PREPARED REBUTTAL TESTIMONY OF DAVID S. BAKER ON … · PREPARED REBUTTAL TESTIMONY OF DAVID S....

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Southern California Edison Company

)))

Dkt. No.

ER09-1534-001

PREPARED REBUTTAL TESTIMONY OF

DAVID S. BAKER ON BEHALF OF

SOUTHERN CALIFORNIA EDISON COMPANY

(EXHIBIT SCE-36)

OCTOBER 2010




)))

Dkt. No.

ER09-1534-001

SUMMARY OF THE PREPARED REBUTTAL TESTIMONY OF

DAVID S. BAKER (EXHIBIT SCE-36)

In his testimony, Mr. Baker addresses the adjustments to SCE’s Period II

Operation and Maintenance (“O&M”) expenses proposed by: FERC Staff

witnesses Mr. Craig Deters, Ms. Kerri Miller, and Ms. Chrystina Steffy; CPUC

witness Mr. Mihai Cosman; SWP witness Mr. David Marcus; Six Cities witness

Mr. Terry Meyers; and M-S-R/LADWP witness Mr. David Cohen. Mr. Baker

shows that SCE actually exceeded its projected 32 percent O&M cost increase for

2009 (SCE’s actual increase in O&M costs in 2009 was 35 percent), and that its

Period II projection of approximately 70 percent of this level of increase is

reasonable and well-supported. (pp. 2-3).

With respect to FERC Staff’s recommendations, Mr. Baker shows that Ms.

Miller’s proposed reduction to SCE’s transmission line expenses should be

rejected. (pp. 4-8). He demonstrates that SCE’s projections were based on the

Federal Government’s published rental rates, and that SCE’s forecasts were

reasonable when made. (pp. 5-6). He also demonstrates that Ms. Miller has failed

to show that the use of these forecasted costs would produce unreasonable results,

as she alleges. (pp. 7-8). Mr. Baker testifies that he agrees with Ms. Steffy’s

testimony regarding transferring certain Tehachapi Renewable Transmission

Project (“TRTP”) costs from Transmission O&M to capital. (pp. 4-5).

Mr. Baker shows that Mr. Marcus’ proposed adjustments to SCE’s O&M

forecast should be rejected. H shows that Mr. Marcus’ adjustment is based solely

on the forecast error in prior forecasts, and that Mr. Marcus fails to demonstrate

that SCE’s forecast in this proceeding is unreasonable in any way. (pp. 9-12).

Mr. Baker shows that Mr. Cosman’s proposed reductions to SCE’s

projections should be rejected. (pp. 12-44). He demonstrates that Mr. Cosman

presents two inconsistent analyses, and that neither analysis has merit. Mr. Baker

shows that Mr. Cosman’s first analysis, in which he addresses twelve individual

O&M accounts, fails to show that SCE’s projections for those accounts were not

reasonable when made. (19-44). Mr. Baker shows that Mr. Cosman’s second

analysis, which forms the basis for his recommendation, and which is unrelated to

Mr. Cosman’s first analysis, is an improper trend-line analysis that fails to

consider the cost drivers that currently are impacting SCE’s O&M costs. (pp. 12-

18).

Mr. Baker testifies that he agrees with Mr. Myers’ and Mr. Cohen’s

proposed transfer of certain TRTP costs from Transmission O&M to capital, as

well as their reduction of SCE’s bulk power training costs. (pp. 44, 50). Mr. Baker

explains why Mr. Cohen’s additional adjustment, which relates to SCE’s projected

cost increase for generation interconnection and contract development, should be

rejected. Mr. Baker explains that SCE is experiencing substantial additional

workload in this area, and that its projected cost increase is reasonable. (pp. 44-

50).



Southern California Edison Company )))

Dkt. No.

ER09-1534-001

TABLE OF CONTENTS OF THE PREPARED REBUTTAL TESTIMONY OF

DAVID S. BAKER (EXHIBIT SCE-36)

I. PURPOSE OF REBUTTAL TESTIMONY................................................. 1

II. OVERVIEW ................................................................................................. 2

III. FERC STAFF’S PROPOSED ADJUSTMENTS......................................... 4

IV. SWP’S PROPOSED ADJUSTMENTS........................................................ 9

V. CPUC’S PROPOSED ADJUSTMENTS.................................................... 12

A. Account 560.100..................................................................................... 19

B. Account 561.200..................................................................................... 23

C. Account 561.500..................................................................................... 24

D. Account 562.200..................................................................................... 27

E. Account 563.100..................................................................................... 28

F. Account 566.200..................................................................................... 29

G. Account 566.500..................................................................................... 30

H. Account 566.700..................................................................................... 35

I. Account 570.400..................................................................................... 36

J. Account 571.100..................................................................................... 38

K. Account 571.200..................................................................................... 40

L. Account 571.300..................................................................................... 41

VI. SIX CITIES’ PROPOSED TRANSMISSION O&M ADJUSTMENTS ... 44

VII. M-S-R/LADWP’S PROPOSED TRANSMISSION O&M ADJUSTMENTS ........................................................................................ 44

Dkt. No. ER09-1534-001 Exhibit SCE-36

Page 1 of 50




)))

Dkt. No.

ER09-1534-001

PREPARED REBUTTAL TESTIMONY OF DAVID S. BAKER ON BEHALF OF

SOUTHERN CALIFORNIA EDISON COMPANY

Q. Please state your name and business address for the record. 1

A. My name is David S. Baker, and my business address is 26100 Menifee 2

Road, Romoland, California, 92380. 3

Q. Have you submitted prior testimony in this proceeding? 4

A. Yes, please see my prior testimony and qualifications in Exhibit SCE-4, 5

submitted July 2009. 6

I. PURPOSE OF REBUTTAL TESTIMONY 7

Q. What is the purpose of your rebuttal testimony in this proceeding? 8

A. The purpose of my testimony is to respond to allegations by FERC Staff 9

witnesses Mr. Craig Deters, Ms. Kerri Miller and Ms. Chrystina Steffy; 10

CPUC witness Mr. Mihai Cosman; SWP witness Mr. David Marcus; Six 11

Cities witness Mr. Terry Myers; and M-S-R/LADWP witness Mr. David 12

Cohen that SCE has over-estimated its transmission operation and 13

maintenance (“O&M”) expenses for Period II. I will show that SCE’s 14


Page 2 of 50

forecasts were reasonable when they were made and are appropriate for use 1

in setting SCE’s rates in this proceeding. 2

II. OVERVIEW 3

Q. As an introductory matter, how did SCE estimate its transmission 4

O&M expenses for 2010 – the estimates which these witnesses now 5

criticize? 6

A. I explained this in considerable detail in my direct testimony, filed in July 7

2009. Briefly, I began with the Company’s 2008 actual transmission O&M 8

expenses, and then made the necessary adjustments to those expenses for 9

ratemaking purposes. Exhibit SCE-4, pp. 2-3. I then increased or 10

decreased the expenses, as appropriate, to reflect anticipated changes in the 11

Company’s O&M costs, in constant 2008 year dollars. I described these 12

adjustments on an account by account basis and provided details in my 13

workpapers for the accounts with the largest cost increases. Exhibit SCE-4, 14

pp. 5-21. Finally, the 2008 estimates were increased to 2010 year dollars 15

based on expected inflation. 16

Q. Do your projections show an increase in SCE’s ISO O&M costs? 17

A. Yes. SCE is facing unprecedented new obligations in the operation and 18

maintenance of its transmission system. As a result, SCE projected 19


Page 3 of 50

substantial increases in its ISO Transmission O&M costs.1 These 1

projections are being borne out. In its filing in this case, SCE projected that 2

its ISO O&M costs would increase by 32 percent from 2008 to 2009, and 3

then increase another 25 percent from 2009 to 2010. These are large 4

percentage increases, by any measure. And, although you would never 5

know it from certain of the intervenors’ testimony in this case, our forecasts 6

have been reliable. Our actual ISO O&M costs rose 35 percent from 2008 7

to 2009, fairly close to our 32 percent estimate. 8

Q. What is causing these large cost increases? 9

A. There has been an increased emphasis on transmission reliability, and SCE 10

has experienced additional demands for use of its transmission system (e.g., 11

interconnection of solar-powered generation in the solar-rich Southern 12

California deserts). These factors, and others, have been driving up SCE’s 13

ISO O&M costs. As I explain in more detail below, SCE has reasonably 14

estimated its increased ISO O&M costs, and they should be approved. I 15

will address each party’s allegations in turn. 16

1 SCE proposes to recover through its FERC-jurisdictional rates only those costs

related to SCE’s transmission and distribution facilities that are under the operational control of the California Independent System Operator (“CAISO” or “ISO”). In this filing, SCE refers to those costs as “ISO” costs or “ISO Transmission” and “ISO Distribution.”


Page 4 of 50

III. FERC STAFF’S PROPOSED ADJUSTMENTS 1

Q. Does FERC Staff propose any adjustments to SCE’s ISO O&M 2

expenses? 3

A. Yes. FERC Staff proposes four adjustments: 4

• Transfer from ISO Transmission O&M to ISO Transmission capital 5

expenditures $2.299 million in costs for environmental mitigation 6

associated with SCE’s Tehachapi Renewable Transmission Project 7

Segments 1-3A (“TRTP 1-3A”) transmission line; 8

• Reduce SCE’s estimate of transmission line rents; 9

• Reduce SCE’s bulk power training costs; and 10

• Eliminate cost escalation for SCE’s ISO transmission labor costs 11

Q. Which of these adjustments are you addressing? 12

A. I am addressing the first three. Dr. Hunt addresses FERC Staff’s cost 13

escalation adjustment in his testimony. 14

Q. Turning to the first issue in your list, please explain FERC Staff’s 15

proposed adjustment to FERC sub-account 571.300 for TRTP 1-3A 16

environmental mitigation. 17

A. In her testimony, FERC Staff witness Chrystina Steffy proposes to transfer 18

$2.299 million of ISO Transmission O&M expenses to Account 101, Plant 19

in Service (Exhibit No. S-18, pp. 16-17), based on SCE’s response to a data 20

request (which she attaches as Exhibit No. S-25, to her testimony). 21


Page 5 of 50

Q. Does SCE agree with this transfer? 1

A. Yes. When the TRTP 1-3A environmental mitigation forecast was 2

developed, it was unclear if site preparation and planting activity would 3

qualify as capital expenditures. In its 2010 O&M forecast, SCE included 4

the costs associated with environmental mitigation for TRTP 1-3A in the 5

amount of $1.523 million for site preparation and $0.776 million for 6

planting activities. SCE subsequently determined that the environmental 7

mitigation costs for right-of-way site preparation and planting should be 8

reclassified from O&M to capital expenditures. 9

Q. Does the transfer of these costs from O&M accounts to capital 10

accounts affect SCE’s calculation of its ISO rate base and depreciation 11

expense in this proceeding? 12

A. Yes. The plant-related costs would increase, as described in Ms. Steffy’s 13

testimony at page 17. Exhibit No. S-18. 14

Q. Please explain FERC Staff’s proposed adjustment to FERC sub-15

account 567.100 for transmission line rents. 16

A. In Exhibit No. S-14, on page 4, FERC Staff witness Kerri Miller proposes 17

to reduce 2010 ISO O&M expenses associated with certain transmission 18

line rents by $2.081 million. Ms. Miller’s adjustment is based on fact that 19

the invoices received by SCE to date for 2010 from the Bureau of Land 20

Management (“BLM”) and United States Forest Service (“USFS”) were 21


Page 6 of 50

lower than the bills that SCE would have received had those two agencies 1

charged SCE the rates that were published in the Federal Register. The 2

difference between the initially projected expense ($11.4 million) and the 3

latest estimate of the 2010 expense ($9.0 million) is $2.4 million, of which 4

$2.082 million is ISO-related. 5

Q. Do you agree with this reduction? 6

A. No. SCE believes the transmission line rents forecast was reasonable at the 7

time it was developed for this filing. Ms. Miller’s testimony does not 8

challenge SCE’s position that the line rents forecast was reasonable when 9

made, and she confirmed in discovery (SCE-FERC Staff Q 53) that she had 10

no basis for contending otherwise. Exhibit SCE-37, p. 1. Instead, she 11

rejects the portion of the increase that exceeds the amounts actually billed 12

by BLM and USFS for 2010. 13

Initially, the projected BLM and USFS rent expense was based upon 14

the revised rent schedules published in the October 31, 2008 Federal 15

Register. However, the invoices received to date from the USFS and BLM 16

have been inconsistent with the rates published in the Federal Register. 17

These rents are assessed and invoiced by various field offices of the federal 18

agencies. Some field offices charged rental rates that were either higher or 19

lower than those calculated by SCE per the Federal Register schedule, 20

while other field offices reflected no change in the rental rate. 21


Page 7 of 50

SCE believes that it was reasonable in the filing to use these federal 1

government agencies’ officially published rental rates to determine SCE’s 2

rental expense, and that the expense should not be adjusted downward 3

because, for whatever reason, the bills actually received by SCE have been 4

lower. While SCE does not currently anticipate spending $11.4 million for 5

line rents in 2010, there is no guarantee that BLM and USFS will not send 6

out corrected bills for 2010 seeking to recover the difference between the 7

rates already billed and the rates published in the October 31, 2008 Federal 8

Register. If that happens, then under Ms. Miller’s approach, SCE’s 9

shareholders would be forced to absorb the difference. That is 10

unreasonable. 11

The question here is not simply whether there is a difference 12

between the projected and actual amounts for 2010, but whether the use of 13

the projected amount is unreasonable in the circumstances. This is not a 14

situation, for example, where SCE projected to pay $11.40 for a piece of 15

equipment, and it actually cost $9. The final billed amount here is not 16

known. Certainly, if the Company received a make-up bill in 2011 for the 17

$2.4 million difference, it could not be said that it was unreasonable to use 18

the $11.4 million estimate as the basis for SCE’s rates. And Ms. Miller has 19

no basis for predicting that that will not occur. 20

Additionally, the issue here is whether it is reasonable to use the 21


Page 8 of 50

forecast amount in order to establish rates that will remain in effect 1

indefinitely. Even if the billing is not corrected for 2010, then all that will 2

have occurred is that SCE will have received a non-recurring discount. 3

This is no different from a one-time overcharge that is not expected to be 4

repeated. In both cases, the billed charges are not reasonably representative 5

of future conditions, and not appropriate for rate making purposes. Indeed, 6

SCE has already received some of its BLM and USFS bills for 2011 and 7

anticipates that its rental expense will rise to $10.6 million next year, which 8

is only 8 percent lower than, and not substantially different from, SCE’s 9

projection for 2010 in this case. 10

Q. Please explain FERC Staff’s proposed adjustment to FERC sub-11

account 566.700 for Bulk Power Training. 12

A. Ms. Miller proposes a reduction to ISO Transmission O&M of $0.203 13

million. In Exhibit No. S-14, pp. 5-6, Ms. Miller indicates that SCE has 14

provided a correction to its forecast for Bulk Power Training in SCE’s 15

responses to data requests (which she attaches to her testimony as Exhibit 16

S-16, pp. 2-3). 17

Q. Does SCE agree with this reduction? 18

A. Yes. 19


Page 9 of 50

IV. SWP’S PROPOSED ADJUSTMENTS 1

Q. Please summarize SWP’s proposed adjustment to ISO O&M expense. 2

A. In contrast to FERC Staff, which actually evaluates projections of 3

individual expense items to determine if they are reasonable, Mr. Marcus 4

recommends reducing SCE’s ISO Transmission O&M expense projection 5

without evaluating a single one of its components. Instead, Mr. Marcus 6

calculates the mathematical variance between SCE’s forecasts for 2008 and 7

2009 made in its prior rate case (Docket No. ER08-1343, or “TO4”) and 8

SCE’s actual recorded ISO Transmission O&M expense for the years 2008 9

and 2009, and concludes that SCE over-forecasted its 2008 and 2009 ISO 10

Transmission O&M costs by 24.7 percent in that case. Exhibit SWP-6, p. 11

43. Based on this analysis, Mr. Marcus concludes that SCE must have 12

over-forecast its transmission O&M expense in this case by 24.7 percent as 13

well, so SCE’s 2010 forecast O&M should be reduced by 24.7 percent. 14

This results in a $20.666 million reduction to SCE’s 2010 forecast O&M 15

expense, which would result in a level of expense that is actually lower than 16

SCE’s recorded 2009 ISO Transmission O&M, without any showing that 17

there is actually anything amiss in SCE’s forecast made in this case. 18

Q. Does SCE agree with this proposed reduction? 19

A. No. Mr. Marcus’ analysis of SCE’s TO4 ISO Transmission O&M forecast 20

does not serve as a reasonable basis for reducing the 2010 forecast in this 21


Page 10 of 50

proceeding. 1

Q. Please explain. 2

A. First, Mr. Marcus’ calculation of the “forecast error” for 2008 is itself in 3

error. He compares an unadjusted 2008 recorded number of $53.8 million 4

to an adjusted TO4 Period II forecast of $65.4 million. This is an apples 5

and oranges comparison. The 2008 recorded number reflects the amounts 6

recorded in SCE’s ISO Transmission O&M accounts for 2008, and does not 7

reflect the numerous adjustments that SCE makes for ratemaking purposes 8

when establishing its O&M forecasts. For example, it does not include any 9

Results Sharing dollars, because such dollars are recorded in A&G 10

accounts.2 11

Volume 9, WP-AH/AI-7 of 295 of my workpapers provides a 12

calculation of the adjusted 2008 recorded ISO O&M expense. This shows 13

that SCE’s TO4 forecast and actual ISO O&M expense for 2008 were 14

$69.064 and $63.918 million (both expressed in 2008 dollars), respectively, 15

an over-forecast of 7.5 percent. 16

2 SCE’s Results Sharing program is a component of employees’ annual compensation

and an adjustment is made to directly assign these costs to each business function for ratemaking purposes.


Page 11 of 50

Q. What did SCE forecast for ISO O&M for 2009 in the current TO5 1

filing? 2

A. SCE forecast $84.423 million for 2009 ISO O&M (expressed in 2009 3

dollars). As it turns out, this forecast was actually low in that SCE’s actual 4

ISO O&M was $86.082 million. This information alone illustrates the 5

fallacy of Mr. Marcus’ position. Given the significant increase in ISO 6

O&M that SCE has incurred from 2008 to 2009, a percentage increase from 7

2009 to 2010 O&M of 71 percent of the 2008 to 2009 increase is entirely 8

plausible and fully supported in SCE’s filing. 9

Q. As corrected, does Mr. Marcus’ analysis provide a reasonable basis for 10

adjusting SCE’s 2010 forecast? 11

A. No, it does not. There is no valid basis for assuming that whatever forecast 12

error occurred in past cases will occur in the future, and the evidence shows 13

exactly the opposite occurred, particularly the significant increase in ISO 14

O&M costs SCE actually incurred from 2008 through 2009. 15

In essence, Mr. Marcus says, “Prepare your very best forecast, 16

taking into account the accuracy of your prior forecasts, and then when 17

you’re done increase or decrease that forecast by the amount of your prior 18

forecast error because you know you really didn’t take it into account.” 19

This is unreasonable and is certainly not a valid basis for slicing $20 20

million from SCE’s revenue requirement. Mr. Marcus does not show that 21


Page 12 of 50

there is anything wrong with SCE’s forecast in this proceeding, or that it 1

contains a single error or unreasonable estimate. Having failed to take the 2

time to perform an analysis of SCE’s forecast, he defaults to a simplistic 3

and flawed methodology. 4

Q. Does Mr. Marcus contend that his O&M expense methodology is 5

consistent with accepted practice? 6

A. Mr. Marcus conceded in discovery (SCE-SWP Q 41 and 46) that he was 7

unaware of any FERC precedent in support of his O&M expense 8

methodology, and indeed that he was unaware of any case in which his 9

proposed O&M expense methodology was adopted by any regulatory 10

commission. Exhibit SCE-37, pp. 2-3. He also conceded that he had never 11

prepared an O&M expense budget for an electric utility. SCE-SWP Q 44 at 12

Exhibit SCE-37, p. 4. His recommendation should be disregarded. 13

V. CPUC’S PROPOSED ADJUSTMENTS 14

Q. Please describe Mr. Cosman’s testimony and his proposed adjustment 15

to SCE’s O&M expense. 16

A. Mr. Cosman presents two inconsistent analyses. On pages 15 through 33 of 17

his direct testimony (Exhibit PUC-1), Mr. Cosman presents his analysis of 18

SCE’s O&M projections for twelve specific accounts (to distinguish the 19

two analyses, I refer to this analysis as “Cosman I”). Unlike FERC Staff, 20

however, he fails to translate his objections into specific adjustments. 21


Page 13 of 50

Instead, on pages 34-36 of his testimony, he discards his first analysis, and 1

replaces SCE’s forecast with a simplistic trend-line formula that bears no 2

relationship to the concerns he identified in first analysis. In that second 3

analysis, he simply assumes that whatever level of annual increase in ISO 4

O&M costs SCE experienced in each account between 2003 and 2007, the 5

same will occur between 2008 and 2010 (“Cosman II”). His two analyses 6

are so disjointed that he criticizes SCE on pages 21-22 for increasing its 7

Account 563.1 costs by $2.4 million, and then advocates an increase twice 8

that level on pages 34-36. The reason this happens is because he 9

straightjackets his recommendation for each account to its historical annual 10

increase regardless of the circumstances. Based upon his analysis, Mr. 11

Cosman states that he is proposing a $31.020 million reduction to SCE’s 12

2010 ISO O&M expense, bringing SCE’s 2010 ISO O&M expense $15 13

million below SCE’s actual 2009 ISO O&M expense. Mr. Cosman 14

confirmed that, prior to this case, he had never prepared a forecast of an 15

electric utility’s O&M expenses. SCE-CPUC Q 25 (Exhibit SCE-37, p. 5). 16

Q. How does Mr. Cosman’s account-by-account analysis affect his 17

account-by-account recommendation? 18

A. It has no effect. His account-by-account analysis (Cosman I) is completely 19

independent from his account-by-account recommendation (Cosman II). 20

There is no tie between the two. 21


Page 14 of 50

Q. Does Mr. Cosman claim that the annual increase in costs that SCE 1

experienced during the 2003-07 period is representative of its cost 2

increases for the 2008-2010 period? 3

A. No. He simply states that the magnitude of SCE’s proposed increase calls 4

for a consistent, objective methodology applied to each sub-account. He 5

makes no claim, however, that the cost changes that SCE experienced from 6

2003 to 2007 are representative of the cost changes he believes SCE will 7

experience from 2008 to 2010. And of course, not having even made that 8

claim, he provides no evidence that 2003-07 is a reasonably representative 9

period for evaluating SCE’s 2008-10 cost changes. 10

Q. Is it? 11

A. No, it is not. As I explained in my Direct Testimony (Exhibit SCE-4), most 12

of SCE’s proposed ISO O&M increases are due to factors that are not 13

reflected in the historical period that Mr. Cosman uses in his trend-line. As 14

a result, Mr. Cosman is benchmarking today’s cost changes using an 15

historical period that is not representative of today’s circumstances. 16

Q. Please explain. 17

A. First, the largest component of SCE’s increase – the $7.6 million increase 18

in line rents imposed by SCE’s lessors – is not reflected in the 2003-07 19

figures, when line rents were relatively flat. Those rents rose by an average 20

of 1.33 percent per year during 2003-07 (as reflected in Mr. Cosman’s 21


Page 15 of 50

Appendix B calculation), and are projected to rise by over 500 percent 1

during 2008-10. The second largest increase in SCE’s costs – $6.9 million 2

for Advanced Technology activities – is a new program not reflected at all 3

in the 2003-07 period. A 2003-07 trend-line analysis would fail to capture 4

any of this cost increase. SCE is also facing unprecedented challenges in 5

the cost of operating and maintaining its transmission system, and the third 6

largest increase ($4.2 million) in this case is for transmission maintenance. 7

Q. Are there other changes in SCE’s ISO O&M costs that are driven by 8

factors not present in 2003-07? 9

A. Yes. In my prior answer, I discussed the three largest categories of cost 10

increases reflected in SCE’s Period II projections, and showed that Mr. 11

Cosman’s approach would either omit or under-forecast the costs 12

associated with each one of them. Filling out the remainder of the top ten 13

are: 14

15

CPC/CAB staff $3.6 million Right of way maintenance $2.5 million Transmission and interconnection planning $2.2 million Misc (results sharing, substation maintenance, write-off, engineering) $1.9 million

Capital work order related expense $1.7 million Arizona Public Service 500 kV line $1.6 million TRTP 1-3A environmental $1.5 million

