that SCE pays the pilot who

flies the helicopter. Both need to be taken into in calculating the escalation

ratios, as the above example shows. My calculations do that; Mr. Deters’, Mr.

Cohen’s, and Mr. Myers’ don’t.

Q. Does Mr. Cohen acknowledge that there are labor expenses booked to

non-labor O&M?

A. Yes. In Exhibit ML-1, on page 49, line 23 of his testimony he states “SCE

classifies certain labor costs as non-labor expenses.”

Q. How does Mr. Cohen propose to deal with these indirect labor expenses

booked to non-labor expenses?

A. Mr. Cohen simply wants to treat the indirect labor as a non-labor expense. In

other words, Mr. Cohen recommends escalating labor costs under the non-

labor escalation rate. Expressed differently, he would hold the non-labor

escalation rate at 2% in the above example, rather than setting it at 3%, which

is correct.


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Q. Is Mr. Cohen’s suggested methodology, to escalate indirect labor costs

with a non-labor escalation rate, an accurate methodology to predict

future labor costs?

A. No. He is incorrectly suggesting calculating an escalation rate for labor based

upon a non-labor escalation rate. A more appropriate methodology would be

to escalate the non-labor costs using IHS Global Insight’s non-labor

projections and to escalate the labor costs using SCE’s proposed labor

escalation rates, which are the weighted average of SCE contractual

obligations and IHS Global Insights forecast of labor costs, and which more

accurately represent the future labor costs SCE will incur. That is what SCE

does.

Q. Do you agree with Mr. Cohen’s recommendation on page 52?

A. No. SCE does not agree with Mr. Cohen’s recommendation that we should

escalate our indirect labor costs with non-labor escalation rates.

Q. Did you read the testimony provided by Mr. Myers in Exhibit SC-4?

A. Yes, I did.


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Q. Regarding Mr. Myers’ rebuttal testimony in Exhibit SC-4 on page 24,

lines 16-19, Mr. Myers claims “If Ms. Schiminske's argument that Labor

expense is mistakenly recorded in Non-labor Accounts in 2008 is valid,

then the sum of her FERC Labor and FERC Non-labor expenses in 2008

for each function should still equal and tie to the SCE 2008 FERC Form

1.” Do the costs reported in the unrevised 2008 FERC Form 1 (pages 322-

323) tie to the numbers provided within Ms. Schiminske’s response to

FERC Staff settlement data request, question 59?

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A. Yes. Mr. Myers is correct in his thinking; however, Ms. Schiminske

discovered an error in her filed workpapers and testimony. She corrected this

error in response to a FERC Staff data request. Consequently, the unrevised

2008 FERC Form 1 data on page 322-323 and the FERC Labor and Non-labor

data in FERC Staff settlement data request, question 59 (Exhibit SCE-50, pp.

18-20) do in fact match.

Q. Are you saying that Mr. Myers used the wrong data in his comparison in

Exhibit SC-11, page 2?

A. Yes, if Mr. Myers had used the data provided in the response to FERC Staff

settlement data request question 59 (Exhibit SCE-50, pp. 18-20) and compared

it to the unrevised 2008 FERC Form 1 data, which Ms. Schiminske’s data

request response was based upon, he would find that they do match.

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Q. Why did you use the “unrevised” 2008 FERC Form 1 for comparison?

A. The revised FERC Form 1 was issued after the completion of data request

FERC Staff settlement data request question 59. (Exhibit SCE-50, pp. 18-20.)

The unrevised 2008 FERC Form 1 was the basis for the calculation of data

request FERC Staff settlement data request, question 59.

Q. Can you prove that the 2008 unrevised FERC Form 1 and Ms.

Schiminske’s FERC Labor, Non-labor and total numbers from the

response to FERC Staff settlement data request, question 59, match?

A. Yes. I will provide Ms. Schiminske’s FERC Labor, Non-labor and total

numbers from FERC Staff settlement data request question 59 (Exhibit SCE-

50, pp. 18-20) highlight the exclusions for fuel, and replicate my calculations.

Next, I will add back in the exclusions to bring the number back up to the

FERC Form 1 data and demonstrate how Ms. Schiminske’s FERC Labor and

Non-labor data and the unrevised 2008 FERC Form 1 match. Next, I will pull

the totals directly from the 2008 unrevised FERC Form 1 and demonstrate how

they match.

I provide the analysis here:


From Indirect Labor in Nonlabor Calculation - Data Request set FERC STAFF-SCE-003

2008 2008 2008 2008Function Low High Acct. Exclude Amount Labor Nonlabor Total Total w/ ExclusionsSteam 500 514 501 96,040,624$ 3,630,869$ 50,374,771$ 54,005,640$ 150,046,264$ Nuclear 517 532 518 87,961,827$ 208,244,965$ 181,563,572$ 389,808,536$ 477,770,364$ Hydro 535 545 19,620,521$ 17,077,748$ 36,698,269$ 36,698,269$ Other 546 554 547 10,136,606$ 5,673,331$ 15,957,662$ 21,630,992$ 31,767,599$ Transmission 560 573 54,268,790$ 219,626,986$ 273,895,777$ 273,895,777$ Distribution 580 598 170,799,389$ 175,181,894$ 345,981,283$ 345,981,283$ Customer Accts. 901 905 107,200,921$ 100,192,662$ 207,393,584$ 207,393,584$ CS&I 907 910 72,097,386$ 458,970,792$ 531,068,178$ 531,068,178$ Total 2,054,621,317$ 2008 FERC FORM 1 (UNREVISED) 2008 UnrevisedPAGE 322-323 FERC FROM 1 FERC FORM 121 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 150,046,264$ 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 477,770,364$ 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 36,698,269$ 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 31,767,599$ 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 273,895,777$ 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 345,981,286$ 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 207,393,584$ 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 531,068,178$ Total 2,054,621,321$

Ferc Accounts Non Labor Fuel Accts

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Q. Are you saying that the unrevised FERC Form 1 and the FERC data in

FERC Staff settlement data request, question 59 match?

A. Essentially. Due to rounding, Distribution differs by only $3 and the total by

only $4.

Q. So, in summary, what are the implications of your analysis above on Mr.

Myers’ statement in Exhibit SC-4 on page 24, lines 16-19, “If Ms.

Schiminske's argument that Labor expense is mistakenly recorded in Non-

labor Accounts in 2008 is valid, then the sum of her FERC Labor and

FERC Non-labor expenses in 2008 for each function should still equal and

tie to the SCE 2008 FERC Form 1.”?


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A. I have shown that Ms. Schiminske’s corrected numbers do indeed match, and

therefore Mr. Myers cannot summarily dismiss SCE’s analysis on the grounds

that it is calculated inaccurately.

Q. Just to close the loop, above you provided testimony on the revised 2008

FERC Form 1 and calculate the impacts to the indirect labor in non-labor

ratios and non-labor escalation rates. Do the revised 2008 FERC Form 1

data match your new FERC labor and non-labor numbers used for

calculation of labor and non-labor escalation rates?

A. Yes, they match, without exception.

Q. Can you prove that your FERC numbers tie to the 2008 revised FERC

Form 1?

A. Yes. I will provide my FERC labor, non-labor and total numbers, highlight the

exclusions for fuel, and replicate my calculations. Next, I will add back in the

exclusions to bring the number back up to the FERC Form 1 data and

demonstrate how my FERC data and the 2008 revised FERC Form 1 match to

the dollar in every instance. Next I will pull the totals directly from the FERC

Form 1 and demonstrate how they match to the dollar.

I provide this analysis here:


From Indirect Labor in Nonlabor Calculation (revised 2008 FERC form 1)

2008 2008 2008 2008Function Low High Acct. Exclude Amount Labor Nonlabor Total Total w/ ExclusionsSteam 500 514 501 96,040,624$ 3,630,984$ 50,374,656$ 54,005,640$ 150,046,264$ Nuclear 517 532 518 87,961,827$ 208,244,965$ 181,563,572$ 389,808,536$ 477,770,364$ Hydro 535 545 19,648,952$ 17,049,316$ 36,698,269$ 36,698,269$ Other 546 554 547 10,136,606$ 5,673,331$ 15,957,662$ 21,630,992$ 31,767,599$ Transmission 560 573 54,268,508$ 231,308,992$ 285,577,500$ 285,577,500$ Distribution 580 598 171,164,970$ 163,719,036$ 334,884,006$ 334,884,006$ Customer Accts. 901 905 107,200,921$ 100,192,662$ 207,393,584$ 207,393,584$ CS&I 907 910 72,097,386$ 458,970,792$ 531,068,178$ 531,068,178$

2008 FERC FORM 1 (revised) 2008PAGE 322-323 FERC FROM 1 FERC FORM 121 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 150,046,264$ 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 477,770,364$ 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 36,698,269$ 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 31,767,599$ 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 285,577,500$ 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 334,884,006$ 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 207,393,584$ 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 531,068,178$

Non Labor Fuel AcctsFerc Accounts

1

3

4

5

6

7

8

9

10

Q. In Exhibit SC-4, does Mr. Myers compare the testimony O&M numbers 2

with the FERC Form 1 numbers?

A. Yes.

Q. What does Mr. Myers state about this comparison?

A. Mr. Myers states in Exhibit SC-4, page 24, lines 10-13 “The 2008 labor and

non-labor expenses supported by these three witnesses serve as the foundation

for the development of Period II O&M and A&G costs, and they all

substantially tie to the total costs (labor and non-labor) included in the 2008

SCE FERC Form 1.”


2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Q. Given your testimony above on the consistency of SCE’s calculations, is 1

there any basis for Mr. Myers’ statements that “These discrepancies in

labor costs among witnesses and with the Form 1 are unexplained and

render the adjustment proposed by Witness Schiminske unsupported and

unreliable”?

A. No. As stated above, Mr. Myers used the incorrect data in his analysis in

Exhibit SC-11, page 2 and, therefore, there is no basis for this statement or

conclusions. There are no discrepancies. All of Ms. Schiminske’s corrected

numbers match the 2008 unrevised FERC Form 1.

Q. In summary of your non-labor testimony, do you agree with witness

Myers’, Deters’, and Cohen’s conclusions that the labor in non-labor

adjustment is unsupported and should be removed from TRR?

A. No, I do not agree with removing indirect labor escalation. Now that we have

demonstrated that the indirect labor in non-labor is reasonable, supported,

calculated correctly, and matches FERC Form 1 data, SCE has proven the

validity and appropriateness of its indirect adjustment. In essence, the

witnesses recommend escalating indirect labor with a non-labor escalation rate.

It is essential that the utility’s labor expenses be correctly calculated,

otherwise, a misallocation will occur and ISO transmission customers will be

under-charged or over-charged, neither of which is desirable.


1

2

Q. Does this conclude your testimony?

A. Yes, it does.




)))

Dkt. No.

ER09-1534-001

DATA REQUEST RESPONSES IN SOUTHERN

CALIFORNIA EDISON COMPANY’S TO5 PROCEEDING (ER09-1534-001) CITED IN

WITNESS DR. PAUL T. HUNT’S PREPARED REBUTTAL TESTIMONY

(EXHIBIT SCE-50)

OCTOBER 2010

Prepared by: Robert Keyton Date: 9/21/10 Rule 403(c) Statement: I hereby certify that the above response is true and accurate to the best of my knowledge, information and belief formed after reasonable inquiry.

SCE-FERC Staff-29: At pages 13 and 14 of Exhibit No. S-7, Mr. Keyton

provides a list of 11 screening criteria that he used in forming his proxy group.

Please explain how each of these screening criteria is consistent with Commission

precedent, including specific citations to Commission decisions that adopt such

criteria.

Response: Subject to Staff’s objections and related discovery conferences with

SCE, Staff provides the following response. Screening criteria 1 (in part), 2, 4, 7

(in part), 8, 10, and 11 are based on Southern California Edison Company, 131

FERC ¶ 61,020 (2010) at PP 52, 56 and 58. Screening criteria 3 and 5 are based

on Golden Spread Electric Cooperative, Inc., 123 FERC ¶ 61,047 at P 64. The

rest of the criteria 1 (in part), 6, 7 (in part), and 9 have not been explicitly adopted

by the Commission but Staff believes that these criteria still closely follow the

Commission’s guidelines.


Southern California Edison

2010 Transmission Rate Case ER09-1534-000

DATA REQUEST SET SCE-CPUC-L002

To: SCE Prepared by: R. Mihai Cosman

Title: Senior Public Utilities Regulatory Analyst Dated: 10/08/2010

Question 001

Regarding the seven proxy group selection criteria listed on page 56 of Mr. Cosman's Exhibit

PUC-1, please provide the following information:

a. Please provide, in hardcopy and electronic form, all data used to apply the proxy

group screening criteria discussed at lines 2-12 of page 56 of Exhibit PUC-1.

b. If not included in the response to part a of this question, please provide the data

requested in part a for all Value Line Electric Utilities.

c. If not included in the responses to parts a and b of this question, please provide a copy

of all spreadsheets and computer models used to apply these screens, in printed and

electronic form. Please ensure that any computer spreadsheets provided preserve all

original data, with formulas available and cells unlocked. Please provide all computer

spreadsheets in Excel format.

Response to Question 001

a) All the data that Mr. Cosman used in his DCF calculation has already been provided

in Mr. Cosman’s testimony at CPUC Exhibit Nr. 2, Appendix C and in response to

SCE-CPUC-L001 Q1. The attached DCF spreadsheet in SCE-CPUC-L001 Q1 along

with Mr. Cosman’s previously submitted testimony contains all the data Mr. Cosman

used in his DCF calculation.

b) Please see response to part a.

c) Please see response to part a. No other spreadsheets or computer models were used.


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2

Question 002

Regarding Mr. Cosman's testimony at Exhibit PUC-1, page 57, lines 4-21, please provide the

following information:

a. Zack's Investment Survey growth rates for Mr. Cosman's proxy group and all Value Line

Electric Utilities.

b. All Value Line Investment Survey data used to calculate the "sustainable growth term"

discussed at Exhibit PUC-1, page 57, lines 11-17.

c. If not included in the response to part b of this question, please provide the data requested

in part b for all Value Line Electric Utilities.

d. Please provide the precise mathematical formulae used to calculate the b, r, s, and v terms

discussed at Exhibit PUC-1, page 57, lines 11-17.

e. Also regarding the b, r, s, and v terms, please provide a copy of all spreadsheets and

computer models used to produce these calculations, in printed and electronic form.

Please ensure that any computer spreadsheets provided preserve all original data, with

formulas available and cells unlocked. Please provide all computer spreadsheets in Excel

format.

f. Regarding Mr. Cosman's Zack's Investment Survey growth rates, please provide all

details regarding how Mr. Cosman obtained these data, including information regarding

intermediate data source or sources, if any, subscriptions required, etc.

Response to Question 002

a) The information requested has already been provided. Please see Mr. Cosman’s

testimony at CPUC Exhibit Nr. 2, Appendix C. Additionally, the DCF attachment to

SCE-CPUC-L001 Q1 contains a spreadsheet that includes the larger unsorted sample

before all screening criteria was applied. This is the extent of all the data that Mr.

Cosman used in preparing his DCF calculation, and it contains the information requested.

b) Please see answer to part a.

c) Please see answer to part b.

d) Mr. Cosman did not calculate the b, r, s, and v terms.

e) Please see answer to part d.


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3

f) The Energy Division of the California Public Utilities Commission does not have a

subscription to Zack’s Investment Survey, if one is available. The Zack’s growth rates

Mr. Cosman utilized in his DCF calculation are readily available on Zack’s website1

without a subscription. Mr. Cosman, on June 28, 2010, retrieved the growth rates for

each utility in the proxy group from Zack’s website.

1 www.zacks.com




DATA REQUEST SET SCE-CPUC-L001

To: SCE

Dated: 09/03/2010

Question 001:

Please provide all workpapers Mr. Cosman used to develop his testimony and the responses to these data requests. Please provide these workpapers in hardcopy format and as working electronic files that can be manipulated (i.e., in Excel spreadsheet format), with all formulas in place, and indexed so that the reviewer can trace the calculation from the data inputs through to the final result.

Response to Question 001:

All workpapers used by Mr. Cosman are attached to his testimony already submitted. For a

hardcopy, please see Exhibit No. PUC-2 of Mr. Cosman’s testimony. Electronic files of the

workpapers Mr. Cosman used to develop his testimony are attached:

• CPUC Capital Additions Adjustment – Appendix A

• CPUC Operations and Maintenance Expense Adjustment – Appendix B

• CPUC DCF Analysis – Appendix C

• PG&E 2008 Annual Report – Appendix E

In the process of compiling the electronic versions of Mr. Cosman’s workpapers, an error

pertaining to Mr. Cosman’s analysis on SCE’s Blanket and Blanket Specific projects was

identified. Mr. Cosman deducted $14,922,660 pertaining to Blanket and Blanket Specific

projects when in fact the entire $23,680,000 should have been deducted. Mr. Cosman should

have made an additional adjustment of $8,757,340. The error occurred in Exhibit CPUC-1 page

13, line 13 – 20 and page 14, line 1 – 19. Additionally, the error occurred in Exhibit CPUC-2


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page 2, Appendix A – Section 1.

The attached electronic CPUC Capital Additions Adjustment workpaper contains the corrected workpaper with the full adjustment that Mr. Cosman should have incorporated.

SCE-CPUC-L001 Q.001_A1_CPUC Capital Additions Worksheet_Appendix A.xls

SCE-CPUC-L001 Q.001_A2_CPUC O&M Adjustment_Attach B.xls

SCE-CPUC-L001 Q.001_A3_CPUC DCF_Appendix C.xls

SCE-CPUC-L001 Q.001_A4_PGE 2008 AnnualReport.pdf SCE-CPUC-L001 Q.001_A4_PGE 2008 AnnualReport.pdf


1 2 3 4 5 6 7 8 10 11 12 13

Avg High

Stk Price

Avg Low

Stk Price

Avg

Annual

Dividend

Low

Dividend

Yield

High

Dividend

Yield

Low

Expected

Dividend

Yield

High

Expected

Dividend

Yield

Zacks

Growth

Rates

Sustainable

Growth

Weighted

Avg

Growth

Rate

Low DCF

ROE

High DCF

ROE

Midpoint

DCF ROE

Alliant Energy BBB+ LNT 33.92 31.63 1.58 4.66% 5.00% 4.74% 5.12% 5.00% 3.60% 4.30% 8.34% 10.12% 9.23%

Amer. Elect. Power BBB AEP 34.83 32.85 1.64 4.71% 4.99% 4.79% 5.09% 4.00% 3.50% 3.75% 8.29% 9.09% 8.69%

Consolidated Edison A- ED 45.21 42.95 2.38 5.26% 5.54% 5.36% 5.65% 3.69% 3.85% 3.77% 9.05% 9.50% 9.27%

DTE Energy BBB DTE 46.59 43.70 2.12 4.55% 4.85% 4.65% 4.97% 5.00% 4.25% 4.63% 8.90% 9.97% 9.43%

Entergy Corp. BBB ETR 81.11 75.96 3.32 4.09% 4.37% 4.17% 4.54% 3.60% 7.75% 5.68% 7.77% 12.29% 10.03%

FirstEnergy Corp. BBB FE 40.91 37.82 2.2 5.38% 5.82% 5.47% 5.95% 3.50% 4.50% 4.00% 8.97% 10.45% 9.71%

Hawaiian Elec. BBB HE 22.66 20.83 1.24 5.47% 5.95% 5.53% 6.23% 9.33% 2.00% 5.67% 7.53% 15.56% 11.54%

Integrys Energy BBB+ TEG 47.25 43.67 2.72 5.76% 6.23% 5.87% 6.54% 10.03% 4.00% 7.02% 9.87% 16.57% 13.22%

Pepco Holdings BBB POM 16.90 16.04 1.06 6.27% 6.61% 6.32% 6.79% 5.33% 1.55% 3.44% 7.87% 12.12% 9.99%

PG&E BBB+ PCG 43.87 41.69 1.82 4.15% 4.37% 4.24% 4.52% 7.25% 4.50% 5.88% 8.74% 11.77% 10.26%

PPL Corp. BBB PPL 28.75 26.64 1.4 4.87% 5.26% 4.94% 5.33% 2.94% 3.00% 2.97% 7.88% 8.33% 8.11%

Progress Energy BBB+ PGN 40.23 38.17 2.48 6.16% 6.50% 6.27% 6.63% 4.00% 3.55% 3.78% 9.82% 10.63% 10.23%

SCANA Corp. BBB+ SCG 38.19 35.98 1.9 4.98% 5.28% 5.06% 5.39% 4.29% 3.50% 3.90% 8.56% 9.68% 9.12%

Sempra Energy BBB+ SRE 51.65 48.04 1.56 3.02% 3.25% 3.11% 3.36% 7.00% 5.75% 6.38% 8.86% 10.36% 9.61%

Vectren Corp. A- VVC 24.75 23.16 1.36 5.50% 5.87% 5.56% 6.02% 5.00% 2.25% 3.63% 7.81% 11.02% 9.41%

Wisconsin Energy BBB+ WEC 51.60 48.68 1.6 3.10% 3.29% 3.18% 3.44% 9.50% 5.00% 7.25% 8.18% 12.94% 10.56%

ZONE MAX 16.57%

ZONE MIN 7.53%

ZONE MEDIAN 9.66%


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Exhibit PUC-2, Page 10, Appendix C, Workpaper page

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Southern California Edison Company, Docket No. ER09-1534 TO-5 Transmission Rate Case

Responses!of!the!M"S"R!Public!Power!Agency!and!!

the!Los!Angeles!Department!of!Water!and!Power!!

to!the!First!Set!of!SCE!Data!Requests!!

Prepared!by!Jonathan!Lesser,!PhD!

September!17,!2010!

SCE!M!S!R/LADWP!86:""Please!provide!all!workpapers!Dr.!Lesser!used!to!

develop!his!testimony.!!!Please!provide!these!workpapers!in!hardcopy!

format!and!as!working!electronic!files!that!can!be!manipulated!(i.e.,!in!

Excel!spreadsheet!format),!with!all!formulas!in!place,!and!indexed!so!that!

the!reviewer!can!trace!the!calculation!from!the!data!inputs!through!to!the!

final!result.!

"

"

SCE!M!S!R/LADWP!86"Response:"""

"

The!files!attached!to!this!response!include!all!of!the!workpapers!I!used!to!

develop!my!testimony.!!They!are!provided!in!Excel!spreadsheet!formula!with!all!

formulas!intact.!!I!understand!that!the!M"S"R!attorneys!are!sending!a!hard!copy!

to!you!by!mail.!!!

!

!


