REBUTTAL TO ORA AND TURN TESTIMONY ON ... · Web viewFigure VI-4 Moorpark Substation 220kV...

Application No.: A.04-12-014Exhibit No.: SCE-15, Vol. 2Witnesses: D. Lowerison

C. SilsbeeE. TakayesuR. LeeA. ThielB. Chiu

(U 338-E)

2006 General Rate CaseRebuttal Testimony

SCE-15, Vol. 2 - Rebuttal to ORA and TURN Testimony on Transmission & Distribution Capital Expenditures

Before thePublic Utilities Commission of the State of California

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Rosemead, CaliforniaMay 2005

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EXECUTIVE SUMMARY SCE is faced with the dual challenges of meeting the needs of recent increased

levels of customer growth in its service territory, while at the same time replacing aging infrastructure installed in the boom period of the 1950s and 1960s.

In response to customer and electric load growth, SCE identified capital expenditures to install new meters and upgrade existing substations, particularly in the Inland Empire area of our service territory, one of the fastest growing areas within California. In response to the challenge of an aging infrastructure, SCE identified capital expenditures to replace wood poles, underground cable, older transformers, and other vital electric system equipment and structures.

ORA has proposed radical and irresponsible reductions to our proposed expenditures. In the Load Growth category, for example, ORA wrongly assumes we can defer substation upgrades needed to handle increased customer load, recommending we accommodate overloads on SCE’s system simply by spraying transformers with a water hose. This proposal alone would jeopardize reliable service to some 40,000 customers.

In the category of Distribution Infrastructure Replacement, ORA’s proposed spending level would cause SCE to be 40,000 poles short of the requirements of Commission General Order 165.

Our Annual Circuit Review Program annually refurbishes our worst-performing circuits. ORA’s proposed funding implies the absurd – refurbishing each circuit once every 800 years!

In the categories of Distribution Circuit Breakers and Transformers, ORA comes to the bizarre conclusion that equipment age has no bearing on replacement. ORA’s proposed spending level implies an unrealistic service life of 100 years for circuit breakers and transformers.

ORA’s proposed reductions to our Infrastructure Replacement expenditures stem from its fixation on past expenditures. But recorded expenditures were affected by SCE’s financial crisis and its aftermath. Infrastructure replacement is based on engineering assessments and the increasing age and deterioration of the equipment, not on how much we spent last year or the year before. ORA’s proposed reductions to our capital expenditures would jeopardize employee safety and

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SCE-15, Vol. 2: Rebuttal To ORA And TURN Testimony On Transmission & Distribution Capital

Table Of ContentsSection Page Witness

I. INTRODUCTION..........................................................1.................................................................................All

II. CUSTOMER GROWTH.................................................4................................................................D. Lowerison

A. ORA’s 2005 And 2006 Cost-Per-Meter Analysis Is Flawed...........................................................5

B. TURN’s 2004 – 2008 Cost-Per-Meter for Customer Growth Under Estimates The Necessary Costs to Serve New Customer Connections......................................................8

C. SCE’s Line and Service Extension Tariffs Reflect Efficient Cost Sharing Between Existing and New Customers for New Service Connections 12

1. SCE’s Sub-Transmission System Costs Should Be Included In SCE’s Distribution Rates Because Of The Radial Nature Of SCE’s Sub-Transmission System...........12

2. SCE’s Rule 15 Periodic Review Is The Proper Vehicle To Revise The Residential Line And Service Extension Allowance..13..................................................C. Silsbee

3. SCE’s Data Collection And Retention Is Sufficient To Support Analysis of Cost-Causing Principles Relating To Line And Service Extension Tariffs.......................15.............................................D. Lowerison

4. SCE’s Distribution Project Information System Is In The Process Of Being Upgraded That Will Provide More Data For Future Policy Analyses....................17

5. SCE’s New Service Connection Allowance Applies to All Customers With New Bona Fide Load...............................................18

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Table Of Contents (Continued)Section Page Witness

6. TURN Provides no Policy Justification for Freezing SCE’s Allowance.....................20

III. LOAD GROWTH........................................................22..................................................................E. Takayesu

A. Introduction....................................................23

B. ORA’s Conclusions about SCE’s Rated Capacity and Operation Are Wrong...............................24

C. ORA Appears to Misunderstand SCE’s Testimony on Load Growth Projections and Temperature Adjustment...............................27

D. Risk of Project Deferrals.................................30

E. ORA’s Proposed Reductions By Project...........31

1. Ellis 220/66...........................................32

2. Vista 220/66..........................................32

3. Hinson 220/66.......................................33

4. Rush 66/16............................................34

5. Kernville 66/12......................................34

6. Summit 66/12kV...................................35

7. Santa Susana 66/12..............................35

8. San Bernardino 220/66.........................35

9. Arrowhead Reconfiguration Project.......35

10. Distribution Substation Program (DSP (BI 353).......................................................35

IV. DISTRIBUTION INFRASTRUCTURE REPLACEMENT....35...........................................................................R. Lee

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A. Overview of SCE’s Request and ORA’s Proposed Reductions......................................35

B. ORA’s Proposed $42.1 Million Reduction In 2005 And $66.9 Million in 2006 To SCE’s Proposed Spending On Distribution Wood Pole Replacement Is Based On A Flawed Analysis And Would Cause SCE To Be Out Of Compliance With The Commission’s General Orders.............................................................35

C. ORA’s Proposed Reduction Of $10 Million In 2005 And $35 Million In 2006 To SCE’s Forecast For Underground Cable Replacement Is Based On A Flawed Analysis.....................................35

D. ORA’s Proposed Reduction Of $7.9 Million In 2005 And $23.8 Million In 2006 To SCE’s Forecast For Underground Switch Replacements Is Based On A Flawed Analysis35

E. ORA’s Proposed $564,000 Reduction In 2005 And $587,000 In 2006 To SCE’s Forecast For Automatic Recloser Replacements Is Based On A Flawed Analysis...........................................35

F. ORA’s Proposed $1 Million Reduction In Both 2005 And 2006 To SCE’s Forecast For Capacitor Bank Replacements Is Based On A Flawed Analysis..........................................................35

G. ORA’s Proposal To Not Fund Replacement Of Underground Structures In 2005 And 2006 Is Based On A Flawed Analysis...........................35

H. ORA’s Proposed Reduction Of $2.3 Million In 2005 And $12.2 Million In 2006 To SCE’s ACR Circuit Refurbishment Is Based On A Flawed Analyses.........................................................35

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I. ORA’s Proposed Reduction Of $12.4 Million In 2005 And $18.4 Million In 2006 For Distribution Pole Repairs Is Based On A Flawed Analysis And A Disregard Of SCE’s Need To Comply With CPUC General Orders......................................35

J. ORA’s Recommended Reduction in Funding for Bark Beetle Pole Replacement is Appropriate 35

K. ORA’s Proposed Reduction of $7 Million in 2005 and $7.2 Million in 2006 for Subtransmission Pole Replacement and Repair is Based on Flawed Analyses and a Disregard for SCE’s Need to Comply with Regulatory Requirements35

L. TURN’s Criticisms of SCE’s Analysis Supporting Preemptive Replacement Are Flawed.............35

1. TURN’s Comment Regarding Taxes......35..................................................C. Silsbee

2. TURN’s Comment Regarding Ratemaking35

3. TURN’s Comment Regarding Service Lives of Switches...................................35........................................................R. Lee

V. DISTRIBUTION AUTOMATION....................................35.........................................................................A. Thiel

A. Introduction....................................................35

B. Contrary To ORA’s Assertions, The Material Costs For Automation Are In Line With Unit Price Used In SCE’s Cost Calculation For Each Type Of Automation Equipment.....................35

C. ORA Has Incorrectly Compared ACMI Reduction For SCE’s Circuit Breaker Replacement Program To The Distribution Automation Program..........................................................35

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D. ORA Uses Inconsistent Recorded Data To Arrive At Its Forecast For Remote Control Software And Circuit Automation..................................35

E. ORA’s Reliable Distribution Accountability Mechanism Proposal Takes Credit For SCE’s Proposed Distribution Automation Program, Which ORA’s Capital Expenditure Would Largely Disallow.............................................35

VI. SUBSTATION CAPITAL REPLACEMENTS AND OTHER CAPITAL REQUIREMENTS..........................................35..........................................................................B. Chiu

A. ORA’s Analysis of SCE’s Expenditures Failed To Distinguish Between Proactive And Reactive Programs........................................................35

B. ORA’s Reliance On Recorded Expenditure Data Is Not A Valid Indicator Of Future Expenditure Needs.............................................................35

C. Substation Infrastructure Replacement Program..........................................................35

1. Circuit Breaker Replacement Program..35

a) Bulk Power Circuit Breaker Replacement Program.................35

b) Distribution Circuit Breaker Replacement Program.................35

c) Incorrect Application of Escalation Rate by ORA................................35

d) ORA’s Recommendations not Support by Reliability Impacts Analysis.......................................35

2. Power Transformer Replacement Program................................................35

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a) Transformer Replacement Program – A Bank.......................................35

b) Transformer Replacement Program – B Bank.......................................35

3. Protection and Control Replacement Program................................................35

a) Distribution Protection and Control Replacement Program.................35

b) A/AA Control Room Upgrade........35

D. Routine Capital Replacements.......................35

1. Substation Equipment Reactive Replacement Blankets..........................35

a) Reactive Replacement Not Previously Identified in Blanket. . .35

(1) Butyl CT Replacement........35

(2) Cable Trench Cover Replacement......................35

(3) Disconnect Switch Replacement......................35

b) Reactive Replacement Blankets Recommendation........................35

2. Rule 20B Circuit Breaker Replacement. 35

E. Other Capital Requirements...........................35

1. Tools, Spare Parts and Equipment........35

2. Non-Operational Facility Blanket...........35

3. Fee Simple and Right of Way................35

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List Of FiguresFigure Page

Figure V-1 SCE And ORA Distribution Automation Forecast Comparison35Figure VI-2 Comparison of Average Man-Hours Spent On Repairs At

Different Ages For Circuit Breaker Model Types 242GA...................35Figure VI-3 SCE’s Power Transformers Cumulative End-of-Life Projection

Based On Actual Age Demographics And Historical Failure Data....35Figure VI-4 Moorpark Substation 220kV System Single Line Diagram 35Figure VI-5 Mesa Substation 220kV System Single Line Diagram........35Figure VI-6 Age Demographic of Circuit Breakers Removed From

Service.............................................................................................35

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List Of TablesTable Page

Table I-1 2005-2006 Transmission & Distribution Capital Expenditures SCE Estimated Compared To ORA.....................................................3

Table II-2 SCE Compared To ORA...........................................................5Table II-3 SCE Compared To TURN.........................................................8Table II-4 SCE’s Original And Revised Customer Growth Forecast.......11Table III-5 Total Capital Load Growth...................................................23Table IV-6 Distribution Capital Replacement Program.........................35Table IV-7 SCE Historical Costs For Underground Cable Replacement.35Table IV-8 SCE Vault Undergound Replacement Schedule...................35Table IV-9 Projected Break Even Time..................................................35Table V-10 Distribution Automation Program.......................................35Table V-11 Circuit Automation Estimated Costs...................................35Table V-12 Unit Cost Table...................................................................35Table V-13 Circuit Automation Devices................................................35Table V-14 Automation Material Costs.................................................35Table VI-15 2005-2006 Substation Capital Replacements And Other

Capital Requirements SCE Forecast Compared To ORA’s Recommendation.............................................................................35

Table VI-16 2005-2006 Substation Infrastructure Replacements SCE Forecast Compared To ORA’s Recommendation.............................35

Table VI-17 2005-2006 Substation Routine Capital Replacements And Other Capital Requirements SCE Forecast Compared To ORA’s Recommendation.............................................................................35

Table VI-18 Analysis Of ORA Calculations On DCBRP Expenditures.....35

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Error: Reference source not foundList Of Tables (Continued)

Table Page

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I.

INTRODUCTION

In this 2006 general rate case, Southern California Edison Company (SCE) forecast $6.6 billion of transmission and distribution capital expenditures over the 2004-2008 period. Subsequent to filing its application, SCE provided the Commission’s Office of Ratepayer Advocates (ORA) our recorded 2004 capital expenditures, which ORA has “accepted” in lieu of SCE’s 2004 forecast. For the 2007-2009 period, ORA proposes an attrition mechanism in lieu of SCE’s 2007-2008 forecast; ORA has not proposed any direct adjustments to SCE’s project-specific forecasts for those years. SCE rebuts ORA “acceptance” of our 2004 recorded amounts in Exhibit SCE-19. In Exhibit SCE-22, SCE rebuts ORA’s 2007-2009 proposals. The present exhibit rebuts ORA’s proposed $447 million reduction to SCE’s $2,590 million forecast of transmission and distribution capital expenditures over the 2005-2006 period. In addition, SCE rebuts various issues raised by The Utility Reform Network (TURN).

This rebuttal follows the same sequence of capital expenditure categories presented in SCE’s direct testimony:

In Chapter II, Dave Lowerison rebuts ORA’s proposed reductions to our expenditures to accommodate additional customer growth on our system. Mr. Lowerison and Carl Silsbee also rebut various proposals from TURN in the customer growth area.

In Chapter III, Erik Takayesu rebuts ORA’s proposed reductions to our estimated expenditures to expand capacity at our substations to accommodate load growth on our system.

In Chapter IV, Roger Lee rebuts ORA’s proposed reductions to our estimated expenditures for distribution infrastructure replacement.

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Also, Mr. Lee and Mr. Silsbee rebut various proposals from TURN in the distribution infrastructure area.

In Chapter V, Allen Thiel rebuts ORA’s proposed reductions to our estimated expenditures for distribution automation.

In Chapter VI, Bill Chiu rebuts ORA’s proposed reductions to our estimated expenditures for Substation Capital Replacements and Other Capital Replacements.

Table I-1, below, contrasts SCE’s 2005-2006 forecast with ORA’s.

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Table I-12005-2006 Transmission & Distribution Capital Expenditures

SCE Estimated Compared To ORASCE ORA SCE/ORA SCE/ORA

Forecast Forecast Difference PercentPart 1 - Customer Growth

2005 218,003 213,355 (4,648) -2.1%2006 221,345 210,125 (11,220) -5.1%2005-2006 Total 439,348 423,480 (15,868) -3.6%

Part 1 - Customer Requests2005 55,030 55,030 0 0.0%2006 66,680 66,680 0 0.0%2005-2006 Total 121,710 121,710 0 0.0%

Part 1 - Conversions2005 80,140 80,140 0 0.0%2006 90,448 90,448 0 0.0%2005-2006 Total 170,588 170,588 0 0.0%

Part 1 - Storms & Claims2005 31,607 31,607 0 0.0%2006 32,555 32,555 0 0.0%2005-2006 Total 64,162 64,162 0 0.0%

Part 1 - Total2005 384,780 380,132 (4,648) -1.2%2006 411,028 399,808 (11,220) -2.7%2005-2006 Total 795,808 779,940 (15,868) -2.0%

Part 2 - Load Growth2005 313,717 297,048 (16,669) -5.3%2006 398,038 389,833 (8,205) -2.1%2005-2006 Total 711,755 686,881 (24,874) -3.5%

Part 3 - Distribution Replacements2005 326,819 238,906 (87,913) -26.9%2006 401,549 224,831 (176,718) -44.0%2005-2006 Total 728,368 463,737 (264,631) -36.3%

Part 3 - Automation2005 12,934 10,733 (2,200) -17.0%2006 13,405 11,104 (2,300) -17.2%2005-2006 Total 26,339 21,838 (4,501) -17.1%

Part 4 - Substation Replacements2005 148,050 93,069 (54,981) -37.1%2006 180,149 97,749 (82,400) -45.7%2005-2006 Total 328,199 190,818 (137,381) -41.9%

Total Capital Request2005 1,186,300 1,019,888 (166,411) -14.0%2006 1,404,169 1,123,325 (280,843) -20.0%2005-2006 Total 2,590,469 2,143,214 (447,255) -17.3%

Type of Expenditure

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II.

CUSTOMER GROWTH

EXECUTIVE SUMMARY

SCE’s projected expenditures in the Customer Growth area -- $218.004 million in 2005, and $221.344 million in 2006 -- are based on annual sales forecast for residential, commercial/industrial, agricultural gross meter sets, and associated street lights and new business related expenditures.

ORA proposes $213.356 million in 2005 and $210.125 million in 2006, for a total reduction of 3.6 percent in Customer Growth capital expenditures for the same period.

ORA has ignored the higher volume of 2004 gross meter sets. Also, ORA would apply our 2004 Cost-Per-Meter to 2005 and 2006 without adjusting for cost escalation in these years. ORA’s conclusions are based on misunderstanding of SCE’s data and are not supported by ORA’s own analysis.

TURN proposes a $36.374 million reduction in Customer growth for 2004-2008. TURN’s line and service extension policy recommendations would conflict with

those developed in the recently concluded Order Instituting Rulemaking on the Commission’s Own Motion to Consider the Line Extension Rules of Electric and Gas Utilities (R.92-03-050).

TURN’s proposal to deny allowances for existing customers’ home remodels, additions, or panel upgrades when new bona fide load is added by these projects misapplies service extension policy.

SCE’s Cost-Per-Meter (CPM) and Commission approved allowance methodology reflects the principles for efficient cost sharing between existing and new customers for new service connections and should be approved.

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A. ORA’s 2005 And 2006 Cost-Per-Meter Analysis Is Flawed

ORA takes issue with our 2005-2006 Customer Growth estimates, in which we proposed cumulative spending of $439.348 million over the 2005-2006 period. ORA proposes $423.48 million, a 3.6 percent reduction to our forecast over that same period. ORA does not recommend any adjustments to SCE’s capital expenditures for Customer Requests, Conversion of Overhead Lines, and Storms and Claims.1 ORA did not address our project specific estimates for 2007-2008.2 Table II-2, below, compares SCE’s forecast to ORA’s.

Table II-2SCE Compared To ORA

(Nominal $000)SCE ORA SCE/ORA SCE/ORA

Forecast Forecast Difference PercentPart 1 - Customer Growth

2005 218,004 213,356 (4,648) -2.1%2006 221,344 210,125 (11,219) -5.1%2005-2006 Total 439,348 423,481 (15,867) -3.6%

Part 1 - Customer Requests2005 55,030 55,030 0 0.0%2006 66,680 66,680 0 0.0%2005-2006 Total 121,710 121,710 0 0.0%

Part 1 - Conversions2005 80,140 80,140 0 0.0%2006 90,448 90,448 0 0.0%2005-2006 Total 170,588 170,588 0 0.0%

Part 1 - Storms & Claims2005 31,607 31,607 0 0.0%2006 32,555 32,555 0 0.0%2005-2006 Total 64,162 64,162 0 0.0%

Part 1 - Total2005 384,781 380,133 (4,648) -1.2%2006 411,027 399,808 (11,219) -2.7%2005-2006 Total 795,808 779,941 (15,867) -2.0%

Type of Expenditure

Our Customer Growth capital expenditures are a product of the estimated number of new customer meters to be set times the cost-per-meter to set them. ORA accepts our 2005 and 2006 customer growth estimates, but disputes our forecast cost-per-meter (CPM). ORA asserts that “it is reasonable to expect that

1 ORA Report on Results of Operations (“ORA Report”), Volume 2 p. 13-C-6.2 SCE rebuts ORA’s 2004 recorded and 2007-2009 attrition proposal in Exhibit SCE-22.

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overtime labor, contract labor, and contract overtime labor costs will stabilize at current levels.”3 This assertion, which ignores the effect of the increased gross meter sets on CPM, does not support capping 2005-2006 CPM at the 2004 amount.4

The fact that actual gross meter sets in 2004 exceeded SCE’s sales forecast for that year does not lead to the conclusion that our 2004 recorded CPM would be a reasonable proxy for 2005 and 2006.

Our CPM forecast assumes that not until the volume of our “annual gross meter sets decrease below our sales forecast and our Linemen work force increases at our forecast levels, … would [SCE] expect a downward trend in our overall CPM during the 2004-2008 period.”5 ORA disputes our assumption of a continued need for overtime and contract labor to complete the new meter installations.6 ORA ignores a key fact: “in the event annual gross meter sets decrease below our sales forecast and our Linemen work force increases at our forecast levels, then we would expect a downward trend in our overall CPM during the 2004-[2006] period.”7 ORA also ignores its own testimony opposing SCE’s request for incremental funding due to an aging workforce.8

ORA correctly observes that a large portion of our CPM “is the labor required to actually install the meters.”9 ORA also acknowledges that our recorded “gross meter sets in 2004 did not decrease below SCE’s sales forecast.”10 SCE’s direct

3 ORA Report, Volume 2, p. 13-C-5.4 Id., SCE response to DR-ORA-117, Question 2.5 SCE-3, Volume 3, Part I, pp. 14-15.6 ORA Report, Volume 2, p. 13-C-5.7 SCE-3, Volume 3, Part I, pp. 14-15 (emphasis added).8 ORA Report, Volume 1, p. 6-B-9.9 ORA Report, Volume 2, p. 13-C-4.10 ORA Report, Volume 2, p. 13-C-4.

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testimony forecast 73,749 gross meter sets in 2004.11 We actually set 77,437 gross meters that year, far higher than any recorded year since 1999, at a composite cost-per-meter (CPM) of $2,922 (2004 nominal dollars).12 But ORA concludes that because we increased our Linemen work force, and thus “one of the two criteria (an increase in the Linemen work force) that SCE listed for expecting the CPM to decrease have been met … the need for overtime, contract labor, and contract overtime will be reduced.”13

ORA provides no basis for using 2004 gross meter sets as a new baseline, or for predicting a downward trend in gross meter sets. In fact, ORA ignores the recent, significant increase in gross meter sets for 2003-2004, which has continued to exert upward pressure on us to timely meet the demands of energizing new home developments, work that can not be delayed or rescheduled into subsequent years. The continued upward trend in recorded gross meter sets requires us to use overtime, contract labor, and contractor overtime, all of which increase our CPM, and which have been factored into our forecast.

Even assuming recorded 2004 unit costs were a reasonable basis from which to forecast 2005 and 2006 unit costs, that amount should be adjusted for inflation. Adding the Transmission and Distribution (T&D) capital escalation14 to the recorded 2004 CPM of $2,922 yields a $3,010 CPM for 2005, and a $3,100 CPM for 2006, both of which are higher than our forecast. Thus, ORA’s analysis, when adjusted for inflation, corroborates the reasonableness of SCE’s forecast CPM. Therefore, ORA’s proposal to use the 2004 recorded CPM for the 2005 CPM and 2006 CPM should be rejected. 11 SCE-3, Volume 3, Part I, p. 12.12 This information was provided to ORA in response to data request DR-ORA- 117, Question 2.13 ORA Report, Volume 2, p. 13-C-4 and 13-C-5 (emphasis added).14 See SCE-3, Volume 2, Chapter 8 Supporting Workpaper entitled “Capital Escalation” at pp. 13-

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B. TURN’s 2004 – 2008 Cost-Per-Meter for Customer Growth Under

Estimates The Necessary Costs to Serve New Customer Connections

TURN recommends: (1) a $36.374 million reduction to SCE’s new service connections capital forecast over the 2004-2008 period; (2) the well-vetted policies in the recently concluded Order Instituting Rulemaking (OIR) on the Commission’s Own Motion to Consider the Line Extension Rules of Electric and Gas Utilities (R.92-03-050) should be rejected; (3) allowances should not be provided for home remodels, additions or panel upgrades as provided in SCE’s Rule 16, Section F; (4) removal of the costs of subtransmission included in distribution rates; and, (5) SCE’s residential allowance be frozen at the current rate of $1,247.

Table II-3, below, compares SCE’s proposals to TURN’s. Each of TURN’s allegations is separately addressed in the following sections.

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Table II-3SCE Compared To TURN

(Nominal $000)SCE TURN SCE/TURN SCE/TURN

Forecast Forecast Difference PercentResidential Customer Growth

2004 97,118 94,852 (2,266) -2.33%2005 99,929 96,097 (3,832) -3.83%2006 101,279 97,130 (4,149) -4.10%2004-2006 Subtotal 298,326 288,079 (10,247) -3.43%2007 105,064 100,135 (4,929) -4.69%2008 108,588 102,970 (5,618) -5.17%2004-2008 Total 511,978 491,184 (20,794) -4.06%

C&I Customer Growth2004 48,728 47,595 (1,133) -2.33%2005 51,021 49,069 (1,952) -3.83%2006 52,005 49,879 (2,126) -4.09%2004-2006 Subtotal 151,754 146,543 (5,211) -3.43%2007 53,330 50,832 (2,498) -4.68%2008 54,418 51,608 (2,810) -5.16%2004-2008 Total 259,502 248,983 (10,519) -4.05%

Street Lighting Service2004 28,663 27,787 (876) -3.06%2005 29,568 28,507 (1,061) -3.59%2006 29,993 29,282 (711) -2.37%2004-2006 Subtotal 88,224 85,576 (2,648) -3.00%2007 31,062 29,973 (1,089) -3.51%2008 32,044 30,717 (1,327) -4.14%2004-2008 Total 151,330 146,266 (5,064) -3.35%

Type of Expenditure

SCE’s testimony states that our Cost-Per-Meter (CPM) has increased due in part to increased volume, a constrained work-force,15 and an increase in our prevailing wages for represented personnel.16 TURN disregards the impact on our workforce due to the higher volume of gross meters SCE has experienced in the last three years. We experienced a 15 percent increase from 2002 to 2003, and another 6 percent increase from 2003 to 2004.17 TURN claims our forecast is “flat” and that “[SCE] should be required to more efficiently schedule new customer

15 Mr. Kludjian discusses SCE’s workload planning for the Transmission and Distribution Business Unit construction and maintenance in Exhibit SCE-3, Volume1, and in his rebuttal testimony in Exhibit SCE-15, Volume 1

16 SCE-3, Volume 3, Part I, pp. 13-20, inclusive, Cost-Per-Meter Analyses 2004 through 2008.17 SCE recorded 63,463 gross meters in 2002, 73,204 gross meters in 2003, and 77,437 gross

meters in 2004.

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connection jobs.”18 As discussed in SCE’s testimony and supporting workpapers, wage increases for IBEW Local 47 represented employees will be 3.5 percent per year with many line trades (Linemen, Troublemen, Patrolmen, Senior Splicers, and some Apprentice Linemen) receiving an additional increase of 2 percent in 2004 and 3 percent in 2005.19 Moreover, with the continued increase in gross meter volume since 2003, SCE has used contract labor to meet its obligations to connect these new customers. SCE’s forecast CPM reflects these cost drivers.20

TURN, on the other hand, recommends escalating SCE’s 2003 CPM by a universal escalator that is not germane to T&D’s true costs of operations.21 Even ORA recognized that SCE’s 2004 recorded CPM was reasonable based on the 6 percent increase in the number of gross meters installed by SCE in 2004 compared to 2003 (a 22 percent increase in gross meter sets from 2002 to 2004). TURN’s analysis ignores the volume of new service connections and its impact on timely new service installations.

SCE notes a discrepancy in our 2004 and 2005 CPM, which also impacts the 2006-2008 CPM, and that will reduce our estimates. Applying our T&D capital escalation22 would reduce our new service connections estimate by approximately $18.121 million for the period 2004 -2008, as shown below in Table II-4.

18 Prepared Testimony of Jeffrey A. Nahigian in Phase I of Southern California Edison’s Test Year 2006 General Rate Case on behalf of The Utility Reform Network (TURN) (hereinafter referred to as “TURN Testimony by Jeff Nahigian”), p. 8.

19 See SCE-3, Volume 2, Chapter 8, Supporting Workpapers, pp. 13-16.20 Id.21 TURN Testimony by Jeff Nahigian, p. 8.22 See SCE-3, Volume 2, Chapter 8 Supporting Workpaper entitled “Capital Escalation” at pp. 13-

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Table II-4SCE’s Original And Revised Customer Growth Forecast

(Nominal $000)

CUSTOMER GROWTH - ORIGINAL FORECAST 2004 2005 2006 2007 2008 Total

Residential 97,118 99,929 101,279 105,064 108,588 511,977

Commercial 48,728 51,021 52,006 53,330 54,418 259,502

Agricultural 918 956 985 1,015 1,045 4,918

Street Lighting 28,663 29,568 29,993 31,062 32,044 151,330

SUBTOTAL NEW SERVICE CONNECTIONS 175,427 181,474 184,262 190,470 196,095 927,728

New Service Related 35,812 36,530 37,083 38,388 39,601 187,413

TOTAL CUSTOMER GROWTH 211,239 218,003 221,345 228,857 235,696 1,115,140

CUSTOMER GROWTH - REVISED FORECAST 2004 2005 2006 2007 2008 Total

Residential 96,007 97,657 98,975 102,676 106,118 501,433

Commercial 48,175 49,865 50,827 52,122 53,186 254,174

Agricultural 918 956 985 1,015 1,045 4,918

Street Lighting 28,543 29,034 29,426 30,526 31,549 149,077


New Service Related 35,812 36,530 37,083 38,388 39,601 187,413

TOTAL CUSTOMER GROWTH 209,455 214,041 217,295 224,725 231,499 1,097,015

CUSTOMER GROWTH - SCE REDUCTIONS 2004 2005 2006 2007 2008 Total

Residential 1,111 2,273 2,303 2,388 2,470 10,544

Commercial 554 1,156 1,179 1,208 1,232 5,328

Agriculatural - - - - - -

Street Lighting 120 534 568 536 495 2,253


New Service Related - - - - - -

TOTAL CUSTOMER GROWTH 1,784 3,962 4,050 4,132 4,197 18,125

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C. SCE’s Line and Service Extension Tariffs Reflect Efficient Cost

Sharing Between Existing and New Customers for New Service

Connections

1. SCE’s Sub-Transmission System Costs Should Be Included In

SCE’s Distribution Rates Because Of The Design Of SCE’s Sub-

Transmission System

TURN recommends disaggregating SCE’s distribution rates to remove SCE’s sub-transmission costs.23 TURN’s recommendation should be rejected. Unlike other utilities’ networked 69kV sub-transmission systems, SCE’s subtransmission facilities has network characteristics but any upgrade/additions to serve new load are primarily radial in design because these facilities serve only local load/customer growth. SCE’s Load Growth forecast depends on customer growth, which reflects historical growth rates, large project developments, and local economic conditions based on input from local cities, developers, and large customers.24 Our load forecast for 2004-2013 estimates annual growth of 2.09 percent for our service territory, predominantly in the Inland Empire (Riverside and San Bernardino County), south Orange County and its undeveloped coastal land, and the Santa Clarita Valley and Palmdale/Lancaster communities (also known as the Antelope Valley) of Los Angeles County.25

Our Load Growth and Customer Growth capital expenditures are driven by new service connections as well as additional load increases from existing customers. As such, SCE has properly included its subtransmission facilities in the calculation of distribution rates. These costs are allocated to customers similar to

23 TURN Testimony by Jeff Nahigian, p. 19.24 SCE-3, Volume 3, Part II, pp. 7-9.25 SCE-3, Volume 3, Part II, p. 10, referring to SCE-3, Volume 3, Part I-Customer Growth testimony.