16

Costs associated with the Compliance, Policy, & Contracts (”CP&C”) and 17


Page 16 of 50

Contract Administration & Billing (”CA&B”) accounting change and 1

increased staff requirements have grown recently primarily due to 2

interconnection requests and reliability standards requirements and 3

accounting shift to O&M, and would be under-forecasted by a 2003-07 4

trend-line analysis. Transmission and interconnection planning has grown 5

dramatically during the past two years due to increased interest in 6

renewable generation, so a trend-line analysis would under-forecast this 7

cost as well. Capital work order related expense is driven by SCE’s 8

construction program, which has grown dramatically during the past two 9

years, so a 2003-07 trend-line analysis would under-forecast these costs as 10

well. The Arizona Public Service 500 kV line increases are not reflected in 11

the 2003-07 period, so the 2003-07 trend-line forecast would miss these 12

increases. TRTP 1-3A environmental mitigation is for a transmission 13

facility that did not exist during 2003-07, so Mr. Cosman’s trend-line 14

analysis would omit this cost in its entirety (SCE projected $4 million for 15

this cost, but I have reduced it to $1.5 million consistent with SCE’s 16

transfer of $2.5 million of these costs to capital expense). I discuss these 17

changes in more detail below when I respond to Mr. Cosman’s account-by-18

account analysis. But it is clear from the above discussion that an O&M 19

trend-line analysis based on the 2003-07 period will fail to capture the 20

O&M cost increases that SCE is experiencing. 21


Page 17 of 50

Q. Is there empirical evidence of this? 1

A. Yes. In Cosman II, Mr. Cosman asserts that SCE’s ISO O&M costs in 2

2008 were $63.9 million, and he predicts that they will rise by $7.8 million 3

by 2010. About half of that, or $3.9 million, would occur in 2009, yielding 4

a 2009 O&M cost of just under $68 million, in contrast to SCE’s forecast of 5

$84 million. In fact, those costs rose to $86 million due to the factors I 6

identified above. Mr. Cosman’s methodology does not reflect the increases 7

in ISO O&M expenses that actually occurred in 2009 and is fundamentally 8

flawed and should be rejected. 9

Q. Mr. Cosman states that SCE’s proposed O&M increase is inconsistent 10

with the economic slowdown in SCE’s service area, SCE’s forecast of 11

reduced retail electricity sales, and lack of growth in SCE’s FERC- 12

jurisdictional circuit miles. Please respond. 13

A. Many of the cost increases that SCE projects for 2009 and 2010 result from 14

non-discretionary activities or contractual obligations, and therefore are not 15

impacted by economic conditions and retail sales. With few exceptions, the 16

cost of operating and maintaining SCE’s transmission system is not 17

affected by the reduced demands that SCE has seen: the lines still have to 18

be inspected and maintained in the same manner; rents still have to be paid; 19

generator interconnection requests still have to be responded to; and 20

planning for enhancements to and expansions of the system continues. 21


Page 18 of 50

While in the long-term increases in ISO O&M costs may moderate if 1

transmission expansion is demand-driven, that is certainly not true in the 2

short-term. For example, in 2009, in the face of a dramatic slowdown in 3

California’s economy, SCE’s actual ISO O&M costs rose 35 percent year 4

over year. 5

Q. Mr. Cosman includes a table on page 34 of his testimony showing that 6

SCE’s transmission miles have not increased, and asserts that this 7

shows that SCE’s projections are unreasonable. Is this correct? 8

A. No, it is not. Although SCE’s “aggressive capital investment goal” (Mr. 9

Cosman’s words) creates increased ISO O&M costs associated with that 10

program, none of SCE’s transmission O&M cost increases are related to 11

maintaining additional miles of transmission circuits, so Mr. Cosman’s 12

table proves nothing. 13

Q. Putting aside your concerns about the inappropriateness of using a 14

2003-07 trend-line analysis for projecting 2010 costs, are the numbers 15

set forth in Mr. Cosman’s testimony and exhibits consistent? 16

A. No, they are not. On page 15 of his testimony, Mr. Cosman states that 17

SCE’s recorded 2008 transmission O&M expense is $53,614,000, and that 18

its projected transmission O&M expense for 2010 is $104,335,000. In 19

Exhibit PUC-2, in contrast, he shows SCE’s 2008 transmission O&M 20

expenses as $63,945,000, more than $10 million higher than the figure on 21


Page 19 of 50

page 15, and SCE’s projected 2010 transmission O&M expense as 1

$102,733,000, or about $2 million lower than SCE’s projection shown on 2

page 15. This confusion carries over to his recommendation: on page 35 3

of his testimony, he states that he recommends a $31,020,100 decrease 4

from SCE’s filing, based on the analysis in Exhibit PUC-2. On page 15, 5

however, he recommends reducing SCE’s transmission expense from 6

$104,335,000 to $71,712,900, a reduction of $32,622,100. 7

Q. You noted earlier that Mr. Cosman’s recommendations in Cosman II 8

are unrelated to his account-by-account analysis in Cosman I. Do you 9

have any observations on Cosman I? 10

A. Yes. Mr. Cosman analyzes SCE’s projections for twelve specific accounts. 11

I will respond to his allegations in the order in which he makes them. 12

A. ACCOUNT 560.100 13

Q. The first account that Mr. Cosman addresses in his testimony is 14

Account 560.100. What are Mr. Cosman’s objections to SCE’s 15

projected increase for this account? 16

A. Mr. Cosman asserts that SCE has not shown that Advanced Technology 17

activity is cost effective or that spending money on this activity is justified; 18

that SCE has failed to provide enough specificity regarding capital project 19

deferrals or cancellations that result in capital write-offs; and that SCE may 20

be attempting to double collect costs in the engineering organization for 21


Page 20 of 50

engineering vacancies because the cost of vacancies should be present in 1

the 2008 base year. Increases in these three items are the reason for the 2

increase in this account. 3

Q. Please respond. 4

A. As Mr. Cosman notes, SCE created the Advanced Technology section in 5

2009, in order to focus on deploying technologies to lower costs and 6

improve service. Mr. Cosman asserts that SCE has failed to provide a cost-7

benefit study that justifies the spending that SCE anticipates for this 8

organization, and that the expense should therefore be rejected. This 9

contention does not go to the question of whether SCE reasonably projected 10

what expenses it will incur, but rather whether SCE should be permitted to 11

incur them at all – i.e., the prudence of the cost. Mr. Cosman, however, has 12

provided no evidence that the cost is imprudent. The program is necessary 13

for SCE to continue to provide reliable and cost-effective service to its 14

customers. 15

Mr. Cosman makes no argument that SCE has not reasonably 16

projected its 2010 Advanced Technology section expenses, and in either 17

event that projection is well supported with estimates and detailed project 18

descriptions provided in the report included in the response to CPUC-SCE-19

L004 Q 104. Exhibit SCE-37, pp. 6-70. (a summary of that report was 20

included in my direct testimony at Exhibit SCE-4, pp. 5-7). The response 21


Page 21 of 50

includes descriptions for the $6.27 million to study the impacts and 1

mitigation of integrating renewable generation. It also provides 2

descriptions for the $2.432 million of transmission technology 3

advancements in substation automation, communications integration, 4

equipment monitoring and system evaluation, synchrophasor measurement 5

systems, engineering of safety measures into equipment design and 6

deployment, and advanced applications for SCE’s satellite system. SCE 7

believes this cost projection is well supported. 8

Mr. Cosman’s concerns about SCE’s capital write-off costs are 9

without merit. SCE’s increase for capital write-offs is based on the five-10

year average ratio of capital work order write-offs to capital spending. In 11

light of the significant increase in SCE’s forecasted capital spending, this 12

expense is expected to rise as well. Given the nature and volume of SCE’s 13

capital projects, SCE cannot possibly predict “specific or general project 14

deferrals or cancellations” as discussed by Mr. Cosman, and therefore 15

utilizes a historical percentage methodology. SCE’s capital write-off 16

percentage has remained relatively constant, and is likely to do so in the 17

future. 18

Finally, Mr. Cosman objects to the increase in SCE’s engineering 19

organization expense in that SCE may be double-collecting the cost of 20

vacant positions. In support of that argument, Mr. Cosman contends that 21


Page 22 of 50

“[t]he position may have been vacant in 2008, but the expense associated 1

with the position was present in the base year.” Exhibit PUC-1, p. 18, ll. 8-2

16. The cost of filling these vacancies is only part of the projected increase, 3

but in either event Mr. Cosman’s assertion is false. Contrary to Mr. 4

Cosman’s assertion, engineering vacancies in 2008 are not reflected in the 5

2008 recorded expenses. The company’s actual recorded expenses are just 6

that – actual. There may be budgeted expenses associated with a vacant 7

position, but when a position is vacant obviously there are no actual 8

recorded labor expenses for that position until that position is filled. SCE is 9

no different from the Commission or any other organization in this respect: 10

its budget may include the cost of vacancies it expects to fill, but its actual 11

costs for a prior year only reflects the employees it actually paid. Since 12

these vacancies existed in 2008, and no labor cost was recorded while the 13

positions were open through the end of 2008, backfilling these positions in 14

2010 will in result in an increase in 2010 versus the 2008 base year. 15

Q. Does Mr. Cosman propose an adjustment to this account? 16

A. Yes. Mr. Cosman’s calculation provided in Appendix B proposes a 2010 17

projection for sub-account 560.100 of $2.235 million. 18

Q. Is this proposal based on the three arguments discussed above? 19

A. No. It has nothing to do with it. The basis for Mr. Cosman’s proposed 20

adjustment is strictly Mr. Cosman’s trend-line analysis (Cosman II). I 21


Page 23 of 50

explain above why the recommendations in that trend-line analysis are 1

unreasonable. With specific reference to this account, the majority of the 2

cost increase (advanced technology study) relates to a program that did not 3

exist in 2003-07, so a trend-line analysis would not capture that cost. The 4

increases for Engineering labor, contract labor, and software are also not 5

reflected in the 2003-2007 historical spend utilized in Mr. Cosman’s 6

analysis. And the increase for capital write-offs is not reflected in the 7

2003-2007 historical cost utilized in Mr. Cosman’s analysis, either. 8

B. ACCOUNT 561.200 9

Q. Please explain Mr. Cosman’s objections to SCE’s projection for this 10

account. 11

A. Mr. Cosman asserts that SCE did not support its projection, and references 12

SCE’s data request response regarding overheads. 13


A. SCE explained in response to the CPUC’s data request (CPUC-SCE-L004 15

Q 105) that the increase from 2008 to 2010 is attributable to Grid Control 16

Center (“GCC”) operations and engineering. Exhibit SCE-37, pp. 71-72. 17

The GCC operations and engineering increase was budgeted in 2009 and is 18

continuing in 2010. The GCC serves as a 24-hour, 365 days a year dispatch, 19

operating and communications center for transmission and distribution. The 20


Page 24 of 50

GCC is the primary point of contact with the CAISO and supervises the 1

routine and emergency operations of the SCE transmission system. 2

Q. Does Mr. Cosman propose an adjustment to SCE’s projection for 3

Account 561.200? 4

A. Yes. Mr. Cosman’s calculation provided in Appendix B proposes a 2010 5

projection for sub-account 561.200 of $2.170 million, which he states is a 6

reduction of $0.228 million to SCE’s forecast. 7

Q. Is this proposal based on arguments presented on pages 18-19 of his 8

testimony? 9

A. No. The basis for Mr. Cosman’s proposed adjustment to Account 561.200 10

is Mr. Cosman’s 2003-07 trend-line analysis (Cosman II). I explain above 11

why the recommendations in that trend-line analysis are unreasonable and 12

should not be adopted. This increase is not reflected in the 2003-2007 13

historical spending utilized in Mr. Cosman’s analysis, so a 2003-07 trend-14

line analysis would not reflect it. 15

C. ACCOUNT 561.500 16

Q. Please explain Mr. Cosman’s concerns with SCE’s projection for this 17

account. 18

A. Mr. Cosman asserts that SCE provides no justification for the forecast 19

increase. With respect to the Renewable Energy Transmission Incentive 20

(“RETI”), he states that SCE failed to spend any of the $3 million it 21


Page 25 of 50

projected to spend on this project in 2009, so its proposal to spend any 1

money in 2010 is questionable. He argues that SCE does not indicate what 2

functions its additional Transmission and Interconnection Planning 3

(“T&IP”) staff will perform, and should not charge customers for its 4

California Transmission Planning Group activities (part of T&IP). Cost 5

increases for RETI and T&IP comprise part of the increase for this account. 6


A. Mr. Cosman’s testimony ignores the cost drivers that are creating the 8

increases for this account for 2010. The CPUC itself authorized $4.5 9

million for RETI due to the urgent need for transmission for renewable 10

resources in California. At the time of the TO5 filing, SCE estimated it 11

would spend $0.971 million on RETI activity in 2010; the fact that it did 12

not spend any money in 2009 has no bearing on the reasonableness of this 13

2010 projection. Second, Mr. Cosman’s assertion that SCE “does not 14

mention why” additional staff is required in the T&IP organization is 15

incorrect. I discussed the T&IP cost increase drivers in my direct 16

testimony (Exhibit SCE-4, p.8) and in my response to CPUC-SCE-L004 Q 17

106 (Exhibit SCE-37, pp. 73-78). The increase is in part due to the hiring 18

of additional staff to study generator interconnection requests, which is 19

reasonable given the expansion of the transmission system and hundreds of 20

generator interconnections requests received. In addition, it should be 21


Page 26 of 50

noted that SCE has filled all of the forecasted T&IP positions. 1

Finally, Mr. Cosman’s arguments regarding the California 2

Transmission Planning Group activities are without merit. Mr. Cosman 3

makes no assertion that SCE’s projection of its costs of participating in this 4

group are unreasonable; rather, Mr. Cosman argues that SCE has not 5

justified its participation in this group at all. This is a prudence argument. 6

Mr. Cosman has made no showing that SCE’s participation in this group is 7

imprudent or otherwise unwise from the perspective of California 8

transmission customers. SCE’s participation in the group promotes 9

regional planning, a key objective of this Commission. Mr. Cosman’s 10

arguments should be rejected. 11


Account 561.500? 13

A. Yes. Mr. Cosman’s calculation provided in Appendix B proposes 2010 test 14

year funding for sub-account 561.500 at $3.501 million. Mr. Cosman 15

applies the five year average (2003 to 2007) yearly change percentage to 16

2008 recorded, resulting in a reduction of $2.945 million to SCE’s forecast. 17

Q. Is this proposal based on arguments presented on pages 19-20 of his 18

testimony? 19

A. No. The basis for Mr. Cosman’s proposed adjustment to Account 561.500 20

is Mr. Cosman’s 2003-07 trend-line analysis (Cosman II). It has nothing to 21


Page 27 of 50

do with his arguments regarding RETI and T&IP. I explain above why the 1

recommendations in that trend-line analysis are unreasonable and should 2

not be adopted. With respect to this account in particular, the increased 3

costs for RETI are for a program that did not exist in 2003-07, so Mr. 4

Cosman’s trend-line forecast would miss that cost entirely. The same may 5

be said for SCE’s cost of participating in the California Transmission 6

Planning Group. SCE’s increased T&IP costs also reflect a level of activity 7

well above that experienced in 2003-07, so Mr. Cosman’s trendline forecast 8

is a poor forecaster of that cost as well. 9

D. ACCOUNT 562.200 10

Q. Please explain Mr. Cosman’s comments on SCE’s projection for 11

Account 562.200. 12

A. Mr. Cosman’s testimony states that SCE did not provide testimony for the 13

increase in this account. 14


A. The increase from 2008 to 2010 is attributable to an increase in relay 16

routines, which are diagnostic tests of substation equipment, occurring in 17

2009 and continuing in 2010. Mr. Cosman’s testimony ignores SCE’s 18

explanation regarding this increase, which was provided in response to 19

CPUC-SCE-L004 Q 108. Exhibit SCE-37, p. 79. 20


Page 28 of 50


Account 562.200? 2

A. Mr. Cosman’s calculation provided in Appendix B proposes 2010 test year 3

funding for sub-account 562.200 at $1.292 million. Mr. Cosman applies the 4

five year average (2003 to 2007) yearly change percentage to 2008 5

recorded, resulting in a reduction of $0.192 million to SCE’s forecast. I 6


unreasonable. 8

E. ACCOUNT 563.100 9

Q. Please explain Mr. Cosman’s objections to SCE’s projections for 10

Account 563.100. 11

A. Mr. Cosman states that SCE did not provide testimony to support its 12

projection for this account, and asserts that SCE is doubling this account 13

without justification. 14


A. Mr. Cosman’s testimony ignores SCE’s adjustments to Account 563.100 16

for the transmission line rating study, one of the cost components in this 17

account. The adjustment transfers the study cost from Account 560.100 to 18

Account 563.100 where it is forecasted. After reflecting this adjustment, 19

Account 563.100 is actually decreasing by $1 million. The decrease is due 20

to lower 2010 expense for the transmission line rating study and an 21


Page 29 of 50

accounting practice change that occurred in 2009 for tool expenses, offset 1

by an increase in transmission patrols and inspections. 2


Account 563.200? 4

A. Yes. However, Mr. Cosman’s Appendix B calculation is contrary to his 5

testimony and proposes a 2010 test year funding increase for sub-account 6

563.100 at $9.038 million. Mr. Cosman applies the five year average (2003 7

to 2007) yearly change percentage to 2008 recorded, resulting in an 8

increase of $4.217 million to SCE’s request. Mr. Cosman’s recommended 9

increase for this account only serves to underscore that Mr. Cosman’s 10

criticisms of SCE’s projections in Cosman I have absolutely nothing to do 11

with his actual recommendations in this proceeding. 12

F. ACCOUNT 566.200 13

Q. What are Mr. Cosman’s concerns with regard to SCE’s projection for 14

Account 566.200? 15

A. Mr. Cosman’s testimony asserts that SCE provides no justification for the 16

forecast increase. In addition, he asserts that the justification that SCE 17

provides for this increase in its data response is vague and inadequate. 18

Q. How do you respond? 19

A. As discussed in SCE’s response to CPUC-SCE-L004 Q 110 (Exhibit SCE-20

37, p. 80), the increase in this account is due to early engineering 21


Page 30 of 50

assessments of large transmission and substation projects. This activity is 1

reflected in O&M expenses due to its conceptual nature and is performed 2

prior to the preliminary engineering of specific capital projects. Given the 3

significant increase in forecasted capital projects the modest increase of 4

$0.252 million in this account is reasonable. 5


Account 566.200? 7

A. Yes. However, Mr. Cosman’s calculation provided in Appendix B applies 8

the five year average (2003 to 2007) yearly change percentage to 2008 9

recorded, resulting in an increase of $0.035 million. The only 10

quantification of Mr. Cosman’s proposed adjustments is that set forth in 11

Appendix B, and that quantification 1) is not supported by the first part of 12

his testimony, and 2) is based on a trend-line analysis that is entirely 13

inappropriate for forecasting SCE’s transmission O&M expenses. Mr. 14

Cosman’s testimony provides no basis for revising any of SCE’s O&M 15

projections, and should be disregarded. 16

G. ACCOUNT 566.500 17

Q. Please explain Mr. Cosman’s objection to SCE’s projection for 18

Account 566.500. 19

A. Mr. Cosman asserts that SCE is proposing a substantial increase for routine 20

work that the Company already performs. In particular, he argues that SCE 21


Page 31 of 50

has failed to provide sufficient support for its cost increases for three items 1

included in this account: Compliance Policy and Contracts (“CP&C”), 2

Grid Interconnection and Contracts Development (“GI&CD”), CP&C 3

Transmission Regulatory Policy, and CP&C Reliability Standards 4

Compliance. 5

Q. How do you respond? 6

A. Mr. Cosman mistakenly attempts to forecast the personnel required in 2010 7

by looking at the past rather than the future. As of mid-September 2010, 8

the FERC-jurisdictional interconnection queue stands at 440 active 9

requests. This represents a 175 percent increase over 2008 and a 144 10

percent increase over the 2009 level.3 During 2008, GI&CD had 10 11

employees and SCE has requested a total increase of 15 employees, 12

bringing the size of the group in 2010 to 25 employees. This represents a 13

150 percent increase, which is very much in line with the growth in the 14

interconnection queue. SCE anticipates that California’s ambitious 15

renewable portfolios standards goal of 33 percent and the CEC and CPUC 16

programs such as rooftop solar will sustain the growth rate of 17

interconnection requests. Consequently, Mr. Cosman’s adjustment for 18

3 As explained in SCE’s testimony, as of mid-July 2009, there were 180 active FERC-

jurisdictional interconnection requests.