CALCULATION OF "BR+SV" EARNINGS GROWTH RATES

AND SUPPORTING DATA

Docket No. ER09-1534-000Exhibit MSR-5

Page 1 of 2

FERC COMPARABLE GROUP

Company SymbolEarnings Per

Share (EPS)

Dividend Per

Share (DPS)

Book Value

Per Share

(BV)

Internal

Growth (br)

Average

Market Price

Per Share

(MV)

MV/BV 2008 20112008-2011

Growth

External

Growth (sv)br+sv

[2] [3] [4] [6] [7] [8]

1 Alliant Energy LNT 2.41$ 1.52$ 26.11$ 3.27% 31.79$ 1.22 110.45 112.00 0.47% 0.10% 3.37%

2 Amer.Elec. Power AEP 3.02$ 1.65$ 28.04$ 4.91% 33.57$ 1.20 406.07 488.00 6.32% 1.24% 6.15%

3 Centerpoint Energy CNP 1.17$ 0.76$ 6.78$ 5.96% 13.89$ 2.05 346.09 400.00 4.94% 5.19% 11.15%

4 Consol. Edison ED 3.34$ 2.37$ 36.41$ 2.66% 43.49$ 1.19 273.70 281.00 0.88% 0.17% 2.83%

5 DPL Inc. DPL 2.23$ 1.17$ 9.17$ 11.43% 26.94$ 2.94 115.96 122.00 1.71% 3.31% 14.73%

6 DTE Energy DTE 3.22$ 2.16$ 38.75$ 2.66% 44.25$ 1.14 163.02 172.00 1.80% 0.26% 2.92%

7 Duke Energy DUK 1.16$ 0.92$ 16.87$ 1.42% 16.34$ 0.97 1272.00 1335.00 1.62% -0.05% 1.37%

8 Exelon Corp. EXC 4.13$ 2.08$ 19.55$ 10.64% 44.58$ 2.28 658.00 664.00 0.30% 0.39% 11.02%

9 Hawaiian Electric HE 1.23$ 1.24$ 15.84$ -0.64% 21.06$ 1.33 90.52 96.50 2.16% 0.71% 0.07%

10 IDACORP, Inc. IDA 2.57$ 1.20$ 29.69$ 4.55% 33.08$ 1.11 46.92 49.00 1.46% 0.17% 4.72%

11 Northeast Utilities NU 1.90$ 0.96$ 20.59$ 4.60% 25.97$ 1.26 155.83 176.00 4.14% 1.08% 5.68%

12 Pepco Holdings POM 1.43$ 1.08$ 19.48$ 1.30% 16.35$ 0.84 218.91 235.00 2.39% -0.38% 0.92%

13 PG&E Corp. PCG 3.30$ 1.73$ 28.58$ 5.49% 42.77$ 1.50 361.06 390.00 2.60% 1.29% 6.78%

14 Portland General POR 1.47$ 1.02$ 21.13$ 2.09% 19.40$ 0.92 62.58 90.00 12.88% -1.05% 1.03%

15 PPL Corp. PPL 2.51$ 1.47$ 15.32$ 4.89% 28.20$ 1.84 374.58 379.00 0.39% 0.33% 5.22%

16 Progress Energy PGN 3.05$ 2.49$ 34.28$ 1.63% 38.89$ 1.13 264.00 284.00 2.46% 0.33% 1.96%

17 PSEG PEG 3.09$ 1.33$ 17.84$ 9.97% 31.30$ 1.75 506.02 506.00 0.00% 0.00% 9.97%

18 SCANA Corp SCG 2.95$ 1.88$ 27.87$ 3.85% 36.42$ 1.31 118.00 138.00 5.36% 1.64% 5.49%

19 Sempra Energy SRE 4.54$ 1.54$ 37.31$ 8.13% 50.75$ 1.36 243.32 250.00 0.91% 0.33% 8.46%

20 TECO Energy TE 1.04$ 0.81$ 9.96$ 1.91% 15.66$ 1.57 212.90 216.00 0.48% 0.28% 2.19%

21 Vectren Corp. VVC 1.83$ 1.35$ 17.30$ 2.77% 23.65$ 1.37 81.03 82.00 0.40% 0.15% 2.92%

22 Wisconsin Energy WEC 3.41$ 1.41$ 31.17$ 6.44% 49.34$ 1.58 116.92 117.00 0.02% 0.01% 6.45%

23 Xcel Energy XEL 1.55$ 0.98$ 16.22$ 3.50% 20.98$ 1.29 453.79 484.00 2.17% 0.64% 4.13%

Notes:

[1] Source: Value Line Investment Survey (Arithmetic Average of 2008, 2009, and 2011 Forecast Values)

[2] Equals (EPS-DPS)/BV

[3] Equals arithmetic average of 6-month monthly high and low stock prices ending May 28, 2010.

[4] Equals MV/BV

[5] Source: Value Line Investment Survey (Common Shares Outstanding in Millions Adjusted for Split)

[6] Equals annual growth of common shares outstanding in [5]

[7] Equals ([4]-1)*[6]

[8] Equals [2]+[7]

Earnings Growth Rates (br+sv)

[1] [5]

Common Shares Outstanding (in millions)


CALCULATION OF "BR+SV" EARNINGS GROWTH RATES

AND SUPPORTING DATA

Docket No. ER09-1534-000Exhibit MSR-5

Page 2 of 2

FERC Comparables Group Note: Declared dividends per share, per VL 2008 2009 2011 2008 2009 2011 Average Average

EPS 08 EPS 09 EPS 11 DPS 08 DPS 09 DPS 11 BVS 08 BVS 09 BVS 11 b b b r r r b r br

1 Alliant Energy $2.54 $1.89 $2.80 $1.40 $1.50 $1.65 $25.56 $25.07 $27.70 44.9% 20.6% 41.1% 10% 7.5% 10.1% 35.5% 9.2% 3.27%

2 Amer.Elec. Power $2.99 $2.97 $3.10 $1.64 $1.64 $1.66 $26.33 $27.49 $30.30 45.2% 44.8% 46.5% 11% 10.8% 10.2% 45.5% 10.8% 4.91%

3 Centerpoint Energy $1.30 $1.01 $1.20 $0.73 $0.76 $0.80 $5.89 $6.74 $7.70 43.8% 24.8% 33.3% 22% 15.0% 15.6% 34.0% 17.5% 5.96%

4 Consol. Edison $3.36 $3.16 $3.50 $2.34 $2.36 $2.40 $35.43 $36.10 $37.70 30.4% 25.3% 31.4% 9% 8.8% 9.3% 29.0% 9.2% 2.66%

5 DPL Inc. $2.12 $2.01 $2.55 $1.10 $1.14 $1.28 $8.41 $9.25 $9.85 48.1% 43.3% 49.8% 25% 21.7% 25.9% 47.1% 24.3% 11.43%

6 DTE Energy $2.73 $3.24 $3.70 $2.12 $2.12 $2.24 $36.77 $38.19 $41.30 22.3% 34.6% 39.5% 7% 8.5% 9.0% 32.1% 8.3% 2.66%

7 Duke Energy $1.01 $1.13 $1.35 $0.86 $0.90 $0.99 $16.50 $16.70 $17.40 14.9% 20.4% 26.7% 6% 6.8% 7.8% 20.6% 6.9% 1.42%

8 Exelon Corp. $4.10 $4.29 $4.00 $2.05 $2.10 $2.10 $16.79 $19.15 $22.70 50.0% 51.0% 47.5% 24% 22.4% 17.6% 49.5% 21.5% 10.64%

9 Hawaiian Electric $1.07 $0.91 $1.70 $1.24 $1.24 $1.24 $15.35 $15.58 $16.60 -15.9% -36.3% 27.1% 7% 5.8% 10.2% -8.4% 7.7% -0.64%

10 IDACORP, Inc. $2.18 $2.64 $2.90 $1.20 $1.20 $1.20 $27.76 $29.17 $32.15 45.0% 54.5% 58.6% 8% 9.1% 9.0% 52.7% 8.6% 4.55%

11 Northeast Utilities $1.86 $1.85 $2.00 $0.83 $0.95 $1.10 $19.38 $20.30 $22.10 55.4% 48.6% 45.0% 10% 9.1% 9.0% 49.7% 9.3% 4.60%

12 Pepco Holdings $1.93 $0.95 $1.40 $1.08 $1.08 $1.08 $19.14 $19.50 $19.80 44.0% -13.7% 22.9% 10% 4.9% 7.1% 17.7% 7.3% 1.30%

13 PG&E Corp. $3.22 $3.03 $3.65 $1.56 $1.68 $1.96 $25.97 $27.88 $31.90 51.6% 44.6% 46.3% 12% 10.9% 11.4% 47.5% 11.6% 5.49%

14 Portland General $1.39 $1.31 $1.70 $0.97 $1.01 $1.07 $21.64 $20.50 $21.25 30.2% 22.9% 37.1% 6% 6.4% 8.0% 30.1% 6.9% 2.09%

15 PPL Corp. $1.19 $3.25 $3.10 $1.34 $1.38 $1.68 $13.55 $14.60 $17.80 -12.6% 57.5% 45.8% 9% 22.3% 17.4% 30.2% 16.2% 4.89%

16 Progress Energy $2.96 $3.03 $3.15 $2.46 $2.48 $2.52 $32.55 $34.30 $36.00 16.9% 18.2% 20.0% 9% 8.8% 8.8% 18.3% 8.9% 1.63%

17 PSEG $2.90 $3.08 $3.30 $1.29 $1.33 $1.37 $15.36 $17.15 $21.00 55.5% 56.8% 58.5% 19% 18.0% 15.7% 56.9% 17.5% 9.97%

18 SCANA Corp $2.95 $2.85 $3.05 $1.84 $1.88 $1.92 $25.81 $27.50 $30.30 37.6% 34.0% 37.0% 11% 10.4% 10.1% 36.2% 10.6% 3.85%

19 Sempra Energy $4.43 $4.78 $4.40 $1.37 $1.56 $1.68 $32.75 $36.54 $42.65 69.1% 67.4% 61.8% 14% 13.1% 10.3% 66.1% 12.3% 8.13%

20 TECO Energy $0.77 $1.00 $1.35 $0.80 $0.80 $0.82 $9.43 $9.75 $10.70 -3.9% 20.0% 39.3% 8% 10.3% 12.6% 18.5% 10.3% 1.91%

21 Vectren Corp. $1.79 $1.80 $1.90 $1.31 $1.35 $1.39 $16.68 $17.23 $18.00 26.8% 25.0% 26.8% 11% 10.4% 10.6% 26.2% 10.6% 2.77%

22 Wisconsin Energy $3.03 $3.20 $4.00 $1.08 $1.35 $1.80 $28.54 $30.51 $34.45 64.4% 57.8% 55.0% 11% 10.5% 11.6% 59.1% 10.9% 6.44%

23 Xcel Energy $1.46 $1.49 $1.70 $0.94 $0.97 $1.03 $15.35 $15.92 $17.40 35.6% 34.9% 39.4% 10% 9.4% 9.8% 36.6% 9.5% 3.50%




DATA REQUEST SET FERC STAFF-SCE-L001

To: FERC STAFF

Prepared by: Paul T. Hunt

Title: Manager of Regulatory Finance and Economics

Dated: 06/14/2010

Received Date: 06/14/2010

Question 017:

With respect to the Direct Testimony of Yelena Schiminske, Exhibit SCE-16, page 7, line 8, through page 8, line 4:

a) Please explain, in detail, why SCE’s accounting system books certain labor costs in non-labor expense.

b) Please list and describe each criterion used to determine which labor costs and amounts are booked as non-labor expense?

c) Please provide and explain the derivation of the percentages of non-labor expense that is actually labor expense presented in Table 4. Include all supporting workpapers with your response.

d) Please list and describe what specific labor is represented by these percentages.

e) Please explain, in detail, why the wages and salaries identified by FERC account in Statement AI do not reflect these “non-labor” labor amounts.

Response to Question 017:

a) SCE’s accounting systems were designed for the dual purposes of accurate financial/regulatory reporting and useful management reporting. When planning for the situation of costs incurred in one area or activity and transferred, charged back or allocated to another area, SCE was faced with a choice as to how to characterize these charges. One option would be to retain the original designations of Labor, Materials, etc. The negative to this option is that managers responsible for budgeting and managing costs would not be able to distinguish charges that they incur directly from charges transferred to them. As such, for example, managers trying to monitor their labor budget would see charges for employees other than their own. The alternative to this is to recast the transferred charge with a


designation describing the nature of the transfer, i.e., Automotive, Supply Expense, Division Overhead, etc.

SCE’s accounting system does re-cast certain costs using the nature of the transfer, but the internal record is marked with the labor component. This is what allows Edison to make adjustments to account for the labor that gets booked and reported as Non-Labor.

As an example, Tool Expense includes the purchase costs of tools as well as the labor for the staff of the tool rooms in each service center. Tool Expense is accumulated in a clearing account as Labor, Materials, etc. It is then allocated to the cost objects consuming the tools with the designation “Tool Expense” which is defined as Non-Labor. This allows managers to monitor their tool expense as an activity. The company can still do studies using the internal record to determine the labor component of these transferred or allocated charges.

SCE is providing two examples, one example shows how division overhead (including the applicable labor expenses) is allocated. This example uses SCE's retired accounting system "CARS". The second example shows how tool expense (including the labor expenses) is allocated. This example is based on SCE's new SAP accounting system. These examples are contained in the spreadsheets that are attached to this response.

b) During January-June 2008, SCE’s system of record was “CARS” and during July-December 2008, SCE’s system of records was SAP. The answer to this question will be split according to the two systems.

Under CARS, all labor charged directly to a business unit function maintains its classification as labor. All labor charged to an activity that is either transferred or allocated to a business unit function is summarized with the non-labor component and recorded as non-labor. This would include Divisional Overheads, Automotive, Internal Chargebacks (IMM), Job Orders, Supply Expense and Tool Expense. In the case of capitalized A&G, the credit to O&M is all recorded as non-labor.

Within SAP, the instances of labor being booked as non-labor are affected by the structure of the software cost flow processing. SAP utilizes a special module for reporting costs for regulatory reporting, known as the FERC module. Within the initial processing of charges within SAP used for management reporting, a similar concept to CARS reporting is employed where most transferred labor is designated as non-labor. This is done for the reasons outlined in part a) above. However, for regulatory reporting, in most cases, the FERC module unwinds the transfer designation and re-instates the classification of labor. The situation where labor is still reported as non-labor relates to certain instances of Divisional Overheads and other allocations for TDBU. The reason they are not recorded as non-labor is not due to application of criterion, but rather because of the FERC module treatment of TDBU’s cost flows.

c) As explained in the response to part a) above, in the recorded data there is a portion of labor that is recorded as non-labor. In order to account for this in the escalation rate calculations,


we develop “weights” that represent the portion of labor numbers within non-labor data.

Each year, SCE calculates true labor cost data by reallocating these labor costs to the appropriate accounts. These true labor cost data are aggregated by three-digit FERC accounts. We subtract FERC account labor data from the true labor data in order to get the labor component that is booked in non-labor expense. Finally, we divide this labor- in-non-labor component by total FERC non-labor amount. These percentages represent the portion of labor expense within non-labor expense. We use these as weights to adjust Global Insight non-labor escalation rates to be consistent with how labor costs are recorded in our FERC expense data.

A copy of Period II Statement AH/AI workpapers, Volume 9, Schiminske, WP-AH/AI-8 thru 10 of 10 is attached.

d) See the response to part b) above.

e) As stated in part a) above, these “non-labor” labor amounts are not booked to labor accounts, thus they would not be reflected in the Statement AI wage and salary amounts.


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WP-AH/AI- 8 of 10 SCHIMINSKE


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UNITED STATES OF AMERICA

BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

SKEWNESS OF DCF ESTIMATES

(EXHIBIT SCE-51)

OCTOBER 2010

Avg Low High Avg

American Electric Power AEP 9.27% Alliant Energy LNT 8.00% 15.10% 11.55%

Amer.Elec. Power AEP 8.85% 11.34% 10.09%

CenterPoint Energy CNP 12.99% Centerpoint Energy CNP 10.67% 17.15% 13.91%

Consol. Edison ED 8.22% 10.80% 9.51%

DTE Energy Company DTE 9.27% DPL Inc. DPL

DTE Energy DTE 7.63% 9.99% 8.81%

IDACORP, Inc. IDA 8.58% Duke Energy DUK 6.81% 10.18% 8.49%

Exelon Corp. EXC

Northeast Utilities NU 9.99% Hawaiian Electric HE

IDACORP, Inc. IDA 8.07% 8.61% 8.34%

Portland General Electric Co. POR 8.78% Northeast Utilities NU 9.33% 11.45% 10.39%

Pepco Holdings POM 7.33% 14.60% 10.97%

TECO Energy, Inc. TE 11.74% PG&E Corp. PCG 10.74% 11.08% 10.91%

Portland General POR

Skewness 1.14 PPL Corp. PPL 7.75% 10.47% 9.11%

Progress Energy PGN 8.25% 10.56% 9.41%

PSEG PEG

SCANA Corp SCG 9.25% 10.98% 10.11%

Sempra Energy SRE

TECO Energy TE

Vectren Corp. VVC 8.53% 10.91% 9.72%

Wisconsin Energy WEC 9.20% 12.48% 10.84%

Xcel Energy XEL 8.74% 11.25% 9.99%

Skewness 1.24 1.31

Keyton Lesser


Low High Avg Low High Avg

Alliant Energy 9.19% 13.80% 11.49% Alliant Energy 8.34% 10.12% 9.23%

Amer. Elec. Power 8.73% 10.21% 9.47% Amer. Elect. Power 8.29% 9.09% 8.69%

CenterPoint Energy 10.64% 13.77% 12.21% Consolidated Edison 9.05% 9.50% 9.27%

Consol. Edison 8.38% 10.79% 9.59% DTE Energy 8.90% 9.97% 9.43%

Dominion Resources 9.19% 10.16% 9.68% Entergy Corp. 7.77% 12.29% 10.03%

DPL Inc. FirstEnergy Corp. 8.97% 10.45% 9.71%

DTE Energy 8.43% 10.02% 9.22% Hawaiian Elec. 7.53% 15.56% 11.54%

Duke Energy 7.74% 10.51% 9.13% Integrys Energy 9.87% 16.57% 13.22%

G't Plains Energy Pepco Holdings 7.87% 12.12% 9.99%

Hawaiian Elec. 8.83% 13.99% 11.41% PG&E 8.74% 11.77% 10.26%

Integrys Energy 7.81% 16.12% 11.97% PPL Corp. 7.88% 8.33% 8.11%

Northeast Utilities 8.30% 11.58% 9.94% Progress Energy 9.82% 10.63% 10.23%

OGE Energy 7.74% 11.93% 9.84% SCANA Corp. 8.56% 9.68% 9.12%

Pepco Holdings Sempra Energy 8.86% 10.36% 9.61%

PG&E Corp. 10.34% 11.32% 10.83% Vectren Corp. 7.81% 11.02% 9.41%

Portland General 7.45% 10.60% 9.03% Wisconsin Energy 8.18% 12.94% 10.56%

Progress Energy 8.15% 10.54% 9.35%

Public Serv. Enterprise Skewness 1.61 1.49

SCANA Corp. 9.29% 10.60% 9.95%

Sempra Energy

TECO Energy 9.94% 11.76% 10.85%

Wisconsin Energy 9.58% 12.87% 11.23%

Xcel Energy Inc. 9.01% 11.31% 10.16%

Skewness 0.92 0.55

CosmanSolomon


Low High Avg

Alliant Energy 9.46% 15.06% 12.26%

Amer. Elec. Power 9.17% 9.76% 9.46%

CenterPoint Energy 11.10% 14.24% 12.67%

Consol. Edison 8.33% 10.02% 9.18%

Dominion Resources 7.79% 10.18% 8.99%

DPL Inc.

DTE Energy 8.67% 9.93% 9.30%

Duke Energy 7.85% 10.12% 8.99%

Exelon Corp.

G't Plains Energy

Hawaiian Elec. 8.14% 13.25% 10.70%

IDACORP, Inc. 7.35% 9.15% 8.25%

Integrys Energy 7.33% 15.67% 11.50%

NextEra Energy 10.67% 11.86% 11.27%

Northeast Utilities 8.74% 11.54% 10.14%

OGE Energy 8.64% 12.17% 10.40%

PG&E Corp. 10.37% 11.52% 10.95%

Portland General 7.49% 11.06% 9.27%

Progress Energy 8.36% 10.05% 9.20%

Public Serv. Enterprise

SCANA Corp. 9.79% 10.56% 10.18%

Sempra Energy

TECO Energy 9.88% 12.15% 11.02%

Westar Energy 8.12% 15.16% 11.64%

Wisconsin Energy 10.00% 12.85% 11.43%

Xcel Energy Inc. 9.01% 11.60% 10.30%

Skewness 0.83 0.20

Hunt (Updated September)



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

LIST OF ELECTRIC UTILITIES FROM

STANDARD & POOR’S RATINGSDIRECT

(EXHIBIT SCE-52)

OCTOBER 2010

Ratings Summary: Electric

Last Updated: 20-Sep-2010 18:11:51 EST

Description Long-TermRating CreditWatch/Outlook MDS Score Date

AES Corp. (The)

Alabama Power Co.

Allegheny Energy Supply Co. LLC

American Electric Power Co. Inc.

Cinergy Corp.

Constellation Energy Group Inc.

DPL Inc.

Duke Energy Carolinas LLC

Dynegy Holdings Inc.

Edison Mission Energy

Energy Future Holdings Corp.

Entergy Corp.

Exelon Corp.

Exelon Generation Co. LLC

FirstEnergy Corp.

FPL Group Capital Inc.

KCP&L Greater Missouri Operations Co.

Mirant North America LLC

NextEra Energy Inc.

Northeast Utilities

NRG Energy Inc.

Pacific Gas & Electric Co.

PEPCO Holdings Inc.

PPL Energy Supply LLC

Progress Energy Inc.

PSEG Power LLC

RRI Energy Inc.

Southern California Edison Co.

Southern Co.

Texas Competitive Electric Holdings Co. LLC

AEP Resources Inc.

AEP Texas Central Co

AEP Texas North Co

Alabama Power Capital Trust I

Allegheny Energy Inc.

Allegheny Generating Co.

ALLETE Inc.

AmerenEnergy Generating Co.

American Transmission Co.

American Transmission Systems, Inc.

Appalachian Power Co.

Aquila Merchant Services Inc

Arizona Public Service Co.

Arnold Fuel Inc.

Atlantic City Electric Co.

Baltimore Gas & Electric Co.

Bangor Hydro-Electric Co.

Black Hills Power & Light Co.

Black Hills Power Inc.

California Indpt Sys Operator Corp

Calpine CCFC Holdings LLC

Calpine Construction Finance Co. L.P.

Calpine Corp.

Calpine Generating Co. LLC

Cambridge Electric Light Co.

Canal Electric Co.

Carolina Power & Light Co. d/b/a Progress Energy Carolinas Inc.

CenterPoint Energy Houston Electric LLC

Central and South West Corp.

Central Hudson Gas & Electric Corp.

Central Illinois Light Co.

Central Illinois Public Service Co.

Central Maine Power Co.

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Central Vermont Public Service Corp.

CILCORP Inc.

CL&P Capital L.P.

Cleco Corp.

Cleco Power LLC

Cleveland Electric Illuminating Co.

Cobb Elec Membership Corp

Cogentrix Energy Inc.

Columbia Fuels Inc.

Columbus & Southern Ohio Electric Co.

Columbus Southern Power Co.

ComEd Financing I

Commonwealth Edison Co.

Connecticut Light & Power Co.

Connecticut Yankee Atomic Power Co.

Consumers Energy Co.

Coral Energy LLC

Covanta ARC LLC

Covanta Energy Corp.

CTC Mansfield Funding Corp.

Dayton Power & Light Co.

Dayton Ventures Inc.

Delmarva Power Financing I

Detroit Edison Co.

DQU II Funding Corp.

Duke Energy Corp.

Duke Energy Indiana Inc.

Duke Energy Kentucky Inc.

Duke Energy Ohio Inc.

Duquesne Capital L.P.

Duquesne Light Co.

Duquesne Light Holdings Inc.

Dynegy Inc.

E.ON U.S. LLC

Edison International

Edison Mission Energy Funding Corp.

Edison Mission Marketing and Trading

El Paso Electric Co.

Empire District Electric Co.

Empire District Electric Trust II

Energy Future Competitive Holdings Co.

Energy Future Intermediate Holding Company LLC

Enron Corp.

Entergy Arkansas Inc.

Entergy Gulf States Inc.

Entergy Gulf States Louisiana LLC

Entergy Louisiana Capital I

Entergy Louisiana Holdings Inc.

Entergy Louisiana LLC

Entergy Mississippi Inc.

Entergy New Orleans Inc.

Entergy Texas Inc.

error correction

First Choice Power

First PV Funding Corp.

FirstEnergy Solutions Corp.

Florida Power & Light Co.

Florida Power Corp. d/b/a Progress Energy Florida Inc.

Florida Progress Corp.

GenOn Energy Inc.

GenOn Escrow Corp.

Georgia Power Capital, L.P.

Georgia Power Co.

GG1A Funding Corp.

GPU Inc.

Great Plains Energy Inc.

Green Mountain Power Corp.

Gulf Power Co.

Hartford Electric Light Co.

Hawaii Electric Light Company, Inc.

Hawaiian Electric Co. Inc.

Hawaiian Electric Industries Inc.

Iberdrola Renewables Holdings Inc.

IDACORP Inc.

Idaho Power Co.




Illinois Power Co.

Illinois Power Financing I

Illinois Power Fuel Co.

Illinova Corp.

Indiana Michigan Power Co.

Indianapolis Power & Light Co.

International Transmission Co.

Interstate Power & Light Co.

Interstate Power Co.

Iowa Power Inc.

Iowa Southern Utilities Co.

Iowa-Illinois Gas & Electric Co.

IPALCO Enterprises Inc.

ITC Holdings Corp.

ITC Midwest LLC

JC P&L Capital, L.P.

Jersey Central Power & Light Co.

Kansas City Power & Light Co.

Kansas Gas & Electric Co.

Kentucky Power Co.

Kentucky Utilities Co.

KeySpan Generation LLC

Long Island Lighting Co.

Louisville Gas & Electric Co.

Maine Yankee Atomic Power Co.

Marlin Water Trust II

Massachusetts Electric Co.

Maui Electric Company, Ltd.

Met-Ed Capital L.P.

Metropolitan Edison Co.

Michigan Electric Transmission Co

MidAmerican Energy Co.

Midwest Generation LLC

Midwest Independent Transmission System Operator Inc.

Mirant Americas Energy Marketing L.P.

Mirant Americas Generating LLC

Mirant Corp.

Mississippi Power Co.

Missouri Power & Light Co.

Monongahela Power Co.

Narragansett Electric Co.

National Energy & Gas Transmission Inc.

National Grid USA

Nevada Power Co.

New Century Energies Inc.

New England Power Co.

NewEnergy Inc.

Niagara Mohawk Power Corp.

North Atlantic Energy Corp.