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other distribution costs recovered through Commission jurisdictional distribution rates because they arise from providing distribution services. Accordingly, SCE’s residential allowance properly includes the costs of constructing, operating and maintaining our subtransmission facilities.26

2. SCE’s Rule 15 Periodic Review Is The Proper Vehicle To Revise

The Residential Line And Service Extension Allowance

TURN claims that SCE is investing more per new customer than is justified by the line and service extension allowances. In addition, TURN makes a vague recommendation that the Commission should initiate “a separate process” to reevaluate utility line and service extension policies.27 TURN’s assertions regarding the level of SCE’s current line extension amounts are without merit as the analysis is flawed, and certainly do not provide a basis for the Commission to open a broad new policy proceeding.

SCE’s Rule 15 provides applicants (typically developers) with a revenue-based allowance towards the cost of line and service extensions, with any costs beyond the allowance the responsibility of the applicant. The formula for the allowance is:

Allowance = Net Revenues / Cost of Service FactorFor residential service, net revenues are based on a typical customer’s

usage, so a single allowance value is applicable to all residential line and service extensions. As specified in the tariff, generation, transmission, public purpose programs, and certain metering and billing service revenues are excluded from

26 TURN correctly notes that on December 15, 2004, SCE filed Advice Letter 1847-E seeking approval to increase its current residential line extension allowance. Due to protests from TURN and the ORA, the Energy Division issued a proposed resolution (Resolution E-3921) addressing Edison’s request. At the time of writing this rebuttal testimony, the Commission has not voted on Resolution E-3921.

27 Prepared Testimony of Jeffrey A. Nahigian on behalf of The Utility Reform Network, May 6, 2005, Section IV.D.1.

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the calculation of the residential revenues used in calculating the allowance.28 In Advice 1847-E (December 15, 2004), SCE requested an increase in the allowance from $1247 to $2197. This advice letter was protested by TURN, and a final resolution (Resolution E-3921) is pending. The calculation which SCE presented to support the recommended line extension allowance in that Advice filing is:

Distribution Net RevenuesTOU-D1 distribution component charge

($0.05438 x 6,750 kwh/customer) $367TOU-D1 basic charge of ($0.029 x 365 days) $11

Credit for meter services, meter reading and billing

$-25

Net Revenues $353

Cost of Service Factor 0.162

Allowance (Net Revenue / Cost of Service Factor)

$2,179

In this GRC proceeding, TURN argues that the costs of providing service to new customers, assuming that such customers fully utilize the allowance, exceeds the net revenues which customers are likely to provide utilities over a 25-year period after the line and service extension. There are numerous problems with TURN’s allegation and supporting example. First, the purpose of the line and service extension allowance is to prevent existing ratepayers from being unfairly burdened by the cost of extending service to customers who are particularly costly to serve. The allowance calculates an amount that will be collected recovered rates.

Second, TURN’s use of adopted rates and marginal cost exhibits is comparing apples to oranges. The marginal costs of serving new customers may not match the revenue requirements associated with service to existing customers 28 SCE Rule 15, Section J Definitions: 1) Net Revenue- “That portion of the total rate revenues

that support SCE’s Distribution Line and Service Extension costs and excludes such items as Energy, transmission Public Purpose Programs, revenue cycle services revenues, and other revenues that do not support the Distribution Line and Service Extension costs.”

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for a wide variety of reasons, and this is an accepted part of ratemaking practice. It is well recognized that marginal cost revenues and revenue requirements (which are based on embedded costs) are not necessarily the same, and an equal percent of marginal cost (EPMC) scalar is necessary to adjust marginal cost revenues to match overall revenue requirements when allocating revenue requirements to various customer groups. In addition, adjustments to the revenue allocation and rate design process, such as rate caps and the allocation of subsidy programs (such as CARE) to other rate groups, further affect the differences between marginal cost revenues and revenue requirements.29 Thus it is the nature of the ratemaking process that revenues may not equal marginal cost, and TURN’s comparison of the two is fundamentally flawed.

In addition, the calculation that TURN has performed to conclude that the net revenues included in the allowance calculation would result in a shortfall is substantially flawed. TURN does not offer any justification for a 2.5 percent annual growth rate in revenues or for truncating the analysis after 25 years. The cost of service factor on which the allowance is based uses an analysis of asset accounts with depreciation lives between 25 and 65 years and with a simple average life of 45 years. In addition, TURN adds costs of metering and billing activities, which are specifically omitted from the allowance calculation of net revenues for the purpose of the allowance calculation. TURN double counts final line transformer O&M cost, which is already included in the customer O&M marginal cost TURN uses. Finally, TURN significantly understates the net revenues by using the prior allowance value of $1,247 per new customer instead of the current value recommended by SCE in Advice 1847-E. Using TURN’s fundamentally flawed approach, but fixing their errors by using the right cost of service factor, removing meter & revenue cycle

29 In SCE’s 2003 GRC, TURN advocated capping the residential rate increase and parties agreed to a settlement that capped the residential rate increase to ten percent.

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service related costs, and using the current allowance of $2,179 yields a slight positive 25-year NPV.

3. SCE’s Data Collection And Retention Is Sufficient To Support

Analysis of Cost-Causing Principles Relating To Line And

Service Extension Tariffs

SCE and the other California investor-owned utilities fully participated in the recently concluded Line Extension OIR. This proceeding addressed many issues, one of which was the proposed accounting treatment for utility-designed and utility-installed line extension projects and applicant-designed and applicant-installed line extensions.30 In regard to these accounting issues, the Commission stated:

[W]e will not adopt new rules based on the hope that everything would work out to the advantage of ratepayers and third party contractors.31

…When a utility’s actual cost of a job is less than its estimate, the difference is reflected in lower ratebase, just as an overrun would be recorded to ratebase. (Footnote omitted) The theory is that over time, the overruns and underruns offset each other; therefore, the net effect on ratebase resulting from the differences between estimates and actual cost, should be minimal.32

TURN cites SCE’s data request responses as a reason to begin another Commission proceeding, even suggesting a data collection workshop.33 This is not necessary. In this GRC, TURN propounded 20 separate Data Requests (DRs) regarding SCE’s Customer Growth testimony. For Residential Customer Growth, TURN requested a sample of 200 SCE work orders (“jobs”), 50 each for Budget

30 See D.03-03-032 (R.92-03-050), Alternate Opinion of Commissioner Wood on Proposed Free Inspections and Accounting Changes for Line Extensions, (mimeo) pp. 9-18, inclusive.

31 Id., at pp. 13-14.32 Id., at p. 15.33 TURN Testimony by Jeff Nahigian, p. 19.

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Items (B.I.s) 101-Residential Services, B.I. 110-Residential New Business, B.I. 118-Residential Tracts, Rule 15, and B.I. 119-Residential Backbone Installation.34 As part of this DR, TURN requested “[t]he utility’s total estimated cost for the job broken out by … [a]ny other cost items not listed above, and the “[a]mount of allowances granted and calculation of those allowances.”35 Also, TURN asked SCE to “breakout the costs reported in the column titled “Other Costs” into refundable costs and nonrefundable costs …”36 SCE provided this information. However, TURN’s testimony fails to reference or provide any analysis of the 200 jobs provided by SCE from our active files in our Distribution Project Information System (DPIS).

TURN argues: “[SCE] still does not collect sufficient information that would allow for evaluation of its customer connection policies by [TURN] or the Commission.”37 TURN references the limited “historical records on the number of units that use the nonrefundable 50 percent discount option versus the refundable option.”38 Yet, TURN ignores the data SCE provided on the refundable option and 50 percent discount option in the 200 jobs.39 Although SCE provided approximately 3,400 data points40 on the 200 jobs, TURN provides no explanation why they failed

34 DR-TURN-07, Question 1, included herein as Customer Growth – Appendix II-1.35 Id.36 DR-TURN-11, Question 1, included herein as Customer Growth – Appendix II-2.37 TURN Testimony by Jeff Nahigian, p. 18.38 Id. (TURN references SCE’s response to DR-TURN-11, Question 8, included herein as Customer

Growth – Appendix II-3) (emphasis added)39 See SCE response to DR-TURN-11, Question 7 (SCE provided summary data on Rule 15

residential refundable and discount option work orders for years 2002-2005, as currently available in SCE’s Ledgers Accounting System), included herein as Customer Growth – Appendix II-4.

40 DR-TURN-07, Question 1, requested data points, from a random sample of 200 line and service extension jobs, for a) number of units constructed; b) utility’s total estimated cost for the job(s) broken out by i) feet and cost ($/foot) of service, ii) feet and cost ($/foot) of primary or secondary line installed, iii) number of cost of transformers, iv) number of and cost of meters installed, and v) any other cost items not listed above; c) amount of allowances granted and

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to include any analysis of this data in its testimony. Accordingly, SCE has provided TURN sufficient data to evaluate the current line and service extension policies, but TURN has failed to articulate any shortcomings in the data provided.

4. SCE’s Distribution Project Information System Is In The Process

Of Being Upgraded That Will Provide More Data For Future

Policy Analyses

SCE’s DPIS is a legacy system, and the program coding required to retain all of the active data in historical records that TURN believes might be useful would be costly and not justified. SCE has initiated a new capital software project, known as the Distribution Service Request Pricing (DSRP) system to replace this legacy system by the 2nd Quarter of 2006. One of the drivers behind improving SCE’s DPIS is the Commission statement in our 2003 General Rate Case: “[SCE] may need to modify its record keeping so that it is able to keep track of the data in a manner that would allow calculation of the total line extension job costs recorded to rate base, versus total estimated costs and total allowances for the same work orders.”41 That decision was not adopted until July 2004, about a month before SCE tendered its Notice of Intent for this 2006 GRC. Prior to adoption of that decision, SCE had already initiated the project activities for developing an improved repository of work order data through the new DSRP system.

Even though TURN has failed to evaluate the data for the 200 jobs provided to them (with many of the jobs dating back to 2003, and some as far back as 2001), we believe our new DSRP will provide sufficient data to further

calculation of allowances; d) the amount of refundable advance collected from the customer; e) the amount of nonrefundable advance collected by the customer; and, f) any refunds actually granted back to the applicant. DR-TURN-11 Question 1, referring to DR-TURN-07, Question 1, requested a breakout of the costs reported in the “Other Costs” into refundable costs and nonrefundable costs.

41 See, SCE’s 2003 General Rate Case (A.02-05-004), Wood Alternate Decision, D.04-07-022, pp. 117-119. (emphasis added)

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enhance the evaluation of SCE’s costs and polices for connecting new customers. TURN has failed to demonstrate any problem with the data SCE provided or that any change to the line and service extension policies of Rules 15 and 16 is necessary.42

5. SCE’s New Service Connection Allowance Applies to All

Customers With New Bona Fide Load

Addressing SCE’s Rule 16, Section F, TURN attempts to distinguish the benefits of reinforcing the SCE system to serve added load for residential remodels, additions or panel upgrades versus new home construction.43 This issue was fully vetted in the Commission’s Line Extension OIR and in a complaint case involving a mobile home park rearrangement request, Colony Mobile Home Park v.

Southern California Edison, C.02-12-037.44 SCE Tariff Rule 16, Section F.1.a. addresses the situation in which SCE determines that our system must be reinforced or upgraded to continue delivering service. In such cases, if a customer can provide sufficient documentation of bona fide added load, the customer may be entitled to an allowance.45 The Colony decision reiterated the Commission’s longstanding policy of ensuring that customers should bear the appropriate costs.

42 See, for example, D.03-03-032 (R.92-03-050), Alternate Opinion of Commissioner Wood on Proposed Free Inspections and Accounting Changes for Line Extensions, (mimeo), p. 14 (The Commission stated, in dicta, that it “would first need a clearer indication that [the utilities are systematically overstating the potential costs in their estimates or that third-party contractors provide more accurate charges] and that a proposed change [in the accounting practices for utility-designed and utility-installed line extension projects] is reasonably likely to mitigate or eliminate that problem.”).

43 TURN Testimony by Jeff Nahigian, pp. 10-12.44 See, for example, Colony Mobile Home Park v. Southern California Edison, (Colony) D.02-12-037

(In this case, SCE did not grant allowances to a mobile home park (MHP) that desired to upgrade their customer owned distribution system from 240 volts to 480 volts when the MHP did not provide sufficient evidence of bona fide load pursuant to SCE’s Rule 15 and Rule 16.)

45 See Complaint Case No.: 02-12-037, SCE-1, Testimony of Southern California Edison Company Regarding The Colony Mobile Home Park, Ltd. And The Western Manufacturing Housing Community Association v. Southern California Edison Company, pp. 14-15, is included herein as Customer Growth – Appendix II-5.

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The complainant was not granted allowances merely to replace SCE transformers for a change in voltage request when new, bona fide load was not present.46

Once again, TURN fails to present any analysis of the additional data SCE provided in response to DR-TURN-07, Question 1.47 The requested sample provided costs and allowance information for 28 new residence jobs, 18 electric panel upgrades, and 4 home remodels. This additional information shows that 41 of the 50 jobs had nonrefundable payments, and 6 of the 28 new residence jobs were for recently constructed line extension projects, representing 217 meters out of the 251 meter total in the sample. For one panel upgrade job, the installation of a 3-phase padmount transformer was required (Job # 27-41010), for which the customer paid a nonrefundable payment of $8,924, after receiving an allowance for $1,247. As well, all of the panel upgrade jobs had some nonrefundable payment, after receiving an allowance of $1,247. Although SCE does not track, on an ongoing basis, the costs associated between new residences, home remodels and panel upgrades, the sample clearly reflects SCE’s adherence to the principles underlying the service extension tariff as approved by this Commission.

This Commission should not change Rule 16 F. SCE has continued to reasonably apply the cost-causing principles of Section F.1.a. which applies to allowances for service reinforcement due to new bona fide load, and Section F.2.b.

46 Also, see attached SCE’s response to Western Manufacturing Housing Association’s (WMA’s) Data Request (DR-WMA-01), Question 14. (SCE’s Rule 16 attachment omitted), included herein as Customer Growth – Appendix II-6.

47 DR-TURN-11, Question 3, referring to SCE’s response to DR-TURN-07, Question 1, with regard to the 50 jobs for Budget Item 101 – Residential Services, requested a) an additional column that describes whether the unit was an existing residence, new residence, home remodel, or other measure [sic]; b) an additional column that explains whether (an when) these same customers received an extension under Rule 15 and were subject to Rule 15 extension costs and allowances; and, c) confirm and provide documentation that none of these units have already received an allowance under Rule 15, and [i]f they have received an earlier allowance under Rule 15, please provide the amount and timing of that allowance; included herein as Customer Growth – Appendix II-7.

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which applies when the applicant pays SCE the total estimated costs to relocate or rearrange existing facilities.

6. TURN Provides no Policy Justification for Freezing SCE’s

Allowance

As discussed above, TURN arbitrarily recommends excluding SCE's subtransmission costs from the calculation methodology for residential allowances. Just because TURN protested SCE's Advice Letter 1847-E does not lend any merit to their recommendation when TURN has provided little, if any, analysis to support their position. As in the past, SCE's request to modify the current residential allowance has been properly addressed in our Advice filing, and a Proposed Resolution (E-3921) acknowledges SCE’s increase in the residential allowance. As TURN notes: “there may be some attractiveness to addressing the issues simultaneously for the four major energy utilities,"48 similar to that of the extensive Line Extension OIR proceedings. Subsequent to a final Commission resolution on SCE Advice Letter 1847-E there would be sufficient time to more thoroughly address these issues. If the Commission wishes to test different methods of calculating the residential line and service extension allowance, a better place to do so would be in a future generic proceeding. Accordingly, the residential allowance should not be frozen at $1,247.

48 TURN Testimony by Jeff Nahigian, p. 17.

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III.

LOAD GROWTH

EXECUTIVE SUMMARY

Over the period 2005-2006, SCE projects total expenditures of approximately $711.8 million for the system expansion and modification necessary to accommodate load growth in our service territory. SCE’s load growth expenditures are required under established design and operating criteria in order for our equipment to operate within its design ratings and maintain service reliability to our customers. They are also necessary for SCE to maintain a safe and reliable system. Adopting ORA’s proposed deferrals could negatively impact the cumulative reliability to over 40,000 SCE customers during high load periods.

ORA would have the Commission reduce SCE’s projections by approximately $24.9 million, concluding wrongly that: (1) there is a low probability that substations will reach their projected loads and exceed equipment ratings; (2) projected loads in excess of our maximum equipment ratings could be offset by ORA’s alternative engineering calculations; (3) substation equipment can be operated indefinitely at rated capacity and offset, if exceeded, by ORA’s proposed cooling procedures; and, (4) there is no risk of deferral due to items (1) through (3).

ORA’s conclusions are at odds with proper engineering analysis. In fact, recent load studies completed in 2005 have caused upward revisions to our load forecasts due to higher than projected peak loads in 2004.

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A. Introduction

SCE proposed a total of $1,841 million for load growth expenditures over the 2004-2008 period. These load growth projects are to accommodate the growth of electricity consumption in our service territory and to maintain service reliability. For the 2005-2006 period, SCE proposed $711.755 million for CPUC jurisdictional load growth projects. In addition to the 127 pages of prepared direct testimony, SCE also provided ORA 7,792 pages of workpapers supporting these expenditures. Upon receipt of SCE’s testimony, ORA commenced discovery on SCE’s load growth program methodology and expenditures, sending SCE about 22 separate questions. SCE provided to ORA both written and verbal responses to address ORA’s questions. This includes 38 pages of written response, three separate phone conversations between two separate witnesses, and one in-person meeting.

While ORA clearly had sufficient information with which to assess the reasonableness of SCE’s proposed expenditures on the load growth programs, it appears that in many instances ORA misunderstood that information.

ORA recommended $686.881 million for load growth projects, which represents a $24.874 million or 3.5 percent reduction to our forecast. Table III-5 compares SCE’s 2005-2006 load growth expenditures to ORA:

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Table III-5Total Capital Load Growth

($ Millions)Line SCE ORA SCE/ORA SCE/ORANo. Forecast Forecast Difference Percent1 LG Planning Programs2 2005 204,479 187,810 (16,669) -8.2%3 2006 280,002 276,539 (3,463) -1.2%4 2005-2006 Total 484,481 464,349 (20,132) -4.2%5 Improvement/Reinforcement6 2005 67,145 67,145 0 0.0%7 2006 78,776 74,034 (4,742) -6.0%8 2005-2006 Total 145,921 141,179 (4,742) -3.2%9 Generation Interconnection

10 2005 42,093 42,093 0 0.0%11 2006 39,260 39,260 0 0.0%12 2005-2006 Total 81,353 81,353 0 0.0%13 Total: Customer Requests14 2005-2006 Total 711,755 686,881 (24,874) -3.5%

Type of Expenditure

ORA’s approach to reviewing SCE’s load growth forecast was to select nine projects (i.e., Etiwanda 220/66, Valley-Auld-Pauba & Valley Auld Moraga, Auld 115/12, Tulare 66/12, Victor 115/12, Mira Loma 66/12, Rector 66/12, Summit 66/12, Tiefort 115/33)49, then ask through discovery how SCE determined the rated capacity and projected load.50 SCE provided ORA these calculations in a confidential data request response,51 which shows recorded peak loads at these substations for normal temperature, the addition of load growth, pre-designed transfers for load balancing purposes, and adjustments to accommodate for maximum temperature conditions. Taken together, this information leads to a year-by-year load projection for each substation. ORA also asked through discovery how SCE derived the rated capacities and load adjustments, and SCE provided this information as well. From this information, ORA reached its own

49 The numbers listed after the substation names represent the high and low sides of the transformers. For example, 66/12 would represent transformation of 66,000 volts to 12,000 volts.

50 Data requests: DR-ORA-75, DR-ORA-91, DR-ORA 134, and DR-ORA-162.51 This information SCE provided in response to ORA’s data request contains confidential and

proprietary load flow studies and other engineering data.

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conclusions as to the loading capability of SCE’s facilities, that is, how much load can be safely tolerated, and concluded that SCE could safely defer or cancel some of its load growth projects. ORA is wrong. SCE has developed reasonable and likely load projections using criteria based on industry guidelines to insure the safe, reliable operation of substation equipment.B. ORA’s Conclusions about SCE’s Rated Capacity and Operation Are

Wrong

ORA’s investigation into SCE’s load growth estimates began by determining how SCE concluded that so many of its lines and substations needed to be upgraded or supplemented. To do this, ORA selected several projects that SCE had proposed to construct and requested SCE’s peak load calculations, which SCE provided. ORA then compared this information to the substation’s rated capacity, which SCE describes as the utilization factor. Based on its comparison, ORA concludes that:

[a]t the 100% level, the facility52 can be run indefinitely, even under 10-year maximum temperature conditions. As the utilization percentage increases beyond 100%, either the facility must be cooled (with the addition of fans, or simply spraying with a water hose), or the amount of time the facility is run may be reduced.53 Upon receipt of ORA’s testimony, SCE asked ORA to provide the expected

increase in transformer capacity that would be gained by adding more fans or “simply spraying [a facility] with a water hose.” ORA responded by quoting the United States Department of the Interior – Bureau of Reclamation transformer loading manual, which states: “self-cooled transformers may have the output increased in many cases 25 to 33 percent by the addition of forced-air cooling by means of fans.”54 We agree with this statement. In fact, the rating limits on SCE’s transformers already take account of forced air cooling and are based on

52 SCE assumes that a “facility” is either a substation or substation transformer.53 ORA Report, Volume 2, p. 13-C-9, lines 19-23.

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manufacturer test reports and special overload heat runs, as recognized by industry power transformer loading guides provided by IEEE.55

What ORA apparently does not realize is that in order to gain additional capacity, we already install fans on substation transformers as a standard practice. The “100 percent utilization,” referred to by SCE in its testimony, actually represents reaching the forced air cooling limits of the transformers, which is typically 120 - 130 percent above the nameplate rating on B-bank transformers, and is consistent with recommended industry guidelines. This value is required to accommodate projected increases in load during maximum ten-year temperature conditions. It does not include any additional reserve capacity. The projected load is adjusted to account for maximum temperature conditions and cannot exceed this design limit without risking overheating and damaging the transformers. Also, the 100 percent utilization factor and forced-air cooled ratings are based on transformer loss-of-life calculations that use loading and ambient temperature profiles. These calculations assume reduced loading and ambient temperature during off-peak, so the transformers cannot be run at this limit “indefinitely” as ORA believes.

ORA also failed to provide any support for its claim that a “facility can be run indefinitely” by “simply spraying [a transformer] with a water hose.” When asked, ORA simply responded: “I do not have any similar percentages for cooling with a water hose.”56 SCE is similarly unaware of any support for ORA’s claim. Indeed, “spraying [a transformer] with a water hose” is not a technically reliable method of providing additional transformer cooling and cannot be counted on to provide reliable service to SCE’s customers. IEEE Standard C57.91-1995, page 4, states:54 ORA Response to Data Request SCE-ORA-01, Question 2, attached as Appendix III-1 to this

rebuttal testimony.55 IEEE Standard C57.91-1995.56 ORA Response to Data Request SCE-ORA-01, Question 2.

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The use of water spray equipment for supplemental cooling is not recommended for use in normal loading beyond nameplate rating. Appropriate precautions should be made for application of water spray equipment for supplemental cooling during emergency overloads. The major problem is the build up of scale on the cooling equipment due to minerals in the water. Over the long term this buildup will hinder the cooling efficiency. The spray and steam generated can also cause phase-to-phase flashover between bushings.Based on this IEEE Standard and ORA’s failure to provide any basis or

support for its “spray with a water hose” recommendation, either in its testimony or its response to SCE-ORA-01, SCE can only conclude that ORA has misunderstood and misinterpreted the utilization factor, transformer rating capacity, and cooling measures used by SCE.

ORA also claims that in order to avoid exceeding the utilization factor “the amount of time the facility is run may be reduced.”57 ORA is wrong. The amount of time a facility (substation) can be run is not controllable; the power flowing through a substation transformer and circuit is based on the power demand from the customers being served. Therefore, sufficient capacity must be available at the facility to meet peak load requirements, which occur typically between 2 and 8 p.m. If the temperature of the transformers is exceeded due to overload, some customer load must be shed. While in some cases loads can be transferred to adjacent facilities where capacity is available, that is not always possible due to capacity limitations.58 Therefore, ORA is wrong in asserting that “the amount of time the facility is run may be reduced.”C. ORA Appears to Misunderstand SCE’s Testimony on Load Growth

Projections and Temperature Adjustment

As ORA evaluated each of the nine projects it selected, it claims to have identified:

57 ORA Report, Volume 2, p. 13-C-9, lines 22-23.58 Planning such transfers prior to peak conditions is part of our normal planning process and is

always considered prior to adding a new distribution circuit or additional transformer capacity.

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An apparent discrepancy in the way SCE described how it determined the projected maximum load (the amount of load [usually measured in amps] that SCE estimates a facility will experience during peak load and temperature conditions) in its exhibits versus how it actually calculated those loads, as provided in response to an ORA data request.59

ORA then states: SCE provided a slightly different methodology for calculating the projected peak load. In these confidential computations, the calculation typically proceeds as follows:First a recorded peak load for the facility is obtained.Second, the load is adjusted for a normalized temperature.Third, projected load growth is added.Fourth, load transfers from adjacent facilities are added or subtracted.Fifth, the load is increased to account for a maximum 10-year temperature.60

ORA’s description of SCE’s methodology is correct, but SCE does not see the “discrepancy” ORA claims to have found.

Because of this phantom discrepancy, ORA proposes an alterative approach:ORA believes it makes more sense to add the 10-year maximum temperature factor before adding the additional load growth that SCE expects a facility to experience. Using hypothetical but realistic numbers, if load growth is estimated to be 300 amps, and if load transfers are estimated to be 400 amps, then the adjustment for the 10-year maximum temperature would be applied to an additional 700 amps. While the actual adjustment percentage used by SCE is confidential, for each percentage point that SCE uses to adjust for the 10-year maximum temperature, in this example an additional 7 amps of load would be added to the theoretical projected total.61

ORA’s interpretation would result in not adjusting future projected load growth for 10-year maximum temperatures, although previous year’s peaks were adjusted.

ORA claims this is a methodology outlined in SCE’s exhibit:

59 ORA Report, Volume 2, p. 13-C-10, lines 1-6.60 Id., at lines 14-23.61 ORA Report, Volume 2, p. 13-C-11, lines 6-15.

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ORA believes that the computational methodology outlined in the exhibit (which does not apply a 10-year maximum temperature adjustment to the load growth or load transfers) is a more realistic procedure than the methodology outlined in SCE’s confidential data response.62

ORA is mistaken. SCE’s testimony states:The peak load starting point is based on recorded peaks at each…[facility]…that have been adjusted to reflect a normal temperature year and a maximum expected temperature year over a ten-year period. The peak load starting point and load growth forecasts are then combined to develop a ten-year peak load forecast.63

The peak load starting points and load growth are combined on a normal temperature basis, then adjusted for a maximum temperature year, consistent with SCE’s response to ORA’s data request. The maximum temperature adjustment on the peak load starting point is done to determine how much operating reserve is available. ORA has apparently misunderstood SCE’s testimony and the methods it used.

Load growth and load transfer calculations for normal temperature conditions are made prior to other adjustments that address ten-year maximum temperature conditions. Therefore, the calculations must be temperature-adjusted to more realistically model the effect of higher temperatures on projected load.

Likewise, load transfers are planned shifts between substations that are designed to occur prior to the summer peak load day in order to avoid overloads. The load identified for transfer is determined on a pre-adjusted basis and is therefore treated similarly to load growth, reflecting the projected amount under normal temperature conditions. SCE adjusts for maximum temperature to allow sufficient operating reserve margin to serve load under projected peak temperature and load conditions above what is considered average normal temperature. In order to reserve sufficient capacity, it is necessary to adjust all normal temperature components of a substation peak, including the previous

62 Id., at p. 13-C-12, lines 9-13.63 SCE-3, Volume 3, Part II, p. 9.

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year’s peak, load growth, and pre-planned load transfers, which together reflect a realistic projection in the following years.