Page 32 of 50

GI&CD should be rejected. 1

Mr. Cosman protests the need for additional staff required by the 2

CP&C Transmission Regulatory Policy. As I stated in my direct testimony, 3

the work of this group has grown significantly. In order to meet 4

California’s unprecedented goal of 33 percent renewable generation by 5

2020, new transmission lines must be built and renewable generators must 6

be interconnected. The development of new policies, tariffs and regulations 7

to support the planning, construction, and financing of these new facilities 8

requires significant stakeholder participation. SCE is working with the 9

CAISO to establish that access to renewable resources should be included 10

in the planning process as a new criterion for approving transmission 11

projects. Due to the increasing volume of small generator interconnection 12

requests, the CAISO has launched a reform effort related to the Small 13

Generator Interconnection Procedures that SCE participates in. SCE also 14

advocates for policies that promote the financing of generator 15

interconnection, either by up-front financing by SCE or recognition in the 16

development of policies and procedures that generators being funded by the 17

American Recovery and Reinvestment Act have unique deadlines that 18

should be accommodated. Additional staff is also required to handle the 19

increased work associated with developing reliability standards, including 20

the new critical infrastructure protection standards. Because the pace and 21


Page 33 of 50

complexity of the regulatory issues required to support renewable 1

integration and develop reliability standards is showing no signs of 2

slowing, Mr. Cosman’s adjustment for Transmission Regulatory Policy 3

group should be rejected. 4

Mr. Cosman also argues against the need for additional staff required 5

by the Reliability Standard Compliance Group (RSC). Mr. Cosman 6

acknowledges the changing circumstances that led to the need for 7

additional staff when he stated, “FERC reliability standards became 8

mandatory in the summer of 2007.” Exhibit PUC-1, p. 24. However, he 9

continues, “[b]ut even before 2007, SCE was subject to WECC’s standards 10

under the Reliability Management System.” Exhibit PUC-1, p. 24. In other 11

words, he believes that although FERC took charge of reliability standards, 12

made those standards mandatory, enforceable and subject to penalties, and 13

designated NERC as the industry organization to develop the standards 14

subject to FERC’s oversight and approval, not much has changed that 15

would impact SCE’s staffing requirements. 16

Contrary to Mr. Cosman’s belief, the reliability framework that 17

FERC ushered in has had a significant and widespread effect on the 18

industry. As a result, in 2008, SCE formed the Reliability Standards 19

Compliance Group to manage the significant increase in workload. 20

Compare for example, the fact that currently SCE must comply with 71 21


Page 34 of 50

reliability standards involving 782 requirements, while under the WECC 1

Reliability Management System, SCE was subject to only three reliability 2

criteria. NERC’s currently enforceable standards are over 1,000 pages 3

while WECC has merely a fraction of that. Moreover, concern over 4

safeguarding the grid from terrorist or other attacks has led to the time-5

intensive, but necessary development and implementation of NERC’s 6

Critical Infrastructure Protection Standards. FERC is well aware of the 7

time the industry has devoted to improving the reliability of the nation’s 8

electric system and has similarly increased the number of its own staff 9

devoted to standards development, compliance and enforcement. 10

Therefore, Mr. Cosman’s incorrect analysis should be rejected. 11


Account 566.500? 13





Q. Is this proposal based on his discussion regarding CP&C Grid 18

Interconnection and Contracts Development, CP&C Transmission 19

Regulatory Policy, and CP&C Reliability Standards Compliance? 20

A. No. The basis for Mr. Cosman’s proposed adjustment is strictly Mr. 21


Page 35 of 50

Cosman’s trend-line analysis (Cosman II), and has nothing to do with his 1

discussion of SCE’s projections for these three groups. I explain above 2

why the recommendations in that trend-line analysis are unreasonable. 3

With specific reference to this account, the increases for these groups are 4

not reflected in the 2003-2007 historical spending utilized in Mr. Cosman’s 5

analysis, so the use of that trend-line is inappropriate. 6

H. Account 566.700 7

Q. Please explain Mr. Cosman’s concerns with SCE’s projection for 8

Account 566.700. 9

A. In his testimony, Mr. Cosman asserts that SCE provides no testimony 10

providing the reasons for the projected increase, and that a 2010 test year 11

increase is not justified. 12


A. I discussed the required training increase on pages 14 to 16 of my direct 14

testimony (Exhibit SCE-4) and provided additional details in my 15

workpapers. In summary, the increase in training expense is needed to 16

adequately support the training requirements associated with an increasing 17

workload and workforce, attrition, the rapid pace of upgrades to our 18

existing technology systems and tools, and ongoing safety challenges. 19


Page 36 of 50


Account 566.700? 2

A. Yes. However, in Appendix, B Mr. Cosman applies the five year average 3

(2003 to 2007) yearly change percentage to 2008 recorded, resulting in an 4

increase of $0.781 million to SCE’s revised forecast (including the Bulk 5

Power calculation correction). This trendline-based adjustment should be 6

rejected, for the reasons discussed above. 7

I. Account 570.400 8

Q. Please summarize Mr. Cosman’s concerns with SCE’s projection for 9

this account. 10

A. Mr. Cosman asserts that SCE does not show why its existing expense level 11

is insufficient, and that SCE’s forecast is out of line with the historical 12

trend. He also states that SCE is requesting an increase in costs (Predictive 13

Maintenance Assessment (“PMA”), switch rack lighting and trench covers) 14

that it does not track. 15

Q. Do you agree with Mr. Cosman’s observations? 16

A. No. Mr. Cosman’s testimony compares historical and forecast PMA repair 17

volumes and asserts there is no justification for an increased cost from 2009 18

to 2010. As indicated in SCE’s response to CPUC-SCE-L004 Q 116 19

(Exhibit SCE-37, pp. 81-83), SCE performed 770 PMAs in 2008 and 20

forecast to perform 1,262 PMAs in 2010. This results in an increase of 492 21


Page 37 of 50

PMAs over the 2008 base year, upon which SCE based its increase in PMA 1

expense. In 2009, SCE's population of PMA activity included high volume, 2

but low cost PMAs that were included in the total (e.g., un-energized 3

disconnects found to be not completely latched were pushed closed and 4

counted in the volume). See SCE’s response to FERC-STAFF-SCE-L004 5

Q 113 at Exhibit SCE-37, p. 84. 6

Mr. Cosman asserts that the increase for deteriorated trench covers 7

and upgrading switch-rack lighting cannot be substantiated. As indicated in 8

the response to CPUC-SCE-L004 Q 116, switch-rack lighting is critical to 9

the safety of SCE’s and its contractors’ personnel, and is performed when 10

necessary. Exhibit SCE-37, p. 81-83. SCE estimated the cost of switch-11

rack lighting upgrades at a transmission substation is approximately 12

$42,000. SCE forecast to perform ten upgrades in 2010 and there were no 13

lighting upgrades performed in 2008. See SCE’s response to FERC-14

STAFF-SCE-L004 Q 114 (Exhibit SCE-37, pp. 85-86). Composite trench 15

cover material costs approximately $25.36 per square foot and SCE 16

forecast to replace an additional 14,000 square feet in 2010 (i.e., beyond 17

that performed in 2008). Id. It is not necessary to separately track each 18

switch rack lighting upgrade and trench cover repair in order to determine 19

whether such costs are increasing; the cost increase is based on change in 20

the activity level, which SCE has reasonably forecast as indicated above. 21


Page 38 of 50


Account 570.400? 2


funding for sub-account 570.400 at $3.475 million. Mr. Cosman applies 4


recorded, resulting in a reduction of $2.538 million to SCE’s forecast. 6

Q. Is this proposal based on his arguments regarding PMA, switch rack 7

lighting and trench covers, discussed in his testimony? 8

A. No. It has nothing to do with it. The basis for Mr. Cosman’s proposed 9

adjustment is strictly Mr. Cosman’s trend-line analysis (Cosman II). I 10


unreasonable. 12

J. Account 571.100 13

Q. Please explain Mr. Cosman’s objections to SCE’s projection for 14

Account 571.100. 15

A. Mr. Cosman’s asserts that SCE provides only an overview in testimony and 16

inadequate justification for the forecast increase. He also questions the 17

effectiveness of SCE’s transmission life extension program. A portion of 18

the costs of this program is included in this account. 19


A. Contrary to Mr. Cosman’s assertions, SCE’s testimony, workpapers and 21


Page 39 of 50

data request responses describe the need for the increases in this account. 1

As discussed in SCE’s response to CPUC-SCE-L004 Q 117 (Exhibit SCE-2

37, p. 87-88), this is the same program described as the Transmission Life 3

Extension Program in SCE’s 2009 CPUC GRC. Included in SCE’s 4

response to MSR/LADWP-SCE-L002 Q 84 (Exhibit SCE-37, pp. 89-152) 5

is the Transmission Life Extension Program workpaper from SCE's 2009 6

CPUC GRC application, which provides additional information on the need 7

for this work. The activities included in the increase had minimal spending 8

starting in 2007 and 2008, but ramped up significantly in 2009. Mr. 9

Cosman also incorrectly asserts that this maintenance program should 10

lower the depreciable lives and that it would be prudent if that were the 11

case. As indicated in SCE’s responses to multiple data requests, the life 12

extension program is not intended to increase the transmission asset 13

depreciable lives. The goal of transmission life extension program is to 14

slow the deterioration of capital assets so that the facilities can reach their 15

expected useful life and thus reduce the amount of capital replacement 16

expenditures that would otherwise have to be made. Reducing the required 17

capital investment is beneficial to ratepayers and therefore pursuing this 18

proactive maintenance program is prudent, and Mr. Cosman has failed to 19

show otherwise. 20


Page 40 of 50


Account 571.100? 2





As with his other recommendations, this adjustment has no relationship to 7

the concerns that he identifies in his testimony with respect to SCE’s 8

projections, and instead is based on his trendline analysis. I explain above 9

why the recommendations in that trend-line analysis are unreasonable. 10

With specific reference to this account, the transmission life extension 11

program did not exist in 2003-06 and had only minimal spending in 2007, 12

so a trend-line analysis would not capture that cost. 13

K. Account 571.200 14

Q. Please explain Mr. Cosman’s objections to SCE’s projection for 15

Account 571.200. 16

A. Mr. Cosman’s asserts that SCE provides only an overview in testimony and 17

inadequate justification for the forecast increase. He also questions the 18

effectiveness of SCE’s transmission life extension policy. A portion of the 19

costs of this program is included in this account. 20


Page 41 of 50


A. Mr. Cosman’s assertions are essentially the same as those provided for 2

Account 571.100. Contrary to Mr. Cosman’s assertions, SCE’s testimony, 3

workpapers and data request responses describe the need for the increases 4

in this account. In addition, I explain above why Mr. Cosman’s arguments 5

with respect to the transmission life extension program are erroneous. 6


Account 571.200? 8





Again, this recommendation is unrelated to Mr. Cosman’s testimony 13

(Cosman I), and should be rejected. With specific reference to this account, 14

the transmission life extension program did not exist in 2003-06 and had 15

only minimal spending in 2007, so a trend-line analysis would not capture 16

that cost. 17

L. Account 571.300 18

Q. Please explain Mr. Cosman’s position on SCE’s projections for 19

Account 571.300. 20

A. Mr. Cosman’s testimony discusses TRTP 1-3A environmental mitigation 21


Page 42 of 50

O&M and indicates it “may be an instance of double collecting.” 1

Q. Is he correct? 2

A. No. The O&M reduction should be $2.229 million for the reclassification 3

of Tehachapi environmental mitigation of O&M to capital. As discussed in 4

response to FERC Staff’s adjustments, when the TRTP 1-3A environmental 5

mitigation forecast was developed it was unclear if site preparation and 6

planting activity would qualify for capitalization so these activities were 7

forecast as O&M. SCE subsequently determined that the 2010 O&M 8

forecast of $1.523 million for site preparation and $0.776 million for 9

planting activities should be reclassified as capital. See SCE’s response to 10

FERC-STAFF-SCE-L004 Q 109 at Exhibit SCE-37, p. 153. As discussed 11

in SCE’s response to FERC STAFF-SCE-L004 Q 115 (Exhibit SCE-37, pp. 12

154-155), the total 2009 recorded right-of-way clearing activity was $9.571 13

million, which was nearly double the 2008 recorded expense of $4.998 14

million, and exceeds SCE's 2010 forecast of $8.832 million. See SCE 15

Direct Testimony, Volume 9, WP-AH/AI-37 of 295, BAKER. SCE 16

believes this level of annual spending is required to address regulatory 17

compliance requirements (i.e. fire code enforcement, weed abatement and 18

maintaining access to facilities). If SCE does not maintain this level of 19

clearing activity, then SCE, by allowing vegetation growth and road 20

deterioration, will face future environmental access constraints and 21


Page 43 of 50

exponential cost increases like those occurring in the Angeles Forest and at 1

Camp Pendleton. By allowing vegetation growth to return, SCE risks the 2

development of animal habitats and certain plant species, which become 3

subject to additional environmental clearance constraints. By allowing 4

access roads to deteriorate SCE can face additional engineering and grading 5

expenses. In addition, SCE is required to maintain safe access to 6

transmission lines to allow for inspection, maintenance, and restoration of 7

transmission lines. The right of way clearing activity also provides fire 8

breaks for fire crews in the event of a fire or other emergencies. 9


Account 571.300? 11


funding for sub-account 571.300 at $5.481 million. Mr. Cosman applies 13


recorded, resulting in a reduction of $5.492 million to SCE’s original 15

forecast (or a $3.193 million reduction to SCE revised forecast after 16

reclassifying $2.299 million for site preparation and planting as capital). 17

Q. Is this reasonable? 18

A. Mr. Cosman’s recommendation should be rejected. It has nothing to do 19

with the concerns he identifies in his testimony. Instead, it is based on Mr. 20

Cosman’s trend-line analysis (Cosman II). I explain above why the 21


Page 44 of 50

recommendations in that trend-line analysis are unreasonable. With 1

specific reference to this account, the 2010 increase for the remaining $1.67 2

million of Tehachapi environmental mitigation activity and the $3.835 3

million additional right-of-way maintenance are not reflected in the 2003 to 4

2007 historical data used in Mr. Cosman’s Appendix B analysis, so his 5

trend-line analysis would not capture this cost. 6

VI. SIX CITIES’ PROPOSED TRANSMISSION O&M ADJUSTMENTS 7

Q. Please explain Mr. Myers’ proposed adjustments to SCE’s 2010 ISO 8

O&M expense. 9

A. Mr. Myers proposes to reduce the TRTP 1-3A environmental mitigation in 10

FERC sub-account 571.300 by $2.299 million and the Bulk Power Training 11

costs in FERC sub-account 566.700 by $0.203 million. These reductions 12

are consistent with those proposed by FERC Staff witnesses, Ms. Miller 13

and Ms. Steffy, respectively, as discussed above. 14

Q. Does SCE agree with these reductions? 15

A. Yes. 16

VII. M-S-R/LADWP’S PROPOSED TRANSMISSION O&M 17

ADJUSTMENTS 18

Q. Does M-S-R/LADWP propose any adjustments to SCE’s proposed 19

transmission O&M expenses? 20

A. Yes. M-S-R/LADWP witness David Cohen proposed to reduce SCE’s 21

Account 566.500, 571.300, and 566.700 costs. Exhibit ML-1, pp. 42-49. 22


Page 45 of 50

Q. Please explain M-S-R/LADWP’s proposed adjustment to 2010 O&M 1

expense for FERC sub-account 566.500. 2

A. SCE’s Period I O&M expenses for Account 566.500 included the cost of 3

ten employees in the Generation Interconnection and Contract 4

Development (“GI&CD”) group. In its filing in this case, SCE projected 5

that it would add five additional employees to this group in 2009, and ten 6

more in 2010. 7

Mr. Cohen does not challenge SCE’s projection that it would add 8

five additional positions in 2009, but argues against including the cost of 9

ten new positions in 2010. He makes two arguments in support of his 10

position. First, he contends that SCE has not proven such an increase in 11

staffing is warranted given the size of SCE’s interconnection queue. 12

Second, he states that SCE’s requested increase should be denied because 13

the fees that SCE is charging interconnection customers are not sufficient to 14

cover the costs associated with that activity. 15

Q. Please respond to Mr. Cohen’s assertion that the ten additional 16

positions in the GI&CD group are not needed. 17

A. First, Mr. Cohen’s argument is misdirected. The issue here is whether 18

SCE’s projection that it will hire ten additional employees into this group in 19

2010 is reasonable, not whether the employees are needed. The distinction 20

is subtle, but important. Mr. Cohen’s assertion that SCE does not need the 21


Page 46 of 50

employees is relevant to whether it would be prudent for SCE to hire them, 1

not whether SCE reasonably projected that it would hire them, which is the 2

issue here. Mr. Cohen certainly has not demonstrated that it would be 3

imprudent for SCE to hire the ten additional employees that it projects. 4

And his failure to address whether SCE reasonably projected that it would 5

hire the additional employees makes his testimony irrelevant. 6

Second, Mr. Cohen’s assumptions about the level of SCE’s 7

generator interconnection activity are incorrect. SCE reasonably projected 8

that this activity would grow due in part to the growth of the renewable 9

generation industry in Southern California. Both the Commission and 10

Congress have encouraged the growth of the renewable generation industry, 11

and their encouragement has had a tremendous impact on the workload of 12

the utilities that have to deliver that generation from the power plants to the 13

load, including SCE. As of mid September 2010, there were 440 active 14

generator interconnection requests in SCE’s FERC-jurisdictional 15

interconnection queue. This represents a 175 percent increase in FERC-16

jurisdictional interconnections requests over the number in 2008 and a 144 17

percent increase over the 2009 level.4 The Commission wants these 18

4 As explained in SCE’s testimony in Exhibit SCE-4, as of mid-July 2009, there were

(Continued)


Page 47 of 50

applications processed in a timely manner, and can impose financial 1

penalties on transmission providers if they fail to do so. 2

SCE’s projected staff increases are well-supported, and proportional 3

to the increase in level of generation interconnection activity. During 2008, 4

GI&CD had ten employees, and SCE has projected that it would hire 5

fifteen more, bringing the size of the group in 2010 to twenty-five 6

employees. This represents a 150 percent increase, which is very much in 7

line with the anticipated growth in SCE’s interconnection queue. We 8

anticipate that California’s ambitious renewable portfolios standards goal of 9

33% will sustain the growth rate of interconnection requests. 10

Consequently, Mr. Cohen’s GI&CD adjustment should be rejected. 11

Q. Mr. Cohen identifies five “facts” in his testimony that he asserts shows 12

that SCE does not need additional staff in this group. Exhibit ML-1, 13

pp. 46-47. Please respond. 14

A. First, I would again note that Mr. Cohen does not challenge the 15

reasonableness of SCE’s projection that it will hire these ten additional 16

employees. Turning from that general observation, however, I fail to see 17

Continued from the previous page

180 active FERC-jurisdictional interconnection requests.


Page 48 of 50

how the statistics that Mr. Cohen identifies suggests that the additional 1

personnel are not needed or will not be hired, and he does not explain it, 2

either. As noted above, the statistics show that SCE has had a 175 percent 3

increase in interconnection requests from 2008 to 2010, and that level of 4

growth was anticipated when SCE made its filing in this case. Requesting 5

150 percent additional personnel is in line with that growth. Mr. Cohen’s 6

argument that 31 percent of SCE’s interconnection requests can be 7

processed more quickly than others, even if true, would apply to the 8

interconnection requests submitted in both 2008 and 2010, so that has no 9

effect on the need for additional personnel. And projecting the precise 10

number of interconnection requests that would be received in 2010, another 11

one of Mr. Cohen’s concerns, was not required in order to determine 12

increased staffing levels. SCE saw the sharply increasing number of 13

applications being submitted, and developed its cost projections in view of 14

that increase. 15

Q. Please respond to Mr. Cohen’s assertions regarding the fees that SCE 16

recovers from generation interconnection customers. 17

A. Mr. Cohen’s assertion that the fees SCE is charging interconnection 18

customers are not sufficient to cover SCE’s cost shows a lack of 19

understanding of the CAISO’s and SCE’s generator interconnection tariffs. 20

Under these Commission-approved tariffs, only certain costs of the study 21


Page 49 of 50

process are reimbursable from generators. For example, the costs that SCE 1

incurs in reviewing the interconnection customer’s application, in 2

participating in meetings with the generation interconnection customer 3

regarding the scope of its project, in attending meetings with the customer 4

to discuss the results of SCE’s interconnection studies, and in preparing 5

interconnection study agreements are generally reimbursable costs paid for 6

by the generator. Other costs such as pre-application meetings, contract 7

development and negotiation, time spent to resolve policy/procedural issues 8

and dispute resolution are not reimbursable. Yet, these activities are 9

essential in order to interconnect new generators and provide transmission 10

service. So while Mr. Cohen is correct that SCE does not collect sufficient 11

dollars to cover all of its costs in processing interconnection requests, his 12

quarrel is with the FERC, not SCE. 13

Q. Does Mr. Cohen contend that SCE is failing to recover the amount of 14

revenue that it is permitted to collect from FERC-jurisdictional 15

customers under the applicable tariffs? 16

A. No. He admitted in discovery that he is not making any such contention. 17

SCE-MSR/LADWP Q 27, Exhibit SCE-37, p. 156. In view of that 18

admission, his argument that SCE “does not collect sufficient revenues to 19

recover its costs of processing FERC-jurisdictional interconnection 20

requests” (Exhibit ML-1, p. 48, ll. 4-5) is empty. SCE is recovering from 21


Page 50 of 50

generation-interconnection customers the amounts that its FERC tariff 1

allows it to collect, and neither Mr. Cohen nor any other party to this 2

proceeding contends otherwise. 3

Q. Does Mr. Cohen propose other reductions to SCE’s 2010 ISO 4

Transmission O&M expense? 5

A. Yes. Consistent with FERC Staff and Six Cities, Mr. Cohen proposes the 6

same adjustments to FERC sub-accounts 571.300 and 566.700. As 7

discussed above, SCE agrees with those reductions. 8

Q. Does this conclude your testimony? 9

A. Yes, it does.10




)))

Dkt. No.

ER09-1534-001

DATA REQUEST RESPONSES IN SOUTHERN

CALIFORNIA EDISON COMPANY’S TO5 PROCEEDING (ER09-1534-001) CITED IN WITNESS DAVID S. BAKER PREPARED

REBUTTAL TESTIMONY

(EXHIBIT SCE-37)

OCTOBER 2010

SOUTHERN CALIFORNIA EDISON COMPANY Docket No. ER09-1534-000

Staff Response to the First Set of Litigation Data Requests of Southern California Edison Company

To Commission Trial Staff SCE-FERC Staff-53: On page 4, lines 14-15 of her direct testimony, Ms. Miller states that there is reason to believe that SCE’s estimate of its rent expense is inaccurate. Does Ms. Miller have an opinion on whether SCE’s estimate of its rent expense was reasonable when made? If so, please state that opinion, and provide the complete basis for it. Response: Subject to Staff’s objections and related discovery conferences with SCE, Staff provides the following response. Ms. Miller has no basis for determining that the rent expense was not reasonable when made. However, as explained in her testimony, subsequent events occurred which led Ms. Miller to adjust SCE’s rent expense. The Commission states, “to rely exclusively on the test year data unless it can be demonstrated that the estimates were either unreasonable when made or, if reasonable when made, subsequent events indicate that to use them as a basis for future projections would yield unreasonable results.” Southern California Edison Company, 8 FERC ¶ 61,099 at 61,375 (1979). SCE refers to this subsequent event in SCE’s response to FERC Staff-SCE-46 (d & e), when SCE states that “Invoices presented by the BLM and USFS were inconsistent with the rates defined in the Federal Register.” SCE also states that “SCE does not anticipate spending $11.4 million in 2010 due to the reasons discussed in response to part d. SCE anticipates 2010 line rents will be $9.0 million and will increase to $10.6 million in 2011.” Prepared by: Kerri H. Miller Date: September 21, 2010 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.

Dkt. No. ER09-1534-001 Exhibit SCE-37 Page 1 of 156

Southern California Edison Company TO5: 2010 Transmission Rate Case

Docket No. ER09-1534

STATE WATER PROJECT’S RESPONSES TO SOUTHERN CALIFORNIA EDISON COMPANY’S FIRST SET OF DATA REQUESTS

Prepared by David Marcus

September 16, 2010

Question SCE-SWP-041: At page 44, line 19 through page 45, line 4 of his direct testimony, Mr. Marcus recommends lowering SCE's TO5 2010 CAISO transmission O&M forecast by what Mr. Marcus contends was SCE's over-forecast of such expenses in TO4 for 2008 and 2009. Does Mr. Marcus contend that lowering SCE's forecast in this manner is consistent with FERC precedent? If so, please identify such precedent. Response to Question SCE-SWP-041: Mr. Marcus does not know, and thus can not identify whether or not there is precedent.






September 16, 2010

Question SCE-SWP-046: Is Mr. Marcus aware of any case in which the methodology that he used to determine SCE's operation and maintenance expenses in this case (adjusting the utility's forecast by the alleged percentage error in the utility's prior rate case forecasts) was adopted by a regulatory commission? If so, please identify each such case, and provide a copy of the regulatory commission order adopting the proposal. Response to Question SCE-SWP-046: No, Mr. Marcus is not aware of any case in which the methodology that he used to determine SCE's operation and maintenance expenses in this case was adopted by a regulatory commission.






September 16, 2010

Question SCE-SWP-044: Has Mr. Marcus ever prepared an operation and maintenance expense budget for an electric utility? If so please provide each such budget together with all supporting materials and testimony for such budget. Response to Question SCE-SWP-044: Subject to SWP’s September 9, 2010 objection, no, Mr. Marcus has not prepared an operation and maintenance expense budget for an electric utility.


31

Question 025

Has Mr. Cosman ever prepared a forecast of an electric utility’s operation and maintenance

costs? If so, please provide each such forecast together with all supporting materials and

testimony for such forecast.

Answer to Question 025

No, this is the first time. Please see Mr. Cosman’s testimony in Exhibit CPUC-1, section 3 –

Operations and Maintenance Expense.


Southern California Edison2010 Transmission Rate Case ER09-1534-000

DATA REQUEST SET CPUC-SCE-L004

To: CPUCPrepared by: David Baker

Title: ManagerDated: 04/14/2010

Received Date: 04/14/2010

Question 104:

Regarding FERC Sub-Account 560.100, please answer the following:a) SCE forecasts and increase of $7.564 million assigned to ISO and $6.919 of this amount

is for the Advanced Technology organization. Please provide the recorded costs for the Advanced Technology organization for the past five years. Please break down this amount between FERC and CPUC.

b) How many people work in The Advanced Technology organization and for how many years has this organization existed within SCE?

c) The Advanced Technology organization engages in activities that “deploy technologies that lower installation expenditures, reduce maintenance costs, improve safety, and help ensure that utility assets reach their expected service life.” ER09-1534-000, Exhibit SCE-4, p5, line 14-16. Please provide a cost benefit analysis that justifies the increase spending from 2008 to 2010 for this organization. Please provide documentation that supports and demonstrates that these programs “lower installation expenditures, reduce maintenance costs, improve safety, and help ensure that utility assets reach their expected service life.” Id.

d) Please provide the amount spent, for the past five years, on studying the impacts of integrating intermittent renewable generation and the potential solutions.

e) Of the amount associated with studying the impacts of integrating intermittent renewable generation, how much is for the acquisition of hardware or software tools?

f) SCE states that $.0648 million of the amount allocated to Advanced Technology is for “substation automation advancements, communication technologies integration, equipment and monitoring system evaluation, phasor measurement wide area measurement system…..and advanced applications for SCE’s satellite system.” ER09-1534-000, Exhibit SCE-4, p6, line 13 – 18. Please provide recorded costs for the past five years associated with these activities.

g) Please provide the recorded cost for the past five years associated with capital work write-offs.

h) Please explain how SCE calculated $.164 million for 2008 vacancies in 2009. Is this not a retroactive request? Please describe the position filled and salary in 2009.

i) Please provide a budget or supporting calculation showing how SCE calculated the $.255 million for contact employees. Please describe the increased workload mentioned.


Additionally, please provide the recorded cost for the past five years that SCE spend for contract employees.

j) Provide all work papers, budgets and supporting documents justifying the $.650 million estimate for various engineering software maintenance and licenses, and automation development projects. How much did SCE spend on these categories in the past five years? Additionally please itemize the software maintenance, licenses and automation development projects.

Response to Question 104:

a) SCE’s Advanced Technology organization was created in January 2009. Prior to the creation of the Advanced Technology organization, this work was performed by the Engineering Advancement organization within SCE’s Transmission and Distribution Business Unit; therefore, the expenditures attributed to the years 2005 – 2008 pertain to work performed by Engineering Advancement and those attributed to 2009 pertain to work performed by Advanced Technology. The table below includes cost recording to sub-account 560.100. 2009 is not yet available on a comparable basis.

($000)

b) Advanced Technologies became an organization on January 1, 2009. The AT organization currently has 66 employees.

c) The attachments include the estimates and descriptions for the $8.7 million of Advanced Technology increases, of which $6.9 million is allocated to ISO, and provide justification for the increased spending in 2010.