Northern Indiana Public Service Co.

Northern States Power Co.

Northern States Power Wisconsin

Northwestern Energy Montana

NSTAR Electric Co.

NV Energy Inc.

OES Fuel Inc.

Ohio Edison Co.

Ohio Edison Financing Trust

Ohio Edison Financing Trust II

Ohio Power Co.

Ohio Valley Electric Corp.

Oklahoma Gas & Electric Co.

Oncor Electric Delivery Co. LLC

Orange and Rockland Utilities Inc.

Orion Power Holdings Inc.

Otter Tail Corp.

Otter Tail Power Company

Oyster Creek Fuel Corp.

PacifiCorp

PacifiCorp Capital I

PacifiCorp Delaware LP

PacifiCorp Group Holdings Co.

PacifiCorp Holdings Inc.

PECO Energy Capital L.P.

PECO Energy Co.




Penelec Capital

Penn Fuel Corp.

Pennsylvania Electric Co.

Pennsylvania Power & Light Energy Trust

Pennsylvania Power Co.

PG&E Capital I, II, III, IV

Pinnacle West Capital Corp.

Pinnacle West Energy Corp.

PNG Companies LLC

PNM Resources Inc.

PNPP II Funding Corp.

Portland General Electric Co.

Potomac Capital Investment Corp.

Potomac Edison Co.

Potomac Electric Power Co.

PPL Corp.

PPL Electric Utilities Corp.

Public Service Co. of Colorado

Public Service Co. of New Hampshire

Public Service Co. of New Mexico

Public Service Co. of Oklahoma

Public Service Electric & Gas Co.

PVNGS Funding Corp. Inc.

PVNGS II Funding Corp. Inc.

Reliant Energy HL&P

Reliant Energy Mid-Atlantic Power Holdings LLC

Rochester Gas & Electric Corp.

Rockland Electric Co.

San Miguel Electric Cooperative Inc.

Savannah Electric & Power Co.

Scottish Power Finance U.S.

Sierra Pacific Power Capital I

Sierra Pacific Power Co.

South Carolina Electric & Gas Co.

Southern Co. Services Inc.

Southern Company Funding Corp.

Southern Electric Generating Co.

Southern Indiana Gas & Electric Co.

Southern Power Co.

Southwestern Electric Power Co.

Southwestern Public Service Co.

St. Joseph Light & Power Co.

System Energy Resources Inc.

Tampa Electric Co.

Texas Genco LLC

Texas-New Mexico Power Co.

Thermal North America Inc.

Toledo Edison Co.

Trans-Allegheny Interstate Line Company

TU Electric Capital I

TU Electric Capital II

TU Electric Capital III

Tucson Electric Power Co.

UIL Holdings Corp.

Unicom Corp.

Union Electric Co. d/b/a AmerenUE

United Capital Funding Partnership L.P.

United Illuminating Co. (The)

USGen New England, Inc.

Utah Power & Light Co.

Vectren Capital Corp.

Virginia Electric & Power Co.

Virginia Power Capital Trust I

West Penn Power Co.

Westar Energy Inc.

Western Massachusetts Electric Co.

Western Resources Capital II

Wisconsin Electric Fuel Trust

Wisconsin Electric Power Co.

Wisconsin Power & Light Co.

Wisconsin Public Service Corp.

WPS Resources Capital Corp.





BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

CAPITAL COST UNDER-RECOVERY FROM

FERC STAFF CAPITAL STRUCTURE PROPOSAL

(EXHIBIT SCE-53)

OCTOBER 2010

SINGLE ISSUE EMBEDDED COST CALCULATION

Assumptions:

Issuance (Face Value): 100,000,000

Maturity (in Years) 30

Coupon 7.00%

Issuance Costs

Discount 0.05% 50,000

Expense 0.09% 90,000

Total Issuance Cost 140,000

Net Proceeds from Issuance 99,860,000

Recovery of Debt Cost (FERC Method) Debt Cost

"Cost of Money" 7.0113%

(FERC Regulations, Statement AV, 18 CFR )

Year Cost of Debt Rate Base

Revenue

Requirement Cost

Under-/Over-

Recovery

Present Value

(At Cost of

Debt) Total

Interest

Expense

Amortization

(Issuance Costs

/Maturity)

Net Proceeds

(Mid-Year)

Annual Cost/

Net Proceeds

0 99,860,000

1 7.0113% 99,862,333 7,001,643 7,004,667 -3,024 -2,826 7,004,667 7,000,000 4,667 99,862,333 7.0143%

2 7.0113% 99,867,000 7,001,970 7,004,667 -2,697 -2,355 7,004,667 7,000,000 4,667 99,867,000 7.0140%

3 7.0113% 99,871,667 7,002,297 7,004,667 -2,370 -1,934 7,004,667 7,000,000 4,667 99,871,667 7.0137%

4 7.0113% 99,876,333 7,002,624 7,004,667 -2,042 -1,557 7,004,667 7,000,000 4,667 99,876,333 7.0133%

5 7.0113% 99,881,000 7,002,951 7,004,667 -1,715 -1,222 7,004,667 7,000,000 4,667 99,881,000 7.0130%

6 7.0113% 99,885,667 7,003,279 7,004,667 -1,388 -924 7,004,667 7,000,000 4,667 99,885,667 7.0127%

7 7.0113% 99,890,333 7,003,606 7,004,667 -1,061 -660 7,004,667 7,000,000 4,667 99,890,333 7.0124%

8 7.0113% 99,895,000 7,003,933 7,004,667 -734 -427 7,004,667 7,000,000 4,667 99,895,000 7.0120%

9 7.0113% 99,899,667 7,004,260 7,004,667 -406 -221 7,004,667 7,000,000 4,667 99,899,667 7.0117%

10 7.0113% 99,904,333 7,004,587 7,004,667 -79 -40 7,004,667 7,000,000 4,667 99,904,333 7.0114%

11 7.0113% 99,909,000 7,004,915 7,004,667 248 118 7,004,667 7,000,000 4,667 99,909,000 7.0110%

12 7.0113% 99,913,667 7,005,242 7,004,667 575 255 7,004,667 7,000,000 4,667 99,913,667 7.0107%

13 7.0113% 99,918,333 7,005,569 7,004,667 902 374 7,004,667 7,000,000 4,667 99,918,333 7.0104%

14 7.0113% 99,923,000 7,005,896 7,004,667 1,230 476 7,004,667 7,000,000 4,667 99,923,000 7.0101%

15 7.0113% 99,927,667 7,006,223 7,004,667 1,557 563 7,004,667 7,000,000 4,667 99,927,667 7.0097%

16 7.0113% 99,932,333 7,006,551 7,004,667 1,884 637 7,004,667 7,000,000 4,667 99,932,333 7.0094%

17 7.0113% 99,937,000 7,006,878 7,004,667 2,211 699 7,004,667 7,000,000 4,667 99,937,000 7.0091%

18 7.0113% 99,941,667 7,007,205 7,004,667 2,538 750 7,004,667 7,000,000 4,667 99,941,667 7.0088%

19 7.0113% 99,946,333 7,007,532 7,004,667 2,866 791 7,004,667 7,000,000 4,667 99,946,333 7.0084%

20 7.0113% 99,951,000 7,007,859 7,004,667 3,193 823 7,004,667 7,000,000 4,667 99,951,000 7.0081%

21 7.0113% 99,955,667 7,008,187 7,004,667 3,520 848 7,004,667 7,000,000 4,667 99,955,667 7.0078%

22 7.0113% 99,960,333 7,008,514 7,004,667 3,847 866 7,004,667 7,000,000 4,667 99,960,333 7.0074%

23 7.0113% 99,965,000 7,008,841 7,004,667 4,174 878 7,004,667 7,000,000 4,667 99,965,000 7.0071%

24 7.0113% 99,969,667 7,009,168 7,004,667 4,501 885 7,004,667 7,000,000 4,667 99,969,667 7.0068%

25 7.0113% 99,974,333 7,009,495 7,004,667 4,829 887 7,004,667 7,000,000 4,667 99,974,333 7.0065%

26 7.0113% 99,979,000 7,009,823 7,004,667 5,156 885 7,004,667 7,000,000 4,667 99,979,000 7.0061%

27 7.0113% 99,983,667 7,010,150 7,004,667 5,483 880 7,004,667 7,000,000 4,667 99,983,667 7.0058%

28 7.0113% 99,988,333 7,010,477 7,004,667 5,810 871 7,004,667 7,000,000 4,667 99,988,333 7.0055%

29 7.0113% 99,993,000 7,010,804 7,004,667 6,137 860 7,004,667 7,000,000 4,667 99,993,000 7.0052%

30 7.0113% 99,997,667 7,011,131 7,004,667 6,465 847 7,004,667 7,000,000 4,667 99,997,667 7.0048%

Total 51,610 2,028


Year

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

Total

CAPITAL STRUCTURE AND WEIGHTED AVERAGE COST OF CAPITAL

Assumptions:

Common Equity Outstanding (Book Value) 100,000,000

Long-Term Debt Outstanding (Face Value) 100,000,000

Total Capital Cost Recovery of Capital Cost (FERC Staff Capital Structure)

Cost of Equity 12.25%

Equity Ratio (Book Value/Face Value) 50.00%

Weighted Average Cost of Capital 9.63065%

Total Equity

Cost Total Debt Cost

Total Cost of

Capital Rate Base Return

Under-/Over-

Recovery

Present Value

(At Weighted

Average Cost

of Capital)

12,250,000 7,004,667 19,254,667 199,862,333 19,248,037 -6,630 -6,048

12,250,000 7,004,667 19,254,667 199,867,000 19,248,486 -6,181 -5,142

12,250,000 7,004,667 19,254,667 199,871,667 19,248,936 -5,731 -4,350

12,250,000 7,004,667 19,254,667 199,876,333 19,249,385 -5,282 -3,656

12,250,000 7,004,667 19,254,667 199,881,000 19,249,834 -4,832 -3,051

12,250,000 7,004,667 19,254,667 199,885,667 19,250,284 -4,383 -2,524

12,250,000 7,004,667 19,254,667 199,890,333 19,250,733 -3,933 -2,067

12,250,000 7,004,667 19,254,667 199,895,000 19,251,183 -3,484 -1,670

12,250,000 7,004,667 19,254,667 199,899,667 19,251,632 -3,035 -1,326

12,250,000 7,004,667 19,254,667 199,904,333 19,252,082 -2,585 -1,031

12,250,000 7,004,667 19,254,667 199,909,000 19,252,531 -2,136 -777

12,250,000 7,004,667 19,254,667 199,913,667 19,252,980 -1,686 -559

12,250,000 7,004,667 19,254,667 199,918,333 19,253,430 -1,237 -374

12,250,000 7,004,667 19,254,667 199,923,000 19,253,879 -787 -217

12,250,000 7,004,667 19,254,667 199,927,667 19,254,329 -338 -85

12,250,000 7,004,667 19,254,667 199,932,333 19,254,778 111 26

12,250,000 7,004,667 19,254,667 199,937,000 19,255,228 561 118

12,250,000 7,004,667 19,254,667 199,941,667 19,255,677 1,010 193

12,250,000 7,004,667 19,254,667 199,946,333 19,256,126 1,460 254

12,250,000 7,004,667 19,254,667 199,951,000 19,256,576 1,909 304

12,250,000 7,004,667 19,254,667 199,955,667 19,257,025 2,359 342

12,250,000 7,004,667 19,254,667 199,960,333 19,257,475 2,808 371

12,250,000 7,004,667 19,254,667 199,965,000 19,257,924 3,258 393

12,250,000 7,004,667 19,254,667 199,969,667 19,258,374 3,707 408

12,250,000 7,004,667 19,254,667 199,974,333 19,258,823 4,156 417

12,250,000 7,004,667 19,254,667 199,979,000 19,259,272 4,606 422

12,250,000 7,004,667 19,254,667 199,983,667 19,259,722 5,055 422

12,250,000 7,004,667 19,254,667 199,988,333 19,260,171 5,505 419

12,250,000 7,004,667 19,254,667 199,993,000 19,260,621 5,954 414

12,250,000 7,004,667 19,254,667 199,997,667 19,261,070 6,404 406

-3,397 -27,969



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

UPDATED SCE EMBEDDED COST OF

LONG-TERM DEBT

(EXHIBIT SCE-54)

OCTOBER 2010

Projected Embedded Cost of Debt

FERC Method

2010

LT Debt

As of: Rate

12/31/09 6.11%12/31/10 6.02%

Average 6.06%


Line

No. Series

Date of

Offering

Maturity

Date

Coupon

Rate Face Value

Net Premium or

Discount Net Proceeds

Cost of

Money

Principal

Amount Outstanding Interest Annual Cost

1 6.65% NOTES 4/99 4/29 6.650% 300,000$ (4,976)$ 295,024$ 6.780% 300,000$ 19,950$ 20,340$

2 2004A 1/04 1/14 5.000% 300,000 (16,039)$ 283,961$ 5.709% 300,000 15,000 17,127 3 2004B 1/04 1/34 6.000% 525,000 (35,914)$ 489,086$ 6.522% 525,000 31,500 34,242

4 2004F 3/04 3/15 4.650% 300,000 (4,688)$ 295,312$ 4.835% 300,000 13,950 14,505 5 2004G 3/04 3/35 5.750% 350,000 (5,658)$ 344,342$ 5.864% 350,000 20,125 20,523

6 Ft. Irwin Acquisition Debt 9/03 8/53 5.060% 6,989 -$ 6,989$ 5.060% 6,989 354 354 7 2005A 1/05 1/16 5.000% 400,000 (2,727)$ 397,273$ 5.082% 400,000 20,000 20,327

8 2005B 1/05 1/36 5.550% 250,000 (64,103)$ 185,897$ 7.744% 250,000 13,875 19,359 9 2005E 6/05 7/35 5.350% 350,000 (26,772)$ 323,228$ 5.897% 350,000 18,725 20,638

10 2005ABC (SONGS) 8/05 8/35 2.940% 248,585 (9,321)$ 239,264$ 3.134% 248,585 7,308 7,790 11 2006A 1/06 2/36 5.625% 350,000 (4,288)$ 345,713$ 5.711% 350,000 19,688 19,988

12 2006E 12/06 1/37 5.550% 400,000 (14,982)$ 385,018$ 5.815% 400,000 22,200 23,261

13 2008A 1/08 2/38 5.950% 600,000 (30,483)$ 569,517$ 6.330% 600,000 35,700 37,981

14 2005 ABC (SONGS) Repurchased 8/05 8/35 2.940% (248,585) -$ (248,585)$ 2.940% (248,585) (7,308) (7,308)

15 4CORNERS 99A 4/99 4/29 5.125% 55,540 (14,304)$ 41,236$ 7.240% 55,540 2,846 4,021

16 SONGS 99 A-B 9/99 9/29 5.450% 100,000 (22,045)$ 77,955$ 7.265% 100,000 5,450 7,265

17 SONGS 99 C 9/99 9/31 5.550% 30,000 (500)$ 29,500$ 5.663% 30,000 1,665 1,699

18 SONGS 99 D 9/99 9/15 5.200% 8,300 (138)$ 8,162$ 5.356% 8,300 432 445

19 2005A&B (FARMINGTON) 4/10 4/29 3.550% 203,460 (5,067)$ 198,393$ 3.734% 203,460 7,223 7,598

20 2006A&B 4/06 4/28 4.100% 196,000 (9,261)$ 186,739$ 4.439% 196,000 8,036 8,700

21 2006C&D 4/06 11/33 4.250% 135,000 (2,042)$ 132,958$ 4.344% 135,000 5,738 5,864

22 2008B 8/08 8/18 5.500% 400,000 (16,932)$ 383,068$ 6.071% 400,000 22,000 24,284

23 2008C 10/08 3/14 5.750% 500,000 (6,340)$ 493,660$ 6.048% 500,000 28,750 30,238

24 2009A 3/09 3/39 6.050% 500,000 (8,470)$ 491,530$ 6.175% 500,000 30,250 30,874

25 85-A 1,102

26 85-C 766

27 86-B 649

28 86-C 1,263

29 86-K 1,123

30 89-A 0

31 90-B 255

32 90-D 157

33 91-B 562

34 91-C 546

35 91-SER-A 251

36 92-E CPC 1,098 37 93-C 567 38 93-D-(PC) 203 39 93-G 508 40 93-I 555


December 31, 2009

(Thousands of Dollars)

Embedded Cost of Debt


Line

No. Series

Date of

Offering

Maturity

Date

Coupon

Rate Face Value

Net Premium or


Cost of

Money

Principal



December 31, 2009



41 MOHAVE-88-A-20M 82

42 PV-85-ABCD 4

43 RR 249

44 TT 55

45 ZZ 2,248

46 Hedge Interest -

47 Interest Rate Lock Economic Hedge -

48 Interest Rate Hedge Expense -

49 Transferred to 2008A -

50 Transferred to 2008B -

51 Placeholder

52 TOTAL 6,260,289$ (305,049)$ 5,955,240$ 6.11% 6,260,289$ 343,455$ 382,357$


Line

No. Series

Date of

Offering

Maturity

Date

Coupon

Rate Face Value

Net Premium or


Cost of

Money

Principal


1 6.65% NOTES 4/99 4/29 6.650% 300,000$ (4,976)$ 295,024$ 6.780% 300,000$ 19,950$ 20,340$

2 2004A 1/04 1/14 5.000% 300,000 (16,039)$ 283,961$ 5.709% 300,000 15,000 17,127 3 2004B 1/04 1/34 6.000% 525,000 (35,914)$ 489,086$ 6.522% 525,000 31,500 34,242

4 2004F 3/04 3/15 4.650% 300,000 (4,688)$ 295,312$ 4.835% 300,000 13,950 14,505 5 2004G 3/04 3/35 5.750% 350,000 (5,658)$ 344,342$ 5.864% 350,000 20,125 20,523

6 Ft. Irwin Acquisition Debt 9/03 8/53 5.060% 6,944 -$ 6,944$ 5.060% 6,944 351 351 7 2005A 1/05 1/16 5.000% 400,000 (2,727)$ 397,273$ 5.082% 400,000 20,000 20,327

8 2005B 1/05 1/36 5.550% 250,000 (64,103)$ 185,897$ 7.744% 250,000 13,875 19,359 9 2005E 6/05 7/35 5.350% 350,000 (26,772)$ 323,228$ 5.897% 350,000 18,725 20,638

10 2005ABC (SONGS) 8/05 8/35 2.940% 248,585 (9,321)$ 239,264$ 3.134% 248,585 7,308 7,790 11 2006A 1/06 2/36 5.625% 350,000 (4,288)$ 345,713$ 5.711% 350,000 19,688 19,988

12 2006E 12/06 1/37 5.550% 400,000 (14,982)$ 385,018$ 5.815% 400,000 22,200 23,261

13 2008A 1/08 2/38 5.950% 600,000 (30,483)$ 569,517$ 6.330% 600,000 35,700 37,981

14 2005 ABC (SONGS) Repurchased 8/05 8/35 2.940% (248,585) -$ (248,585)$ 2.940% (248,585) (7,308) (7,308)

15 4CORNERS 99A 4/99 4/29 5.125% 55,540 (14,304)$ 41,236$ 7.240% 55,540 2,846 4,021

16 SONGS 99 A-B 9/99 9/29 5.450% 100,000 (22,045)$ 77,955$ 7.265% 100,000 5,450 7,265

17 SONGS 99 C 9/99 9/31 5.550% 30,000 (500)$ 29,500$ 5.663% 30,000 1,665 1,699

18 SONGS 99 D 9/99 9/15 5.200% 8,300 (138)$ 8,162$ 5.356% 8,300 432 445

19 2005A&B (FARMINGTON) 4/10 4/29 2.880% 203,460 (5,067)$ 198,393$ 3.054% 203,460 5,860 6,213

20 2006A&B 4/06 4/28 4.100% 196,000 (9,261)$ 186,739$ 4.439% 196,000 8,036 8,700

21 2006C&D 4/06 11/33 4.250% 135,000 (2,042)$ 132,958$ 4.344% 135,000 5,738 5,864

22 2008B 8/08 8/18 5.500% 400,000 (16,932)$ 383,068$ 6.071% 400,000 22,000 24,284

23 2008C 10/08 3/14 5.750% 500,000 (6,340)$ 493,660$ 6.048% 500,000 28,750 30,238

24 2009A 3/09 3/39 6.050% 500,000 (8,470)$ 491,530$ 6.175% 500,000 30,250 30,874

25 2010A 3/10 3/40 5.500% 500,000 (11,365)$ 488,635$ 5.658% 500,000 27,500 28,291

26 2010B 8/10 9/40 4.500% 500,000 (8,505)$ 491,495$ 4.605% 500,000 22,500 23,026

27 2010C 9/10 9/29 4.500% 100,000 (2,512)$ 97,488$ 4.701% 100,000 4,500 4,701

28 2010Q4 Projected Issue 11/10 11/40 6.000% 200,000 (2,000)$ 198,000$ 6.073% 200,000 12,000 12,146

29 85-A (4,634) 1,102

30 85-C (3,660) 766

31 86-B (4,680) 649

32 86-C (10,465) 1,263

33 86-K (7,767) 1,123

34 89-A (1) 0

35 90-B (2,667) 255 36 90-D (1,870) 157 37 91-B (6,926) 562 38 91-C (7,321) 546 39 91-SER-A (2,573) 251 40 92-E CPC (15,282) 1,098


December 31, 2010




Line

No. Series

Date of

Offering

Maturity

Date

Coupon

Rate Face Value

Net Premium or


Cost of

Money

Principal



December 31, 2010



41 93-C (8,606) 567

42 93-D-(PC) (2,535) 203

43 93-G (7,379) 508 44 93-I (4,299) 555

45 MOHAVE-88-A-20M (0) -

46 PV-85-ABCD 0 -

47 RR (228) 249

48 TT (69) 55 49 ZZ (8,806) 2,248

50 Hedge Interest (7,212) 243

51 Interest Rate Lock Economic Hedge (25,214) 850

52 Interest Rate Hedge Expense 7 (0)

53 Transferred to 2008A 21,135 (712)

54 Transferred to 2008B 11,284 (380)

55 Remarketed 2000AB (526) 18

56 Placeholder

57 TOTAL 7,560,244$ (329,431)$ 7,230,813$ 6.02% 7,459,950$ 408,590$ 449,066$



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

UPDATED SCE EMBEDDED COST OF

PREFERRED EQUITY

(EXHIBIT SCE-55)

OCTOBER 2010

Projected Embedded Cost of Preferred Equity

FERC Method

2010

Preferred Equity

As of: Rate

12/31/09 5.77%12/31/10 6.21%

2010 Average 5.99%


Preferred EquityTerms Net Percent Stated

Line Date of Call Of Dividend Face Proceeds at Of Face Cost Amount AnnualizedNo. Title Offering/Call Price Conversion Rate Value Issuance Value Of Money Outstanding Cost

1 4.320% May-47 28.75 4.320% $41,336 $42,099 101.8% 4.24% $41,336 $1,7532 4.080% May-50 25.50 4.080% $25,000 $25,040 100.2% 4.07% $16,250 $6623 4.240% Feb-56 25.58 4.240% $30,000 $30,084 100.3% 4.23% $30,000 $1,2684 4.780% Feb-58 25.25 4.780% $32,419 $32,469 100.2% 4.77% $32,419 $1,5475 5.349% Apr-05 5.349% $400,000 $394,440 98.6% 5.67% $400,000 $22,6816 6.125% Sep-05 6.125% $200,000 $196,500 98.3% 6.25% $200,000 $12,509

7 6.000% Jan-06 6.000% $200,000 $196,100 98.1% 6.14% $200,000 $12,2858 8.540% Nov-85 $91 ($8)9 12.000% Feb-86 ($2,037) $184

10 12.000% Feb-86 ($334) $3011 6.050% May-05 ($370) $012 7.230% May-05 ($493) $0

13 Total $928,755 $916,732 5.77% $916,862 $52,912

SOUTHERN CALIFORNIA EDISON COMPANYPREFERRED AND PREFERENCE EQUITY EMBEDDED COST

(In Thousands)

December 31, 2009


Preferred EquityTerms Net Percent Stated

Line Date of Call Of Dividend Face Proceeds at Of Face Cost Amount AnnualizedNo. Title Offering/Call Price Conversion Rate Value Issuance Value Of Money Outstanding Cost

1 4.320% May-47 28.75 4.320% $41,336 $42,099 101.8% 4.24% $41,336 $1,7532 4.080% May-50 25.50 4.080% $25,000 $25,040 100.2% 4.07% $16,250 $6623 4.240% Feb-56 25.58 4.240% $30,000 $30,084 100.3% 4.23% $30,000 $1,2684 4.780% Feb-58 25.25 4.780% $32,419 $32,469 100.2% 4.77% $32,419 $1,5475 5.349% Apr-05 5.349% $400,000 $394,440 98.6% 5.67% $400,000 $22,6816 6.125% Sep-05 6.125% $200,000 $196,500 98.3% 6.25% $200,000 $12,5097 6.000% Jan-06 6.000% $200,000 $196,100 98.1% 6.14% $200,000 $12,2858 2010A Aug-10 7.000% $125,000 $122,500 98.0% 7.16% $125,000 $8,9539 2010B Nov-10 7.000% $300,000 $294,000 98.0% 7.16% $300,000 $21,488

10 8.540% Nov-85 $91 ($8)11 12.000% Feb-86 ($2,037) $18412 12.000% Feb-86 ($334) $3013 6.050% May-05 ($370) $014 7.230% May-05 ($493) $0

15 Total $1,353,755 $1,333,232 6.21% $1,341,862 $83,353

SOUTHERN CALIFORNIA EDISON COMPANYPREFERRED AND PREFERENCE EQUITY EMBEDDED COST

(In Thousands)

December 31, 2010





)))

Dkt. No.

