DeAngelis Agenda Dec. Revision 3 Appendices A-D
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ALJ/RMD/rbg/hkr ** DRAFT Agenda ID #8129 (Rev. 3)

Decision PROPOSED DECISION OF ALJ DeANGELIS (Mailed 11/18/ 2008)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of SOUTHERN CALIFORNIA EDISON COMPANY (U338E) for Authority to, Among Other Things, Increase Its Authorized Revenues For Electric Service in 2009, And to Reflect That Increase In Rates.

Application 07-11-011

(Filed November 19, 2007)

And Related Matter.

Investigation 08-01-026

(See Appendix A for a list of appearances.)

DECISION ON TEST YEAR 2009 GENERAL RATE CASE
FOR SOUTHERN CALIFORNIA EDISON COMPANY

TABLE OF CONTENTS

APPENDIX A

List of Appearances

APPENDIX B

Transportation Increase in O&M by Activity - Allocation of Forecast - $(000) 2006$

APPENDIX C

TY 2009 Revenue Requirement

APPENDIX D

Post-TY 2010 and 2011 Revenue Requirement

DECISION ON TEST YEAR 2009 GENERAL RATE CASE
FOR SOUTHERN CALIFORNIA EDISON COMPANY

1. Summary

This decision authorizes a $4.644 billion base revenue requirement for test year (TY) 2009 for Southern California Edison Company (SCE). We find that the authorized revenue requirement provides SCE with sufficient funding to provide safe and reliable service at just and reasonable rates. The adopted revenue requirement represents a 23.9% increase over the 2006 authorized revenue requirement of $3.749 billion, a 13.1% increase over SCE's 2006 recorded base revenues of $4.106 billion, a 7.1% increase over the projected revenue at present rates of $4.334 billion, and an 10.78% reduction from the 2009 revenue requirement requested by SCE of $5.205 billion,1 which represented a 20.1% increase over the projected revenues at present rates. The adopted methodology for calculating post-test year revenue requirement results in a revenue requirement for 2010 of $4.783 billion and for 2011 of $4.927 billion. As a result of our decision today, SCE's projected total company revenue requirement for 2009 is approximately $12.4 billion. This proceeding is closed.

1.1. Forecast Test Year Ratemaking

Our decision today is guided by a fundamental tenet of forecast test year ratemaking that inclusion of a particular expense category in a general rate case (GRC) authorization does not create a specific obligation for the utility to spend the authorized amount during the test year. Utility management is generally provided discretion regarding use of funds and is not bound by the adopted forecast. However, as we have observed in prior decisions, there are limits to that management discretion and when a utility's GRC expense estimate includes the performance of a task it had planned to accomplish with previously authorized funds, the Commission wants to know why the utility did not spend its funds as planned and we will be hesitant to charge ratepayers twice for the same expense.2

In this proceeding, SCE seeks additional funds for activities explicitly authorized by the Commission in the past. SCE seeks funds to redress maintenance postponed due to unanticipated load and customer growth in 2006-2007. To address this unforeseen customer and load growth, SCE diverted millions of dollars in capital replacements3 away from its Infrastructure Replacement project, including funds for preventative maintenance of distribution and substation equipment, such as circuit breakers and other similar equipment. SCE also seeks funds related to the July 2006 "heat storms," when approximately 1,300 distribution transformers were either damaged or destroyed.4 Because of these and other circumstances, SCE spent approximately $300 million5 more than authorized in its 2006 GRC, with a large percentage of this amount related to unanticipated customer growth needs.6 In considering that SCE spent above amounts authorized in test year 2006, we also take into consideration that SCE's authorized rate of return for 2006 was 8.77% and its recorded rate of return for 2006 was 8.70%. This 0.07% difference equals approximately $8.4 million.

SCE asks the Commission to find SCE's explanation, unforeseen customer and load growth, justifies, in part, the magnitude of its requested increases. SCE explains, for example, that recorded 2006 capital additions were $1.463 billion and for 2009 SCE seeks $3.201 billion, an over 200% increase, to address, among other things, matters deferred because SCE directed funds to other areas impacted by unanticipated load and customer growth. SCE does not quantify the specific amount of funds diverted or identify any additional costs resulting from this decision to defer routine maintenance.

In the past we have found circumstances, such as the unanticipated scope of Year 2000 (Y2K) projects, to justify deferral of certain maintenance work. The circumstances surrounding Y2K and the related Y2K projects were one-time events and, as such, unique. In contrast, we do not find customer and load growth, even when unanticipated, to create unique circumstances. Load growth and customer growth are routine aspects of any rate case. If the adopted forecast overestimates expenses we do not ask a utility to return funds to ratepayers. Similarly, if an adopted forecast underestimates expenses, we do not go back and give the utility funds to complete projects that should have been addressed in the prior GRC cycle. In short, errors in forecasting occur and we do not go back and fix these errors.

Our policy has been explained by Justice Clark, dissenting, in Southern Cal. Edison Co. v. Pub. Util. Comm., (1978) 20 Cal.3d 813, 836, Justice Clark addressed matters related to errors in forecasting as follows: "If the estimated revenues were too high or the estimated costs too low, the utility will bear the loss and fail to recover the projected rate of return. On the other hand, if the estimated revenues are lower than those that actually occur or the estimated costs higher than actual costs, the utility will benefit. Because so many circumstances exist significantly affecting expense and revenue, it is to be anticipated that estimated costs and revenues will rarely, if ever, equal actual ones and that the utility will realize more or less than the predicted rate of return."

It is also our policy that it would be unjust and unreasonable to make ratepayers responsible for expenses directly attributable to deficient or unreasonably deferred maintenance or to make ratepayers pay a second time for activities explicitly authorized by the Commission in the past. As we stated in Decision No. (D.) 82-12-055:

"For us to authorize Edison's recovery of deferred maintenance expense would establish an undesirable precedent, whereby the utility is effectively guaranteed that it can earn (or exceed) its authorized rate of return, regardless of its operating efficiency or inefficiency, simply by curtailing current maintenance activities, in the assurance that they could be refinanced later through recovery of deferred maintenance expenses in a succeeding rate case."

In Southern California Edison, supra, the Justice Clark expressed the same concern and cautioned that shifting "the risk of error in estimating costs and revenues from the utility to the consumer," reduces the utilities' incentive for efficiency. Consistent with our policy regarding deferred maintenance, in certain instances in this decision, we adopt reductions to SCE's forecast for operation & maintenance and capital expenditures to reflect our finding that unanticipated load and customer growth does not justify SCE's decision to, among other things, defer maintenance.

In other instances, our reductions to SCE's requested revenue requirement are consistent with SCE's May 2008 downward adjustment to its request to reflect the economic downturn. The financial markets in the United States continue to suffer significant upheaval in large part due to the home mortgage lending market crisis which directly led to the failures or mergers of many long-standing financial institutions. We do not yet know the long-term implications of this financial crisis. In these circumstances, it remains our obligation to use our best judgment, knowledge and experience to authorize a revenue requirement that provides SCE with sufficient funding to provide safe and reliable service at just and reasonable rates.

The authorized base revenue requirement in this case should also be considered within the context of the Commission's regulation of the expenses of the entire company. The revenues from SCE's GRC represent approximately 36% of SCE's total company revenues. The remaining 64% of SCE's total company revenues is determined in various other proceedings before this Commission, many of which are governed by balancing accounts, and include fuel and purchased power, the Department of Water Resources Power and Bond Charge, Federal Energy Regulatory Commission (FERC) jurisdictional costs, and funding for Public Purpose Programs.

A significant percentage, approximately 44%, of SCE's total company revenues is determined by SCE's fuel and purchased power costs. The Commission reviews these amounts in the Energy Resource Recovery Account (ERRA) proceedings. SCE's most recent ERRA filing, Application (A.) 08-09-011, requests a 2009 ERRA revenue requirement of $4.639 billion effective January 1, 2009. SCE's total company revenue requirement also consists of amounts approved by FERC which are associated with transmission. The Commission incorporates these costs into California rates and SCE's total company revenue requirement. This case also does not adopt a cost of capital. We address cost of capital in a separate proceeding. The most recent cost of capital proceeding, A.07-12-049, authorized an 8.75% cost of capital. In phase II of this general rate case process, which is a separate proceeding, A.08-03-002, the Commission uses the revenue requirement authorized in this proceeding and divides it up between the various customer classes.

In short, the expenses authorized in this proceeding, $4,643,839,000, do not amount to all the costs included in rates. The authorized amount does, however, provide SCE with sufficient funding to provide safe and reliable service at just and reasonable rates.

1.2. Procedural History

On November 19, 2007, SCE filed its test year (TY) 2009 GRC application. In support of its application, SCE provided over 8,500 pages of testimony, 53,000 pages of workpapers and sponsored more than 100 witnesses. The prehearing conference in this proceeding was held on January 15, 2008. The presiding officer, Administrative Law Judge (ALJ) Regina M. DeAngelis, and the assigned Commissioner, President Michael R. Peevey, attended. SCE proposed a procedural schedule based on the Commission's 1989 Rate Case Plan, as modified by numerous subsequent decisions, the most recent being D.07-07-004. The Division of Ratepayer Advocates (DRA) and The Utility Reform Network (TURN) proposed a more extended schedule similar to the schedules adopted by the Commission for other large energy utility general rate cases for the last ten years. In the end, the assigned Commissioner adopted a schedule with the goal of presenting the full Commission with a proposed decision for consideration before the end of 2008.

The assigned Commissioner, knowing the adopted schedule was ambitious, strongly encouraged parties to engage in alternative dispute resolution. Consistent with the assigned Commissioner's statements at the prehearing conference regarding settlement, the procedural schedule specifically incorporated a mechanism for alternative dispute resolution and the Commissioner urged the parties to rely on the settlement process when appropriate. While parties made minor efforts in this regard, nothing notable was accomplished. In future general rate cases, we expect parties to make more of an effort to engage in the resolution of GRC matters.

SCE's application generated a significant amount of interest from customers residing in SCE's service area. In response to this interest, the Commission held public participation hearings between April 14, 2008 and June 19, 2008 in Palm Springs, Visalia, Long Beach, Santa Ana, San Bernardino, Compton and San Clemente. Evidentiary hearings were held in Los Angeles on May 29 - May 30, 2008 and continued in San Francisco through June 16, 2008. In an effort to make the hearings more accessible, the Commission video webcast the hearings held in San Francisco. Parties submitted concurrent opening and reply briefs on July 25, 2008 and August 8, 2008, respectively. This consolidated proceeding was submitted on October 6, 2008 after the conclusion of update hearings. The Commission held an oral argument on December 9, 2008. TURN filed a motion to reopen the evidentiary record on January 12, 2009. TURN's motion argued that the economic downturn required the Commission to consider new evidence on the accuracy of SCE's forecasts. SCE and others responded to this motion. TURN's motion is denied.

1.3. Burden of Proof

The Commission is charged with the responsibility of ensuring that all rates demanded or received by a public utility are just and reasonable: "no public utility shall change any rate... except upon a showing before the Commission, and a finding by the Commission that the new rate is justified."7 As the applicant, SCE must meet the burden of proving that it is entitled to the relief it is seeking in this proceeding.8 SCE has the burden of affirmatively establishing the reasonableness of all aspects of its application. Other parties do not have the burden of proving the unreasonableness of SCE's showing.

1.4. Standard of Proof

With the burden of proof placed on the applicant in rate cases, the Commission has held that the standard of proof the applicant must meet is that of a preponderance of evidence, which the Commission has, at times, incorrectly referred to as "clear and convincing" evidence.9 Evidence Code § 190 defines "proof" as the establishment by evidence of "a requisite degree of belief."10 We have analyzed the record in this proceeding within these parameters.

2. Generation Expenses

2.1. Nuclear Generation

2.1.1. SONGS 2 & 3 Operation and Maintenance

SCE is the operating agent and 78.21% co-owner11 of San Onofre Nuclear Generating Station Unit Nos. 2 & 3 (SONGS 2 & 3).12 SONGS 2 & 3 entered commercial operation on August 8, 1983 and April 1, 1984 and provide SCE with a maximum capacity of 837 MW and 845 MW (SCE 78.21% share). For TY 2009, SCE forecasts base O&M expenses13 of $264.2 million (100% level) (constant 2006$) or $206.4 million (SCE share). SCE's request of $206.4 million represents a 1.4% increase over 2006.14 SCE's forecast for base O&M expenses excludes refueling and maintenance outage expenses. SCE requests an additional $39.6 million for refueling and maintenance outage O&M.

DRA recommends removing from SCE's TY 2009 request $4.4 million associated with a proposed Nuclear Regulatory Commission (NRC) license renewal study and $0.340 million, representing 50% of SCE's Nuclear Energy Institute (NEI) fees. DRA also recommends a reduced forecast of $38.2 million (SCE share) for refueling and maintenance outage O&M, which represents a reduction of $1.5 million from SCE's request of $39.6 million.

2.1.2. NRC License Renewal Feasibility Study - FERC Account 524

SCE's TY 2009 forecast includes $5.6 million (100% level and constant 2006$) or $4.4 million (SCE share) for a SONGS 2 & 3 license renewal feasibility study. The NRC issued operating licenses to SONGS 2 & 3 in 1982 and 1983, respectively, and their licenses expire in 2022.15 SCE plans to begin studying the feasibility of license renewal in 2009, a process that SCE claims will take about 3 years. SCE explains that it would then file an application with the NRC in late 2012 and would anticipate obtaining a decision from the NRC around 2015,16 which would be about seven years before the current operating licenses expire. SCE includes the license renewal study costs in FERC Account 524.17 SCE's proposal to pay for the license renewal study with offsetting O&M cost reductions is unconvincing.18 SCE is starting its SONGS 2 & 3 license renewal study at just beyond the midpoint of its current licenses and well before the cutoff point of 35 years.

DRA recommends that the Commission reject funding for SCE's NRC license renewal study. DRA asserts that the NRC license renewal study is premature and SCE will have a better understanding of the status of SONGS 2 & 3 closer to the end of the current license period. DRA further points out SCE proposes to replace the steam generators at SONGS in 2009 and 2010,19 a major capital investment, and suggests that initiating the license renewal study before the steam generator replacements is premature. DRA recommends that SCE propose the license renewal study in its TY 2012 GRC and provide any necessary evidence supporting the study at that time.

We agree with DRA that SCE's replacement of the steam generators will provide SCE with valuable information that is likely to improve the relicensing process. We do not find that SCE must start this relicensing process during 2009-2011. Instead, we find that a later start date will not jeopardize obtaining a NRC license in a timely manner. DRA argues and we agree that SCE does not need to initiate this study until at least 2012. Accordingly, SCE's request to include in the TY 2009 forecast $4.4 million (SCE share) for a SONGS 2 & 3 license renewal feasibility study is not adopted.

2.1.3. Nuclear Energy Institute Fees - FERC Account 517

SCE's TY 2009 forecast includes $0.685 million (constant 2006$ and 100% level) ($0.536 million - SCE 78.21% share) for NEI fees.20 NEI is the policy organization of the nuclear energy and technologies industry. It promotes the beneficial uses of nuclear energy and technologies in the United States and around the world. DRA recommends removal of 50% of SCE's NEI fees from SCE's TY 2009 forecast. DRA points out that in the 2006 SCE GRC, the Commission disallowed 50% of SCE's NEI fee request. In that decision, we found "[f]or ratepayer recovery of NEI dues, in the future, SCE should provide more detailed descriptions of the activities, the associated costs, and the resulting company and ratepayer benefits. With that information, in the future, we can make a more informed decision regarding disallowances."21

We agree with DRA. SCE asserts that its participation in NEI programs, committees, and activities helps SCE to address issues important to the nuclear industry. These issues include regulatory reform, management of used nuclear fuel, provision of a stable fuel supply, and license renewal.22 However, SCE fails to establish that all the benefits of its NEI membership go to its customers. For instance, NEI engages in work that furthers the interests of the nuclear industry. Such work (for example, public relations and image advertising) may not be appropriate for ratepayer funding. SCE estimates that approximately 15% of membership fees are for these types of activities.23 Other work performed by NEI may benefit the industry rather than ratepayers. For example, DRA points out that "ratepayers should not be paying . . .to support NEI as it goes about `[s]tudying nuclear energy's intrinsic economic value to promote a general understanding of the value of nuclear power by policymakers and the public; and [b]uilding the next generation of nuclear power plants and technologies.'"24 SCE fails to address the amount of resources allocated to these types of studies. Accordingly, while SCE made further efforts to describe how the work performed by NEI benefits ratepayers, the extent to which NEI's work benefits ratepayers versus the members of the nuclear generation industry remains unclear.

We adopt DRA's recommendation to continue our policy set forth in D.06-05-01625 of authorizing SCE to recover half of its share of NEI fees, $268,000.

2.1.4. SONGS Refueling and Maintenance Outages - FERC Accounts 517,520, 524, 525, 528, 529, and 532

SCE asks the Commission to adopt its refueling and maintenance outage forecast costs of $39.6 million (SCE share26 and constant 2006$) per outage per unit. SCE forecasts one refueling and maintenance outage in 2009. However, SCE asserts that since it is difficult to predict with certainty whether zero, one, or two outages will occur in any given year, SCE asks the Commission to continue the flexible outage schedule.

The post-test year ratemaking flexible outage schedule mechanism establishes a standard per unit per outage cost in the GRC and then allows determination of whether zero, one, or two outages will occur in each year of the GRC cycle (2009-2011). The Commission has adopted this mechanism in prior GRCs as the means to most accurately predict PTYR refueling and maintenance outage costs.27 No parties opposes SCE's request to continue the mechanism.28 Accordingly, we adopt the mechanism for years 2009-2011.

SCE developed its TY 2009 refueling and maintenance outage estimate by averaging its estimates for TY 2009 and post-TY 2010 and 2011.29 SCE expects to replace the SONGS 2 & 3 steam generators in 2009 and 2010,30 so it did not include the cost of steam generator inspections in those years but added $5.4 million for steam generator inspections in post-TY 2011. Since SCE will not incur steam generator inspection costs in TY 2009, DRA recommends the Commission adopt a TY 2009 refueling and maintenance outage forecast of $38.2 million (SCE share), a difference of $1.5 million.

We find SCE's TY 2009 refueling and maintenance outage O&M forecast of $39.6 million (SCE share) reasonable as it normalizes the 2011 costs over the three-year (2009-2011) GRC period.

2.1.5. Palo Verde - FERC Accounts 517, 519, 520, 523, 524, 528-532

SCE is 15.8% co-owner of Palo Verde Nuclear Generation Stations (Palo Verde).31 Arizona Public Service Company (APS) is the operating agent of Palo Verde.32 SCE forecasts Palo Verde O&M costs of $82.5 million (constant 2006$ and SCE share) in TY 2009.33 To forecast Palo Verde O&M expenses, SCE uses the last recorded year, 2006, adjusted to eliminate one-time expenses, and then applies the necessary future adjustments.34 SCE does not rely on the APS forecast of O&M expenses because, according to SCE, APS consistently underestimates its O&M expenses by an average $9.9 million per year.35 Given the uncertainty of the APS forecasts, SCE suggests the Commission adopt a two-way balancing account for Palo Verde O&M costs, beginning with the decision in this proceeding.36

DRA recommends the Commission adopt a TY 2009 forecast equal to SCE's estimated 2007 O&M expenses ($64.2 million). DRA's recommendation represents a reduction to SCE's forecast of $18.3 million.37 DRA's recommendation mainly reflects its concern about significant O&M increases in recent years and a rejection of additional staffing increases proposed by APS. APS's proposed staffing increases seek to reduce backlogs in areas of engineering and elective maintenance. DRA claims these backlogs can be addressed without staff increases.

In support of its request to include staffing increases in the TY 2009 forecast, SCE claims that Palo Verde's engineering backlog has increased significantly because of necessary improvement initiatives in response to NRC oversight, resulting in a 42% increase in work in 2007, and that even with substantial effort and good progress, APS would be working to reduce backlog items well through 2009.38

We find SCE's argument convincing. Furthermore, it appears SCE has historically under-recovered its Palo Verde O&M expenses by an average $9.9 million per year due to APS consistently underestimating its O&M expenses.39 To address these uncertainties and, to a certain extent, DRA's concerns, we adopt SCE's suggestion of relying on a two-way balancing account for Palo Verde O&M costs, beginning with the decision in this proceeding.40

Under SCE's proposal, the Palo Verde Balancing Account (PVBA) would record the difference between: (1) O&M expenses authorized by the Commission in the GRC proceeding; (2) actual O&M expenses billed to SCE by APS under the Palo Verde Operating Agreement for SCE's share of expenses, including refueling outage O&M expense and contractual overheads; and, (3) actual SCE oversight expenses.41 The balance in the PVBA will be carried forward from month-to-month throughout the year. SCE proposes to transfer the balance recorded in the PVBA annually to the generation subaccount in the base revenue requirement balancing account to be recovered from or returned to customers on an annual basis. SCE suggests that the Commission review the operation of the PVBA in SCE's April ERRA annual reasonableness proceedings.

We find this proposal reasonable. A balancing account will ensure that recorded Palo Verde O&M expenses are recovered from customers, no more and no less. This balancing account will address SCE's concern of not recovering actual costs as well as other parties' concerns of over-recovery. We have adopted similar balancing accounts under similar circumstances.42

2.2. Coal Generation

2.2.1. Four Corners Generating Station - Staffing Increase Costs-FERC Accounts 500-502, 505-507, and 510-514

Four Corners Generating Station (Four Corners) has five coal-fired units. SCE owns 48% of Units 4 & 5,43 each rated at 750 MW.44 APS is the operating agent for Four Corners. APS prepared a Long Range Forecast in 2007, which includes an estimate of 2009 expenses. SCE's forecast, which does not rely on the APS forecast, is $39.171 million (constant 2006$ and SCE share) for Four Corners TY 2009 O&M expenses.45

DRA recommends a reduction of $2.1 million to remove SCE's request for 50 additional employees at Four Corners. DRA asserts SCE's proposal to hire additional staff now to address retirements that may happen in 5-10 years is premature.

TURN recommends that the estimate for O&M expenses at Four Corners be based on the 2009 Long Range Forecast Budget prepared by APS. TURN explains that APS, as the plant operator, has the responsibility for managing and operating the Four Corners plant. Accordingly, TURN argues that the budget determined by APS is the most reasonable starting point for any forecast of future expenditures. Alternatively, TURN supports DRA's recommendation.

We agree with DRA. It is premature to include additional staff hiring to account for retirements that may happen in 5-10 years.

2.2.2. Mohave Generating Station-FERC Subaccounts 506.013 and 514.013

The Mohave Generating Station (Mohave) ceased operation on December 31, 2005.46 SCE and the other Mohave owners47 are currently proceeding with final disposition of the power plant equipment and the site, including physical decommissioning of the plant during the 2009-2011 GRC period.48 SCE forecasts $4 million ($2.2 million - constant 2006$ and SCE share) for Mohave O&M for TY 2009 to manage the Mohave site during and after decommissioning.49 This forecast is based on the expectation that Mohave will be decommissioned by 2011. SCE also proposes to continue the Mohave Balancing Account50 (MBA) for costs recorded through 2011, and possibly beyond. SCE included a 15% contingency in its Mohave O&M cost estimate, totaling $0.530 million in TY 2009 (100% share).

DRA does not object to continuing the MBA but would eliminate the 15% contingency. DRA asserts that a contingency is unnecessary as long as SCE has balancing account treatment. After removing the 15% contingency, DRA recommends a Mohave TY 2009 O&M expense of $3.5 million (100% share) or $2.0 million (SCE share), a difference from the SCE forecast of $0.2 million. SCE states that, given the difficulty of identifying what additional efforts might be needed, this contingency is appropriate and conforms to standard industry practice.51

We find continuation of the MBA reasonable for 2009-2011 but reject SCE's request to add a 15% contingency to account for cost uncertainties. Unlike cost forecasting for capital construction projects, an overall contingency is not normally included in O&M cost forecasts. As we found in D.06-05-016, the MBA will give sufficient protection against unknown costs and will continue to be subject to reasonableness review. Accordingly, we adopt a TY 2009 forecast of $2.0 million for Mohave O&M.

2.3. Hydroelectric Generation Forecasting Method - FERC Accounts 535-545

SCE's Hydroelectric (Hydro) Generation facilities are forecasted to provide an aggregate of 1,176 MW in TY 2009. SCE forecasts TY 2009 O&M expenses of $50.4 million (constant 2006$). SCE's O&M expense forecast for TY 2009 of $50.4 million is $12.1 million, or approximately one-third higher than the $38.3 million recorded O&M expenses in 2006.

SCE's forecasting methodology for its 2009 Hydro O&M forecast is composed of two parts, the "base estimate," as it is referred to by SCE, and the increases to this base estimate, referred to as "future adjustments." SCE develops its "base estimate" by using its 2002-2006 recorded expenses adjusted to remove one-time charges and to correct accounting errors. SCE then makes 11 future adjustments to include additional costs to this base estimate. These additional amounts total $13.504 million. DRA, TURN, and Inland Aquaculture Group, LLC (IAG) offer lower forecasts by relying on different forecasting methods or by finding certain expenses unreasonable.

DRA recommends a TY 2009 forecast of $36.8 million, which is SCE's estimate of 2007 expenses, a reduction of $13.6 million to SCE's forecast. DRA asserts SCE's 2007 estimate of Hydro O&M expenses serves as an appropriate basis for the TY 2009 forecast because Hydro O&M expenses have been relatively stable. DRA also presents arguments in opposition to two specific future adjustments identified by SCE, hydro staffing and cloud-seeding activities, that total $2.45 million.

TURN recommends reducing SCE's Hydro O&M forecast by $3.46 million because of lower 2006 base year expenses recorded in the relevant FERC Accounts, the closure of the San Gorgonio hydro project, reductions in labor cost estimates for SCE's proposed new staff, reductions in housing rehabilitation and asbestos abatement expenses, and the capitalization, instead of expensing, of housing rehabilitation and the Agnew Tramway.52

IAG also recommends reducing SCE's Hydro O&M forecast. IAG proposes a reduction of $70,000 for the Rush Creek Heliport brush clearing forecast for 2010 and removal of all amounts included for this project in 2009 and 2011. IAG also proposes an annual reduction of $230,000 in 2009, 2010, and 2011 for vegetation management at Big Creek. IAG recommends a reduction of $56,000 for refurbishment of the Poole 3-unit apartment building and a reduction of $66,000 for asbestos abatement at the Poole and Rush Creek projects. IAG recommends disallowing the $2.4 million included in SCE's 2007-2011 capital forecast for the Lundy Reline Conveyance System and requests the Commission order no further action on this item unless SCE obtains FERC approval. Lastly, IAG alleges that SCE committed a Rule 1.1. ethical violation regarding the Lundy Reline Conveyance System by misrepresenting the status of FERC approval.

We find SCE's methodology generally reasonable for determining its TY 2009 forecast for Hydro O&M. However, in response to concerns raised by TURN, DRA, and IAG, we find that the results of SCE's forecasting methodology require minor adjustments. We discuss these adjustments below. We also address the reasonableness of the actual forecasted amount requested, $50.4 million, and the recommendations by DRA, TURN, and IAG to reduce this forecast.

2.3.1. Operations of Reservoirs, Dams and Waterways - FERC Account 537

FERC Account 537 Hydraulic Expenses contains three functional subaccounts. One of these subaccounts is referred to as Operations of Reservoirs, Dams and Waterways. To forecast the TY 2009 expenses for this subaccount, SCE uses expenses from the last recorded year 2006 for non-labor costs, $969,000 (constant 2006$). TURN recommends that SCE's TY 2009 forecast be reduced by $169,000 to reflect a base year adjustment to this subaccount.53 Specifically, TURN claims a five-year average forecasting methodology is appropriate because non-labor costs in this specific area have fluctuated significantly, mainly due to weather-related events, with no discernable trend over the past five years. TURN acknowledges SCE appropriately forecasted the remainder of the account based on last recorded year. The following table illustrates the non-labor fluctuations in the subaccount.

Year

Operation of Reservoirs, Dams and Waterways, Non-Labor Costs

2002

$735,000

2003

$600,000

2004

$1,073,000

2005

$624,000

2006

$969,000

 

 

5-year average

$800,200

TURN points out that the five-year average of these non-labor costs is approximately $800,000, a reduction of $169,000 to SCE's TY 2009 base estimate. SCE argues it is inappropriate to utilize a portion of a subaccount to derive an expense reduction.

We adopt TURN's $169,000 reduction in SCE's TY 2009 base estimate for Account 537. Costs that fluctuate based on weather are better forecasted on a historical average basis, rather than last recorded year. Accordingly, it is reasonable to forecast these subaccount costs by estimating them separately, as TURN recommends.

2.3.2. Cloud Seeding - FERC Account 536

SCE's testimony includes $250,000 (constant 2006$) for cloud seeding efficiency improvements. SCE proposes to add this amount to its TY 2009 Hydro base estimate. DRA recommends complete disallowance of this amount based on the lack of scientific agreement on the results of cloud seeding. TURN generally agrees that no consensus exists on this topic in the scientific community but does not dispute the additional amount requested by SCE. We find SCE's request reasonable. However, because the efficacy of cloud seeding is unknown, we direct SCE to provide the Commission additional information regarding this process in SCE's next GRC application, including the policy position of the California Energy Commission.

2.3.3. San Gorgonio Hydro Project - FERC Accounts 536, 537, 538, 540, 542, 543, 544

San Gorgonio is a small hydro project that has not operated since an accident in 1998 destroyed its water tanks. SCE proposes $7 million in capital expenditures to decommission San Gorgonio in 2009. This capital request will be addressed in a separate section of this decision. SCE also requests the TY 2009 O&M forecast include $181,000 (SCE's recorded 2006 expenses and the highest year recorded for 2002-2006) for this project.

Based on SCE's plan to decommission the facility in 2009 and SCE's assertion that it is contractually obligated to perform ongoing O&M until the ownership transfer to Banning Heights Mutual Water Company in 2010, TURN recommends reducing the TY 2009 forecast to protect ratepayers from paying for O&M in 2010 and 2011, at which point the plant will be decommissioned. To normalize SCE's projected 2009 expense of $181,000 over three years, TURN proposes to reduce $181,000 by two-thirds ($120,000) and leave the remaining amount of $61,000 in the TY 2009 forecast.

SCE claims that O&M expenses will be incurred into the foreseeable future and offers an alternative TY 2009 forecast of $123,000, which represents the average recorded O&M expenses for 2002-2006. Because SCE states it will incur O&M into the foreseeable future, we find SCE's alternative proposal reasonable and reduce SCE's TY 2009 Hydro base estimate forecast accordingly. However, we expect this amount to be removed from SCE's next O&M forecast.

2.3.4. Future Adjustment No. 1 Hydro Staffing Increases - FERC Accounts 537, 538, 539, 543, 544, 545

As shown below, SCE's TY 2009 forecast includes a total of 252 active full-time hydro employees by the end of 2009.

Future Adjustments54
Hydro Generation Operation And Maintenance Expense

(Constant 2006 $)

In the 2006 GRC, SCE requested 209 active full-time employees. SCE is seeking an increase of 43 over the 2006 base year. As of January 1, 2007, SCE had 197 hydro employees. To achieve SCE's proposed increase, SCE forecasts the need for an additional $4.3 million (constant 2006$). This additional $4.3 million would be a future adjustment to SCE's TY 2009 base estimate. SCE submits this increase is needed to replace the anticipated wave of baby-boomer retirements and to meet increased work load resulting from both increased regulatory requirements and recently issued FERC licenses as well as licenses expected to be issued in the near future.

DRA recommends the Commission reject SCE's request for an additional $4.3 million and, instead, adopt the estimated 2007 amounts for TY 2009. DRA claims no additional amount is appropriate because the proposed additional staff will perform work unrelated to hydro matters and SCE's proposal to start hiring to replace retirements is premature.

We agree, in part, with DRA. SCE is requesting 23 additional positions (22 apprentices and 1 training position) to prepare for retirements. SCE has failed to adequately explain how retirements will impact the requested additions to the workforce. Accordingly, in the absence of sufficient information from SCE, we reduce SCE's requested amount by 50% as follows: SCE's request for 22 apprentices is reduced to 11 apprentices and SCE's request for a training instructor is eliminated. We discuss our rationale for eliminating the training instructor ($131,000)55 below in response to TURN's recommendations. After these reductions, we find an additional 11 apprentice positions reasonable to accommodate SCE's preparations for retirements. We make no reductions to the number of positions requested by SCE to accommodate increased work associated with FERC relicensing and refurbishment of hydro infrastructure.

While TURN is not convinced that SCE's proposal to hire an additional 43 employees is reasonable, TURN focuses on reducing the salary amount requested by SCE for the additional positions. TURN recommends a total increase of $3,886,000 for these 43 employees, $237,000 less than SCE's request, to reflect the actual wages of the proposed new positions rather than SCE's recommendation to use the average wage of all hydro staff. TURN also recommends removing expenses related to training staff on the basis that training is included in SCE's wage calculation.56

We find both of TURN's recommended adjustments reasonable. We adopt these adjustments as applied to the total number of increased hydro positions and find reasonable 11 apprentice positions to address future retirements and 20 positions to address increased work load.

2.3.5. Future Adjustment Nos. 4 & 7 Housing & Asbestos Abatement Project - Poole and Rush Creek - FERC Account 542

SCE's TY 2009 base estimate for FERC Account 542 is $1.21 million (constant 2006$). The average future adjustment for 2009-2011 is $1.76 million (constant 2006$). The base estimate and the average future adjustment results in a TY 2009 forecast of $2.97 million. SCE's future adjustments to FERC Account 542, including future adjustments nos. 4 and 7, reflect housing rehabilitation averaging $544,900 per year and asbestos removal averaging $1.218 million per year.

TURN suggests $374,000 of these future adjustment expenses are unreasonable and should be removed from SCE's forecast. TURN further recommends the remaining $1.389 million be capitalized instead of expensed.57 These recommendations would result in a reduction to SCE's total O&M expense for hydro housing and building rehabilitation of $1.763 million, essentially eliminating SCE's two future O&M adjustments. All of these estimates exclude labor costs. Labor expenses associated with these future adjustments are addressed elsewhere in SCE's showing.58 IAG and TURN also point out that SCE requested $387,000 in its 2006 GRC to demolish housing units at remotely operated power plants at Poole and Rush Creek because, according to SCE, demolition was required by FERC.59 In this case, SCE seeks to spend $371,000 to rehabilitate these same housing units at Poole and Rush Creek -- $161,500 for housing rehabilitation at Poole, $98,300 for asbestos removal at Poole, and $112,000 for asbestos removal at four Rush Creek houses.60 In response, SCE explains it intended to demolish this housing but reevaluated this plan when it became clear that, due to the severe lack of affordable housing for existing and new hydro personnel, SCE should instead refurbish the housing.