In data request SCE-ORA-01, ORA was asked to confirm whether or not additional load projected at a substation due to load growth would have any sensitivity to temperature. ORA responded: “It would be higher under extreme temperature conditions.” Therefore, ORA’s proposal to not temperature-adjust load growth is incorrect and leads to erroneous conclusions. ORA’s approach does not conform to sound engineering practice and the conclusions ORA reaches based on that approach would jeopardize SCE’s customers.

Furthermore, even if ORA’s methodology were correct, applying it would result in only a one percent reduction in the overall projected load growth, a negligible amount as even ORA acknowledges:

In reality, a “best estimate” for future load growth will still contain a great deal of uncertainty, which raises the question of whether any additional precision is gained by making relatively minor adjustments to load growth to account for 10-year maximum temperature adjustments.64

SCE’s experience has been that in the high growth areas where projects are typically recommended, historical load growth and response to temperature suggest there is a reasonable probability of exceeding load projections. For these reasons, SCE does not believe it would be reasonable to rely on ORA’s alternative methodology and postpone necessary upgrades.D. Risk of Project Deferrals

ORA states it was struck with how many “extreme” events would have to occur before the utilization percentage would reach 100 percent.65 These “extreme” events ORA lists include: (1) a peak load day; (2) a ten-year maximum temperature day; (3) all of SCE’s projected load growth occurring; and, (4) nearby

64 ORA Report, Volume 2, p. 13-C-12, lines 13-17.65 ORA Report, Volume 2, p. 13-C-13, lines 6-12.

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facilities transferring load to the facility being considered. ORA is wrong. These are not “extreme,” events; they are to be expected.

First, SCE experiences a peak load day every year so this is not an “extreme” event, as ORA believes, but an annual one. For example, last year’s recorded peak across the entire SCE system occurred on August 10. Second, SCE historically experiences a ten-year maximum temperature event at least once during a ten-year heat period. The last time this occurred was in 1998, nearly seven years ago. SCE has always designed its system to handle a 1-in-10 year event, which is a consistent practice among utilities in California. Third, although all projections are by nature uncertain, SCE’s load growth projections for this GRC have been corroborated by a more recent load growth study that was completed in early 2005. The increase was determined by comparing previous load projections to what was experienced in 2004. Finally, as discussed above, load transfers are planned shifts between substations that are designed to occur prior to the summer peak load day in order to avoid overloads. This is not “unlikely” it is certain. Load transfers are needed to offload other overloaded facilities and only until such time that no other transfers are available are upgrade projects identified. Therefore, experiencing the simultaneous conditions ORA characterizes as “extreme,” in fact have a reasonable probability of occurring based on SCE’s experience, and should continue to be necessary criteria for ensuring adequate capacity for SCE’s customers.

Because the conditions that create the need for these projects is a likely occurrence, there is a risk to SCE’s ratepayers by deferring the projects as ORA recommends. In a response to SCE-ORA-01, ORA states: “ORA does not believe there will be any impact to SCE’s customers” by delaying certain projects due to this extreme circumstance. ORA is wrong again. The potential impact to SCE’s customers if these facility upgrades are not completed is load shedding -- their

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lights and equipment go out. This risk is exacerbated by the loss of any distribution circuit or transformer that may occur during peak. If sufficient capacity is not provided, we would have no restoration capability because no additional reserve has been provided for, either at the substation or the distribution circuit. This would result in extended outages to customers until load is reduced during off-peak hours or until repairs can be made.

In summary, ORA misunderstands how we developed our load projections. Also, ORA assumed additional capacity at SCE’s facilities can be achieved, but in fact, that capacity is already included in SCE’s ratings. Further, ORA’s proposed approach to calculating peak loads would result in artificial and slightly lower values than what SCE projected. Therefore, ORA’s assumption that there is no risk to SCE’s customers by delaying facility upgrades is wrong. The remainder of SCE’s rebuttal to ORA addresses the specific project deferrals ORA recommends.E. ORA’s Proposed Reductions By Project

ORA recommended SCE defer nine load growth projects, seven to be deferred for one-year, and two others indefinitely (i.e., San Bernardino 220/66, Ellis 220/66, Vista 220/66, Hinson 220/66, Arrowhead 115/12, Rush 66/16, Kernville 66/12, Summit 66/12, Santa Susana 66/12). Seven of ORA’s project deferrals are based on ORA’s conclusion that there is a low probability of exceeding the utilization factors identified by SCE, ORA’s alternative approach to calculating projected loads, and ORA’s assumption of an overload capability above 100 percent utilization. Two of ORA’s project deferrals are based upon ORA’s conclusion that there is no risk to ratepayers if the substation reconfiguration projects are deferred that is required to maintain reliability to SCE’s customers.

1. Ellis 220/66

Ellis 220/66kV Substation is one of the projects for which ORA concluded that “the utilization factor is within one or two percentage points of

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100%”, and “can run fewer hours or simply be cooled by other means.”66 Ellis Substation is a 200/66kV A-bank substation that represents 800 MVA of capacity and serves an estimated 200,000 customers. The project does not require the addition of new transformers but is using reconfiguration of source lines to balance the loads within the substation, a cost effective alternative. If load projections are met or are exceeded, SCE would have to shed load due to our projection that corresponding transformer temperatures would increase beyond rated limits if overloaded. Because this project is intended to relieve the “A” section at Ellis Substation, which represents approximately 560 MVA of capacity and an estimated 65,000 customers, exceeding this value by two percentage points is equivalent to 11.2 MVA, or an estimated 2800 customers being dropped. ORA is wrong in concluding that exceeding the utilization factor under base case conditions is an acceptable practice. ORA’s recommendation to defer this project should be rejected.

2. Vista 220/66

ORA recommended deferring the Vista 220/66kV Substation upgrade for one year for the same reasons as Ellis Substation. This substation represents approximately 800 MVA of capacity and also serves the City of Riverside. The projected load growth is primarily driven by Riverside’s growth. If the transformers become overloaded, load shed schemes will need to be in place to offload customers in the City of Riverside. ORA’s basis for recommending the deferral of this project is that “ORA has concluded that projects where the utilization percentage, as calculated by SCE, is within one or two percentage points of 100% should be delayed by one year.”67 It is not known how many Riverside customers would be affected. However, for the same reasons discussed above regarding the

66 ORA Report, Volume 2, p. 13-C-14, lines 12-17.67 ORA Report, Volume 2, p. 13-C-14, lines 22-24.

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Ellis 220/66kV project, ORA’s recommendation to defer this project should be rejected.

3. Hinson 220/66

ORA recommends deferring the Hinson 220/66kV Substation upgrade for the same reasons as Ellis 220/66kV. Hinson Substation represents approximately 560 MVA of capacity and serves an estimated 80,000 customers. This project is the second phase of a project to increase capacity by adding an additional transformer that was identified to be in service in 2004. The second phase is necessary to split the operation of the transformers because the new transformer cannot be placed in service under normal load conditions. This is due to an increase in the short circuit duty in the event of faults within Hinson Substation that exceed the interrupting capability of the circuit breakers and is the cost-effective alternative to replacing and upgrading existing breakers. Without completing this second phase, it is likely that either load will be shed to maintain loading on the existing transformer banks or, we would run a high risk of breaker failure should a fault occur. Because this substation represents approximately 560 MVA of capacity and an estimated 80,000 customers, exceeding this value by one percentage points is equivalent to 5.6 MVA, or an estimated 800 customers being dropped. ORA’s recommendation to defer this project is based on that “ORA has concluded that projects where the percentage, as calculated by SCE, is within one or two percentage points of 100% should be delayed by one year.”68 For the same reasons discussed above for the Ellis 220/66kV project, ORA’s recommendation to defer this project should be rejected.

4. Rush 66/16

Rush 66/16kV Substation is another project for which ORA recommends a one year deferral. Rush Substation has approximately 100 MVA of 68 Id, at p. 13-C-15, lines 1-2.

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capacity and serves just under 20,000 customers. The upgrade is required to avoid the station exceeding 100 percent utilization to avoid shedding load under overload conditions. The scope of the project is to reconfigure the existing transformers within the substation; a cost effective alternative to purchasing and installing new transformers. ORA recommends deferral on the basis that “the utilization percentage has only slightly exceeded 100 percent.69 Each percentage point above the utilization factor is equivalent to 1 MVA, or an estimated 200 customers. As stated above, ORA’s approach of allowing substations to exceed 100 percent utilization is wrong. ORA’s recommendation to defer this project should be rejected.

5. Kernville 66/12

Kernville 66/12kV Substation is another one of the projects for which ORA recommends a one-year deferral. Kernville Substation is located in a sparsely populated area and is much smaller in size than a typical SCE Substation (3 MVA total). The Mustang circuit, as described in SCE’s direct testimony, does not have any load restoration capability through any adjacent facilities except for Kernville Substation, due to the rural nature of the area in which this substation is located. Because of the rural characteristics, the circuit is subject to higher incidences of outages. This circuit experienced 12 interruptions in 2003 alone. If an outage were to occur, approximately 2,150 customers on the Mustang circuit would be exposed to extended outages until such time that the faulted section can be repaired. Kernville does not have sufficient capacity to restore power to these customers if an outage were to occur under high load conditions, which would be corrected by the upgrade. ORA believes that this is a “theoretical concern that

69 ORA Report, Volume 2, p. 13-C-15, line 27.

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may occur under extreme conditions.”70 Because these events are not theoretical or extreme, ORA’s recommendation to defer this project should be rejected.

6. Summit 66/12kV

Summit 66/12kV Substation is another project for which ORA recommended a one-year deferral. This project is for a new substation in the area of Rancho Cucamonga and Fontana, which is currently served by three substations, the Archline, Declez, and Randall Substations. These substations serve approximately 63,000 customers and there is no planned reserve margin among the three. ORA cites a discrepancy in the operating date in the workpapers, causing some confusion as to whether the project is needed in 2006 or 2007. SCE recognizes this as a typo because this project was originally developed with a 2007 operating date several years ago and was advanced to 2006 because of previous projected loads that were exceeded since the project was identified at the substations currently serving the area. ORA is recommending this project be deferred because of “previously stated concerns whenever the utilization percentage is close to 100%.”71 Because SCE does not project being “close to 100%” but projects to exceed the maximum capacity, and because exceeding capacity is not a low probability event, ORA’s recommendation to defer an additional year should be rejected.

7. Santa Susana 66/12

Santa Susana 66/12kV Substation was one of the projects ORA would defer one year due to the utilization factor being slightly above 100 percent. Santa Susana Substation has approximately 100 MVA of capacity and serves just under 26,000 customers. The upgrade is required to avoid the station exceeding 100 percent utilization to avoid shedding load under overload conditions. ORA

70 ORA Report, Volume 2, p. 13-C-16, line 10.71 Id., at lines 25-26.

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recommends deferral on the basis that “projects with utilization percentages that are close to 100% be delayed by one year.”72 Each percentage point above the utilization factor is equivalent to 1.0 MVA, or an estimated 260 customers. SCE does not project being “close to 100%” but projects to exceed the utilization factor. As discussed above, ORA’s approach to utilization factor is wrong and its recommendation to defer this project one year should be rejected.

8. San Bernardino 220/66

The San Bernardino 220/66kV Substation is one of the projects ORA recommended for indefinite postponement. SCE’s San Bernardino Substation currently serves over 100,000 customers. ORA claims: “SCE simply stated that its planning criteria required that circuit breakers be installed to isolate the transformers from the substation busses,” and that “not having the circuit breakers does not adversely affect the overall reliability or capacity of the substation.”73

SCE’s planning criteria requires that A-bank transformers (typically 280 MVA units) be terminated on the primary side through circuit breakers rather than tied directly to substation busses. This practice decreases the risk of extended outages if a failure occurs within the Substation.74 While this substation was originally constructed without these breakers, it is prudent to upgrade to current standards in order to avert significant and immediate loss of customers. This project may be a lesser priority than other projects required to avoid significant overloads, but deferral could lead to a loss of 280 MVA, affecting an estimated 30,000 customers in the event of a fault within San Bernardino Substation.

72 ORA Report, Volume 2, p. 13-C-17, lines 4-5.73 Id., at p. 13-C-14, lines 2-5.74 SCE-3, Volume 3, Part II, p. 20.

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9. Arrowhead Reconfiguration Project

ORA recommends indefinite postponement of the Arrowhead Reconfiguration project. The project is to convert the substation from a preferred/emergency configuration, in which two lines enter the substation but only one is energized at any given time, to a two-line loop service, in which two lines are energized all the time. This project will eliminate momentary service interruptions. All of the circuits and substations that serve the Arrowhead community, about 24,000 customers, are subjected to momentary interruptions each time the line is interrupted. The reliability history indicates that the primary source line to this substation experienced approximately six interruptions in 2003. SCE acknowledges this project is a somewhat lower priority than projects to remedy substations that are severely overloaded. Nonetheless, the project is prudent given the number of customers that are affected and the frequency of interruptions. ORA’s proposed deferral of this project should be rejected.

10. Distribution Substation Program (DSP (BI 353)

ORA recommends an adjustment due to the deferral of Summit Substation and the associated distribution circuits required for the project. The distribution circuits are necessary to be constructed as part of the new Summit Substation to reduce the loading at Archline, Declez, and Randall Substations. These substations currently serve the area of Fontana and Rancho Cucamonga and are projected to exceed their rated capacities. Summit Substation could not be functional without the addition of these new circuits. Because SCE does not agree that it is acceptable to plan the system in this area with less than adequate reserve margin, SCE does not agree with deferral of the necessary distribution circuits required for the entire project. ORA’s proposed adjustment should be rejected.

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IV.

DISTRIBUTION INFRASTRUCTURE REPLACEMENT

EXECUTIVE SUMMARY

The volume of pole replacements and repairs SCE must perform are increasing due to the increased levels of inspections in past years. ORA recommends reductions in almost every category in which our forecast exceeds recorded spending – regardless of the reason or the consequence, even if performing less work will put SCE in non-compliance with regulatory requirements.

SCE proposed modest increases in preemptive replacements of underground switches and cable to deal with the reality of an aging infrastructure and to forestall an increase in the number of in-service failures. ORA discounts or denies the problem and the needed funding.

Refurbishing SCE’s worst-performing circuits is necessary to move all customers toward the same level of service. ORA rejects most of the funding for this work, recommending, in effect, an 800-year refurbishment cycle.

SCE requested funding to address the emerging problem of deteriorating concrete vaults and manholes. ORA rejects this entirely based on the absence of historical spending.

ORA would reduce funding to replace old, obsolete automatic circuit reclosers and capacitor banks, based on ORA’s extrapolations of historical spending. In short, ORA’s forecasts are all backward-looking, and ignore the consequences on SCE’s customers.

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A. Overview of SCE’s Request and ORA’s Proposed Reductions

For the period 2005-2006, SCE forecasts a total of $728.3 million for its Distribution Capital Replacement Program. ORA proposes that SCE be authorized to spend $463.7 million for this program, a 36 percent reduction to SCE’s forecast. The amounts ORA proposes would not be sufficient for SCE to meet the requirements of Commission General Orders 95 and 165. Table IV-6, below, compares SCE’s 2005-2006 Distribution Capital Replacement forecast to ORA’s proposal.75

As shown in Table IV-6, most of ORA’s proposed reductions to SCE’s Distribution Capital Replacement Program are in the categories we budget for pole replacements. The ORA’s recommendations are based entirely on analyzing our recorded costs, which are not representative of the spending levels we need for the 2005-2006 period.

Table IV-6Distribution Capital Replacement Program

75 SCE does agree with one of ORA’s proposed reductions – its $6.7 million proposed reduction to our Bark Beetle program. Fewer poles will actually need to be replaced than estimated in the original forecast which was based on an early survey of the total work scope. In fact, ORA’s proposed reduction is too low. SCE proposes to reduce its request for 2005 and 2006 by $7.8 million.

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S C E O R A S C E / O R A S C E / O R AF o r e c a s t F o r e c a s t D i f f e r e n c e P e r c e n t

2 0 0 5 1 5 2 , 9 0 0 8 7 , 9 0 0 ( 6 5 , 0 0 0 ) - 4 3 %2 0 0 6 2 1 3 , 5 0 0 6 5 , 7 0 0 ( 1 4 7 , 8 0 0 ) - 6 9 %2 0 0 5 - 2 0 0 6 T o t a l 3 6 6 , 4 0 0 1 5 3 , 6 0 0 ( 2 1 2 , 8 0 0 ) - 5 8 %

B I 4 7 7 - M i n o r P l a n t A d d i t i o n s2 0 0 5 1 3 , 9 0 5 1 , 5 0 5 ( 1 2 , 4 0 0 ) - 8 9 %2 0 0 6 1 9 , 9 4 4 1 , 5 4 4 ( 1 8 , 4 0 0 ) - 9 2 %2 0 0 5 - 2 0 0 6 T o t a l 3 3 , 8 4 9 3 , 0 4 9 ( 3 0 , 8 0 0 ) - 9 1 %

B I - 2 5 8 - E m e r g . P o l e R e p l .2 0 0 5 1 , 6 0 0 1 , 6 0 0 0 0 %2 0 0 6 1 , 6 0 0 1 , 6 0 0 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 3 , 2 0 0 3 , 2 0 0 0 0 %

S I 0 8 1 - S u b t r a n s . P o l e R e p l .2 0 0 5 1 9 , 5 4 9 1 2 , 5 0 0 ( 7 , 0 4 9 ) - 3 6 %2 0 0 6 2 0 , 1 3 6 1 2 , 9 3 6 ( 7 , 2 0 0 ) - 3 6 %2 0 0 5 - 2 0 0 6 T o t a l 3 9 , 6 8 5 2 5 , 4 3 6 ( 1 4 , 2 4 9 ) - 3 6 %

B I 5 9 4 - W o o d P o l e D i s p o s a l2 0 0 5 1 , 3 4 1 1 , 3 4 1 0 0 %2 0 0 6 1 , 3 3 2 1 , 3 3 2 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 2 , 6 7 3 2 , 6 7 3 0 0 %

B I 5 8 6 - D i s t . J o i n t P o l e T r a n s a c t i o n s2 0 0 5 ( 1 0 , 5 6 6 ) ( 1 0 , 5 6 6 ) 0 0 %2 0 0 6 ( 1 1 , 5 8 5 ) ( 1 1 , 5 8 5 ) 0 0 %2 0 0 5 - 2 0 0 6 T o t a l ( 2 2 , 1 5 1 ) ( 2 2 , 1 5 1 ) 0 0 %

S I 0 8 7 - T r a n s J o i n t P o l e T r a n s a c t i o n s2 0 0 5 ( 4 6 0 ) ( 4 6 0 ) 0 0 %2 0 0 6 ( 4 7 4 ) ( 4 7 4 ) 0 0 %2 0 0 5 - 2 0 0 6 T o t a l ( 9 3 4 ) ( 9 3 4 ) 0 0 %

B I 2 5 7 - B a r e W i r e S e r v i c e R e p l2 0 0 5 3 , 4 0 1 3 , 4 0 1 0 0 %2 0 0 6 3 , 4 0 1 3 , 4 0 1 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 6 , 8 0 2 6 , 8 0 2 0 0 %

B I 5 8 0 - D i s t r i b u t i o n T r a n s f o r m e r s2 0 0 5 1 7 , 9 2 7 1 7 , 9 2 7 0 0 %2 0 0 6 1 8 , 3 7 5 1 8 , 3 7 5 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 3 6 , 3 0 2 3 6 , 3 0 2 0 0 %

B I 2 6 9 - P r e v e n t i v e R e p l .2 0 0 5 6 0 , 8 0 0 6 0 , 8 0 0 0 0 %2 0 0 6 6 2 , 7 0 0 6 2 , 7 0 0 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 1 2 3 , 5 0 0 1 2 3 , 5 0 0 0 0 %

B I 2 6 3 - B r e a k d o w n R e p l .2 0 0 5 4 2 , 8 9 9 4 2 , 8 9 9 0 0 %2 0 0 6 4 4 , 0 9 5 4 4 , 0 9 5 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 8 6 , 9 9 4 8 6 , 9 9 4 0 0 %

B I 2 6 1 - S t r e e t l i g h t R e p l .2 0 0 5 4 , 6 0 0 4 , 6 0 0 0 0 %2 0 0 6 1 3 , 9 9 7 1 3 , 9 9 7 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 1 8 , 5 9 7 1 8 , 5 9 7 0 0 %

B I 3 7 9 - R e m o v a l o f I d l e F a c i l i t i e s2 0 0 5 2 , 5 9 7 2 , 5 9 7 0 0 %2 0 0 6 2 , 5 9 7 2 , 5 9 7 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 5 , 1 9 4 5 , 1 9 4 0 0 %

B I 3 9 5 - P r e f a b r i c a t i o n D i s t r i c t S t o r e s2 0 0 5 8 , 3 6 2 8 , 3 6 2 0 0 %2 0 0 6 8 , 6 1 3 8 , 6 1 3 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 1 6 , 9 7 5 1 6 , 9 7 5 0 0 %

B a r k B e e t l e C a p i t a l R e p l .2 0 0 5 7 , 9 6 4 4 , 5 0 0 ( 3 , 4 6 4 ) - 4 3 %2 0 0 6 3 , 3 1 8 0 ( 3 , 3 1 8 ) - 1 0 0 %2 0 0 5 - 2 0 0 6 T o t a l 1 1 , 2 8 2 4 , 5 0 0 ( 6 , 7 8 2 ) - 6 0 %

T o t a l D i s t r i b u t i o n C a p i t a l R e p l a c e m e n t2 0 0 5 3 2 6 , 8 1 9 2 3 8 , 9 0 6 ( 8 7 , 9 1 3 ) - 2 7 %2 0 0 6 4 0 1 , 5 4 9 2 2 4 , 8 3 1 ( 1 7 6 , 7 1 8 ) - 4 4 %2 0 0 5 - 2 0 0 6 T o t a l 7 2 8 , 3 6 8 4 6 3 , 7 3 7 ( 2 6 4 , 6 3 1 ) - 3 6 %

T y p e o f E x p e n d i t u r e

B I 4 8 0 - I n f r a R e p l & W o o d P o l e s

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B. ORA’s Proposed $42.1 Million Reduction In 2005 And $66.9 Million in

2006 To SCE’s Proposed Spending On Distribution Wood Pole

Replacement Is Based On A Flawed Analysis And Would Cause SCE

To Be Out Of Compliance With The Commission’s General Orders

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ORA recommends 9,512 pole replacements in 200576 versus SCE’s forecast of 14,900. ORA recommends 6,499 pole replacements in 200677 versus SCE’s forecast of 14,800.

ORA appears to misunderstand much about SCE’s pole inspection and replacement program. ORA states that Priority 1 or 2 poles may be corrected by pole top replacement if identified through visual examinations.78 This is incorrect. Currently, pole top replacements are an option only for Priority 4-Repairs. To clarify, SCE has five categories or “Priorities” for deteriorated poles. Regardless of how they are identified, poles are replaced or repaired as follows:

Poles identified as Priority 1 must replaced immediately. Poles identified as Priority 2 must be replaced within 90 days. Priority 3 poles must be replaced within one year. Priority 4-Replace poles must be replaced within three years. Priority 4-Repair poles must be repaired within three years.The fact that this schedule has changed over the past has also apparently

led to confusion on the part of ORA. As SCE explained in its response to data request DR-ORA-69, Question 2-d, the replacement schedules have changed over the past years. In 2001–2002, the replacement schedules were as follows:

Poles identified as Priority 1 must replaced immediately. Poles identified as Priority 2 must be replaced within one year. Priority 3 poles must be replaced within three years. Priority 4 poles must be repaired within five years.In addition to misunderstanding the prioritization system, ORA seems to

misunderstand how SCE schedules pole replacements. ORA seems to believe that

76 ORA Report, Volume 2, p. 13-D-14, line 22.77 Id., at p. 13-D-15, line 19.78 Id., at p. 13-D-9, lines 10-11.

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SCE schedules pole replacements past the year in which they are due.79 This is incorrect. Pole replacements are scheduled according to the assigned priority and are performed in the scheduled year unless there are circumstances beyond SCE’s control. Lack of available crews has been the major driver of our pole replacement schedule. Occasionally, poles cannot be replaced due to environmental reasons (such as nests of endangered birds) or access issues (such as washed out roads) or delays in obtaining necessary permit (from Caltrans or the Forest Service). Notwithstanding these exceptions, SCE’s policy is to make every possible effort to perform the pole replacement in the year it is due.

Its misunderstandings of SCE’s pole replacement schedule led ORA to criticize SCE’s “deferral” of replacements due in 2002 and 2003 to 2005 and 2006.

As stated in ORA’s testimony on page 13-D-13, lines 22-25, it is ORA’s observation that the number of deferred poles, i.e. 3,769 in 2005 and 2,332 poles in 2006, that were due for replacement in 2003 but were not replaced, seems excessively high compared to the number of deferred poles in 2002 and 2003.80

ORA’s conclusion is incorrect. The 3,769 replacements forecast in 2005 are replacements due in 2005 from inspections performed prior to 2004. Poles identified in 2002 as Priority 3 would not be due for replacement until 2005, i.e., three years after inspection. Similarly, the 2,332 poles forecast for replacement in 2006 were poles identified by inspections in 2003 as Priority 4-Replace poles, and due for replacement three years later, i.e., 2006.

ORA seems unclear on the requirements of GO 165. ORA’s recommendation to reduce the volume of intrusive inspections – to 89,647 in 200681 – would place SCE in noncompliance with GO 165 to the tune of 40,000 intrusive inspections. In a data request ORA was asked: “Is ORA recommending that SCE should plan on 79 ORA Report, Volume 2, p.13-D-13, lines 14-16.80 ORA Response to Data Request No. SCE-ORA-14, Question 1. Data Request Responses SCE-

ORA-14, SCE-ORA-15, and SCE-ORA-16 are attached as Appendix IV-20.81 ORA Report, Volume 2, p. 13-D-15, lines 12-17.

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performing fewer pole replacements than what would be required to comply with GO 95,” ORA responded:

ORA is not recommending that SCE should plan on performing fewer pole replacements as required to comply with G.O. 165. However, ORA understands that SCE has been cognizant of the requirements of G.O. 165 since 1999. ORA finds that SCE should have been replacing affected poles all along and should not have deferred the replacement work until 2005 and 2006 when the company filed its GRC Application.82

ORA seems confused about the requirements of the Commission’s General Orders. While perhaps a minor point, General Order 165 was published in 1997, not 1999. Also, General Order 165 establishes the requirements for pole inspections, not replacements. General Order 95 establishes requirements for pole strength and these requirements are what drive SCE’s replacement criteria and schedule once the pole has been inspected. Finally, ORA’s response implies a belief that GO 165 prescribes some sort of levelized schedule for performing the inspections. This is not the case. GO 165 simply states that: “Wood Poles over 15 years which have not been subject to intrusive inspection,” must be intrusively inspected within ten years. Ten years from the issuance of GO 165 will be March 2007, which is the date by which SCE will have intrusively inspected all poles required to comply with this requirement of GO 165. Contrary to what ORA seems to believe, GO 165 does not prescribe a specific inspection rate but allows the utility the flexibility to complete these inspections in conjunction with meeting all the other needs of its business such as meeting the demands of new customers, load growth, storms, and infrastructure replacement.

Another problem is ORA’s seemingly unrealistic expectations of our data records. SCE’s use of the Passport system for distribution equipment is relatively recent, having begun in mid-2001. Much of the data in the system was manually transferred from paper copies. Passport is a work management tool designed to

82 ORA Response in Data Request No. SCE-ORA-14, Question 9.

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ensure compliance. Data essential for day-to-day operations such as structure numbers, required work, and work due dates, are easily retrievable. Data not essential to day-to-day operations, such as the reason for a replacement occurring in past years, are more difficult to retrieve. Yet, it is those prior years’ data that forms the basis of ORA’s approach to forecasting.

Even if this data were available, using it to forecast pole replacements, which are driven by the volume of inspections, is not reasonable. The flaw with this approach is that future levels of inspections will not be the same as in the past.

Furthermore, ORA has been inconsistent in its use of that recorded data. According to ORA, its “calculations yield a total of 9,512 poles with an annual expenditure of $74.5 million for 2005.”83 This would mean that ORA would have SCE replace 3,400 fewer poles in 2005 than it replaced in 2004, despite the fact that SCE essentially met its 2004 forecast pole replacements. (SCE’s deteriorated pole replacement program replaced approximately 12,900 poles in 2004, missing its goal of 13,000 by only 4½ percent due to the record-breaking rain storms during the last weeks of 2004.)

SCE must replace a minimum of 14,900 distribution wood poles in 2005 and a minimum of 14,800 poles in 2006 in order to comply with regulations established by the CPUC. The forecast SCE provided in Exhibit SCE 3, Volume 3, Part 3, Chapter I, was our best estimate at the time based on available data. More recent data corroborates the reasonableness of our initial forecast.

SCE currently has a list of 15,673 deteriorated wood poles that must be replaced in 2005.84 We expect Priority 1 and 2 poles identified during the remainder of 2005 to add a minimum of 2,100 more poles needing to be replaced

83 ORA Report, Volume 2, p. 13-D-14, lines 21-22.84 A list of the individual structure numbers of these poles is attached as Appendix IV-1.