ER09-1534-001

DCF ESTIMATE COMPARISON FOR

MAY 2010, SCE AND SIX CITIES

(EXHIBIT SCE-56)

OCTOBER 2010

Low High br + sv b r s v IBES Low High Average

LNT Alliant Energy 4.65% 5.18% 4.49% 0.41 0.10 0.01 0.21 8.45% 9.24% 13.85% 11.55%

AEP Amer. Elec. Power 4.64% 5.11% 5.00% 0.46 0.10 0.01 0.18 4.00% 8.73% 10.23% 9.48%

CNP CenterPoint Energy 5.25% 6.04% 6.62% 0.34 0.16 0.02 0.51 5.25% 10.64% 12.86% 11.75%

ED Consol. Edison 5.21% 5.55% 3.09% 0.32 0.09 0.01 0.17 5.10% 8.38% 10.79% 9.59%

D Dominion Resources 4.42% 4.78% 5.27% 0.38 0.15 -0.01 0.51 4.70% 9.22% 10.17% 9.70%

DPL DPL Inc. 4.20% 4.54% 15.15% 0.49 0.27 0.03 0.66 5.85% 10.17% 20.03% 15.10%

DTE DTE Energy 4.58% 4.99% 3.79% 0.39 0.09 0.02 0.13 4.90% 8.45% 10.02% 9.24%

DUK Duke Energy 5.60% 5.95% 2.08% 0.26 0.08 0.00 0.00 4.43% 7.74% 10.51% 9.13%

EXC Exelon Corp. 4.46% 6.05% 7.74% 0.47 0.18 -0.01 0.55 1.52% 6.01% 14.02% 10.02%

FPL FPL Group 3.76% 4.10% 7.58% 0.54 0.13 0.02 0.37 6.65% 10.54% 11.83% 11.18%

GXP G't Plains Energy 4.27% 4.71% 2.26% 0.36 0.07 0.03 -0.12 13.00% 6.58% 18.02% 12.30%

HE Hawaiian Elec. 5.50% 6.15% 3.26% 0.26 0.10 0.02 0.27 7.60% 8.85% 13.99% 11.42%

IDA IDACORP, Inc. 3.44% 3.80% 5.37% 0.57 0.09 0.02 0.12 4.67% 8.19% 9.28% 8.73%

TEG Integrys Energy 5.81% 6.42% 1.95% 0.21 0.09 0.01 0.16 9.40% 7.81% 16.12% 11.97%

NU Northeast Utilities 3.66% 3.96% 4.63% 0.45 0.09 0.02 0.22 7.52% 8.37% 11.63% 10.00%

OGE OGE Energy 3.67% 4.09% 7.73% 0.52 0.13 0.02 0.43 4.00% 7.74% 11.98% 9.86%

PCG PG&E Corp. 3.93% 4.32% 6.39% 0.46 0.12 0.02 0.34 6.90% 10.44% 11.38% 10.91%

POR Portland General 5.00% 5.47% 2.41% 0.34 0.08 0.03 -0.05 5.00% 7.47% 10.60% 9.04%

PPL PPL Corp. 4.65% 5.12% 7.52% 0.49 0.17 -0.02 0.48 2.95% 7.67% 12.83% 10.25%

PGN Progress Energy 6.09% 6.52% 2.01% 0.22 0.09 0.01 0.15 3.57% 8.16% 10.20% 9.18%

PEG Public Serv. Enterprise 4.13% 4.54% 8.43% 0.55 0.15 0.00 0.43 1.54% 5.70% 13.16% 9.43%

SCG SCANA Corp. 4.91% 5.31% 5.24% 0.39 0.10 0.05 0.25 4.40% 9.42% 10.68% 10.05%

SRE Sempra Energy 2.94% 3.23% 8.09% 0.66 0.12 0.00 0.27 3.50% 6.49% 11.45% 8.97%

TE TECO Energy 4.82% 5.34% 5.00% 0.37 0.13 0.01 0.38 6.25% 9.95% 11.76% 10.85%

WR Westar Energy 5.31% 5.76% 2.78% 0.32 0.09 0.01 0.06 9.28% 8.17% 15.31% 11.74%

WEC Wisconsin Energy 2.94% 3.19% 6.55% 0.54 0.12 0.00 0.38 9.53% 9.58% 12.87% 11.22%

XEL Xcel Energy Inc. 4.50% 4.81% 4.44% 0.40 0.10 0.02 0.24 6.35% 9.03% 11.31% 10.17%

Average

Average Div Yield Growth Rates

SCE #s

Estimated ROE


LNT Alliant Energy

AEP Amer. Elec. Power

CNP CenterPoint Energy

ED Consol. Edison

D Dominion Resources

DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EXC Exelon Corp.

FPL FPL Group

GXP G't Plains Energy

HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

NU Northeast Utilities

OGE OGE Energy

PCG PG&E Corp.

POR Portland General

PPL PPL Corp.

PGN Progress Energy

PEG Public Serv. Enterprise

SCG SCANA Corp.

SRE Sempra Energy

TE TECO Energy

WR Westar Energy

WEC Wisconsin Energy

XEL Xcel Energy Inc.

Average


4.61% 5.14% 4.47% 0.41 0.10 0.01 0.20 8.45% 9.19% 13.80% 11.49%

4.64% 5.10% 4.98% 0.46 0.10 0.01 0.17 4.00% 8.73% 10.21% 9.47%

5.25% 7.01% 6.53% 0.34 0.16 0.02 0.49 5.25% 10.64% 13.77% 12.21%

5.21% 5.55% 3.09% 0.32 0.09 0.00 0.17 5.10% 8.38% 10.79% 9.59%

4.39% 4.75% 5.29% 0.38 0.15 -0.01 0.49 4.70% 9.19% 10.16% 9.68%

4.21% 4.54% 15.12% 0.49 0.27 0.03 0.66 5.85% 10.18% 20.00% 15.09%

4.58% 4.99% 3.77% 0.39 0.09 0.02 0.12 4.90% 8.43% 10.02% 9.22%

5.60% 5.95% 2.08% 0.26 0.08 0.00 -0.01 4.43% 7.74% 10.51% 9.13%

4.28% 4.73% 2.25% 0.36 0.07 0.03 -0.12 13.00% 6.58% 18.03% 12.31%

5.50% 6.15% 3.25% 0.26 0.10 0.02 0.26 7.60% 8.83% 13.99% 11.41%

5.81% 6.42% 1.94% 0.21 0.09 0.01 0.15 9.40% 7.81% 16.12% 11.97%

3.61% 3.92% 4.61% 0.45 0.09 0.02 0.21 7.52% 8.30% 11.58% 9.94%

3.67% 4.10% 7.68% 0.52 0.13 0.02 0.42 4.00% 7.74% 11.93% 9.84%

3.88% 4.27% 6.34% 0.46 0.12 0.02 0.33 6.90% 10.34% 11.32% 10.83%

5.00% 5.47% 2.39% 0.34 0.08 0.03 -0.06 5.00% 7.45% 10.60% 9.03%

6.09% 6.52% 2.00% 0.22 0.09 0.01 0.13 3.90% 8.15% 10.54% 9.35%

4.32% 4.39% 8.43% 0.55 0.15 0.00 0.42 1.54% 5.89% 13.01% 9.45%

4.91% 5.31% 5.16% 0.39 0.10 0.05 0.23 4.28% 9.29% 10.60% 9.95%

2.94% 3.23% 8.08% 0.66 0.12 0.00 0.26 3.50% 6.49% 11.44% 8.97%

4.82% 5.34% 4.99% 0.37 0.13 0.01 0.37 6.25% 9.94% 11.76% 10.85%

2.94% 3.19% 6.55% 0.54 0.12 0.00 0.37 9.53% 9.58% 12.87% 11.23%

4.50% 4.81% 4.41% 0.40 0.10 0.02 0.23 6.35% 9.01% 11.31% 10.16%

Solomon #s

Average Div Yield Growth Rates Estimated ROE


LNT Alliant Energy



ED Consol. Edison


DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EXC Exelon Corp.

FPL FPL Group


HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy


OGE OGE Energy

PCG PG&E Corp.


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

TE TECO Energy

WR Westar Energy



Average


0.04% 0.04% 0.02% 0.00 0.00 0.0002 0.0107 0.00% 0.06% 0.05% 0.05%

0.00% 0.00% 0.02% 0.00 0.00 0.0002 0.0131 0.00% 0.00% 0.02% 0.01%

0.00% -0.98% 0.09% 0.00 0.00 0.0009 0.0232 0.00% 0.00% -0.91% -0.46%

0.00% 0.00% 0.00% 0.00 0.00 0.0000 0.0060 0.00% 0.00% 0.00% 0.00%

0.03% 0.03% -0.02% 0.00 0.00 -0.0002 0.0199 0.00% 0.03% 0.01% 0.02%

0.00% -0.01% 0.03% 0.00 0.00 0.0003 0.0033 0.00% 0.00% 0.02% 0.01%

0.00% 0.00% 0.02% 0.00 0.00 0.0002 0.0113 0.00% 0.02% 0.00% 0.01%

0.00% 0.00% 0.00% 0.00 0.00 0.0000 0.0055 0.00% 0.00% 0.00% 0.00%

-0.01% -0.01% 0.01% 0.00 0.00 0.0001 0.0052 0.00% 0.00% -0.01% 0.00%

0.00% 0.00% 0.02% 0.00 0.00 0.0002 0.0064 0.00% 0.02% 0.00% 0.01%

0.00% 0.00% 0.00% 0.00 0.00 0.0000 0.0035 0.00% 0.00% 0.00% 0.00%

0.04% 0.05% 0.02% 0.00 0.00 0.0002 0.0106 0.00% 0.07% 0.05% 0.06%

0.00% 0.00% 0.05% 0.00 0.00 0.0005 0.0132 0.00% 0.00% 0.05% 0.02%

0.05% 0.06% 0.05% 0.00 0.00 0.0005 0.0139 0.00% 0.10% 0.06% 0.08%

0.00% 0.00% 0.02% 0.00 0.00 0.0002 0.0051 0.00% 0.02% 0.00% 0.01%

0.00% 0.00% 0.01% 0.00 0.00 0.0001 0.0157 -0.33% 0.01% -0.34% -0.17%

-0.18% 0.15% 0.00% 0.00 0.00 0.0000 0.0181 0.00% -0.19% 0.15% -0.02%

0.00% 0.00% 0.08% 0.00 0.00 0.0008 0.0131 0.12% 0.12% 0.08% 0.10%

0.00% 0.00% 0.01% 0.00 0.00 0.0001 0.0164 0.00% 0.00% 0.01% 0.00%

0.00% 0.00% 0.01% 0.00 0.00 0.0001 0.0083 0.00% 0.01% 0.00% 0.01%

0.00% 0.00% 0.00% 0.00 0.00 0.0000 0.0130 0.00% 0.00% -0.01% 0.00%

0.00% 0.00% 0.03% 0.00 0.00 0.0003 0.0099 0.00% 0.03% 0.00% 0.01%

0.02% 0.0112

Difference

Average Div Yield Growth Rates Estimated ROE



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

VALUE LINE PAGES FOR

SELECTED COMPANIES

(EXHIBIT SCE-57)

OCTOBER 2010

200160

1008060504030

20

Percentsharestraded

15105

Target Price Range2013 2014 2015

ENTERGY CORP. NYSE-ETR 76.79 12.8 12.314.0 0.79 4.4%

TIMELINESS 4 Lowered 5/7/10

SAFETY 2 New 12/26/08

TECHNICAL 3 Lowered 6/18/10BETA .70 (1.00 = Market)

2013-15 PROJECTIONSAnn’l Total

Price Gain ReturnHigh 125 (+65%) 16%Low 95 (+25%) 10%Insider Decisions

A S O N D J F M Ato Buy 0 0 0 0 0 0 0 0 0Options 6 0 1 1 0 0 0 0 0to Sell 6 0 1 1 0 0 0 0 0Institutional Decisions

3Q2009 4Q2009 1Q2010to Buy 199 191 203to Sell 228 208 201Hld’s(000) 150775 148575 147730

High: 33.5 43.9 44.7 46.8 57.2 68.7 79.2 94.0 125.0 127.5 86.6 84.3Low: 23.7 15.9 32.6 32.1 42.3 50.6 64.5 66.8 89.6 61.9 59.9 71.3

% TOT. RETURN 5/10THIS VL ARITH.

STOCK INDEX1 yr. 4.7 41.63 yr. -26.2 -2.65 yr. 22.4 37.2

CAPITAL STRUCTURE as of 3/31/10Total Debt $12152 mill. Due in 5 Yrs $5231.7 mill.LT Debt $11173 mill. LT Interest $575.0 mill.Incl. $36.6 mill. capitalized leases.(LT interest earned: 4.1x)Leases, Uncapitalized Annual rentals $95.4 mill.Pension Assets-12/09 $2.61 bill.

Oblig. $3.84 bill.Pfd Stock $310.7 mill. Pfd Div’d $20.0 mill.6,115,105 shs. $4.20 to $7.88, $100 par; 1,000,000shs. 11.50%, all without sinking fund.Common Stock 189,303,044 shs.as of 4/30/10MARKET CAP: $15 billion (Large Cap)

ELECTRIC OPERATING STATISTICS2007 2008 2009

% Change Retail Sales (KWH) +5.5 -1.4 -1.5Avg. Indust. Use (MWH) 920 898 NAAvg. Indust. Revs. per KWH(¢) 6.53 7.75 5.60Capacity at Peak (Mw) 23996 24844 NAPeak Load, Summer (Mw) 22001 21241 21009Annual Load Factor (%) 59.0 59.0 NA% Change Customers (yr-end) +2.8 +.8 +1.1

Fixed Charge Cov. (%) 288 339 355ANNUAL RATES Past Past Est’d ’07-’09of change (per sh) 10 Yrs. 5 Yrs. to ’13-’15Revenues 4.5% 8.5% 5.0%‘‘Cash Flow’’ 8.0% 10.0% 7.0%Earnings 10.5% 10.0% 4.5%Dividends 6.5% 12.0% 6.5%Book Value 4.0% 3.0% 5.5%

Cal- Fullendar Year

QUARTERLY REVENUES ($ mill.)Mar.31 Jun.30 Sep.30 Dec.31

2007 2600 2769 3289 2826 114842008 2865 3264 3964 3001 130942009 2789 2521 2937 2499 107462010 2759 2900 3200 2741 116002011 2900 3050 3350 2900 12200Cal- Full

endar YearEARNINGS PER SHARE A

Mar.31 Jun.30 Sep.30 Dec.312007 1.03 1.32 2.30 .96 5.602008 1.56 1.37 2.41 .89 6.202009 1.20 1.14 2.32 1.64 6.302010 1.12 .98 2.65 1.25 6.002011 1.50 1.35 2.70 1.40 6.95Cal- Full

endar YearQUARTERLY DIVIDENDS PAID B ■ †

Mar.31 Jun.30 Sep.30 Dec.312006 .54 .54 .54 .54 2.162007 .54 .54 .75 .75 2.582008 .75 .75 .75 .75 3.002009 .75 .75 .75 .75 3.002010 .75 .83

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 200726.22 27.55 30.75 38.89 46.57 35.51 45.61 43.59 37.34 40.17 46.69 46.61 53.94 59.47

4.49 5.16 5.84 6.20 6.11 5.06 6.49 6.41 7.62 7.43 8.33 8.18 10.69 11.731.58 2.13 2.48 2.25 2.22 2.25 2.97 3.08 3.68 3.69 3.93 4.40 5.36 5.601.80 1.80 1.80 1.80 1.50 1.20 1.22 1.28 1.34 1.60 1.89 2.16 2.16 2.582.97 2.72 2.45 3.45 4.63 4.84 6.80 6.25 6.88 6.85 6.51 6.72 9.44 10.29

27.93 28.41 28.51 27.23 28.79 28.81 31.89 33.78 35.24 38.02 38.26 35.71 40.45 40.71227.41 227.77 232.96 245.84 246.83 247.08 219.60 220.73 222.42 228.90 216.83 216.83 202.67 193.12

17.5 11.5 11.1 11.6 12.9 13.2 10.1 12.5 11.5 13.8 15.1 16.3 14.3 19.31.15 .77 .70 .67 .67 .75 .66 .64 .63 .79 .80 .87 .77 1.02

6.5% 7.4% 6.5% 6.9% 5.2% 4.1% 4.1% 3.3% 3.2% 3.1% 3.2% 3.0% 2.8% 2.4%

10016 9621.0 8305.0 9195.0 10124 10106 10932 11484710.9 716.8 878.4 874.2 933.1 943.1 1160.9 1160.0

40.3% 38.9% 25.1% 35.9% 28.2% 37.2% 27.6% 30.7%7.9% 6.6% 6.4% 8.7% 7.0% 8.0% 5.5% 5.8%

50.4% 47.7% 45.7% 44.8% 44.7% 51.9% 51.2% 54.3%45.6% 48.6% 50.6% 53.2% 52.9% 45.5% 46.7% 43.9%15351 15353 15499 16361 15696 17013 17539 1790216497 17264 17195 18299 18696 19197 19438 209746.2% 6.4% 7.3% 6.8% 7.4% 6.8% 8.0% 7.9%9.3% 8.9% 10.4% 9.7% 10.8% 11.5% 13.6% 14.2%9.7% 9.3% 10.9% 9.8% 11.0% 11.9% 13.8% 14.4%5.8% 5.7% 7.1% 5.6% 5.8% 6.0% 8.3% 8.0%43% 41% 37% 44% 48% 51% 41% 46%

2008 2009 2010 2011 © VALUE LINE PUB., INC. 13-1569.15 56.82 64.45 67.80 Revenues per sh 82.2512.89 13.29 14.55 15.95 ‘‘Cash Flow’’ per sh 19.00

6.20 6.30 6.00 6.95 Earnings per sh A 7.753.00 3.00 3.24 3.53 Div’d Decl’d per sh B ■ † 4.15

13.92 12.99 13.05 15.80 Cap’l Spending per sh 14.7542.07 45.54 46.60 50.10 Book Value per sh C 59.50

189.36 189.12 180.00 180.00 Common Shs Outst’g D 170.0016.6 12.0 Bold figures are

Value Lineestimates

Avg Ann’l P/E Ratio 14.01.00 .80 Relative P/E Ratio .95

2.9% 4.0% Avg Ann’l Div’d Yield 3.8%

13094 10746 11600 12200 Revenues ($mill) 140001240.5 1251.1 1140 1295 Net Profit ($mill) 137032.7% 33.6% 36.0% 36.0% Income Tax Rate 36.0%

5.6% 7.4% 9.0% 8.0% AFUDC % to Net Profit 7.0%58.2% 55.3% 57.0% 56.5% Long-Term Debt Ratio 58.0%40.2% 43.1% 41.5% 42.0% Common Equity Ratio 40.5%19795 19985 20250 21500 Total Capital ($mill) 2500022429 23389 24300 25600 Net Plant ($mill) 274007.5% 7.6% 7.0% 7.5% Return on Total Cap’l 7.0%

15.0% 14.0% 13.0% 14.0% Return on Shr. Equity 13.0%15.3% 14.3% 13.5% 14.0% Return on Com Equity E 13.5%

8.1% 7.6% 6.0% 7.0% Retained to Com Eq 6.5%48% 48% 54% 51% All Div’ds to Net Prof 53%

Company’s Financial Strength AStock’s Price Stability 100Price Growth Persistence 85Earnings Predictability 90

(A) Diluted EPS. Excl. nonrecur. gains (losses):’97, ($1.22); ’98, 78¢; ’01, 15¢; ’02, ($1.04);’03, 33¢ net; ’05, (21¢). ’07 EPS don’t add dueto rounding, ’08 due to change in shares. Next

earnings report due late July. (B) Div’ds histori-cally paid in early Mar., June, Sept., and Dec. ■

Div’d reinvestment plan available. † Sharehold-er investment plan available. (C) Incl. deferred

charges. In ’09: $25.47/sh. (D) In mill. (E) Ratebase: net original cost. Rates allowed on com.eq.: 9.45%-14.42%; earned on avg. com. eq.,’09: 14.8%. Regulatory Climate: Average.

BUSINESS: Entergy Corporation supplies electricity to 2.7 millioncustomers through subsidiaries in Arkansas, Louisiana, Mississippi,Texas, and New Orleans. Distributes gas to 188,000 customers inLouisiana. Merged with Gulf States Utilities 12/93. Has a nonutilitynuclear subsidiary that owns six units. Electric revenue breakdown,’09: residential, 38%; commercial, 28%; industrial, 25%; other, 9%.

Generating sources, ’09: nuclear, 34%; gas, 19%; coal, 12%; pur-chased, 35%. Fuel costs: 34% of revenues. ’09 reported deprecia-tion rate: 2.7%. Has 15,200 employees. Chairman & CEO: J.Wayne Leonard. President & COO: Richard J. Smith. Inc.: Dela-ware. Address: 639 Loyola Avenue, P.O. Box 61000, New Orleans,Louisiana 70161. Tel.: 504-576-4000. Internet: www.entergy.com.

Entergy has canceled its plan to spinoff the nonregulated nuclear unitsinto a separate company. The NewYork commission rejected the company’sproposal, and Entergy decided to unwindthe infrastructure that it created in prepa-ration for the corporate separation. Thismatter has been dragging on since Enter-gy announced its plan in the fourth quar-ter of 2007. The company has been incur-ring expenses each quarter in connectionwith the proposed spinoff, and expects totake a charge of $0.40-$0.45 a share (mostof it in the second quarter) to write offsome other related costs. We are includingthese items in our earnings presentation.Entergy hasn’t ruled out some other kindof restructuring of its business.The board of directors raised the divi-dend by $0.08 a share (10.7%) in thesecond quarter. The directors had es-chewed a dividend hike while the spinoff(and the surrounding uncertainty) waspending. We project that healthy dividendgrowth will continue over the next 3 to 5years, thanks to Entergy’s low payoutratio and sound finances.Entergy plans to buy back some stock.

In the fourth quarter of 2009, the boardauthorized a $750 million repurchase pro-gram, which the company intends to com-plete this year.We have cut our earnings estimatesfor 2010 and 2011. This year, first-periodprofits were well below our estimate, andEntergy will incur the aforementionedcharge for unwinding the planned spinoff.Low power prices are affecting the profita-bility of the company’s nonregulated oper-ations, too.Entergy received a rate order inArkansas. The utility was granted a tariffincrease of $46.5 million, based on a 10.2%return on equity. Entergy had sought a$168 million raise, based on a 10.65%ROE. New rates will take effect in July.A rate case is pending in Texas. Enter-gy is seeking a rate hike of $198.7 million,based on an 11.5% ROE. An order isscheduled for November and will be retro-active to mid-September.The dividend yield is comparable withthe industry average, as is total re-turn potential to 2013-2015. But thestock is untimely.Paul E. Debbas, CFA June 25, 2010

LEGENDS1.28 x Dividends p shdivided by Interest Rate. . . . Relative Price Strength

Options: YesShaded area: prior recession

Latest recession began 12/07

© 2010, Value Line Publishing, Inc. All rights reserved. Factual material is obtained from sources believed to be reliable and is provided without warranties of any kind.THE PUBLISHER IS NOT RESPONSIBLE FOR ANY ERRORS OR OMISSIONS HEREIN. This publication is strictly for subscriber’s own, non-commercial, internal use. No partof it may be reproduced, resold, stored or transmitted in any printed, electronic or other form, or used for generating or marketing any printed or electronic publication, service or product.

To subscribe call 1-800-833-0046.