Attachments CPUC-SCE-L004 q104c.xls and CPUC-SCE-L004 q104c2.doc provide descriptions for $6.27 of the $8.7 million to study the impacts of integrating intermittent renewable generation and develop solutions to mitigate the impacts. Subsequent to SCE's TO5 filing, this estimate was revised to $6.479 million as reflected in the attachments, although SCE is not seeking to recover the additional dollars.

CPUC-SCE-L004 q104c1.doc provides descriptions for the $2.432 million of transmission technologies advancements in substation automation, communications integration, equipment monitoring and system evaluation, synchrophasor measurement systems, engineering safety into equipment design and deployment, and advanced applications for SCE’s satellite system.

d) Advanced Technology as a distinct SCE organization has only existed since January 1, 2009. Most of SCE’s work in studying impacts and solutions for intermittent renewable generation began concurrently with the formation of Advanced Technology in 2009. In addition to 2009 Advanced Technology initiatives, some renewables efforts were started by its predecessor organizations in 2008


and carried over into the new organization in 2009; therefore, SCE’s response to this question only focuses on 2008 and 2009 activities. The total amount spent by Advanced Technology and its predecessor organizations during the years 2008 and 2009 for the purpose of studying the impacts of integrating intermittent renewable generation and potential solutions was approximately $2.17 million. These costs are inclusive of engineering consultant/contractor expenditures, equipment and tools costs, and estimated SCE labor costs.

e) All acquisitions of hardware or software tools for studying the impacts of intermittent renewable generation are capitalized.

f) SCE’s Advanced Technology organization was created in January 2009. At that time, the organization instituted new accounts to track expenditures by activity. Prior to the creation of Advanced Technology, SCE tracked these expenditures at the FERC account level; therefore, only 2009 amounts are provided in this response. These are unadjusted preliminary numbers for sub-account 560.100.

ACTIVITY 2009Substation Automation Advancements 113,054Integration of Communication Technologies for

T&D Operations 251,629

Equipment & Monitoring Systems Evaluation 2,059,029Phasor Measurement Wide Area Measurement

System 538,149

Advanced Transmission Technology Applications 277,045

Engineering Safety Into Equipment Design and Deployment 31,726

Advanced Applications for USAT SatCom Satellite System 348,432

TOTAL $3,619,064

g) See attached Excel spreadsheet CPUC-SCE-L004 Q. 104g response.xls.

h) SCE's Engineering organization employees charge their time to capital, overhead, and O&M accounts. For example, an Engineer spends some time working on a capital project and other time on an O&M project. Of the 253 positions in this organization in 2009, the portion of Engineering labor recording to O&M was forecast to be equivalent to 51 FTEs in both 2009 and 2010. The $.164 million O&M increase is the difference between the 2008 recorded dollars, which only equated to approximately 49 FTEs because of vacancies, and the forecasted cost for 51 FTEs. The vacancies were not filled in 2009, but are forecast to be filled in 2010.

i) $255,000 is for updating existing substation panel labeling standards.

Contract Spending


j) The following is a list of the software and automation development increases (in thousands).

Software Maintenance and Licensing- $163 - Powerline Systems Inc. new licenses and upgrades to existing licenses- $30 - DocsOpen CADDE new licenses- $87 - Autodesk Civil 3D new licenses plus annual maintenance- $70 - AutoCAD new licenses

Automation Development- $150 - General Networks Corporation Substation Engineering Modeling Tool (SEMT) - $150 - Bow Networks Maintenance contract

This is an increase to prior year spending reflected in the table below.


2010 FERC PROJECTS

PROJECT NAME PROJECT DESCRIPTION Non-SCE Labor 2010 Non-SCE Labor 2011 Total Non-SCE Labor 2010-2011

PROJECT DURATION

Voltage VAR Control at Devers and Valley Substations

Devers substation has multiple VAR control devices: shunt reactors, static VAR controllers, and shunt capacitors at 500 kV, 230 kV, and 115 kV; and the AA banks at Devers have load tap chargers. This program will coordinate these different devices so they do not counter-act or negatively impact each other. PMU technology will be used to obtain high-speed inputs from various devices, a valuable tool for coordinating controls.

$245,000 $294,000 $539,000 2 YEARS

Frequency Response and Dynamic Power Balancing in Wind and Solar Generation

Study the load balancing and frequency regulation impacts of renewable generation on the CAISO controlled transmission system. A significant component of this research effort is to develop a platform to fully analyze this condition and test mitigation strategies to ensure reliable service to SCE customers while maintaining full compliance with mandatory NERC and WECC reliability standards.

$343,000 $343,000 1 YEAR

Real-Time Power System Security Margin Identification

Using real-time PMU data, develop an effective method (faster than SCADA) for identifying the security margin for a wide-area situational awareness system. Verify that by measuring the local voltage and current using phasors, near real-time voltage instability analysis can be performed resulting in greater reliability and grid stability. PMU will also make ATC calculations faster to meet present and future utility operational security requirements.

$490,000 $980,000 $1,470,000 2 YEARS

Very Short-Time Forecast Technology in High Renewable Penetration Power System Operation

Investigate an effective methord for forecasting 5-minute ahead tie line power, bus voltage, renewable generation, etc. for wide-area situational awareness systems. $367,500 $735,000 $1,102,500 2 YEARS

Synchronized Phasor Measurement and Grid Stability Assessment and Control

Develop advanced tools to measure transmission system stress, provide visualization to system operators, and automatically take the corrective action to maintain grid stability. $245,000 $735,000 $980,000 2 YEARS

Real-Time Stability Mitigation In High Renewable Penetration

Develop the next generation of RAS for the integration of the high penetration of renewable generation. A U.S. patent is pending. Field testing is anticipated. $367,500 $490,000 $857,500 2 YEARS

EPRI 39.004 - Measurement-Based Voltage Stability Monitoring and Control

Given the limitations of VSA programs, this project will use data from PMU installed at an SCE substation to calculate voltage stability margins. The intent is to investigate various methodologies for calculating voltage stability margins in real-time at the substation level. These calculated voltage stability margins can be sent to help system operators monitor system voltage stability and to trigger the control device to prevent fast voltage collapse. This project is associated with the proposed Real-Time Power System Security Margin Identification project.

$80,000 $80,000 $160,000 2 YEARS

EPRI 173 - Integration of Variable Generation and Controllable Loads

Study ways to resolve issues caused by increased integration of renewable energy resources and adoption of distributed generation and demand-side resources. The 2010 projects are: Grid Performance and Modeling of Variable Generation and Evolving Power System Resources, Determination of Optimal Reserve with Consideration of Variable Generation and Controllable Loads, Advanced Frequency Control for High Variable Generation Systems and Evolving System Resources, and Advanced Planning Tools to Study the Impact of Variable Generation and Controllable Loads.

$250,000 $250,000 $500,000 2 YEARS

Dynamic Modeling of Existing Solar and Wind Generation Technologies on the Bulk Power System

Develop electromagnetic transient (EMTP) type models for existing and projected wind and solar generation technologies and farms that SCE expects to have connected to its transmission grid. EMTP-type models are needed to facilitate effective and reliable integration of renewable resources, but are not yet available to SCE planners.

$294,000 $441,000 $735,000 2 YEARS

Optimal Large-Scale Renewable Generation and Energy Storage Integration

Compare several integrated renewable generation and storage solutions to evaluate the most optimal resource plan to minimize costs while complying with NERC reliability standards. $318,500 $367,500 $686,000 2 YEARS

Inverter Testing and Modeling for Transmission Impact Studies

Test small commercial solar PV inverters to assess their behavior during voltage and frequency oscillations and analyze the test data for developing Solar PV Inverter models to evaluate their impact on the grid (especially at high penetration levels). Validate the newly developed models with actual test and field data to perform transmission system impact studies at 0, 5 and 10 year marks . These additonal tests will further validate the inverter models developed under Dynamic Modeling and Solar PV Impact Projects. In addition, the project will test, model and validate other DC technologies (i.e. batteries, fuel cell).

$245,000 $490,000 $735,000 2 YEARS

Southern California Edison CPUC-SCE-L004 q104(c) Page 1


2010 FERC PROJECTS

RTDS Large Model of the SCE 230 kV and 500 kV System Including All System Generation

Develop a complete model of SCE’s 230 kV and 500 kV system and its generation, including the turbine-generator models and respective controls (exciter, governors and power system stabilizers). The model will include all the FACTS devices on the SCE system with a level of detail based on the RTDS available memory (RACKS). The system will capture any inter-area oscillations that exist between the SCE system and its neighboring utilities to evaluate mitigating technologies to help in the damping of system oscillations and for fine-tuning the relay protection's out-of-step conditions setting. The project will help optimize available RTDS resources to develop a model that addresses the many different scenarios to be simulated and assessed.

$269,500 $269,500 1 YEAR

PROJECT NAME PROJECT DESCRIPTION Non-SCE Labor 2010

Non-SCE Labor 2011

Total Non-SCE Labor 2010-2011

PROJECT DURATION

Real Time Analysis of SCE's System with High Levels of Renewable Penetration

Utilize real-time digital simulators (RTDS) to plan and deploy additional control and protection devices on the SCE system as renewable integration surpasses 20% penitration levels. $367,500 $490,000 $857,500 2 YEARS

High Voltage DC Event Modeling and HVDC System Modulation

Study past system disturbances on the PDCI to investigate oscillations specifically caused by the HVDC line. It is very important to monitor, analyze and understand such events to prevent future occurramces, or provide for quick mitigation. This project will use an RTDS platform to analyze these types of events and investigate solutions such as HVDC modulation for enhancing the performance of the PDCI and PACI systems.

$245,000 $686,000 $931,000 2 YEARS

Innovative Transmission Solutions for Accelerating Wind Power Integration in the U.S.

Develop a master plan for the entire SCE transmission system to identify transmission, energy storage and alternative technologies required to handle up to 40% renewable penetration by 2010. Based upon renewable resource location maps, SCE's system is expected to integrate much higher levels of renewable generation than those required by California's RPS.

$490,000 $367,500 $857,500 2 YEARS

Feasibility of Online Condition-Based Maintenance (CBM) of Geographically Dispersed Renewable Resources (Quanta)

With the large proliferation of greater amounts of geographically dispersed and remotely located renewables equipment, (e.g., wind turbines and solar PV panels, inverters, LVRTs) comes the need for equipment that works at peak efficiency and availability. Effective maintenance is critical (e.g., cleaning dust off solar arrays). Defining an effective maintenance strategy requires assessment of many parameters such as asset criticality, failure history, current maintenance intervals, MTBF, and cost of alternatives. In order to establish an optimal maintenance strategy for dispersed renewable assets, requires evaluation of alternatives including infrastructure requirements for data collection, costs and benefits, and recommended maintenance strategies including condition-based maintenance (CBM) for each type of asset. This investigation will produce a comprehensive assessment of the feasibility, cost and benefits of different maintenance strategies for the dispersed renewable asset classes (e.g. wind, solar). This project will help SCE meet the RPS goals.

$416,500 $416,500 9 months

Energy Storage Mix Optimization - Centralized and Decentralized

Survey energy storage technologies and assess their applicability to SCE's transmission system based on the proposed location, centralized (local) or decentralized (remote), of variable generation resources. $612,500 $612,500 1 YEAR

Master Transmission Plan to Integrate Renewables Under RPS Framework (Quanta)

Identify and evaluate the transmission, energy storage and alternative technologies necessary to handle the integration of greater amounts of renewable generation to be added to the SCE system in the next decade. To ensure the addition of new technologies meet all applicable reliability criteria the team will conduct thermal, voltage ride-through, voltage stability, short circuit, power quality, and transient stability analyses for each of the solutions considered in the study. The drawbacks and benefits of each design for each alternative will be documented and a preferred master plan identified. A modular approach will be taken through 2020 that allows for incremental system evaluations and improvements as more generation comes online.This project will provide a forward-looking plan for the new technologies SCE needs to accomomodate the RPS scenario. Bigger than technology evaluation, this will allow SCE to leverage the results of Dynamic Modeling and RTDS projects as well as insights garnered from the Solar PV Impact Study project.

$833,000 $833,000 1 YEAR

TOTALS $6,479,500 $6,406,000 $12,885,500

Southern California Edison CPUC-SCE-L004 q104(c) Page 2


CPUC-SCE-L004 Q104 c

• Substation Automation Advancements

The Substation Automation System, (SAS), project was begun in 1995 for the purpose of improving operational efficiency, reliability and replacement of aging infrastructure. The 220 plus SAS substations, that have since been commissioned, are now providing benefits which include automatic load restoration, remote and local control and enhanced monitoring. These benefits supported the reduction of substation personnel, while increasing the overall level of service.

The additional information now available to operators, field crews, and engineers has enhanced the development and planning of the electric system.1 Additionally, this information has contributed towards maintaining our system reliability, determining where and when problems occur, and providing the information necessary to perform a detailed post-mortem event analysis.

Demands on the system continue to increase while technological advancements become available at an increasing pace. Collaborative efforts initiated with distribution automation will further increase and enhance this system’s information, control and automation capabilities.

Background: Substation automation, communications and control technology is advancing at an ever-increasing pace and creating opportunities for new utility applications. Intelligent electronic devices (IEDs), such as relays, programmable logic controllers (PLC’s) and gateways, and advanced sensor technologies that capture temperature, weather data, and equipment operating status in real-time are now more capable, reliable, and interoperable with current field equipment. Improved communication and control technologies in recent years have also contributed to enabling utilities to monitor and control grid operations in ways not possible more than a decade ago.

For instance, open system integration combined with necessary system security allows evaluation of communications options ranging from secure dedicated channel DNP 3.0 for supervisory control and data acquisition (SCADA), Virtual Private Network (VPN), wireless technologies, and Broadband over Power Line (BPL) to public communication networks.

In order to be in a position to support the addition of new devices or replace and upgrade existing technologies for next generation substation automation, this program would provide for test, evaluation, and recommendation of new applications and devices prior to deployment. Collaborative work to efficiently integrate the Substation Automation and Distribution Automation advancements is an outgrowth of this initiative.

1 SAS information includes: voltage, current, power, maintenance information, temperatures, fault records, combustible gasses, breaker speed, relay operations time, etc.


Project Description:

This project will provide funding needed to transition the existing substation automation system to the next generation of products and technologies. A major objective of this effort is to optimally integrate SCE required protective devices, other IEDs, and substation equipment into one intelligent monitoring and control system. New substation technologies will be evaluated, tested and integrated, while enabling operators and engineers to access information/intelligence on a real-time basis. Associated with this work will be the evaluation and development of software tools to allow the integration of these newer technologies into existing systems. The scope of this automation effort will augment the existing SAS platform and will address expansion plans toward system goals supporting Operations, Maintenance, and Engineering.

Evaluation of new components, systems, communication architectures and protocols, as applied to Substation Automation Systems, will be compared against the SA-2 prototype, which was developed for Edison’s 230kV Viejo Substation. New sensing, monitoring and control technologies (e.g. transformers, battery chargers, weather stations, distribution equipment temperature measurements, and distance to fault information) will be improved and better integrated into utility operations. Evaluation and recommendation of potential benefits from integration of Distribution System Automation applications via the substation as a hub will promote development that will benefit both distribution and substation systems. Technologies such as the IEC 61850 Protocol Standard and IED to IED communications capabilities via Generic Object Oriented Substation Event (GOOSE) Messaging are areas that will be evaluated. The annual cost of this program is estimated to be: Substation Automation Advancements Total SCE FTE

(Eng -4) Contract

FTE Materials and Service

Contracts Personnel and Equipment 2 1 1 Test and Instrumentation

Forecast ($000) 326 111 125 90 System enhancement and substation automation components, communications and software advancements, successfully integrated into our substation automation system, can lower installation costs, while maintaining reliability and operational efficiencies. Additionally, efforts toward standardization of components, communications, programs, procedures, databases and integration methods can reduce workload and system complexity. Additional information, properly integrated into standardized operations and maintenance tools, will initiate and/or support efficient maintenance procedures. Evaluated technologies allowing for remote IED and IEE access and remote trouble shooting may significantly reduce technician drive times to remote substations.

• Integration of Communication Technologies for T&D Operations

Background The communications industry is changing rapidly and many new technologies are becoming available for utility use. These communications options range from use of


public networks (data over cell system and pagers) to the use of private systems (radio, satellite, and power line carrier). In addition to the communications technologies themselves, there is a continuing push to use standard protocols to simplify the communications process. This program is designed to determine how these new technologies might be best integrated into the transmission and distribution system for grid control and monitoring. Some technologies that might be integrated include satellite, high-speed power line carrier, gateway devices for field equipment, and standardized communications protocols. Project Description This project will investigate new and emerging communications technologies and determine which ones might be most useful for transmission and distribution operations. This investigation will include both public and private networks. New developments in Wi-Fi and Wi-Max will also be investigated to see how they might be leveraged for use by SCE. Standard communication protocols will be evaluated to determine their value to SCE and our customers. SCE is starting to use the GOOSE messaging portion of the IEC 61850 standard for substation status communications. Information from this project will be shared with the Customer Service Business Unit to determine if any of the technologies can also be used for automated meter reading or customer load management. Likewise, any communications technology adopted by the Customer Service Business Unit for metering or load control will be investigated to see how it might be used for T&D operations. A differentiation will be made between systems that are functional only when power is present in the power lines and systems that can be used for control to restore power during outages.

As SCE increasingly relies on sophisticated communications technologies, securing these channels becomes more important. This project will review available security technologies and recommend, which ones should be used with the various communications technologies. In addition, gateway devices will be investigated to provide secured access to substation equipment. Once promising technologies or protocols are identified, a pilot installation will be designed and implemented. Those technologies that are successful in the pilot installations may be turned over for widespread installation. Part of this installation process would be training of SCE operations personnel and planning for deployment. These steps would be taken in cooperation with the departments that will be responsible for long-term system operations and maintenance.


Technologies that will be evaluated include satellite, broadband over power line, mesh radio networks, Wi-Fi, Wi-Max and public cell/pager systems. Protocols that will be evaluated include, among others, IEC 61850 and DNP over IP. Any technologies that are used by SCE automated meter reading or load management will also be evaluated for distribution system monitoring. The annual cost of this program is estimated to be:

Integration of Communication Technologies for T&D Operations

Total

SCE FTE (Eng 4 at 100% /

Eng 1 at 50%)

Contract FTE

Materials and Service Contracts

Personnel and Equipment 2.5 1.5 1 Pilot Equipment

Forecast ($000) 369 144 125 100 The increased use of advanced communications capabilities will help SCE maintain reliability, increase safety, and improve operational efficiency. With more information on the behavior of the electrical equipment, more cost-effective maintenance procedures can be implemented. Some of the technologies used on the T&D system will also have applications for automated meter reading and customer load management communications.

• Equipment & Monitoring Systems Evaluation

This program provides a platform for evaluating apparatus inside the substation. Each year, new, high- potential equipment (e.g., transformers, circuit breakers, insulators, etc.) become commercially available. This program provides for the evaluation of implementation feasibility and technical readiness of these new products to determine whether to deploy them. Associated with this evaluation is the evaluation and testing of hardware and the related systems needed to diagnose potential failure modes or weak components on the existing electric grid. Problems, like SCE’s recent issue with cracks developing in epoxy barrier board between the tap changer and the main tank on transformers, would be addressed by this program. These defects did lead to catastrophic failures (e.g. Eldorado and Mira Loma AA Bank failures). The annual cost of this program is estimated to be: Equipment & Monitoring Systems Evaluation

Total SCE FTE (Eng 3)

Contract FTE


Personnel and equipment 1.5 0.5 1 Equipment & Tools

Forecast ($000) 560 55 125 380

Funding would be used in part to develop a test process/hardware to evaluate transformers with similar concerns. Coupled with this would be an evaluation of new monitoring equipment to assist with identifying and diagnosing potential problems before they occur. This project could save tens of millions of dollars in restoration-related costs from the avoidance of one catastrophic failure.


• Phasor Measurement Wide Area Measurement System

Background: The growing complexity of the interconnected electric grids is creating challenges in their operations. Events in far remote area can cause major system disturbances and blackouts in other remote areas. This was recently witnessed in the Northeast blackout on August 14, 2003 and earlier in the system disturbance of August 10, 1996 on the west coast. It is becoming very important to monitor the large grids using Wide Area Measurement systems. The Phasor Measurement Technology is a promising technology which can enable real-time monitoring and reduce the probability of such major disturbances.

SCE has been conducting RD&D on this technology since 1995 and has a very good RD&D system, monitoring its grid and exchanging data with Bonneville Power Administration and the California Independent System Operator. Before 2009, SCE expects to have data from all interconnecting utilities. Project Description: This project deploys the results of SCE’s long-term RD&D effort on phasor measurement technologies for the post event analysis of grid disturbances and real-time monitoring and assessment of the electric grid. As a necessary step to full integration into the energy management systems and control room operations, SCE will create and staff a “Situational Awareness Room” to provide engineering information to control room operators during and subsequent to system disturbances. This will also provide a means to train operators on the phasor measurement technologies and their use. The annual cost of this program is estimated to be: Phasor Measurement Wide-Area Measurement System


Contract FTE


Personnel and Equipment 2.0 1.0 1.0 Equipment, Cables and

Communications Forecast ($000) 296 111 125 60 As phasor technologies are further developed in the RD&D program, they will be incorporated into operations via this project. This project will also enable SCE to take advantage of many of the benefits associated with phasor measurement technologies during initial capital deployment phases. The application of this technology will enable operators to operate the grid at higher transmission power levels and will provide an increased level of grid reliability that would help prevent a grid collapse. It will enhance the ability to restore power quickly in the event of such a collapse.

• Advanced Transmission Technology Applications

This program aims to identify commercially-available advanced transmission technologies and determine the feasibility of deploying them on the transmission system. This effort will make use of highly-leveraged RD&D projects conducted internally and external organizations, like the Department of Energy, the California Energy Commission and the Electric Power Research Institute to maintain power


transfer capability, efficiency and reliability of the electric grid. The following are areas in which SCE will focus during the 2009:

1. Flexible AC Transmission Systems (FACTS) – This project will evaluate the application of new FACTS technologies to determine the feasibility of using such advancements on the transmission system.

2. Advanced Conductors – This project will evaluate the deployment of new advanced conductors (e.g. low-sag composite conductors, and high temperature super conducting cables) to determine the feasibility of using such advancements on the transmission system. By reconductoring the old towers with new conductor technologies, SCE may be able increase the capacity of the line without having to acquire new rights of way.

3. Advanced System Components – New designs and high-temperature superconducting technologies are improving transmission system components, like fault current limiters and transformers. Although some of these technologies remain in the development and demonstration phases of RD&D, others are commercial available. This project will evaluate the feasibility of deploying these new devices on the transmission system. The annual cost of this program is estimated to be:

Advanced Transmission Technology Applications


Contract FTE


Personnel and Equipment 1.0 1.0 0.0 Test Results, Equipment,

Information Access Forecast ($000) 386 136 0.0 250 The increased use of advanced transmission technologies will help SCE maintain reliability and power quality, while increasing transfer capabilities. These projects would be leveraged with RD&D completed internally and with external partners (e.g. CEC, DOE, EPRI, etc).

• Engineering Safety into Equipment Design and Deployment

This program was created to integrate safety concepts into engineering work products at initial design phase. This area will focus on advancing the level of field safety through innovative engineering solutions associated with electric utility transmission and substation related issues (e.g. controls, equipment, structures, and work practices). This program will develop and document new technical standards and create a resource for other organizations and multidiscipline teams as needed. Distribution activities will be charged to FERC account 580.100. The annual cost of this program is estimated to be:

Engineering Safety into Equipment Design and Deployment

Total SCE FTE

(Eng 4 at 50%/ Eng 2 at 50% )

Contract FTE


Personnel and equipment 1.0 1.0 0.0 Instrumentation, test

Forecast ($000) 197 97 0 100


The funding of this project will enable SCE to proactively address safety, thereby reducing accidents, injuries and their associated costs.

• Advanced Applications for USAT SatCom Satellite System

Background SCE’s proprietary USAT satellite communication system is currently used for substation Supervisory Control and Data Acquisition (SCADA) at over 220 substation remote terminal units. In addition to the SCADA application, SCE’s SatCom team has developed and implemented several other applications for the USAT system, including SAS automation, weather station monitoring, and Coordinated Trip Substation Relay Logic. SCE’s 50,000 square mile service territory requires intensive remote communication, and SCE’s USAT program is uniquely available to provide low-cost solutions to Edison’s communication needs. Project Description This project will investigate and pilot new applications for SCE’s USAT satellite communication technology. The following USAT applications would be evaluated:

1. Transfer Trip Application Using Schweitzer Relays: To determine the

feasibility of using the USAT system for Rule 21 anti-islanding transfer trip applications, it is proposed that a demonstration system be installed at Mira Loma Substation. Two USAT terminals at Mira Loma can act as the two ends of a complete USAT transfer trip system. The demonstration system will be built around Schweitzer Engineering Labs (SEL) relays to act as the transfer trip sending and receiving (tripping) relays.