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in 2005 (or very early 2006) based on the number of forecast inspections85 and historic reject rates86 provided in the workpapers to our direct testimony. The resulting number 17,773 is 2,873 more than our original forecast of 14,900 poles.

ORA has proposed that SCE replace only 6,499 deteriorated poles in 2006.Relying on the same basis used in ORA’s 2005 calculations and SCE’s 2006 unit cost, ORA is recommending a total replacement of 6,499 poles with an annual expenditure of $52.4 million.87

SCE currently has a list of 4,179 poles that must be replaced in 2006.88 SCE has a list of 7,137 poles which are due for a SAM inspection in 2005.89 Based on historical SAM rejections rates gathered during the first part of 2005,90 51 percent of these SAM poles will require replacement by the end of 2006. This will add 3,639 more poles needing to be replaced in 2006. We expect at least an additional 2,000 poles needing to be replaced from other sources, as has historically occurred.91 Finally, we expect over 2,372 Priority 1 and 2 poles needing replacement in 2006 coming from intrusive and detailed inspections performed in 2006. Including the carry-over from 2005 of 2,873 poles (which SCE will schedule as early as possible in 2006 in order to minimize or eliminate non-compliance) foresees the need to replace 15,063 poles in 2006. This is 8,564 more poles than ORA proposes for 2006.

85 See SCE-3, Volume 3, Part III, Chapter I, Workpaper, p. 96, attached as Appendix IV-2.86 See SCE-3, Volume 3, Part III, Chapter I, Workpaper, p. 97, attached as Appendix IV-3.87 ORA Report, Volume 2, p. 13-D-15, lines 18-20.88 A list of the individual structure numbers of these poles is attached as Appendix IV-4.89 A list of the individual structure numbers of these poles is attached as Appendix IV-5.90 The 2005 year to date SAM rejection-for-replacement rates are shown in Appendix IV6.91 823 poles were identified for replacement in January – April 2005 from sources other than

intrusive, detailed, or SAM inspections. These poles were identified via patrols or observed while working on nearby projects, or involved major maintenance work on marginal poles. This rate of at least 2,000 per year is expected to recur in 2006.

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The more recent data discussed above corroborates the reasonableness of SCE’s forecast in the GRC. This level of work will be a challenge with the budget SCE has proposed. It will be impossible within the budget ORA proposes.C. ORA’s Proposed Reduction Of $10 Million In 2005 And $35 Million In

2006 To SCE’s Forecast For Underground Cable Replacement Is

Based On A Flawed Analysis

The problem of aging infrastructure is a growing problem facing U.S. electric utilities, as discussed in a July 2002 article in Utility Automation & Engineering

T&D:Based on research and analysis completed recently by consulting firm R.J. Rudden Associates Inc., the reliability of the nation's electric distribution system is likely to be put to the test in the future.Rudden's conclusions are based on a combination of “field analyses,” interviews with distribution engineers and managers, analysis of data from major utilities nationwide, and secondary research that relied on reports and analyses performed by some of the country's leading research, academic and industry institutions.Kevin Harper, another co-author, pointed out that transmission problems have been receiving most of the press recently, and for good reason. “A sound transmission system is the backbone of cost-effective, competitive markets, and the nation needs to get its priorities straight on this matter,” Harper said. “However, reliability and power quality-two essential ingredients to a healthy digital economy-are overwhelmingly related to distribution.” Harper pointed to the nation’s distribution system as “more critical to future reliability than either lack of generation reserves or congested transmission systems.”The report identified a number of reasons why recent trends in the traditional measures of reliability may not be telling the whole story. “First, as our research shows, while national average trends in reliability measures appear acceptable, the averages mask some challenging conditions in certain parts of the U.S.,” (third co-author Michael) Mount said. “In many parts of the country, the lack of severe weather has not stressed the integrity of many systems. Further, reliability statistics themselves do not necessarily reflect the underlying condition and age of a system. However, we do know that the distribution infrastructure is aging rapidly on many systems,

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especially in many central cities, and that without significant replacements and upgrades, reliability problems could begin to arise.”92

To deal with this challenge, SCE recommended preemptive replacement of 60 conductor-miles of underground distribution primary cable at a funding level of $10.2 million in 2005 and of 200 conductor-miles at a funding level of $35 million in 2006. ORA recommends a replacement of 1.2 miles of cable with funding of $0.17 million in 2005 and zero replacements in 2006.

SCE has demonstrated that the problem of aging infrastructure is real and daunting.93 Using ORA’s own method, we calculate that in the future 1,400 conductor-miles of underground cable will reach the end of its service life and need to be replaced on an annual basis.94 This is a seven-fold increase in the current rate of replacement.

Because there simply are no viable diagnostic methods that allow us to conclusively determine an underground cable’s proximity to end of life, we have only two choices: (1) preemptively replace cable sections determined, utilizing the best predictive methods available to be close to failure; or, (2) run our cable to failure – a choice that will lead to more circuit interruptions and lower reliability. ORA, without explicitly saying so, effectively recommends the option of running the cable to failure. SCE, by contrast, has chosen the option of preemptive replacements because of the priority we place on maintaining the high level of reliability our customers have come to expect from us.

SCE’s option is cost-justified. In its decision in SCE’s 2003 GRC, D.04-07-022, the Commission asked SCE to demonstrate that our efforts to manage reliability are cost-justified from the ratepayers’ point of view. SCE complied with the

92 “Spending on Distribution Increasing, but Reliability Still at Risk,” Electric Light & Power’s Utility Automation & Engineering T&D, July 2002.

93 See SCE’s rebuttal to ORA Report, Chapter 17.94 42,000 conductor-miles / 30 year average service life = 1,400 conductor-miles/year compared

with a current replacement rate of about 200 conductor-miles/year.

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Commission’s directive by demonstrating that preemptive replacements of infrastructure, made of the right components at the right time are indeed in the best financial interests of the ratepayer.95 SCE has provided a demonstration of how the methodology is applied to ensure that replacements of cable and switches are cost-justified.96 Unless preemptive replacements can be empirically shown to be cost-justified, SCE will not do them.

SCE’s proposal for preemptive cable replacement is modest – replacement of 0.1 percent of the system in 2005 and 0.5 percent in 2006. But ORA recommends that SCE terminate this program. It offers no consistent rationale for this recommendation. ORA rejects the cable replacement plan for 2006 because no detailed work scopes exist a year in advance of the work:

ORA is recommending $0 in expenditures for 2006 because SCE has not yet identified the cable replacements for 2006.97

Even when there are detailed work scopes - as in the case for 2005 - ORA still rejected all but 1.2 miles of the proposed cable replacements in 2005. Detailed work scopes were submitted in response to data request DR-ORA-149, Question 1,98 and seventeen conductor-miles have already been replaced in 2005 to date.

Rather, ORA appears opposed to any expenditures that impact the ratepayer even when those expenditures are justified. This is apparent in ORA’s response to SCE’s question regarding what SCE should do if its judgments about increasing 95 SCE-3, Volume 3, Part III, Chapter III, Workpaper pp. 188-205, “Toward Optimizing the

Timing of Infrastructure Replacement.” This workpaper is attached as Appendix IV-7 to this rebuttal.

96 See SCE’s Response to Data Request DR-ORA-144, Question 2 (2), attached as Appendix IV-8.97 ORA Report, Volume 2, p. 13-D-20, lines 15-16. Expecting detailed work plans a year in

advance is unrealistic. The engineering practice is to identify potential circuit section candidates, perform an evaluation of the cable’s approach to failure, assess the probabilistic benefits of replacements, perform inspections of the termination points of selected cable sections, identify work scopes, prepare work packages, and initiate work.

98 ORA Report, Volume 2, p. 13-D-20, lines 9-12.

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failures of cable are true and significant amounts of cable needed to be replaced before year-end 2008. ORA responded:

ORA recommends that SCE take whatever actions necessary to repair or replace these cables in order to continue providing service to its customers.Assuming that the Commission has not provided funding in SCE’s rates for the costs of this cable replacement, and that replacing the cable is necessary to provide services to SCE’s customers, ORA recommends that SCE use the same source of funding that it normally uses for all sources of capital expenditures.99

ORA has no better strategy for dealing with the problem of aging cable. SCE asked: “Does ORA have an alternate strategy for replacing aging underground cable?” ORA simply referred to its recommendation for replacing 1.2 miles of PILC cable in 2005 and nothing in 2006-2008.100

ORA’s apparent denial that SCE’s cable population is wearing out results in a course of action that effectively directs SCE to adopt a run-to-failure policy for its underground cable system. Such a directive will surely result in a significant increase in the number of circuit interruptions. The result could be the reliability of SCE’s system beginning to reflect that of Commonwealth Edison in Chicago in the summer of 1999.101

Finally, ORA takes issue with SCE’s unit cost of underground cable replacement. In its Exhibit SCE 3, Volume 3, Part 3, Chapter I, p. 31, (and explained in Workpapers, pp. 128-132), SCE states that the 2005 forecast unit cost

99 ORA Response to Data Request No. SCE-ORA-15, Question 12.100 ORA Response to Data Request No. SCE-ORA-15, Question 4.101 Report of the U.S. Department of Energy’s Power Outage Study Team – Findings and

Recommendations to Enhance Reliability from the Summer of 1999, March 2000, Final Report.Interim Report of the U.S. Department of Energy’s Power Outage Study Team – Findings from the Summer of 1999, January 2000.

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of replacing cable is $170,000 per conductor-mile. ORA asserts this cost should be $147,379 per conductor-mile in 2005 dollars.102

When assessing the best way to estimate the future average cost per mile for this GRC, SCE decided to use an “estimate from scratch” method rather than historical costs alone. The primary reason for this decision was the wide variability known to be inherent in smaller projects (which our past cable replacements work has been.)

Material costs are a function of length, but labor costs are not. Labor costs can vary significantly from job to job due to conditions that have no relationship to the length of the cable run. For this reason, historical data can yield seemingly inconsistent costs/mile for differing “normal” conditions. In the “estimate from scratch” method, the variables can be controlled to ensure a valid cost basis. Table VI-7 below shows the historical costs that we have experienced since 1999.

Table IV-7SCE Historical Costs For Underground Cable Replacement

102 This number is not explicitly stated by ORA but deduced from ORA’s proposed allowance of $176,855 to replace 1.2 miles of PILC cable in 2005. Ref. ORA Report, Volume 2, p. 13-D-20, lines 8-12.

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Normalize to 2003YEAR $ QTY $/mi $s @ 3%/yr Qty X esclt'd $

1999 850,000$ 6.25 136,000$ 153,069$ 956,682$ 2000 3,300,000$ 20.5 160,976$ 175,902$ 3,605,999$ 2001 -$ 0 na2002 2,900,000$ 21 138,095$ 146,505$ 3,076,610$ 2003 3,480,000$ 28 124,286$ 124,286$ 3,480,000$

TOTAL QTY 75.75 TOTAL $ 11,119,292$

AVG UNIT COST in 2003 $s 146,789$

The Std. Dev. of the "raw" unit prices= 25,944$ 18%The Std. Dev. of the "normalized" unit prices= 21,243$ 14%

USE 12.5% 18,349$

subtotal 165,138$

escalate to 2004 3% 4,954$

TOTAL 170,092$

The annual cable quantity of these samples is roughly one tenth of the size proposed in the GRC. In other words, it is not representative of the mix of labor conditions or of cable types that will be experienced in the GRC period. However, to demonstrate that our $170,000 cost is consistent with historical data, we have calculated the unit costs for each year and then normalized each year to constant 2003 dollars. This calculation shows that the annual unit costs/mile vary significantly, as expected. The standard deviation of the historical unit costs is between 14 and 18 percent. This is an indicator of the potential degree of error in using this small data sample.

By adding only 12.5 percent to the average of the small sample we arrive at a cost per mile that is consistent with the cost per mile developed using the “estimate from scratch” method. The $147,000 cost per mile ORA proposes is not consistent with any interpretation of this historical data nor has any other basis been put forth to support it.

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D. ORA’s Proposed Reduction Of $7.9 Million In 2005 And $23.8 Million

In 2006 To SCE’s Forecast For Underground Switch Replacements Is

Based On A Flawed Analysis

SCE has proposed preemptively replacing certain underground distribution switches as part of its infrastructure replacement program under Budget Item 480. ORA correctly states that some underground distribution switches are replaced under two other accounts:

It is worth mentioning that mainline switches and BURD switches are also replaced and tracked under two other accounts, “Preventive Replacement” and “Breakdown Replacement”, and at a much higher replacement level compared to the Infrastructure Replacement Program.103

However, the preemptive replacements for which SCE is requesting funding under B.I. 480 do not fall under the rubric of either of these other accounts. Budget Item 269, “Preventive Replacement,” is for the replacement of equipment that has observable indications of deterioration as noted during inspections conducted in compliance with GO 165. Budget item 263, “Breakdown Replacement,” records the replacement of equipment that has failed in service. SCE proposes to replace more switches than will be replaced under these two accounts. As stated in Exhibit SCE 3, Volume 3, Part 3, Chapter I, the reasons for these additional proposed switch replacements are system reliability and safety.

ORA claims that SCE’s distribution infrastructure is not aging and that SCE has a “stable” system in which the number of components wearing out and needing to be replaced will be the same from year to year.104 This appears to be wishful thinking and not reality. In our rebuttal to Chapter 17 of ORA’s Report on Results of Operations, we demonstrate that our cable population, pole population,

103 ORA Report, Volume 2, p. 13-D-17, lines 8-12.104 ORA Report, Volume 2, p. 17-8, lines 12-25.

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and underground distribution system are all growing older and requiring an increasing number of annual replacements.

As stated in Exhibit SCE 3, Volume 3, Part 3, Chapter I, p. 37, SCE has over 24,200 underground oil switches and fuse cabinets. Assuming a mean-time-to-failure of about 25 years, the replacement rate of a “stable” system would be about 970 per year. As indicated in its response to data request DR-ORA-132, Question 2, SCE’s replacement rate of these components is well below that rate.

In 2001, SCE replaced approximately 500 switches through inspections or failures.

In 2002, SCE replaced 600 switches through inspections or failures plus approximately 60 through preemptive replacement.

In 2003, SCE replaced approximately 500 switches through inspections or failures plus approximately 70 through preemptive replacement.

In 2004 SCE replaced approximately 590 switches through inspections or failures plus approximately 90 through preemptive replacement.

This is evidence that SCE’s switch population has not reached its “stable” replacement rate. It is continuing to age and the number of annual switch replacements will continue to increase each year.

The switches SCE proposes to preemptively replace have been targeted for their potential impact on reliability and safety. As stated in SCE 3, Volume 3, Part 3, Chapter I, page 4, many impending switch failures cannot be detected with today’s inspection tools. Many switches will fail even though they pass a GO 165 inspection. SCE experienced 85 failures of underground switches in 2001, 107 failures in 2002, and 124 failures in 2003 – all in spite of an inspection program. Unless these specific types of switches are replaced based on a preemptive basis, they will fail in service. And in-service failures of subsurface oil-filled switches will reduce SCE’s reliability.

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In-service failures of subsurface oil-filled switches also pose a safety hazard. As discussed in our response to data request DR-ORA-132, Question 3, the mineral oil used in these switches is flammable. Furthermore, electrical arcing under oil produces acetylene gas, which is highly explosive. The attachment to the referenced data request response provides a description of the magnitude of violent failures of underground oil-filled switches.105

SCE has proposed a replacement program that will significantly improve the likelihood of removing underground oil-filled switches prior to in-service failure. The switches targeted for preemptive replacement are the oldest switches in the system and those we believe most likely to fail.

Many mainline switches are at the end of their service lives -- 2,500 of these are older than 30 years. The manually operated switches (i.e., no spring-loaded contacts) are inherently more dangerous to operate. They pose operational problems due to their having been de-rated (i.e., limited) to carry only 200 amps instead of the normal 400 amps.

We have also targeted the oldest of our oil-filled BURD switches and fuse cabinets for preemptive replacement. There are 1,100 oil-filled BURD switches older than 30 years and these pose the same reliability and safety issues as posed by the mainline oil switches. While not a safety issue, the proximity of many submersible fuse cabinets to their expected end of life will impact reliability. Almost 400 submersible fuse cabinets are older than 40 years.

ORA’s forecast of the number of switches needing to be replaced completely ignores the reality of the increasing volumes of infrastructure wearing out. ORA’s forecast is backward-looking and anticipates nothing in the future other than what occurred in the past:

105 See Appendix IV-9.

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Based on the lack of data available to support an increase in the replacement rate over historical levels, and the fact that switch failures have been an on-going issue, ORA recommends continuing the level of replacement that SCE has been performing most recently.106

ORA seems to assume, incorrectly, that lower historical spending levels on switch replacement indicate this work is not important. While SCE’s expenditures on switch replacement in 2003 and 2004 fell short of the forecasts in the 2003 GRC, ORA fails to consider the broader picture and SCE’s other spending needs. SCE’s actual expenditures in 2004 in the area of infrastructure replacement exceeded the $242 million forecast made in the 2003 GRC by $3.7 million due to a larger number of poles needing to be replaced than expected. SCE’s actual expenditures in 2004 for Maintenance, Breakdown, Storm and Claims exceeded the $161 million forecast made in the 2003 GRC by $11 million due to a higher number of in-service failures and inspection-driven replacements than expected. SCE’s actual expenditures for in 2004 exceeded the $175 million new customer forecast made in the 2003 GRC by $12 million. In short, while preemptive replacement of underground oil-filled switches is extremely important to SCE due to its impact on future reliability, in the recent past, SCE has been compelled to delay some of this work to meet the more urgent needs identified above.

ORA was asked for its opinion on what it considered more important, reliability or meeting demand. ORA responded that it had no opinion on what is the higher priority.107 SCE does not have the luxury of taking no position on how it deals with the challenges of an aging infrastructure. Inaction is a choice – but the wrong choice. And a reactive approach fails to serve the best interests of its customers or its employees. Therefore, SCE’s proposed program of preemptive cost-justified replacements of targeted underground oil switches and its oldest submersible fuse cabinets is appropriate and should be funded.

106 ORA Report, Volume 2, p. 13-D-17, lines 13-18.107 ORA Response to Data Request No. SCE-ORA-15, Question 11.

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E. ORA’s Proposed $564,000 Reduction In 2005 And $587,000 In 2006

To SCE’s Forecast For Automatic Recloser Replacements Is Based On

A Flawed Analysis

SCE began performing preemptive replacements of Automatic Reclosers (ARs) in 2000 in response to a relatively high failure rate and the importance of these components to system reliability. SCE proposes to continue its preemptive replacement program for ARs that are either of an obsolete design or believed to be close to the end of their services lives. SCE proposes to replace 80 ARs in 2005-2008 at a rate of 20 per year.108

ORA proposes that this replacement rate be cut in half, to ten ARs per year. ORA’s going-forward rate is the average of the annual replacement rates during the 2002-2004 period:

Since SCE did not adequately support its forecasted number of ARs, ORA recommends looking back at the company’s AR replacement history to determine the forecast for years 2005 and 2006. The three-year average number of ARs replaced for years 2002-2004 is 10 ARs. ORA recommends a replacement rate of 10 ARs each year for 2005 and 2006 using SCE’s unit cost as the basis for the forecast.109

ORA overlooks the fact that SCE replaced 22 ARs in 2000, and 21 in 2002. No replacements were possible in 2001 due to the financial crisis. Only nine were replaced in 2003 and none in 2004 due to lineman resource limitations and corporate financial constraints due largely to the priority of meeting customer demand. (See SCE’s response above in rebuttal to Switches). Yet, our priority of meeting customer demand should not be construed as negating the need for infrastructure replacement.

108 SCE-3, Volume 3, Part III, Chapter I, p. 42.109 ORA Report, Volume 2, p. 13-D-21, lines 9-14.

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The preemptive replacement rate of ARs proposed by ORA is insufficient. As stated in our response to data request DR-ORA-132, Question 7, SCE has replaced ARs, preemptively or post-failure, at an annual average rate of 42 per year.

ORA’s proposed cuts will have a real impact on system reliability and safety. ARs are installed only on those circuits where interruptions have a relativity large impact on reliability, and because the test interval for the vast majority of our ARs is only once every five years, dependable ARs are important.

ARs are also important to safety. On long circuits where the electrical resistance of the ground is high, ARs are necessary to ensure that ground faults near the end of the circuit are detected and isolated. On these types of circuits, failed overhead conductors that are not isolated by an AR could be left energized in areas accessible to the public and pose an electrocution hazard. Finally, ARs are frequently installed on circuits located in wilderness/rural areas. Should a circuit experience a situation where a tree limb or branch contacts the overhead conductors, the AR is designed to open the circuit and keep it open in order to prevent initiation of a fire. For all these reasons, SCE needs to increase the dependability of its ARs by performing more preemptive replacements of old ARs rather than waiting for in-service failures to occur.

SCE’s population of ARs is very old with over 100 ARs older than 40 years. Given the importance of dependable ARs, a program to preemptively replace 80 of SCE’s oldest ARs in the years 2005 through 2008 at the modest rate of 20 per year is in the best interest of its customers. ORA’s contrary recommended funding level is irresponsible and should be rejected.

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F. ORA’s Proposed $1 Million Reduction In Both 2005 And 2006 To

SCE’s Forecast For Capacitor Bank Replacements Is Based On A

Flawed Analysis

SCE has requested funding for the replacement of 410 capacitor banks and 800 capacitor switches on an annual basis between 2004 and 2008. The requested funding is based on forecast replacement rates and unit costs. ORA disregards SCE’s forecast and instead focuses solely on past expenditures:

However, with the limited data provided, ORA was able to conclude that the trend for replacing capacitor banks is increasing. The recorded cost for replacing capacitor banks in 2004 is $5.8 million compared to 2003 recorded cost of $3.4 million. ORA agrees with SCE’s constant forecast for years 2004-2008 as presented in testimony. Therefore, ORA recommends escalating the recorded cost of 2004 as forecast expenditure for 2005 and 2006.110

Although ORA acknowledges an upward trend in the replacement of capacitor banks, it freezes future replacement rates at the 2004 level. In 2004, SCE spent $5,799,000 for capacitor replacements. ORA proposes this same amount, adjusted for inflation, for 2005.111

ORA’s proposed funding will not meet the need SCE foresees to maintain its population of capacitor banks and switches. In 2004, SCE expended $5,799,000 on capacitor and switch replacements. This work involved replacement of 379 capacitor banks, removal (without replacing) 51 capacitor banks, and replacement of 190 capacitor switches.

This work in 2004 was less than what SCE forecasts going forward. As stated in Exhibit SCE 3, Volume 3, Part 3, Chapter I, page 45, SCE forecasts replacing 410 capacitor banks and 800 capacitor switches each year in 2005 through 2008.

110 ORA Report, Volume 2, p. 13-D-22, lines 13-19.111 ORA misstates the amount SCE spent in 2003 as $3.4 million. The actual amount was $4.4

million as stated in SCE’s attached response to DR-ORA-132, Question 9.

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Capacitor banks are critical to SCE’s distribution system. As stated in Exhibit SCE 3, Volume 3, Part 3, Chapter I, capacitors are necessary for maintaining system voltage. The consequences of inadequate voltage can be even more severe than a circuit interruption. Voltage drops can damage appliances with larger motors such as refrigerators, washing machines, and air conditioners. Less likely but more severe in impact, inadequate capacitance (VAR support) can lead to grid instability and even grid collapse resulting in massive blackouts. The critical nature of maintaining sufficient VAR support is evident in the high level of funding provided for capacitor replacement even during the financial crisis of 2001.

An annual replacement rate of 410 capacitor banks per year (3 percent of the system) is reasonable. An annual replacement rate of 800 capacitor switches per year (3 percent of the total capacitor switch population) is reasonable. SCE’s GRC request of $6,890,000 for capacitor bank and switch replacements in 2005 is reasonable.112 ORA’s proposed funding is based on an arbitrary projection of historical experience rather than any careful analysis of future replacement needs or an understanding of the important role capacitors play in SCE’s distribution system.

112 The recorded cost data from 2004 can be used to corroborate SCE’s cost forecast for 2005:• Subtracting the cost of removing 400 capacitors at a cost of $5,000 each, the cost of

replacing capacitors and switches is $5,799,000 – (51 cap removals x $5,000) = $5,544,000.• This cost is broken down into $5,544,000 = $5,009,000 for 379 cap replacements and

$535,000 for 400 switch replacements.• The uninflated cost of replacing 410 capacitor banks in 2005 will be 410/378 x $5,009,000 =

$5,433,000.• The uninflated cost of replacing 800 capacitor switches in 2005 will be 800/400 x $500,000

= $1,000,000.• SCE expects to remove-only (not replace) 55 capacitor banks in 2005. The uninflated cost of

these capacitor removals in 2005 will be 55 cap removals x $5,000 = $275,000.• The inflated total for 2005 will be ($5,433,000 + $1,000,000 + $275,000) x 1.03 =

$6,909,000.

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G. ORA’s Proposal To Not Fund Replacement Of Underground

Structures In 2005 And 2006 Is Based On A Flawed Analysis

SCE is facing an unprecedented challenge with the aging of its underground structures. Many vaults and manholes have deteriorated to the point they must be replaced.

ORA is under the impression, that replacements of deteriorated vaults have been a regular part of SCE’s historic maintenance program, and so no additional funding is required:

As shown in SCE’s response to ORA data request, in the past when vaults were identified as damaged, they were replaced, removed or relocated and the expenses for these work activities were accounted for elsewhere and not under the Infrastructure Replacement Program. ORA questions the need to include these work activities and the associated costs in this account, especially since there is no data which shows that vaults need to be preemptively replaced.113

ORA has misunderstood SCE’s response to data request DR-ORA-132, Question 14. Contrary to ORA’s belief, no replacement of deteriorated vaults of the type proposed in our 2006 GRC application have occurred prior to 2004. For example, SCE provided a list of 30 vaults that had been replaced in 2004. However, thirteen of these were vault removals or replacements requested and paid for by the customer. Four were vault removals or replacements performed as part of and funded by large construction projects such as freeway projects. Ten records were found to be in error where no vault replacement or removal occurred at all. One replacement was a refurbishment of a “stacked” vault.114 Of the thirty vaults reported as having been replaced in 2004, only two were actual replacements of deteriorated pre-cast concrete structures as described in SCE’s testimony. These two vaults, (Structure # V5127267 and Structure # V5061483)

113 ORA Report, Volume 2, p. 13-D-24, lines 6-12.114 “Stacked” vaults are significantly different in design from SCE’s standard type of vault, are

relatively rare, and are much easier and less expensive to replace than the pre-cast concrete vaults and manholes SCE described in SCE’s testimony.

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as well as one manhole (Structure # MS5127269), were the first structures replaced under the Infrastructure Replacement program that SCE is proposing to deal with the issue of deteriorating concrete vaults and manholes. ORA is incorrect in its belief that deteriorated pre-cast vaults and manholes have been replaced prior to 2004 under other accounts.

The problem with deterioration of major pre-cast concrete vaults and manholes is a newly emerging one. Around 1964, the concrete industry began transitioning from poured-in-place concrete structures to pre-cast concrete structures. The reasons for this transition included lower costs and faster construction times. Over the following decades, the methodology evolved and more stringent standards were developed to ensure strength and longevity. However, during the first roughly twenty years, lessons were still being learned about adequate rebar depth, chemical admixtures, and reactive aggregate. The result was that structures installed between 1964 and about 1983 have shown faster than average rates of deterioration. The problem with deteriorating concrete vaults and manholes involves employee safety as well as reliability. Left alone, concrete walls will weaken and collapse.

SCE has identified the problem and its scope, has provided a reasonable and proactive approach to dealing with it, and has already embarked on working it. SCE replaced two deteriorated vaults and one manhole in 2004 as part of its Infrastructure Replacement Program. SCE will replace five deteriorated vaults in 2005 per our forecast. The status of these replacements in 2005 is as follows:

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Table IV-8SCE Vault Undergound Replacement Schedule

Structure Number Location Status

V5085487 Irvine CompleteV5090871 Yorba Linda CompleteV5023601 Ventura CompleteV5017277 Visalia To be completed by

June 2005V5138376 San Fernando To be completed by

September 2005The problem with deteriorating pre-cast vaults and manholes is an emerging

one. The funding to resolve this problem is unprecedented. Therefore, historic expenditures cannot be used to forecast future needs. ORA’s analysis is based solely on recorded expenditures and essentially denies the existence of this problem. H. ORA’s Proposed Reduction Of $2.3 Million In 2005 And $12.2 Million

In 2006 To SCE’s ACR Circuit Refurbishment Is Based On A Flawed

Analyses

While the preemptive cable and switch replacement programs are anticipatory or predictive in nature, the ACR program is reactive or corrective in nature. These programs complement one another and together form a complete strategy for dealing with the challenge of an aging infrastructure.

The ACR program could be considered an even higher priority than the cable and switch replacement programs. While the cable and switch replacement programs replace equipment in anticipation of problems, the ACR program addresses problems that are already happening.

ORA has recommended expenditures in the ACR circuit refurbishment that are a fraction of that requested by SCE.

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And as mentioned earlier, SCE did not remediate any circuit in 2004, so the most recent unit costs from 2002 and 2003 should be used instead of a 1999-2003 unit cost that SCE proposed. ORA has escalated the 2003 unit cost to $540,000 for 2005 and $555,000 for 2006. With a recommendation of five circuits each year, ORA’s forecast is $2.7 million for 2005 and $2.8 million for 2006, as opposed to SCE’s $5 million and $15 million.115

Echoing a theme that runs through much of ORA’s testimony, ORA again assumes that SCE’s aging infrastructure does not present new challenges. ORA has posited its theory that SCE’s distribution system is not aging but is mature and “stable.”116 SCE has clearly demonstrated in rebuttal testimony, that this theory is incorrect. Acting upon this assumption could have disastrous consequences to SCE’s customers.