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VECTREN CORP. NYSE-VVC 23.87 14.0 14.316.0 0.86 5.7%


SAFETY 2 Lowered 1/5/01






High: 26.5 24.4 26.1 26.1 27.1 29.5 29.3 30.5 32.2 26.9 25.6Low: 15.8 19.8 18.0 19.7 22.9 25.0 25.2 24.8 19.5 18.1 21.7


STOCK INDEX1 yr. 7.4 41.63 yr. -6.8 -2.65 yr. 8.1 37.2

Vectren was formed on March 31, 2000through the merger of Indiana Energy andSIGCORP. The merger was consummatedwith a tax-free exchange of shares and hasbeen accounted for as a pooling of interests.Indiana Energy common stockholdersreceived one Vectren common share foreach share held. SIGCORP stockholdersexchanged each common share for 1.333common shares of Vectren. Data prior to themerger are pro forma.CAPITAL STRUCTURE as of 3/31/10Total Debt $1803.5 mill. Due in 5 Yrs $698.6 mill.LT Debt $1549.9 mill. LT Interest $90.0 mill.(LT interest earned: 2.8x)

Pension Assets-12/09 $211.1 mill.Oblig. $271.5 mill.

Pfd Stock None

Common Stock 81,192,348 shs.as of 4/30/10

MARKET CAP: $1.9 billion (Mid Cap)


% Change Retail Sales (KWH) +3.5 -14.4 -5.3Avg. Indust. Use (MWH) NA NA NAAvg. Indust. Revs. per KWH (¢) NA NA NACapacity at Peak (Mw) 1487 1492 1493Peak Load, Summer (Mw) 1341 1242 1143Annual Load Factor (%) 60.6 55.1 56.2% Change Customers (yr-end) +.9 -.1 -.2

Fixed Charge Cov. (%) 254 269 280ANNUAL RATES Past Past Est’d ’07-’09of change (per sh) 10 Yrs. 5 Yrs. to ’13-’15Revenues - - 2.0% 3.5%‘‘Cash Flow’’ - - 4.5% 5.5%Earnings - - 2.5% 4.5%Dividends - - 3.5% 2.5%Book Value - - 4.0% 3.5%

Cal- Fullendar Year

QUARTERLY REVENUES ($ mill.)Mar.31 Jun. 30 Sep. 30 Dec. 31

2007 834.0 421.7 381.4 644.8 2281.92008 902.1 463.9 411.4 707.3 2484.72009 795.2 375.5 349.6 568.6 2088.92010 740.3 410 425 684.7 22602011 780 460 470 740 2450Cal- Full


Mar.31 Jun. 30 Sep. 30 Dec. 312007 .88 .21 .22 .52 1.832008 .84 .06 .27 .46 1.632009 .90 .07 .15 .67 1.792010 .78 .10 .25 .57 1.702011 .90 .15 .25 .60 1.90Cal- Full

endar YearQUARTERLY DIVIDENDS PAID B■ †

Mar.31 Jun.30 Sep.30 Dec.312006 .305 .305 .305 .315 1.232007 .315 .315 .315 .325 1.272008 .325 .325 .325 .335 1.312009 .335 .335 .335 .340 1.352010 .340 .340

2000 2001 2002 2003 2004 2005 2006 200726.84 32.05 26.53 21.00 22.26 26.62 26.83 29.88

2.88 2.89 3.43 3.17 3.27 3.87 3.69 4.291.17 1.08 1.68 1.56 1.42 1.81 1.44 1.83

.98 1.03 1.07 1.11 1.15 1.19 1.23 1.272.67 3.48 3.22 3.12 3.66 3.04 3.70 4.38

11.91 12.53 12.79 14.18 14.42 15.01 15.43 16.1661.42 67.70 68.01 75.60 75.90 76.19 76.10 76.36

17.4 20.3 14.2 14.8 17.6 15.1 18.9 15.31.13 1.04 .78 .84 .93 .80 1.02 .81

4.8% 4.7% 4.5% 4.8% 4.6% 4.4% 4.5% 4.5%

1648.7 2170.0 1804.3 1587.6 1689.8 2028.0 2041.6 2281.972.0 73.1 114.0 111.2 108.0 136.8 108.8 143.1

32.2% 20.3% 25.4% 25.3% 26.5% 24.4% 21.8% 34.7%- - 7.7% 4.6% 4.5% 3.0% 1.4% 3.8% 2.8%

45.8% 54.4% 52.3% 50.0% 48.1% 51.2% 50.7% 50.2%53.0% 45.5% 47.7% 50.0% 51.8% 48.8% 49.3% 49.8%1380.6 1863.1 1824.4 2144.7 2111.5 2341.3 2382.2 2479.11555.8 1595.0 1648.1 2003.7 2156.2 2251.9 2385.5 2539.7

6.1% 5.5% 7.7% 6.6% 6.4% 7.2% 6.0% 7.2%9.6% 8.6% 13.1% 10.4% 9.9% 12.0% 9.3% 11.6%9.7% 8.5% 13.1% 10.4% 9.9% 12.0% 9.3% 11.6%1.5% .3% 4.8% 3.0% 1.9% 4.0% 1.3% 3.8%85% 96% 63% 71% 81% 66% 86% 67%

2008 2009 2010 2011 © VALUE LINE PUB., INC. 13-1530.67 25.75 27.75 29.90 Revenues per sh 35.703.97 4.40 4.40 4.80 ‘‘Cash Flow’’ per sh 5.851.63 1.79 1.70 1.90 Earnings per sh A 2.251.31 1.35 1.37 1.39 Div’d Decl’d per sh B■† 1.504.83 5.33 3.70 4.90 Cap’l Spending per sh 6.55

16.68 17.23 18.40 19.50 Book Value per sh C 22.0081.03 81.10 81.50 82.00 Common Shs Outst’g D 84.00

16.8 12.9 Bold figures areValue Lineestimates

Avg Ann’l P/E Ratio 15.01.01 .85 Relative P/E Ratio 1.00


2484.7 2088.9 2260 2450 Revenues ($mill) 3000129.0 145.0 140 155 Net Profit ($mill) 190

37.1% 32.5% 35.0% 35.0% Income Tax Rate 35.0%2.9% 3.0% 3.0% 3.0% AFUDC % to Net Profit 3.0%

48.0% 52.5% 51.0% 50.0% Long-Term Debt Ratio 49.5%52.0% 47.5% 49.0% 50.0% Common Equity Ratio 50.5%2599.5 2938.0 3050 3200 Total Capital ($mill) 36502720.3 2878.8 2925 3000 Net Plant ($mill) 3300

6.5% 6.3% 6.0% 6.5% Return on Total Cap’l 6.5%9.5% 10.0% 9.0% 9.5% Return on Shr. Equity 10.0%9.5% 10.5% 9.5% 9.5% Return on Com Equity E 10.5%2.0% 2.5% 2.0% 2.5% Retained to Com Eq 3.5%80% 76% 80% 74% All Div’ds to Net Prof 66%

Company’s Financial Strength AStock’s Price Stability 100Price Growth Persistence 55Earnings Predictability 90

(A) Diluted EPS. Excl. nonrecur. gain (loss):’00, 8¢; ’01, (13¢); ’03, (6¢); ’09, 15¢; incl.charges for merger costs: ’00, 60¢; ’01, 17¢.Next earnings report due late July/early Au-

gust. (B) Div’ds historically paid in early March,June, September, and December. ■Div’d rein-vest. plan avail. † Shareholder invest. planavail. (C) Incl. intang. In ’09, $5.30/sh. (D) In

millions. (E) Electric rate base determination:fair value. Rate allowed on elect. commonequity in ’07: 10.4%. Regulatory Climate:Above Average.

BUSINESS: Vectren is a holding company formed through themerger of Indiana Energy and SIGCORP. Supplies electricity andgas to an area nearly two-thirds of the state of Indiana. Owns gasdistribution assets in Ohio. Has a customer base of 1,125,000.2009 Electricity revenues: residential, 37%; commercial, 28%; in-dustrial, 33%; other, 2%. 2009 Gas revenues: residential, 68%;

commercial, 26%; other, 6%. Also provides energy-related productsand services and has an investment subsidiary. Est’d plant age:electric, 8 years. ’09 deprec. rate: 4.6%. Has 3,700 employees.Chairman & CEO: Niel C. Ellerbrook. President: Carl Chapman. In-corporated: IN. Address: One Vectren Square, Evansville, Indiana47708. Telephone: 812-491-4000. Internet: www.vectren.com.

Vectren reported lower revenues andshare earnings for the first quarter.Earnings for the utility business almostequaled the prior-year tally. However, re-sults in the company’s nonutility opera-tions declined somewhat, due to unfavor-able weather in the Mid-Atlantic andNortheast regions, which limited MillerPipeline’s construction activities.ProLiance’s operating earnings decreased,reflecting lower margins for its transporta-tion and storage portfolio.The company will probably continueto face headwinds in the comingquarters. Some economic softness shouldcontinue to result in lower demand forelectricity, coal, and natural gas, comparedto historical trends. Nevertheless, per-formance ought to remain solid at the util-ity businesses, and we expect that earn-ings in the second and third quarters willcompare favorably with the prior-year pe-riods. Overall, though, we expect a modestbottom-line decline for the current year,due to weakness in the recent interim andassuming a bottom-line shortfall in thefourth quarter. The company’s operatingenvironment ought to improve, over time.

Share earnings may well rebound in 2011,assuming higher revenues and greatercost control.Vectren is seeking higher rates in In-diana. The company has filed an electricrate case with the Indiana Utility Regu-latory Commission, requesting an increasefor its utility, which is located in thesouthwestern part of the state. Vectren isalso seeking improved rate design. Thecompany cited investments in infrastruc-ture of roughly $325 million over the pastthree years, along with a slight increase inoperating and maintenance expenses.This stock is ranked to trail thebroader market averages over thecoming six to 12 months. Looking fur-ther out, we anticipate higher revenuesand share earnings by 2013-2015. Fromthe present quotation, this issue hashealthy total return potential for the com-ing 3 to 5 years, aided by its solid dividendyield. Moreover, Vectren earns favorablemarks for Safety, Price Stability, andEarnings Predictability. As a result, thestock may appeal to conservative, income-oriented accounts.Michael Napoli, CFA June 25, 2010






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WISCONSIN ENERGY NYSE-WEC 50.61 13.7 16.315.0 0.85 3.2%


SAFETY 2 Lowered 7/11/97






High: 31.6 23.6 24.6 26.5 33.7 34.6 40.8 48.7 50.5 49.6 50.6 53.8Low: 19.1 16.8 19.1 20.2 22.6 29.5 33.3 38.2 41.1 34.9 36.3 46.8


STOCK INDEX1 yr. 28.1 41.63 yr. 9.9 -2.65 yr. 53.2 37.2

CAPITAL STRUCTURE as of 3/31/10Total Debt $4916.8 mill. Due in 5 Yrs $1706.5 mill.LT Debt $4396.1 mill. LT Interest $248.4 mill.Incl. $141.9 mill. capitalized leases.(LT interest earned: 3.3x)Leases, Uncapitalized Annual rentals $21.3 mill.Pension Assets-12/09 $1.03 bill.

Oblig. $1.16 bill.Pfd Stock $30.4 mill. Pfd Div’d $1.2 mill.260,000 shs. 3.60%, $100 par, callable at $101;44,498 shs. 6%, $100 par.Common Stock 116,900,740 shs.

MARKET CAP: $5.9 billion (Large Cap)


% Change Retail Sales (KWH) +2.2 -2.2 -8.1Avg. Indust. Use (MWH) NA NA NAAvg. Indust. Revs. per KWH (¢) 6.02 6.05 6.57Capacity at Peak (Mw) NA NA NAPeak Load, Summer (Mw) 6166 5740 5812Annual Load Factor (%) NA NA NA% Change Customers (yr-end) +.2 +.5 +.2

Fixed Charge Cov. (%) 258 270 281ANNUAL RATES Past Past Est’d ’07-’09of change (per sh) 10 Yrs. 5 Yrs. to ’13-’15Revenues 7.5% 2.5% 3.0%‘‘Cash Flow’’ 4.5% 2.0% 7.0%Earnings 8.5% 7.0% 9.0%Dividends -3.0% 7.0% 13.0%Book Value 5.5% 7.5% 6.0%

Cal- Fullendar Year

QUARTERLY REVENUES ($ mill.)Mar.31 Jun.30 Sep.30 Dec.31

2007 1301.1 906.5 881.5 1148.7 4237.82008 1431.8 946.1 852.5 1200.6 4431.02009 1396.2 842.5 821.9 1067.3 4127.92010 1255.9 900 850 1144.1 41502011 1350 950 900 1200 4400Cal- Full


Mar.31 Jun.30 Sep.30 Dec.312007 .85 .49 .70 .80 2.842008 1.04 .49 .65 .85 3.032009 1.20 .54 .50 .96 3.202010 1.10 .65 .95 1.00 3.702011 1.25 .70 1.00 1.05 4.00Cal- Full

endar YearQUARTERLY DIVIDENDS PAID B ■ †

Mar.31 Jun.30 Sep.30 Dec.312006 .23 .23 .23 .23 .922007 .25 .25 .25 .25 1.002008 .27 .27 .27 .27 1.082009 .3375 .3375 .3375 .3375 1.352010 .40 .40

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 200715.99 15.98 15.88 15.86 17.13 19.11 28.28 34.04 32.20 34.24 29.33 32.62 34.17 36.24

3.81 4.28 4.25 2.96 4.13 4.53 4.48 5.44 5.68 5.71 5.16 5.78 5.80 5.971.67 2.13 1.97 .54 1.65 1.88 1.08 1.84 2.32 2.26 1.85 2.56 2.64 2.841.40 1.46 1.51 1.54 1.56 1.56 1.37 .80 .80 .80 .83 .88 .92 1.002.76 2.50 3.53 3.13 3.52 4.44 5.29 6.03 5.07 5.89 5.70 6.79 8.35 10.56

16.01 16.89 17.42 16.51 16.46 16.89 17.00 17.81 18.44 19.92 21.31 22.91 24.70 26.50108.94 110.82 111.68 112.87 115.61 118.90 118.65 115.42 116.03 118.43 116.99 116.98 116.97 116.94

15.2 13.1 14.3 47.3 18.0 13.3 18.7 12.1 10.5 12.4 17.5 14.5 16.0 16.51.00 .88 .90 2.73 .94 .76 1.22 .62 .57 .71 .92 .77 .86 .88

5.5% 5.2% 5.4% 6.0% 5.2% 6.3% 6.8% 3.6% 3.3% 2.8% 2.6% 2.4% 2.2% 2.1%

3354.7 3928.5 3736.2 4054.3 3431.1 3815.5 3996.4 4237.8132.0 218.8 270.8 269.2 221.2 304.8 313.7 337.7

43.7% 40.9% 37.4% 35.5% 37.5% 32.9% 35.8% 39.1%12.3% 6.9% 4.1% 6.9% 10.0% 12.5% 19.0% 23.8%58.9% 62.2% 59.8% 59.9% 56.2% 52.8% 51.3% 50.3%40.5% 37.2% 39.6% 39.6% 43.3% 46.7% 48.2% 49.2%4979.9 5523.8 5400.3 5963.3 5762.3 5741.5 5992.8 6302.14152.4 4188.0 4398.8 5926.1 5903.1 6362.9 7052.5 7681.2

4.7% 5.8% 7.1% 6.3% 5.6% 7.0% 6.6% 7.0%6.4% 10.5% 12.5% 11.3% 8.8% 11.2% 10.7% 10.8%6.5% 10.6% 12.6% 11.4% 8.8% 11.3% 10.8% 10.9%NMF 6.0% 8.3% 7.4% 4.9% 7.5% 7.1% 7.1%NMF 43% 35% 35% 45% 34% 35% 35%

2008 2009 2010 2011 © VALUE LINE PUB., INC. 13-1537.90 35.31 35.50 37.65 Revenues per sh 44.00

5.91 6.22 6.35 6.85 ‘‘Cash Flow’’ per sh 9.003.03 3.20 3.70 4.00 Earnings per sh A 5.001.08 1.35 1.60 1.80 Div’d Decl’d per sh B ■ † 2.409.73 6.99 8.15 8.70 Cap’l Spending per sh 6.50

28.54 30.51 32.45 34.45 Book Value per sh C 40.75116.92 116.91 116.90 116.90 Common Shs Outst’g D 116.90

14.8 13.3 Bold figures areValue Lineestimates

Avg Ann’l P/E Ratio 14.0.89 .88 Relative P/E Ratio .95


4431.0 4127.9 4150 4400 Revenues ($mill) 5150359.8 378.4 435 475 Net Profit ($mill) 595

37.6% 36.5% 35.5% 35.5% Income Tax Rate 34.5%27.2% 25.0% 16.0% 15.0% AFUDC % to Net Profit 10.0%54.8% 51.9% 55.0% 54.0% Long-Term Debt Ratio 51.5%44.8% 47.7% 44.5% 45.5% Common Equity Ratio 48.5%7442.0 7473.1 8500 8835 Total Capital ($mill) 98758517.0 9070.5 9660 10350 Net Plant ($mill) 11525

6.3% 6.4% 6.5% 7.0% Return on Total Cap’l 7.5%10.7% 10.5% 11.5% 11.5% Return on Shr. Equity 12.5%10.7% 10.6% 11.5% 11.5% Return on Com Equity E 12.5%

7.0% 6.2% 6.5% 6.5% Retained to Com Eq 6.5%35% 42% 43% 45% All Div’ds to Net Prof 48%

Company’s Financial Strength B++Stock’s Price Stability 100Price Growth Persistence 95Earnings Predictability 90

(A) Diluted EPS. Excl. nonrec. gains (losses):’99, (9¢); ’00, 19¢ net; ’01, 1¢ net; ’02, (88¢);’03, (20¢) net; ’04, (81¢); gains on discont.ops.: ’04, $1.54; ’05, 4¢; ’06, 4¢; ’09, 4¢. Next

earnings report due early Aug. (B) Div’ds his-torically paid in early Mar., June, Sept. & Dec.■ Div’d reinvestment plan avail. † Shareholderinvestment plan avail. (C) Incl. intang. In ’09:

$13.98/sh. (D) In mill. (E) Rate base: Net orig.cost. Rates allowed on com. eq. in ’10: 10.4%-10.5%; earned on avg. com. eq., ’09: 10.8%.Regulatory Climate: Above Average.

BUSINESS: Wisconsin Energy Corporation is a holding companyfor We Energies, which provides electric, gas & steam service inWisconsin. Customers: 1.1 mill. elec., 1 mill. gas. Acq’d EdisonSault Electric 5/98 & sold it 5/10; acq’d WICOR 4/00. Discontinuedpump-manufacturing ops. in ’04. Sold Point Beach nuclear plant in’07. Electric rev. breakdown, ’09: residential, 37%; small comm’l &

ind’l, 32%; large comm’l & ind’l, 23%; other, 8%. Generatingsources, ’09: coal, 52%; gas, 8%; hydro, 1%; wind, 1%; purchased,38%. Fuel costs: 48% of revs. ’09 reported depr. rate (utility): 3.7%.Has 4,700 empls. Chairman, Pres. & CEO: Gale E. Klappa. Inc.:WI. Address: 231 W. Michigan St., P.O. Box 1331, Milwaukee, WI53201. Tel.: 414-221-2345. Internet: www.wisconsinenergy.com.

Construction of generating plants un-der Wisconsin Energy’s ‘‘Power theFuture’’ program is concluding thisyear. The program called for the additionof two gas-fired and two coal-fired unitsthat are owned by a nonutility subsidiaryand leased to Wisconsin Electric underlong-term agreements that provide for anattractive return on equity of 12.7%. Thegas-fired units provided 1,150 megawattsof capacity at a cost of $664 million andwent on line in 2005 and 2008. One of thecoal-fired facilities began commercial oper-ation earlier this year, and the othershould be completed by August. The twounits will provide 1,030 mw of capacity atan expected cost of $2 billion. Thanks tothe income provided by the new coal plant,corporate profits should rise nicely in 2010and 2011.The utility is building morerenewable-energy projects. This isnecessary in order to meet renewable re-quirements in the state. Wisconsin Elec-tric already has a 145-mw wind projectthat was completed in 2008, at a cost of$295 million, and plans to add 160 mw ofwind capacity in 2011, at a cost of $367

million. The company is also requestingcommission approval to build a 50-mwbiomass facility, at a cost of $255 million,with an in-service date of 2013. It shouldget a decision by yearend. Finally, the util-ity intends to build 12.5 mw of solarprojects, at a cost of $85 million-$90 mil-lion, with the initial projects in service in2013.Wisconsin Energy sold its electricutility operation in the upper penin-sula of Michigan. The company soldEdison Sault Electric for $61.5 million,slightly above book value. The utilitywasn’t strategically important for Wiscon-sin Energy.This stock has a low yield (by utilitystandards), but offers excellent divi-dend growth potential to 2013-2015.The yield is about one and a half percent-age points below the industry mean. Wis-consin Energy is targeting a payout ratioof 40%-45% through 2011 and 45%-50%subsequently. As the dividend is raised toachieve these targets, this should producea 3- to 5-year total return that is near theutility average.Paul E. Debbas, CFA June 25, 2010






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)

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Dkt. No.

ER09-1534-001

VERIFICATION OF 2009 VALUE LINE DIVIDEND

DATA

(EXHIBIT SCE-58)

OCTOBER 2010

Calculations to verify that

dividend data are Value Line

data for 2009

VL DPS 09

from Ex. MSR-5

Company Stock Price Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Page 2 Same?

1 Alliant Energy High $30.45 $32.37 $32.06 $33.40 $35.32 $34.53

Low $27.22 $29.63 $30.25 $31.84 $33.22 $31.14

(High+Low)/2 $28.84 $31.00 $31.16 $32.62 $34.27 $32.84 $31.79

Annual Dividend $1.50 $1.50 $1.50 $1.50 $1.50 $1.50 $1.50 TRUE

Dividend Yield (Low) 4.93% 4.63% 4.68% 4.49% 4.25% 4.34% 4.55%

Dividend Yield (High) 5.51% 5.06% 4.96% 4.71% 4.52% 4.82% 4.93%

Dividend Yield (Average) 5.20% 4.84% 4.81% 4.60% 4.38% 4.57% 4.73%

2 Amer.Elec. Power High $34.70 $35.62 $34.20 $34.38 $34.06 $34.13

Low $32.23 $33.69 $32.41 $33.47 $32.92 $30.97

(High+Low)/2 $33.47 $34.66 $33.31 $33.93 $33.49 $32.55 $33.57





3 Centerpoint Energy High $14.40 $14.45 $14.33 $14.27 $14.54 $14.37

Low $13.10 $13.56 $13.20 $13.41 $13.99 $13.06

(High+Low)/2 $13.75 $14.01 $13.77 $13.84 $14.27 $13.72 $13.89





4 Consol. Edison High $44.88 $45.16 $42.95 $44.08 $44.80 $45.12

Low $42.14 $42.33 $41.65 $42.61 $43.91 $42.27

(High+Low)/2 $43.51 $43.75 $42.30 $43.35 $44.36 $43.70 $43.49





5 DPL Inc. High $28.04 $27.84 $27.09 $27.43 $27.87 $27.79

Low $26.93 $26.24 $25.92 $26.68 $26.91 $24.52

(High+Low)/2 $27.49 $27.04 $26.51 $27.06 $27.39 $26.16 $26.94





6 DTE Energy High $44.12 $43.82 $44.10 $45.38 $48.29 $48.91

Low $40.04 $41.55 $41.02 $43.80 $45.38 $44.54

(High+Low)/2 $42.08 $42.69 $42.56 $44.59 $46.84 $46.73 $44.25





7 Duke Energy High $17.30 $16.60 $16.37 $16.38 $16.54 $16.74Low $16.62 $16.06 $15.86 $16.07 $15.78 $15.71(High+Low)/2 $16.96 $16.33 $16.12 $16.23 $16.16 $16.23 $16.34





8 Exelon Corp. High $50.37 $48.47 $45.03 $44.94 $44.53 $43.59Low $47.70 $44.52 $42.71 $42.66 $42.32 $38.06(High+Low)/2 $49.04 $46.50 $43.87 $43.80 $43.43 $40.83 $44.58





9 Hawaiian Electric High $20.74 $21.11 $20.90 $22.30 $23.58 $23.40Low $19.14 $19.22 $18.25 $20.23 $22.33 $21.51(High+Low)/2 $19.94 $20.17 $19.58 $21.27 $22.96 $22.46 $21.06





10 OGE Energy High $32.05 $32.63 $33.66 $35.19 $36.29 $36.81Low $29.55 $30.79 $30.19 $33.19 $34.70 $31.88(High+Low)/2 $30.80 $31.71 $31.93 $34.19 $35.50 $34.35 $33.08

Annual Dividend $1.20 $1.20 $1.20 $1.20 $1.20 $1.20 #N/A #N/A




11 Northeast Utilities High $25.81 $25.89 $26.16 $27.55 $27.92 $27.47Low $23.87 $24.82 $24.29 $25.85 $26.75 $25.27(High+Low)/2 $24.84 $25.36 $25.23 $26.70 $27.34 $26.37 $25.97





12 Pepco Holdings High $16.83 $16.99 $16.56 $17.03 $17.36 $16.74Low $15.94 $15.84 $15.39 $16.19 $15.97 $15.40(High+Low)/2 $16.39 $16.42 $15.98 $16.61 $16.67 $16.07 $16.35





Average Prices Based on Previous Number of Days' Trades

Closing Date: May 28, 2010

DR. LESSER'S DATA FROM DATA REQUEST SCE-M-S-R/LADWP-86


Calculations to verify that

dividend data are Value Line

data for 2009

VL DPS 09

from Ex. MSR-5

Company Stock Price Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Page 2 Same?