We agree with TURN and IAG that ratepayers, having funded the proposed demolition of these housing units in SCE's 2006 GRC, should not now have to fund their rehabilitation. We therefore reject as unreasonable $374,000 from SCE's future adjustment nos. 4 and 7. Accordingly, based on the information provided by TURN, we adopt TURN's recommendation that $374,000 in unreasonable expenses be removed from SCE's future adjustments reflected in FERC Account 542. We also find reasonable TURN's recommendation to capitalize the remaining $1.389 million61 rather than expense it.62 These changes result in an average reduction to SCE's total O&M expense for hydro housing and building rehabilitation of $1.763 million,63 an amount equal to the total of SCE's requested future adjustment nos. 4 & 7 to Account 542.

2.3.6. Alleged Discrepancies on Hydro Projects

IAG requests the Commission order SCE to file an explanation of certain alleged discrepancies in amounts requested for various projects.64 SCE adequately responded to IAG's concerns.65 While we do not always find SCE's forecasted costs reasonable, we find IAG fails to establish conduct by SCE of sufficient concern to warrant further action under Investigation (I.) 08-01-029.

2.3.7. Alleged Rule 1.1. Violation

IAG requests the Commission find SCE in violation of Rule 1.1. Rule 1.1. provides, in part as follows:

"Any person who signs a pleading or brief, enters an appearance, offers testimony at a hearing, or transacts business with the Commission. . . agrees. . . never to mislead the Commission or its staff by an artifice or false statement of fact or law."

IAG claims SCE mislead the Commission to believe FERC directed SCE to complete the Lundy Project with this statement: "The project benefit and justification is to comply with a FERC relicensing requirement." In fact, SCE was acting in compliance with a private settlement, referred to as the Lundy Hydroelectric Project Settlement Agreement, dated February 3, 2005.66 In response, SCE claims IAG uses an overly narrow definition of the phrase "FERC relicensing requirement."67 SCE further explains that "SCE views the Lundy Project and Settlement, which was entered into as part of obtaining a new FERC license, as a FERC relicensing requirement, regardless of whether it was specifically ordered by FERC or not. SCE has never stated that the Lundy project was an order of the FERC license."68

We find IAG's request fails to establish a prima facie case of a Rule 1.1. violation. Although SCE's initial statements are cursory on this matter, SCE's explanation in its rebuttal testimony is reasonable and sufficiently clarifies the extent of the involvement of FERC. Based on the existing evidence, no further action will be taken with respect to this matter.

2.3.8. Future Adjustment No. 8 - Hydro Vegetation Management Expenses - FERC Account 539

SCE's TY 2009 base estimate for FERC Account 539 is $13.2 million (constant 2006$). This represents an increase from its recorded 2006 expenses of $9,206,450 (constant 2006$). By future adjustment no. 8, SCE proposes an average increase to its base estimate of $430,000 per year (2009 through 2011) for maintenance, inspection, and repair of its helicopter operations. IAG proposes certain reductions to SCE's forecast related to brush clearing. Specifically, IAG requests a reduction of $23,333 for the Rush Creek Heliport Brush Clearing and $230,000 for Big Creek Vegetation Management, for a total reduction of $253,333 to SCE's TY 2009 forecast. In response, SCE explains that the project recorded in FERC Account 539 will involve more than brush clearing. The helicopter landing site must be moved and a new heliport site constructed, which requires that vegetation be removed and the site graded and covered with rock. Based on the information provided by SCE, the amount requested is reasonable.

2.4. Gas-Fired Generation

2.4.1. Mountainview O&M Expenses

Consistent with D.03-12-059, D.04-03-037 and D.04-04-019, SCE acquired Mountainview Power Company, LLC (MVL) as a wholly-owned SCE subsidiary and executed a Power Purchase Agreement (PPA) for cost recovery with MVL for electricity from MVL's Mountainview Generating Station (Mountainview).69 In this proceeding, SCE asks the Commission for permission to include Mountainview in rate base and allow recovery of Mountainview's operating costs through its TY 2009 forecast. In addition, Mountainview's capital costs would no longer be recovered as purchased power costs, through the operation of the ERRA, but would instead be recovered in SCE's authorized base generation revenue requirement and through rates. The fuel costs and availability and heat rate incentive payments will still be recovered through the annual operation of the ERRA balancing account process. SCE states if the Commission does not approve of its request now, it will not terminate the PPA and, instead, continue to recover its Mountainview operating costs through the FERC-jurisdictional PPA.70 SCE's TY 2009 forecast for Mountainview O&M is $42.505 million (constant 2006$). SCE made future adjustments totaling $13.779 million to 2006 recorded costs to compute its TY 2009 forecast.

In response to SCE's request to operate Mountainview as a utility-owned generation facility, DRA raises various concerns related to SCE's proposed cost recovery, not to the transfer of ownership. TURN's recommendations for Mountainview are related to SCE's request for peaker O&M and related capital and will be addressed in a separate section of this decision.

DRA recommends $41.5 million in O&M expenses for TY 2009 for Mountainview. DRA reduces SCE's TY 2009 forecast by $1 million to remove $0.454 million for additional staff and $0.5 million for "Additional Future Projects (Unforeseen)."71 According to DRA, the Commission should not increase funding in TY 2009 for retirements that may occur over "the next several years" and for Additional Future Projects (Unforeseen) that in DRA's view are an unsupported contingency.

SCE defends the cost of seven additional employees, all of whom SCE hired in 2008, to address increased workload at Mountainview. Regarding the amounts forecasted in Additional Future Projects (Unforeseen), SCE says the funding is needed for projects to address areas of concern that have arisen since mid-2007 and would be reflected in recorded cost history if Mountainview were an older plant.72

We find that SCE has adequately explained and justified the additional employees and the Additional Future Projects (unforeseen) O&M projects. Thus, we find SCE's TY 2009 O&M forecast for Mountainview reasonable. However, we do not anticipate approving any amounts for Additional Future Projects (Unforeseen) in SCE's next GRC because historical data should reflect these expenses. In addition, we approve the transfer of ownership. While the Commission in D.03-12-059 found "... that unless Edison decides to purchase Mountainview as utility owned generation, a CPCN is not necessary,"73 we addressed all necessary CPCN and CEQA matters in A.03-07-032. When finalized, this transfer will place Mountainview under Commission-jurisdictional ratemaking. However, this change in ratemaking cannot occur until FERC issues a decision approving termination of the existing power purchase agreement.

2.4.2. Peaker O&M - FERC Accounts 546, 548, 549, 551, 553, 554

SCE proposes O&M expenses of $9.7 million in TY 2009 to operate its five new peakers (constant 2006$).74 The TY 2009 forecast includes $3.214 million for labor expense. In total, SCE's TY 2009 forecast for non-labor costs, which includes contract labor, materials, and supplies, is $6.488 million. No history of recorded plant O&M costs exists for these peakers. Therefore, SCE's estimate of O&M expenses uses a "zero-based budget."75 Only four of the five new peakers are commercially operational, as of September 17, 2007. Construction of the fifth peaker, located at McGrath Beach in the City of Oxnard, has been delayed due to permitting issues. During the course of the proceeding, SCE was unable to provide a date certain for operation of the fifth peaker. At the beginning of the proceeding, SCE explained, "It is very difficult to forecast when permit approval will be received"76 but SCE anticipates the fifth peaker will be operational by the end of 2008. Later, at hearings in June 2008, SCE informed the Commission that the commercial operational date for the fifth peaker is still unclear.77 In SCE's September 4, 2008 update testimony,78 SCE suggested that "operation of the fifth peaker could begin as early as August 2009,"79 At this point, SCE updated its testimony to reflect a 15% reduction in its forecasted peaker O&M up until August 2009, the date SCE hopes the fifth peaker will be operational. SCE's revised request is addressed below. We also address DRA's and TURN's concerns about construction delay, staffing, and the use of a one-way balancing account.

2.4.3. One-Way Balancing Account for Peaker O&M

Due to the uncertainties as to when the fifth peaker will be operational, DRA recommends a one-way balancing account for all peaker O&M. Under DRA's proposal, if the spending target determined by the Commission is not met, the unspent funds are returned to the ratepayers but, if expenditures exceed the target, the amount over the target is not recoverable through rates. In response, SCE explains its TY 2009 O&M forecast assumes operation of all five peaker units and, as a result, SCE has not estimated an appropriate reduction to the peaker TY 2009 O&M forecast if only four units operate during 2009, rather than five units. Although SCE did not forecast O&M for each individual peaker, it claims in direct testimony that its peaker O&M forecast for TY 2009 for the fifth peaker is less than 20% and possibly even less than 10% of its forecast total. Accordingly, SCE argues that placing all O&M in a one-way balancing account is unreasonable.

Instead, SCE suggests if any uncertainty remains regarding the fifth peaker later this year, the Commission can adequately address the uncertainty in its final decision in this proceeding. Should the fifth peaker not be operational by the date the Commission authorizes SCE's 2009 GRC revenue requirement, SCE suggests the Commission rely on the existing Peakers Generation Memorandum Account (PGMA).80 SCE proposes to modify the existing PGMA to record the difference between the 2009 authorized peaker revenue requirement (i.e., O&M and capital revenue requirement) and the actual recorded peaker revenue requirement. SCE also proposes to record both over-collections and under-collections in the modified PGMA. In update testimony, SCE did not address the merits of a one-way balancing account.

Based on SCE's claim that O&M associated with the fifth peaker is a small percentage of the overall peaker forecasts, we reject DRA's proposal to track all peaker O&M in a one-way balancing account. We also reject SCE's proposal to rely on the PGMA because SCE does not address treatment of overcollections. Finally, we reject SCE's most recent recommendation, to reduce the O&M forecast by 15% until August 2009, because SCE has not shown the permit process is moving forward on a reliable timeline. Instead, based on the existing evidence and the lack of a firm date for the issuance of permits, we reduce SCE's forecast by 10%, an amount equal to SCE's best estimate of the costs associated with the operation of the fifth peaker.

2.4.4. Integration with Mountainview-Staffing & Information Technology - FERC Accounts 546, 548, 549, 551-554

DRA recommends reducing peaker O&M expenses by a total of $81,000 (constant 2006$). DRA would reduce the employee count to reflect integrated SCE operations with Mountainview and would reduce IT costs to reflect one-time expenses. TURN also claims SCE's failure to integrate the operating systems of the new peakers with Mountainview results in unreasonable labor costs. As a result, TURN would reduce peaker O&M expenses by $536,000.

We reject DRA's and TURN's recommendations on employee count. From the information provided by SCE regarding the projected workloads to operate the two control systems, it is not clear that integrating the operating systems of Mountainview and the peakers would be efficient. However, we agree that SCE should continue to explore ways to increase cross-support between the staffs of the peakers and Mountainview.

2.4.5. Information Technology Equipment Purchases-One Time Expenses - FERC Account 549

SCE forecasts $800,000 (constant 2006$) of IT costs for TY 2009 for the new peakers. SCE's forecast includes a one-time $400,000 O&M project for additional plant instrumentation and data collection hardware and software. TURN and DRA recommend reducing SCE's O&M forecast for the peaker units by $267,000 to average one-time expenses across the rate case cycle. They would include only one-third of this project ($133,000) in SCE's TY 2009 forecast for FERC Account 549.

SCE concedes it "has not identified additional specific one-time O&M projects beyond 2009."81 But it argues that because the peakers are very new plants, the Commission should assume that "similar one-time O&M projects will arise in 2010 and 2011 and authorize SCE to recover the full $400,000 amount in 2009."82 As support for this request, SCE offers that its "power plant operating experience is that such one-time O&M projects are likely to arise in 2010 and 2011."83 Yet SCE apparently cannot predict whether those additional costs would even be related to computer systems, as it refers generally to one-time O&M projects.

We reject SCE's request for a contingency for unknown costs that might possibly occur. SCE has failed to demonstrate the reasonableness of collecting $400,000 each year in the rate case cycle for what it acknowledges are one-time IT costs in 2009. Instead, we adopt TURN's and DRA's proposal to normalize SCE's proposed one-time IT costs over the rate case cycle and remove $267,000 from Account 549.

2.5. Solar Two Decommissioning Project

SCE requests recovery of $4.6 million in capital expenditures for its one-third share of the Solar Two decommissioning project. SCE relied upon a 1999 estimate to forecast costs for this proceeding. This 1999 estimate was prepared for the Department of Energy and found the cost to decommission the site to be $5.7 million (100%). SCE then escalated to 2009 this 1999 estimate and arrived at $7.660 million, of which SCE's share is $4.639 million.84 No party opposes SCE's request. DRA, however, proposes to limit SCE's cost recovery to $4.6 million,85 asserting that SCE included contractor profit and overhead and a contingency in its 1999 cost estimate and, therefore, the Commission should cap that estimate. 86 DRA explains that a cost cap will make SCE accountable for its decommissioning cost estimate. Based on SCE's decision to rely on 1999 cost data for this estimate rather than more recent data, we assume SCE is confident in the accuracy of the results of its analysis. Accordingly, we find a cost cap reasonable and adopt DRA's recommendation.

2.6. Project Development Division-Request to Include RD&D - FERC Accounts 506 and 549

SCE's forecast for TY 2009 O&M for its Project Development Division (PDD) is $26.4 million (constant 2006$). This request consists of $5,012,000 to continue the PDD activities authorized for rate recovery in the 2006 GRC87 and $21,572,000 to begin generation-related technology demonstration, testing, and evaluation and to fund the incremental staffing required to conduct that work. This $21,572,000 will fund an expansion of the existing responsibilities of the PDD to include what SCE describes as research, development, and demonstration (RD&D). SCE also asks the Commission to permit the entire forecasted amount, including its RD&D, to be recovered through traditional ratemaking, rather than continued use of the PDD Memorandum Account (PDDMA).

DRA and the Western Power Trading Forum (WPTF) oppose SCE's request for RD&D funding. WPTF asserts that the RD&D funding by ratepayers, as requested by SCE, will subsidize utility generation project development and, as a result, is anticompetitive. WPTF also opposes SCE's request to eliminate the memorandum account because, among other reasons, traditional rate recovery will undercut the Commission directive in D.07-12-052 that IOUs are not permitted to recoup from ratepayers any bid development costs associated with losing bids in competitive Request for Offers. DRA asserts that utilities should not use ratepayer funds to invest in RD&D because generation manufacturers, venture capital, developers, and governmental agencies are better suited for such activities. DRA suggests no RD&D funding be approved in the TY 2009 forecast and, instead, the Commission should maintain the memorandum account with a $3 million per year cap.

In D.06-05-016, the Commission approved SCE's request for cost recovery for certain so-called "support" functions associated with SCE's proposed PDD. These "support functions" included the following: (1) analyze generation technologies and costs; (2) locate appropriate sites for potential generation development; (3) monitor and participate in generation-related regulatory and legislative activity; and (4) develop and maintain the best option outside negotiation (BOON) for relevant generation technologies.88

The Commission, however, rejected SCE's request to include in rates efforts by the PDD to engage in activities such as "develop and implement plans to advance projects from the development phase to the construction and operations phase." The Commission found such activities to be "development" costs and concluded that "Independent producers' development costs associated with unsuccessful projects are not recoverable from ratepayers. It is a matter of fairness that SCE assume that same risk, if it chooses to participate."89 In addition, because the Commission had concerns regarding the potential for anti-competitive impacts of funding the "support functions" of the PDD, the Commission required SCE to track all expenses of its PDD in a memorandum account and limited cost recovery to "support" functions.

Currently, RD&D is not a part of the PDD's "support" functions approved by the Commission. However, in this proceeding SCE claims a need for generation-related RD&D.90 SCE states this need will include a limited amount of generation primary research which would be a minor sub-set of the money requested, but the vast majority of the requested $20 million per year would be used to demonstrate generation-related technologies in general and renewable generation technologies in particular. Specifically, SCE proposes to partner, as appropriate, with technology developers, the California Energy Commission (CEC), the U.S. Department of Energy (DOE), Electric Power Research Institute (EPRI), and others on RD&D related to technologies specifically targeted to generation, generation deployment, and related energy storage.

In D.06-05-016, the Commission adopted the PDDMA, a memorandum account to enable SCE to exclude project development costs for specific projects from this 2009 GRC request.91 SCE has done so but has added $20 million per year to its TY 2009 forecast for RD&D. For the same reasons as set forth in D.06-05-016, we reject SCE's $20 million request for cost recovery of RD&D. In D.06-05-016, the Commission expressed concerns regarding the potential to create an uneven playing field for competitors. The Commission stated, "...from a policy perspective, we feel it is important that the project development costs for proposed new projects should not be specifically included in rates."92 These same concerns continue to exist. To address these concerns, the Commission excluded SCE's entire PDD request from rates. The Commission allowed rate recovery after review in an ERRA proceeding through a memorandum account of costs that generally support new generation but not those costs associated with actual proposed projects. The Commission directed SCE to track such supportive project development costs in a memorandum account and stated that "Such costs can then be recovered in future rates to the extent that they are incurred, to the extent that SCE can justify their supportive nature, and to the extent that the total recorded PDD costs do not exceed SCE's forecasted amount."

We agree with DRA and WPTF, and we affirm the procedures and restrictions adopted in D.06-05-016. Under those procedures and restrictions, we stated that, if SCE chooses to do so, it may identify appropriate "support" costs and include the forecast of such costs in its TY 2009 forecast. According to SCE, that amount is $5,012,000. We will continue to rely on the PDDMA and will not include any "support" costs in the forecast. We will not permit rate recovery for any additional functions of the PDD beyond those approved in D.06-05-016.

2.7. Pebbly Beach Generation Station-Catalina Island Forecasting Method - FERC Accounts 548, 549, 553

SCE's TY 2009 forecast for Pebbly Beach Generation Station93 O&M expense is $5.38 million (constant 2006$). SCE considered the activities contained in each FERC Account, then separately decided on a forecast for labor and non-labor expenses.94 In support of its forecasting methodology, SCE states each FERC Account is unique and SCE could not apply the same forecast method to all FERC accounts. For example, SCE used 2006 recorded expenses to forecast labor in Account 548. SCE anticipates that the staffing will remain constant at 2006 levels in TY 2009.95 For Account 553, SCE used a 3-year average of 2003-2006 expenses to forecast labor because SCE found this method to accurately reflect current and future staffing levels. DRA disagrees with SCE's forecast methodology for the O&M recorded to these FERC Accounts. DRA's proposal includes a $739,000 reduction to SCE's forecast. We have reviewed SCE's request and find SCE's forecast methodology is appropriate in this instance. Accordingly, we find SCE's TY 2009 forecast for Pebbly Beach Generation Station O&M expense of $5.38 million reasonable.

3. Transmission & Distribution Expenses - FERC Accounts 560-573 Transmission Expenses; FERC Accounts 580-598 Distribution Expenses

SCE requests $619.334 million (constant 2006$)96 for TY 2009 Transmission and Distribution (T&D) O&M expenses.97 SCE's 2006 recorded expenses are $493.322 million. DRA recommends the Commission adopt T&D O&M expenses of no more than $428.9 million.98 TURN and other parties also recommend reductions to SCE's forecast. Our analysis and findings follow.99

3.1. Operations Supervision and Engineering - FERC Account 560

SCE's TY 2009 forecast for its Operation Supervision and Engineering expenses recorded to FERC Account 560 is $16.701 million (constant 2006$).100 DRA's estimate is $14.239 million.101 SCE's FERC Account 560 includes three subaccounts: 560.100 Operations Engineering; 560.200 Transmission Systems Operations Supervision; and 560.980 Allocated Division Overhead-Transmission Operation.102 No disputes exist regarding subaccount 560.200. We address SCE's forecasts for subaccounts 560.100 and 560.980 below.

3.1.1. Operations Engineering - FERC Subaccount 560.100

SCE forecasts $8.211 million (constant 2006$) for TY 2009 expenses for subaccount 560.100. SCE's forecast includes increases over 2006 recorded costs in the following areas: (1) Engineering Advancement Projects; (2) Project Management Organization Work Order Write-Offs; (3) Standards and Publications; (4) Reallocation of Overhead; (5) Engineering Staff; and (6) Engineer's Desktop Software Upgrades. DRA recommends the Commission reject almost all of the increases requested by SCE.103 These recommendations are discussed below.

3.1.1.1. Engineering Advancement

SCE requests an increase in funding over the 2006 base year for Engineering Advancement as follows: (1) $2.094 million (constant 2006$) for subaccount 560.100 (transmission) and (2) $2.140 million (constant 2006$) for subaccount 580.100 (distribution).104 SCE explains that the additional funding for subaccount 560.100 will support SCE's efforts to develop and deploy "smart" technologies on the electric grid and that these technologies, when combined with advanced communications and practices, will comprise what is commonly referred to as the "Smart Grid."105 According to SCE, it uses the soundest possible basis for estimating costs, and SCE cannot reach the next level of specificity in estimating these cost projections until it has actual bids in hand and personnel actually doing the work.106 Thus, these increased costs simply cannot be developed with more specificity until 2009 and beyond.107

DRA would deny the requested increase in funding, arguing that there is inadequate information to support the need for additional funding and inadequate demonstration of the benefits to customers. The California Farm Bureau Federation (CFBF) agrees.108

SCE is requesting a significant increase. Without further data and based on the level of detail provided by SCE, we can not approve the full request. We find reasonable 50% of SCE's requested increase for Engineering Advancement in subaccount 560.100.

3.1.1.2. Additional Engineering Staff

SCE requests $285,000 (constant 2006$) to add three civil engineers to handle apparatus design review and substation automation. DRA asserts SCE's workload can be addressed by its current staffing.109 DRA presents customer and load growth forecasts for 2009 that are lower than 2006 levels. SCE claims, and its evidence shows, the increase in staffing is necessary whether or not SCE experiences customer growth in the test year.110 SCE explains that new positions are needed for work related to improvements and expansions to the transmission system and continued expansion of the substation automation system and are necessary to address design issues posed by SCE's transmission and substation systems as they currently exist. We find SCE's request reasonable as the additional staff will address new recently emerging issues not currently addressed in historical costs.

3.1.1.3. Standards and Publications Contract Group

DRA rejects SCE's proposed credit adjustment of $616,000 to reflect the elimination of certain contract resources from SCE's Standards and Publications Contract group. Instead of contract resources, SCE is proposing to rely partially on additional personnel, as reflected by the increase of $285,000 for additional employees, discussed above.111 Based on the evidence presented and our finding above that SCE's proposal for additional staffing is reasonable, we find SCE's reduction in contract resources reasonable.

3.1.1.4. Reallocation of Overhead

SCE requests a decrease of $1,145,000 (constant 2006$) as a result of a shift of $1,145,000 from O&M to capital. DRA objects to SCE's request.112 SCE explains this adjustment was a result of an analysis it conducted in 2006 of the cost recording practices for clearing accounts. SCE's analysis showed the need to make changes in the way costs were recorded for several accounts. As a result, SCE incorporated into this GRC these changes in its cost recording practice. The changes are shown in the relevant O&M accounts as an adjustment for overhead allocation. SCE explains that the adjustments must be made to accurately reflect the costs that will be recorded on an ongoing basis. SCE claims this modification is solely an accounting adjustment113 and follows the FERC accounting guideline. We agree and find SCE's request to modify its accounting practices reasonable.

3.1.1.5. Desktop Software Upgrade

SCE requested $500,000 (constant 2006$) to upgrade desktop software.114 DRA recommends the Commission normalize this increase, proposing one-third of SCE's request be included in the TY 2009 forecast. DRA justifies the normalization "[b]ased on the fact that SCE has embedded costs for software upgrades in its historical expenses...."115 SCE has established there were no software upgrades in 2006, so there are no upgrade costs embedded in 2006 recorded expenses.116 SCE provided detailed documentation of the upgrades it needs in 2009, 2010 and 2011, establishing that the upgrade costs are not TY 2009 one-time expenses.117 We find SCE's request reasonable.

3.1.1.6. Project Management Organization Work Order Write-Offs

SCE requests a $333,000 (constant 2006$) increase for write-offs of work orders in its Project Management Organization.118 DRA opposes SCE's request, arguing that the recorded 2006 expenses for Project Management Organization write-offs is the high point of the historical period and SCE has not shown that "2006 recorded expenses are insufficient" to meet test year needs.119 SCE explains that Project Management Organization write-offs vary with the level of Project Management Organization-related capital expenditures. The evidence supports SCE's analysis. DRA has incorrectly connected these expenses to customer growth. As explained in a separate section of this decision, we reduce SCE's request for capital spending by $549.4 million. Accordingly, based on the relationship between capital spending and Project Management Organization write-offs, we find it reasonable to reduce SCE's requested increase in Project Management Organization work order write-offs by 14.56%.

3.2. Allocated Division Overhead to Clearing Accounts - FERC Subaccounts 560.980, 568.980, 580.980, and 590.980

SCE's TY 2009 forecast for subaccount 560.980 is $7.125 million (constant 2006$).120 SCE's 2006 recorded expenses for this subaccount are $6.285 million. DRA recommends a TY forecast of $5.933 million. SCE's TY 2009 forecast for subaccount 568.980 is $4.701 million. SCE's 2006 recorded expenses for this subaccount are $3.985 million. DRA recommends $3.869 million. SCE's TY 2009 forecast for subaccount 580.980 is $22.432 million. SCE's 2006 recorded expenses for this subaccount are $20.009 million. DRA recommends $19.360 million. SCE's TY 2009 forecast for subaccount 590.980 is $16.115 million. SCE's 2006 recorded expenses for this subaccount are $13.569 million. DRA recommends $13.263 million.

Because we are authorizing less of an overall increase than requested by SCE, the increase in clearing account activity should be less as well. In response to concerns expressed by the Commission in the 2006 GRC decision regarding the absence of a proposal by SCE to account for any adjustments in clearing account activity when related O&M or capital costs are adjusted,121 SCE offers an approach by which reductions to O&M are applied to the associated clearing accounts as a ratio.122 SCE proposes specific ratios for each FERC account. SCE, explaining that its suggested approach attempts to apply the overall reductions to O&M to the associated clearing accounts as a ratio, states: "For example, the requested increase in sub-account 560.980 is $1.192 million. This increase supports Transmission operations activities recording to accounts 560 through 567, which cumulatively forecast an increase of $32.669 million. The ratio of 1.192 divided by 32.669 is 3.6%. Therefore, if SCE's requested increase in 560 through 567 were reduced by $1,000.00, SCE would accept a reduction to 560.980 of $36.00."123 SCE presents its recommended ratios in the table reproduced below.

High Level Ratios of

Clearing Accounts to Accounts Supported124

FERC Accounts

Increase from '06 - '09
(Constant 2006 $000)

Support Ratio

 

 

 

Transmission Operations

 

 

560 through 567

$ 32,669

 

560.980

$ 1,192

3.6%

 

 

 

Transmission Maintenance

 

 

568 through 573

$ 16,707

 

568.980

$ 832

5.0%

 

 

 

Distribution Operations

 

 

580 through 589

$ 43,491

 

580.980

$ 3,072

7.1%

 

 

 

Distribution Maintenance

 

 

590 through 598

$ 24,422

 

590.980

$ 2,848

11.7%

     

SCE's analysis is flawed as it fails to explain the relationship between SCE's requested increases in the clearing account to the related total forecasted amount in a corresponding O&M account. We find that the record in the proceeding does not include a reasonable explanation of the relationship between the clearing account activity and O&M and capital costs. However, we will reduce SCE's requested increase in each of the above XXX.980 accounts by 40%125 to reflect an approximation of the reduction in these clearing account expenses due to reductions in SCE's request for T&D expenses in this decision.

3.3. Transmission Station Expenses - FERC Account 562

SCE's forecast for TY 2009 O&M for Account 562 is $16.287 million (constant 2006$). The 2006 recorded amount for this account is $14.712 million. DRA recommends certain reductions to SCE's forecast in subaccount 562.100 for Vehicle Costs and Grid Operations and in subaccount 562.200 for Vehicle Costs. Vehicle Costs are addressed in a separate section of this decision. Grid Operations are discussed below.

SCE forecasts $12.301 million for subaccount 562.100, which is an increase of $891,000 over 2006 recorded expenses.126 FERC subaccount 562.100 records the cost of labor, materials, and other expenses to operate transmission substations and switching centers. This proposed increase is made up of $396,000 for 20 additional substation operators and $495,000 for Vehicle Costs.127 DRA recommends that the Commission adopt expenses in the amount of SCE's 2006 recorded expenses, $11.410 million, for TY 2009.128 DRA and CFBF assert that the 20 additional substation operators can be funded through a reduction in the overtime costs.129 Based on SCE's current staff shortages, we find the additional amount requested for substation operators reasonable and expect overtime to be reduced.

3.4. Vehicle Costs Transmission & Distribution Business Unit - FERC Accounts 562, 563, 566, 568, 570, 571, 582, 583, 584, 587, 588, 590, 592, 593, 594, and 596

The Transmission & Distribution Business Unit (TDBU) operates a vehicle and equipment fleet consisting of passenger cars, vans, pick-up trucks, forklifts, trucks with aerial equipment (buckets and cranes), loaders, tractors, stringing equipment, trailers, and other vehicles. TDBU utilizes this fleet to operate and maintain SCE's transmission and distribution facilities, while SCE's Transportation Services Department acquires, maintains, and repairs the fleet. The Transportation Services Department also provides TDBU with Heavy Equipment, Rental, and Crane services (HERC), and helicopter services (Aircraft Operations).

TDBU recorded $56.584 million for the vehicle and equipment fleet expenses in 2006. For TY 2009, SCE forecasts $90.779 million (constant 2006$) in expenses for the fleet, a $34.195 million increase.130 For TY 2009, the total forecast for the fleet, HERC, and aircraft operations is $95.954 million (constant 2006$), an increase of $37.329 million over year 2006.131 The components of the total forecast are as follows: (1) $41.048 million for vehicle and equipment replacements; (2) $6.017 million for vehicle and equipment additions; (3) $30.595 million for Transportation Services Department base operations related to the current TDBU fleet; (4) $2.160 million for compliance with the California Air Resources Board rules on certain diesel vehicles; (5) $10.959 million for fuel and fueling; (6) $1.650 million for HERC; and (7) $3.573 for aircraft operations.132 SCE explains that it allocates Vehicle Costs to FERC subaccounts either directly (7%) or based on labor (93%).133

DRA claims that based on historical 2002-2006 data, SCE's request is not justified.134 According to DRA, nothing exists in SCE's direct testimony to support its Vehicle Cost forecast other than the indication that the costs were developed using a budget-based methodology.

In rebuttal, SCE offers explanations why DRA's estimate is low, but SCE still provides insufficient information to justify its request. As SCE showed in direct testimony, approximately 56% of the increased Vehicle Cost represents replacement of vehicles that have exceeded their useful lives and no longer comply with state and federal emission requirements. SCE explains that, because these vehicles must be replaced and the proposed replacement rate exceeds the past replacement rate, the replacement costs exceed the current costs.135 SCE also explains that its vehicle replacement strategy has been to replace vehicles in a timely manner, thus reducing downtime and repair costs, minimizing vehicle rental expense, and maximizing residual value in the vehicles by aggressively reselling them whenever possible.136

It is unclear why SCE's replacement rate is increasing when, according to SCE, its strategy has been to replace vehicles in a "timely manner." Accordingly, we find it reasonable to reduce the request by SCE for increases to Vehicle Costs and adopt DRA's recommendation.

3.5. Inspect and Patrol Lines Overhead Line Expenses - FERC Subaccount 563.100

SCE forecasts $16.565 million (constant 2006$) in labor and non-labor expenses recorded to FERC Account 563.137 This forecast is an increase of $11.310 million, or more than 206%, over SCE's 2006 recorded adjusted expenses of $5.485 million. DRA's forecast is $7.7 million.138 SCE's Account 563 has one subaccount, 563.100. SCE seeks increases to this subaccount by (1) $10.623 million for its Transmission Line Clearance Study, (2) $1.08 million for Transmission Line patrols, and (3) $487,000 for Vehicle Costs. These increases are partly offset by a reduction of $811,000 for Reallocation of Tool Expense to Overhead.139 Vehicle Costs are addressed in a separate section of this decision. The remaining three issues are addressed below.

3.5.1. Transmission Line Clearance

SCE requests additional funding of $10.623 million (constant 2006$) for its Transmission Line Clearance Study. DRA uses SCE's 2006 recorded expenses of $5.485 million as a basis for its forecast and recommends $2.215 million in additional funding for SCE's Transmission Line Clearance Study for a total of $7.7 million.140 CFBF also challenges SCE's request for Transmission Line Clearance Study funding, asserting (1) a purported double-counting of $1.104 million and (2) a theory that SCE's request is "non-urgent" and will result in "waste and inefficiencies."141

SCE's proposed funding is for study, evaluation, and mitigation planning to address potential clearance issues on SCE's transmission and sub-transmission lines.142 Given the magnitude and complexity of this effort, including the need for additional engineers to oversee this project and to participate in mitigation design during the 2009-2011 period, we find SCE's forecast reasonable.

3.5.2. Transmission Line Patrols

SCE seeks an increase of $781,000 (constant 2006$) in labor and non-labor expenses for additional Transmission Line Patrols. SCE states it "...must increase staffing to perform patrols on transmission lines as required by the Cal-ISO."143 DRA opposes this increase. According to DRA, the inspection of transmission lines is not a new responsibility and SCE has embedded labor expenses in its historical 2006 expenses for this activity. Moreover, DRA points to SCE's claim that it averaged approximately 42% in overtime rates in the historical period. DRA suggests SCE use the embedded costs of the overtime and premium rates to hire the employees it claims to need. SCE states it is adding circuit miles to its transmission system, and as DRA observed, SCE is already recording excess overtime with its current staffing. SCE argues it must bolster its staffing to carry out patrols on the new circuit miles. Based on SCE's projected increase to its transmission system, we find SCE's request reasonable.144

3.5.3. Reallocation of Overhead

SCE requests a decrease of $811,000. DRA objects to SCE's request. As described above in reference to FERC Account 560, SCE is requesting certain adjustments as a result of an analysis it conducted in 2006 to review the cost recording practices for clearing accounts. SCE's analysis recognized the need to make changes in the way that costs were recorded for several accounts. SCE explains that the internal account previously used to expense tools was changed to an account that allocates their cost on the basis of the labor of the personnel using the tools, thus capitalizing and expensing them in the same ratio. The result was a shift of $811,000 from O&M to capital.145 SCE's request to reflect those modifications to its accounting practices is reasonable.

3.6. Safety Meetings-Miscellaneous Transmission Expenses - FERC Subaccount 566.100

In subaccount 566.100, SCE forecasts $3.239 million (constant 2006$) in labor and non-labor expenses for safety meetings. SCE's forecast is an increase of $721,000 or about 28% over its 2006 recorded expenses.146 In SCE's 2006 GRC, SCE was authorized funding of $3.214 million for safety meetings and training for new employees.147 SCE notes the expenses in this subaccount are primarily for transmission personnel participating in safety meetings. Many of the meetings are mandatory (e.g., CAL-OSHA and environmental regulation meetings). SCE needs additional funding for such safety meetings because it is adding new employees and these new employees will need to participate in the safety-related activities.148 Based on increased staffing, we find SCE's request reasonable.