2. USAT for Automated Meter Interface (AMI)/Metering: Develop USAT for use with AMI using back-haul radio links to data collectors. Develop USAT for use with ISO Metering.

3. USAT for video for Infrastructure Security Applications: Develop Infrastructure security application to provide event-driven alarms and video using USAT at remote SCE substations and facilities.

4. USAT for Distribution Pole top Applications: Develop USAT for Distribution pole-top applications through the energy management system.

5. USAT for Voice Communication: Deploy USAT solutions to replace the aging HSAT communications system at remote substations for phone/voice communications and incorporating video and file transfer capabilities.

6. USAT for Data Beyond Scada Communications: Utilize USAT for file transfer and data collection at remote locations and substations to provide data beyond SCADA to operations and engineering.

7. USAT for Demand Response: Utilize USAT for interface with energy management systems to enable load control for demand response.


Those technologies that are successful in the pilot installations will be turned over for widespread installation. The annual cost of this program is estimated to be:

Advanced Applications for USAT SatCom Satellite System


Contract FTE/study


Personnel and equipment 1.0 1.0 0.0 Instrumentation and Test

Forecast ($000) 297 97 0.0 200 USAT SatCom offers a competitive, low-cost solution for monitoring and control applications, and will allow SCE to automate equipment that would be prohibitively expensive to automate using standard communication systems, such as leased lines or fiber optic line installation. The increased use of USAT satellite communications can help SCE maintain reliability and efficiency, increase safety, and avoid the higher costs associated with other forms of communication.


FINAL 2010 FERC Rate Case Workpaper 560.100_Advanced_Technology_11-02-09_dac 1

Subaccount 560.100 – Operation Engineering (Transmission) Advanced Technology

SCE’s Advanced Technology organization is responsible for identifying, evaluating and

integrating advanced technologies into the design, construction, operations, and maintenance

aspects of the transmission and distribution systems. Increased Advanced Technology activity,

accounts for $8.702 million of the total increase and $6.919 million of the Independent System

Operator (ISO) increase. This program focuses on deploying technologies that lower installation

expenditures, reduce maintenance costs, improve safety, and help ensure that utility assets reach

their expected useful service life.

Advanced Technology projects play an integral role in the advancement of a secure and

reliable smart grid, and the integration of clean, sustainable renewable energy resources. Of the

$6.270 million increase Advanced Technology proposes, 100 percent is assigned to the ISO and is

for studying the impacts of integrating intermittent renewable generation onto the system and

developing solutions. California’s Renewables Portfolio Standard (RPS) presently requires retail

sellers of electricity to service 20 percent of their load with renewable energy by 2010 and the

November 17, 2008 Executive Order S-14-08 issued by Governor Schwarzenegger established a

target of 33 percent by 2020. It is broadly recognized that the integration of higher volumes of

renewable resources on to the grid, particularly intermittent resources such as wind and solar,

presents unique challenges to operational performance and system reliability. Relevant issues

include developing an understanding of how significant increases in intermittent generation

resources will affect operating reserves, load following capabilities, and resource adequacy

requirements. SCE will utilize a mix of internally managed studies and broader work with external

entities such as the California Energy Commission (CEC) and the Electric Power Research

Institute (EPRI) to address these issues.

The additional $2.432 million increase Advanced Technology requires has $0.648 million

assigned to the ISO for transmission technologies advancements in substation automation,

communications integration, equipment monitoring and system evaluation, synchrophasor

measurement systems, engineering safety into equipment design and deployment, and advanced

applications for SCE’s satellite system. These types of projects support or include many of the

technologies necessary for a smart grid.



SCE’s Advanced Technologies Organization and its Engineering Advancement division

plan on pursuing these objectives by leveraging internal and external research, development and

demonstration projects, new vendor advancements, and technologies utilized in other industries.

This effort is critical to addressing challenges such as replacing SCE’s outdated infrastructure with

a more robust and environmentally responsible electric grid, recruiting and training the workforce

that will take the utility into the future, while continuing to provide the highest level of service to

its customers.

SCE believes the research, development and demonstration projects it plans for 2010 and

2011 will bring about vast improvements in productivity, but expects any productivity gains to be

offset by the need to increase its workload to accommodate the growing demand for electricity and

greater loads on the utility’s aging infrastructure. Investing in improvements to the SCE grid now,

will ultimately benefit the utility’s customer by decelerating future cost increases.

Proposed Advanced Technology Projects

The project scopes presented here, provide descriptions and projected cost estimates for

SCE’s 2010-2011 Advanced Technology program within five primary areas of focus:

• Synchrophasor measurement

• Dynamic Modeling

• Real-Time Digital Simulation Studies

• Operational Strategy and Tool Development

• Power System Planning

Cost estimates for contracted labor are based on calculations using weighted hourly rates ($117) for contracted engineers, programmers, analysts, consultants, and project managers.



Voltage and VAR Control Project at Devers and Valley Substations Total 2010 incremental costs: $245,000 Project Description SCE plans on conducting research to study the development of a voltage and VAR control system at Devers substation based on phasor measurement technology. Devers substation utilizes multiple VAR control devices such as: shunt reactors, static VAR controllers, and shunt capacitors at 500 kV, 230 kV, and 115 kV. Additionally, the transformer (AA) banks at Devers have load tap chargers. The objective of this program is to coordinate these different devices so they do not counter-act each other. This will be accomplished using phasor measurement technology to obtain high-speed data from the various devices required for coordination and control. The goals for this project are:

• Engineering, design and installation of VAR/power flow monitoring system • Development of the voltage/VAR controlling program • Hardware selection and procurement • System coding and lab testing • Installing the system at Devers substation

Tasks Task 1

• Engineer, design and installation of VAR/power flow monitoring system. Data will be collected using the capabilities of the phasor measurement systems at Devers and Valley substations. The phasor quantities as well as device status will be monitored.

• Integrate data already available at Devers substation from PMU, SCADA, HMI, SER,

DFRs and other devices through a gateway. Automation Group will be in charge of this task connecting the above-mentioned devices and those available for the new equipment using a gateway with inputs for different protocols and providing the proper output to be fed to the intelligent system.

• Use the Devers PMU digital channels to provide a permanent and complete record of the

operation of line reactors, SVC, shunt capacitors, transmission lines, transformers, LTC, and other necessary equipment to control the voltage at Devers substation and manage the necessary VAR according to system operations protocol.

Task 2

• Develop voltage/VAR controlling real-time monitoring software capable of using data from the various devices for displaying key system information to system operators. The software will allow on-line viewing of the voltage magnitude, phase angle for the north



side of the Western Electricity Coordinating Council (WECC) system, and power margin toward voltage instability limits. Color coding will be used to improve operator monitoring of activities and their proximity to operating limits. The system will be developed and tested on the system model to ensure it works properly. Some recorded events from past disturbances will be used to test and validate the system under various operating control strategies.

Task 3

• Select and procure hardware. The master controller could be a phasor measurement system, a phasor data concentrator type device or a real-time controller type device with multiple input/output and processing capabilities. The inputs will simulate actual system flows, status, etc. The outputs will be the commands to the VAR controlling devices. For devices such as the static VAR controller, the controller will be used to obtain desired VAR output and voltage hold limits. The simulations will determine precise control strategies.

Task 4

• Develop software to create an intelligent system for managing reactive power, supporting the voltage at Devers substation, and ensuring stability of the WECC system. Continuous calculation of power margin toward voltage instability limit will be part of the study. The system should act as an automatic controller of the reactive power at Devers substation. Extensive off-line system analysis will be conducted to determine what remedial actions are required to prevent cascading failures (i.e. generation/load control, etc.) System coding and lab testing will be used to implement the control strategies. Part of the testing will be performed in a suitable lab using precise and detailed Valley-Devers system models.

Task 5

• Install the tested system at Devers substation. A high-speed communication channel will need to be built connecting Devers to Valley substation, enabling coordination between these two substations due to their close proximity. The system will remain in monitoring mode for six months to ensure it operates properly.

Deliverables

• Engineering design of the VAR/power flow monitoring system • voltage/VAR real-time monitoring software source code • Procurement of the hardware with the real-time master control capability • Intelligent system software source code to manage the reactive power and support the

voltage at Devers substation ensuring WECC system stability. All developed software should include clear comments on the statements to allow an engineer to follow the program. All developed software must be user-configurable in such a way that it can be applied to another station with different equipment, requirements and resources. In other words, the inputs to the program must provide all necessary data to allow the program to work properly with all defined devices, resources and equations.

• User manuals for all delivered programs.



• Documentation with several examples of the use of the programs and covering all the functionalities and options of the programs.

• Develop and schedule training sessions to train SCE engineers how to use the software with special emphasis on the main capabilities of the software.

• System installation at Devers substation Project Cost/Funding Breakdown

Activity Start Contract Labor Costs

Task 1 - Engineering, design and installation of VAR/power flow monitoring system 1/4/2010 $49,000

Task 2 - Development of the Voltage/VAR controlling program 2/1/2010 $122,500

Task 3 – Hardware selection and procurement 8/1/2010 $73,500

Task 4 - System coding and lab testing 1/3/2011 $245,000

Task 5 – System installation at Devers substation 7/1/2011 $49,000

TOTAL $539,000



Frequency Response and Dynamic Power Balancing in Wind and Solar Generation Total 2010 incremental costs: $343,000 Background Large-scale deployment of renewable resources is expected to greatly impact the operational characteristics of the electric grid. Specific challenges such as load-balancing and area control error (ACE)/frequency regulation have been attributed to the increased integration of renewable energy resources. How these conditions are handled is regulated according to performance and reliability standards established by the Western Electric Coordinating Council (WECC) and the North American Electric Reliability Council (NERC). Compliance with these standards is mandatory and non-compliance subject to penalty. Project Description Southern California Edison (SCE) plans on conducting research to study how renewable generation on the California Independent System Operator (ISO) controlled transmission system will impact load-balancing and ACE/frequency regulation. A significant component of this research effort is to develop a platform capable of analyzing load-balancing and ACE conditions, and testing mitigation strategies to ensure delivery of reliable service to SCE’s customers and full compliance with NERC and WECC Reliability Standards. This project will use a real-time digital simulation (RTDS) platform as its primary analysis tool to study operational conditions and test mitigation strategies. The use of SCE’s Dispatcher Training Simulator (DTS) as an alternative platform is also being considered. The goals for achieving these efforts are:

• Develop ramp-rate requirements using six solar and wind production profile scenarios. Scenarios/cases to be considered are:

1) 20% reference 2) 33% reference 3) 33% high wind 4) 33% distributed generation 5) 33% high out-of-state delivered 6) All gas

• Study frequency regulation for the same six profile scenarios.

• Develop spinning reserve requirement for the six profile scenarios. • Develop mitigation strategies necessary to ensure appropriate load balancing and

ACE/frequency regulation.



Tasks Task 1: Project planning and data gathering to determine regulating and non-regulating generator operating factors, including their governing systems and prime mover characteristics. This task is being done in 2009. Task 2: Develop composite load for the study horizon (year 2020). This task is being done in 2009. Task 3: Conduct a preliminary assessment of power balancing and regulating capabilities. This task is being done in 2009. Task 4: Perform analysis and document results. Task 5: Establish specifications for power balancing and regulating capabilities. Deliverables

• Summary report on the project plan’s available data, assumptions and methodology of the analysis. (2009)

• Report on composite load under/above solar and wind production profile scenarios. (2009)

• Summary report on required ramp rates and load balancing capabilities utilizing Excel

spreadsheets. (2009)

• Detailed report describing the analysis results, mitigation strategies and recommendations. (2010)

• Complete report on required ramp-rates, load-balancing and ACE/frequency regulation.

(2010) Project Cost/Funding Breakdown


Task 4 - Perform comprehensive analysis and simulations 1/4/2010 $245,000

Task 5 - Ramp rates, regulation, and load balancing 4/1/2010 $98,000

TOTAL $343,000



Real-Time Power System Security Margin Identification Total 2010 incremental costs: $490,000 Background Power system security has always been essentially and intrinsically in conflict with economic and, more recently, environmental (renewable) requirements. Power system security control aims at making decisions in various time horizons so as to prevent the power system operation from undesired internal situations, in particular to avoid large catastrophic outages such as blackouts and brownouts. Project Description SCE plans on conducting research to study real-time power security margin identification using synchrophasor technology for measurements that are available every .1 – 0.2 second versus supervisory control and data acquisition (SCADA) measurements taken every 1 – 5 seconds. Voltage instability in the transmission networks has directly led to or significantly contributed to some wide-area blackouts around the globe. The timely recognition of these instabilities is crucial to effective control and protection interventions and there is growing worldwide interest in defining effective real-time voltage stability indicators under the assumption of very fast measurements of system electrical variables using phasor measurement units (PMU). This study will verify that near real-time voltage instability analysis can be performed using PMU measurements of voltage and current. The goals for achieving these efforts are to conduct online transfer limit studies and develop near real-time prospective calculations of operational security limits. Tasks

1. Develop and prepare functional specifications to be used by SCE to select a contractor.

2. Perform online available transfer capability (ATC) limit studies

At the present speed, ATC calculations are performed about every 10 minutes. A much faster calculation algorithm/method using PMU measurements is necessary to meet present and future utility operations requirements. Using ATC results in hour-ahead and real-time dispatching will provide utilities with greater operational security and reliability.

3. Perform look-ahead calculations (very short-time forecast) and analysis of voltage stability

margins from an existing operating point. The objective is to identify, test and procure, or develop a fast and simple tool, one that enables online applications for estimating the voltage stability margin of a power system using immediate past PMU measurements. In general the analysis of voltage stability will involve the examination of:



• How close the system is to voltage instability or collapse • When the voltage instability occurs • Where the vulnerable areas of the system are • What the key contributing factors are • What areas are involved

Voltage stability analysis often requires examination of many system states and contingency scenarios. For this reason, the approach based on steady-state analysis is most feasible and can provide insight into voltage reactive power problems. Because voltage stability is a dynamic phenomenon some utilities use Q-V curves at some load busses to determine the proximity to voltage instability. One problem with the Q-V curve method is that when focusing on a small number busses system-wide voltage stability problems are not easily revealed.

Deliverables

• Prepare RFPs for Tasks 2 and 3

• Reports and prototype software for Tasks 2 and 3 Project Cost/Funding Breakdown


Task 1 1/4/2010 $245,000

Task 2 7/1/2010 $245,000

Task 3 1/3/2011 $980,000

TOTAL $1,470,000



Very Short-Time Forecast Technology in High Renewable Penetration Power System Operation Total 2010 incremental costs: $367,500 Project Description One of the fundamental challenges of power system operation is running a true supply-on-demand system that is reliable. Historically this challenge led to a power system based on highly controllable supply to match a largely uncontrolled demand. However variable energy sources have become an increasingly attractive proposition and are now beginning to achieve significant levels of penetration in certain areas. This can cause problems with the conventional system balancing methodologies. Since penetration levels of renewable energy are likely to continue to rise, a re-examination of the existing energy balancing paradigm may be required. Fortunately, an operational electrical grid has the potential to mitigate some of the difficulties that are posed by high levels of renewable energy generation. A truly reliable grid will provide essential accurate information to facilitate effective decision-making in regards to both supply-side and the demand-side power system operations. SCE plans on conducting research to identify very short time forecast (VSTF) technologies to be utilized in intermittent renewable energy, phasor measurements (voltage and current magnitudes and angles) and transmission line flows for reliable real-time operation. The goals of these efforts are to:

• Identify an effective method for VSTF (5 minutes ahead): neural network or other method, • Forecast intermittent renewable generation for starting backup units • Forecast very short time load • Forecast tie line power, bus voltage, and bus voltage angle to predict near future

operational status Tasks

1. Develop and prepare functional specifications to be used by SCE to select a contractor.

2. Identify robust products (methods) for very short time (5 minutes to 4 hours) forecasting of

load, intermittent generation, tie line power, bus voltage, etc.

3. Forecast very short time intermittent generation.

4. Forecast very short time load. The process and work are similar to Task 3.

5. Forecast tie line power, bus voltage, bus voltage angle to predict near future operational status. The process and work are similar to Task 3.



Deliverables

• RFPs for Tasks 2, 3, 4, and 5.

• Report and prototype software Project Cost/Funding Breakdown


Task 1 1/4/2010 $245,000

Task 2 6/1/2010 $122,500

Task 3 1/3/2011 $245,000

Task 4 1/3/2011 $245,000

Task 5 7/1/2011 $245,000

TOTAL $1,102,500



Synchronized Phasor Measurement and Grid Stability Assessment and Control Total 2010 incremental costs: $245,000 Background SCE’s Synchronous Phasor Measurement System (SPMS) got its start in 1995 as a research project with the Electric Power Research Institute (EPRI) and Bonneville Power Administration (BPA). After a large-scale disturbance on the western grid the following year, SCE began additional research into wide-area-measurement technologies and installed phasor measurement units (PMU) at its substations to monitor power system activity and disturbances. This led to the development of the off-line analysis and decision making software, Power System Outlook (PSO) for planning and operations training, and Synchronized Measurement and Analysis in Real-Time or SMART®. Both of these tools are being demonstrated in the SCE Grid Control Center (GCC). Project Description SCE plans on conducting research and performing advanced studies to provide measurements of transmission system stress to present to system operators, to establish advance alarm and warning limits and automatically take corrective action to maintain grid stability. The goals of these efforts are to:

• Explore the use of PMU data in transmission operations environment • Conduct evaluation of phase angle separation limits between different load/source areas

and establish limits • Research phase angle separation relation to the system stress • Analyze voltage and angle stability issues • Perform modal analysis for different WECC regions • Establish limits on phase angle separation to identify safe, marginal and unsafe (stressed)

system conditions Tasks

1. Establish analytical framework using equal-area criterion 2. Establish analytical framework using phase-plane method 3. Conduct analysis to establish phase angle separation between Grand Coulee and SCE

Devers Substation 4. Extend the analysis to other source-load areas 5. Analyze and study voltage support requirements and stability limits 6. Determine alarm criterion, limits and severity 7. Analyze modal frequencies and system characteristics of WECC to determine the modal

map of the system



Deliverables

• White paper detailing application of equal-area criterion to phase angle separation between two busses.

• White paper detailing application of phase-plane method to phase angle separation between two busses.

• Report on the accuracy and practicality of the proposed methods by performing dynamic simulations studies.

• Table with phase angle separation between Grand Coulee and SCE Devers and other source load areas.

• Table of alarm limits and severity. • Identification of key locations in the WECC system where voltage support is required and

a table with critical points when the system starts to display low-level oscillations and establish limits on the dv/dp or the percent of deviation.

• Modal map of the WECC system. Frequencies change with loading and system configurations.

Project Cost/Funding Breakdown


Task 1: Analytical framework using equal-area criterion 1/4/2010 $122,500

Task 2: Analytical framework using phase-plane method 7/1/2010 $122,500

Task 3: Analysis to establish phase angle separation between Grand Coulee and SCE Devers Substation

1/3/2011 $122,500

Task 4: Extend the analysis to other source-load areas 3/1/2011 $245,000

Task 5: Analyze and study voltage support requirements and stability limits 1/3/2011 $122,500

Task 6: Determine alarm criterion, limits and severity 6/1/2011 $122,500

Task 7: Analyze modal frequencies and system characteristics of WECC to determine the modal map of the system

9/1/2011 $122,500

TOTAL $980,000



Real-Time Stability Mitigation in High Renewable Penetration Total 2010 incremental costs: $367,500 Background Remedial Action Scheme (RAS) can be deployed at the transmission corridor or grid interface to prevent an AC power system from synchronous out-of-step conditions following large disturbances. The existing RAS is a preset logical trigger scheme based on the status changes (on or off) of monitored transmission lines and generators. These RAS respond quickly, but sometimes the response ineffective or unnecessary. As more grids become part of the transmission topology and greater amounts of intermittent renewable generation are integrated on to the SCE grid, the preset status change logical scheme can’t handle the complicated mutable operational scenarios. A smarter RAS is required. Project Description An innovative method consisting of the inter-area model without parameters and the adaptive instability prediction criteria without settings is being proposed. Simulations show a more precise method for predicting instabilities in various scenarios. Additional algorithm improvements and simulations reveal an effective method for predicting unstable circumstances and returning them to a stable state. This methodology is supported in the paper Adaptive Impact Energy Method for Synchrophasor Measurements Based Inter-Area Instability Prediction and Remedy presented at the IEEE PES 2008 General Meeting. The presented model, criteria and algorithm are pending U.S. patent. The goal of the project is to provide an optimal solution for integrating large-scale wind generation on Southern California Edison’s (SCE) power system in compliance with North American Electric Reliability Council (NERC) requirements at a minimum cost. This study will conduct instability prediction tests at the utility’s Rector - Pacific Direct Current Invertie (PDCI) and remedial action tests to investigate more effective remedial measures. Tasks Task 1

• Develop and prepare functional specifications to be used by SCE to select a contractor. Task 2

• Prepare the field test with Rector PDCI • Verify the criteria using additional PMU historic data • Study the interface with Rector PDCI • Master the relevant software tool and programming language



Task 3

• Test the instability prediction with Rector PDCI • Have PMU stream data available • Code program to implement real-time instability prediction • Record and validate the results

Task 4

• Test the remedial action based on instability prediction result • Obtain approvals for connecting the remedy mechanism of the existing RAS • Test the remedial action based on instability prediction result.

Deliverables

• Prepare RFPs for Tasks 1, 2, 3, and 4 • Prepare reports and present prototype software for Tasks 1, 2, 3, and 4



Task 1 1/4/2010 $245,000

Task 2 7/1/2010 $122,500

Task 3 1/3/2011 $294,000

Task 4 8/1/2011 $196,000

TOTAL $875,500



EPRI 39.004 Measurement-based Voltage Stability Monitoring and Control Total 2010 incremental costs: $80,000 Background Voltage stability is a major concern in power system operations and a leading factor that limits transfers in the prevailing open access environment. Voltage stability assessment (VSA) is a computer simulation tool used to help operators monitor and control system voltage stability. The accuracy of VSA results depend on the accuracy with which the generation, load and transmission facilities are modeled. Uncertainties with these factors pose challenges to obtaining accurate voltage stability analysis results using a VSA program, which may in turn lead operators to make incorrect decisions and increase the risk of voltage collapse. Moreover, a VSA program also relies on the state estimator to provide steady-state solutions for further analysis. In extreme operating conditions when the state estimator fails to converge, VSA programs also fail to help operators monitor and control system voltage stability. Project Description Given the limitations of VSA programs, this collaborative Southern California Edison (SCE) and Electric Power Research Institute (EPRI) project will investigate using data from phasor measurement units (PMU) installed at an SCE substation to calculate voltage stability margins in real-time and send the data to the utility’s control center to help SCE operators monitor the system’s voltage stability. The goal to achieving this effort is to investigate various methodologies for calculating voltage stability margins in real-time using PMU at the substation level. Then these calculated voltage stability margins can be sent to the control center to help system operators monitor system voltage stability and used to trigger the appropriate control device for preventing fast voltage collapses. Tasks

1. Develop a software package based on the Voltage Instability Load Shedding (VILS) algorithm to help operators monitor the voltage stability conditions at the substation level using PMU data.

2. Develop a software package based on a load center algorithm for measurement-based

voltage stability monitoring and control to help system operators monitor voltage stability conditions at the control center level using real-time PMU data obtained at the boundary substations of each load center.

3. Engage operators of participating utilities and experts in human factors to design an

effective human-to-machine interface to convey critical voltage stability information calculated at the local substation and load centers.



Deliverables

• VILS-based software package

• Technical report on the functional specifications of measurement-based voltage stability analysis at control centers (SAAC) to provide a design document for helping system operators visualize the critical voltage stability information calculated at local substations and load centers.



Task 1 1/4/2010 $80,000

Task 2 1/3/2011 $80,000

Task 3 1/3/2011 NA

TOTAL $160,000



EPRI 173 - Integration of Variable Generation and Controllable Loads Total 2010 incremental costs: $250,000 Background A number of ongoing environmentally driven regulatory issues—including greenhouse gas reductions and climate change initiatives, the U.S. Clean Water Act: Cooling Water Intake Structures and the U.S. Clean Air Act: Interstate and Mercury Rules—have increased implementation of renewable energy resources and adoption of distributed generation (DG) and demand-side resources. Southern California Edison (SCE), an industry leader in renewable energy integration, is actively participating in a variety of research projects, on it own and in collaboration with other entities. The Electric Power Research Institute (EPRI) is one of SCE’s most prominent and productive affiliations and the utility again plans on continuing this important affiliation by joining EPRI’s 2010 Integration of Variable Generation and Controllable Loads program. Project Description EPRI research and development in integrating generation and controllable load area will produce the knowledge base and tools to help system operators and planners:

• Understand the impacts of variable generation and controllable load on system reliability • Control variable generation and controllable load to minimize operational risks • Design robust transmission systems to integrate variable generation and controllable load.