ORA recommends that SCE perform an ACR refurbishment on only five circuits each year instead of the 15 forecast for 2006 and 20 forecast in 2007 and 2008.117 Visiting only five circuits per year would mean that, on average, every circuit would be refurbished once every 800 years! This would be foolish regulatory policy indeed.

SCE’s request for funding in the area of ACR is based on the amount of work to be performed, not on the number of circuits. All available ACR funds will be invested, whether they cover more or fewer than the number of circuits targeted in the original forecast. SCE’s forecast of $1 million of ACR refurbishment per circuit is an average. Some circuits will cost more, some less. Where the corrective actions to a circuit’s poor performance can be addressed with the installation of isolation devices, such as automatic reclosers and fuses, the cost may be lower. Where the corrective actions to a circuit’s performance are more focused on reducing the number of circuit interruptions, such as replacing underground cable or undergrounding overhead conductors, the costs will likely be much higher. 115 ORA Report, Volume 2, p. 13-D-26, lines 3-9.116 ORA Report, Volume 2, p. 17-8, lines 12-25.117 SCE-3, Volume 3, Part III, Chapter I, p. 51.

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ORA’s recommended $2.8 million for ACR in 2006 would fund the replacement of a scant 5.5 miles of underground circuit per year. Contrary to ORA, far more spending could be justified than what we have proposed. The amount of work we expect to do will be limited, for the time being, by engineering analyses required of the targeted circuits to identify interruption root causes and develop cost-effective corrective actions.

SCE’s current ACR program is exactly what ORA asked for in the previous rate case. In our 2003 GRC decision, ORA expressed a concern that SCE’s customers may not be receiving equal service.

ORA also proposes that SCE’s next GRC be used to review and address whether all customers receive a similar level of service for the rates they pay as do other customers in the same customer class.118

We share this concern. No aspect of SCE’s infrastructure replacement program is more responsive to this concern than SCE’s ACR program which identifies those circuits whose customers are receiving poorer than average service and works to correct the situation.

In our 2003 GRC decision, ORA expressed a concern that SCE’s efforts to maintain system reliability should be cost-justified.

It is at least theoretically possible to create an overly reliable T&D system that adds unnecessarily to ratepayer costs…While the prospect of “too much reliability” might seem remote, it is reasonable for regulators to take steps to avoid the realization of that theoretical possibility.119

We share this concern as well. Clearly, no effort can be more cost-effective in affecting overall system reliability (i.e., making the greatest impact on reliability for the dollars invested) than efforts which direct expenditures toward those circuits with the most potential for improvement. This is what the ACR program does.

118 D.04-07-022, (mimeo) p. 95.119 D.04-07-022, (mimeo) p. 96.

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ACR is the most cost-effective work SCE does to counteract the tendency of aging to reduce our system reliability. We anticipate a benefit/cost ratio for the ACR work being performed in 2005 and beyond to be in the range of two. Furthermore, the ultimate cost of this program to the ratepayer is small. An investment of $15 million will add $0.03 to the monthly bill of the average residential customer.

The requested amounts are reasonable and minimal in light of the magnitude of the system and the reality of its aging. Funding less than what is requested virtually assures that there will be circuits with reliability well below average and with very dissatisfied customers. I. ORA’s Proposed Reduction Of $12.4 Million In 2005 And $18.4

Million In 2006 For Distribution Pole Repairs Is Based On A Flawed

Analysis And A Disregard Of SCE’s Need To Comply With CPUC

General Orders

SCE requested funding for the installation of 3,000 fiberglass wraps and 4,000 steel stubs in 2005, followed by 4,000 fiberglass wraps and 6,000 steel stubs in 2006. ORA has recommended funding for installation of 105 fiberglass wraps and 1,154 steel stubs in 2005 followed by the identical volume in 2006.

Recorded data from January 1, 2004 through November 26, 20 allowed ORA to forecast a total of 105 poles for fiberglass wraps at an escalated unit cost of $3,416 per wrap and 1,154 poles for steel stubs at an escalated unit cost of $964 per steel stub for 2005. As for 2006, ORA forecasts the same number of poles to be repaired and the unit cost for each type of repair is escalated to 2006 dollars. ORA’s forecast for overall pole repair is $1.5 million for each year. This is a reduction of $12.4 million and $18.4 million from SCE’s forecast of $13.9 million and $19.9 million for 2005 and 2006.120

This recommendation appears to be based on: (1) a philosophy of “no increases over historical spending;” (2) data from SCE’s relatively new data system

120 ORA Report, Volume 2, p. 13-D-27, line 21 through p. 13-D-28, line 6.

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not being as robust as ORA (or SCE) would like it to be; and (3) a disregard for the need to comply with CPUC General Orders.

Attached to this rebuttal are structure numbers for all deteriorated wood poles identified to be repaired by fiberglass wrap or steel stub in 2005, 2006, and 2007. To comply with GO 95:

By the end of 2005, 743 poles must be fiberglass wrapped and 733 poles must be steel stubbed.121

By the end of 2006, 3,561 additional poles must be fiberglass wrapped and 5,446 additional poles must be steel stubbed.122

By the end of 2007, an additional 4,809 poles must be fiberglass wrapped and an additional 7,926 poles must be steel stubbed.123

In summary, SCE currently has identified 23,218 deteriorated wood poles which must be repaired by their scheduled due date with either fiberglass wrap or steel stub in order to comply with internal procedures which, in turn, exist to ensure compliance with General Order 95.

SCE will not be able to perform the nearly 13,000 pole repairs due in 2007. A significant number of repairs must be completed ahead of their compliance due dates. SCE’s current plan is to perform 1,745 fiberglass wraps and 2,691 steel stubs in 2005, and 4,000 fiberglass wraps and 6,000 steel stubs in 2006. This will leave roughly the same number (about 3,500 fiberglass wraps and about 5,500 steel stubs) to be performed in 2007. SCE’s plan will ensure compliance with the Commission’s General Orders. ORA’s recommended pole repair rate guarantees noncompliance with GO 95 in 2005, 2006, 2007, and beyond.

121 A list of structure numbers of poles scheduled for repair in 2005 is provided in Appendix IV-10.122 A list of structure numbers of poles scheduled for repair in 2006 is provided in Appendix IV-11.123 A list of structure numbers of poles scheduled for repair in 2007 is provided in Appendix IV-12.

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SCE’s GRC forecast (developed in early 2004) of 27,000 pole repairs in 2005-2007 was only slightly conservative. Our current forecast for repairing the deteriorated wood poles that we know with certainty must be done, provides us with the best chance of compliance with CPUC regulations.

Note that this increase in the number of wood pole repairs is not the result of system neglect or deferrals, but rather the result of large numbers of poles being inspected three years earlier coupled with SCE’s policy to perform repairs in the year the work is due. The increase is amplified by the fact that time frames for completing pole repairs were adjusted, in 2003, from five years to three years. Prior to the year 2003, pole repairs were given a five-year window for the repair work to be performed. In 2003, all newly identified pole repairs were given a three-year window for the work to be completed. This shortening of the time frame for corrective actions on wood poles was internally-initiated in order to increase the safety margins in poles awaiting repair and based on feedback from the field. The result is that new three-year repairs are now being added to previously identified five-year repairs.

In addition to the volumetric issues discussed above, ORA also forecasts a different unit cost than does SCE for steel stub and fiberglass wrap repairs. ORA projects the 2005 cost of a fiberglass wrap to be $3,416, $429 more than SCE’s projection. ORA projects the 2005 cost of a steel stub to be $964, $272 less than SCE’s projection. Notwithstanding the fact that ORA’s unit costs applied to SCE’s projected repairs in both 2005 and 2006 afford SCE more funding, SCE maintains that its unit costs will be much closer to reality than the costs derived by ORA.124

124 SCE-3, Volume 3, Part III, Chapter I, p. 17.

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J. ORA’s Recommended Reduction in Funding for Bark Beetle Pole

Replacement is Appropriate

SCE’s original forecast of the capital costs associated with the Bark Beetle project was developed in early 2004 based on a general survey of all trees with attachments. At the time the estimate was produced no actual detailed planning of work had been done. The estimate assumed that of the trees with any kind of attachment 30 percent would have to be replaced. Of those poles replaced, 14 percent would be replaced with primary poles, 43 percent with service poles, and 43 percent with Guy poles. The estimate assumed that the service and primary poles would require more expense than the guy poles. Once the project was planned in more detail, it was discovered that fewer attachments would require a new pole and more could be handled with anchors or moved to a pole already in place. Therefore, the volume of work has been less and the speed of the project has been faster than the original forecast.

ORA is correct that zero dollars will be required in 2006. Furthermore, SCE will require only $3.5 million to complete the project in 2005. Therefore, $1 million less than the $4.5 million ORA has recommended in 2005 will be needed. SCE will adjust its request accordingly. K. ORA’s Proposed Reduction of $7 Million in 2005 and $7.2 Million in

2006 for Subtransmission Pole Replacement and Repair is Based on

Flawed Analyses and a Disregard for SCE’s Need to Comply with

Regulatory Requirements

SCE has forecast a replacement rate of 986 subtransmission poles per year in 2005 – 2008. This was based on a forecast of about 9,000 intrusive inspections per year (consistent with guidance published in, “Maintenance Practices for Transmission Facilities under the Control of the California Independent System

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Operator (ISO),” originally published December 23, 1997. The forecast rejection rate was based on the historical rejection rate.125

SCE fell short of its forecast volume of subtransmission pole replacements in 2004, replacing 857 rather than 986. ORA recommends that SCE be limited to funding sufficient to replace and repair (via fiberglass wrap and steel stub) in the future a volume of poles no more than what was performed in 2004:

Based on the constant level of pole repair, replacement and cost for year 2004 forward, ORA’s 2005 and 2006 forecast will be the same as 2004 recorded with escalated costs. ORA’s forecast is $12.5 million for 2005 and $12.9 million for 2006. ORA’s recommendation is a reduction of $7 million and $7.2 million from SCE’s 2005 and 2006 forecast. (p. 13-D-30, line 20 though p. 13-D-31, line 3)SCE cannot comply with regulatory requirements with this volume of work

and level of funding. SCE currently has a list of 860 subtransmission poles identified for replacement in 2005.126 Based on historical rejection rates, we expect roughly 120 Priority 1 and Priority 2 poles to be identified during the inspections in the balance of this year.127 Therefore, we anticipate the need to replace a minimum of 980 subtransmission poles in 2005 in order to comply with regulatory requirements.

SCE currently has a list of 553 subtransmission poles identified for replacement in 2006.128 Based on historical rejection rates, we expect roughly 258 Priority 3 poles to be identified by intrusive inspections performed during the balance of this year. These must be replaced in 2006. We also expect, based on

125 SCE-3, Volume 3, Part III, Chapter I, Workpapers p. 111.126 A list of structure numbers for poles scheduled for replacement in 2005 is provided in Appendix

IV-13.127 Our forecast of subtransmission pole replacement and repair was provided in Exhibit SCE-3,

Volume 3, Part III, Chapter I, Workpapers p. 110 and is attached as Appendix IV-14.Rejection rates used in this forecast were based on historical data provided in Exhibit SCE-3, Volume 3, Part III, Chapter I, Workpapers p. 111 and is attached as Appendix IV-15.

128 A list of structure numbers for poles scheduled for replacement in 2006 is provided in Appendix IV-16.

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historical rejection rates, that about 160 Priority 1 and Priority 2 poles will be identified in 2006 that must be replaced that year. Therefore, we anticipate the need to replace a minimum of 971 subtransmission poles in 2006 in order to comply with regulatory requirements.

Emergent situations will identify additional poles to be replaced in each of these years. Therefore, SCE believes that its original forecast of replacing 983 subtransmission poles in 2005 and 2006 is reasonable.

SCE has identified the deteriorated subtransmission poles required to be repaired by fiberglass wrap or steel stub in 2005, 2006, and 2007:

By the end of 2005, 43 poles must be fiberglass wrapped and 68 poles must be steel-stubbed.129

By the end of 2006, 119 additional poles must be fiberglass wrapped and 151 additional poles must be steel-stubbed.130

By the end of 2007, an additional 289 poles must be fiberglass wrapped and an additional 399 poles must be steel stubbed.131

In summary, SCE currently has identified 1,069 deteriorated subtransmission poles that must be repaired by their scheduled due date with either fiberglass wrap or steel stub in order to comply with regulatory requirements.

In order to levelize the workload, SCE intends to move some work ahead of their compliance due dates. SCE’s current plan is to perform 65 fiberglass wraps and 99 steel stubs in 2005, and 105 fiberglass wraps and 201 steel stubs in 2006. This will leave a large number of repairs (about 281 fiberglass wraps and about 318 steel stubs) to be performed in 2007.

129 A list of structure numbers for poles scheduled for repair in 2005 is provided in Appendix IV-17.130 A list of structure numbers for poles scheduled for repair in 2006 is provided in Appendix IV-18.131 A list of structure numbers for poles scheduled for repair in 2007 is provided in Appendix IV-19.

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Note that this increase in the number of wood pole repairs is not the result of system neglect or deferrals, but rather the result of large numbers of poles being inspected three years earlier coupled with SCE’s policy to perform repairs in the year the work is due. The increase is amplified by the fact that time frames for completing pole repairs were adjusted, in 2003, from five years to three years. Prior to the year 2003, pole repairs were given a five-year window for the repair work to be performed. In 2003, all newly identified pole repairs were given a three-year window for the work to be completed. This shortening of the time frame for corrective actions on wood poles was internally-initiated in order to increase the safety margins in poles awaiting repair and based on feedback from the field. The result is that new three-year repairs are now being added to previously identified five-year repairs.

In 2004, SCE experienced a lower unit cost for subtransmission pole replacement ($12,167,000 / 857 replacements = $14,197 per pole) than forecast in its GRC. SCE believes that this was anomalous. A very high percentage of poles replaced in 2004 were located in the San Joaquin region, which has been shown to have a relatively low replacement cost due to its rural nature and ease of work.132 SCE continues to believe that the unit costs for subtransmission pole replacements as well as repairs forecast in Exhibit SCE 3, Volume 3, Part 3, Chapter I, page 22 are realistic projections.

As clearly demonstrated, ORA’s recommended funding for the replacement and repair of subtransmission poles will ensure non-compliance with regulatory requirements.

132 SCE-3, Volume 3, Part III, Chapter I, p. 13.

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L. TURN’s Criticisms of SCE’s Analysis Supporting Preemptive

Replacement Are Flawed

In response to D.04-07-022, SCE included in its GRC application an empirical analysis comparing the costs and benefits associated with infrastructure replacements designed to impact system reliability.133 This analysis demonstrated that preemptive replacements of infrastructure, made of the right components at the right time are in the best interest of the ratepayer.

Although TURN appears to accept the basic premise of SCE’s analysis (i.e., that preemptive replacements can benefit ratepayers given the right circumstances), TURN claims SCE’s specific quantification is flawed by failing to consider “economic and ratemaking consequences.” TURN has leveled three criticisms of this analysis which are discussed below.

1. TURN’s Comment Regarding Taxes

TURN states:Edison’s figures only compare the cost of the new equipment installed early. They do not include the present value of revenue requirements associated with income taxes and property taxes, thus understating the cost of the new asset by about 30%.134

SCE agrees that it would improve the accuracy of its analysis to “gross up” the cost of new equipment installed early to reflect income taxes. However, since this “gross up” would also apply to the investment in a new asset replaced after an in-service failure, there is little impact on the overall analysis. Using TURN’s proposed 30 percent gross-up factor delays the timing of preemptive replacements by about one year. With the break-even time being between 13 and 18 years prior to switch end of life, there is clearly uncertainty associated with the

133 SCE-3, Volume 3, Part III, Chapter I, Workpapers, pp. 188-205, “Toward Optimizing the Timing of Infrastructure Replacement,” attached as Appendix IV-7.

134 Report on Various Results of Operations Issues in Southern California Edison’s 2006 Test Year General Rate Case, (“TURN Testimony”) William B. Marcus, on behalf of TURN, p. 63, lines 15-18

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results of the analysis. Adjustments to the cost of the switch attributable to the present value of taxes would be well within the precision of the calculations.

2. TURN’s Comment Regarding Ratemaking

TURN also states:Edison’s figures also do not take into account the additional burden that will be placed on ratepayers not just by the replacement but over many years through the future shortening of depreciable lives of the assets subject to early replacement. This impact could be considerably larger than simply the replacement costs 13 years early.135

This is clearly a “ratemaking consequence” and not an economic consideration that belongs in a forward-looking analysis of asset placement. The original investment in SCE’s current stock of assets is a sunk cost, and should not be included in an economic analysis. SCE should perform preemptive replacements when the overall ratepayer value of these replacements is beneficial (compared with replacement on failure), without regard for historic costs. Essentially, SCE’s analysis demonstrates that the economic life of certain assets is shorter than the expected physical life, which then suggests that depreciation rates for such assets should be increased. Failure to account for a proper depreciation rate has the effect of shifting costs that should be recovered in current rates into a burden on future ratepayers. It should also be noted that the ratemaking impact that TURN describes will be offset by the lower costs of asset replacement which takes place on a planned basis.

3. TURN’s Comment Regarding Service Lives of Switches

Finally, TURN states:Still, we are concerned that Edison’s testimony supporting switch replacement quotes an average switch life as considerably shorter (15-35 years, SCE 3 V.3 part III p. 34) than in the Timing of Infrastructure Replacement Study (35-55 years for vintages 1979

135 TURN Testimony, Marcus, p. 63, lines 20-24.

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and earlier). But this view of short lives is one more factor that leads Edison to hasten its infrastructure replacement.136

TURN does not seem to understand the analysis. As stated in the original testimony, SCE 3, Volume 3, Part 3, Chapter I, the average life of a switch is between 15 and 35 years. The reference TURN makes to “35-55 years” is taken from a table in the analysis which shows:

Table IV-9Projected Break Even Time

Vintage of switch installed

Projected End-of-service-life

(yr)Prior 1964 55

1965 – 1969 451970 – 1974 391975 – 1979 35

The numbers in the right column do not indicate average lives but rather the “end of life” or maximum time a switch is expected to survive. The average life of a switch will be much less than the maximum expected life. There is no inconsistency with these numbers and TURN’s criticism is unfounded.

SCE does find itself in agreement with one of TURN’s statements: TURN urges caution and balance in considering ratepayer interests when deciding on the replacement of infrastructure.137

SCE has made a good faith effort to empirically find that balance in infrastructure replacement, which is in the best interest of the ratepayer. On one side of the scale are infrastructure replacements performed only after equipment has failed in service. The impact on reliability of a run-to-failure policy is not, in our opinion, in the best interest of the ratepayer. On the other side of the scale are infrastructure replacements in advance of any probable failure. The impact on 136 Id., p. 64, lines 3-8.137 TURN Testimony, Marcus, p. 64, lines 9-10

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the system might be even better reliability but accompanied by unjustified costs. This too, in our opinion, is not in the best interest of the ratepayer.

SCE is studying equipment failure rates and targeting those whose risk (probability multiplied by the consequences of an in-service failure) exceeds the cost of preemptive replacement. This method finds the balance between reliability and costs. An infrastructure replacement program based on such a strategy is, in our opinion, in the best interest of the ratepayer and the one we propose to pursue.

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V.

DISTRIBUTION AUTOMATION

EXECUTIVE SUMMARY

SCE’s projected expenditures in the Distribution Automation area are for capital installations of automated switches, capacitor controls and radios that assist in maintaining a high level of distribution system reliability. Adopting ORA’s proposed reductions could negatively impact customer minutes of interruption.

Over the period of 2005-2006, SCE projects total expenditures of approximately $26.3 million for continued implementation of its Distribution Automation Program. ORA recommends adjustments that reduce SCE’s total request by approximately $4.5 million by recommending reduced scope of circuit automation. These are summarized by major category in Table V-10 below.

ORA’s recommended adjustments are based on its conclusions that: (1) SCE’s estimated material costs are higher than vendor costs; (2) Distribution Circuit Breaker Replacement ACMI is below historical levels; (3) forecasted expenditures should be based on 2002-2004 recorded costs; and, (4) its adjustments would have no impact ORA’s proposed Reliable Distribution Accountability Mechanism (RDAM) or SCE system reliability.

ORA’s conclusions are not supported by its own analysis or historical data. Moreover, contrary to ORA’s conclusions, SCE has demonstrated: (1) our estimated material costs are in line with vendor costs; (2) our Distribution Circuit Breaker Replacement ACMI is not related to the Distribution Automation Program; and, (3) our proposed automation expenditures are required for future circuit automation and in line with recorded costs. ORA has also done no evaluation to see what impact its proposed reduction would have on system reliability and ORA’s RDAM proposal.

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A. Introduction

For the period 2005-2006, SCE forecast total expenditures of $26.3 million for our Distribution Automation Program. For 2005, SCE forecast expenditures of $5.9 million for the Circuit Automation portion of the Distribution Automation Program, with $6.1 million in 2006. In support of these expenditures, SCE provided 15 pages of testimony and 18 pages of workpapers, responded to 21 separate data request questions, met with the ORA witnesses in San Francisco, and held a telephone conversation with the ORA witness. Yet, ORA continues to misunderstand much of this information. This lack of understanding is evident in ORA’s proposed reductions of $2.2 million in 2005 (or a $3.7 million expenditure) and $2.3 million in 2006 (or a $3.8 million expenditure), which in the aggregate represents a 37.5 percent reduction to SCE’s forecast. Table V-10, below, contrasts SCE’s 2005-2006 Distribution Automation forecast with ORA’s projection.

Table V-10Distribution Automation Program ($000)

SCE ORA SCE/ORA SCE/ORA Forecast Forecast Difference Percent

BI 359 - Capacitor Automation 2005 1,145 1,145 0 0% 2006 1,183 1,183 0 0% 2005-2006 Total 2,328 2,328 0 0%

BI 360 - Circuit Automation 2005 5,939 3,739 (2,200) -37% 2006 6,138 3,838 (2,300) -37% 2005-2006 Total 12,078 7,577 (4,501) -37%

Distribution System Efficiency Enhancement 2005 5,849 5,849 0 0% 2006 6,083 6,083 0 0% 2005-2006 Total 11,933 11,933 0 0%

Total: Distribution Automation 2005 12,934 10,733 (2,200) -17% 2006 13,405 11,104 (2,300) -17% 2005-2006 Total 26,339 21,838 (4,501) -17%

Type of Expenditure

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B. Contrary To ORA’s Assertions, The Material Costs For Automation

Are In Line With Unit Price Used In SCE’s Cost Calculation For Each

Type Of Automation Equipment

ORA states it “is not confident that SCE’s automation cost calculation accurately reflects the true unit cost”138 and “contends that the SCE provided vendor contracts show a unit price that is two to three times lower than the unit price in SCE’s cost calculation for each type of automation equipment.”139 ORA is wrong. SCE has shown that the material costs for automation are in line with the unit price used in SCE’s cost calculation for each type of automation equipment.

SCE has provided ORA all the information to necessary support our proposed expenditures. SCE provided ORA both installed cost estimates and Major Equipment Cost estimates and discussed the types of major equipment to be installed for switch and fault indicator automation in our Circuit Automation Workpapers, SCE-3, Vol. 3, Part 3, pages 170-173. Table V-11 shows the data provided in that workpaper.

Table V-11Circuit Automation Estimated Costs

Automation Device Quantity Unit Cost Total Major Equipment CostRemote Control Switches -Overhead 200 $16,000 $3,200,000 Operator and PT $6,000 -Underground 50 $35,000 $1,750,000 Automated Switch $12,000Remote Transmission Switches 25 $20,000 $500,000 Operator and PT $6,000Remote Fault Indicators 200 $1,750 $350,000 RFI $900

Total Cost $5,800,000

SCE provided even more data in response to ORA’s Data Request No. 130, Question 2, which asked for a copy of the workpapers SCE used to derive the Unit Cost for the overhead and underground RCS, the remote transmission switches, 138 ORA Report, Volume 2, p. 13-D-34.139 Id.

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and the remote fault indicators. The information SCE provided to ORA in response to that data request is shown in Table V-12.

Table V-12Unit Cost Table

2003 2004

BANK TYPE BARE "B"

Non-SW Constr. Matls TOTAL

crew -days INSTL-ST OUTAGE-PT

Non-line crew

labor/expense OVHD TOTAL

CNSTR. COORD. PLNG PM/SPT TOTAL

GRAND TOTAL

Escalation @ 3%

GRAND TOTAL

Remote Fault Indicator 900$ 450$ -$ 1,350$ 0.05 175$ -$ 35$ 42$ 252$ -$ 100$ 100$ 1,702$ 51$ 1,753$ RCS - Overhead 6,000$ 3,000$ -$ 9,000$ 0.7 2,450$ 245$ 490$ 637$ 3,822$ 1,103$ 1,000$ 700$ 1,700$ 15,625$ 469$ 16,093$ RCS - Underground 12,000$ 6,000$ -$ 18,000$ 2 7,000$ 700$ 1,400$ 1,820$ 10,920$ 3,150$ 1,000$ 700$ 1,700$ 33,770$ 1,013$ 34,783$ Remote Trans Switch 6,000$ 3,000$ -$ 9,000$ 1.3 4,550$ 455$ 910$ 1,183$ 7,098$ 2,048$ 1,000$ 700$ 1,700$ 19,846$ 595$ 20,441$

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INSTALLATION OFFICE

ORA claims that the Bare material costs are not same as the major equipment/cost provided in SCE-3, Vol. 3, Part 3 workpapers page 171.140 ORA is wrong. Table V-2, Major Equipment Costs are the same values in Table V-3, Bare material costs.

ORA also requested a copy of the purchase orders along with listing of manufacturers of the devices shown above. SCE responded by providing purchase orders which were sent for the automation devices shown in Table V-13:

Table V-13Circuit Automation Devices

Material Code Automation Devices 557 00777 CPI ADMO for OH RCS 557 00793 CPI ADMO for RTS 535 00435 Elastimold Switch for UG RCS 557 00892 Elastimold UAD for UG RCS 403 00923,931,956 Joslyn FIs for RFI 403 00964 Joslyn FI Receiver for RFI

SCE also provided ORA the basis for the installed Unit Costs shown in our workpapers, including material, installation labor, and support costs. ORA also requested Vendor Prices for the automation devices. Again, SCE provided this information. Further, additional detailed backup for the installed Unit Costs was

140 See Appendix V-1, ORA’s Response to Data Request SCE-ORA-05, Question 1.

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not requested by ORA. For example, price detail for all the material required to install automation devices, such as potential transformers (PT), lightning arrestors, switches, and cable, was available, but not requested by ORA. Even without that additional detail, however, SCE provided ORA with ample documentation of the basis for our forecast. Despite being provided with all this information, SCE has learned based on conversations it had with ORA’s witness following receipt of ORA’s testimony, that ORA used only some of the vendor costs to analyze the Bare material costs.

ORA’s failure to use all the information provided by SCE appears to be the reason ORA reached the wrong conclusions. Both material code 535 00435 (switch) and 557 00892 (control panel and motor operator) are needed to install an underground RCSs, as shown in Table V-14.

Table V-14Automation Material Costs

SCE-3, Vol. 3, Part 3 Workpaper P. 171 SCE's Response to ORA-130, Q.2BI360 Circuit Automation

Automation Device Major Equipment Cost Bare Automation Mat Code Vendor Total Typical Add'l Cost TotalRemote Control Switches Device Price Equipment Material -Overhead Operator and PT $6,000 $6,000 OH RCS Oper 557-00777 $4,130 $4,130 PT $605 $6,661

Lightning Arrestors $72Switch $1,854

-Underground Automated Switch $12,000 $12,000 UG RCS Switch 535-00435 $4,209 $9,363 PT $1,448 $11,220UG RCS Oper 557-00892 $5,154 Cable $409

Remote Trans Switches Operator and PT $6,000 $6,000 RTS Operator 557-00793 $4,612 $4,612 PT $605 $5,289Lightning Arrestors $72

Remote Fault Indicators RFI $900 $900 RFI 403-00923 $175 $854 $854RFI 403-00931 $175RFI 403-00956 $175RFI Receiver 403-00964 $329

As Table V-14 shows, the vendor contract prices are not two-to-three times lower than the Bare/Cost of the automation equipment and are, in fact, in line with the Cost/Bare values provided to ORA. To reach SCE’s automation cost estimates, ORA only needed to add in (as shown in SCE’s work papers) typical additional material used for automation installations, such as potential transformers,

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lightning arrestors, switches, and cable, the total material costs support the Bare/Cost values used in SCE’s automation cost estimates.141

C. ORA Has Incorrectly Compared ACMI Reduction For SCE’s Circuit

Breaker Replacement Program To The Distribution Automation

Program

ORA states as a reason for its proposed reduction to the number of Remote Control Switches (RCS) the fact that the Infrastructure Replacement Program for Circuit Breakers has reduced SCE’s average customer minutes of interruption (ACMI) for 2001-2003 below historical levels.142 The ACMI data to which ORA refers relate to interruptions caused by failure of circuit breakers. The Distribution Circuit Automation program, however, reduces ACMI on distribution circuits due to faults on the circuit, not circuit breaker failures. Indeed, ORA admits that its testimony is wrong on this point. In its response to SCE’s Data Request SCE-ORA-05, Question 2, ORA admits that its testimony incorrectly assumes that SCE’s circuit breaker replacement program ACMI data applied to the distribution circuit automation program.143

Since ORA’s analysis is based on the wrong data, ORA’s conclusion that SCE does not need to install more RCSs is also incorrect. SCE’s good record of reliability will be maintained by the Distribution Automation Program and the proposed expenditures for that program should be adopted by the Commission.D. ORA Uses Inconsistent Recorded Data To Arrive At Its Forecast For

Remote Control Software And Circuit Automation

ORA also uses inconsistent recorded data to arrive at its forecast for remote control switches and circuit automation. This is evident by examining how ORA’s 141 SCE-3, Volume 3, Part III, Circuit Automation Workpaper pp. 170-173.142 ORA Report, Volume 2, p. 13-D-34. During 2001-2003, SCE’s ACMI improved due to our Circuit

Breaker Replacement Program and specific maintenance initiatives.143 Appendix V-1, ORA Response to Data Request SCE-ORA-05, Question 2.