3.7. Miscellaneous Transmission Line Expenses - FERC Subaccount 566.200

In subaccount 566.200, SCE forecasts $4.028 million (constant 2006$) in expenses. SCE's forecast is an increase of $1.136 million or approximately 39% over 2006 recorded expenses. DRA notes this increase includes additional funding of (1) $725,000 for increased transmission line maintenance, (2) $87,000 for Employee Recognition, and (3) $324,000 for Vehicle Costs.149 Vehicle Costs and Employee Recognition are addressed in separate sections of this decision. Regarding the remaining issue, the $725,000 for increased transmission line maintenance, DRA recommends the Commission adopt SCE's 2006 recorded expense level of $2.892 million for this subaccount. DRA asserts these activities are "recurring costs" for "ongoing activities" embedded in SCE's 2006 recorded expenses.150 We find SCE's request reasonable because the basis for SCE's request is that there will be additional miles of transmission line added, and incremental funding is required for activities supporting those new miles.

3.8. Miscellaneous Expenses from Other Organizations - FERC Subaccount 566.300

SCE forecasts $11.034 million (constant 2006$) in labor and non-labor expenses in subaccount 566.300. SCE's forecast is an increase of $1.963 million or approximately 21% over 2006 recorded expenses. This increase includes additional funding of (1) $971,000 for a Corporate Real Estate Chargeback, (2) $655,000 for IT Products and Services Chargeback, (3) $323,000 for Reallocation of Field Accounting from Overhead, and (4) $3,000 for increased Vehicle Costs.151 DRA recommends the Commission adopt SCE's 2006 recorded expense level of $2.892 million for this subaccount. Vehicle Costs are addressed elsewhere in this decision. The remaining issues are addressed below.

3.8.1. Corporate Real Estate and Additional IT Costs

DRA opposes SCE's $971,000 increase for additional real estate costs and $665,000 for additional IT costs, asserting that the 2006 GRC decision authorized an increase in maintenance funding for this subaccount and that SCE's requested funding represents ongoing activities already embedded in rates.

Regarding real estate costs, we find SCE's request reasonable as SCE has provided documentation for the increased real estate costs. In addition, SCE has documented the additional IT costs, showing that these increases are driven by increased office and field personnel, who require additional computers, communication devices, and photocopiers. Accordingly, we also find SCE's requested increase for IT costs reasonable.

3.8.2. Reallocation of Overhead

As described above in reference to Account 560, SCE is requesting certain adjustments as a result of an analysis it conducted in 2006 to review the cost recording practices for clearing accounts. SCE's analysis recognized the need to make changes in the way costs are recorded to several accounts. SCE explains that the transmission and substation portion of the Field Accounting Organization largely supports capital activities, since they perform the accounting for capital work orders throughout TDBU. However, a portion of their work occurs in support of both capital and O&M. As a result, a portion of Field Accounting Organization costs are now being allocated to O&M, which results in a shift of $323,000 from capital to O&M. SCE's request to adjust its TY 2009 forecast to reflect these modifications to its accounting practices is reasonable.

3.9. Regulatory, Planning, and Business Development - FERC Subaccount 566.500

For subaccount 566.500, SCE forecasts $5.605 million (constant 2006$) in labor and non-labor expenses, consisting of $4.861 million in labor costs and $744,000 in non-labor costs. SCE's forecast is an increase of $107,000 above 2006 recorded expense. Six of SCE's adjustments to 2006 recorded expenses are for increased staffing. DRA recommends the Commission use SCE's 2006 recorded labor expenses of $3.385 million and SCE's TY 2009 non-labor forecast of $445,000 for a total of $3.830 million. DRA points out that SCE's requested increase is due in large part to its request to add approximately 22 new positions. DRA argues SCE has not provided documentation to demonstrate that its 2006 recorded expense and staffing levels are insufficient to meet its TY 2009 needs. In response, SCE states its increased staffing levels are needed to support the development and implementation of new projects affecting future system expansion. For instance, SCE notes, one of biggest increases is for staffing to perform Grid Interconnection studies. SCE's workload increased from 72 studies in 2005 to 140 studies in 2006, and has further increased since 2006 to 160 studies.152 Based on SCE's increased workload, we find SCE's forecast reasonable.

3.10. Training Miscellaneous Transmission Expenses - FERC Subaccount 566.700; Training Miscellaneous Distribution Expenses - FERC Subaccount 588.700

SCE forecasts $13.380 million (constant 2006$) in expenses for subaccount 566.700, Transmission Training, a $4.673 million increase over 2006 recorded expenses of $8.707 million.153 SCE forecasts $31.632 million in expenses for subaccount 588.700, Distribution Training, a $10.385 million increase over 2006 recorded expenses of $21.247 million.154 SCE states that, while most of the programs are the same, the employees receiving the training are different.

DRA claims SCE's requests for a 53% increase for subaccount 566.700 and a 48% increase for subaccount 588.700 are excessive. DRA suggests (1) SCE's proposed incremental increases are included in 2006 embedded costs and (2) SCE is requesting duplicative funding for the same or similar training in subaccounts 566.700 and 588.700.155 DRA proposes no increase over 2006 recorded figures.156

SCE states its forecast is largely proportional to its forecasted hiring increase.157 According to SCE, the TDBU Full-Time Equivalent employee headcount increased from 5,125 at the end of 2006 to 5,590 as of April 2008,158 and the TDBU forecast for year-end 2009 is 6,333 Full-Time Equivalent employees.159 Furthermore, in SCE's opinion, the Commission in the 2006 GRC allowed a 7.7% ratio of training costs to total labor, which included both O&M and capital-related labor.160 SCE's training request, as a ratio of the TDBU O&M and capital-related labor dollars in TY 2009, results in a similar ratio of 7.76% for the test year.

SCE's analysis of our 2006 GRC decision is not correct. In addition, while we understand SCE's forecast may include incremental costs for new and additional programs, based on SCE's historical expenditures for these two subaccounts we find SCE's request excessive. Accordingly, to provide SCE with incremental funding, we adopt a forecast that includes 50% of SCE's incremental requests ($7.529 million)161 for these two subaccounts and a total for both subaccounts of $37.483 million.

3.11. Maintenance of Station Equipment - FERC Account 570

SCE forecasts $11.482 million (constant 2006$) for its Maintenance of Station Equipment expenses recorded to FERC Account 570. This forecast is an increase of $3.094 million or 35% over 2006 recorded expenses of $8.748 million. DRA's estimate is $9.359 million. SCE's FERC Account 570 includes four subaccounts. DRA disputes SCE's recommendations for subaccount 570.200 Maintenance of Transmission Circuit Breakers and subaccount 570.400 Maintenance of Miscellaneous Station Equipment.162

3.11.1. Routine Maintenance of Transmission Circuit Breakers - FERC Subaccount 570.200

Subaccount 570.200 is for maintenance and repair of transmission circuit breakers. SCE forecasts $2.188 million (constant 2006$) in 2009.163 DRA proposes $1.757 million based on a five-year average of expenses recorded in this subaccount.164 DRA states SCE's request is an increase of $633,000 or 40% over 2006 recorded expenses of $1.555 million. DRA proposes reductions to SCE's forecast of $346,000 for circuit breaker maintenance and $287,000 for increased Vehicle Costs.165

SCE states it "deferred due to resource constraints" circuit breaker maintenance in 2006 and seeks an increase over 2006 levels to "...perform approximately 660 transmission/sub-transmission MMs166 in addition to regularly scheduled MMs at an average cost of $460/$690 respectively each."167 By resource constraints, SCE is referring to what it describes as unprecedented customer growth and SCE's decision to reprioritize certain work described in SCE's 2006 GRC. SCE has the burden to show that its forecasts are fully justified and supported. SCE did not provide specific information on the work deferred as a result of the customer growth issues. Moreover, we find that customer growth issues should not detract from regular maintenance of its transmission system. We find DRA provides convincing evidence that historical expenses are an appropriate methodology for forecasting TY 2009 expenses. We find DRA's estimate based on a five-year average reasonable168 and remove $346,000 from SCE's forecast and also remove $287,000 to reflect recorded costs for vehicles.

3.11.2. Maintenance of Miscellaneous Station Equipment - FERC Subaccount 570.400

FERC subaccount 570.400 records expenses for maintaining miscellaneous transmission substation equipment. SCE forecasts TY 2009 expenses of $8.805 million (constant 2006$). DRA proposes $6.753 million. According to DRA, SCE's forecast is an increase of $2.297 million or approximately 35.30% over its 2006 recorded expenses of $6.508 million. DRA challenges SCE's request in six areas: (1) Disconnect Repairs; (2) Switchrack Lighting; (3) Cable Trench Covers; (4) Rack Inspections; (5) Capital-related O&M expenses; and (6) Vehicle Costs. With the exception of Vehicle Costs, which are addressed separately, these adjustments are discussed below.

3.11.2.1. Disconnect Repairs

For disconnect repairs, SCE requests an increase of $584,000 (constant 2006$). DRA recommends no increase over the 2006 base year. SCE states it will perform approximately 500 Preventive Maintenance Assessments169 related to disconnect repairs in the TY 2009. According to DRA, SCE's repair estimate represents an increase of 614% over the historical period.170 Since the average number of Preventative Maintenance Assessments related disconnect repairs that SCE has performed in the past five years is 70 per year, DRA considers SCE's forecast unrealistic. DRA also points out that, according to SCE, it deferred work in this area for the short-term but must now address the back-log of problems. For this reason, DRA argues SCE's request should be considered deferred maintenance and, on that basis, rejected. In this circumstance, SCE has not satisfactorily explained what events occurred that require the expenditure of a 600% increase.

We do not find SCE explanation that customer growth required it to divert funds to other matters sufficient to explain the dramatic increase in this area. Moreover, based on SCE's testimony, we do not find SCE's decision to defer work in this area reasonable. SCE urges the Commission to approve of the increase on the basis that this equipment is crucial to the integrity of the entire transmission system, stating that the failure and "inability of a disconnect switch to conduct or insulate will result in significant loss of the substation's ability to even function, leading to wide outages." However, SCE also states that

"[T]here is some discretionary amount of time involved in when they [disconnect repairs] must be completed. Accordingly, as discussed in Mr. Kelly's rebuttal testimony, senior management necessarily prioritizes according to good management practices to utilize our limited funds for the most immediately necessary work. We were able to defer the work for the short-term, but we can no longer continue this trend."171

SCE's testimony is contradictory. SCE explains that this equipment is essential to the integrity of the network but also explains that deferring maintenance of this essential equipment is reasonable. For these reasons and the fact that SCE's request finds no support in historical data, we find it reasonable to adopt DRA's forecast and reject SCE's requested increase.

3.11.2.2. Switchrack Lighting

SCE is asking for funds to replace lighting, much of which is over 50 years old, at many of its substations. SCE requests an additional $400,000 (constant 2006$) for this activity. DRA recommends $133,000. DRA argues that SCE's embedded costs include this activity. We agree with SCE that the need to replace lighting exists but, again, we do not find SCE's explanation sufficient to explain why it has not maintained this equipment regularly. Accordingly, we find the amount excessive based on DRA's argument. We reduce SCE's request by 50%, which provides for an increase over 2006 base level. We find a forecasted amount of $200,000 reasonable for TY 2009.

3.11.2.3. Cable Trench Covers

SCE requests an additional $335,000 (constant 2006$) for this activity. DRA recommends $112,000 (a 67% reduction) on the basis that SCE is already replacing trench covers and, as a result, the costs of those replacements are embedded in SCE's historical expenses. Again, we agree with the need to replace trench covers but find the amount excessive based on DRA's argument which analyzes historical costs. Accordingly, we reduce SCE's request by 50%. We find a forecasted amount of $167,000 reasonable for TY 2009.

3.11.2.4. Rack Inspections

SCE estimates an additional $90,000 (constant 2006$) for rack inspections. DRA recommends no increase. DRA suggests the inspections are part of embedded cost and can be funded through existing expenses. SCE states that its field assessments show a modest increase is warranted in this area. According to SCE, "[o]f particular concern are steel structures located in the coastal part of our service territory. These structures tend to corrode more quickly due to the ocean environment in these locations."172 SCE also explains that these activities were "deferred" as SCE's non-labor resources were allocated to higher priority activities.173 We agree with DRA that these activities are included in embedded cost and for the reasons discussed above in connection with disconnect repairs, we reject SCE's request for an additional $90,000 for TY 2009.

3.11.2.5. Work Order Related Expenses - FERC Account 570.400

SCE requests additional funding for subaccount 570.400. The request includes additional labor of $585,000 partially offset by a non-labor adjustment of $110,000, for a total of $475,000 (constant 2006$). DRA claims SCE has not provided documentation to demonstrate historic expense levels are insufficient to meet its test year requirements. We find the underlying cost drivers for work order expenses are capital projects. In this decision, we reduce SCE's forecasted capital expenditures by $549.4 million or 14.56%. Accordingly, we find it reasonable to reduce SCE's forecasted work order expenses by 14.56%.

3.12. Maintenance of Overhead Lines - FERC Account 571

SCE's FERC Account 571 includes the following three subaccounts: 571.100 Poles and Structures; 571.200 Insulators and Conductors; and 571.300 Transmission Line Rights-of-Way. DRA disputes the increases SCE requests in each of these subaccounts. SCE explains that incremental funding for its Transmission Life Extension Program accounts for the majority of its additional forecasted expense.174

3.12.1. Poles and Structures - FERC Subaccount 571.100

In subaccount 571.100, SCE forecasts $13.336 million (constant 2006$) in labor and non-labor expenses, an $8.128 million increase over SCE's 2006 recorded expenses.175 SCE's forecast includes additional funding of $7.626 million for its Transmission Life Extension Program, $156,000 for Transmission Intrusive Pole Inspections, and $346,000 for Vehicle Costs.176 Vehicle Costs are addressed in another section of this decision. DRA recommends the Commission adopt SCE's 2006 recorded expenses of $5.028 million for TY 2009. The issues pertaining to the Transmission Life Extension Program and Intrusive Pole Inspections are addressed below.

Regarding the Transmission Life Extension Program, DRA indicates that SCE's historical expenses have embedded costs in them for the line items identified in SCE's Life Extension Program. DRA asserts that SCE has not shown that its 2006 expense levels are insufficient to address its Life Extension Program activities in the test year.177

Although SCE made efforts to specifically identify how its authorized Life Extension funding was spent in prior years and, where appropriate, to remove the costs from SCE's base year,178 SCE failed to meet the requirements of D.06-05-016 to provide additional detail and clarification on the incremental nature of this request. In addition, since SCE is requesting a significant increase over past expenses, SCE must provide details to support its rejection of the use of historical trends. SCE does not offer such evidence. Accordingly, in the absence of sufficient proof, SCE's request for an additional $7.626 million is denied

SCE requests incremental funding of $156,000 for intrusive inspections of transmission poles. DRA opposes this request, observing that because the number of intrusive inspections in 2006 is relatively high, recorded costs should be sufficient. SCE provides evidence that its request for intrusive inspections is based on a levelized plan to meet GO 165 requirements and that the majority of the additional expenses stem from an increase in a competitively-bid contract.179 Accordingly, we find this SCE request reasonable.

3.12.2. Insulators and Conductors - FERC Subaccount 571.200

In subaccount 571.200, SCE forecasts $16.643 million (constant 2006$) in labor and non-labor expenses. This forecast is an increase of $9.766 million over 2006 recorded expenses of $6.877 million. SCE's forecast includes additional funding of (1) $2.007 million for Insulator Washing, (2) $4.812 million for Insulator Replacement, (3) $1.524 million for Work Order-Related Expense, and (4) $1.423 million for Vehicle Costs. DRA relies on SCE's 2006 recorded expense for a forecast of $7.385 million.180 Vehicle Costs are addressed in another part of this decision. The remaining issues are addressed below.

3.12.2.1. Insulator Washing

SCE estimated incremental funding of $2.007 million for insulator washing in the San Joaquin Valley. SCE claims DRA mistakenly finds 2006 recorded costs include insulator washing.181 According to SCE, the program for insulator washing in the San Joaquin Valley did not begin until 2007, so no costs were recorded in 2006.182 However, according to D.06-05-016, SCE's efforts to address insulator washing in the San Joaquin Valley were included in SCE's TY 2006 GRC request.183 We summarized SCE's position in support of its 2006 request as follows:

"[A] severe particulate problem exists and that its proposed funding for washing insulators [in San Joaquin Valley] represents an effort to be proactive in maintaining the reliability of the transmission system in the face of a known problem."184

In this proceeding, SCE has not explained why amounts requested in the 2006 GRC for a "severe" problem that impacts reliability were not sufficient or whether such maintenance was deferred. Accordingly, we do not adopt SCE's request for incremental funds of $2.007 million.

3.12.2.2. Work Order Related Expenses

SCE proposes an increase of $1.524 million for work order-related expenses to address "...the physical relocation and electrical re-configuration of transmission and sub-transmission line equipment to support the capital additions" due to SCE's anticipated increase in "capital expenditures for infrastructure replacement and load growth projects."185 DRA argues SCE's customer growth, which is a driver of SCE's capital projects, is forecasted to be below 2006 levels in the test year. In addition, DRA points out that SCE's historical expenses include embedded costs for the "physical relocation and electrical re-configuration of transmission and sub-transmission line equipment." As a result, DRA recommends normalizing SCE's forecast over a three-year period (2009-2011) for an increase of no more than $508,000 for TY 2009.186 As we noted earlier, the underlying cost drivers for work order expenses are capital projects. In this decision, we reduce SCE's forecasted capital expenditures by $549.4 million or 14.56%. Accordingly, we find it reasonable to reduce SCE's forecasted work order expenses by 14.56%.

3.12.2.3. Insulator Replacement

SCE's forecast also includes a $4.812 million (constant 2006$) increase for insulator replacement as part of its Transmission Life Extension Program. SCE claims that the increase represents the cost of materials and the use of contract crews to supplement SCE's crews for insulator and hardware replacements.187 DRA claims historical expenses have embedded costs for insulator replacements. According to SCE, some of the circuits it will be replacing are over 90 years old and many of the insulators on its system have exceeded their life expectancies.188

Based on the evidence provided, it is unclear how SCE's request constitutes a Life Extension Program, which is designed to extend the life of the asset. In this case, SCE is addressing problems that have resulted from deferred maintenance. In addition, while these types of programs may be a cost-effective way to maintain the integrity of the system and slow the deterioration of capital assets, SCE has not sufficiently addressed our concerns, noted above, about the relationship of these programs to costs embedded in the historic data. In instances where such a significant increase is requested, SCE must provide a stronger showing which includes the reasons SCE has not performed maintenance of this equipment on a regular basis. Accordingly, SCE's request for $4.812 million to increase its insulator replacement as part of its Life Extension Program is denied.

3.12.3. Transmission Line Rights-of-Way - FERC Subaccount 571.300

SCE forecasts $9.397 million in labor and non-labor expenses for this FERC subaccount.189 SCE's forecast is an increase of $799,000 or 9.29% over 2006 recorded expenses of $8.598 million. SCE's forecast includes $300,000 for grading in Angeles National Forest, as part of its Life Extension Program, and $499,000 for Vehicle Costs. Vehicle Costs are addressed in another section of this decision. Regarding the grading request, for Angeles National Forest, we find SCE has provided insufficient evidence to fund this activity as part of the Life Extension Program. SCE has not established the connection between grading in a National Forest and the purpose of the Life Extension Program, which is designed to extend the life of an asset. Accordingly, SCE's request is denied.

3.13. Operation Supervision and Engineering-FERC Account 580

SCE's TY 2009 forecast for FERC Account 580 is $51.403 million. In 2006, SCE recorded $38.767 million to this account, which includes several subaccounts: 580.100 Distribution Operations Supervision and Operations; 580.200 Internal Market Mechanism Distribution Operations & Engineering; 580.300 Meter Services Operations and Management; 580.500 Research, Development & Demonstration; and 580.980 Allocated Division Overheard for Distribution Operations.

3.13.1. FERC Subaccount 580.100

SCE forecasts $10.843 million (constant 2006$) for TY 2009, an increase of $3.482 million or 47% over 2006 recorded expenses of $7.261 million. SCE's forecast includes additional funding of (1) $2.140 million for Engineering Advancement projects, (2) $1.295 million for Project Management Organization Work Order Write-Offs and (3) $174,000 for Customer Service Business Unit Safety Activities. DRA rejects these proposed increases. Instead, DRA's forecast starts with SCE's 2006 recorded expenses of $7.361 million and removes $600,673 related to Awards to Celebrate Excellence and Employee Recognition, leaving $6.760 million. Awards to Celebrate Excellence and Employee Recognition are addressed in a separate section of this decision. The remaining issues are addressed below

3.13.1.1. Engineering Advancement

SCE's forecast includes additional funding of $2.140 million (constant 2006$) for Engineering Advancement projects. We have addressed this issue above in reference to subaccount 560.100. We find the same result reasonable here, namely, we find reasonable 50% of the increased amount requested by SCE.

3.13.1.2. Project Management Organization Work Order Write-Offs

SCE's 2009 estimate of Project Management Organization work order write-offs is based on the historical average ratio of write-offs to capital spending, multiplied by the forecast level of capital spending in the Project Management Organization-related areas.190 DRA points to SCE's four year average (2003-2006) for Project Management Organization write-offs, which is $791,000.191 DRA explains that between 2005 and 2006, SCE's expenses for Project Management Organization write-offs increased from $735,533 to $1.481 million.192 As explained in this decision, we reduce SCE's request for capital spending by $549.4 million. Accordingly, based on the relationship between capital spending and Project Management Organization write-offs, we find it reasonable to reduce SCE's requested increase in expenses for Project Management Organization write-offs by 14.56%.

3.13.1.3. Customer Service Business Unit Safety Activities

SCE requested $174,000 for additional staff in the Customer Service Business Unit Safety Organization.193 DRA argues safety is an ongoing responsibility and, in addition, SCE added a number of safety-related personnel in previous years.194 DRA also states that, because SCE did not provide a cost-benefit analysis to support previous staff additions, the embedded costs in recorded 2006 are sufficient for ongoing operations. SCE claims its request is to "...provide additional safety training classes for our meter readers and to handle an increase in ergonomic assessments."195 The funding requested is to provide training beyond the type offered in the past. Accordingly, we find SCE's request reasonable.

3.13.2. Internal Market Mechanism Distribution Operations & Engineering - FERC Subaccount 580.200

SCE forecasts $9.237 million (constant 2006$) in test year expenses for subaccount 580.200, in which SCE records expenses for services that other departments provide to TDBU.196 The expenses are recorded through SCE's Internal Market Mechanism charges and are embedded in TDBU's historical costs. For this reason, SCE explains, the expenses are not discussed in the Internal Market Mechanism testimony of the other departments.197 DRA asserts historical costs should be sufficient to meet relevant future needs.198 Accordingly, DRA recommends the Commission adopt SCE's 2006 recorded expenses of $6.417 million for this subaccount in TY 2009.199 We agree with DRA that SCE fails to adequately support this request. No direct testimony was submitted on this issue.200 However, DRA's analysis fails to take into consideration costs for certain new activities, such as the new ongoing annual costs in response to guidelines from the U.S. Fish and Wildlife Service ($156,000)201 and facility operation and maintenance costs for new facilities ($1.6 million).202 We find reasonable only these two increases. We also reduce the request for costs for new facilities by 14.56% 203 to reflect our decision regarding additional capital spending.

3.13.3. Meter Services Operations and Management - FERC Subaccount 580.300

This subaccount records expenses related to the management and supervision of the Meter Services Organization. SCE notes that since preparing and filing its GRC application, the expected customer growth for 2007-2009 has slowed due to the changing economy.204 As a result, SCE lowered its customer growth projection in rebuttal testimony, which lowered its forecast for this subaccount. SCE forecasts $2.485 million (constant 2006$). SCE claims that no further reductions are warranted.205 SCE's 2006 recorded expenses were $2.751 million. DRA recommends a reduction to SCE's forecast to reflect Enterprise Resource Planning implementation productivity for TY 2009 and presents a forecast of $2.429 million.206 Because SCE has reduced its forecast to reflect the changing economy and, in addition, has included a reduction to its forecast to reflect increased productivity, we find SCE's request reasonable.

3.13.4. Research Development and Demonstration

SCE forecasts $5.830 million (constant 2006$) for subaccount 580.500.207 SCE's 2006 recorded expenses are $2.229 million. SCE's forecast is an increase of $3.601 million over 2006 recorded levels. DRA recommends the Commission adopt a TY 2009 expense level of $2.136 million, which is the average of SCE's spending levels in 2005 and 2006.208

SCE states that its estimate is "based on the professional judgment of SCE's engineering and scientific personnel."209 In addition, SCE provides details and cost estimates for proposed projects,210 and cites to unprecedented load growth in past years.211 The evidence is inadequate to support the level of increase requested by SCE. In addition, SCE's request is not supported by historical data. For these reasons, we deny SCE's request and adopt the 2006 base level.

SCE also proposes the continuation of the one-way RD&D Balancing Account that was established in 1988. SCE's proposal to continue the one-way RD&D balancing account is reasonable and will be adopted. SCE's funding under this balancing account is restricted to endeavors that meet the criteria for permissible RD&D projects as stated in Pub. Util. Code § 740.1.

3.14. Distribution Substations - FERC Account 582

SCE forecasts $17.53 million (constant 2006$) for Distribution Station Expenses recorded to FERC Account 582.212 SCE's 2006 recorded expenses are $16.269 million. DRA recommends $16.391 million. SCE's FERC Account 582 includes two subaccounts. DRA disputes SCE's estimate in subaccount 582.100, Operation Relay Protection of Distribution Substations.213

SCE forecasted $15.603 million (constant 2006$) in expenses for subaccount 582.100.214 SCE's 2006 recorded expenses are $14.464 million. DRA and CFBF recommend no increase over 2006 base year for this subaccount. SCE requests additional funding of $517,000215 over 2006 recorded expenses for 20 additional substation operators and $622,000 for Vehicle Costs. As we decided regarding the recommendations of DRA and CFBF on subaccount 562.100, we find that, based on SCE's staff shortages, the additional amount for Grid Operators is reasonable, and we expect overtime to be reduced. SCE's request for an increase of $622,000 for Vehicle Costs is addressed in a separate section of this decision.

3.15. Overhead Line Operations - FERC Subaccount 583.400

SCE's TY 2009 forecast for this subaccount is $25.667 million (constant 2006$). SCE's forecast is based on the last recorded year expenses of 2006 of $13.999 million, plus identified incremental costs.216 DRA bases its estimate of $17.283 million on the average of 2005 and 2006 recorded figures, which is a reduction of $8.83 million from SCE's forecast. DRA contests additional funding of (1) $516,000 for Overhead Detail Inspections, (2) $636,000 for Pre-Construction Site Readiness Checks, (3) $1.21 million for Vehicle Costs, (4) $1.209 million for Troublemen Accounting Changes, and (5) $1.408 million for Distribution Wood Pole Inspections.217 TURN presents its own arguments for reductions to SCE's forecasts for Intrusive Wood Pole Inspections and Overhead Detail Inspections. With the exception of Vehicle Costs, we address these issues below. Vehicle Costs are addressed in a separate section of this decision.

3.15.1. Overhead Detail Inspections

SCE's TY 2009 forecast for subaccount 583.400 includes Overhead Detail Inspection expenses for SCE's new Distribution Inspection & Maintenance Program, also know as DIMP.218 SCE is forecasting $0.516 million, which consists of labor expense of $0.901 million and a reduction in non-labor of $0.385 million. The Distribution Inspection & Maintenance Program219 was created in consultation with the Commission's Consumer Protection and Safety Division to ensure compliance with Commission regulations.220 The ultimate goal shared by SCE and the Consumer Protection and Safety Division "was to deliver to customers, employees and the general public greater safety and equal reliability for the same or lower cost."221

DRA recommends cutting $516,000 for overhead inspections recorded in subaccount 583.400, thus eliminating the net increase in this account associated with SCE's requested 13 additional Electrical System Inspectors to perform grid patrols.222 TURN supports a reduction to SCE's forecast of $83,000.223 SCE claims all but $83,000 of the increase is offset by a corresponding reduction in Troublemen charges for patrols.224

We find SCE has convincingly demonstrated that its Distribution Inspection & Maintenance Program entails increased work. The program emphasizes a condition's risk to safety and reliability from a much broader perspective than before and the inspectors have greater responsibilities and burdens. SCE explains, going forward, inspectors will assess not only the condition itself but also take into account a great deal of surrounding information, such as the surrounding environment, system conditions, probability and consequence of failure, and so on. The inspectors will also take pictures and provide comments to include in the work orders. Because of the overall increase in the amount of work forecasted related to the Distribution Inspection & Maintenance Program, we find SCE's request reasonable.

3.15.2. Pre-Construction Site Readiness Checks

SCE's forecast for subaccount 583.400 also includes $0.636 million (constant 2006$) for Pre-Construction Site Readiness Checks. SCE states additional labor and non-labor expenses are needed to support load growth and customer growth capital projects in TY 2009.225 DRA claims SCE did not prepare a cost benefit analysis to determine that additional site readiness checks are needed to support load growth and customer growth projects.226 In response, SCE again cites to increased workloads but also explains it intends to replace some contract construction/materials coordinators with additional employees. For the reasons presented by DRA, we agree that SCE's forecast is excessive. However, we also find SCE's arguments regarding replacement of contract labor and, in part, load growth, persuasive. For these reasons it is reasonable to reduce SCE's request by 50%.

3.15.3. Troublemen Accounting Changes

SCE's forecast for subaccount 583.400 includes $3.628 million (constant 2006$) to account for adjustments related to the charging practices for Troublemen. SCE proposes to move costs from capital to O&M. SCE says it recently determined that some costs incurred during emergency responses to non-storm outages should have been charged to O&M.227 DRA opposes SCE's request. DRA claims SCE failed to provide any effective means to analyze the detail of expenses included in its proposal and failed to compare expense patterns over a historical period to determine if the identified expenses fluctuated significantly from year to year or remained flat. DRA suggests the Commission normalize SCE's request of $3.628 million over a three-year period and forecasts $1.209 million for TY 2009.228 Contrary to DRA's contentions, SCE presents data showing its proposal is reasonable.229 We find SCE's decision to shift $4.061 from capital to O&M appropriate. The net number is $3.628 million because SCE reduces the amount by $433,000 to reflect the shift of annual patrols to Electrical System Inspectors under the new Distribution Inspection & Maintenance Program.

3.15.4. Distribution Wood Pole Inspections

SCE's forecast for subaccount 583.400 also includes an additional $5.030 million (constant 2006$) of expenses and reflects a levelized number of approximately 130,000 wood pole intrusive inspections per year.230 DRA proposes a reduction of $3.622 million based on a three-year average of historic expenses to perform these inspections.231 TURN suggests SCE's forecast be reduced by $3.7 million because SCE's forecast reflects an excessive number of planned inspections and excessive costs per inspection.232

In support of its forecast, SCE provides evidence that historical costs do not reflect projected 2009 activity. In addition, SCE points to DRA's failure to address SCE's claim that the actual inspection costs will be affected by new cost drivers, including higher inspection costs that became effective on May 1, 2008 following a mandatory contract renegotiation in 2007 based on a competitive bid solicitation process.233 SCE also shows that TURN was mistaken in asserting some intrusive inspections are undertaken by SCE personnel, as opposed to contract labor, and that TURN's historical cost analysis is not entirely reliable because such costs do not accurately reflect future inspection costs.234

However, TURN convincingly demonstrates that the actual number of intrusive inspections forecasted by SCE is excessive.235 SCE has failed to justify the reasonableness of its proposal to intrusively inspect 130,000 wood distribution poles per year during this rate case cycle.236 Accordingly, we reduce SCE's forecast of $5.030 million by 17%237 or $855,000. We adopt a TY 2009 forecast of $4.175 million as reasonable.

3.16. Underground Line Expenses - FERC Account 584

SCE forecasts $6.138 million (constant 2006$) for expenses recorded to FERC Account 584.238 SCE's forecast is an increase of $2.348 million or approximately 61% over 2006 recorded expenses of $3.790 million.239 DRA's forecast is $4.246 million.240 FERC Account 584 includes several subaccounts. Of these, DRA disputes SCE's forecast for subaccounts 584.200 Transformers In/Out and 584.400 Underground Line Operations. The dispute over subaccount 584.200 concerns Vehicle Costs, which we address elsewhere in today's decision.

SCE forecasts $4.874 million (constant 2006$) for subaccount 584.400, which is an increase of $2.165 million. SCE's forecast is more than 79% over SCE's 2006 recorded expenses of $2.709 million. DRA uses SCE's 2006 recorded expenses as a starting point and forecasts $3.099 million. SCE's request includes an additional (1) $581,000 for Underground Detail Inspections, (2) $1.170 million for Underground Cable/Conduit Inspections, and (3) $414,000 for Vehicle Costs. Vehicle Costs are addressed in a separate section of this decision.

Regarding SCE's forecast of an additional $581,000 to implement the Distribution Inspection & Maintenance Program, we find this amount reasonable, which is consistent with our findings regarding subaccount 583.400. Regarding the additional $1.170 million for Underground Cable/Conduit Inspections, SCE explains in rebuttal testimony that this additional amount will fund a proposed underground cable testing program.241 We agree with DRA that SCE fails to adequately explain the scope of this program. From SCE's general description, it is difficult to determine the existing, continuing, and new activities as related to this proposed program. Accordingly, we find insufficient support to justify SCE's proposed increase of $1.170 million.

3.17. Meter Expenses - FERC Account 586

SCE forecasted $26.632 million (constant 2006$) for Meter Expenses recorded to FERC Account 586. SCE's 2006 recorded expenses are $26.908 million. DRA recommends $24.903 million. SCE's FERC Account 586 includes two subaccounts. DRA disputes SCE's estimate in subaccount 586.100 of $15.984 million and subaccount 586.400 of $9.525 million.242 We discuss these issues below.

3.17.1. Meter Turn On and Off Services - FERC Account 586.100

SCE's forecast for subaccount 586.100 is $15.984 million (constant 2006$) for TY 2009.243 SCE's forecast is based on 2006 recorded expenses of $15.613 million, increased by $316,000 for customer growth and $181,000 for increased Vehicle Costs, and partially offset by a reduction of $126,000 for productivity from GPS-based order dispatch and routing.244 DRA recommends a forecast less than 2006 recorded.245 In support of its request, SCE explains that, while costs have remained relatively stable during the historical period, SCE does not expect this trend to continue. We find SCE's request for an increase, as adjusted, of $316,000 for customer growth reasonable. Vehicle Costs are addressed in a separate section of this decision.

3.17.2. Test or Inspect Meters - FERC Subaccount 586.400

Subaccount 586.400 records expenses for the operation, inspection, and testing of meters and associated metering equipment pursuant to Tariff Rule 17 and the Direct Access Standards Metering and Meter Data (DASMMD).246 SCE forecasts $9.526 million (constant 2006$) for subaccount 586.400.247 In its rebuttal testimony, SCE reduced this forecast to reflect changes in its customer growth forecast based on the economic downturn.248 SCE's recorded expenses for 2006 are $9.061 million. DRA recommends a forecast of $7.653 million.249

The differences between DRA's snd SCE's forecasts are, in part, driven by SCE's and DRA's use of different forecasting methodologies. DRA's recommendation is based on using the five-year average of recorded expenses (2002-2006) of $7.653 million.250 SCE relies on the last recorded year plus customer growth for its forecasting methodology.251 Because SCE has reduced its forecast to reflect changes in economic growth, we find SCE's forecasting methodology reasonable as applied to this subaccount for TY 2009.252

DRA also opposes SCE's request for $183,000 for customer growth, $207,000 to replace expected retirees, and $74,000 for increased Vehicle Costs.253 We address Vehicle Costs elsewhere in today's decision.