The integration of variable generation and controllable load program offers members both short- and long-term value that can be realized in a number of ways:

• Anticipating future developments, creating new strategies, and outlining roadmaps • Developing methods and tools • Demonstrating and deploying technologies • Providing training and staff development • Sharing knowledge, information, and experience • Building networks and conducting outreach.

EPRI’s 2010 goals include:

• Understanding the state of the art, best practices and gaps of existing tools • Preparing a set of requirement specifications for expanding the capabilities of tools to deal

with the variability of resources • Exploring new methodologies to deal with uncertainty of variable generation and

controllable load • Developing business case studies to quantify financial benefits of controllable load and

storage Projects/Tasks



P173.003 Grid Performance and Modeling of Variable Generation and Evolving Power System Resources Describe the technical performance requirements of variable generation and other emerging generation technologies, help develop generic non-proprietary models for modeling and planning the integration of such resources into the utility grid, and guide efforts in model validation. P173.004 Determination of Optimal Reserve with Consideration of Variable Generation and Controllable Loads Determine energy and reserve schedules with consideration of power system uncertainties arising from conventional and emerging energy technologies such as controllable loads, price-sensitive demand, energy storage, and PHEVs. P173.005 Advanced Frequency Control for High Variable Generation Systems and Evolving System Resources System operators depend on generating resources to supply frequency regulation through the load frequency control (LFC) portion of AGC. Present LFC algorithms may be tuned in a way that does not provide optimal or even adequate frequency control for high penetrations of variable generation. For example, recent EPRI studies performed on a small island system with high wind penetration showed that control tolerances had to be loosened to prevent hunting, or over-control, which degraded control performance. This project will evaluate potential changes to existing LFC functionality and maintenance for high variable generation scenarios. Additionally, the project will assess gaps in existing control algorithms, communications infrastructure, or any other barrier that would preclude new sources that provide system flexibility from participating in frequency control. This information will then be used to create a roadmap and possible demonstration efforts needed to take the concept to an implementation phase. P173.006 Advanced Planning Tools to Study the Impact of Variable Generation and Controllable Loads This project will investigate future load composition, system load shapes, business cases for energy storage, regulatory policy impacts and the value of ancillary services as affected by integrating high penetrations of renewable generation, controllable loads, PHEV, energy storage, and demand response. Information developed through this project will prove useful to members when planning their future transmission grids. 2010 Deliverables Project 173.003

• Workshop on Variable Generation Performance and Modeling Planned - Completion Date 12/31/10



• Technical Report on Variable Generation Performance and Modeling - Completion Date 12/31/10

Project 173.004

• Technical report on the Technique for Reserve Determination with Consideration for Conventional and Emerging Technologies – Completion date 12/31/10

• Software for the Model for Reserve Determination with Consideration for Conventional and Emerging Technologies – Completion date 12/31/10

Project 173.005

• Technical report on Advanced Frequency Control for High Variable Generation Systems and Evolving System Resources – Completion date 12/31/10

Project 173.006

• Technical update on the issues and methods for assessing and planning for customer demand and energy storage for regional transmission grid: Technical update on the issues and methods for assessing and planning for customer demand and energy storage for regional transmission grid – Completion date 12/31/10



Task 1 1/4/2010 $250,000

Task 2 1/3/2011 $250,000

TOTAL $500,000



Dynamic Modeling of Solar and Wind Generation Technologies on the Bulk Power System Total 2010 incremental costs: $294,000 Background California’s Renewables Portfolio Standard (RPS) is driving the high penetration of renewable resources onto the electric grid. In order to comply with the RPS Southern California Edison (SCE) must perform intensive analyses to understand and quantify the impact this generation will have on its system. Computer models will be needed to conduct the most accurate analyses and in many cases developing these models requires actual field-testing to assure the behavior of the mathematical models closely simulates actual system behavior. Project Description This project will investigate enhanced capabilities of SCE’s electric system models in order to replicate real-world conditions that result from integrating increasing amounts of solar and wind generation technologies on the bulk power transmission system. The goal of the project is to develop a library of models that will enable SCE to more accurately assess the impact increasing levels of renewable energy has on its system and formulate more effective mitigation strategies for greater system reliability and to ensure compliance to Western Electricity Coordinating Council (WECC) and North American Reliability Council (NERC) standards. Tasks Task 1. Project Initiation

• Host project kickoff meeting • Conduct interviews • Determine data availability and quality

Task 2. Wind Farm Models Development

• Develop electromagnetic transient (PSCAD) models for wind turbines • Develop dynamic PSLF models for wind turbines • Develop wind farm models

Task 3. Solar Generation Models Development

• Develop PSCAD electromagnetic transient models for solar generation • Develop dynamic models for solar inverters

Task 4. Model Validation and Stakeholder Buy-In



• Project team to prepare detailed study scopes. These studies will utilize the models developed during the project to simulate system performance. Output from the analysis will be compared with historical system performance, system test results and other studies to validate the models to ensure appropriate performance.

• Document models and develop a project report. • Review the models and obtain the buy-ins of key stakeholders (WECC, California

Independent System Operators (ISO)) as needed. This effort will start early in the project with the formation of a stakeholder team to monitor and provide feedback to the project team throughout the development of the models. The project team will meet periodically with the stakeholder team to present interim results and the status of the system models. This approach is proposed to ensure that stakeholders are actively engaged throughout the project to maximize the likelihood of acceptance of the models.

Deliverables • Initial project plan • Data requirement/availability plan • Individual and aggregate electromagnetic models for wind farm by type

o PSLF o PSCAD o CAPE o CYME Dist

• Individual and aggregate electromagnetic models for solar farm by type o PSLF o PSCAD o CAPE o CYME Dist

• Validation study results and project report Project Cost/Funding Breakdown


Task 1 – Project Initiation 1/4/2010 $98,000

Task 2- Wind Farm Models Development 4/26/2010 $196,000

Task 3 - Solar Generation Models Development 1/23/2011 $196,000

Task 4 - Model Validation and Stakeholder Buy-in 5/2/2011 $245,000

TOTAL $735,000



Optimal Large-Scale Renewable Generation and Energy Storage Integration Total 2010 incremental costs: $318,500 Background Large-scale wind generation has already been approved for connection to the Southern California Edison (SCE) system, 1500 MW at Tehachapi and an additional 4000 MW is planned at a location yet to be determined. The inherent intermittent nature of wind presents challenges to power system reliability and economic operations; therefore it is imperative that the issues are resolved in the most cost-effective manner while complying with stringent North American Reliability Council (NERC) standards requirements. Some impacts the intermittency of large-scale wind generation presents are:

• Significant frequency and voltage deviations • Inadequate generation reserve capacity • Grid overloading • High probability of instability • Uneconomical unit commitment and operational dispatch

Some potential measures to resolve intermittency issues are:

• Installing new generation reserve capacity • Operating more generation spinning capacity • Constructing new transmission lines or upgrading the existing lines • Adopting wind generation weighted locational marginal price (LMP) congestion

management practices • Installing and operating energy storage device

Project Description This project will evaluate the various options for the most feasible and efficient method of integrating wind generation onto electric utility systems. Tasks

1. Develop and prepare functional specifications to be used by SCE for selecting a contractor.

2. Identify the operational and economic impacts of large-scale wind generation on the SCE system. Through 2011, 2016 and 2021 without integration solution case studies, find reliability and economics problems caused by large-scale wind generation intermittency.



3. Investigate appropriate energy storage type, capacity and location for large-scale wind generation integration.

4. Form several integration solutions by combining potential measures. All solutions include

the evolution from 2011, 2016 to 2021.

5. Perform feasibility studies on various potential integration solutions. Conduct quasi-steady-state production simulation, LMP-based grid congestion relief studies to verify generation resource adequacies in various time frames, and schedule unit commitment and generation economic dispatches with grid constraints. Conduct power system steady and dynamic contingency studies in compliance with NERC thermal, voltage and frequency requirements. Conduct financial analysis to calculate total cost, including construction cost and operational cost.

6. Conduct risk and optimization studies on the impact of various uncertainties and policy

changes on all integration solutions. Recommend an optimal integration solution that does not compromise compliance, cost and risk.

Deliverables

• Prepare RFPs for Tasks 1, 2, 3, and 4 • Provide test reports and prototypes software for each task



Task 1 1/4/2010 $24,500 Task 2 1/25/2010 $98,000 Task 3 4/26/2010 $98,000 Task 4 8/30/2010 $98,000 Task 5 1/3/2011 $245,000 Task 6 8/11/2011 $122,500 TOTAL $686,000



Inverter Testing and Modeling for Transmission Impact Studies Total 2010 incremental costs: $245,000 Background The California Public Utility Commission (CPUC) approved a five year 500 MW solar PV program in Southern California Edison’s (SCE) service territory. Additionally, the California Solar Initiative (CSI) provides for 10 years of state funded solar rebates to customers in the state's investor-owned utility territories. These two solar initiatives will significantly increase SCE’s renewable generation penetration. This higher penetration of renewable generation will make the utility vulnerable to negative impacts because solar energy is intermittent – the sun doesn’t shine all the time – and this type of generation may be unavailable when it is needed most. No steady-state, dynamic or harmonic models are presently available for studying the impacts of this type of generation; therefore, effective models must be developed to accurately assess the issues and make appropriate recommendations for mitigating the problem. Project Description SCE is planning to test residential/small commercial solar photovoltaic (PV) inverters to assess their behavior during voltage and frequency oscillations. This test data will be analyzed and used to develop solar PV inverter models and assess their impact on the grid, especially at high penetrations. The newly developed models will be test and validated using actual field testing and data. The new models will be used to perform transmission system impact studies for the present year, and five and ten years into the future. Tasks The goals of these efforts are to:

1. Acquire 20 residential and/or small commercial single-phase and three-phase inverters approved by the California Energy Commission (CEC) for residential or commercial use. Develop a test protocol to test the different inverters. Test the inverters during voltage and frequency oscillation deviations, especially for common transmission fault clearing times.

2. Install high sampling data recorders at 5 different solar PV residential and/or small

commercial and/or solar roof top PV generating sites. The recorded data will be used for field validation of the solar PV inverter dynamic model.

3. Analyze the test data and prepare a detailed test report with the key findings.

4. Report the test results and provide the proper analysis for PSLF model development and

validation to the Western Electricity Coordinating Council (WECC) Modeling and Validation Working Group to help in the development of solar PV inverter models.



5. Test and validate the WECC developed solar PV inverter models with actual field events.

Test and validate the solar PV model. The validation will be performed on a unit and aggregated basis. The unit model will be validated against the actual inverter tests provided in Task 1. The aggregated model will be validated using the captured field solar PV inverter data provided by Task 3.

6. Perform system-wide impact studies (especially at high penetration) of the solar PV

inverters in the field for the present year, and 5- and 10-year PSLF base cases. Deliverables

• Test protocol used to test the solar PV inverters

• Test report for the solar PV inverters test

• Field data analysis

• Presentation to the WECC of the solar inverter test results

• Test and validation of the solar PV inverter model developed in PSLF by WECC

• Report of system-wide impact studies Project Cost/Funding Breakdown


Task 1 – Test of Solar PV Inverters 1/4/2010 $24,500

Task 2 – Field Installation of Data Recorders 2/1/2010 $73,500

Task 3 – Test Analysis and Report 6/1/2010 $98,000

Task 4 – Collaborate with WECC in the model development 10/1/2010 $49,000

Task 5 – Test and Validate WECC PSLF Solar PV Inverter Models 1/3/2011 $245,000

Task 6 – System Wide impact Studies Results 7/1/2011 $245,000

TOTAL $735,000



RTDS Large Model of the SCE 230 kV and 500 kV System Including All System Generation Total 2010 incremental costs: $269,500 Background As the power systems become more complex new tools are required for conducting analyses. To assure the proper functionality and optimization of faster communications and advanced controls testing must be conducted before implementing these new technologies in the field. The Southern California Edison (SCE) real-time digital simulator (RTDS) will facilitate the implementation of these smart grid devices. Project Description The intent of this study is to develop a complete model of the SCE 230 kV and 500 kV systems and its generation, including the turbine-generator models and its respective controls (exciter, governors and power system stabilizers). The model will also include all the FACTS devices on the SCE system with its level of detail based on the RTDS available memory (RACKS). The system will also be able to capture any inter-area oscillations that exist between the SCE system and neighboring utilities to evaluate mitigating technologies for the damping of system oscillations. The model can also be used to fine-tune the relay protection’s out-of-step setting. The project will help in optimizing available RTDS resources to address the various scenarios being simulated and assessed. The goals of these efforts are to:

• Develop the most suitable model for use in the greatest number and most diverse cross-section of subject areas (i.e. controls, protection, stability, operations, etc.).

• Address the question of whether centralized, distributed or combined storage strategies will be integrated on the SCE system.

• Analyze system stability studies, interconnection issues, economic impact, operational performance and other issues affecting overall performance.

• Develop specifications for the energy storage technology. • Design, build, install, test, and demonstrate the storage. • Evaluate performance and cost-effectiveness. • Perform GIS studies, spatial load density analysis, load type assessment, physical

requirements, and seismic analyses. Tasks Task 1 Develop an RTDS electromagnetic transient model of the SCE system of the 230 kV and 500 kV systems with equivalent short circuit sources based on SCE short circuit database.



Task 2 Replace the short circuit equivalents of the by classical synchronous turbine generators including its controls (exciter, governor and power system stabilizer). Task 3 Validate the RTDS model against phasor measurement unit (PMU) disturbances to represent the proper system response. Task 4 Develop and model all SCE existing FACTS (SVC) devices on the RTDS model. Task 5 Develop a model of the Pacific HVDC Intertie system’s Sylmar and Celilo stations. Deliverables

• Complete and validate RTDS model of the SCE system including 500 kV and 230 kV busses

• Model documentation that includes all validation reports load flows, short crcuit and

stability Project Cost/Funding Breakdown


Task 1 1/4/2010 $73,500

Task 2 3/15/2010 $24,500

Task 3 4/22/2010 $73,500

Task 4 8/16/2010 $49,000

Task 5 10/1/2010 $49,000

TOTAL $269,500



Real-Time Analysis of SCE System with High Levels of Renewable Penetration Total 2010 incremental costs: $367,500 Background With its renewable energy penetration level expected to exceed 20 percent in the near future, Southern California Edison (SCE) believes it is necessary to conduct research on how wind turbines and thermal and photovoltaic (PV) solar will impact the behavior of electric power systems by interacting with conventional generation and loads. This requires adding a variety of complex digital controllers and protection devices on the network. Modeling of power system transient and dynamic phenomena is essential to study their impacts on the network design and operation. Project Description The goal of this project is to develop models and use SCE’s Real Time Digital Simulator (RTDS) to conduct electromagnetic analysis. These models will allow SCE to accurately simulate the SCE system on the RTDS for the purpose of assessing the performance of the system with increasing levels of renewable energy. The study will include analyses of:

• Wide-area control strategies • Equipment designs • Protection devices assessment • Storage controller settings

This project will also allow the RTDS to be used for developing, testing and verifying a certain equipment standards. Tasks

1. Project Launch

• Define a list of wind turbine types, solar and storage systems technologies to be included in the project.

• Define a list of digital device types and technologies to be included in the project. • Perform initial assessment on the source and quality of data available to SCE to

validate the models to be developed, identify potential gaps, and draft a plan to collect additional data and make the data readily available to the project team.

• Refine the scope and finalize the project plan.

2. Data Gathering and Analysis

• Perform initial assessment of the modeling and operational data requirements.



• Identify SCE system interconnection and design standards as well as list of functional specifications proposed for emerging technology generation design and operation within SCE’s system territories (vendors, device compliance and specifications).

• Perform initial assessment on the source and quality of data available to SCE to validate the models to be developed, identify potential gaps, and prioritize them. The data assessment will include existing SCE data readily accessible to the project team and data that may be available in the public domain.

• Recommend a plan to make the data readily available to the project and collect additional data through additional instrumentation – if any additional instrumentation is needed.

• Collect data. • Specify system drawings and one-line diagrams required in the project • Obtain SCE RTDS system specifications and peripheral equipment (amplifiers, I/O

cards, testing devices, etc.). • Define a typical benchmark system to be used through out the project for preliminary

model validation and assessment of source/device interactions with the rest of the system.

3. Digital Device Models Development

• Identify RTDS system interface and develop generic RTDS-type models for IED (digital controllers and protection devices) to the level required for overall power system validations.

• Make adjustments to the electromagnetic models as needed.

4. Wind Turbines and Wind Farm Models Development

• Develop RTDS models for various types of wind turbines (as specified in Task 1) incorporating the main building blocks and control/protection circuitry.

• Validate RTDS-type models for various wind turbine types using actual wind farm data collected.

• Make adjustments to the RTDS models as needed, including modifications of the control circuitry and calibration of the feedback loops.

5. Solar Technologies and Solar Farm Models Development

• Develop RTDS-type models for various solar technologies, including inverters. • Coordinate with solar inverter manufacturers to define the data requirements for the

generator outputs under different solar radiations. • Propose a scaled PV farm (around 500 kW) with different PV and inverter

technologies. • Validate the RTDS-type models for various types of solar generation as defined in with

actual solar farm data collected. • Make adjustments to the RTDS models as needed.



• Develop dynamic models for solar inverters to determine short circuit contribution of solar farms and distributed PV systems.

• Develop generic and performance models for solar farms to determine the dynamic behavior.

6. Storage System Models Development

• Develop electromagnetic (RTDS-type) models for storage systems. • Develop a benchmark system comprising energy storage – wind – solar as the base to

test and verify the operation and different functionalities expected in the models. A typical benchmark example is shown below for clarifications. Detailed specifications will be identified and proposed as part of the task.

• Verifications and fine tuning of the models based on the real-time evaluations and expected system responses.

7. Validation Study

• Detailed study scopes will be determined with SCE project team, based on mutually agreement and considering the limited time and effort.

8. Project Report

• Develop the project report and prepare an executive presentation for SCE approval.

9. Public Discussion

• Support SCE in validating the models and getting the buy-ins of stake-holders (WECC, CAISO, others) as needed.

• Deliverables

1. Kickoff meeting and deliver project plan

2. Identify required data and data sources

3. Digital device models

4. Wind turbines and wind farms models

5. Solar technologies and solar farm models

6. Storage systems models

7. Results, analysis and interpretation of distributed energy resources (DER) system

impact study

8. Final project report

9. Public discussion (workshop with stakeholders for buy-in as needed)





Task 1 – Project Launch 1/4/2010 $49,000

Task 2 - Data Gathering and Analysis 2/8/2010 $98,000

Task 3 - Digital Device Models Development 5/3/2010 $98,000

Task 4 - Wind Turbines & Wind Farm Models Development 8/16/2010 $122,500

Task 5 – Solar Technologies & Solar Farm Models Development 1/3/2011 $122,500

Task 6 – Storage System Models Development 4/4/2011 $122,500

Task 7 – Validation Study 7/25/2011 $98,000

Task 8 – Final Project Report 10/24/2011 $98,000

Task 9 – Public Discussion 11/28/2011 $49,000

TOTAL $857,500



High Voltage Direct Current Event Modeling and HVDC System Modulation Total 2010 incremental costs: $245,000 Background System disturbances have occurred on Southern California Edison’s (SCE) high voltage direct current (HVDC) line between its Celilio and Sylmar substations and it is known that certain oscillations are actually caused by the HVDC line. Some of these oscillations persisted for almost an hour and could have escalated to a larger disturbance. It is very important to monitor, analyze and understand these oscillation events so that they do not occur in future or can be mitigated quickly. Project Description Because there are no known studies on these types of oscillations SCE proposes an investigation that uses a real-time digital simulation (RTDS) platform to analyze such events and determine effective solutions. One such solution the project will study is the use of HVDC modulation to enhance the performance of Pacific Direct Current Invertie (PDCI) like the one at Sylmar, and Pacific Alternating Current Invertie (PACI) systems. The goals of these efforts are:

• Analyze and understand nature of the oscillations caused by the HVDC.

• Investigate the possible solutions such as HVDC modulation through analysis and simulations using RTDS.

• Design and test of the controller to quickly damp the oscillations.

• Install a prototype control system at Sylmar and nearby substations. Operate the prototype

system for six month and monitor its performance.

• When successful operation recorded, propose the controller for permanent installation and operation.

Tasks

1. Conduct analysis of the selected past events including DC Probe tests and comparing the results with the recorded data. The selected system events will be simulated by developing suitable models on the RTDS. New technologies will be developed for improved performance. The system will be developed and tested on the RTDS system model to ensure the system perform satisfactorily.



2. Engineering, design and installation of phasor measurement units (PMU) and the associated communication system (jointly with LADWP and BPA) to monitor the HVDC system performance.

3. Hardware selection and procurement. The master controller could be a phasor

measurement system, phasor data concentrator type device or a real-time controller type device. Simulations will be done to determine the precise control strategies.

4. Laboratory testing will be done to assess the developed control strategies. RTDS platform

will be used along with the HVDC and selected dynamic systems modeled in detail.

5. Once the system is tested, it will be installed at Sylmar and other nearby substations. High speed communication channels will be built to interconnect several substations to obtain required data and control input. The system will be kept in monitoring mode for six months to ensure satisfactory operation.

Deliverables

• Report the modeling efforts on the RTDS and publish the analysis results on few significant events from the past recorded data. RSCAD model of the system for future applications.

• Design and construction documents to install PMU and associated communication system

at Sylmar Substation.

• Developed control strategy. Results of simulation will be reported. Controller hardware list will be prepared. RSCAD model of the test for future applications.

• Hardware on the loop of the controller performance using RTDS platform. • Prototype system installed for field testing on the actual HVDC system.



Task 1 – Analysis of past events with RTDS 1/4/2010 $98,000 Task 2 - Install PMU, Comm. Links at Sylmar 5/24/2010 $147,000 Task 3 - Procure HDWR, simulate strategies 1/3/2011 $196,000 Task 4 - Laboratory test of controller 8/1/2011 $122,500 Task 5 - Build prototype and install at the field 12/5/2011 $367,500 TOTAL $931,000 Note: Task 5 will be continued in 2012.



Innovative Transmission Solutions for Accelerating Wind Power Integration in the U.S. Total 2010 incremental costs: $490,000 Background In March 2009 Intellicon responded to the U. S. Department of Energy Funding Opportunity Announcement (FOA) Number: DE-PS36-09GO99009 titled 20% Wind by 2030: Overcoming the Challenges. For a project of this scope, the technology development, power system expert, and consulting firm chose Southern California Edison as its utility partner and technical advisor. The application was not awarded funding, but SCE believing in the importance of the study and impressed by Intellicon’s testing and analysis of substations, would like to pursue the project should funding be secured. Intellicon’s DOE proposal was submitted for Topic Area 4: Transmission Analysis, Planning and Assessments to specifically address section A, Utility Wind Energy Integration to address a growth of wind power development that is well beyond the agency’s expectations, as articulated in the FOA’s background information:

“. . . up to 6000 MW of wind needs interconnection to the Bonneville Power Administration (BPA) system within the next five years, which will place BPA with the highest proportion of wind power to total electric load for large power systems in the nation. The expected pace of wind power growth will soon outstrip current capability to provide the integration services required for reliable system operation, and there is a need to explore innovative solutions for continuing reliable operation with the most economic integration of additional wind energy. A number of these integration solution paths involve closer cooperation among utility balancing authorities in the region for supplying third party integration services, dynamic scheduling of wind power across interties, pooling integration responsibility and services, and adopting new transmission scheduling, practices and procedures.”

Project Description SCE, now providing project leadership for its partners Intellicon, Mitsubishi Electric Power Products, Inc. (MEPPI), and Argonne National Laboratory (ANL), proposes conducting research using the highly advanced electric grid analysis tools developed by Intellicon to expand and accelerate wind energy integration into existing and evolving electric power systems. This project will demonstrate how using these new analytical tools can reduce the technical barriers that typically impede large-scale implementation of wind energy and other renewable technologies. Unlike traditional transmission studies, this project will investigate the most effective methodologies for resolving issues related to wind integration. The goals for achieving these efforts are:



• Directly address the need for more innovative solutions to improve operational reliability while providing for the most cost-effective integration of wind energy.

• Accurately assess power flows to provide effective models on how to best guide the

implementation of more robust grid reinforcement strategies. Instead of providing localized wind integration services, the SCE/Intellicon approach will employ more practical and cost-effective methodologies to allow for expanded and accelerated wind integration.