Average Prices Based on Previous Number of Days' Trades

Closing Date: May 28, 2010

DR. LESSER'S DATA FROM DATA REQUEST SCE-M-S-R/LADWP-86

13 PG&E Corp. High $44.99 $45.11 $42.16 $42.86 $43.96 $44.48Low $42.04 $41.79 $40.59 $41.59 $42.47 $41.21(High+Low)/2 $43.52 $43.45 $41.38 $42.23 $43.22 $42.85 $42.77





14 Portland General High $20.68 $20.23 $19.49 $19.42 $20.15 $20.40Low $19.41 $19.24 $17.75 $17.97 $19.44 $18.61(High+Low)/2 $20.05 $19.74 $18.62 $18.70 $19.80 $19.51 $19.40





15 PPL Corp. High $32.14 $31.78 $29.10 $28.78 $28.25 $25.81Low $30.10 $28.74 $27.75 $27.20 $24.42 $24.33(High+Low)/2 $31.12 $30.26 $28.43 $27.99 $26.34 $25.07 $28.20





16 Progress Energy High $40.70 $39.68 $38.88 $39.27 $39.92 $40.53Low $38.39 $37.93 $36.73 $38.05 $38.66 $37.98(High+Low)/2 $39.55 $38.81 $37.81 $38.66 $39.29 $39.26 $38.89





17 PSEG High $33.78 $33.63 $31.18 $31.20 $32.13 $32.77Low $31.68 $30.57 $29.48 $29.11 $30.12 $29.89(High+Low)/2 $32.73 $32.10 $30.33 $30.16 $31.13 $31.33 $31.30





18 SCANA Corp High $37.45 $36.80 $35.49 $37.52 $38.95 $39.40Low $34.44 $34.69 $33.66 $35.82 $37.50 $35.30(High+Low)/2 $35.95 $35.75 $34.58 $36.67 $38.23 $37.35 $36.42





19 Sempra Energy High $56.44 $55.47 $51.09 $50.75 $51.36 $50.37Low $53.03 $50.36 $47.76 $48.41 $49.02 $44.96(High+Low)/2 $54.74 $52.92 $49.43 $49.58 $50.19 $47.67 $50.75





20 TECO Energy High $16.18 $16.06 $15.58 $15.97 $16.84 $17.05Low $14.70 $15.17 $14.37 $15.22 $15.95 $14.85(High+Low)/2 $15.44 $15.62 $14.98 $15.60 $16.40 $15.95 $15.66





21 Vectren Corp. High $24.55 $24.16 $23.15 $24.56 $25.24 $25.00Low $23.12 $22.61 $22.01 $22.93 $24.02 $22.41(High+Low)/2 $23.84 $23.39 $22.58 $23.75 $24.63 $23.71 $23.65





22 Wisconsin Energy High $49.62 $49.90 $49.42 $50.80 $52.11 $53.03Low $45.07 $48.12 $47.33 $48.93 $49.53 $48.21(High+Low)/2 $47.35 $49.01 $48.38 $49.87 $50.82 $50.62 $49.34





23 Xcel Energy High $21.35 $21.36 $20.93 $21.33 $21.94 $22.10Low $20.09 $20.54 $19.81 $20.78 $21.23 $20.27(High+Low)/2 $20.72 $20.95 $20.37 $21.06 $21.59 $21.19 $20.98







BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

UPDATED DCF ESTIMATES, SEPTEMBER 2010

(EXHIBIT SCE-59)

OCTOBER 2010

Discounted Cash Flow (DCF) Analysis

National Proxy Group

Line

No. Company Low High Low High br + sv I/B/E/S Low High Average

1. LNT Alliant Energy 4.43% 4.92% 4.54% 5.16% 4.92% 9.90% 9.46% - 15.06% 12.26%

2. AEP Amer. Elec. Power 4.69% 5.20% 4.79% 5.31% 4.45% 4.38% 9.17% - 9.76% 9.46%

3. CNP CenterPoint Energy 5.25% 6.04% 5.40% 6.28% 7.96% 5.70% 11.10% - 14.24% 12.67%

4. ED Consol. Edison 5.08% 5.43% 5.16% 5.55% 3.17% 4.47% 8.33% - 10.02% 9.18%

5. D Dominion Resources 4.22% 4.57% 4.29% 4.69% 5.49% 3.50% 7.79% - 10.18% 8.99%

6. DPL DPL Inc. 4.49% 4.90% 4.62% 5.26% 14.75% 5.90% 10.52% - 20.01% 15.26%

7. DTE DTE Energy 4.40% 4.81% 4.49% 4.93% 4.18% 5.00% 8.67% - 9.93% 9.30%

8. DUK Duke Energy 5.57% 6.00% 5.64% 6.12% 2.22% 4.00% 7.85% - 10.12% 8.99%

9. EXC Exelon Corp. 4.85% 5.37% 4.87% 5.55% 6.95% 0.97% 5.84% - 12.50% 9.17%

10. GXP G't Plains Energy 4.38% 4.75% 4.44% 5.06% 2.55% 13.00% 6.99% - 18.06% 12.52%

11. HE Hawaiian Elec. 5.10% 5.62% 5.18% 5.83% 2.96% 7.43% 8.14% - 13.25% 10.70%

12. IDA IDACORP, Inc. 3.28% 3.63% 3.35% 3.73% 5.43% 4.00% 7.35% - 9.15% 8.25%

13. TEG Integrys Energy 5.42% 5.99% 5.47% 6.27% 1.86% 9.40% 7.33% - 15.67% 11.50%

14. NEE NextEra Energy 3.71% 4.04% 3.83% 4.19% 7.67% 6.83% 10.67% - 11.86% 11.27%

15. NU Northeast Utilities 3.58% 3.88% 3.67% 4.02% 5.07% 7.51% 8.74% - 11.54% 10.14%

16. OGE OGE Energy 3.55% 3.98% 3.64% 4.14% 8.03% 5.00% 8.64% - 12.17% 10.40%

17. PCG PG&E Corp. 3.98% 4.48% 4.11% 4.64% 6.27% 6.88% 10.37% - 11.52% 10.95%

18. POR Portland General 5.11% 5.51% 5.17% 5.66% 2.32% 5.40% 7.49% - 11.06% 9.27%

19. PGN Progress Energy 5.89% 6.30% 5.96% 6.42% 2.39% 3.63% 8.36% - 10.05% 9.20%

20. PEG Public Serv. Enterprise 4.08% 4.52% 4.12% 4.70% 8.15% 2.00% 6.12% - 12.85% 9.49%

21. SCG SCANA Corp. 4.78% 5.20% 4.89% 5.33% 5.23% 4.90% 9.79% - 10.56% 10.18%

22. SRE Sempra Energy 3.01% 3.32% 3.06% 3.42% 6.09% 3.50% 6.56% - 9.52% 8.04%

23. TE TECO Energy 4.75% 5.29% 4.87% 5.47% 5.01% 6.68% 9.88% - 12.15% 11.02%

24. WR Westar Energy 5.15% 5.62% 5.22% 5.88% 2.90% 9.28% 8.12% - 15.16% 11.64%

25. WEC Wisconsin Energy 2.91% 3.18% 3.01% 3.33% 6.99% 9.53% 10.00% - 12.85% 11.43%

26. XEL Xcel Energy Inc. 4.45% 4.80% 4.55% 4.96% 4.46% 6.64% 9.01% - 11.60% 10.30%

27. Range 5.84% 20.01%

28. Midpoint of Range 12.92%

29. Average of Range 10.44%

30. Median of Range 10.01%

31. Median of Company Averages 10.24%

32. Number of Company Averages 26

33. Number of Individual Estimates 52

34. Adjusted Range

35. Midpoint of Adjusted Range

36. Average of Adjusted Range

37. Median of Adjusted Range

38. Median of Company Averages, Adjusted Range

39. Number of Company Averages, Adjusted Range

40. Number of Individual Estimates, Adjusted Range

Adj Average Div YieldAverage Div Yield Estimated ROEGrowth Rates




Line

No. Company

1. LNT Alliant Energy

2. AEP Amer. Elec. Power

3. CNP CenterPoint Energy

4. ED Consol. Edison

5. D Dominion Resources

6. DPL DPL Inc.

7. DTE DTE Energy

8. DUK Duke Energy

9. EXC Exelon Corp.

10. GXP G't Plains Energy

11. HE Hawaiian Elec.

12. IDA IDACORP, Inc.

13. TEG Integrys Energy

14. NEE NextEra Energy

15. NU Northeast Utilities

16. OGE OGE Energy

17. PCG PG&E Corp.

18. POR Portland General

19. PGN Progress Energy

20. PEG Public Serv. Enterprise

21. SCG SCANA Corp.

22. SRE Sempra Energy

23. TE TECO Energy

24. WR Westar Energy

25. WEC Wisconsin Energy

26. XEL Xcel Energy Inc.

27. Range

28. Midpoint of Range

29. Average of Range

30. Median of Range

31. Median of Company Averages

32. Number of Company Averages

33. Number of Individual Estimates

34. Adjusted Range

35. Midpoint of Adjusted Range

36. Average of Adjusted Range

37. Median of Adjusted Range

38. Median of Company Averages, Adjusted Range

39. Number of Company Averages, Adjusted Range

40. Number of Individual Estimates, Adjusted Range

Low

Est.

Above

Bond

Yield

+100

High

Est.

Below

17.7%;

g Below

13.3%

S&P

Issuer

Credit

Rating

Bond Yield

Threshold

(Moody's Rate

plus 100 Basis

Points)

Low High Average

9.46% 15.06% 12.26% TRUE TRUE BBB+ 6.90%

9.17% 9.76% 9.46% TRUE TRUE BBB 6.90%

11.10% 14.24% 12.67% TRUE TRUE BBB 6.90%

8.33% 10.02% 9.18% TRUE TRUE A- 6.34%

7.79% 10.18% 8.99% TRUE TRUE A- 6.34%

10.52% TRUE FALSE A- 6.34%

8.67% 9.93% 9.30% TRUE TRUE BBB 6.90%

7.85% 10.12% 8.99% TRUE TRUE A- 6.34%

12.50% FALSE TRUE BBB 6.90%

6.99% TRUE FALSE BBB 6.90%

8.14% 13.25% 10.70% TRUE TRUE BBB 6.90%

7.35% 9.15% 8.25% TRUE TRUE BBB 6.90%

7.33% 15.67% 11.50% TRUE TRUE BBB+ 6.90%

10.67% 11.86% 11.27% TRUE TRUE A- 6.34%

8.74% 11.54% 10.14% TRUE TRUE BBB 6.90%

8.64% 12.17% 10.40% TRUE TRUE BBB+ 6.90%

10.37% 11.52% 10.95% TRUE TRUE BBB+ 6.90%

7.49% 11.06% 9.27% TRUE TRUE BBB 6.90%

8.36% 10.05% 9.20% TRUE TRUE BBB+ 6.90%

12.85% FALSE TRUE BBB 6.90%

9.79% 10.56% 10.18% TRUE TRUE BBB+ 6.90%

9.52% FALSE TRUE BBB+ 6.90%

9.88% 12.15% 11.02% TRUE TRUE BBB 6.90%

8.12% 15.16% 11.64% TRUE TRUE BBB 6.90%

10.00% 12.85% 11.43% TRUE TRUE BBB+ 6.90%

9.01% 11.60% 10.30% TRUE TRUE A- 6.34%

6.99% 15.67%

11.33%

10.35%

10.02%

10.30%

21

47

Estimated ROE,

Adjusted Range



National SCE Proxy Group

Line 2010 2011 2013-15 AverageNo. Name 2010 2011 2013-15

1. LNT Alliant Energy 0.392 0.431 0.467 0.430

2. AEP Amer. Elec. Power 0.345 0.460 0.457 0.421

3. CNP CenterPoint Energy 0.257 0.333 0.400 0.330

4. ED Consol. Edison 0.300 0.314 0.361 0.325

5. D Dominion Resources 0.369 0.406 0.400 0.392

6. DPL DPL Inc. 0.506 0.517 0.500 0.508

7. DTE DTE Energy 0.426 0.403 0.365 0.398

8. DUK Duke Energy 0.254 0.267 0.300 0.274

9. EXC Exelon Corp. 0.447 0.475 0.400 0.441

10. GXP G't Plains Energy 0.447 0.420 0.343 0.403

11. HE Hawaiian Elec. 0.114 0.225 0.350 0.230

12. IDA IDACORP, Inc. 0.564 0.586 0.548 0.566

13. TEG Integrys Energy 0.078 0.176 0.320 0.191

14. NEE NextEra Energy 0.583 0.512 0.520 0.538

15. NU Northeast Utilities 0.472 0.488 0.480 0.480

16. OGE OGE Energy 0.488 0.511 0.543 0.514

17. PCG PG&E Corp. 0.448 0.463 0.467 0.459

18. POR Portland General 0.230 0.371 0.400 0.333

19. PGN Progress Energy 0.173 0.200 0.273 0.216

20. PEG Public Serv. Enterprise 0.543 0.552 0.508 0.534

21. SCG SCANA Corp. 0.367 0.370 0.429 0.389

22. SRE Sempra Energy 0.567 0.635 0.590 0.597

23. TE TECO Energy 0.317 0.378 0.406 0.367

24. WR Westar Energy 0.291 0.308 0.378 0.326

25. WEC Wisconsin Energy 0.568 0.561 0.543 0.557

26. XEL Xcel Energy Inc. 0.375 0.394 0.425 0.398

b




LineNo. Name






6. DPL DPL Inc.

7. DTE DTE Energy

8. DUK Duke Energy

9. EXC Exelon Corp.







16. OGE OGE Energy

17. PCG PG&E Corp.




21. SCG SCANA Corp.


23. TE TECO Energy




2010 2011 2013-15 Average Adjusted2010 2011 2013-15

0.095 0.105 0.115 0.105 0.108

0.090 0.105 0.100 0.098 0.101

0.135 0.150 0.145 0.143 0.151

0.090 0.095 0.095 0.093 0.095

0.140 0.145 0.145 0.143 0.149

0.245 0.250 0.255 0.250 0.258

0.095 0.095 0.095 0.095 0.098

0.080 0.080 0.080 0.080 0.081

0.185 0.175 0.145 0.168 0.172

0.070 0.070 0.075 0.072 0.073

0.090 0.095 0.110 0.098 0.101

0.090 0.090 0.085 0.088 0.091

0.080 0.085 0.095 0.087 0.088

0.140 0.120 0.115 0.125 0.130

0.090 0.095 0.095 0.093 0.096

0.130 0.120 0.115 0.122 0.128

0.110 0.115 0.120 0.115 0.119

0.065 0.070 0.085 0.073 0.076

0.095 0.095 0.100 0.097 0.099

0.160 0.150 0.130 0.147 0.152

0.100 0.095 0.100 0.098 0.102

0.095 0.115 0.105 0.105 0.108

0.120 0.125 0.130 0.125 0.128

0.085 0.080 0.085 0.083 0.086

0.115 0.120 0.130 0.122 0.125

0.095 0.095 0.100 0.097 0.100

r




LineNo. Name






6. DPL DPL Inc.

7. DTE DTE Energy

8. DUK Duke Energy

9. EXC Exelon Corp.







16. OGE OGE Energy

17. PCG PG&E Corp.




21. SCG SCANA Corp.


23. TE TECO Energy




I/B/E/S

Estimated

Long-Term

s v g = br + sv Growth

0.012 0.233 4.92% 9.90%

0.011 0.180 4.45% 4.38%

0.060 0.494 7.96% 5.70%

0.005 0.187 3.17% 4.47%

-0.006 0.525 5.49% 3.50%

0.027 0.626 14.75% 5.90%

0.018 0.166 4.18% 5.00%

0.004 0.012 2.22% 4.00%

-0.013 0.515 6.95% 0.97%

0.029 -0.144 2.55% 13.00%

0.020 0.321 2.96% 7.43%

0.019 0.142 5.43% 4.00%

0.008 0.213 1.86% 9.40%

0.018 0.366 7.67% 6.83%

0.018 0.246 5.07% 7.51%

0.034 0.439 8.03% 5.00%

0.023 0.336 6.27% 6.88%

0.035 -0.059 2.32% 5.40%

0.016 0.169 2.39% 3.63%

0.000 0.431 8.15% 2.00%

0.049 0.256 5.23% 4.90%

-0.014 0.245 6.09% 3.50%

0.008 0.391 5.01% 6.68%

0.012 0.093 2.90% 9.28%

0.000 0.404 6.99% 9.53%

0.020 0.249 4.46% 6.64%


Ticker Company

Proxy

Group

Tickers

Proxy

Group

Names

Include in

Proxy

Group

Electric

Utility

Credit

Rating

Screen

Revenue

Screen

AYE Allegheny Energy FALSE TRUE FALSE TRUE

ALE ALLETE FALSE TRUE TRUE FALSE

LNT Alliant Energy LNT Alliant Energy TRUE TRUE TRUE TRUE

AEP Amer. Elec. Power AEP Amer. Elec. Power TRUE TRUE TRUE TRUE

AEE Ameren Corp. FALSE TRUE FALSE TRUE

AVA Avista Corp. FALSE TRUE FALSE TRUE

BKH Black Hills FALSE TRUE FALSE FALSE

CV Cen. Vermont Pub. Serv. FALSE TRUE FALSE FALSE

CNP CenterPoint Energy CNP CenterPoint Energy TRUE TRUE TRUE TRUE

CHG CH Energy Group FALSE TRUE FALSE FALSE

CNL Cleco Corp. FALSE TRUE TRUE FALSE

CMS CMS Energy Corp. FALSE TRUE FALSE TRUE

ED Consol. Edison ED Consol. Edison TRUE TRUE TRUE TRUE

CEG Constellation Energy FALSE TRUE FALSE TRUE

D Dominion Resources D Dominion Resources TRUE TRUE TRUE TRUE

DPL DPL Inc. DPL DPL Inc. TRUE TRUE TRUE TRUE

DTE DTE Energy DTE DTE Energy TRUE TRUE TRUE TRUE

DUK Duke Energy DUK Duke Energy TRUE TRUE TRUE TRUE

EIX Edison Int'l FALSE TRUE FALSE TRUE

EE El Paso Electric FALSE TRUE TRUE FALSE

EDE Empire Dist. Elec. FALSE TRUE FALSE FALSE

ETR Entergy Corp. FALSE TRUE TRUE TRUE

EXC Exelon Corp. EXC Exelon Corp. TRUE TRUE TRUE TRUE

FE FirstEnergy Corp. FALSE TRUE FALSE TRUE

GXP G't Plains Energy GXP G't Plains Energy TRUE TRUE TRUE TRUE

HE Hawaiian Elec. HE Hawaiian Elec. TRUE TRUE TRUE TRUE

IDA IDACORP, Inc. IDA IDACORP, Inc. TRUE TRUE TRUE TRUE

TEG Integrys Energy TEG Integrys Energy TRUE TRUE TRUE TRUE

ITC ITC Holdings FALSE TRUE TRUE FALSE

MGEE MGE Energy FALSE TRUE FALSE TRUE

NEE NextEra Energy NEE NextEra Energy TRUE TRUE TRUE TRUE

NU Northeast Utilities NU Northeast Utilities TRUE TRUE TRUE TRUE

NST NSTAR FALSE TRUE FALSE TRUE

NVE NV Energy Inc. FALSE TRUE FALSE TRUE

OGE OGE Energy OGE OGE Energy TRUE TRUE TRUE TRUE

OTTR Otter Tail Corp. FALSE TRUE FALSE FALSE

POM Pepco Holdings FALSE TRUE TRUE TRUE

PCG PG&E Corp. PCG PG&E Corp. TRUE TRUE TRUE TRUE

PNW Pinnacle West Capital FALSE TRUE FALSE TRUE

PNM PNM Resources FALSE TRUE FALSE TRUE

POR Portland General POR Portland General TRUE TRUE TRUE TRUE

PPL PPL Corp. FALSE TRUE TRUE TRUE

PGN Progress Energy PGN Progress Energy TRUE TRUE TRUE TRUE

PEG Public Serv. Enterprise PEG Public Serv. Enterprise TRUE TRUE TRUE TRUE

SCG SCANA Corp. SCG SCANA Corp. TRUE TRUE TRUE TRUE

SRE Sempra Energy SRE Sempra Energy TRUE TRUE TRUE TRUE

SO Southern Co. FALSE TRUE FALSE TRUE

TE TECO Energy TE TECO Energy TRUE TRUE TRUE TRUE

UIL UIL Holdings FALSE TRUE TRUE FALSE

UNS UniSource Energy FALSE TRUE FALSE TRUE

VVC Vectren Corp. FALSE TRUE TRUE FALSE

WR Westar Energy WR Westar Energy TRUE TRUE TRUE TRUE

WEC Wisconsin Energy WEC Wisconsin Energy TRUE TRUE TRUE TRUE

XEL Xcel Energy Inc. XEL Xcel Energy Inc. TRUE TRUE TRUE TRUE

Information to Screen Companies for



Ticker Company

AYE Allegheny Energy

ALE ALLETE

LNT Alliant Energy


AEE Ameren Corp.

AVA Avista Corp.

BKH Black Hills

CV Cen. Vermont Pub. Serv.


CHG CH Energy Group

CNL Cleco Corp.

CMS CMS Energy Corp.

ED Consol. Edison

CEG Constellation Energy


DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EIX Edison Int'l

EE El Paso Electric

EDE Empire Dist. Elec.

ETR Entergy Corp.

EXC Exelon Corp.

FE FirstEnergy Corp.


HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

ITC ITC Holdings

MGEE MGE Energy

NEE NextEra Energy


NST NSTAR

NVE NV Energy Inc.

OGE OGE Energy

OTTR Otter Tail Corp.

POM Pepco Holdings

PCG PG&E Corp.

PNW Pinnacle West Capital

PNM PNM Resources


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

SO Southern Co.

TE TECO Energy

UIL UIL Holdings

UNS UniSource Energy

VVC Vectren Corp.

WR Westar Energy





3 4

Dividend

Screen

Apr 2010

Sep 2010

Merger

Screen

Apr 2010

Sep 2010

Analyst

Screen

IBES

Growth

Rate

Issuer

Credit

Rating

Annual

Electric

Revenues

4/1/2010 9/30/2010

TRUE FALSE TRUE TRUE BBB- 3649.4

TRUE TRUE TRUE TRUE BBB+ 820.9


TRUE TRUE TRUE TRUE BBB 13023

TRUE TRUE TRUE TRUE BBB- 5972

TRUE TRUE TRUE TRUE BBB- 1426.726


TRUE TRUE TRUE FALSE NR 339.688


TRUE TRUE TRUE FALSE #N/A 541.878

TRUE TRUE TRUE TRUE BBB 924.029


TRUE TRUE TRUE TRUE A- 8707

TRUE FALSE TRUE TRUE BBB- 2760.6


TRUE TRUE TRUE TRUE A- 1709.4




FALSE TRUE TRUE FALSE BBB 780.734

TRUE TRUE TRUE FALSE BBB- 443.97

TRUE FALSE TRUE TRUE BBB 8155.693


TRUE FALSE TRUE TRUE BBB- 10244






TRUE TRUE FALSE TRUE #N/A 131429.147



TRUE TRUE TRUE TRUE A+ 2432.37

TRUE TRUE TRUE TRUE BB 3281.448

TRUE TRUE TRUE TRUE BBB+ 1946

TRUE TRUE FALSE TRUE BBB- 322.693

TRUE FALSE TRUE TRUE BBB+ 5000



TRUE TRUE TRUE TRUE BB- 1649.86


TRUE FALSE TRUE TRUE BBB 3901





TRUE TRUE TRUE TRUE A 16466.453


TRUE FALSE TRUE TRUE BBB 887.637

TRUE TRUE TRUE TRUE #N/A 1172.453






Ticker Company


ALE ALLETE

LNT Alliant Energy


AEE Ameren Corp.

AVA Avista Corp.

BKH Black Hills



CHG CH Energy Group

CNL Cleco Corp.


ED Consol. Edison



DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EIX Edison Int'l

EE El Paso Electric


ETR Entergy Corp.

EXC Exelon Corp.



HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

ITC ITC Holdings

MGEE MGE Energy

NEE NextEra Energy


NST NSTAR

NVE NV Energy Inc.

OGE OGE Energy


POM Pepco Holdings

PCG PG&E Corp.