We find SCE's request for $183,000 related to customer growth reasonable because SCE reduced its forecast to reflect changing economic circumstances. Regarding the additional $207,000 to replace expected retirees, we agree with SCE that, in this instance, it is prudent to train new hires so they are ready to be dispatched to the field, avoiding vacancies that cannot be quickly filled with qualified employees. We also understand that, due to the specialized technical training requirements of the position, it takes three to five years for a MT1 to progress to a MT5.254 However, SCE fails to adequately explain the relationship between decreased costs associated with retirements and the increased costs associated with training and new hires. Because SCE has not shown the relationship between its forecasted increase in expenses and the expected retirements, we will not include in the TY 2009 forecast the $207,000 for new hires to replace retirees.

3.18. Miscellaneous Distribution Expenses - FERC Account 588

SCE forecasts $82.735 million (constant 2006$) for FERC Account 588.255 As explained below, SCE slightly revised this forecast in rebuttal testimony. SCE's forecast represents an increase of $17.623 million or approximately 27% over SCE's 2006 recorded expenses of $65.112 million.256 DRA's forecast for FERC Account 588 is $60.404 million.257 SCE's FERC Account 588 includes eight subaccounts. DRA disputes SCE's estimates in five subaccounts: (1) 588.000 Mapping Expense; (2) 588.300 Management and Supervision; (3) 588.700 Training Distribution; (4) 588.800 Miscellaneous Other; and (5) 588.900 Service Guarantees. These issues are discussed below.

3.18.1. Mapping Staff - FERC Subaccount 588.000

SCE forecasts $4.245 million (constant 2006$) for this subaccount. In 2006, SCE recorded $4.505 million to this subaccount. DRA does not dispute SCE's non-labor forecast which decreased from $833,000 (2006 recorded) to $106,000 (TY 2009 forecast). DRA disagrees with SCE's proposal for an additional $467,000258 in labor expenses for seven more mapping personnel.259 We find SCE's request reasonable. SCE shows that while its productivity has increased, a significant backlog of map sketches still exists.260 SCE's forecast assumes workload will grow at less than half the historical rate of growth and that productivity will increase by 7% per year, which is consistent with past historical data.261

3.18.2. Management and Supervision - FERC Subaccount 588.300

SCE's TY 2009 forecast for this subaccount is $30.691 million (constant 2006$).262 In 2006, the recorded expenses for this subaccount were $21.811 million.263 DRA's forecast is $20.622 million.264 DRA proposes the following eight reductions to SCE's forecast: (1) $78,000 for Distribution Construction and Maintenance stand-by time;265 (2) $1.579 million for Management and Supervision; (3) $547,000 for Safety Activities; (4) $438,000 for Design Joint Pole personnel; (5)  $4.424 million for Business Process and Technology Improvement program/job orders; (6) $1.509 million for Field Accounting & Grid Operations costs due to the reallocation of overhead; (7) $27,000 for Vehicles; and (8) $1.503 million for Awards to Celebrate Excellence and Employee Recognition. Vehicle Costs and Awards to Celebrate Excellence/Employee Recognition are addressed in separate sections of this decision. The remaining issues are addressed below.

3.18.2.1. Distribution Construction and Maintenance Stand-by Time

DRA disputes SCE's request for an additional $78,000 over 2006 recorded amounts for stand-by time. SCE explains two of its eight distribution regions mistakenly did not record any stand-by time in 2006. SCE's forecast corrects this oversight by adding $78,000, as the two regions have since implemented the correct practices to record stand-by time.266 We find SCE's request reasonable.

3.18.2.2. Management and Supervision

DRA disputes SCE's request for additional funding of approximately $238,000 for a Mapping supervisor and two Joint Pole supervisors.267 SCE explains the additional Mapping supervisor is needed for new hires noted in reference to Account 588.000. We find SCE's request reasonable. SCE also requests additional funds for two Joint Pole supervisors. SCE claims this increase is attributable to the need to add six additional positions to address a 300% increase in workload for Requests for Pole Attachments, including an enormous number of Pole Attachment Agreements with third parties to provide broadband access to schools using federal funds.268 Based on SCE's increased workload, we find SCE's request for the additional Joint Pole supervisor positions reasonable.

3.18.2.3. Safety Activities

SCE proposes an increase of $511,000 for Safety Activities.269 SCE claims this additional amount is needed for new personnel, such as a Maintenance Electrician and new Groundmen, to engage in safety-related activities.270 DRA argues against this requested increase based on SCE's description of these costs as "recurring costs."271 We find SCE has not adequately explained why this requested increase is not already included in the recorded 2006 base year.

3.18.2.4. Design Joint Pole Staffing

SCE requests a $438,000 increase in labor expenses for the Joint Pole Organization to fund six additional positions. SCE claims the Joint Pole Organization experienced an increase in Joint Pole Agreements from 2006-2007 of 25% and Requests for Pole Attachments have increased by 333% in that same time period.272 Based on the evidence of increased workload presented, we find SCE's request reasonable.

3.18.2.5. Business Process and Technology Improvement Program/Job Orders

SCE requests an additional $4.424 million for its Business Process and Technology Improvement projects for TY 2009. SCE's 2006 recorded expenses are $12.378 million.273 SCE's 2009 forecast was developed on a project-by-project basis by building the forecast from a bottoms-up approach.274 DRA suggests SCE's 2006 recorded expense levels are sufficient to address these test year needs.275 SCE fails to provide convincing evidence of the reasonableness of its methodology for forecasting these expenses. Accordingly, SCE's request for additional funding beyond the 2006 base year is denied.

3.18.2.6. Reallocation of Overhead

SCE requests an increase of $1.509 million related to reallocation of overhead. According to SCE, this increase reflects a shift of $1.823 million from capital to O&M. DRA recommends partial funding of $314,000. SCE explains this adjustment is a result of an analysis conducted in 2006 to review the cost recording practices for clearing accounts. SCE's 2006 analysis recognized the need to make changes in the way costs are recorded for several accounts. As a result, SCE incorporated into this rate case these changes in cost recording practices. SCE explains that the adjustments must be made to accurately reflect the costs recorded to this account on an ongoing basis. SCE further claims this modification is solely an accounting adjustment276 and follows FERC accounting guidelines. Consistent with our finding regarding subaccount 566.300, we find SCE's request to adjust its TY 2009 forecast to reflect modifications to its accounting practices reasonable.

3.18.3. Miscellaneous Other - FERC Account 588.800

Subaccount 588.800 records expenses SCE incurs for work order write-offs, as well as certain relatively minor charges for non-capital furniture and equipment.277 SCE forecasts $11.922 million (constant 2006$) for this subaccount for TY 2009.278 SCE's 2006 recorded expenses are $11.062 million.279 SCE's forecast includes additional funding over 2006 recorded expenses of (1) $742,000 for Work Order Write-Offs, (2) $89,000 for non-capital furniture & equipment, and (3) $29,000 for Vehicle Costs. DRA recommends the Commission adopt SCE's 2006 recorded expense level of $11.062 million. Vehicle Costs are addressed in a separate section of this decision. We address the other matters below.

3.18.3.1. Work Order Write-Offs

Based on SCE's rebuttal testimony, SCE requests 2006 level. DRA agrees. Accordingly, no disputed issues exist regarding this matter.

3.18.3.2. Non-Capital Furniture & Equipment

SCE requests an additional $89,000 for non-capital furniture & equipment.280 SCE recorded 2006 expenses are $10,016.281 SCE claims that this increase is needed due to increased personnel in the Field Accounting Organization.282 DRA recommends the Commission reject this proposed increase. SCE fails to adequately explain the reason for an increase of this relative magnitude. Accordingly, the record fails to contain sufficient evidence to support SCE's request, and SCE's request is denied.283

3.18.4. Service Guarantees - FERC Subaccount 588.900

SCE proposes an additional $514,000 (constant 2006$) for Service Guarantee Credits, which is part of SCE's tariffed continuing Service Guarantee Program. SCE claims it has submitted sufficient evidence to establish a "baseline level of credits" and refers to the 2006 GRC decision to support its request. SCE notes that its request only addresses two of the four elements of SCE's Service Guarantee Program, the Notification of Planned Outage Standard and the Restoration of Service within 24 Hours Standard.284 DRA opposes any ratepayer funding.285 In the past, the Commission has found that SCE's shareholders should pay this amount. The record in this proceeding is insufficient to establish a baseline or to change our previously adopted policy.286 For these reasons, we continue the approach we adopted in the 2006 GRC and assign the liability for missed commitments to shareholders.

3.19. Maintenance of Station Equipment - FERC Account 592

SCE forecasts $13.038 million (constant 2006$) for expenses recorded to FERC Account 592.287 SCE's forecast is an increase of $4.360 million or about 50% over 2006 recorded expenses of $8.678 million.288 DRA's forecast is $9.544 million. SCE's FERC Account 592 includes several subaccounts. DRA disputes SCE's forecasts for subaccounts 592.200 Maintenance of Distribution Circuit Breakers and 592.400 Maintenance of Distribution Substation Equipment.

3.19.1. Maintenance of Distribution Circuit Breakers - FERC Subaccount 592.200

SCE forecasts TY 2009 expenses for subaccount 592.200 to be $3.619 million, which represents a $908,000 increase over the 2006 base year.289 SCE explains that an increase of $511,000 is needed to support maintenance postponed due to resource constraints.290 By resource constraints, SCE is presumably referring to what it describes as unprecedented customer growth and SCE's decision to reprioritize certain maintenance work described in SCE's 2006 GRC. We do not find unprecedented customer growth a sufficient reason to postpone maintenance on circuit breakers. SCE's failure to accurately predict customer growth in its prior GRC does not excuse it from performing importance maintenance work on its distribution system. We find DRA provides convincing evidence that historical expenses are an appropriate methodology for forecasting TY 2009 expenses. We find DRA's estimate of $2.857 million based on a five year average reasonable.291

3.19.2. Maintenance of Station Equipment - FERC Subaccount 592.400

SCE forecasts $7.421 million (constant 2006$) for subaccount 592.400.292 SCE uses this subaccount to record expenses incurred to maintain miscellaneous distribution substation equipment. SCE's forecast is an increase of $3.171 million or 74.61% over 2006 recorded expenses of $4.250 million. DRA recommends the Commission adopt $4.689 million for this subaccount. SCE's forecast includes $2.694 million for Miscellaneous Distribution Substation Maintenance, including repairing Switchrack Lighting, replacing Trench Covers, and Rack Inspection, and $477,000 for Vehicle Costs. Vehicle Costs are addressed in a separate section of this decision. We address the remaining issues below. Generally, however, SCE states maintenance activities recorded to this subaccount were reprioritized, that is, non-labor resources were allocated to higher priority maintenance activities. Higher priority work included, according to SCE, work that implicated reliability and safety issues.293 SCE does not explain the nature of this higher priority work. Nor does SCE offer any evidence to quantify the expenses associated with this reprioritization of work.294

3.19.2.1. Miscellaneous Substation Maintenance Labor Disconnect Repairs

SCE requests an additional $1.078 million (constant 2006$) in labor expenses for disconnect repairs. SCE's forecast for disconnect repairs is based on the existing backlog and the amount of repairs SCE has historically performed.295 DRA argues this amount of increase is excessive and not supported by historical costs.296 SCE fails to offer a sufficient explanation for deferring this maintenance work. Accordingly, we agree with DRA. As a result, we deny SCE's requested increases.

3.19.2.2. Switchrack Lighting

SCE's forecast includes an additional $600,000 over 2006 recorded expenses for repairing and upgrading (transmission) switchrack lighting in its substations. This is in addition to the increase of $400,000 over 2006 recorded expenses SCE seeks in FERC subaccount 570.400 to repair and upgrade its (distribution) switchrack lighting in substations.297 DRA argues that SCE's embedded costs include this activity.298 We agree with SCE regarding the need for this work, but we find the requested amount excessive based on DRA's argument and our finding of unreasonable deferred maintenance. Accordingly, we reduce SCE's request by 50%. We find an additional $300,000 reasonable for TY 2009.

3.19.2.3. Trench Covers

SCE's forecast includes an additional $716,000 for replacing trench covers located in its substations.299 DRA normalized SCE's request of $716,000 over a three year period and forecasted $239,000 for the test year. Consistent with our findings regarding subaccount 570.400, we find that additional work is needed, but we find the requested amount excessive based on DRA's argument and our finding of unreasonable deferred maintenance. Accordingly, we reduce SCE's request by 50%. We find an additional $358,000 reasonable for TY 2009.

3.19.2.4. Steel Structures

SCE's forecast also includes an additional $300,000 for inspecting and repairing steel structures.300 DRA argues SCE's current level of funding is sufficient and recommends the Commission deny this increase. We find the amount excessive based on DRA's analysis of historical trends and our finding of unreasonable deferred maintenance. Accordingly, we find it reasonable to deny the additional amount requested over 2006 recorded expenses.

3.20. Maintenance of Overhead Lines - FERC Account 593

SCE requests a total of $93.243 million (constant 2006$) for TY 2009 in FERC Account 593, which includes $15.706 million for labor and $77.537 million for non-labor. FERC Account 593 records the maintenance cost of overhead distribution lines, including repairs to conductors, cross-arms, switches, equipment brackets, and ground molding. These activities consist of planned and emergency repair of equipment or apparatus. SCE also records in this account expenses for trimming and removing trees and brush. All overhead line maintenance is booked into this account with the exception of storm-related repairs, pole replacements, apparatus repairs, and transformer repairs. In addition, beginning in 2008, SCE is recording into this account expenses relating to the Distribution Inspection & Maintenance Program, developed in collaboration with the Consumer Protection and Safety Division. SCE divides FERC Account 593 into five subaccounts. Some of these subaccounts are discussed below.301

3.20.1. Line Clearing Expenses-Tree Trimming and Removal - FERC Subaccount 593.200

SCE forecasts $39.729 million (constant 2006$) for subaccount 593.200 for line clearing expenses, including both vegetation management (tree trimming and removal) and line clearing around poles.302 SCE's forecast is an increase of $4.556 million over 2006 recorded expenses of $35.173 million. SCE's forecast includes additional funding of (1) $3.971 million for Vegetation Management, (2) $582,000 for Line Clearing, and (3) $3,000 for Vehicle Costs. Vehicle Costs are addressed elsewhere in this decision. SCE claims that it needs the additional funding to cover forecasted contract increases, additional tree removals or trims, and an increase in mid-cycle trims.303

DRA disagrees with all of these proposed increases. Based on historical analysis, DRA recommends that the Commission adopt a TY 2009 forecast of $35.173 million, which is SCE's 2006 recorded expenses. TURN agrees with DRA and also recommends SCE contain tree trimming costs by working towards a system average 2-year trim cycle.304

Regarding the increases associated with vegetation management and line clearing, we find SCE's evidence on the increase in labor and non-labor costs sufficient to justify the proposed increase.305 SCE has raised legitimate concerns regarding the viability of TURN's recommendation regarding using a 2-year trim cycle. Nevertheless, TURN provides sound evidence to support its recommendation. Accordingly, while we are not convinced that SCE's failure rely on such a trim cycle warrants a reduction to its TY 2009 forecast, we direct SCE to research the benefits of the 2-year trim cycle (or similar concept) and provide the Commission with the results of its research in its next GRC.

3.20.2. Overhead Line Maintenance - FERC Subaccount 593.300

FERC subaccount 593.300 records labor and material expenses required for overhead line repairs, whether identified during circuit inspections or as the result of a breakdown. SCE's forecast for subaccount 593.300 is $53.291 million. SCE's recorded 2006 expenses for this subaccount are $37.168 million. DRA proposes a TY forecast of $37.168 million.

DRA excludes most of SCE's incremental requests. DRA argues that funding related to the activities in this account are already embedded in SCE's 2006 recorded expenses and, accordingly, are either not justified or should be normalized over a three-year period. DRA excludes SCE's incremental request for (1) Breakdown/Reactive Maintenance expenses of $1.442 million, (2) Work Order Related expenses of $7.781 million, (3) Line Maintenance expenses of $1.538 million, and (4) Vehicle Costs of $2.275 million. The latter costs are addressed elsewhere in this decision. SCE explains that additional funding is needed because its new Distribution Inspection & Maintenance Program is changing the way SCE performs inspections.

While we find SCE will be performing additional work to implement its new Distribution Inspection & Maintenance Program, we are concerned about the deferral of preventive maintenance, as described by SCE:

"Over the past several years Capital constraints and resource constraints have forced Edison to defer preventive maintenance work, such as planned infrastructure replacement, and at the same time operate existing equipment at higher load levels. This means that SCE is leaving equipment in service longer (age of assets is getting older), while at the same time the amount of stress placed on equipment is increasing. All of these factors support a continuation of the increasing trend for breakdown/reactive maintenance."306

It appears this deferral impacts the requested increases in this subaccount but the evidence submitted by SCE on the extent of the impact of deferred maintenance on its forecast is unclear. Accordingly, we find it reasonable to adopt DRA's recommendation.

3.21. Maintenance of Underground Lines - FERC Account 594

SCE forecasts $18.456 million (constant 2006$) for expenses recorded to FERC Account 594.307 According to DRA, SCE's forecast of $18.456 million is an increase of $4.018 million or about 27% over 2006 recorded expenses of $14.438 million. SCE developed its forecast by using 2006 recorded expenses plus additional expenses for proposed projects and activities. DRA's forecast for SCE's FERC Account 594 is $15.381 million. SCE's FERC Account 594 includes several subaccounts. DRA disputes SCE's forecast for subaccount 594.300 Underground Line Maintenance.

SCE forecasts $18.041 million (constant 2006$) for subaccount 594.300.308 SCE's forecast is an increase of $3.965 million or about 28% over 2006 recorded expenses of $14.076 million. DRA uses SCE's 2006 recorded expenses as a basis for its analysis and forecasts $14.966 million for this subaccount.309 SCE's forecast includes additional funding of $2.670 million for line maintenance to address scheduled/planned maintenance and breakdown/reactive maintenance.310 SCE states that it has based the portion of its forecast that relates to planned maintenance on its new Distribution Inspection & Maintenance Program.311

As we stated previously in this decision, we agree with SCE that, under its new Distribution Inspection & Maintenance Program, it will incur more costs and also perform more comprehensive inspections and repairs. However, DRA's historical analysis shows declining expenditures since 2006. In this instance, we find DRA's analysis convincing. Accordingly, we reject SCE's requested increase of $3.965 million for subaccount 594.300. This subaccount also includes $1.295 million for funding for additional Vehicle Costs. Vehicle Costs are addressed elsewhere in this decision.

3.21.1. Maintenance of Streetlight and Signal System - FERC Subaccount 596.400

SCE's TY 2009 forecast for this subaccount is $7.994 million (constant 2006$).312 Subaccount 596.400 records expenses related to maintaining and repairing streetlight equipment. SCE's recorded 2006 expenses for this subaccount are $5.947 million. DRA proposes a TY forecast of $6.192 million.313 DRA proposes three adjustments to SCE's forecasted TY 2009 expenses: (1) eliminate $1.270 million for vehicles; (2) eliminate $184,000 for increased O&M repairs; and (3) reduce SCE's proposed increase for lamp replacements by $348,000.314 DRA supports its recommendation by citing the slower rate of customer growth, historical trends, and 2006 recorded costs.

SCE's expense forecast starts with its estimate of the total number of repairs that will occur in the test year.315 SCE agrees with DRA that the number of O&M repairs in 2006 was lower than in previous years. According to SCE, lower O&M repairs were a consequence of the fact that SCE performed the highest number of capital fixture replacements for its streetlights. SCE's forecast for 2009 reflects a higher forecast in the total number of streetlights, a higher forecast of streetlight failures, and a significantly lower number of capital fixture replacements.316

Based on the evidence presented, we find DRA's recommendation to eliminate the $184,000 for increased O&M repairs and reduce SCE's proposed increase for lamp replacements by $348,000 convincing. SCE's forecasting methodology fails to adequately take into consideration historical trends. Vehicle Costs of $1.270 million are addressed elsewhere in this decision.

4. Customer Service

4.1. Expenses-Operations Division - FERC Accounts 901-905, 580, 586, 587, and 597

The Customer Service Operations Division is a subset of the Customer Service Business Unit. The O&M expenses for Customer Service Operations Division are recorded in FERC Accounts 901 through 905 and as well as 580, 586, 587, and 597. SCE initially forecasted $210.665 million for TY 2009, an increase of $16.536 million over recorded 2006 levels. According to SCE, the major cause of its increase in O&M over 2006 is customer growth and new programs, partially offset by improved performance. In rebuttal testimony, SCE reduced its forecast by $4.17 million. DRA recommends a forecast of $195.752 million, a $1.622 million increase over recorded 2006.

DRA generally rejects SCE's increase for labor317 and non-labor costs associated with incremental customer growth. DRA argues that recorded costs did not increase despite increased customers and, therefore, forecasted 2009 expenses should not include additional customer growth costs. In response, SCE points out that during these recorded years it implemented 12 productivity initiatives that produced cost savings. SCE explains that its estimates of additional costs for new customers were reduced by productivity savings where such savings could be identified.318 As a result, despite the customer growth, SCE maintained stable recorded costs. Furthermore, SCE states this method has been used and adopted by the Commission in each of the last GRC applications.319 SCE further explains that while SCE reduced its estimated expenses to reflect reduced customer growth,320 every new customer requires installation of a meter, monthly reading of the meter, and other activities such as phone calls, billing and similar services which add to overall expenses.

We find that SCE's methodology is reasonable in adjusting recorded costs to reflect productivity and forecasting the cost effects of additional customer growth. Thus, we adopt SCE's revised estimates as reasonable for those expenses affected by customer growth.321

4.2. Vehicles - FERC Subaccounts 586.100, 586.400, 902.00, 903.00

Vehicle expenses for Customer Service Business Unit are recorded in Accounts 586.100 Turn On and Off Service, 586.400 Test or Inspect Meters, 902.000 Meter Reading, and 903.200 Credit. SCE's 2006 recorded Vehicle expenses are $10.56 million. SCE is requesting an additional $964,000. As discussed in the T&D O&M expense portion of this decision, our adopted Vehicle costs are consistent with DRA's recommendations to reduce SCE's forecast. For Accounts 586.100, 586.400, 902.000 and 903.200, we adopt the same result.

4.3. Community Choice Aggregation - FERC Account 903

Community Choice Aggregators (CCAs) are groups formed by governmental entities to serve the energy requirements of local residents and businesses. In D.04-12-046, we adopted policies to implement a CCA program to facilitate energy procurement activities by cities and counties. DRA and TURN disagree with SCE regarding the reasonable level of CCA expenses in Accounts 903.200 Credit, 903.500 Billing, 903.700 ESP Services and 903.800 CCCO (Phone Center). SCE points out that CCA expenses are offset by CCA service fees which are recorded as Other Operating Revenues.

As an alternative to including forecasted revenues and expenses in results of operations, TURN recommends recording these fees and costs in a memorandum account.322 TURN argues that although limited CCA operations in SCE's service area are likely to begin in 2009,323 the actual level of CCA fees and costs are too speculative to be included in rates and fees at this time.

We believe that TURN's proposal has merit. With the exception of the San Joaquin Valley Power Authority it is uncertain whether other CCAs will even be established within the period covered by this decision. Furthermore, as TURN points out, even the establishment of the San Joaquin Valley Power Authority CCA will take time. Given this uncertainty, and the protection of ratepayer and shareholder interests accomplished through a memorandum account, we will adopt TURN's proposal.

Therefore, we have excluded estimated CCA fees in Account 456, Other Electric Revenues, CCA expenses in Accounts 903.200, 903.500, 903.700 and 903.800, and a portion of CCA capital spending from our adopted results of operations. SCE is directed to place these amounts in the existing CCA memorandum account which will track CCA-related revenues, expenses, and capital spending. This memorandum account was established in D.04-12-046 and is known as the Community Choice Aggregation Implementation Costs Balancing Account (CCAICBA). Balances in this memorandum account shall be reviewed in SCE's annual ERRA reasonableness proceedings, commencing with the first ERRA proceeding after SCE begins recording costs and revenues in the account.

4.4. Rural Related Expenses and Ledgers - FERC Subaccount 903.000

SCE requests 10 new positions for a forecasted amount of $730,000 in its Ledgers Organization, stating that the workload and backlog have increased. DRA reviewed the Ledgers Organization and noted that there has been little change in overall staffing324 or overall expenses (in constant dollars) during the past five years.325 In addition, the five-year average (2002-2006) for this subaccount is $4,748,000.326 In consideration of these factors and as we have provided for SCE's customer growth, as discussed above, we will adopt DRA's estimate with regard to this issue.

4.5. Credit Fraud Staffing and GPS - FERC Subaccount 903.200

SCE requested three additional credit fraud employees and to establish a centralized fraud prevention group. SCE states that the new employees are necessary as new payment options are added to SCE's services, opportunities for credit fraud increase.327 DRA argues that these employees are not necessary as the recorded expenses have not increased despite an increased caseload.328 SCE points out that there may be some confusion with regard to DRA's reference to caseload which actually occurs in a different account.329

In light of new payment options and other activities to be addressed by the additional employees, such as identify theft, we find SCE's request for these employees, and associated non-labor costs, reasonable.

SCE forecasts labor expense savings of $87,000 based on the use of a global positioning satellite project. DRA's estimate, based on using the last recorded year, did not include this saving.330 We will adopt SCE's estimate, which reduces this account by $87,000.

4.6. Service Guarantee Credits - FERC Subaccount 903.500

Service Guarantee Credits provide bill credits to customers when SCE misses an appointment or presents an inaccurate bill.331 SCE requests that the estimated costs of these credits be included as customer service expenses. DRA and TURN disagree and recommend that these costs continue to be paid by shareholders. In D.06-05-016, we determined that costs for reimbursing customers would be paid by shareholders.332 Today, we approve reasonable amounts for expenses for continued administration of this program and we do not change our policy with regard to these credits, which should continue to be paid by shareholders.

TURN also proposes that SCE implement an explicit policy for when a customer's service is disconnected in error and to add erroneous disconnect to SCE's Service Guarantee Program. We find TURN's proposal reasonable and direct SCE to file an advice letter within 90 days to implement a new tariff provision. Similar to the procedure relied upon in D.07-03-044, we direct SCE to arrive at a consensus regarding the language of this rule. While SCE argues that its existing internal company policy is sufficient to address erroneous disconnects,333 we find that a formal tariffed rule is more appropriate to ensure customers are properly noticed of this policy and, similar to our finding in D.07-03-044, ratepayers should not bear the costs of SCE's errors. TURN estimates that its proposal would reduce SCE's forecast by $50,000. We accept TURN's estimate as the reasonable costs for implementing TURN's proposal. Regarding TURN's proposal to increase to credit from $50 to $100, we find the record does not include sufficient evidence to justify this increase.

4.7. Electric Service Provider Services - FERC Subaccount 903.700

DRA agrees with SCE's request to fill vacant positions in the Customer Service Business Unit. However, DRA's estimate is based on recorded 2005 expenses and is $142,000 lower than SCE's estimate of $1.2 million. SCE uses a budget-based approach for its forecast. SCE's 2006 recorded expenses for subaccount 903.700 are $726,000. SCE explains that the lower 2005 recorded expenses are the result of positions which were vacant due to unexpected staff turnover for most of 2005.334 Accepting SCE's explanation for this difference in 2005 and 2006 recorded costs, we adopt SCE's estimate as reasonable.

4.8. Customer Communication Organization - Phone Center - FERC Subaccount 903.800

SCE requests an increase in phone center costs of $1,276,000 to reflect an increase in call volume growth beyond the call volume attributed to new customers. DRA argues that historical recorded costs do not justify an increase since these costs were stable while the number of customers was increasing.

SCE responds that the recorded costs include application of the productivity measures discussed above, in particular the contract call center and the Meter Process Automation initiatives.335 SCE contends these productivity measures will not continue to produce cost savings in 2009. SCE explains that the application of the productivity measures means that the recorded costs are lower than the costs would be without these measures.336

We note that the average call volume increase of 3.4% 337 during the past 5 years exceeds customer growth.338 This indicates that even with past productivity measures, future phone call growth apart from customer growth will necessitate additional phone center costs. Therefore, we will adopt SCE's requested increase. Any amounts related to CCAs should be recorded in the memorandum account.

4.9. Uncollectible Expense - FERC Account 904

Uncollectible expense represents billed but uncollected revenue and is recorded in Account 904. Uncollectible expense is forecasted as that portion of revenues not collected, estimated by SCE as 0.240% using a ten-year average of recorded uncollectible factors (0.239%) plus 0.01% for Other Operating Revenues increases not reflected in these factors. DRA forecasts the uncollectible factor as 0.134% by averaging the factors recorded in the last three years plus the 0.01% recommended by SCE. The 2006 authorized uncollectible factor is 0.225%.

SCE explains that its ten-year average is supported by averages using the past 15 and 20 year periods.339 DRA argues that the uncollectible factor has been declining since 1999 when it was 0.348% and that a 3-year average best forecasts the uncollectible factor.340

Neither SCE nor DRA sufficiently explain the continuous decline in the uncollectible factor. SCE suggests that extraordinary economic influences, including a healthy regional economy, have helped reduce the factor during the past 5 years, and that recent uncollectible expenses have increased by 73% between 2006 and 2007.341 SCE also offers a statistical measure that correlates interest rates, lagged by two years, and the uncollectible factor.342 Using this analysis, SCE would forecast the uncollectible factor as 0.283%.

Despite SCE's arguments for the use of at least a 10-year average, it is apparent from the recorded uncollectible factors from 1999 through 2006 that the factor has been declining.343 There may be reasonable explanations for this decline including increased customer service activities, automatic bill payment, improved customer communications, or other factors. A reasonable forecast of the uncollectible factor should reflect the fact that the uncollectible factor has been declining for the last 7 years.

However, we agree with SCE that the current economic outlook, as indicated by the most recent uncollectible expenses, would support a TY 2009 factor above either 2005 or 2006. SCE notes that a 5-year average (2000-2004) was used in D.07-03-044, the PG&E 2007 GRC.344 As a reasonable forecast we will also use a five-year average of the uncollectible factors during the last five recorded years, 2002-2006, plus 0.01% for Other Operating Revenue. Thus our adopted uncollectible factor is 0.168%.

4.10. Market Research and Communication - FERC Subaccount 905.900

SCE requests an increase of $988,000 for this subaccount over the amount recorded in 2006. This increase includes $500,000 for development of on-line tools, bill inserts and communications informing customers of environmental impacts regarding their cost of energy and $488,000 for planned and unplanned customer outage communications. DRA rejects both of these incremental cost increases and argues these costs are reflected in other FERC accounts, the Public Goods Charges and Demand Response Funding. DRA's forecast is based on 2006 recorded expenses. SCE's recorded 2006 expenses are $5.583 million.

A review of the recorded expenses for subaccount 905.900 shows that the total costs in this subaccount have been increasing and that 2006 was the highest recorded amount in the last 5 years, exceeding 2005 by over 20%.345 Furthermore, as SCE points out, some of the funding is incremental to communications spending in distribution accounts or is intended to provide an enhanced type of outage notice.346 While such improvements may have benefits, we note that communications funds are provided through other cost mechanisms not included in this GRC. Accordingly, we agree with DRA and adopt an expense level for this subaccount based on the highest recorded amount, which is the 2006 recorded expense.

4.11. Policy Adjustments-Miscellaneous - FERC Subaccount 905.300

Subaccount 905.300 records costs associated with adjusting customer bills. DRA, citing a decline in this expense from a high of $1,573,000 in 2004 to $660,000 in 2006, forecasts $660,000 based on the last recorded year. TURN supports this estimate. SCE notes that the recorded amounts for this expense fluctuate with changes in customer sentiment, weather, and other unpredictable factors. On this basis SCE used an average of the last five years of recorded expense.347

Our review of the recorded amounts indicates that there is significant variance in these expenses, such that the recorded amount increased by 200% between 2003 and 2004, and then declined by almost 140% towards 2006.348 According to TURN, the 200% increase is largely the result of a one-time cost resulting from SCE's decision to assign $882,684 in costs related to a downward bill adjustment to subaccount 905.300. In light of this anomaly in cost data included within SCE's proposed forecasting method, we find SCE's forecast unreliable and adopt the last-recorded year of $660,000 as a more reasonable method of forecasting costs for this subaccount.

4.12. Electric Transportation - FERC Subaccount 912.100

Electric Transportation expenses reflect activities related to compliance with certain provisions of the Energy Policy Act, electro-drive system impacts, low-emission and alternative fuel vehicles, and education outreach information on these vehicles.349 For TY 2009, SCE forecasts $12.776 million in subaccount 912.100, an increase of 157% over 2006 recorded expense of $4.976 million. DRA recommends an increase of 59% over 2006 recorded expenses.350 The difference between SCE's and DRA's forecasts is due to DRA's rejection of incremental funding for various SCE-proposed Electric Transportation programs and activities as discussed below.

4.13. Energy Policy Act and Other Compliance

SCE requests an additional $298,000 for three additional employees for compliance workload and an additional $400,000 for a Petroleum Reduction and Education Program (PREP).

DRA rejects both of these increases. DRA notes that the current spending levels for Energy Policy Act compliance have not increased during 2002 - 2006. DRA asserts that PREP is unnecessary as training programs to achieve the same purpose already exist.351 SCE responds that PREP is not duplicative and is necessary to acquire information and meet SCE's obligations under Pub. Util. Code §§ 740.3, 740.8 and 451.352

Our adopted expenses provide the $400,000 for PREP but do not provide for additional employees. We agree with SCE that PREP may reduce overall usage of petroleum products and provide other productivity benefits for ratepayers. However, we note DRA's argument that the number of compliance employees has not varied during the past years,353 and, in this activity, we expect SCE will utilize existing employee levels to achieve its purpose.

4.14. Load Management & Conservation

SCE requests an additional $909,000 for load management and conservation programs. These programs are intended to shift peak load and promote energy conservation by encouraging customers to engage in efficient and safe practices for the operation and charging of electric Low Emission Vehicles.354 These programs include improved load management and electric forklift incentives and additional employees.355 DRA argues that although customers using electric Low Emission Vehicles are required by law to reduce emissions, it is unreasonable for ratepayers to provide financial incentives for customers to obey the law.

We do not adopt SCE's additional Electric Vehicle load management program expenses. In other non-GRC proceedings, including proceedings addressing energy efficiency and demand response, the Commission and parties study various load management issues and develop load management information. Rather than provide separate funding here for vehicle load management studies and planning, we expect SCE will include the effects of potential additions of Electric Vehicles to the system as an input to the overall development of load management and conservation in these other proceedings.