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arrived at its conclusions. To estimate Circuit Automation Program expenditures, ORA “recommends using the escalated three-year average expenditure of 2002-2004, which is $3.5 million, as the forecast for 2005 and 2006 expenditures.”144 But ORA also states, however, that “the three-year average expenditure of 2000-2004 is $3.6 million,”145 which is shown in its workpaper as $3.647 million. ORA further states in its Summary/Recommendations for Transmission and Distribution Plant that “ORA’s recommendation for both Parts 3 and 4 of SCE’s capital expenditures is consistent with historical spending for years 1999-2004.”146 And, ORA recommends that SCE install RCSs on 115 circuits per year and 196 RCSs per year based on the 1993-2003 average.147

Although ORA identified several methods to forecast Circuit Automation capital expenditures, it ultimately decided to average 2002-2004 expenditures, which produced the lowest average of recorded costs (i.e., $3.6 million). ORA also calculated the 2000-2004 average expenditures, excluding 2001, as $3.6 million, which ORA characterized as a three-year average. The average over that period is actually $3.8 million, and is a four-year, not a three-year average. In response to SCE data request SCE-ORA-05, Question 3, ORA admitted that its testimony should have referred to a 2002-2004 average of $3.6 million instead of a 2000-2004 average expenditure of $3.6 million. If ORA had done what was stated in its Result of Operations Chapter 13D, Summary/Recommendations, ORA would have based its forecast on the 1999-2004 average, excluding 2001. If that average was then escalated, the result would be $4.8 million.

144 ORA Report, Volume 2, p. 13-D-34.145 Id., at p. 13-D-33.146 Id., at p. 13-D-3.147 Id., at p. 13-D-34.

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ORA’s averaging approach to forecasting Distribution Automation expenditures does not account for the difference between the current and future mix of overhead and underground equipment. SCE’s proposed expenditure level does address these issues and should be approved.

In 2003-2004, SCE installed a total of 233 RCSs, 34 of which were underground (UG) RCSs. Recorded costs in these years cannot be used to forecast 2005-2006 expenditures since it would be insufficient to install ORA’s recommended 196 RCSs per year. The ORA’s 10-year average (1993-2003) of installed RCSs148 does not accurately reflect what is required to automate 100-150 circuits per year, which is SCE’s proposed Circuit Automation plan. Our plan to install 250 RCSs per year was provided in SCE’s 2003 General Rate Case for Transmission and Distribution Volume 3 – Capital Chapter IV149 and the SCE T&D capital forecast approved in Decision D.04-07-022.150

Figure V-1 shows SCE’s recorded Circuit Automation costs for 1997-2004, which average (with escalation) $5.6 million. The lower expenditures in 2003-2004 were due to higher budget priorities for load growth and compliance-related projects, and insufficient lineman to install RCSs. Using the 1997-2004 escalated average, the forecast for expenditures would be $5.7 million for 2005 and $5.9 million for 2006.

148 ORA Report, Volume 2, p. 13-D-34.149 See Appendix V-2, SCE 2003 General Rate Case, Transmission & Distribution, Volume 3 –

Capital, Chapter IV, Distribution Automation, p. 143.150 D.04-07-022, (mimeo) p. 111.

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Figure V-1SCE And ORA Distribution Automation Forecast

Comparison ($000)

1999 2000 2001 2002 2003Recorded $6,000 $7,096 $6,633 $4,655 $553 $4,156 $3,141 $3,418SCE Forecast $5,939 $6,183ORA Proposed $3,739 $3,838

$0

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$4,000

$5,000

$6,000

$7,000

$8,000

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Recorded SCE Forecast ORA Proposed

As of 2004, only 88 of the total of 1,960 RCSs SCE installed were underground RCSs. As stated in SCE’s testimony, the cost of underground RCSs is two to three times higher than that of overhead RCSs. Our forecast expenditures must be higher than recorded in part due to the higher costs of underground circuit automation. To continue automating the worst performing circuits, many of which are underground, additional expenditures for UG RCSs will be required in 2005 and 2006.E. ORA’s Reliable Distribution Accountability Mechanism Proposal

Takes Credit For SCE’s Proposed Distribution Automation Program,

Which ORA’s Capital Expenditure Would Largely Disallow

ORA is proposing an indexed-based Reliable Distribution Accountability Mechanism (RDAM).151 ORA’s recommended SAIDI threshold for that mechanism would be adjusted by an aggregate of three SAIDI minutes to account for the beneficial effects of distribution automation. ORA refers to SCE’s five-year switch

151 ORA Report,Volume 2, p. 17-1.

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installation schedule in making that proposal.152 In response to SCE data request SCE-ORA-05, Question 4, ORA stated that it “has not performed an analysis of reduced circuit automation set forth in Chapter 13.” ORA also said that the key input is the analysis of the worst 662 circuits and that the workpaper can be readily adjusted for lesser or greater circuit automation.

This seems to be a case of ORA’s Transmission and Distribution Plant witness not knowing what the RDAM witness was doing. The ORA witness proposing the Reliability mechanism is assuming SCE’s proposed Distribution Automation Program will go forward as proposed, while ORA’s witness on distribution automation proposes substantial reductions to that same program. ORA cannot have it both ways.

Furthermore, as SCE stated in response to ORA data request ORA-130, Question 4, the worst performing circuits change from year to year. The worst performing circuits in the future will be different from the worst performing circuits today due to aging infrastructure and circuit modifications and the repair of specific historical poor performing circuits. Past reliability performance will not continue unless circuit automation is implemented annually on that year’s worst performing circuits. The forecast of the costs to fix each year’s worst performing circuits are correctly identified in SCE’s testimony and should be adopted.

152 ORA Report, Volume 2, p. 17-10.

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VI.

SUBSTATION CAPITAL REPLACEMENTS AND

OTHER CAPITAL REQUIREMENTS

EXECUTIVE SUMMARY

SCE’s expenditures for Substation Capital Replacements are necessary to maintain the current level of system reliability, curtail the increase of O&M expenditures, and minimize the safety risk to our employees and customers. These expenditures allow us to proactively replace aging infrastructure, and reactively replace equipment that has failed while in service.

The vast aging infrastructure in our substations poses significant reliability and cost challenges. These reliability and cost challenges will increase exponentially in the near future if proactive actions are not taken now to correct them.

Over the period 2005-2006, SCE projects total expenditures of $328.2 million in these two categories. ORA recommends adjustments which reduce the total request by $137.4 million.

ORA’s recommendations are flawed in that: (1) ORA did not address the key driver of aging infrastructure challenges, which is the basis for a majority of forecasts of capital requirements; (2) ORA ignored important factual information provided by SCE; (3) ORA’s analysis is no more than a simple comparison of historical expenditures, which do not adequately reflect the investments required to reduce the average age of the equipment, thus temper the potentially worsening reliability performance.

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SCE proposed cumulative expenditures of about $328 million over the 2005-2006 period for Substation Capital Replacements and Other Capital Requirements. Our forecast is based on an analysis of our system needs and the age and condition of the installed equipment.153 ORA would have the Commission cut those expenditures almost in half (42 percent), to about $191 million. Tables VI-15 through VI-17, below, compare SCE’s and ORA’s proposed spending on Substation Capital Replacements and Other Capital Requirements. Table VI-15 summarizes ORA recommendations by major programs; while Tables VI-16 and VI-17 compare the differences between SCE’s and ORA’s forecasts on the detail program components for the Substation Infrastructure Replacement Program and for the Substation Routine Capital Replacements and Other Capital Requirements, respectively.

153 Information on SCE’s methods of forecasting capital expenditures was also presented in written form in SCE witness Erik Takayesu’s workpapers to Exhibit SCE-3, Volume 3, Chapter I-IV, Part XXI, pp 25-29P. See also Workpaper in Appendix VI-A entitled, “Cost Estimating.”

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Table VI-152005-2006 Substation Capital Replacements And Other Capital

RequirementsSCE Forecast Compared To ORA’s Recommendation154

Expenditure by Major Program SCE ORA SCE/ORA SCE/ORAForecast Forecast Difference Percent

Subtotal: Infrastructure Replacement 2005 91,146 61,046 (30,100) -33% 2006 121,061 64,961 (56,100) -46% 2005-2006 Subtotal 212,207 126,007 (86,200) -41%

Subtotal: Routine Capital Replacements 2005 38,147 25,366 (12,781) -34% 2006 42,724 26,024 (16,700) -39% 2005-2006 Subtotal 80,871 51,390 (29,481) -36%

Subtotal: Other Capital Requirements 2005 18,757 6,657 (12,100) -65% 2006 16,364 6,764 (9,600) -59% 2005-2006 Subtotal 35,121 13,421 (21,700) -62%

Total 2005 148,050 93,069 (54,981) -37% 2006 180,149 97,749 (82,400) -46% 2005-2006 Total 328,199 190,818 (137,381) -42%

154 In most cases, SCE’s forecast in this testimony represents CPUC jurisdictional expenditures only. Some line items include both FERC and CPUC jurisdictional expenditures, which are then allocated between the two jurisdictions in SCE’s Results of Operations model. The ORA amounts shown in the tables are CPUC jurisdictional amounts only. Detailed comparisons between all FERC and CPUC jurisdictional expenditures will be presented by the Post Hearing Joint Comparison Exhibit.

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Table VI-162005-2006 Substation Infrastructure ReplacementsSCE Forecast Compared To ORA’s Recommendation

Type of Expenditure by Program Component SCE ORA SCE/ORA SCE/ORAForecast Forecast Difference Percent

Circuit Breaker Replacement 2005 36,660 28,660 (8,000) -22% 2006 43,770 29,270 (14,500) -33% 2005-2006 Total 80,430 57,930 (22,500) -28%Power Transformer Replacement 2005 10,650 3,650 (7,000) -66% 2006 35,420 7,120 (28,300) -80% 2005-2006 Total 46,070 10,770 (35,300) -77%

Protection & Control Replacement 2005 32,976 17,876 (15,100) -46% 2006 30,621 17,321 (13,300) -43% 2005-2006 Total 63,597 35,197 (28,400) -45%

GIS Replacement 2005 4,500 4,500 0 0% 2006 4,700 4,700 0 0% 2005-2006 Total 9,200 9,200 0 0%Series Capacitor Replacement 2005 6,360 6,360 0 0% 2006 6,550 6,550 0 0% 2005-2006 Total 12,910 12,910 0 0%

Subtotal: Infrastructure Replacement 2005 91,146 61,046 (30,100) -33% 2006 121,061 64,961 (56,100) -46% 2005-2006 Total 212,207 126,007 (86,200) -41%

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Table VI-172005-2006 Substation Routine Capital Replacements And Other

Capital RequirementsSCE Forecast Compared To ORA’s RecommendationType of Expenditure by Program Component SCE ORA SCE/ORA SCE/ORA

Forecast Forecast Difference PercentSubstation Additions and Betterments155 2005 34,089 23,089 (11,000) -32% 2006 40,363 23,663 (16,700) -41% 2005-2006 Total 74,452 46,752 (27,700) -37%Subtransmission Line Addition and Removal156 2005 4,058 2,277 (1,781) -44% 2006 2,361 2,361 0 0% 2005-2006 Total 6,419 4,638 (1,781) -28%Subtotal: Routine Capital Replacements 2005 38,147 25,366 (12,781) -34% 2006 42,724 26,024 (16,700) -39% 2005-2006 Total 80,871 51,390 (29,481) -36%

Tools, Spare Parts and Equipment 2005 8,112 4,912 (3,200) -39% 2006 9,119 5,019 (4,100) -45% 2005-2006 Total 17,231 9,931 (7,300) -42%Furniture and Equipment & Facilities 2005 6,745 1,745 (5,000) -74% 2006 6,745 1,745 (5,000) -74% 2005-2006 Total 13,490 3,490 (10,000) -74%Fee Simple and Right-of-ways 2005 3,900 0 (3,900) -100% 2006 500 0 (500) -100% 2005-2006 Total 4,400 0 (4,400) -100%Subtotal: Other Capital Requirements 2005 18,757 6,657 (12,100) -65% 2006 16,364 6,764 (9,600) -59% 2005-2006 Total 35,121 13,421 (21,700) -62%

155 Substation Addition and Betterments: The forecast includes AA-Bank Transformer Fire Mitigation. SCE agrees with the ORA testimony - this activity is FERC jurisdictional and has been allocated accordingly.

156 Subtransmission Line Addition and Removal: The $1.781 million increase to support the access bridges across the flood control channels that bisect the Mesa-Antelope 220kV right-of-way is necessary. Without these bridges, the access to the SCE right-of-way is limited and restrictive. However, upon review, the bridge expenditures are FERC jurisdictional, and SCE will allocate this expenditure accordingly.

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SCE provided more than sufficient support for our projected expenditures shown above. In addition to 70 pages of prepared direct testimony, SCE provided ORA 459 pages of workpapers and responses to 108 separate data requests amounting to approximately 1,000 pages of information. In addition, SCE led ORA representative on a site visit of facilities that are representative of the substation capital replacement program and discussed these expenditures with ORA by telephone and in meetings at the Commission’s San Francisco office. Nonetheless, it appears that in many instances ORA has misunderstood the information provided157 and that misunderstanding is largely responsible for ORA’s proposed reductions.A. ORA’s Analysis of SCE’s Expenditures Failed To Distinguish

Between Proactive And Reactive Programs

Both the Load Growth and the Substation Capital Replacement Program involve capital expenditures that replace aged substation equipment in order to maintain system reliability. The fundamental purpose of each program, however, is different. The Load Growth program’s fundamental purpose is to add to or replace equipment to increase capacity as required to support customer load growth. By contrast, the Substation Capital Replacement program’s fundamental purpose is to replace equipment either proactively (i.e., our Substation Infrastructure Replacement Program), or reactively, (our Routine Capital Replacements expenditures). Proactive infrastructure replacement expenditures are based on engineering assessments of the state of aging equipment.

157 SCE has noted 59 discrepancies, errors and omissions in ORA’s testimony on the Substation Capital Replacement and Other Capital Requirements. Of these 59 errors, 19 were of the facts SCE had presented, 35 were in interpreting that data, and 3 were due to ORA confusing one budget item with another.

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ORA’s analysis of SCE’s expenditures fails to observe this fundamental distinction. The approach ORA follows analyzing only SCE’s recorded replacement expenditures without differentiating between the reasons for the replacements is not a valid approach to estimating future spending needs to replace increasingly aging equipment. It is this fundamental difference in approach, along with ORA’s misunderstanding of data we provided, that accounts for much of the difference between SCE’s and ORA’s expenditure forecasts. This rebuttal will show how ORA’s analysis missed the fundamental distinction between proactive and reactive expenditures and how that led to our different estimates.B. ORA’s Reliance On Recorded Expenditure Data Is Not A Valid

Indicator Of Future Expenditure Needs

As stated above, ORA appears to have relied exclusively on an analysis of SCE’s recorded expenditures to determine the level of future expenditures.158 While this may be appropriate in some situations,159 it is not a sound method to forecast expenditures for a proactive infrastructure replacement program, where future year expenditures are based on engineering analyses developed independently of recorded spending. The forecast must reflect the reality of SCE’s progressively aging equipment, and reflect an expenditure program that is insufficiently portrayed in the recent historical data.

158 Not only is ORA’s underlying method wrong, ORA did not consistently apply it. To properly average recorded expenditures, all dollars must first be converted to constant dollars, then averaged, then escalated to the forecast year. Not only did ORA perform these calculations incorrectly, they used inconsistently incorrect methodology. For example, the method ORA used to calculate the average for the Reactive Replacements Blanket is different than the method used for the Distribution Circuit Breaker Replacement Program.

159 It might, for example, be appropriate to use a recorded spending analysis in the case of an ongoing program of similar scope in which expenditures fluctuate from year to year due to elements such as weather related incidents, or equipment damage.

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As presented in my direct testimony, a significant portion of SCE’s substation infrastructure was installed in the late 1950s and 1960s and is now approaching or has exceeded the end of its useful life. This situation is not unique to SCE. In deed, it is as discussed by a panel of power engineering experts at the 2000 General Meeting of IEEE Power Engineering Society on the topic of Aging T&D Infrastructure and Customer Service Reliability -- a widespread problem facing the utility industry:

In many areas of the United States and Europe, there are portions of the local power delivery system where the average equipment age exceeds its design lifetime by a significant amount.…

Generally, equipment in service more than 35 years begins to exhibit significantly higher rate of failure than newer equipment. Generally, area or the system composed of aged equipment experience a higher than average incidence of both unexpected clear-weather failures, and storm-related outages.…Old equipment, that is in service more than 35-40 years, typically has failure rates three times that of 5-year old equipment. This contributed to higher O&M costs, and poor service reliability.160

Eventual equipment failure due to old age is an inescapable fact. Not proactively replacing that equipment now will lead to major outages with great impacts on our customers.161 SCE must take prudent measures now to address this situation or we will not be able to catch up with the increasing failure of our aging equipment. If the Commission were to adopt ORA’s recommendations, our customers will be subjected to the risk of degraded 160 Panel Discussion on Aging T&D Infrastructure and Customer Service Reliability - IEEE

Power Engineering Society General Meeting, Summer of 2000, IEEE Conference Proceeding Volume 3, pp. 1494 – 1496, Doc. No. 0-7803-6420-1.

161 As examples: 1) Failure of a 35-year old CB at Barre Substation on 8/4/2004 resulted in power outages that affected more than 171,000 customers; 2) Failure of a 31-year old A-Bank transformer at Moorpark Substation on 9/12/2004 resulted in immediate power outages that affected more than 130,000 customers. The failure also severely impacted system loading on the remaining equipment that required sustaining rotating blackouts that impacted customers in eight communities.

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reliability and increased O&M costs as more resources must be diverted to nursing critical substation infrastructure, such as circuit breakers and transformers, beyond their useful lives.

Figure VI-2, below, is an example of non-routine maintenance and repairs performed on a family of circuit breaker model types in our system. It shows the increasing trend in the average man-hours we are spending on non-routine maintenance and repair activities as the equipment get older.

Figure VI-2Comparison of Average Man-Hours Spent On Repairs

At Different Ages For Circuit Breaker Model Types 242GA162

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In our direct testimony, workpapers, and responses to ORA’s data requests, we provided factual information on the age demographics and related failures on our substation infrastructure. ORA largely ignored that 162 Based on limited available data from 1998 to 2004, extracted from PassPort WMS. Ages

groups with less than 5 repair count were excluded to avoid skewing of averages.

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data and instead focused on developing historical averages of our recorded expenditures. ORA’s approach may be analogized to trying to predict future health care needs of a fifty-year old person based solely on previous expenditures, ignoring all other health care diagnostics.

To further demonstrate the impact of our aging infrastructure, we projected failure rates based on our equipment’s age demographics and historical failure data.163 Figure VI-3, below, projects the likelihood of SCE’s fleet of power transformers reaching the end-of-life event such as failures.

163 This analysis is based on data provided to ORA in response to data requests. See Incorporating Aging Failures in Power System Reliability Evaluation, by Wenyuan Li, Fellow, IEEE, IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 17, NO. 3, August 2002, and Evaluating Mean Life of Power System Equipment With Limited End-of-Life Failure Data, Wenyuan Li, Fellow, IEEE, IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 19, NO. 1, February 2004.

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Figure VI-3SCE’s Power Transformers

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Based On Actual Age Demographics And Historical Failure Data

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C. Substation Infrastructure Replacement Program

SCE’s Substation Infrastructure Replacement Program has several components, as shown in Table VI-16, above. ORA’s proposals in each of the constituent programs are rebutted separately below. In general, ORA chose to forecast Substation Infrastructure Replacement expenditures based on a three-year average of 2002-2004 recorded expenditures. As discussed above, averaging is not an appropriate method to forecast expenditures in a 164 In this projection, end-of-life event included the removal of equipment from service,

while primarily due to failure, could also include events that are non-failure related such as capacity shortage and overload conditions.

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proactive expenditure program, since recorded expenditures do not reflect future needs.

Even if it were, the years ORA chose to average are not representative of future spending needs. While ORA appropriately excluded 2001 amounts from its average due to the effect of SCE’s financial crisis, 2002 and 2003 were also anomalous years and not representative of future spending needs. SCE trimmed the Substation Infrastructure Replacement Programs to a bare minimum during those years to focus on meeting the needs of unanticipated customer and load growth.165 An average based on those years is therefore not a reasonable approach to forecasting 2005-2006 expenditures. The Commission recognized a similar phenomenon and supported the exclusion of lower capital addition from the financial crisis years in decision D.04-07-022 for the 2003 GRC:

The use of historical capital spending incorporates the lower capital additions from SCE’s financial crisis years, and may not adequately reflects the increased pace of capital investments associated with the infrastructure replacement program.166

While the decision D.04-07-022 specifically addressed SCE’s 2001 spending, I believe the same rationale also applies to our 2002 and 2003 recorded expenditures for the reason elaborated above.

ORA’s proposals for each of the components of SCE’s Substation Infrastructure Replacement Program are discussed further below.

1. Circuit Breaker Replacement Program

As discussed in my direct testimony, the Circuit Breaker Replacement Program is designed to address reliability concerns on our over 11,000 power circuit breakers. Circuit breakers are critical to isolating

165 See SCE-3, Volume 3, Part I and Part II for discussion of customer and load growth in SCE’s service area.

166 D.04-07-022 (mimeo) p. 268.

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system problems quickly, thus preventing those problems from cascading into much larger ones. SCE divides its Circuit Breaker Replacement Program into the Bulk Power Circuit Breaker Replacement Program and Distribution Circuit Breaker Replacement Program based on the voltage levels at which the circuit breakers operate. SCE proposed cumulative 2005-2006 expenditures of $80.43 million on this program. ORA proposes $57.93 million, a $22.5 million reduction to SCE’s estimate. ORA’s proposed reductions are addressed below.

a) Bulk Power Circuit Breaker Replacement Program For Bulk Power Circuit Breakers, SCE forecasts $20.56

million in 2005 and $21.18 million in 2006. Because these components operate at both FERC and CPUC jurisdictional levels, we apply an allocation factor to assign a portion to FERC and a portion to CPUC jurisdiction. SCE’s Results of Operations model allocates 80 percent of these costs to FERC and 20 percent to CPUC jurisdictions.167 Therefore, SCE’s resulting estimate for CPUC jurisdiction is about $4.112 million for 2005 and $4.236 million for 2006, or a cumulative total of about $8.348 million. ORA proposes this entire amount be assigned to FERC jurisdictional customers.168 ORA’s proposed reallocation of this $8.348 million is based on a misunderstanding of the diagram in SCE’s testimony. ORA incorrectly observes:

According to the illustration entitled Transmission and Distribution Infrastructure Model, power at the 500 kV and 220kV has been distinctly identified as part of the transmission grid and therefore, FERC jurisdictional.169

167 This split is based on the methodology described in Exhibit SCE-8 – Results of Operations, Volume 1, Section IV.B.

168 ORA Report, Volume 2, p. 13-D-39, lines 21-23.169 Id., at lines 11-14.

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The diagram ORA cites was only to conceptually illustrate basic electric functions; it was not intended as a cost allocation scheme.170 Our bulk power circuit breakers are a mix of FERC and CPUC jurisdiction. SCE’s Moorpark Substation presents a good example. Figure VI-4, below, shows the Santa Clara No. 1 and 2, Pardee No. 1, 2, and 3, the 220kV buses, and the No. 6 capacitors are FERC jurisdictional. Whereas the Ormond Beach No. 1, 2, 3, and 4 lines are subject to a radial line agreement, and the 4A transformer bank is under CPUC jurisdiction. The numbered positions represent circuit breakers, (e.g. 4072 and 6072 are the 220kV CBs for the 4A transformer bank.) In this case, both CB 4072 and 6072 are bank breakers for the protection of the 4A transformer bank and, therefore, are under CPUC jurisdiction. Because the Bulk Power Circuit Breaker Replacement Program contains both FERC and CPUC jurisdictional equipment, the forecast costs must be allocated.

170 SCE-3, Volume 3, Part IV, pp. 19-20, Figure II-8.

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Figure VI-4Moorpark Substation 220kV System Single Line Diagram

Another example is SCE’s Mesa Substation, shown in Figure VI-5. The 1A, 2A, and 3A transformer banks and associated CBs (4012, 6012, 4042, 6042, 4082, and 6082) are identified as CPUC jurisdictional. The remaining 220kV CBs are FERC jurisdictional.

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Figure VI-5Mesa Substation 220kV

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As shown in the above two examples, there are clearly bulk power circuit breakers that are CPUC jurisdictional. When SCE identifies a specific replacement of a bulk power circuit breaker, we identify whether that individual equipment is under CPUC or FERC jurisdiction and account for it accordingly. However, when forecasting future expenditures where the specific mix of components has not yet been identified, it is appropriate to use the proposed allocation methodology that ORA agreed to elsewhere in its testimony:

ORA recommends the use of jurisdictional allocation adopted by the Commission in SCE’s last GRC. Both ORA and SCE use the jurisdictional allocation factors based on this methodology.171

To be consistent with the allocation methodology adopted in D.04-07-022, ORA’s proposed $8.4 million cost reallocation should be rejected.

171 ORA Report, Volume 1, p. 3-2, lines 17-19.

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b) Distribution Circuit Breaker Replacement Program As ORA did with its testimony on SCE’s Bulk Power Circuit

Breaker Replacement Program, it also proposes to reallocate some of SCE’s Distribution Circuit Breaker Replacement Program expenditures to FERC jurisdiction:

As for the DCBRP, three percent of the approximate $16 million forecast for 2005 and 2006, or $500,000 each year has been allocated to FERC. This action will add back $1 million to Commission capital expenditures and result in an overall decrease of $7.4 million to Commission capital expenditures as a result of both reallocations.172

ORA’s suggested reallocation of DCBRP -- like its reallocation proposal related to Bulk Power Circuit Breaker -- contradicts the allocation methodology adopted in D.04-07-022 and ORA’s agreement elsewhere in its testimony.173 Again, to be consistent with the accepted allocation methodology in D.04-07-022, ORA’s recommendation should be rejected.

Distribution Circuit Breakers operate at lower voltage levels but serve essentially the same purpose as the Bulk Power Circuit Breakers – to isolate circuits in the event of faults, thus preventing problems from cascading to the remainder of the system. SCE proposed expenditures of $16.1 million in 2005 and $22.59 million in 2006 to replace aging Distribution Circuit Breakers. ORA proposes a $14.1 million reduction.174 ORA’s analysis contains several errors.

First, ORA describes our Distribution Circuit Breaker Replacement Program as follows:

172 ORA Report, Volume 2, p.13-D-39, line 23 – p. 13-D-40, line 3.173 ORA Report, Volume 1, p. 3-2, lines 17-19.174 ORA Report, Volume 2, p. 13-D-42, lines 1-3.

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The DCBRP captures the cost of replacing subtransmission and distribution CBs that are >=66kV and <161kV and metal-clad switchgears (MCLDs).175

While this statement is partially correct, it omits the below-66kV circuit breakers.176 ORA acknowledges this error in its response to data request SCE-ORA-06, Question 4:

ORA erroneously left out CBs<66kV. These CBs should be included as part of the distribution CBs.It is not clear just what impact ORA’s omission of the

below-66kV circuit breakers had on its recommendation, nor what ORA means when it states these circuit breakers “should be included as part of the distribution CBs,” but this omission does show ORA’s misunderstanding.

Putting aside this omission, ORA’s reasons for rejecting our forecast are faulty. ORA erroneously argues that SCE has not demonstrated that: (1) Metal-Clad Switchgear (MCLD) needs replacing; (2) Kelman circuit breakers are still causing outages; and (3) circuit breakers 40 years old or older need to be replaced.177

Regarding MCLD, ORA supports its conclusion by claiming that (1) “there was no justification offered as to why the [MCLD] need to be replaced” and (2) “there has been no MCLD replacement between the inception of the [Distribution Circuit Breaker Replacement Program] in 1997 and 2004, except for the Santa Monica substation, which was replaced in 2003.”178

As for the first reasons, ORA is simply wrong. SCE’s testimony identified MCLD switchgear as a separate element of the

175 Id., at p. 13-D-40, lines 6-8.176 SCE described the justification for its Distribution Circuit Breaker Replacement Program

in Exhibit SCE-3, Volume 3, Part IV, pp. 15 - 19.177 ORA Report, Volume 2, p. 13-D-41, lines 20-22.178 Id., at p. 13-D-40, lines 16-20.