PNM PNM Resources


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

SO Southern Co.

TE TECO Energy

UIL UIL Holdings


VVC Vectren Corp.

WR Westar Energy




National Proxy Group 6

10 11 12 13 14 14 9 29

Quarterly

Electric

Revenues

Number of

Analysts

IBES

Growth

Rate Dividend Data

9/30/2010

793.7 861.1 1048.9 945.7 0 12 1 0.15

160.1 216 233.6 211.2 0 2 6.5 0.44

725.3 574.7 604.9 627.3 0 9 9.9 0.395

3364 3067 3406 3186 0 19 4.375 0.42

1679 1320 1440 1533 0 9 -5.95 0.385

290.74 376.578 428.686 330.722 0 5 4 0.25

191.857 302.576 148.809 136.265 0 4 6 0.36

81.791 86.953 91.007 79.937 0 2 -- 0.23

608 472 482 562 0 12 5.7 0.195

138.685 132.135 145.962 125.096 0 3 -- 0.54

228.952 181.178 252.798 261.101 0 6 3 0.25

1000 745 838 975 0 14 6 0.15

2604 1958 1889 2256 0 16 4.46666667 0.595

788.3 569.9 751.3 651.1 0 9 9.9 0.24

2904 1985 2662 2528 0 19 3.5 0.4575

407.3 405.4 451.2 445.5 0 7 5.9 0.3025

1300 1191 1146 1208 0 12 5 0.56

2784 2316 2625 2531 0 23 4 0.245

3065 2433 2159 2246 0 18 2.22 0.315

240.898 124.271 204.168 211.397 0 5 -- 0

121.487 102.634 113.6 106.249 0 4 -- 0.32

2195.461 1739.193 2006.931 2214.108 0 19 5.14 0.83

4277 3905 4135 4309 0 20 0.96666667 0.525

2940 2388 2543 2373 0 15 2 0.55

587.7 477.6 506.9 552 0 8 13 0.2075

548.44 574.355 548.111 584.095 0 6 7.425 0.31

323.128 252.321 252.46 240.79 0 5 4 0.3

332.3 2541.7 330.1 610.8 0 6 9.4 0.68

#N/A N/A 0 0 0 0 8 16.5266667 0.335

106.878 131056 158.541 107.728 0 1 5 0.3751

3301 2753 2328 2580 0 21 6.83333333 0.5

1082 1023.2 1000 884.5 0 15 7.514 0.25625

699.162 571.615 579.777 581.816 0 13 5.775 0.4

1199.254 700.303 636.941 744.95 0 13 12.37 0.11

577.9 411.3 444 512.8 0 7 5 0.3625

73.506 81.868 91.086 76.233 0 1 20 0.2975

1400 1284 1167 1149 0 8 7 0.27

2630 2647 2510 2515 0 16 6.884 0.455

1083.75 650.349 611.425 799.416 0 11 6.5 0.525

477.665 382.982 383.396 405.817 0 11 13.3675 0.125

445 485 449 415 0 11 5.4 0.26

989 1001 1118 793 0 9 5.6 0.35

2824 2307 2535 2372 0 17 3.63333333 0.62

1685 1121 1225 1193 0 17 2 0.3425

615 508 540 575 0 5 4.9 0.475

693 460 742 586 0 8 3.5 0.39

4656.65 3487 4135.942 4186.861 0 20 5.07428571 0.455

620.9 502.4 525.1 552.8 0 17 6.68333333 0.205

255 205.248 220.276 207.113 0 7 3.875 0.432

377.723 266.725 240.891 287.114 0 6 5 0.39

143 127.9 144.9 151 0 6 4.85 0.34

528.534 440.118 459.83 495.181 0 10 9.275 0.31

689.1 678.6 711.1 701.7 0 14 9.525 0.4

2128.955 1953.81 1995.592 2040.702 0 14 6.6375 0.2525


Ticker Company


ALE ALLETE

LNT Alliant Energy


AEE Ameren Corp.

AVA Avista Corp.

BKH Black Hills



CHG CH Energy Group

CNL Cleco Corp.


ED Consol. Edison



DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EIX Edison Int'l

EE El Paso Electric


ETR Entergy Corp.

EXC Exelon Corp.



HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

ITC ITC Holdings

MGEE MGE Energy

NEE NextEra Energy


NST NSTAR

NVE NV Energy Inc.

OGE OGE Energy


POM Pepco Holdings

PCG PG&E Corp.


PNM PNM Resources


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

SO Southern Co.

TE TECO Energy

UIL UIL Holdings


VVC Vectren Corp.

WR Westar Energy





28 27 26 25 24 23 22 21

Dividend Data

8/31/2010 7/31/2010 6/30/2010 5/31/2010 4/30/2010 3/31/2010 2/28/2010 1/31/2010

0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15

0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44

0.395 0.395 0.395 0.395 0.395 0.395 0.395 0.395

0.42 0.42 0.42 0.42 0.41 0.41 0.41 0.41

0.385 0.385 0.385 0.385 0.385 0.385 0.385 0.385

0.25 0.25 0.25 0.25 0.25 0.25 0.25 0.21

0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.355

0.23 0.23 0.23 0.23 0.23 0.23 0.23 0.23

0.195 0.195 0.195 0.195 0.195 0.195 0.195 0.19

0.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54

0.25 0.25 0.25 0.25 0.225 0.225 0.225 0.225

0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.125

0.595 0.595 0.595 0.595 0.595 0.595 0.595 0.59

0.24 0.24 0.24 0.24 0.24 0.24 0.24 0.24

0.4575 0.4575 0.4575 0.4575 0.4575 0.4575 0.4575 0.4375

0.3025 0.3025 0.3025 0.3025 0.3025 0.3025 0.3025 0.285

0.53 0.53 0.53 0.53 0.53 0.53 0.53 0.53

0.245 0.24 0.24 0.24 0.24 0.24 0.24 0.24

0.315 0.315 0.315 0.315 0.315 0.315 0.315 0.315

0 0 0 0 0 0 0 0

0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32

0.83 0.83 0.83 0.83 0.75 0.75 0.75 0.75

0.525 0.525 0.525 0.525 0.525 0.525 0.525 0.525

0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55

0.2075 0.2075 0.2075 0.2075 0.2075 0.2075 0.2075 0.2075

0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31

0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

0.68 0.68 0.68 0.68 0.68 0.68 0.68 0.68

0.335 0.32 0.32 0.32 0.32 0.32 0.32 0.32

0.3751 0.3684 0.3684 0.3684 0.3684 0.3684 0.3684 0.3684

0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.4725

0.25625 0.25625 0.25625 0.25625 0.25625 0.25625 0.25625 0.2375

0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4

0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11

0.3625 0.3625 0.3625 0.3625 0.3625 0.3625 0.3625 0.3625

0.2975 0.2975 0.2975 0.2975 0.2975 0.2975 0.2975 0.2975

0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27

0.455 0.455 0.455 0.455 0.455 0.455 0.42 0.42

0.525 0.525 0.525 0.525 0.525 0.525 0.525 0.525

0.125 0.125 0.125 0.125 0.125 0.125 0.125 0.125

0.26 0.26 0.26 0.255 0.255 0.255 0.255 0.255

0.35 0.35 0.35 0.35 0.35 0.35 0.345 0.345

0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62

0.3425 0.3425 0.3425 0.3425 0.3425 0.3425 0.3325 0.3325

0.475 0.475 0.475 0.475 0.475 0.475 0.47 0.47

0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.39

0.455 0.455 0.455 0.455 0.455 0.4375 0.4375 0.4375

0.205 0.205 0.205 0.205 0.2 0.2 0.2 0.2

0.432 0.432 0.432 0.432 0.432 0.432 0.432 0.432

0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.29

0.34 0.34 0.34 0.34 0.34 0.34 0.34 0.34

0.31 0.31 0.31 0.31 0.31 0.31 0.3 0.3

0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.3375

0.2525 0.2525 0.2525 0.245 0.245 0.245 0.245 0.245


Ticker Company


ALE ALLETE

LNT Alliant Energy


AEE Ameren Corp.

AVA Avista Corp.

BKH Black Hills



CHG CH Energy Group

CNL Cleco Corp.


ED Consol. Edison



DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EIX Edison Int'l

EE El Paso Electric


ETR Entergy Corp.

EXC Exelon Corp.



HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

ITC ITC Holdings

MGEE MGE Energy

NEE NextEra Energy


NST NSTAR

NVE NV Energy Inc.

OGE OGE Energy


POM Pepco Holdings

PCG PG&E Corp.


PNM PNM Resources


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

SO Southern Co.

TE TECO Energy

UIL UIL Holdings


VVC Vectren Corp.

WR Westar Energy





20 19 18 17 16 15 14 13

12/31/2009 11/30/2009 10/31/2009 9/30/2009 8/31/2009 7/31/2009 6/30/2009 5/31/2009

0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15

0.44 0.44 0.44 0.44 0.44 0.44 0.44 0.44

0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375

0.41 0.41 0.41 0.41 0.41 0.41 0.41 0.41

0.385 0.385 0.385 0.385 0.385 0.385 0.385 0.385

0.21 0.21 0.21 0.21 0.21 0.21 0.21 0.21

0.355 0.355 0.355 0.355 0.355 0.355 0.355 0.355

0.23 0.23 0.23 0.23 0.23 0.23 0.23 0.23

0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19

0.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54

0.225 0.225 0.225 0.225 0.225 0.225 0.225 0.225

0.125 0.125 0.125 0.125 0.125 0.125 0.125 0.125

0.59 0.59 0.59 0.59 0.59 0.59 0.59 0.59

0.24 0.24 0.24 0.24 0.24 0.24 0.24 0.24

0.4375 0.4375 0.4375 0.4375 0.4375 0.4375 0.4375 0.4375

0.285 0.285 0.285 0.285 0.285 0.285 0.285 0.285

0.53 0.53 0.53 0.53 0.53 0.53 0.53 0.53

0.24 0.24 0.24 0.24 0.24 0.23 0.23 0.23

0.315 0.31 0.31 0.31 0.31 0.31 0.31 0.31

0 0 0 0 0 0 0 0

0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32

0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75

0.525 0.525 0.525 0.525 0.525 0.525 0.525 0.525

0.55 0.55 0.55 0.55 0.55 0.55 0.55 0.55

0.2075 0.2075 0.2075 0.2075 0.2075 0.2075 0.2075 0.2075

0.31 0.31 0.31 0.31 0.31 0.31 0.31 0.31

0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

0.68 0.68 0.68 0.68 0.68 0.68 0.68 0.68

0.32 0.32 0.32 0.32 0.32 0.305 0.305 0.305

0.3684 0.3684 0.3684 0.3684 0.3684 0.3617 0.3617 0.3617

0.4725 0.4725 0.4725 0.4725 0.4725 0.4725 0.4725 0.4725

0.2375 0.2375 0.2375 0.2375 0.2375 0.2375 0.2375 0.2375

0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375

0.11 0.11 0.1 0.1 0.1 0.1 0.1 0.1

0.355 0.355 0.355 0.355 0.355 0.355 0.355 0.355

0.2975 0.2975 0.2975 0.2975 0.2975 0.2975 0.2975 0.2975

0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27

0.42 0.42 0.42 0.42 0.42 0.42 0.42 0.42

0.525 0.525 0.525 0.525 0.525 0.525 0.525 0.525

0.125 0.125 0.125 0.125 0.125 0.125 0.125 0.125

0.255 0.255 0.255 0.255 0.255 0.255 0.255 0.245

0.345 0.345 0.345 0.345 0.345 0.345 0.345 0.345

0.62 0.62 0.62 0.62 0.62 0.62 0.62 0.62

0.3325 0.3325 0.3325 0.3325 0.3325 0.3325 0.3325 0.3325

0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47

0.39 0.39 0.39 0.39 0.39 0.39 0.39 0.39

0.4375 0.4375 0.4375 0.4375 0.4375 0.4375 0.4375 0.4375

0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

0.432 0.432 0.432 0.432 0.432 0.432 0.432 0.432

0.29 0 0.29 0.29 0.29 0.29 0.29 0.29

0.34 0.34 0.335 0.335 0.335 0.335 0.335 0.335

0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

0.3375 0.3375 0.3375 0.3375 0.3375 0.3375 0.3375 0.3375

0.245 0.245 0.245 0.245 0.245 0.245 0.245 0.2375


Ticker Company


ALE ALLETE

LNT Alliant Energy


AEE Ameren Corp.

AVA Avista Corp.

BKH Black Hills



CHG CH Energy Group

CNL Cleco Corp.


ED Consol. Edison



DPL DPL Inc.

DTE DTE Energy

DUK Duke Energy

EIX Edison Int'l

EE El Paso Electric


ETR Entergy Corp.

EXC Exelon Corp.



HE Hawaiian Elec.

IDA IDACORP, Inc.

TEG Integrys Energy

ITC ITC Holdings

MGEE MGE Energy

NEE NextEra Energy


NST NSTAR

NVE NV Energy Inc.

OGE OGE Energy


POM Pepco Holdings

PCG PG&E Corp.


PNM PNM Resources


PPL PPL Corp.

PGN Progress Energy


SCG SCANA Corp.

SRE Sempra Energy

SO Southern Co.

TE TECO Energy

UIL UIL Holdings


VVC Vectren Corp.

WR Westar Energy





12 11 10 9 8 7 6

4/30/2009 3/31/2009 2/28/2009 1/31/2009 12/31/2008 11/30/2008 10/31/2008

0.15 0.15 0.15 0.15 0.15 0.15 0.15

0.44 0.44 0.44 0.43 0.43 0.43 0.43

0.375 0.375 0.375 0.375 0.35 0.35 0.35

0.41 0.41 0.41 0.41 0.41 0.41 0.41

0.385 0.385 0.635 0.635 0.635 0.635 0.635

0.18 0.18 0.18 0.18 0.18 0.18 0.18

0.355 0.355 0.355 0.35 0.35 0.35 0.35

0.23 0.23 0.23 0.23 0.23 0.23 0.23

0.19 0.19 0.19 0.1825 0.1825 0.1825 0.1825

0.54 0.54 0.54 0.54 0.54 0.54 0.54

0.225 0.225 0.225 0.225 0.225 0.225 0.225

0.125 0.125 0.125 0.09 0.09 0.09 0.09

0.59 0.59 0.59 0.585 0.585 0.585 0.585

0.24 0.24 0.4775 0.4775 0.4775 0.4775 0.4775

0.4375 0.4375 0.4375 0.395 0.395 0.395 0.395

0.285 0.285 0.285 0.275 0.275 0.275 0.275

0.53 0.53 0.53 0.53 0.53 0.53 0.53

0.23 0.23 0.23 0.23 0.23 0.23 0.23

0.31 0.31 0.31 0.31 0.31 0.305 0.305

0 0 0 0 0 0 0

0.32 0.32 0.32 0.32 0.32 0.32 0.32

0.75 0.75 0.75 0.75 0.75 0.75 0.75

0.525 0.525 0.525 0.525 0.525 0.525 0.5

0.55 0.55 0.55 0.55 0.55 0.55 0.55

0.2075 0.2075 0.2075 0.415 0.415 0.415 0.415

0.31 0.31 0.31 0.31 0.31 0.31 0.31

0.3 0.3 0.3 0.3 0.3 0.3 0.3

0.68 0.68 0.68 0.67 0.67 0.67 0.67

0.305 0.305 0.305 0.305 0.305 0.305 0.305

0.3617 0.3617 0.3617 0.3617 0.3617 0.3617 0.3617

0.4725 0.4725 0.4725 0.445 0.445 0.445 0.445

0.2375 0.2375 0.2375 0.2125 0.2125 0.2125 0.2125

0.375 0.375 0.375 0.375 0.35 0.35 0.35

0.1 0.1 0.1 0.1 0.1 0.1 0.08

0.355 0.355 0.355 0.355 0.3475 0.3475 0.3475

0.2975 0.2975 0.2975 0.2975 0.2975 0.2975 0.2975

0.27 0.27 0.27 0.27 0.27 0.27 0.27

0.42 0.42 0.39 0.39 0.39 0.39 0.39

0.525 0.525 0.525 0.525 0.525 0.525 0.525

0.125 0.125 0.125 0.125 0.125 0.125 0.125

0.245 0.245 0.245 0.245 0.245 0.245 0.245

0.345 0.345 0.335 0.335 0.335 0.335 0.335

0.62 0.62 0.62 0.62 0.615 0.615 0.615

0.3325 0.3325 0.3225 0.3225 0.3225 0.3225 0.3225

0.47 0.47 0.46 0.46 0.46 0.46 0.46

0.39 0.39 0.35 0.35 0.35 0.35 0.35

0.4375 0.42 0.42 0.42 0.42 0.42 0.42

0.2 0.2 0.2 0.2 0.2 0.2 0.2

0.432 0.432 0.432 0.432 0.432 0.432 0.432

0.29 0.29 0.29 0.24 0.24 0 0.24

0.335 0.335 0.335 0.335 0.335 0.335 0.325

0.3 0.3 0.29 0.29 0.29 0.29 0.29

0.3375 0.3375 0.3375 0.27 0.27 0.27 0.27

0.2375 0.2375 0.2375 0.2375 0.2375 0.2375 0.2375


Moody's Long-Term Utility Bond Yields

Month Aa Rate (%) Month A Rate (%)

October 2008 6.95 October 2008 7.56

November 2008 6.83 November 2008 7.6

December 2008 5.92 December 2008 6.52

January 2009 6.01 January 2009 6.39

February 2009 6.11 February 2009 6.3

March 2009 6.14 March 2009 6.42

April 2009 6.2 April 2009 6.48

May 2009 6.23 May 2009 6.49

June 2009 6.13 June 2009 6.2

July 2009 5.63 July 2009 5.97

August 2009 5.33 August 2009 5.71

September 2009 5.15 September 2009 5.53

October 2009 5.23 October 2009 5.55

November 2009 5.32 November 2009 5.63

December 2009 5.52 December 2009 5.79

January 2010 5.55 January 2010 5.77

February 2010 5.69 February 2010 5.87

March 2010 5.64 March 2010 5.84

April 2010 5.62 April 2010 5.81

May 2010 5.29 May 2010 5.5

June 2010 5.22 June 2010 5.46

July 2010 4.99 July 2010 5.26

August 2010 4.75 August 2010 5.01

September 2010 4.74 September 2010 5.01

6-Month Historical Period

Average 5.10% 5.34%

Threshold Rate 6.10% 6.34%


Month Baa Rate (%)

October 2008 8.58

November 2008 8.98

December 2008 8.11

January 2009 7.9

February 2009 7.74

March 2009 8

April 2009 8.03

May 2009 7.76

June 2009 7.3

July 2009 6.87

August 2009 6.36

September 2009 6.12

October 2009 6.14

November 2009 6.17

December 2009 6.26

January 2010 6.16

February 2010 6.25

March 2010 6.22

April 2010 6.19

May 2010 5.97

June 2010 6.18

July 2010 5.98

August 2010 5.55

September 2010 5.53

5.90%

6.90%


Merger

Ticker Company NameM&A Activity

Beginning Date

Ending Date Comments

AYE Allegheny Energy TRUE 2/11/2010 12/31/2099First Energy and Allegheny Energy announced a merger February 11, 2010. AYE shareholders will receive 0.667 FE shares for one AYE share.

ALE ALLETE FALSE 1/1/1900 1/1/1900LNT Alliant Energy FALSE 1/1/1900 1/1/1900AEP Amer. Elec. Power FALSE 1/1/1900 1/1/1900AEE Ameren Corp. FALSE 1/1/1900 1/1/1900AVA Avista Corp. FALSE 1/1/1900 1/1/1900BKH Black Hills FALSE 1/1/1900 1/1/1900CV Cen. Vermont Pub. Serv. FALSE 1/1/1900 1/1/1900CNP CenterPoint Energy FALSE 1/1/1900 1/1/1900CHG CH Energy Group FALSE 1/1/1900 1/1/1900CNL Cleco Corp. FALSE 1/1/1900 1/1/1900CMS CMS Energy Corp. FALSE 1/1/1900 1/1/1900ED Consol. Edison FALSE 1/1/1900 1/1/1900

CEG Constellation Energy TRUE 8/7/2010 12/31/2099

On August 7, 2010, Constellation Energy announced the potential purchase of natural gas-fired plants in New England for approximately $1.1 billion. At June 30, 2010, Constellation's assets were approximately $21.7 billion, so the acquisition is approximately 5.1% of CEG assets.

CEG1 Constellation Energy TRUE 9/18/2008 11/6/2009

Mid-American Energy Holdings acquisition of Constellation Energy announced September 18, 2008. That agreement terminated upon acceptance of a competing agreement with EDF. The EDF agreement included a sale of a 49.99% share of Constellation's nuclear assets to EDF. That sale closed on or about November 6, 2009.

CEG2 Constellation Energy TRUE 8/7/2010 12/31/2099

On August 7, 2010, Constellation Energy announced the potential purchase of natural gas-fired plants in New England for approximately $1.1 billion. At June 30, 2010, Constellation's assets were approximately $21.7 billion, so the acquisition is approximately 5.1% of CEG assets.

D Dominion Resources FALSE 1/1/1900 1/1/1900DPL DPL Inc. FALSE 1/1/1900 1/1/1900DTE DTE Energy FALSE 1/1/1900 1/1/1900DUK Duke Energy FALSE 1/1/1900 1/1/1900EIX Edison Int'l FALSE 1/1/1900 1/1/1900EE El Paso Electric FALSE 1/1/1900 1/1/1900EDE Empire Dist. Elec. FALSE 1/1/1900 1/1/1900

ETR Entergy Corp. TRUE 8/7/2008 4/5/2010

Spinoff of nuclear units targeted for 2008 Q4 (ETR 10-Q, 8/7/2008). Existing shareholders receive all shares in spinoff. Value Line suspended projecting ETR data after Hurricane Ike (Value Line 9/26/2008 sheet for ETR.) ETR announced unwinding of spinoff on April 5, 2010.

EXC Exelon Corp. TRUE 10/20/2008 7/22/2009 Exelon made offer for NRG on October 20, 2008; withdrew offer on July 22, 2009.

FE FirstEnergy Corp. TRUE 2/11/2010 12/31/2099First Energy and Allegheny Energy announced a merger February 11, 2010. AYE shareholders will receive 0.667 FE shares for one AYE share.

FPL FPL Group FALSE 1/1/1900 1/1/1900GXP G't Plains Energy TRUE 2/1/2007 7/31/2008 Great Plains Energy acquired Aquila, Inc. in July 2008. Transaction was announced in February 2007.HE Hawaiian Elec. FALSE 1/1/1900 1/1/1900IDA IDACORP, Inc. FALSE 1/1/1900 1/1/1900

TEG Integrys Energy TRUE 12/23/2009 3/31/2010

Purchase and sale agreement with Macquarie Cook Power to sell commodity contracts comprising wholesale electric marketing and trading business. Assets involved in sale are approximately $1.85 billion, about 15 percent of Integrys Energy's assets. The sale closed on March 31, 2010.

ITC ITC Holdings FALSE 1/1/1900 1/1/1900MGEE MGE Energy FALSE 1/1/1900 1/1/1900NEE NextEra Energy FALSE 1/1/1900 1/1/1900NU Northeast Utilities FALSE 1/1/1900 1/1/1900NST NSTAR FALSE 1/1/1900 1/1/1900NVE NV Energy Inc. FALSE 1/1/1900 1/1/1900OGE OGE Energy FALSE 1/1/1900 1/1/1900OTTR Otter Tail Corp. FALSE 1/1/1900 1/1/1900

POM Pepco Holdings TRUE 4/20/2010 7/1/2010 Pepco Holdings announced sale of Conectiv generating assets to Calpine, April 20, 2010. The sale was completed on July 1, 2010.PCG PG&E Corp. FALSE 1/1/1900 1/1/1900PNW Pinnacle West Capital FALSE 1/1/1900 1/1/1900PNM PNM Resources FALSE 1/1/1900 1/1/1900POR Portland General FALSE 1/1/1900 1/1/1900

PPL PPL Corp. TRUE 4/29/2010 10/31/2010PPL announced purchase of E.ON-US utility assets in Kentucky on April 29, 2010. On September 16, 2010, PPL announced that it anticipated closing the transaction by October 31, 2010.

PGN Progress Energy FALSE 1/1/1900 1/1/1900PEG Public Serv. Enterprise FALSE 1/1/1900 1/1/1900SCG SCANA Corp. FALSE 1/1/1900 1/1/1900SRE Sempra Energy FALSE 1/1/1900 1/1/1900 Acquisition of EnergySouth announced 7/28/2008. ENSI assets are approximately 2.9% of SRE assets.SO Southern Co. FALSE 1/1/1900 1/1/1900TE TECO Energy FALSE 1/1/1900 1/1/1900

UIL UIL Holdings TRUE 5/25/2010 12/31/2099UIL Holdings entered into a purchase agreement to acquire Connecticut Energy Corporation, Connecticut Natural Gas Corporation and The Berkshire Gas Company from Iberdrola USA, Inc. for $1.3 billion on May 25, 2010.