Although DRA agrees with SCE's request for differential costs of replacing non-electric forklifts with electric forklifts and similar electric vehicle replacements, DRA rejects SCE's proposal to provide electric forklift incentives for other customers.356 SCE responds that the intention of the forklift incentives is to change behavior.357 We reject SCE's forklift incentives proposal. We note that SCE supports its own transition to Electric Vehicles, including forklifts, on the basis of the advantages of these vehicles, including reduced petroleum consumption and fuel costs, fewer moving parts, and no oil changes or smog checks.358

4.15. Safety

SCE requests $100,000 to fund certain Electric Vehicle safety studies. DRA argues that such studies should not be funded to assist customers in obeying emission regulations.359 We will provide the additional $100,000 for such studies since, as discussed below, we have not adopted other requested studies for future Plug-in hybrid vehicles (PHEV). We expect that this amount combined with other adopted expenses described below will provide SCE a sufficient amount for expected electric vehicle activities during the 2009 GRC cycle.

4.16. Customer Outreach

SCE proposes additional Electric Transportation outreach efforts through two additional employees ($143,000) and customer and employee safety education programs ($671,000). DRA contends these additional expenses are unnecessary since no PHEVs are commercially available and no evidence exists that a significant numbers of PHEVs will be operational during the 2009 GRC cycle.360 SCE responds that it must anticipate and plan for emerging technologies such as PHEVs.361

Although PHEVs are not yet commercially available, we recognize that some preparation and planning will likely be necessary during the 2009 GRC cycle. Therefore, we approve $407,000 (50% of SCE's request) for purposes of planning for Electric Transportation Customer Outreach.

4.17. System Impact

SCE requests an increase of $2,330,000 over 2006 recorded cost, including $0.8 million to fund PHEV studies to assess environmental and economic impacts of PHEVs and $1.53 million to study and evaluate Vehicle to Grid (V2G) and energy storage.362 DRA argues that these studies are not justified since PHEVs, as noted above, are not commercially available. DRA also argues that ratepayers should not be funding this type of research and that other studies are being conducted on PHEV characteristics by the Department of Energy and as part of the Public Interest Energy Research (PIER) Program. Separate from these studies, however, DRA does recommend funding SCE's request for $0.5 million to test and evaluate truckstop electrification and seaport electrification.

For the reasons stated by DRA, we do not adopt the additional $2.33 million requested by SCE. Specifically, various research projects are being conducted on PHEVs by other entities, and PHEVs are not yet commercially available. In addition, SCE's rates already include research funding through the PIER Program. Furthermore, research of the type proposed by SCE should be conducted on a statewide basis because all utilities will be impacted by PHEVs when these vehicles become more available.

In addition to approving the $500,000 for truckstop and seaport electrification, discussed above, we approve increases for safety planning ($407,000) and electric vehicle safety ($100,000). These amounts provide an increase of over $1,000,000 above the recorded 2006 expenses for studies, planning, and research for PHEVs and other projects in Electric Transportation. We also provide an increase of $400,000 for PREP. When all of these increases, including the amounts previously recommended by DRA, are included in rates, our adopted expenses for Account 912.100 will increase by almost 90% above amounts recorded in 2006. We find this provides a reasonable amount for SCE's Electric Transportation expenses.

4.18. Other Operating Revenues

4.18.1. Community Choice Aggregation - FERC Subaccount 456.412

As discussed in more detail above, we adopt the recommendation of TURN to continue the memorandum account for Community Choice Aggregation revenues and expenses, known as the CCAICBA. Accordingly, we have removed $2,689,000 from forecasted Other Operating Revenues, which represents the estimated amount of revenues attributable to CCA fees in TY 2009.

4.18.2. Residential Late Payment Charge - FERC Account 450

SCE's TY 2009 forecast for residential late payment charges is $10,170,000 based on applying a two-year (2005-2006) average ratio of late payment charges multiplied by the amount of non-CARE electric revenues. TURN forecasts late payment charge revenues of $10,433,000 using a three-year average (2005-2007) ratio and increases the base residential revenues by $105,000,000 to reflect SCE's recent TY 2009 rate design application, A.08-03-002, in phase II of this GRC process. TURN then multiplies the increased revenues by TURN's 3-year average ratio. We find the later information provided by TURN and the longer period TURN recommends more accurately forecasts late payment charge revenues. Accordingly, we adopt TURN's estimate of $10,433,000 for the residential late payment charge in TY 2009.

4.18.3. Field Assignment Charge - FERC Subaccount 451.600

SCE forecasts Other Operating Revenues from the Field Assignment Charge (FAC)363 at $8,352,000. SCE's forecast is based on increasing the FAC service fee to $20.00 from the current $13.75 service fee adopted in SCE's 2006 GRC. DRA and TURN object to this increase and recommend that the FAC service fee remain at the current $13.75. DRA and TURN state that the cost to perform a field assignment decreased from $21.30 in 2003 to $19.74 in 2006.364 They contend that increasing the FAC service fee will make it more difficult for late-paying customers to pay their bills and increase the likelihood of incurring disconnections for these customers. TURN indicates that a slightly higher reconnection charge would be a better way to recover some of the increased costs related to the FAC. SCE argues that increasing the FAC service fee is fair to other ratepayers and reflects the cost-of-service basis for the FAC service charge.365

DRA and TURN's arguments are reasonable if we were to only consider the policy of the FAC. However, we must also recognize that the cost of the FAC has increased by about 30% from the $13.75 service charge adopted in 2006.366 As an alternative, we will adopt a FAC service fee of $17.00. This amount, although less than the $19.74 cost-of- service, will increase the FAC service fee by approximately 24% and is a reasonable balance between the cost of this service, the potential for increasing service disconnections, and the ability of late-paying customers to pay their bills.

4.18.4. Joint Pole Attachment Fees - FERC Account 454.500

SCE agrees with TURN's proposal to maintain the amount of revenue from joint pole attachment fees at current rates. SCE also agrees to update the pole attachment charge when new rates from SCE's negotiations with telecommunications providers are available.367 Accordingly, as agreed to by SCE, we direct SCE to update the joint pole OOR and the resulting GRC revenue requirement in an advice letter filing in compliance with this decision or, if the new rates are not yet known at the time of this compliance filing, in the annual PTYR advice letter.

4.19. Tariff Rule 17-D Adjustment of Bill for Billing Errors

TURN proposes a modification to SCE's Tariff Rule 17-D to conform the rule to Resolution G-3372 and D.05-09-046. TURN notes that PG&E, SDG&E, and Southern California Gas Company have all update their tariffs to conform with Commission decisions. SCE indicates that, while it views such changes as unnecessary, it will make them if the Commission directs SCE to do so. Accordingly, we direct SCE to file an advice letter within 90 days of the issuance of this decision to conform Rule 17-D to Resolution G-3372 and D.05-09-046 in a manner similar to the above-identified utilities.

5. Information Technology Expenses-Computing Services

5.1. Information Technology Expenses-Computing Services - Outside Services - FERC Account 923

SCE initially estimated 2009 expenses for this account of $19.496 million (non-labor). SCE subsequently reduced its estimate to $18.996 million to correct an error in its calculation. Expense forecasts for 2007, 2008 and 2009 are based on 2006 recorded costs with adjustments for supplemental labor, software maintenance, etc.368

DRA recommends a TY 2009 forecast for this account of $14.086 million based on a linear trend using 2003-2006 recorded expenses. DRA explains that its forecast is superior to SCE's because the recorded costs from 2003-2006 show the most consistent trend and SCE's forecast contains inconsistencies.369

SCE has corrected its calculation error. Its detailed explanation of its forecast starting with 2006 recorded expenditures is reasonable, and we find that forecast superior to DRA's forecast based on a linear trend because we consider SCE's most recent experience with this category of expenses to be more reliable than data going back to 2003.

5.2. Information Technology Expenses-Computing Services - Salaries, Office Supplies, and Expenses - FERC Accounts 920/921

SCE estimates 2009 expenses for this account of $23.383 million ($12.045 million labor and $11.338 million non-labor).370 Included in SCE's estimates are expenses related to relocation of its data center. DRA estimates 2009 expenses for this account of $21.993 million.371

DRA proposes removal of the 20% contingency of $0.09 million ($0.050 million labor and $0.040 million non-labor) included in SCE's estimate (related to data center relocation). DRA argues the forecast should account for any possible uncertainties in the estimate, a contingency is not necessary, and the estimate includes a sizable increase over 2006 recorded figures.372

SCE argues that its contingency is consistent with other major projects of the same size and complexity.373

Inclusion of a contingency in a project cost estimate for budgeting purposes is normal. However, there is a difference between setting a budget for a project and estimating what it will likely cost. According to SCE, "best practices state that estimates should include a contingency to cover unforeseen factors that may arise as the project progresses."374 The key words "may arise" means that it is uncertain whether all of the contingency will be needed. Therefore, we adopt half of the contingency and reduce SCE's estimate by $0.045 million ($0.025 million labor and $0.020 million non-labor).

DRA also proposes a reduction of 13 positions ($1.3 million) because SCE transferred 13 positions from Computing Services to other information technology divisions in 2007.375 SCE claims that these positions were transferred to another part of its organization due to a reorganization, and that they still perform the same functions.376 SCE's explanation is reasonable and DRA's reduction is not adopted.

Overall the Commission adopts a reduction from SCE's estimate of $0.045 million ($0.025 million labor and $0.020 million non-labor) for the reasons discussed above. The resulting adopted expenses are $23.338 million ($12.020 million labor and $11.318 million non-labor).

5.3. Information Technology Expenses -NERC Critical Infrastructure Protection

The purpose of these activities is to ensure compliance with the standards mandated by the North American Electric Reliability Corporation (NERC) relating to critical cyber assets and Critical Infrastructure Protection (CIP).377 SCE requests $1.978 million ($1.404 million labor and $0.574 million non-labor) in expenses in FERC Account 920/921 (Salaries, Office supplies and Expenses).378

DRA states that SCE planned to start this effort in 2007 by hiring 14 Full-Time Equivalent positions (FTEs). However, only six FTEs were actually filled. Therefore, DRA recommends funding only the six filled positions for a reduction of $0.920 million (labor) for the test year.379 SCE states that while it only filled six FTEs because it was unable to find sufficient new hires soon enough, it hired 11 contract employees whose costs were recorded in Account 923 (Outside Services).380

SCE and DRA agree on the need for personnel to do this work, and DRA's only dispute is that the positions were not filled. Since SCE did use 17 personnel including contractors to do this work, the positions are needed and will be filled. Therefore, SCE's estimate is reasonable and is adopted.

5.4. Information Technology Expenses -New Technology Evaluation

SCE projects a need for six senior technology analysts at $1.2 million ($0.78 million for labor and $0.42 million non-labor) (constant 2006$) in FERC Account 920/921 (Salaries, Office Supplies and Expenses).381 The purpose of these positions is to evaluate relevant emerging technologies where the capabilities or underlying architecture are dramatically different from those currently in use. SCE states that the technologies will require long-term, hands-on, and in-depth evaluation and planning. SCE says this type of evaluation is different from short planning horizon evaluations currently being done or research and development work.382 SCE also projects a need for $0.5 million (non-labor) in FERC Account 923 (Outside Services) for contractor and consultant services to assist in the evaluations.383

DRA states that the exact nature of the technologies is unknown and the potential benefits are unknown. Additionally, some of this work is being done by other personnel. Therefore, DRA recommends that two positions be funded at a cost of $0.26 million384 for labor and $0.21 million for non-labor in FERC Account 920/921.385 For the same reasons, DRA recommends a reduction of $0.25 million in FERC Account 923.386

There is no dispute between SCE and DRA as to the need for additional positions. Since these would be new positions with no history, a cautious approach is reasonable and funding will be reduced by half. Funding equivalent to three positions at $0.6 million ($0.390 million labor and $0.21 million non-labor) in FERC Accounts 920/921 and $0.25 million (non-labor) in FERC Account 923 is adopted.

6. Administrative & General Expenses

6.1. Total Compensation Study

A total compensation study compares the utility's total compensation - salaries, short- and long-term incentives, and benefits - to the relevant market.387 SCE claims the "Total Compensation Study unequivocally demonstrates the reasonableness of SCE's per-employee compensation."388 SCE argues that, because the Study demonstrates reasonableness, ratepayers must bear the total costs. SCE makes assumptions based on the conclusions of the Study. These assumptions, however, are not addressed by the Study. The Study addresses the narrow issue of whether SCE's compensation is consistent with other similar companies. To clarify, the Study does not address the issue of whether SCE's compensation is "reasonable" or who should bear the costs of this total compensation, e.g., shareholders or ratepayers. The Study never purports to present information from similar companies regarding who bears the cost of employee compensation and makes no finding on this matter relative to SCE.

6.2. Results Sharing - Short Term Incentives for Non-Executives - FERC Accounts 500, 588, 905 and 920/921

Results Sharing is SCE's short-term (annual) incentive compensation program, under which eligible employees, including represented employees, can earn pay based on their job performance and SCE's performance on pre-established goals.389 About 99% of SCE's workforce earned a Results Sharing payout in 2006.

SCE forecasts Results Sharing expenses of $106,413,000 (constant 2006$) for TY 2009. Costs are recorded in Accounts 500, 588, 905, and 920/921.390 SCE's 2006 recorded expenses are $91,293,000. SCE explains the $15.1 million increase is due to the significant increase in anticipated labor costs.391 DRA recommends no funding for SCE's Results Sharing and other incentive compensation programs. In the alternative, DRA recommends ratepayer funding be limited to a 5-year average of the historical payout, $86.2 million, or the 2006 base year recorded costs of $91.3 million.392 TURN recommends either 50/50 sharing of Results Sharing Program costs between ratepayers and shareholders or, alternatively, continuing the mechanism the Commission adopted in SCE's 2006 GRC393 which provides full funding for incentives along with a one-way balancing account to refund money to ratepayers if the target amount is not met.394

The Commission recently investigated certain problems with SCE's Results Sharing Program. On June 15, 2006, the Commission opened an investigation into the alleged manipulation of data used by SCE to calculate revenues and rewards under its Performance Based Ratemaking. On September 18, 2008, the Commission adopted D.08-09-038 which, among other things, ordered SCE to refund to ratepayers that portion of the revenue requirement for Results Sharing attributed to Performance Based Ratemaking data.395 The Commission summarized its findings as follows:

"This decision concludes that Southern California Edison Company (SCE) employees and management manipulated and submitted false customer satisfaction data, and the data was used to determine Performance Based Ratemaking (PBR) customer satisfaction rewards for a period of seven years. Therefore, SCE is ordered to refund to its ratepayers all $28 million in PBR customer satisfaction rewards it has received and forgo an additional $20 million in rewards that it has requested. The decision also finds that SCE submitted false and misleading health and safety data, and the data was used to determine PBR health and safety rewards for a period of seven years. Therefore, SCE is ordered to refund to its ratepayers all $20 million in PBR health and safety rewards it has received and forgo an additional $15 million in rewards that it has requested. The decision further concludes that SCE should refund the portion of its 2003 to 2005 revenue requirement related to the utility's Results Sharing program that was affected by fraudulent data, which the decision finds to be $32,714,000. Finally, the decision orders SCE to pay a fine of $30 million for violations of the Public Utilities Code."

In this proceeding, SCE reminds us that it extensively redesigned the Results Sharing program in 2006.396

We reject SCE's methodology for forecasting costs for the Results Sharing Program. Based on the evidence presented in this proceeding and the Commission's findings in D.08-09-038, we remain concerned about employee incentive compensation proposals, such as the Results Sharing Program, that provide shareholder value without imposing shareholder costs.397 DRA raises significant concerns about the success of SCE's efforts to redesign this program. We have no data to support funding this program, as redesigned, and to ensure that the redesign successfully addresses the known deficiencies identified in the 2006 GRC and in D.08-09-038. Therefore, it is reasonable to reduce SCE's forecast by 50% for TY 2009, consistent with TURN's recommendation. In addition, consistent with our decision in the 2006 GRC, we will continue to require SCE to rely on a one-way balancing account for the Results Sharing Program.398 This account is known as the Results Sharing Memorandum Account (RSMA). When actual Results Sharing payouts for 2009, 2010, or 2011 are determined, any shortfall in the payment to employees when compared to the authorized amount for that particular year should be credited to the Authorized Base Revenue Requirement Balancing Account.

6.3. Spot Bonus and Awards to Celebrate Excellence Programs - FERC Accounts 566.200, 566.300, 580.100, 588.300, 588, and 920/921

In SCE's opening brief, SCE states it estimated $4.25 million in 2009 for its Spot Bonus and Awards to Celebrate Excellence Programs.399 For 2006, spot bonus costs were 0.3 % of SCE's payroll dollars, amounting to $3.28 million.400 Spot bonuses were excluded from the Total Compensation Study because unavailability of data and wide variances exist in the marketplace. For these reasons, DRA and SCE agreed that spot bonuses would not be included in the Total Compensation Study for this GRC.401 Costs associated with Spot Bonuses are embedded in the labor and expense forecasts of individual business units and departments.402

This estimate presumably does not include costs associated with the Awards to Celebrate Excellence program but the exact amount is not provided. SCE claims in rebuttal testimony that:

"SCE's historical and forecast expenses for Spot Bonus Programs are summarized in Vol. 2 of Exhibit SCE-06, pp. 26-28 but embedded in the labor and expense forecasts of individual business units and departments. SCE's historical and forecast expenses for the ACE program are included in the miscellaneous benefits section of Vol. 2 of Exhibit SCE-06, pp. 28, 84, 86." 403

We found no separate forecasts for TY 2009 in SCE's testimony for the Awards to Celebrate Excellence and the Spot Bonus Programs. SCE provided an aggregate figure of $4.25 million but did not adequately explain its methodology for arriving at this combined amount. Therefore, while SCE claims it addressed the issues regarding tracking of these amounts that we raised in our 2006 GRC decision, we disagree based on the absence of evidence. SCE's failure to provide a specific forecast for either of these programs refutes any claim by SCE that accounting concerns have been resolved and that ratepayer interest is served by the amounts awarded under these programs. DRA opposes the entire amount requested. For the reasons stated herein, we do not find reasonable SCE's request to include amounts associated with Spot Bonus or Awards to Celebrate Excellence programs in TY 2009 revenue requirement.

6.4. Executive Compensation - FERC Accounts 920/921 and 923

SCE compensates its executive officers with cash compensation, including base salaries, annual bonuses, associated expenses, and short and long-term incentives.404 SCE is requesting $24.588 million405 for executive base salaries, related expenses, and short-term bonuses, while SCE's 2006 recorded total is $21.208 million.406 SCE is also requesting $23.304 million407 for related expenses, annual bonuses, and long-term incentives. This latter amount, $23.304 million for related expenses, annual bonuses, and long-term incentives, has not previously been included in SCE's revenue requirement. Greenlining, TURN, and DRA recommend adjustments to SCE's requests.

We reject SCE's request to include $23.304 million in long-term incentives in its 2009 TY forecast.408 As DRA and TURN note, these incentives have not been included in rates in the past and are closely tied to stock performance of the parent company, Edison International, and, therefore, to non-utility activities. We continue the Commission's existing policy of excluding these amounts from revenue requirement.

Regarding SCE's request for $24.588 million for executive base salaries, related expenses, and short-term bonuses, we agree with TURN and DRA that it is premature to include in the TY 2009 forecast an additional officer to implement the SmartConnect program. SCE has not shown that SmartConnect will occur in TY 2009. Accordingly, it is reasonable to reduce SCE's forecast by one officer. In the absence of specific information regarding officer salaries, we reduce SCE's estimate of $24.588 million by $664,540.409

In addition, regarding executive short-term incentives, SCE fails to specify the amount for such incentives included in its TY 2009 forecast of $24.588 million ($23.186 million plus $1.402 million for related expenses) for executive compensation. DRA opposes all incentives, including short-term incentives.

Given the lack of information regarding the short-term incentive component within executive compensation in SCE's testimony, we reduce SCE's TY 2009 forecast by 50% or $11.961.410 This estimate is as accurate as possible based on the evidence presented by SCE regarding the components of executive compensation.

6.5. Board of Directors and Corporate Governance - FERC Account 930.2

Corporate Governance activities recorded in FERC Account 930.2 (Corporate Governance and Miscellaneous) include fees and expenses paid to members of SCE's Board of Directors, expenses associated with the SCE's Annual Shareholder Meetings, contract services, and other proxy-solicitation fees, as well as costs related to filing requirements of the SEC.411 The labor component of this account refers to the charges made by SCE's various employees for their time spent providing assistance during annual shareholders' meetings. SCE classifies all other expenses, including directors' annual retainer fees, fees for annual meeting attendance, and non-equity compensation, as non-labor. SCE uses 2006 recorded expenses plus a future-year adjustment to forecast overall FERC Account 930.2 (Corporate Governance and Miscellaneous) expenses for TY 2009.412 SCE's method yields a total forecast of $4.752 million, roughly a 16% increase over its 2006 expenses of $4.108 million.413

In support of its requested increase, SCE states only that the additional costs result from the "increasing frequency of corporate reporting required of Corporate Governance and oversight by the Board of Directors in response to increased corporate compliance requirements, public scrutiny, and frequent adoption of new and revised laws, regulations, and rules."414 TURN recommends the Commission deny all of SCE's requested increase over 2006 base year Account 930.2 expenses for Corporate Governance. In addition, TURN recommends removing $0.884 million from 2006 recorded base year directors' compensation to remove stock-based compensation. TURN argues these requests are unsubstantiated and not adequately tied to ratepayer benefits. We agree. After these reductions, we find reasonable an overall forecast for FERC Account 930.2 (Corporate Governance and Miscellaneous) of $3.224 million.

6.6. Human Resources Department Expenses - FERC Accounts 920, 921, 923, and 926

SCE's HR Department consists of seven "operating functions": Total Compensation, HR Service Center, Talent Management, HR Client Services, Labor Relations, HR Administration, and Equal Opportunity. The expenses associated with the HR Department are recorded in FERC Accounts 920/921, 923, and 926. SCE forecasts a total of $69.106 million (constant 2006$) for combined HR Department and executive officer activities for TY 2009.415 SCE's 2006 recorded expenses are $60.867 million. In support of its request for increases above 2006 base year, SCE explains "SCE faces many concurrent challenges. A massive need for infrastructure replacement, growth in our customer base, transmission system expansion, an aging workforce, major technology initiatives all of which require a strategic alignment of our people with our business direction."416 SCE also states in reference to one of the specific function areas of the HR Department, Talent Management, "SCE's aging infrastructure requires increased staffing levels as we seek to maintain quality electric service for our customers. The impact of both retirement and attrition and the increasing workload in TDBU impact Talent Management directly."417 SCE's forecasts for three of the operating functions of the HR Department are disputed. We address them below.

6.6.1. Talent Management - FERC Accounts 920/921

In FERC Accounts 920/921, SCE relies on budget-based forecasting to propose a TY 2009 forecast of $17.668 million (constant 2006$) for Talent Management.418 SCE's forecast is an increase of $4.806 million over 2006 recorded costs of $12.862 million.419

DRA recommends a $4.651 million reduction to SCE's forecast for TY 2009 and presents a forecast of $13.017 million. DRA notes SCE has already increased its spending for Talent Management by 81% from 2002 to 2006. DRA also relies on our 2006 GRC decision ordering sharing of certain Talent Management program expenses between ratepayers and shareholders.420 TURN recommends reducing SCE's forecast for Talent Management expenses by $3,428,000 to adjust for declining productivity (total new employee hires per Talent Management staff has decreased since 2002) and the lack of a discernable trend between the increase in SCE's TY 2009 forecast and the relatively constant expenses recorded for 2006 and forecasted in 2007-2008.421 In response, SCE states that its increased costs are related to increased hiring and that its Leadership Programs are legitimate costs of service and should be fully funded by ratepayers.

In the 2006 GRC, the Commission adjusted SCE's forecast and disallowed 50% of the additional money requested for SCE's Leadership Programs.422 We find no evidence in the record to support changing this policy. As such, SCE's forecast is reduced by $1.644 million (50% of $2.979 million plus 50% of $310,000). In addition, SCE relies upon its hiring forecast to justify the increases over 2006 base level.423 Based on the arguments presented by TURN and DRA regarding the increases in these accounts for years 2002-2008, we find the 2006 base level of $12.862 million plus $1.644 million for SCE's Leadership Programs, sufficient to cover SCE's projected expenses for Talent Management. The result is $14.506 million.

6.6.2. Outside Services - Total Compensation - Client Services - FERC Account 923

Regarding FERC Account 923, SCE uses a three-year average (2004-2006) of expenses to calculate its TY 2009 forecast of $844,000 for outside services of Total Compensation.424 TURN suggests SCE's straight, three-year average is inflated because it includes one-time expenses for consultants related to the Fair Labor Standards Act 2004 amendment and fails to account for the periodic nature of much of the remainder of SCE's recorded, outside services expenses concentrated in 2004 and 2005. TURN recommends a $354,000 reduction to SCE's forecast, which results in a TY 2009 forecast of $490,000. In response SCE points out it expects to incur future expenses during 2009-2011 related to continued implementation of the revisions to the Fair Labor Standards Act. Based on SCE's projected need of additional resources, we adopt SCE's forecast.

6.6.3. Client Services - FERC Account 923

TURN recommends a $99,000 reduction to SCE's TY forecast for FERC Account 923 related to the one-time cost of $494,000 for responding to union organizing in 2004. SCE includes the $494,000 expenses and relies on a five-year average of historical costs for forecasting TY 2009 expenses of $263,000. SCE concedes this expense is a one-time cost, stating "the need to resist organizing drives may not be ever present,"425 but also states it expects to experience future union-sponsored organizing drives. SCE does not explain the level of expenses it would expect to incur. In the absence of adequate information to predict future costs, we find that SCE's historical analysis should be revised to remove this one-time expense. According to TURN, the exclusion of $494,000 from 2004 expenses yields a five-year average forecast of $164,000.426 We adopt this figure.

6.7. Pension and Benefits - FERC Account 926

SCE is forecasting $52.947 million (nominal $) for TY 2009 pension costs. Pension costs are currently subject to a two-way balancing account. DRA recommends no funding for TY 2009 because SCE's legally-required minimum contribution for 2009 is zero. SCE does not dispute the fact that its legally required minimum contribution for 2009 is zero. SCE explains that the Pension Protection Act of 2006 (PPA) made changes to pension plan minimum funding requirements and to the rules for determining annual maximum tax deductible contributions. SCE further explains the drawbacks to only planning for a minimum contribution, stating:

"Replacement of SCE's long-standing pension funding and rate recovery policy with PPA minimum contributions would likely reduce or eliminate plan contributions in the short run. But, total long term contributions would significantly increase because PPA minimum funding would reduce both trust fund value and the investment earnings for the trust fund that help to pay the long-term costs of the plan." 427

In this GRC, SCE also proposes that the Commission continue using the two-way balancing account for pension costs adopted in the 2006 GRC decision.428 DRA supports the continuation of the balancing account. Under this procedure, the difference between 2006-2008 authorized amounts vs. actual pension contributions under the existing funding policy will be amortized beginning in 2009, and the difference between authorized and actual 2009-2011 pension costs will be amortized beginning in 2012. Annual amortization may be appropriate in certain circumstances and SCE may file an advice letter seeking this process. Any accumulated balances receive interest at the commercial paper rate, consistent with treatment of interest accruals for other SCE balancing accounts.

In the past, we have adopted SCE's forecast if a substantial difference exists between the minimum contribution and its forecast. We decline to follow this reasoning here as it provides SCE with an incentive to overestimate its 2009 contribution. The historical information indicates that SCE estimates exceed actual contributions. We adopt $26.473 million for TY 2009 (nominal $) as this figure falls at the mid-point between the legally required minimum contributions and SCE's forecast. We also continue balancing account treatment of this amount.

6.7.1. Medical Program

SCE forecasts medical program costs of $115.921 million (nominal $) for TY 2009.429 SCE projected the revenue requirement for 2009 by applying a 10% escalation to 2006 recorded costs for 2007 and 2009.430 SCE arrived at the 10% escalation by evaluating numerous factors influencing medical costs for its covered population,431 analyzing multiple surveys forecasting medical cost trends,432 and reviewing underwriting projections from its medical plans.433 The forecast related to escalation charges is approximately $5.9 million.434

DRA recommends lower escalation rates for 2007 and 2009. It suggests that 7.30% and 7% are supported by the U.S. Bureau of Labor Statistics and from Towers Perrin.435 DRA recommends a TY 2009 forecast of $96.034 million, which is $19.893 million less than SCE's forecast.

We agree with SCE's forecasting methodology but, because SCE's forecasted medical expenses are such a significant amount, we adopt a two-way balancing account to protect ratepayers from any overestimating of this amount. This balancing account will function in the same manner as the balancing account applied to PBOPs. SCE is directed to file a Tier 2 Advice Letter implementing this medical expenses balancing account, which will also include dental and vision expenses, within 30 days of the issuance of this decision. In addition, the adopted forecast for these programs will be adjusted to account for labor changes adopted in other sections of this decision.

6.7.2. Disability Programs

SCE projects expenses of $23.658 million (nominal $) for disability programs for TY 2009.436 This includes projected costs for short-term and long-term pay replacement benefits through the Comprehensive Disability Plan and the Long-Term Disability Plan and assistance to help employees with work restrictions find alternative or modified employment through the Return to Work Program.437 SCE forecast its TY 2009 costs by multiplying the projected number of eligible employees by the projected per-eligible-employee cost. SCE derived the projected number of eligible employees by dividing the forecast labor cost for 2009 (expressed in 2006 dollars) by the 2006 average per-employee labor cost.438

DRA asserts that SCE should eliminate its Comprehensive Disability Plan, $4.058 million, and instead simply utilize the State Disability Program.

Based on SCE's assertion that its plans are more cost effective, provide greater protections to employees, and return employees back to work more rapidly,439 we adopt SCE's forecast and reject DRA's recommendation that SCE rely on the State Disability Program. In addition, the adopted forecast for these programs will be adjusted to account for labor changes adopted in other sections of this decision. We also address escalation rates for PTYR in a separate section of this decision.

6.7.3. Miscellaneous Benefit Programs

SCE forecasts 2009 expenses of $7.705 million (nominal $) for Miscellaneous Benefit Programs.440 SCE's 2006 recorded expenses are $6,129,718. SCE's Miscellaneous Benefit Programs include Electric Service Reimbursement, Awards to Celebrate Excellence, Corporate Relocation, Commuter Programs, Educational Reimbursement, Severance Benefits, and Work Life Balance Assistance.

DRA recommends the exclusion of costs for Awards to Celebrate Excellence and the following programs: Health Resources, Work Life Initiatives, and Environmental Affairs - Management Information Systems. In support of these costs, SCE claims these programs provide benefits to SCE's customers and are a normal cost of service. SCE uses the same forecast methodology as used for its Disability Program. SCE explains that program costs were forecasted by multiplying the projected number of eligible employees by the projected per-eligible-employee composite cost. The projected number of eligible employees was derived by dividing the forecast labor cost for 2009 (expressed in 2006 dollars) by the 2006 average per-employee labor cost. Projected per-eligible-employee costs for these programs were assumed to increase at the non-labor escalation rate through 2009 as developed in SCE's testimony.441

We find that SCE's request for costs associated with some of these programs is reasonable. They provide benefits to ratepayers in the form of reduced medical costs or are appropriate costs for SCE's Commuter Programs. However, we addressed Awards to Celebrate Excellence in a separate section of this decision and deny all such costs. We extend this ruling to the $896,000 included for Awards to Celebrate Excellence under Miscellaneous Benefits in FERC Account 926.442 Because it is unclear from the record in this proceeding, SCE is directed to explain in its next GRC why it records amounts for Awards to Celebrate Excellence under Miscellaneous Benefit Programs in FERC Account 926.

In addition, the adopted forecast for these programs will be adjusted to account for labor changes adopted in other sections of this decision.

6.7.4. Executive Pension and Benefits

SCE forecasts 2009 expenses of $23.954 million (nominal $) for Executive Benefits.443 These Executive Benefits encompass the Executive Retirement Plan that supplements the SCE Retirement Plan, a survivor benefit plan, and other benefits of such negligible costs that SCE does not included such "other benefits" costs in its forecast.444 DRA opposes the inclusion of any of these Executive Benefits for TY 2009.445 SCE supports its request based on the Total Compensation Study. As we have indicated elsewhere in this decision, the scope of the Total Compensation Study does not support SCE's position here. Also, because these Executive Benefits are largely tied to the amount of compensation awarded the executive, we find including 50% of this forecast in rates reasonable after reducing the total amount by one officer. See the discussion above regarding Executive Compensation.

6.7.5. Executive Benefits Retirement Severance Benefits of Top Executives-FERC Accounts 920/921

SCE explains that, if an executive is involuntarily severed not for cause, SCE offers the executive an enhanced retirement severance benefit equal to the added value of one additional year of age and service in the formula used by the Executive Retirement Plan for calculating executive retirement benefits. SCE further explains that senior officers who lose their positions in connection with a change in control of Edison International receive not one, but two additional years of age and service (three for CEOs) in the formula. In addition, severed executives with four or fewer years of service become fully vested in the Executive Retirement Plan.446

In connection with these enhanced retirement severance benefits, SCE now responds to the directive in D.06-05-016, to provide information on the present and future "market value" of the retirement severance benefits of its top executives. In Exhibit SCE-6B, pp. 86-87, Exhibit SCE-51 and Exhibit SCE-51WP, SCE provides actuarial present value calculations using hypothetical severance dates. In Exhibit SCE-51, SCE also explains its view that no market exists for the additional age and service credits in SCE's Executive Retirement Plan that comprise the retirement severance benefit, and no apparent way exists to accurately determine the future "market value" of these additional credits. Accordingly, SCE requests that the valuation requirement regarding SCE's executive retirement severance benefits be clarified to pertain only to, and be satisfied by, actuarial present value calculations using hypothetical severance dates.

In response to SCE's request, we find SCE's additional information satisfactorily responds to our direction in D.06-05-016. This finding has no ratemaking impact.

6.8. Four Corners Pension and Benefits & Participant Credits and Capitalized Pension and Benefit Expense - FERC Accounts 925 and 926

TURN proposes that we use APS's 2009 Four Corners budget forecast (which is part of APS's Long Range Forecast for the period 2009-2017).447 In a separate section of this decision, we reject the same proposal by TURN when addressing O&M issues related to Four Corners. Consistent with our decision to reject SCE's request for 50 additional employees at Four Corners, we reduce SCE's Four Corners' Pension and Benefits forecast by the appropriate amounts.