• Encourage greater cooperation for pooling and supplying third-party integration services.

• Adopt improved transmission scheduling practices and procedures for integrating wind

resources on the grid using new techniques to examine area-specific isolation solutions.

• Develop strategies to reduce islanding and other system imbalances to increase the capacity of integrating wind energy on to existing systems.

• Define the benefits of using smart grid, demand response, re-dispatch, unit commitment,

and dynamic scheduling of wind as supplemental integration services. Conventional load flow models have been used for decades to assess operational stability and adequacy issues for electric power systems, and more recently to measure the impact of integrating new technologies on to the grid. The root causes identified by traditional load flow simulations represent technical impediments that must be resolved prior to attempting operation of the system. This involves the computationally intensive process of analyzing a great number of unplanned outage events that might affect individual grid components such as transmission lines, transformers, and circuit breakers. The standard practice is to simulate outage events known as contingencies, individually to assess whether grid reinforcements are needed, but only a fraction of feasible events can be examined due to practical considerations, limiting the methodology’s ability to recognize and respond to a full spectrum of problem conditions. Intellicon’s state-of-the-art tools provide distinct advantages over standard transmission studies by developing more robust transmission system designs, thereby facilitating wind-power integration efforts. Innovative breakthroughs by Intellicon have culminated in powerful tools capable of identifying and simulating root causes for hundreds, or even thousands of potential component outages. Using Intellicon’s advanced modeling technology will increase feasible penetration levels for wind integration, while lowering the costs associated with strengthening the system. Six technical characteristics of the advanced methodology to be applied in the proposed study are: 1. Comprehensive Contingency Selection that finds hundreds to thousands of unsolved contingencies as compared with only dozens found in benchmark tests against conventional steady-state stability tools. 2. More thorough Identification of Blackout and Voltage Instability Regions to detect types of blackout regions generally missed by conventional technologies. Because using conventional methods to analyze new generating technologies such as wind often results in technical problems



that ultimately limit the installed wind capacity that can be accommodated without disruptions in service, a more comprehensive methodology is needed. 3. Root Cause Identification and Categorization to determine which of three categories applies to each root cause. This categorization provides the information necessary for subsequent diagnoses. 4. Design Guidance to indicate all of the contingencies associated with the root-cause that produces the voltage instability or collapse and provide the metrics for recommending which enhancements will resolve unsolved contingencies and shrink the blackout regions. 5. Optimized Design Process to sequentially and optimally select the root-cause and then the type, location, size and in some cases control for the appropriate system enhancement. 6. Diagnostic Linkages to effectively link contingencies to affected outage areas, and in reverse, link outage areas with the appropriate contingencies. This feature directly addresses the FERC-identified weakness cited for conventional methods. This root-cause linkage makes it possible to pursue robust and optimized design guidance for hundreds to thousands of root-cause-related contingencies, clearly an impossible task for conventional methods. Tasks

1. Establish Benchmark Simulations and Study Parameters Establish benchmark simulations for the existing system and identify the transmission islands produced by the root-cause anomalies (structural deficiencies) in the transmission network. The island boundaries do not necessarily conform to utility boundaries, but may instead correspond to areas within the utilities. By identifying the island boundaries, this task identifies where integration services are compromised. Integration services will be defined to include: (a) voltage control, (b) transfer of active and reactive power across island boundaries, (c) unit commitment reserves of active generation, and (d) control of frequency and interchange of power between utilities across island boundaries. The provision of these integration services for large wind power installations can change over time and significantly affect production costs and reliability. This first task determines the root causes that produce the island boundaries, the contingencies that exploit the root-causes, and the regions where voltage instability and collapse occur. Analyses will be provided using three Intellicon programs: Comprehensive Contingency Selection, Root-Cause Identification, and Voltage Instability and Blackout Region Identification.

2. Determine Optimal Grid Enhancements

Determine optimal grid enhancements such as the addition of lines, compensation of lines to increase power transfer capacity, and methods for preventing voltage instability. An optimized transmission expansion plan will provide the means to: (a) achieve all of the integration services required through collaborative efforts across a large region, (b) reduce costs for integration services, (c) increase overall system reliability and security, and (d) allow far greater penetration of wind than possible without the enhancements. These



transmission enhancements are designed to heal the root-causes of problems. Without this step, the cost of providing the integration services becomes substantial and the reliability of the grid is compromised by large wind power installations; therefore, this task represents an essential element of strategies to expand and accelerate the use of wind power.

3. Identify Alternative Operational Strategies to Resolve Transmission Problems Use Intellicon technology to determine alternative operational strategies (Smart Grid or changing specific generator dispatch/output schedules) to heal transmission island boundaries and increase transfer capacity. These operational strategies will be used to provide alternatives to transmission enhancements where environmental, political, economic, or other technical considerations do not allow for transmission enhancement.

4. Identify Adaptive Transmission Procedures to Provide Integration Services Develop adaptive transmission scheduling procedures for:

• committing additional generators • altering output levels of generators • using Smart Grids to expand the reserves and balancing control capabilities (integration

services) in a collaborative region • providing additional generation reserves and balancing control compensation for

equipment outages and wind power fluctuations occurring at any particular time

5. Determine System Operating Reserves Using Argonne’s unit commitment tools, determine the appropriate levels of system operating reserves as required for solving reliability problems and evaluate the impact on frequency and interchange of power. This task will assess the effectiveness of providing integration services by comparing the results before and after the operational enhancements for any collaborative region or component island (from Task 4).

6. Assess Production Costs and Overall System Reliability

Apply Argonne’s production-cost and reliability programs to estimate the production costs (total operating cost for a period of 5-30 years) and reliability of the grid before enhancement, after transmission enhancement, and after operational enhancement. The net avoided cost of integration will be determined by comparing outcomes from the different case studies. Integration services that impact transmission reliability will also be identified.

7. Prepare Reports on Analysis and Findings

Provide quarterly progress reports and a final report at the termination of the project and document the study effort with substantial inputs from all team members.



Deliverables The project team will deliver regular progress reports, an interim report, and a final project report at the end of the project that documents the methodology, the analyses, and the results. The following technical outcomes are expected:

• The ability to heal island boundaries by transmission enhancement [18] or by Smart Grid/Operations Controls using developed methods.

• The ability to provide integration services over several component islands that comprise a

collaborative island or the entire ISO.

• The development and testing of a program that is able to determine the needed generation reserves (that can respond to a loss of generation and wind power predicted trend and the fluctuations around it) in component island and in collaborative island.

• The development and testing of Smart Grid/Operations Control that has demand response,

renewables, voltage monitoring and control, and storage capabilities to provide the needed reserves. The operations control would change the scheduling of power over a transmission corridor, add generators to a collaborative island and change the level of generation on the generators in an island to increase the generation reserves.

• An estimation of the production cost (total operating cost over 5-30 years) and reliability

before and after healing island boundaries to increase the size of collaborative islands and the integration services contained in them. The production cost and reliability of adding reserves to the collaborative islands through Smart Grid / Operations would also be determined. Other integration services will be investigated beyond generation reserves and balancing control.

Project Cost/Funding Breakdown The proposed work is anticipated to take 15 months starting from contract execution.


Task 1 - Establish Benchmarks Milestone: Progress Report (1st Quarter) 1/4/2010

$122,500

Task 2 - Determine Grid Enhancements Milestone: Progress Report (Quarters 1 & 2) 2/22/2010

$122,500

Task 3 - Identify Alternative Strategies Milestone: Interim Report (Quarters I, 2, 3) 2/22/2010

$122,500

4. Identify Adaptive Procedures Milestone: Progress Report (Quarters 2, 3,4) 4/19/2010

$122,500



5. Determine Operating Reserves Milestone: Progress Report (Quarters 2,3, 4) 1/3/2011

$122,500

6. Assess Production Costs (Quarters 3,4,5) 2/14/2011

$122,500

7. Prepare Final Report Milestone: Final Report (Quarter 5) 6/27/2011

$122,500

TOTAL $857,500



Feasibility of Online Condition-Based Maintenance (CBM) of Geographically Dispersed Renewable Resources Total 2010 incremental costs: $416,500 Background The continuing installation of geographically dispersed renewable resource facilities on the SCE system creates a need to examine the feasibility of remote monitoring of equipment operation and condition to ensure equipment performance. Development of efficient maintenance strategies for remote and dispersed facilities is needed to optimize maintenance programming and funding. A condition based maintenance (CBM) program based on data collected through on-line condition monitoring may be an effective way to achieve the desired result. Project Description SCE plans on conducting research to study the feasibility of installing on-line condition monitoring equipment on remote and dispersed renewable facilities to collect operating condition data. That data will be used to develop maintenance strategies and schedules that can most effectively use both human and financial resources to ensure ongoing operation of the remote facilities. The goals of these efforts are to:

• Identify methods of monitoring the operating condition of remotely located equipment and facilities.

• Identify and quantify the infrastructure requirements necessary to implement an on-line condition monitoring system for remotely located equipment.

• Perform feasibility studies to determine the cost and benefits of an on-line condition monitoring program and the management of the data collected.

• Develop comprehensive maintenance strategies for remotely located equipment based on condition monitoring capability and data collected.

Tasks

1. Develop asset inventory and identify maintenance requirements. This task includes development of a full equipment inventory of dispersed renewable assets and a complete listing of the recommended maintenance requirements for each class of asset. This detailed information will serve as the foundation for development of a remote monitoring requirement and capability. The inventory will identify the potential for on-line condition monitoring of each asset class.

2. Investigate remote condition monitoring for each asset class.



From the equipment inventory, an investigation of on-line condition monitoring needs and capabilities will be conducted. Each asset class will be studied to determine what data should be acquired through a monitoring capability, the availability of condition monitoring systems for those assets, and the requirements for installation and operation of monitoring equipment. This task will consider the existing or planned communications capabilities for operational control or metering at the dispersed generation sites and how those capabilities may be used to facilitate on-line condition monitoring.

3. Develop a condition monitoring and data collection strategy for each asset class.

From the information developed in Tasks 1 & 2, a condition monitoring approach for each asset class will be defined. This approach will include for each asset class the operating data to be collected, the type of monitoring equipment to be used (if any), the frequency of data collection, and all infrastructure requirements to achieve the desired level of data collection for the specific asset class.

4. Maintenance program strategy definition with cost and benefit analysis.

This task will provide a final definition of a comprehensive maintenance strategy for each asset class. The strategy defined will be dependent upon the specific type of equipment, the potential for remote condition monitoring of that equipment, and the maintenance requirements for the equipment as defined operating experience of the equipment in the industry and the manufacturer’s recommendations. Upon development of a maintenance strategy the task will also conduct a cost and benefit analysis for the strategy as compared to existing maintenance operations or to other suggested strategies identified in the project.

5. Reporting

This task includes the development of a comprehensive report detailing the findings from Tasks 1-4. The report will offer recommendations for an approach to maintenance of geographically dispersed renewable generation facilities that considers the type of maintenance program to be implemented (time based, CBM, RCM), the infrastructure requirements associated with each approach, and the cost/benefit comparison for each strategy.

In addition to the final report, monthly progress reports will be generated as the project progresses with reviews by SCE management to identify any mid-project issues or changes in direction that may be required as information is gathered.

Deliverables The deliverable of this project initiative will be a recommended maintenance strategy for each class of dispersed renewable generation asset with a financial analysis that justifies the approach. The deliverable will include detailed asset class inventories, definition of maintenance requirements for each asset class, recommended maintenance programs for each asset class and the cost and benefit associated with each.





Task 1 – Develop asset inventory and identify maintenance requirements 1/4/2010 $98,000

Task 2 - Investigate remote condition monitoring for each asset class 2/22/2010 $147,000

Task 3 - Develop a condition monitoring and data collection strategy for each asset class 5/31/2010 $73,500

Task 4 - Maintenance program strategy definition with cost and benefit analysis 7/19/2010 $49,000

Task 5 - Reporting 8/23/2010 $49,000

TOTAL $416,500



Energy Storage Mix Optimization: Centralized and Decentralized Total 2010 incremental costs: $612,500 Background Energy storage technology must be developed and incorporated onto Southern California Edison’s (SCE) grid before 2020 in order to improve wind and solar capacity factors and reduce transmission congestion for new wind and solar resources so the utility complies with California’s Renewable Portfolio Standards (RPS),. To facilitate this increase in energy storage technology directly interfacing the SCE system in Tehachapi and other areas, it is essential the system be capable of storing excess generation for later use. Subsequently, an optimal mix of decentralized (distributed) and centralized storage facilities requires the development of key performance indicators in order to apply the right form of energy storage to the site where the most effective control can be achieved. Centralized storage is located where the energy is generated (one specific bus) and decentralized is generated and sent to another location for storage to control the entire system. Project Description This effort will survey a variety of energy storage projects and evaluate their applicability to the SCE system. The project will determine the storage capabilities – how much (limited) and how long (time) and how fast each type of storage responds (i.e. pump, battery, compressed air, flywheels, hydro pump). An important element of advanced energy storage is the development of super-capacitors. If the real-time digital simulation (RTDS) project is funded, the RTDS can be used to conduct tests for this study. The goals for achieving these efforts are to:

• Investigate existing and new storage technologies and evaluate the SCE system for appropriate factors that affect the selection of the technology and the location.

• Address the question of whether centralized, distributed or combined storage strategies will be integrated on the SCE system.

• Analyze system stability studies, interconnection issues, economic impact, operational performance and other issues affecting overall performance.

• Develop specifications for the energy storage technology. • Design, build, install, test, and demonstrate the storage. • Evaluate performance and cost-effectiveness. • Perform GIS studies, spatial load density analysis, an assessment of load type, physical

requirements, seismic analysis. Tasks

1. Conduct a comprehensive one-year study of existing and new storage technologies.



2. Evaluate and recommend the best technologies and SCE sites for implementation.

3. Develop specifications for selected energy storage technologies. Deliverables Produce quarterly and final reports for internal use Project Cost/Funding Breakdown


Task 1 1/4/2010 $ 245,000 Task 2 5/1/2010 $ 122,500 Task 3 8/2/2010 $ 245,000 TOTAL $612,500



Master Transmission Plan to Integrate Renewables Under RPS Framework Total 2010 incremental costs: $833,000 Background California has a Renewable Portfolio Standard (RPS) that requires 20 percent renewables by 2010 and an Executive Order from the Governor that further specifies 33 percent renewables by 2020. The implementation of highly variable renewable resources poses many planning and operational challenges for the bulk power system operators. An April 2009 NERC report, Accommodating High Levels of Variable Generation, states:

“There are two major attributes of variable generation that notably impact the bulk power system planning and operations:

• Variability: The output of variable generation changes according to the availability of the primary fuel (wind, sunlight and moving water) resulting in fluctuations in the plant output on all time scales.

• Uncertainty: The magnitude and timing of variable generation

output is less predictable than for conventional generation. When accommodating large amounts of variable generation, these two attributes can have significant impact, requiring changes to the practices and tools used for both bulk power system planning and operations. Power system planners and operators are already familiar with designing a system which can be operated reliably while containing a certain amount of variability and uncertainty, particularly as it relates to system demand and, to a lesser extent, to conventional generation. However, large scale integration of variable generation can significantly alter familiar system conditions due to unfamiliar and increased supply variability and uncertainty.”

At higher penetration levels of renewable energy, transmission planners must consider a regional approach and multi-objective perspective within a balancing area. Transmission has been identified as a resource necessary to manage load and generation imbalance by acquiring ancillary services and flexible generation resources from a larger generation base. Wide-area transmission can improve composite capacity value of variable generation and improve overall system reliability. In addition, new generation and storage technologies will be introduced to the transmission and distribution networks that may affect reliability and power quality of the grid. Project Description



This study intends to identify and evaluate the transmission, energy storage and alternative technologies necessary to handle the integration of greater amounts of renewable generation that will be added to the SCE system in the next decade. To ensure the addition of new technologies meet all applicable reliability criteria the team will conduct thermal, voltage ride-through, voltage stability, short circuit, power quality, and transient stability analyses for each of the solutions considered in the study. The drawbacks and benefits of each design for each alternative considered will be documented and a preferred master plan identified. A modular approach will be taken through 2020 that allows for incremental system evaluations and improvements as more generation comes online. This project will lay out a forward-looking plan specifying what new technologies SCE needs to accommodate the RPS scenario. SCE plans on conducting research to study the impacts of high levels of renewable generation sources on its transmission planning requirements. The goal of transmission planning is to ensure sufficient delivery capacity exists to interconnect new generation resources and demand requirements are met in a reliable and efficient manner. In the face of unprecedented levels of new renewable resources this research will investigate what changes to the existing transmission planning process are necessary to maintain acceptable levels of reliability. This research is comprised of a comprehensive system impact study to identify the preferred transmission plans and facilities to integrate up to 12 GW of mainly wind and solar generation in the in Tehachapi, Palm Springs, Mohave, Antelope Bailey and other areas to be added to the SCE system before 2020. The anticipated load growth will be around 30 GW, reflecting an anticipated renewable energy penetration level of 40 percent. Intially, these intermittent resources will go through the SCE transmission facilities before being dispersed to neighboring utilities. These renewable resources are internal to the SCE system. The clear goal is develop a staged transmission expansion plan to integrate this potential level renewable penetration levels. Using transmission modeling tools, different resource scenarios will be developed and tested for long-term viability. In contrast to traditional planning methods this research will incorporate additional anticipated variables resulting from the addition of intermittent renewable resources, such as energy storage, FACTS devices, etc. Goals

• Identify and evaluate new generation, energy storage and other advanced grid technologies based on grid reliability and stability.

• Evaluate the different renewable scenarios and possible mitigation measures for serving the potential renewable generation on the grid in a centralized and distributed manner.

• Ensure that the alternatives meet all applicable reliability criteria by conducting thermal, voltage ride-through, voltage stability, short circuit, power quality and transient stability analysis for each of the solutions considered in the study.

• Provide the results to SCE including the drawbacks and benefits of each design for each alternative considered.

• Identify the preferred master plan and provide a detailed plan of service for this alternative.



• Use a modular approach, allowing for incremental system improvements as more generation comes online, to evaluate proposed alternatives till 2020

Tasks

1. Identify new generation, energy storage and other advanced grid technologies that may impact grid reliability and stability.

2. Perform model upgrades and refinements in two stages 2014 and 2020. Upgrades to the existing PSLF, CAPE and PSACD models from the newly developed planning toolbox.

3. Update renewable energy generator models for wind and solar generation technologies. These upgrades need to include short circuit models, dynamic variance models like clouding and short-term wind fluctuations.

4. Where required, validation of different models. 5. Identify nature, location, growth and characteristics of renewable resources in the

different areas like Tehachapi, Palm Springs, Mohave, Antelope Bailey and other areas.

6. Perform the following analyses: i. Thermal studies

ii. Contingency studies iii. Short-Circuit analysis iv. Voltage and angular stability v. Power Quality, including harmonics and flicker

vi. Voltage ride-through analysis vii. SCE relevant energy storage controllers

7. Propose mitigation solutions and alternatives for 33% renewable penetration i. Transmission alternatives and proposed ROWs

ii. FACTS devices iii. HVDC transmission lines and Back-to-Back DC interconnections. iv. Regional and inter-company interconnections v. Large power balancing and control areas.

vi. Centralized and decentralized energy storage Deliverables

• Kick-off meeting and consensus setting of expectations • Assessment of existing models and need for upgrades • Growth scenarios and characteristics of anticipated renewable resources • Results from analytics and modeling • Discussion and analysis of proposed solutions and alternatives • Proposed roadmap for grid upgrades • Final report

Project Cost The labor cost of this project is estimated for 2010 to be $980,000 based on four (4) FTE. The following table shows the estimated labor cost by tasks.




Task 1 - Identify new generation, energy storage and other advanced grid technologies that may impact grid reliability and stability.

1/4/2010 $49,000

Task 2 - Perform model upgrades and refinements in two stages 2014 and 2020. Upgrades to the existing PSLF, CAPE and PSACD models from the newly developed planning toolbox.

3/1/2010 $196,000

Task 3 - Update renewable energy generator models for wind and solar generation technologies. These upgrades need to include short circuit models, dynamic variance models like clouding and short-term wind fluctuations.

3/1/2010 $122,500

Task 4 - Where required, validation of different models. 7/18/2010 $98,000

Task 5 - Identify nature, location, growth and characteristics of renewable resources in the different areas like Tehachapi, Palm Springs, Mohave, Antelope Bailey and other areas.

8/15/2010 $49,000

Task 6 - Perform the following analysis 9/1/2010 $196,000

Task 7 - Propose mitigation solutions and alternatives for 33% renewable penetration 11/8/2010 $122,500

TOTAL $833,000



GLOSSARY WECC Western Electric Coordinating Council SAAC Situational Awareness and Analysis Center SCE Southern California Edison PG&E Pacific Gas & Electric BLM Bureau of Land Management BPA Bonneville Power Administration RTDS Real-Time Digital Simulator PMU phasor measurement unit HVDC high voltage direct curren LADWP Los Angeles Department of Water and Power PDCI Pacific Direct Current Invertie LCF Low frequency control AGC Automatic Generation Control LMP Locational Marginal Price EPRI Electric Power Research Institute PACI Pacific Alternating Current Invertie ACE area control error GCC General Control Center NERC North American Electric Reliability Council DTS dispatcher training simulator VILS voltage instability load shedding VSA voltage stability assessment ISO Independent System Operator MW megawatt kW kilowatt FTE full time engineer VAR volt-ampere reactive PSO Power Systems Outlook RAS remedial action scheme SMART® Synchronized Measurement and Analysis in Real-Time SPMS synchronized phasor measurement system PLSF Positive Sequence Load Flow FACTS flexible alternating current transmission system ATC available transfer capability Q – V curves MVAR – voltage graphs RFP request for proposal VSTF very short time forecast NWP numerical weather prediction AI artificial intelligence RPS Renewables Portfolio Standard CEC California Energy Commission AA banks Transformers 500 kV / 230 kV SCADA Supervisory control and data acquisition



HMI human machine interface SER Sequence of Event Recorder DFR digital fault recorder SVC static VAR compensator LTC load tap changing APS Arizona Public Service WAPA Western Area Power Administration FFT analysis Fast Fourier Transform Analysis PV Photovoltaic PV – QV curves Power Voltage – Reactive Power Voltage curves RSCAD model RTDS Simulator user-friendly interface software suite PSCAD model Software tool for electromagnetic transients simulation DER distributed energy resources CAPE Short Circuit Program CYME Distribution Feeder Analysis Program CPUC California Public Utilities Commission CSI California Solar Initiative RACKS RTDS Hardware/Circuit Boards IED Intelligent Electronic Device







Question 105:

Regarding FERC Sub-Account 561.200, please answer the following:a) Please identify the activities booked to this account and itemize the cost associated with

each activity that adds up to the forecasted 2010 figure of $2,398,000. b) From 2003 to 2007, the recorded adjusted expense for this account held around $1.5

million. The period I recorded adjusted expense is some 38% higher. Please explain away this increase.

c) The adjustment performed to this account, moving transmission training to a different account, has it been performed in 2007, 2006 & 2005 or is 2008 the first time for this specific adjustment to this account?

d) The forecasted amount of $2,398,000 is 50% higher than the adjusted recorded value for 2007. Besides the fact that the 2007 figure is in 2007 dollars, which explains away a portion of the percentage increase, please explain the additional activities that will be performed in 2010 that were not performed in 2007. Why such an increase from 2007 to 2010? What is the cause for the increase?


a) The table includes total adjusted expenses, prior to ISO allocation, with activity descriptions.

b) This question is comparing the 2003 -2007 totals from the ISO allocation study. The ISO study removed allocated overheads to consolidated overhead accounts 560.980 and 568.980 due to SCE's CPUC GRC format. In 2008, the allocated overheads were left in the accounts where they recorded instead of consolidated overhead accounts. The 2003-2007 versus 2008 difference is attributable to this 2003-2007 adjustment for allocated overheads.

c) The adjustment to centralize training into 566.700 is done every year.


d) 2007 and 2008 are equivalent on the same basis as described in part b. The table in part a reflects increases in the Grid Operations Grid Control Center.