UNS UniSource Energy FALSE 1/1/1900 1/1/1900VVC Vectren Corp. FALSE 1/1/1900 1/1/1900WR Westar Energy FALSE 1/1/1900 1/1/1900WEC Wisconsin Energy FALSE 1/1/1900 1/1/1900XEL Xcel Energy Inc. FALSE 1/1/1900 1/1/1900AGL AGL Resources FALSE 1/1/1900 1/1/1900ATO Atmos Energy FALSE 1/1/1900 1/1/1900LG Laclede Group FALSE 1/1/1900 1/1/1900NJR New Jersey Resources FALSE 1/1/1900 1/1/1900GAS Nicor Inc. FALSE 1/1/1900 1/1/1900NI NiSource Inc. FALSE 1/1/1900 1/1/1900NWN Northwest Nat. Gas FALSE 1/1/1900 1/1/1900PNY Piedmont Natural Gas FALSE 1/1/1900 1/1/1900SJI South Jersey Inds. FALSE 1/1/1900 1/1/1900SWX Southwest Gas FALSE 1/1/1900 1/1/1900UGI UGI Corp. FALSE 1/1/1900 1/1/1900WGL WGL Holdings Inc. FALSE 1/1/1900 1/1/1900ALSK Alaska Communic. FALSE 1/1/1900 1/1/1900BCE BCE Inc. FALSE 1/1/1900 1/1/1900BT BT Group ADR FALSE 1/1/1900 1/1/1900CTL CenturyLink Inc. FALSE 1/1/1900 1/1/1900CBB Cincinnati Bell FALSE 1/1/1900 1/1/1900CNSL Consol. Communic. FALSE 1/1/1900 1/1/1900FTR Frontier Communic. FALSE 1/1/1900 1/1/1900TEF Telefonica SA ADR FALSE 1/1/1900 1/1/1900TMX Telefonos de Mexico ADR FALSE 1/1/1900 1/1/1900TWTC tw telecom FALSE 1/1/1900 1/1/1900WIN Windstream Corp. FALSE 1/1/1900 1/1/1900AWR Amer. States Water FALSE 1/1/1900 1/1/1900AWK Amer. Water Works FALSE 1/1/1900 1/1/1900WTR Aqua America FALSE 1/1/1900 1/1/1900CWT California Water FALSE 1 1SWWC Southwest Water FALSE 1 1



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

EXCERPTS FROM DOMINION RESOURCES

FORM 10-Q FILINGS

(EXHIBIT SCE-60)

OCTOBER 2010

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Table of Contents

UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10−Q

(Mark one)⌧ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF

1934

For the quarterly period ended March 31, 2010

or

� TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934

For the transition period from to

Commission FileNumber

Exact name of registrants as specified in their charters, address ofprincipal executive offices and registrants’ telephone number

I.R.S. EmployerIdentification Number

001−08489 DOMINION RESOURCES, INC. 54−1229715001−02255 VIRGINIA ELECTRIC AND POWER COMPANY 54−0418825

120 Tredegar StreetRichmond, Virginia 23219

(804) 819−2000

State or other jurisdiction of incorporation or organization of the Companies: Virginia

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.

Dominion Resources, Inc. Yes ⌧ No � Virginia Electric and Power Company Yes ⌧ No �

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File requiredto be submitted and posted pursuant to Rule 405 of Regulation S−T (§232.405 of this chapter) during the preceding 12 months (or for such shorter periodthat the registrant was required to submit and post such files).

Dominion Resources, Inc. Yes ⌧ No � Virginia Electric and Power Company Yes � No �

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non−accelerated filer or a smaller reporting company. Seethe definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b−2 of the Exchange Act.

Dominion Resources, Inc.Large accelerated filer ⌧ Accelerated filer �Non−accelerated filer � (Do not check if a smaller reporting company) Smaller reporting company �

Virginia Electric and Power CompanyLarge accelerated filer � Accelerated filer �Non−accelerated filer ⌧ (Do not check if a smaller reporting company) Smaller reporting company �

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b−2 of the Exchange Act).

Dominion Resources, Inc. Yes � No ⌧ Virginia Electric and Power Company Yes � No ⌧

At March 31, 2010, the latest practicable date for determination, Dominion had 596,053,590 shares of common stock outstanding and Virginia Power had256,310 shares of common stock outstanding. Dominion is the sole holder of Virginia Electric and Power Company’s common stock.

This combined Form 10−Q represents separate filings by Dominion Resources, Inc. and Virginia Electric and Power Company. Information containedherein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Power makes no representations as to the information relatingto Dominion’s other operations.


Table of ContentsDOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS(Unaudited)

(millions)March 31,

2010

December

31,2009(1)

ASSETSCurrent AssetsCash and cash equivalents $ 85 $ 48Customer receivables (less allowance for doubtful accounts of $31 at both dates) 1,955 2,050Other receivables (less allowance for doubtful accounts of $14 at both dates) 105 130Inventories 984 1,185Derivative assets 1,638 1,128Assets held for sale — 1,018Prepayments 147 405Other 1,119 853

Total current assets 6,033 6,817

InvestmentsNuclear decommissioning trust funds 2,735 2,625Investment in equity method affiliates 601 595Other 276 272

Total investments 3,612 3,492

Property, Plant and EquipmentProperty, plant and equipment 39,729 39,036Accumulated depreciation, depletion and amortization (13,691) (13,444)

Total property, plant and equipment, net 26,038 25,592

Deferred Charges and Other AssetsGoodwill 3,275 3,354Regulatory assets 1,240 1,390Other 1,965 1,909

Total deferred charges and other assets 6,480 6,653

Total assets $ 42,163 $ 42,554

(1) Dominion’s Consolidated Balance Sheet at December 31, 2009 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 6


Table of ContentsThe results of operations for Dominion’s Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Incomesince Dominion did not sell its entire U.S. cost pool, which includes the retained Appalachian assets located on or near its natural gas storage fields.

Due to the announced sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of gas wouldnot occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after−tax)benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for thesecontracts in the three months ended March 31, 2010.

Sale of Peoples

In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after−tax proceeds of approximately $542 million. The saleresulted in an after−tax loss of approximately $134 million, which included a $79 million write−off of goodwill. The sale also resulted in after−tax expensesof approximately $27 million, including transaction and benefit−related costs. In addition, Peoples had income from operations of $12 million after−tax forthe three months ended March 31, 2010.

Dominion did not previously report Peoples as discontinued operations since it expected to have significant continuing cash flows related primarily to thesale to Peoples of natural gas production from its Appalachian E&P business. Due to the pending sale of its Appalachian E&P business, Dominion no longerexpects to have significant continuing cash flows with Peoples; therefore, the results of Peoples were reclassified to discontinued operations in theConsolidated Statements of Income for all periods presented.

The carrying amounts of the major classes of assets and liabilities classified as held for sale in Dominion’s Consolidated Balance Sheet were as follows:

December 31,2009

(millions)ASSETSCurrent AssetsCustomer receivables $ 87Other 56

Total current assets 143

Property, Plant and EquipmentProperty, plant and equipment 985Accumulated depreciation, depletion and amortization (284)

Total property, plant and equipment, net 701

Deferred Charges and Other AssetsRegulatory assets 125Other 49

Total deferred charges and other assets 174

Assets held for sale $ 1,018

LIABILITIESCurrent Liabilities $ 133Deferred Credits and Other LiabilitiesDeferred income taxes and investment tax credits 238Other 57

Total deferred credits and other liabilities 295

Liabilities held for sale $ 428

PAGE 14





)))

Dkt. No.

ER09-1534-001

EXCERPTS FROM PPL CORPORATION FORM 8-

K FILINGS

(EXHIBIT SCE-61)

OCTOBER 2010

Exhibit 99.1

PPL Corporation to acquire Kentucky’s two major utilities Transaction expands footprint and improves business mix

ALLENTOWN, Pa. ( April 28, 2010) -- PPL Corporation (NYSE: PPL) and E.ON AG today announced a definitive

agreement under which PPL will acquire E.ON U.S. LLC, the parent company of Kentucky’s two major utilities, Louisville Gas & Electric Company and Kentucky Utilities Company. These high-performing utilities serve 1.2 million customers, principally in Kentucky.

PPL is acquiring E.ON U.S. for $7.625 billion and will receive tax benefits with a present value of about $450 million as part of the transaction. Taking into account the tax benefits, the effective purchase price is $7.175 billion.

The acquisition will transform PPL into a more geographically diverse utility holding company with combined annual revenues of about $10 billion, serving nearly 5 million electricity customers in the United States and the United Kingdom, and owning or controlling about 20,000 megawatts of U.S. electricity generating capacity.

“This is a transformational, value-rich transaction, which will immediately improve PPL’s business mix by adding high-performing regulated utility operations to our already strong combination of excellent regulated businesses and our high-value competitive generation fleet,” said James H. Miller, PPL’s chairman, president and chief executive officer.

“We are adding scale, creating a much stronger and more diversified enterprise while providing additional opportunities for regulated-business growth and, importantly, retaining the upside benefits of our competitive fleet when wholesale power market prices improve,” said Miller. “Clearly, for PPL shareowners, this is the right deal at the right time.”

The transaction, Miller said, takes advantage of “a rare opportunity to add to PPL the experience, talent and values of an organization with a proven track record of cost-effective operations, a strong focus on customer service and constructive regulatory relationships.”

Miller said PPL intends to operate the company as a wholly owned subsidiary of PPL Corporation, retaining the headquarters in Louisville, as has been the case with E.ON AG ownership. Customers will continue to be served by LG&E and KU, with operational headquarters in Louisville and Lexington, respectively.

“We are very pleased to join the excellent management team and employees of PPL, who operate one of the most effective and customer-friendly utilities in the United States and the U.K.,” said Vic Staffieri, chairman, chief executive officer and president of E.ON U.S.

PPL, Miller said, is committed to providing the highest quality service to Kentucky customers and does not anticipate any change in Kentucky employment levels as a result of this transaction.

PPL will pay for the transaction with $6.7 billion of cash and through the assumption of $925 million of tax-exempt debt. PPL has committed bridge financing in place from Bank of America Merrill Lynch and Credit Suisse. Miller said the permanent financing plan will include a combination of common equity, first mortgage bonds, corporate debt, high-equity-content securities and cash on hand. Proceeds from the sale of PPL non-core assets may be explored as a potential to fund a portion of the transaction.

Miller said the transaction is anticipated to be modestly dilutive in the first full year and accretive to earnings by 2013.

“Adding the proven operations of LG&E and KU in the constructive Kentucky regulatory framework will enhance the overall business risk profile of PPL, which we believe will lead to improved access to capital, a stronger credit profile and solid, investment-grade credit ratings in each of our businesses,” said Miller.

Miller also said that the company expects to announce next week (May 6) reported earnings of $0.66 per share for the first quarter of 2010 compared with $0.64 per share for the first quarter of 2009, and earnings from ongoing operations of $0.94 per share for the first quarter of 2010 compared with $0.60 per share for the first quarter of 2009.

At that time, he said, the company also will reaffirm its 2010 forecast of earnings from ongoing operations of $3.10 to $3.50 per share and for reported earnings of $2.82 to $3.22 per share (reflecting special items recorded through March 31, 2010). These forecasts do not reflect any impact of this transaction or the related financings.

The transaction is expected to close by the end of this year. It requires approvals by state regulators in Kentucky, Virginia and Tennessee and by the Federal Energy Regulatory Commission as well as the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. No shareowner approvals are necessary for the transaction. Credit Suisse and Bank of America Merrill Lynch served as PPL’s financial advisers. Simpson Thacher & Bartlett, LLP, served as legal adviser.

E.ON U.S., through LG&E and KU, provides electricity service to 941,000 customers, mostly in the state of Kentucky, with some customers in Virginia and Tennessee. LG&E also provides natural gas delivery service to 321,000 customers in Kentucky. E.ON U.S. has about 3,100 employees and owns and operates about 8,000 megawatts of regulated electric generation capacity.

Contact: Media Contacts: PPL: Daniel J. McCarthy, 610-774-5758 Investor Contacts: PPL: Joseph P. Bergstein, 610-774-5609

Page 2 of 6PPL CORP - 8-K - 20100429 - EXHIBIT_99

10/12/2010http://yahoo.brand.edgar-online.com/EFX_dll/EDGARpro.dll?FetchFilingHtmlSection1?...


PPL Corporation, headquartered in Allentown, Pa., owns or controls nearly 12,000 megawatts of generating capacity in the United States, sells energy in key U.S. markets and delivers electricity to about 4 million customers in Pennsylvania and the United Kingdom. The company has about 10,000 employees. See the electronic version of this news release at www.pplweb.com for a fact sheet for the combined companies.

# # #




PPL CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL INFORMATION (a)

Condensed Consolidated Balance Sheet (Unaudited) (Millions of Dollars)

March 31, December 31, 2010 2009 Assets Cash and cash equivalents $ 1,724 $ 801 Price risk management assets - current 3,348 2,157 Assets held for sale 127 Other current assets 2,149 1,667 Investments 638 613 Property, plant and equipment Electric plant 21,089 21,151 Gas and oil plant 68 68 Other property 157 166 Property, plant and equipment, gross 21,314 21,385 Less: accumulated depreciation 8,256 8,211 Property, plant and equipment, net 13,058 13,174 Regulatory assets 529 531 Goodwill and other intangibles 1,362 1,421 Price risk management assets - noncurrent 1,713 1,274 Other noncurrent assets 414 400 Total assets $ 24,935 $ 22,165 Liabilities and Equity Short-term debt (including current portion of long-term debt) $ 589 $ 639 Price risk management liabilities - current 2,391 1,502 Other current liabilities 2,812 2,041 Long-term debt (less current portion) 7,652 7,143 Deferred income taxes and investment tax credits 2,313 2,153 Price risk management liabilities - noncurrent 853 582 Accrued pension obligations 1,104 1,283 Other noncurrent liabilities 1,010 1,007 Common stock and capital in excess of par value 2,314 2,284 Earnings reinvested 3,866 3,749 Accumulated other comprehensive loss (288 ) (537 ) Noncontrolling interests 319 319 Total liabilities and equity $ 24,935 $ 22,165

(a) The Financial Statements in this news release have been condensed and summarized for purposes of this presentation. Please refer to PPL Corporation's periodic filings with the Securities and Exchange Commission for full financial statements, including note disclosure.





BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

EXCERPTS FROM INTEGRYS ENERGY

FORM 10-K FILING

(EXHIBIT SCE-62)

OCTOBER 2010

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the fiscal year ended December 31, 2009

OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________ Commission File Number

Registrant; State of Incorporation; Address; and Telephone Number

IRS Employer Identification No.

1-11337 INTEGRYS ENERGY GROUP, INC.

(A Wisconsin Corporation) 130 East Randolph Drive

Chicago, IL 60601 (312) 228-5400

39-1775292

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Name of each exchange on which registered

Common Stock, $1 par value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes [X] No [ ] Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes [ ] No [X] Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]


ITEM 6. SELECTED FINANCIAL DATA

As of or for Year Ended December 31

(Millions, except per share amounts, stock price, return on average equity

and number of shareholders and employees) 2009 2008 2007 (1) 2006 (2) 2005

Total revenues $7,499.8 $14,047.8 $10,292.4 $6,890.7 $6,825.5

Net income (loss) from continuing operations (71.6) 124.7 181.0 147.8 146.1

Net income (loss) attributed to common shareholders (70.9) 126.4 251.3 155.8 157.4

Total assets 11,847.9 14,272.5 11,234.4 6,861.7 5,462.5

Preferred stock of subsidiary 51.1 51.1 51.1 51.1 51.1

Long-term debt (excluding current portion) 2,394.7 2,285.7 2,265.1 1,287.2 867.1

Shares of common stock (less treasury stock and shares in deferred

compensation trust)

Outstanding 76.0 76.0 76.0 43.1 39.8

Average 76.8 76.7 71.6 42.3 38.3

Earnings (loss) per common share (basic)

Net income (loss) from continuing operations ($0.96) $1.59 $2.49 $3.51 $3.85

Earnings (loss) per common share (0.92) 1.65 3.51 3.68 4.11

Earnings (loss) per common share (diluted)

Net income (loss) from continuing operations (0.96) 1.58 2.48 3.50 3.81

Earnings (loss) per common share (0.92) 1.64 3.50 3.67 4.07

Dividends per common share declared 2.72 2.68 2.56 2.28 2.24

Stock price at year-end $41.99 $42.98 $51.69 $54.03 $55.31

Book value per share $37.62 $40.78 $42.58 $35.61 $32.76

Return on average equity (2.5)% 3.7% 8.5% 10.6% 13.6%

Number of common stock shareholders 32,755 34,016 35,212 19,837 20,701

Number of employees 5,025 5,191 5,231 3,326 2,945

(1) Includes the impact of the PEC merger on February 21, 2007.(2) Includes the impact of the acquisition of natural gas distribution operations from Aquila by MGU on April 1, 2006 and MERC on July 1, 2006.

INTEGRYS ENERGY GROUP, INC.COMPARATIVE FINANCIAL DATA AND

OTHER STATISTICS (2005 TO 2009)

-28-


-95-

(Millions) 2009 Employee-related costs $10.1 Legal and consulting 9.2 Software write-offs and accelerated depreciation 5.9 Miscellaneous 0.3 Total restructuring expense $25.5

All of the above costs were related to the Integrys Energy Services segment and were included in the restructuring expense line item on the Consolidated Statements of Income. The following table summarizes the activity related to employee-related restructuring expense: (Millions) 2009 Accrued employee-related costs at beginning of period $ - Employee-related costs expensed 10.1 Cash payments 1.9 Accrued employee-related costs at end of period $ 8.2

Integrys Energy Group expects to incur total employee-related restructuring expense of approximately $12 million related to the Integrys Energy Services strategy change by the end of 2010, including the $10.1 million expensed as of December 31, 2009. NOTE 4--DISPOSITIONS Integrys Energy Services Strategy Change As part of Integrys Energy Group's decision to significantly reduce the size of its nonregulated energy services business segment with significantly reduced credit and collateral support requirements, it entered into the following sale agreements during 2009. Proposed Sale of United States Wholesale Electric Marketing and Trading Business In December 2009, Integrys Energy Services entered into a definitive agreement to sell substantially all of its United States wholesale electric marketing and trading business. The closing of this sale is contingent upon obtaining certain customary contractual consents and necessary regulatory approvals. Effective February 1, 2010, Integrys Energy Services transferred substantially all of the market risk associated with this business by entering into trades with the buyer that mirror Integrys Energy Services' underlying wholesale electric contracts. Integrys Energy Services expects to transfer title to the underlying contracts and close the transaction by the end of the second quarter of 2010, at which time these mirror transactions will terminate. The carrying values of the major classes of assets and liabilities included in the sale agreement were as follows at December 31, 2009: (Millions) Current assets from risk management activities $1,219.7 Long-term assets from risk management activities 629.4 Total assets $1,849.1

Current liabilities from risk management activities $1,229.8 Long-term liabilities from risk management activities 602.2 Total liabilities $1,832.0



BEFORE THE



)

)

)

Dkt. No.

ER09-1534-001

EXCERPTS FROM PEPCO HOLDINGS

FORM 8-K AND 10-Q FILINGS

(EXHIBIT SCE-63)

OCTOBER 2010

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION


FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): April 20, 2010

PEPCO HOLDINGS, INC. (Exact name of registrant as specified in its charter)

Delaware 001-31403 52-2297449 (State or other jurisdiction

of incorporation) (Commission

File Number) (IRS Employer

Identification No.)

701 Ninth Street, N.W., Washington, DC 20068 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (202) 872-3526

Not Applicable

(Former name or former address, if changed since last report.) Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

� Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

� Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

� Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

� Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))


Pepco Holdings, Inc. Form 8-K

2

Item 1.01 Entry into a Material Definitive Agreement. Sale of Conectiv Wholesale Power Generation Business On April 20, 2010, Pepco Holdings, Inc. (“PHI”) entered into an agreement to sell its Conectiv Energy wholesale power generation assets to New Development Holding, LLC (the “Purchaser”), a wholly owned subsidiary of Calpine Corporation (“Calpine Corporation”). Under the terms of the purchase agreement (the “Purchase Agreement”), the Purchaser will purchase Conectiv Energy Holding Company (“CEHC”), an indirect wholly owned subsidiary of PHI, for a purchase price of $1.65 billion, plus the market value of the fuel oil inventory at closing, and subject to adjustments for (i) the level of working capital and non-fuel oil inventory at closing and (ii) actual capital expenditures relative to budgeted capital expenditures through the closing date. All of CEHC’s generation facilities and assets, which have an aggregate generating capacity of 3,860 megawatts, are included in the sale. The assets are located in the eastern PJM region and consist of:

� the Deepwater steam plant in New Jersey, with a generating capacity of 158 megawatts;

� the Edge Moor steam plant in Delaware, with a generating capacity of 710 megawatts;

� 2 combined cycle plants, one in each of Pennsylvania and Delaware, which have aggregate generating capacity of 2,260 megawatts;

� 30 peaking units – 20 combustion turbines and 10 diesels, located in Delaware (5), New Jersey (14),

Virginia (7) and Maryland (4), which have an aggregate generating capacity of 728 megawatts; and

� the 4 megawatt Vineland, New Jersey solar photovoltaic facility. CEHC also is constructing a 565 megawatt combined cycle generating plant located in southern Pennsylvania referred to as the Delta Project. Both the Delta Project and the six-year tolling agreement associated with the Delta Project are included in the sale. The sale does not include the balance of PHI’s Conectiv Energy segment, which includes Conectiv Energy’s load service supply contracts, energy hedging portfolio, certain tolling agreements, and other non-core assets. PHI’s Board of Directors has approved a plan to liquidate these contracts and other assets within the next 12 months. The estimated after-tax proceeds of the sale of the Conectiv Energy wholesale power generation assets and the liquidation of the other assets and contracts, combined with the return of collateral posted under the contracts, are expected to be approximately $1.75 billion. PHI expects to use the proceeds primarily to retire its existing debt. Taxes on the sale and liquidation of the assets are currently estimated to be approximately $300 million. Completion of the transaction will require the approval of the Federal Energy Regulatory Commission and satisfaction of the requirements of the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Each party’s obligation to complete the sale also is contingent on other customary closing conditions, including the material accuracy of the other party’s representations and warranties and the compliance by the other party with its covenants. The obligation of the Purchaser to complete the purchase also is contingent on no event, condition or developments occurring after the date of the Purchase


UNITED STATES SECURITIES AND EXCHANGE COMMISSION


FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2010

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Commission File Number

Name of Registrant, State of Incorporation,

Address of Principal Executive Offices, and Telephone Number

I.R.S. Employer

Identification

Number

001-31403

PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000

52-2297449

001-01072

POTOMAC ELECTRIC POWER COMPANY(Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000

53-0127880

001-01405

DELMARVA POWER & LIGHT COMPANY(DPL), a Delaware and Virginia corporation 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000

51-0084283

001-03559

ATLANTIC CITY ELECTRIC COMPANY(ACE), a New Jersey corporation 800 King Street, P.O. Box 231 Wilmington, Delaware 19899 Telephone: (202)872-2000

21-0398280

Pepco Holdings Yes � No � Pepco Yes � No �

DPL Yes � No � ACE Yes � No �

Pepco Holdings Yes � No � Pepco Yes � No �

DPL Yes � No � ACE Yes � No �


PEPCO HOLDINGS

PEPCO HOLDINGS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

(Unaudited)

The accompanying Notes are an integral part of these Consolidated Financial Statements.

4

March 31,

2010

December 31,

2009 (millions of dollars)

ASSETS

CURRENT ASSETS

Cash and cash equivalents $ 38 $ 46 Restricted cash equivalents 10 11Accounts receivable, less allowance for uncollectible accounts of $47 million and $45 million,

respectively 1,205 1,213Inventories 226 252Derivative assets 70 43Prepayments of income taxes 163 167Deferred income tax assets, net 110 126 Prepaid expenses and other 52 68

Total Current Assets 1,874 1,926

INVESTMENTS AND OTHER ASSETS

Goodwill 1,407 1,407Regulatory assets 1,792 1,801Investment in finance leases held in trust 1,382 1,386Income taxes receivable 135 141Restricted cash equivalents 3 4Assets and accrued interest related to uncertain tax positions 12 12 Derivative assets 64 43Other 198 196

Total Investments and Other Assets 4,993 4,990

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment 13,883 13,717Accumulated depreciation (4,918) (4,854)

Net Property, Plant and Equipment 8,965 8,863

TOTAL ASSETS $15,832 $ 15,779


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...))) Dkt. No. ER09-1534-001 SUMMARY OF THE PREPARED REBUTTAL TESTIMONY OF DR. PAUL T. HUNT...

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