Pensions and benefits must be divided between expense and capital labor.448 As SCE explains, the amount of capitalized pensions and benefits "is recorded as a credit to Account 926.900 (Employee P&B Transferred) and a debit to Account 107 (Construction Work In Progress) and ultimately included in Plant in Service."449 SCE forecasts total costs in Accounts 925 and 926 of $451,597,000 in 2009, of which $149,930,000 will be capitalized, leaving $301,665,000 in expenses in those accounts.450

TURN recommends that SCE's calculation of capitalized P&B be modified to exclude pensions and benefits associated with labor as below-the-line expenditures, rather capitalizing or expensing these costs.451 TURN originally recommended a reduction of $2.161 million in Capitalized Pensions & Benefits.452 SCE accepted the principle suggested by TURN that a portion of pensions and benefits costs should be disallowed based on labor costs assigned to Account 426 (below-the-line), but SCE produces a different estimate of the effect on revenue requirements than TURN's estimate.453 TURN accepts SCE's revised estimate of the treatment of capitalized and disallowed pensions and benefits.454 TURN's position is that the Commission should adopt TURN's proposal to assign Pension and Benefit costs to the labor costs that SCE records below-the-line by using a rate of .54% applied to the ultimately adopted Accounts 925 and 926 amounts.455 The parties appear to be in agreement on these matters. We find their agreed to positions reasonable and adopt them.

6.9. Law Department Salaries and Related Expenses - FERC Accounts 920/921

For In-House Salaries and related expenses, SCE forecasts $26.278 million (constant 2006$) for TY 2009. According to DRA, this represents an overall increase of 15.9% over 2006 adjusted recorded costs of $22.676 million.456 SCE calculated its Law Department In-House labor as $21.3 million using the 2006 recorded labor expenses with an incremental adjustment of $2.5 million. This incremental increase for labor is for 31 Full-Time Equivalent employee positions (10 attorneys, 5 Legal Aides, 4 Case Administrators, 11 Office Staff, and 1 Librarian).457 SCE's Law Department forecasts its non-labor costs using a five-year average ratio of labor to non-labor. The five-year average, 23.26%,458 is applied to the labor forecast for 2007, 2008 and 2009. SCE's non-labor forecast for TY 2009 was $4.952 million.459

DRA recommends reducing SCE's forecast by $3.088 million to eliminate the labor, and nearly all of the non-labor, for the 31 incremental Law Department Full-Time Equivalent employees included in the forecast.460 We agree.

SCE has failed to support its need for additional amounts beyond the 2006 base year for its Law Department. Based on historical trends, we find no further increase is warranted beyond the 2006 base year amount of $22.676 million (constant 2006$). The incremental work identified by SCE to justify the additional amounts beyond 2006 base year is included in embedded costs. SCE argues that, at a minimum, the incremental expenses attributed to filling vacant positions as of year-end 2006 or to meet Law's technology demands should not be removed from SCE's forecast. 461 However, SCE provides no evidence on the costs associated with filling these vacant positions. Therefore, SCE's request for additional amounts is denied.

We reject DRA's suggestion that a timekeeping system is needed to support any increased expenses by the Law Department. Regarding the timekeeping system, SCE's Hildebrandt International Study concluded that "the substantial expenses and diversion of resources associated with implementing and operating an attorney timekeeping system should not be imposed upon SCE and its customers."462 We agree. Accordingly, we will not require SCE to implement the type of attorney timekeeping system recommended by DRA.

6.10. Outside Counsel - Outside Service - FERC Account 923

SCE inadvertently included certain outside counsel costs for the Performance-Based Ratemaking matter in its recorded costs for Account 923. SCE agrees with DRA that such costs should be removed from the recorded costs underlying SCE's forecast of 2009 outside counsel costs.463 SCE claims the appropriate adjustment should be $1,188,000, rather than $1,597,000 as proposed by DRA, because SCE already removed $424,000 in a Business Unit adjustment.464 DRA indicates it has not verified the accuracy of SCE's proposed reduction and, therefore, continues to support a reduction of $1,597,000. We find SCE's recommendation reasonable based on SCE's explanation that the difference DRA still identifies is probably accounted for in the related Business Unit adjustment of $424,000.465

6.11. Claims

For TY 2009, SCE forecasts for its claims division a total of $15.3 million (constant 2006$) in Administrative & General expenses (including injuries and damages - claims reserves).466 The 2006 recorded costs are $9.315 million. As discussed below, DRA recommends $5.173 million be removed from SCE's TY forecast.467

6.11.1. Additional Claims Personnel - FERC Accounts 920/921

SCE records salaries of claims division personnel to FERC Accounts 920/921 (Administrative and General Salaries and related non-labor expenses). SCE forecasts six new positions for the TY 2009 at an incremental labor cost of $451,102 (constant 2006$).468 SCE's TY 2009 forecast for additional non-labor is $86,000 (constant 2006$).469 SCE explains the claims division labor expenses from 2002-2006 were relatively flat.470 SCE expects the claims division's claims-related workload to continue to increase consistent with the overall upward trend in total claims cases handled by the division during 2002-2006.471

Based on the evidence provided, SCE has not justified its requested increase over 2006 base year. As DRA notes, between 2006 and 2007 the claims division workload increased approximately 1.35% based on the number of claims addressed and completed. DRA further points out, and we agree, that even the transfer of 316 claims investigations from Environmental and Safety does not warrant six new positions.472 This transfer results in an increase of 3.89%.473 Lastly, between 2002 and 2006, SCE experienced an average increase in claims filed against SCE of approximately 11.8% while keeping its claims division labor expenses flat.

Based on the projected increased workload for years 2002-2006 of 11.8% together with SCE's statement that it expects workload to increase consistent with the trend in total claims cases handled by the division during 2002-2006,474 we find SCE fails to justify its requests for costs above 2006 base year. Accordingly, we do not adopt SCE's proposed incremental costs.

6.11.2. Additional Claims Reserves - FERC Account 925

The claims division records to FERC Account 925 (Injuries and Damages - Reserves) amounts reserved by SCE as self-insurance for general liability losses resulting from injuries and damages to persons and property that are not covered by SCE's insurance policies. SCE establishes reserves up to its self-insured limit of $2 million per incident. Also included in this account is the amortization of insurance expense for specific coverage of covered losses resulting from injuries and damages to persons and property, such as premiums paid for asbestos-related injuries and damages under the Masters Insurance Program.475 For TY 2009, SCE forecasts $8.577 million (constant 2006$) for claims reserves based on the five year average of 2002-2006 recorded expenses. SCE's 2006 recorded expenses are $3.855 million.

While SCE provides evidence to support its contention that costs fluctuate over the 2002-2006 period, SCE fails to explain what accounts for this fluctuation. In the absence of this information, the Commission can not determine if such fluctuations were caused by one-time events. In rebuttal testimony, SCE asserts "SCE's experience in 2007 also demonstrates that its forecast of Claims Reserves for Test Year 2009 is reasonable."476 However, SCE does not explain what this 2007 experience consisted of.

For this reason, we adopt $3.855 million (constant 2006$) and find SCE has failed to prove the need for amounts beyond 2006 base year.

6.12. Workers' Compensation

SCE's forecast for the TY 2009 for its workers' compensation division is $43.162 million (constant 2006$) for workers' compensation, including reserves.477 SCE's 2006 recorded expenses are $25.557 million, so the forecast represents an overall increase of 68.9% over the 2006 base year. As discussed below, DRA recommends $17.281 million (almost all of the increase) be removed from SCE's TY estimate.478

6.12.1. Additional Workers' Compensation Personnel - FERC Account 925

SCE's Workers' Compensation Division has the primary responsibility for administering workers' compensation benefits, providing information to SCE employees regarding such benefits, and determining workers' compensation benefit eligibility. SCE's TY 2009 forecast includes $1.028 million (constant 2006$) associated with 12 additional full-time equivalent employees to its workers' compensation division.479 SCE's recorded 2006 expenses are $5.346 million and its TY 2009 forecast is $6.374 million.

SCE explains that, at year-end 2006, the Workers' Compensation Division had 39 employees on staff, three vacant positions, and five agency personnel.480 SCE also notes that the Workers' Compensation Division's labor expenses were relatively flat during the 2002-2006 time period.481 SCE expects workload to increase as the new employee population increases.482 DRA recommends a reduction to SCE's request of $703,000. According to DRA, funding for 6 Full-Time Equivalent employees is sufficient to address increased workload based on industry standards.483 DRA recommends four additional Claim Representatives and two Administrative Aides for TY 2009.484

We find DRA's argument based on industry standards convincing. SCE has failed to support the full amount of its requested increase. Accordingly, we adopt a $703,000 reduction to SCE's request to reflect approval of 6 rather than 12 additional employees.

6.12.2. Workers' Compensation Reserve - FERC Account 925

For Workers' Compensation Reserves, SCE's TY 2009 forecast is $36.788 million (constant 2006$). SCE calculates its forecast for Workers' Compensation Reserves expenses using a budget-based forecast methodology.485 SCE's 2006 recorded expenses are $20.210 million. SCE explains that in connection with the 2006 GRC, Workers' Compensation Reserve expenses were forecasted based on the anticipated value (i.e., SCE's exposure) of all new and existing workers' compensation claims for a given year. Under SCE's budget-based approach, the TY 2009 forecast for Workers' Compensation Reserves is based on the ultimate (total) value of anticipated new claims arising from injuries during the 2007-2009 time period.486

DRA's forecast is equal to SCE's 2006 recorded costs, $20.210 million. DRA reasons that forecasted employee growth may not be as high as SCE projects and thus SCE's forecast is uncertain. TURN recommends rejecting SCE's increase on the ground that it would provide an unjustified windfall to SCE. Instead, TURN proposes a forecast of $20.535 million based on the same methodology (four-year average of past reserve expenses) used in SCE's 2006 GRC.487

We find that relying on our existing methodology for forecasting reserve expenses is reasonable. In addition, SCE fails to demonstrate the reasonableness of its proposed new forecasting methodology for Workers' Compensation reserves and of the amount of reserve expense it seeks from ratepayers. Accordingly, we reject Edison's proposal and, using the existing methodology, we adopt TURN's proposed four-year average of past reserve expenses, a TY 2009 forecast of $20.535 million.

6.13. Ethics and Compliance - FERC Accounts 920/921 and 923

SCE's TY 2009 forecast for Ethics and Compliance is $1.698 million (constant 2006$) for FERC Accounts 920/921 and $0.414 million (constant 2006$) for FERC Account 923, for a total forecast of $2.112 million (constant 2006$). SCE's 2006 recorded costs are $1.347 million. SCE describes the costs recorded to FERC Account 920/921 as, generally, overseeing the Ethics and Compliance Helpline and related investigations; implementing a program to ensure that employees understand relevant standards and how to raise concerns or seek advice; developing a standard Ethics and Compliance Code; and guiding business practices along ethical lines, identifying action that may be needed to limit the opportunity for non-compliance.488 The primary costs recorded to FERC Account 923 are for the outside vendor that provides the company's helpline service and case management database, as well as costs for the outside consulting firm, Ethical Leadership Group, which has been retained to assist with the development of the company's ethics training, ethics communications, ethics and compliance review process, and other ethics-related matters, as needed.489 SCE describes its use of a budget-based forecasting methodology for Ethic and Compliance as follows:

"Given the relatively recent creation of the Ethics and Compliance Department, a budget based forecast methodology, based on the workforce we expect to have in place in 2009, has been used to establish reasonable base expense for FERC accounts 920 and 921 for the 2009 Test Year. The last recorded year forecast methodology has been used to establish a reasonable base expense for FERC account 923 for the 2009 Test Year."490

DRA recommends no ratepayer funding for Ethics and Compliance. DRA claims that because the increased costs incurred by this department are directly linked with the circumstances resulting in the Commission's fraud investigation of SCE's PBR, ratepayers should not have to cover these costs. DRA also argues that SCE's Ethics and Compliance Department appears to benefit shareholders, and contributes to SCE's corporate image enhancement,491 but has no defined ratepayer value. For these reasons, DRA recommends that SCE shareholders fund the Ethics and Compliance Department, not the ratepayers.

SCE seeks to justify its forecast, in part, by citing to compliance with the Sarbanes Oxley Act of 2002 and the Federal Sentencing Guidelines revised in 2002, but SCE fails to explain the costs associated with these functions or why these functions would contribute to SCE's requested incremental costs. Moreover, based on the record, it appears that the vast majority of these costs support SCE's response to unethical behavior highlighted in I.06-06-014, the Commission's Performance Based Ratemaking Investigation. The Commission adopted a final decision in I.06-06-014 on September 18, 2008, D.08-09-038, as we summarize above in our discussion regarding Results Sharing. Based on the Commission's finding that fraud occurred, it is reasonable to require SCE to bear the costs of addressing this problem, rather than the ratepayers. In the absence of any specific information regarding the costs associated with the functions of the department beyond addressing the events related to I.06-06-014, we reduce SCE's forecast by the full amount of the request, $2.112 million.

6.14. Regulatory Policy and Affairs Department - FERC Accounts 920/921

SCE estimates $13.414 million (constant 2006$) in 2009 TY O&M expenses for its Regulatory Policy & Affairs department, with a projected increase of $1.471 million over 2006 recorded levels. SCE explains that this increase is primarily due to increased labor costs resulting from a substantial and continuing increase in regulatory workload. SCE's labor forecast includes seven new Full-Time Equivalent employees in 2009, as well as filling vacancies that existed at the end of 2006. In addition, Regulatory Policy & Affairs' TY 2009 forecast includes 100% of the salaries associated with the employees who work on Affiliate Transaction Rules compliance activities492 and $0.209 million for the Spot Bonus program. We have addressed the latter issue elsewhere in this decision; accordingly, the latter amount is removed from the TY 2009 forecast.

DRA recommends the Commission reduce SCE's forecast by $169,000 by removing $0.038 million as a one-time severance payment and relying on a five-year average of the recorded data for both labor and non-labor. Recorded labor costs have been relatively stable during 2002-2008. As such, SCE has failed to adequately support its request of $1.471 million for its TY 2009 labor forecast. In this instance, we find it reasonable to rely on a five-year average of the recorded data for both labor and non-labor. In addition, we remove the one-time 2002 severance payment of $0.038 million as SCE does not dispute the one-time nature of this payment.

SCE estimates $0.285 million (constant 2006$) in 2009 TY O&M expenses for compliance with the Affiliate Transaction Rules by the Regulatory Policy & Affairs department. DRA recommends this amount be removed from the forecast, noting that the Commission excluded these amounts from revenue requirement in the 2006 GRC. In response, SCE contends that, for approximately two decades, the Commission permitted SCE to recover these costs in rates and the Commission's reversal of policy on this matter in the 2006 GRC was not well-founded.493 SCE asserts that ratepayers have an interest in SCE maintaining Affiliate Transaction Rule compliance.494

We affirm the policy set forth in the 2006 GRC and remove these compliance costs from the forecast. We disagree with SCE's argument that ratepayers should pay because SCE's compliance with these rules protects ratepayers. These compliance costs are incurred to support the operations of SCE's affiliates and, as such, requiring ratepayers to bear those costs would amount to a subsidy of those operations by ratepayers.

6.15. Financial Organizations

6.15.1. Controller's Central Services and Corporate Accounting Groups - FERC Accounts 920/921

SCE's Controller's Organization estimates $16.164 million (constant 2006$) in TY 2009 labor and non-labor expenses for its Central Services and Corporate Accounting groups.495 DRA suggests removing $1,000 from the Central Services group based on its belief that SCE had requested $500 above the market reference point for a Business Analyst position.496 It appears DRA's proposed adjustment is based on an error in SCE's workpapers that inadvertently understated SCE's forecast.497 We find SCE's forecast reasonable.

6.15.2. Audit Services - FERC Accounts 920/921

SCE estimates $9.254 million (constant 2006$) in TY 2009 O&M expenses for its Audit Services department, with a projected increase of $1.270 million over 2006 recorded levels. SCE explains this increase is primarily due to increased labor costs resulting from (1) auditing of new construction and systems, (2) an increased emphasis on energy efficiency, safety, and ethics programs, (3) new required compliance auditing, and (4) an increase in non-utility audits (refunded to ratepayers). SCE's labor forecast includes the addition of 7 new auditors by 2009, as well as the filling of current vacancies.498

DRA recommends $24,000 be removed from SCE's Audit Services department TY 2009 labor costs for non-recurring severance costs. DRA also proposes $513,000 be removed to reflect the difference between using last recorded year 2006 plus adjustments and a five-year average.

SCE agrees with DRA's proposal to remove $24,000.499 We agree with DRA that expenses in years 2002-2006 have been relatively stable and SCE's reasons for expecting an increase of approximately 16% over 2006 base year lack specificity because SCE fails to sufficiently explain the nature of all the costs included in the 2006 base year. DRA's forecast is adopted. We also remove the $24,000 severance costs because their one-time nature makes them inappropriate for forecast purposes.

6.15.3. Treasurer's Organization - FERC Accounts 920/921 and 930

SCE's Treasurer's Organization is forecasting $10.757 million (constant 2006$) for the TY 2009,500 a 20.5% increase over SCE's 2006 recorded costs of $8.925 million.501 SCE forecasts labor to increase by $548,455 for five new positions, inclusive of a 15% salary premium.502 DRA does not address the need for additional employees but recommends $72,000 be removed from SCE's forecast of $548,455 for salary premiums that should not be funded by ratepayers.

We reject the requested increase insofar as it relates to additional employees. In large part, SCE justifies the five additional positions based on "SCE's unprecedented $17 billion capital investment program projected for 2007 through 2011...."503 While SCE refers to increases in power procurement activities to justify these new positions, SCE does not quantify the extent to which these activities will rely on additional staff. For reasons we have explained in other parts of this decision, we do not authorize capital projects of the magnitude requested by SCE in this GRC. Accordingly, we find SCE's requested increases unreasonable and reject SCE's requested increase in labor of $548,455 and the related non-labor costs.

6.16. Tax Department

SCE's Tax Department forecasts $2.94 million (constant 2006$) for TY 2009,504 a 25% increase over SCE's 2006 recorded costs of $2.347 million. SCE forecasts four additional tax specialists at labor cost of $558,400, inclusive of an 8% salary premium.505

DRA recommends $40,000 for salary premiums should not be funded by ratepayers. DRA argues that ratepayers should not have to pay salary premiums for new positions that will remain in rates indefinitely. Moreover, DRA states that, since SCE's Tax Department also functions as the EIX tax department and prepares consolidated tax returns for the entire EIX affiliated group, including SCE,506 it is reasonable for shareholders to cover the costs of salary premiums. DRA does not contest the need for these additional tax specialists, just the salary premiums.

SCE testifies that, to the extent the Tax Department performs work for any entities other than SCE and its regulated subsidiaries, the costs are subject to the affiliate credit mechanism discussed in Exhibit SCE-11, Results of Operations. According to SCE, the mechanism ensures that ratepayers are only charged for costs related to the regulated utility.507 SCE cites areas of increased work to justify its request for additional positions in the Tax Department, including new tax forms, new electronic filing requirements, new California audit requirements, and implementation of a new financial accounting standard for computing income taxes for publicly traded companies - FIN 48.

Based on the evidence presented by SCE, we find its request to include additional expenses in its TY 2009 forecast to reflect the need for increased labor reasonable, including the salary premiums. Accordingly, we adopt SCE's TY 2009 forecast.

6.17. Property and Liability Insurance

6.17.1. Corporate Property Insurance - FERC Account 924

SCE requested $10.042 million (constant 2006$) for property insurance for TY 2009, as compared to 2006 recorded expenses of $7.688 million. The request includes increases of $500,000 for Mountainview and $200,000 for additional SONGS accidental outage insurance. The remainder of the increase is predicated on growth in assets for which, in large part, SCE requests authorization in this proceeding.508

DRA does not dispute the forecasted additional costs for the requested $500,000 for Mountainview and $200,000 for additional SONGS insurance, but DRA claims SCE has not fully justified the rest of the requested increase. DRA recommends a total increase of $1.288 million.509

We approve the increases related to Mountainview and SONGS, which total of $700,000. Regarding the remaining increases, SCE states its forecast is reasonable because "SCE has justified an intense growth program throughout this application in order to serve our Customers."510 SCE's assertion lacks sufficient specificity to support the additional amounts requested over 2006 base year of $7.688 million. Therefore, in this decision, we authorize an increase of $700,000 over 2006 recorded expenses.

6.17.2. Corporate Liability Insurance - FERC Account 925

SCE's forecast for Account 925 also includes $11.259 million for corporate liability insurance. The 2006 recorded amount is $9.137 million. SCE includes $78,000 for Mountainview's liability insurance and approximately $329,000 for hull insurance to cover any loss or damage to three additional helicopters requested in this proceeding. The estimated annual cost of hull insurance is at 7% of the value of the helicopters. The value of each helicopter is approximately $4.7 million each. With the exception of the materials presented regarding the helicopters and Mountainview, SCE's assertions in support of this requested increase lack sufficient specificity. Therefore, for the same reasons discussed previously, we adopt recorded 2006 amount of $9.137 million plus amounts for Mountainview and the helicopters. We find these additional amounts reasonable.

6.18. Corporate Communications - FERC Accounts 920/921, 923 and 930

SCE's TY 2009 forecast is $11.264 million (constant 2006$) for Corporate Communications A&G expenses. SCE claims the increase centers around three factors. First, 2006 recorded labor expenses were significantly below budget as several positions remained vacant; also, additional Full-Time Equivalent employees are needed. Second, SCE is expanding its customer facing website. Third, SCE is increasing the frequency of bill inserts from quarterly to monthly. Corporate Communications provides information to SCE customers and other stakeholders (such as public officials, community organizations, and SCE's shareholders, business partners, and suppliers) on a variety of topics.511 Corporate Communications also researches, develops, and facilitates the delivery of this information to a large and varied group of stakeholders, including residential and business customers, public officials, policymakers, the company's business partners and suppliers, community organizations, shareholders, and other key groups.512

6.18.1. Forecast Methodology - FERC Accounts 920/921

SCE used the last recorded year and then applied a future year adjustment for its forecast. SCE determined 2006 was the most representative year and added $657,579 to include eight additional Full-Time Equivalent employees that were authorized in the 2006 GRC decision but never filled due to retirement and attrition.513 DRA suggests using a five-year average is more appropriate due to the fluctuating nature of the historical costs.514 In this instance, we prefer SCE's methodology over DRA's because DRA fails to explain why we should take into account these historical fluctuations.

DRA also recommends removal of any one-time severance payments, but SCE explains it has effectively removed severance payments from its forecast because 2006 recorded costs do not include any severance payments. DRA also contests the costs associated with SCE's Spot Bonus program. We address SCE's Spot Bonus program in a separate section of this decision. Accordingly, we find SCE's forecast reasonable as adjusted to reflect our findings on Spot Bonuses.

6.18.2. Design Costs - FERC Account 930

SCE estimates $1.465 million in TY 2009 FERC Account 930, which includes the expenses for communications products, including the production, design, and distribution of customer information booklets, brochures, and notices. SCE used the last recorded year and then applied a future year adjustment for its forecast. SCE anticipates these communications costs to remain relatively stable and consistent with 2006 expenses with the exception of an increase of $75,000 in TY 2009 due to an increase in design costs to support customer bill inserts.515 As above, DRA suggests a five-year average. DRA would also normalize the increased design costs of $75,000. We find SCE provides sufficient evidence to support its claim that 2006 recorded costs are representative of future costs with the addition of the increased design costs. Accordingly, we find SCE's forecast reasonable.

6.19. Power Procurement Business Unit

The Power Procurement Business Unit, the organization responsible for buying and selling power, has four departments: Market Strategy and Resource Planning, Energy Supply and Management, Renewable and Alternative Power, and Power Procurement Finance. SCE forecasts $52,664,000 (excluding Account 926/Pension and Benefits) of A&G expenses for TY 2009. DRA's estimate is $38,206,000,516 consisting of $2,760,000 for Market Strategy and Resource Planning; $17,403,000 for Energy Supply and Management; $7,348,000 for Renewable and Alternative Power; and $10,696,000 for Power Procurement Finance.

6.19.1. MRTU New Software Applications - FERC Accounts 920/921 and 923

SCE's forecast for its Power Procurement Business Unit includes certain MRTU expenses. Regarding MRTU expenses in general, DRA recommends that costs associated with implementation of MRTU be recorded in the MRTU memorandum account. We address the appropriateness of the memorandum account in a separate section of this decision.

Regarding the amount of these forecasted expenses, SCE forecasts additional O&M costs associated with a new software application of $8.191 million.517 DRA proposes a reduction of $3.289 million to SCE's TY 2009 forecast for new software to reflect information technology costs associated with MRTU. DRA also proposes various additional reductions to FERC Accounts 920/921 to reflect the removal of MRTU-related costs to the memorandum account.

DRA and SCE disagree on the exact amount of additional expenses related to MRTU but SCE agrees that the costs related to MRTU forecasted in FERC Accounts 920/921 are approximately $5.448 million518 and $598,000 in FERC Account 923.519 Regarding DRA's estimate, SCE explains that even if DRA's proposal to remove MRTU-related costs from the GRC was appropriate, DRA's adjustment is incorrect as it includes amounts not related to MRTU.520

As we discuss in more detail in a separate section of this decision, we find that labor and non-labor expenses related to MRTU should continue to be recorded in the memorandum account. We also find it appropriate to include all amounts related to MRTU, including outside services recorded to FERC Account 923, in the memorandum account. Accordingly, we adopt DRA's recommended reduction of $3.289 million521 in information technology MRTU-related costs and an additional approximately $5.448 million to FERC Accounts 920/921. Similarly, SCE's TY 2009 forecast in FERC Account 923 is reduced by $598,000. SCE's update testimony forecasts additional increases associated with O&M expenses for MRTU implementation. The increase to O&M expenses is $1.109 million (constant 2006$)522 for TY 2009. We adjust our adopted figures accordingly.

6.19.2. Power Procurement Business Unit - FERC Accounts 920/921 and 923

In addition to the MRTU-related adjustments to SCE's forecast for the Power Procurement Business Unit,523 DRA recommends the Commission limit SCE's increase above base year 2006 costs. SCE's TY 2009 forecast, represents an increase over 2006 recorded expenses of approximately $16.8 million or 60%. DRA asserts SCE fails to adequately describe the increasing workload and the need for additional employees to meet that workload by 2009.524 We agree. While SCE claims its forecast is based on the additional staff needed by 2009 to meet rapidly expanding workload, the information provided is not sufficient to justify an approximately 60% increase in costs. DRA's recommendation is consistent with SCE's historical trend for increased costs for 2002-2006.525 Accordingly, we adopt DRA's recommendation and authorize an increase of approximately 30% ($8.409 million), rather than 60%.

6.20. Risk Control - FERC Accounts 920/921 and 923

The Risk Control Group provides risk governance and oversight over the procurement activities of the Power Procurement Business.526 SCE's TY 2009 forecast is $4.465 million (constant 2006$) for labor in FERC Account 920 and $0.824 million (constant 2006$) for non-labor in FERC Account 921. SCE's 2006 recorded expenses for Risk Control are $2.240 million for Account 920 and $0.215 million for Account 921. SCE uses year 2006, the last recorded year, for its labor forecast plus future year adjustments.

TURN recommends reducing SCE's estimate of risk control-related expenses by $2,383,000 to maintain staff at 25 Full-Time Equivalent employees and to remove costs for certain consulting expenses, which TURN finds unnecessary based on its productivity analysis.527 In response, SCE claims the productivity metric offered by TURN is not a valid measurement for determining staffing levels, as the proposed metric does not consider the size, complexities, risks or dollar impact of the transactions.528

TURN's metric is sufficient to demonstrate that the record fails to support SCE's request. Consequently, regarding FERC Account 920, we find SCE's request unreasonable based on declining productivity, and we adopt TURN's recommendation. We authorize SCE to increase its Full-Time Equivalent employees up to 25, but we reject SCE's proposal to add 15 additional staff.529 Regarding non-labor expenses, TURN recommends $651,000 for FERC Account 921, a reduction of $173,000. To reflect our findings related to labor, we adopt TURN's recommendation regarding FERC Account 921.

SCE also forecasts $0.600 million in expenses in Account 923, Outside Services, to address increased needs for recruiting services to fill positions within the Risk Control Group, and to provide consulting services to establish a framework for its Enterprise Risk Management program.530

SCE's 2006 recorded expenses are $285,000.531 TURN recommends reducing SCE's figures by $150,000 for consulting related to the Enterprise Risk Management program that will be complete before TY 2009, and by $176,000 for recruitment consulting to reflect the reduced staffing forecast, for a total reduction of $326,000. TURN's adjustments result in a forecast of $274,000 for this account. We agree with TURN and adopt its recommended adjustments to SCE's forecast.

6.21. Operations Support Business Unit - FERC Accounts 920/921 and 923

SCE requests $78.095 million in TY 2009, an increase over 2006 recorded expenses of $48.008 million532 SCE relies upon a budget-based estimating method for this forecast.533 SCE's Operations Support Business Unit supports other SCE business units, such as T&D, Customer Service, and Generation.534

Currently, Operations Support Business Unit consists of seven "business lines," which perform different functions within this Unit. For example, Business and Organization Support assists other areas of SCE with drawing management, maintaining the corporate records center, information management, and mailing services.535 Other functions fall under Corporate Real Estate, which is responsible for all activities related to the management of SCE property and buildings, including the planning, design, construction and maintenance of 171 non-electric facilities, and which also manages the procurement, sale, and maintenance of all real property owned by SCE.536 SCE explains this "support" function by stating that Operations Support's employees do not generally interact directly with SCE's customers but, instead, work "behind the scenes" to support other SCE business units.537

In direct testimony, SCE summarizes its proposed increases as follows:

2006 Recorded/Adjusted

Test Year 2009 Forecast538

Accounts 920/921 $31.161 Million

$41.658 Million (constant 2006$)

Account 923 $ 0.118 Million

$ 0.630 Million

Account 925 $ 2.723 Million

$ 4.019 Million

Account 931 $ 6.396 Million

$11.361 Million

Account 935 $ 7.610 Million

$24.397 Million

In support of the increase, SCE asserts that over the past few years, it has experienced unprecedented growth in both new customers and system load, exceeding its authorized spending levels. This has resulted in corporate-wide reallocation or deferral of funding from other projects, and has caused a strain on workforce capacities.539

DRA recommends reducing SCE's request to $62 million for TY 2009.540 TURN makes a number of recommendations to reduce SCE's forecast in Accounts 920/921 and 923 based on, among other things, SCE's use of a budget-based approach to forecasting which TURN claims is inherently flawed.541

We find that DRA and TURN present compelling arguments for reductions. Also, we are concerned with an overarching flaw in SCE's analysis. As TURN points out, SCE relies on budget-based forecasting here. As a result, at least in this instance, SCE presents an unreliable forecast. Based on the record, we cannot identify the full impact of this budget-based forecasting on SCE's specific recommendations. Accordingly, we find the most reliable data to be 2006 recorded expenses for the Operations Support Business Unit, which is $48.008 million and find it reasonable to adopt this amount for TY 2009. SCE's forecast is reduced accordingly.

7. Depreciation

The purpose of depreciation is to recover the original cost of the asset, as well as the net salvage value, over the life of the asset. Thus assets are paid for by the customers who benefit from their use. Under straight line depreciation, the annual depreciation amount and rate are shown by the following formulas:

Annual depreciation = (original cost-net salvage) /asset life

Depreciation rate = annual depreciation/original cost x 100%

Under this method, the annual depreciation is set once and the depreciation remains uniform over the life of the asset. This method works well for a single asset where the net salvage value and life are known in advance. However, depreciation is done by account where there are multiple assets of various ages. In this case most of the assets are partially depreciated, and the useful lives and net salvage vary and are not certain.

As a result, the Commission has historically used a variation of this method called straight line remaining life depreciation. Under this method, the undepreciated asset amount (original cost less accumulated depreciation plus the estimated net salvage) is depreciated over the remaining life of the asset. The net salvage includes the cost of removal of the asset at the end of its useful life as well as any salvage value the asset may have at that time. The original cost of the asset and the net salvage are expressed in nominal dollars. For example, if the end of an asset's useful life is 2010, the net salvage would be expressed in nominal 2010 dollars. Likewise, if the asset was put into service in 2000, its original cost would be in nominal 2000 dollars.

TURN does not oppose SCE's remaining life estimates and accepts SCE's future net salvage estimates.542 However, TURN provides a different proposal as to how the net salvage value is determined. TURN states that the escalation of net salvage costs has far exceeded inflation.543 As a result, TURN proposes that net salvage be based on the estimated net salvage that would be incurred if the asset is retired during the test year rather than an estimate of the net salvage cost that will actually be incurred at the end of the asset's life.544 TURN claims the future effects of inflation on net salvage would be recovered in future depreciation rates.545

Under TURN's proposal the net salvage value used to calculate depreciation rates would be calculated as the present value of the estimated future net salvage costs.546 The present value of a future cost is the amount of money that would have to be invested at a specified interest rate to pay the future cost at the time it is incurred. The basic assumption of a net present value calculation is that the present value amount will earn interest sufficient to accumulate the future amount by the future date the cost is incurred. However, depreciation is recorded in the depreciation reserve at the nominal amount and does not earn interest. As a result future ratepayers will have to make up the shortfall. TURN acknowledges that future ratepayers will pay more in inflated nominal dollars.547 The fact that the future nominal dollars would be inflated does not address the fact that future ratepayers would be paying what is essentially the interest on the amount paid by past ratepayers in addition to their share of such future costs. Additionally, TURN appears to assume that future ratepayers will have more of the inflated dollars to pay with. This, in turn, assumes that ratepayers' incomes keep up with inflation. The record does not demonstrate that this is necessarily the case, particularly with respect to ratepayers who are on fixed incomes.

Another consequence of TURN's proposal is that current ratepayers will have to pay a return on a larger rate base and income taxes on the larger return.548 This would offset to some degree the current ratepayer benefit of lower depreciation. In addition, the depreciation reserve would be smaller in the future resulting in a larger rate base with resulting increased return and taxes.

Under the current method, current ratepayers do pay more for net salvage on a net present value basis than future ratepayers. However, this is offset by the fact that rate base is correspondingly reduced, due to a larger depreciation reserve, now and into the future. This means that current ratepayers will pay a smaller return on rate base and less income tax on that return. In the future, ratepayers will continue to pay a smaller return on rate base, less income taxes on that return, and less depreciation expense.

On balance, the record does not demonstrate TURN's proposal is superior to the Commission's longstanding depreciation rate calculation methodology and it is not adopted.

DRA does not oppose SCE's remaining life estimates, but DRA opposes SCE's future net salvage estimates and recommends SCE retain current net salvage estimates.549 DRA did not perform an account-by-account analysis of depreciation rates.550 Instead, its recommendations are based on policy reasons.551 Some of the reasons cited by DRA for its proposal are that (1) SCE has collected $2.7 billion in rates for future costs of removal that is yet to be spent;552 (2) compared to other California utilities, SCE's current net salvage rates rank among the highest;553 and (3) for other utilities, net salvage rates have or will remain unchanged for more than the traditional 3-year GRC cycles due to the adoption of longer GRC cycles.554

The fact that SCE has accumulated a depreciation reserve attributable for recovery of net salvage in excess of expenditures is no surprise. One of the purposes of depreciation is to accumulate a reserve to fund future net salvage before the expenditures actually occur.

Likewise, the fact that SCE's net salvage rates may be higher than other utilities' rates or that other utilities' net salvage rates may remain unchanged for several years does not mean that SCE's rates are unreasonable. Nevertheless we take the net salvage rates of other utilities into consideration as part of our determination of reasonableness.