Question 106:

For FERC Sub-Account 561.500 please answer the following questions and please provide all documents, data, analysis and budgets along with your answer.

a) How did SCE determine that $3.150 million of the increase forecast in this account is assigned to the ISO?

b) How much did SCE spend in 2009 for RETI phase 2 expenses? c) How did SCE calculate the $1.758 million in increased staff? d) How many employees are forecast to be hired in 2010? e) How many employees worked in the Transmission and Interconnection Planning

organization in 2008 and 2009? Provide number of hires forecast in 2010, position title and salary.

f) How many employees has SCE hired so far this year and for which positions? g) Please explain what is meant by “planning system enhancements” ER09-1534-000, Exhibit

SCE-4, p8, line 4-5. and what additional enhancements are forecast for 2010 that were not performed in 2008?

h) SCE testimony states that part of the increase to this sub-account is due to “the significant increase for interconnection studies from generators.” Please provide the number of interconnection studies SCE performed in 2005, 2006, 2007, 2008 & 2009? Please also list the number of studies SCE forecasts to perform in 2010?

i) SCE forecasts an increase for this sub-account due to the proposed acquisition of transmission expansion software tools. Please identify, for each of the previous three year, how much SCE spent on production cost software, cooperative planning software and consulting support, and renewable integration intermittency system evaluation software?

j) Please provide all invoices, bills or other documents supporting the increase in expansion software tools.

k) For this sub-account SCE is projecting cost for software to evaluate renewable integration. In FERC sub-account 560.1, SCE states that part of the increase in Advanced Technology is for studying the impacts of integrating intermittent renewable generation. Why is SCE requesting money associated with the same activity in two different sub-accounts?



a) The ISO increase is allocated based upon on the O&M Cost Allocation Study for Account 561.500 (see Volume 9, WP-AH/AI-56 of 295), with the exception of the $.971 million for the RETI study which was assigned 100% to ISO.

b) $0

c) Please see Volume 9, WP-AH/AI-13 of 295. Total labor is increasing $1.957 million ($2.542 million in 2008 to $4.499 million in 2010). $1.758 million is the portion allocated to ISO based on the O&M Cost Allocation Study for account 561.500.

d) Five.

e) There were 33 employees as of December 31, 2008 and 41 as of December 31, 2009. Five additional employees were forecasted to be hired in 2010. Please see Volume 9, WP-AH/AI-13 of 295, which provides titles and salaries.

f) At this time, none of the 2010 additions have been hired.

g) The planning activity is the process of identifying electric system addition upgrades, expansions, new lines and new substations.

The technical assessments to support the planning activity included forecasting long term load growth, performing power flow and stability studies to identify needed facilities to support reliability needs, and identifying the need for increased renewable generation access to achieve Renewable Portfolio Scenario (RPS) target in California, as examples.

Also, additional workload activities are forecasted for 2010 involving the new subregional planning group – California Transmission Planning Group (CTPG) which requires evaluating state mandated “Once Through Cooling” impacts on the grid, complying with new NERC Standards, supporting federal and state legislation mandated activities related to interconnecting renewables, developing transmission and supporting cost recovery requirements, and assessing federal and state land use regulations, and supporting corridors land permitting and siting.

h) These numbers represent studies for which SCE received Study Agreements. However, these numbers do not account for studies that were started, but the project withdrew while the study was being performed.


2005 - 152006 - 152007 - 312008 - 612009 - 1432010 - 173 forecast

i) See attachment which reflects software and maintenance expenses for the Transmission & Interconnection Planning organization.

j) The transmission expansion software tools have not been purchased. Attached is the estimate for PROMOD IV and PowerBase Suite.

k) SCE is projecting cost for software to evaluate renewable integration by the following two organizations:

1. Transmission and Interconnection Planning: The Cooperative Planning software PACT is planned to be acquired to support and assess California Renewable Energy Transmission Initiative (RETI) proposed transmission corridors and the WIRES project.

2. Advanced Technology: Software to study Ancillary Services impacts in order to support and analyze Spinning Reserve and Frequency Control issues related to renewable intermittency due to expected growth in renewable generation.


CPUC- SCE-L004 q.106 i

# Licenses Software 2007

Maintenance Cost ($)

2008 Maintenance

Cost ($)

2009 Maintenance

Cost ($)

Purchase Cost ($)

3 PSS/MUST (Maint. Fees) 16,210 14,000 N/A (prior to 2007)

10 PSS/E (Maint. Fees) 8,330 8,660 10,225 N/A (prior to 2007)

3 MatLab (Maint. Fees) 3,551 3,652 N/A (prior to 2007)

2 PS CAD

20,000 (Acquired

in 2008 and

estimated cost)

38 PSLF (company-wide) Maint. Fees 8,400 8,400 8,400

Textpad (sitewide)

40 Google Earth Pro (5/11/09)

Now provided

by SCE IT Dept

16 AutoCad LT

Now provided

by SCE IT Dept

43 Adobe Acrobat Pro (V8/9)

Now provided

by SCE IT Dept


# Licenses Software 2007

Maintenance Cost ($)

2008 Maintenance

Cost ($)

2009 Maintenance

Cost ($)

Purchase Cost ($) Contact

2 Adobe Photoshop 0 0 0 1,800

2 Adobe Illustrator 0 0 0 800

2 Adobe InDesign 0 0 0 800

43 Microsoft Visio Pro 0 0 0 6,500


Ventyx 3301 Windy Ridge Parkway Atlanta, Georgia 30339

August 14, 2009 Vishal Patel 2244 Walnut Grove Ave. Rosemead, CA 91770 [email protected] (626) 302-0371 Re: Pricing for PROMOD IV and PowerBase Suite Dear Vishal,

Ventyx is pleased to respond to your request for pricing of PROMOD IV nodal and the PowerBase data management suite.

REQUIRED SOFTWARE

Product Users Annual License*

PowerBase Data Management System 5 $80,000

PROMOD IV LMP 5 $25,000 * First year annual license fee.

DATA (optional)

Ventyx WECC database and powerflow case up to 10 $35,000 Ventyx’s proprietary database. SCE may use the publicly-available database developed by TEPPC.

TRAINING

PROMOD IV Training 10 days (labor only) up to 10 $18,000 If you have any further questions, please contact me at (916) 609-7753 or [email protected]

Sincerely,

Carl Huppert

Director

CPUC-SCE-L004 q106







Question 108:

For FERC Sub-Account 562.200 please answer the following questionsa) SCE is forecasting $1,484,000 for 2010 and shows a recorded adjusted 2008 value of

$1,227,000. In 2007, this account had a recorded and adjusted amount of $1,165,000. Please identify each category within this sub-account with its corresponding expense for the years 2006, 2007, 2008, 2009 and proposed 2010.

b) For each category within this sub account, (e.g. Relay Routines, vehicle costs...) please provide documentation or reason for the increase from 2007 to 2008.

c) For each category within this sub account, (e.g. Grid Ops, vehicle costs...) please provide documentation or reason for the increase from 2008 to 2010.


a) This question is comparing the 2003 -2007 totals from the ISO allocation study. The ISO study removed allocated overheads to consolidated overhead accounts 560.980 and 568.980 due to SCE's CPUC GRC format. In 2008, the allocated overheads were left in the accounts where they recorded instead of consolidated overhead accounts. The 2003-2007 versus 2008 difference is attributable to this 2003-2007 adjustment for allocated overheads. The 2008 to 2010 $.257 million ISO increase is due to an increase in relay routines occurring in 2009.

The table includes total adjusted expenses, prior to ISO allocation, with activity descriptions.







Question 110:

For FERC Sub-Account 566.200 please answer the following questionsa) SCE is forecasting $1,685,000 for 2010 and shows a recorded adjusted 2008 value of

$1,443,000. In 2007, this account had a recorded and adjusted amount of $1,287,000. Please identify each category within this sub-account with its corresponding expense for the years 2006, 2007, 2008, 2009 and proposed 2010.

b) For each category within this sub account, (e.g. Transmission Line Maintenance, Employee Recognition, vehicle cost ...) please provide documentation or reason for the increase from 2007 to 2008.

c) For each category within this sub account, (e.g. Transmission Line Maintenance, Employee Recognition, vehicle cost ...) please provide documentation or reason for the increase from 2008 to 2010.

d) Please provide documentation that demonstrates why SCE’s increase for this sub-account from 2004 – 2007, which is embedded in SCE’s recorded expenses, is insufficient to address its expenses in period II?


This question is comparing the 2003-2007 totals from the ISO allocation study. The ISO study removed allocated overheads to consolidated overhead accounts 560.980 and 568.980 due to SCE's CPUC GRC format. In 2008, the allocated overheads were left in the accounts where they recorded instead of consolidated overhead accounts. The 2003-2007 versus 2008 difference is attributable to this 2003-2007 adjustment for allocated overheads.

The 2008 to 2010 $0.252 million ISO increase is due to an increase in Miscellaneous Transmission for early engineering assessments of large transmission and substation projects. This activity is reflected in O&M due to its conceptual nature and is performed prior to the preliminary engineering of specific capital projects.







Question 116:

For Sub-Account 570.400, please answer the following questions:a) How did SCE determine that $2.149 million of the $3.793 million increase is assigned to

the ISO? b) How many PMA repairs or replacements did SCE perform in 2006, 2007, 2008, 2009,

and forecasted for 2010?c) How much did SCE spend in 2006, 2007, 2008 and 2009 on PMAs? d) How much did SCE spend in 2006, 2007, 2008 and 2009 on upgrading switch-rack

lighting at substations? e) SCE states in their testimony that upgrading switch-rack lighting is done for safety and

security. Please identify the priority of this task and identify the imminent threat to employee safety.

f) Provide the documents showing the cost and number of upgrades and repairs SCE performed from 2006 – 2009 for upgrading switch-rack lighting since SCE states they are doing this for safety and security concerns. Identify the specific substations and itemize the cost incurred.

g) How much did SCE spend in 2006, 2007, 2008 and 2009 to replace deteriorated trench covers? Is this a yearly ongoing program?

h) How does SCE determine a trench cover is deteriorated to the point that it needs replacement?

i) How may trench covers has SCE replaced in 2006, 2007, 2008, 2009 and projects in 2010?

j) How did SCE calculate an increase in capital work-order related expenses of $2.417 million ($1.457 million ISO)? Which capital projects in the TO5 filing require “physical relocation and electrical re-configuration of substation equipment to support the capital additions?” Provide all documents, budgets, work orders and data used to generate this response.



a) The increase allocated to ISO is based on the O&M Cost Allocation Study for account 570.400 (Volume 9, WP-AH/AI-184 of 295).

b) 2006 - 1.3112007 - 1,4252008 - 7702009 - 2,6222010 - 1,262

c) In SCE's existing system, PMA repairs are considered general maintenance and are accounted for as such. Separate accounting is not used to track these costs.

d) SCE does not possess specific documentation showing 2006 to 2009 switch-rack lighting improvements or specifically related costs. Since this is classified as a miscellaneous repair, detailed records have not been kept.

e) Safety & SecuritySwitch-rack lighting is critical to the safety of personnel moving and working in the switch-racks and cable trenches. The possibility of injury to personnel increases at any voltage level due to current exposure and close proximity to the personnel. In some locations where theft or vandalism is a problem, the switch-rack lighting is left on at night to deter criminal activity.

PrioritySubstation switch-rack lightning is typically repaired when a problem is identified by SC&M field crews or Grid Operations. Low lighting levels pose a safety risk for substation operators because they must identify specific equipment prior to switching.

f) See d) above.

g) Trench cover replacement is a yearly ongoing program. Prior to 2009, SCE did not track specific costs for trench cover replacements. This program was captured collectively, along with similar activities, under miscellaneous repair. In 2009, SCE spent $1.8 million for the trench cover program.


h) Wooden trench covers have a variable life span depending on local air and ground humidity levels along with conditions which promote dry rot and other forms of deterioration. Replacement of trench covers is done based on deterioration levels and potential employee traffic in the substation. To this end, replacing trench covers is an on-going effort to ensure their effective and intended purpose.

i) Individual trench cover replacement is not tracked. SCE tracks completion status at the substation level.

COMPLETED 50% COMPLETE

For the period 2006 - 2009 36 substations 12 substations

2010 PLANNED

COMPLETIONS

COMPLETED AS OF 1ST QUARTER

2010 2010 30 substations 8 substations

j) Capital work order related expenses include, but are not limited to, physical relocation and electrical re-configuration of substation equipment. The 2010 forecast is based on the 2003-2007 five year average of recorded work order related expense as a percentage of recorded capital (0.62%), multiplied by the 2010 capital forecast. 2008 was excluded from the five year average due to the issues with the work order related expense in that year. The majority of TDBU capital projects have a related expense component. However, a list of all projects with related expense does not exist. As indicated the forecast is based on a historical percentage of total capital, not a compilation of related expense estimates by project.



DATA REQUEST SET FERC STAFF-SCE-L004

To: FERC STAFFPrepared by: David Baker



Question 113:

With respect to SCE’s response to data request CPUC-SCE-116:

a) Please provide SCE’s total recorded expense for sub account 570.4 in 2009.

b) Please explain why it is appropriate for SCE to increase the expense associated with Predictive Maintenance Assessment (PMA) in 2010 when the forecasted PMA repairs or replacements in 2010 are half as many as in 2009.

c) Please provide the total amount to date that SCE has spent in sub account 570.4 in 2010.


a) SCE recorded $6.78 million to account 570.400 in 2009, of which $3.51 million was ISO.

b) As indicated in response to CPUC-SCE-116, SCE performed 770 PMAs in 2008 and forecast to perform 1,262 PMAs in 2010. This results in an increase of 492 PMAs over the 2008 base year, upon which SCE based its increase in PMA expense. In 2009, SCE's population of PMA activity included high volume, but low cost PMAs that were included in the total (e.g., un-energized disconnects found to be not completely latched were pushed closed and counted in the volume).

c) SCE has recorded $4.76 million to account 570.400 through July 2010.







Question 114:

In reference to SCE’s response to data request CPUC-SCE-116, please explain how SCE can forecast a $1.399 million increase in expenses for sub account 570.4 in 2010 when there are no records kept of the costs associated with PMA repairs, upgrades to switch-rack lighting, or trench cover replacements.


Question CPUC-SCE-116 requested annual totals for these specific costs, which SCE did not have. However, SCE is able to forecast these costs based on the projected level of activity and the known cost of performing these activities on a per unit basis. As a result, SCE was able to calculate its 2010 forecast increase based on the expected increase in the number of PMA repairs, switch-rack lighting upgrades, and trench cover replacements:

PMA repairs average $1,260 per repair based on 20 hours of labor per service. As indicated in SCE's response to CPUC-SCE-116 we are forecasting an increase from 770 PMAs in 2008 to 1,262 PMAs in 2010. As shown in that response, the number of PMAs performed in 2008 was low by historic standards, and therefore a substantial increase over 2008 levels was projected. The projection is below the number of PMAs performed in 2006, 2007 and 2009. This information was also provided in that earlier response.

We estimate the cost of switch-rack lighting upgrades at a transmission substation is approximately $42,000. SCE forecast to perform 10 upgrades in 2010 and there were no lighting upgrades performed in 2008. As indicated in the response to CPUC-SCE-116, this lighting is critical to the safety of SCE’s and its contractors’ personnel, and is performed when necessary.

Composite trench cover material costs approximately $25.36 per square foot and we forecast to replace an additional 14,000 square feet in 2010 (i.e, beyond that performed in 2008).


Increase Activity 2008-2010 Unit Cost Total IncreasePMA 492 $1,260 $0.62 millionSwitch-rack lighting 10 $42,000 $0.42 millionTrench Cover 14,000 sq. ft $25.36 $0.36 million

AssumptionsPMA - 20 scheduled hours per service at $57.48 loaded hourly Electrician labor and $5.52/hour associated non-labor.Switch-Rack Lighting - Verbal cost estimate from contractor for upgrading 80 light racks per station at $525 per rack. Stations of this nature typically have approximately 80 light racks on average.Trench Covers - Historical average cost per square foot of composite trench cover material (92,000 square feet - January 2005 through June 2007).







Question 117:

For Sub-Account 571.100, please answer the following questions:a) This sub-account has steadily increased from 2005 – 2008. These historical increases

were embedded in the forecast period. Please explain why the historical increase is not enough and an additional $2.304 is required for activities that occur on a yearly basis.

b) The activities described in the testimony on page 18 pertaining to this sub-account seems to indicate that the activities are associated with a life extension program, is this correct? If so, when did this program start?

c) Please breakdown the total forecasted amount for 2010 by specific activity within the sub-account. Please list all activities.

d) Please describe and provide documentation showing that the base year amount is insufficient to address the activities in this subaccount for the test year.


a & b) This is the same program described as the Transmission Life Extension Program in SCE's 2009 CPUC GRC. The activities included in the increase had minimal spending starting in 2007 and 2008, but ramped up significantly in 2009. The 2009 and 2010 increases, over 2008 recorded, are for maintenance activities aimed at slowing the deterioration of the transmission assets, so that the facilities can reach their expected useful life.

Similar to the testing of bridge structures, new testing methods have increased the awareness of stress damages due to specific regional environmental impacts on transmission assets previously thought to have only light maintenance requirements. Tower bolts and tower protective coatings are subject to accelerated loosening and degradation in certain localized climactic conditions. The tower bolts forecasted to be tightened are located in the desert areas of the system that are subjected to high winds and extreme temperature fluctuations. Both of these conditions cause tower bolts to loosen at an accelerated rate, compromising the structural integrity of the structure if not addressed. Protective coatings on towers in the urban and coastal areas were found to be substantially degraded. Left unchecked the structures will rust at a significant rate, compromising the structural integrity of the towers. The scope and priority for these activities


was found to be considerably greater than was originally suspected by performing sample testing in preparation of SCE's 2009 GRC.

c) Repair Towers $2.75 million (includes $111,000 for SCE's share of the LADWP DC intertie)Paint Towers $2.5 millionRepair Poles $1.9 millionTotal $7.15 million

d) Volume 9, WP-AH/AI-24 to 35 of 295 describes the need for this increase. Also, included in the response to M-S-R/LADWP-SCE-L002 question 84 is the Transmission Life Extension Program workpaper from SCE's 2009 CPUC General Rate Case application, which provides additional information on the need for this work.



DATA REQUEST SET M-S-R/LADWP-SCE-L002

To: M-S-R/LADWPPrepared by: David Baker



Question 084:

The following questions relate to SCE programs and studies related to plant service lives.

(a) Identify and explain all Company programs that are designed to extend plant lives.

(b) Please provide all internal life extension studies relating to any transmission plant account prepared by SCE since January 1, 1998. Life extension refers to any program, maintenance, or capital designed to extend or otherwise affect service lives and/or increase capacity of existing plant. Identify the functions and accounts to which these studies relate.

(c) Provide copy of Transmission Life Extension Program workpapers from SCE’s 2009 CPUC General Rate Case application and a list of all other such studies since 1998.


a&b) Subject to the previously provided objection, SCE is not responding to this request.

c) Attached is the Transmission Life Extension Program workpaper from SCE's 2009 CPUC General Rate Case application. The intent of life extension activities described is to slow the deterioration of capital assets, so that the facilities can reach their expected useful life, and thus reduce the amount of capital replacement expenditures that would otherwise have to be made. Page two of the attachment identifies the FERC sub-accounts where the activities record. SCE does not have any other such studies prior to that provided in the 2009 CPUC GRC.






































































Question 109:

Please explain, in detail, why SCE expensed amounts related to environmental mitigation activities labeled “Site Preparation” and “Planting of Trees” associated with the Tehachapi Project and booked to Account 571.3 rather than capitalizing such amounts. Include with you response any FERC precedent, policy or regulation relied upon in expensing these amounts.


SCE forecast a total of $3.969 million for environmental mitigation O&M in 2010. The classification of costs of this nature as an expense or capital item is performed based on the Uniform System of Accounts and a review of the nature of the costs. At the time the forecast was developed, it was not clear if the site preparation and planting activities (primarily, native ground cover) in that forecast would qualify for capital treatment. SCE has subsequently determined that the 2010 O&M forecast of $1.523 million for site preparation and $0.776 million for planting activities should be reclassified as capital.

The remaining amount of SCE's environmental mitigation O&M forecast ($1.67 million) is for watering, maintenance, and monitoring and reporting.







Question 115:

In reference to SCE’s response to data request Staff-SCE-27 relating to Account 571, Maintenance of Overhead Lines:

a) Please explain, in detail, the $6.452 million transmission right-of-way backlog and specify whether this backlog will be eliminated in 2010.

b) Please explain how SCE determined that $4.979 million more is necessary for the ISO portion of transmission maintenance.

c) Is there any requirement that the transmission right-of-way clearing work and transmission maintenance be performed in 2010? Please explain.


a) The $6.452 million increase includes $3.834 million for right-of way clearing, of which $2.448 million is allocated to ISO. The $3.834 million includes $1.0 million for backlogged right-of-way clearing due to environmental clearances and $2.835 million for other right-of-way clearing activity due to significant increases attributable to regulatory compliance requirements for clearing roads, facilities, and property (see volume 9, WP-AH/AI-37 of 295). In addition, the $6.452 million amount includes $3.969 million for the Tehachapi Renewable Transmission Project (“TRTP”) Segments 1-3 environmental impact mitigation, which is assigned 100% to ISO. Note that SCE has determined that $2.299 million of this amount is eligible for capitalization. See SCE’s response to Staff-SCE-109 and Staff-SCE-122 - Revised.

The $1 million of back-logged work is for projects delayed because SCE has not received all necessary environmental clearances to perform work on the property, including: Camp Pendleton grading; Big Creek road grading; Angeles Forest clearing work; and weed abatement/brush clearing not able to be completed due to environmental clearances. SCE's elimination of the backlog in 2010 is dependent on receipt of environmental clearances, which is provided in an approval letter from the subject agency. When SCE made its forecast in July 2009, SCE expected it would get the necessary approvals to complete the backlogged


transmission right-of-way clearing.

The total 2009 recorded right-of-way clearing activity was $9.571 million, which was nearly double 2008 recorded expense of $4.998, and exceeds SCE's 2010 forecast of $8.832 million (see volume 9, WP-AH/AI-37 of 295 BAKER). SCE believes this level of annual spending is required to address regulatory compliance requirements (i.e. fire code enforcement, weed abatement and maintaining access to facilities). If SCE does not maintain this level of clearing activity, then SCE, by allowing vegetation growth and road deterioration, will face future environmental access constraints and exponential cost increases like those occurring in the Angeles Forest and at Camp Pendleton. By allowing vegetation growth to return SCE risks the development of animal habitats and certain plant species, which become subject to additional environmental clearance constraints. By allowing access roads to deteriorate SCE can face additional engineering and grading expenses. In addition, SCE is required to maintain safe access to transmission lines to allow for inspection, maintenance, and restoration of transmission lines. The right of way clearing activity also provides fire breaks for fire crews in the event of a fire or other emergencies.

b) SCE forecast an increase to its overall transmission maintenance program, of which $4.979 million was assigned to ISO based upon SCE's O&M Cost Allocation Study. The increased transmission maintenance program, which was first identified in SCE's 2009 CPUC General Rate Case Transmission Life Extension program, ramped up in 2009 and continues through 2014. In 2009 transmission maintenance increased $3.995 million over 2008, of which $1.825 million is assigned to ISO. As discussed in Mr. Baker's testimony (volume 2, Exhibit 4, pages 14-21) these identified activities were not performed as part of normal maintenance prior to this program. Included in the program is an extensive and systematic approach to structure painting and re-coating, tower footing and erosion repairs, tower bolt re-tightening, insulators, and insulator hardware replacement. The risk associated with not performing these activities includes tower failure due to corrosion, hardware failure, insulator failure, foundation degradation, and foundation exposure due to erosion. This planned maintenance program is a much lower cost alternative versus unplanned reactive maintenance resulting from equipment failure.

c) In response to parts a and b, SCE addresses the ramifications of not performing these activities.


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 David B. Cohen

September 17, 2010

SCE‐M‐S‐R/LADWP‐27: At page 48, lines 4‐8 of his direct testimony, Mr. Cohen

states that “SCE does not collect sufficient revenues to cover its costs of

processing FERC‐jurisdictional interconnection requests.” With respect to

this testimony:

a. Please state the complete basis for this testimony.

b. Is it Mr. Cohen’s position that the amount of revenue that SCE

collected in 2008 for processing FERC‐jurisdictional interconnection

requests was below that level that SCE was permitted to collect

from FERC‐jurisdictional interconnection customers under the

applicable tariffs? If so please state the amount of revenue that Mr.

Cohen contends SCE was authorized to collect from FERC‐

jurisdictional interconnection customers under the applicable

tariffs, and provide the complete basis for Mr. Cohen’s opinion.

SCE‐M‐S‐R/LADWP‐27 Response:

a. The basis for the testimony is Mr. Baker’s workpapers for Account

566.500 which demonstrates that the amount of revenues SCE has

collected for interconnection applications is far below the direct

labor costs SCE has incurred or has forecasted to incur. At page 48

of my testimony in Table 3, I compare the GI & CD staff costs to the

revenue collected for interconnection requests.

b. I have not taken a position on this issue.


Date post:	04-Jun-2020
Category:	Documents
Upload:	others
View:	5 times
Download:	0 times

PREPARED REBUTTAL TESTIMONY OF DAVID S. BAKER ON … · PREPARED REBUTTAL TESTIMONY OF DAVID S....

Documents