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distribution circuit breaker replacement program because that equipment has different unit costs. Some circuit breakers are in MCLD configuration, some are not. But the justification for replacing MCLD is the same as replacing any other type of distribution circuit breaker.

As for ORA’s second reason, the fact that we have not previously had to replace MCLD does not contradict our forecast for such replacements, as ORA seems to believe. The reason there has been no MCLD replaced since 1997 except at Santa Monica is that we first tried to retrofit the equipment (a fact SCE explained to ORA during its February 2005 visit to SCE). MCLD retrofits were considered and tried in the past, in cases where the external enclosure was still intact and suitable modifications could be made to achieve operational requirements. However, these past retrofits have not always resulted in reliable operation, and as a result, this approach have been problematic. Furthermore, most existing MCLD installations are of an early vintage and retrofitting that older equipment is prohibitively expensive, approaching the cost of a complete replacement.179 Therefore, we plan to replace the remaining MCLDs rather than attempting further retrofits. The fact that we have not previously had to do so does not contradict that forecast, as ORA seems to believe.

ORA also misunderstands the issue of Kelman circuit breakers. ORA’s claim that SCE has not demonstrated that the Kelman circuit breakers are still causing a problem is irrelevant. ORA is correct that the Kelman equipment is no longer a problem because SCE has already replaced most of that equipment. SCE never claimed that replacing Kelman circuit breakers was the sole basis for our forecast. I mentioned the Kelman

179 See Appendix VI-B “Metal-Clad Switchgear Project Summary”

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issue in my testimony as background information.180 Our forecast is based on replacing the poorest performing circuit breakers on an approximately 50-year replacement cycle to minimize degradation of our current reliability level, not on replacing Kelman circuit breakers.181

ORA’s third reason for rejecting our forecast is its mistaken belief that age is a not causative factor:

As for SCE’s claim that age, (those CBs 40 years and older,) is a determinant factor in the replacement of CBs, ORA found that this is not necessarily the case. Based on 1997-2004 CB replacement records, ORA discovered that SCE is just as likely to replace CBs that are younger than 40 years old as it is to replace those that are older than 40 years. SCE’s data shows that between 1997 and 2004, out of a total of 1344 distribution CBs, SCE replaced 628 CBs that are under 40 years of age, and 716 CBs 40 years of age or older. Since 43 percent of the total replacements in that time frame have been for CBs younger than 40 years, ORA is not persuaded that age has been a determinant factor. If that was the case, SCE would have been replacing primarily older CBs.182

ORA bases this statement on SCE’s response to ORA’s Data Request 38, Question 1(e), in which SCE provided data on all its circuit breakers, as asked. ORA seems to have incorrectly concluded that the information provided in that data request was limited to the circuit breakers replaced under the Distribution Circuit Breaker Replacement Program. But SCE also replaces circuit breakers in order to support new customer load, which is budgeted under our Capital Load Growth Program, as discussed in Exhibit SCE-03, Vol. 3, Part II. The data on circuit breakers replaced under that Load Growth program was included with the information provided in response to Data Request 38, Question 1(e) because ORA asked for

180 SCE-3, Volume 3, Part IV, p. 16.181 SCE-3, Volume 3, Part IV, p. 17, Section 4 - Continuation of Program Implementation.182 ORA Report, Volume 2, p. 13-D-41, lines 9-19.

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information on all circuit breakers replaced. Some Load Growth projects require SCE to reconfigure existing substations in which the equipment may not yet have reached the end of its useful life. Replacements of such newer equipment skews the overall replacement age. Ignoring the different reasons why we replace equipment, ORA has wrongly concluded that age is not a factor and rejected SCE’s forecast. By misinterpreting SCE’s response to a data request, ORA has drawn the wrong conclusion.

ORA has also come up with an arbitrary analysis of SCE’s data, drawing an arbitrary line at an equipment age of 40 years. ORA would apparently treat all equipment more than 40-years old as “old” and all equipment below that age, whether 1-year old or 39-years old as “not old.” Figure VI-6 below, is the age modal curve of SCE’s circuit breakers at the time they are removed from service. This figure, based on the same data SCE provided ORA in response to data request ORA-38, Question 1(e), shows that while a significant number of the circuit breakers were replaced below the age of 40, most were in the older part of that range.

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Furthermore, age is only one of several factors considered when deciding whether to replace equipment. Other relevant factors are the availability of spare parts, operating and maintenance experience on the equipment, component failure root cause analysis, environmental considerations, cost, reliability, safety risk, and changes in operating conditions. ORA also appears to have misunderstood the basis of SCE’s forecast, stating:

SCE is requesting $16.1 million for 2005 to replace 99 distribution CBs and $22.6 million for 2006 to replace 130 distribution CBs and MCLDs.183


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In fact, SCE testimony clearly stated 130 CBs and 187 CBs, respectively, for the years 2005 and 2006.184 ORA acknowledges this error in its response to data request SCE-ORA-06, Question 5:

ORA misquoted SCE. Page 13-D-40, lines 8-9 should read, “SCE is requesting $16.1 million for 2005 to replace 130 distribution CBs and MCLDs and $22.6 million for 2006 to replace 187 distribution CBs and MCLDs.”

c) Incorrect Application of Escalation Rate by ORA As discussed above, ORA’s reasons for rejecting SCE’s

forecast are mistaken. In addition, ORA’s proposed alternative forecast, which is based on a three-year average of 2002-2004 expenditures, is flawed.185 First, as discussed above, historical averages of Substation Infrastructure Replacement Program expenditures are not representative of future spending needs. Second, ORA’s 2002-2004 average fails to address the fact that the financial crisis had impacts beyond 2001. In 2002 and 2003 SCE reduced capital expenditures on substation infrastructure replacement programs to allow for higher priority load growth capital expenditures. Third, ORA fails to properly adjust the average for the effects of inflation, using an erroneous escalation method based on simple arithmetic to forecast

184 ORA Report, Volume 2, p. 13-D-40, lines 9-12.185 “The six-year average of 1999-2004 expenditures for this program is $9.9 million. SCE’s

2005 and 2006 request is 63 percent and 128 percent, respectively, higher than 1999-2004 recorded spending.” ORA Report, Volume 2, p. 13-D-40, lines 6-8.

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expenditures instead of compounding escalation through multiple years.186 Table VI-18 below shows the calculation made by ORA.

Table VI-18Analysis Of ORA Calculations On DCBRP Expenditures

($000)Description of Calculations 2002 2003 2004 2005 2006

ORA’s Escalation Rate 4.37% 2.36% 1.76% 2.59% 2.72%

DCBRP Expenditures $12,605$14,65

0 $11,800

Santa Monica Expenditure $4,352

DCBRP less Santa Monica Expenditures $12,605

$10,298 $11,800

2005 $ from ORA’s Calculation$13,45

2$10,93

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$13,471

$10,751 $12,106

$12,110

$12,439

d) ORA’s Recommendations Are Not Support by Reliability Impacts AnalysisORA has not performed any analysis on the impact of its

recommended cuts on the reliability of SCE’s network. For example, in response to data request SCE-ORA-06, Question 10, ORA was asked about its CB design life and average service life assumptions and replied:

ORA’s recommendation is not based on the design life and average service life of the CB.187

186 Similarly incorrect financial analysis appears throughout ORA’s testimony. In addition to using a questionable escalation rate, ORA’s calculations are also incorrect. For example, ORA incorrectly presents the calculation to convert the $12.6 million expenditure in 2002 to 2005. ORA uses the following calculation (1+.0236+.0176+.0259) * $12.6 = $13.452 million rather than the correct calculation, which is 1.0236*1.0176*1.0259*$12.6 = $13.471 million. ORA also takes the incorrectly escalated value for 2003 expenditures ($14.7 million) and subtracts the un-escalated expenditures from the Santa Monica Metal Clad Switchgear Replacement ($4.4 million), which results in an incorrect value of $10.9 million in 2005 dollars.

187 ORA’s response to SCE-ORA-06, Question 10.

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By omitting this important analysis, ORA is blind to the effects of its recommendations. ORA’s cuts would mean that our SIRP could only afford to replace about 100 CBs per year. At such a pace, it would take approximately 100 years to complete the replacement cycle, leading to the highly unrealistic scenario that circuit breakers have an average life of 100 years. Even if a circuit breaker could be coaxed into lasting for 100 years, the reliability risk and maintenance costs to achieve that life would be prohibitively high.

As discussed in SCE’s direct testimony, a single CB failure can severely impact service reliability. Almost 96 percent of the total annual interruption duration in 2000 was caused by a single circuit breaker failure where more than 17,000 customers went without power for hours.188 More recently, a 35-year-old circuit breaker (1969 vintage) failed at our Barre Substation on August 4, 2004, causing a significant outage to the Orange County area of SCE's service territory affecting more than 171,000 customers. These two examples demonstrate the widespread reliability impact a single circuit breaker failure can have on SCE’s customers. ORA completely ignored this implication of its proposal. We urge the Commission to reject ORA’s recommended slashing of this program.

2. Power Transformer Replacement Program

SCE’s Power Transformer Replacement Program consists of: (1) AA-Bank Replacement Program; (2) A-Bank Replacement Program; and, (3) B-Bank Replacement Program. Of these programs, the A-Bank and B-Bank programs are under CPUC jurisdiction and were addressed in ORA’s testimony.189 ORA has proposed reductions to our forecast expenditures in 188 SCE-3, Volume 3, Part IV, pp. 6-8 (Santa Monica MCLD incident, 10/26/2000). 17,578

customers were interrupted. GCC Morning Report 10/26/2000.189 SCE also presented data on the AA-Bank program, which is FERC jurisdictional.

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each of these categories. The shortcomings with ORA’s proposals are discussed below.

a) Transformer Replacement Program – A Bank SCE replaces transformers both proactively, that is, before

in-service failure, and reactively, that is, after failure in-service. As with circuit breakers, the Power Transformer Replacement Program is an important component of the SIRP. Its purpose is to proactively identify transformers that are showing signs of imminent failure and/or high maintenance cost and replace them before failure occurs. SCE draws from our expertise with power transformers and our operational experience to determine the need and priority of proactive transformer replacement.

Replacement prior to imminent failure is one of the main goals of the infrastructure replacement program since it mitigates outages and the resulting costs to customers. A successful measure of the infrastructure replacement and maintenance program would be minimal in-service failures because the equipment would have been replaced just prior to failures.

The A-Bank Replacement Program starts with expenditures of $25.5 million in 2006, planned to allow replacement of 46 A-bank transformers by 2008.190 ORA’s forecast for 2006 is $3.8 million for two A-Bank transformer replacements, a reduction of $21.7 million from SCE’s 2006 forecast.191 ORA’s recommendation is, once again, based on SCE’s recorded costs:

190 See Appendix VI-C “A-Bank Replacement Project Summary.”191 ORA Report, Volume 2, p. 13-D-45, lines 13-15.

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Again, ORA recommends looking at A-Bank replacement history to determine the forecast for 2006. SCE was unable to provide its 1999 recorded costs for transformer failures. However, SCE provided ORA with the number of projects and total cost for years 2000, 2001, and 2002 where SCE replaced A-Bank transformers even though there were no failures recorded.192

As discussed above, historical data is not determinative of the amount of spending necessary in the future to replace aging equipment. Furthermore, ORA’s recommendation conflicts with the fundamental principle of infrastructure replacement. ORA “acknowledges that the replacement of A-Bank transformers is sometimes necessary, and it is even prudent to identify those that show signs of imminent failures and replace them proactively.”193 However, ORA recommends “a replacement of [only] two A-Bank transformers for 2006.194 ORA’s “recorded average” approach completely ignores the transformer’s expected service life, the high cost of maintaining transformers to such an advanced age, or the frequent, prolonged forced outages that would occur from failures of such old transformers. In deed, ORA’s recommended program scope – replacing [only] two A-Bank Transformers a year – would amount to a replacement cycle of more than 100 years, more than five times the transformer’s nominal design life!

ORA claims SCE did not substantiate our forecast to ORA’s satisfaction, stating: “Based on the lack of information to support SCE’s forecast, ORA cannot corroborate that the replacement of these 25 A-Bank transformers is necessary.”195 The following passage from ORA’s testimony

192 Id., at p. 13-D-45, lines 5-10.193 Id., at lines 7-10.194 ORA Report, Volume 2, p. 13-D-44, lines 14-16.195 Id., at lines 1-4.

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shows that it appears to have, again, misunderstood the basis of SCE’s forecast and the data SCE provided:

With regard to determining the level of expenditure for 2006, ORA takes issue with SCE’s unit cost for A-Bank replacement. In its work papers, SCE presented the calculations for a typical A-Bank transformer replacement. ORA requested the work order under which the typical cost for A-Bank transformers was presented and SCE responded with an explanation that the typical cost presented was for a B-Bank transformer replacement. Although SCE claims that the unit cost of an A-bank transformer replacement is $1.7 million, the estimated cost data that SCE provided has no support. ORA was unable to verify that these numbers accurately reflect actual costs or from what they were based on.196

ORA is confused.197 ORA data request ORA-139, Question 4, which ORA cites in the above-quoted passage, asked for information on a specific work order number, which was for a B-Bank transformer replacement project, not an A-Bank. Question 4 of data request ORA-139 asks:

With respect to the workpaper for transformer replacement typical costs, (p. 280) identify the unit cost of $512,773 under work order 5309-5014. Why is this work order used as the basis for the unit cost? A copy of this work order.SCE’s response to this question, quoted below, provided

the cost details of work order 5309-5014 and explained why this work order was used to develop our B-Bank cost estimates (i.e., it is the most recent data available and its scope is representative):

196 Id., at line 19 – p. 13-D-45, line 4.197 SCE-3, Volume 3, Part IV, Workpaper p. 280.

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The work order 5309-5014 for Goshen Substation was used. This work order was the last to be completed during the preparation of the estimate. The scope of this project was the replacement of two 66/12kV transformers. The total direct cost for this project (in 2003 dollars) is $965,760. The escalated cost in 2004 dollars for the project is $994,773 using a 3% escalation rate or $497,366 each. A similar work order completed a few months earlier, work order 5322-5002 Poplar Sub, has a recorded cost of $1,154,225 (in 2003 dollars) or $1,188,852 in 2004 dollars. This gives a unit cost of $594,426. These work orders represent a typical transformer replacement project of a B-Bank. The actual project cost is variable based on the exact project scope. See the attached document for recorded cost and completion dates.In a separate question, ORA also asked for “a detailed

explanation of how SCE determined the unit cost of A-bank replacements.” SCE provided the requested information with details of the cost estimation for a typical A-Bank replacement.198 ORA is simply wrong in claiming that SCE based its A-bank and AA-bank estimates on B-bank data.

ORA is also confused about the cost information provided in Exhibit SCE-3, Vol.3, Part IV, Workpaper page 280, which listed typical costs for B-Banks,(shown with the referenced specific work orders for B-Banks), AA-Banks, and A- Banks. SCE stated that the cost of an A-Bank replacement is $1.7 million, as ORA notes. This cost is based on SCE’s standard engineering estimating process used throughout SCE’s testimony. SCE’s response to ORA’s data request 139 provided the engineering documentation to support that $1.7 million.199

198 SCE’s response to Data Request ORA-DR-139, Question 3, See Appendix VI-D “Cost Estimation Details for A-Bank Replacement.”

199 SCE’s response to DR-ORA-139, Question 3 provided cost estimation of A-Bank replacement with 14 pages of supporting details. A copy of the complete response to DR-ORA-139, Question 3 is attached as Appendix VI-D “Cost Estimation Details for A-Bank Replacement.”

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ORA also faults SCE for “not even provid[ing] the average time to wear out for an A-Bank transformer.”200 The transformer information SCE provided in its response to ORA’s data request 139, Question 7,201 identified the average age of the transformers we plan to replace as 52 years, significantly above both the nominal design life of 20.55 years identified by IEEE202 and the historical average age at replacement of 42 years.203 The age information described above should have provided more than sufficient details for ORA’s analysis.

An additional problem with ORA’s analysis is that it discounted SCE’s claim that age is a significant factor in determining need for replacement:

While SCE claims that age of equipment is a significant factor in reducing reliability, it is noteworthy to mention that from 2000 through 2003, SCE did not have any A-Bank failures.204

This statement cites the information SCE provided in response to ORA’s data request 139, Question 5. While it is true that SCE did not have any A-Bank failures from 2000-2003, that response also stated that SCE had three A-Bank failures in 2004. ORA also misstated information SCE provided regarding the 2004 failures.205 The ages of these three transformers at the time they failed were 53, 31, and 31 years old. In fact, post mortem analysis on two of the failures indicated “material aging, which points to 200 ORA Report, Volume 2, p. 13-D-43, line 25 – p. 13-D-44, line 1.201 See Appendix VI-C entitled, “A-Bank Replacement Project Summary” and Appendix VI-E -

A-Bank Replacement Program Details for details.202 IEEE C57.91-1995 (Reaffirmed 2004) – IEEE Guide for Loading Mineral-Oil Immersed

Transformers.203 Data Request DR-ORA-139, Question 6, Response.204 ORA Report, Volume 2, p. 13-D-44, lines 5-7.205 SCE’s response to DR-ORA-139 Question 5 stated three A-Banks failures. ORA misstates

this information, the ORA Report, Volume 2, p. 13-D-45, footnote 95, as four failures.

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some form of wear-out as a primary cause of failure” as the contributing factor in four out of the six high potential failure scenarios identified.206 This information, along with analysis of transformer failures performed by a utility insurance provider, provided significant evidence of a correlation between age and the likelihood of failures.207

This is more than an academic discussion about forecasting methods. One of the three failures in 2004 mentioned above occurred at SCE’s Moorpark Substation on September, 12, 2004 and affected 130,598 customers. This failure also resulted in a rotating blackout impacting the communities of Moorpark, Simi Valley, Thousand Oaks, Agoura Hills, West Lake Village, Malibu, Calabasas, and Newbury Park. If SCE does not proactively address our aging substation infrastructure, much more severe problems can be expected in the future.

In sum, ORA has misunderstood or ignored much of the data SCE presented in testimony, workpapers, and responses to data requests. ORA’s recommended expenditures, based on SCE’s recorded expenditures during a period of lower spending, would not address the need for a proactive replacement program. ORA’s recommended cuts to our forecast should be rejected.

b) Transformer Replacement Program – B Bank In direct testimony, SCE forecast B-Bank replacement

program expenditures of $7 million in 2005 and $6.6 million in 2006, which

206 SCE failure root cause evaluation – Root Cause Report No. 04-021, dated 4/5/2005.207 “Analysis of Transformer Failures” by William H. Bartley, P. E., The Hartford Steam Boiler

Inspection & Insurance Co., presented at the International Association of Engineering Insurers 36th Annual Conference - Stockholm, 2003, IMIA – WGP (03).

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are for replacement of 14 and 13 transformer banks, respectively. ORA proposes a $13.6 million reduction, completely eliminating the program.208

Based on the above analysis, ORA finds no justification for the work in 2005 and in 2006. Accordingly, ORA’s recommendation is a reduction of $7 million for 2005 and $6.6 million for 2006. ORA’s recommendation regarding SCE’s B-Bank

transformer replacement expenditures is based on incomplete and inaccurate analysis of the data SCE provided. For example, in response to ORA’s data request 139 (not 193 as stated in ORA’s testimony), SCE stated that we replaced seven transformer banks, comprised of 18 individual transformer units, for a cost of $2.8 million. ORA mischaracterizes this information as follows:

In 2004, however, SCE replaced only four B-Bank transformers and recorded a total of $2.9 million in expenditures.209

…ORA must therefore assume that one project is equivalent to one transformer unit.210

What SCE actually told ORA is that in 2004 we expended $2.9 million for four B-Bank Replacement Program projects,211 representing 18 transformer units.212

208 ORA Report, Volume 2, p. 13-D-48, lines 13-15.209 ORA Report, Volume 2, p. 13-D-46, lines 16-18.210 Id., at p. 13-D-47, lines 3-4.211 SCE’s response to DR-ORA-139, Question 1.212 SCE’s response to DR-ORA-139, Question 10. ORA acknowledges that a single project

can support the replacement of multiple transformer units: “These nine units are part of three substations, Crater, Mesa, and Adler, with three units per station.” ORA Report, Volume 2, p. 13-D-48 lines 4-5.

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ORA has also confused the proactive B Bank Replacement Program with the Substation Equipment Reactive Replacement Program, stating:

It appears from the data provided that SCE performed on average 6 transformer replacements each year from 2000-2004. This number compares closely to SCE’s average number of 6.5 failures per year from 1993-2003.213

…In its testimony, SCE states that the 1998 TRMC analysis identified six B-Bank transformers for replacement and that an additional 150 units were identified which make up the plan for 2004-2008 as presented in the GRC. In its response to ORA’s data request, however, SCE states that the company identified 15 units for the replacement plan as part of the GRC and that 212 units were identified for replacement by 2001.214

ORA misrepresents the factual information provided by SCE. In response to ORA’s data request 139, Question 9, SCE actually stated:

The TRM was performed annually until the financial crisis of 2001. As shown in the attached spreadsheet, the initial analysis in 1998 identified 15 units for the replacement plan. By 2001 we had performed analysis on 212 units.As this response shows, SCE clearly stated that by 2001 we

had performed analysis on 212 units, not “identified for replacement by 2001” as the ORA claims.

ORA also accuses SCE of failing to provide requested information:

Additionally, the TRMC data provided was missing information regarding the ‘planned year of replacement’.215

213 ORA Report, Volume 2, p. 13-D-47, lines 4-8.214 ORA Report, Volume 2, p. 13-D-47, lines 10-16.215 Id., at lines 18-20.

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This is an unfair criticism that reflects a lack of understanding of the TRMC process. Our analysis of the 212 units only established a “planned year of replacement” if the transformer unit was to be included in the B-Bank Replacement Program. If the transformer unit was not to be included in that program it would not be appropriate to establish a planned year of replacement.

ORA also expresses skepticism about the status of SCE’s program:

ORA has reason to believe that all nine units have already been replaced. These nine units are part of three substations, Crater, Mesa, and Adler, with three units per station. According to SCE data, the units at the Crater and Mesa stations were replaced. As mentioned earlier, only 2000, 2003 and 2004 data was provided. Adler substation was not one of the stations replaced in 2003 or 2004. Adler was also not part of the list of stations scheduled for replacement for 2005. As for 2006, SCE’s work plan is not yet developed. Adler may have already been replaced in the years following its identification by TRMC, but was part of the data SCE claimed it could not provide.216

Again, ORA’s concerns are unfounded. In response to ORA’s data request 139, SCE clearly identified the replacement of transformers at the Crater and Mesa substations as part of the TRM program. Adler was clearly identified in that same response as part of the DSP. SCE identified transformers for replacement under SIRP primarily based on our O&M experience with units that experienced degraded reliability. Once a unit is identified as a replacement candidate, it is coordinated with the load growth Distribution Substation Program to avoid duplication of effort.

In sum, ORA has misinterpreted or ignored much of the data SCE presented in testimony, workpapers, and responses to data requests. ORA’s recommendation, based on unrepresentative recorded 216 ORA Report, Volume 2, p. 13-D-48.

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expenditures, would not address the need for a proactive replacement program and should be rejected.

3. Protection and Control Replacement Program

a) Distribution Protection and Control Replacement Program In direct testimony, SCE identified the Distribution

Protection and Control Replacement Program, in which we identified planned expenditures of $14.8 million in 2005 and $14.9 million in 2006. ORA proposes a $17.1 million reduction, based on recorded averages:217

ORA recommends using the escalated three-year average 2002-2004 expenditures and the actual number of substations replaced, as the basis for the 2005 and 2006 forecast. ORA’s calculations yield a work forecast of 17 substations and $6.2 million for 2005 and $6.4 million for 2006. This is a reduction of $8.6 million in 2005 from SCE’s request of $14.8 million and a reduction of $8.5 million in 2006 from SCE’s request of $14.9 million.218

As in the case of previously discussed programs, ORA’s recommendation for our Distribution Protection and Control Replacement Program is also based on incorrect interpretation of information we provided to ORA. For example, ORA misinterprets SCE’s response to data request 101, Question 3:

ORA requested a breakdown of the remaining 700 substations by type of relay equipment. SCE responded that a breakdown was not possible. Therefore, ORA could not confirm that all 700 substations are equipped with Electro Mechanical equipment.219

While SCE does not track the breakdown by relay type in each of its approximately 700 stations in question, we did provide the approximate number of relays, stating that one distribution feeder normally

217 ORA Report, Volume 2, p. 13-D-51, lines 6-12.218 ORA Report, Volume 2, p. 13-D-51, lines 6-12.219 Id., at p. 13-D-49, line 13 – p. 13-D-50, line 1.

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requires five electromechanical relays (a typical application). We also stated that digital relays, which perform a similar function, have only been available since the mid 1980s and that we have only 5,200 digital relays on the SCE system. The following is our actual response to ORA’s data request ORA-101, Question 3:

SCE response to Data Request 101 Question 3:Depending on the application and the control and protection needs of the substations, there are a variety of different relay types applied in each of the substations, thus no breakdown of the number of substations by type of relays is possible. In reference to the relay failure analysis, the following definition applies:Auxiliary: Auxiliary relays are used in every substation for several purposes. This would include alarm relays, interposing, and tripping auxiliaries. These relays are not individually tracked in our asset management system.Electro-Mechanical: Electro-Mechanical relays are used as protective relays. This is an older style of relay protection including, the traditional electro-mechanical relays and the early solid state relays that do not have relay failure alarms. Edison has approximately 34,000 of this type of relay in its system. For comparison, one distribution feeder normally requires 5 relays of this type to provide adequate protection.Digital: Digital or Microprocessor relays are used as protective relays. This relay, which became available in the mid 1980’s, has relay failure alarms. Edison has approximately 5,200 of these relays on its system. For comparison, one distribution feeder normally requires 1 relay of this type to provide adequate protection.RFL: RFL devices are primarily used in transfer trip schemes. Edison has approximately 530 of these devices on its system. It takes at least 2 of these relays to make a transfer trip scheme.Thus ORA’s criticism is unwarranted. SCE provided the

information necessary to evaluate our planned expenditures. ORA also criticizes information SCE provided regarding work orders, stating it is unable to conclude SCE’s cost estimates are reasonable:

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These work orders do not contain actual recorded activities or costs, but are based on what SCE calls “engineering estimates.” Although the replacement work has always existed under one program or another, SCE is not able to provide any recorded cost as a basis for its forecast. As such, ORA cannot reasonably conclude that the unit cost SCE provided is reflective of the replacement work requested.220

Again, ORA ignores information SCE provided in response to ORA’s data request DR-ORA-102, Question 1(d), which explicitly states: “The average cost for the program each year varies depending on the mix of the different relays to be replaced.” There is not a single unit cost that would apply across the entire program. ORA is being unrealistic to the extent it is looking for an imaginary “standard unit cost.” To compound the problem, in searching for an all-purpose unit cost, ORA incorrectly interprets more of the information SCE provided:

Also, SCE’s unit cost does not appear to compare closely with historical costs of the program since its inception in 2001. Most notably, in 2002 SCE’s recorded cost was $1.1 million for the replacement work of 18 substations resulting in a unit cost of $62,000 per substation.221

This statement ignores information SCE provided in response to ORA’s data request DR-ORA-101 Question 1, which specifically addressed the transition from the Substation Automation Program to the Distribution Protection and Control Replacement Program (DPCRP). The dollar amount used by ORA for its estimate is only from the DPCRP, while the number of substations is from both programs. ORA mixed portions of two programs for its calculation of an all-purpose unit cost. SCE’s engineering estimates are based on longstanding time and motion studies (which establish how long each task requires), and prevailing labor and material costs. In place of those estimates, ORA would rely on a simple average of

220 ORA Report, Volume 2, p. 13-D-50, lines 12-17.221 ORA Report, Volume 2, p. 13-D-50, lines 21-24.

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historical costs, completely ignoring the fact that there is no single unit cost that can be applied across all such projects due to the wide variation in the scope of the projects from year to year and project to project:

Based on the analysis presented above, ORA recommends using the escalated three-year average 2002-2004 expenditures and the actual number of substations replaced, as the basis for the 2005 and 2006 forecast. ORA’s calculations yield a work forecast of 17 substations and $6.2 million for 2005 and $6.4 million for 2006.222

ORA’s approach is to divide average expenditures on protection and control replacement over the 2002-2004 period by the number of substations replaced during that period to yield an average cost per substation, which ORA then multiplies by a “work forecast” of 17 substations. Averages of recorded infrastructure replacement costs are neither valid predictors of future spending, as previously discussed in this rebuttal, nor is ORA’s substation unit cost calculation a reasonable way to forecast future spending. The costs of each substation are driven by the protection requirements of each piece of substation equipment. ORA’s analysis is further flawed because of a fundamental misunderstanding of the information SCE provided. For example, ORA wrongly implied that SCE did not replace the protection and controls equipment in 187 substations223:

Also, SCE could not prove that the 187 substations where SCE claimed this equipment was previously replaced, actually experienced Electro Mechanical equipment failures, or that this equipment was actually replaced.224

When SCE asked ORA for the basis of this conclusion, ORA responded as follows:

222 Id., at p. 13-D-51, lines 6-10.223 See Appendix VI-F, “2003 GRC, Substation Automation Project.”224 ORA Report, Volume 2, p. 13-D-50, lines 2-5.