DRA's further explanation for its recommendation is the following: "SCE currently accrues negative net salvage at a level sufficiently higher than the annual recorded cost of removal, so the utility will continue to accrue net salvage costs at a positive rate even without the requested increase. Therefore, DRA is recommending that a conservative approach be adopted in addressing this issue which in this case is to retain the negative salvage rates adopted in D.06-05-016, SCE's last GRC."555

DRA states recovery of net salvage "is not a critical requirement that impacts the utility's ability to provide safe and reliable services to its customers and therefore is one area where the requested rate increase may be mitigated with no risk or adverse impact to the utility and its shareholders."556 DRA further states that "SCE and its shareholders are never at risk for cost of removal and are always made whole whether or not the final cost of removal exceeds or is below the amount accrued in the reserve account."557

DRA's primary concern appears to be to retain the previously adopted net salvage rates in order to keep SCE's electricity rates down. Based on the current economic downturn, DRA's policy recommendation has merit. SCE performed a comprehensive depreciation study and its proposed depreciation rates were derived following the Commission's longstanding methodology.558 We find SCE's methodology reasonable but, in an effort to mitigate SCE's requested rate increase, we will retain the net salvage rates adopted in D.06-05-016. Prior to the TY 2006 GRC, the Commission did not modify net salvage rates for approximately 10 years. We will review SCE's net salvage rates in SCE's next GRC. SCE's remaining lives and future net salvage values are not opposed by TURN. As discussed above, DRA does not oppose SCE's remaining lives but does oppose its future net salvage estimates.

DRA also recommends that SCE provide the following information in its next GRC filing:559

DRA states that its request is reasonable because the Commission has imposed similar requirements in previous rate cases. Since DRA is proposing these reporting requirements, it has the burden of demonstrating the usefulness of the requested information. SCE's estimated escalation rates for net salvage would be included in the portion of SCE's GRC workpapers pertaining to future net salvage. As to the other information, DRA has not explained the purpose of the requested information or how the requested information would be used to achieve that purpose. In addition to the above, DRA recommends the Commission require SCE to identify the accruals for cost of removal separately from accruals for depreciation expense in its next annual depreciation rate filing.560 Here again, DRA has not explained the purpose of the requested information or how the requested information would be used to achieve that purpose. For the above reasons, we do not adopt DRA's proposal. However, by rejecting the proposal, we do not intend to restrict DRA's ability to conduct future discovery.

8. Rate Base, Plant-In-Service, and Capital Expenditures

8.1. General Plant-In-Service Issues - Plant Weighting

SCE forecasts a 2009 plant weighting factor of 50.27%. DRA recommends that, after adjusting for two atypical projects, the weighting factor should be no higher than 42.554%.561 DRA excluded both the Mohave Decommissioning Project and the Enterprise Resource Planning Program from its calculation. These two projects are scheduled to be booked to plant very early in 2009. Because they are atypical projects, totaling over $315 million, they are likely to have a noticeable impact on the weighting percentages.

SCE, acknowledging that atypical projects have an impact on the plant weighting factor, excluded the largest atypical project, the Enterprise Resource Planning Program, from its plant weighting calculation to demonstrate the impact on the overall weighting factor. SCE shows that if the Enterprise Resource Planning Program is excluded from the weighting calculation, its plant weighting factor is 43.57%, a difference of 1.016% from DRA's recommended 42.554%.562 SCE argues that the 43.57% weighting factor is close to the 42.554% nine-year historical average adopted in SCE's 2003 GRC and to the 41.16% weighting factor adopted in its 2006 GRC.563

In prior decisions for SCE, the Commission has found that a 42.554% weighting percentage for plant weighting is reasonable. In D.04-07-022, the Commission stated the following in adopting the 42.554% weighting factor:

Notwithstanding SCE's claims that its method is more rigorous and sophisticated, and is based on the intimate knowledge of business unit managers, SCE has not demonstrated that rigor, sophistication, and intimacy yield more accurate and reliable forecasts than the historical record. SCE improperly attempts to shift the burden of proof to ORA in this GRC by pointing out that ORA provided no conclusive explanation of why an average of historical weighting percentages better represents the plant weighting than a detailed budget. The more pertinent question, not adequately addressed by SCE, is why its budget-based approach, which suffers from the problem that budgets are not always carried out as planned, is necessarily more accurate and reliable than data based on actual performance over an extended period.564

In this GRC, SCE's increased levels of proposed capital expenditures make more problematic the ability of SCE to meet its construction completion forecasts. We also note that in SCE's 2006 GRC, the adopted overall weighting percentage of 41.16% was even lower than the 42.554% previously found reasonable. Moreover, the inclusion of atypical projects in the calculation of a plant weighting factor has a significant impact on the overall weighting factor, a result acknowledged by SCE and shown by the results of SCE's supplemental calculation which excluded the Enterprise Resource Planning Program.565 As a result, such projects should not be included in calculating the plant weighting factor. Therefore, consistent with previous Commission decisions, and after excluding the two atypical projects, DRA's recommendation to use a plant weighting factor of no higher than 42.554% is reasonable and should be adopted.

8.2. Generation Capital

8.2.1. Nuclear Generation

SCE requests $49.2 million in capital expenditures for SONGS 2 & 3 in TY 2009. DRA does not oppose SCE's forecast.566 However, DRA's Results of Operations model reduced the nuclear generation plant category by $9.9 million, of which $5.9 million was applicable to SONGS 2007 costs and $4 million to Palo Verde.567 DRA identified in Exhibit DRA-73 the $5.9 million SONGS 2007 cost as the difference between SCE's 2007 forecasted and actual SONGS costs. DRA also identified $34.3 million in prior years SONGS capital expenditures that have been deferred. There is no mention of Palo Verde capital expenditures in the exhibit. Further, there is no recommended adjustment in Exhibit DRA-73 or in the Exhibit's summary of recommendations. Because SCE's forecast appears uncontested, SCE's capital expenditures forecast for SONGS and Palo Verde should be adopted.

8.2.2. Coal Generation

SCE requests $39.2 million (SCE share) in test year 2009 capital expenditures for Four Corners. The majority of this cost is for reliability, environmental and safety projects. SCE also requests $56 million to decommission its Mohave plant.

8.2.2.1. Four Corners

Included in the $87.1 million TY 2009 (SCE 48% share is $39.2 million)568 request for Four Corners is $6 million (SCE share) per year 2009-2011 for "Future Reliability Projects Unallocated." SCE derived this estimate by multiplying the estimated cost of other specifically identified reliability projects by a 10% contingency factor.569 The $6 million is to be used to fund short-noticed capital projects that are sudden and unforeseen. SCE notes this 10% contingency factor is lower than the 15% contingency factor SCE requested and was authorized in its 2006 GRC. SCE explains that it used this lower 10% contingency factor because it has increased its efforts with APS to better identify future project needs.570

DRA contends that the requested $6 million for unforeseen short-noticed projects is excessive based on SCE's annual level of unanticipated reliability-related capital projects, which included $0 for 2007 and $553,000 for 2008. DRA further contends that a 10% contingency factor is unwarranted because SCE already includes an 8.7% contingency in its capital expenditures forecast on all of its specifically-identified projects.571 According to DRA, SCE's application of a 10% contingency on total project estimates, which already includes an 8.7% contingency factor, effectively provides a "contingency for contingencies" and results in a contingency reserve in excess of 18.7% for specifically identified reliability projects.

Based on SCE's increased efforts with APS to better identify future project needs, we find no justification to set aside an additional 10% contingency reserve for unforeseen short-noticed projects at this time.

Moreover, in R.06-04-009572 we are considering whether the future capital expenditures identified by SCE associated with its ownership share of Four Corners are allowable under Pub. Util. Code § 8341(d)(1). Because R.06-04-009 is pending, we do not address any of SCE's requested Four Corners capital expenditures for 2009-2011. The issue of whether any Four Corners capital expenditures shall be authorized will be decided in R.06-04-009. Accordingly, we remove $39.2 million (2009) $47.089 million (2010) and $27.398 million (2011) from SCE's forecasted capital expenditures. In R.06-04-009, we will also address the issue of whether the revenue requirement authorized in this decision must be modified to include additional capital expenditures related to Four Corners as a result of the rulemaking. In addition, we may also need to consider whether amounts included in the rate base adopted in this decision should be reduced prospectively to reflect the disallowance of certain Four Corners capital expenditures incurred after the effective date of D.07-01-039.

8.2.2.2. Mohave

SCE forecasts its total share of Mohave decommissioning cost at $55.769 million. SCE's Mohave decommissioning TY 2009 estimate includes $12.8 million or 30% in contingency reserves.573 The basis of SCE's Mohave Decommissioning Project cost estimate is SCE's preliminary engineering completed to date.574 SCE explains that contingency is a standard practice throughout the industry and standard practice in the cost estimating of government construction projects, as noted by the U.S. Department of Energy in publication DOE G-430.101.575

Regardless of whether a standard practice exists throughout the industry of providing for contingencies, DRA recommends the disallowance of SCE's 30% contingency. DRA cites to SCE's testimony that SCE will ultimately only collect in rates the final actual cost of the decommissioning through the operation of its Mohave Balancing Account.576

There is no dispute that Mohave expenditures are subject to a two-way balancing account approved in SCE's 2006 GRC.577 There is also no dispute that the inclusion of contingency in some circumstances is standard practice throughout the industry. However, in this instance, SCE has an established balancing account to ensure that SCE recovers its reasonable and necessary costs related to the Mohave decommissioning. Such a balancing account is not consistent with what SCE describes above as standard industry practice. This balancing account fully mitigates the need to provide for a 30% contingency reserve. SCE's TY 2009 $12.8 million Mojave contingency reserves are disallowed.

8.2.3. Hydroelectric Generation

8.2.3.1. Big Creek and Poole Housing Projects

Three adjustments to SCE's Big Creek Housing Project forecast have been proposed. DRA recommends and TURN concurs that the $0.440 million earmarked in the 2009 capital forecast for the construction of new apartments at Big Creek be excluded. TURN also recommends a $0.462 million or 40% overall reduction to SCE's housing capital forecast. TURN's recommendation includes a $1.733 million increase in the overall budget for additional capital improvements, contingent upon SCE's capitalizing the Big Creek housing repairs instead of expensing as proposed in the application.

DRA recommends excluding new apartments at Big Creek because it opposes any expansion of SCE's hydro staff.578 However, SCE contends that it needs additional housing at Big Creek regardless of whether its hydro staff is increased to retain and replace retiring staff. SCE explains this is because SCE has company housing for only 83 of its 155 employees located at its remote Big Creek site. Other employees unable to find near-by affordable housing must now travel long distances.579

SCE's proposed new apartments at Big Creek will mitigate SCE's difficulty in recruiting and retaining employees in this remote location and the need for employees to travel long distances in the absence of affordable local housing. We find SCE's explanation reasonable and do not adopt DRA's recommended reduction.

TURN's 40% recommended reduction in the Big Creek housing refurbishment capital projects (2008-2011) was accepted by SCE.580 Hence, SCE's housing capital budget should be reduced by $0.462 million in 2009, $0.176 million in 2010, and $0.400 million in 2011.

TURN's remaining adjustment is a $1.773 million increase in SCE's housing capital projects contingent upon SCE capitalizing the Big Creek housing repairs that SCE seeks to expense in Account 542.581 Consistent with our finding in a separate section of this decision regarding Hydro O&M for SCE's Big Creek repairs, SCE's housing capital projects are increased by $1.773 million for TY 2009.

IAG recommends a $0.1 million reduction to SCE's capital forecast designated by SCE for removal of asbestos siding at its Poole housing unit.582 SCE clarified that the term "siding" was an abbreviation to reference all of the work to the Poole housing unit. This project encompasses replacement of the existing roof containing asbestos and the application of a coating to the exterior of the building to mitigate spalling (chunks of concrete at the surface popping off) due to the freeze and thaw cycles encountered during winter.583 Based on this clarification, the $0.1 million Poole Housing Project is reasonable.

8.2.4. California Independent System Operator & Western Energy Coordinating Council Projects

SCE proposes approximately $2.8 million in unidentified projects to respond to the CAISO and Western Energy Coordinating Council (CAISO/WECC) requirements. TURN recommends a 50% reduction to SCE's CAISO/WECC projects. SCE agrees to reduce the cost of its CAISO/WECC projects by $1.397 million or 50% for the years 2008 through 2011.584 We therefore reduce the costs for SCE's CAISO/WECC projects by $0.412 million in 2008, $0.266 million in 2009, $0.438 million in 2010, and $0.282 million in 2011.

8.2.5. Hydro Project Benefit/Cost Ratio

SCE includes small hydro refurbishment projects in its TY 2009 capital budget. These projects include refurbishment or replacement of circuit protection and transformers. The projects also include water turbine refurbishment and replacement of turbine shut-off valves, runners or seals, wicket gates, and governors. SCE identifies these projects based on the condition of the equipment, consideration of replacement prior to the equipment failing while in service (which can damage adjacent equipment), and a benefit-cost analysis.585

TURN disagrees with the method SCE uses for its benefit-cost analysis. One problem TURN identifies is that when SCE undertakes a project benefit-cost analysis at a multiple unit hydro turbine plant, the amount of energy loss may be less than SCE estimates if only one turbine cannot operate and SCE is still able to operate the remaining turbines.586 From TURN's own benefit-cost analysis on select SCE projects, TURN concludes that where SCE calculated a benefit-cost ratio of 2.0 or less (2.2 or less with energy production under 25000 MWh per year), proper analysis would yield ratios of only 1.3 or less. TURN recommends removing 12 hydro refurbishment projects totaling $2.768 million from SCE's TY 2009 capital forecast.587

SCE's and TURN's recommendations are based on different assumptions of how long equipment can run without replacement before a catastrophic failure occurs. We find SCE's method of assessing its equipment condition, its ongoing maintenance program, its economic analysis (which considers how long an equipment outage will occur, how much customers save if the equipment replacement is delayed, and how long the equipment can run before the equipment fails) and its policy of not running equipment to failure are reasonable.588 Further, as cited by TURN, projects in which the benefit-cost ratio falls below 2.0 can be approved when the additional replacement is required for safety or other regulatory reasons, or when the benefit-cost ratio is above 1.0 and there is a high degree of confidence in the assumptions used in the benefit-cost calculation.589 Accordingly, we reject TURN's recommendation to remove 12 hydro refurbishment projects from SCE's TY 2009 small hydro refurbishment projects capital forecast.

DRA recommends SCE be required to evaluate the cost-effectiveness of its continued investments in small hydro projects in its next GRC.590 DRA makes this recommendation because SCE includes capital improvements in this proceeding to its small hydro projects with capacity factors ranging from 15% in 2002 to 75%. According to DRA, these projects appear to be just barely cost-effective, and DRA expresses concern that SCE did not undertake a cost benefit analysis or consider decommissioning any of the projects.591

SCE contends DRA's cost-effectiveness recommendation is unnecessary because the requested analysis can be undertaken through the normal GRC discovery process. While the GRC discovery process provides a means for DRA to obtain the necessary information to evaluate the cost effectiveness of SCE's small hydro projects, we find it to be more efficient to require SCE to provide this information as part of its next GRC application.

8.2.6. Lundy Powerhouse Project

SCE includes $2.4 million in its 2007-2011 capital forecast to modify its 3 MW Lundy Powerhouse which discharges water to Wilson Creek. This project entails the upgrading of an earthen ditch from the Lundy Powerhouse to Mill Creek either by application of concrete gunite or by installing a new parallel pipeline to handle the flow rates now mandated.592 This project is opposed by IAG and TURN.

SCE has not yet made a formal project design request from its in-house engineering and technical services group.593 Therefore, SCE does not know whether the project will require gunite, plastic pipe, steel pipe, or something else. Upon completion of the project engineering, which SCE expects to occur in mid-2009, SCE must then submit the project plans to five agencies for review. These agencies include FERC, U.S. Fish & Wildlife, U.S. Forest Service, U.S. Bureau of Land Management, and the County of Mono. The project plans may also need to be submitted to two additional agencies for review, the U.S. Army Corp of Engineers and California State Water Resources Control Board.594

SCE did not provide a specific time when it intends to actually undertake this project. However, given that project engineering is not expected to be completed until mid-2009 and that it must then undergo review by at least five separate agencies, we doubt this $2.4 million project can even be completed prior to the 2011. Therefore, this project is excluded from SCE's forecasted capital expenditures.

8.2.7. Gas-Fired Generation

SCE forecasts $34.646 million in capital expenditures for its five peakers. Of this amount, there is a disagreement on $26.237 million, of which $19.134 million pertains to the purchase and installation of new service air and back-up gas compressors at each of its peaker sites for system reliability, and $7.103 million pertains to purchase of a spare combustion turbine.

8.2.7.1. New Compressors

SCE wants to construct new back-up gas compressors and service air compressors at each peaker site during 2008 through 2010 for system reliability. The gas compressors are estimated to cost $13.299 million and the air compressors $5.835 million.

TURN recommends that this project be reduced by $9.134 million to $10 million because SCE (1) acted with questionable prudence during the construction of the peakers causing a need for new compressors, and then (2) compounded its original errors by choosing a high cost method for installing the new compressors. TURN also claims this installation method, besides being costly, is less reliable than other available equipment and requires more maintenance.595 TURN's $10 million recommendation represents the cost of buying, but not installing, screw-type air and gas compressors plus the cost of a set of spares as calculated by TURN.

SCE acknowledges that General Electric's standard offering consisted of only a single gas reciprocating unit and single air compressor at each site and that SCE knew the reciprocating units have lower capital cost, but higher maintenance costs and down-time, than screw-type compressors. SCE states it considered alternatives. These alternatives included: purchasing new peakers using the manufacturer's standard design to meet the construction schedule at minimum cost; purchasing spare compressors to reduce peaker downtime (but causing increased operating and maintenance costs); upgrading the original units during the design of the peakers (requiring a redesign and resulting in increased costs and an extension of the construction schedule); and completing the project using the manufacturer's standard design and then later adding redundant compressors at each site. SCE chose the latter option to enhance reliability. SCE asserts that option is consistent with industry practice for these compressor systems. Redundant screw-type design compressors were selected to reduce operating and maintenance costs.596 SCE supported its project with benefit-cost analyses showing that air compressors have a 1.9 benefit-cost ratio and gas compressors a 1.8 benefit-cost ratio.

We find that SCE has successfully refuted TURN's criticism of SCE's decisions during construction of the peakers. However, elsewhere in this decision we remove from SCE's request for O&M the expenses associated with operation of the yet-to-be constructed fifth peaker. Accordingly, consistent with this O&M reduction, we remove from SCE's proposed capital projects the approximate costs associated with the fifth set of back-up compressors, $3.426 million.597 SCE's proposed capital expenditures to construct new back-up gas and service air compressors at four peaker sites during 2008 through 2010 for system reliability are reasonable and are adopted.

8.2.7.2. Spare Combustion Turbine

SCE forecasts $7.103 million to purchase a spare General Electric LM 6000 combustion turbine to sustain peaker reliability and minimize overhaul outage time. Its request to include the spare combustion turbine was based on the results of its economic analysis that shows a 1.6 benefit-cost ratio and consideration of alternative solutions, such as leasing.598

TURN opposes this spare combustion turbine based on the results of its own economic analysis which showed only a 0.7 benefit-cost ratio. However, TURN did not use the turbine manufacturer's specifications. TURN analyzed two scenarios, one based on a 99% peaker availability and the other on 98.1%, both of which exceeded the manufacturer's 96.8% specifications for the combustion turbine. At the manufacturer's (lower) availability level, the usefulness (and hence the cost-effectiveness) of the spare turbine increases. SCE's $7.103 million spare combustion turbine project for the 2010 attrition year is reasonable and is adopted.

8.2.8. Pebbly Beach

SCE forecasts $24.085 million of capital expenditures on Pebbly Beach generating station capital projects. Two of these projects totaling $5.54 million are opposed by DRA, namely, a new administration building and land for an adjacent micro turbine.

SCE forecasts $4.92 million of capital expenditures to construct a new administration building. SCE describes the current administration building as inadequate for health, safety, and security, and lacking sufficient office and parking space. SCE was authorized $3.9 million in its 2006 GRC to fund a new administration building, but it diverted these funds to meet unforeseen load growth during that time period.

No party disputes the need for a new Pebbly Beach administration building. However, DRA opposes SCE's request because SCE already obtained funds for this project.599 While SCE reallocated the administration building funds to an important customer use, load growth, we find no justification for SCE's decision to continue to require employees to work in a facility it describes as inadequate for health and safety. We allocated these funds to SCE in our prior GRC decision, and we expected this project to be completed based on the risks the facility presents to employees. SCE's request for $4.92 million for the Pebbly Beach administration building project is denied.

SCE's micro turbine project involves installing up to 25 micro turbines providing 60 kW to Pebbly Beach customers. These micro turbines will be located on land adjacent to the current Pebbly Beach Generating Plant. Although this land is owned by the Catalina Island Company (Catalina Island) and is being used by a tenant for a container storage facility, SCE has the right to request that Catalina Island provide the land to SCE for electric utility purposes pursuant to a memorandum agreement between SCE and Catalina Island. As a condition for use of the site, Catalina Island requires SCE to design and improve a new site for the storage facility.600 SCE has included $0.62 million in its capital expenditures for the relocation of the existing container storage facility at this site.

DRA opposes capitalization of this relocation cost on the basis that it is a one-time expense and SCE will not retain any assets associated with relocating the container storage facility.601 Although SCE will not retain any assets from relocating the tenant's containers, the cost is a necessary component of SCE's ability to place its micro turbines on the land. This relocation cost should be capitalized as land rights because the land being made available as a result will be used for utility purposes. We therefore deny DRA's $0.62 million micro turbine relocation adjustment.

8.3. Transmission & Distribution Capital

SCE provides testimony supporting T&D capital expenditures over the five-year period 2007-2011. For 2007-2009, SCE proposes cumulative T&D capital expenditures of $5.704 billion.

8.3.1. Customer Growth

Customer growth capital expenditures are costs incurred to construct the facilities that connect new customers to SCE's distribution system. This forecast is an arithmetic product of the meter forecast times the cost per meter forecast. In rebuttal, SCE agreed to revise its meter set forecast to match the meter forecasts of DRA and TURN.602 This leaves the following customer growth issues to be resolved: (1) Cost Per-Meter, (2) Transformers, and (3) New Service Related Growth.

8.3.1.1. Cost Per-Meter

SCE's residential, agricultural, and commercial/industrial customers Cost Per-Meter forecasts are based on 2006 recorded amounts.603 TURN recommends lower Cost Per-Meter expenditures for each customer category. DRA recommends a lower Cost Per-Meter amount for the residential category only. DRA and TURN cite to declining meter sets, backbone expenditures in 2007 that will not go forward, and comparisons to overtime and increasing workforce levels to support their recommendation.604 SCE substantially reduced its forecast in the number of meters for each customer class.605 Even with this reduction, SCE asserts that its overall workload is increasing and SCE will need to depend on contract crews and overtime to accommodate the significant overall volume of work that needs to be accomplished.606 Therefore, the overall mix of contract crews to SCE's labor charge will not significantly change. Overtime will occur and should be provided for whether it is in meter installation or elsewhere. However, it should not be double counted. SCE explains that even if SCE increases the number of contract crews by the same proportion as the increase in work, the contract overtime rate would remain the same. For these reasons, SCE's Cost Per-Meter forecast for residential, agricultural and commercial/industrial customers is reasonable and is adopted.

8.3.1.2. Transformers

SCE's forecast of capital expenditures for transformers related to new business is similar to Customer Growth expenditures and is based on a forecast unit price times the meter set forecast. SCE forecasts $59.4 million in capital expenditures for the period 2008-2009 based on a total of 144.8 thousand new meters. TURN recommends capital additions of $42.0 million or $17.4 million less than SCE requests based on 42.4 thousand less meters during the same time period.607 In its rebuttal testimony, SCE agreed to the lesser number of meters but increased its per-unit transformer costs to reflect actual price increases. Price increases included a 12.6% increase on August 1, 2006, 11.0% increase on January 1, 2007, 9.6% increase on October 1, 2007, and 2.9% increase effective January 1, 2008. Hence, SCE revised its initial capital expenditure forecast down to $51.2 million, an $8.2 million reduction from its initial $59.4 million forecast for the period 2008-2009.608 We find SCE's revised $51.2 million of Transformer capital expenditures for the period 2008-2009, of which $26.9 million is for 2008 and $24.3 million for 2009, reasonable and is adopted.

8.3.1.3. Customer Growth

In some instances, DRA supports the use of recorded 2007 capital data in on the basis that recorded data eliminates an additional year of forecasting errors but in other instance DRA supports the use of forecasted 2007 capital data. Regarding New Service Related Growth, DRA recommends SCE's 2007 recorded amount of $53.574 million for New Service Related Growth be adopted over SCE's 2007 forecasted data. The forecasted data is lower than SCE's recorded costs for that year.609 DRA uses SCE's 2007 recorded over 2007 forecasted data on the basis that the increased amount of capital expenditures spent are costs that are ultimately customer financed.610 It is reasonable and appropriate to adopt a consistent forecasting method, e.g., forecast or actual costs, for the capital expenditures associated with New Service Related Growth adopted in this proceeding. However, exceptions exists. Whether relying on forecasted or recorded data for capital expenditures is preferred often depends on an individual account analysis and the reasons why differences exist between forecast and actual expenditures. In this case, we find SCE's forecast reasonable. We adopt SCE's forecast of $294.892 million.

8.3.2. Load Growth Capital Expenditures

Load growth capital expenditures are for the expansion of SCE's system to meet increased customer load due to new customers entering the service territory, existing customers increasing their electric loads and to interconnect new generating plants to the system. Over the period 2008-2009, SCE forecasts System Load Growth capital expenditures of $721.7 million of which $283.0 million is for 2008 and $438.7 million for 2009. DRA recommends reducing SCE's forecast for Load Growth expenditures for this period611 by $182.1 million and presents a forecast of $539.6 million of which $209.6 million is for 2008 and $330.0 million for 2009.612 Because SCE's proposes a budget-based approach to PTYR, SCE also presents a specific forecast for 2010 and 2011.613 We address years 2010-2011 and PTYR elsewhere in this decision.

SCE explains it overspent its authorized load growth expenditures by $56.0 million in 2006.614 To maintain reliability of its system, SCE proposes a significant increase in capital expenditures. It uses peak load forecasts, identification of system requirements primarily through load flow studies, and an evaluation of several alternative projects that are needed to meet its reliability criteria.615

DRA uses a similar method to forecast load growth and determines that SCE's methodology does not capture demand reductions due to conservation and self generation. In addition, DRA claims SCE's capital expenditures forecast fails to adequately reflect the recently updated 2008 and 2009 lower sales forecast. DRA concludes that SCE's peak demand forecast should be reduced by six percent in 2008 and seven percent in 2009 because SCE did not adequately reflect updated or lower sales forecast for 2008 and 2009 resulting in a deferral of need until after 2009 for a number of projects forecasted by SCE.616

Both SCE and DRA employed load forecasts to support their respective proposals. Detailed descriptions of these forecasts, some of which are confidential, are contained in the record and are not repeated here. Although DRA's and SCE's forecasts are objective and employ similar methodologies, they are dependent on subjective inputs. SCE and DRA advance arguments in support of their respective subjective inputs and in criticism of the subjective inputs used by the other party. Some of these differences pertain to how the recent changes in the overall California economy, customer growth, weather, and energy efficiency impact the results of dated 2006 forecasts.

Given these most recent changes, insufficient information exists to conclude that the result of either party's load growth study is preferred over the other. However, the results are helpful in establishing a realm of reasonableness. Therefore, the mid-range between SCE's load growth request and DRA's recommendation for the years 2008 and 2009 should be adopted. SCE should be authorized $246.3 million in 2008 ($283.0 million plus $209.6 million divided by two) and $384.4 million in 2009 ($438.7 million plus $330.0 million divided by two) for a total load growth of $630.7 million for the period 2008-2009 to be managed by SCE. This results in a $91.05 million reduction in SCE's forecast for 2008-2009. For 2007, we find the recorded expenditures reasonable and we adopt those amounts. SCE completion dates are reasonable and are adopted.

8.3.3. Distribution Infrastructure Replacement

SCE plans to spend $2.9 billion over the five-year period 2007-2011 on its infrastructure replacement program. This request is discussed below.

8.3.3.1. Deteriorated Distribution Pole Replacements

SCE requests a total of $505.2 million in capital expenditures ($80.0 million in 2007, $88.1 million in 2008, $109.7 million in 2009, $112.2 million in 2010, and $115.2 million in 2011) to replace deteriorating distribution wood poles. These capital funds will be used to replace 8,630 poles in 2007, 9,673 poles in 2008, and 11,768 poles in 2009.617 DRA recommends that SCE's 2007 forecast be reduced by $3.4 million to $76.6 million from $80.0 million and that the subsequent years, 2008 and 2009, be adjusted to the $76.6 million actual 2007 capital expenditures.618 SCE argues that its historical experience should not be the basis for future capital expenditures in this category because its prior experience of significant and unforeseen increases in customer and load growth required SCE to reprioritize its capital spending, which led to reductions in spending on its pole replacement program.

We disagree. We find that recorded costs, rather than a budget-based method, is a more reliable forecasting methodology in this instance as SCE has failed to provide a reasonable explanation for deferring work in this area and does not adequately explain its forecasted increase in expenditures. Unexpected load growth is not a sufficient reason to excuse maintaining distribution poles. Accordingly, we adopt DRA's proposal for years 2007-2009.

8.3.3.2. Suspected PCB Transformers

SCE requests $1.0 million each year, beginning in 2009 to proactively remove an estimated 24,000 PCB-contaminated distribution transformers at a rate of 250 each year. This request supplements its current program of removing 55 of its PCB-contaminated distribution transformers from its system each year through normal replacements. SCE's request to accelerate this project is based on its belief that the federal government may soon pass legislation requiring all utilities to remove from their system equipment containing more than 50 PPM of PCB by the year 2025 and because the Environmental Protection Agency's proactive voluntary removal program imposes significant management and liability concerns.619

DRA recommends that this project not be approved because SCE is not required to accelerate its current program and SCE's belief that legislation will soon pass requiring utilities to remove equipment containing PCBs in the next few years is speculative.620

Although SCE is not currently required to accelerate its program of replacing PCB Transformers, PCB is a health and safety issue that impacts both its employees and customers. It is appropriate that SCE aggressively addresses this matter. The PCB Transformer capital replacement program of $1.0 million annually beginning in 2009 is reasonable and is adopted.

8.3.3.3. Street Light Replacement

SCE forecasts a constant $14.4 million level of expenditures for years 2007-2009 to replace overhead street light wire and underground cable serving street lights, deteriorated street light fixtures and street light poles. DRA recommends adjusting SCE's forecast to reflect the 2007 recorded spending level of $10.5 million for each of the years 2007-2009, adjusted for inflation.621 DRA's forecast is based on more recent recorded data. In Rebuttal, SCE says that "...SCE's plan for replacing street light poles and fixtures in 2007 could not be performed for reasons beyond its control. Unforeseen surges in customer and load growth compelled SCE to redirect funds away from street light needs to fund the more urgent need to service customers."622 We do not find SCE explanation of unforeseen load growth a sufficient reason to defer maintenance in this area. Accordingly, we find DRA's forecast reasonable. Therefore, an annual $10.5 million of Street Light Replacement capital expenditures for the years 2007-2009 is adopted.

8.3.3.4. Capacitor Bank & Switch Replacement

SCE requests $23.1 million in capital expenditures over the period 2007-2009 to replace 1,280 capacitor banks and 1,331 capacitor switches due to aging infrastructure.623 This equates to $7.3 million in 2007, $7.5 million in 2008, and $8.3 million in 2009.

DRA recommends that SCE's $23.1 million Capacitor Bank & Switch Replacement Program be reduced by $3.5 million to $19.6 million. DRA's lower forecast is based on SCE's failure to demonstrate a need to substantially increase the replacement of older capacitor banks at the 2007 rate of 404 each year, which enables SCE to replace all of its older banks within the next five years. In regards to bank and switch replacements, DRA disagrees with SCE's proposal to base these replacements based on historical number of capacitor banks and switches identified for replacement instead of the number actually replaced. For example, in 2006, SCE only replaced 200 of its 373 capacitor banks identified for replacement, and in 2007 it replaced only 404 of the 456 capacitor banks it identified for replacement.624 As for capacitor switches, SCE only has data that shows the number of capacitor switches replaced and not those identified for replacement.625 For these reasons, DRA places reliance on SCE's recorded data.

We find SCE has not justified a two-year acceleration of its current five-year bank replacement program in light of the 2007 recorded replacement rate of 404 each year. Regarding the capacitor switches, reliance must be placed on the only data available, a history of recorded data. Therefore, DRA's $19.6 million capital expenditure forecast for the years 2007-2009 is reasonable and is adopted.

8.3.3.5. Deteriorated Underground Structure Replacement

SCE forecasts $7.2 million in capital expenditures for the period 2009-2011, of which $2.0 million is applicable to 2009, to replace eight deteriorated underground structures (vaults) per year.626 This forecast is based on SCE's knowledge of a construction quality issue in vaults built between 1964 and 1983, the existence of 500 active work orders for serious problems in these vaults, and the fact that ten vaults have already been condemned and identified for replacement.627

DRA relies on recorded data which shows that SCE only replaced two underground vaults in 2004 and four in 2005 and recommends $0.8 million for the replacement of three of SCE's requested eight vaults in 2009. In response, SCE's explain that its failure to adhere to its 2006 GRC forecast for replacement of underground structures was due to the seriousness of the unexpected surge in load/customer growth. The decision to postpone replacement of structures was not, in SCE's view, discretionary but necessary to meet the needs of our customers.628

SCE has not substantiated its claims that reliance of recorded data in this instance is not appropriate. Moreover, it is unclear why this serious problem took a lower priority to customer growth matters. In the absence of a proposal by SCE that incorporates historical data and further explains why SCE viewed this deferral as mandatory, we adopt DRA's recommendation.

8.3.3.6. Underground Mainline Oil Switch

SCE forecasts $32.7 million to replace Underground Mainline Oil Switches during the period 2007-2009. Of this amount $10.3 million is forecasted in 2007 to replace 232 switches, $8.4 million in 2008 to replace 185 switches, and $14.0 million in 2009 to replace 300 switches. DRA recommends $27.3 million, a $5.4 million reduction in SCE's 2009 forecast to bring down the number of switch replacements in that year to the 2008 number of 185 switch replacements.

SCE began a program to replace these older switches in 2000. SCE currently has approximately 7,000 of these switches in service, of which 1,700 are 35 years or older. These switches, used in SCE's distribution system for opening and closing electrical circuit connections, are inspected every three years and if found to be deteriorating during those inspections are replaced. However, deterioration of the electrical contact and other components internal to the switch cannot be detected. Any failure of these switches that results in arcing across electrical components under oil creates highly explosive acetylene gas. In-service failures of these switches result in circuit interruptions, pose a threat to public and employee safety and affect system reliability.629

SCE has replaced a yearly average of 180 switches from the start of its replacement program in 2000 through 2006 and a yearly average of 188 switches through 2008. SCE seeks to further increase that replacement number to an annual replacement level of 300 switches. Although no party opposes SCE's systematic replacement of these switches, DRA finds no reason to accelerate this replacement program at this time.