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ORA interpreted SCE’s response to ORA 101 Question 4 to mean that SCE does not have the information that ORA requested. ORA assumed that SCE would not replace a functioning piece of equipment, therefore it requested a breakdown of relay failure by type for each of the 187 substations. ORA assumed that the relays and control equipment in question may not have been replaced because SCE could not provide the breakdown by type of relays.This is again wrong. First, in the case of SCE’s past

substation automation program, it was more cost-effective to replace the existing equipment, even if still functioning, with new automated technology.225 SCE told ORA this in response to ORA’s data request 101, Question 4, in which SCE stated that relay failure was not the driver of the program:

SCE does not have the requested information on the breakdown of relay failure by type for these 187 substations. Relay failure is not the driver for this program. The description for Substation Automation Program address(es)sic the reasoning behind the replacement of the protection and control equipment for these 187 substation. Please refer to the answer for DR-ORA-101 Question 1 for a copy of the Substation Automation Program.ORA’s allegation that SCE may not have done that work are

also unjustified. In that same data request, SCE provided ORA expenditures by year showing the number of substation projects each year. ORA also states:

Additionally, the number of substations with replaced equipment differs from SCE’s data response and the testimony. According to SCE’s data response, when the Automation program ended in 2003, 244 substations had the protection and control equipments replaced compared to 187 substations presented in the Application.226

This is another mistake. In response to ORA’s data request DR-101, Question 1(d), SCE provided the details requested by ORA for all 225 See Appendix VI-F for a description of Substation Automation Project.226 ORA Report, Volume 2, p. 13-D-51, lines 1-5.

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replacements, which included equipment replaced under the substation SCADA227 expansion (PIN 3363), the Automation Program (PIN 4160), and the Protection and Control Equipment Replacement Program (PIN 4837). ORA mistakenly took the total of PIN 3363, PIN 4160, and PIN 4837 and compared that to the 187 substations associated with PIN 4160.

In sum, ORA has fundamentally mischaracterized, misinterpreted, or ignored the data SCE provided. ORA’s alternative forecast, based on recorded expenditures, ignores the impact of the financial crisis on this program and industry accepted engineering estimating processes.228 SCE’s Distribution Protection and Control Replacement Program provides the funding necessary to replace and upgrade the obsolete protective relays and control equipment that work in conjunction with the circuit breakers to protect the distribution system. Our forecast expenditures should be accepted as proposed in SCE testimony. Without these timely upgrades and replacements, the protection and control equipment could malfunction, either tripping a circuit when not needed or not trip a critical fault when the situation requires it, such as the Santa Monica failure referenced earlier in this testimony. These situations have direct impact on the reliability of service SCE is able to provide to our customers.

b) A/AA Control Room Upgrade SCE identified seven stations for upgrade and forecast

capital expenditures of $7.6 million in 2005 and $5.8 million in 2006. ORA proposes a $11.3 million reduction to that program, $1 million in each of the

227 SCADA – Supervisory Control and Data Acquisition.228 See Appendix VI-A entitled, “Cost Estimating.”

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years 2005 and 2006 based on the $2.4 million cost to upgrade the Villa Park substation.229

As stated in SCE’s direct testimony, the A/AA Control Room Upgrade and Replacement Program will provide automated control of our large attended stations by replacing the existing manual controls with a networked system.230 This program is a part of our effort to modernize obsolete monitoring and control equipment. It is required because several of our major switching centers have, in the past, become uninhabitable during emergency situations, leaving major interconnections without any monitoring and control. This program, once complete, will allow the remote monitoring and control of our major switching centers when such a situation arises again.

While ORA does not contest the need for this program, it challenged SCE’s estimated costs, alleging that SCE was unable to provide the support for those estimates:

ORA requested that SCE provide the support it relied upon for the forecast. SCE could not provide any support for the forecast and claims that “the numbers in this table were arrived [at] based on conceptual estimates.” Since SCE is only able to provide support for one project, that of the Villa Park substation, ORA recommends that only this project be included in the 2005 and 2006 forecast.231

Contrary to ORA’s assertions, SCE provided the cost breakdown in the same level of detail provided for the Villa Park and Mesa projects.232 As mentioned earlier, ORA simply asserts that SCE’s cost

229 ORA Report, Volume 2, p. 13-D-52, lines 17-19.230 SCE-3, Volume 3, Part IV, p. 38.231 ORA Report, Volume 2, p. 13-D-52, lines 9-15.232 SCE-3, Volume3, Part IV, Workpaper, pp. 324-326. Relevant excerpts are attached to

this testimony. See Appendix G “Cost Summary for A/AA Stations.”

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estimates, which were based on industry accepted standard engineering methods, are not acceptable while offering no objective alternatives.233 Since SCE’s estimates followed accepted industry practice, our A/AA Control Room Upgrade Program should be accepted as proposed.

Moreover, if ORA’s recommendation for a single upgrade were to be adopted, then the next time an emergency, such as fire, flood, train derailment, or earthquake requires SCE’s employees to vacate one of the targeted stations, SCE will be unable to operate that station remotely and a significant part of SCE’s service territory could go without power.D. Routine Capital Replacements

Notwithstanding SCE’s criticism of ORA’s averaging approaches, as discussed above, recorded expenditures can, in some circumstances, be a valid way to forecast future spending. In the context of ongoing Operations and Maintenance expenses, for example, the Commission has recognized that recorded averages can be appropriate in some cases:

For those accounts which have significant fluctuations in recorded expenses from year-to-year, or which are influenced by weather or other external forces beyond the control of the utility, an average of recorded expenses over a period of time (typically four years) is a reasonable base expense …234.While the above-quoted text came in the context of O&M expenses,

the concept can in some instances be applicable to capital expenditures, particularly expenditures in which the future scope of the program is similar to past levels, but the volume fluctuate from year-to-year. The concept of the recorded average is that each of the recorded years could be equally representative of forecast year expenditures. The averaging simply 233 See Appendix VI-A entitled, “Cost Estimating.” SCE’s estimating methodology is in

alignment with industry standards such as the Association for the Advancement of Cost Engineering (AACE). AACE methodology is recognized by federal agency such as the Federal Highway Administration.

234 D.04-07-022, (mimeo) p. 15.

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smoothes out year-to-year fluctuations. If an average of recorded capital expenditures is used, the data must be expressed in the same denomination, that is, it must be stated on a constant dollar basis. SCE applied the averaging approach to corroborate our forecast expenditures in several budget items that have been in existence for several years and in which the scope is not expected to change dramatically in the future. However, we did not rely solely on an average, even in those instances. We went on to identify increments necessary to reflect new activities that were not reflected in the recorded data. This is the approach we followed in estimating several of our Routine Capital Replacement categories. ORA has challenged several of those forecasts, which are discussed separately below.

1. Substation Equipment Reactive Replacement Blankets

In contrast to the Infrastructure Replacement Program, which tries to proactively replace equipment before it fails in service, the Substation Equipment Reactive Replacement Blankets fund substation equipment that has either already failed in service or requires immediate replacement due to inspections showing imminent failure. SCE proposed $26.779 million in 2005 and $32.933 million in 2006 for this program. ORA proposes a $23.8 million reduction:235

ORA is recommending a total of $17.7 million for 2005 and $18.2 million for 2006. ORA’s recommendation is based on the escalated four-year average for 1999-2003 expenditures, (which is $17.2 million for 2005 and $17.6 million for 2006,) and not $24.3 million, as SCE has claimed. ORA’s recommendation also includes costs for environmental remedial action in 2005 and in 2006 as requested by SCE.236

In proposing this reduction to our forecast, ORA wrongly accuses SCE of artificially inflating the historical averages. Also, ORA ignored the

235 ORA Report, Volume 2, p. 13-D-59, Table 13-D-17.236 Id., at p.13-D-58, lines 19-24.

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necessary adjustments to incorporate reactive replacements not accounted for in these blanket budget items.237 Finally, ORA failed to consider the known scope increase of these blanket expenditures.

As an initial matter, SCE did not inflate the historical averages, but adjusted the recorded cost to properly account for all reactive replacement expenditures. Prior to 2002, a portion of reactive replacement activities, such as those involving greater degree of complexity in project scope (for example, the replacement of a failed A-Bank transformer) were funded by offsetting this reactive blanket against another budget item (such as SIRP), resulting in the reduction in the recorded expenditure in this reactive blanket.

This same budget offset was also used on other reactive replacement projects of significant scope (i.e. more than a simple like-for-like swap-out) that required engineering and design work. In these cases, SCE’s Project Management Organization238 manages those projects and blanket budgets are offset by the expended capital amount. Again, this effectively reduces historical expenditures in these blanket budgets for reactive replacement of greater complexity.

With all the reactive replacement activities properly accounted for, the correct historical average is $24.3 million in constant 2003 dollars, not $15.6 million, as ORA claims. To estimate 2005 or 2006 expenditures, the $24.3 million in average expenditures (in constant 2003 dollars), should be escalated to the forecast year dollars, yielding $26 million in 2005 and $26.6 million in 2006. However, as discussed below, even with 237 SCE-3, Volume 3, Part IV, Workpapers, p. 324 - 326 shows the details of this average

calculation.238 The Project Management Organization’s role is to coordinate efforts among multiple

internal and external resources to ensure timely and cost-effective execution of capital expenditures.

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the correct inflation adjustments, this averaging approach would not be sufficient.

a) Reactive Replacement Not Previously Identified in Blanket Even if ORA’s analysis had been correctly escalated,

historical averages still do not reflect several new programs that do not appear in the recorded data. First, in 2005 we will make a one-time expenditure of $600,000 to replace butyl CTs that exhibit a failure mode during routine inspection. Second, SCE will be implementing an ongoing program to address the short lifespan of deteriorated wood cable trench covers, which will cost $1.6 million in 2006. Finally, we anticipate a greater number of reactive replacements of disconnect switches due to failures identified by the life extension initiative on disconnect switch maintenance, which is forecast to cost $560,000 in 2005 and $3 million in 2006. The following sections address each of the three new programs.

(1) Butyl CT Replacement In 1987, we surveyed and replaced those butyl CTs

that fit the specific criteria described in our workpapers. If the equipment did not meet the criteria for replacement, we left it in service. Recently, we have been experiencing increasing problems with this class of equipment, so we resurveyed it and identified the need to replace those CTs in an imminent-failure mode.239 ORA recommended a $600,000 disallowance in SCE’s Butyl CT Replacement Program,240 claiming:

ORA reviewed the data contained in the spreadsheet and discovered that vital information was missing in several places. One particular field, “Date Installed”, does not have any data. Therefore, ORA cannot determine if the butyl CTs in the spreadsheet provided and the ones

239 Data Request DR-ORA-137, Question 3.240 ORA Report, Volume 2, p. 13-D-56, line 8.

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identified as problematic in 1987 are one and the same.241

ORA is wrong. ORA has ignored the fact that we took action in 1987 to replace those CTs that had cracks, and prudently allowed the lower risk bulging CTs to remain in service another 17 years (as presented in SCE-3, Vol.3, Part IV, page 50, lines 4-5). SCE's 1987 decision was in the best interest of our customers since it avoided the replacement until 2005.

(2) Cable Trench Cover Replacement ORA proposes a $1.6 million disallowance in SCE’s

Cable Trench Cover Replacement Program:SCE’s request for $1.6 million in expenditures to replace cable trench covers in 2006 should be disallowed. SCE is requesting this additional amount to replace redwood covers with fiberglass reinforced polymer covers, normally tracked as an O&M expense. SCE claims that since the life expectancy of these covers will be extended, SCE has chosen to capitalize 75% of the cost and treat 25% as an O&M expense.242

SCE’s response to DR-ORA-45, Question 1(a) states our policy on the split between capital and O&M cost. ORA testimony completely mischaracterizes the information presented:

Through discovery, ORA determined that the level of replacement in 2006 is similar to that of 2001 and 2002. Furthermore, SCE has not demonstrated that there is a need to treat this as an urgent problem and accelerate the replacement rate.243

In response to DR-ORA-45, we provided detailed information on the expenditure in FERC Subaccount 570.400 to replace deteriorated redwood cable trench covers with new redwood covers. The 241 Id., at lines 19-24.242 Id., at p. 13-D-57, lines 2-7.243 ORA Report, Volume 2, p. 13-D-57, lines 8-11.

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reactive replacement information for the distribution substations is not included in the discussion of subaccount 570.400 which only covers transmission substations. Thus ORA’s claim that the proactive replacement program proposed for 2006 is similar to the reactive program in 2001 and 2002 is based on incomplete information. ORA’s testimony fails to recognize the scope of SCE’s proactive approach regarding the safety of its employees. ORA assumes that the historical rate of replacement was sufficient to address the replacement need going forward:

While ORA acknowledges the fact that deteriorated covers are a safety concern, ORA understands that this has been an ongoing problem for some time and that SCE has been replacing the cable trench covers as a maintenance issue.244

ORA failed to recognize that during recent years SCE has been in the process of developing a new trench cover with enhanced durability. While this development was taking place, SCE used redwood trench covers on an interim basis to replace trench covers that had failed and this historical replacement rate was insufficient to address the safety concerns of the increasing number of deteriorated trench covers.

ORA also mischaracterizes SCE’s guidelines for trench cover replacement costs:

According to SCE’s guidelines for the Replacement of Component Parts Independently of Retirement Unit, the company has been allocating cost to O&M and capital since 1987 so this is not a new issue.245

SCE’s guideline is very explicit that “like-for-like” component replacement is an O&M cost. Consistent with that policy, SCE has expensed past like-for-like replacement of redwood trench covers with redwood trench covers. ORA is 244 Id., at lines 11-14.245 ORA Report, Volume 2, p. 13-D-57, lines 14-17.

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simply wrong in its assumption that SCE has been allocating costs to O&M and capital since 1987. SCE has never allocated the like-for-like replacement of redwood trench covers to any capital plant account. The basis for allocating future replacement cost to capital is the significant improvement of longer life expectancy of this new material.

Additionally, ORA claims we provided inconsistent data regarding our increase in capital expenditures:

Also, SCE provided inconsistent data to substantiate its request for the increase in capital expenditures, ORA recommends that SCE continues at the level of spending as recorded for 2003 and that $1.6 million should be excluded from this request.246

This claim is refuted by SCE’s response to data requests, DEF-SCE-3-VOL-2, Question 1 Supplemental and DR-ORA-45, Question 1 (Supplemental), both of which state:

The correct allocation between Capital and O&M expense is 75% Capital and 25% O&M. The forecast amounts stated in the respective sections of Capital and O&M Testimony are correct and remain unchanged.Rather than discuss the capital expenditures on the

replacement of trench covers, ORA points to another section in its testimony for a more detailed discussion in its O&M testimony:

A detailed discussion of cable trench cover replacements can be found in Chapter 6-B of ORA’s Results of Operations Report.247

However, ORA’s testimony in Chapter 6-B does not include a detailed discussion of the entire Cable Trench Cover Replacement Program. The account in question (FERC 570.400) only addresses the expenses in SCE’s

246 Id., at lines 17-20.247 ORA Report, Volume 2, p. 13-D-57, lines 20-22.

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500 and 220kV substations. In fact, the ORA did not even address the cable trench cover replacement program at distribution substations.248

(3) Disconnect Switch Replacement ORA proposes a $3.6 million disallowance in SCE’s

Disconnect Switch Replacement Program, claiming SCE failed to support the quantity requested:249

Although SCE discussed the need to replace disconnect switches in great detail in its testimony, the company did not provide any support for the quantity it is requesting for 2005 and 2006. ORA requested the number of disconnect switches identified for repair and those identified for replacement, as well as the unit cost from 1999-2004, in order to determine the reasonableness of SCE’s forecast. SCE could not provide the data requested and claims the information was not available.250

Although the specific information requested by ORA was not available,251 ORA ignores factual information presented in SCE’s direct testimony, supporting workpapers, and responses to data requests. For example, SCE’s response to DR-ORA-137, Question 10, Exhibit SCE-3, Vol. 3, Part IV, Pages 51-53, and Workpaper page 472 provided the basis for determining the cost of the program with specific quantities and unit costs. This information is sufficient for ORA to do a proper analysis and support SCE’s requested expenditures

248 See Rebuttal Testimony on 570.400 for a detailed analysis of ORA testimony.249 ORA Report, Volume 2, Volume 2, p. 13-D-58, lines 2-3.250 Id., at lines 3-10.251 The specific information requested by ORA was not available because we have not

previously made a concerted effort to proactively replace disconnect switches. Disconnect switches typically have not required frequent maintenance and adjustments. But the need for adjustments and maintenance becomes increasingly more important as switches age due to weather exposure and gradual annealing due to loading, which reduces the switch blade's tensile strength and results in misalignment of contacts and overheating.

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because provided the reasons for the replacement, the rate of replacement, and the unit cost of these anticipated replacements.

b) Reactive Replacement Blankets Recommendation ORA’s recorded cost analysis does not account for all

reactive replacements we made in the past. Also, as discussed, ORA did not include the anticipated reactive replacements of butyl CTs, cable trench covers, and disconnect switches, all of which contribute toward maintaining the reliability of the service and minimizing the safety risk of our employees. ORA’s incomplete analysis should be rejected.

By contrast, SCE has not only demonstrated that these anticipated replacements are necessary, but also that they are based on prudent inspections stemming from our life extension initiative.252

2. Rule 20B Circuit Breaker Replacement

ORA proposes a $3.9 million disallowance in SCE’s Rule 20B Circuit Breaker Replacement Program claiming SCE did not justify its request:253

While SCE is unable to justify its request for 2005 and 2006, ORA recognizes that the replacement of circuit breakers as a result of Rule 20B projects is sometimes necessary. As such, ORA recommends the adoption of the escalated three-year average of 2002-2004 recorded expenditures as the 2005 and 2006 forecast. ORA’s recommendation is $294,397 for 2005 and $302,3999[sic] for 2006 compared to SCE’s estimates of $2.2 million and $2.3 million respectively, for 2005 and 2006.254

On the contrary, SCE’s testimony describes the need for this program:

252 See SCE-15 Volume 2 – T&D O&M, Subaccount 570.400 for further discussion on life extension initiatives.

253 Note: ORA Report, Volume 2, p. 13-D-61, Table 13-D-19 has SCE expenditures $2.2 million in both 2005 and 2006. SCE forecast is $2.21 and 2.27 million, respectively. This presents another inconsistency in the ORA testimony.


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Older circuit breakers may not meet newer operational requirements. A number of the older 66kV and 115kV class circuit breakers are incapable of de-energizing underground cable beyond a certain length. When the Rule 20B projects cause the cable to exceed this length, the circuit breaker must be replaced.255

Furthermore, SCE also described the basis for our forecast:For subtransmission capital expenditures (System Item 089B/C), our five-year average capital expenditures are $7.8 million (in 2003 constant dollars). However, we experienced an abnormally low year in 2003 in this category, which is not representative of ongoing capital expenditures. A four-year average for 1999 through 2002 capital expenditures is $9.2 million (in 2003 constant dollars), which is reasonably representative of ongoing expenditures in this category. We therefore forecast our 2004 through 2008 subtransmission capital expenditures for Rule 20B projects as a four-year average of 1999-2002 expenditures, adjusted for inflation.256

Another problem with ORA’s forecast is that it is based on a three-year average of historical expenditures. This is not appropriate for two reasons. First, the Rule 20B projects historically did not include the replacement of the circuit breakers. It was only recently, in the 2002-2003 timeframe, that we began to include circuit breaker replacement as a part of the Rule 20B project scope. Second, in 2003 the expenditures related to Rule 20B work in general was abnormally low and not representative of future spending needs. Therefore, a three-year average cannot produce a reasonable estimate of future spending. SCE’s forecast reflects the appropriate sharing of these costs between developers and rate payers.257 ORA’s recommendation would unfairly burden ratepayers by not having the respective developers share the upfront cost of replacing circuit breakers associated with Rule 20B circuits. These replacements are necessary when the additional capacitive current caused by the underground cable exceeds

255 SCE-3, Volume 3, Part IV, p. 54.256 SCE-3, Volume 3, Part I, p. 76.257 SCE’s response to DR-ORA-136, Question 7.

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the capability of the circuit breaker’s rating for successful interruption. Not replacing these circuit breakers could result in significant safety risk to the public and to SCE’s employees, plus the accelerated failure of the affected circuit breakers. For these reasons, SCE’s forecast should be adopted.E. Other Capital Requirements

1. Tools, Spare Parts and Equipment

In direct testimony, SCE stated that its Tools, Spare Parts, and Equipment category is comprised of three individual sub-categories: (1) Grid Dispatch; (2) Tools and Work Equipment; and (3) Substation Spare Parts and Equipment. SCE forecasts total expenditures of $8.1 million in 2005 and $9.1 million in 2006. ORA’s analysis did not examine the unique characteristics of each sub-categories program, but rather focus its discussion on the Substation Spare Parts and Equipment, and then based a three-year average from an incorrect set of recorded expenditures as the basis of recommendation for the combined expenditures of all three sub-categories.

ORA’s testimony contains many miscalculations and wrong assumptions. For example, ORA states:

SCE is requesting $8.1 million for 2005 and $9.1 million for 2006. These requests are more than double the actual expenditures of $4.3 million recorded for 2004. Last year, SCE spent $2.4 million less than its original forecast of $6.7 million for 2004. SCE’s 2005 and 2006 forecast is more than twice the three-year average of 2002 through 2004 expenditures, which totaled $4.7 million.258

…SCE is forecasting twice as many failures, fourteen in 2005 and thirteen in 2006, compared to historical levels.259

258 ORA Report, Volume 2, p. 13-D-63 lines 17-23.259 Id., at p. 13-D-64, lines 12-13.

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In the first paragraph quoted above, ORA states that the three-year average, 2002, 2003, and 2004, in nominal dollars is $4.7 million. This is incorrect. In response to DR-ORA-32 Question 1 and DR-ORA-144 Question 5, SCE provided the recorded expenditures of $7.528 million, $3.965 million, and $4.305 million for 2002, 2003, and 2004 respectively, all in nominal dollars. The correct escalated average of recorded expenditures is $5.300 million in constant 2003 dollars, not $4.7 million as presented by ORA.

In the second paragraph, ORA assumes that the number of transformers identified for replacement in the B-Bank Replacement Program is the number of failed transformers. ORA acknowledges this error in data request SCE-ORA-12, Question 26, in which is stated:

ORA mis-quoted SCE’s testimony. ORA’s testimony, page 13-D-64, lines 12-13, beginning with “SCE is forecasting” and ending with “historical levels” should be stricken and replaced with “ SCE is forecasting twice as many transformers that will experience imminent failures, fourteen in 2005 and thirteen in 2006, compared to historical levels of failures.”However, even in this restatement, ORA has failed to

demonstrate the understanding that signs of imminent failure, while a significant component of overall evaluation, is not the sole reason for replacement. SCE has clearly identified the B-Bank Replacement Program as the proactive replacement of transformers while the expenditures in this blanket are primarily in support of the reactive replacement of transformers which have failed in service due to the long lead time in manufacturing and delivery of key substation equipment. The ORA testimony also states:

ORA explored the issue of historical B-Banks failures, but could not find SCE’s support for an increase in the number of failures in the near future.260


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ORA has ignored SCE’s response to DR-ORA-139, Question 13, in which ORA requested the total number of B-Bank failures in 2004 and we informed ORA that we had experienced eight failures. Our replenishment rate for the existing transformer spare inventory (provided in response to DR-ORA-135 Q8)261 added only five units in the B-bank category for both 12kV and 16kV distribution system in 2004, when we experienced 8 failures. This is a clear indication of our need to increase spending on our transformer bank inventory to maintain adequate spare support for a population of approximately 1,300 units over the age of 50 out of the total of approximately 3,000 units in service. All of this information was provided in the testimony SCE-3, Vol. 3, Part IV, p 32. In 2004, SCE experienced 11 failures of the power transformers, three A-banks and eight B-banks. Historically, due to the lead time of transformers, significant changes occur in the expenditures supporting this account in the year following a significant change in the failure rate of transformers.

ORA’s recommendation is based on an incorrect s a three year average:

Based on the assessments above, ORA recommends the adoption of SCE’s escalated three-year average spending each year for 2005 and 2006. ORA’s recommendation is $4.9 million for 2005 and $5 million for 2006. This recommendation compares closely to SCE’s 2004 cost of $4.3 million. ORA’s recommendation will be a reduction of $3.2 million in 2005 and $4.1 million in 2006 to SCE’s request of $8.1 million and $9.1 million, respectively.262

ORA’s analysis is inaccurate and resulted in erroneous conclusions. ORA’s proposed reduction to our forecast not only did not account for the need to provide tools and equipment for our increasing workforce to support the new customer and load growth and the aging 261 See Appendix VI-H, “Emergency Spare Transformer Purchase Costs, 1999 – 2004.”262 ORA Report, Volume 2, p. 13-D-65, lines 12-18.

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infrastructure, it also puts SCE at risk of not having adequate spare inventory of long lead-time equipment for emergency replacements. SCE’s forecast account for the needs described above in addition to the support provided in my direct testimony and should be accepted.263

2. Non-Operational Facility Blanket

ORA recommended a $10 million disallowance in SCE’s Non-Operational Facility Blanket claiming:

ORA requested a breakdown of the $5 million in expenditures each year for 2005 and 2006 by the witnesses referenced. SCE could not provide specific allocations to new employees, contract workforce, or T&D upgrades, although the company claimed that this request is designated specifically to these areas.264

However, SCE did not provide any historical data or document any experience to support the company’s forecast.265

ORA ignored the data SCE provided in response to DR-ORA-135, Question 3, which showed details on the increases in SCE contractor and office employees, showing the significant increase of workforce impacting the availability office space and facilities.266 From 1999 and 2004, total head count with direct impact to facility need grew from 4,328 to 4,853, a more than 10 percent increase in manning that has impacted facility needs.

ORA testimony also takes issue with the fact that SCE addressed these expenditures in our T&D testimony:

Furthermore, ORA notes that SCE should have addressed this issue in Mr. Schuur’s testimony.

263 See SCE-3, Volume 3, Part IV, pp. 60-62 for additional details on the need for tools and work equipment.

264 ORA Report, Volume 2, p. 13-D-66, lines 10-14.265 Id., at lines 21-23.266 See Appendix VI-I, “TDBU Employee Count.”

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First, which exhibit we choose to present a cost estimate should be our discretion. Second, SCE’s Corporate Real Estate testimony has only addressed defined projects. However, even these defined projects can be subjected to cost and scope impacts. For example, the San Jacinto Service Center which is in one of the fastest growing areas of our service territory, has a defined project within Mr. Schuur’s testimony. The congestions at the San Jacinto Service Center have created numerous challenges in meeting the growing demands of our customers in that vicinity. Initial plan for relieving the facility congestion was quickly overwhelmed by the continuous increasing in workload and the additional staffing to support these increased workloads. Further options were explored to relieve the congestion at the facility. Instead of taking a band-aid approach to solving space limitation with temporary trailers, permanent building additions are now part of the project scope. The project scope is further expanded by the requirements imposed by the local authorities on issues such as permanent sewer connections, ingress and egress expansion, and block-wall fencing. On top of these scope changes, the complexity of maintaining the normal business operation while expansion construction takes place has also resulted in an increase of the project budget. These overwhelming scope changes has resulted in an large increase in the project budget from the original estimate of $2 million presented in Mr. Schuur’s testimony to over $8 million in early 2005. These forecast increases are directly related to the resolution of the severe shortage of facilities in this rapidly growing area. The San Jacinto facility expansion is an example of the challenges SCE faces in several other high growth area discussed in my direct testimony. The forecast expenditures in this non-operational facility blanket are absolutely necessary. Without this blanket, the SCE’s severe facilities shortage would

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negatively impact our ability to meet the needs of customer growth and load growth. Given the inaccurate and incomplete analysis of the information provided by ORA, its recommendation should be rejected. SCE’s requested expenditure in testimony should be approved.

3. Fee Simple and Right of Way

ORA proposes a $4.4 million disallowance in SCE’s Fee Simple and Rights of Way acquisition in support of the load growth projects.267 SCE identified the following projects, Las Lomas (DSP 2009), Akers (DSP 2009), Canine (DSP 2009) and Oak Valley (DSP 2008) in this expenditure. Of these only Oak Valley would be directly addressed in Mr. Takayesu’s Load Growth Testimony, SCE-3, Volume 3, Part II, T&D Capital. ORA states:

ORA has reviewed SCE’s supporting documents for this work category. According to responses to ORA data requests, SCE has not yet begun work on the Oak Valley acquisition project. The Akers and Canine projects currently have no supporting data to show that these projects will be completed in the year forecasted. It appears that SCE has not yet located potential substation sites for the Akers project and that the target date for this project, January 28, 2005, has not been met. As for the Canine project, SCE provided no supporting data at all for this acquisition. Finally, ORA learned that the Las Lomas acquisition is currently on hold pending a municipalization decision by the City of Irvine. As such, SCE will not need any of the requested capital expenditures it has previously requested.268

ORA incorrectly assumes that the capital requirement for these projects is not needed although it does not refute the need for the Oak Valley project, which is in SCE’s testimony. The other stations are identified as being in-service in the 2009 timeframe. These projects are not cancelled. While there is a slight delay in executing the land purchase agreements, the expenditures of for these site purchases will occurs soon after the issues are resolved.267 ORA Report, Volume 2, p. 13-D-68, Table 13-D-23.268 Id. at lines 1-12.

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ORA has taken an irresponsible position in completely eliminated the funding to acquire new site for substations needs due to customer growth and load growth. The request funding is necessary to support system extension needed to serve customers and should be accepted.

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REBUTTAL TO ORA AND TURN TESTIMONY ON ... · Web viewFigure VI-4 Moorpark Substation 220kV...

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