Although these switches are dated, SCE has an overlapping program that enables it to replace switches found to be deteriorating during periodic inspections. In addition, to the extent SCE deemed work on this equipment unnecessary due to unexpected load growth, we find SCE's explanation inconsistent with the public safety issues that could result from such deferred maintenance. Such a deferral also fails to support SCE's request to increase its replacement rate. Accordingly, we find SCE has not adequately justified a need to almost double its replacement of switches under this program. DRA's $27.3 million forecast for the replacement of Underground Mainline Oil Switches during the period 2007-2009 is reasonable and is adopted.

8.3.3.7. Underground Cable Replacement

SCE forecasts $58.5 million for Underground Cable Replacement during the period 2007-2009. Of this amount $6.3 million is forecasted in 2007 to replace 35 miles of cable, $14.4 million in 2008 to replace 78 miles of cable, and $37.8 million in 2009 to replace 200 miles of cable.630 DRA recommends $10.5 million, a $48 million reduction in SCE's total forecast based on SCE's 36 mile yearly average rate of replacing underground cable over the recorded years 2005-2007.631

SCE has approximately 46,000 miles of underground primary cable in its distribution system. This cable is comprised of four different types of cable, a majority of which is tree retardant cross-linked polyethylene. Approximately 10% of its underground primary cable or 4,495 miles of SCE's oldest cable consists of paper insulated lead covered cable which is incompatible with modern components and cannot be used with today's removable elbow connectors for which all modern switches, transformers, and junction bars are designed. Near the end of its useful service life is its next oldest cable consisting of high molecular weight polyethylene. This cable represents approximately 3% or 1,451 miles of SCE's underground primary cable.632

SCE claims that failure of this cable could pose serious reliability problems to its system but at this same time SCE found it reasonable to fund the costs of new meters and install new distribution facilities to meet that growth by reprioritize its capital spending, which led to reductions in spending on preemptive cable replacement.633 As a result, it is unclear what the level of urgency is for the proposed cable replacement. In this situation, we find reliance on historical date more reliable. Accordingly, DRA's $10.5 million forecast for Underground Cable Replacement during the period 2007-2009 is reasonable and is adopted.

8.3.3.8. Cable in Conduit Replacement Program

SCE forecasts $5.8 million to replace 30 miles of cable in conduit (CIC) in 2009 as a pilot program to explore and develop improved replacement methods. DRA does not recommend funding this program on the basis that SCE has not substantiated the program's need and because SCE already proactively replaces cables under two other programs, the Cable Replacement Program and the Worst Circuit Rehabilitation Program.634

CIC is an unjacketed cable housed in polypropylene plastic tubing making it difficult and costly to remove cable from the polypropylene tubing so that replacement cable can be reinserted, often resulting in abandoning the cable in place and digging a trench to install new cable. Among the reasons for this pilot program is to investigate new approaches to replacing CIC so that future replacement of the approximate 10,000 conductor-miles of CIC type cable currently in SCE's system can be replaced at a more affordable costs than currently.635

SCE's $5.8 million pilot CIC Cable Replacement Program is reasonable and is adopted.

8.3.3.9. Worst Circuit Rehabilitation

SCE forecasts $31.8 million over the period 2008-2009 to rehabilitate the worst performing circuits on its system in terms of reliability, of which $10.8 million is for 29 circuits in 2008 and $21.0 million for 40 circuits in 2009.636 DRA recommends $10.5 million based on SCE's recorded data, a $21.3 million reduction in SCE's forecast.637 In 2006, SCE's recorded costs associated with rehabilitating the worst performing circuits was $5.8 million and during the 2002-2006 period, SCE spent a total of approximately $13 million.

SCE is requesting a substantial increase based on recorded costs for this program. In addition, SCE explains that because it experienced significant and unforeseen increases in both customer growth and load growth, SCE funded the costs to set new meters and install new distribution facilities to meet that growth by reducing its spending in this area.638 SCE does not quantify the impact of its decision to postpone rehabilitation of these circuits by, for example, explaining whether maintenance costs increased or the amount of work needed to rehabilitate the circuits increased as a result of this deferral. Moreover, it is unclear why rehabilitation of these circuits is urgent now but, during 2006-2007, it was not. In this situation, we find historical data more reliable than SCE's projections.

DRA's $10.5 million Worst Circuit Rehabilitation Program capital expenditure forecast is reasonable and is adopted.

8.3.4. Substation Infrastructure Replacement Program

SCE's capital substation replacement programs are designed to replace aging substation infrastructure, consisting primarily of circuit breakers and transformers, before that equipment fails. SCE forecasts approximately $434.6 million over the period 2007-2009 for these programs. DRA recommends $359.2 million, $75.4 million less than SCE's forecast for the same period.639 Differences between SCE and DRA are in the following replacement programs: (1) Transformer A-Banks, (2) Transformer B-Banks, (3) Distribution Circuit Breakers, (4) Distribution Protection and Control, and (5) Routine Capital Replacements consisting of (a) On-Line Gas Monitoring for Bulk Transformers, (b) Rule 20B Circuit Breakers, (c) Overhead Lines, and (d) Circuit Electrical Infrastructure. These differences are addressed below.

8.3.4.1. Transformer A-Banks

SCE forecasts $42.0 million over the period 2007-2009 to replace 10 A-Bank transformers of which $12.2 million is for replacing three transformers in 2007, $4.2 million for replacing one transformer in 2008, and $25.6 million for replacing six transformers in 2009.640 DRA recommends a total of $20.7 million, $21.3 million less than SCE's forecast over the same period. This $21.3 million difference results solely in the year 2009. SCE forecasts the replacement of six transformers in 2009 and DRA only recommends one replacement.

Although SCE forecasts the number of A-Bank transformers as part of its Transformer Research Management Program its selection of replacement A-Bank transformers was based on a ground-up forecast based on an average per-unit cost and does not account for historical failure rates.641 On average the number of A-Bank Transformer failures is 1.1 per 12 months which equals one failure every 11 months.642

SCE should have taken into consideration the actual failure rate of these transformers in considering how often to replace its transformers. Based on this failure rate, SCE's forecast for replacing six transformers in 2009 appears excessive and DRA's one transformer inadequate. Given SCE's A-Banks 1.1 failure rate, we find it reasonable to authorize SCE to replace two A-Bank transformers in 2009 for a total of $8.4 million, twice the 2009 amount recommended by DRA for the replacement of one such transformer. Accordingly, we adopt SCE estimates with the exception of 2009. For 2009, we adopt a forecast of $8.4 million.

8.3.4.2. Transformer B-Banks

SCE forecasts $31.8 million over the period 2007-2009 to replace B-Bank transformers of which $7.9 million is for 2007, $11.8 million to replace 16 transformers in 2008, and $12.1 million to also replace 16 transformers in 2009.643 DRA recommends $16.6 million, $15.2 million less than SCE during the same period.644 This difference is attributed to DRA using 2004 and 2006 historical replacement data to determine an appropriate number of transformers that should be replaced in 2008 and 2009. Based on its review of historical data, DRA recommends SCE only replace six of the 16 transformers it forecasts for replacement in both 2008 and 2009.645

Unlike its A-Bank replacement forecast, SCE reflected the higher B-Bank failure rate of 10 (versus one a year for A-Bank Transformers) in forecasting the number of B-Bank transformers to be replaced. 646 SCE's $31.8 million forecast over the period 2007-2009 to replace B-Bank Transformers is reasonable and is adopted.

8.3.4.3. Distribution Circuit Breakers

SCE forecasts $47.1 million over the period 2007-2009 to replace 342 aging power circuit breakers, which consists of $7.2 million to replace 54 in 2007, $20.3 million to replace 148 in 2008, and $19.6 million to replace 140 in 2009.647 DRA recommends $25.2 million for the replacement of 184 circuit breakers based on SCE's historical experience. This is $21.9 million lower than SCE's forecast for the same period. DRA accepts SCE's 2007 forecast of replacing 54 circuit breakers in 2007. However, DRA recommends reducing SCE's 2008 forecast of replacing 148 circuit breakers in 2009 and 140 in 2009 to 65 in each of those years.

SCE's circuit breaker replacement forecast is not based on historical data. Instead, SCE bases its forecast on the age or condition of equipment needing replacement. SCE explains that historical data would show a decrease in SCE's replacement efforts due to unexpected customer load growth.648 Historical data is relevant and SCE fails to provide an adequate explanation for deferring work on this important project. Therefore, SCE's forecast of $47.1 million over the period 2007-2009 to replace 342 aging power circuit breakers is unreasonable. Instead, we adopt DRA's forecast, which relies on historical data.

8.3.4.4. Distribution Protection & Control

SCE forecasts $18.6 million over the period 2007-2009 to replace protection and control equipment, of which $1.9 million is for 2007, $1.2 million for 2008, and $15.5 million for 2009.649 DRA recommends $10.5 million, $8 million less than SCE for the same period. The only difference between SCE and DRA is in the number of protection and control equipment to be replaced. SCE forecasts it will replace 25 and DRA recommends 12 based on historical data. SCE explains that, due to unprecedented customer growth and load growth, it diverted funds from this program to address growth issues.650 Now, SCE will return the program to its original scope and will increase its replacement of substations to 25 per year. SCE does not quantify its reduced spending due to customer and load growth issues.

DRA's recommended replacement of 12 protection and control substations per year will take 50 years for SCE to completely replace its antiquated electro-mechanical devices at its 600 substations.651 It will also place some of its aging equipment well beyond their reasonable expected life. However, we remain concerned about SCE's decision to defer this important program for reasons we find insufficient, unanticipated customer and load growth. Based on SCE's decision, the urgency of replacement is unclear. In addition, in the absence of specific amounts related to funding customer growth issues, we find it reasonable to reduce SCE's $18.6 million forecast over the period 2007-2009 by adopting DRA's position.

8.3.4.5. Routine Capital Replacements

SCE and DRA differ in the forecasts of four Routine Capital Replacement programs, each of which are discussed below. These programs are: (1) On-Line Gas Monitoring for Bulk Transformers, (2) Rule 20B Circuit Breakers, (3) Overhead Lines, and (4) Critical Electric Infrastructure.

SCE forecasts $20.1 million for the period 2008 through 2011 to install monitoring equipment that will automatically measure transformer oil on its 246 AA- and A-Bank transformers every four hours, thus allowing for remote monitoring. Of this amount, $14.4 million is under the CPUC jurisdiction, leaving a yearly California jurisdictional cost of $4.7 million for the years 2009, 2010, and 2011.652 SCE intends to install approximately 60 units each year.

DRA recommends that this program be scaled down to $1.5 million (19 units each year rather than 60 units per year). This is because approximately one-third of the transformers that will be automatically monitored are under 30 years old and because SCE has not demonstrated a need to monitor this group as frequently as every four hours.

SCE acknowledges that age is an important factor in determining which transformers are near their technical end-of-life. However, it asserts that DRA's recommended 19 units per year would undermine the objective of this program which is to employ modern technology to assess the condition of its A- and AA- Bank transformers. Further, it would enhance reliability levels and extend the operating life of transformers by detecting the onset of transformer failures.653

Although SCE has a valid interest in mechanizing its monitoring of A- and AA-Bank transformers, it has not substantiated an accelerated need to mechanize the monitoring of its newer Bank transformers. DRA's recommendation for the installation of 19 automatic monitoring equipment on its A- and AA-Bank transformers at a cost of $1.5 million in 2009 is reasonable and is adopted.

SCE forecasted $5.2 million over the period 2007-2009 to replace older 66 kV and 115kV class circuit breakers that are incapable of de-energizing underground cable beyond a certain length, of which $1.3 million is for 2007, $1.4 million for 2008, and $2.5 million for 2009. Based on recorded data, DRA recommends $3.7 million over the same time period, which equals a $1.5 million reduction to SCE's forecast.654 However, SCE subsequently agreed with DRA's total $3.7 million recommendation for Rule 20B Circuit Breakers over the period 2007-2009.655 Hence, DRA's $3.7 million recommendation is reasonable and is adopted.

SCE forecasted $8.3 million over the period 2007-2009 for work activity associated with sub-transmission line additions and retirements, of which $4.4 million is for 2007, $1.95 million for 2008, and $1.99 million for 2009. DRA recommends $5.5 million over the same time period, or $2.8 million lower than SCE's forecast. This $2.8 million difference largely resulted from SCE including a one-time project in its 2007 forecast, which was not completed. SCE subsequently stated that recorded 2007 data should be used.656 The 2007 recorded data reflects the removal of the one-time project. We agree that recorded 2007 data is more reliable and find the use 2007 recorded data appropriate in this instance.

SCE forecasts $1.5 million over the period 2007-2009 on a pre-fabricated, mobile system that could be transported to any of its 50 bulk power substations to restore control and protection of the power grid in the event of a major disaster.657 DRA recommends no funding on the basis that the project is not fully supported.658 This project is designed to enhance system reliability. Accordingly, we find it reasonable and adopt it.

8.3.5. Reliability Investment Incentive Mechanism

SCE recommends that the Reliability Investment Incentive Mechanism, referred to as RIIM, which was authorized in the 2006 GRC by D.06-05-016 be reauthorized in this proceeding with certain modifications. SCE proposes setting a RIIM target of $2.566 million in reliability-related capital expenditures.659 In a separate section of this decision, we reject the RIIM. Our decision to reject RIIM has no impact on SCE's requested revenue requirement. This matter is addressed in more detail in a separate section of this decision.

8.3.6. Operational Technology

SCE requests $275 million in capital expenditures for Operational Technology projects during the period 2007-2011, which include both FERC and CPUC jurisdictional projects. These projects are: (1) Phasor Measurement & Grid Stability System, (2) Distribution Control & Monitoring System, (3) Distribution Automation - Circuit Automation, (4) Critical Video Substation Surveillance, (5) Energy Management System, and (6) Centralized Remedial Action Scheme (C-RAS).

8.3.6.1. Phasor Measurement & Grid Stability System

SCE forecasts $34.0 million over the period 2009-2011, of which $13.0 million is applicable to 2009 to implement a system that will give its system operators a direct indication of transmission system stress, and how close to the margins SCE is operating from system instability and potential system failure.660

DRA recommends no funding for this project because, among other reasons, SCE could not identify what equipment it was basing its estimates on and was unable to explain the potential vendors' knowledge of Phasor Measurement and Grid Stability Systems.661

We find this system will enable SCE to better provide system reliability, to manage its electric system during times of transmission system stress, and avoid close operating margins and system instability. SCE's $13.0 million forecast for the year 2009 to implement its Phasor Measurement & Grid Stability System is reasonable and is adopted.

8.3.6.2. Distribution Control & Monitoring System

SCE forecasts $20 million over the period 2009-2011 to upgrade its Distribution Control & Monitoring System (DCMS) with new hardware and software, of which $3.0 million is applicable to 2009. DRA recommends that SCE be authorized only $0.1 million in 2009 to upgrade its software. Since installed in 1994, SCE's DCMS has undergone several upgrades, its software was upgraded in 1999 and server hardware in 2007. Problems with the existing DCMS reported by SCE include: (1) obsolete software not supported by vendors, (2) inability to mitigate known security vulnerabilities in the system, (3) lack of an operator training simulation, and (4) insufficient data management capabilities.662 We find that, although DRA's proposal would enable SCE to upgrade its software, SCE would actually need an additional $0.9 million above DRA's recommended $0.1 million to undertake that upgrade.663 In addition, DRA's recommendation would not resolve the other shortcomings of the existing DCMS. SCE's 2009 forecast of $3.0 million for upgrading its DCMS is reasonable and is adopted.

8.3.6.3. Circuit Automation

SCE forecasts $16.9 million over the period 2007-2009 to automate overhead and underground distribution switches, of which $4.8 million is for 2007, $5.5 million for 2008, and $6.6 million for 2009. DRA recommends $14.7 million over the same time period, or $2.2 million lower than SCE's forecast, based on SCE's most recent spending level for this program and lack of support for the number of overhead and underground remote control switches that SCE intends to install. DRA's $14.7 million forecast for Circuit Automation switches is reasonable and is adopted.

8.3.6.4. Critical Video Substation Surveillance

SCE forecasts $7.0 million over the period 2009-2011 to upgrade its existing security plans at 14 of its 220 kV substations by installing perimeter intrusion detection systems with remote video surveillance. Of this total, $3 million will be spent to install this equipment at six substations in 2009 and $2.0 million for four substations in each of the 2010 and 2011 years.664

Although DRA accepts SCE's cost estimate to install the surveillance equipment per substation it recommends only $1.0 million for 2009, $2.0 million less than SCE's forecast. In support of its recommendation, DRA cites the time line required from preparing a request for proposal, which has not yet occurred, to the completion date for installation. DRA contends that SCE will only be able to complete installation at two substations in 2009.665

SCE, having previous experience with this type of security project, anticipates a rigorous vendor selection process that will be completed by the second quarter of 2009 and, as a result, it will be able to complete its forecasted six substations in 2009. SCE's $7.0 million forecast over the period 2009-2011 to upgrade its existing security plans at 14 of its 220 kV substations is reasonable and is adopted to protect the safety and security of its most critical facilities.

8.3.6.5. Energy Management System

The Energy Management System (EMS) is a computer platform that monitors and controls the flow of power throughout SCE's transmission grid. In other words, this system serves as the primary tool used by grid operators to monitor and control SCE's transmission and distribution system. SCE explains that its current EMS is obsolete.666

SCE requests $17.4 million to upgrade its EMS. Of this amount, $9.6 million is forecasted in 2007, $5.5 million in 2008, and $2.3 million in 2009. DRA recommends $13.5 million. This amount includes reductions of $1.7 million in 2007 to reflect SCE's actual capital expenditures, $1.1 million in 2008 because SCE has historically spent only 88.5% of its 2006 and 2007 forecast for this ongoing project, and $1.0 million in 2009 for "unknown" updates.667 SCE subsequently agreed that its 2007 forecast should be adjusted downward by $1.7 million to reflect its actual 2007 EMS capital additions.668

DRA's forecast, which is based on historical data, is more reliable than SCE's goals regarding EMS. DRA's $13.5 million EMS capital expenditure forecast for the period 2007 through 2009 is reasonable and is adopted.

8.3.6.6. Centralized Remedial Action Scheme

SCE requests $112.2 million over the period 2007-2011 for its Centralized Remedial Action Scheme (C-RAS) project that impacts Transmission Substations, General Buildings, and Telecommunications Equipment. Of this amount, $52 million applicable to Transmission Substations is allocated to FERC jurisdictional rates, $18.2 million of the $19.2 million applicable to General Buildings is allocated to the CPUC, and $38.9 million of the $41.0 million applicable to Telecommunications Equipment is allocated to the CPUC.669

DRA initially recommended that this request be denied based on its understanding that the project was entirely under FERC jurisdiction. DRA subsequently recognized in its opening brief that the C-RAS project is subject to FERC and CPUC jurisdiction and should be allowed.670 Therefore, SCE's $58.1 million capital expenditures associated with its C-RAS project is reasonable and is adopted.

8.3.7. Customer Requests

8.3.7.1. Purchase and Upgrade of Distribution Systems on Military Bases

SCE initially forecasted $73.1 million in capital expenditures for the purchase and upgrade of distribution systems at eight military bases, of which $53.0 million was for purchases in 2008 and $10.6 million for upgrading of facilities in 2008 and $9.5 million in 2009. SCE subsequently reduced its $73.1 million capital expenditures request by $67.2 million to $5.9 million, of which $1.7 million is for purchase and $4.2 million for upgrading one military base distribution system in 2008.671

DRA opposed the inclusion of any capital expenditures for the purchase and upgrade of the military base distribution systems because negotiations between SCE and the federal government for seven of the eight distribution systems were postponed until after 2009. DRA did not provide any funds for the purchase and upgrade of facilities for the remaining military base because of continued negotiations between SCE and the federal government and uncertainty that SCE will actually complete the purchase. To the extent that negotiations are successful and SCE purchases and upgrades the eight military base distribution systems, DRA recommends SCE be authorized to file an advice letter to recover its net cost.672

SCE has not reasonably substantiated it will acquire any of the eight military base distribution systems before the end of 2009. Therefore, SCE's $5.9 million capital expenditure forecast for the purchase and upgrade of the single military distribution system should be disallowed.

8.3.7.2. Rule 20A Conversions

SCE's Rule 20A tariff provides capital expenditures to governmental agencies within SCE's service territory for undergrounding existing overhead lines. SCE forecasts $116.1 million of Rule 20A capital expenditures for the years 2007-2009. This forecast is $28.3 million higher than DRA's $87.8 million forecast for the same period. DRA bases its forecast on 2007 recorded Rule 20A capital expenditures of $29.3 million. DRA did not rely on SCE's forecast because SCE has consistently under spent its authorized amounts. For example, SCE only spent $180.6 million of its $283.6 million authorized Rule 20A capital expenditures, or $103.1 million less than authorized, during its prior 2003-2007 period.673 Therefore, DRA recommends SCE's 2007 recorded Rule 20A capital expenditures of $29.3 million be adopted for each of the years 2007, 2008, and 2009 for a total $87.9 million.

DRA's forecast for 2008-2009 is more in line with the current economic conditions and more realistic given SCE's consistent under-spending of its Rule 20A funds. DRA's Rule 20A capital expenditure forecast of $29.3 million is reasonable and is adopted for 2007, 2008 and 2009.

8.4. Customer Service Capital

SCE presents four categories for its customer service capital expenditures: (1) structures and improvements, (2) furniture and equipment, (3) specialized equipment, and (4) meters. SCE forecasts a total of $105.412 million for customer service capital expenditures for the three-year period 2007, 2008, and 2009. DRA forecasts $85.719 million for the same time period, resulting in a $19.693 million difference between the two parties.674 This difference is the result of the use of different forecasting methods.

SCE derives its customer service capital forecast from a detailed five-year construction plan which undergoes review by manager-level planning committees for approval by project and reviewed at least annually.675 DRA uses SCE's 2007 recorded data for its 2007 forecasts for each of the four customer service categories. With the exception of adopting SCE's 2009 specialized equipment forecasts, DRA uses SCE's 2002-2006 five-year recorded average for its 2008 and 2009 forecasts of the first three customer service categories. DRA uses a different forecasting method for customer service meters, which is discussed separately.

Both SCE and DRA have a systematic method for forecasting customer service capital expenditures. However, we are unable to assess the reasonableness of DRA`s forecasting method for several reasons. These reasons include DRA's failure to reflect changes in the number of service employees and customers or provide for obsolescence of the customer service capital components in its historical five-year average. SCE's structures and improvements, furniture and equipment, and specialized equipment forecasts should be adopted as follows.

8.4.1. Structures and Improvements

SCE's Structures and Improvements capital expenditures forecast of $2.12 million in 2007, $2.01 million in 2008, and $5.88 million in 2009 is reasonable and should be adopted.

8.4.2. Furniture and Equipment

SCE's Furniture and Equipment capital expenditures forecast of $1.95 million in 2007, $2.05 million in 2008, and $2.25 million in 2009 is reasonable and should be adopted.

8.4.3. Specialized Equipment

SCE's Specialized Equipment capital expenditures forecast of $7.13 million in 2007, $1.94 million in 2008, and $5.90 million in 2009 is reasonable and should be adopted.

8.4.4. Meters

SCE's meters forecast includes two categories, routine work and non-routine work. Routine work pertains to new metering installations for new customers, routine maintenance and rate changes. Non-routine work pertains to new meters for special programs such as radio technology meters, remotely-read meters to address safety and access problems, and meter leasing.676

SCE and DRA differ on forecasted capital expenditures for meters. SCE forecasts $70.295 million for the three-year period 2007, 2008, and 2009 and DRA forecasts $65.4 million for this period, $4.89 million less than SCE. SCE forecasts its capital expenditures for meters by multiplying its estimated number of meter sets and changes for 2007, 2008, and 2009 to its yearly expected cost per meter. SCE then reduces that result by $0.113 million for anticipated productivity savings from its Enterprise Resource Planning program. This method results in capital expenditures of $22.7 million in 2007, $23.806 million in 2008, and $23.789 million in 2009.677

DRA's forecast differs from SCE's in that DRA uses SCE's $20.50 million 2007 recorded capital expenditures for its 2007 forecast. It also uses SCE's 2007 average recorded unit meter costs for its 2008 and 2009 forecasts. DRA multiplies that average recorded unit meter cost by its own 2008 and 2009 new meter connections forecast and to SCE's volume forecasts for routine changes and safety/access work. DRA accepts SCE's meter leasing forecasts.678 This forecasting method results in DRA recommending $20.5 million in 2007, $22.0 million in 2008, and $22.90 million in 2009.

DRA recommends that SCE's $70.295 million capital expenditures for meters be reduced by $4.895 million, the difference between SCE's $70.295 million 2007 through 2009 capital expenditures and DRA's $65.40 million.

The cost of new meter connections varies by customer class. Residential new meter connections are the most inexpensive of the customer classes. Agricultural and non-residential new meter connections cost more than twice the average rate of residential customer class meter connections. As a result, the mix of new meter connections by customer class can vary significantly from year-to-year resulting in an inaccurate cost of new meter connections in subsequent years.679

DRA's 2007 forecast of $20.5 million, reflecting SCE's actual mix and costs of meters in that year, is reasonable and should be adopted. However, DRA's use of 2007 average cost-per-meter installation for the years 2008 and 2009 is not reasonable because the mix of new meter connections varies by year and because DRA did not include any inflation effects to its 2008 and 2009 forecasts. Therefore, SCE's 2008 and 2009 cost-per-meter and customer forecasts, adjusted to reflect the volume of new customers being adopted in this decision, should be adopted.

8.5. Information Technology & Enterprise Resource Planning Capital

SCE identifies $697.9 million of capital expenditures for IT and Enterprise Resource Planning projects for the three-year period 2007, 2008 and 2009680 in its application.681 IT capital expenditure projects include infrastructure, storage media, communications, operating systems, application software, and personal computing and communications hardware used by its employees. The Enterprise Resource Planning project consists of software asset management upgrades to replace SCE's aging financial information system that have been in place for over twenty years. DRA recommends $612.3 million of capital expenditures for SCE's IT and Enterprise Resource Planning projects, $85.6 million less than SCE's request.

During evidentiary hearings, SCE and DRA agreed that $25.1 million of capital expenditures for UNIX hardware over the three-year period 2007 through 2009. We find this amount is reasonable and it is adopted.682 This amount is $7.4 million less than SCE's $32.643 million request and $4.475 million higher than DRA's $20.725 million forecast.683 SCE also agreed to DRA's forecast of $2 million for Identity Management. As part of its rebuttal testimony, SCE accepted DRA's use of 2007 recorded cost for all IT capital forecasts except for its 2007 NERC Critical Infrastructure request.684 SCE's acceptance of DRA's use of 2007 recorded data for IT forecasts, excluding NERC CIP which is discussed separately, is reasonable and should be adopted.

The agreed-upon capital expenditures for Identity Management, UNIX hardware, and the use of 2007 recorded data for all IT forecasts except for NERC CPI leaves three issues to resolve in this capital expenditure category: (1) Enterprise Resource Planning, (2) NERC CIP, and (3) Market Redesign and Technology Upgrade.

8.5.1. Enterprise Resource Planning Program

SCE forecasts $295.0 million in capital expenditures for the three-year period 2007, 2008, and 2009 to complete Phase 3 of its Enterprise Resource Planning Program.

DRA concurs with SCE's 2008 forecast of $114.5 million and 2009 forecast of $32.8 million. However, it recommends a $7.5 million downward adjustment to SCE's 2007 forecast of $147.7 million to $140.2 million.685

SCE testified that the $7.5 million difference between its forecast and actual capital expenditures for this project in 2007 resulted from several invoices that were expected to be received in 2007 for work performed in 2007 but that were instead received late and not paid until 2008. In addition, certain contract work that was expected to be invoiced in late 2007 was not invoiced until 2008. None of this work performed in 2007 but paid for in 2008 was included by SCE in either the 2008 or 2009 forecast. 686

SCE has substantiated its 2007 Enterprise Resource Planning forecast, which is reasonable and is adopted.

8.5.2. NERC Critical Infrastructure Project

SCE's 2007 IT Critical Infrastructure Project forecast of $3.123 million is $3.071 million higher than the $0.052 million it actually expended in 2007. DRA recommends SCE be authorized only the actual amount it expended in 2007. However, SCE explains it did not spend its entire 2007 forecast amount in 2007 because FERC took more time than SCE expected to approve the Critical Infrastructure Project Reliability Standards. FERC merely postponed implementation to 2008. SCE must now satisfy two FERC milestone dates, June 2009 and June 2010.687 SCE's 2007 IT Critical Infrastructure Project capital expenditures of $3.123 million are reasonable and are adopted.

8.5.3. Market Redesign and Technology Upgrade

SCE initially forecasted $51 million in capital expenditures for MRTU-related initiatives. Of this amount, $27.0 million is for 2007, $9.8 million for 2008, and $12.0 million for 2009. Pursuant to Resolution-4087, SCE is currently authorized to track its MRTU expenditures in a separate memorandum account and seek recovery of these costs in an ERRA proceeding outside of the GRC. SCE should use its authorized memorandum account to track and recover its MRTU capital expenditures. SCE's proposal to eliminate the memorandum account is discussed elsewhere in this decision.

8.6. Operations Support Capital - Corporate Real Estate

SCE's initial forecast for 2007-2011 for capital projects to construct or remediate non-electric facilities used by its Operations Support Business Unit was $1.243 billion. SCE later reduced its forecast to $1.197 billion.688 SCE's capital projects fall into three categories: (1) individual projects of at least $1 million; (2) individual blanket work orders of at least $1 million; and (3) projects and blanket work orders below the $1 million threshold.689 The third category cumulatively amounts to $3.7 million from 2007-2011. There is no controversy regarding the forecast for the third category of projects, and they should be approved as requested by SCE.

8.6.1. "Uncontested" Capital Projects Greater Than $1 Million

SCE identifies 25 Category 1 projects totaling $181 million as being uncontested projects that should be approved for the reasons stated in its direct testimony.690 Uncontested is commonly defined as "not disputed". However, the record does not support SCE's uncontested assertion for the Category 1 capital projects. SCE disagrees, for example, with DRA's forecasting methodology. DRA's forecasting method is not based on a project by project review, as acknowledged by SCE.691 DRA argues that, among other things, the most recent economic data should be used in projecting customer and load growth, infrastructure expansion needs, and so on. Current economic data and historical patterns of investment logically relate to the need and timing for these capital projects, just as they do for much of the forecasts that we consider throughout today's decision. In addition, TURN takes exception to SCE including contingencies in the range of 5% to 20% on each of its Category 1 projects.692 SCE's labeling of these 25 projects totaling $181 million over the five-year period, 2007 through 2011, as being uncontested is simply incorrect.693 The difference between the SCE and DRA forecasts are summarized in the table below:

DRA and TURN have made arguments in favor of a lower forecast than presented by SCE. We now examine the merits of those arguments.

8.6.2. DRA's Recommendations for Larger Capital Projects -Category 1

DRA recommends that SCE's $449 million Category 1 capital expenditures for 2007-2009 be reduced to $178 million for the same period. For 2007, DRA used SCE's actual capital expenditures of $60 million, which SCE was not able to allocate between Category 1 and Category 2 projects. DRA's 2008 forecast of $25 million is equal to SCE's forecast for that year, and DRA's 2009 forecast of $93 million is based on a two-year average of capital expenditures for 2006 and 2007, which equals $56 million. DRA then added $37 million to this $56 million base forecast to arrive at a total of $178 million Category 1 forecast for 2007-2009. The $37 million addition is for two of the larger Category 1 projects (the GO2 Data Center Upgrade and Remodel project and the GO3 and GO4 Furniture and Infrastructure project).696

SCE's forecast is based on detailed analysis of 38 individual projects. Such analysis does not guarantee that the individual projects will be carried out per the forecast. For example, in 2006, unanticipated levels of customer and load growth required SCE to shift funding to those needs and to scale back on authorized infrastructure replacement spending.

DRA had the advantage of using more recent economic data in its forecast than SCE. That data resulted in DRA recommending, and SCE subsequently accepting, substantially lower customer growth. The lower customer growth, in turn, reduces SCE's load growth operating requirements, electric infrastructure system expansion needs, and additional operating expense needs. DRA also relied on SCE's building survey, which concluded that its buildings are generally in good condition with few deferred maintenance issues. 697

At the same time, DRA recognizes that reduced customer and load growth do not uniformly affect SCE's proposed projects. For example, as identified by SCE, some of its capital projects, such as installation of high definition cameras in its helicopters to perform circuit patrols, respond to needs other than customer and load growth.698

8.6.3. TURN's Recommendations for Larger Capital Projects - Category 1

TURN recommends adjustments for the following projects out of SCE's larger Category 1 capital expenditure projects: (1) GO2 Data Center Upgrade & Remodel; (2) GO3 and GO4 Furniture and Infrastructure; (3) Energy Efficiency, (4) Satellite Service Center; (5) New Headquarters Building; and (6) the Rivergrade projects. According to TURN's analysis, SCE requests authorization to spend in 2009 ($332.8 million) approximately six times the amount actually spent in 2007 ($59.6 million). We discuss these projects in the order listed above.

The Data Center Upgrade was approved for funding in SCE's 2006 GRC at a total forecast of $31.5 million. SCE now seeks $10 million in 2009 to complete this project. DRA concurs with SCE, but TURN excludes this $10 million request from its 2009 Category 1 forecast on the basis that SCE inflated its costs. TURN instead recommends that SCE be authorized $9.34 million to renovate and repair all deficiencies associated with the GO2 Data Center in 2010.699

The evidence does not support TURN's contention that costs for this project have been inflated. SCE has substantiated, and DRA has affirmed, that renovation of the GO2 Data Center is reasonable and should continue. Category 1 capital expenditures for 2009 should include $10 million for this project.

The Furniture and Infrastructure project was also approved for funding in SCE's 2006 GRC at a total cost of $15.3 million. SCE seeks $27 million in 2009 to complete this project. DRA concurs with SCE's proposal, but TURN recommends that SCE be allowed only $11.5 million in 2009 to complete this project because the full $27 million request would result in a 77% increase over the cost estimate in the 2006 GRC.700

This project was initially approved for furniture and electrical and mechanical infrastructure upgrades in the 2006 GRC. However, SCE subsequently added remodeling and reconfiguration of building interior spaces to the project due to operational needs of the business units housed in the GO3 and GO4 buildings.701 The enlarged scope of the project justifies the additional expenditure. SCE should be authorized $27 million in 2009 to complete its GO3 and GO4 Furniture and Infrastructure project.

The Energy Efficiency project implements SCE's Energy Resource Management Policy (ERMP) that addresses the shortcomings of its existing non-electric facilities and provides construction guidelines for new facilities to meet the current best practices for energy efficiency, electrical demand response, and resource consumption.702 SCE seeks to phase in this project beginning in 2009 and continuing through 2011 at